Thermal Methods of Petroleum Production (Developments in Petroleum Science)

Developments in Petroleum Science, 25 thermal methods of petroleum production DEVELOPMENTS IN PETROLEUM SCIENCE Advi...

Author: N. K. Baibakov | A. R. Garushev | W. J. Cieslericz

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Developments in Petroleum Science, 25

thermal methods of petroleum production

DEVELOPMENTS IN PETROLEUM SCIENCE Advisory Editor: G.V. Chilingarian Volumes 1 , 3 , 4 , 7 and 13 are out of print. 2. W.H.FERTL ABNORMAL FORMATION PRESSURES T.F. YEN and G.V. CHILINGARIAN (Editors) 5. OIL SHALE 6. D.W. PEACEMAN FUNDAMENTALS OF NUMERICAL RESERVOIR SIMULATION 8. . L.P. DAKE FUNDAMENTALS OF RESERVOIR ENGINEERING 9. K.MAGARA COMPACTION AND FLUID MIGRATION M.T. SILVIA and E.A. ROBINSON 10. DECONVOLUTION OF GEOPHYSICAL TIME SERIES IN T H E EXPLORATION FOR OIL AND NATURAL GAS G.V. CHILINGARIAN and P. VORABUTR 11. DRILLING AND DRILLING FLUIDS 12. T.D. VAN GOLF-RACHT FUNDAMENTALS OF FRACTURED RESERVOIR ENGINEERING 14. G. MOZES (Editor) PARAFFIN PRODUCTS 15A 0.SERRA FUNDAMENTALS OF WELL-LOG INTERPRETATION 1. THE ACQUISITION OF LOGGING DATA

15B 0.SERRA FUNDAMENTALS OF WELL-LOG INTERPRETATION 2. THE INTERPRETATION OF LOGGING DATA

16. R.E. CHAPMAN PETROLEUMGEOLOGY 17A E.C. DONALDSON, G.V. CHILINGARIAN and T.F. YEN ENHANCED OIL RECOVERY, I FUNDAMENTALS AND ANALYSES

18A A.P. SZILAS PRODUCTION AND TRANSPORT OF OIL AND GAS A. FLOW MECHANICS AND PRODUCTION second completely revised edition

18B A.P. SZILAS PRODUCTIONAND TRANSPORT OF OIL AND GAS B. GATHERING AND TRANSPORTATION second completely revised edition

19A G.V. CHILINGARIAN, J.O. ROBERTSON Jr. and S. KUMAR SURFACE OPERATIONS IN PETROLEUM PRODUCTION, I 19B G.V. CHILINGARIAN, J.O. ROBERTSON Jr. and S. KUMAR SURFACE OPERATIONS IN PETROLEUM PRODUCTION, I1 20. A.J. DIKKERS GEOLOGY IN PETROLEUM PRODUCTION 21. W.F. RAMIREZ APPLICATION OF OPTIMAL CONTROL THEORY TO ENHANCED OIL RECOVERY E.C. DONALDSON, G.V. CHILINGARIAN and T.F. YEN (Editors) 22. MICROBIAL ENHANCED OIL RECOVERY J. HAGOORT 23. FUNDAMENTALS OF GAS RESERVOIR ENGINEERING W. LITTMANN 24. POLYMER FLOODING

Developments in Petroleum Science, 25

thermal methods of petroleum production N.K. BAIBAKOV A.R. GARUSHEV translatedby

W.J. CIESLEWICZ Colorado School of Mines

ELSEVIER -Amsterdam - Oxford - New York -Tokyo 1989

ELSEVIER SCIENCE PUBLISHERS B.V. Sara Burgerhartstraat 25 P.O. Box 211,1000 AE Amsterdam, The Netherlands Distributors for the United States and Canada: ELSEVIER SCIENCE PUBLISHING COMPANY INC. 655, Avenue of the Americas New York, NY 10010, U S A .

ISBN 0-444-87372-4 (Vol. 25) ISBN 0-444-41625-0 (Series) 0 Elsevier Science Publishers B.V., 1989

All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior written permission of the publisher, Elsevier Science Publishers B.V./ Physical Sciences & Engineering Division, P.O. Box 330,1000 AH Amsterdam, The Netherlands. Special regulations for readers in the USA - This publication has been registered with the Copyright Clearance Center Inc. (CCC), Salem, Massachusetts. Information can be obtained from the CCC about conditions under which photocopies of parts of this publication may be made in the USA. All other copyright questions, including photocopying outside of the USA, should be referred to the publisher. No responsibility is assumed by the publisher for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions or ideas contained in the material herein. Printed in The Netherlands

TABLE OF CONTENTS PART I. PETROLEUM PRODUCTION EMPLOYING HEAT CARRIERS 1 . Developmentof thermal methods and the prospects of using them to increase oil yield from reservoirs.............................................................................. 2 2 . Reservoirs with high viscosity crude: targets for application of thermal methods........ 2 3. Study of factors determining petroleum yield of reservoir rocks containing high viscosity crudes .............................................................................. 6 6 a. Filtration characteristics of viscous-elastic systems ....................................... b. Petroleum yield of reservoirs with micro- and macroporosities ......................... 9 4. Yield of high viscosity oil from reservoirs producing by dissolved gas drive..............17 5. Increasing the yield of high viscosity oil by use of different heat carriers ..................22 a. Use of water of different temperatures to displace high viscosity crude ...............22 b. Effect of temperature on destruction of structural and mechanical properties of viscous elastic systems and on the efficiency of capillary soaking .............................................................................. 26 c . Displacement of high viscosity oil by different heat camers............................. 27 d. Effectiveness of cyclic steaming on water-invaded formations ......................... 30 6. Use of thermal methods at Zybza field containing high viscosity oil ........................ 36 a . Petroleum yield from reservoir rocks of micro- and macroporosity types .............36 b. Experience with different methods of reservoir stimulation during the period preceding start of steam injection ................................................... 38 7. Selecting the best steaming methods for reservoirs lacking uniform characteristics....... 41 41 a . Steam as an effective heating agent ......................................................... b. Selection of oil fields and of specific wells for application of thermal treatment 41 42 c . Steam injection techniques ................................................................... d . Steam treatment by block-cyclic techniques .............................................. 43 8. Experimental and commercial scale application of different reservoir steaming techniques ............................................................................... 46 46 a . Development of reservoir steaming method in Russia.................................... b . Amount of water cut in the recovered oil and its effect on applicability of .... 49 the steaming method .................................................................... c . Efficacy of repeating the steam soaking.................................................... 54 d. Frontal displacement of oil by continuous area-steam injection ......................... 57 e. Selecting most suitable blocks in the oil field for steam flooding investigations...... 59 f . Techniques and technology used in area-steam flooding ................................ 62 g. Experimental work and commercialproduction using the 76 block-cyclic steaming technique ............................................................. 9. Monitoring and control of block-cyclic steaming under field conditions.................... 81 10. Results of reservoir steaming under experimental conditions in producing fields ......... 90 a . Combined steaming and water flooding in Sakhalin oil fields........................... 90 b . Steaming at Yarega oil field in Khomi region ............................................. 92 c . Increasing oil production from Azerbaijan fields by steam injection.................... 96 d . Steam treatment at Kenkiiak oil field in Aktiubinsk region .............................. 98 e. Use of heat carriers for production from fields with low viscosity oil ................. 99 f . High temperature water as an effective solvent assuring highest oil recovery ........100

......

..

Y

PART 11: PETROLEUM PRODUCTION BY IN SITU COMBUSTION (FIRE FLOODING) 1 . Characteristicsof in situ combustion: EOR method .......................................... 103 103 a . Different variants of in situ combustion method .......................................... b. Selectingpetroleum reservoirs for application of fire flooding.......................... 107 c . Methods of starting in siru combustion ..................................................... 108 d . Use of wet oxidizer for start-up of in situ combustion ................................... 113 2 . Equipment and installations used in fiie flooding ............................................. 114 a . Equipment for start-up of in situ combustion .............................................. 114 b. Selection of equipment for oxidizer injection .............................................. 119 c . Top-side and wellbottom equipment ........................................................ 124 129 3. Oxidation and heat exchange processes in oil reservoir ....................................... a. In situ combustion ............................................................................ 129 b. Rate of chemical reaction and the energy of activation .................................... 129 c. Rate of advance of combustion zone and heat distribution ............................... 136 d. Temperature field of oil-bearing bed and conditionsrequired to sustain in situ combustion .................................................................................... 138 4 . Experimental and commercial production of oil from reservoirs by in situ combustion .. 145 a. Background notes ............................................................................. 145 b. Results of in siru combustion in the homogeneous bed at Pavlova Gora oil field.... 146 c. Cementing of loose sands in near wellbottom zone by coking ......................... 163 d . In situ combustion at Zybza-Glubokii Yar oil fields where rocks with 167 macro- and microporosities occur together in the same reservoir .......................

PART III. HEAT-ENERGY INSTALLATIONS FOR USE WITH THERMAL EOR h4ETHODS 1 . Steam generating plants ........................................................................... 177 a. General requirements of steam generators for use with EOR work ..................... 177 b. Technical characteristicsand special design features of different steam generators ... 178 c. Improving the steam generators and the prospects of employing high temperature reactors ........................................................................... 188 2 . Special compressor installations for in siru combustion ...................................... 190 PART IV. PLANNING OF OIL PRODUCTION BY THERMAL METHODS 1 . Prerequisite geological and physical conditions ............................................... 198 2. Technological requirements for application of thermal methods ............................. 199 3. Basis for oil production system by thermal EOR methods ................................... 201 a. Selection of oil reservoirs.................................................................... 201 b . Oil production schemes used with thermal treatments .................................... 202 c . Selection of well-grid density ............................................................... 203 d . Effects of rates of well-grid development on oil production regime .................... 203 4 . Planning of oil production by thermal methods for the Karazhanbas field project ........ 204 BIBLIOGRAPHY ..........................................................................................

206

Classification of thermal methods of enhanced recovery:

II

I

I on the near bonomhole zone

I

I

1

to heat water

with surface sources 'of energy and fuel

thermal a c r l I I on reservoir

I

I

I using underaround

on extracted crude

I

I

2:

in-well

in the well column

in an installation withhotinput of agents

surface

using

I

remove paraffin

thennochemical treatment

nstallaions ellhead

thermoelectric treatment fuels

P--r using high requenc urrents

using

continuously

I

in-well install8 tions

currents

using underground explosions

using waste

added as fuels tion

U using heat

recovery of surfactants and solvents

1

installation having a shifting center of combustion with coal

atomic power stations

with acid treatment with other

*

in an I installation having a shifting center of combustion using only crude oil as fuel

controlled nudear reactions

injec

by air injection with addition of gas

combat formation

injection wells

complete drilled well by I eliminating water through evaportion

ACKNOWLEDGEMENTS The following organizations contributed $500 U.S.each toward partial payment of my expenses incurred in the preparation of this translation: 1. Department of Mineral Economics, Colorado School of Mines, Golden, Colorado. 2. Beb Erd Gas und Erdol, G.M.B.H. of Hanover. West Gemany.

3. Chevron Oil Field Research Company, La Habra, California. 4. Mobil R & D Corporation,Dallas, Texas.

5. Tenneco Oil Exploration and Production, Bakersfield, California. I wish to thank these sponsors for their support. No government funds were used on this translation project.

W. J. Cieslewicz Associate Professor of Mineral Economics Colorado School of Mines

Part I.

PETROLEUM PRODUCTION EMPLOYING HEAT

CARRIERS

1.

DEVE~PMENTOF-TlrIIiRMBL_METH4DS-B~~-~~E-~~~~~ECIT Y S I ~ G _ T f I E ~ T e I ~ ~ B E B ~ ~ I ~ - QIBS ~~~-E~Q~-BE~

Steam-injection for enhanced oil recovery (EOR) was first carried out in Russia in 1965 in the oil fields of Krasnodar Temtory, a geographical region located north of the Caucasus Mountains and east of the Awv Sea. Encouraging results obtained in these experiments led to the decision to organize the different Krasnodar fields into one oil and gas district. One of the oil fields, the Zybza-Glubokii Yar (Zybza for short) was selected for experimental and pilot work to further develop the steam-injection method. The Petroleum Scientific Institute for Research and Planning at Krasnodar (Krasnodar Petroleum Institute) was placed in charge of this project. The knowledge gained at this experiemental field is now being utilized for EOR in Russian petroleum producing regions. Between 1965 and 1975 the following specific work was performed at the Zybza field by the Krasnodar Petroleum Institute working in cooperation with other research and industrial organizations: (a) Field testing of different technological variants of steam injection. (b) Laboratory studies on displacement of oil from reservoir rocks by different heat caniers. (c) Field testing of new, economic transportable steam generators specially designed and built for steam injection work at the Machine Construction Plant in Nal'chik in the KabordinoBalkar region in European Russia. (d) Designing and making (at the Zybza field machine shops) of special bottom-hole and wellhead equipment required for high temperature steam-injection work. (e) Completion (1969) of the first steam injection installation with stationary steam generator for use in commercial production of oil from reservoirs.

Krasnodar Territory is one of Russia's oldest oil producing regions. The majority of its oil fields lie along the southern flank of the West-Kuban trough. A large number of these fields have heavy, high viscosity crudes, rich in tars. The fields containing heavy crudes lie at depths ranging from 50 to lo00 m. The reservoir rocks represent embayment environment and are found from the Azov Sea to the Abino-UkrainianArea, a region extending for over 250 km. The oil traps occur in monoclinal structures. The reservoir rocks have a permeability of 200-300 millidarcies. The density of petroleum varies from 0.950 to 0.985 g/cm3; the content of sour tars ranges from 55 to 60%, oil viscosity ranges from hundreds to thousands of centipoise. The oil recovery factor of the typical reservoir is very low, making the production either extremely difficult or practically impossible. These reservoirs have been exploited for the last 3040 years; they are now marginal and in final stages of production. Their oil recovery factor is 0.1; this figure applies both to the producing horiwn I of the Maikop series (0lig.-Mioc. clays and silts) in the Neftanyi sector of the Krasnodar petroliferous region and to the Kumsk producing horizon of the Zybza, Kholmsk and Severo-Ukrainsk oil fields of the same petroliferous region. According to the Krasnodar Petroleum Institute, the probable (indicated) heavy oil reserves of the Krasnodar petroliferous region are much higher than the proven (measured) reserves. 2

Petroleum Production Employing Heat Carriers Confiiation of these probable oil deposits is expected in the near future. In earlier exploration work, whenever such heavy oil deposits were found, they were considered noncommercial because the oil flow during tests of discovery wells was very poor. As a result, these discovery wells were abandoned and the respective oil-saturated beds were no longer considered as exploration targets. This exclusion applied to the horizon I of the Pont stage (Pliocene) of the Akhtyr-Bugundyrsk field, the Meotis Stage (Miocene) of the Ukrainsk field and the horizon I of the Maikop series at the Pavlova Gora field in the eastern embayment sector of the Krasnodar petroliferous region. For this reason, in a number of wells that were drilled subsequently, both the Miocene oil-bearing beds at the Kholmsk field and the Paleocene oil-bearing beds in the Akhtyrsk area were no longer tested at all for oil flow. Independently, the stratigraphic wells drilled at the same time by the different geological organizations of the Krasnodar Temtory accumulated a great amount of information on petroleum occurrence in the sedimentary deposits of this region. Analysis of cores and of other well data indicated a high degree of reservoir rock saturation with high-viscosityoil. Only some individual fields such as Zybza. Yuzhno-Karsk, also in part the AbinoUkrainsk, and several others were developed, and for a period of time they produced at high rates. These initially high yields were due to the abnormally high permeability of reservoir rocks saturated with the viscous-elastic non-Newtonian crudes. The typical structural and mechanical properties of these super-viscous heavy petroleums are shown in Table 1. Table 1. Physical and chemical properties of petroleum produced from Yuzhno-Karsk oil field ~~

Well

Constants

Number

60

428

Density at 2 8 C Content, in %: water cut

0.981

0.984

tars

47.5

paraffins Temperature, OC solidification point flash point Dynamic viscosity (in centipow at 2oOC at 3oOC at 4oOC at 5ooC Beginning of boiling, OC

--

2 128

----

0.990

--

--

40.0 50.0

---

--

--- ,

2172 700

1590 488

1570 522

407.7 246

254

--

391.4 241

4 3 3

37.0 42.5

28.0 57.5

--

431 0.986

477.7 254

144

--

--

---

Although the gasoline fraction is almost absent in this crude, it is nevertheless a valuable stock-feed for production of diesel fuel and of special kerosenes, also as source of high quality bitumens. In tests, this crude showed a shift in its limit of stress 2. equal to 28 kgIcm2, and on that basis, it was classified as a liquid of non-Newtonian type. 3

Thermal Methods of Petroleum Production When the yields from the aforementioned fields declined, water-flooding and gas injection were tried, both without much luck. Other, more radical methods of recovering high viscosity crudes did not exist at that time. Ultimately, these production difficulties caused the interest in oil deposits of this type, in general, to abate. As a result, during the last twenty years, the deposits of high viscosity crudes were overlooked and no longer studied during geological exploration work for petroleum. At this time (1980). the deposits of high viscosity crudes are again actively studied and searched for during exploration work. In fact, a special institute, the All-Russian Scientific Research Institute on Thermal Methods of Oil Production, has been organized to study deposits of this type and to develop methods of recovering their high viscosity crudes. This Institute has worked out detailed projects to explore for deposits with heavy crudes both in some new areas and in several old producing regions. Right now, the Union Thermal Petroleum (a national organization)-and Krasnodar Oil and Gas (a regional organization) are both carrying out geological exploration work according to these project guidelines. Both the old deposits, now "being rediscovered," and the newly found ones all lie at shallow depths ranging from 50 to 1000 m. They are all located in or near areas with already existing oil production installations. The application of new methods of oil recovery in these fields is therefore greatly facilitated. The thermal EOR technique was selected because it proved to be more effective for production of high viscosity oil than other methods. Accurate knowledge of the reservoir is essential for proper application of any method of production. Right up to the time when steam injection studies were about to begin, the data on the character of the reservoir were inadequate. The reservoir was thought to be of fracture-porosity type with the filtration of fluids taking place principally along a system of connected fractures. It was assumed that the heat carrier, that is, steam or hot water, would move along the fractures, heating and at the same time displacing the oil from the rock pores. From the very beginning of its application, the thermal EOR method, along with good results produced some bad effects as well. Additional study of the reservoirs was therefore requird, it called for drilling of special reservoir-evaluationwells with core recovery from the oilbearing beds. The marine embayments of this entire petroliferous sedimentary basin were apparently situated along some foothills. These embayment deposits are lenticular in cross section and show, typically, maximum accumulation of large-size fragments. Earlier, these lenticular sedimentary features, 50-70 m in thickness, were interpreted as carbonate reefs, although the only basis for this interpretation was the carbonate lithology of the large-size fragments. High porosity of these reservoirs was attributed to fractures and caverns which are so typical of carbonate reefs. Detailed study of cores recovered from the reservoir-evaluationwell No. 788 disproved the reef theory. The coarse fragments of limestone rocks and especially of dolomite breccia were both of detrital origin. They came from the weathering and erosion of carbonate beds in the mountains adjacent at that time to the ancient sedimentary basin with its embayments. The reservoir rocks of the Zybza field, in particular, consist essentially of detritus of different size. The porosity within the reservoir varies sharply from place to place, depending on the natural arrangement of these fragments and on the amount of cementing material. Reservoir rocks filled with fine-grained carbonate cement or with basalt mylonite breccia have porosities ranging from 17 to 36%; those with silt cement, from 21 to 35%. The size. of breccia fragments vary from 1 to 100 mm. Largesize breccia, even when fractured, does not form a reservoir rock because the openings in these fractures are extremely small. In cross section, further down dip of these strata, other oil-bearing zones are found within the silt-stone and sand stone lithofacies. 4

Petroleum Production Employing Heat Carriers

11.

I.

II

.

I.

II

.

11.

\

These additional studies canied out by the Krasnodar Scientific Research and Project Development Institute have thus disproved the earlier interpretation of the oil trap as a reservoir of fracture porosity type. On the basis of their principal characteristics, the producing reservoirs of high viscosity crudes found in the Krasnodar Territory conform to two general thermo-hydrodynamic models: Type I (microporous) reservoirs: They consist of oil-saturated siltstones interlayered with barren shales, siltstones, and also with dolomite and clay breccias. The porosities of the reservoir rock of this type range from 50 to 250 millidarcies. The oil recovery factor, as determined by many years of production experience, does not exceed 0.1. At present, the oil fields with this type of reservoir rock are not workable by conventional methods. Type I1 (macroporous) reservoirs: the reservoir is made up of large breccia fragments with big cavities. Reservoir rock permeabilities range from 500 to 1000 Darcies. The oil apparently formed in situ,accumulatingin these cavities.

Fig. 1. Reservoir models of micre and macroporositiesfrom Zybza oil field. No type I1 oil reservoirs have been found occumng by themselves; they are usually present with type I reservoirs. Type II reservoirs are less common and account for a much smaller share of oil reserves. However, whenever the deposit consists of both types of reservoir rocks, type I1 accounts for most of the production during the initial stages, while type I rocks show practically no oil flow. On the other hand, the free flow of oil from reservoir rocks of type I1 is only of short duration; at Zybza field the free flow lasted only 5-6 months. Even this short period of free flow is made possible only because of the viscous-elastic properties of these non-Newtonian viscous crudes. In this book the authors discuss the principles of thermal methods of oil production from the type I reservoirs. Indeed, these methods are thought to offer the best prospects for EOR of viscous crudes. The authors, together with a group of specialists from a number of different organizations, are now continuing the development work on thermal EOR methods for use in geological conditions of oil occurrence similar to those of the Krasnodar petroliferous region. Actually, in the Krasnodar region the practical experience anticipated subsequent theoretical studies. Thermal EOR methods were used here even before any laboratory investigations were undertaken. 5

Thermal Methods of Petroleum Production

3.

STUDY OF FACTORS DETERMINING PETROLEUM YIELD OF RESERVOIR ROCKS C O h ' T m G H - V I S C O S I T Y CRUDES

Enhanced recovery of high-viscosity crudes from reservoirs requires very careful study of past production history from these fields. Very pertinent are the filtration characteristics of highviscosity crudes and the mechanism of oil extraction from the reservoir rocks. Both of these phenomena were studied at the Zybza field. During the initial stage of production, all oil wells flowed freely with a natural gas ratio of 5-6m3/m3. During that period, the bottom-hole pressures were apparently close to the gas saturation pressure. In such cases, the viscous-elastic properies of the crude come into play under the conditions that exist in the zone adjacient to the well bottom. The gas-liquid mixture flows into the well not only because of direct pressure drop between the reservoir and the well but also because of the energy reserves of the viscous-elastic system: oil-reservoir rock. The initial freeflow period lasts on average from 6 to 8 months. sometimes longer. The producing life of the well is 10-12 years. At the beginning of the final period, the gas factors decrease to 2-3m3/m3 and formation water appears with the oil. By the time the water cut in produced oil reaches 30%. the free flow of the well ceases completely and bottom-hole pumps must be employed. During the period of transition from the free flow to artificial lift, when water content is still substantially below 30% and gas factors drop below 5m3/m3, the well is made to produce by pumping formation water into the annular space of the well. Except for this purpose, during the transition stage the pumps are not turned on at all. The filtration properties of super-viscous crudes and the mechanism of their drainage from the reservoir rocks are now known as a result of the hydrodynamic studies. The latter were carried out, for example, at the Abino-Ukminsk field in the course of oil production by artificial lift using bottom-hole pumps. To enable these hydrodynamic investigations of producing wells, a specially built attachment was installed. It used an adapter at the pump intake, replacing the elongate pump sleeve. In the case of the free flowing wells, this attachment was installed on the shoe of the free flow smng. One or two pressure gauges were installed beforehand within the attachment. These gauges recorded pressure changes caused by fluids entering the attachment through slit openings located in the upper part of the attachment. To prevent plugging-up of these openings, the attachment, with instruments already placed in it, was filled with water up to the level of slit openings. The adapter was also provided with openings through which the fluids from the well entered the pump intake and then into the lift smng. After the lowering of the tubing with these instruments down to the oil-bearing horizon, the well was started up at regimes assigned to it according to the program of study. Fig. 2 shows indicator diagrams for wells operated by down-hole pumps in late production stage of the oil field.

-

3&E a

Q. t(tons)/day

Q. t(tons)/&y

Q. t(tons/day

I - formation fluids II - water III - oil

0,l 0.2

0.3 0.4 O,I

well t 3 8

well t39

Fig. 2. Indicator diagrams 6

Petroleum Production Employing Heat Carriers This is the frst time that such studies were conducted anywhere on fields with superviscous crudes. Studies of this kind are important because they make it possible to get information on reservoirs of heavy petroleum still at early stages of production. In evaluating wells 55 and 60, drilled within the confines of Abino-Ukrainsk field, cores were taken. In well 55, core saturation with oil was the same as the initial saturation r e p o d at the time when the field frst started production. However, both the gas ratio and the reservoir pressure gave readings that were lower than the initial figures. Limited interaction between the section of the oil field being exploited and the adjacent already depleted section accounted for the differences between the intial and subsequent gas ratio and pressure figures. In well 60, the content of free formation water was 25-30%. After completion and study of the wells Nos. 55 and 60 and the determination of filtration values, it was decided to place these wells in production by air-lift method, with water delivered into annular space. Inasmuch as the required start-up pressure. with other conditions being equal, depends on the type of lifter, all known lift designs were examined and necessary calculations made. In well 60. a single-line central system lift was used with a diameter of 63 mm. This type of lift enabled safe lowering to the bottom through the lubricator, of the two pressure gauges: the differential manometer and the maximum manometer, the latter coupled with the former. Well 60 was equipped with a 126-mm diameter water shut-off string. The air was supplied by a transportable compressor, type UKP. First, the air was forced through for a period of four hours at the start-up pressure of 75 kg/cm2, then the well was placed in production at the working pressure of 40-45 kg/cm*- To bring the pressure down to this level, part of the air in the well was released into the atmosphere. During the production period, the well yielded liquids at the rate of 16 tondday with water content of 32%. The well was then shut in for a period of 6 hours to restore the formation pressure. At the end of the exploitation period employing the above cyclic regimen, the production of the well became erratic with disruptions occurring in the delivery of formation liquids. To maintain the yield of liquids at the rate establishedearlier, injection of liquids was started into the central string with simultaneous injection of compressed air. The change of regimen in the pumping out of liquid required a change in the depth to which the tubes had to be lowered. This step was followed by forcing air into the central string. In the course of one hour, a high yield of liquids amounting to 310 tondday was established in the well, with a sharp increase also recorded in the water cut (up to 99.8%). At this point, the study of well No. 60 was terminated. The changes in the operating regimen of well 60 are significant. For the fmt 3 hours of the first stage, the well produced without need of water injection. During the fourth and,last hour, however, water injection was necessary to maintain stable yield of liquids. The above changes are characteristic of reservoir conditions existing towards the end of the free-flow production stage. A different method was used to study well 55. This well was provided with a water shutoff casing string. A two-line lift was employed: the outer line with tube diameter of 89 mm, and the inner with a diameter of 50 mm. The well manometers, one measuring the differential pressure, and the other the maximum pressure, were mounted in the adapter on the shoe of the second tubing string. Knock pumping-compression tubes, 101 mm in diameter, were installed between the intake slits and the adapter. The purpose of these tubes was to dampen and to compensate the hydraulic blows during the start-up of the well. Fast well start up was facilitated by injection of air into the inner tubing string and of some water into the annular space betwen the inner and the outer tubing strings of the lift. To inject the water, a pumping unit, type AN-400, was employed. The water, pumped in between the two tubing strings, then egressed through the annular space between the outer tubing string and the casing. With pressure at 40 kg/cm2, the well then produced only petroleum at the rate of 11 tondday. 7


Gas ratio equaled 6m3/ton. which corresponded to the initial value. Precisely at these gas factor values, all the wells of the above mentioned deposits showed free flow during the early production stage. Upon completion of well 55. the formation pressure in that part of the reservoir was 28.7 kg/cm2. Had this pressure been sufficient, well 55 would have been completed to produce by free flow. The analysis of core data and the high gas saturation of the crude indicated that except for the pressure at the time of completion of well 55. the condition of the reservoir at that particular place corresponded to early stages of production. Lower pressure readings were due to the fact that by the time well 55 was drilled, that section of the reservoir was already exploited by wells with strong encroachment of formation waters. The productivity coefficient at any point on the indicator curve describing the two phases, oil and water is (K product) liquids = (K product) oil + K (product) water.

As seen on Fig. 2. the indicator diagram gives the following values for well No. 41: liquids - 46(tons/day)/(kg/cm2) = 532 (cm3/sec)/(kg/cm2) water - 36(tons/day)/(kg/cm2) = 416(cm3/sec)/(kg/cm2) oil - lO(tons/day)/(kg/cm2) = 116(cm3/sec)/(kg/Cm2) In the Abino-Ukrainsk oil field the average well spacing is 100 m, oil viscosity is 4.000 centipoise, and the thickness of the producing horizon is 10 m. The phase permeability for oil is

k=

m=

k = 0.366 (K permeability)oil 1 g !!-0.366 x 116 x 3 4000 510 Darcies rsec.

The above value of 510 Darcies was obtained for well 41 at the time when the water cut of the existing wells in the AbincFUkrainsk field was already 80%. At the same time, the water cut of well 41 was still only 30%. a value corresponding to the transition stage of production by free flow to production by artificial lift using downhole pump. These data indicate that at the ratio of 80/30 P 2.7, the productivity and consequently the permeability for oil should be higher, as per figures below: k = 510 x 2.7-1400 Darcies With permeability values of 1400 Darcies and with oil viscosities of 2,000-4,000 centipoise, the crude should have normal mobility in any reservoir rock characterized by macroporosity. The producing formations in the Abino-Ukrainsk field are essentially of this porosity type. Like the Zybza field, the Abino-Ukrainsk field also has some reservoir rocks of the microporosity type. Inasmuch as the oil in the reservoirs of the latter type is not mobile, only the oil-bearing horizons of macroporosity type are being worked during the early production stage of the field. The above discussion shows how downhole hydrodynamic studies of the well can reveal the drainage mechanism active in the reservoirs containing viscous-elastic petroleums of nonNewtonian type. The following conclusions can be made in this regard: a. The mechanism of filtration of gas-liquid mixture in oil fields with viscous-elastic crudes of non-Newtonian type is very different from the mechanism of filtration in the oil fields with light 8

Petroleum Production Employing Heat Carriers crudes of normal viscosity. Two production periods characterize oil reservoirs of macroporosity type: free flow period and the artificial lift period. In the reservoirs of microporosity type, the viscous-elasticcrudes of non-Newtonian type cannot filtrate through the reservoir rocks. b. The period of production corresponds to the early stage, when the oil field is worked for 6-8 months according to the model applicable to reservoirs of microporosity type. The formation pressure is close to the saturation pressure; the gas ratios are on the order of 5-6m3/m3, and the oil viscosity is so high that it cannot be determined by standard methods. The yields of water-free crude and the productivity do not differ from those of ordinary average oil fields with light crudes of normal viscosity. Non-Newtonian liquid in a system: oil-reservoir rock obeys the viscosity-elasticity law of filtration. In the filtration of this type of oil the character of the phases has no influence on the flow. The latter remains unaffected even though very fine bubbles of gas may be present in the oil that filters to the well from the oil reservoir. Because the oil viscosity is particularly high, these tiny bubbles remain in the oil for several days, even after the crude is brought up to the surface. This indifference of the phase character on the flow is what distinguishes the filtration of viscous petroleum from the two-phase flow of the gas-holdingcrudes with low or normal viscosities. c. The second period of production continues until the wells in the oil field are shut down. During this period, the amount of water produced with the crude progressively increases and the oil yield decreases to the point at which it's no longer economical. A wrong conclusion is made at this point that formation water fully encroached upon the reservoir and that further operation of the wells would be pointless. Actually, this water encroachment is merely due to the macroporosity of the oil reservoir. Because the oil reservoir consisted of both types of beds, some with macroporosity and others with microporosity. the application of steaming of the reservoir became very complicated. In opening up such a reservoir, the two types of beds cannot be isolated. A production technique must therefore be found which would permit effective and simultaneous working of the beds with microporosity, together with those with macroporosity. To supplement the above discussed hydrodynamic studies of the oil reservoir, great amounts of laboratory work was also carried out on oil displacement from reservoir rocks of microporosity type. In these studies the reservoir rocks showing different degrees of water encroachmentwere subjected to action of different types of heat carriers.

Back in 1950, several lithological wells were drilled in one of the oil fields of the Krasnodor Temtory. However, low core recovery made it impossible to obtain a detailed description of producing horizons. Not a single core adequate for lithologic study could be recovered. Nevertheless, a model of the reservoir rock was prepared on the basis of indirect data. It incorrectly described the reservoir as one consisting of fracture porosity of rocks with cavities. This concept was later accepted in making calculations for oil production from reservoirs formed in Miocene marine beds in the Krasnodar Tenitory. For a long time it was assumed that oil or gas-oil mixture drained from the porous blocks of reservoir rocks into the fractures and then flowed along these fractures into the wells. Twenty years later, first attempts were made to apply fii flooding at a sector of the Zybza field selected for the study. The so-called "lense" of Horizon IV of the Sarmatsk stage of Miocene epoch was the target of this EOR test. The air injected into the ignition well flowed quickly through the reservoir rocks, as through a pipe, and into the production well. After the initial displacement and, at times, violent ejection of some crude oil, only injected air flowed into the production wells. When the latter were shut in, their wellhead pressures built up almost immediately to those 9


(30kg/cm2) maintained at the injection well. From the results of hydrodynamic tests of the wells carried out earlier at different periods during the life of the Zybza field, it was established that the producing bed had high Permeability. It ranged from 100 to 600 Darcies, and in individual sections of the field, it exceeded lo00 Darcies. Since, however, earlier geological and geophysical data on the Zybza field were insufficient and the cores were altogether lacking, not even a rough reservoir model could be constructed at that time, neither could oil reserves be accurately calculated. In 1968-69, in a sector of the Zybza oil field, where fieflooding was to be employed, an inclined directional well (90) was drilled. Core recovery again was very difficult so that only partial cores of the oil bearing bed could be obtained. Additionally, 16 wells were drilled in the same sector of the field without coring. While drilling through the interval that showed high permeability and loss of drilling fluid, well cuttings brought to the surface large 10-15 cm long, irregularly shaped fragments of breccia. These fragments were then studied in detail both visually, in the laboratory, and in polished sections. Shallow, very small oil saturated fractures and cavities were indeed found, however, they were far too limited to hold significant amounts of oil. The rocks themselves were not permeable and, therefore, could not have served as flow channels for gas-oil fluids. These findings placed in doubt the accuracy of the reservoir model constructed earlier. In 1972, a special well (788) was drilled in order to recover enough cores to enable the construction of a correct model of the Zybza field reservoir. Using a coring tool "Nedra," almost 100% of the core was recovered along the entire productive thickness of the bed. A complex of lithological and geophysical studies were then carried out on all of the recovered cores. The presence of two different types of reservoirs was established, one of microporosity type, the otherof macroporosity. The permeability of the former ranged from 50 to 200 millidarcies, and of the latter from hundreds to thousands of Darcies. Within the petroliferous bed, the reservoir of macroporosity type was not as well developed as was the other type. Hydrodynamically, the two reservoir types are tightly connected, often alternating. one with another. At Zybza oil field for example. the thickness of the macroporosity (cavity) type reservoir measured in the well 788 ranged from 0.3 to 3.0 m, but in another well drilled in the more central part of the oil field, it ranged from 5.0 to 10.0 m and sometimes even more. The oil field sectors in which reservoirs of macroporous type are better developed are the ones which during early stages show high productivity and a significantoil yield. These zones in which both types of reservoir rocks are present are characterized by relatively high readings of both electrical laterologs and the spontaneous potential logs. Originally these readings were interpreted erroneously as corresponding to massive beds of limestone. Actually, they represented either thick, highly permeable reservoir rocks of macroporosity type, made up of large breccia fragments with oil-saturated large pore spaces or weakly permeable reservoir rocks of the microporosity type consisting of coarse breccia fragments with oil saturated clay or silt material filling cavities between breccia fragments. The microporosity type reservoir predominates in the Zybza field and it contains large unrecoverable reserves of petroleum. Although the readings of laterologs (up to 50 m V x A) and of spontaneous potential logs were very similar for both types of reservoirs, upon well completion the oil yield of the microporosity type reservoir was much lower. At Zybza field, over 50 wells when completed. began production with low yields of 1-3 tondday. Another 40 wells would not produce at all even though they were completed in petroliferous beds. Not until 20 years later the majority of these wells fmt became producers after steaming treatment had been applied. The above studies carried out at Zybza show that in the case of Miocene petroleum deposits containing high viscosity crudes, a complex of studies including lithological data, hydrodynamic 10

Petroleum Production Employing Heat Carriers formation tests, and borehole geophysical surveys are all necessary in order to determine accurately the type of oil reservoir. In case of Miocene beds containing high viscosity crudes, the above studies led to the identification of a new type of oil field. It is a reservoir of high porosity occurring in close association with the reservoir of microporosity type. In terms of volume, in fields of this type the microporosity reservoirs strongly dominate those of the macroporosity type. For the deposits of this type, the oil movement within the bed and its flow into the well can be represented by the following model. Table 2. Oil yields of wells showing similar characteristicsof their geophysical logs Number of wells having the same log readin PS

Average initial oil yield, tonsfday

454; 442 453; 452 446; 452 110; 12

0.5; 26.0; 5.0; 60.0;

46; 47 257; 256 159; 444 439; 441 107; 106 164; 134 106; 168 26; 34 191; 192

0.5 12.0 1.2 1.5

20; 7 20; 0.5 0.1; 0.5 1.2; 3.5 20; 0.5 22; 23 0.5; 1.0 0.5; 12.0 17; 1.0

Old interpretation of reservoir character based on laterologs (L) and spontanouspotential logs (SP) High resistivities on L and SP logs same same Frequent alternation of clay intercalationswith thin oil-saturated beds of high SP resistivities High resistivities on L and SP logs. same same same same same same

Actual type of reservoir I

II dominant I dominant

1 and I1

I I

[I and I U dominant 1

and II + I same Frequent alternatingof clays and [ dominant. [I subordinate oil producing beds 326324 [Iinterlayers 22; 21 same 46; 47 High resistivities on L and SP logs [I and I 20.0; 7.0 376; 378 1.0; 0.5 Very high resistivities on L and [ SP logs 317; 306 15.0; 1.5 [I and I same [ 2.0; 3.0; 0.5 182; 386388 same [ and I1 184; 386 5.0; 23 same 133: 107 0.5: 15.0 [ and I1 same 1. servoirs with hil resistivitieson L and SP logs were earlier interpreted as massive limestone dS. 2. I designates reservoir of microporosity type; 11-macroporosity. During the first stage of production from oil fields with reservoirs of the types shown above, the high permeability macroporosity-type reservoirs are worked first. During the exploitation of such reservoirs the oil remains highly mobile to the end, behaving just like an ordinary Newtonian liquid. The fact that the crude has anomalously high viscosity and its 11

Thermal Methods of Petroleum Production structural as well as mechanical properties are therefore typical of non-Newtonian liquids does not seem to reduce its mobility. The reservoir rocks of macroporosity type are developed to a lesser or greater degree in the oil fields of Zybza, Abino-Ukrainsk, Yuzhno-Karsk and others in the Krasnodar Petroliferous Region. Analyzing the history of each one of these oil fields, it was easy to establish that during initial stages of production, as new development wells were drilled, the oil yield of each field increased strongly. But then, within a relatively short period of 6 to 12 months, the yields of oil and even of water for each of these individual fields separately, decreased sharply. For example, at Zybza field during the fmt three months, the approximately 200 working wells produced liquids at the rate of 5000 tons/day, but during the subsequent 5-6 years, the same number of wells were producing at the rate of only 2,000 tons/day (Fig. 3)

m

P

- -

r

I"

Fig. 3. Dynamics of production of liquids and petroleum. During the same period of 5-6 years the formation pressure dropped from 70 to 20 kg/cm*. Furthermore, due to low permeability, only poor contact existed between the oil field and the area outside of the contour of closure, that is outside of the trap, thus preventing active water drive. Therefore, as the yield of liquids declined, the formation pressure stabilized giving rise to a condition very similar to that of a shut-in oil field without active water drive. These findings are confmed by production data. During the producing life of the oil field of over 30 years, about 9,600,000 tons of petroleum and 9,000,000m3 of formation water were produced. Characteristically,most of the wells of the aforementionedfields initially produced high oil yields of as much as 100 tons/day and only insignificant water cut. Then, within a relatively short time, the yields decreased markedly, while at the same time the percentage of water cut increased. Although the encroachment of formation water into the oil field might be suspected, that was not the case. Actually, only the production suffered from water flooding through coning but not the field itself. As soon as the oil field is developed, the high permeability zones, that is, the individual reservoirs of macroporosity type, start producing fiist. The connate water present in these zones also flows readily into the wells. It is this condition of the reservoir, rather than early water. The encroachment of the oil field as a whole. that gives high water cut. The exact amount of water as a 12

Petroleum Production Employing Heat Carriers percentage of liquids produced depends on the oikonnate water ratio of each macroporosity zone and on the relative mobility of the two liquids. High oil and water yields of wells located in high porosity zones of the petroliferous bed within the specific oil fields have been confirmed by both the geological and production data. For example, many wells located in the central part of the oil field that start producing at high initial rates of 70 to 100 tondday become, nevertheless, water flooded within a relatively short period of time. These wells contrast with other wells located likewise in the central part of the oil field or even near its edge right next to the contour of closure but completed in the microporosity zones of the oil-bearing bed. Such wells throughout their entire productive life show hardly any water cut. The total oil and water yields of wells completed in macroporosity zones produced during the entire period of exploitation are given in Table 3. Table 3. Average annual yields of wells producing from macroporosity zones of the oil field (in 1000s of tons). Well Vumbe.

fith

sixth

C Yield

110 289 164 87 309 107 364 88 89 298 61 161 304 134

Yea secon, third

Years

30 26 16 40 26 30 15 28 7 17 42 18 41 41

20 15 7 27 18 24 10 16 5 10 31 9 35 34

- -

10 7 4 9 11 12 5 5 3 3 10 4 11 10 -

5 5 3 7 9 8 3 5 2 3 7 4 7 7

-

7 3 1 3 5 4 2 3 2 2 3 1 3 2

3

first

II

-

1 ter Yil

1

3.0 2.0 2.5

2.5 3.3 2.0 5.1 5.5 6.0 3.5 4.5 2.5 4.5 2.6 3.1 3.6 4.5

5.2 6.5 4.1 11.5 12.1 14.5 9.0 11.0 5.0 8.2 5.5 7.1 6.9 12

17.0 8.0 7.0 14.0 15.0 14.0 10.0 14.0 8.0 11.0 10.0 11.0 12.0 13.0

11.0 11.0 7.0 20.0 21.0 20.0 15.0 20.0 10.0 14.0 16.0 15.0 17.0 20.0

--

The average annual yields of oil and water obtained for the same group of wells are shown on Fig. 4.

Y-

Fi 4. Dynamics of oil and water yield during production from reservoirs of t--: macroporosity type. At least some of the water that is produced with the oil probably flows in also from the adjacent zones of reservoir rocks of the microporosity type. 13

Thermal Methods of Petroleum Production The above data show that the wells completed in reservoir rocks of macroporosity type have much higher oil and water yields than the wells completed in reservoir rocks of the microporosity type. In case of the reservoirs of macroporosity type, at the early stage of production, the wells typically yield only oil; later, formation water appears in ever increasing relative amounts while the oil yield sharply decreases; finally, the amount of water again decreases. For example, the group of wells investigated (Table 3 and Fig. 4), other conditions being unchanged, in the course of one year reduced their oil yield from 377,000tons to 250,000tons, or 40%. During the fifth year the same group of wells produced only 36,000tons, 10 times less than initially. The total production of these wells during that five-year period amounted to 879,000tons of oil and about 600,000tons of formation water. During a period of over 20 years, the wells completed in the zones of oil-saturated reservoir rocks of the microporosity type produced 86,000tons of oil and 8.600 tons of formation water. Thus. reservoir rocks of this type, which contain large oil reserves, yielded only about 1/10of the oil and W O O of the water that were produced from the reservoir of the macroporosity type. Moreover, until the end of production from the field, the above ratios remained unchanged both for the indicated wells and for the oil field as a whole. By 1957,essentially all of the oil of the macroporosity type reservoirs was exhausted, and from that time on only the microporosity type reservoirs were being exploited. The yield from the reservoirs of the latter type was. however, very small. Between 1947 and 1957,the oil field as a whole produced 8,650,000tons of oil. Most of this production came from the reservoirs of the macroporosity type, only a small portion from the reservoirs of the other type. By contrast. during a period of more than 30 years, the wells producing from the zones of reservoir rocks of the microporosity type gave a total yield of only 950,000tons of oil. During production from oil reservoirs containing high viscosity non-Newtonian liquids, the formation water, if it is present in certain volume ratios, does actually facilitate normal movement of the crude through the reservoir rocks and up the tubing column of the well. Production investigations show that n o d flow of viscoelastic crudes results when formation water accounts for 35-40% of the liquids. With an increase of water content above this percentage, the phase mobility of oil diminishes, giving rise to a gradual increase of the water cut in the produced crude. Thus. proper combination of the two factors, the water ratios and the crudes of anomalous viscosity, does favor effective production from the oil field. ,gh permeability reservoirs of Until now, no one investigated the recovery fact' macroporosity type saturated with viscous-elasticcrude oil. i...,,..ents were therefore canied out to get more information on this subject. A reservoir model with fracture-type porosity was used in these tests, reproducing the real conditions of the petroliferous formation. The model reservoir was then saturated with a sample of synthetically recombined crude oil. The details of these experiments are described on the subsequent pages of this book. It was determined that oil recovery from reservoirs of this type can reach 75-80%, even without applicationof such secondary recovery techniques as water injection. Fig. 5 shows the rates of petroleum and water recovery for the entire oil field during the corresponding time periods I, II, and III, with almost a constant number of active producing wells. This diagram, together with Table 4,make it possible to interpret, period by period, the working mechanics of an oil reservoir of the macroporosity type saturated with high viscosity crude. These same data also allow approximatedetermination of the oil recovery factor for this type of reservoir.

