Technology for Developing Marginal Offshore Oilfields

TECHNOLOGY FOR DEVELOPING MARGINAL OFFSHORE OILFIELDS TECHNOLOGY FOR DEVELOPING MARGINAL OFFSHORE OILFIELDS D.A.FEE C...

Author: D.A. Fee

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TECHNOLOGY FOR DEVELOPING MARGINAL OFFSHORE OILFIELDS

TECHNOLOGY FOR DEVELOPING MARGINAL OFFSHORE OILFIELDS D.A.FEE Commission of the European Communities, Brussels, Belgium and J.O’DEA Institute for Industrial Research and Standards, Dublin, Eire

ELSEVIER APPLIED SCIENCE PUBLISHERS LONDON and NEW YORK ELSEVIER APPLIED SCIENCE PUBLISHERS LTD Crown House, Linton Road, Barking, Essex IG11 8JU, England

This edition published in the Taylor & Francis e-Library, 2005. “ To purchase your own copy of this or any of Taylor & Francis or Routledge’s collection of thousands of eBooks please go to http://www.ebookstore.tandf.co.uk/.” Sole Distributor in the USA and Canada ELSEVIER SCIENCE PUBLISHING CO., INC. 52 Vanderbilt Avenue, New York, NY 10017, USA WITH 42 TABLES AND 94 ILLUSTRATIONS © ELSEVIER APPLIED SCIENCE PUBLISHERS LTD 1986 British Library Cataloguing in Publication Data Fee, D.A. Technology for developing marginal offshore oilfields. 1. Drilling platforms—Design and construction 2. Offshore structure—Design and construction I. Title II. O’Dea, J. 627′.98 TN871.3 Library of Congress Cataloging in Publication Data Fee, D.A. Technology for developing marginal offshore oilfields. Bibliography: p. Includes index. 1. Oil well drilling, Submarine. 2. Petroleum in submerged lands. I. O’Dea, J. II. Title. TN871.3.F44 1986 622′.3382 86–439 ISBN 0-203-97390-9 Master e-book ISBN

ISBN 0-85334-435-3 (Print Edition) The selection and presentation of material and the opinions expressed in this publication are the sole responsibility of the authors concerned. 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. 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. Photoset in Malta by Interprint Ltd.

To our respective wives, Áine and Marita

Preface The idea for this review of the technology for developing marginal offshore oilfields arose out of a report which we were commissioned to undertake for the Irish Department of Energy in October 1984. The Department were looking for information on the different options for developing small oil accumulations in the exposed Irish offshore area, what systems were currently available, what new developments were likely in the next decade and the approximate cost of developing various sizes of reservoir using these systems. While compiling the report we discovered that, while all the literature and industry spokesmen agreed on the importance of marginal field technology, there was no publication which addressed the topic in any comprehensive fashion, with the possible exception of studies costing several thousands of dollars or confidential oil company inhouse reports. This review aims to cover this very broad topic in a way which is intelligible to a general technical reader. It is not possible to cover detailed design aspects of the various systems described here in a book of this size. References and a bibliography covering the topics discussed in each chapter are provided for those interested in pursuing the various subjects in more detail. We have sought the views of oil companies, design engineers, offshore consultants, contractors and researchers. We have obtained invaluable assistance from innumerable individuals and firms, far too many to list here. However, we would like to express our appreciation for all the time and assistance given, queries answered, literature searches undertaken, articles provided, etc. We would especially like to express our appreciation to a number of individuals who reviewed and edited the draft versions of this book: —A.R.(Bert) Schultz, Vice-President of Intec Engineering Inc. who provided advice on technology and cost parameters. —Dr Pat Shannon, Department of Petroleum Geology, University College Dublin. —F.B.(Fergus) Cahill, Exploration & Production Manager, Irish National Petroleum Corporation. We also thank our respective organisations, the Petroleum Affairs Division, Department of Energy and the Institute for Industrial Research and Standards, Dublin for their interest in this area and their permission to incorporate certain material from their report. However, we wish to emphasise that the opinions expressed herein are the authors’ own and do not necessarily reflect the views of the Petroleum Affairs Division of the Department of Energy nor the Institute for Industrial Research and Standards. Last, but certainly not least, we wish to thank Anna Kennedy, who patiently typed, and retyped, the document and Heather Gibson, who executed the line drawings. DEREK FEE JOHN O’DEA

Contents Preface Chapter 1 The Challenge of Marginal Fields

vii 1

Chapter 2 Elements of a Marginal Field Development Scheme

23

Chapter 3 Existing Marginal Field Technology

86

Chapter 4 Current and Future Marginal Field Development Concepts

149

Chapter 5 Construction and Operating History of North Sea Floating Production Systems Chapter 6 Marginal Field Economics and Costs

189

Bibliography

209 223

Appendix Conversion Factors 1:

229

Appendix Glossary of Terms 2:

230

Index

235

Chapter 1 The Challenge of Marginal Fields Nearly half of the world’s proven reserves of oil lie offshore and it is estimated that over two-thirds of all future oil discoveries will also be located offshore. But in any oil exploration area it is the larger fields which tend to be found first and even when small discoveries are made the oil tends to be left in the ground as the oil companies rush to develop the larger and more commercial fields. Classification of a discovery as ‘commercial’, ‘uncommerciar’ or ‘marginal’ depends on a combination of many factors, economic, technical and political, and is not necessarily indicative of the size of the field. A useful definition of the three terms would be: Commercial

— The prospect yields an economically attractive rate of return to the oil company when conventional technology is applied to its exploitation.

Uncommercial — The prospect is unlikely to yield an economic return to the oil company under any foreseeable technical or fiscal scenarios. Marginal

— The prospect may be capable of yielding an economic return to the oil company but only by using some innovative, technical and/or financial options.

While there is no general rule constituting what is an acceptable return, it appears that most companies regard a 7% to 15% real rate of return as being ‘marginal’. If the projected return is less than this level the development is usually postponed, while at higher rates the project could be expected to proceed. Oil companies share a characteristic which is common to most economic entities— they are not charities. It is quite natural that they should develop their more commercial discoveries first. However, offshore exploration and oil production has now been underway in the harsh northern latitudes for more than a decade. During that period a considerable number of marginal fields have been discovered. Indeed many fields which were quite uncommercial when they were found are now considered marginal as a result of the dramatic oil price increases since 1973 and recent technological advances. The purpose of this book is to provide a fairly comprehensive look at the technology for developing these offshore oilfields which are now considered marginal but which must be developed in order to ensure the western world’s continued production of petroleum. The layout of this book and the order in which the topics are discussed are as follows: Remainder of this chapter. We consider what is a marginal field, look at some figures for fields yet to be developed and attempt to put the subject in brief historical perspective.

Technology for developing marginal offshore oilfields

2

Chapter 2. We look at the various elements that could be incorporated into an offshore development. The actual design of any offshore production system is defined by the characteristics of the particular reservoir and the specific site. Each component of the system has advantages and limitations. Chapter 3. Many of the ideas proposed for developing marginal fields are not new. They tend to include elements which have been proven in other locations or in different combinations. Indeed several of the elements are incorporated in fields which have been operating in various areas for many years. A complete listing of these fields and details of the developments are provided. Even though some of these fields were never in the marginal category, even at project inception, they incorporate the reduced investment and accelerated production aspects usually associated with marginal field economics. Chapter 4. We review the various development concepts which are being proposed for marginal offshore developments. Some of these are available ‘off the shelf’ now, while some are more futuristic. Considerable work has been done on systems which have yet to be installed while many of the concepts which have been proposed will never be used. The parameters and constraints of the different concepts are tabulated to facilitate comparison between them. Chapter 5. It is one thing knowing that a system is in place—but does it work? Has it performed as well as expected? This chapter looks at two existing developments. Chapter 6. No review would be complete without some consideration of the construction and operating costs associated with the various elements and systems described in the earlier chapters. Unit costs are presented for the various elements of a development to enable the reader to estimate the cost of a particular development scheme. 1.1 WHAT IS A MARGINAL FIELD? As noted above, the ‘marginal’ field as generally understood is primarily an economic concept rather than a technical one. An offshore field is considered marginal if it cannot be developed at a reasonable profit using tried and tested, or conventional technology. The conventional technology for developing offshore oilfields in harsh environments is typically that of the steel template jacket supporting a combined drilling and production facility. The fixed platform solution works well for prolific offshore fields. However, when considering methods to develop smaller and smaller fields, in ever deeper water, the fixed steel or concrete platform has a number of major drawbacks: —They require an extended construction period. The time between the decision to develop and first oil production is, typically, four years. Thus they involve major capital outlays for an extended period before any cash flow is generated.