14

Fig. 5. Dynamics of oil recovery during production from reservoirs of macroporosity type. Table 4. Total yields of wells MacrouorositvreserVOir Well {umber 110 289 164 87 309 107 364 88 89 298 61 161 304 134

I

Microuorositvreservoir

Yield ii OOO's of tons water

Well Number

Oil

73 50 30 101 70 82 32 58 18 32 94 34 99 106

26 35 22 54 59 63 40 59 24 40 30 37 35 50

418

I

Yiel in l w doil

I:;

pr 4.3

247 27 173 179 458 384 396 312 378 47 48

5.7

10

of tons water

0.6 1.2 0.4 1.o 0.5 0.1 0.1 1.o 0.1 0.5 0.2 1.5 0.8 1.8

Period I of the oil field production was characterized by a very strong increase of the total oil yield resulting from the completion of a great number of development wells. The total oil yield of the field (Qoil) during the first year of Period I amounted to 2,600,000 tons, while the water cut during the same period was very small. All in all, only 150,000 tons of formation water (Qw)was extracted, representing about 5% of the total liquids produced. During Period I, the formation pressure (Pf) decreased from 77 to 60 kg/cm2. High rates of production also continued during the second year of Period I, giving a total oil yield of 1,500,000 tons. The water cut was about 150,000 tons or about 10%of the oil produced. 15

Thermal Methods of Petroleum Production Formation pressure dropped to 40 kg/cm2. For each 1,000,OOO tons of oil produced during Period I, about 7 kg/cm2 equivalent of formation energy was expanded. In this manner, in the course of nearly two years time nearly 4,000,000 tons of oil were extracted, that is 45% of all the oil recovered from the field during its entire period of production. During the entire Period I, the reservoir drive was provided by gas dissolved in oil and by the elasticity forces of the crude. Period I1 lasted 7 years; oil yield was 4,500,000 tons and the amount of formation water produced was 2.900,OOO tons. Formation pressure declined from 40 kg/cm2 to 15 kg/cm2. Characteristically for this period, the water in the liquids recovered increased, then, towards the end of the period, decreased again. Gas dissolved in the oil provided the basic drive during this period. Forces of molecular cohesion between the oil and the reservoir rocks are weakened and oil mobility enhanced when water cut stays within the 35-50% range. Period III represented the terminal production stage of the field. Oil and water yields declined sharply; during a period of over 10 years only about 800.000 tons of oil were produced. The above field data and results of experimental work gave a clear picture of production mechanism for fields containing high viscosity crudes with up to 50% of tars. Initially, with the completion of development wells, such fields, for a short time, give high yields of oil accompanied by a sharp drop in reservoir pressure. During that stage, the elastic forces of viscous oil and the energy of dissolved gas constitute the principal reservoir drives. Bound formation water also assists in displacing the oil from the reservoir by weakening the forces of molecular adhesion betwen the oil and the rocks. During the subsequent stage of production, in spite of greatly reduced reservoir pressure, petroleum continues to move through the reservoir rocks at a pretty good rate, even when gas factors are low. According to an earlier assumption, the dissolved gas drive would give only very small coefficients of oil displacement from reservoirs containing high viscosity crudes with low gadoil ratio. However, this was not the case with the Miocene crudes studied at Zybza field. Viscous-elastic systems of this kind, characterized by high percentages of tars, effectively prevents the escape of dissolved gas, favoring its efficient utilization. Numerous studies were carried out both at the early and later stages of production on degassing of the Zybza crude upon its recovery at the surface. The crude brought to the surface from the wells resembles a foam-like, swollen mass. It releases its dissolved gas very slowly and, even at atmospheric pressure, takes 3-5days and more to degassify itself. Volume shrinkage takes place as the gas is released from the crude. The shrinkage factor determined by experimental studies for this gas-holding elastic mass was 0.3-0.7.To fully degassify this petroleum, it is necessary to heat it in crude oil stills. It is not yet known exactly in what state the dissolved gas is present in this crude. State of absorption was suggested by some earlier investigators. However, now it is thought that in all probability the gas is adsorbed on the surface of tars from which it cannot readily separate. This phenomenon would explain the slow release of gas from these crudes. Special study would have to be made to c o n f m this adsorption theory. Moreover, observations made during production suggest that in reservoirs with high permeabilities, conditions may be present that favor formation of a stable water-oil emulsion. Should reservoir pressure decline gradually, gas separation from such an emulsion would be slower within the reservoir than at the surface. Thus, from many wells

16

Petroleum Production Employing Heat Carriers which produced oil with water cuts of 50%, emulsions of extremely high viscosity of over 5,ooO centipoise were recovered. Within oil reservoirs of macropomsity type, such emulsions apparently form when the crude mixes with gassed formation water, especially if the liquids flow through such reservoirs at relatively high rates of speed. Two lines of evidence support the above conclusion: (a) Gas cap formation in the structurallyhigh part of the oil trap of this type does not take place. (b) Gadoil ratios of the producing wells remain stable over long periods of their operation. In this manner. the energy of gas dissolved in such high viscosity and tar-rich crudes. under these conditions, helps to drive the oil strongly through the reservoir bed. At the same time, the gassed crude and the water-oil emulsion behave as a homogeneous liquid with greatly increased elasticity. The interplay of the factors discussed above should result in high recovery factor for such viscous-elastic systems in oil reservoirs of macroporosity type. However, oil yield of such a system depends on the influence of the gas dissolved in the crude and on the permeability of the reservoir rocks. Most of the remaining oil reserves present in the Miocene strata of the Krasnodar Petroliferous Region are concentrated in reservoirs with poor permeability. Special experimental studies were therefore carried out to find an efficient method of increasing the oil recovery factor of these low permeability reservoirs. Models of two different kinds of porous media and of different gas factors were used in these experiments. 4. YIFT .D OF HIGH VISCOSITY 011. FROM m R V O R S PRODUCING BY DISSOLVED

GAS DRIVE The mechanism of displacement of superviscouscrudes from reservoirs of different geological characteristicsis not yet fully understood. The oil fields subject to this particular study all belong to strata of Miocene age. These reservoirs either do not have any aquifer drive or else their contact with formation water present outside of the oil trap is limited. Therefore, their water drive is weak and they produce essentially by dissolved gas drive. Application of new EOR methods called for detailed study of geological characteristicsof the oil field and for the determination of permeabilities of its reservoir rocks. The dominance of the dissolved gas drive and the absence of the aquifer drive in most of the oil fields in question were also taken into account. Earlier on, several authors studied some factors that influence oil yield from fracture-type reservoirs producing by dissolved gas drive 122.241. In their models, they represented crude oil by mixtures of kerosene with Vaseline The viscosity of these mixures was considerably lower than that of the Miocene crudes of Krasnodar oil fields. Two types of reservoirs, each with different permeability, are found within the petroliferous bed of the fields in the Krasnodar Petroliferous Region. A number of laboratory models were therefore prepared to reproduce these permeability differences. Models using sand as porous medium (porosiry-rype models) simulated the reservoirs of the first type. The range of permeability of this medium corresponded to that of the actual reservoirs of the same type. Models characterized by fracture-type porosity Ifracture-rype models), were used to represent the second type of the reservoir. Again. the permeability characteristics of the medium used in the latter type models were similar to those of the real reservoirs. At the start of production from oil fields of this heterogeneous nature, crude oil is held both in the reservoirs of micro- and of macroporosity types. The permeability of type I reservoir ranges from 100 to 200 millidarcies, and the permeability of type II reservoir, from 500 to over 1,OOO Darcies. Because of this large difference in values, the high permeability reservoirs of type 11, 17

Thermal Methods of Petroleum Production e.g., those occurring in Zybza oil field, are exploited fist. Under favorable conditions, the oil flows from the porous blocks into the fractures and then along the high permeability channels into the producing wells. Within a relatively short period of time, the macroporosity reservoirs of this type attain high recovery coefficients approaching the value of 1. By contrast, type I reservoirs, in the course of 10-20years of production still yield less than 10%of their oil reserves in place. This low yield, characteristic of such fields as Pavlova Gora and Akhtyrsk-Bugundyrsk. is due to weak filtration of viscous crude through reservoir rocks of microporosity type. In experiments, the drainage and extraction of crude oil were studied separately for the fracturetype and for the porosity-type reservoirs. The corresponding types of models were used to study each of the two reservoir types. Thefracture-type model consisted of a tube, 50 cm long, 5 cm in diameter, packed with glass strips, each strip 50 cm long, and 3-mm thick. The widths of these strips varied depending on the position of the particular glass strip within the cross section of the tube. The edges of the outer strips were fitted snugly against the inner wall surface of the tube. Five-millimeter wide strips of foil, 100 microns in thickness, were inserted between the inner walls of the tube and the glass strips. In this manner, the model formed a system of parallel strips, 50 cm in length. The width of the fractures varied depending on their position along the cross section of the tube. The openings within these cracks were 100 microns wide, corresponding to the presumed size of fracture opening in the real reservoir of the fracture type. Fracture porosity of such models calculated by the method of material balance equation was 13.5%. The porosity-type (granular) model consisted of a tube filled with quartz sand of different size fractions. This model was used to study the influence of dissolved gas on the yield of high viscosity oil from different types of reservoirs, including the macro- and microporosity types. Some experiments were run with the pressure of the bed reduced in order to determine the effect of such pressure decreases on the gadoil ratio and on the development of the dissolved gas drive in the system. The crude oil in the system was represented by a sample prepared through recombining of oil and gas. For this purpose, the degassed crude oil taken from Zybza field was combined with the gas taken from the gas cap of the petroliferous horizon IV of the AnastasievskTroitsk oil field. The properties of this gas were similar to those of the casinghead gas from the Zybza field. The sample of this "recombined crude'' had the following characteristics: 68 - gas saturation pressure, kg/cm2 - gas factor, &ton 20.8 - volume coefficient 1.05 6 x 10-5 - compressibilitycoefficient - density under reservoir conditions, g/cm3 0.943 - density after gas separation, g/cm3 0.969 All experiments were conducted at a temperature of 3WC, corresponding to the temperature in the oil-bearing formation at Zybza field. The reservoir model was laid in a horizontal position in order to exclude the influence of gravity on the oil drainage mechanism. Employed in the first series of experiments was the porosity-type (granular) model having absolute permeability (k) = 5.2 Darcies. The effect of the rate of pressure reduction on ultimate recovery was studied. The initial formation pressure used in these experiments was 100 kg/cm*. In the course of each experiment, the pressure at the exit point from the reservoir model was being reduced at a constant rate. The data in Table 5 established two facts: (1) The ultimate oil yield from a granular reservoir producing by a dissolved gas drive is about 35%. 18

Petroleum Production Employing Heat Carriers (2) The rate of pressure reduction has very little effect on the ultimate yield Table 5. Yield of crude oil at different rates of pressure reduction lumber

pressure reduction,

recover)

Experiment number

r minu crude oil 0.25 0.5 1 .o 2.0 5.0 10.0 20.0

Rate of pressure reduction,

oil recovery, %

kerosenc 0.25 0.5 1 .o 2.0 5.0 10.0 20.0

35.1 34.4 36.1 35.5 34.7 34.8 35.0

37.0 37.0 36.7 37.2 36.6 36.7 36.5

To determine the effect of the properties of liquids on oil recovery. tests were carried out using low viscosity products. In this case a gassed kerosene served as the liquid. Its gas content was the same as the gas content of the crude oil. According to the results, only 37% of the kerosene by volume has been displaced from the reservoir model although the kerosene viscosity under the conditions of the experiment was 100 times smaller than the viscosity of the crude oil. The rate of pressure reduction had no effect on oil recovery from the bed. Subsequently, studies were made to determine the effect of permeability of the porous medium on oil recovery. In Table 6 and Fig. 6 the results of experiments are given for permeability range of 0.26-294 Darcies. Table 6. Changes in ultirnate oil recovery depending on reservoir permeability

Type of reservoir Fracture type model Porosity type (granular) model

Permeability, in Darcies 506 294 100 58 13 5.2 2.2 0.9 0.58 0.26

19

Crude oil recovery, %

75.6 59.5 45.6 42.7 36.2 34.6 32.1 31.6 31.3 29.7


Darcies

Fig. 6. Dependence of oil recovery on permeability of reservoir producing by dissolved gas drive. Once it was determined that the rate of pressure reduction had no effect on ultimate oil recovery from the formation, maximum possible rates of pressure reduction (amounting to 20 kg/cm*per minute) were used in all subsequent tests employing reservoir models. The experimental data obtained for fracture-type (mamporosity) reservoir indicate a rather high ultimate oil recovery of 75.6%. These results agree closely with the actual figures for recovery factors obtained during the early stage of production from the Zybza field. Thus, it can be concluded that nearly 75% or 7,000,000 out of 9,600,000 tons of oil produced has been recovered from the reservoirs of macroporosity type. Of course, the bulk of the reserves was concentrated in the reservoirs of microporosity type. Therefore, the ultimate oil recovery of the field as a whole still remained small in spite of high yields from the less important reservoirs of macroporosity type. The experiments showed strong effect of reservoir permeability on oil recovery. For example, the model of the petroliferous bed of microporosity type but with permeability of 294 Darcies gave an oil recovery factor of 60%, whereas the same porosity-type reservoir but with permeability of 5.2 Dmies yielded only 30% of oil in place. Gas content in crude oil also exerts strong influence on the recovery factor of high viscosity oil, especially in the case of low permeability reservoirs of microporosity type. In reservoirs with anomalously high permeability, gas imparts great mobility to high viscosity oil. As such, the gas factor is of particular importance in exploitationof reservoirs containing high viscosity crude oils of non-Newtonian type. In such crudes the gas is adsorbed to the surfaces of tars; it can't separate from them and escape from the elastic system. Expanding gradually, gas provides the energy that drives the crude oil through the formation. The efficiency factor of this energy source approaches a value of 1. This expansion of the dissolved gas formed the principal drive in all the experiments, regardless of permeabilitiesof the reservoir models employed. In a series of experiments, both the fracture- and the porosity-models were used; the permeabilities of the models used were 0.26 Darcies and 5.2 Darcies. Two kinds of samples of liquids were used: (a) samples of crude oil with different gas content, (b) samples of degassed oil recombined with gas with gas factors of 1.5, 4.6, 9.1, 14.4, and 20.8 m3. The results of these experiments are given in Table 7 and Fig. 7.


Table Gas factor, m3/ton

Reservoir type

20.8

14.4

9.1

Fracture Porosity (granular)

75.6

72.3

69.4

64.8

62.0

~ = 5 . 2D

34.6 29.7

34.1 28.8

33.4 24.9

32.1 19.3

32.0 13.2

d.26 D

4.6

2.5

ll 1.0

0.8 0.6

0

6

16

10

10

Fig. 7. Dependence of oil yield on gas content during the filtration of high viscosity oil through the models under dissolved gas drive. The data show that oil recovery goes down as gas content decreases. This effect is particularly pronounced for reservoirs of low permeability. For example, in the reservoir model of granular type having absolute permeability of only 0.26 Darcies, the decrease in gas factor from 20.8 down to 2.5 m3/ton results in an oil recovery reduction of 57%. The above change demonstrates how effective the dissolved gas is in mobilizing oil within an elastic sysfem. Of course, in the case of a reservoir with such low permeability, the capillary resistance further restricts the flow of oil through the formation, thus significantlyreducing the ultimate recovery. On the other hand, the ultimate recovery from a reservoir of fracture type remains high even when the gas factor is reduced many times. For example, with the decrease in the gas ratio from 20.8 all the way to 2.5m3/ton, the oil recovery factor declined only from 75.6% to 62%. There are two reasons for this restricted decline: (1) In the reservoirs of fracture type, forces of resistance to oil flow are very small; therefore, only limited amounts of the dissolved-gas energy must be spent to overcome them. (2) Because of high viscosity of the oil, gas cannot escape from it. This gives rise to an unutilized excess energy of the gas present in the crude. In fact, some of that gas remains in the crude even after the degasification treatment of the crude in surface separators. Fig. 8 shows the dynamics of oil extraction with reduction of pressure within the reservoir model. The graph shows that within the pressure intervals from 0.1 to 1.0, the rate of increase of the total oil yield does not remain the same everywhere. Maximum displacementof oil from porous media takes place within two particular pressure intervals. 21


-.

-

Presshe intervals Value of 1.0 on the horizontal scale corresponds to infinitepressure.

Fig. 8. Dynamics of extraction of high viscosity oil with reduction in pressure.

The first of these intervals corresponds to the scale values of 0.3-0.7. This regime exists when the pressure in the formation is brought down to a point below the gas saturation pressure of the oil sample. With further pressure reduction, in the intervals of 0.7 to 0.9, the rates of oil extraction decrease somewhat. Sharp increases in gas factors is observed within this range, and the infinite gas factor reaches the value of 1. With pressure reduction within the interval 0.9-1.0, the gas factor decreases sharply from 1.0 to the initial values of 0.02-0.03. This drop in gas factor is accompanied by a significant increase in the rate of total oil yield. The above rate increases from 0.06 to 0.1 per unit of pressure drop. The production experience of such fields as Zybza and Karsk confirm the effect which abnormally high oil viscosity has on rate of gas escape. Even at atmospheric pressure, both the degassing of these crudes and the separation of casinghead gas from them occur slowly. AS a result, a mobile gas-liquid system forms characterized by strong elastic properties. The energy of gas dissolved in oil undoubtedly creates the basic force moving the oil through the petroliferous formation. As such, the dissolved gas drive plays an important role in oil recovery. Proper utilization of this drive must therefore always be considered whenever any new EOR methods are applied to reservoirs containing crude with non-Newtonian properties. Methods must be devised to saturate such crudes again with gas within the reservoir, should they be found present there already in the degassed state. In petroleum fields characterized by dense reservoir rocks, it is necessary first to create reservoir conditions resembling those existing in formations of macroporosity type. Such conditions can be brought about by use of special methods, for example, by blasting or by drilling of horizontal wells within the oil-bearing formation. 5.

INCREASING THE YIELD OF HIGH VISCOSITY O K BY USE OF D I F F E m HEAT CARRIERS

Already on earlier occasions, thermal EOR methods, including steaming, were employed on a commercial scale in the oil fields of Krasnodar Temtory. Among others, Zybza field was also subjected to these treatments. The objective, of course, was to increase the recovery of oil. In the 22


beginning. however. these methods were applied without any prior laboratory study to determine the ability of heat carriers to displace crude oil present in different porous media. Although a number of studies related to thermal EOR methods have been already conducted by different investigators, the mechanism by which high viscosity oil can be displaced from the reservoir and the methods of acting upon such reservoirs received hitherto inadequate attention. The laboratory studies described here were therefore intended to answer important theoretical and practical questions regarding the application of thermal methods to petroleum production. These experiments were carried out in special laboratory models simulating the oil reservoir itself. Quartz sand of large size fraction with porosity of 37.1% and permeability of 2.1 Darcies served hs the medium. Degassed, high viscosity crude taken from well 399 of the Zybza field was used in the experiments. This oil sample had the following properties: specific gravity, glcm3 ................... .0.969 acidity, milligrams KOW100g. ............... 682 content of pitch tars (pitch), %. ............... 18.86 solidification point, OC.. ................... 20 viscosity in centipoise at OC: 250 C 2000 50 290.35 60 152.6 70 96.8 80 53.6 90 33.4 start of boiling, OC 268 distillation fraction (in %) up to temperature, O

2800C 290 300 310 320 330 340 350

C

2.5% 5 7 9 10 12 15 22.5

Formation water recovered from the Zybza field was used as the oil-displacingliquid. Two kinds of experiments were carried out: (a) with simulation of the initial water saturation; (b) without simulation. In experiments ofthefirsf kind, at the start, the formation was saturated with water. The latter was then displaced with degassed oil at ambient temperature. Inasmuch as oil viscosity was high at that temperature, the permeability of the formation model was significant. The initial water saturation was fairly low, staying within the range of 9.5-11.2%.

23


Experiments were carried out at temperatures of 30, 75. 100, 125, 150 and 2000C, at pressures of 50 kg/cm2. With each increase in the temperature of the experiment, thermal expansion was taking place causing some displacement of oil from the formation model. These volumes were measured during the process of temperature stabilization in the bed. The volumetric rate of displacement equal to 0.01 11 cm3/sec was assumed in accordance with the theory of approximate modeling. Each experiment was concluded after injection of four pore-volumes of water through the porous medium. During the entire time in which water was being displaced from the bed, the expelled liquid was being collected on exit from the bed. This procedure made it possible to determine the following three displacementcoefficients in succession: the water-less, the current, and the terminal. The results are given in Table 8. Table 8. Results of experiments on displacement of Zybza field oil by water Indicators

Experiment number

3 Temperam, OC Water saturation of bed, % Oil saturation of bed, 8 88.8 88.8 Oil displaced due to thermal expansion, % Displacement coefficient during waterless 0.18 0.359 period, * Displacement coefficientat the end of 0.432 0.609 experiment,*

100

11.2 88.8 3.3 0.503

7.1

0.745

*On the original table, the authors show:

7

018

0

0,4

0.8

l,Z

I,6

Qw,

2,O

214

Z,8

5,2

3,6

4,O

in pore volumes

Fig. 9. Dependence of current displacement coefficient (q) on volume of water (Qw) forced through the bed at different temperatures.


Table 8 and Fig. 9 show that with the increase in formation temperature, the indicators of displacement process improve. For example, the terminal displacement coefficient of 43.2%, at temperature of 30OC increases to 83.6%, at temperature of 2OOOC. Maximum increase. in the terminal displacement coefficient obviously takes place at temperature increases from 30 to 1200C. In this case, it is directly dependent on temperature and reaches a value of 78% at 120OC. Subsequently, in the temperature interval of 120-1500C, this displacement coefficient increases only to about 80%, and in the 150-2WC interval, only to 83% (see Fig. 10). We can also look at it in a different way. As Fig. 10 indicates, at normal conditions, with a temperature of 300C, the displacement coefficient attains the value of 43%. In order to raise it to 788, that is. 35 percentage points above the initial level of 43%, a temperature jump of lO00C is required. To raise this displacementcoefficient from that level (78%) to a new level of 83%. that is, only by an additional 5 percentage points, another temperature jump of lOOOC (from 130 to 2300C) would be required. These calculations mean that energy input in the second zone along the curve drawn on Fig. 10 is 6-7 times higher than in the first. This conclusion is of great importance as regards the application of any thermal treatment to the petroliferousformation.

1:

c

Fig. 10. Change in oil displacement coefficient (q)with reservoir temperature. The experiments of the second kind, that is, without simulation of the initial water saturation, were carried out at temperature of 2WC. Results recorded in Table 8 for experiment No. 7 show that, in this case, the displacement coefficient amounted to 78.3%. This value was 5.3 percentage points lower than results obtained in experiment No. 6, that is, with the simulation of water saturation. The displacement of liquids from the bed is more complete in instances when initial water saturation is simulated. This phenomenon is explained by the character of distribution of oil and water in the bed and by the surface properties of the porous medium. Thus we can conclude that, in using hot water, maximum displacement of high viscosity oil from the porous medium takes place at the temperature of 1200C. Moreover, the temperature values determined in the above described simulation experiments agree fairly well with the temperatures employed in oil field production practice during hot water stimulation treatments [4]. Temperature studies were also conducted during the process of oil well steaming in the Zybza field. In order to obtain maximum effectiveness of cyclic steaming, it was necessary to raise the temperature of the petroliferous formation in the well-bottom zone to 120-13OOC. The attainment of best results in the earlier identified range from 30 to 1200C of formation temperature was found to be a uniform rule. This behavior can be explained by sharp changes that occur in the propemes of petroleum within the temperature range of 30-12OOC. For example, the decrease in viscosity and changes in elastic propemes of oil both take place at that time.

25


Fig. 11.

(Left) Dependence of viscosity of degassed oil (po) on temperature.

Fig. 12.

(Right) Dependence of displacement coefficient (q)on oil viscosity &).

1

0 0 0 0

800400

Thus, as Fig. 11 indicates, the vikcosity of degassed oil decreases most within the temperature range of 30-12OOC; above that range, it decreases only slightly. Fig.12 shows that coefficients of oil displacement drop off sharply as oil viscosity increases from 22 to 150 centipoise; above that viscosity range they tend to stabilize. Consequently, in application of thermal EOR methods, oil viscosity exerts great influence on the recckery factor. Moreover, with' increase in formation temperature, oil viscosity decreases in much greater degree than the viscosity of formation water. Other factors affecting the mechanism of oil extraction from the formation were also studied. Thermal expansion of oil also exerts an influence on the process of oil displacement from a porous medium. The volume of displaced oil essentially depends on the oil's properties and on the thermodynamic conditions of the formation. The changes in the displacement coefficients attributed to thermal expansion of oil were given in Table 8. At temperatures of 125, 150, and 2000C, the percentage share of oil yield due to its v o l u m e ~ cexpansion within the reservoir rocks is 5.4.

The displacement of liquids is strongly affected by surface properties of the system: crude oil-water-rocks. With increases in temperature, surface properties of both the formation rocks and the formation liquids change. When water is injected into the formation, some of the surface-active substances of the crude dissolve in the water. This dissolution brings about a reduction in surface tension at the phase boundary. Selective wetting of the surfaces of capillary pores with water is also improved. The surface-active molecules of oil form a layer that is adsorbed on the surfaces of pore canals. When the temperature is increased, the thickness of this layer is reduced, which, in turn, leads to an increase in permeability of the formation. 26

Petroleum Production Employing Heat Carriers The oil from Zybza field contains 3.78% of organic acids and other compounds that can be hydrolized with alkalies. On that basis, it belongs to high octane petroleums. Tests show the following decrease in surface tension of Zybza crude measured at the boundary with formation water, depending on temperature: Surface tension, erg/cm2 temperature, OC This sharp reduction in surface tension of petroleum with increase in temperature plays an important role in the processes that occur within the formation. Experiments were carried out to determine the effect of capillary forces on the mechanics of oil displacement from reservoir by water injection. Samples of sand from petroliferous formation of Zybza field and the reservoir water from the same oil field were employed. Core samples had a diameter of 36 mm, height of 20 mm, porosity of 30% by volume, and permeability of 2.1 Darcies. Initial water saturation of the formation was not simulated in the samples used in the experiments. Sampleswere first placed in a thermostaticallycontrolled chamber filled with degassed crude. The temperature in the chamber was stabilized at a fmed degree and the press- was increased to 50 kg/cm2. The sample was then left inside the chamber for 24 hours. Next, the sample now saturated with the degassed crude was kept for a period of two weeks in a tightly sealed container filled with the same crude oil. The experiments were carried on simultaneously on two samples. Subsequently, for a period of 24 hours the samples were saturated with formation water. It was injected for that purpose into the container in such a quantity that the samples inside became fully immersed in water and no longer in the crude. In this process, the soaking of capillary pores with formation water and a simultaneous displacement of the crude from these pores was taking place. Finally, the samples were removed from the containei; the determinations were then made of both the volume of water and of oil yield produced thanks to these capillary processes.

A number of experiments were carried out to determine the effectiveness of using different kinds of heat carriers to displace the high viscosity crude of the Zybza field. Pertinent data regarding these experiments are as follows: granular-type of reservoir model was used, crude oil and hot formation water, both taken from Zybza field. served as liquids; to obtain steam, distilled water was fed into a small steam generator installed inside a thermally controlled jacket together with the formation model; formation water, steam, and air heated to the temperature of the formation (equal to 2000C in this experiment) were used to displace the crude; the soaking time was 24 hours; in experiments using hot formation water as the displacing liquid, the formation pressure was kept at 50 kg/cm2, in experiments using steam and air, 10 kg/cm*, that is, below the vapor pressure of the water at 2000C; volume of the displacing agent run through the bed equalled 4 x the total pore space; the conditions of bound water present in the capillaries of the reservoir rocks were not reproduced in the model; the rate of oil displacement was kept constant at 0.0111 cm3/sec with the aid of a (hydraulic*) press system; liquids produced during the experimentswere being removed continuously and their volumes measured.

* hydraulic - translator's assumption 27


By placing the small steam generator together with the bed model within a thermally controlled sleeve, it was possible to inject the heated steam directly from the generator into the model. The reservoir temperature and pressure and the rates at which the liquids were being charged into the steam generator. were all kept constant by use of automatic controls. For that purpose, the UIPK-IV, a device designed for well core studies, was especially modified. Gravity forces had some effect on the quantity of liquids, inasmuch as the liquids were being extracted by a system of (hydraulic) presses. Nonetheless, the data obtained made it possible to evaluate the processes that were occurring within the porous medium. Inasmuch as the liquids produced were continuously removed and measured, it was possible to determine both the current and the terminal coefficientsof oil displacementup to the moment of breakthrough of the injected agent. Table 9. Experimentalresults of capillary soaking. Experiment number 1 2 3

I

I

Temperature, Oil recovery,

oc

OC

22 55 100

4.85 55.3

61.85

4 5 6

125 150 200

%

64.6 68.6 75.45

These studies show that the process of capillary soaking takes place both at low and at high temperatures; however. it does accelerate noticeably with increases in temperature (see Table 9). At lOOOC, 62% of petroleum is displaced, at 1 5WC, about 70%; and at 2000C, about 75%. Changes in the surface properties and wettability of the system: petroleum-water-rocksexplain the increase that occurs in the oil yield with temperature during the process of water soaking of the capillaries. Relatively high oil yields were obtained with prolonged soaking even at low temperatures. However, in all of these cases, samples of very high permeability of 2.1 Darcies were used. Under real conditions, in the oil-bearing formations of low permeability and at reservoir temperatures, the capillary processes are considerably less intensive. This fact was c o n f i i e d by numerous field experiments carried out at a number of oil fields including Zybza. Both prolonged soaking and periodic injection of cold water into the oil-bearingformation gave negative results. The curves shown on Fig. 13 were corrected as follows: to the volume of oil displaced by the injected agent was also added the volume of oil displaced due to thermal expansion. The curves show that best oil recovery is obtained with steam, the poorest with air. Under conditions of the experiment, the ultimate oil recovery factors were as follows: 86.83% for steam, 78.31% for hot water, and 46.24% for air. Even higher recovery factors are known for steam. For example, A. Abbasov obtained oil recovery of 94% using steam at a temperature of 200% However, in his experiments, Abbasov used a porous medium of much higher permeability (12-13Darcies); also the oil used by him at STP conditions, was of a somewhat lighter (density of 0.926g/cm3) and less viscous (230centipoise).


Q, pore volume of bed

Fig. 13. Dependence of the displacement coefficient (q) on the volume of displacing agent run through the bed model. When relatively light crudes in the formation are treated with steam, the low boiling-point fractions present in such crudes turn to gas. This fact, as well as the mechanical displacement of the crude by steam, that is by a gaseous phase, explain for the most part why higher recovery factors are obtained for such crudes than for those that are much heavier. In the case of these very heavy petroleums, the gasification of their low boiling-point fractions either does not take place at all or is nearly absent. Consequently,it has no measurable effect on oil yield. Thus, in fractional distillation of heavy petroleum from Zybza field, the crude begins to boil at 268T. This temperature is significantly higher than that employed in the above described experiments. Even during the distillation at 2800C, only 2.5% of the Zybza heavy crude boils off. Consequently, for these heavy petroleums and at thermal treatments employing temperatures of 2OOOC or even somewhat higher, the gasification of the low boiling-point fraction does not influence very much either the displacement mechanism itself or the oil recovery factor. At Zybza field during the actual steam injection treatment, the optimal temperature in the heated zone of the oil-bearing formation reaches 150OC and occasionally 2000C. Since,at these temperature levels very little gasificationof the low boiling-point fraction does take place, the effect of such gasification on oil recovery can be ignored. Steaming of the formation gives higher oil recovery than hot water injection. The reason for this difference is simple. Steam more effectivelyreduces the capilIary forces and it is better able to wet the surfaces of the porous medium. As a result, steam penetrates even into the finest pores in the formation, displacing oil. In other words, with steam treatment. a significantly greater number of pore openings actually participate in the filtration process than with water injection. Moreover, the front of oil displacement that forms in the formation during steaming is more stabilized. This fact is confirmed by high values of oil recovery coefficients even prior to the steam breakthrough. When cold water is used, the displacement mechanism basically depends on the surface molecular and capillary processes occuning in the bed. In their turn, these processes are controlled by the properties of the crude, the formation water, and the reservoir rocks. For one thing, the dimension of pore openings is not uniform. Furthermore, there is a great difference between the viscosity of the crude and of the water. Because of these two factors, water can move through the 29

Thermal Methods of Petroleum Production formation ahead of the petroleum, thus leaving behind the water-oil contact zones with different degrees of water saturation. Use of hot water is accompanied by high rates of capillary soaking. Therefore, hot water tends to move ahead of the main displacement front of the crude where it gives rise to a zone of two-phase mixture. These processes reduce the phase permeability for crude oil in the area of water-oil contact, and at the same time, they create additional capillary forces that resist the movement of the main displacement front. The effectiveness of oil displacement is somewhat reduced by comparison with steam. 5d. EE E E C T I Y E N E S S - Q E - C X CL I.C - S T E A M I N G - Q N - E A T E B :I N Y A P E P EQBMATIQNS Beginning in 1965, studies were undertaken at Zybza field on cyclic steaming of near bottomhole zones of old wells. In general, this steam treatment proved highly effective. However, in some of the wells, especially those strongly invaded by reservoir water, the results were disappointing. Laboratory experiments were therefore carried out, principally to determine the influence of water encroachment and of the temperature of steam-heated zones on this thermal treatment itself. The earlier described formation model of granular type was used in these experiments. Reservoir conditions were characterized by very low formation pressure and by absence of flow of liquids into the well. The experiments were carried out as follows: At first the reservoir model-was saturated with degassed crude oil. Then the oil was displaced from the bed to a fixed degree by formation water. The degree of water invasion of the model was varied by about 10-12% from one experiment to the next, ranging from 14.5 to 75.8% for the entire test series. Once the assigned degree of water encroachment was attained for a particular experiment, the temperature of the formation was stabilized at the desired level by thermostatic controls. The tests were carried out at temperatures of lOoOC, 125OC, 15oOC, and 200OC. In each case, prior to the temperature stabilization, any hydrodynamic connection and intake into the formation from outside was cut off. The reservoir outlet could be opened as required. The initial formation pressure was that resulting from the heating of the bed model. The value of 50 kg/cm* was taken as the initial formation pressure. As the temperatureof the formation was being stabilized at a fixed level, a certain volume of liquids was being displaced. It was measured upon leaving the model. Once the temperature and the pressure were stabilized at the assigned levels, the liquids were removed from the formation at a fixed rate and without any external action on the bed. For that purpose, as in previous experiments, a system of (hydraulic) presses was used. The volumetric rate amounted to 0.01 11 cm3/sec, and the filtration rate was 0.000567 cdsec. As the liquid was being removed from the model, the pressure in the bed decreased from the formation pressure down to atmospheric and even lower. With pressure in the bed model decreasing below the vapor pressure of water, depending on the conditions of the experiment, at first a steam-water mixture formed in the formation. If both the pressure in the bed and the degree of its water invasion are further reduced, dry steam will form. This steam-water mixture, in the first case, and the dry steam, in the second, act as the actual agents of displacement. The experiment is terminated when the liquid ceases to flow from the bed. First to be determined in these tests was the dependence of oil yield on (a) the degree of formation-waterencroachment in the reservoir, and (b) the amount of steam injected into the model 30

Petroleum Production Employing Heat Carriers at a given fixed temperature. The volume of injected steam was calculated in terms of its water equivalent. The exact degree (in % of pore space) to which the bed model had to be invaded with formation water and the temperature at which the steam had to be injected in order to give the highest oil yield were both determined empirically through experimentation. By increasing the formation temperature to loooC and with the degree of water invasion of the bed remaining within a range of 1545% of pore volume, the oil recovery factor does not exceed 19%. However, with subsequent increase of the temperature to 125OC, 1500C, and 2WC, the oil yield sharply increases. Economically justified results are fist obtained beginning at the temperature of 125OC with the degree of formation-water invasion of the reservoir of 35%. In this case, the recovery of the crude from the bed after the first cycle of treatment exceeds 50-5556 (Fig. 14).

Water saturation, %

Fig. 14.

Dependence of oil yield on the degree of water invasion of the reservoir during cyclic steaming.

With the temperatures kept constant (at 125OC. 1500C. or 2000C). the oil yield at first increases with the degree of water saturation. Maximum oil recovery, amounting to 53-552, was attained when the degree of water invasion of the model equaled about 35%. Within these limits of bed saturation by formation water, enough heat is brought in with the steam to convert part of the formation water also to steam. The resultant pressure increase within the bed model, in its turn, favored oil displacement from the porous reservoir. Further increase in the percentage of water saturation above the value of 35% causes a reduction in oil recovery. The indicated temperatures of 125OC, 1 5 W ,and 2oooC are simply not high enough to insure adequate heating of the entire bed. Too many calories are lost on heating of the formation water. However, when the temperature of the bed reaches 2000C, the aggregate state of formation water undergoes a sharp change. Water converts to steam or to steam-water mixture. The latter supplies the reservoir with enough thermal energy to lower the viscosity of the oil and to stimulate the process of capillary soaking. In this case, that is at temperatures of 2WC, even at very high degree of water saturation, the oil recovery still remains quite high (Fig. 14). Thus, experiments proved that even at water-saturation levels as high as 75%, cyclic steaming can still produce maximum oil yields from the bed model. In this case, however, the temperature of the bed must be raised substantially. Highest oil recoveries were observed at the temperature of 2WC. The curves on Figure 15 show that at water saturation levels above 35%. the oil yield increases with the temperature of the formation. But with water saturation of up to 35%, the oil yield stays practically the same (53-55%) regardless of temperature.

31


Fig. 15. Dependence of oil yield on temperatureduring reservoir stimulation by cyclic steaming. The above studies showed that steaming of reservoir or of the near bottomhole zones of the wells has greatest effectiveness when the reservoir saturation by formation water does not exceed 40-50%. At these levels of water invasion, petroleum can be very effectively displaced even at relatively low temperatures of 125-15OOC. At higher degrees of water saturation of the formation, the bottomhole zones must be heated to higher temperatures in order to maintain the same oil yield. These higher temperatures are necessary in order to reduce the viscosity of oil in the formation and to increase its phase mobility. In conducting stimulation treatment of near bottomhole zone by cyclic steaming, a number of parameters must be determined: (a) the oil recovery factor obtained from that zone after a single cycle treatment; (b) the ultimate oil recovery factor for the treated zone; (c) optimal number of effective steam cycles for the particular oil well. For this purpose special experiments were carried out on application of cyclic stimulation to the reservoir model. The experiments consisted of the following steps: (a) Constructionof reservoir model invaded in part (1516%)by formation water, with the remainder of the pore space saturated with crude oil. (b) Heating of the model up to assigned temperature at formation pressure of 50 kg/cm2. (c) Once the formation temperature and pressure were stabilized at assigned values, the formation liquids were allowed to flow out via an outlet located at the end of the model at the opposite side from the steam injection inlet. (d) Once the flow (production) of liquids through the outlet ceased, the steam was again injected into the model, thus reconstructingconditions analogous to those existing in the near bottomhole zone during cyclic thermal stimulation of wells in the oil field; this steam re-injection continued until the original formation pressure of 50 kg/cmz was reestablished. (e) Once the assigned temperature and pressure were again stabilized, the outlet was opened to allow flow (production)of liquids. ( f ) The above cycles were repeated until no more oil flowed from the model. Of course, during cyclic steaming under oil field conditions, the temperature of the oilbearing zone being mated is not uniform. It is highest right next to the well through which the steam is being injected, and lowest away from the well in the peripheral zone still affected by this thermal treatment. Therefore, in order to determine the effectiveness of cyclic steaming on oil displacement in these different zones of the formation, and to show the influence of temperature on oil recovery, these experiments were carried out at temperatures of 125OC. 15OOC and 2000C. During the experiment, both current and final oil recoveries were determined. The change in the current oil recovery from the reservoir model recorded with each subsequent cycle is shown on Fig. 16. 32

Petroleum Production Employing Heat Carriers 80

60 40

20

0

I

II

111

IV

Cycle number

v

VI

Fig. 16. Dependence-ofoil recovery on the number of cycles during steam treatment. The above-described laboratory studies of reservoir stimulation by cyclic steaming conducted at different temperatures of the bed model showed a strong dependence of oil recovery on the temperature of the steam-treated zone. Thus, at the formation temperature of 125OC, after seven cycles of steaming the oil recovery was 60.3% of oil in place; at 150OC, 68.5%; and at 2000C, 77.0% (see Table 10). Table 10. Data on oil recovery from the reservoir for each cycle of steam treatment.

I

matment IT

VI VII Oil recovery during each cycle expressed as % of the initial oil saturation of the formation

33

27.0

I

3.5

I

I 15.6

21 3

5.6

9.8

3.1

4.6 3.8

25

1

1.1 1.o


As regards the effectiveness of repeating the steaming cycles, we can conclude that, at relatively high temperaturesof 125-2OOOC. the bulk of the oil displaced by this treatment is already produced during the first two or three cycles. Of the total volume of oil displaced, 90-96% is displaced during the first three cycles of steam injection. These results mean that, barring inflow of additional petroleum from outside of the steam-treated zone, all of the recoverable oil initially in place within that zone should be produced after two or three cycles. From one cycle to the next, the volume of displaced oil sharply decreases (Table 10). At the formation temperature of 20OOC. after repeating the treatment four times, the amount of oil displaced during the fifth cycle was only 3.1% of the residual oil saturation. However, these results are true only for conditions close to ideal. In oil field practice, during steam stimulation of the near bottomhole zones, 8-10 and sometimes even more cycles are repeated. Enough oil is produced during each one of these cycles to make each repetition fairly effective. Two facts can explain these additional oil yields: (a) During the f i s t few cycles the injected steam can penetrate only to a very limited distance away from the well. (b) During the later cycles, additional crude oil flows from more distant zones of the formation into the zone nearest to the well from which oil initially in place has been already displaced during the earlier cycles. The distribution of the residual oil along the bed in the zone of steam penetration must be known in order to effectivelycarry out cyclic steam treatment of the near bottomhole zone. For this purpose; after the completion of the above experiments, and while the bed model was being dismantled, samples of porous medium were removed from the model and placed in a special instrument, the LP-4,used for extraction of liquids from porous media. The oil distribution data obtained during the extraction are shown in Table 11 and on Figure 17. Table 11. Distribution of residual oil saturation along the length of the reservoir model

32.1 33.0 42.2 46.2 54.0 59.1 37.7

90 110 130 150 170 190 Averaee value of oil saturation. %

34

.

20.6 23.4 29.6 33.0 42.1 48.3 28.48

18.4 18.2 16.9 22.0 28.1 34.3 21.25


Length of bed model, cm

Fig. 17. Distribution of residual oil saturation along the length of bed model. We can see that the residual oil is not distributed uniformly along the length of the bed. First let us look at the zone that has been uniformly flushed out, located nearest to the inlet for steam injection and outlet for liquids produced. The length of this zone changes, depending on the temperatures at which cyclic steam treatments were carried out earlier. This zone shows the minimal values of residual oil saturation possible for the particular conditions of the experiment. With an increase in temperature, the length of the zone flushed out by the injected steam increases. At the temperature of 125OC, it is less than one-half of the total length of the reservoir model, whereas at 2000C, it is three-founhs of that length. Within the’treated zone, the greater the’distance from the axial line of steam injection, the higher the oil saturation of the formation. During injection of water into the forrgtion model, the oil saturation becomes redistributed in this manner along the bed. Namely, some of the oil with which the bed was initially saturated is pushed back by the injected water from the inlet area of the model towards its far end. Moreov.er. at the peripheries of the zone of steam treatment, the energy available within the bed is insufficient to drive out the oil from the bed during the process of withdrawal (production) of the liquids. For these two reasons, highest residual oil saturations are found in these peripheral areas of the steamtreated zones. Non-uniform displacement of oil along the bed thus represents an additional factor which tends to reduce oil yield during the steam stimulation conducted at low temperatures. In one of the experiments the direction of oil displacement was therefore reversed in order to increase oil recovery from the zone of steaming. It was done at the end of the sixth cycle of steam treatment carried out at a temperature of 125OC. By this method, additional oil yield of 12.3% was produced. This oil, which came from the far end of the bed model. away from the line of steam injection, could not be produced in earlier experiments using ordinary direction of steam injection. The results of this experiment were confmed quite well by oil field practice. Several practical conclusions can be drawn from the experimental studies described in this section: a. The indicators of oil displacement substantiallyimprove with increases in the temperature within the formation. In case of high-viscosity oil saturating porous media in high permeability reservoirs, 1200C represents the optimal temperature for hot water treatment. Up to 80% of oil-inplace can be recovered under these conditions. 35

Thermal Methods of Petroleum Production b. Factors with great influence on oil recovery are: reduction of viscosity and density of the crude oil; thermal expansion of oil;surface and wetting properties of the liquids and of the porous media. c. Steam, hot water, and air, in this order, are the most effective heat carriers for displacing crude oil from the reservoir. The ultimate recoveries obtained by using these agents were 86.83% for steam, 78.31% for hot water, and 46.24% for air. d. Cyclic steam stimulation of the near bottomhole zone of the well can be carried out on peaoleurn reservoirs having low formation pressure and a high degree of encroachment by formation water. In this case, the effectiveness of the process will depend on the degree of water saturation and on the formation temperature, that is, on the amount of heat introduced into the formation. e. With increases in the degree of invasion of the reservoir by formation water, the effectivenessof cyclic steaming of the near-bottomhole zone of the well decreases. f. The effectiveness of steam injection increases with the temperature of the treated zone. In case. of reservoirs invaded by formation water, 120-15OOC is considered to be the minimum temperam to which the formation should be heated. At the temperature of 100OC, the effectiveness of the process is already sharply reduced. g. To increase the effectiveness of the process, it is necessary to conduct the withdrawal of the liquids from the foxmation at pressures below the vapor pressure of water. In this case, the displacing agent that forces the oil out of the bed is in the gaseous state. h. In carrying out cyclic steaming on the near-bottomhole zone of wells that have low formation pressures, the bulk of the oil volume can be displaced in the course of the f i s t 2-3 cycles. The above is m e of treatments in which discrete blocks of reservoir formation are steamed separately and only in cases in which no additional crude oil flows into the block from the adjacent sections of the oil-bearing formation. 6.

USE OF THERMAL 1 Q€L

Zybza is a typical deposit of high viscosity petroleum and as such is a good example of many other oil fields of this same type. The production of the Zybza viscous-elastic crude began in 1947, yielding since that time a total of 9,600,OOO tons. The field was developed on a triangular grid using a l00m well spacing. In the central part of the field, a well spacing of 50m was used. Between 1947 and 1951, about 300 wells were drilled, although at any one time not more than 230 wells were actually pumping. Most of the remaining wells became completely water flooded and were shut down during the fist months of operation. The production from Zybza deposit of Miocene crude oil can be divided into four periods: [period from January 1947 to September 1950: It was characterized by rapid increase in the rates of production due to the completion of a p a t number of wells. The rate of extraction of crude rose from 50 to 4920 tondday with the number of active producing wells reaching 288. The cumulative oil yield during that period amounted to 2,814,000 tons. The water cut in the petroleum produced did not exceed 8.8%. It augmented very gradually from year to year with a maximum rate of increase for any particular year amounting to only 3.5%. Restricting the pumping rates proved to be an effective method both of reducing the water cut and of prolonging the producing life of the Zybza wells. Ilperiod from September 1950 to October 1951: Crude oil production attained relative stability, declining only slightly towards the end of the period. Drilling of development wells continued 36

Petroleum Production Employing Heat Carriers mainly in the central part of the field; the well-spacing grid was reduced. Total number of the producing wells fluctuated between 212 and 220. Cumulative amount of liquids extracted was 1.875,OOO tons. of which 1,704,000 tons was oil. The water cut was increasing gradually towards the end of the perid, however, it never exceeded 12%. Illperiod from October 1951 to December 1957: The average production of petroleum dropped sharply from 4.200 tons/day, at the beginning of the period, to 200 tons/day, at the end of the period. Formation pressure declined futher, reaching 7.5 kglcm2. Intensive encroachment of the reservoir by formation water took place with water cut rising to 76%. The number of pumping wells decreased from 228 to 132. Two measures were taken in an attempt to arrest the drop in formation pressure of the Zybza field and to make it more gradual: (a) pumping rates of the wells with good production were restricted according to the apparent capacity of each well, (b) additional development wells were drilled in the central part of the field where the most productive sections of the Sarmatsk series of the Miocene strata were located within the Zybza field. Inasmuch as the above measures to stabilize reservoir pressure failed, the injection of air was initiated in August 1951; it was then followed by gas injection. Both of these injection treatments were targeted at the highest structural part of the oil field. With gas injection. a quick breaktbugh of the gas took place from the injection wells to the producing wells. However, the rapid drop in formation pressure continued unabated, while current yield of cFde oil from the field did not increase. Consequently, beginning in September 1952 the volume of injected gas was first reduced and then stopped altogether. Starting in 1952, water flooding of the reservoir was resorted to using eight injection wells situated at the edges of the field, that is, along its contour of closure. At first the volume of water injected every 24 hours was at the rate of 3,100 m3, then the rate was reduced to 800 m3. However, due to the presence of reservoir rocks of microporosity type in different parts of the Zybza field, the aforesaid water flooding failed to produce frontal displacement of petroleum from the injection wells to the oil pumping wells. To study further the effect of reservoir stimulation by water flooding, this treatment was interrupted a number of times and for different durations, ranging from one to six months. During these time intervals most of the pumping wells stopped producing water and a number of wells, which pumped only water before, now started to produce some oil. Lower rates of decline in the reservoir pressure were recorded during the time period corresponding to water injection. However, even this treatment did not bring about the equalization of formation pressure and intensification of petroleum production at the Zybza field. For the sixyear period from 1951 to 1957, the cumulative yield of liquids was 7.151,OOO tons, including in this amount, 3,800,000 tons of oil . At the end of the III period, that is, in December 1957, the water cut reached 76% of the liquids produced. Nperiod from January 1958 to August 1965: During this 7-year period the oil yield from the field continued to diminish, dropping from 200 to 86 tonsfday. The above rate of decrease, however, was sharply lower than the decrease recorded during the 111period. The amount of water injected into the Zybza field was gradually reduced from 800 m3/day at the beginning of 1958, to 160 m3/day at the end of 1960. Thereafter, the water injection was stopped altogether. With the petroleum yield steadily declining, the water cut continued to rise, attaining 86-88% at the end of the period. The cumulative volume of water injected into the Zybza field was 2,500,000 m3. Because of continued water flooding of the producing wells, the number of wells actively pumping was reduced to 98. During this last stage of oil production from the Zybza field, extremely wide differences have been recorded in the average daily yield from one well to the next. This phenomenon was due to the greatly uneven drainage of crude oil that was still taking place from the 31

Thermal Methods of Petroleum Production different producing horizons. Thus, towards the end of the IV period, some wells, e.g.. well Nos. 30 and 56, produced at the rate of only 60 kdday, while others, e.g.. well Nos. 373, produced 7-9 tonslday. Fig. 3 shows the change in the yield of total liquids and of crude oil during the exploitation of the Zybza field. As the graph shows, a rapid increase in oil production took place within a short period of time 1.5-2 years. Later the decline in the oil yield occurred at a similarly fast rate, notwithstanding the continually increasing number of additional well completions in the Zybza field. This flareup in oil yield was due to the drainage of oil field sectors with reservoir rocks of macroporosity type. As it was determined both in laboratory studies and in field practice, the reservoirs of this type have high oil recovery factors of up to 60-75%. Thus, during the entire period of exploitation of the field that preceded the application of thermal treatment, practically all of the crude oil was produced due to the dissolved gas drive. During the same time, the sectors of the Zybza field occupied by reservoir rocks of microporosity type remained virtually unexploited. with their recovery factors not exceeding 5% of oil-in-place.

STEAM-INIIECIIQN Different customary methods of primary well stimulation and of secondary recovery were employed on large scale at the Zybza field during the period of production preceding the application of the steam treatment. These techniques included the following: injection of water, natural gas and air to maintain the reservoir pressure; pumping of cement sluny and emplacement of plugging tars to isolate formation water and to block its flow into the producing wells; treatment of wells with hydrochloric acid; hydraulic formation fracturing; side wall bullet shooting of producing intervals; production pumping at forced rates, and vice versa, at restricted rates. The attempt to maintain formation pressure by water, natural gas, and air injection ihl failed. Two different techniques were used, both unsuccessfully, to block formation waters from flooding the pumping wells at the early stages of production. One technique was to force cement slurries of different composition into the formation; the other, to block the water by emplacement of special plugging tars, the TSD-9 and TSD-10. As a rule, the wells producing from high permeability reservoirs of macroporosity type suffered greatest water flooding. In these cases, when large volumes of cement slurries were injected, the reservoirs of the above-describedtype would plug up first. As a result, in many instances, the wells would stop producing liquids altogether. The use of plugging tars also had little effect. It was simply impossible to reliably isolate and block the formation waters, whenever the reservoir encountered was that of macroporosity type and had high permeability. Another technique employed was to shift vertically the liner setting of the producing wells into higher positions within oil-saturated horizons. The purpose of this technique was often twofold: (a) to combat water flooding of the well, and (b) to drain the crude oil from new horizons and thus increase its yield. However, because the reservoir rocks of macroporosity type were not uniformly distributed throughout the Zybza field both along the profile and horizontally, vertical shifting of liner setting, in most cases, did not appreciably block the formation water from entering the well. Over one hundered liner resettings were carried out. In these re-settings the most modem methods of completion were employed, including sidewall bullet perforations of new intervals within the oil bearing horizons. As a rule, the new opened-up intervals of the producing strata were several times thicker than those completed with the original liner setting. Moreover, the geophysical characteristics of the new intervals were just as favorable for petroleum accumulation as were the original horizons. 38


Nevertheless, as shown on Table 12, no matter what particular interval along the profile might be completed later in the individual wells, the bulk of the crude oil was always produced from the originally perforated horizons. For the wells listed in Table 12. the I interval of the reservoir rocks, with average thickness of 10-20m, produced a cumulative total of about 900,000 tons of oil. The I1 interval, lying above the first in each of the wells listed, and generally much thicker than the first, yielded only 90,000 tons. bble 15 Effectiveness of

fting liner Total oil Years of completed well -PmA tion thickness I I1 lumber of nterval interval I interval. m 137 14 13 15 181 4 10 25 86 6 7 32 28 1 4 3 8 63 6 7 43 252 5 6 20 12 300 12 18 163 10 20 9 6 21 133 36 343 8 10 26 354 6 20 17 376 23 3 34 344 6 20 40 5 21 356 16 367 4 12 23 24 378 2 17.6 1 493 25 9 46 1 1 8 7 313 4 22 19 324 14 2 5 24 346 2 33 358 6 16 18 2 369 6 16

ine in reservc Total completed thickness of

II

of micrp lLdawc

jorositv mulativt ields of liaui u&E I interv (

Q

Oil

interval. m

44 75 100 60 58 22 9 10 57 31 34 54 55 36 47 25 34 14 38 63 118 32 61

97 28 78 49.4 76.6 6.3 4.3 85 76.5 58.6 27 18.4 16.7 12.6 32.2 17.5 14.8 3.7 42.7 21.8 17.9 55.4 17.4

Q

water 32 11 11 10.7 5.6 23.8 61.8 28 5.1 98 2.4 8.6 1.3 0.1 4.3 4.4 4 1.3 10.8 0.1 2.4 67.9

2 3il

8 6.6 7.5 3.4 1.6 1.o 0.9 4.4 1.63 1.0 6.3 1.2 3.0 0.03 1.04 9.1 1.42 0.02 2.66 2.4 4.9 2.3

. 4 15.0 1

d 2

water 42.6 54 45 14 16 21.6 1.7 69 30 13 34 60 26 0.06

19 18.6 28.1 0.0 2.5 1.6 5.9 3.6 _z(L

The volume of water extracted from the I and I1 intervals was roughly the same, amounting to 400,000 and 513,000 tons, respectively. Apparently, whenever the reservoirs of type II, that is, of macroporosity type, are present, individual vertical sections within the oil field are wellconnected hydrodynamically. This condition explains, in turn,why in reservoirs of macroporosity type, the measures employed to isolate and block the formation water had very limited success. Without doubt, during the first stage of field exploitation, when sections with reservoir rocks of macroporosity type account for most of the production, plugging materials must not be used to isolate and block formation waters. Any such attempt will only plug up the formation and result in reduction of ultimate oil recovery from the high permeability reservoirs. Because the water cut increases sharply as production continues in time, the measures to block and isolate formation water must be employed in a discriminatory fashion. When, at a particular point during the production from reservoir sections of macroporosity type, it becomes necessary to isolate formation water, it must still be remembered that the same high permeability channels that must be blocked may later have to be used again to inject different agents, such as steam, to stimulate production from adjoining sections of the reservoir with rocks of microporosity 39

Thermal Methods of Petroleum Production type. In such cases, the most effective technique would be to employ plugging agents representing elastic, 2-3 phase systems having degeneration periods of 3-4 months and longer. Injection of such mixtures would temporarily block the selected sections of high permeability reservoir at calculated distances from the well to allow normal extraction of crude oil from reservoir sections of macroporosity type without obstructing later the application of EOR treatments. Unfortunately, many problems still have to be solved before such systems can be employed. Another method of reducing water flooding of the wells during certain stages of production of the Zybza field was to limit their pumping rates. This technique was fairly effective, especially in wells with high production capacity drilled in the central, most productive part of the field and draining the reservoir sections with rocks of macroporosity type. As the rates of production of the liquids from these wells was being decreased, the water cut also dropped and occasionally was completely eliminated. Moreover, the wells produced for long periods of time at a stable rate without pumping any formation water. However, the employment of the limited pumping regime had the disadvantage of reducing the oil yield for the field as a whole. Attempts were also made to resort to hydraulic fracturing of the oil-bearing formation. In retrospect it is now realized that this method of reservoir stimulation could not be effective in an oil field such as Zybza in which high permeability reservoirs of the macroporosity type were also present. Under such geological conditions, all of these many hydrofrac treatments carried out earlier at Zybza merely represented a wasted effort to create fractures in a reservoir in which nature had already created them. Subsequent detection of these natural fractures served to explain the catastrophic circulation losses of liquids (regardless of their viscosities) suffered during actual application of the hydrofrac treatments in the Zybza field. For the same reason, during these hydrofracjobs it was never possible to raise the downhole pressure to the level presumed necessary to fracture the formation. Hydraulic fracturing proved to be both ineffective and inapplicable to the Zybza oil field and to other similar fields. Reservoir stimulation by acid treatment of the bottomfiole zone was also employedBt Zybza oil field over long periods of time. Both hydrochloric and silicic acid solutions were used. Fair results were obtained in the wells drilled in the central part of the oil field where the strata forming the reservoir dip to the North. The sedimentary column in this part of the field also contains fragments of dolomitized limestone. The wells drilled into reservoir sections of low peqneability either did not respond at all to the acid treatment or responded only very weakly. Best results were obtained by using silicic acid in new wells treated right after the completion of drilling, also in wells treated after liner resetting at new intervals of the reservoir rocks. During the first 20 years of oil production, a total of 1800 treatments with hydrochloric acid were carried out on the wells of the Zybza field. These treatments are credited with a crude oil yield of 100,000 tons. Of this number, most successful were the 300 acid treatments performed on newly drilled wells and on those with liners just reset at new intervals. The remaining 1500 acid stimulationsproved ineffective. The data discussed above indicate that during 'the primary production from the Zybza field, the application of the customary stimulation techniques based on geological characteristics of the reservoir, as a rule, failed to increase the rate of petroleum extraction and the oil recovery factor. History of oil production at the Zybza field showed that only the reservoir sections of macroporosity type were effectively exploited. The reservoir rocks of microporosity type did not yield their petroleum in spite of the application of the then known and proven methods of reservoir stimulation. The above experience and the studies conducted at Zybza on reservoir systems of this particular type leads to a certain conclusion. In the fields with high viscosity crudes in which reservoirs of the microporosity type predominateover those of macroporosity,the employment of 40

Petroleum Production Employing Heat Carriers standard reservoir stimulation techniques during the primary stage of production is not recommended. Instead, appropriately designed thermal methods should be applied, once a thorough study of the reservoir characteristics of the individual fields of high viscosity oil have been completed.

7.

SELECTING THE BEST STEAMING METHOD FOR RESERVOIRS LACKING

P

Both laboratory experiments and oil field practice showed that saturated steam, if injected under pressures of 8@ 150 kglcm2. can increase petroleum yield from the reservoir more effectively than any other agent. As a heating agent, steam possesses three outstanding characteristics: (a) Due to the latent heat of steam formation, steam has a high heat content (see Table 13):when the degree of dryness of injected steam is 0.8 (mixtures of 80% steam and 20% of water), the steam can introduce into the reservoir much more heat per unit of the agent than injected hot water can. (b) Injected into the formation, steam can come to occupy a volume 25-40times greater than the water can. (c) Steam is capable of displacing from porous media almost up to 90% of the crude ted steam and of water at the line of saturation

Pressure, kg/cm2

1 5 10 15 20 30 40 80 100 120 140

Temperature of saturation, OC

99.09 151.11 179.04 197.36 21 1.38 232.76 249.18 293.62 309.53 323.15 335.09

Specific volume, m3ikg water

saturated steam ..

0.001 043 0.001 092 0.001 126 0.001 153 0.001 175 0.001 214 0.001 249 0.001 379 0.001 445 0.001 517 0.001 600

1.725 0.381 7 0.1880 0.134 2 0.101 5 0.06797 0.05077 0.024 05 0.018 46 0.01463 0.011 82

I

I

Heat content, k cal/kg water

99.19 152.1 181.3 200.7 215.9 239.6 258.4 312.8 334.2 353.9 372.7

saturated

steam

*

638.8 656.3 663.3 666.7 668.5 669.6 669.0 659.3 651.7 642.5 631.7

The feasibility of applying steam treatment in order to increase the rates of oil production depends on such factors as character of the oil field and of the wells designated for steam injection; cost of fuel and electricity; cost of water and water treatments required, finally, type of installation necessary for reservoir steaming. As regards the character of the oil field itself, some of the parameters that must be considered are as follows: depth of the wells; type of reservoir; thickness of the oil-saturated formations and their water fill; proven reserves of oil-in-place; its specific gravity under reservoir conditions; formation pressure; geological type of petroleum trap; and original oil saturation. The experience with steam injection in the oil fields, at home and abroad, indicates that its employment can be economical under the following conditions: 41

Thermal Methods of Petroleum Production The depth of the reservoir must not exceed 1500 m. If a number of problems, including that of heat losses along the well column, could be eliminated even greater reservoir depth might be tolerated. The reservoir, preferably sands and silts. should be at least 14-15 m thick. However, cases (b) of successful steaming are known involving reservoirs with smaller thicknesses of petroliferous strata. Steam treatment gives best results when applied to reservoirs of microporosity type saturated with viscous crude. Formation pressure should be high. However, good results also have been obtained from (c) formations recording pressures of only 7-8 kg/cm2. The reservoirs of dissolved-gas-drivetype are best suited for oil production enhanced by (d) steam treatment. Once a particular oil field is selected in accordance with the above requirements, the specifications for steam injeCKiOn are drawn up. Such things as the configuration and spacing of steam injection wells and the location and steam generators are determined at that time. Geological, physical, technical, and other parameters under which producing wells will be operating must also be described in detail. (a)

7C.

STEAM_IME~TIP~-TE~~~~~~ES

Three principal variants of steam treatment are (a) cyclical steam injection (steam soak or “huff and puff); (b) steam circulation technique; and (c) area steam injection (steamflooding) (see Fig. 18).

Fig. 18.

Three techniques of steam injection into the reservoir and bottomhole zone: a -steam soak b-steam circulation c-steam flooding

The respective advantages and shortcomings of each of the three variants are as follows: 42


For a period of 3-6weeks, steam is being injected into the top and bottom of the reservoir through the tubing string of the producing well. Next, the well is shut-in for 2-3 days. It is then placed back in production. One and the same well is used both for steam injection and oil production. After the treatment, the well produces at a higher rate. The cycles of steam injectionoil production can be repeated several times. Advantages: High oil yields follow the steam soak treatment heat losses along the well column are lower than with the other two techniques; during the steam injection, the casing string is not heated as much as with the other two techniques. Disadvantages: Production from the well becomes periodic in nature; after each subsequent steam soak,the oil yields decline more and more; the extraction of oil from the reservoir is incomplete; the thermal regime of the bottomhole wne is difficult to control; only a limited area of the reservoir is being heated, a great time loss is involved in rigging up of steam injection installation and in pulling and lowering of tubing; it becomes necessary to use special pumps for lifting liquids at high temperatures (18OOC and more). Steam circulation Steam is being injected into the reservoir through the annular space while the liquids displaced from the reservoir are lifted by the pump up the production string of the well. A special packer, set downhole, separates the steam injection interval above from the oil production interval below. Heating of the reservoir by the steam proceeds from the top towards the bottom. Steam that condensates in the reservoir is extracted and pumped up to the surface together with the oil. This variant requires very thick and relatively homogeneous beds with good vertical permeability. Advanrage: Oil production of the well is not interrupted, Disadvantages: Great heat losses occur especially through casing walls along the well column; the casing walls become very heated, so that the entire casing column must be protected against deformation; the steam can heat only a limited wne of the reservok the technique requires special packers and well pumps for lifting of produced reservoir liquids heated to 1800C and higher. Area steam iniection (steam floodinel Steam is being introduced into the reservoir through the injection well and the oil displaced from the reservoir by the bank of hot steam condensate and steam is pumped up through adjacent production wells. Advantage: The heating of a large reservoir block results in high oil yield. Disadvantage: In some cases, substantialloss of heat may make this technique uneconomical. Each of the three variants of steam injection has its own specific requirements as regards the equipment, as well as the manner of rigging up and operation.

7d . STEAM_TBEATME~.T_BX-Bk~€~~€X€k~€-~E€H~I~~E~ If such factors as heat loss and the difficulty of process control are ignored, it is theoretically possible to displace all of the crude oil from a "clean" porous reservoir by continuous injection of steam. But in practice, in the oil fields with reservoirs of both micro- and macroporosity types, this process cannot be carried out to completion. The three principal limiting factors are the escape of heat through the reservoirs of macroporosity type, further large heat losses that occur in the well column, and the inability to smctly conml the movement of the heat carrier. Under these conditions, the employment of conventional steam soak,steam circulation, or steam 43

Thermal Methods of Petroleum Production flooding techniques becomes both difficult and ineffective. Steaming of the near bottomhole zone may be the only exception in this regard. To overcome these shortcomings, steaming by block-cyclic technique has been developed at the Zybza field through both experimental work and field testing. In this variant of steam soak, separate closed and relatively stable high temperature fields are created by the thermodynamic process. Each one of these fields encloses a descrete block of the petroleum reservoir. Each field is confined within pre-selected boundaries beyond which the heat front does not extend. This method insures both maximum distance of penetration by the heat carrier into the individual reservoir sections of microporosity type and high oil recovery factors for this type of reservoir. The basic steps followed in cyclic steaming by this technique are as follows: First, a discrete block is selected in an oil field which is made up mostly of reservoir sections of microporosity type and of some sections of macroporosity (fracture porosity) types. Next, wells are drilled into this block at close spacing of not more than 100 m either on a checkered grid or in rows. The cyclic steaming of the reservoir block follows according to a pre-set plan. With the arrangement of wells in rows, steam is injected into the second line of wells. The row of production wells is in the middle. These production wells are drilled mainly in the central part of the block (see Fig. 19). The wells in .the outer rows, that is, on the peripheries of the block, are kept shut-in during the entire period of steam treatment. This technique prevents the flow of heat carrier in. the wrong directions. The shut-in wells are used for observation. To get the heat carrier flowing in the desired direction, a low pressure area is created within the block. This effect is accomplished when production wells in the central row are placed in operation. Pumping through these production wells creates a pressure gradient causing the heat carrier present within the reserv'oir. block to move towards its central part. At the same time, this regime makes it possible to maintain the thermo- and hydrodynamic control of the process. 0

0

Fig. 19. Basic layout of wells used in cyclic steaming of reservoir by block method: I-shut-in production-observation wells 2-operating production-observation wells 3-production-steam injection wells

As a result of oil displacement from the porous reservoir, the yield of these centrally located production wells will go up. Just how soon this increase will occur depends on the rate of steam injection and on the amount and distribution (within the reservoir) of rocks of microporosity type vis-64s those of macroporosity. However, in this process, the heat carrier can break through a 44

Petroleum Production Employing Heat Carriers macroporous section that may be present within the reservoir between an injection well and a pumping well. Whenever such a breakthrough happens, the producing well must be shut-in. The corresponding steam injection well must also be closed temporarily. The steam injected through it earlier will then be able to penetrate microporous areas present along this particular section of the reservoir. Otherwise, oil will not be displaced from the microporous rocks. While these two above mentioned wells are being shut down, the producing wells in the outer row are placed in operation. For short periods of time, the pumping wells and the injection wells are started up and then shut down in succession. If close thermo- and hydrodynamic control of this process is maintained, the movement of the steam front can be so regulated that the steam will penetrate into the reservoir areas with microporous rocks. .As a result, the oil is displaced from these rocks into the macroporous sections of high permeability. When downhole temperature of 100-12OOC is reached in the production wells, the steam injection is interrupted. At that time, intensive pumping of the liquids begins, fiist using the production wells of the block and then the injection wells. Production from the block continues for as long as it is economical, after which time the cycle is repeated. To carry out this EOR operation, the entire oil field is f i i t divided into appropriate blocks. Then, in a checkered pattern, the steam is injected successively in one block after another. To apply this method, one must study very carefully the hydrodynamic regime of the wells. To that end, every wellhead in the block must be equipped with a special device (Fig. 20). This simple attachment, designed by one of the authors, can be easily constructed in any individual machine shop. It serves to make any kind of downhole measurement while the well is in operation and without the necessity of pulling the production tubing.

Fig. 20. Wellhead attachment enabling downhole thermodynamic measurements of operating wells. 45


In comparison with the earlier used techniques, cyclic steaming by blocks offers the following advantages: (a) It m,akes steam soaking of capillaries possible so that oil also can be displaced from pores of reservoir sections of microporosity type. However, for this effect to be produced, the limits of thermal field must be relatively stable. (b) The oil displaced in this process from microporous reservoir rocks flows to the producing wells through the macroporous reservoir sections of high permeability. Due to the dissolved gas drive, this viscous-elastic system becomes very mobile even in instances when viscosity is reduced. (c) The flow of the mixture-gas-liquids to the well bore-regardless of its direction, always takes place through the closed thermal field of the heated block. For this reason, the thermal energy spent in each cycle on heating up of the reservoir rocks and of water is utilized to a maximum degree with oil recovery taking place at the same time. 8.

EXPERIMENTAL-AND COMMERCIAL-SCALE APPJ JCATION OF DIFFERENT RESERVOIR STEAMING TECHNIOUES

This work took place in several stages:

Study was carried out to determine the effectiveness of reservoir steaming in general. Both stationary industrial boilers and transportable boilers (PPU-3M type) were used for steam generation. Requirements of ancilliary surface and downhole equipment for steam injection were also studied. These investigationsconfmed the feasibility of reservoir steaming as an EOR method.

1:-

Design work was performed on special equipment for efficient, large-scale application of reservoir steaming. This work included the construction of suitable steam generators (bqilers) and of such other equipment as thermostatic packers, thermal expansion compensators for the wellheads and different recording instruments. Krasnodar Petroleum Institute jointly with Machinery Construction Plant of Nal'chik built and tested two mobile steam generators, the PGU-1 and XU-2. Working regimes of these boilers were as follows: p = 100 kg/cm2; output: 3 + 3.5 tons of s t e m ; and t = 2000C. They also built and then tested (under industrial conditions) a larger mobile, scrubber type steam generator with the following characteristics: p = 60 kg/cm*; output: 5.5 + 6 tons of steam/hr; t = 22OOC. Subsequently,a working series of steam boilers has been produced with output capacities from 5 to 25 tons of s t e a m . Krasnodar Petroleum Institute,jointly with the Scientific Research and Planning Institute of Northern Caucasus and later with the Kazan' Branch of the Azerbaijan Research Institute for Oil Field Machinery Construction, designed and built thermally stable packers and tested (in field operations) thermal expansion compensators as well as movable insulated sectional quick-assembly surface (pipe) lines for steam delivery. The employment of thermally stable packers and of temperature compensators produced two advantages: (a) the production tubing was protected from heat damage; (b) the air screen created in the annular space acted as an insulator, helping to reduce the heat loss along the well tubing column. -2:

46

Petroleum Production Employing Heat Carriers Reference [20] gives the description of the first steam boilers and of other equipment used in reservoir steaming.

m:Work was ciuried on to perfect further both the techniquesand the technology of reservoir

steaming. The scope of steaming treatments was broadened beyond the early strictly localized applications. The individual treatments now encompassed larger areas of a given oil field, e.g., an entire reservoir block, in order to obtain a much higher total final oil recovery from the reservoir. Specifically,the following problems have been investigated

(a) Criteria of selecting individual wells for steam treatment. (b) Effect of formation water on efficacy of the steam treatment. (c) Optimal volumes of steam to be injected into the reservoir bed and the heating radius of each injection well. (d) Effectiveness of repeated steam treatments. (e) Effectiveness of steam treatment in wells earlier abandoned because of their low productivity or absence of oil flow. (f) Propects of applying continuous steaming flooding technique in oil fields that were geologically heterogeneous. (g) Possibility of using cold water to drive the thermal front. Over 200 individual steam treatments were carried out under geologically diverse reservoir conditions. The wells that responded positively to these treatments produced as a result over 100,000tons of crude oil. Of this total amount, a surprisingly high percentage (40%) came from wells abandoned earlier when they ceased to produce. The average yield per steam treatment, calculated only for the wells that did respond positively, was 850 t of oil. For the wells belonging to the earlier-abandoned category, this average yield was actually higher, amounting to loo0 t. In determining the overall efficacy of reservoir steaming, the results obtained from all of the treated wells were taken into account. Thus, the calculation also included the negative results from noneffective wells, that is, the wells which for different reasons unrelated to the steaming method itself failed to produce. About 70 oil wells were in this non-effective category. Although no additional oil was produced from them, a lot of very useful data were obtained in the process. This information helped advance the technique of steam treatment and better appraise its efficacy under different reservoir conditions. The failure of the steam treatment in these instances also showed how important it is to have very detailed knowledge of the reservoir, both with regard to its geological structure and lithology. Staee 4; The study of reservoir steaming method continued using a greatly enlarged battery of steam generators. It now consisted of the following elements: (a) Earlier described movable boilers PGU- 1, PGU-2 and PSP. (b) Two new semi-stationary Japanese boilers manufactured by the Takuma Boiler Company. These boilers were used specifically for steam injection into low permeability and high pressure zones of the oil reservoir. (c) Three stationary boilers of the DKVR-10-39 type erected in a boiler room. A system of transmission (pipe) lines allowed the manipulation of steam delivery from these boilers to any well throughout the Zybza Oil Field (Fig. 21).

41

Thermal Methods of Petroleum Production The joint steam output of the two Japanese boilers and the three stationary boilers was 45 t of steam/hr. If the output of the mobile boilers, PGU and PSP, was added, the boiler battery at Zybza field could produce a total of 50-55 t of steam/hr.

b

r

h

I h h I 1 \

\

-

Fig. 21. Set-up of technicstl facilities for reservoir steaming at Zybza oil field. In addition to securing an adequate and reliable steam generation and delivery system, the work during this stage included the following: (a) Complex study of the Zybza field with its high viscosity crude. (b) Selection of specific target areas within Zybza field for steam treatment. (c) Preparation within selected areas of facilities both for steam injection and oil production. Unfortunately, 40% of all the production wells in areas selected for steam treatment broke down for different reasons. This failure made it difficult to carry out some of the planned technological tests. Although several of these wells were put back into operation, they were not properly located to enable effective control of the steamingprocess for the field as a whole. Stage 5; General conclusions were formulated regarding the application of steam treatment in oil fields containing high viscosity crudes. These conclusions were based on broad data collected during commercial-scale production from the Zybza field both before and after the application of steam treatment. A multi-faceted study was completed on the material collected. Investigations were carried out on physical and chemical properties of the crude, its structural and mechanical characteristics, lithology of the oil reservoir, and on thermodynamicsof the wells. The existence of a new, cavity48

Petroleum Production Employing Heat Carriers type mamporous reserovir (type 11)of very high permeability was discovered. In the Zybza field, type I1 reservoir has more limited occurrence than the microporous reservoir of type I. Nevertheless, type I1 reservoir, whenever present within a given field. creates a number of serious problems which arise both at the stage of prospecting and development as well as during production. In fields of this type the reserves of both oil-in-place and of recoverable oil must be calculated in a new way. In fact, in order to insure maximum oil recovery from these fields, suitable steam treatments must be employed right from the beginning of production. Based on the analysis of theoretical and field data, including the information on past development and production, a technological plan was prepared and put into operation at Zybza oil field. Steam treatment, including the cyclic steaming of the reservoir by blocks, formed an integral part of this plan.

An effort was made to select for the Zybza field a variant of the steam treatment suitable for reservoirs of both type I (microporous) and type II (macroporous) characteristics. Some of the questions that had to be answered were as follows: (a) Effectivenessof cyclic (huff and puff) steam treatment on producing wells; (b) Effectiveness of sustained or continuous steam flooding under different physical and geological conditions; (c) Effectiveness of reservoir steaming upon each repetition of the treatment; (d) Prospects of recovering residualErude oil left in the water-flooded reservoirs after the treatments. During the first stage of steam treatment, cyclic steaming (huff and puff) of the wells was canied out over an extended time period. Between 1965 and 1969, more than 200 such treatments were completed. Technical and economic data for these treatments are given in Table r4. As a rule, either low yield wells or those already abandoned were selected for these cyclic steam treatments. After the injection of 1000-1500 t of steam and upon reservoir heating up to 1200-15OOC, these wells again produced at higher rates. Steam soak proved to be the most practicable method with a fast payback. The purpose of these steam soaks was to determine the optimum variant of reservoir heating that would result in high ultimate oil recovery factor. Investigations in the oil field detected a certain relationship between the effectiveness of the steam soak and the amount of water cut in the additional oil produced by the treatment. Likewise, the amount of additional oil yield showed a certain dependence on the heating of the reservoir. Thus, wells producing with low (up to 30%) water cut prior to steam soak give good yield improvement when their wellbottom zones are heated up to 1200C. Tests showed that in these cases only 3 tons of steam are required in order to produce each additional ton of oil. By contrast, wells producing with high water cut require 5-7 tons of steam in order to yield one additional ton of oil by steam soak. To generate each ton of steam for these thermal treatments, 65 kg of natural gas was required. At that rate of hydrocarbon fuel consumption an oilheam factor of 1 ton/ 5-7 tons represented the economic limit for the Zybza field. Whenever the wells were properly selected for the steam soak and all of the technical requirements'of the process were fully met, the treatment, as a rule, gave very good results (Fig. 22).

49

Table 14. Technical and economic indicators of cyclic steaming (steam soak) - -

B

z g

turn consumption anusoaks

9

5b

er year.

Ei

ms

mud mnsumption II all effective soaks. lousand tons

umulative

s

4vvaage annual steamid factor per well,

.?4

ZI

Onsltons

38 a

ncluding Ion-effeCtiV wells

Wusand

8

effective wells d Y

- 3

2

1

3.1

.ooo

2

2

0.2

0.2

15.5

31

15

16

30.7

1O . OO

15

17

4.0

4.2

7.7

4.1

450

1

10

-

100 9.82

15.50

31

24

13

42.1

1.140

26.9

43.9

14.0

18.4

2.98

2.4

750

9.36

6.39

40

25

15

55.4

1.380

34.5

78.4

20.2

38.6

2.74

2.1

800

1053

4.23

25

16

9

37.6

1,500

24

102.4

25.5

64.1

1.97

1.6

1.600

10.94

3.31

53

35

18

69.1

1.310

46

148.4

19.3

83.4

3.58

1.7

550

11.44

4.20

40

23

17

39.5

990

22.9

171.3

13.8

97.2

2.86

1.8

700

13.14

4.10

19

190.3

19.8

117.0

2.5

1.6

1.OOO

14.20

4.15

26

19

- -

7

21

1.ooO


K , K, 1

r/r

Qoil.

16 10 14 13 12

11 10

9 8 7 6 5 4

9 1

Fig. 22. Dynamics of additional oil production by steam soak treatments. K1-includes non-effective wells; Kyeffective wells only Careful investigation showed that nearly all of the recorded failures of the steam soak had nothing to do with the method itself. In most cases, the low effectiveness of the treatments was due to other causes: Improper selection of wells. (Those that produced with high water cut, many of which were situated already beyond the oil-water contact of the reservoir). Physical and lithological conditions of the reservoir. (This applied to beds with complicated porosity and permeability characteristics, also to wells that produced from horizons dominated by impermeable shale layers with only a few silt and sand interlayers of low oil saturation). Insufficient heating of the bottomhole zone of the reservoir. Steam breakthroughs into nearby wells. (These occurred in the macroporous, typk 11, high permeability sections of the reservoir and they caused failure of the steam soak to penetrate oil saturated microporous, type I, sections). Technical causes (e.g.. casing fractures, sticking of packer) Unreliable monitoring equipment employed for process control. (It caused inaccurate calculation of heat input into the reservoir). Discrepancy between the volumes of condensate that formed from injected steam and the volumes of liquids pumped out during the treatment. (These errors gave rise to water flooding of the reservoir, increased water cut in producing wells, and reduced oil flow from porous reservoir blocks. The last mentioned effect was attributed to the counter-pressure blockage exerted by excess steam condensate against the oil-saturatedporous bed). The causes of unsatisfactory steam soaks and the incidence of these failures are indicated below: 51


Incidence, number of wells

Cause Insufficient heating of the reservoir - - - - - - - - - - - - - - - - - - - - - - - -

35

16

10

Selected wells producing from horizons dominated by low permeability shale layers with only few sandstone rind silt interlayers of low oil saturation- - - - - - - - - - - - - - - - - - - - - -

14

Breakthroughs of injected steam into nearby wells through macroporous, high permeability rections of reservoir with resulting limited penetration md heating of microporous reservoir sections in the bottomhole zone of treated wells - - - - - - - - - - - - - - - - - - - - -

21

Both the field experience with commercial scale production and the laboratory stuqies show that in cyclic steaming, best results are obtained when the reservoir is heated to a temperature of 1200C or higher. The amount of steam that must be injected into the reservoir during each "huff and puff' treatment ranges from 1,OOO to 1,500 tons. It depends on the porosity and permeability of reservoir rocks, the drilled thickness of the formation, and the degree of its water fill. For each meter of effective thickness of the producing formation. 70-100 tons of steam should beinjected. The majority of the wells which before the steam soaks had had flow rates of liquids of only 0.1-0.5 tons/day, after the treatment increased their flows to 5-15 tons/day. The period of commercial production that followed the steaming treatment lasted 60 to 500 days, and in individual cases, it was even longer. Thus, for 20 wells, commercial production lasted 60 days; for 21 wells, 125 days; for 31 wells, 280 days; for 35 wells, 500 days and longer. Prior to their steaming, the total production from all of these wells amounted only to 20 tondday. Without reservoir steaming, commercial production of these wells ceased already back in 1966- 1967. As noted above, a group of wells originally drilled into reservoirs of macroporosity type, when treated with steam proved non-effective due to steam breakthroughs into the adjacent wells. At least, the latter responded to this incidental stimulation by yielding additional oil. This side effect of the steam soak on nearby wells was fairly general, and it was taken into account in calculating the end result of the treatment. Thus, this incidental additionalyield obtained from these nearby wells in macroporous reservoirs amounted to 40%, over and above their original production. Thanks to the reservoir steaming, the current daily flow rate of the treated wells increased sharply. At times it attained 100 tons, and sometimes 140 tons. The average annual yield of crude oil per each effective well was 845 tons, reaching in some individual years, 1600 tons. The 52

Petroleum Production Employing Heat Carriers steadoil factor (K), that is, the amount of steam consumed to produce each additional ton of oil, decreased from 10 t/t to 1.6 t/t. The water cut in the oil produced by the steam treated wells did not exceed 50%, although in individual cases it attained 75%. The amount of water produced daily, fluctuated between 0.1 tons and 10 tons. The study of steam treatment of wells has been carried out at Zybza field over a period of 8 years. The results point to high effectiveness of steam soak when the reservoir was heated to 12OOC and higher. The effectiveness of reservoir steaming depended on the degree of water fill of the producing formation (Fig. 23, Table 15).

Fig. 23. Effectiveness of steam soak depending on water cut in produced oil. Table 15a. Effectiveness of steam soaking depending on water cut of produced oil Number of steam soaks

25 36 31 52 159

Total steam Water cut consumption, prior to tons steam soak treatments, ton s/dailv 28,500 40,800 35,000 58,000 18,000

Quantity of additional crude oil produced, tons

0.0-0.5 0.5-2.0 2.0-5.0 5.0-10.0 10 and up

31,500 38,000 2 1,000 21,000

Lx!Q

steadoil Quantity of additional factor K. oil crude produced pel tons/tons each steam soak. tons 0.98 1.1 1.65 2.7 3.3

1,250 950 650 400 350

117,000

In technical and economic terms, highest efficiencies of the reservoir steaming corresponded to the water flow rates of up to 2 tons/day (Table 15b). At that rate of water flow, the additional oil produced per one steam soak exceeded 1100 tons. As the rate of water flow increased up to 5 tons/day, the amount of additional oil produced per each steam soak decreased to 650 tons, while, at the same time, the energy consumption increased somewhat. 53

Table 15b. Relationship between the amounts of additional oil produced by Water produced per day, tons

Quantity of additional 011 meed

tons

as%oftotal additional yield

70,000 2 1,000 2 1,000

up to 2 up to 5 up to 10 over 10

60 18 18 4

5,500

SteamJOil factor. tons/tons

1.0 1.65 2.7 3.3

As the rate of water flow increased from 5 tons/day to 10 and more, the energy consumption again increased correspondingly. At the same time, the amount of additional oil produced per each steam soak dropped to 350 tons. In other words, at these high rates of water flow, the steam treatment became only 1/3 to 1/4 as effective as that of the wells with low rates of water flow. But even at high rates of water flow (above 5 tondday), the steam soak treatment can still be economic. In these cases, however, studies of technical and economic feasibility must be made beforehand.

E E E L C B ~ X - ~ R E E E A T I ~ ~ H ~ ~ ~ E ~ ~ ~ A ~ ~ ~ ~

8C.

In the majority of treated wells at Zybza field, the amount of additional oil produced upon repetition of the steam soak showed a decrease from the amount of additional oil produced during the first treatment. In this study, the steam soak was systematically repeated over an extended period of time on 30 oil wells. The aim was to determine the ultimate effectiveness of a treatment resmcted to the near bottomhole zone, and to determine the maximum final recovery of oil by this method. Altogether 73 individual “huff and puff treatments were carried out in seven cycles. Not all of the 30 wells were treated during each successivecycle (Table 16). Table 16. Results of repeating steam soaks in wells producting from reservoirs in which microporous type was dominant Numk of wells mated ~

a8*

Quantity of steam

c o ~ ~ m for e dall of

Specific unrmp tion of steam per

theweUsmated,tons

welLtons

For all steam soaks of the

cycle)

Same ordinal

number

16

21.ooO

cumulatively 21.000

PerW steam

:umu-

quantity each

soak 1.350

13.200

820 13300 445 20.320

16

21.ooO

42000

1.310

7.120

14

19.500

61.500

1.360

4.035

300 24.355

12

18.ooo

79.m

l.m

2.800

235 27.155

6

9.600

89.100

1.600

1.320

220 28.475

5

8.500

97.600

1.700

825

165 29.300

4

7300

104,800

1,800

29,900

54

Petroleum Production Employing Heat Carriers In analyzing the data obtained after each steaming cycle, only the wells meeting more or less the same requisite conditions were considered. Results of a particular steam cycle were not used for the wells which during that steam cycle lacked the conditions specified in this study. For example, sometimes the yields obtained from some wells during the third steam cycle were higher than those during the first cycle. This type of result had to be disregarded. Subsequent study showed that in such cases the specified conditions of the steam soak were not observed during the first cycle of treatment. Insufficient heating of the wellbottom zone during the particular steam soak was one of the most common types of failures to observe required conditions. Another important specification was the presence of type I reservok that is, one in which microporosity was dominant. The only data used were those obtained from effective steam soaks of type I reservoirs uexformed under conditions conforming to requirements. The results of the study are given in Fig. 24 and 25. Qoil,

T

K,dl

1400-

1 4 ~

1200-

12-

1oOo-

10-

900-

9-

800-

8-

700-

7-

Mx)-

6-

500-

5-

400-

4-

300-

3-

200-

2-

I00

1

Fig. 24. Effect of repetition on results of steam soak treatment. Qoil-additional yield of crude oil; qoil recovery factor according to laboratory and oil field data; Q0p relative additional yield of crude oil; q-functions of steam cycles; Ks t e d o i l factor. I

0

I

2

3

4

5

J 6 1 1

. 25.

tons

55

Dependence of total additional oil yield (ZQ0d) on the repetitiveness of the steam cycle (q) and on the steam consumption (Q).

Thermal Methods of Petroleum Production Curve q of Fig. 24 shows the oil recovery factor obtained in laboratory experiments, and curve Q oil - the additional oil yield per well obtained at Zybza field during this study after repeated commercial-scale steam soak treatments. The results are sirnilc, they were obtained in both cases by steam treatment of specific sections of the producing bed. Practically no oil can be extracted by ordinary primary and secondary production methods from microporous. type I. reservoirs. For this reason, the final cumulative additional yield attained during the steam cycles of these reservoirs can be considered as their oil recovery coeffficient. As expected, a decrease in the effectiveness of the steam soak can be observed upon repetition of the treatment. Best results were.obtainedduring the first 3-4 cycles of steaming. This fact was already pointed out earlier during the discussion of studies conducted on: Effectivenessof cyclic steaming on water invaded formations (see: Part I. 5d, Figs. 14, 15, 16 and Table 10). The percentages of residual oil-in-place extracted during the first 3 steam cycles at 3 different temperatureregimes were as follows:

Reservoir temperature upon steaming, oc

first steam soak second steam soak ,third steam soak

125

150

200

35 10 4.2

(45.8) 53.0 12.4 21.5 7.0 4.9

It will be recalled that in these laboratory investigations. a model of microporous reservoir (type I) was used. Corresponding oil field study. to determine best conditions for repeated application of steam soak were carried out mostly at the temperatures of 120-125OC. In these tests, during the f i t four steam cycles, the cumulative extraction amounted to 51.4% of the residual oil in place. This percentage is close to the recovery factor obtained under corresponding laboratory conditions with steaming conducted at similar temperatures (125-13OOC). The fifth and sixth successive steam soaks still gave positive results. After a lapse of two years, the seventh and eighth steam cycles were carried out. In a number of wells at Zybza field these last two treatments were also positive, with oil yields of about 140-150 tons, not much lower than the yields obtained in cycles five and six. Apparently, in these cases, the oil from other, yet untreated parts of the field flowed into the reservoirs near the bottomhole of the wells being steamed again. However, high viscosity of the residual crude and low permeability of the microporous reservoirs combined to slow down the oil filtration from the untreated zones to the treated zones. The data indicate that, under these conditions, it takes a fairly long period of time for the filtrating oil to fully resaturate the earliersteamed reservoir. In these studies the maximum amount of oil recovered from the reservoir model in the laboratory was 77%. It was also achieved in the course of the first three steaming cycles. For the laboratory model, the ultimate oil recovery factors were: 60.3%, 68.5% and 77.0%. These total cumulative recoveries of oil-in-place corresponded to the reservoir temperatures of 125OC; 150% and 2000C. In the laboratory experiments, the oil extracted by cyclic steaming from the formation model was fully de-gassed so that there was no dissolved gas drive. By contrast, during cyclic steaming of oil wells in the Zybza field, the dissolved gas drive provided one of the major sources 56

Petroleum Production Employing Heat Carriers of energy. It helped move viscous oil through the formation, thus improving the ultimate oil recovery factor. In fact, thanks to the presence of this drive, the results of repeated steam soaks performed on the wells were better than those carried out on the reservoir model. Of course, the latter is a closed system; therefore, when maximum oil recovery is attained, no additional oil flows in from other parts to replace it. For this reason, beginning with the fifth steam cycle, the amount of additional oil sharply decreases. When the reservoir model is heated during the steaming to 1 5 R , practically all of the recoverable viscous oil is produced during the first three steam soaks. During all of the subsequent steam cycles, the final oil recovery factor can be increased only by slightly over 2%. But in field experiments, during cycles 5 , 6, and 7. it was still possible to increase the oil recovery factor, on the average, by 5% per each additional steam soak. This increment of 5% represented from 5 to 7% of the total additional oil produced by all of the steam treatments put together. The experiments carried out at Zybza field over a number of years gave the following basic results regarding the effectivenessof repeating steam soaking of the wells: 35% of all additional oil was recovered during the 1st cycle; 80%of all additional oil was recovered during the lst, 2nd and 3rd cycles; 20% of all additional oil was recovered during the 5th. 6th and 7th cycles; k average s t e d o i l factor during the 1st cycle soaks did not exceed 2 t average s t e d o i l factor during cycles 5,6, and 7 was 3.3 t/t.

8d. E B Q ~ I T A L _ P I S E L A € E M E ~ ~ - Q E ~ X L - ~ X - € Q ~ I ~ ~ Q ~ ~ - A ~ ~ A h i s method, known as sreumflooding. is. as a rule, applied in oil fields with relatively favorable geological conditions, lying at shallow depths not exceeding 700-800 m. Where geological conditions of the oil field are complex and the reservoirs lack uniform characteristics, it is difficult to control the process of continuous s t e q injection. However, many oil fields of the latter type represent good prospects for steam flooding. Studies are now being conducted, particularly in the USA, to adapt to these oil fields the technique of reservoir steaming. As regards the oil fields suitable for application of steam flooding technique, in the USA the reservoirs must generally meet the following conditions [36]:

- depth to oil bearing formation, m - type of reservoir - thickness of producing bed, m - effective thickness, m - permeabilityof reservoir rock, Darcies - oil fill (saturation), % - oil viscosity, centipoise - specific gravity of oil g/cm3 - area of field sections used for testing, hectares - well pattern, number of spots - spacing between injection wells and production well, m - unit area for steam flood treatment, hectares

50 - 800 sands and sandstones with limited interlayers of clays and shales 15 - 75 8 - 35 0.5 - 5 60 - 75 200- 1500 0.950 - 0.970 2-45 5-7 20 - 50, occasionally up to 90 0.1 - 4.0


- number of observation wells in steamed area of oil field - number of unit areas in oil field under simultaneous treatment - average rate of steam injection, varied according to

4 - 15 up to 10

50- 170

well spacing, t/day

- total quantity of steam injected, varied according to size of unit area and volume of oil-saturated reservoir being treated, thousands of tons - duration of treatment, years - additional oil produced, thousands of tons - steam/oil factor, t/t - coefficient of horizontal sweep by injected steam (as determined by specially drilled wells),% by thickness - by area - increase in oil recovery factor by unit area

50 - 200 2-5 15 - 60 0.3 - 2.5 40 - 50 60 - 85 40-77

A number of undesirable phenomena can create difficulties during steam flood treatment: collapse of the bottomhole zone of producing well, sand plugging of well, formation of stable oil emulsions, production using "overheated" wells, and shortage of water of sufficient quality for steam generation. In the USA, steam flooding is considered to be an expensive EOR method. The completion of the treatment requires a relatively long period of time; furthermore. it has high operating expenses especially for fuel (energy) and water. In Russia, steam flooding technique has been applied with best economic results at the Okha oil field located on the Sakhalin Island in the Far East. Here, under relatively favorable geological conditions, oil has been recovered by steaming ever since 1968 [19]. Select$ for the EOR project was the petroliferous bed No. IV in block No. X located on the central part of an (anticlinal) fold. The principal reservoir characteristics and technical data on the field prior to the commencement of steam flooding were as follows: depth down to the producing horizon was variable-from 90 to 150 m; average thickness of the bed40 m; bed porosity-28%; permeability-1 Darcy; oil fill-80%; specific gravity of crude oil under surface conditions-0.93 g/cm3; oil viscosity-165 centipoise; tar content of crude45%; formation pressure immediately prior to the commencement of steam treatment-from 1 to 3 kg/cm2; temperature from 4 to 6OC; oil recovery factor during the 40 years of conventional production prior to EOR work-14%; number of wells drilled into the block X of the field-52; number of separate unit areas-9; area of each unit-from 0.34 to 0.87 ha. For steam flooding, the unit areas were assigned different sizes in order to determine the effectivenessof the method at different well spacings. Some old but still producing wells, as well as some new specially drilled wells, were used for steam injection. For each group of 7-10 producing wells, one steam injection well was employed. The distance between the injection well and the producing wells was 50-60m. Steam was injected at the rate of 50-60 t/day per each injection well under the pressure of 8-24 kg/cm2 at the wellhead temperature of 180-2800. For the 2-year period, the cumulative volume of steam injected into the individual unit areas of the Okha field amounted to 25-40 thousand tons. For the treated sections of bed IV as a whole, the steadoil factor averaged 3.6 t/t; however, from one unit area to another it fluctuated widely between 1.7 and 12.5 t/t. Again, for the treated section of bed IV as a whole, the oil recovery factor increased from 0.13 before the steaming to 0.238 after the treatment. In some of the individual unit areas the recovery factor went up to 0.4-0.5. 58

Petroleum Production Employing Heat Carriers Continuous injection of steam results not only in higher oil yield but also creates a hydrodynamic connection between the injection well, on one hand, and the production wells. on the other. Moreover, a number of problems often typically develop during application of steam flooding method: (a) Steam breakthrough may occur from the injection well through the formation to the producing wells, reducing the amount of oil recovered. These breakthroughs can be controlled by injecting small volumes of cold water into the affected producing well. Also, such wells must be shut down temporarily. (b) Sand plugging of bottomhole often occurs. Attempts were made to control intensive sand production by employment of carbamide resins. However, so far no reliable means have been found to reinforce the near bottomhole zone against sand plugging. (c) At steam injection temperatures above lOOOC, the plungers of oil well pumps have a tendency to jam. Efficient means of preventing it have not yet been found In 1969, experimental work on the application of continuous steam injection technique started in a block of the Khorosany oil field in the Baku Petroliferous Basin of Azerbaijan. The depth of oil-bearing formation in this block ranged from 500 to 700 m. Producing wells were spaced at 80-90 m distance from the injection well. After 3-4 months of steam flooding, the producing wells began to respond; their yields increased up to 3-4 t/day. As in the case of steam flooding in the Okha oil field, sand plugging of the production wells also became one of the main problems at Khorosany. At this time (1980) work on the continuous steam injection is also being conducted in a number of other oil fields in Russia's different petroliferous regions. Some of these fields and their locations are as follows: Kenkiiak ahd Karazhanbas in Kazakhstan; Katangli on Sakhalin Island; Yarega and Usinsk in the Komi Region; Binagady and Kiurdakhany in Azerbaijan; Akhtyr-Bugund in Krasnodar Territory; Novo-Suksin and Severo-Tavel' in Tartaria; Gremikhin in Udmurtiia Region; Borislav and Urichesk in the Ukraine. Steam flooding now under way or planned in the above listed regions involves the application of this particular technique to the following two types of reservoir rocks: (a) porous sandstones and siltstones, both stable and those with tendency to flow; and (b) carbonate rocks, both of cavernous, porous, and fractured types. Working with these different types of reservoirs should soon produce sufficient information to reach unambiguous conclusions regarding technical details, oil recoveries, and economics of steam flooding under different physical and geological conditions.

At Zybza the following criteria were used to select specific oil field blocks for the work on steam flooding technique: (a) geological and oil production characteristics of the reservoir; (b) facies changes occuring within the reservoir; (c) interconnections among otherwise separate individual petroliferous horizons; and (d) the degree to which these blocks have been already exploited by conventional production methods. Two blocks were thus selected: block I located in the northwestern part of the field, and block I1 in the southern part. In this study, it was assumed that during production by conventional methods practically all of the oil has been extracted from the macroporous reservoirs of high permeability. Thus, most of the reserves of residual oil (86-90%) still present in the field were to be found in the micropomus part of the petroliferous formation. The aim was to devise a suitable steam flooding technique to extract this oil. 59

Thermal Methods of Petroleum Production charactenst'ICS of block I Fie. 26): Production comes from horizons VII, VIII,and IX of the Sannat sedimentary series. The latter is of Miocene age and consists of marine sandstones, siltstones, shales, and limestones. The oil-bearing horizons VII, VIII. and IX lie at the depth of 750 m. They have two types of reservoirs: (a) microporous, with permeability of 250 millidarcies; and (b) macroporous, much more restricted in occurrence. Fifteen wells were drilled down to these horizons on a triangular grid using 100 m spacing.

Fig. 26. Movement of heat flows during area steam flooding of block I reservoirs. l-production - observation wells; 2-observation wells; 3-abandoned shut-in wells; &steam injection wells; 5-"a", " b arbitrary designation of subblock areas of blocks I; &nominator: well number; denominator: temperature at the wellhead.


On the average, each unit area covers 2.5 ha; the entire block I has an area of 21.5 ha. Total volume of the reservoir rocks in the block is approx. 13,000.000 m3. Just prior to steam flooding treatment (1969-1970), the reservoir pressure ranged from 3.4 to 15 kgkm3. Originally, many of the newly drilled wells, upon completion, started producing with yields of 30-70t/day. Shortly thereafter their yields diminished sharply. This production pattern was due to the presence of macroporosity reservoir, type 11, within the radius of influence of these wells. During the most active period of development of the Zybza field (1949-1951),the average daily oil output from block I reached 500 t. However, after only 5 years, the production declined to 50 t/day. By 1965,it amounted only to 2-3t/day. which means that by that time the production from block I by conventional methods practically ceased. Immediately prior to the commencement of steam flooding (1970)the average daily output per well for the 15 wells of block I ranged between 0.1 and 0.5 t, and in case of well 383,it was 3.5 t. The total cumulative annual production of block I was 820 t. The water cut of the produced liquids ranged from 5 to 90%.

Fig. 27 Well pattern and movement of heat flows in block II. 1-5-same as in Fig. 26; 6- contours of heat flows.

61

Thermal Methods of Petroleum Production stlcs of block 11 f F a The Southern part of Zybza field, where this block is located, is structually higher than the northwestern part. The oilibearing horizons of block I1 occur at depths ranging from 440 to 735 m The effective thickness of producing beds attains 130 m. Both type I and type 11reservoirs are found present in the cross section. During initial production the reservoir had a dissolved gas drive with gas also separating to form a gas cap. Because of very high gadoil ratio most of the wells drilled in this block had to be shut in. However, as the gas was being depleted from the reservoir, some of these wells were brought back into production, yielding up to 10 t of oil daily. By the time the steam flooding work began, gas was nearly absent from the wells and the reservoir liquids were rising in them to a greatly reduced height of not more than 10-15 m. By that time, the flow rate of the wells amounted only to 0.1-2.5 dday and the total annual oil production from the entire block I1 was 1,960 t. Twenty wells were still operating, producing with a water cut not exceeding 5%.

Inasmuch as the old wells of blocks I and 11of the Zybza field were not originally designed for steam treatment regime, all of them were examined beforehand for leaks and integrity of their casing strings. Moreover, steam injection wells were partly rebuilt. In block I, where steam injection treatment was expected to continue for a long time, the injection wells 354 and 356 were equipped with a 102-mm casing from the wellhead all the way down to the producing zone at the bottom. In this manner, a reliable casing column was constructed to insure normal conduct of steam treatment. Unlike the injection wells of block I, those of block I1 were provided with a 63' mm well tubing and with a packer. Steam was supplied from a stationary boiler plant of the DKUR-10/39 type provided with Russian-made PSP equipment and with a "Takuma" Japanese-made steam injection equipment. The following numbered wells were used for steam injection: block I: wells 354, 356, 376 and 383; block II: wells 256 and 257. In block I the steam treatment began in May 1970, and in block 11, February 1970. The rate of steam injection per well varied with the degree of steam acceptance by the reservoir. In block I, it ranged from 70-90 dday, and in block 11-from 100 to 150 dday. At the wellhead of injection wells, the steam temperature fluctuated from 215 to 2200C, and the steam pressure from 25 to 35 kg/cm*. The following data were regularly recorded in the wells of the two blocks: production wells: changes in rates of flow of reservoir liquids; temperature changes at the wellhead, chlorine ion concentrationin formation water; observation wells: changes in static level of reservoir liquids in the well; changes in formation temperature measured at the well liner interval. By monitoring the above data, it was possible both to follow the shift of the steam front within the reservoir and to control the steam flooding process itself. The pertinent data for the steam flood treatment and its results, by blocks, were as follows: Block I: It was arbitrarily divided into two subblocks "a" and "b" (see Fig. 26). The steam injection began simultaneously from the south through wells 354 and 356, and from the north through wells 376 and 383. The intent was to displace the oil into the adjacent production wells arranged in a row within a geologically most favorable zone. The possibility of oil flow also into other production wells of block I was not excluded, inasmuch as both type I and type II reservoirs were present within this block. Greatest stability of steam injection was recorded in subblock "a", where, in course of 650 days, 52,000 and 49,000 t of steam were forced into wells 354 and 356, respectively.

62


In subblock "b", over a period of 350 days, 30,000 t of steam was injected through well No. 383. At the end of that period, the treatment was stopped because the movement of the steam could not be controlled.

ft

a b C Fig. 28. Improved variants of equipment and wellhead connections for steam injection wells: a-packing (stuffing) box to insure reciprocal mobility of casing and tubing strings; b and c-telescopic equipment to enable the extension of tubing string, without raising of the pump (b); and the process of withdraw1 of reservoir liquids (c). All in all, this experiment with continuous steam injection by area lasted two years, from 1970 until 1972. It was stopped upon completion of the program, as planned. In order to insure hydrodynamic contact between the rows of production wells, block I was additionally treated by steam soak. During the indicated time period, the following numbered 9 63

Thermal Methods of Petroleum Production wells were thus treated: wells 343, 156,207, 38, 367, 34,344, 364 and 377. Approximately 110,OOOt of steam was consumed in the process. During the entire period of steam treatment of block I, 142,000t of steam was injected into the wells and 18,000t of crude oil was produced. Beginning essentially with the second half of 1976,individual production wells of block I started to interact with the injection wells. Greatest effectiveness was shown by production wells of subblock "a". Thus. prior to the treatment, well 156 had an average monthly oil yield of only 15 t. After the steam soak of this well with input of 850 t of steam, and its subsequent response to the area steam flooding. the latter administered through well 356,the yield of well 156 increased by a factor of 3. During individual time periods the yield reached 50-60t/month (see Fig. 29). As already noted, the wells were monitored during the steam flooding for shift in steam front, chlorine ion concentration in reservoir water, also for temperature changes on the well bottom and at the wellhead. Seven months after the commencement of steam flooding the chlorine ion concentration began to decrease both in the injection well 354 and in the responding production well 156. Towards the time when production showed high water cut, this concentration of chlorine ion decreased from 6 to 0.85gjl.

e m

Fig. 29.

Yield changes of wells 156 and 364 during continuous steam flooding in subblock "a" of block I. 64


During the treatment the steam condensate intensively penetrated the high permeability reservoirs of type II,which accounted for the increased water cut with produced oil. Whereas, at the beginning of the treatment the water was produced from well 156 at the rate of 1.5 t/day, after 7 months of steam flooding the rate increased to 12 t/day. During the same period of time the temperature at the wellhead increased to 400C from the earlier average annual value of 18-2OOC. The average daily oil yield rose from 0.5 t to 1.5-2.0 .t Production well 364 drilled into the oil bearing bed at a distance of 100 m from the injection well 354 also began to respond to steam flooding (see Fig. 26). Thus, 6 months before the treatment began, well 364 was producing daily 0.6 t of oil and 3.5 t of water, 2 months after the commencement of steam flooding, that is from July 1970, the corresponding daily yields were 1.5 t and 12 t. Early in the third month of steam flooding the chlorine ion concentration in the formation water started to decrease sharply while the water cut progressively increased reaching a rate of 20 dday. The temperature at the wellhead of well 364 rose to 48OC. Production wells 34-38 of subblock "a" were situated within the sphere of influence of the injection wells 354 and 356 (see Fig. 30).

Years

Fig. 30. Yield changes of wells 34,38 during continuous steam flooding on subblock "a" of block I.

65

Thermal Methods of Petroleum Production Judging from the well-log data, both well 34 and 38 had the same reservoir characteristics. Nevertheless they reacted differently to steam flooding treatment. Thus. before the treatment, well 38 produced daily 9 t of water and 1 t of oil. Fifteen days after the steam flooding began the daily flow of water increased to 23 t and that of oil to 3 t. After 6 months of treatment the corresponding daily yields were 31 t and 4 t. During the same time the temperature at the wellhead of well 38 increased to 47OC. The relative increases in flow rates of well 34 were smaller. Prior to the steam flooding this well produced for a long period of time at the daily rate of 6 t of water and 0.5 t of oil. But after 6 months of continuous steam injection well 34 increased its yield to 9 t of water and 1 t of oil; and by the end of the 7th month it further increased the daily flow to 13.5 t of water and 1.5 t of oil. By that time the temperature at the wellhead reached 45OC. In subblock "b" steam flooding was administered through injection well No. 383. Within its sphere of influence the production wells 387,388 and 389 were situated somewhat higher on the structure than well 383, whereas production wells 248 were somewhat lower (see Fig. 39). The best results were obtained from well 387 (see Fig. 31). %at-.

thonth Qoil. t/mon*

I I

1-7 a I

4

I

6

I

6

I

7

I

8

I

e

I

IOTII

I

IZ

I

$3

Years

Fig. 31. Yield changes of wells 389 and 387 during continuous steam flooding at subblock " b of block I.