The challenge of marginal fields

3

—They are extremely capital intensive because of their massive size. Unfortunately, decreasing the topside loads, for smaller fields, will not decrease the size, and hence cost, of the structure to any appreciable extent. This is because up to 80% of the mass of the structure is acting to resist the environmental forces of waves, current and wind. —They are site specific—when a field is depleted a fixed structure becomes a major liability. Again, this is not a problem if the field is in production for the 15 or 20 years typical of large offshore developments. However, when one considers a marginal field which may only produce for three to seven years, the non-revisability of a fixed platform which cannot be redeployed has to be amortised over the brief life of the field. The alternative approach to the use of fixed platforms is to consider the use of what we call ‘Marginal field technology’, i.e. technology which aims to have the following characteristics: —Low capital cost—this generally involves a trade-off with higher operating costs and decreased reliability. —Rapid development period—thus reducing the time from start of expenditure to first oil. —Suitability for short-term use—thus promoting mobility and reuse of the system on other fields. —Amenable to innovative financing. The different marginal field technology options are discussed in the following chapters, but first let us consider how many of the offshore developments of the next two decades will be of the marginal field type. So far most of the development in the North Sea has been concentrated on the larger, easier to find deposits. The discovery of many further fields of the size of Brent or Forties is considered unlikely. The cushion of steeply rising oil prices is most unlikely to offset

TABLE 1.1 Likely Number of Future Offshore Developments in UK Continental Shelf Size of field (millions of bbls)

Number of future developments

Under 50

50

50–100

20

100–150

10

200–500

5

500–1000

1

Over 1000

—

Source: Offshore Business, Vol. I, 1983, Hoare Govett.


4

TABLE 1.2 Some W.European Offshore Discoveries and Development Prospect UK: Fields with development possibilities Name/block number(s)

Operator

Notes

West Heather 2/5

Union

Oil discovery separate from main Heather structure. May contain around 15 mn barrels recoverable

Emerald 2/10a, 2/15 & 3/11b

Chevron/ Sovereign

Oil discovered ’74, declared commercial under new tax regime. Plans for an extended production test and for possible floating production facility. Recoverable reserves 40–50 mn barrels

Lyell 3/2

Conoco

Oil discovered ’75. Requires further appraisal

Columba 3/7 & 3/8

Chevron/ BP Marginal oil discovery south of Ninian. Talk of single steel platform tied back to Ninian, but no decision expected until results of extended production test planned for 1985 are known. Recoverable reserves 100 mn barrels

Bressay 3/28a & Chevron/ 3/27 Lasmo

Heavy oil discovery. Feasibility study underway

Bruce 9/8a & 9/9b

Hamilton/ BP

Gas/condensate field plus small oil reservoir. Development, hindered by lack of pipeline in area, unlikely before late ’80 s. Estimated 100–150 mn barrels of condensate plus 2.4 Tcf of gas

Southwest Beryl 9/12a & 9/13

Mobil

Feasibility study by John Brown Offshore is said to be concentrating on a floating production facility. Recoverable reserves 60–100 mn barrels

Crawford 9/28a & 9/29a

Hamilton

Oil discovery. Further appraisal expected

Scapa 14/19

Occidental

Engineering studies undertaken by John Brown Offshore and McDermott. Hope to get annex B approval for a subsea development tied back to Claymore in late 1985. Recoverable reserves 35 mn barrels

—14/20

Texaco

Small oil field close to Tartan. Subsea development planned

Name/block number(s)

Operator

Notes

South Piper 15/17

Occidental Possible subsea development tied back to Piper which is now in decline. Recoverable reserves 30 mn barrels

Ivanhoe and Rob Roy 15/21a

Monsanto Oil discovery to south of Tartan. Recoverable reserves 80–120 mn barrels. Feasibility study by John Brown—possible floater

Galley 15/23

Occidental ’74 oil discovery. Complex geology and further appraisal drilling required. Possible single steel platform. Recoverable reserves 50–70 mn barrels


5

Central, East & West Marathon Brae 16/3 & 16/7a

Several structures undergoing appraisal. Steel platform similar to North Brae likely for 16/3 if reserves are proved

Miller 16/8b

Conoco

Oil and gas discovery. Approximately 110 mn barrels recoverable. Might extend into BP block 16/7b

‘T’block 16/17

Phillips

Comprises Tiffany, Toni, Thelma and Southeast Thelma. Tiffany likely to be developed first from single steel platform. 80–100 mn barrels of oil recoverable. May extend into 16/12a

Glamis & Sterling 16/21

Sun Oil

Two small discoveries close to Balmoral currently under development. 10–30 mn barrels recoverable, likely to be developed through Balmoral facilities

Andrew 16/27 & 16/28

BP

Marginal 80–90 mn barrel oil and gas prospect. Annex B application for single steel platform could be forthcoming ’85

Ettrick 20/2

Britoil

Regarded as high priority by operator, but requires further appraisal. Talk of single steel platform or floater depending on final reserves estimate (currently 50–75 mn barrels) into 20/3

Glenn 21/2

Zapex

Estimated recoverable reserves 60 mn barrels


Operator

Gannet & Kittiwake 21/25 & 21/30

Shell

Five separate structures containing an estimated 220 mn bbls oil and 17 mn m3 gas. Plans call for four steel platforms plus possible umc on Gannet North, feeding gas to Fulmar and oil via a pipeline to shore. Further steel platform on sixth structure, Gannet South, possible. Annex B expected 1986

Drake 22/5b

Superior

Oil and gas/condensate field. Recent appraisal wells have been disappointing. Conceptual design by Bechtel

Arbroath 22/17 & 22/18

Amoco

Department of Energy has ruled that this is an extension of Montrose. Any development will probably involve a simple platform installed over template already installed for appraisal drilling

Lomond 23/21 & 23/22

Amoco

Gas condensate field, recoverable reserves estimated at 34 bn m3. Interest in this field has been revived with building of Fulmar gas line.

Joanne 30/7a

Phillips

Oil and gas discovery still under appraisal, but could contain 100–200 mn barrels. Amoco’s 30/12b find is close by. Development decision expected soon

Notes

Cleeton, Hyde, BP Ravenspurn Hoton 42/29, 42/30, 48/6 & 48/7

Four gas accumulations. Plans call for eight to ten platforms (three process and the remainder wellhead). Possibly on stream by 1989 building up to a peak production of 11.5 mn m3/d

Amethyst 47/14a

Small gas find with reserves of around 8 bn m3. Nine slot template awaiting installation for early production pending development study

Britoil


6

Sole Pit 48/13 & 48/14

Shell

Several tight gas accumulations. Could contain 28 bn m3 of recoverable gas

—48/21a

Lasmo

Gas and condensates discovery in 15 m of water. Development studies underway


Operator

Notes

Audrey 49/11a

Phillips

Gas field, recoverable reserves around 28 bn m3. Gas already sold to BGC. Annex B for single platform development expected later this year. On stream by ’87?

‘V’ block 49/16 & 49/21

Conoco

Comprises North and South Valient, Vulcan and Vanguard. Possible two stage development requiring up to nine platforms. Design contract to Brown & Root. Reserves put at 212 bn m3

Welland 49/29 & 53/4

Arco

1984 discovery close to Thames field. Unitization talks underway with Mobil (49/29)

Eider 211/16

Shell

Likely to follow Tern development. Estimated 75 mn barrels recoverable. Conventional steel platform likely. Design contracts to JBOs and Matthew Hall

Don 211/18

Britoil

Oil discovery, extends in to 211/13. Still under appraisal

North West Dunlin 211/3

Shell

Possible subsea development from simplified umc producing to Dunlin—start up 1987. Recoverable reserves 35 mn barrels

UK: Other discoveries and prospects Block number

Operator

3/4

Texaco

Oil, 1975—close to Brent reservoir

3/14a

Total

Oil and condensates, 1973, Alwyn

3/25

Total

Gas, 1977

3/29

BP

Oil, 1977

9/9a

Total

Oil and gas, 1984—Bruce extension?

9/18a

Conoco

Oil, 1979

9/19

Conoco

Oil and condensates, 1976

9/24b

BP

Condensates, 1983

Block number Operator

Notes: hydrocarbons, date discovered, name, etc.

Notes: hydrocarbons, datediscovered, name, etc.

12/27

Burmah

Gas, 1983—may be developed to provide power for Beatrice nearby

13/29

Ultramar

Oil, 1981—30–50 mn barrels recoverable

14/18

Occidental Oil, 1978—later wells dry

15/13a

BP

Oil, 1975—SWOPS candidate?

15/22

Amoco

Oil, 1984


7

15/26a

BP

Oil, SWOPS candidate?

15/27

Phillips

Oil, 1976, Renee

15/30

Conoco

Gas condensate, 1975, Bosun

16/7b

BP

Oil, 1983

16/8a

Shell

Oil, 1984

16/12a

Occidental Oil, 1984—Tiffany extension?

16/13a

Britoil

Gas and condensates, 1984

16/18

Mobil

Condensates, 1983

16/22

Total

Oil, 1977

16/26

Gulf

Gas condensates, 1977

16/29

Phillips

Oil, 1975, Mable

21/15a

Britoil

Oil, 1981

21/19

Shell

Oil, 81

21/24

Texaco

Oil, 1978—close to Gannet

21/29a

Texaco

Oil, 1984

21/29b

Britoil

Oil, 1985

22/2

Burmah

Oil, 1984

22/5a

Amoco


22/19

Occidental Gas condensate, 1984—close to Montrose

22/24a

BP


23/26a

BP

Oil, 1976

23/27

Ranger

Oil, 1976

29/2a

Conoco


29/5a, 29/10

Arco

Oil and gas condensates, 1981

29/8b

Premier

Oil, 1983—Acorn

30/2

Britoil

Gas condensate, 1971

30/6

Shell

Oil, 1984

Block number

Operator

Notes: hydrocarbons, date discovered, name, etc.