66

Petroleum Production Employing Heat Carriers Within the radius of influence of the producing well 387 microporous reservoirs of type I are dominant. Steam condensate from the steam injected into well 383 moves slowly through the bed displacing the oil from the microporous reservoirs to the macroporous. This process results in a gradual increase of the flow rate of well 387. Whereas prior to the steam treatment well 387 had daily outputs of reservoir liquids of 0.1-0.2 t, after the first 3-4 months of the treatment it increased its daily flow rate to 3-35 t. No real breakthrough of the steam condensate from the injection well 383 to the producing well 387, situated farther up dip, was recorded during that time. However, such a breakthrough did occur into the producing well 389 situated at the same elevation of the structure contour as the injection well 383. Production wells 248 and 377, situated somewhat lower on the structure than producing wells 387. 388 and 389, responded more quickly to steam injection into wells 383 and 376. Whereas prior to treatment their daily flows were 3.0 t of water and 0.5 t of oil each, in two months following the steam injection these daily rates increased to 13.0 t and 2.5 t each. After six months of treatment, each produced daily 15.0t of water and 3.5 t of oil. Thus, as a result of prolonged steam injection, nearly all production wells of block I responded, to one degree or another, to the treatment. Fig. 32 shows this increase in oil yields due to continuous steam injection.

Fig. 32. Effectiveness of steam soak and steam flooding on block I. 67


For four years prior to the area steam flooding, the wells of block I were systematically treated by cyclic steaming. After the subsequent application of steam flooding, the effectiveness of these two methods were compared (see Fig. 32) Between 1966 and 1969,as a result of the aforementioned cyclic steaming of the wells, a total of 16.000 t of oil was extracted in block I at an average steam/oil factor of 1.8 t/t. Calculations show that without reservoir steaming the oil yield for the above period of time would have been only 2,000 tons instead of 16,000t. Examination of data given on Fig. 32 and in Table 17 show that the effectiveness of area steam flooding started to decrease in comparison with the cyclic method. With area steam flooding, the steadoil factor showed afminimum of 7 t/t and a maximum of 16 t/t. This means that the energy loss incurred on oil extmtion by area steam flooding was 6-7times that of cyclic steaming.

Table 17. Yields of oil and reservoir liquids; also steam consumption in block I. Quantity of stear used in cyclic steaming of well 'OOO of tons

Oil yield fkmcyclic steaming of wells, '000 of tons

Continuous Oil yield areasteam from continuous injection areasteam 'OOO tons injection 'OOO of tons

Yield of

Steam/oil factor

resaVOiI

liquids 'OOO of tons

for cyclic for steaming continuous of wells area steam 'OOO of injection, 'OOOoftm fons

1

1.4 1.9 1.95 1.9

2 3 4

5 6 7

11 16 12 11

8

Bfock11 (Fig. 27): Within this block the oil-bearing bed lies somewhat higher structurally. Main reserves accessible through the wells of this block were recovered already during early production at the time when dissolved gas drive was still present in this part of the Zybza field. Large reserves of residual oil were left behind in the individual reservoirs of microporous type. In order to take advantage of the gravity drive during the area steam flooding, the injection wells were placed higher on the oil bearing formation and the production wells downdip from them.. In this way, the bank of steam condensate that formed within the degassed part of the bed could displace the degassed immobile high viscosity crude from the microporous reservoirs into the high permeability channels formed by individual zones with reservoirs of macroporosity type. Finally, by shifting the heat front, this oil was then driven towards the production wells situated further downdip. To bring about the aforementioned shift of the heat front, cold water flooding was 68

Petroleum Production Employing Heat Carriers employed. The water was pumped into the oil reservoirs through the injection wells. By this method the efficiency of the process was enhanced, while, at the same time, some of the steam originally injected could be recovered through production wells. Wells 256, 257 and 258, situated higher updip, were selected for steam injection wells 292,453,454,477, and 478, located further downdip, served both for production and to monitor the steam flow within the reservoir. A distance of 100 m and more separated these productionobservation wells from the injection wells. Prior to the steam treatment the above enumerated wells registered formation pressures of 1-3 kg/cm2 and a very low level of reservoir liquids in the well column. Block II had an area of about 20 ha and contained an estimated volume of 15,000,000 m3 of oil saturated rocks. The unit areas "a" and " b had sizes of about 2.5 ha each. Producing horizons penetrated by the wells were at a depth of 500-550 m. Immediately prior to steam injection, the crude oil had a density ranging from 0.985 to 0.990 and a viscosity of not more than 2000 centipoise, measured at 3WC. Steam injection continued for a period of two years using wells 257 and 258. At first, injection well 256 was also used, but later it had to be excluded for technical reasons. The continuous steam flooding was carried out under the following regime: volume of steam injected ranged from 120 to 170 t/day; injection pressure and temperature, measured at the wellhead, were 28-30 kglcrn2 and 220-225OC. In unit "a" the distance between the injection well 256 and the production-observationwell 474 was 100 m. During the steam treatment a good hydrodynamic connection was quickly established between the two wells. Already 5 days after the commencement of steam injection into the well ,256, a rise in the level of reservoir liquids was registered in the well 474. Soon thereafter the last mentioned well was placed i6 production. At that moment its yield of reservoir liquids was 1.5-2.0 t/day. The well was closely monitored. The yield of reservoir liquids kept on increasing steadily, fist to 10-15 t/day, and after 60 days-30 t/day. During the same time the wellhead temperature also kept rising. It went up from the average annual value of 180C-390C. The chlorine ion concentration dropped to 1 gil. The oil yield at the end of this period of 60 days was over 3 t/day. In order to better control the process and to improve its effectiveness, the steam injection into the well 256 was periodically interrupted. As the period of continuous steam injection lengthened, the wellhead pressure in the production well 474 registered sharp increases. During the 10-15 day intervals in the steam injection through well 256, a drop in the yield of reservoir liquids was registered in the producing well. At the same time, however, its oil production increased. After 85-90 days of this periodic "on-again and off-again'' regime of steam injectidn, sharp qualitative changes occurred in the reservoir liquids produced by well 474. Namely, the total yield of reservoir liquids dropped to 15 t/day, while the yield of oil itself reached 12-14 t/day. This technique of periodic area steam flooding of oil fields with reservoirs of heterogeneous types was studied earlier by the author [ 5 ] . The experience of that earlier work was applied with good results at Zybza during the continuous steam flooding of block II. Following the above described periodic steam flooding, further steam injection was shifted from well 256 to well 257. Still, production well 474 continued to yield oil for over two more years. By the end of that period of time, however, its yield was down to 2-3 t/day. The stimulation of well 474 was due entirely to the steam injection through well 256. The steam injection well 257 was located at a distance of 170 m from the production well 474. At no time during the steam injection through well 257 was any effect recorded in the well 474 (see Fig. 33). Prior to steam stimulation, the production well 474 was "dry," and it was kept abandoned. However, it produced 1950 t of crude oil during the subsequent steam treatment via well 256. Altogether, about 6750 t of steam was injected into the well 256. Even if all of that steam 69

Thermal Methods of Petroleum Production consumption were to be used up to produce the additional 1950 t of oil actually recovered from well 474, we would still obtain a steadoil factor of only 3.3 t/t. The latter figure is very satisfactory both from an economic and technical point of view.

30

20 15

10 5

steam

injection

Fig. 33.

b

Pavie

Stcam

injection

Pause

Stcam

P

injection

A

U

S

E

Time. days

Yield changes of production well 474 in response to periodic steam flooding via well 256.

When the effectiveness of periodic steam flooding via well 256 sharply decreased, steam injection was shifted to well 257. A regime of unintemptd flooding was employed with daily steam input of 160-170 t at wellhead pressure of 35-40 kg/cm2 and at a temperature of 220-225OC. To control the movement of heat front in the reservoirs of unit area "b," the temperature, the flow of reservoir liquids and the geochemical changes were monitored in the production wells downdip from the injection well 257. Within 6 months, counting from the time these experiments began on block II. 6750 t of steam was first injected into the well 276, and then another 7800 t into the well 257. During that time the temperature readings in the downdip production wells increased as follows: in well 476,100 m downdip, temperature rose to 48OC; in well 454, 170 m downdip, temperature rose to 40OC; in well 564,200 m downdip, temperature rose to 39OC. Later, measurements were made in production well 477, also showing a temperature increase to 41OC (Fig. 34 and 35). As a rule, temperature increases were recorded in the wells located down the dip of the petroliferous bed. No changes in bottomhole temperatures were recorded in the updip wells. As the steam injection progressed, the thermal front advanced downdip along an irregular contour. The rate of heat flow was fastest where the petroliferous bed consisted of macroporous type reservoirs. Using these high permeability zones, the steam was breaking through to a considerable distance away from the injection well without displacing the crude oil from the microporous reservoirs present along its path.

70


h

1

I

1

I

I

I

25

30

35

40

45

50

t,"C

.Y

' Fig. 35: Change in bottomhole temperature of well 477.

Fig. 34. Temperature change in weil 476 during the advance of heat front caused by injection of cold water into well 257. 1-9: temperature profiles.

At the same time, the level of fluids in these stimulated wells recorded a rise. Thus, the height of the column of fluids was 30-35 m in the "dry" well 476 and as much as 20 m in the well 258. Steam condensate reached the production wells located as far as 300 m away. Thus, wells 441,442,443,444,446 and 457 all showed changes in the geochemistry of formation water. In the course of one year, the chlorine ion concentration of the produced water decreased froh 6-7 gA to 2-3 gA. While the salinity of water dropped, its production rates increased (Fig. 36). At the time the steam injection began, it was expected that the steam or steam condensate would spread throughout the producing formation over an area of about 2.5 ha. Actually, within one year, steam condensate penetrated an area of 20 ha, which, in this particular case, was not at all desirable. The steam condensate cooled as it flowed through the producing formation. By the time it reached the producing wells, its temperature was only slightly above that of the formation water. Consequently, steam condensate had no effect on oil yield. During the final stage of application the process of steam flooding generally produced results resembling those of water flooding applied earlier in this same section of the Zybza field. But as a method of maintaining formation pressure, both proved to be equally unsatisfactory because of intensive waterheam condensate breakthroughs along high permeability channels of macroporous type reservoirs. In the case of block 11, the steam flooding resulted in actual net decrease rather than increase of oil yield.

71


0138

~~

Fig. 36.

Change in chlorine ion concentrationof formation water in producing wells of block 11. Wells: I-producing; &abandoned; 111-steam injection. Dates: 1-May 25; 2-June 29; >July 4; &July 24.

Table 18 and Figure 37 show that during the 3-year period of steaming by "huff and puff" method, on the average, about 5,000 t of oil was produced annually. During that time 10,OOO t of steam was injected, resulting in a s t e d o i l factor of only 0.7.

12


Table 18. Basic data on steam input, also on yield of oil and of reservoir fluids in Block 11. Steam injected in cyclic, treatment, 'OOO of tons

I

I

Oil yield

Steam

Oil yield

from Blockn, 'OOO t

injected in

from Block II '000t

areasteam

I

flooding, 'Ooot

I in cyclic in area stear steaming injection

Cumulatively 1966 1967 1968

0.8 3.9 2.7

1970 1971 1972

-

-

10.3 10.3 10.3

1.7 4.1 6.6

23.8 24.4 24.3 24.5

0.67

A

Years

b -

cyclic steaming area

stearn flooding area

4

Fig. 37. Effectiveness of cyclic steaming and of area steam flooding in block II.

73

Thermal Methods of Petroleum Production With the commencement of continuous steam flooding in 1970,the oil yield decreased. Quick passage of the heat carrier from the injection well to the producing wells and increased water cut in the fluids produced both conmbuted to this negative result. During the initial year of continuous steam flooding, the oil yield was actually higher than during the initial year of steam treatment by cyclic method. However, in successive years of treatments this relationship was reversed. Moreover, the technological-economic results of steam flooding proved to be very inferior to those of cyclic treatment. Thus, in two years, 182,000t of steam was consumed on steam flooding, resulting in oil production of slightly more than 7,000t (Fig. 37). Theoretical calculations were made prior to the steam flooding to determine both the duration of treatment and the amount of steam that would be required in order to move the heat front a certain distance through the oil-bearing formation. Uniform rates of movement of the heat carrier were assumed. For the injection well 257 these figures were as follows: distance of heat front advance, m duration of steam injection, days amount of steam. tons

45* 260 41.000

52 280 82.00Q

In accordance with this calculation, 82,000t of steam was injected into the well 257 during a period of 540 days. However, when an oil-bearing formation consists of different types of reservoirs, it is not possible to establish heat front advance with any degree of stability. This fact was borne out by actual field studies. Thus, towards the end of this two-year experiment the steam condensate was being recovered even from producing wells located as far as 400 and 500 m away from the injection well 257 (see Fig. 36). Schematically. the flow of heat carrier has been illustrated earlier (see Fig. 27). In order to promote the enhanced recovery and to obtain additional information regarding the steam flow in steam flooding treatment, cold water was injected into the well 257. The amount of water was calculated beforehand. Of course, the objective was to displace the heat front at the expense of heat accumulated in the formation. This experiment, carried out under field conditions, med to determine how the profiles of temperature maxima were affected by (a) the injection of superheated steam and of cold water and (b) the order in which these two agents were being pumped into the formation. To determine the location of these profile maxima, the temperature readings were taken at points along the middle of bed thickness, the latter measured in the vertical plane. According to calculations, 35,000m3 of cold water had to be injected into the well 257 in order to remove 6,350,000giga calories of thermal energy accumulated in its bottomhole zone. The calculation called for cold water injection over a period of 170 days. Actually, the injection was continued only for 150 days at an average daily rate of 195-200m3. In order to control the process of steam flooding and to be able to predict its progress, a number of thermoand hydrodynamic surveys were carried out both during the period of steam injection and of cold water injection. Temperature profiles were constructed for several wells, and maps were drawn showing isobars and isotherms for specific points in time. Using these data it was possible to follow the steam penetration within the oil-bearing bed and to decide on application of appropriate measures in the EOR treatment.

74

Petroleum Production Employing Heat Carriers Figure 38 gives information on steam and cold-water injection into wells 257,258 and 454. Figure 35 shows several temperature profiles determined in succession throughout the entire duration of the experiment in the observation well 477 located 100 m northwest from the injection well 257. The first profile, dated April 16, 1971 was taken after one year of injecting superheated steam at the rate of 180,OOO t/day. During that year the temperaturerose from the natural formation temperature of 300C to a maximum of 35OC. The location of this maximum corresponds to the middle of the bed thickness, measured in vertical plane.

Fig. 38. Data on steam and cold-water injection: 1 and 2-f steam and cold water into well 257; 3-0f steam in well 258; 4-of cold water in well 454.

While the experiment was in progress, steam injection into the well 257 was interrupted for one month. During that period of time, steam was injected into the production well 258 (located 100 m west of well 257) at the rate of 190 t/day and into production well 454 (located 200 m north of well 257) at the rate of 200 t/day. During this same time the temperature in the observation well 477 decreased to 31OC, that is, almost down to natural formation temperature. As indicated earlier, after heating the oil bearing bed with superheated steam forced through well No. 257. cold water was injected into that well. In response, the bottomhole temperature of the production-observationwell 477 increased at fist by 5OC, and after one month it reached 44OC. At the same time the point of temperature maximum shifted upwards to the top of the producing formation, a distance approximately equal to the bed thickness (see Fig. 35). This change in position denoted the beginning of a process of intensive heat loss. When the injection of cold water into well 257 failed to produce the desired effects, it was terminated. Soon after that the point of maximum temperature in the well 477 moved back to a position midway of the bed thickness, while the temperature for a long time remained at about 38OC level. Equally interesting results were obtained at production-observation well 476. During the period of steam injection into well 257, the bottomhole temperature in well 476 reached 430C, remaining at that level practically unchanged until the commencement of cold water injection into well 257. Within 30 days following the beginning of heat front displacement by cold water, the bottomhole temperature in well 476 increased to 500C, and after another 27 days it reached 53OC. Subsequently, as the cold water front moved through, the bottomhole temperature in the well 476 gradually decreased, and towards the end of the experiment it became even with the natural

Thermal Methods of Petroleum Production temperature of the formation. Fig. 34 shows the thermogram of well 476 corresponding to periods of steam injection in well 257 and of the displacementof heat front by cold water. The above experiment showed that a heat front can be created and then displaced through the oil-bearing formation by alternating the injection of superheated steam and of cold water. Such a technique can be effective under specific and rather uncomplicated geological conditions. In this process, the point of temperature maximum should always be kept in the middle of the bed thickness. This requirement can be met by properly restricting the volume of cold water being pumped into the injection well. Under complex geological conditions steam flooding through an injection well, supplemented with cyclic steaming of some producing wells, is more effective. However, in these cases, the unit area subjected to the steam flooding treatment must be more restricted. Notwithstanding the positive results obtained during area steam flooding in the above described experiment, this method is generally ineffective when applied to large sections of the petroliferous formation of complex geology. On the other hand, it can be very efficient in oil fields characterized by simpler geological conditions. The experience with area steam flooding in blocks I and I1 at the Zybza field leads to the following conclusions: (a) Heat carrier can advance easily through the petroliferous formation using high permeability channels provided by the macroporosity type reservoirs. (b) The distance of heat carrier penetration away from the injection well can be quite significant. Under these conditions, no stable heat front of any kind can be created whose (c) contours would resemble those of the heat front based on experimental and theoretical calculations. (d) Frontal displacement of crude oil from the bed cannot be obtained by area steam flooding; this method is ineffective for petroliferous formations consisting of macroand microporous type reservoirs. Enhanced recovery in oil fields of the above type requirea new technique of steam treatment. To be effective, this technique must be able to utilize the high permeability channels of the macroporous type reservoirs for (a) introduction of steam into the oil-bearing formation, (b) subsequent displacement of crude oil from the microporous type reservoirs and (c) free flow of displaced oil to the production wells. Precisely such a new method, called the block-cyclicsteaming or cyclic-steaming-by-blocks,has been developed. It is based on the experience with earlier described work on area steam flooding, heat front displacement by cold water, cyclic steaming of individual production wells, also on geological, lithological, geophysical, thermo- and hydrodynamic studies. 8g.

E X E E E I M E ~ I T A L - ~ Q E g _ ~ ~ ~ - € Q M M E E € I A ~ ~ ~ USINGQ ~ U € ITTH~EQ ~ .BLQ€:B: €X€LI€~STEAMMG_TE€H~~QUE

For this study a section of Zybza field was selected which had sufficient number of wells for steam injection, for oil recovery and for conduct of different temperature surveys. The section was located on a large stratigraphic trap in the central part of the field. A structure contour map of the section was drawn up, and all the different investigations preliminary to block-cyclic steaming were completed before the start-up of actual steam treatment. Fig. 39 shows the actual location of wells used in this cyclic-steaming-by-block project. The two types of wells present in this section were as follows: active producing: 41,61,63,84, 131, 134, 159, 163, 164, 184,251,343,364,107,54,279,373and 133; abandoned (used for observation): 42,281, 108, 136, 162,501,353,382 and 374. 76

Petroleum Production Employing Heat Carriers Average formation pressure in the section did not exceed 12-15 kg/crn*. Lithologically the formation consists here mainly of rocks characterizing type I (microporous) and I1 (macroporous) reservoirs. Both types of reservoirs are well developed. During the initial period of production the principal part of crude oil came from the macroporous-type reservoirs.

I formation. Wells: I-production; 2-injection; 3-abandoned; 4-observation; 5-structure contours drawn on top of massive carbonate bed (contour figures indicate depths measured from a surface datum level).

I1

Thermal Methods of Petroleum Production Before the block-cycle-steaming proper commenced, a series of steam soaks of individual wells was carried out. This was done in order to be able to compare the results with the subsequent block-cyclic steaming and to evaluate its effectiveness. During the steam soak,the average daily oil output per treated well was 10-12t. Cumulative figures for these steam soak treatments as a whole were as follows: steam consumption 13,900t 6,000t crude oil recovered s t e d o i l factor 2.2 t average oil yield per single steam soak 1,390t

period

1st cycle of block steaming

2nd cycle of block steaming

Fig. 4 0 Effectiveness of steam soaks and of block-cyclic-steaming. Because these steam soaks were carried out in the very same section of the oil field, they provided control data for measuring the effectivenessof the subsequent block-cyclic-steaming. The steam soaks were followed by thermo- and hydrodynamic studies. Finally, the blockcyclic-steaming treatment itself was carried out using the earlier described technique (refer to Section 7d). The aim of this technique was to establish relatively stable limits for the advance of the thermal front. Only under these conditions could the saturation of the capillaries and subsequent oil displacement from the microporous reservoirs be assured. Both the steam and the displaced oil were directed towards the centrally located wells 373,54,279, 107 and 133. These wells were situated on the higher part of the stratigraphic trap. Their yields of reservoir liquids prior to the treatment ranged from 2 to 2.5 t/day. Well 133 was abandoned back in 1959 because of low productivity. During the first cycle of treatment, steam was injected through wells 184,343, 164, 163 and 84. In the course of 1972,altogether 16,500t of steam was injected into these wells, resulting in recovery of 8,500t of oil. This figure showed a higher rate of production than prior to the first cycle steaming (see Fig. 40). Before the start-up of the second cycle, the steadoil ratio attained

1.9 t/t. 78

Petroleum Production Employing Heat Carriers During the second cycle of block steaming, producing wells 41,61,106,159 and 277 were used for injection. The idea of using different wells for steam injection this time was to reroute its flow through parts of the block not previously heated. In this manner, steam breakthroughs along earlier established channels hopefully could be avoided. These new injection wells were located roughly along the dip of the petroliferous formation both in the Eastern and Western halves of the block In an earlier period, even before this block was selected for treatment by the new technique, wells 41,61,106, 159 and 277 all were stimulated with different results by steam soaks. Later, during the first cycle of block steaming, they were used as production-observation wells. Just before the start of steam injection these wells produced oil at the rate of 0.5-1t/day. Before the commencement of the second cycle operations, thermo- and hydrodynamic surveys were run on all of the producing, shut-in and abandoned wells in the block. In this manner, it was possible to compare subsequently the effectiveness of the fist cycle treatment with that of the second cycle. Steam injection during the second cycle continued for approximatelyfour months. During this period the operating regimes of the steam injection wells and of the production wells themselves have been regulated depending on the character of stimulated production wells and on the degree of their stimulation (see Table 19). In the second cycle, from 6,000to 9,000t of steam, on the average, was injected in each well at wellhead pressures ranging from 10 to 30 kg/cm2 and at a temperature of 2100C. In any one day, up to 600 t of steam was injected into the six wells taken together. The total quantity of steam injected into the entire block during the second cycle was about 40,OOO t (see Table 19). Table 19. Average monthly regimes of steam injection wells during the second cycle of block steaming. Well number

Beginning and end of steam injection, year 1973.

159 61 106 251 277 41

l R 9 -4111 2f21 -514 2R7 -514 311 - 514 3/12 - 514 413 - 514

Iverage monthly indicators

Quantity of injected

Total quantity of steam Apr May injected,t

iteam t

1500 2,400 2,500 3.100 3,000 5,200 590

-

9,000

650

6.000

-

4,500 7,100 7.500 6,050

650

600 850 680

at wellhead, kg/cm2

-

12 28 11 - 2 8 20 - 27 10 - 30 18 - 30 11 - 2 8

easured at

210 200 210 I200 210 200

Production wells started to respond in a relatively short period of time of 15-20days. The monitoring of production wells indicated the following changes: (a) the mineralization of formation water produced with crude oil dropped due to the penetration of steam condensate through macroporosity channels, (b) bottomhole temperatures of the wells went up and (c) their crude oil yields increased. Additionally, measures were taken to make sure that the amount of liquids removed from the reservoir by production wells exceeded the quantity of steam condensate and of encroaching formation water entering into the block. In this manner the production regime of dissolved gas drive could be maintained. 79

Thermal Methods of Petroleum Production Counting from the beginning of the second cycle, the bottomhole temperatures in the production wells rose from 30 to 500C within two months, and from 30 to 75OC (on the average) within five months. The oil yield in the producing wells throughout the block increased. Well 133, originally abandoned, situated in the highest part of the field, now started to produce, yielding 25-30 tjday of water-free crude oil. Wells 54, 107, 134 and several others increased their individual oil yields from 1-2 to 15-25 tjday. It was characteristicof the pumping regimes of the producing wells that these high oil yields were obtained at the expense of only a slight drop in reservoir pressure, in this case amounting to less than 1 kg/cm2. The second cycle operation was also successful in two other respects. Namely, it was possible to direct the heat flow from injection wells westward towards the centrally located producing wells, also to create a stable heat front, keeping it within the limits of the block. Thus, high temperatures, sometimes reaching 90-10OOC, were registered in all of the production wells situated between the rows of the injection wells to the east and west. At the same time, the bottomhole temperaturesremained practically unchanged in the observation shut-in and abandoned wells, even in those located very close to the steam injection wells. The results of temperature readings taken for the injection, production and observation wells before, during and after the block-cyclic-steaming treatment are given in Table 21. In this manner, the main objective of the treatment by this new technique has been attained. It was possible to create a stable thermal front limited to a section or block of an oil field. Practically all of the heat introduced into the petroliferous bed has been utilized within the limits of that selected block. This was evidenced by relatively high bottomhole temperatures of 6570% recorded over time in the active production wells of the block. Apparently the thermal energy spent on the heating-up of the petroliferous bed and on promotion of enhanced recovery processes was utilized to maximum degree. In theoretical studies, calculations are usually given for loss of heat along the well column and from there into the top and bottom of the oil-bearing formation. These losses do indeed occur in any thermal process, but they increase significantly in petroliferous formations that consist of micro- and macroporosity reservoirs. In such formations the injected heat carrier cannot be retained locally because it easily escapes along high permeability channels. Continuous area steam flooding in such cases becomes ineffective as an EOR technique because the process itself cannot be adequately controlled. Reduced heat loss represents one of the advantages of the cyclic-steaming-by-block In this connection, special studies should be carried out to develop methods for determining heat losses in oil-bearing formations with reservoirs of fracture porosity type. Such methods are not available at the present time so that it is difficult to make even any approximate calculations. The new technique of block-cyclic-steaming does not diminish the role of steam soak. Rather than excluding one another, these two methods are very complementary especially during the period of initial well completion and oil field development. In this process, the steam soak is used to stimulate the bottomhole zone of the individual wells, whereas block-cyclic-steaming results in heating-up of larger sections of the oil bearing bed. Used in combination, these two techniques make possible a high percent of recovery from oil fields with very viscous crudes. The application of these two steaming techniques in the above described block at Zybza field gave the following results: Steam soak treatments of individual wells produced 6,000t of crude oil. Calculated per well this yield averaged 1390 t of oil at steam/oil factor of 2.5 tjt. The average daily oil output rose from 10 t to 25-30 t, dropping back to 10 t just before the commencement of the block-cyclicsteaming. 80

Petroleum Production Employing Heat Carriers First block-steaming cycle involved injection of 16,500 t of steam and resulted in production of 8,500 t of crude oil from the wells. The daily oil output per well increased from 10 to 40 t, falling back to 20- 25 t towards the end of the first cycle period of one year. The average stewoil factor for the entire production period of this cycle was 1.85 t/t. The second block-steaming cycle consumed about 40,000 t of steam for injection into the formation. The oil yield for the block rose to 80 t/day that is, it increased 8-10 times over the daily yield recorded prior to the stimulation of individual wells by steam soaks. At the same time, the water cut in the produced fluids decreased. A relationship has been established between the oil yield and the total production of fluids from the block as a whole. With the increase in the yield of fluids, the crude oil yield also rose. Sharp 'individual drops recorded in the oil yields occurred mostly for technical reasons. Additional oil produced from the block amounted to 15,500 t, and the stewoil factor was 2.6 t/t (see Table 20). Table 20. Comparative indicators for crude oil production from selected block by steam soak of individual wells and by block-cycle-steaming techniques. Operation

Block-cyclicsteaming first cycle second cycle

Number of Quantity of steam wells involved injected into oil bearing bed, in treatment 'OOO tons 10

14.1

12 8 10

56.5 16.5 40.0

Additional oil yield from block, '000 tons 5.66 24.0 8.5 15.5

Additional

oil yield

Stewoil factor

per each well, tons 1.390

2.5

2,000 1,050 1,550

2.3 1.85 2.6

I

High figures recorded both for the block as a whole and for the individual wells following block-steaming show that by applying this technique crude oil can be successfully displaced from the microporous reservoirs into the macroporous. Characteristically, in this process. the oil flows through the high permeability channels of the microporousreservoir with low gas factors of 2 m?t. In low permeability reservoirs saturated with high viscosity crude oil. the forces of capillary resistance are so strong that they almost completely dissipate the energy of any dissovled gas. By contrast, in high permeability reservoirs the energy of the dissolved gas becomes the principal drive mechanism moving the crude oil through the bed. Later on, even after significant decrease in the temperature of the formation and of gas-oil-water fluids back to normal, the mobility of crude oil remains high nevertheless. The high output wells of this block can thus be made to produce by creating in the wellbottom zone only mimirnal pressure drops of 0.05-0.1 kg/cm2. The above described study canied out under field conditions proved the effectiveness of the block-cyclic-steaming technique to displace from large sections of the formation the crude oil locked in microporous-type reservoirs. This oil cannot be recovered otherwise by conventional steam soaks of individual wells because the effect of such treatments is resmcted to the near bottomhole zone.

9. MONITORING AND CONTROL OF BLOCK-CYCLIC-SmAMING UNDER FIELD CONDITIONS To monitor and control the process, fluid- and thermodynamic observations were carried out during the application of the block-cyclic-steaming under conditions of field production. At 81

Thermal Methods of Petroleum Production different depths along the well column, the temperatures were measured using an electronic thermometer (type TEG) of the well surveying equipment (type APEL). As the counter passes opposite the frequency panel, the register draws continuous temperature profiles on graph paper. In the electronic thermometer, metal resistors were used as counters. They had a sensitivity of up to O.OlOC, which was sufficient for the purpose. Parallel with the temperature profiling, well surveys were carried out to determine the productivity coefficient. All of the borehole surveys for wells in the block treated by the new cyclic-steaming technique were run separately during three different periods: before, during and after the treatment (see Table 21). This method offered a number of advantages. It permitted objective comparison of obtained results and making of necessary corrections in the basic parameters of the process. Moreover, the information and experience gained during a specific cycle of the treatment could then be used for corresponding cycles of similar treatments in other sections of the oil field. Analysis of results: The great majority of wells in the Zybza field of high viscosity oil are characterized by very high productivity. This characteristic is especially true of the wells in the selected section of the petroliferous bed consisting for the most part of microporous type reservoir. The pressure drops required to make the wells produce are very small, amounting to tenths, even hundredth parts of 1 kg/cm2. At the same time, the yield of reservoir fluids is relatively small, ranging mostly from 30 to 40 t/day. Because of these conditions, wells in the block can be operated jointly with practically no interference. During the steam injection into the formation an interaction can be observed taking place betwen the injection wells and the nearest producing wells. This relationship is revealed on maps showing temperature and pressure fields (see Figs. 45 and 46). As part of this study, indicator diagrams were constructed using yield of the wells versus pressure drop as the two coordinates. Separate curves were plotted for total fluids produced, for formation water and for crude oil. These diagrams for wells No. 38, 39 and 41 are shown on Fig. 2. For the three wells, all three curves have common characteristics. The total fluids curve is a straight line showing increase in productivity with the increase in pressure drop (gradiant) caused by pumping. At higher pumping regimes, the water curve becomes concave in direction of pressure drop axis and the crude oil in direction of yield axis. In order to make comparisons, it sufficed to study each of the wells during all of the three periods, that is before, during and after the block-cyclic-steaming using one and the same pumping regime. The effectiveness of any process resulting in the intensification of oil recovery is best indicated by oil yield. Oil productivities were therefore analysed for ordinary operating regime of the wells (see Figs. 41-44). Comparison of curves drawn on Figs. 41-44 shows that the cyclic-steaming-by-block was most effective on the group of wells 107, 133, 184 and 134 stimulated by steam injection into well 159. Thanks to the temperature increase in the third period, the productivities (qofi) of these wells were, respectively, 2.0, 1.25, 2.06, and 2.9 times greater after the treatment (3rd pedod) than before it (1st period) (see Fig. 41). The productivity q oil of the injection well 159 itself rose 1.5 times. The relatively limited oil productivity increase of well 159 itself can be explained by the fact that the oil in its zone of influence has been drained already during prior production. However, the productivity of fluids of well 159 remained high as before; it was also true of the other steam injection wells. Productivity increases due to drop in oil viscosity are indicated by counterclockwise shifts of straight line plots from their original position 1 to positions 2 and 3 in the direction of the yield axis (see Figs. 4144).

82

Table 21. Results of thenno- and fluid-dynamic studies carried out on oil wells of the block before,during and after merit by h e new blockcycle-steaming technique During blockcyclic-steam UeatmenL

Before blockcyclic-steam treatment.

- -

Pressure, k&m2

Yield,

Y

-

i 0

27 :5 L3 i x

E

,B

rn

-5 ,a

8

b 4

- 41'

13.41

-B

VhY

30.0

0.02

13.39

i i .$ E

3

46

Pressure, kg/cm2

C

.2J r: .-

3

Pressure,

Yield, VbY

.L 8

?a

3

4

-

Q

z Q

d

-

70

0.09

19.8

0.6

6.6

-

!90

-

-

210

0.09

30.5

2.5

27.7

46

160

-

0.10

2.0

33

18.8

11.38

0.08

7.5

33

12.24

159.

7.24

7.19

0.05

4.0

36

34.3

131

12.88

12.79

0.09

4.4

33

13.13

7.94

0.06

38

84.3

12.15

13.04

-

50

-

-

210 200 36

14.93

14.91

0.02

30.4

8

g 0

1.2

5

!'

i?

O> 60

16.8

16.7

0.1

28.0

0.2

2.0

12.03

11.96

0.07

22.2

4.3

61.4

9.35

9.30

0.05

21.0

0.3

6.0

13.77

13.70

0.07

31.5

2.7

38.6

Na

210

working

13.17

13.08

0.09

37.6

4.2

46.6

33

14.34

14.24

0.1

31.6

3.8

38.0

37

14.58

14.50

0.08

35.3

5.9

54

10.59

10.52

0.07

19.7

6.0

85.7

33.5

11.34

11.26

0.08

20.1

6.3

79.0

36

10.31

10.24

0.07

16.5

10.5

150

5.21

0.04

22.0

7.4

185.0

55

247

370

0.10

32.0

0.1

1.o

32

61*

5.25 13.7

13.6

4.23 35.5

d

E

373

107

g

3A

-

15.93

V

.? 67

-

11.46

t/day

- -

-

16.03

-

Yield,

kgjcm2

56.6

84

Not Wokicing

li-

-$

c

251.

106.

8

After block-cyclic-steam treatment

4.20

0.03

22.0

7.4

-

-

170

-

0.03

42.8

4.2

73.7

55

5.19

5.18

0.01

20.8

3.7

200

13.55

13.53

0.02

38.9

0.1

5.0

3.9

195.0

134

5.64

5.6

0.04

42.8

2.7

67.5

65

4.65

4.62

140

58

5.72

5.70

0.02

41.2

184

7.74

7.68

0.06

44.8

2.7

45.1

54

7.60

7.54

0.06

44.8

2.8

46.6

54

7.64

7.60

0.04

45.3

3.7

92.5

279

7.90

7.84

0.06

43.0

0.8

13.3

44

7.67

7.62

0.05

43.0

I .2

24.0

485

7.4

7.3

0.1

42.8

2.9

29.0

133

1.49

1.44

0.05

33.9

19.8

2.75

343

395

32

NU W d i q

364 15.4

15.3

I

*Steam-injection wells

0.1

48.6

0

-

35.5

0.02

39.6

23.8

1I 9 0

45

25.85

22.7

3.15

16.5

0.2

0.063

36

15.16

15.06

0.1

48.6

0

-

2.77

43

4.02 25.8 15.04

4.01 23.8 15.00

0.01

39.6

27.3

2.73(

2.0

18.0

0.3

0.15

0.04

34.0

0.4

10

K 'gB E

9

03

64 48 21 45 39 35 79 55 50 70 70 44 42 75 65 84 75 I02 43 61 57 61 54.5 51 45 65 65 45 36 44

36

- -

- -

-


I

Well No.

111

Fig. 41. Change in well temperature with time; and change in productivity coefficient qoil depending on Ap during block-cyclic-steaming.

84


Change in temperature field around injection well

I I I

-

1

I

I

I I

I

I

I

\I

L

Well Nw

Oil Roductivity

1 - 1 25 1

=I/ 54

111

I

l

TLM; months

373

Period: 1-before;2-during; 3-&%

Fig. 42.

Change in well temperature with time and change in productivity coefficient qoil depending on dpduring block-cyclic-steaming.

85


Change in wnpauurc field around injection well

Well No.

r-1311/ I

I

Time; monrhr

/If 279

Y.

, - ,

I

..-

,

Period: 1-before: 2during; 3-dier

Fig. 43. Change in well temperature with time; and change in productivity coefficientq0g depending on Ap during block-cyclic-steaming.

86

Petroleum Production Employing Heat Carriers Change in tunpcruurc field uound injection well

t

1w--

150

--

Period of injection into well 41

-

_ .

I

I

1 I

,! 1

~

I

I

----! -

I

! I ,---

I

1 , I

I

I

I

I

I 1I I

- 1

1-

.-

I

- t-

I

.

I kx-l

0

4'

b

1 8 4 81.4

2

Fig. 44. Change in well temperature with time; and change in productivity coefficient qoa depending on Ap during block-cyclic-steaming. The productivity of two other groups of wells increased by larger amounts. Wells 84,364, 41 and wells 131,279,61 had respective productivity increases of 8.2,2.4,2.0,and of 8.8,8.2, 2.0 times. The productivity increases of the group of wells 373,54,251were smaller. On the average, following the block steaming treatment, the productivity of all of the wells increased 2-3times. However, the total oil output rose only by about 1.5 times. These two figures indicate that the potential of this process has not been fully realized.

87

Thermal Methods of Petroleum Production Little effect was noted after steam injection into the well 106 during the second cycle of block steaming. Only well 343,located in the area of influence of well No. 106,showed slight stimulation; it was. however; without any practical significance. The dynamics of change in productivity show a certain characteristic. The productivity change over time reached highest values near the temperature maxima on the temperature-time curve. The maximum of the function, temperature-timeof the production-observationwell, occurs after two months' lapse following the cessation of steam injection into the injection well. This temperature maximum then remains stable for one to two months. The total duration of the period from the moment of heating-up of the petroliferons formation following the steam injection to the time when the formation temperature drops back to normal was six months. Apparently there is an optimal point correspondingto certain values on temperature and time coordinates at which the next cycle of steaming should be started without waiting for the formation to cool off completely. The function, temperature-time for the group of production-observation wells 107, 133, 184 and 134 steamed through the injection well 159,has the tendency to rise on the left limb, that is, in the part of the curves corresponding to the first period of the treatment (before the block steaming). It was particularly true of wells 133 and 134. This anomaly was due to higher temperatures caused by aftereffects of similar block steaming treatment canied out earlier in the section of the field to the south of the aforementioned group of wells. The results of the data analysis made it possible to construct isobar and isotherm maps (see Figs. 45 and 46). Pressure and temperaturefieldr: To determine the changes in formation pressure in all of the wells wi,thin the block, readings were repeated in the course of a long period of time. Appmximately after one month, counting h m the moment of initiation of steam injection, the pressure in the production-observation wells went up and then stabilized. Only the stabilized pressures were taken into account. In the injection well 159 the formation pressure rose from 7.2 to 27.1 kg/cm2 and stabilized at 34.3 kg/cm2. During the same time, in the production-observation wells of this group, that is in wells 107, 133, 184 and 134. the formation pressure also rose but by much smaller amounts. For wells 134 and 133 these increases amounted only to 0.1 and 2.5 kg/cm2, respectively. In the injection wells 41, 251, 61. the corresponding increases in bottomhole pressure were 10.1,22.8, 21.8 kg/cm2. The bottomhole pressure of injection wells was determined according to the known barometric formula. However, for the gas wells a correction was made for the increase in gas density. The steam density was calculated to be 20-30% higher on account of the moisture content, and gas density was assumed to equal 0.7 of ak density. Inasmuch as the pressure changes in the production-observation wells were not significant, the effects that the injection wells exerted mutually among themselves could be ignored. In other words, it was assumed that all injection wells operated independently of one another. Before the pressure field map was constructed, all pressures measured in the production-observation wells were brought up to the moment at which steam injection was discontinued. Visual extrapolation was used for that purpose. Pressure interpolation was camed out between the injection well and every one of the production-observationwells located within the former's zone of influence. This interpolation was made according to the logarithmic law corresponding to the elastic regime of filtration in a stationary state. Pressure increases in the production wells were not uniform. For this reason, the lack of uniformity in parameters of filtration along the lines: injection well-production well had to be taken into account when constructing the maps of pressure fields. An isobar map showing the stationary field of injection is given on Fig. 45.

88


Fig. 45. Isobar map. Numerator: well number. Denominator: pressure in kg/cm2. Wells: 1-production; 2-injection.

I

1

1 4 1 2

According to this map, during the block steaming, the average formation pressure, weighted for this block, amounted to 10.1 kg/cm2., Prior to the treatment this pressure was 8 kg/cm2. Thus, the character of the pressure field prior to and then during the steam injection did not change much. As with the pressure map, also in constructing the isothermal map, all temperature readings both in the injection and in production-observation wells were brought up to the moment at which steam injection was discontinued. Chekaliuk and Oganov have shown in their work [26] that within the system represented by the formation. its thermal field must somehow correspond to its pressure field and that, at specific points in time, the differences in temperatures measured in individual wells correspond' to the differences in pressures. These correlations do develop providing that: (a) the conditions within this system have been stabilized, (b) specific conditions do exist in the elastic bed and (c) the flow rate of heat carrier proceeds at a fixed rate. In an earlier study, Garushev [6] also considered these factors and proposed an approximate logarithmic formula for the interpolation of temperatures between the steam injection (thermal) well and each one of the production-observationwells. This formula took the form: At (r)=A-w log r, where: At (r) - the difference between temperatures stabilized in the injection well and in the production-observationwells, in O C A - a section on axis At, equal to At max, cut off by a sloping straight line constructed within coordinates At and log r w - angle of slope, in degrees. The constructed map of thermal fields corresponds to the stabilized injection of the heat carrier into the formation (Fig. 46). 89


Fig. 46. Map of thermal fields. Numerator: well number. Denominator: temperature in OC. Wells: 1-production; 2-injection.

E

-

l

/

q

j

r

The comparison of pressure field with that of the temperature shows their outward resemblance. It was to be expected, inasmuch as logarithmic formulas were used in both instances. Noticeable in both fields are weakly interacting zones (ovals) of pressures and temperatures. Obviously, the identical structure of the formulas used for the interpolation cannot, by itself, account for this resemblance of the two fields. This conclusion is based also on other evidence. The similarity of the two fields is detected with simple linear interpolation, but this is known to be incorrect. Furthermore, the likeness of the two fields was detected in observations and measurements ancillary to commercial production and recorded over prolonged time periods on such things as: (a) the rate of water inflow into the wells, (b) the change in oil yield and (c) the mineralogicalcomposition of the water.

10.

RESULTS OF RESERVOIR STEAMING UNDER EXPERIMENTAL CONDITIONS IN PRODUCING FIELDS

10 a.

~QMBX~!EP_STEAMI~~-A~R-~A~~~-~~QQ~~~~-~~-S~~H

Principal reserves of high viscosity oil in Sakhalin are found at the fields of Okha, Katangli, Uiglekuty, Vostochnoe Ekhabi and Zapadnoe Sabo. The production from these fields by primary methods, also by secondary methods other than thermal, was not very effective. For the majority of these fields, the total recovery factor, even after 40 years of production, did not exceed 20%. 90

Petroleum Production Employing Heat Carriers In 1968, the steam flooding was started first at the Okha field and then at the Katangli and Vostochnoe Ekhabi fields. The Okha fiefd reservoir is formed by a doubly plunging anticline. This structure is complicated by numerous gravity and reverse faults, some of which cut the anticline transversely, others diagonally. Thus the trap is divided into 10 discrete blocks. Within these blocks oil is found in beds No. 3,4,7 and 8. These beds form separate oil reservoirs, each confined within its own structure contour lines. Eighty percent of the Okha field oil reserves is found in these four beds. Their cumulative thickness averages 22-36 m Reservoir rocks consist of poorly cemented sands that lie buried at depths ranging from 100 to 950 m. They show porosity of 27% and permeability of about 1500 millidarcies and contain oil with gravity of 0.92-0.95 g/cm3. In 1968, bed No. 4 of block X was selected for EOR tests by steaming method. Experimental work was then carried out in 1971 to develop a steam treatment plan for all of the principal producing beds in the Okha field. The technique consisted of steam flooding followed by cold water flooding to drive the steam front through the reservoir rocks. Beds No. 3 and 4 were treated separately, beds No. 7 and 8 together. The volume of steam injected into the individual beds equaled 0.3-0.5 of the pore-space volume of each reservoir. In determining the steam volumes, proper consideration was given to the spacing of wells. According to calculations this treatment should result in a final recovery factor of 52% of the original oil in place. The steam consumption is 2.0 t per ton of oil. In subsequent years this combined steam-water flooding was greatly extended. By the end of 1975, part of the Okha field that originally accounted for 26.4% of Okha field's total reserves of oil in place was producing by this technique (Table 22). Very good results were obtained in the Sakhalin oil fields by application of this technique. In the course of 8 years it resulted both in an increase and stabilization of oil production. In 1979, 25% of the total oil obtained that year from the Sakhalin oil fields was produced by this EOR technique. All in all, 4 million tons of steam and about 4 millions m3 of water have been injected into the producing beds.

Table 22. Basic production data at the Central Okha oil field

Yea isfpI rn I 1 2 L 4 56

Oil production, thousands of tons: -using steam injection and water flooding .47.4 171.6 196.1 223.6 -without steam injection and water flooding 00.7 98.2 97.8 94.5 Volume of injected steam, thousands of tons 56.0 245.7 163.1 473.1 Volume of injected water, thousands of m3 25.8 154.9 !74.0 4 15.5 Number of wells: producing 793 824 805 824 injection 42 19 52 27 Oil production cost per ton, in %:* -with steam injection and water flooding 100 103.7 100.7 93.0 -without steam injection and water flooding 100 104.2 105.0 106.2 Annual economic effect, in 'OOO of Rubles 043 465 !231 3378

* 100% probably means that production costs were

821 58

307 83

107.3 117.4 114.3 121.9 3046 !992

-

illy recovered from operati g inc me.

In 1980 the rate of water injection exceeded that of steam injection. 91

240.8 254 82.7 75.9 648.6 635.6 539.7 722.9

Thermal Methods of Petroleum Production At the Katanglijield the steam flooding experiment started in 1969. In this study the steam is being injected into the producing bed No. 1 of the reservoir block No. I, within a surface area of 14 ha (Table 23). Katangli field is formed by an anticlinal fold whose structure is complicated by faults. Three separate beds, numbered 1 , 2 and 3. make up the oil reservoir in this block. All three consist of unconsolidated sands. This block (No. I) has the following reservoir characteristics: depth of producing beds: 80-150 m; thicknesses: 18-35 m; porosities: 29-32%; permeability: 3.85 Darcies; degree of oil fill: 71-75%; oil viscosity at the reservoir temperature of 7OC: 2000 centipoise; specific gravity of oil:0.936 glcm3.

During the 40 years of production that preceded the EOR by steaming, the recovery coefficient amounted to approximately 14%. At the same time. with well spacing ranging from 1.2 to 2.0 hdwell, the water saturation of the reservoir reached 80%. Production was by gravity drive augmented by weak water drive from below the oil water contact. In the course of subsequent EOR treatment, a total of 529,200 t of steam was injected, resulting in 195,400 t of additional oil yield. All in all, the application of steaming at the different fields of Sakhalin resulted in the recovery of more than 2 million tons of oil.

The reservoir of this field is formed by a thick, gently sloping sandstone bed belonging to the Zhivet stage of Middle Devonian age lying at the depth of 180-200 m. principal characteristics of the reservoir are as follows: thickness of the producing bed-up to 30 m; porosity-up to 24%; permeability-up to 3-5Darcies; initial reservoir pressure-up to 15 kg/cm2; reservoir temperature6OC; oil viscosity at reservoir temperature - between 11,000 and 15,000 centipoise; specific gravity of degassed crude496 glcm3; oil saturation coefficient-from 0.42 to 0.98. Numerous faults with throws of 6-8 m broke up the reservoir into a number of separate segments, each 10-30 m in length. The development and production of the Yarega oil field passed through the following three phases: I. Production by conventional oil wells drilled from the surface: Well spacing ranging from 70 to 100 m was employed. The very low recovery factor attained by conventional wells first suggested the employment of a mining method.

92

Petroleum Production Employing Heat Carriers 11. Production by mining: From 1939 on, 3 mines have been in operation at the Yarega field Two different variants of mining method were used: 1. Ukhta system: The access drifts and drilling chambers were completed in the tuffite caprock.just above the reservoir. A dense network of straight shallow (less than 50 m deep) wells, 12 cm in diameter, with well bottoms spaced at 12-20 m were drilled from the chambers into the reservoir sands below. 2. System of slanted wells: The main access and ventilation drifts were also situated in the tuffite caprock above the reservoir. At 150 m intervals, inclined openings (winzes) were then driven from the main drifts downward into the upper part of the reservoir. Drilling chambers were then cut at that level at the end of each winze. Low angle as well as horizontal production wells, each 200 m long were drilled radially from these chambers. The bottoms of these wells were not more than 15 m apart. Each cluster of these production wells drained a hexagonally shaped area of 8-12 hectares. (Fig. 47). Using this system, the volume of mining excavation that had to be performed amounted only to one-third of that required with the Ukhta system. Because of this advantage, beginning with 1954 a changeover to the new system was undertaken at the Yarega oil fields. Towards the end of 1960s, substantial increase in the average oil recovery was reportedfor the part of the Yarega field worked by the mining method. The spacing of wells used varied within wide limits. But, as experience of 13 years of oil production by this method showed. smaller spacing of wells by itself, even when carried to the extreme, did not result in a higher recovery factor. 111. Production by mining-steaming method combined. Field testing of this method started at the Yarega field in 1968. During a five-year period, a large amount of expenmental work was completed under field conditions. It led to the decision to carry out the complete changeover to the combined mining-thermal method. At first, the Ukhta system was used in the experiments. Production wells were drilled around single steam-injection wells at distances from 2 to 20 m from the latter. Very good results were obtained with close spaced grids. Thus, 63 injection and 71 production wells were drilled in an experimental section of only 1.8 hectare. With steam consumption of 3.5 t per each ton of oil produced. a recovery factor of nearly 40% was attained. Following this experimental work. other petroleum mines of the Yarega field started using this system commercially. Simultaneously with continued testing and field employment of the combined, Ukhta mining-steam ireatment method, a new variant, utilizing the system of slanted wells was also being developed. This two-horizon or two-level system of thermal treatment can be described as follows: Steam is injected through wells drilled from chambers located in the overlying tuffite caprock. The oil is produced through the low angle and horizontal wells drilled from the chambers cut at the bottom of inclined winzes in the top part of the reservoir bed (Fig. 47). The changeover to this new two-horizon system began at the end of 1971. It was applied to all sections of the Yarega field that were being treated with steam. To that end, wells were drilled into the gently dipping sections of the reservoir bed. A sloping reservoir block with a surface area of 10-15 ha was initially chosen for production by this method. Spacing of 200-300 m was used for the steam injection wells. During the 2.5-3 years of production, the average yield per day amounted to 200 tons with steam consumption of 2.5 tons per each ton of oil. The recovery factor was 40-50%.

93


Cyclic steaming of bed

Oil displacementby water

Design of injection wells

d=32

MN

t Fig. 47. Combined mining-steaming method of oil extraction.

94

Program to develop effective steam EOR techniques for high viscosity petroleum. pperimental and physical studies 1

I

Determining the relationship 1

equipment including testing of .

Experimental and oil field work to test different technological variants of steamine method

I

Effectiveness of one-time Isteaming treatments

I

1

I

Schemes for commercial scale amlication of enhanced oil

Studying the effectiveness of steaming in abandoned (nonproducing) wells

I

I Air I

Hotwater

Studying the effectiveness o repeated steaming treatments

I Steam ]

I I

Farge steam volume treatments

I

I

1

Presentation of basic process an engineering data for plannin

from reservoirs with macro\o vI

I termimng e e echveness o steaming depending on degree of water N1

I

steaming following primary mxluction.

s3 c

a .,P g. B

I

I

I

La

Development of a special heat resistant pump for lifting viscous petmleum from the well prepbation of the physical model of producing bed

Multifaceted and detailed1 eological study of the oil fields.

bottom zone and within the reservoir by means of electronic

Thermal Methods of Petroleum Production The experience at Yarega in applying the two-horizon method of thermal treatment showed that it is possible to reduce the steam consumption down to two tons per each ton of oil produced while attaining the ultimate recovery factor of more than 50% (Table 24). To get these results the following measures were employed: the technique of the two-horizon system was refined, also at a certain stage of thermal treatment, a changeover was made from steam injection, first, to that of the waste hot water from industrial processes and, ultimately, to cold water. The savings obtained during the period 1973-1975 at the Yarega field through the application of this thermal treatment amounted to 1.8 million rubles. This cost saving was due to the increase in the current output of oil and the enhancement of the oil recovery factor, both of which were attained with a lower capital investment per each ton of additional oil. Table 24. Data on thermal treatment at Yarega oil field.

Based on this new technology, combining petroleum mining with thermal treatment of the reservoir, a general plan has been proposed to increase the oil production at Yarega in several annual increments from 340,000 tons in 1978 to l,OOO,OOO tons.

Within 10 different fields in the Apsheron Petroliferous Province 48 individual oil reservoirs have been identified as suitable for steaming treatment. Selection of these reservoirs was based on the detailed study of basic geological as well as current oil production data. They all lie at depths of less than lo00 m. In Azerbaijan, the field tests on frontal displacement of viscous oil by steam flooding began in 1969. First experimental work is being carried out (1980) in the Khorusuny reservoir of the Balakhano-Sabunchino-Romanin field. Pertinent reservoir data are as follows: surface area-55 hectares; reservoir rock-a sandstone bed designated as PKsv ;depth of the pay zone-between 400 and 600 m; effective thickness-15 m; permeability-218 millidarcies; oil viscosity under reservoir conditions-55 centipoise; specific gravity of oil-0.934 g/cm3.The oil contains 30 % of tars and 1.26 % of asphalts. Oil recovery factor at the beginning of steam treatment was 0.25. Steam injection started in April 1969 in the northern part of the area, and in December 1970 in the southern part. During the period from 1969 to 1976, a total of 350,000 t of steam was injected into the reservoir, yielding an additional amount of 24,000 t of oil (Table 25). Starting in January 1974, cold water was being injected into the Khorasany reservoir in order to displace the heat bank. As of 1980, 144,000 m3 of water was injected and resulted in the recovery of approximately 24,000 tons of additional oil. 96


Steam flooding treatment was also carried out on the Binagady-Kirmakin reservoir. Pertinent data for this project was as follows: surface area-59.2 hectares; pay zone treated producing bed KSSa+b; depth of reservoir-between 250 and 500 m; effective thickness of the reservoir bed-12.5 m; permeability-59 millidarcies; oil recovery factor-O.19; oil viscosity under reservoir conditions-30 centipoise; specific gravity of o i l 4 9 18 g/cm3; tar content-30%, asphalts 1.2%. Steam injection began in August 1972 and it was terminated in December 1978 (Table 26). Table 26. Basic data on steam treatment of Binagady-Kirmakin reservoir.

tons produced, tons

Although steam is no longer charged into some of the injection wells, the production wells located within the zone of original thermal treatment continue to produce with higher oil yields. At the reservoir Puta-Kushkhana, steam flooding treatment began in January 1974. The salient data for this reservoir are as follows: surface area-29 hectares; depth to producing horizonfrom 610 to 660 m; effective thickness of the bed-I8 m; permeability-10 millidarcies; crude oil viscosity under reservoir conditions-23 centipoise; specific gravity4915 glcm3; tar content-30%. During the first 5 years of steam treatment an additional 4,600 tons of oil have been produced from the Puta-Kushkhana reservoir. Overall, increased oil yields were recorded from every reservoir subjected to steam flooding. However, any one of the following causes, whenever present, significantly reduced the effectivenessof the treatment: (a) Inadequate geological study and preparation of the reservoir for steam flooding. (b) Plugging of the producing wells with sand entering with the oil. (c) Lack of reliable means of lifting the oil to the surface. 91


(d) Shortage of fresh water for steam generation. In addition, other causes of lesser significancecould also be listed. Whenever the steam injection is interrupted,the steam gives up its heat to the reservoir rock and ceases to be a heat carrier. Should the steam injection then be renewed, additional heat loss occurs. This factor lowers the effectiveness of the steam flooding process and increases the expense of producing each ton of additional oil. Moreover, when the regime of continuous steam injection is disturbed, the drop of pressure and temperature within the reservoir gives rise to a reverse flow of the condensed hot water. The latter then enters back into the bottom of the injection well, carrying with it a large amount of sand. The reservoirs of the Azerbaijan oil fields are made up of poorly cemented unconsolidated sands. The experience of commercial production from these fields shows that any sharp fluctuations in the heat regime within these beds must be avoided. Otherwise the bonds holding the sand grains together break down, causing intensive sand plugging of the wells.

1 0d . S T E ~ T B E A T M E ~ I T A T _ K E ~ ~ I A ~ ~ Q X ~ ~ E I E ~ R ~ I ~ I ~ I ~ K This petroleum trap is formed by an asymmetric doubly plunging anticline broken up by faults into four separate reservoirs. The treatment was designed to steam the temgenous sediments of producing strata I and I1 belonging to the Middle Jurassic age lying at the depth of 300-350 m and consisting of alternating sandstones, siltstones and shales. Within the selected reservoir, the thickness of the oil saturated sand was 25.7 m, porosity-30.5%. permeability4 Darcies, degree of oil saturation-72%, oil viscosity at 2WC-180 centipoise, oil density4915 g/cm3. Back in 1968, the All Russian Petroleum Research Institute designed a steam treatment which was first used in this experimental sector. Then, in 1972, the project was extended to include the entire Kenkiiak field. This plan calls for displacement of oil by steam flooding. The volume of steam to be injected in the reservoirs of the Kenkiiak field is to equal 56% of the pore volume. Cold water will then be injected in order to move the steam bank. Attainment of a recovery factor of 44% is expected to result from this treatment. The anticipated steam consumption is 2 tons per each ton of oil.

1

2

3

Years 4

5

Amount of additional oil produced, 1OOO's of tons

5.6

20.5

45

50

64.9

65

Amount of injected steam, 1OOO's of tons

13.4

47.2

105

110

109

128

2.3

2.3

2.2

1.8

2.0

Steam consumption, ronshon of oil

2.4

6

The planned treatment of the Kenkiiak field on an industrial scale began in 1973. Since then, in the course of 6 years, 648,000 t of steam has been injected, resulting in an oil yield of 98

Petroleum Production Employing Heat Carriers about 300.000 t. As originally planned, 10 injection wells are being used. Further increase in the scale of operation at the Kenkiiak field will require the employment of additional steam generators to supplement the 4 that are currently used. Moreover. a number of technical problems will have to be solved in order to prevent sand production from the wells.

Recent field experiments show that thermal treatment can also be effectively employed to produce low viscosity crudes. Many reservoirs contain a large amount of residual oil of this type. Thermal EOR methods become therefore potentidy very important also on this account. In Russia, the first studies in this field were carried out by scientists and specialists in the Ukraine. The following institutes participated in this work: The Ukrainian State Project Scientific Research Institute, the Institute of Hydrology, and the State Hydrology Institute of the Ukrainian Academy of Science. These institutes proposed the following two methods of heat treatment: (1) the combined method, (2) the water injection method using high thermodynamic parameters. Combined method: The most important feature of this thermal method is its two-stage character. During the first stage, steam is charged into the injection well. A high temperature zone, also called heat bank, forms around the bottom of the injection well. This zone has definite dimensions, encompassing from 25 to 50% of the volume of the petroliferous bed. During the second stage, cold water is pumped into the same injection well. Upon reaching the earlier steamed zone, the water absorbs heat from it and carries it deeper into the bed. In the process. some of the water also turns to steam. This two-phase mixture of steam and water filters through the oilbearing strata, resulting in a wider heat penemtion both thickness-and area-wise. A more complete displacement of oil from the reservoir is the result. The combined method of thermal treatment has already been tested on an industrial scale in a reservoir containing low viscosity oil. Sector MEP of the Boryslaw oil field was chosen for this study. The oil bearing sandstone belonging to the Yamen horizon of the Albian (Tertiary) age was selected for treatment. It lies at the depth of 450-500 m and contains crude oil with viscosity of 5-7 centipose. From 1971 on, this reservoir has been treated by the combined method on a large scale. Preliminary results indicate the steam consumption to be 2-3 tons per each ton of oil. As a result of this treatment, the rate of oil production from this sector of the field increased by several times. The rate of flow of the wells increased 3-8 times, resulting in greatly improved econhics of production. The results obtained by the Ukrainian State Project Scientific Research Institute at the sector MEP of the Boryslaw field served as the basis for planning of steam-water treatments of certain other reservoirs. The method was used on the oil-bearing sand of the Yamen horizon at the Urich oil field and on the petroliferous Stryj strata of the Miriam sector of the Boryslaw oil field. The combined method of thermal treatment is particularly suitable for use in small oil fields found on the territory of the Ukraine that have been worked already for many years. According to the estimates of K.A. Organov, this particular method of thermal treatment, once applied on a broad scale in these fields, will yield 300,000-500,000t of additional oil annually. Water injection using high thermodynamic parameters: This is the second method of thermal treatment proposed by the aforementioned Ukrainian research institute. It calls for injection of water heated to temperatures of 320-34OOC under pressures of 160-220 kg/cm2. At these temperatures and pressures water, independently of its physical properties, does become a good solvent of crude oil. It means that the mechanism of oil removal from the reservoir rock is based in 99

Thermd Methods of Petroleum Production

this method on the dissolution of oil in the superheated water. Unfortunately, so far, this method has been tested only under laboratory conditions. 1O f .

H I P H _ T E M E E B A T Y B E _ ~ A T E R - A S - A ~ - E E E E € TEI -YS P L Y ENIT

ASSYBI~P_HIPBEST_PIL-~E€PYEEX At the present time, this method of attaining higher oil recovery factors has drawn the attention of both scientists and researchers. Within certain areas of temperatures and pressures, it is possible to attain unlimited mutual dissolution of oil and water. These parameters were determined during 1970 in laboratory experiments conducted by the Institute of Hydrology and the State Hydrology Institute of the Ukrainian Academy of Science [26,27]. At temperatures of up to 300OC and pressures of 210-220 kg/cm2, the recovery factor for crude oil with viscosity of 17 centipoise was 42.7%, and for crude oil with viscosity of 4.6 centipoise, up to 48.2%. When the temperature of injected water was raised to 305-310OC, in the case of sample No. 1, and to 310-32OOC, in case of sample No. 2, with the pressure unchanged. the oil recovery factor increased sharply, attaining .975 and .997, respectively. These figures indicate almost complete dissolution of oil and water in each other directly within the porous media. Down to the depth of 1000-1200 m, with reservoir pressure of 150 kg/cm2 and temperatures of up to 340OC. the water vapor can act as .an effective thermosolvent. At depths exceeding 1500 m with reservoir pressures above 160 kg/cm2 and at temperatures of 34OOC. water in liquid phase is also capable of acting as a thermo-solvent. These data were determined in a series of experiments. lt is a well known fact that water vapor is an economical and effective technological solvent of oil. However, due to heat loss and condensation, water vapor cannot be readily transported over any significant distance. For this reason, the steaming treatment is. in practice, limited to oil reservoirs lying at depths not exceeding 1200-1500 m. On the other hand, at certain temperatures and pressures, water can be used as an industrial solvent to extract crude oil from reservoirs lying at depths of up to 5 km. At pressures of close to 200 kg/cm2 and temperatures of 320-34OOC. practically unlimited solubility of oil in the water is attained [26]. To be used for injection of water with parameters high enough to assure the dissolution of oil within the reservoir, the heaters will have to meet the following performance criteria: high output rates and ability to heat the water up to 400OC at pressures of up to 250 kg/cm2. At the same time, it will be necessary to solve other related problems such as protection of well casing from the effects of high temperature. The Ukrainian Scientific Research Institute of Exploration Geology is studying methods of lowering the critical temperature at which oil dissolves in water. In experiments, certain stimulators such as carbon dioxide, alcohol. and ammonia have been added to water. The Institute completed a cycle of experiments on solubilities in the system: distilled water-carbon dioxide-degasified oil [26]. The crude oil for the experiments was taken from the Dolin oil field. During the series, the initial content of carbon dioxide in the water m g e d from 4 to 41 cm3/cm3. The experiments were carried out at temperatures of 300-32OOC and pressures of 350, 300,250 and 200 kg/cm2. Results showed that the addition of carbon dioxide as a stimulator makes it possible to lower the temperature of injected water. This reduction amounted to 20-25OC and 25-3OOC for pressures fixed, first, within a range of 300-250 and then changed to 250-200 and 200-150 kg/cm2. For planning an experimental project under field conditions, the following parameters are suggested [27]: depth down to the oil-bearing bed, m ... 1700 and less effective thickness of the bed, m ... 20-30 permeability of the reservoir rock, millidarcies ... above 100 100

Petroleum Production Employing Heat Carriers pattern of producing wells ...5-7 and 9 spacing between wells, m ...200-300 residual oil saturation, % ... not less than 40%. At this time (1980), preparations are being made to carry out an experiment on petrolierous bed P3, in a sector of the Gnedintsev oil field belonging to the Ukrainian State Oil Monopoly (Ukraine Oil). The unit selected consists of one injection well and six producing wells. Reservoir bed, P3, has permeability of 100 millidarcies, allowing the injection of a heat carrier at the rate of 55-60 t/hr. To supply the heat carrier, a plant will be used with an output rate of 40 t/hr. It will heat the water to 325OC at the pressure of 160 kg/cm? According to the design calculations, a volume of 1,600,000 t of heat carrier will be injected during a 3-year period. Then, during the subsequent 2-year period, the heat bank will be displaced by injecting a volume of 2,600,000 t of cold water. During the entire period, this experiment is expected to produce 500,000 t of oil. The authors believe that the above described method of dissolving oil with water can also be widely employed with "fireflooding" in which the thermal processes will take place at grater depths. Wellbottom heat generators are now being designed for use with the new method. Under this system, the cold water will be injected from the surface. As it passes through the generator at the well bottom, the water will be heated to 340-4OOOC under suitable pressures to become a thermo-solvent. For deep oil fields such method may be very economical.

101

Part 11.

PETROLEUM PRODUCTION BY IN SITU COMBUSTION (FIRE FLOODING)

1. mARACTERISTICS OF IN SlTU COMBUSTION EOR METHOD

As a method of oil production, the in situ combustion is designed to act upon the petroliferous bed as a whole. This method was first proposed and developed in Russia [28]. In brief, it can be described as follows: Two types of wells are distinguished; ignition and production. As the first step, conditions are created in the botttomhole zone of the ignition well necessary to initiate combustion, and then to sustain it along uniform front. Bottomhole fuel-fired burners, electric heaters or chemical agents can be employed for that purpose. Once a combustion front is formed, an oxidizer, such as air,oxygen-enriched air, or an oxygen-containing gas mixture is injected into the well. The quantity of the oxidizer fed into the well must be sufficient to sustain the thermal reaction and to insure continued advance of the combustion front within the bed. In this process, up to 15%of the oil in place is consumed and the heat generated acts upon the bed helping to push the oil out. The products of the in situ burning, namely: crude oil, combustion gases, hydrocarbon gases, and water, are then withdrawn through the producing well. Two basic variants of in situ combustion method are differentiated: directflow and counter flow. In the directflow variant, one and the same well is used both for the ignition of the oilbearing bed and for the subsequent oxidizer injection. Thus, the flow of the oxidizer and the advance of the burning front is in the same direction, namely from the injection well to the producing well. With the counter flow variant, the bed is ignited through one well and the oxidizer is injected through a different well. Upon initiation of burning in the ignition-well zone, the oxidizer is then supplied through the injection well into the oil saturated but still unheated part of the bed opposite the moving center of combustion. The products of this thermal process, that is: steam, gases, and crude oil. are then displaced through the burned-out zone towards the ignition well, the latter now acting as the producing well. The counter flow variant was developed specifically for deposits containing either wholly immobile crudes or bitumens. In these instances the direct flow variant is practically useless. Additionally, variants have been developed that combine the in situ burning with other thermal EOR methods. The in situ combustion method can also be employed as a means of treatment, such as the stimulation, of the bottomhole zone of oil wells. In case of the direct flow variant, the temperature distribution curve has the following character: a high rise along the combustion front, a sharp drop immediately ahead of the combustion front extending in the direction of flow of the injected air, and finally a gradually declining curve behind the front of combustion. The different thermal zones that form within the oil-bearing bed as the burning front advances are shown on Fig. 48. In the zone of combustion the temperature may reach 400W or even more. 'At this temperature, all liquids vaporize completely. In this process, the heavy fractions of crude oil are deposited as coke residue on mineral grains of the reservoir rock. It is t h i s part of the crude oil that serves as fuel for in situ burning. 103


Fig. 48. Spreading of the combustion front within the petrolifemus bed. 1-injection well; 2-the steam plateau; 3-production well; 4-burned out zone; 5-the combustion front; &steam zone; 7-bank of hot water and light hydrocarbons; 8-crude oil bank. Ahead of the combustion front forms the steam zone with temperatures already down to the range of 93-204OC. Farther out, oil and steam condense, giving rise to a ring of hot water and light hydrocarbons. Finally, ahead of this bank of hot water and light hydrocarbons forms another front, this one consisting of the crude oil itself. The temperature in this zone is the same as that of the formation. In each zone. the temperature determines the mechanism of heat exchange and of crude oil displacement from the bed. Thus, in the steam and hot water zones, the oil is displaced from the formation by the steam and hot water; in the zone of light hydrocarbons, by the nascent miscible liquids; and finally, in the still unheated zone, by the gases generated in the process itself and acting on the crude oil at normal formation temperature. In a way, practically all of the known EOR methods are therefore naturally utilized during the in siru combustion process, to wit: the formation steaming, hot water flooding, also miscible liquids and gas injection. For crude oil, the material balance equation of the in situ combustion process can be written as follows [28]: 10 = Iop + Icr + Ihg where:

10 - oil in place in the formation prior to application of the process Iop - amount of oil produced as result of process application Icr - amount of oil consumed as coke residue to sustain the in siru combustion process Ihg - amount of hydrocarbon gases generated during the process

The formula for calculating oil recovery factor (coefficient)of the in situ combustion can be expressed thus: where: &il- oil recovery factor Scr - coke residue as a percentage of the volume of total pore space of the formation (reservoir rock) 104

Petroleum Production by In Situ Combustion (Fire Flooding) Sgc - hydrocarbon gas content as a percentage of the volume of the total pore space; this gas is expressed in terms of gas equivalent original crude oil Sos - initial oil saturation (expressed as a fraction of 1)

where: gr

- ratio of the mass of coke residue to the mass of the reservoir rocks (rock mass of

the formation)

- density of the reservoir rock, kdm3 poi1 - density of the original crude oil, kdm3 m - rock porosity, in fraction of 1

Qt

- specific consumption of air per unit of the mass of coke residue, m3kg - heat generating capacity of the gas obtained in the process of in situ combustion,

Qoil

- heat generating capacity ofthe initial crude oil, kcal/kg

where: vres

k cum3

It must be also taken into account that the advancing burning front leaves out pm of the volume of the oil-bearing bed. The total or summary oil recovery factor for the bed as a whole is therefore calculated according to the formula:

Kmt = AVK,,~+ n( 1-Av) where:

Kbt - summary oil recovery coeffecient for the burned bed as a whole Av - coefficient (degree) of envelopment of the reservoir rock by the combuspon front Koil - oil recovery factor (coefficient)

The relationship between the initial oil saturation and the oil recovery factor (K,,il) during the in siru combustion process is shown on Fig. 49 [28]. The quantity of the coke residue that forms during the in situ combustion depends on: a. properties of the crude oil (e.g., its tar content), b. characteristics of the petroliferous bed (e.g., its porosity and degree of oil saturation), c. regime of the process (e.g., the temperature and rate of advance of the burning front).

105

Thermal Methods of Petroleum Production Fig. 49.

Original degree of oil saturation, %

1-

Relationship between oil recovery factor and the original degree of oil saturation during the in situ combustion process. (Assumption was made that the original oil saturation did not have any effect on the quantity of coke residue).

Pail = 800 kg/cm2, porosity (m) = 30 % 2 - Poi1 = 800 kg/cm2, porosity (m) = 20 % 3 - Pail = 1.000 kg/cm2. porosity (m) = 30 % 4 - Pail = 1.000 kg/cm2, porosity (m) = 20 %

formation formation formation formation

A.A. Abbasov has studied how the quantity of residual coke changes depending on the density and viscosity of the crude oil and its H/C ratio and C content. In his published works, Abbasov gives these data for a number of crude oil types. The relationship between the volume of air necessary to complete the combustion process in one volume of oil saturated rocks and the density of the crude oil is shown on Fig. 50. Fig. 50.

0 1,0

0,934

0,876

0,825

Relationship between the density of crude oil and the specific quantity of air required for i n situ combustion in formations with porosities (m) of 120%. 2-30%. 3-40. Oxygen utilization coefficieitis 100%.

Crude oil density, g/cm3 Fig. 51 shows experimentally determined relationships between the viscosity of crude oil and the oil recovery factor [32]. The curves show that, as an EOR method, in situ combustion is more effective than water flooding. In situ burning is especially suitable for deposits that contain heavy oil. With the application of the counterflow variant, the oil recovery factor increases up to SO%, and with the direct flow variant, up to 70% and higher [28]. During production of heavy crude the pores of reservoir rock in the unheated part of the oil-bearing bed often plug up. To remove these plugs, an oxidizer must be injected into the petroleum reservoir under high pressure.

106

Petroleum Production by In Situ Combustion (Fire Flooding) However, when the petroleum reservoir lies at a shallow depth, increasing the pressure may lead to the formation of bypass channels that divert the oxidizer flow. Fig. 51.

Dependence of oil recovery factor on viscosity (cSt) of crude oil during production using: 1- i n situ combustion process (with original oil saturation of 80%). 2-water flooding (at water saturation of 90%).

Oil viscosity, c Standard

In siru combustion makes it possible to put in production some oil fields whose reservoir characteristics have been already fully determined, which, however, cannot be exploited by any other method.

Not all petroleum reservoirs can be exploited successfully by the in siru combustion method. The applicability of this method depends on such factors as depth to the oil reservoir, thickness of the oil-bearing bed, amount of oil in place within the reservoir, degree of water saturation of the petroliferous formation, specific gravity of the crude and its fractional composition. reservoir pressure, geological type of the oil trap, physical characteristics of reservoir rocks, and the initial oil recovery factor prior to fiie flooding. All of these factors must be thoroughly studied before it is decided to apply the in situ combustion method. Some favorable parameters are as follows: a. b. C.

Reservoir depth not greater than 1,500 m; the smaller the depth the lower the capital costs for equipment and installation for oxidizer injection into the reservoir; Petroliierousbed with a thickness of 3 to 25 m; Residual oil saturation of not less than 50-60%;with initial water saturation not greater than 40%;

d. e.

f.

Viscosity and specific gravity of the crude oil can vary within a fairly wide range but viscosity should not be less than 5 centipoise, and specific gravity not less than 0.82 glcm3; Porosity of the reservoir rock ranging from 12 to 43% and more; these figures are based on field experience with fii flooding; formation porosity has great influence on both the rate of advance of the combustion front and on the pressure that is required for injection of the Oxidizer, Dissolved gas drive is the most effective production mechanism with in situ combustion but this method does not exclude the possibility of ulitizing other types of reservoir drives.

107


Experience shows that.it may take anywhere from several days to several weeks, or even months for the crude oil in the formation to ignite and then to form a combustion front. Air, oxygen, or air enriched with oxygen can be used as oxidizers to initiate the in situ burning. Oxidation characteristicsof crudes differ substantially,depending on their specific chemical composition and physical properties. According to the experimental data, the temperature of crude oil ignition in the bed varies from 150-4WC [20].

Sdf:k!iliQ!l When 0 2 is injected from the surface into the formation, the oil present in the reservoir oxidizes rather quickly. This oxidation reaction is exothermic. If the heat is generated fast enough and in amounts sufficient to compensate for heat losses, the petroliferous bed can ignite spontaneously,without additional heat from an outside source. Studies indicate that the ignition can be attained in a shorter period of time when formation temperature is higher (see Table 28). Table 28. Results of bed ignition studies carried out by L.K.Strange Thickness of oil-bearin, Specific gravitj of oil. g/cm3

air injection pressure prior to ignition, kg/cm2

iwhL total

effective

11.28 159.72 116.73

10.67 49.68 71.62

0.9799 0.9692 0.9770

30.6 51.7 29.4

152.40

67.06

0.9725

45.0

14.94 23.16 64.01

12.19 15.55 39.53

0.9854 0.9909 0.9593

14.5 66.8 10.5 (120 days) 15.5 (30 days) 31.6 (54 days) 33.4 (8 days) 83.3 63.3 28.1

60.0 51.7 35.0

* quantity of air

injected prior to ignition, looOm3lday

calculated time required to ignite the bed

15.447 28.3 14 2.832

100 17

33,980

150

56,630

62

84,950 5.154 25,490 9,061

13 9 24

60.65 27.43 0.9487 2 3 . 9 8 . 53 6 . 8 1 0 4 7 *! ange, L.1 , 1964, Bed: iition in application of thermal methods of oil production, Petroleum Engineer, Nos. 12 and 1 pp. 13-14.

It is very important to determine oxidation characteristics of the different crudes because the economic feasibility of inducing their self-ignition in the reservoir depends on them. When the specific rate of the oxidation reaction is known, then one can calculate the time necessary to ignite the formation. 108

Petroleum Production by In Situ Combustion (Fire Flooding)

The following formula is proposed by Strange: ti

' = tff

cfpje

_E Rt

Qj(p.S ...)Adt '

where: '-time necessary to ignite the bed, Cf - specific heat (capacity) of the saturated porous bed; Pf - specific gravity of the reservoir rock; Q - specific heat of reaction of oxygen that took part in the reaction; j(p,S)Ae-mt - specific rate of reaction of the oxygen that took part in the reaction; j(p,s ...) - function of oxygen pressure, of contact surface with crude oil etc.; A - frequency facm, E - activation energy; R - universal gas constant; - temperature; t ti - temperature of ignition of reservoir oil; tf - reservoir temperature. Values Cj and pf depend mainly on formation porosity and, in many instances, they are practically the same. The heat of reaction is also fairly stable for hydrocarbon components commonly present in reservoir crudes. The principal variable that has significant importance for spontaneous ignition of the petroleum bed is the specific rate of reaction. Its value can be determined in two different ways: (a) from the cores, (b) from an artificial sample of petroleum bed containing oil sand under simulated reservoir conditions. The time required for the spontaneous ignition to occur under actual reservoir conditions is, of course, longer than that calculated by Strange's formula. The difference is due to the heat losses that take place under actual conditions into beds lying both above and below the reservoir. However, a simplified calculation for adiabatic conditions does offer certain advantages. For example, if the time required to ignite the reservoir bed is limited to a few hours or days, then it is possible for spontaneous ignition to occur. On the other hand, if it takes several months or even years to ignite the reservoir bed, then additional heat from outside will have to be supplied, If the actual reservoir temperature is low and heat losses into the beds lying above and below the reservoir are high, then spontateous combustion will not take place. It won't occur even within the calculated adiabatic time period not exceeding several hours. Generally, even reservoir beds of considerable thickness can still be treated successfullyby thermal methods. However, the use of the in situ combustion method in such reservoirs creates certain problems. It is better in such cases when the reservoir holds crude oil that can ignite spontaneously on reaction with oxygen. Even then there is no guarantee that the process of in situ combustion can sustain itself. According to American researchers-Strange, Tranthach, and Scheiker-nditions can develop in thick oil-bearing beds which may give rise to a gravity drive. Upon heating, oil viscosity sharply decreases so that crude oil can flow again. Because of the gravity forces, it may start flowing towards the bottomhole of the injection well itself. In that zone, of course, the oxygen concentration is high. Therefore the rate of oxidation and, consequently, the amount of heat released in this zone are also high.

109


Nevertheless, oil ignition that is ultimately induced by oxidation does not begin directly at the bottomhole of the injection well. Why? Because as the air is being injected, it displaces the heat away from the bottomhale zone and drives it deeper into the oil-bearing bed. As a result, with the direct-flowvariant of in situ combustion,oil ignition in the bed first takes place at some distance from the injection well. In this manner, the process of in situ combustion may proceed from the ignition point in two directions: (a) towards the bottomhole of the injection well, (b) away from the injection well and farther into the oil-beaxing formation. Thus, in the bottomhole zone the temperature may reach high values. As a result, particularly in cases in which free crude oil has entered the injection well, great damage to well equipment may result even when heat resistant materials are used. Different protective measures are used to insure, to a degree. a damage-free application of this thermal method.

hilkSiQIl-Qfia.s i t u _ ~ Q m h ~ S i Q n Y r i - i ~ ~ Q ~ ~ ~ S i Q ~ f - h ~ ~ Crude oil present in some beds is difficult to oxidize and will not ignite spontanmusly. To initiate in situ combustion in such cases, different methods are used. The bottomhole zone of the injection well may be heated with special fuel-consuming downhole burners. electric heaters or with chemical reagents, Once the ignition temperature of the particular crude oil is reached and in situ combustion initiated, the oxidizer is supplied into that zone. In order to insure a stable and sufficiently big combustion front, the two operations are carried out either in succession or simultaneously. Charcoal in its different forms was sometimes used for that purpose. In Russia, this method was fist employed in the 1930s [28]. The downhole heaters are of two types: (a) fuelconsuming flame heaters and (b) electric. The flame heaters, in turn, can be of two subtypes: (a) diffusors. in which the fuel and the oxidizer are brought into the combustion chamber separately; and (b) mixers, in which the flammable mixture is brought into the combustion chamber already preprep&. Electric heaters are the type most widely employed for the development of the in situ combustion front. They are fairly simple and convenient to use. The specific types employed for bottomhole heating can last a long time, working at downhole temperatures of more than 7000C. They range in power from 10 to 74 kw. To enhance heat transfer, the space between the electric heater and the walls of the well, as well as the the cracks and fissures around the well should be filled with material of high thermal conductivity,e.g., metal particles. Sometimes it is difficult to initiate in situ combustion because the pores of the reservoir rock are plugged up with heavy crude. The heater should then be periodically turned off while still continuing to inject the oxidizer. Usually, after several such cycles, the permeability of the oilbearing formation increases. These operations should be repeated until the in situ combustion can sustain itself merely by continuing to supply the oxidizer. Now and then in this process, a stable in situ combustion is achieved after completing a few of these cycles. Studies have been canied out on at a number of oil fields on ignition of petroliferous beds and creation of in situ combustion fronts. The oxidizer consumption per unit of bed thickness determined in these studies ranged from 22 to 200 &day for each m of bed thickness (Table 29). Heat consumption per 1 m of thickness of oil-bearing bed ranged from 0.25 to 2.72 G cal. The specific amount of heat expended in each instance depended on the duration of heating and on the ignition temperatureof the oil present in the formation. 110

Petroleum Production by In Situ Combustion (Fire

Flooding)

In these calculations, the heat losses for generation of electric energy used up to compress the air injected into the bed were disregarded. Table 29. Data on artificial ignition of oil-bearingbedsL 3il Field

I

Thickness of producin bed, m

Type of

Heat Rated power consumption, of heater, Gigacdm kwor Giga CaVm

head

0.933 0.944

7 -I-

10.55

E E

45 I 45

1.32 0.743

Goodwill

230 984

(maximum)

0.811

rlew York3

Average rate of air injection during bed ignition, m3/day/m

I

118.3 5.5 6.1

__

0.938 0.969 1.001

I

6.0 15.12 21.8

E E E

I

I

920 24

57 1 %2 11960

29

24

(total)

E

24.4 18.3 9.1

0.33

45 1

F F

0.165 0.248 2.72

29 2.52G caUm 1.51

Delaware Childers,

15.6

0.84-0.85

F

0.826

3.02

865

rJiitsU,

10.1

0.945

F

1.817

4.03

929

2.7

0.916

F

___

F

___

Japan Southwest

___

&SaS

ihannon, Nyoming

10.1

I. Strange L.K., 1964. p. 12.

2.5

1122

Bed ignition in application of thermal methods of oil production, Petroleum Engineer, No.]:

!. Ignition not attained I. Access to oil-bearing bed through cut-out in casing

.. E-electric heater; F-flame heater

!!QLmaliQIl-QfShLfKQnLQf-iD.sitU-GQmhU.SliQn The energy input required to create a burning front may be fairly high. It is therefore important to determine as quickly as possible the moment at which the crude oil in the bed does actually ignite. The time period required for the ignition to take place and for the combustion front to fonn depends on such factors as oil formation characteristics, physical and chemical properties of crude

111

Thermal Methods of Petroleum Production oil, the method of ignition, type of construction, and the power of the downhole heater and on the bottomhole equipment of the ignition well. Change in the temperature gives the first indication that a combustion front has actually deve1op.d. To detect this change, a thermo-couple or some other heat-sensitive device is installed in the injectiodignition well. For more accurate temperature measurement, the oxidizerlair injection is interrupted while the reading is being made. This step is taken to reduce the cooling of the heatsensitive instrument. The moment in which the front of in situ combustion does form can be determined by analyzing gas samples taken from production wells. In most cases, gas breaks through into the production wells and can be detected very soon after the start of oxidizer injection into the ignition well. At first, the exiting gases are typically high in hydrocarbons, then, carbon dioxide, carbon monoxide, and oxygen also appear. Decrease of oxygen content in the gas usually signals the formation of the combustion front. Some crude oils react readily with oxygen and they quickly self-ignite when oxidizer is injected into the formation. In such cases, gases coming out of production wells either do not have any oxygen or contain it only in very small quantities. When air is used as the oxidizer, the gases obtained from the production wells may contain 8-16% C02 and 1-4% CO. However, Co;! gas readily dissolves both in formation oil and in water, and, for this reason, it may not come out at all for some time with the produced gases. On the other hand, CO is less soluble, and it is therefore more likely to appear in the produced gases as soon as the bed is ignited, although, generally, the CO concentration in the produced gases is lower than that of C02. The composition of gases generated during in situ combustion is the same whether the burning front has developed by self-ignition or was initiated by heat supplied from the outside.

Fig. 52. Drop in well receptivity to air at the moment of oil ignition

Fig. 53. Thermograms taken with a downhole electric heater at the time of oil ignition in the bed

Field practice shows that during bed ignition, at first both the rate of oil displacement from the bottomhole zone of the injection well and the receptivity of the well to air quickly rise. However, once the combustion front is formed, the receptivity of the injection well to air drops sharply (Fig. 52). This phenomenon is caused by "liquid barrier" to air flow. This blocking forms in the zone immediately ahead of the burning front and it acts to reduce the phase permeability to air entering the bed from the injection well. 112

Petroleum Production by In Situ Combustion (Fire

Flooding)

Later, as the front of in situ combustion shifts away from the well. the receptivity of the oilbearing bed to air may again increase or become stable. The specific time when the receptivity to air attains its maximum value only to drop sharply immediately thereafter signals the moment in which oil ignition in the bed occurs. The moment of ignition of crude oil can also be determined from thermal logs [35]. Curve 1 on Fig. 53 was recorded with the heater at position u. Obviously, the burning started in the upper 2.4 m thick section of the producing bed. The zone lying below the top 3.5 m thick section of the bed shows little temperature increase. Apparently, little or no air entered into that part of the bed. To maintain controlled conditions, the bottomhole zone was fiist cleaned and liquids removed, then the thermal log was run again, this time with the electric heater at position b. Curve 2 on Fig. 53 clearly shows that the ignition of crude oil in the bed did successfully take place.

M

.5 0 a

Fig. 54. h

0

Thermal logs taken with downhole gas flame heaters during the time of ignition of crude oil in the bed. a, b. c - heater positions

During thermal logging illustrated on Fig. 54. the control temperature of ignition was 250OC. Active combustion apparently took place at the depth of 6.7 m below the top of the

producing formation. However, it is entirely possible that the burning of oil was taking place only within the well column. Several hours after the first measurment (curve I), a second thermal log (curve 2) was run for control. It recorded the final peak value, which confiied the presence of in situ combustion within the bed. The burning process apparently continued even though the well itself was subjected to cooling in the time interval between the first and second survey. The facts discussed show that temperature measurements, together with analysis of the gases produced, when correctly interpreted, can reliably verify the presence of an on-going process of in situ combustion. 1d

.

Y S E _ P E _ ~ ~ T _ P I I P I Z E B ~ ~ ~S-[I'~U-CQMBUSTlQH ~~~T~~-QE-~~.

This method is gaining greater and greater acceptance in field practice. It offers two advantages: (a) the reduction of air to crude-oil ratio; (b) an improvement in both technical and economic parameters of the process. The addition of water to the air that is being injected greatly enhances the heat capacity of the gas stream entering the bed. Along the burning front, the dry injected air cannot receive the heat from the rock at the same rate at which this rock is being heated by in situ combustion. However, this heat generated in the burned out zone can be better absorbed from the rocks when water is added to the air. Moreover, when air-water mixture is injected, a large zone of saturated steam forms ahead of the combustion front, creating better conditions for displacement of the crude from the bed. The actual amount of oil produced by injection of moist air is higher than that prcduced by 113

Thermal Methods of Petroleum Production injection of the dry air because the steam and hot water that form in a zone far ahead of the combustion front strip some of the oil before it is burned. This partial removal of crude oil ahead of the burning front also means that the concentration of oil remaining in the bed is decreased. Consequently, the specific quantity of air required to complete the in situ combustion is also reduced. When the water-air ratio is increased from 0.002 m3/m3 to 0-.01 m3/m3, the temperature along the burning front is reduced and, in this case, the process of in siru combustion is called supermoist. The process of moist and supermoist in situ combustion enhances the utilization of heat generated in the oil-bearing bed. The heat is transferred into the zone lying ahead of the combustion front. In an extreme case possible under most favorable conditions, in this zone practically all of the heat generated during in siru combustion can be regenerated. The presence of a fairly large zone of steam ahead of the burning front allows much earlier termination of the combustion process than is the case with the dry air injection. This circumstance leads to reduction in air consumption by 2-3 times. Studies of the process of moist in situ combustion indicate that this method has great potential for application in oil field production. When employing this method, the water and air, in the desired proportions, can be injected either separately, alternating one with the other, or simultaneously,as a mixture.

The two general types of downhole heaters employed in the ignition well to start-up the combustion process in the bed are (a) flame heaters, using either natural gas or liquid fuel; and (b) AC-powered electric heaters. Variants of these two main types of heaters have been constructed in Russia and abroad. Natural Car Heaters: They can be of three different designs: (a) Injection heaters - fuel and oxidizer are fed into the heater separately; the oxidizer is injected into the heater in amounts necessary for full combustion of the gas (b) Mixers - natural gas and air mixture enters the heater already preprepared (c) Flameless heaters - natural gas and air mixture is burned in ceramic elements of different design Gas heaters of other designs also exist, e.g., diffusor heaters and micro-flares or microtorches. Depending on the design of the gas heater, it can be lowered to the wellbottom by a line, cable, or on the end of a string of tubing. Fig.55 shows a downhole gas-air flame heater. It is lowered on a cable (2) through suction-compression (production) tubing and is then positioned in the lower section of the tubing column. The fuel gas supplied from the surface also utilizes the production tubing to reach the heater. Through openings, the gas first enters the gas holding chambers (l), then, through other openings and the nozzle, it is directed to the ejector (4). Here, gas mixes with the air that enters the ejector from the annular space (7) of the well. The gas-air mixture then exits from the heater through the perforated tail pipe ( 5 ) and is set aflame by the ignition device (6). The use of the perforated metal sleeve insures a stable and uniform distribution of the gas flame along the entire length of the tail pipe. 114


The air/oxidizer is injected into the ignition well through the annular space. A portion of the air is forced into the heater by the injector. The remaining part flows on the outside of the heater along the tail pipe down towards the bottomhole. Here, the air flow insures combustion of the gas fuel and, by entering the formation, it also participates in the in sim oxidation of the crude oil. Fig. 55. Downhole gas-air flame heater. 1-gas chamber provided with inlet openings; 2-cable; 3-nozzle; 4ejector; %perforated 4.5 m long tail pipe enclosed in a perforated metal sleeve; 6-electrical or chemical ignition device affixed on the outside to the upper end of the tail pipe.

The heater can raise the bottomhole temperature of the well to 260OC in the course of 24 hours. Use of gas-air heaters of modified design has been proposed. One of these designs provides for attaching the heater to the end of the tubing string. A detachable piece with a system of narrow slits is mounted just above the gas chamber. The slits are used to prevent the penetration of the flame back into the tubing string. When the slits become plugged up. the entirc! piece is removed and replaced. Products of combustion go into a diffusor and from there go through the perforated tailpipe and out into the bed. In another variant a no-return check valve is installed between the diffusor and the tailpipe so that the flow of gases can proceed only in one direction. In heaters employing a microflare/microtorch system of combustion. both the air and natural gas are preheated before they are brought into the combustion chamber where they mix. From there the mixture. proceeds to the openings made along the entire length of the heater. In the downhole U-shaped heater of American design (U.S. Patent No. 3004603,10-171961). a U-bend piece made of refractory ceramics is installed below the combustion chamber of the heater. Through its walls, the U-bend transfers the heat of combustion to the bottomhole of the well. The products of combustion are then removed from the well through a parallel string of tubing. As the gas-air mixture is supplied to the downhole heater, it is cooled by circulating water. In a variant of the U-shaped heater, a small diameter pipe connects the combustion chamber with 115


the ceramic U-bend on the well bottom. The pipe restriction causes the flow of the combustion gases to become turbulent, thus insuring better heating of the walls of the U-bend piece. Flameless gas-air heaters also have been designed. They have a cylindrical body made of porous .refractory ceramic material. After the ignition of the air-gas mixture, a flameless combustion takes place within the pores of the heater's ceramic body. The flameless burning has two advantages: (a) the fuel combustion is very complete, and (b) the bottomhole zone does not become fouled with soot. During the combustion process, the body of the heater becomes red hot, radiating the heat into the oil-bearing bed. In another variant, the porous ceramic piece is placed directly on the wellbottom in such a manner that it encloses the perforated body of the heater like a jacket. Gas heaters of the above-discussed designs have been tested in the oil fields. The results show that, with some of them, it is possible to create burning fronts with temperatures of 8009OOOC. The basic elements of the asssembly of these downhole heaters are made of heat resistant steels. Some technical data for the gas heater developed by the Gas Institute together with the Krasnodar Petroleum Project organization are given below:

- Heat output, 1OOO'sof kg c a m - Gas heating value, kg cUm3 - Volume output (amount of working,agent.that is, of the mixture of combustion products with secondary air), m3/hr

- Temperature of working agent, OC - Pressure of working agent, kg/cm2

- Consumption of

n a t d gas, m3/hr

7 10 7,715 480 450 14-17 92

- Consumption of air used in combustion (at the air-excess coefficient a =1-2), m3/hr

92.3 377

- Consumption of heat carrier, m3/hr

Some technical data for the gas heater built by Ishimbai Oil and Gas organization:

- Heat output, 1OOO'sof kg cal& - Heating value, kg cal/m3 - Pressure of working agent, kglcm2

300 8,500 1-50 34

- Fuel consumption, m 3 b

The heaters of the type illustrated in Fig. 56 can be built to bum different forms of liquid fuel such as crude oil, fuel oil, or diesel fuel. The heater is lowered to the bottomhole through the production tubing. Once it is in place, the fuel-air mixture is pumped downhole under a certain amount of required pressure. During the treatment the pressure can be regulated from the surface within a broad range. Prior to entry into the combustion chamber the fuel-air mixture is run through a separator. The heater is equipped with an ignition device such as a glow plug. The combustion itself takes place in accordance with the diffusion principle with excess of air (a= 2.2-3). The heat output of this tool can be regulated within the range of 50-200 thousand kg cal/hr. 116


Y&ovlev's TOYakovlev's Apparatus Apparatus

TO

Diesel Fuel

--

Products of combustion

-

Elecmc heatm:

"

Downhole flame heater built Borislav Oil and Gas. Columns: b-single row; a double row; 1-suction-compression (production) string; 2 4 - f u e l separator, >fuel ignition device; k o n e seat; 5-combustion chamber, &housing; 7-production string; %packer. 9 4 1ter.

b

Downhole heaters of this type with an output of 30-50 thousand kg cal(45-75 kg W) are used for startup of in siru combustion more often than the heaters of other types. The heater is lowered into the well on a cable reinforced mechanically to withstand ielatively high temperatures in liquid medium. Electric power is supplied to the heater either by hook-up to the existing industrial power network or from special movable generators. Diesel generators manufactured in Russia can be used for this work under industrial oil field conditions. Fig. 57 shows an electric heater that can be used for long periods of time in the bottomhole at temperatures of up to 725OC. The length of the heater body is determined by the thickness of the oil-bearing horizon which is to be treated. The heater housing is thin-walled and is made of heat resistant metal alloy. The heater consists of three sections: heating, heat insulation, and the head. The heating section holds two spiral heat-emanating elements. A string of tubing protecting the power cable is attached to the head section. The heater works on AC current of 480 V. An auto-transformeris provided to enable the regulation of the voltage. Electric heaters with either U-shaped or straight elements have also been built. They have a power output of 8 and 10 thousand kg c a n r (10.5 and 13.2 kg W), respectively. Heaters with even higher power outputs have been constructed. Downhole heaters with straight elements are built as cylinders with a maximum diameter of 140 mm and length of 3030 mm. They consist of the head section, the tail, the heating elements (model ET-160), and the housing. The total power output of the 12 elements, each 1600 mm in length, amounts to 10 thousand kg c a n r (13.2 kg W). The heaters are built either for 380 or 760 V current. For cable attachment and to seal the cable's entry into the head section, the latter is covered with babbitt metal or with other similar material. The heaters are equipped with thermometers placed in special chambers. 117

Thermal Methods of Petroleum Production Heaters with U-shaped elements (Fig. 58) are also cylindrical. They have a length of 2605 mm and a maximum diameter of 130 mm. Their two principal sections are the head with head body and the heater with housing. The heating elements (model NMM) consist of several U-shaped pipes, each 3.1 rn in length. They are built for 380 or 660V current and have a total power output of 8 thousand kg cal/hr (10.5 kg W).

Fig. 57. (above) A downhole electric heater

Fig. 58. (at right) Bottomhole electrical heater with U-shaped elements built by Oil & Gas Institute: I-cable 2-head section 3-tubular elements &housing 5-thermometer 118

Petroleum Production by In Situ Combustion (Fire Flooding) It is noteworthy that the heat output of downhole elecmc heaters is smaller than that of the flame heaters. For this reason, it is better to use the latter whenever the reservoirs are thick or contain crude oil that is difficult to oxidize and has high ignition temperature. The effectiveness of using in situ combustion to produce petroleum from the bed quickly diminishes if the time required to ignite the bed lengthens. The heat output of the downhole electric heater can be determined by the formula: Qenergy = 864Wqe9 where:

864-thermal equivalent of elecmc energy, kg caVkg W x hr W-required power output at surface next to the treated well, kg W qe-heater's efficiency coefficient for a uniphase elecmc heater q e = (I - 2R

I u), for a *-phase

elecmc heater

I q e = (I - V G R v where:

Rrresistivity of the cable core I-required intensity of the current U-voltage of the current used

Linear power losses in the cable can be reduced either by using large diameter cables or by increasing voltage of the current used. Energy losses along the well column are smaller for three-phase elecmc motors than for one-phase motors. Fig. 59 indicates that with an increase in depth of the well, power losses in the cable can reach such values that, in individual cases, at the bottom of the ignition well only 50% of the power output employed can actually be utilized. This loss must be taken into account separately in order to prevent the failure of operation due to improper selection of power output of the heater.

z

3M

30

Fig. 59.

a s

!y

Power losses in the cable with 44OV current Number of phases: 1- 3; 2-1

81.

a" 0

100

Boo

1200

Depth, m 2 b.

S E L E C T I Q N Q E EQYIEMENIT E B B Q X X P I Z E B I H l E € I I Q N

Special movable or stationary compressor equipment must be used to insure the injection of oxidizer into this bed under a certain pressure and at a rate required not only to start-up the in situ 119

Thermal Methods of Petroleum Production combustion but also to sustain it as the burning front shifts. The selection of such equipment is made on the basis of data obtained either from calculationsor field experience. Field practice indicates that in order to sustain in situ combustion, it is necessary to inject into the bed 20-250 thousand &/day, sometimes even more, of oxidizer (air) under the pressure of 20-90 kg/cm2, at times at even higher pressures. The total amount of air that must be injected during the entire period of in siru combustion can be determined according to [21], depending on the volume of the burning zone, by employing the formula:

where:

Vrvolume of the combustion zone of the oil saturated bed Av-volume coefficient for the engulfing of the bed by in siru burning 8-specific expenditure of air required to insure the process of combustion per unit volume of the bed m3/m3

For fairly good reservoirs, it is assumed that Av equals 30-50%. that is Av = 0.3-0.5 [29]. For the majority of petroleums, the specific expenditure of air fluctuates between 200 and 500 m3/m3 of the reservoir volume under conditions of nearly full utilization of oxygen present in the injected air. Cases are known in which the specific expenditure of air per unit volume of the bed reached 760-1030 m3. Where very high rates of air expenditure are recorded, part of the injected oxidizer apparently does not participate in the combustion process. instead it spreads out within the bed bypassing the combustion front. Some authors [29,33] considered this process as stoichiometric which, under conditions of in situ combustion, could be described by the chemical material balance equation. Taking into account that in burning of petroleum residues (coke-CH)n, the compounds CO2, CO and H20 form, the authors obtained the following equation to describe the process of combustion of coke residue in situ::

where:

n-ratio between the number of H atoms to C atoms in the coke residue

m-ratio between the number of C a moles to CO moles Thus the ratio between the number of 02 moles to number of coke moles is

f&+ 5) If the molecular mass of the coke residue is (12 + n), and the volume of 1 kg mole of air equals 22.4 m3, then it follows that per 1 kg of coke residue the amount of 02 in m3 will be m + l

22*4

fm+ 5) 12+n 120

Petroleum Production by I n Situ Combustion (Fire Flooding)

Considering that the 0 2 content in the air is approximately 21%. and that, during burning, this 02 is only incompletely utilized, we can determine the specific expenditure of air, 6 air, required for the combustion of the coke residue per 1 m3 of the bed, that is

22.42 6air =

fa+ t)

021y (12 + n)

z-coke content per volume of bed, kg/m3 y-oxygen utilization coefficient, equal to 0.6-1.0 [21]

where:

The value for n, according to [29], can be determined from analysis data of combustion gases by using the material balance equation for stoichiometric process:

n=

106 + 2CO

- 5.06 ((202 + CO + 02) (C02 + CO)

where: COz-concentrationof carbon dioxide in the gases of combustion, % Opconcentration of oxygen in the gases of combustion, %

Of course, value n, calculated in accordance with this equation, can be used only as a guide, inasmuch as an assumption was made that all of the oxygen not extracted together with the gases of combustion was used up to form water. The results of experimental studies carried'out both in the U.S.A. [33] and in Russia indicate that the consumption of oxidizer (air) injected into the petroliferous bed during in siru combustion depends to a great extent on a number of factors. Among the latter can be listed the following: the content of coke fuel within the volume of the treated bed, composition of the coke, COz/CO ratio in the combustion gases; the density of the crude oil, porosity and oil saturation of the reservoir rock, the temperature of combustion, and heat losses. Fig. 60. Dependence of required quantity of air consumed in fuel combustion on temperature of the burning process. Quantity of air: 1 - maximum 2 - minimum

i

.e

d

&

0

Combustion temperature, OC According to laboratory data, the quantity of air required for the combustion of the nascent fuel in low-temperature oxidation reactions can attain 40.3 m3 per 100 kg of reservoir rock (curve 1 on Fig. 60). This amount is almost three times greater than the volume of air required in high temperature combustion. 121

Thermal Methods of Petroleum Production Low temperatures during the in situ combustion process may be caused by inadequate formation of fuel in the bed, low permeability of the reservoir rock, and also by high heat losses. The data discussed-clearly show that earlier-given formulas for the determination of air consumption during in situ combustion must also include corresponding coefficients and corrections. These complementary figures need to take into account the different causes that affect air supply requirements. Certainly, among these causes must be also listed the possibility that part of the air injected into the bed changes its direction and bypasses the burning front without having taken part in the oxidation process. The pressure that must be used to inject the air depends on the sum total of all resistances encountered by the air flow as it moves from the air compressor itself down to the bottomhole of the injection well, and then through the bed finally to the bottomhole of producing wells. The spacing of injection and production wells and the specific technological system used for production with the in situ combustion method also have bearing on the amount of pressure that must be used for air injection. The general formula used to determine this injection pressure can be written:

Pee= 1.2 (Ppl+ Pwl+ Pbh) where: Pce 4 1

- pressure at compressor exit, kg/cm2 - pressure losses in the pipeline connecting compressor outlet with the well head of the injection well, kg/cm2

Pwl pbi

- pressure losses along the column of the injection well, kg/cm2 - air pressure required at the bottomhole of the injection well, kg/cm2

Pressure losses Ppl and Pwl, allowing also for friction and local resistances to air flow, can be determined quite accurately by using generally known formulas or from calculated nomographic cham. The air pressure which is required at the bottomhole of the injection well depends on many factors. It can be determined by an approximate formula for one five-point element:

l2

r~ Wcmax 71 where:

Pp

- 1,238))

- bottomhole pressure of production wells, kg/cm2

Pa - air viscosity at reservoir temperature, centipoise - formation temperature, O C tf kf - phase permeability of formation for air,Darcies h - weighted mean effective thickness of reservoir along the line of combustion front, m

- distance between injection and production wells, m - time of spreading of combustion front, days 71 WC - rate of shift of combustion front, m/day 6i - air input of injection well, starting with minimum admissible rate of Wc; m3/day - radius of production wells, m ‘P 1

122


where:

V - volume of petroliferous formation (reservoir) in which the combustion front is spreading, m3 6a - specific air consumption required to sustain in siru combustion per unit volume of formation, m3/m3 6i - 3.14 liSaWc min

where:

-

li - distance between wells, m - minimum admissible rate in the displacement of combustion front, d d a y WC

The results of laboratory studies have determined that the rate of spreading of the combustion front fluctuates within a range of 0.0305-1.07m3/day. Under oil field conditions, the corresponding range was 0.152-0.87 m3/day [28]. The rate of advance of burning can be determined either by formulas or by laboratory studies on a model of the reservoir to be treated by the in siru combustion method. Fig. 61 indicates that the minimum rate of advance of the burning front drops with the increase of both bed thickness and its fuel concentration.