30/13

Phillips

Oil, 1972

30/17b

Britoil

Oil, 1979—Clyde satellites

31/26

Amerada

Oil, 1983

41/24a

Total

Gas, 1969


41/25a

Total

Gas, 1969

42/1 5b

Zapex

Gas, 1984

43/26

Hamilton

Gas, 1984—tight reservoir

44/21

BP

Gas, 1984

44/22

Conoco

Gas, 1985

44/23

Texas

Gas, 1968

47/9b

BGC

Gas, 1983

47/13

Conoco

Gas

47/15

Amoco

Gas, 1973

48/6

BP

Gas, 1984—West Sole extension

48/11a

Arco

Gas, 1984

48/11b

Conoco


48/12a

Gulf

Gas, 1975

48/15a

Conoco

Gas, 1983

48/18b

Ranger

Gas, 1985—close to Sole Pit

48/22

Britoil

Oil, 1966

49/4

BP

Gas, 1984

49/5

Ultramar

Gas, 1984

49/6

Phillips

Gas, 1966, Ann

49/16

Conoco

Gas, 1971

49/25a

Shell

Gas, 1983

53/4

Arco

Gas, 1967, Scram

98/11

BGC

Gas, 1984—offshore Wytch Farm

113/26

HGB

Gas, 1982—near to Morecambe Bay field

205/10

Britoil

Oil—460 m of water

206/8

BP

Oil, Clair—heavy oil

210/15

Phillips

Oil, 1977, Wendy

211/13

Shell

Condensate, 1974

211/19

Conoco

Oil, 1977

Block number

Operator

211/22a

Tricentrol Oil, 1984

211/26

Shell

8

Notes: hydrocarbons, date discovered, name, etc. Oil, 1975


211/27

Amoco

Oil, 1976, Southwest Hutton

214/30

BGC

Gas 1984—557 m of water

9

Norway: Future fields and prospects Name/ block number

Operator

Flyndre 1/5a

Phillips

Notes Oil discovered 1973

Tommeliten 1/9 Statoil

Development delayed by haggling over fee for processing oil and gas on Ekofisk. Single wellhead platform planned. 24 bn m3 gas plus 37 mn barrels oil recoverable

—2/1

BP

Oil and gas discovery close to Ekofisk. Undergoing appraisal

—2/2

Saga

Oil find also close to Ekofisk

Gudrun 15/3

Elf

34 bn m3 gas prospect close to Sleipner and Brae in the UK sector. Also separate 70 mn barrel oil prospect close by

Sleipner 15/6 & Statoil 15/9

Gas sales agreement with BGC vetoed by UK Government. Development plans call for two platforms to deplete the estimated 180 bn m3 gas at a peak of 26 mn m3/day by ’97

Gamma 15/9

Statoil

Gas find close to Sleipner. 55 bn m3 gas recoverable

Bream & Brisling 17/12a

Phillips

Oil discovery still under appraisal

Southeast & East Frigg 25/2

Elf

Declared commercial July ’84. Development will probably be through two ‘Skuld’ subsea templates remotely controlled from the main Frigg platform. Combined recoverable reserves are put at 9 mn m3

Name/ block Operator number

Notes

Huldra 30/2, 30/3

Statoil

40–50 bn m3 gas recoverable

Veselfrikk 30/3

Norsk Hydro

250 mn barrel Oseberg satellite

Balder 25/10 & 25/11

Esso

Development licence granted but deferred after poor drilling results. Could be revived in future. Recoverable reserves 220 mn barrels

Hild 29/9 & 30/7

Norsk Hydro

Condensate discovery. Reserves put at 51 bn m3 recoverable

—30/11

Shell

Oil and gas discovery close to Frigg

Brage 31/4

Norsk Hydro

Oil discovery close to Oseberg. Recoverable reserves estimated at 200 mn barrels plus 6 bn m3 gas

Troll 31/2, 31/3 31/5 &

Shell, Saga Largest oil or gas field yet discovered in North Sea. Recoverable Statoil & Norsk reserves estimated at 1 2 trillion m3 of gas Development options


10

31/6

Hydro

for this deepwater field are still being considered, but firm plans are unlikely before ’86. Gas sales talks begun

Munin & Hugin 33/9

Mobil

Statfjord satellites likely to be developed using a subsea system tied back to the main platforms or Murchison. Recoverable reserves 250 mn barrels oil and 5 bn m3 gas

Snorre 34/4 & Saga 34/7

Large oil discovery still undergoing appraisal—recoverable reserves estimated at 725 mn barrels. Onstream 1993?

Agat 35/3

Saga

Oil discovery close to coast, but in deepwater

Tyrihans 6407/1

Statoil

Oil discovery on Halten Bank

Midgard 6407/2 & 6507/11

Saga

Halten Bank discovery with recoverable reserves put at 104 bn m3 of gas, 21 bn m3 of condensates and 876 mn barrels of oil

Name/ block number

Operator

Notes

Draugen 6407/9 Shell

Substantial light oil discovery

Smoerbukk 6506/12

Statoil

Gas/condensate find

—6507/7

Conoco

1985 oil discovery

—7119/12

Statoil

1983 gas discovery

—7120/7

Statoil

1982 gas discovery

Askeladden 7120/8

Statoil

Recoverable reserves estimated at 170 bn m3, but at present is only commercially viable if sold as Ing. Feasibility study in hand

Albatross 7120/9

Statoil

Recoverable reserves estimated at 57 bn m3, but faced with the same disposal problems as Askeladden

Alke 7120/12

Norsk Hydro

Shallow gas discovery

Snow White 7121/4

Statoil

Gas discovery with thin oil column. Reserves put at 130 bn m3 but geology is complex

Netherlands: Future fields and prospects Block number

Operator

Notes: hydrocarbons, status

B18

NAM

Oil, production application submitted

E13

Pennzoil

Gas

F18

BP

Oil

K4

BP

Gas

K6

Petroland

Gas

K9

Placid

Gas, plans for single platform


11

K10a

Pennzoil

Gas, production application submitted

K17

NAM


L8a

Pennzoil

Gas

Block number

Operator


L11b

Union

Gas, design work by Heerema and Global Engineering

L12a

NAM


L13

NAM

Gas

L15

NAM


L2 & F17a

NAM

Oil and gas

L14

Placid

Gas, one platform planned

L16a

Conoco

Oil, production application submitted

P1

NAM


P2a

BP

Gas, production application submitted, plans for unmanned wellhead tied in to P6

P2b

Mobil


P8a

Mobil

Oil

P9

Amoco

Oil, under review

Q8

BP

Gas, plans for unmanned wellhead controlled from shore, water depth 16 m

Denmark: Future fields and prospects There are a number of fields currently undergoing appraisal all operated by DUC. They include: East Rosa, West Lulu, Boje-1, Otto-1, Lulu, Nils, Adda, Nord-Arne, Anne Qwenn, Lola, Arne Olaf, Nora, Gert, Elly, Igor Bo, Liva and number of fields Jens.

Germany: Future fields and prospects Block number

Operator


A6

Gew, Elwerath

Gas, still under appraisal

Mittleplate

Texaco

Oil, two concrete platforms being considered. DM 100 mn pilot scheme under consideration by government. 75 mn barrels recoverable

Ireland: Future fields and prospects Block number

Operator

26/28 Porcupine

BP

Notes: hydrocarbons, status Oil


49/9

Gulf

Oil, appraisal continuing

48/18

BP

Gas, 1985

12

Reproduced by permission of Offshore Engineer.

the higher costs of developing the smaller fields that remain. The trend towards smaller developments in the future is clearly shown in the estimate in Table 1.1 of future developments in the UK continental shelf. A similar distribution of field sizes would be typical of other offshore regions. According to a study by analysts Smith Rea/Hoare Govett, marginal field projects in the North Sea through 1990 are expected to cost $18 billion, with 75–80% of this expenditure in the UK sector. Table 1.2 shows some Western European Fields which are future prospects. Most of these fields are in the marginal category. Thus the outlook is extremely promising for the development of increasing numbers of marginal offshore fields. However, according to the controller at Esso Exploration and Production a 25% reduction in the current cost of developing North Sea fields of 50 million barrels recoverable reserves is necessary in order to make them economic. It must also be borne in mind that every offshore development involves the State as a partner, either indirectly through the various combinations of taxes and royalties, or directly by reason of state participation agreements. Any change in the fiscal environment can affect the economics of an offshore prospect much more rapidly and effectively than developments in technology. This is clearly evidenced by the boost given to marginal field developments by recent favourable changes in the tax code. Similarly, a drop in interest rates or increase in oil prices can dramatically improve marginal field economics. Finally, it is worth remembering that changes in technology, capital costs, the oil price, tax rates, interest rates etc. will not eliminate marginal offshore oilfields. These changes will merely shift the margin to put even less attractive accumulations into the ‘marginal’ category. 1.2 OFFSHORE OIL TECHNOLOGY—A HISTORICAL PERSPECTIVE It is sometimes difficult to appreciate just how recent a phenomenon is the petroleum industry. The world’s first oil well was only drilled in 1859, in Titusville, Pennsylvania by a certain Colonel E.L.Drake. Drilling and production of offshore oil began in the shallow waters of the US Gulf of Mexico in 1946 and production of offshore oil from deep exposed offshore fields commenced only a little more than a decade ago. The story of the development of the offshore industry, from its initial beginnings on a timber platform standing in 18 ft of water off the coast of Louisiana to today’s awe-inspiring structures and space age technology, is a fascinating story in itself. However, this brief overview of the history of offshore oil is principally concerned with charting the offshore developments which have led to the current demand for, and availability of, technology which is applicable to developing marginal fields in harsh offshore environments. Offshore petroleum activities can be usefully divided into:


13

—Exploration drilling: discovering where the oilfield is and what the characteristics of the oil reservoir are; —Oil and gas production: recovering the petroleum from the reservoir and getting it to market. Let us consider the technology involved in each: Exploration Drilling Since that first offshore well in 1946, exploration drilling has advanced rapidly. Today drilling is conducted all around the world in all types of environment and in very deep waters. Wells have been drilled in areas which experience 35 m waves, 6 knot currents, 120 knot winds, in water depths of 1000 m, 400 km offshore and in areas of icebergs and icefloes. Figure 1.1 shows current and future active exploration areas. The first offshore exploration well was drilled from a fixed wooden structure. Operators soon realised that drilling wells from a structure which could be moved from one location to the next would be much more efficient than installing a permanent structure for a well which could easily be a dry hole. The mobile offshore drilling unit was the result. This consisted initially of a barge which could be deballasted to rest on the sea floor and piled in position. The dry upper deck supported a drill rig arrangement almost identical to that used on land. These submersible units were obviously very limited as to the depths of water in which they could operate. Later the jack-up drilling unit was developed. This consisted, essentially, of a bargeshaped structure with legs which could be lowered to the sea bed; it was equipped with a jacking mechanism which enabled the barge, with drill rig and wellhead on top, to be raised above the sea surface and so provide a stable drilling table. Early jack-ups were confined to shallow water depths and the sheltered environments of the Gulf of Mexico and Venezuela. Continued development of these units has produced a current generation which can drill in harsh North Sea environments in water depths up to 100 m. Nevertheless, since jack-ups are founded on the sea bottom they are inherently limited in the water depths in which they can operate. By moving the wellhead to the sea floor and by drilling from a floating vessel operators realised that the depth limitations of the jackup could be overcome. However, when drilling from a vessel floating on the surface it is apparent that the heave, pitch and roll motions (i.e. vertical and lateral) must be compensated for to enable the drill bit to stay on the bottom of the hole with the proper weight and rotation. This was accomplished by developing vessels which had reduced motions in waves and by mechanisms to compensate for the vessel’s heave and so allow drilling to take place in open waters. The two basic floating drilling vessels which have evolved are the ship shaped drilling unit and the semi-submersible. The ship shaped drilling unit: these are self-propelled and have the appearance of conventional sea-going ships with a drill rig on top. The advantage of these units relates to their deep water capability, their capacity to transport huge supplies of drilling equipment and their comparatively low cost. However, the current generation of drill ships have difficulty in operating in rough seas.


14

The semi-submersible: these are typically flat platform decks on which the drilling equipment is mounted. The deck is supported by flotation pontoons. The rig is usually self-propelled and can be moored over the drilling position with the pontoons flooded so that the lower portion of the rig is partly submerged to a depth of 50–80 ft for improved stability. The platform is supported clear of the sea. The semi-submersible’s major advantage when compared to a ship shaped unit is in reduced motions when subjected to waves. Roll, pitch and heave are greatly reduced and the natural period of a semi-submersible is normally about 20 seconds, which is far above the everyday wave period experienced during drilling. Reduced motions allow the operator to keep the operation going efficiently in severe wave conditions. Over the years much has been done to optimise size, shape etc. to further enhance the inherent stability of the semi-submersible. The different kinds of offshore drilling unit are illustrated in Fig. 1.2. A comparison of the typical motion characteristics of semi-submersibles and ship shaped units is shown in Fig. 1.3. Water depth records for offshore drilling operations since 1960 are illustrated in Fig. 1.4.

FIG. 1.1. Areas of major offshore activity. Shaded areas represent continental shelf to 200 m. shaded well drilling areas, Jan. 1979–April 1980. Source: Offshore Magazine and Industry Reports.


15

Oil and Gas Production When oil production moved offshore some kind of platform had to be provided to support the wellheads and the process systems that separated and disposed of the water and associated gas from the oil. As water

FIG. 1.2. The different types of offshore drilling unit.


FIG. 1.3. Comparison of typical motion characteristics of semisubmersible (SSM) and ship shaped units.

16


17

FIG. 1.4. Water depth records for offshore drilling operations 1960–Sept. 1985. depths increased these structures became ever larger and it became increasingly expensive to fabricate a platform for each individual well. The logical solution was to put all the wells on a single platform and to drill deviated wells. (Sea extensions of the Huntingdon Beach field in Southern California were tapped by directional wells drilled from beach locations as early as the 1920 s.) With modern techniques it is possible to reach deviations up to 60° so that the reservoir is drilled in the optimum way (see Fig. 1.5). Plotting the water depths in which platforms have been installed on a log scale against the year that the offshore installation started the result obtained is that of a linear trend (see Fig. 1.6). A similar line can be drawn for exploration wells drilled with mobile drilling units. The lines are found to deviate. The explanation is that with floating drilling techniques the capacity to drill in deeper waters advanced faster than the capacity to install fixed offshore structures. Two factors cause the gap to widen, namely cost and lead time. The cost of drilling in 100 or 300 m of water is not strongly dependent on water depth whereas for fixed platforms it is.


18

FIG. 1.5. Deviated drilling for fixed production platform. For the big structures in increasing water depths one faces an increasing lead time. One of the most familiar types of fixed offshore platform is the piled steel structure. It has certainly been one of the most successful types. From initial beginnings in the shallow Gulf of Mexico steel platforms have been developed to the stage where they now include the giant structures for the oilfields of the North Sea and deep waters of the Gulf of Mexico and offshore California. Concrete (and steel) gravity structures of the type shown in Fig. 1.7 have been developed, mainly for the North Sea. They offer the attraction of integrated oil storage, a short installation time since no piling is required, and the possibility of installing most of the topside facilities at sheltered inshore locations. These gravity platforms are huge structures and are only suited to large field developments.


19

FIG. 1.6. Deviation between exploration and production depth.—— , exploration: exploration wells, water depth record;—·—, production: production wells, water depth record. The progress of fixed structures is shown graphically in Fig. 1.8. It appears that the limits may soon be reached for these fixed structures. They are costly and difficult to fabricate and install and lead times become excessively long. In view of the increasingly massive size of fixed structures as water depths increased it is not surprising that companies have looked for alternatives. One possible solution consisted of utilising the experience with drilling units—semi-submersibles and ship shapes—to arrive at a floating production solution. The first floating production unit was installed in 1975 on the Argyll field in the North Sea. Since then many more such systems have been developed and refined. The various floating production systems will be examined closely in later chapters. Another school of thought believes that the solution lies somewhere between the completely fixed structure and the floating production unit. Accordingly various hybrid type structures have been proposed. Three such hybrid types have already been developed and installed. These are the Guyed Tower (installed on the LENA field, 1983),


20

FIG. 1.7. Concrete gravity platform. the Tension Leg Platform (installed on the Hutton field, 1984) and the Articulated Column (installed on the N.E.Frigg field in 1983 and also used for various flare structures and offshore loading points). These various hybrid options will also be examined later. A plot of platform water depth records since 1960 for fixed and compliant structures is shown in Fig. 1.8. The third alternative is to eliminate the need for any topside facility and to transfer all operations to the sea bed. Subsea wellheads were installed in the early 1960 s and since then there have been considerable developments in subsea technology, underwater control systems etc. and rapid development of the depth capabilities of underwater completions. See Fig. 1.9 for an illustration of water depth records for subsea production since 1960.


21

FIG. 1.8. Platform water depth records since 1960 for fixed and compliant structures.——, fixed structures; – – – –, compliant structures.

FIG. 1.9. Water depth records for subsea completions. With the development of compliant, or moving, structures the connections between the wellheads and the production facilities—the flowlines—assume a new importance. In onshore oilfields the flowlines are simple flanged steel pipes. When the wellheads are now transferred to the sea bed the problems of underwater flowlines and the flowlines between the sea bed and the surface facilities (the flowline risers) assume major importance. The development of flexible flowlines and the various developments in riser


22

design and technology had a major part to play in the history of offshore production; the major milestones in their development are discussed in Chapter 2. Once oil is produced there is still the problem of bringing it ashore. Two methods are commonly used—pipelines to shore and offshore loading into tankers. The technology of offshore pipelines has kept pace with other offshore developments. Pipelines have now been successful in over 500 m of water in the Mediterranean. While pipelines have low operating costs they can involve a large capital investment, especially for remote offshore fields. Offshore loading systems have also developed over the years. Originally confined to sheltered coastal waters and estuaries, they are now operating in some of the harshest offshore environments. The major milestones in the developments of offshore loading systems are discussed in Chapter 2.