Fig. 61. Dependence of minimum rate of advance of burning front on thickness of bed and on oil concentration in the bed at reservoir temperature of 260OC. FueVcoke concentration, kg/m3: 1-32, 2-24, 3-20, 4-19.2, 5-18.4.

Formation thickness, m Once the amount of air needed for in sifu combustion and the necessary air pressure are determined, the selection of suitable compressors is then made (Table 30).

123


Table 30. Characteristics of some compressors most suitable for petroleum production by the method of in situ combustion output, m3/day

Compressor tYPe

8 GKM - 1/38-55 8 GK - 35 - 100 3 GKM-yl.l-14D20 3 GKM-3/1-50 3GK-3 2 SGD - 100 7 VP - 20/200 205VP - 16/70

I

2SG-50

VG - 50 UKP - 80

Pressure, kg/cm2

I 352,800 108,000 51,840 3 1,680 30,200 72,000 27,360 23,040 18,700 17,300 11,500

1

I

on intake on discharge

38 34-45 20 1 1 40-50 1 1 1 1

--

Power/Output

Motor

I "

Gasmotor 100 Gasmotor 50 Gasmotor 13/50 Gas motor 50 Gasmotor 100 ElectricDrivc 220 ElectricDrive 70 ElectricDrive 50 ElectricDrive 50 ElectricDrivc DieselB2-300 80 55

I

I

I

At the surface, the ignition wells for use with downhole electric heaters must have a highpressure lubricator, stuffing box, fittings, also necessary measurement and control instruments (Fig. 62). The equipment includes a special electric cable of correct length, AC current source, and an air supply system. Special care must be taken to protect the stuffing box seal from electric current.

Fig. 62. Surface equipment of wells used in start-up of in situ combustion, working with a downhole electric heater: 1-lubricator; 2-guide pulley; 3electric cable; 44ontrol station; 5source of electric power; 6-air intake (receiver); 7-compressor house; 8-stuffing box.

124


For ignition wells using downhole gas flame heaters, the topside equipment includes a choke with fittings on the production string for natural gas input, a choke with fittings mounted on the casing string for air injection, cable of a right length for lowering the flame heater to bottomhole, stuffing box, cable for the electric lighter, electricity source for the lighter, and also measurement and control instruments (Fig.63).

Fig. 63. Head of ignition well used for start up of in situ combustion with a gas flame downhole heater: l-gas inlet; 2-oxidizer (air) intake; -able for the thermocouple.

The surface installation also includes a system for air injection, moisture separator, fittings and lead-ins for thermocouple cable. When an oil-bearing formation consists of loose, uncemented sand, a ceramic filter should be installed on the wellbottom (Fig. 64). The filter protects the bottomhole equipment from intensive wear that would be caused otherwise by the sand carried into the well with hot oil and gas. These filters are made for different permeabilities, they can withstand temperatures of up to 3,oooOC, and they effectively stop sand penetration into the well. Because the surface of the filter is coarse-grained and has sharp unrounded edges, a turbulent flow is created in the oil entering from the bed. For this reason the filter practically never plugs up. Moreover, the ceramic material is chemically inert; therefore, the filter resists very well the action of low pH liquids and of other corrosive agents in the bottomhole. At the same time, the filter acts as a good heat insulator.

Fig. 64. Well bottomhole equipped with a ceramic filter: l-casing string; 2-production tubing; 3drillable heat resistant packer. &slits cut in production tubing; 5-ceramic filter; 6casing shoe; ir-cementing ring. 125


Ignition wells can be completed with a freely suspended liner of slotted casing (Fig. 65c). Free suspension of the casing column allows it to expand lengthwise with heat. Fundamental and complicated reconstruction of the wellhead is not necessary with the application of the in situ combustion process. Required complementary equipment can be easily installed using standard parts, components, and measurement-controlinstruments. The bottomhole of the injection well used for the in situ combustion process must be mechanically strong and made secure against such hazards as weak, poorly cemented reservoir rocks; intensive corrosion; high temperatures; and even possible explosions (Fig. 65). In newly equipped wells the liners of the casing column near the casing shoes should be made of heat resistant materials. The regulation of bottomhole temperature is easier when electric heaters are used than it is with flame heaters. So, when shallow oil-bearing beds are to be ignited with the help of electric heaters, one can use ordinary materials for bottomhole construction (Fig. 65a). However, in the majority of instances, it is wise to use special liners or, at least, to protect them against high temperature. a

0

ltli b

d

C

Fig. 65. Bottomhole construction of injection wells used for bed ignition with process of in situ combustion.

.e>

&

Whenever possible, the wells to be used for ignition of oil in the bed should have open hole completion (Fig. 65b). This protection from damage due to heat expansion is particularly important when downhole heaters are used in the ignition well. When downhole heaters are to be used for bed ignition, the injection wells should not be completed by cementation, with subsequent perforation of casing (Fig. 65d). Because of thermal expansion, wells completed in this way may suffer damage. However, in cases in which ignition of the petroliferous bed occurs spontaneously within a limited zone, the completion by cementation and perforation of the casing is very suitable. When downhole explosions are resorted to, one or several packers should be set in the lower section of the well. They will obstruct the propagation of the shock wave and limit the fracturing that it may otherwise cause. The space below the packers or the intervals between them should be filled with granulated material. The annular space in the interval above the top of the oilbearing bed should also be sealed off. For this purpose, another packer is set in the well somewhat above the top of the petroliferous zone. Fig. 66 shows the bottomhole of an injection well used for testing of the in situ combustion method by Mene Grande Oil Company in an oil field of eastern Venezuela. In this design of the injection well, the annular space is sealed with a packer. Perforated slits, suspended liner, and a gravel filter are employed to prevent sand from plugging up the well.

126


Fig. 66.

Bottomhole of injection well: 1-178 mm casing column; 2-76 mm injection column; 3-shift; 4-sliding sleeve; 5-packer; &shoe pin; 7packer of liner; 8-slotted liner-filter, 9-perforation openings; 10-liner shoe; Il-plug.

Fig. 67.

Bottomhole of production well. for 1-245 mm casing column; 2a:bel running logs with thermocouple; 3-73 mm control-observationcolumn; 4-63 mm production tubing; 5-pump support packer; 6-thermocouple column; 7-thermocouple; 8-liner packer; 9-liner filter; 10-perforation openings; 11-liner shoe; 12-plug.

Production well used in this Venezuelan field test was secured with a 245 mm casing. Bottomhole of the well opposite the productive zone was packed with gravel, and a liner-filter 140 mm in diameter was lowered into place. Two parallel strings of tubing were lowered into the well. One, 89 mm in diameter, was used for oil production, and for this purpose it was equipped with a support packer for downhole pump. The other tubing string was used for observation; it had an initial diameter of 73 mm, narrowing to 55 mm on entry into the liner-filter. It ended blindly with a plug. Into this observation column, thermocouples were lowered on a wire conductor. The thermojunctions of the three thermocouples were placed at an interval of 1.52 m opposite the perforation openings in the casing.

127


Fig. 68.

Bottomhole of production well: 1-178 mm casing string; 2-heat resistant cement calculated at 29.8 kg of cement per 1 meter of depth, 3-73 rnm production tubing; &hang off support for liner; 5-seating nipple for downhole pump; &slotted liner made of stainless steel; 7-rust resisting section of production tubing opposite the liner; 8-gravel packing; 9-top of oil-bearing zone.

Fig. 68 shows the bottomhole of a producing well used in a test of in siru combustion at the Betmm oil field in southwest Saskatchewan in Canada. The petroliferous horizons in this field consist of dense sandstone beds of variable thickness with inclusions of ozocerite shales. The bottomhole diameter of this well is enlarged. At the surface, small pumps are installed to circulate the water for cooling down of well bottom. Water is injected through the annular space and returns to the surface through the production tubing together with the extracted crude oil. To cool the production well, about 24 m3 of water/day is required.

Gas-airmixture

3 Fig. 69.

4

Bottomhole of ignition well employing water cooling. 1-inner tubing string for injection of gas-air mixture; 2-outer tubing string for removal of combustion (flue) gases; 3-casing column; 441-bearing zone.

Fig. 69 illustrates a proposed design of a water-cooled ignition well. Gas-air fuel mixture and water for cooling are injected into the well bottom through separate tubing strings placed 128

Petroleum Production by In Situ Combustion (Fire Flooding) concentrically within the casing column. Fuel mixture goes through a water column on the well bottom and is then ignited by means of an electric lighter. The pressure exerted by combustion gases causes the water to rise within the inner tubing string (1). Flue gases are removed through the outer tubing string (2) which is also being cooled by circulating water. Other designs of well completion can also be employed with in situ combustion. In each specific case, other solutions may be implemented as required by local conditions. Some old wells cannot be used for injection or ignition. Their suitability for this purpose must be very carefully determined before any work is done on them. 3.

OXIDATION A N D =AT EXCHANGE PRO-

IN OIL,RFSFRVOR

In addition to several factors discussed earlier, this process also depends on two heat phenomena: convection and heat conductivity. Physical, chemical, thermal and hydrodynamic phenomena take place simultaneously and interact with each other during in siru combustion underground. Such a complex process is not encountered with other thermal methods of treating oil reservoirs. For this reason, some investigators attempted to break down this complex process into separate phenomena in order to study them one by one. Authors of references [l. 29 and 341 limited themselves to the study of the thermal field that develops in the oil-bearing bed and in the surrounding rocks during in situ combustion. They tried to separate the phenomena of oxidation processes, heat exchange, and mass exchange. But when we start out with molecular structure of compounds and of media, we find that we still don't have a clear concept of heat- and massexchange mechanism for in siru combustion. Two things occur during in siru combustion underground: (a) oxidation of some of the substances, and (b) thermal treatment of the oil-bearing bed by heat released during this oxidation process. The movement of substances in the zone that has been heated and ahead of it can be described by using equations for filtration of multiphase fluids. Gottfried [31] calculated the solution for the system of equations. Of course, this mathematic description of the underground in situ combustion is not complete. Additional equations should be applied based on such things as the theory of combustion, theory of heat transfer [34], equations for mass exchange by convection, and the theory of dissociation. However, even with help of modem computers it would be difficult to obtain solutions for systems of 'all these equations. For practical calculations, it is therefore advantageous to use simplified scherxieq to represent processes of oxidation as well as heat- and mass-transfer. 3 b.

BdTE-QE-~HEMI~AL_BEA~~IQ~-AN~-~~E-ENER~X-QE ACTIYATIQN

I n situ burning of oil in oxygen injected with the air into the bed is always preceded by its slow oxidation. Depending on the properties of petroleum present in the bed, its oxidation can begin at different temperatures. The rate of oxidation reaction under specific reservoir conditions is not stable. Average rate of reaction is generally determined by the ratio of difference between the final concentration of products (C2) and the original concentration of products (Cl). This change is measured during the time interval (TI,72) in which this reaction was taking place, that is:

129


w= c2-c1. 22 - =1 The true rate of reaction is determined as a deriviativefrom the concentrationover time:

w = * -d .C dz

The rate of paction is always positive, but the derivative d a d T may be positive or negative. If the concentration of initial substance is taken to be diminishing with time, then a minus sign is placed on the right side of the equation, so that the rate would be positive. If, however, we take the concentration of final products of the reaction, then a plus sign is placed on the right side of the equation. Rate of chemical reaction goes up with increases in the number of collisions among reacting molecules. Therefore, at stable temperature, the rate of reaction should go up with increases in the concentration of the reacting substances. The relationship between the rate of reaction and the concentration of reacting substances is governed by the law of acting masses; that is, the rate of reaction is directly proportional to the product of concentration of the reacting substances. Each one of the concentrations is taken in a degree which is equal to the stoichiometric coefficient in the equation of that reaction. For example, for the reaction 2H2+02 t)2H20 the rate w = KCzH2 (2'0,. where: K-proportionality coefficient which, at a determined temperature in a stable value and is called a constant of the rate of reaction. Depending on the number of substances that combine, chemical reactions which proceed to the end can be subdivided as follows:

- monomolecular reactions (A = M + N), - bimolecular (A + B = M + N), - trimolecular (A + B + C = M + N). If we represent the concentration of nascent .substancesas C,C1 and so on, then the kinetic equations for the three indicated types of reactions can be shown in the following form: dC = KC, dz

for monomolecular reaction,

dC = KCI, KC2 dz dc dz

-=

KCI, KC2, KC3

for bimolecular

for trimolecular.

130


At the same time, the rate of reaction depends on the temperature. In 1889. Arrhenius, by experimentalmethod, found the dependenceof the reaction rate constant on the temperature: K=KOe

where: e R t

E

L Rt - constant, that is characteristicfor a given reaction - base of natural logarithms - universal gas constant, kg caVmole - absolute temperature, K - activation energy, kg caVmole

According to the Arrhenius theory, not all of the colliding molecules enter the oxidation reaction, but only those whose energy sum is equal to or exceeds a certain determined value of the activation energy. It means that in order for the chemical reaction to take place, the bonds between atoms or between groups of atoms of reacting molecules must first be weakened or even broken. Without this condition the regrouping of atoms and formation of new molecules is not possible. On the other hand, such weakening of internal bonds between molecules or their breakdown becomes possible when the molecules possess a certain excess energy. The original substances initially have a certain energy reserve (value I in the diagram on Fig. 70). For the molecules of the initial substances to combine, they must have a certain minimal energy reserve shown on the diagram by level K.

Fig. 70. Change of the potential energy of a reacting system.

Course of reaction The difference between level K and I defines the activation energy El of a direct reaction. As a result of the reaction, the total energy reserve of nascent products becomes significantly smaller than the energy reserve of the original substances. The difference between the levels K and I1 defines the activation energy of the reverse reaction E2. This diagram shows that the thermal effect of reaction Q is the same as the difference between the total energy reserve of initial substances and of end products. The general expression for the rate of oxidation reaction, taking activation energy into account, is reDresented bv the known formula where: Cv - molecular concentrationof reacting substances for reaction of any order. The smaller the activation energy, the more readily can the oxidation reaction begin and continue. 131

Thermal Methods of Petroleum Production The above discussion leads to the conclusion that in oxidation reaction (burning) the molecules of reacting substances pass into an active condition.

Thermal self-ignition: The process of acceleration of an oxidation reaction that leads to the ignition of the substance is called self-ignition. The thermal self-ignition concept was first established in 1934 by N.N. Semenov. This theory was later fully developed by O.M. Todes and D.A. Frank-Kameneckii. According to this theory, when the temperature is low, practically no reaction occurs within a mixture between the fuel and the oxygen of the air. Active molecules of oxygen necessary for such a reaction to'take place are absent unless the mixture is heated first. Only then can the oxidation reaction begin. The amount of heat generated in this process, per unit of time, can be calculated as follows:

where: Q V

- heat effect of the reaction, kg caVmole - volume of fuel mixture, cm3

o - speed of reaction. mole/sec .cm3 Substitutingin this equation the value for o we obtain

A part of the thermal energy generated in this reaction is used up to heat the mixture of substances participating in the reaction itself, the rest of it is lost through transfer into adjacent objects and the surroundingmedium. The amount of heat that is lost per unit of time can be calculated, in first approximation, according to Newton's law:

92 = a F(tm - tb) where: a F ,,,t tt,

- heat transfer coefficient, kg ca&$.sec.oC - heat emitting surface (total), rn2 - temperatureof the mixture of substances participating in the reaction, OC - temperature of adjacent bodies or surroundingmedium, OC

In other words, the temperature loss is proportional to the difference in the temperature of the reacting substances of the mixture, on one hand, and the temperature of the adjacent bodies and the surrounding medium, on the other. With the temperature difference that develops between the fuel mixture and the surrounding medium, further heating of the fuel mixture will depend on the rate of heat generation versus that of heat transfer. When q1> 92, then the fuel mixture, while oxidizing, will continue to heat up. When q1 = 42. the fuel mixture will keep on oxidizing at the stable temperature at which the q1= 92 relationship has first been obtained, but no self-heating of the fuel mixture will occur. Thermal self-ignition can thus take place only if the rate of heat generation in the fuel mixture exceeds that of the heat transfer. Only then the slow reaction of oxidation can change to combustion. Moreover, the heat generated by the fuel mixture must exceed the heat of transfer

132

Petroleum Production by I n Situ Combustion (Fire Flooding) (heat loss) in every case, that is at any temperature of the fuel mixture and up to the moment at which the combustion finally occurs. In this process. the rate of oxidation reaction occumng in the fuel mixture. in its turn, depends on the temperature and pressure of the reacting substances.

Fig. 71.

Dependence of heat generation q1 and of heat losses 42 on temperature.

Fig. 71 shows that at the temperature of fuel mixture t. the line of heat generation intersects the line of heat loss at point A. Whereas up to point A the line of heat generation is located higher than the line of heat loss, after these two lines intersect at point A, their direction changes. This change means that, at temperature ti, the rate of heat generation of the oxidation reaction exceeds that of the heat loss; consequently, the fuel mixture is heating up. When the temperature of the mixture reaches tp. the rate of heat generation becomes the same as the rate of the heat loss, at which point further self-heating of the fuel mixture stops. Now, should the fuel mixture temporarily heat up to a temperature above t2, the rate of heat loss will still exceed that of the heat generation, and the fuel mixture will cool down to t2. Thus, when the fuel mixture is heated up to ti, it will cause it to heat by itself through the oxidation process. The fuel mixture will heat up to t2 but it will not yet start to burn. The conditions for self-heating to high temperatures are not yet created. To bring about combustion, it is necessary to heat up the fuel mixture to a higher temperature, such as t3, with other conditions remaining the same. At t3, the rate of heat generation of the oxidation reaction will always exceed that of heat loss. In this case, the fuel mixture can heat up by itself to a temperature at which burning will be possible. The graph shows that self-ignition of the fuel mixture can take place only when heat generation is equal to or exceeds heat loss; that is, when q1>> q2. The temperature at the point of contact B is called the self-ignition temperature. At this temperature, the rate of heat generation of the fuel mixture exceeds the rate of heat losses, so that the fuel mixture can heat itself up to the temperature ti (temperature of self-ignition). Thus, the tangent point B determines the conditions necessary for self-ignition. Such conditions exist when (a) the rates of heat generation and of heat loss are the same, that is: (ql)ti=(q2)ti; and (b) the rates of change of these two values with temperature are also the same:

133


The temperature of self-ignitionti can be determined from these conditions. Employing the formulas for 61 and 62 presented earlier, we shall obtain QWCYe-

E

ti = a F (ti - tb),

In dividing one equation by the other we shall receive:

From the resulting equation we can obtain a quadratic equation to determine the temperature of selfignition:

The temperature of self-ignition will be

It often turns out that E >20,000 kg cal, and tb > 1.OOO K. consequently:

Therefore, ignoring the existing error, the expression under the second mot can be broken down into a series. and we can then obtain for the temperature of self-ignition the following approximate expression:

Or finally:

The graph on Fig. 71, which we have just discussed, can be represented as a graph showing the change in temperature of the fuel mixture with time (Fig. 72).

134


t

J Fig. 72. Change in temperature of the fuel mixture with time.

Time In this case, when reacting substances are found within a medium whose temperature is lower than the oxidation temperature, the temperature of the fuel mixture changes with time along Curve 1. At fiist, the temperature of the fuel mixture slowly increases for a time until it becomes the same as the temperature of the surrounding medium t ~ . If the surrounding medium is heated up to a temperature somewhat above that at which the reacting substances of the fuel mixture can oxidize, e.g., to ti, then the temperature of the fuel mixture will change along Curve 2. In this case, the temperature of the fuel mixture will not become the same as the temperature of the surrounding medium, but rather it will rise above it and, after reaching a maximum, it will start to decline. This initial temperature increase is due to heat generated in the oxidation process. Up to a certain maximum temperature of the reacting substances, this heat generation occurs at a rate exceeding that of the heat losses. Once this maximum temperature is attained, the heat losses become greater than heat generation, so that the temperature of the fuel mixture starts again to decline. If the temperature of the surrounding medium is increased still higher, e.g., to tb. then the change in the temperature of the fuel mixture will correspond to Curve 3. Due to heat generated during the oxidation reaction (within time interval z ), the temperature of the fuel mixture, at first rises sharply, then relatively slowly until point B is reached. A further sharp temperature increase takes place above point B, caused this time by the burning of the fuel mixture. As the graph in Fig. 72 shows after the temperature of surrounding bodies or medium tb is established in the fuel mixture and before temperature of self-ignition ti is attained at point'B, some time still passes before the fuel mixture self-ignites. This time lapse is referred to as the induction period or the time lag. For this reason, in order to enkindle the fuel mixture, it is not necessary to heat it up to the temperature of self-ignition ti. It suffices to raise the temperatureof the surroundingmedium to and then wait for a determined time period required for the spontaneous pre-ignition reactions to take place. The induction period depends on the temperature and the composition of the fuel mixture. At high temperatures, above 600OC, this period amounts to a few seconds, with self-ignition occurring almost instantly. The temperature of thermal self-ignition of crude oil varies from 300 to 6500C. It depends on such factors as the composition of the crude, and on physical and chemical properties. When pressure is increased, the self-ignitiontemperature becomes significantlylower.

135

Thermal Methods of Petroleum Production Analysis of the individual assumptions of the theory for combustible substances and media shows that these assumptions are to a certain degree also applicable to petroliferous formations. An oil-bearing bed likewise represents a special kind of a combustible substance. It consists of mineral ash, acting as a skeleton, and of the flammable organic part, present in the form of a strongly dispersed oil-water-gas mixture. The combustible part of petroliferous beds, unlike that of hard coal and oil shale, is only weakly bound to the solid mineral skeleton and becomes very mobile when heated. During in situ combustion of crude oil in a petroliferous sand only 2.5%of the substance, by volume, participates in the process of burning [28]. This fact makes it obvious that the petroliferous formation, when regarded as a combustible substance, has very unique characteristics. Porosity, permeability, structure of pore space, quality of the crude, the degree of its saturation with gas, also the presence of connate water are some of the factors upon which self-ignitionof the oil reservoir will depend.

3c.

B A T E _ Q E _ A P Y ~ ~ Q E _ ~ Q ~ ~ ~ ~ ~ ~ ~ Q ~ E - A ~ P - H

Within the volume of the oil reservoir, the zone of burning is three-dimensional. The front of advance corresponds to an isothermic surface of maximum temperatures; the rear corresponds to the surface along which the burning of coke-like residue is coming to an end. Oxidation reaction gives rise to the burning front. The latter, in turn. serves as the source of thermal energy to heat the sections situated both ahead of it and behind it. The heat ahead of the combustion zone is transferred through convection-diffusionheat exchange. As the burning front moves, it leaves behind very hot rocks. These rocks cool off gradually, giving up their heat both to the oxidizer (air) being injected and to the rocks surrounding the oil-bearing bed.

Fig. 73. Temperaturedistribution in the petroliferous bed along distance x during in situ combustion. Time in minutes: 1-13 + 33 (beginning of the experiment); 2-14 +. 13; 3-14 + 48; 4-15 + 25

200

0

10

40

50

80 X , C M

Fig. 74. Diagram of in situ combustion in a homogeneous bed. Zones: I-cold air; &heated &,III-burning; IV-evaporation and condensation of oil and water; V-multiphase movement of oil, water, and gas.

Q,-

X

If we represent the data on the course of in situ combustion by curves of temperature and of distance X for definite time moments, then it becomes obvious that the temperature maxima indicating the burning front shift along the bed at a definite rate [28] (Figs. 73 and 74). 136


Results of experiments carried out both in Russia [15, 21,251 and abroad r29.331, show that the rate of advance of the burning front is directly proportional to the amount of oxidizer consumed. This finding proves that with the change in the amount of injected air the size of the combustion zone does not change, and only the rate of advance of the burning front changes. In this case. for the rate of advance

the following [101 simple formula is proposed:

- volume of oxidizer injected into the bed, - area through which the burning front moves.

where: Q

S-

Analysis of experimentaldata [28] shows that stream density of the air being injected and its oxygen concentration also have an effect on the rate of advance of the burning front (Figs. 75 and 76). of,r n h Y Fig. 75. Rate of advance of burning front and its dependence on stream density of the oxidizer. Oil density in kglm3: 1-103(?); 2-976; 3-959; 4-910; 5-903; 6-869; 7rate of advance of convection-heatingfront; 8-rate of advance of the burning front. 103(?)- translator's question mark

r.

Fig. 76. Average rate of advance of the burning front and its dependence on oxygen concentration in the injected

ofcm/hOur

air.

1.0

0,5

0

20

40

6

137

Thermal Methods of Petroleum Production The dependence shown on Fig. 76 apparently can be subdivided into two areas: first-area of small rates of advance of the burning front (a non-linear relationship); second-area of higher (>9 m/day) rates of advance (a linear relationship). Of great importance with in situ combustion process is also the rate of heat distribution on the rear side of the burning zone. If in zone I and I1 this rate is greater than the rate of advance of the burning front, then the heat of oxidation reaction will be shifted into the zone situated ahead of the burning front. However, when the opposite is true, then the heat of oxidation reaction will remain behind the zone of combustion. 3d. I E M E E K b I U K E ElELR QE PIL=BEABINP BED A N P C Q N P I T I Q N I S B E Q U I E E R T Q ISUISIAIN I N S I I U € Q M B U I S I I Q N Correct technological parameters must be used a d proper temperature field created within the oil reservoir in order to sustain a stable in siru combustion under field conditions. To accomplish this task difficult and complex mathematical calculations have to be made. Many specialists in this field were actually able to come up with helpful solutions, but only by resorting to many assumptions and simplifications [25, 29, 341. However, many questions regarding successful industrial application of the in siru combustion still remain unanswered. Let us make a number of assumptions about the petroliferous bed within which the in SitU combustion is taking place: (a) Bed is infinite in extent, homogeneous and isotropic; (b) Zone of burning within which the oxidation reaction is taking place is like a bordering surface, that is, it has an infinitely small thickness by comparison with the thickness of the thermal field, that is, of the zone within which the heat is being distributed; Temperatures of the gases and of the rock at any point within the bed are the same; (c) Thermophysical characteristics of the rock and of the injected gas are independent of (d) temperature and pressure. Under these conditions, we shall have a burning front being formed by an infinitely flat source moving at a stable rate with the heat generated along the front of advance being transferred into the bed by gases both through thermal conductivity and convection. The temperature distribution within such a system of coordinates can be represented as

where:

erfx=

2 x -

5 = x-ujt

- the distance from the well axis to the point of the petroliferous bed

Uff

- the distance traveled by the burning front

at which the temperature is being determined 138


h

- temperature conductivity of the rock making up the petroliferous bed %ckpbed - heat capacity of rock and gas Crock, cgm h - heat conductivity, P rock -rock density The velocity u can be. expressed as a=

where: u - velocity of injected &, a= Pr M y &d &,g

Crpr . Crockprmk ' - gas density;

- specific consumption of air per unit of surface at well bottom - oxygen content in the injected air - oil/oxygen ratio of the mixture participating in the oxidation (combustion) reaction - amount of oil burning in one volume unit of rock

The temperature developed at the burning front in this case is VO

Cr ' -

t = -Crock Gil

where:

VO

y b i ~

- heat of oil combustion.

Oxidation (burning) within the petroliferous bed is possible only on condition that the oil content in the bed exceeds certain minimum value Z-:

where: tmin

minimal temperature at which the combustion can take place within the bed; according to experimental data tmin= 250-35OOC).

-

If we consider the moving front of combustion as a surface with a finite height 21, then the temperature developed at the burning front can be determined in the following manner:

Wo, II,00)

= Wo,q,h) =

te-0

x

where: K,,

o,q and h

+h

Ko(4o

+ (q - q')2

-f!

-MacDonald function of zero order, -dimensionless parameters: 139

dq',


y - vertical coordinate in the plane of the burning front. The formula for the determination of the temperature that developed can be brought to the expression:

where:

I

F (0,x) = X

Ko ( d z 2 ) d u .

O

Values for function F(o,x) were determined in this case by numerical integration. Oxidation (combustion) within the oil bearing bed will be stable, if, under the given condition, the temperature at the edge of the burning front is at least equal to the minimum combustion temperature in the bed, otherwise, at h > 2, the temperature in the center of the burning front must be two times higher than the minimal. Then the stability test will be: crock

Cr

.

If the dimensionlessparameter h is equal to uW2a > 2, then the stability test condition can be shown in the form of

Crock

G i I > Zmin =

VO

2t min +

Cr

*

Sheinman et al. [28], studied in detail the problem of burning-front stability relative to two basic parameters: (a) consumption of injected oxidizer (air), and (b) oil saturation of the reservoir bed. Let's consider the moving front of combustion to be a real surface with a height of 21. At first, the combustion process is initiated right next to the injection well. The radius of the initial combustion front coincides with the well radius 6. The heat losses take place in a vertical direction from the combustion zone. The consumption of air injected into the bed is taking place at a steady rate, so that the shift of the burning front occurs at a rate inversely proportional to its distance from the well axis, that is B

uf=, , where: B = constant.

140

Petroleum Production by In Situ Combustion (Fire Flooding) The air is fed from the well radially into the combustion zone; that is, no air flow occurs from the well into the bed along the vertical axis of the well. Under these conditions, if we ignore heat transfer through convection, the temperature distribution within the oil bearing bed can be determined from the equation

where the function for source distribution f(r,z,t) has the form:

IZI

at

QI

lzl>I.

Heating power per unit of height of the burning front will be

4

A=

2nCrockQ rock

.

Initial condition: 0(r,z,O) = 0. Solving the proposed problem by emI.Jying Green's function, we can c - tain B

q% B(r,z,t) =

as rock Crock

tdu 0

[

2 r2+ r o

Texp- (

+ Bt

4au

where: JO - Bessel's function of fist kind from the minimum argument (of zero order). By this formula one can determine the temperature distribution within a petroliferous bed assuming a burning front of finite height spreading out radially from the injection well. If we introduce dimensionlessparameters

then we can write the equation, solved by the method of the Green function, in the following form: 141


The dimensionless parameter R, characterizing the radial distance from the well axis to a point within the bed at which the temperature is being determined can be found in the following manner:

where:

d K is the distance of the well axis to the burning front; r' - distance from the burning front to a point within the bed at which the temperature is being determined:

At a = 0, the temperature is being determined directly at the burning front in the moment of time corresponding to the dimensionless parameter z (Fourier criterion). At a f 0, temperature distribution is being determined at points within the pemliferous bed away from the burning front. Influence of different factors on the temperature distribution within the oil-bearing bed during in situ combustion can be determined by carrying out numerical theoretical calculations. Fig. 77 shows that with reduction in the air flow, the heated zone of the bed becomes stretched out. But the temperature at the burning front decreases at the same time. e,oc

Fig. 77. Temperature distribution ahead of the burning front at different flow rates of the injected air. 1-Qr/21 = 8 k g h h r ; 2-Qr/21 = 16.2 kgJmhr, 3 4 / 2 1 = 8 1 k g h h r , 21 = 20m; RK = 0.33; &il= 2%; y = 0.23. 142

Petroleum Production by In Situ Combustion (Fire Flooding) Within the burning bed, heat transfer by conduction can be also calculated along with that by convection. In that case, the temperature in the oil bearing bed (for dimensionless values) should be calculated according to the formula

where: Ju

- Bessel’sfunction of the first kind from imaginary argument (of v order).

Here: Qr - gas consumption by weight. According to the results of numerical calculations, during convective heat transfer by gases the temperature of the petroliferous bed in the combustion zone increases, on the average, by 20%. H.D. Tad proposed a differential equation to calculate the heat transferred by moving focus of combustion, the heat conductivity of the porous body of an oil saturated bed, and the heat content in the burning zone. Tad accepted as stable both temperature in the burning zone and the rate of expansion of this zone within the petroliferous’bed. In this case, the equation is as follows: dt

(u-ubz)E

-

d2t dz

x 7-

dt a~ =O

where: u

-rate of heat transfer by convection, mhr, u = u gas Peas Cgas ( PC + u oil poi1 Coil 1 PC (symbols bz, gas, oil correspond to the burning zone and the gas, and the oil) - specific heat capacity,kg cal/kg.degree C p - density, kdm3 x - diffusion coefficient, m3/mhr T -time, hr t - temperature, O C -distance downwards along the current away from the burning zone at highest z temperatures, m. Integrating the proposed equation, one can calculate the temperature field both in front and behind the burning zone. Integrating the same equation along the variable z, one can determine the heat content (caloric power) of the burning zone. With a continuous partial combustion of crude oil in the petroliferous bed, the temperature field will depend on the relationship between the rate of shift in the burning front (ubz >> u) and the heat conductivity. This finding is based on results of both practical and theoretical studies. 143

Thermal Methods of Petroleum Production It was noted that with the decrease in the rate of shift of the burning zone and with the reduction in the rate of air injection, the conductivity of the material medium of the bed tends to attain its maximum. Due to this phenomenon, something similar to heat energy accumulation takes place and, as a result, heat content (caloric power) of the burning zone increases. Apparently the rate of heat loss due to thermal conductivityof rocks is significantly smaller than the rate of advance of the burning front. To determine the rate of movement of the burning front for cases involving partial combustion of crude oil in the bed, H.S. Ramey [34] employs the formula: 24 ua uor = CR C a c

where: ua

- rate of air flow in the combustion zone along the surface of burning front, m3/hr

C,

- quantity of coke produced, kg/m3

Rac

-air consumed in coke burning, m3kg

Results of laboratory and field studies demonstrated that the rate of shift of the burning front depends mainly on the rate of air flow along the burning front, that is, on the heat of the injected air and on the degree of utilization of the oxygen present in it. The original equations discussed earlier take into account heat transfer by conduction and convection, heat of evaporation and condensation, capillary effect and Darcy's law, but they ignore the Joule-Thomson effect and the temperature effect of adiabatic expansion of formation liquids and gases. Previously described methods for solving problems of heat and mass transfer in an oil saturated bed with an advancing burning front are given only as examples. A variety of other concepts as well as mathematical solutions, not discussed here, have been also proposed. For example, French researchers R.V. Stalman, I.R. Iffli and N. Farrandon attempted to develop a theory of thermal currents and of heat exchange within porous media. And Ferrandon actually obtained an equation for the energy of filtering liquid or gas [30]. However, until now none of the proposed theories or mathematical solutions take into account the totality of the physical nature of in siru combustion processes. One of the unanswered questions is how to determine heat losses into the rocks enclosing the oil-bearing bed. The equations analytically derived [25] are correct, in first approximation, only for the process related to injection of heat carriers into the bed. They cannot be used to calculate these heat losses when oil is produced from a petroliferous bed by the method of in siru combustion. As the diagrams A and B on Fig. 78 show, the character of heat losses into the overlying and underlying rocks is quite different in these two instances. In cases illustrated by diagram A (Fig. 78), with injection of heat carrier, the area which is giving up heat into the overlying and underlying rocks continuously increases; being limited by a shifting radius only on one side of the burning front. On the other hand, in cases represented by B (Fig. 78), the heat loss area is limited by two shifting radii: on one side-by the radius of the burning front, and on the other-by the radius of the burned out zone of the bed. Moreover, the two radii shown on diagram B do not increase in the same way. The heat distribution within the shifting zones is also very different in instances represented by diagrams A and B. In the case of the internal heat source (diagram B), the heat distribution is uneven in the two opposite directions along the cross section of the shifting zone; it also shows a significant maximum along the shifting radius of the burning front. 144

Petroleum Production by In Situ Combustion (Fire Flooding) A.

G Heat carrier

B

+Oxidizer (air)

78, Conventional diagram of heat losses into rocks overlying and underlying the oilbearing bed. %-zone of bed heating %-radius of burned out zone rf-radius of burning front

Additionally, in instances illustrated by Diagram B, the current of injected air advantageously carries out cooling of the burned out zone and also of the overlying and the underlying rocks. By absorbing heat from these rocks, the injected air heats up, thus recapturing part of the heat losses. This recovered heat is then brought back into the zone of the burning front. Because of this heat recirculation, the heat losses into the rocks enclosing the petrolifemus bed are smaller with the in siru combustion than with other methods. This heat recovery constitutes an essential feature of the direct flow process of in siru combustion.

4. EXPERIMENTAL AND COMMERCIAL PRODUCTION OF OIL FROM RESERVOIRS BY N SlTU COMBUSTIOr\l 4a BACK PBQPNP-NQTES Russians were the first to propose the concept of in siru combustion for petroleum production. During 1932-34, the workers of G I N (State Scientific Research Institute), A.B. Sheiman, K.K. Dubrovai, S.L. Zaks, N.A. Sorokin and M.M. Charygin, carried out extensive laboratory studies on the in siru combustion method. First industrial experiments employing this method took place at the Shirvan oil field in the Krasnodar region [28]. This work was interrupted by the war but it was resumed in 1964. In 1967 a new experimental project on commercial application of in siru combustion began. A number of oil and gas research and engineering design institutes are participating in this work. Following the completion of preparatory work, these institutes began, in 1967, to carry out experiments on in siru combustion in "lense" #4 of the Sannatian-producinghorizon at the Zybza field of heavy petroleum. Pavlova Gora and Zybza, the two oil fields where these experimental studies are being conducted, differ sharply from one another in their physical and geological characteristics,and in respect to production problems. The Pavlova Gora field is more suitable for application of the method of in siru combustion. Its reservoir rock consists of continuous beds of granular sands 145

Thermal Methods of Petroleum Production with high oil saturation. On the other hand, at Zybza field the reservoir is made up of interlayers of clay and silt, and of coarse dolomite and shale breccias. The oil saturates porous sections and layers of rocks or fills the cavities in the breccias. 4b. RESULTS-QEJiY. S I T L r _ € Q M B U S T I Q ~ - I ~ - T H E - H Q M Q ~ E ~ E Q U ~ - ~ E R - A ~ P A Y LQYA-PQBA-QIk-EIELB Main reservoir characteristics of producing Maikop horizon I in the Western Embayment of Pavlova Gora field are as follows: The field is located 3 km northwest from the Neftegorsk village. Petroleum in horizon I of the Westem Embayment was originally indicated by well log data back in 1938. This reservoir was fist tested in 1957, at which time oil flowed at the rate of up to 5,400 tons/day. Western Embayment is connected by a neck with the neighboring Eastern Embayment. Maikop horizon I is also petroliferous in the Eastern Embayment; however, here it has been mostly eroded and, at the highest structural position, it actually crops out. Within the limits of Pavlova Gora field, the Maikop horizon I consists of four series of sands or sandstones interlayered with clays. Structurally,Western Embayment of Pavlova Gora field lies on a monocline that dips to the northeast at an angle of 110. Down dip, on the northeast ,the reservoir is bordered by formation water. The reservoir is about 1,000 m long, and has an average width of 850 m (Fig. 79). The depth measured in the wells from surface down to the top of the producing Maikop horizon I ranges from 91 m, at the highest point of the structure, to 275 m at the lowest petroliferous contour. Effective thickness of the second series of oil-sands of the Maikop horizon I increase from zero meters in the pinch-out zone to 10 m in the vicinity of the injection well 804. Structure contour and isopach maps of producing Maikop horizon I in the Western Embayment of Pavlova Gora oil field, and location of experimental work. 1-isopachs of producing horizon 2-limits of experimental sections of the reservoir 3-structure contom drawn on top of the producing horizon 4-pinch-out lines of producing horizon %first outer contour of oil reservoir &first inner contour of oil reservoir 7-air injection wells 8 4 1 production wells 9-observation wells 10-numbers of experimental sections of the field. 146


For experimental work on the application of in situ combustion, the aforementioned second series of producing sands was selected as object. The Western Embayment was drilled on a triangular grid using well-spacing of 200 m. By the middle of 1960, twelve wells were drilled. Cores were taken of the entire productive Maikop horizon I from six wells drilled in the experimental section I, and from two wells in experimental section 11. Oil-base drilling mud was used during coring. A 60%core recovery was obtained. Core samples consisted mostly of poorly cemented sands and silts. Encountered dense sandstones and siltstones formed only thin interlayers, at most 'several centimeters thick. Table 31. Characteristicsof cores Effective thickness,

%

Permeability millidarcies

25.0 24.9 24.2 25.0 27.5 24.0 21.7 24.1

1036 1990 1265 828 32 1 956 288 536

Porosity.

Oil saturation, %

804 82 1 821a 823 83 1 832 826 827

7.7 5.0 7.0 5.9 4.0 7.5 3.5 4.3

66.1 75.8 71.0 70.0 69.4 74.4

---

Table 32. Characteristicsof productive bed* in each experimental section Experimental section porosity, % I (area of well #804) I1 (area of well #826) III (area of well #833)

25.0 22.9 27.9

permeability, millidarcies

1,100 410 700

effective thickness, m

7 .O 4.0 4.8

*Second series of sands of the producing Maikop horizon I. Physical properties and oil saturation of the cores from individual wells are shown in Table 31. Oil saturation figures represent averaged values. Average values of parameters for the producing bed, with oil saturation of 71%, for the three experimental sections are given in Table 32. 147

Thermal Methods of Petroleum Production Back in 1966,the initial reservoir pressure of the productive Maikop horizon I measured at the oil-water contact, was 15 kg/cm*. Current reservoir pressures range from 2 to 12 kglcm2. Table 33 shows some data on Pavlova Cora crude oil, on the fields reservoir characteristics, and on the process of in situ combustion itself. Oil production from this reservoir began in October 1957 with an output of 6.5tonslday. Maximum average output per day was 21 tons. Thereafter the oil output kept on declining continuously, and towards the end of 1964,with 13 producing wells, it stabilized at 5 tonslday. Table 33.Reservoir characteristicsof the Pavlova Cora oil field Characteristics

Experimental Section

Area, ha Average depth to top of producing bed, m Effective thickness of producing bed, m Porosity, % Permeability, millidarcies Oil saturation, % Reservoir temperature,OC Crude oil density (s.P.). g/cm3 Oil viscosity under reservoir conditions, centipoise Content of tars and asphalts, % WC atomic ratio Coke residue (fuel), % Specific consumption of air for combustion, m3/m3 Coking ability of crude oil,%

I

I1

III

1.545 247 7 25 1100 71 21 0.945

1.5 225 4 22.9 410 71 21 0.945

2.56 244 4.8 27.9 700 71 21 0.945

173 36 1.587 28.4

173 36 1.587 28.4

173 36 1.587 28.4

350 4.5-5.3

350 4.5-5.3

350 4.5-5.3

In May 1961,water flooding was started in order to maintain reservoir pressure. However, the water broke through to the production wells so that further injection had to be stopped. Subsequently, these wells again started to produce oil without water. From the production declining curve for the Western Embayment of the Pavlova Cora field, it was calculated that without application of EOR methods the reservoir would be depleted by 1977 with a total recovery factor of only 11.7% of oil in place. The equipment, installations and processes employed are described below: On the I and I1 experimental sections (see Fig. 79),the in situ combustion is canied on by the "dry" method. A five-point well pattern is used, with the air injection well at the center. The "direct flow" variant of in situ combustion is employed. Observation wells are drilled between the injection well and the producing wells in order to monitor the process at the intervening distances. On the 111experimental section, the new "wet" variant is employed. The well pattern is as shown on Fig. 79. 148

Petroleum Production by In Situ Combustion (Fire Flooding) The equipment and installations consist of the following basic elements: Compressor station which supplies air and gas to three gas engine compressors of the 8GC type; Main air and gas lines leading from the compressor station to distribution points located at the experimental section of the field Distribution point of compressed air and of fuel gas to the wells of the experimental section, also of collection point of exiting combustion gases to be directed to the flare Control and measurement instruments and automation equipment including instruments for visual control, for registration of results and for regulation of the processes during experimentalwork Injection, production and observation wells Group installation including one gas trap for taking measurements and two operation traps with monitoring and control instruments and automation devices Buildings housing chemical laboratories

Fig. 80.

Diagram of system for collection and separation of fluids produced during in situ combustion at Pavlova Gora field: 1-main oil tank; 2-flare; 3-working tank of experimental section I; &measurement tank; 5-working tank of experimental section 11; &pump station; 7-production wells; 8-observation wells; 9-crude oil transfer to collecting point; 10-production from the wells of experimental section II; 1l-air for injection into experimentalsection II; 12-gas for burning to the downhole heater of ignition well at experimental section Ik 1 3 4 for cooling of the downhole heater body; 14-air to sustain in situ combustion within petroliferous bed at experimental section II; 1 5 4 r for cooling of downhole heater body; 16-air for burning to downhole heater; 17-gas for burning to downhole heater of ignition well at experimental section I; 18-air to sustain in situ combustion within petroliferous bed at experimental section I; 19-gas from compressor station; 2O-air from compressor station; 21-sampling outlet for discharge gases of in situ combustion for analysis; 22-to annular space of production wells in experimental section 11; 23-to annular space of production wells in experimental section I. I, 11, 111and IV-valves; Vflow gages. 149


In the process of experimental work, the compressor station was reconstructed twice. First, compressors of the 2SG-50 type were replaced with compressors 8GK(gas compressors), and then in 1979, new equipment, the OVG-2, was installed. The 0%-2 was built at the Chernovits Machine Plant and made it possible to conduct in situ combustion by the "wet variant." Oil production by "wet variant" requires an installation that can carry out the following operations: (a) charging of fuel gas and air to the downhole flame heater placed in the injection well for the period required to ignite the petroliferous bed; (b) air injection into the petroliferous bed to sustain in siru combustion and to make the burning front advance from the ignition well towards the production wells; (c) switching of air injection from the ignition well into the annular spaces of production wells; to intensify the oxidation process, it becomes necessary sometimes to inject air through the production wells, so that it flows in the direction opposite the advance of the burning front; (d) utilization of gases coming out of production wells - these gases are either burned to generate heat or re-injected into the petroliferous bed; (e) siphoning of air from injection lines to the monitoring instruments and automatic controls; ( f ) gas displacement of produced oil from the working tanks into the main tank. At the same time, four additional operationscan be carried out with this installation: (a) bringing of oil extracted by the production wells to a group separator to remove water and gas; (b) removal of combustion gases from the annular spaces of production and observation wells; (c) periodic sampling of gases from the annular space of production and observation wells and from the measurement tank for direct sample transfer to automatic gas analysers to determine their content of oxygen, carbon monoxide, carbon dioxide and methane; (d) recording of consumption of (1) fuel gas and air during the period preceding ignition of the oil-bearing bed,(2) air used up to sustain in situ combustion; ( 3 ) fuel gas used up to complete the combustion of hydrocarbons and carbon monoxide in the combustion gases coming out of production wells; (4) air required to cool the body of the downhole flame heater in the injection well. Some pertinent construction features of injection, production, and observation wells are discussed below. The wells were all cased, with the casing column cemented from top to bottom. Oil-base drilling mud was used to drill through the petroliferous horizon. To protect the casing from effects of high temperature, special liners were installed in the wells opposite the bottom section of the casing column. They consisted of heat resistant tubing, 11-26 m long, with pre-drilled openings, each opening 3 mm in diameter, with 100 openings per meter. The space between the casing and the liner was insulated with asbestos packing. Casing used for injection wells was 273-219 mm i n diameter; for production and observation wells, 219-146 mm in diameter. The liner had a smaller diameter of 146-114 mm. As more data accumulated on the process of in situ combustion, all new wells were drilled right through the petroliferous bed and then secured with a 146 mm casing. Then the column was cemented from top to bottom, and finally perforated opposite the oil-bearing horizon. At the start of production, the wells all sanded up intensively even at low production rates of 1-1.5 tons/day. In the process of in situ combustion, extensive breakdown of the bottomhole zone commonly occurs, resulting in formation of sand plugs. These cave-ins and plugs make the work of well pumps difficult and necessitate frequent well repairs. Bottomhole gravel filters and metal filters with dense screens were at first employed in an attempt to stop sand entry into the well and avoid work interruptions. This problem was finally solved by cementing these sands through coking, a method that was first tried in 1972. The program of experimental field work conducted on commercial scale at the Pavlova Gora field had a number of objectives: 150

Petroleum Production by In Situ Combustion (Fire Flooding) (a) (b) (c) (d) (e)

perfect the technology of igniting oil-bearing bed; improve the methods of creating a burning front within the bed; test the downhole heater installations and instruments; obtain information on effectiveness of in situ combustion; verify data obtained in laboratory experiments; (f) obtain data for preliminary technological and economic calculations.

The program consisted of the following four stages: I. Study of experimental wells in the oil field prior to trial injection of air into the bed 11. Study of hydrodynamic conditions during air injection into the bed and their influence on oil production 111. Study of the mechanics of bed ignition and the carrying out of operations to create the burning front and, then, to make it advance IV. Study of the "direct flow" variant of in situ burning both by dry and wet method over a long time period

Oilproduction prior to air injection Work at this stage was carried out in order to obtain production data under ordinary field conditions, also to test the existing systems for collection, separation and measurements of the extracted crude oil. These data, then, served as basis for evaluating the effectiveness of the subsequent thermal treatment. Production data on wells located within field sections selected for experimental work were collected and studied with special attention. At the same time, necessary adjustments were made in all components of the production equipment, including those of data collection and processing. Measurements were taken of all primary production parameters, that is, of quantities of produced oil, gases and formation water, of dynamic and static fluid levels, of characteristics of crude oil, gases and water, and of formation temperatures and pressures. Study of hydrodynamic conditions during trial injection of air into the petroliferous bed determined a number of facts, to wit: the air intake of injection wells, the distribution of air flows among the different production wells, and the ability of the crude to self-ignite within the bed without preliminary heating of the bottomhole zone. Next, the character of the oxidation processes taking place within the bed was determined from changes recorded (a) in the composition of gases produced, e.g., the reduction in oxygen content and the appearance of both carbon dioxide and monoxide; and (b) in the temperatures in the injection well, as well as in observation and production wells. Along with these measurements, at each stage control was maintained over the amount, temperature, and pressure of air injected. The character of the oil inflow into the injection well was also continuously monitored. At the beginning, fuel gas was being injected into the ignition well at the rate of 12,000 m3/day; later this rate was increased to 27,000 m3/day.

Creation of burning front of the three eqerimental sections of the oilfield The program called for testing the mechanics of igniting the bed using: (a) downhole gas flame heaters; (b) downhole electrical heaters, and (c) carbon packs. The downhole gas flame heater built by the Krasnodar Branch of All-Union Oil & Gas Research Institute is illustrated on Fig. 81. Air and fuel gas are brought separately via tubings into the combustion chamber of the heater. The secondary air, entering the combustion chamber tangentially, helps to stabilize the flare while cooling off the heater's body at the same time. The tangential feedings of the air make it possible to regulate the temperature of outgoing gases within a range of 200- 1,OOO°C. All component parts of the heater are made of heat-resistant steel, mark 1X18N9T. For lighting of the heater, a rocket ignitor fitted with benzine cylinder was used. The 151

Thermal Methods of Petroleum Production rated power of the heater is 150 kg W. This heater was tried on a test-bench well model, working for a period of 23 hours at pressures of 16 and 22.5 kg/cm*. The test data show that when pressure is increased, the heat resistivity requirements of parts making up the combustion chamber become greater. However, the burning process itself is stable and no complications arise either during the lighting of the heater or during its regulation by changing input of gas and secondary air.

a

b Fig. 81 Downhole gas heater. a-heater apparatus; binstallation of heater in the well; 1-body of heater, 2-tangential slits; 34istributor of air and gas for burning; 4-cup; 5reducer; 6-jet; 7- screen; 8conical liner; 9-pocket for thermocouple; 10-tapered tip of 38 mm tubing; 11-tubing column for lowering of heater apparatus; 12-seat for taper fit of heater apparatus; 13packers; 14-63 mm tubing; 15-seat for heating apparatus; 16-gas heater; 17-168 mm tubing; 18-102 mm tubing; 19-38 mm tubing; 20-well head equipment; 21lubricator.

In accordance with the program schedule, on November 22, 1966, trial air injection began through injection well 804 in the experimental section I. This trial injection of air was carried out in three stages, with time intervals of different duration between the periods of air injection (Fig. 82). Gas analyses showed that the oxidation process began taking place within the petroliferous bed within a few days after the start of air injection. First period of air injection into well 804 lasted from November 25, 1966, to December 10, 1966. Producing well 798 showed the strongest reaction to this air injection. Towards the end of this period, the oxygen content in the gas produced from well 798 was 3.2%. The air injection into well 804 was stopped during the period from December 10, 1966, to December 29, 1966. In that interval, the oxygen content in the gases from well 798 dropped to 0.3%, while its carbon dioxide content went up to 6-7%. The amount of air injected through well 804 during the first stage amounted to 103,600 m3. The second period of air injection began on December 29, 1966, and ended on February 10, 1967, during which time 374,000 m3 of air had been injected into the bed in the experimental 152

Petroleum Production by I n Situ Combustion (Fire Flooding) Section I. In that time, the content of carbon dioxide gradually decreased to 4 8 , and that of oxygen increased to 8.5%. After cessation of air injection between February 10,1967, and March 22, 1967, the concentration of carbon dioxide in the gases from well 798 increased to 13.6%. while that of oxygen dropped to 0.2%. During the same time period the temperature in the observation wells increased from 21 to 38OC. Such change in the gas composition and the temperature indicated that petroleum oxidation was taking place within the bed.

I

!

CO,,O,%

1st year 2nd;ear Fig. 82. Indicators characterizing development of in situ combustion at the experimental section I of Pavlova Gora oil field. a-air injection into m l l 804; b-content of carbon dioxide and oxygen in the gases produced through well 798.

Air injection into well 804 was again resumed on March 23, 1967, and was continued until April 4, 1967. The well intake capacity increased during the period from March 23, 1967, to March 29, 1967 from 16,000 to 28,000 m3/day with pressure increases, measured at the wellhead. from 25 to 35 kg/cm*. Subsequently, in spite of pressures of up to 36 kg/cm2, the well intake capacity decreased to 11,500 m3/day. With the resumption of air injection on March 23, 1967, the content of oxygen in the gas from producing well 798 went down from 3.8% all the way to 0.1% by April 7, 1967, while that of carbon dioxide went up from 5% to 10%. After March 31,1967, in the gas extracted from wells 798,831,807,821a, 823,821, and 771 the content of oxygen did not exceed 1-2%, while that of carbon dioxide did not drop below 8-14%. At the same time, the concentration of carbon monoxide in the gas taken from the observation wells was 1-2%. These data give evidence that a combustion front did form within the oil-bearing bed. 153

Thermal Methods of Petroleum Production Formation of the burning front in the area of injection well 804 was confirmed by the following additional data: (a) Temperature measurements were taken at the bottom of well 821 which was located at a distance of only 3.8 m from the bottom of well 804. On April 12, 1967, the temperature was in excess of 218OC. On May 15, 1967, a piece of lead dropped to the bottom of this well melted, indicating at this time a temperature in excess of 327OC. (b) Temperaturereadings from a thermocouple placed in well 804 at a point 14.5 m above the top of the petroliferous bed also showed increased values. (c) The intake capacity of injection well 804 dropped sharply after March 31,1967. The analysis of all of these data makes it possible to fix March 29, 1967, as the date on which the burning front formed at the experimental section I. At the experimental section 11, with ignition well 826 at its center, the burning front was created with the help of the earlier described heater built by the Krasnodar Branch of the All-Union Oil and Gas Research Institute (Fig. 81). Technical problems kept developing at the compressor station which, in turn, caused a number of interruptions in the operation of the heater. Before the burning front could finally form, the heater worked off and on during three separate time periods, as follows: December 27, 1967: period of 4.5 hours, at wellhead pressure of 29 kp/cm*; amount of heat introduced into the bed-434,OOO kg cal. January 8,1968:period of 3 hours; amountof heat introducedinto the bed-128,OOO kg cal. February 7 - February 9,1969: period of 54 hours, at well-head pressure of 30kg/cm2; amount of heat i n d u c e d into the bed4,OOO,OOO kg cal. During the first two periods of heater operation, the following observations were made: Well 327 Oxygen concentration dropped from 10 to 0.2%.carbon dioxide concentration increased from 516%. Well 803: Oxygen concentration remained high (up to 10%). Carbon dioxide concentration ranged from 2-8%. At the end of the third period (February 9, 1969) the front of combustion formed. The heating regime during the l y t 24 hours preceding the formation of the burning front is shown on Fig. 83. Gases leaving the heater had temperaturesranging from 510 - 84OOC. The intake capacity of the injection well continued to increase for some time after the burning front moved away from the well bottom. Towards the end of the heating period of the bottomhole zone of well 826, oxygen was almost entirely absent in the gases coming out of all the production and observation wells. oair/m3/hr

1

2

3 4

6

6 7

8

9 10 11 12 13 14 16 i 6 17 18 19 20 21 22

154

Fig. 83. Work regime of downhole gas heater in 826 from well February 8 to February 9, 1969. 1- temperature of gases on leaving the heater 2- air consumed for cooling 3- gas consumed for burning 232, hs& air consumed for burning.


In Experimental Section III,commercial scale tests on in situ combustion began in February 1976. Inasmuch as oxidized petroleum is more difficult to ignite, it had been decided not to try to inject air into the ignition well (No. 833). Instead, 18 m3 of crude oil was forced into the formation in order to saturate the bottomhole zone. According to calculations, this quantity of crude oil should have been sufficient to saturate the bed across its full thickness within a radius of 1.1 m from the well. The electrical heater was then lowered to the well bottom, whereupon injection of casing head gas, used as heat carrier, commenced. A control system was installed to measure periodically both the temperature and the consumption of the casinghead gas being injected. In the course of 29 days, 90,ooO m3 of casinghead gas has been injected into the bed at the temperature of 28OOC. In terms of heat, 2.36 million kg c d m was introduced. Upon termination of heating, inert gas consisting of final products of combustion was injected for a period of 1.5 hours at a calculated rate of 12,000 m3/day. Finally, air injection followed. The injection pressure kept on increasing continuously during a period of three months. rising from 22.5 to 36 kg/cm2 in spite of a certain reductions in the rate of injection. In May 1976, carbon monoxide was detected in the gases coming out of all of the production wells in the Experimental Section 111. Presence of this gas constituted evidence that in siru burning was taking place in the oil-bearing formation. This process of "dry" combustion continued for 16 months, during which period of time 8,491,400 m3 of air was injected into well 833 at the average rate of 16,100 &day. At the end of August 1976, the "dry" variant was changed to "wet," with simultaneous injection of water and air conducted cyclically. Development of in situ combustion process of Pavlova Gora (Fig. 83) The in situ combustion posed a number of questions that had to be answered. Among these were the following: (a) how to control the advance of burning front to control the in situ combustion itself and to determine the extent of its spread within the formation, and (b) what effect did the process have on oil and gas production from the reservoir and on the operation of the different elements of the oil field installation. Once the burning front had formed, the produced gases were analyzed systematically for their content of oxygen, carbon monoxide, and carbon dioxide. To that end, gas samples were taken periodically from producing wells and then analyzed on a mobile gas analyzer of the ORS type. Checking of gas content showed that accurate results could be obtained from gas samples of production wells. Samples taken continuously as the gases were being produced reflected actual formation conditions existing at the moment of sampling. On the other hand, distorted data on gas composition may result when gases are sampled periodically from temporarily shut-in observation wells. It is known that carbon dioxide readily dissolves in petroleum. After the shut-down of observation wells and the formation of a depression on the well bottom, the gas that filters through the bed to the observation well may pick up part of the carbon dioxide that escaped from the oil. Due to this phenomenon, gas samples periodically taken from the observation wells contained up to 25%. and sometimes even more, of carbon dioxide, whereas the gases sampled continuously in the production wells had no more than 21%. To measure the formation temperature in the observation wells, thermocouples were placed in wells at 1-1.5 m intervals opposite the entire cross-section of the oil-bearing bed. These thermocouple readings were automatically registered at the station of control-measuremen't instruments. In the production wells, the temperature was measured with a maximum mercury 155

Thermal Methods of Petroleum Production thermometer during well servicing work. Crude oil characteristics were determined from recombined samples. The data on oxygen, carbon monoxide, and carbon dioxide content in extracted gases gives evidence that the in siru combustion process became effective in Experimental Section I from 1967 on, and in Experimental Section I1 from the end of February 1969. Content of oxygen in the gas sampled in the wells ranges essentially from zero percent to a fraction of one percent, that of carbon dioxide-from 12-17%. and that of carbon monoxide, measured in observation wells, from 1-2% during the first few months of the process, and then from a fraction of 1% to 1%. A significant difference in gas composition from this general picture was observed during individual time periods only in wells 798, 821a, 821, 803 802, 823 and 771. In these instances, oxygen concentration was going up while that of carbon dioxide was going down. These changes were due to either the breakthrough of injected air from the ignition well to the other wells along the bed or the passage of burning front across the bottomhole of observation wells and the access of pure air. In order to prevent the breakthrough of injected air into the production wells. either their outputs were reduced or they were temporarily shutdown. After the lapse of a period of time these wells would be brought back to a normal production regime. The formation temperature data recorded for observation wells (Fig. 83) allows us to conclude that in Experimental Section I only in two instances was the burning front distinctly marked. The above applies to temperature readings of April 15, 1967, in well 821 and of September 1968 in well 821a. In the Experimental Section 11, the approach of the combustion front was recorded in well 827 at the beginning of March 1970. well 824

tsoc

Fig. 84 Change of formation temperature in observation wells of Experimental Section I.

A _

0

I

2

3

4

5

1

6

1

7

8

1

9

10

11

i2

430

300 200 100

0

Years Examining the temperature distribution along the cross-section of the petroliferous formation, we find maximum value present in the middle of the bed, with sharp temperature decreases occurring towards it top and bottom (Fig. 85). These decreases are due to heat losses into the overlying and underlying rocks; they take place as the combustion front advances along the oil-bearing bed. Additionally, in wells 821, 822 and 824, a tendency can be observed for the 156

Petroleum Production by In Situ Combustion (Fire Flooding) temperature maximum to shift closer towards the top of the petroliferous bed. This peculiar phenomenon has to do with the gravity separation of crude oil and injected air as the two filter through the bed. In Experimental Section I, the formation temperature in all of the observation wells generally dropped in the course of 1969-1970. In the wells 821 and 821a of this section, the temperature decrease occurred because the burned-out zone of the bed was now being cooled by the air as it continued to flow from the injection well 804 to the burning front past the bottomholes of the wells 821 and 821a. In the remaining observation wells of the section the temperature decrease was due to the reduction in the rate of air injection into the well 804. depth, m

well 821

depth

well 822

I

0

!%J

I

t

I00

160

I

200

250 t,*C

depth, m

well 823

depth, m

well 824

I

237.0

237~8

W1,8

Fig. 85. Change in formation temperature across the thickness of the petroliferous bed recorded in observation wells of Experimental SectionIin Pavlova Gora field.

243.8

2,,a 246.8

o 157

eo

I

I

L

loo

IW

200

I:C

I

Thermal Methods of Petroleum Production The oil production of individual wells of the Western Embayment in the Pavlova Gora field increased 10-15 times by comparison with their output prior to the thermal treatment. For the Western Embavment reservoir as a whole, the oil production following the fire flooding increased 4-5 times (Fig.-86). wl

years

1

Fig. 86.

Field operation data on Western Embayment Reservoir of Pavlova Gora oil field.

Under reservoir conditions, with in situ burning, some gaseous products of combustion, mainly carbon dioxide, dissolve in the crude. This process causes changes in the properties of crude oil, e.g., a reduction of viscosity and increase in volume coefficient. However, crude oil extracted from Western Embayment reservoir by in situ combustion method did not show any noticeable changes in its characteristicsduring the entire period of the thermal treatment. To determine the dimensions of burned-out zones as well as the actual critical densities of air flow at the combustion front, the following formulas were employed: 1.

Radius of burning front:

2.

Actual density of air flow of the combustion front: U=

Qair

2mfront %ombh

3.

Critical density of air flow (Combustion front must maintain at least a minimum rate of advance. It is assumed that in situ combustion ceases when this rate drops below the minimum value): 158


The symbols used in the above formulas have the following meanings: burning front radius rfront coefficient of oxygen utilization at the burning front (it is assumed to hXy equal 0.18) C & - total amount of injected air,m3/day Qair - quantity of injected air,m3/day coefficient of vertical sweep (thickness) of petroliferous bed by in situ qomb combustion (it is assumed to equal 0.65) q& - air consumption to burn 1 m3 of reservoir rock (350 m3/m3); hem - effective thickness of oil-saturatedbed, m minimum admissible rate of advance of combustion front (for Umh Experimental Sect. I it is 0.015 m/day, and for Experimental Sec. II 0.03 d d a y )

As of December 31, 1978,the average radius of burned-out zone for each of the three Experimental Sections was as follows: Section I - 21 m, Section II - 15 m, and Section I11 - 31.5 m. The figures quoted for Sections I and I1 were confirmed by geophysical studies, and these for Section III were calculated. In determining the density of air flow, it was assumed that the burning front advanced radially. These calculations indicate that beginning in about 1970,the density and air flow dropped below the critical. However. in Experimental Section I the density of air flow along the borders of the burning front was not uniformly distributed. As a result, the air flow formed "a tongue" "in one direction, namely in the direction of production well 832. Towards the end of 1972,it was almost reaching the bottomhole of this well so that the well had to be shutdown. For the three experimental sections taken as a whole, the rate of air injection was not high enough because the compressor stations were unable to supply the necessary amount of air (Fig. 87). In order to bring the oil production by in siru combustion process from the Western Embayment reservoir to what would be considered a normal rate, the output capacity of air compressor station would have to be increased to lOO,OOO m3/day. Dying out of the combustion process is observed in the direction wells 831,798,797,and 824. This fading is indicated by temperature readings taken in observation wells 822,823,and 824 and by analyses of gases sampled from these same wells. Within the zones in which the in siru burning is dying out, slow processes of oxidation are taking place. These processes tend to stabilize the temperatures in the observation wells for long periods of time; they remain within the range of 110-2OOOC. For indi3idual wells, these temperature changes are as follows: During

Well No.

822 823 824

Temperature increased to

208OC 1968

i During Yeam

1969-74 1969-73 1969-75

189OC 159

Temperature decreased to

900c 1200c 1 l00C

Thermal Methods of Petroleum Production Q, million m3/month

years Fig. 87. Dynamics of air injection at Western Embayment Reservoir of Pavlova Gora oil field. Temperature increase in all of the three wells during 1968 was due to the approach of condensation front to the bottomholes of these wells, after the passage of this front, beginning with 1969, the temperature started to go down. At the Experimental Section 111the "wet" variant of in siru combustion has been tested. A GR-16/40 type pump was installed at Experimental Section 111 to force water downhole of the injection well 833. The water input could be regulated between 30 and 380 m3/day; the pump operated under pressures of up to 40 kg/cm2. Water and air were injected in cycles: first, water was charged for 2 days at the rate of 200 &day; then, air for 5 days. By January 1, 1978, 3.500 m3 of water and 2,000,000 m3 of air were injected. By this same date, the water-air ratio was 1.7 x 10-3 m3/m3. During the period of time when water and air were being alternately injected into the well 833, its wellhead pressure rose only a little. However, during the same time, as a result of re-pressurizing of the petroliferous bed through water and air injection, the producing wells started to yield a stable water-oil emulsion. Formation of this emulsion made the processing of the produced crude difficult so that further combined injection of water and air had to be stopped. Nevertheless, the experiment demonstrated that the use of "wet" variant of in situ combustion does offer several advantages and that it can be conducted without major problems.

Petroleum production from the Western Embayment reservoir Oil production from I Maikop horizon belonging to the second petroliferous series at this sector of Pavlova Gora field started in January 1959. Drilling of development wells in this reservoir was completed by 1970. Natural reservoir drive under the depletion regime was employed for oil production from January 1958 until December 1966. Maximum production from this Western Embayment reservoir was attained at the beginning of 1960, that is, upon completion of the development wells. It amounted to 470 t of oil/month. But, already at the beginning of 1961, the output decreased by about 50%, amounting only to 230 t/month. By December 1966, this reservoir was producing only 110 t/month. The total production by natural drive for the 8-year period amounted to 23.600 t of oil, 9,100 m3 of water and 910,000 m3 of natural gas. The average gas factor was 38 m3 gash of oil. Formation pressure during this period of time decreased from 10 kg/cm2 to 7.5 kg/cm2. Initial reserves of oil in place in the Western Embayment reservoir were sufficient for the conduct of in sifu combustion process. Calculations showed that by natural reservoir drive(s), the final recovery factor by production under depletion regime would have been 11.7% of oil in place. At the end of 1966, that is, immediately prior to the commencement of thermal process, the current recovery factor reached 9.1 %. 160

Petroleum Production by I n Situ Combustion (Fire Flooding) From 1967 until 1978, the in situ combustion method was employed only at 3 (experimental) sections out of a total of 9 that were planned for the Western Embayment reservoir. Moreover, the amount of air injected at the 3 experimental sections was not adequate for this thermal process. In spite of these limitations, the application of the in situ combustion method resulted in significant improvement of oil production at relatively low cost. During the 12 years of in situ combustion, 47,850 t of oil were produced. Of this amount, 41,100 or 86% represented an additional yield attributable to the thermal treatment. From the beginning of production in January 1959 until the end of December 1978, the total amount of oil extracted from the Western Embayment reservoir was 80,100 t; the current recovery factor was 31%.

Thus, the application of in situ combustion made it possible to nearly double the output rate. Already towards the end of the second year of the thermal treatment, the total oil output from the reservoir exceeded the ultimate recovery calculated for production by natural drive(s) at depletion rates. The current recovery factor with the thermal treatment was 2.35 times greater than the maximum recovery factor calculated for production by natural reservoir drive. At the end of 1980, the current production level equalled 150 t of oil per month. The amounts of additional oil produced in any specific year during the in situ combustion treatment was as follows: I 1 1 2 1 3 I 4 1 5 1 6 1 7 1 8 1 9 1 10 I 1 1 112 Year Output,lOOOstonsI 3.4 13.91 4.213.71 2.61 2.41 3.41 3.01 3.51 3.51 4.4 12.1

I [

The above figures show that the amount of additional petroleum produced varied from year to year. At first, it went up; in the fourth year, it started to decrease; went up again in the seventh year; and fiially, during the twelfth year, again declined. These output variations were attributable to (a) changes in the conditions of in siru combustion process, (b) completion of an additional production well, and (c) improvements made on producing wells. During the first stage of experimental work, active advances of combustion fronts were observed. They were accompanied by intensive displacement of crude oil from burned-out zones and by the physical and chemical effects of carbon dioxide as it was dissolving in the crude. From December 1968 on at Experimental Section I, and from March 1970 on at Experimental Section 11, the density of airflow declined to the minimum values, at which the process of in situ combustion begins to fade out. At the same time, the effectiveness of oil displacement also started to diminish. The increase in the additional oil produced during the subsequent two years, in 1973 and 1974, was due to placement in production of five new wells drilled during 1972. The operating conditions of production wells were also improved, at that time, when the entry of sand into the wells was finally stopped by coking of these sands in the bottomhole zones. The data on additional oil production from the I Maikop horizon of the Westem Embayment reservoir attributable to the thermal process are as follows: Experimental Section I Experimental Section II Experimental Section III Total

4,090 t 13,550 t 3.190 t 20,830 t

The effectiveness of the thermal process can also be judged from air consumption per each ton of additional oil output. These figures, shown separately for each year during which oil was produced by the in situ combustion methods, are as follows (Fig. 88): 161

Thermal Methods of Petroleum Producfion Year

1

2

3

4

5

6

7

8

9

10

11

12

Air consumption, m3/t 1.546 2.118 2.183 2.600 3,523 3.445 2,384 2,153 2,324 2,468 2.177 4.286

Fig. 88. Change in air consumption per ton of exnactable oil with years. According to the process flow diagram prepared prior to the experimental field work, the average relative air consumption equalled 1,415 m3/t of additional oil output. However, the data show that only during the first year of in situ combustion was this figure fairly close to that obtained in actual field experiments. In subsequent years the average air consumption per ton of oil started to increase. Even during the three years of active burning, namely 1967.1968, and 1969, it was more than 50% higher than the calculated average. During the period from 1970 to 1972, the relative air consumption increased significantly, exceeding the projected consumption by 1.8-2.6 times. Heat generated at the burning front was actually greater than that projected by the process flow diagram. Therefore more oxygen had to be used in the process, which of course explains the differencebetween the projected and the actual relative air consumption per ton.

Cost effectiveness of in situ combustion process Additional capital or fixed costs for this thermal process amounted to 369.000 rubles. Of this sum 104,400 rubles was spent on drilling new wells in 1966, and 40,000 rubles in 1972. Thanks to the high effectiveness of this process the payback period was only about 2.2 years. The average annual operating expenses for the thermal process amounted to 11O.OOO to 120,000rubles. Included in this figure were 38,400 rubles for air injection. The cost of producing one additional ton of oil by in siru combustion was nearly 20% lower than the cost of producing the same ton of oil without resorting to this method. Total cost savings for the entire period of application of this EOR method amounted to several hundreds of thousands of rubles; however, with the years, cost effectiveness decreased. Thus, during the active phase of the process, namely years 1967,1968 and 1969, cost-effectiveness amounted to 18-20% per year, but during the last years it decreased to 8-11% per year. The results obtained warrant the following conditions: The implementation of the process of in situ combustion in the Western Embayment (a) Reservoir achieved high technical standards and economic efficiency. Prospects for progress are well-founded on a number of research projects that are (b) now under way at the Krasnodar Research and Design Institute. Projected total oil yield with the application of in situ combustion methods from the (c) Western Embayment reservoir will amount to 164,OOO t, representing a coefficient of ultimate recovery of oil in place equal to 0.63. The corresponding figure for production by natural reservoir drive(s) at depletion rates would be only 0.1 1. (d) Studies indicate that in SiM combustion may also be successfully employed on the Eastern Embayment reservoir of Pavlova Gora field. At the first three experimental sections (I, I1 and 111) active phases of this thermal process have been already concluded, giving positive technical and economic results. Experience gained on 162

Petroleum Production by In Situ Combustion (Fire Flooding) this project should make it possible to improve this process even further and to employ it on other petroleum reservoirs. 4C.

CEMEN~ING_QE_LQQSE-SANR~-~N-NEAR-~ELL~~Q~~QM-ZQNE-~ CQKING

Sand entry into the well bottom creates serious problems during oil production both by in siru combustion methods and by cyclic steaming of the reservoir. Carried in with the oil, the sand can abrade equipment. both in the well and at surface installations; it forms plugs on well bottoms, reduces oil output; and may even force the abandonment of production wells. With in siru combustion, these problems are aggravated because of high rates of production that are required in order to achieve cost-effectivenessof the process. This means that individual sections of the oil field, 2 to 5 ha in area, may have to be fully exploited within 3 to 3.5 years. Such high rates of reservoir exploitation become difficult to obtain because of sanding of production wells. To combat sand entry, different methods are used, such as employment of gravel, silt, and other types of filters, or consolidation of loose sands with synthetic tars. Coking of sands in the bottomhole zone of the well offers probably the best solution.

Technological principles of sand cementing by coking Hot air is injected through the well and into the bottomhole zone of the reservoir sand. The petroleum in the sand converts to coke which then becomes the cementing agent, holding the loose sand together. At the same time, aside from the desired consolidation of the sand, a fairly high permeabilityis retained within the treated zone near the well bottom. Studies show that crude oils containing more than 12-14% of tars and asphalts, when thermally treated, can form petroleum coke which then acts as cement. The strength of the consolidated sand depends on the temperature at which the coking treatment took place. It is measured by the compressive strength of core samples of the coked petroliferous sand. With increased temperatures, this strength goes up, and at 3600C it attains its maximum value of 120 kg/cm2. But if the temperature is further increased, the compressive strength of the coke decreases, and at 4600C the sample disintegrates. The permeability of the reservoir sand decreases upon coking by 30% from the initial value; however, with synthetic tars, it decreases by 90%. The coking of reservoir sands in the bottomhole zone must take place under strictly controlled conditions as regards (a) the rate of air injection; (b) rate at which the temperature of injected air is increased, (c) the temperature maximum; (d) the duration of the treatment, and (e) the energy consumption. Based on the data of sand cementing by coking at Pavlova Gora oil field, the recommended rate of air injection is 900 to 1,OOO m3/day for each meter of bed thickness. The temperature of the injected air should be slowly increased, at the rate of 10 to 15OC per hour, in course of the fmt 24 hours until the final temperature of 300 to 350OC is attained. The temperature of about 3 W C is then maintained for most of the duration of the treatment. Only towards the end, is it raised to 350 to 4000C. The length of time of the coking process is determined either by the average heat consumption per each meter of bed thickness, or by detecting the moment at which burning front forms within the reservoir. This moment is indicated when intake capacity of the well changes suddenly and drastically. The average value of relative heat consumption equals approximately 0.5 to 1 million kg c u m . Technical characteristics of equipment used in sand coking For heat generation, serially manufactured equipment for electric heating of oil wells, Mark SUEPS-1200 is employed. When permanent compressor stations are not present in the oil field, one can employ the mobile compressors for air injection, Mark UPK-80 or A D S . The last 163

Thermal Methods of Petroleum Production mentioned type consists of two compressors of the AVSh 3.7/200 class. Inasmuch as the sand coking is a continuous process, it is better to have two compressors in order to insure uninterrupted air supply. The AKDS unit is most suitable for that purpose. Wellhead equipment layout for sand coking in the bottomhole zone is shown on Fig. 89. A wellhead shut-in valve is installed to seal off the well when necessary; also a specially-designed lubricator provided with cable line packer is used so that the heater can be lowered and iaised. TO measure the amount of air injected. flow meter type DP-430 can be employed. Several electrical measurement instruments, such as the potentiometer and megohmmeter are also necessary. Fig. 89 Equipment layout for sand cementing of bottomhole zone by 1-petroliferous bed 2-well 3-electric heater &air from compressor, 5-diaphragm flow 6-shut-off valve €&lubricator %platform for servicing of lubricator seal 1Malfdemck 1l-cable line 12-hoist 13-tranSfOItnU The temperatureof injected air can be monitored as per diagram shown on Fig 90.

Elm 3

Fig. 90. Diagram for remote control measurement of temperature of air injected into oil-bearing bed. 1-weld of thermocouple; 2-thermometer; 3-conductor cables; M-direct current bridge; P-potentiometer. 164

Petroleum Production by In Situ Combustion (Fire Flooding) The temperature of the air, after it has been heated by an electric heater, can also be determined by calculation using the following formula: I&

860N =r+ 400c

where: N

-

C

-

v -

actual power of electric heater. kg W air consumption, m3/hr; volumetric heat capacity of air, kg cal/m3PC (average value is 0.3 kg cal/m3PC)

Well selection for sand cementing by coking Generally speaking, all production wells which have sanding problems can be treated by coking of their bottomhole zone regardless of the bed thickness, well depth, formation pressure or production method employed. In practice, however, well suitability is limited by the following technical characteristics of the available heater installation: (a) conductor cross-section of power cable; (b) quality of cable insulation; (c) length of power cable; and (d) heater capacity. In the case of the earlier mentioned electric heater, type SUEPS-1200 employed at the experimental sections of Western Embayment of Pavlova Gora field, the production wells had to meet the following requirements: (a) depth of oil-bearing bed-not more than 1,200 m; (b) the less than 60% of the diameter of production tubing-168 mm; (c) static bottomhole pressure working pressure available to the air compressor; and (d) absence of large cavities formed as result of sand movement from the bottomhole zone into the well if these cavities are too large to be filled by sand injection. If sand injection becomes necessary, it is advisable to use the coarse-grained sand of the size fraction employed in hydraulic fracturing. Sand cementing techniques coking ability of petroleum in a given reservoir must first be determined. The crude should contain at least 10% of pitches and 3 - 4% of coke, by weight. When the content of these tars and coke is smaller than these percentages, petroleum of such specific composition must be injected in order to saturate the bottomhole zone within a radius of 1-1.5 m from the well. Preliminary injection of suitable crude oil is also advantageous if the well during the preceding production period already yielded a lot of water. In such cases, the oil saturation of loose sands in the bottomhole zone may not be sufficient for successful cementing by cokihg. If during an earlier production period great amounts of loose sand had been carried into the well, large cavities in all probability formed in the bottomhole zone. Such cavities must first be refilled with sand. To prevent the development of this condition, it is useful to cement these loose sands by coking at an early stope of oil production. The cementation procedure takes place in the following sequence: Air injection at input rates of 900 - 1,OOO m3/day per each m of bed thickness. (a) Switching on of electrical heater at the voltage of 410 - 450 V. (b) Measuring of the downhole air temperature after the preliminary heating period. (c) Suitable regulation of the temperature either by changing the voltage of the (d) downhole heater or by adjusting the rate of air injection. For a period of 24-48 hours the air temperature should not be permitted to exceed 250-3OOOC. It must then be increased to 3500C and kept at that level until the end of the treatment. Continuation of coking for a period of time whose duration is determined by the (e) strength of the heater and the average energy consumption per each m of bed 165

Thermal Methods of Petroleum Production thickness. To determine in advance the approximate length of this period in days, the following formula is used:

Where:

Q

- average assumed consumption of heat energy per each m of bed

h N -

(0

thickness, kg cal/m bed thickness, m actual power of heater, kg W

As the data on coking for a particular oil reservoir accumulate with experience, it becomes possible to determine exactly the length of t i e required. In order to avoid the unintended oil ignition in the bottomhole zone during coking, the changes in the air intake capacity of the well must be monitored. The moment of ignition is signalled by a sharp drop in this intake capacity. Switching off of the electric heater and the cessation of air injection at the end of coking of the bottomhole zone. The heater is then raised into the lubricator. With the master gate valve closed, the lubricator is then disassembled.

Well completion The manner in which well completion is carried out has a marked effect on the success of sand coking in the bottomhole zone of production wells and, therefore, on the recovery of additional petroleum during the subsequent in situ combustion drive. As a side effect of the cementing treatment, high viscosity oxidation products form in the bottomhole zone of producing wells. Because well output may suffer as a result, these products must be removed during well completion. This task can be accomplished in one of the following ways: (a)

(b)

(c) (d)

The bottomhole zone is drained immediately after the end of coking treatment. Because of the high temperature which exists of that time in this zone, the abovementioned oxidation products still have a reduced viscosity. As a result, the filter at the bottom of the well becomes actually cleaner. By lowering of the pressure exerted on the bed the rate at which the drawdown increases is limited, which prevents damage to the filter. The pressure should be lowered until the outflow of gases generated during coking completely ceases. Bottomhide zone is reheated by means of cyclic injection of steam at the rate of 1,000 m3/m of bed thickness. This radially-directed heating should raise the bottomhole temperature to a level higher than that achieved during the coking treatment. Effective solvents of asphalt-tar substancescan be employed. Crude oil is injected in the amount 2 to 3 times greater than the well bore volume.

After completion of one of these operations, the downhole pump is installed, where upon the well is placed in production. Main results of cementing loose sands by coking treatment During the three-year period, 9 production wells out of a total of 19 at the Western Embayment of Pavlova Gora field were treated for cementation of the bottomhole zone by coking. 166

Petroleum Production by In Situ Combustion (Fire Flooding) Of these 9 wells. 5 were treated 2 times each, and 3 were treated 3 times each. Repetition of treatment became necessary either because of inappropriate procedure during the first or second treatment, due to inexperience or for other reasons, such as breakdown of air supply system or formation of plugs on well filters. Success of the treatment was judged on the basis of increases in production of additional oil. During the three-year period, these increases were obtained in 94% of all cases. These results demonstrate that coking of loose sand is much more effective than other methods, such as cementation with different synthetic resins. Best results were obtained in wells: 797a. 843,834, and 831. The length' of effective production periods for individual wells subsequent to coking treatment was as follows: nonperiod.Wnths Number of wells

26 > 17 > 15 > 12 > 6 c 6 1 1 1 2 2 7

Maximum length of time of effective production of more than two years was recorded for well 797a. The average duration was 9 months. Let us exclude from our analysis the first cementation treatments carried out during the initial periods when the techniques were not yet perfected and the necessary experience was still lacking, e.g.. the first treatment of well 797a. Further, let us also exclude treatments interrupted because of technical failures or because of plugging of the filter, e.g., treatments of wells 831 and 798. If we disregard these unsuccessful treatments, we shall then obtain an average duration of the effective production period of 21 months per well. As seen from Table 34, the temperature of injected air and the amount of heat introduced into the bed have considerable influence on the effectiveness of the coking treatment of the bottomhole zone. Best results correspond to higher temperatures (35BC) of injected air and higher specific consumption of thermal energy (1 million kg cal) per meter of bed thickness. Wells 797a, 843, and 834 demonstrated this relationship; they recorded air temperatures of approximately 3500C and specific consumption of heat energy of 0.7 - 2.0 million calories. Analysis of data from a number of wells treated in 1974 showed air temperatures of 200 to 32OOC. while the consumption of thermal energy fluctuated within a wide range of 0.5 to 1.0 million kg c a m . It is apparent that at temperatures other than optimal, poorer results are obtained. 4 d.

IN.SIT~(_~=9MB~STIaN_AT_ZYB_zA-cLYB41(II_YAR_PIL_EIELBS fW H E R E R g C E S _ W I T H _ M A C R a , A N P - M ~ ~ ~ a ~ a R ~ I T I E S _ Q ~ ~ Y R Ta~~EB-I~TIIE-SAM~E~~B~~R~

The second reservoir of heavy oil selected in 1964 for the testing of in siru combustion process was Lens IV of the Sarmatian horizon at Zybza-Glubokii Yar field. The oil-bearing bed is heterogeneous in character both along the strike and dip as well as across the profile. The reservoir is made up of siltstones, interlayers of clay, dolomite, and shale breccias or large fragment breccias along fractures. The reservoir-rock permeabilities range from 0.05 to 1 Darcies and more. Oil accumulates in fractures, also in pores or cavities formed by breccia.

167

Thermal Methods of Petroleum Production Table 34. Data on commercial-scaletesting of loose-sand cemenation by coking

-

Treatment

param as

#

'a

t

i

i1

38

3

+i

w

ox

i +j

:5'

-

z -fi

c)

p

Qd -

--

6,000

250

99

797a 26

5.0

4,200

350

707

831

2.5

--

3.100

350

43

Foreign bodies detected on well bottom

798

2.0

10.0

3,600

340

55

Treatment interrupted

808

--

10.0

4,500

280

-

Not effective

798

15

10.0

4,500

350

41

Limited effectiveness

843

17

5.0

4,500

350

355

Effective

831

6

10.0

4,300

350

130

Effective

807

6

10.0

6,600

200

60


808

3

10.0

4,200

300

55


829

3

10.0

5,000

320

32


798

1

10.0

5,500

270

-

Positive results

833

-

10.0

4,200

350

-

Positive results

831

5

5.0

4,700

330

25


833

12

7.0

4,700

340

70


834

12

10.0

5,400

350

125

829

5

10.0

5,100

260

60

797a

4

-- 168

Well was idle prior to treatment Well still producing

Effective Limited effectiveness


Some of the reservoir parameters are as follows: Area of petroliferous lens, ha Average depth of reservoir, m from surface Average thickness, m Current oil saturation, % Formation temperature,OC Oil density, g/cm3 Oil viscosit) under reservoir conditions,centipoise Atomic WC ratio Content of sulfur-rich tars, % Consumption of fuel (coke residue), kg/m3 Air consumption per m3 of rock, m3/m3

6.7 660 5.7 42.1 29 0.976 2,000 1.586

64 39.4 425

Several other oil fields in Krasnodar Petroliferous Region are of a similar type, which is one of the reasons in fist place why Lens IV of Zybza-Gluboku Yar field was selected for this experimental field work on in situ combustion. The plan called for development of a linear burning front. Three injection wells were therefore located along the short axis of Lens IV reservoir at a distance of 70 m from each other (Fig. 91). During subsequent in situ combustion, the burning front advanced in direction of the long axis of Lens IV, 230 m to one side of injection wells and 130 m to the other side. To monitor the in situ combustion process, an observation well was placed on each side of the line formed by the three injection wells. Altogether 18 wells have been drilled into the Lens IV reservoir. Within the limit of Lens IV, the oil-bearing horizon shows great heterogeneity in its reservoir properties; in fact, in places, some of these reservoir characteristics become altogether absent. In one small area of Lens IV, reservoir cores from the wells indicated high permeabilities of the oil-bearing bed. But cores from adjacent wells barely showed the presence of any petroliferous horizon. Finally, in one of the injection wells, namely well 1H situated in the pinch-out zone of Lens IV, the oil-bearing stratum was altogether absent. Lens IV dips to the south; its northernmost part lies about 100 m higher than its southern extreme. According to the original plan, the entire Lens IV was regarded as one single oil reservoir. However, as the experimental work progressed, existence of four separate reservoir units had been ascertained (Fig. 91). From the results of air injection into the individual wells, it was possible to determine, at least conditionally, the limits of these four units. In the central section of Lens IV, where wells 2H, 3H, 4H, 181, 371,2E, 1K and 317 are located, the reservoir rocks are strongly fractured, but they do not contain free, mobile oil. In 1971-1972, work was conducted here to start in situ combustion. The air flowed freely along the fractures from the injection well to the production wells. The amount of oil in this reservoir unit was insufficient. Air was injected here into the well 3H, and subsequently 1852 t and 1460 t of steam was injected into production wells 2E and 317, respectively. Drainage of these two production wells followed, but neither petroleum nor water was produced.

169


Fig. 91.

Structure contour and isopach maps of Lens IV reservoir of Sarmatian horizon. I-injection wells; II-production wells; III-observation wells; IV-pinch-out of Lens IV; V-structure contour lines drawn on top of Lens IV petroliferous horizon; VI-isopach lines; VII-limits of individual sections of Lens IV reservoir.

Repeated attempts have also been made in this central section of Lens IV to initiatein situ combustion. To that end, the earlier described downhole gas heater, built by the Krosnodar Branch of All-Union Research Institute, was installed in the injection wells 2H and 3H. However, each time, 3 - 10 hours after the commencement of heating, the air intake capacity of the two wells would drop. During these attempts, the rate of consumption of natural gas was 240 rn3/day, and that of air input for both gas burning and downhole heater cooling was 12,000 m3/day. However, bed ignition could not be attained. Changes in values of some parameters recorded during one of the stages of downhole heating andof air injection are shown in Fig. 92. For the downhole gas heater to function normally, it must be kept on a stable operating regime which includes also a steady air supply. Because of the decrease in the air intake capacity of the well, it became necessary to increase the air injection pressure, so that the air supply rate to the gas heater could be maintained at the rate of about 12,000 m3/day. Well head pressure was thus gradually increased to 35 kg/cm*, the maximum the compressor station could produce. 170

Petroleum Production by In Situ Combustion (Fire Flooding) Subsequently, the input of air supplied downhole decreased and the heater operation had to be stopped. E

0

1

2

3

4

5

6

7

8

9

10

time, hrs

Fig. 92.

Changes in air consumption, pressure, and temperature with time during operation of downhole gas heater: Curves: 1-air input through annular space between the 65 and 127 mm columns; 2-pressure measured in trap; >pressure in the annular space between 127 and 203 mm columns; &pressure in the annular space between the 65 and 127 mm columns; 5-pressure in 38 mm column; &temperature of gases leaving the heatec 7-input of air injected through 38 mm column to sustain gas burning.

Rock fractures present in this section of Lens IV reservoir provided avenues for movement of fluids through the bed. However, upon heating, reservoir rocks expanded, which in turn tended to close these fractures. Air intake capacity of the bed and therefore of the injection well, also suffered as result. This condition was aggravated by lack of automatic temperature controls on the gas heater installation downhole. Thus, towards the end of each period of operation of the heater, the temperature would rise significantly. This sharp increase in bottomhole temperature was itself, in its turn, caused by the aforementioned reduction in the air intake capacity of the reservoir. As the amount of cool air that could be forced into the bed decreased, so did the amount of heater-generated thermal energy that this cool air flow could remove into the reservoir and away from the bottomhole zone. Moreover, it was noted that after periods of air-cooling, with gas heater turned off, the original air intake capacity of the well could no longer be restored. Apparently during the periods of overheating, the rocks in the bottomhole zone partially fused, with the resulting loss of some permeability. Only after the treatment of the bottomhole zone with solutions of hydrochloric or hydrofluoric acid these sintered rocks would disintegrate, thus restoring the original air intake capacity of the injection well. But subsequent attempts to ignite the petroliferous bed by reheating it with the downhole gas heater again resulted in a reduction of air intake capacity of the well. 171


Laboratory experiments were carried out on a linear model simulating the characteristics of the oil-bearing bed of Zybza field. This model reproduced a heterogeneous porous medium consisting of sand and breccia. The purpose of the study was to determine the mechanism of in situ combustion and to define the working parameters of such a process as it applied to the conditions in Zybza field. The following pertinent facts have been established through these experiments: (a) (b)

(c)

Oil combustion within the rocks made up of breccia takes place with higher rates of air consumption and at slower rates of advance of the burning front than it does within a porous medium made of sand. Amount and size of non-porous inclusions have a significant effect on the in situ combustion process that takes place withii the porous medium. Water encroachment into porous medium makes the conditions for in situ burning worse.

The above discussed failure to start the burning front with a downhole gas heater, together with the data obtained from experiments on the laboratory model, showed the need for more detailed preliminary preparation of the air injection well and for a recourse to other means of bringing about bed ignition. As indicated above, the reservoir in the vicinity of well 3H is strongly fractured and does not contain free oil. When heated, the rocks expand, closing the fissures. Air intake capacity of the bed decreases and burning front does not form. It was therefore decided to inject into well 3H some 50 m3 of heavy crude oil. The latter was treated beforehand to remove from it the gas. water, and solid impurities; then it was preheated to 800C. Following the injection, some of the oil started to flow back into the well; after two days, this oil formed a column in the well, which stood 20 m high above the petroliferous horizon. Downhole gas heaters are most suitable for oil-bearing beds with thicknesses of more than 15 m. containing immobile but easy to oxidize petroleum. With thinner beds, problems arise when gas heaters are used. For one thing, the temperatures of the gaseous heat carrier are very high, ranging from 530 to 8 W C . Now, if the c m n t density of injected air at the moment of ignition is also kept high, then the amount of oil in the bed drops quickly below the minimum concentration that is required to develop a front of combustion. In the case discussed, the effective thickness of the bed was only 5.5 m. For such beds it is better to use an electric heater. Temperatures can be increased more slowly from 10 to lOOOC at small flow density of injected air. The role of temperature increase can be regulated by changing the voltage within a range of 380 - 560 V. At the same time, the density of the air current can be regulated by changing the rates of injection. In order to develop a burning front, the injected air must attain temperatures ranging from 320 - 420OC. Whether or not bed ignition can be successfully carried out depends very much on the total amount of heat input. Experimental data indicate that this heat consumption should be within a range of 0.25 to 2.75 million kg caVm of bed thickness. The electric heater installation employed to develop a combustion front consisted of the following component elements: (a) a three-phase downhole heater, 5.5 m long and 116 mm in diameter, with rated power of 24 kg W, (b) power cable, type KTNG-10; (c) control station, type TEH - 50 v/-13A3; (d) autotransformer ATS 3-30; (e) thermocouple. type HK and a thermal resistor for temperaturecontrol of air injected into bed, and (f) a lubricator for sealing the wellhead. The process of initiating the combustion was started on May 31,1972, and continued until July 7, 1972. The technical parameters of this process are shown on Fig. 93. With air consumption of about 3.500 m3/day and with air temperature of 350 - 400 OC, the downhole power 172

Petroleum Production by In Situ Combustion (Fire Flooding) of the electric heater was maintained at 15 kg W. Altogether 11.5 million kg cal of thermal energy and 135.000 m3 of air were introduced into the bed. Specific heat consumption amounted to 2 million kg caVm. Analyses of combustion gases from production wells 317, 181. 2E and observation well 1K allowed the conclusion that the burning front formed 10 to 15 days after initiation of the process. After bed ignition, electric heating was continued for another 26 days in order to enlarge the zone of high temperatures around this bottomhole of the injection well 3H. This measure was taken to insure successful development of the burning front. The calculation shows that by the time the burning front formed, the bed within the radius of 1 m from the ignition well attained a temperature of 320OC. After the electric heater was turned off, for 23 days that followed the air consumption kept on increasing gradually from 3,000to 19,000 m3/day. The pressure increased from 1.7 to 25 kg/cm2. N, kWt&Q. mill. Kcal.

f

Fig. 93. Technical parameters for initiation of combustion process in well 3H.

1 3 5 7 911

15

1357911 V!. 1972

15

19

23

27

1 3 5 7 V1.1972

23

27

1 3 5 7 v1.1972

From the start-up of the combustion front on June 15,1972,and until November 30,1972, the burning was taking place normally. In this process. oxygen concentration in the produced gas increased slightly from 0 to 2 - 5%, while the content of carbon dioxide deceased from a range of 12 - 15% to that of 8 - 10%. These changes were occurring under the reime of stable pressure and of air injection at a steady rate (Fig. 94).

173


Q, ,CO,, %

01

20 15

10 6

P V1.1972

VII

Vlll

IX

X

XI

XI1 1.1973

.

II

111

IV

V

VI

VII

Fig. 94. Changes in the concentration of (1) carbon dioxide and (2) oxygen in produced gases. From November 30, 1972 on, with both air consumption and pressure unchanged, the oxygen content began to increase from 4-5% range to 1415% range, while carbon dioxide content decreased from 8-10% to 3-4%. In order to sustain the combustion process. the quantity of air injected was cut down from 21,000-22.000 to 11,000-12,000 m3/day. This reduction, in turn. resulted in a pressure drop to 12 kg/cm2. As further consequence, in the course of four months the concentration of oxygen in the produced gases slowly increased while that of carbon dioxide decreased. Towards the end of July 1973. air injection was stopped, inasmuch as the oxygen content in the gases increased to 1819% and that of carbon dioxide dropped to 1.5 - 2%. Obviously, by that time. only low temperature processes of petroleum oxidation were taking place within the reservoir. From the beginning of these field experiments, no additional oil was produced by application of the in siru process. Moreover, in the course of work carried out during the year 1970-1973, it was determined that the earlier data used in planning of this project were incorrect. 174


Significant errors were originally made with regard to location of reservoir limits of Lens IV, the thickness of the oil-bearing bed, and the degree of its oil saturation. The conditions for use of the in situ combustion method also proved to be extremely unfavorable. A number of conclusions can be made on the basis of this experimental field work I n situ combustion is very difficult to cany out in fracture-type reservoirs containing heavy

petroleum. Many problems arise both at the initial stage, that is. during the bed ignition, and at later stage when attempts are made to regulate the advance of the combustion front. The principal difficulty lies in lack of uniformity of reservoir properties with regard to porosity, permeability, degree of oil saturation and thermal characteristics. In reservoirs of fracture-porositytype having an inadequate oil saturation in the bottomhole zone of the ignition well, the burning front, nevertheless, can be created by use of the electric heater and by injection of a small quantity of heavy crude oil into the bed. When fracture systems in a reservoir are well developed while oil saturation is inadequate, breakthroughs of injected air quickly develop between the injection well, on one hand, and production or observation wells, on the other. The results of experimental work on Lens IV reservoir were negative. There was practically no increase in petroleum production, although the in situ combustion process ran normally for about five months.

175

PART 111.

HEAT-ENERGY INSTALLATIONS FOR USE WITH THERMAL EOR METHODS

1.

TING PLANTS

Practice has shown that the effect of steam application in EOR work can be insignificant and sometimes none at all principally due to improper selection of equipment and installationemployed to produce, transport and inject steam into the oil-bearing beds. The facility of serial production or of rapid piece manufacture determines many of the specifications selected in construction of steam generators. Russians have had good oil field experience with stationary steam boilers of industrial and power plant types. However, actual employment of these steam generators for EOR work is very limited for a variety of reasons, such as: (a) Sizes of these installations are very large. (b) These systems lack many of the special elements required for oil field work. (c) They either excessively superheat the steam or they don't generate enough steam pressure. (d) The amount of construction assembly work required to set them up in the oil field is quite large. (e) They are not simple to operate, service or maintain.

(0 They require extensive overhauls. For thermal EOR work one needs special monoblock steam-generating installations consisting of an entire complex of basic, auxiliary and electrotechnicalelements integrated by means of piping, control and automation systems, and equipped with necessary armature. The entire system must be so designed that it can be readily assembled on the site, and then simply c o ~ e ~ t to ed an outside network. Installations of this type are now (1980) being tested in the oil fields. For the EOR work, it is best to use either dry saturated or slightly superheated s t e h under pressures of 90- 180 kglcmzor higher. Before a specific generator outlet-pressure is selected, appropriate calculations must be made for the entire complex system consisting of the steam generator itself, the piping, the steam injection well and the bottomhole. These calculations must take into account such factors as: the depth down to the oil-bearing bed. the reservoir pressure, steam quality, the diameter of surface steam-distributionpipes and of the injection well-pipes, and also the type of pipe insulation. According to the calculations, the pressures required of the steam when it leaves the generator can be grouped in steplike fashion into the following series: 90; 120; 180 kg/cm2 and higher. Steam temperatures should either correspond to the stepped-up pressures of the above series along the line of saturation at 1 degree of dryness or else the steam should be superheated by 3550OC. Of the two, the slight superheating of the steam is preferred because it insures better delivery of proper quality steam to the bottomhole of injection wells. At the present time, mainly wet steam is used for thermal EOR. Its degree of dryness is 0.8 or lower, measured at the outlet from the steam generator. The unavoidable heat loss during steam

Thermal Methods of Petroleum Production transport, iirst through the surface pipes and then down the pipe column of the injection well, causes a drop in the degree of steam dryness. Measured at the bottomhole. it amounts to 0.65-0.70. When wells are deep or when steam injection takes place without prior insulation of the annular space in the well, the degree of steam dryness measured at the bottomhole may decrease to 0.55 and sometimes even lower. At this degree of dryness, the effect of steam injection on the reservoir is practically the same as that of hot water injection. To insure the degree of dryness of up to 0.95 and higher, the steam should first be run through the separator and only then injected. For this purpose, the separator is installed at the steam outlet from the generator or from the group of generators. At the same time, the separator acts as an accumulator which evens out the fluctuations of steam input into ‘the injection well. Otherwise, such fluctuations will normally occur during the reservoir steaming. During the steam injection treatment, the fluctuation of steam input may be occasionally accompanied also by fairly abrupt and large changes in reservoir pressure. In most cases, these changes occur when steam input takes place through a group of injection wells, served by a single steam generator, into reservoirs with heterogeneous physical and geological characteristics. Such pressure fluctuations adversely affect the work of the generator, especially when the latter is operated at a pressure below nominal. Direct-flow high pressure generators cannot tolerate pressures that are less then 65% of nominal (rated). An automatic regulator is therefore installed to insure stable pressure in the generator. As a result, the temperature and steam dryness also remain steady and they are not affected by pressure fluctuations at the wellheads. Steam generators with small unit output of 9-60 t of steam per hour are used for experimental oil field work. Of course, work on large commercial scale, particularly on big oil reservoirs, calls for special high efficiency steam generating and injection installations. For example, the total recovery of 200 million tons of oil from a field with reserves of 500 million tons of oil in place would require 700 million tons of steam for thermal treatment. On annual basis, this would require 23 million tons of steam, and on an hourly basis up to 3,400 tons. To produce this quantity of steam with small boilers, each with an output of 60 tons per hour, would require a battery of more than 50 of them. Such operation would be both uneconomic and very cumbersome. Therefore, generators with much larger unit output must be used. Power plant boilers, e.g., series E-160-100GM, E-220100GM, and E-320-140GM are suitable for this purpose. In addition to high production capacity, these generators can produce steam which has high pressure and temperature.