Chapter 2 Elements of a Marginal Field Development Scheme In this chapter we shall examine the various components which, connected together, go to make up a marginal field development system. The development system may be broadly divided into the following items: —production support, —riser, —subsea equipment, —crude oil storage, —export system. It must be emphasised at this point that the division made above is only to facilitate analysis of the various components and that production systems for individual fields are integrated performing an overall function rather than a series of separate operations. 2.1 PRODUCTION SUPPORTS Production supports can be classified as follows: (1) jack-ups (e.g. Ekofisk, Saltpond, Badejo, etc.) (2) semi-submersibles (Argyll, Enchova, Dorado, etc.) (3) tankers (Castellon, Nilde, Cadlao, Tazerka, etc.) (4) barges (Bekapi, Handil) (5) articulated columns (North East Frigg) (6) tension leg platforms* (Hutton) (7) guyed towers* (Lena) *(6) and (7) may be applicable to deep water marginal finds.

2.1.1 Jack-ups Jack-ups are normally used in drilling operations but may be used as a production support where topside weight and water depth are not limitations. The jack-up consists of a deck section, somewhat like a barge, and several truss or tubular telescopic legs. It is normally towed to the location with the legs raised. On site, the legs are lowered to the sea bed and the platform is then jacked up to safe level above the sea. One prerequisite for the use of


24

this type of support is the suitability of the sea bed soil conditions and the likely penetrations of the legs (Fig. 2.1). The normal water depth operational range of the jack-up is from the seashore to 75 m; however, the latest generation of jack-ups, the Gorilla class, are able to operate in water depths of up to 110 m and sea states of up to 30 m wave heights. A jack-up has been used in only one North Sea development scheme, Ekofisk, where the Gulf Tide was used as a production support in an early production system for three years in a water depth of 70 m. The advantages of using a jack-up as a production support are as follows: —Jack-ups are leaseable and with a worldwide utilisation rate of 76% day rates are very competitive.

FIG. 2.1. Typical jack-up system. —They have all the advantages of a fixed platform in shallow water—no moorings required. —They have a low abandonment cost and can be returned to drilling. —Wells and riser can be of conventional type. The disadvantages of the jack-up are: —Limitations on topside weight and water depth operating range. Existing jack-ups could only operate as production supports in the southern North Sea. However, new jack-up designs could be used in the central North Sea. —Limited to areas where soil conditions permit satisfactory support of the legs.

Elements of a marginal field development scheme

25

—Fatigue problems could limit the utilisation to several years unless costly alterations are made to the structure. —No storage capability. A typical example of a field development using a jack-up as a production support is the Espoir field offshore Ivory Coast. The development was carried out by Phillips Petroleum and utilised a converted jack-up drilling rig, the Dan Duke, which was leased in Japan after a 600 ton production module was installed in 1982. The development system incorporates the following features: —the use of the Dan Duke as production support, —a special driven caisson riser housing, —deepwater, widely spaced subsea wellheads for production in 120–150 m of water, —deepwater pipelines laid by the reel method from a dynamically positioned reel ship, —saturation diving for subsea wellhead hook-up from a dynamically positioned diving support vessel, —CALRAM field storage tanker, —shuttle tanker off-loading. The Dan Duke stands in 130 m of water and is designed to receive through a 1.8 m diameter riser caisson, twelve 8 in. diameter flowlines and one 12 in. export line to a Catenary Anchor Leg Rigid Arm Mooring (CALRAM), essentially a tethered buoy to which is pin connected the Phillips Enterprise, a 230000 dwt. VLCC. An estimated 300000 bbls of processed crude can be stored aboard the Phillips Enterprise. A detailed field development sketch can be found in Chapter 3. The project was begun in 1980 with the conversion of the Dan Duke; the addition of the production module was commenced in 1981 and was completed in early 1982. 2.1.2 Semi-submersibles Until now this has been the most popular form of floating production support, with 19 fields (see Chapter 3) having been developed using semi-submersibles. The semi-submersible type of production support is a buoyant structure which is catenary (conventionally) moored to the sea bed. These moorings allow large heave motions in extreme environments and impose severe problems on the riser configuration often resulting in poor production efficiency. In high sea states the riser is disconnected from the subsea system and recovered on the platform or ‘hung-off’, i.e. suspended from the platform. There are many configurations of semi-submersible but they all consist of a vessel with a majority of its displacement some distance under water and with small crosssectional area members piercing the water surface. The advantages of the semi-submersible are as follows: —The motions of the semi-submersible are small, and therefore it can be used in severe environments. —There are many semi-submersibles available for conversion. —Low abandonment cost, and can be returned to drilling. —Mooring is normally of the conventional catenary type.


26

—Can easily accommodate conventional rigid or flexible risers. —Can provide simultaneous drilling and/or workover capability. Disadvantages associated with semi-submersibles as production supports are: —Operational water depth limited to 70–1000 m. —Payload limited due to displacement and stability sensitivity. —Number of wells 4–40. —Some difficulty with respect to conversion. —Limited storage, if any. —Requires long distance pipeline or SPM tanker loading system for produced crude. British Petroleum’s Buchan Field is the latest development in the North Sea incorporating a semi-submersible as a production support. The Buchan Field was discovered in August 1974, in a deep reservoir 154 km east-north-east of Aberdeen. Because of its complex geology, Buchan was considered as a marginal field with estimated recoverable reserves of 58 million barrels. The development system chosen incorporates the following elements: —A floating oil production platform converted from the Pentagone design semisubmersible exploration rig, Drillmaster, renamed Buchan Alpha. —A production/export riser system consisting of one 12 in. export riser surrounded by eight 4 in. production risers, eight 2 in. gas lift lines and two 4 in. service lines. The whole bundle is supported from the platform by an adjustable tensioning system to prevent buckling. —Eight producing subsea wells, five drilled through a steel 9 slot template measuring 8×15 m, and two satellite wells 1.5 km from the template, an eight-well 2.5 km to the west was completed in 1980. —Two 4 in. flowlines and associated hydraulic control umbilicals connecting each satellite well to the template. One of the flowlines carries oil and associated gas and the second carries ‘lift gas’. —A subsea manifold on the template linking the flowlines to the riser system. —A 15 m diameter CALM (catenary anchor leg mooring) buoy anchored by six 4 in.×400 m chains and associated anchors in 110 m of water. —A 12 in. submarine pipeline 1.7 km long from the manifold on the template to the pipeline end manifold (PLEM) under the CALM buoy. The PLEM is connected to the buoy by a flexible hose. —Two 100000 ton tankers, especially modified for bow loading and dedicated solely to offloading from the field. Tankers are moored to the CALM buoy by a 21 in. diameter hawser. Oil is loaded through a 12 in. floating hose. This development highlighted one of the problems associated with semi-submersiblebased production systems, i.e. difficulty with conversion. Changes in regulatory requirements, some caused through the accident with the Alexander Keilland, led to more extensive rebuilding than anticipated. These changes led to increased cost and a delay of approximately one year. The project took four years (1977–1981) from submission of the development plan to completion. Conversion work began on the Drillmaster in October 1978 and tow out began in September 1980. The drilling of the template wells was completed in November 1978 and the CALM buoy was placed on site in July 1979. Oil


27

production from Buchan began in May 1981 with design production being achieved in July, 1981. 2.1.3 Tankers This type of production support consists of a tanker converted for production operations with a permanent yoke attachment to a single point mooring (SPM). There are various types of SPM that have evolved from the basic catenary anchor leg mooring (CALM) and single anchor leg mooring (SALM); the two types used to date are the single buoy storage (SBS) and the single anchor leg storage (SALS). These systems will be examined in detail in the section on export systems. The tanker is allowed to weathervane around the SPM by means of a fluid swivel arrangement at the yoke/SPM interface. The production riser extends from the sea floor to the fluid swivel. A converted tanker is used because it provides the cheapest form of floating platform and already has existing oil storage capacity. This storage capacity is a major factor in the operation of this type of system as it increases production efficiency by providing buffer storage when the weather prohibits offloading by shuttle tanker. The advantages of a tanker based system can be summarised as follows: —Large capacity in terms of weight carrying. —Large area for process equipment installation. —Large capacity for storage of products. —Oversupply on the market, therefore cheap to buy. —Easily converted to a production support. —Includes adequate accommodation. —Easy loading of shuttle tanker from production tanker. —Ability to withstand 100yr storm conditions while continuing production. The disadvantages of a tanker based production system are: —No possibility of work-over operations (exception: Castellon). —Moored tankers are subject to large motions, therefore the mooring system must incorporate the concept of weathervaning. —The mooring must be combined with the riser system. —Maximum number of wells is currently 8. —Operational water depth is 50–150 m. The Tazerka field development incorporates the latest in technology relating to tanker based production systems. The field was discovered in July 1979 by Shell Tunirex operating for a joint venture with Agip (40%) and Entreprise Tunisienne d’Activites Petrolieres (ETAP 20%). It is situated some 56 km offshore Tunisia in water depths of 140–300 m in the Hammemet Grand Fonds permit. The production system includes the following elements: —A converted 210000 dwt. tanker Murex as a production support. —A production riser system consisting of eight 4 in. production risers and eight 4 in. service lines.