1 b . TECHNKAL CHABACTEBISTICS ANR BIEEEBENT S E A M PENEBATPBS

SEECIAL

BESIPN

EEATUBES

QE

Most of the steam generators used for EOR work have the following general characteristics: direct flow type; high steam pressure (60, 120, 160 kg/cm2); steam output of 9-60 t/hc fired by liquid or gas fuel; with insignificant pressure in the gas tract; without smoke exhaust (draft) fans. At individual oil fields, where the required steam injection pressure does not exceed 40 kg/cm*, DKVr-10/23 and DKVr-10/39 generators are used. They employ natural circulation, without steam superheaters. Besides steam generators of domestic make, some foreign-made boilers are also employed. Fig. 95 shows a self-explanatory schematic drawing of a direct-flow steam generator, fired by liquid fuel, and with a very low pressure in the gas tract.

178

Heat-Energy Installations for Use with Thermal EOR Methods

3

Fig. 95.

Schematic drawing of a steam generating installation. 1-water pump; 2-water-water heater, 3-steam-water heater; &apparatuses for chemical treatment of water; 5-water deaerator; &water charging pump; 7-steam generator; 8capacity for liquid fuel; 9- coarse purification filter; 10-fuel pump; 11-fuel heater; 12fine purification fdter; 13-forced draft fan; 14-air heater; 15-fuel injection nozzle; 16-fire box (furnace chamber); 17-steam-condensate separator.

The products of combustion heat the water pipes of the steam generator and are then exhausted through the smoke stack. From the furnace, the wet steam goes first to the separator where water condensate is removed, some of the dry steam produced is consumed by the system itself to meet the needs of deaerator and of the water-, fuel- and air-heaters. The bulk of the dry steam goes to injection wells. The condensate returning from the internal heaters of the system goes to the deaerator where it joins the stream of water pumped from an outside source. After the gases are removed, the combined water-condensate streams are pumped into the steam generator. The above system of steam generating installation can be modified as required by such factors as: the quality of water used, rates of output and steam parameters desired, type of fuel and the method of burning it, type of heat transfer design, pollution control requirements, the specifics of the particular EOR project and the local conditions. Steam generating installationsconsist of two types of elements: (a) basic-the boiler itself, and (b) the accessory-pumps and treatment apparatuses for water and fuel, water and steam piping, air fans and smoke stacks. An oil- or gas-fired steam generator is shown in Fig. 96. The heating surfaces are divided into economizer section, evaporation elements, and steam superheaters (if present). The steam generator design may differ from the one shown in Fig. 96. A modem steam generator, individually, and the installation, as a whole, are provided with control and automation systems and with proper shielding. These support systems are designed to insure reliable and safe performance, efficient use of fuel and of electric energy, the maintenance of 179

Thermal Methods of Petroleum Production required output rates and steam quality, increased labor productivity, and improved working conditions.

7

6

Fig. 96. Oil- or gas-fired steam generator. 1-furnace chamber (radiant) 2-economizer element 3-radiant element &steam superheater element 5-feed water pump 6-air heater 7 4 fan

All steam generators listed in Table 35 are of fully-equippkd monoblock design and have body housing (Fig. 97).

Fig. 97. Housing of steam generating installation. Strazer Company model. Within the overall system, every monoblock is assigned its own specific position and function. For each of the models described, the installations differ with regard to the number of monoblocks employed, their specific functions, dimensions, weight and energy capacity. These differences notwithstanding,the models may actually have the same steam output and use feed water of the same characteristics. All of the 40-60 ton/hr steam generators listed with the others in Table 35, 6 t h domesticand foreign-made, share a number of characteristics. They are of direct flow type, horizontal, do not use superheaters, have only insignificant pressure in the gas tract, and are not equipped with smoke suction fans. (Fig. 98). However, some Russian-made steam generators do have superheaters. In this group belong the steam generator UPGM-40/180-400 and several other models developed at the Institute of High Temperaturesof the Russian Academy of Science. 180

Table 35. Technical characteristics of some steam generators. Russian make

m-* m - m 9/120

50/60

60/160

12.5 6.0 9

71 25

Amenmake strazersThermo-Flood company

92

s-40/160

86 30 60

11.5 2 11.5

47.3 8 39.7

160 80

105.5

-

-

345

313.8 0.8

348.3 0.8

s-60/60

Takuma Company Loll20 401160 60/60

Output, tons of steam/hr.:

Nominal (rated) Minimal Steam delivery to injection wells, t/hr Outlet steam pressure, kdcm 2

Nominal (rated) Minimal

Nominal (rated)steam temperature, OC Degree of steam dryness

120 60 323 0.8

Temperature of feed water, OC

145

Temperature of exhaust gases, OC Efficiency coefficient of steam generator, % Fuel (oil) consumption, kghr Heat intensity of furnace chamber volume, kg cal/m3 .hr.

343

1.68 x

Heat intensity of f m i d e surfaces, kg ca4m2. hr.

1.113 x

Power of electric feed water pump, kg w Electrical power of the installation, kg w Weight of the installation, t

50

60 20 274 0.8 145 343

83.4 681

0.8

60

-

116 60

160 80

60 20

276.6 0.8

312 0.8 151.1

62

34 0.8

274 0.8

104.4

104.4

169.6

169.6

204

204

-

427

365

89 2617

89 4347

80 675

83 2810

83 4290

1 6

0.133 x

lo6

1.56 x lo6

lo6

0.195 x

106

0.212 x

*upG= Abbreviation for steam generating installation

40

120

4588

-

__

9

204

3933

51

83

-

I

145

84.8

500 1200

56

12.5

320

83.9

-

165

76.5 12 59.5

1 6

88.7 786

-.wo9 x

lod

800

-

1800 300

156 93.5

0.069 x

106

228 512 247

0.8 x

106

1.61 x

106

0.080 x 106

152 861 257

-

-55

620 798 137

340 610 176


Fig. 98. Steam generator UPG-60-160 a-plan view b-view of burners c-cross section of furnace chamber 1-furnace chamber 2onvection surfaces 'J-economizer 4-exhaust pipe

Another model of a steam generating installation,the UPG-60-160is shown in Fig. 99. 182


Fig. 99. The layout of functional monoblocks/units of steam generator installation, model UPG-60/160. l-steam generator block 2-economizer unit 3-fuel system block &blow fan block 5-gas regulation station 6-deaerator block 7-bank of feed water pumps 8-ionic filters assembly 9- purified water tanks 10-assembly of water clarification filters 1l-electric panel block k'

The steam boiler itself of the UPG-60/160 installation consists of a block with insulation and cover sheeting, the fuel system with burners including regulator-and shut-off valves, a steam sampling device for determining moisture content, blowers for cleaning of gas-side slrfaces, a sample cooler, boiler drainage system, and the economizer unit with its own blower device for cleaning. The economizer block is placed to the side of the side of the boiler block, at a right angle to the axis of the boiler. Along the gas tract, the economizer is connected with the boiler and with the smoke stack. Metal ducts are used to connect these elements. The smoke stack stands separately behind the exit-economizerunit along the same axis. The entire steam-generator installation UPG-60/160 consists of eleven functional monoblocks/units (Fig. 99). Depending on the quality of water, the clarification-filter assembly of the UPG-60/160 model can be used both with water from surface sources and with artesian water. The UPG-60/160 installation can operate at ambient temperatures ranging from -400 to +4OOC. The individual blocks/units/assembliesof the UPG-60/160 installation are interconnected by passages that form part of the housing structure. These same passages are also used to gain actess for maintenance work. Pipes, gas-air ducts and electric cables integrate the different functional blockshnits into a single technological system for steam production. The UPG-60/160 is automated to the maximum degree. It is also equipped with safety devices to comply with both the "Rules of Safety for Steam Boiler Operation" and the "Rules of Safety for Gas Industry" dictated by the Gosgortekhnadzor.* The UPG-60/160 is designed for steam injection into petroleum reservoirs lying at depths greater than lo00 m. The installation UPG-50/60 model is somewhat different from the UPG-60/160, and it uses another type of fuel (see Table 35). Steam generating models UPGM-40/180-400GM and UPGM-110/180-400GM are designed for production of high temperaturewater, saturated steam or slightly superheated steam.

* State.Technical Mining Inspection Office - is a Russian equivalent of MISHA.(Translator). 183

Thermal Methods of Petroleum Production @.-A -

Fig. 100. Steam generator installation UPGM-40/180-400GM. These two installations have outputs of 40 and 110 t/hr. respectively; boiler steam pressures are 90-180 kg/cm2. Both of these models are flexible in operation. To make them suitable for steam treatment of petroleum reservoirs with different conditions, the arrangement of the heating surfaces in the boiler end-section can be varied. Moreover, the UPGM-l10/180-400GN has a somewhat different design of the fire box. The latter is put together of two C-shaped blocks which can be transported. By placing the two boilers parallel, the installation UPGM-40/180-400GN can increase its output to (40x2)=80 t/hr. The steam will be superheated to 4OOOC. with boiler pressures of 180 kg/cm2. Steam output of UPGM-110/180-400GM installation can also be doubled in the same manner. Another two models of Russian-made steam generating installations are: PR-86-160 and PR-71-60. They have steam outputs of 86 and 71 thr, respectively, and are characterized by maximum degree of integration. lharacteristicsof the steam generator PR-86-160: Steam output, t/hr: nominal (rated) minimal Steam pressure, kg/cm2: nominal (rated) minimal Maximal temperature of steam, OC Degree of steam dryness Basic fuel Efficiency, % Temperature of exit gases, OC Hydraulic resistance of steam-watertract, k 1cm2 Resistance of gas-air tract, kdm2 Heat intensity of furnace volume, kg/cal/m3/hr

184

86 30 160 80 345 ' 0.8 natural gas 84.8 320 13.2 650 1.6~106

Heat-Energy Installations f o r Use with Thermal EOR Methods For reservoir steaming, single drum vertical water pipe steam generator model E-220-100GM can also be used with high output installations (see Fig. 101).

Fig. 101. Single drum water pipe steam generator E-220-1OOGM. l-continuous flow chamber, 2-drum; 3-steam superheater, 4-economizer. Characteristicsof steam generator E-220-100GM: output, t/hr 220 Steam pressure, kglcm2 100 540 Steam temperature on exit from superheater,OC 180 Temperature of exhaust gases, OC 90 Efficiency coefficient of the unit, % Fuel natural, gas, fuel oil Dimensions, m 12x20~28

185

220 100

320 160 90 natural gas, fuel oil 12x20~28


The E-220-100GM can be assembled at the site in units/blocks. Models have been designed for work in seismic regions, and others for non-seismic; also for covered installations, and others for open. The latter models use lighter formations. Unit E-320-140GM is similar to the E-220-100GM model except that it has a higher steam output (320 t/hr) and higher pressure of produced steam (140 kglcm2). The steam generators described above are very suitable for thermal treatment in EOR work. They have high output capacity per unit and high efficiency coefficient of 90% while at the same time their flue gases have a low temperature of 1800C. These characteristics as well as a number of others make these steam generators superior to any domestic or foreign direct flow housed unit/block steam generator. High pressure steam generators require very good quality feed water. Thus, its overall hardness should be less than 20-30 milligrams/kg, and the silicic acid content less than 30 milligrams/kg. Therefore, water must be chemically purified before it can be fed into the boilers. Water purification system uses the widely accepted sodium cation exchange method with subsequent degasification. Other methods may also be used as required by the quality of source water. In employing steam generators at a big oil field, plans must provide for space to accommodate a couple installation consisting either of one group of generators of 2-4 units each, or of several such groups. In each case, the number of groups depends on the total heating power required. With such a complex of one- or multi-group installation, it is possible to inject steam at rates ranging from 400 to 800 t/hr. Of some interest are also so-called steam-gas generators that produce steam-gas mixtures with high pressures and temperatures. They may have output capacities and other operating parameters that are very similar to those of the traditional steam generators. But they have a number of special design features that make t lore economic, e.g. small dimensions and weight, also insignificantamount of metal required :ir construction. A new thermochemical EOR method is now (1980) under development. It is based on injection downhole of carbonated high temperature steam, the so-called steam-gas. Organic fuel, air and water are injected into the combustion chamber of the generator. As the fuel-air mixture bums, gaseous products of combustion form while, at the same time, the oxidation reaction gives rise to high temperatures. Water sprayed into the reactor quickly evaporates, mixes with the products of burning and forms a high temperature carbonated steam, the so called steam-gas (Fig. 102). Experiments were conducted with different types of hydrocarbon fuels to produce steam-gas mixture at high pressures. Natural gas, crude oil, water-oil emulsions, diesel fuel and kerosene41 of them were tested for their suitability as fuel. This type of steam-gas generator was already tested in Bashkiria under different operating conditions, first, on a bench-size model and, subsequently, on a pilot installation in the oil field.

186


Fig. 102. Steam-gas generator. l-cylindrical combustion chamber 2-jacket (with spiral canals) for air-or-water-cooling of generator 3-fuel injection nozzle &ignition device 5 4 turbulizer device &water jet

head section

tail section

:gases

Exit of Steam-Gas Mixture

An experimental model of steam-gas generator is shown in Fig. 102. Tests were already run on this unit under full operating regime with steam-gas mixtures produced at pressures of 170-180 kg/cm2. The process was controlled by instruments recording pressures, temperatures and inputs. Gas analysers and steam sampling instruments were also used. The generator ran faultlessly under different operating conditions, producing the steam-air mixture in a stable manner. The October Branch of All-Union Research and Design Institute For Petroleum Industry Automation (VNIIKA) built a transportablegenerator installation capable of producing and injecting downhole two tons of steam-gas mixture per hour at pressures of 200 kg/cm2. VNIIKA installed and ran this complex on one of the depleted wells. After two days of injecting the steam-gas mixture into the bottomhole zone the well yielded a flow of oil in commercial quantity. A number of studies have been already conducted on more advanced types of steam-gas generators. Depending on field conditions and on job requirements, the temperature of the steam-gas mixture can be regulated within range of 150-800OC, and the pressure within the range of 90-200 kg/cm2. The regulation is accomplished by changing the amount of water used and by altering the pressure under which air, fuel and water are injected into the reactor. 187

Thermal Methods of Petroleum Production For EOR treatments, the carbonated steam is superior to other thermal and chemical agents. It combines the desirable effects which water vapor, carbon dioxide, nitrogen and other substances, individually, have an oil recovery. Steam-gas contains 10-12% carbon dioxide by weight. Under high pressures. the latter dissolves in crude oil and water, resulting in a low viscosity gas-liquid mixture. At the same time, after the steam condensation, carbon dioxide gas forms with water a socalled carbonated water. In the reservoir, the latter reacts with crude oil, reducing the surface tension at water-oil contact. Furthermore, as this condensed water moves through the petroliferous bed and gradually cools, even more carbon dioxide dissolves in it inasmuch as its solubility in water increases as the temperaturedecreases. The steam-gas thus represents a complex thenno-chemical agent acting both as a heat Wrier, a solvent, and as a physical force to drive crude oil from the reservoir. The problem with carbonated steam-gas injection is the carbonic acid corrosion. The surface lines and injection columns within the well must be properly protected. These steam-gas generators should be especially useful for EOR from reservoirs lying at greater depth. In this case, the consumption of fuel used for well steaming treatments could be greatly reduced. Work on more advanced types of steam-gas generators and on several special steam producing installations started in 1980 at the NPO Soiuztemeft (Institute of Thermal Equipment for Petroleum Industry) and at the Institute of High Temperature of the Russian Academy of Science. 1 C.

IMEBQYING THE STEAM PENEBATQBS ANP THE EBPSEE€TS QE E E L P X I N P JUGH T E W B B T Y B E BEACWES

The average specific consumption of steam per one ton of oil produced by reservoir steaming is 3-3.5 t. Thus. if we had two or three large fields with joint reserves of heavy oil in place of up to 1 billion tons, and if we wanted to produce from them by steaming some 400 million tons of petroleum, it would then require about 1.4 billion tons of steam. To generate this amount of steam would, in tum, call for consumption of 120 million tons of oil as fuel. The analysis actually completed for one of the large fields of heavy oil demonstrated that it would take up to 28 million tons of steam per year in order to put the field into production. In this case, the steam generating installations would have to produce and inject the steam at the rate of 3.500 t/hr. Gererators with small output capacities simply could not produce such quantities of steam. In the case just mentioned, working with generators capable of producing only 60 t/hr, 60 of these units would have to be installed. So, until high capacity steam generators (up to 1500 t/hr) and special auxiliary equipment become available, the steaming operations in such oil fields must be held back. At this time, technical and economic studies are being pursued to determine the feasibility of using atomic reactors for this purpose. One or two steam generators of this type could replace as many as 30-40 units, each with an output capacity of only 60 fir. Additionally, the employment of atomic reactors would eliminate oil consumption for steam generation. With atomic reactors, the working steam can be produced either directly in the reactor (single contour circuit, Fig. 103a) or in a special heat exchanger-steam generator (Fig. 103b). In the latter case, working steam is produced by heat transferred by a heat exchanger from the energy reactor to the working body such as water (two-contour circuit). In the two-contour circuit, the second contour is not radioactive.

188


a

Fig. 103 a and b. Schematic diagram for production of working steam by use of atomic reactors. 1- atomic energy reactor 2-steam generating passages ?-drum-separator 4-circulation pump Spassages for steam superheating &feed water (make-up) pump 7-steam generator &volume compensator 9-heat exchanger

b

I

Additional Water Feed

Depending on the substances used as heat carriers and on the safety requirements, there exist also atomic reactor installations with three-contour circuits. Obviously, an advantage would be offered by atomic energy-technologystations (AETS)or atomic installationsfor remote heat t r a d e r (AIRHT), powered in both cases by high temperature helium reactors (HTHR). Atomic installationsof above types could be used both for heat supply, at a distance, to the fields that produce oil by steam treatment methods, and for simultaneous electricity generation (Fig. 104).

.-.-.-.

Fig. 104.

Scheme for using high temperature helium reactors (HTHR) for remote transfer of heat energy through methane conversion with subsequent methanization: 1-reactor, 2-methane conversion system; 3-steam generator; hethanization system; 5-well; 6 4 1 reservoir. 189


Centralized methanization systems, distant from atomic stations. should be located directly at the oil field. The turbine generators can be installed either directly at the atomic energy-technology station (AETS) or also at the oil field, whenever technically and economically feasible. A variant of themethanization system, in which a special methanator apparatus is placed downhole in the injection well, could also be employed (Fig. 105). This variant would also be suitable for use in reservoir steaming or for heating with high temperature water of deep petroliferous beds of great thickness, including those buried below permafrost layers.

Scheme diagram for employment of downhole apparatuses-elements of methanization systems for production and injection of heat carriers: 1-high pressure water pumps 2-injection well 3-downhole methanator

2.

SOR INSTALLATIONS FOR IN SITU COMBUSTIOly

Effective application of in situ combustion process for EOR depends not only on proper selection of the oil reservoir and on successful ignition of petroliferous bed but also on the right choice of an installation to inject the air downhole in correct quantities and under a definite pressure. The selection of this equipment is made either on basis of calculations or on basis on accumulated empirical data. Field practice shows that in order to sustain in situ combustion, one must inject into the bed at least, 400,000-440,000 m3 of air per day under pressures ranging from 75 to 250 kg/cm2, depending on specific parameters of the petroleum reservoir. In this process, the air consumption per one ton of additional petroleum produced from the reservoir can range anywhere from 850 to 5,000 m3.

190

Heat-Energy Installations f o r Use with Thermal EOR Methods Compressor installations of required parameters are selected largely on basis of availability of suitable serially produced models, or else a particular installation may be selected because it is easy to fabricate to specifications. In Russia, centrifugal and piston type compressor units suitable for different jobs are serially manufactured (Table 36). General features characteristic for all of these installations are: (a) unit(ary)/blockconstruction with housing; (b) use of serially produced components, e.g. pumps; (c) delivery by the manufacturing plant of complete assembly including cooling water pumps, water injection pumps, air tanks, compressors, wellhead equipment for the injection well, downhole electric heaters for bed ignition, apparatuses for air cooling of water, measuring units, operation and control station, and servicing unit. The compressor installations are also provided with safety features and individual manual controls. Table 36.Characteristics and principal parameters of compressorinstallations. Designation Output of installation,m3/mi ,m3/min Air pressure, kg/cm2 at intake of installation on exit from installation Installed capacity, kg W Number of compressors in installation Types of compressors in installation

OVG - 4

OVG - 5

350

350 21,000

OVG - 2

IVG-

60 3600

64 3840

7: 432C

1 35 861

1 70 1090

220 1600

1 150 10,080

1 250 10.450

4

6

4

4

OVG-Ih,

!OSVP-16DOSVP-70

1

020

21,000

VT~-520/0.96-6 ~VTS 1-95/6-31 !VTs16/3O-120 IVM10-4.5/115 -150

Mode of compressor work n installation 4ir pressure by stage on intak md exit from each compressc ;ection,kglcm2: I stage II stage I11 stage -mal Vumber of functional units in nstallation

Parallel

---

191

--

--

--

---

8

lo

--

7

Successive

1-6 6-30 30-115 115-150

VTS-52010.96VT~l-95/6-3 1 !VTS-16/30-12 IVM 10-43 15-250

Successive

1-6 6-30 30-115 115-250

&thin one common housing Nithout division into units/ blocks.

-- -1 1


The compressor installation illustrated on Figures 106 and 107 consists of four compressor machines, type 205VP-16f70, which work parallel charging air into one common tank sitting on a platform. To end use To end use

Fig. 106.

Pneumohydraulic flow diagram of compressor installation OVG-2: I-unified cellular

filter, 230 1.000 >20

>so

up to 100 5-25 30 >I00

>10 0.802-1.OOO >20 >40 up to 150 3-15

6 >lo0

Minimum thicknesses of the oil-bearingbed are based on limits of tolerable heat losses that take place into the overlying and underlying strata. However, in oil fields with multiple petroliferous horizons the indicated minimum thicknesses of individual oil-bearing beds may be even smaller. In these cases, the heat lost from one thermally treated thin horizon may be effectively recaptured by the next overlying or underlying oil-bearing stratum. Similarly, certain other criteria of reservoir suitability may be mitigated. For example, application of thermal methods can be advantageous in reservoirs of low viscosity petroleum if the latter contain great amounts of paraffin. In such cases, the employment of some other production method may lead to an inadmissible reduction in formation temperature. The restrictions placed on maximum permissible formation pressures are dictated by technical limitations of installations used in steam and/or air injection during thermal treatment. As regards viscosities, thermal methods should be restricted to crude oil of less than 1,000 centipoise. The results of employing in situ combustion processes on reservoirs containing petroleum with viscosities greater than 1,OOO centipoise were ambiguous. 198

Planning of Oil Production by Thermal Methods Lithology of reservoir rocks does have an effect on the parameters of thermal processes used in EOR. Unfortunately, reliable data on this effect is still lacking. The only recommendation that can be made at this time is to restrict use of thermal methods to reservoir rocks with less than 15% of clays by weight.

The amount of heat that remains in the oil-bearing bed, expressed as a fraction or percentage of the total amount of heat either introduced into or generated within the bed over a definite time, defines the heat effectiveness of a given thermal method. It is called its thermal efficiency coefficient. Applied to the in siru combustion process, this coefficient has two components: (a) the efficiency co-efficient of heat introduced into the oil bearing bed from outside. and (b) the efficiency co-efficient of heat regeneration. The latter represents the amount of heat accumulated ahead of the combustion front, and is expressed as a fraction of the total amount of heat introduced and/or generated in the bed behind the burning front [3]. Fire flooding experiments showed that total heat losses depend on the geometry of the heat flow [28]. On this basis, it can be concluded that two factors pretty much determine the thermal efficiency of these methods: (a) the rate of heat input or heat generation in the oil-bearing bed, and (b) the heat intake capacity of both the reservoir rocks and the fluids that saturate them. These conditions imply that for best results during the thermal treatment, heat must be brought into the bed at the fastest possible rate, and the period of production must be shortened by increasing the density of the well grid. At the same time, as the area being heated around the injection well enlarges, the losses of heat into the surrounding rocks also continue to increase. At a certain distance from the injection well, with the rate of heat input kept constant, the rate of advance of the burning front will ultimately slow down to almost zero. A dynamic equilibrium develops between heat input and heat losses. It is at that time that the efficiency of reservoir heating decreases. Fig. 111 illustrates the changes in heat losses that take place during reservoir steaming. The graph was constructed on basis of calculations by Lovere's method, and it reflects the conditions of petroleum production by thermal methods in the Karazhanbas field. The steam was injected at the rate of 10 t/day per m of effective thickness of the oil-bearing bed.

9

Fig. 111. Relationship between heat loss co-efficient q and the duration of steam injection at the Karazhanbas oil field.

0.8

0.4

0,2

0

2

4

6

8

Years

199

Thermal Methods of Petroleum Production Fig. 112 shows the temperature profile for the moment at which the dynamic equilibrium is established, when steam is injected into the bed without interruption at rates indicated above. We may accept 700C to be the minimum temperature at which petroleum can still be actively displaced from the reservoir by the heat carrier. In that case, the maximum radial distance from the injection well at which steam still has some effect is about 180 m (Fig. 112). At that point, the thermal efficiency ceefficient does not exceed 0.15. r."C 30(

20(

Fig. 112. IW

C 40

80

120

160

Temperature profile during uninterrupted injection of steam over long periods of time.

r , ~

As result of uninterrupted heat input, however, a large amount of heat will remain in the reserv ir at the time the well is abandoned. This portion of thermal energy introduced into the bed through steaming treatment cannot be recovered. The aforementioned negative effects can be avoided to some degree by the method of creating a thermal bank. Such a technique was fiist proposed by E.B. Chekaliuk, K.A. Oganov and A.N. Snarskii [26]. Later A.A. Bokserman [21] and I.U.P. Zheltova [22] developed it in their experimental work. The thermal bank method was fiist successfully employed in petroleum production from the Okha field in Sakhalin. Formation of thermal banks followed by their displacement by other agents, such as water constitute a very important method of increasing the heat effectivenessof thermal processes. In heterogeneous beds, thermal methods are most effective when used in combination with other newer methods, such as polymer injection. These combined methods promote better displacement of oil and increase the sweep by these agents across the entire thickness of the oil bearing bed. The dimensions of heat banks depend above all on the following factors: (a) geological and physical parameters of oil producing horizons; (b) rates at which heat is either introduced into the bed or generated within it, and (c) the distances between the injection wells and producing wells. As seen in Fig. 113, with an increase in the distances between the wells, the required dimensions of the heat bank increase. When the spacing of well grid is wide, this heat bank technique loses its advantages.

"0

1 0.8 0.6

0.4 0.1 0

40

eo

I;C

160

zoor.

H

200

Fig. 113. Relationship between speed of movement of thermal bank (V,) and distance (r) between injection well and production wells during steam injection under conditions at the Karazhanbas oil field. (Maxi mum temperature in the heated zone at the moment of thermal front approach is 900C.)

Planning of Oil Production by Thermal Methods

In order to increase the speed of heat transfer during in situ combustion, water may be injected into the petroliferous bed simultaneously with the air. In comparison with the air, water possesses greater heat capacity [3]. Depending on the ratio of injected water to air,the so-called wet and supenvet variants of in situ combustion can be distinguished. The two processes differ from each other with regard to the temperatures generated in the bed and the extent of thermal zones that develop. Both laboratory experiments and field studies show that large heated zones form in the process of wet in s h combustion. As a result, the effectiveness of petroleum extraction from the bed increases. As with the injection of a heat carrier, the advantages of wet in situ combustion can be best utilized, when this treatment is used in combination with water flooding. In such cases, the thermal banks that are created, are then driven by water. 3.

BASIS F O K P R O D U C T T O N SYSTEM BY- T

In oil fields producing from multiple horizons, separate extraction of crude oil from each producing horizon by an independent network of wells is not always economical, and sometimes it is not even technically possible. In such cases, two or even more producing horizons must be trouped together into a single production unit. Such a unit can then be worked individually by an independent network of wells. This approach significantly reduces the amount of drilling required and it simplifies the well support system. The technical and economic parameters of petroleum production from the field are thus improved. With respect to the geological and physical characteristics of individual petroliferous horizons grouped into a single producing unit, the requirements which they must meet for successful thermal treatment are generally the same as those for water flooding. Nevertheless, in case of thermal treatment, certain additionalconditions may have to be mec e.g., in shallow petroleum fields with multiple producing horizons made up of poorly cemented reservoir sands that may have tendency to run, such individual sands should not be unified unless effective measures are first taken to prevent sanding of producing wells. Bed thickness determines the degree of utilization of thermal energy that is brought into the oil reservoir or generated within it. On the other hand, with the increase in thickness of a petroliferous bed, the degree of sweep of that bed by the thermal process decreases. With steam injection, maximum oil recoveries are obtained from beds not exceeding 25 m in thickness [18]. For in siru combustion, taking into account great mobility of the oxidizer (air), 15 m should be the upper limit of bed thickness. From this consideration follows one additional condition: beds that are grouped into a single production unit should have a total effective thickness of up to 25 m in the case of steaming treatments, and up to 15 m in the case of in situ combustion. The degree of heat utilization also depends on the presence of partings in the reservoir stratum. For steaming treatments, it is recommended that the total thickness of the reservoir bed not be more than 2-3 times the effective oil saturated thickness [18]. Moreover, the thickness of the individual impermeable interlayers also has an effect on utilization of thermal energy. The interference of heat between successive permeable layers or horizons decreases when they are separated by thick impermeable interlayers. It is also reduced when heat zones shift irregularly along fingers of permeable layers. As a consequence, the overall heat effectiveness of the process suffers [18]. 20 1

Thermal Methods of Petroleum Production Calculations show that these impermeable interlayers separating two adjacent permeable horizons must not exceed 10 m in thickness. If these thicknesses are greater, the adjacent petroliferous layers should not be grouped into a single producing unit. These figures are confirmed by results of an analysis run on cores from a development test well drilled in an oil reservoir of the Khorosany field in Azerbaijan. This particular well was drilled in a zone already situated behind the burning front in a bed treated by in siru combustion. In some fields the oil-bearing strata are massive. Their thicknessesexceed the limits of 25 m and 15 m indicated earlier as suitable for use of steaming and of in siru combustion, respectively. In these cases it is necessary to modify the techniques of thermal treatment, inasmuch as such oil reservoirs cannot be divided into several separate production units. Massive oil-bearing beds can be heated in stages, with the treatment proceeding from the bottom towards the top. Successively higher and higher lying intervals of the petroliferous bed are reperforated, while worked-out lower lying intervals are isolated. The advantage of petroleum production from such massive reservoirs by the bottom-to-top method has been demonstrated in experimentscanied out at the All-Union Petroleum Research Institute (VNII Neft) [111. On the other hand, in oil fields with multiple petroliferous horizons, even a thin bed with a thickness of less than 3 m can form an independent production unit if it is dictated by technical factors. Such a thin bed may be lying between two thicker beds, one above and another below, each containing larger oil reserves. In this case, a dry variant of in siru combustion may be used to extract oil from the thin bed first. Part of the thermal energy generated in this process is then utilized to heat the adjacent overlying and underlying thick beds. Production from these preheated larger oil reservoirs by other suitable methods follows next. Thus, by improving techniques of the different heat treatments, it is possible to broaden substantially the applicabilityof the thermal methods.

With the introduction of heat into the bed, the original reservoir conditions are still preserved at the hydrodynamic front of displacement; e.g., the oil is being driven with water at the temperature of the formation. Because of great viscosity differences between oil and water, as the oil is being displaced by water, the oil-water contact constantly changes, with tongues of water breaking through into the production wells. In producing high viscosity oil by thermal methods, area treatment (dispersed pattern) schemes must therefore be used. Under such schemes, it is possible to disperse quickly the thermal energy supplied by the treatment and to start production right away from a significant number of wells. Because of great viscosity differences between oil and water, 7-point and 9-point well patterns can be employed. These well patterns, by the way, insure better a sweep coefficient of the area treated. Area treatment schemes, howver, have one drawback. Inasmuch as a significant number of wells are involved simultaneously. it is more difficult to control thermal processes by regulating inputs of injection wells and outputs of production wells. And yet the balance between the inputs and outputs must be smctly preserved over the entire area treated. Moreover, both inputs and outputs of individual wells must be maintained in accordance with fixed proportions. One additional factor makes the maintenance of such a rigid operating regimen very difficult. Some wells break down unexpectedly and some require unplanned checkups and investigations. In either case, temporary shutdown of such wells will be the result. Linear schemes of thermal treatment, especially those using multi-row grids, are very adaptable to process regulation. However, large individual heated zones must first be formed before a common linear thermal front can be developed. The dispersed pattern (area treatment plan) 202

Planning of Oil Production by Thermal Methods can thus be converted to a linear scheme. Such a maneuver can best be carried out when the wells in an oil field have been drilled in rows. For such conversion to succeed, equal spacing of rows from one another and of individual wells within each row must be kept. For reservoirs with high viscosity petroleum, the only rational linear pattern is one consisting of two rows of injection wells situated on the outside, and three rows of production wells on the inside. In large oil reservoir, it is best to orient linear rows at right angle to the smke of the petroliferous bed. With this arrangement, it is possible to put the field in production successively,moving up dip.

It was noted earlier that greatest thermal effectiveness is obtained with a relatively dense network of wells. This holds true for the different methods of thermal treatment such as steam flooding, in situ combustion, and the method of forming heat banks with their subsequent displacement by other agents. In the case of the last named method, the analysis shows (Fig. 113) that as the well spacing increases the required size of thermal bank also becomes larger. Admissible well spacing depends, in the first place, on the thickness of the bed and on its permeability. These two parameters basically determine the rate of heat introduction into the bed, the speed of displacement of the heat bank, and the degree of heat loss into the overlying and underlying strata. Recommended well densities for use with thermal methods of enhanced oil recovery vary within a broad range from one well per fraction of one hectar to 10 or more wells per hectar. For example, for shallow reservoirs containing viscous crude oils, such as those of the Kenkiiak and Karazhanbas fields, the well densities of planned thermal treatment call for one well per 1 to 2.25 ha. At Usa oil field, of Upper Paleozoic age, with a thick 30-40 m petroliferous bed lying at depth of 1,400 m, a grid was used with a density of one well per 6.25 ha. For use with wet variants of in sifu combustion, grids are possible with densities of one well per 10-16 ha.

It takes a relatively short time to complete oil production from one unit area of a grid pattern in a field treated by thermal method, providing that the well spacing is sufficiently close. The overall time required to complete production from the entire oil reservoir or field, as a whole, is determined by the rate at which each additional unit of the grid can be drilled, equipped, and placed in production. This relationship is especially pronounced in large oil fields, which may have as many as 1,000 wells (Fig. 114); Fig. 114. Relationship between rates of petroleum output and time required for development, on the one hand, and rates of completing new grid units, on the other. Data applies to the Karazhanbas oil field. Q-oil output in fractions of maximum annual production t-time required for development K,_number of wells drilled per year. 203

Thermal Methods of Petroleum Production Seven variants have been calculated for rates of grid development. I - 2n, I1 - 3n ...VII - 8n wells/yr. As Fig. 114 shows, variant I is least effective, regarding both the maximum petroleum production and the time required to develop new grid units. Drilling of new wells merely compensates for those going out of production, but does not result in intensive increase of oil production. At the same time, in determining the rates of completing new grid units. one must take into account not only the oil output level but also the efficient utilization of compressor and steam generating installations. This equipment can be used over and over again, and it is capable of serving simultaneously the needs of a large number of injection wells. Therefore, when new grid units are placed in operation at an optimum rate. the total requirements of the field being treated for additional compressorand steam generating installationscan be reduced. The data discussed shows that the employment of thermal methods of oil production need not be limited to EOR work. Under proper conditions, these methods, especially in large oil fields, can be used right from the beginning of production to increase the current yield. At the present time, the development of a number of new large oil fields, such as Karazhanbas, Usa, Gremikhin and Novo-Suksin. provide for such early large-scale use of thermal methods of production alongside the primary methods. In this connection, fields containing high viscosity petroleum have been recently classified, with individual deposits rated on the basis of their suitability for application of thermal methods of production: deposits in reservoirs made up of poorly consolidated terrigenous sediments; sands having a tendency to run; reservoirs lying at the depth of down to 800 m; e.g., Karazhanbas field; Class 11: deposits in reservoirs made up of consolidated terrigenous sediments; sands not running; reservoirs lying at depths from 800 to 1500 m Class III: deposits in reservoirs made up of carbonate rocks with complex porosities of fracture, cavern, and and vuggy types. Class I:

4.

PLANNING OF OIL PRODUCTION BY THERMAL =ODs KARAZHANBAS FELD PROJECT

FOR TfIE

Field experiments on commercial-scale oil production by wet in siru combustion and by steaming methods are planned (1980) for the Karazhanbas field. Productive horizons in the field consist of sands, poorly cemented fine-grained sandstones and siltstones. Seven of these petroliferous horizons with commercial reserves have been identified, lying at depths down to 550 m. They can be distinctly traced throughout the entire field. The effective thickness of individual oil-bearing beds ranges from 2 to 33 m. Crude oil is heavy (specific density of 0.93 g/cm3), and has high content of tars (up to 24.5%) and of sulfur (up to 2%). Its viscosity varies from one oil-bearing bed to the next and from one section of the field to another; it ranges from 200 to 650 centipoise. With a change in the temperatureof the crude oil from 300C to 700C, its viscosity decreases by a factor of 10. The content of natural gases, essentially that of methane, dissolved in the petroleum is small, not exceeding 10 m3/t. Under reservoir conditions. crude oil is undersaturated with gas. Formation pressure is by 6-8 kg/cm2 greater than the hydrostatic. Short duration tests of oil wells gave yields varying from 0.5 to 200 m3/day. The majority of wells had yields above 5 m3/day. Productivity coefficients of the wells ranged from 0.007 to 17 m3/day/(kg/cm2). In individual wells, productivity was significantly affected by sand entry. In 204

Planning of Oil Production by Thermal Methods exploration wells, the quantity of this sand is within range of 0.004%-2.0%. Measures to control sand entry, e.g., use of bottomhole filters and controlled start-up of wells, made it possible to increase oil yields by 3-4 times. Karazhanbas field has several petroliferous beds. Separation of the main oil-bearing horizons into independent production units is the first step in developing this field successfully. On the basis of the concentration of petroleum reserves and the distribution of producing horizons, three principal oil reservoirs can be identified within the Karazhanbas field. The effective thickness of these reservoirs ranges from 4 to 16 m. Individual petroliferous beds within each reservoir are to be treated separately. The thermal process in each bed is to be controlled by injection of the agent (air. steam, and water). For this reason, in drilling the production wells, a general plan is being used for the entire reservoir; whereas in drilling injection wells, each petroliferous bed and horizon is considered separately. Three different variants of well grids are being used: (a) 100 x 100 m (IwelVha), (b) 150 x 50 m (lwelv2.25 ha), and (c) 200 x 200 m (1 welY4 ha). The selection of a particular variant for each one of the 3 oil reservoirs was based on (a) physical and geological characteristics, (b) method of thermal treatment to be used. and (c) rates at which new wells are to be added to the particular grid. Regardless of the spacing variant used, all grids are of linear type and are oriented at right angles to the strike of the petroliferous bed. They have equal spacing of rows and the same interval between individual wells within each row. Two lines of injection wells are situated on the outside, and three lines of prodduction wells on the inside. The middle row of production wells can be changed to injection wells. By this maneuver, the multi-line grid pattern can be readily altered to a single line scheme. Furthermore, by introducing the injection wells one at a time in a single-line configuration, one can freely convert this linear grid to a seven-point (dispersed area) pattern. This well arrangementmakes it possible to accomplish two main purposes: (a) Determine the optimum grid density of wells for effective application of each one of the planned thermal processes; (b) Work out methods of control and regulation in developing the field and to determine the technologically the most suitable well pattern. In the Karazhanbas field project, investigation of several thermal methods is being emphasized. One is the creation of thermal banks by in situ combustion with their subsequent displacement by water injection. Variants of this method will also be investigated. Ahead of the thermal bank, in one such projects, a bank consisting of polymer solution is to be formed. Filling up 2-3% of the pore space of the reservoir rock, this polymer bank should improve the sweep of the oil-bearing bed by the subsequent displacing agent, namely by injected water. A variant combining a thermal bank advancing from the ignition wells with thermal treatment of the bottomhole zones of production wells will also be tested. Further study will also be conducted on cyclic steaming by blocks, a new technique that already had results in the oil fields of the Krasnodar region. The plan calls for the development of the three experimental sections of the Karazhanbas field in the course of three years, with the drilling of a total of 600 wells. According to calculations made for two of the oil reservoirs of the Karazhanbas field, production from these two reservoirs over their life of 50 years, with natural drive would result in an oil recovery factor of only 7%, with water flooding-20% but with thermal methods-up to 40%. The thermal teatment project in the Karazhanbas field is being conducted in three stages: First: In this preparatory phase all surface and downhole equipment and installations are tested and operating parameters of the wells are determined. The installations are put to work and, as the initial data start to come in, corrections are made both in technology and techniques. Of equal importance, at this time, is further detailed geological, geophysical, and physical study of the 205

Thermal Methods of Petroleum Production oil reservoir. These investigations include such things as coring of every other well, gas sampling, well logging, and a study of reservoir mechanics, including the calculation of reserves of oil in place. Second: Thermal banks are created during this stage. Initial production starts and the optimum operating regime of the entire complex of surface and downhole equipment is determined. Third: During this final phase, hot water drive created by water injection displaces thermal banks toward production wells. Production continues until all recoverable petroleum is extracted from the reservoir. Inasmuch as the well grids are expanded gradually, with new injection and production wells added in succession, the three stages do not have definite time limits and may overlap. However, as the information accumulates with the addition of each new group of wells and more and more operating problems find their solutions, the first stage for that group of wells should become shorter and shorter. The Karazhanbas oil field project is planned for completion within the next 5-6 years. The expected information and results should provide answers to many hitherto unsolved problems of petroleum production by thermal methods from large deposits.

1.

Avdomin, N.A., 1965.0 vliianii okhlazhdeniia plasta na ego nefte otdachu [Effect of cooling of petroleum reservoir on it yield]. NTS PO dobyche nefti. Vypusk 28, Moskva, Nedra, pp. 66-71. (journal article)

2.

Aleksandrov, A.P., 1978, Atomnaia energetika i nauchnotekhnicheskii progress [Atomic energy and scientific-technicalprogress]. Moskvq, Nauka. (treatise)

3.

Bokserman, A.A., Zheltov Yu.P., Zhdanov S.A., 1974, Vnutriplastovoe gorenie s zavodnieniem pri razrabotke neftianykh mestorozhdenii [Use of in siru combustion with water flooding in petroleum production]. Trudy VNII, Vypusk 58, Moskva, Nedra. (professional paper)

4.

Garushev, A.R., 1971, Zavisimost' prirosta debita skvazhin ot kolichestva wedennogo v plast tepla pri tsiklicheskoi paroteplovoi obrabotke [Dependenceof production increase of oil wells on amount of heat input into the reservoir during cyclic steam injection], Neftiannoe khoziaistvo, No. 7, pp. 37-38. (journal article)

5.

Garushev, A.R., 1972. Termicheskoe vozdeistvie na plast pri razrabotke mestorozhdenii vysokoviazkikh neftei [Thermal stimulation of reservoirs of high viscosity petroleum]. VNIIOENG. (treatise)

6.

Garushev, A.R., Chernov B.S., 1973, Issledovanie temperaturnogo polia vokrug nagnetatelnoi skvazhiny [Study of the temperature field forming around the injection well]. Neftianoe khoziaistvo, No. 3, p. 38. (journal article)

7.

Golubiatnikov, D.V., 1931, Detal'naia geologicheskaia kana Apsheronskogo poluostrova (Khurdalano-Binagadinskiiraion) [A detailed geological map of Apsheron Peninsula, Khurdalan-BinagadmRegion]. Politizdat. 206

Planning of Oil Production by Thermal Methods

8.

Govorova, G.L., 1970, Razrabotka nefianykh mestorozhdenii v SShA [Petroleum production in USA], Moskva, Nedra.

9.

Gubkin, I.M., 1953, Podzemnaia gazifikatsiia neftianykh plastov i termicheskii sposob dobychy nefti [Underground gasification of petroleum deposits and thermal methods of petroleum production]. Trudy II. Izdatel'stvo AN SSSR. (professional paper).

10. Zheltov, Yu. P., 1968, 0 vytesnienii nefti iz plastov dvizhushchimsia frontom goreniia [Displacement of petroleum from reservoirs by a moving front of in siru combustion] V knige: Teoriia i praktika dobychi nefti. Moskva, Nedra, pp. 34-41. (book) 11. Kocheshkov, A.A., Tarasov, A.G., 1979, Eksperimental'nye issledovaniia mekhanisma vytesneniia nefti teplonositeliami primenitel'no k plastam bos'shoi tolshchiny [Experimental studies of oil displacement mechanism employing heat carriers applied to very thick reservoir beds]. Nefte promyslovoe delo, No. 4, pp. 77-1 11. (journal article) 12. Krylov. A.P., 1962, Projektirovanie razrabotki neftianykh mestorozhdenii [Planning of oil field exploitation]. Moskva. Gostoptekhizdat. (book) 13. Liubimov, L.P., 1974, Syr'evoi i energeticheskii krizis i ego vlianie na kapitalisticheskuiu ekonomiku [Raw material and energy crisis and its effect on the capitalist economy]. Mirovaia ekonomika i mezhdunarodnye otnosheniia. No. 12, pp. 14-25. (journal article) 14. Mirzadzhanzade, A. Kh., Kovalev, A.G.. Zaitsev, Yu.B., 1972. Osobennosti ekspluatatsii mestorozhdenii anomalnykh neftei [Characteristicsof production from deposits of anomalous petroleums]. Moskva, Nedra. (book) 15.

Oganov, K.A., 1967, Osnovy teplovogo vozdeistviia na neftianoi plast [Principals of thermal stimulation of petroleum reservoirs]. Moskva, Nedra. (book)

16. Bragin, V.A., Garushev, A.R., Lysov, V.A., 1967, Opyt primeneniia metodov termicheskogo vozdeistviia na neftanoi plast v Obedinenii Krasnodameftegaz [Experience learned in application of thermal stimulation methods in the oil fields exploited by the Krasnodar Region Oil and Gas Organization]. VNIIOENG, pp. 3-39. (professionalpaper) 17. Legasov, V.A., Ponomarev-Stepnoi, N.N., Protsenko, A.N., 1978, Perspektivy ispol'zovaniia i osnovnye problemy vnedreniia VTGR v tekhnologicheskie protsessy i elektroenergetiku [Prospectsand basic problems of utilizing in siru coal gasification for use in industrial processes and for elecmc energy]. Atomnaia energiia, tom 45, vypusk 6, pp. 41 1418. (journal article). 18. Rakovskii, N.L., Borisova, N.P., Dodonova, I.A., 1976, Vlianie geologo-fizicheskikh parametrov na tekhnologicheskie pokazateli razrabotki zalezhei teplovymi metodami [Effectof geological and physical parameters on results of commercial oil production by thermal methods]. Trudy VNII, vypusk 57, pp. 142-153. (report) 19.

, 1975, Teplovye metody dobychy nefti [Thermal methods of petroleum production]. Materialy vyezdnoi sessii Nauchnogo Sovieta PO problemam razrabotki 207

Thermal Methods of Petroleum Production neftianykh mestorozhdenii AN SSSR i Nauchno-tekhinicheskogo Soveta Ministerstva neftanoi promyshlennosti, November, Moskva, Nauka. (report) 20. Baibakov, N.K., Bragin, V.A., Garushev, A.R., 197 1, Termointensifiiatsiia dobychi nefti [Thermal enhancement of oil recovery]. Moskva, Nedra. (book) 21. Bokserman, A.A, Guzhnovskii, L.P., Rakovskii, N.L., 1971, Teplovye metody razrabotki neftianykh mestorozhdenii i obrabotki prizaboinykh zan plasta [Thermal methods of petroleum production and of stimulation of bottomhole zones of the reservoir bed]. Moskva, Nedra. (book) 22. Bokserman, A.A., Danilov, V.L., Zheltov, Yu.P., Kocheshkov, A.A., 1966, Teoriia i praktika dobychi nefti [Theory and practice of petroleum production]. Moskva. Nedra. (book) 23. Trebin, F.A., 1946, Neftepronitsaemost' peschanykh kollektorov [Permeability of sandstone reservoir rocks to petroleum]. Moskva, Gostoptekhizdat. 24. Aslanov, R.T., Bokserman, A.A., Zheltov, Yu.P., Ogandzhaniants, V.G., 1966, Filtratsiia nesmeshivaiushchikhsia zhidkostei v sloistykh poristykh sredakh [Filtration of immiscible liquids in porous bed media]. V sbornike: Teoriia i praktika dobychi nefti. Moskva, Nedra, pp. 19-21. (symposium paper) 25. Chekaliuk, E.B., 1965, Termodinamika neftianogo plasta [Thermodynamics of petroleum reservoir] Moskva, Nedra. (book) 26. Chekaliuk, E.B., Oganov, K.A., 1979, Teplovye metody povysheniia otdachi neftianykh zalezhei [Thermal methods of yield enhancement from petroleum deposits]. Kiev, Naukova dumka (treatise) 27. Chekaliuk, E.B., Filias, Yu.I., 1977, Vodo-neftianye rastvory [water-oil solutions]. Kiev, Naukova dumka. (a treatise) 28. Sheinman, A.B., Malofeev, G.E., Sergeev, A.A., 1969, Vozdeistvie na plast teplom pfi dobyche nefti [thermal stimulation of reservoir in petroleum production]. Moskva, Nedra. (treatise) 29. Bailey, H.R., Larkin, B.K., 1959, Heat conduction in underground combustion. Petrol. Trans. AIME, vol. 216. 30. Ferrandon, J., 1960, Theorie generale des econlements fluides sonterrains. Raport general, Conpt. Vena, 6-es Jornels hydraul. SOC.hydrotechn., France, Nancy. 31. Gottfried, B.S., 1965, A mathematical model of thermal oil recovery. Society of Pet. Engin. Journal, v. 5, No. 3, September. 32. Iroes. J.A., Schwass, N., 1955, Scaled experiment and the theories on water drive process. Petroleum Technology, J., No. 3. 208

Planning of Oil Producfion by Thermal Mefhods

33. Martin, W.L., Alexander, J.D., Dew, J.N., 1958, Process variables of in sifu combustion. Trans. AIME, v. 213. 34. Ramey, H.S.,1962, Wellbore heat transmission. Trans. AIME. Petrol. Technology J. 35. Author not indicated, 1969, Thermal recovery handbook. Gulf Publishing Co., reprinted from World Oil, No. 4. 36. Author not indicated, 1973. World energy problems. Fairplay Int. Shipping J., 299, No. 704, pp. 60-63.

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Geology in Petroleum Production

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Thermal and Catalytic Processes in Petroleum Refining

Tracers in the Oil Field (Developments in Petroleum Science)

Surface Operations in Petroleum Production, II

Casing Design - Theory and Practice (Developments in Petroleum Science)

Well Completion Design, Volume 56 (Developments in Petroleum Science)

Casing Design - Theory and Practice (Developments in Petroleum Science)

Microbial Enhanced Oil Recovery (Developments in Petroleum Science, No. 22)

Petroleum Geoscience

Opportunities in Petroleum

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