28

—A single anchor leg storage (SALS) system including a 25 m across, 7 m high gravity base through which the flowlines from the wells pass into rigid steel piping. —A series of subsea wells (4) connected to the base by flexible flowlines. —A 250 ton manifold chamber installed above the yoke used for tanker mooring. —A 6×4 in. multi-path high pressure swivel specifically designed to accommodate facilities for production, testing, gas-lift and water injection while permitting the production tanker to weathervane. The Tazerka field was the first to utilise a multi-well concept necessitating a high pressure multiple path swivel. The SALS consists of a structural member 140 m long, 5 m in outer diameter with an inner well of 2.2 m diameter which contains all the conduits and control lines for the wells. The fluid-path coupling across the unijoint at the base is by a jumper hose arrangement from steel pipe on a frame on the base to steel pipe extending from the bottom of the riser. Tazerka, having recoverable reserves of 10 m barrels, began producing in 1982 and reached its designed production capacity of 10000 bbls/day in 1983. 2.1.4 Barge Based Systems A barge is the simplest form of monohull structure, being usually box-shaped or semiship shaped. Barges do not generally incorporate a means of propulsion and must be towed to the final location. Barges have not been utilised as production supports in the North Sea although several concepts, including a concrete barge, have been proposed. The advantages of a barge as a production support are as follows: —Large deck area and weight capacity for installation of process equipment. —Capacity for storage of products. —Cheap and available for quick conversion. —Cheap to build in any shipyard. The disadvantages of a barge are: —Physical characteristics similar to a tanker, therefore requires a mooring system which permits the barge to weathervane. —Mooring may combine riser system. —Maximum number of wells is 8. —Operational water depth is 30–150 m. —Requires relatively benign environmental conditions. —No drilling or work-over capability. —If an existing barge is being used it will not normally incorporate accommodation. Barge mounted production systems are relatively rare and although some concepts have been proposed for the North Sea (particularly with reference to offshore LNG) the only systems so far installed have been in the Far East. The Bekapi field in Indonesia developed by Total is typical of this type of production system. A barge mounted system was utilised for twelve months from July 1974 to July 1975 as an early production system.


29

The system consisted of the following elements: —A single wellhead platform. —A barge mounted production system connected to the wellhead by a 4 in. flexible riser. —A storage system consisting of two 1500 ton barges capable of holding two days production each. —A shuttle tanker capable of round tripping to Balikpapan in 48 hours. 2.1.5 Tension Leg Platforms A tension leg platform (TLP) is a semi-submersible shaped steel structure which is connected to the sea bed by tubular steel mooring lines or ‘legs’. The natural buoyancy of the platform creates an upward force keeping the legs under constant tension. This maintains vertical stability while allowing some horizontal movement (Fig. 2.2). The advantages of the TLP are as follows: —Minimal horizontal motions and no vertical motions. —The tethers offer a more efficient length-to-cost ratio than conventional platforms, i.e. such a system would be substantially cheaper than a conventional platform in deeper water. —Most of the assembly can be carried out in sheltered, near shore waters before tow out to the production site. —Good payload capacity, but weight control is critical. —The super-structure can be built in a shipyard. —Can provide workover capability. The disadvantages: —Limited to water depths over 150 m. —It is not possible to convert a semi-submersible to a TLP. The first oilfield to be developed using a TLP is the Hutton field which is located about 150 km north east of the Shetland Islands in about 160 m of water. The recoverable reserves are estimated at 200 m barrels. The TLP consists of four basic elements—the deck, the hull, the mooring system and the well template.


30

FIG. 2.2. Typical tension leg platform. The deck measures 78 m by 74 m. It consists of three integrated deck levels containing the main process and support systems: the main deck, the mezzanine level and the weather deck on top. External modules for the drilling rig, power generation,


31

accommodation, helideck and flare tower were contracted to yards in a number of locations in the UK and elsewhere. The hull, which weighs some 20000 tons, is a semi-submersible structure of six columns interconnected by pontoons, all of which are compartmented, providing buoyancy and containing a ballasting system. The four corner columns are 17.4 m in diameter and the two inner columns 14.5 m in diameter. Each column is 65 m high. In normal operating conditions only half of the hull is above sea level. Deballasting holds the legs in tension, keeping the platform stable in the most severe weather conditions. The mooring system consists of tethers connecting the four corners of the hull to a piled foundation on the sea bed. The tethers consist of 260 mm steel tubes with a 75 mm hollow core; they are manufactured in stands of 9.5 m. The tension leg system is so designed that individual tethers can be removed for maintenance or inspection without affecting the integrity of the platform. The well template is a tubular steel structure which is piled to the sea bed and through which production wells are drilled and the sales line delivers crude oil to the export system. The template is designed to permit pre-drilling of 10 wells which allowed Hutton to come on stream quickly. Although the Hutton field was discovered in 1973 a detailed development plan was not submitted to the Department of Energy until January 1980 and was approved in August of that year. The main structural contracts were awarded in mid-1981 and development drilling began in that year after installation of the well template. The deck was loaded out in February 1984 and mated with the hull in May 1984; the total structure was installed on the Hutton field in August and the TLP came on stream in October 1984. 2.1.6 Articulated Column An articulated column is a structure which is connected to a base (gravity or piled) on the sea bed by means of an articulated joint, normally a cardan type joint. The structure is maintained in a floating condition by means of a flotation collar located just below the surface of the water. The column may be fabricated from steel (in tubular or trellis fashion), or concrete, or a combination of steel and concrete. Because of its articulated connection, the column follows the movement of the waves and is capable of inclining itself in any particular direction. Starting at the sea bed the various elements of the column are as follows: base, articulated joint, floating column, buoyancy or flotation tank just below the surface, splash zone element transparent to wave action and the head of the column. The advantages of articulated columns for producing marginal fields are: —Because the columns are light in steel they are inexpensive relative to fixed structures. —Depth insensitive, articulated columns have been designed for 1000 m water depth. —Wells can be pre-drilled. —Mooring uses proved components, i.e. cardan joint. —Satisfactory motion response. —Storage possibilities in the base structure. —Can incorporate offloading boom for SPM operations. The disadvantages are:


32

—Low payload capability, it is unlikely that an articulated column could be used alone as a production support. —No work-over capability. —No gas lift or water injection capability. The only development utilising an articulated column as a production support is the North East Frigg field developed by Elf. North East Frigg is a marginal field 18 km from the Frigg field, the reserves of which were not sufficient to justify a traditional development. The development incorporates the following elements: (1) A subsea station which includes the wellheads for six clustered gas producing wells, a manifold, the control umbilicals and the 16 in. export line to the Frigg field. The equipment is protected by a heavy subsea template (20 m×30 m×8 m, 350 tonnes) piled to the sea bed. (2) The field control station (FCS) consists of an 8 m diameter articulated steel tubular column installed in 100 m of water and located 150 m from the subsea station. The function of the FCS is to house the equipment required to —convert electrical signals from the Frigg field into hydraulic pressures for operating the subsea gas production valves; —control closely the wells through individual 2 in. kill lines; —periodically leak test the production tubing safety valves in each well; —inject continuously hydrate inhibitor into wells during gas flow. (3) Six specially designed umbilicals, each consisting of one 2 in. tube and twenty tubes, link each christmas tree to the deck of the FCS. (4) The North East Frigg facilities are linked to TCP2 Frigg field platform via a 16 in. gas line. The field development was begun in 1981 with the construction and installation of the subsea template and manifold. The wells were drilled in 1982 and completed in 1985; assembly and installation of the FCS took place in 1983. The total system was commissioned in 1984 and production began in that year. The North East Frigg production support is designed for unattended operation. Routine maintenance is carried out by personnel from the Frigg platform as required. 2.1.7 The Guyed Tower The guyed tower is another form of compliant structure which has been installed by Exxon. This structure is designed particularly for deep water fields in the Gulf of Mexico. The tower is supported by a piled foundation and its stability is maintained by a series of guy wires radiating from the steel tower and termination on piled or gravity anchors on the sea bed. Weights located three-fifths of the way down the guy


33

FIG. 2.3. Guyed tower. wires will allow the structure to tilt without seriously affecting the tension of the wires (Fig. 2.3). The guyed tower has the following advantages: —In similar water depths it is much cheaper than conventional platforms. —It is easy to build because of repetition of design joints. The disadvantages are: —Unproven technology. —Limited payload. —No storage. —Installation and maintenance costs of guy wires unknown. —Guy wires may snarl fishing trawls. There has been only one development incorporating a guyed tower as a production support; that is Mississippi Canyon Block 280in the Gulf of Mexico which has been developed by Exxon. The site is in 300 m of water and lies approximately 183 km southeast of New Orleans. Twenty guy lines secure the tower to the sea bed and allow it to comply with wind and wave forces. Each of the guys is 520 m long and is terminated on the sea bed by 200 ton weights. The weights are joined together on the sea bed somewhat like bicycle chain links. Anchor lines 400 m long extend from each clump to an anchor pile. The production equipment provides separation, oil treatment, gas dehydration and compression for 50MMcfd of natural gas, 30000 b/d of oil and condensate and 10000 b/d of water. Eight


34

main piles have been driven through the centre of the tower into the sea bed to support the weight of the structure and an additional six 1828 mm diameter piles were driven around the outside of the tower to keep it from twisting. The tower was loaded out and installed in July 1983 and production began in early 1984. 2.1.8 Design Criteria for Marginal Field Production Supports Each oilfield development presents its own unique mix of problems to those entrusted with the task of selecting an appropriate production scheme. Also, while each system may consist of individually suitable components, the highly interactive nature of these elements—be they production support, riser system, subsea system or offloading—can lead to some incompatability if the system as a whole is not well designed. The design criteria for a floating production support are briefly listed in order of importance (Patel, M.H., Technical Assessments of Floating Production Systems): —A sufficiently high payload to allow all necessary processing and to encompass the required marine systems and possible oil storage. —Sufficiently low wave-produced support motions to permit process plant, marine equipment and the crew to function with an economically viable minimum down time. —Acceptable mooring system loads in extreme sea states but with sufficiently low mooring offsets to allow a riser system to function with low down time. —Acceptable system behaviour in very extreme sea states with or without remedial actions such as pulling risers or slackening moorings. —Acceptable product transport or sales system (pipe line or SPM) to ensure continuous production with minimal weather down time. —Certification, inspection and maintenance considerations. —Capital and operating costs. —Construction or conversion time scales; also installation time.

TABLE 2.1 Summary of Characteristics of Production Supports Production support

Motions

1. Jack-up

None

None

Yes

Limited

2–10

110

Yes

None

2. Semi-sub

Small

Conventional

Yes

Limited

4–40

70– 1000

Yes

Small

3. Tanker

Small

SPM/conventional

Yes

Large

2–10

50– 750

No

Large

4. Barge

Small

Conventional

Yes

Limited

2–10

50– 150

No

Large

No

Good

20– 40

150– 1000

Yes

None

5. TLP

Mooring

Minimal Tension leg

Conversion Payload No. Water Work- Storage possible of depth over wells (m)


35

6. Articulated Minimal Articulated joint column

No

Limited

6–10

100– 600

No

Minimal

7. Guyed tower

No

Limited

40– 60

100– 400

Yes

Minimal

Minimal Pile plus guy wire system

TABLE 2.2 Comparison of Four Tanker Based Marginal Production Systems Installation site

Vessel size (dwt.)

Mooring Water type depth (m)

Wave ht. (max., m)

Production capacity (b/d)

Number of wells (max)

Excess gas disposal

Castellon field (Spain)

60000

SALS

117

15

20000

1 Incinerators

Nilde field (Italy)

80000

SALS

90

18

20000

1 Vent Stack

Cadlao field (Philippines)

127 000

SBS

90

17

30 000

2 Ground Flare

Tazerka field (Tunisia)

210000

SALS

140

18

20000

8 Vent System

Source: Carter, H.T. and Foolen, J., Evolutionary developments advancing the floating production, storage and offloading concept. OTC 4273, Offshore Technology Conference, Houston, Texas, 1982.

TABLE 2.3 Factors Affecting Choice of a Marginal Field Production Support Drilling/ workover

No. of wells

One

Environmental conditions

No

One

Type of support

Mild/moderate

300 DP tanker with workover rig

Severe

700 Conventionally anchored semi-sub

Yes

Several

Water depth (m)

Mild/moderate

100–500 Jack-up/semi-sub

Severe

100–500 Jack-up/semi-sub

Mild/moderate

50 Barge


36

700 Conventionally anchored tanker Severe

300/500 SWOPS/semi-sub

Mild/moderate Several

750 Tanker weather vane 150–1000 Semi-sub

Severe

−250 Semi-sub −1 000 TLP

There are a large range of design tools available for the selection and testing of the various elements of a marginal production system. Computer programs have been developed which can accurately predict the motion characteristics of various production supports under the influence of forces generated by specific environmental conditions. These programs can examine several mooring configurations and check riser configurations. Table 2.1 and 2.3 summarise the characteristics of the various production supports and give an indication of the conditions under which each support can be used. Table 2.2 compares four tanker based production systems. 2.2 RISERS The riser is one of the most important and complex items in any offshore development, floating or fixed. Before proceeding to an examination of the various riser systems currently being used it is perhaps useful to examine some of the terms used in connection with risers. Definition—‘riser’ is a generic term describing a single tubular or a series of tubulars connecting a sea bed termination to a facility at, or above, the sea surface. The term applies whether fluids are moving upwards or downwards. In general there are five possible riser systems: (a) production riser system, (b) drilling riser, (c) workover riser, (d) wireline riser, (e) product sales/export riser. Production Riser System This embraces all those elements associated with fluid movement from the sea bed to the production facility, including: (a) at the lower end a riser connection package (RCP);


37

(b) at the upper end, the fluid off-takes and the tensioners including compressors and controls. Also included in the production riser system are such items as the RCP test stump, riser test equipment and all riser handling, running and pulling equipment which supplements the derrick, draw-works and outfitted cranage. Riser Bundle This includes all the tubulars, any structural members, buoyancy collars, guide funnels, individual line tensioners, articulated joints, telescopic joints etc. which make up the completed production riser system in its operational form, but excluding the main tensioning system and the fluid off-take flexibles. Integral Riser Bundle This is an arrangement whereby the pulling (retrieval) of a single riser line requires the pulling of the bundle. Non-Integral Riser Bundle This is an arrangement whereby a single riser line may be pulled without disturbing other riser lines within the bundle and without interruption of the function of the other lines. Composite Riser Systems This is a system which incorporates both integral and non-integral features. It is usually the type of riser system used in offshore floating production systems. Lines within the Production Riser System: These may include the following: (a) Production riser—the tubular which conducts upwards the ‘produced fluids’ from the well (or wells if comingled flows are achieved subsea) to the process plant. (b) Gas lift riser—the line which conducts downwards the gas which is to be introduced into the production string down-hole for well ‘kick-off’ (inert or associated hydrocarbon gases) or for production flow enhancement (associated hydrocarbon gases). This line may serve a single well or a series of injection wells. (c) Annulus monitoring line—this line permits periodic monitoring of the well annulus. (d) Export riser—usually a large single bore tubular carrying the processed crude downwards to the sea bed for onward transmission to a pipeline or tanker loading facility (sometimes called a sales riser). (e) Gas export riser—a single or multiple line carrying produced gas to the sea bed for onward transmission.


38

(f) Service riser—one or more lines which have several duties, the more important of which are the hydraulic testing of the connected riser lines and flushing out of riser lines prior to pulling. (g) Hydraulic control lines to control well functions, riser hydraulic connectors, air can monitoring and control. Riser Joint This is one finite length of fluid conductor between connections; these connections may be screwed, bolted or may have ‘dogs’ or latches. Stand This consists of two or three joints made up to 100 ft in length, the stand being stowed in the derrick rack. The handling of stands obviously reduces riser running/pulling times. This operation is similar to drill pipe handling during drilling. Riser Test Stump This is a replica of the sea bed riser connection array used for pressure testing of the riser connection package (RCP) and the checking of dimensional compatability before running the riser. 2.2.1 Riser Design Criteria In general the riser system should be designed to be simple, operationally flexible, use well proven components and be capable of being handled in 100 year storm conditions. The design of the riser is very much dependent on the field characteristics and the other elements of the production system. Among the factors to be considered in riser design are the following: —volume and number of production streams; —level of subsea manifolding; —field secondary recovery requirements, e.g. water injection and gas lift; —drilling/workover capacity of the production support; —riser 100 year storm capability; —export and sales requirements; —the extent to which novel components may be incorporated;


FIG. 2.4. Risers.

FIG. 2.5. Flexible risers.

39


40

—installation, maintenance and repair requirements. Only when all these elements have been considered in detail can the riser be designed and evaluated. Figure 2.4 shows various arrangements of tensioned rigid risers while Fig. 2.5 shows the options available when flexible risers are used. 2.2.2 Operational Riser Systems Since riser systems are highly individual and are designed for specific operational requirements it is difficult to establish general operational systems. In order to bring out the various elements of riser design and operation, six riser systems will be examined in detail: —Argyll/North Sea —Dorado/Spain —Buchan/North Sea —Campos Basin/Brazil —Casablanca/Spain —Balmoral/North Sea The first three installations listed above are permanent tensioned rigid riser systems of various types. The second three installations have flexible riser systems. Argyll Riser System The main function of the Argyll riser is to transport crude oil production from a subsea manifold to the semi-submersible production support and then to transport processed crude from the support back to the subsea manifold for offloading by tanker at an SBM. The initial production system, installed in 1975, comprised four satellite oil wells produced to a subsea manifold and individually routed up the riser. The subsea manifold was designed to accommodate up to six production lines, four water injection lines, one export line, one service line and one purge line. In 1979 a crack appeared in the export line of the manifold and a replacement manifold was designed and fabricated. The second manifold did not include the four water injection lines. Two further production wells were brought on stream in 1979 and these were accommodated on the new manifold. The Argyll riser is a rigid non-integral riser consisting of the central export oil line of 10 in. nominal diameter acting as a structural strength member with ten non-integral production, service and purge lines (4 in. nom. dia.) and one hydraulic line spaced around the periphery in guide funnels. The riser is composed of sections joined by a standard threaded connection and is retrievable to the semi-sub on disconnection from the subsea manifold by a remotely actuated, hydraulic connector. A flexible universal joint sits above the hydraulic connector in order to permit relative angular motions between the riser and the subsea manifold. The top of each riser is connected to an individual tensioner and motion compensator similar in configuration to a normal drilling riser. The non-integral concept was chosen for the Argyll field because this allowed the operator to retrieve single lines for maintenance without halting production.


41

Since the Argyll production system utilises a tanker offloading system and because there is no storage capacity in the production support, the limiting factor for riser disconnection is the sea state at which the tanker would have to disconnect from the mooring buoy. However, operational experience has shown that tanker disconnection is not the limiting factor but the heave of the semi-submersible is in fact the over-riding design parameter. A maximum semi-sub heave of 2.0 m leads to riser disconnection; this heave occurs at wave heights well below the design case for tanker disconnection. Dorado Riser System The Dorado field consists of three closely positioned subsea production wells. The field was developed in two phases. Phase 1 began in 1978 and comprised a long-term tubing production test from a single well; production was via a subsea test tree and string to a surface tree. Crude oil was exported by a tanker loaded directly from the semisub by a floating hose. The second phase comprised the drilling of two additional subsea wells and their connection to the semi-sub via a rigid riser system. The Dorado riser system for the three wells was individual rigid tensioned lines transporting produced fluids to the semi-sub production support. A flex joint is used at the bottom of each riser string to accommodate riser deflections caused by vessel production movements. The initial concept for the individual risers was to run the line inside a 7 in. casing with the dual purpose of riser protection and the provision of an annulus. The production lines were run to surface trees. However, the high bending movements at the subsea tree connection anticipated for the 100 year storm design condition rendered the initial concept unacceptable. Eventually after a detailed study the 7 in. casing was dispensed with. Because of the individual nature of the risers the Dorado field was the first to use its riser system for both production and wireline workover operations from a semi-sub without affecting production from the other wells. Buchan Riser System The function of the Buchan riser system is similar to that of the Argyll system, i.e. the transport of produced fluids from a subsea manifold to the semi-submersible production support and from there to transport the crude oil back to the manifold for eventual export via a tanker based export system. The riser system chosen is a rigid non-integral system similar to Argyll with the addition of a considerable number of lines to accommodate future gas lift for the seven subsea wells (five template and two satellite). The Buchan riser is shown in Fig. 2.6. Since its installation in 1982 the Buchan riser has been made up of one central export oil line (12 in. nom. dia.) with eight production oil lines (4 in. nom. dia.), eight gas lift lines (2 in. nom. dia.) and two service lines (4 in. nom. dia.), each integral with its associated production line. The export line is made up of 50 ft lengths. At the top end, the export


42

FIG. 2.6. Buchan riser system. line is supported by a tension collar to which eight riser tensioners are connected. A gooseneck mounted on top of the riser carries the 12 in. hose which connects to the semisub. At the bottom, the export line is flanged to a universal joint which is fixed to the subsea manifold by a connector. The peripheral lines are also built in 50 ft lengths. Four tensioners provide the tension for the peripheral risers by distribution through a system of bridles. The Buchan riser is designed to permit production in sea states of up to 5 m significant wave height and to remain connected in sea states of up to 6.5 m significant wave. The design wave height for riser disconnection is 7 m whereas the design wave for disconnection of the loading tanker is 5 m (see Chapter 5).


43

FIG. 2.7. Enchova flexible riser systems. 2.2.3 Flexible Risers The various elements of the flexible riser system can be seen by reference to Fig. 2.7; they include the following main items: —flexible riser, —quick connect/disconnect coupling, —bend restrictor, —anchoring device, —riser stainless steel outerwrap. A flexible line is basically composed of steel and plastic. Steel components ensure the mechanical performance and plastic components render the flexible pipe leakproof. This combination constitutes the patented pipe structure. The typical riser structure includes five principal layers:


44

—An interlocking spiralled steel carcass (layer 1) provides resistance to crushing and prevents deformation of the pipe. —An inner thermoplastic sheath (layer 2) and an outside thermoplastic sheath (layer 5) composed of polyamide II render the riser leakproof. —An interlocking zeta spiral (layer 3), called the pressure armour, ensures the inner Rilsan sheath’s binding and the integrity of the structure’s internal pressure. —Two cross-armoured steel wire layers (layer 4) provides resistance to pulling and longitudinal stresses induced by internal pressure. The quick connect/disconnect coupling is used to disconnect the riser quite rapidly (less than 10 seconds) in the event of an emergency, such as fire, anchoring chain rupture etc. without risks of pollution.

FIG. 2.8. Balmoral riser layout.


45

The plastic bending restrictor is fitted behind the end fitting in order to limit the cyclical bending movements of the riser caused by the relative motions of the semi-sub. The riser is anchored so that its position will not be disturbed by the movements of the semi-submersible platform during its operational life. The advantages of flexible risers over rigid risers for some applications may be summarised as follows: —less investment cost; —no requirement for riser retrieval in difficult weather conditions, which means less down time and higher production; —no sea bottom connection or re-entry which means less maintenance cost; —more easily and rapidly installed; —easy extension to system capacity; —marginal impact on floating vessel design; —excellent corrosion resistance. Campos Basin Riser System The geographical area which has seen the greatest use of flexible risers has been the Campos Basin, offshore Brazil. The risers have been installed on different fields and in a variety of water depths. All of the installations have used ‘Coflexip’ flexible pipes as risers and have generally utilised the free hanging configuration. The Enchova field production riser is typical of the risers used by Petrobras in other field areas. The Enchova field began producing in 1979 from a single well via a tubing string inside a drilling riser and blow out preventer (BOP). The Penrod 72 was used as production support. Subsequently a subsea satellite well was completed and a flexible riser bundle installed. lines, a 1 in. hydraulic umbilical, The flexible riser bundle consisted of 4 in. and and electrical cable connected between a subsea satellite well and the semi-sub. A schematic of the riser system is shown in Fig. 2.7. Preliminary studies were carried out to investigate the feasibility of three separate riser system designs. Each design consisted of a bundle of four flexible lines to enable the connection of the subsea wellhead to the semi-submersible platform. The three different riser systems studied were: —the double catenary riser, —the tensioned riser, —the free hanging riser. Installation of the flexible lines was carried out by the laying vessel Flexservice I. Computer calculations and model basin tests led to the selection of the free hanging riser configuration primarily because of its ease of installation and retrieval.


46

Casablanca Riser System Casablanca is a small field in the Mediterranean consisting of two wells. Development of the field took place in four phases with the first three phases utilising the semi-sub Alfortunada as a production support. Phase 1 involved one well producing via the drilling riser and BOP while the second well produced via a free hanging flexible riser composed of 4 in. and 1 in. lines. Phase 2 involved the replacement of the initial export system, i.e. direct floating hose link between the semi-sub and export tanker, with a 12 in. flexible export pipe from the semi-sub to a subsea export pipeline. Phase 3 involved the replacement of the drilling riser production method with a subsea tree and the installation of flexible riser bundles composed of four 6 in. and two 4 in. lines. Phase 4 involved the removal of the semi-sub and its replacement by a fixed platform. Balmoral Riser System The Balmoral riser system will be the first flexible riser system to be used under North Sea conditions. The system chosen has been developed from earlier experience with flexible risers. Figure 2.8 shows the riser system chosen. The general arrangement consists of four independent bundles, simple catenary type linking the bow of the vessel through an intermediate buoy to four riser bases. The intermediate buoys are situated some 50 m above the sea bed with 15 m spacing between them. The distance between the riser bases and the template is 100 m. The lines consist of: Bundle No. 1

4 in. gas lift 4 in. kill line 3 in. annulus control

Bundle No. 2

2×8 in. production

Bundle No. 3

10 in. export line

Bundle No. 4

2×6 in. water injection

In each bundle all lines are independent and free to move relative to each other. 2.2.4 Alternative Riser Designs There are several alternative riser designs being proposed for various applications; among these are: —ribbon riser, —articulated column riser, —catenary flexible riser with subsea tower.


47

Ribbon Riser This type of riser system has been developed by Shell for deep water applications and consists of a flat array of risers in the form of a subsea

FIG. 2.9. Ribbon riser system. articulated boom (see Fig. 2.9). The risers are rigidly fixed to the production support vessel with relative motions being accommodated in the articulated boom by elastomeric joints. Articulated Column Riser Articulated columns have generally been used as mooring devices for tanker based floating production systems. However, the mooring device may also be considered as a rigid self-standing riser linked to subsea wells (see Chapter 4).


48

Systems have been designed which have emphasised the compatability of the fluid transferring equipment with the column and head rotations. This system is particularly useful in extreme environments and in water depths up to 400 m.

FIG. 2.10. Foster wheeler risers concept. Catenary Flexible Riser with Subsea Tower This concept utilises a submerged articulated tower connected to the surface support by flexible pipes. The choke manifold may be located on top of the tower within easy diver access and the use of flexibles eliminates any need for tensioning equipment on the support. The tower extends to within 45–50 m of the water surface from which flexible lines can easily be extended to a floating production vessel. Figure 2.10 shows a typical layout.


49

2.2.5 Comparative Assessment of Risers Table 2.4 shows a comparative assessment of ten riser systems under seventeen different headings. The ten systems assessed were as follows: A. A riser associated with a single anchor leg mooring (SALM). B. A rigid integral riser. C. A rigid non-integral riser.

TABLE 2.4 Comparative Assessment of Risers Riser system SALM Technical and financial aspects 1. Weather sensitivity 2. Water depth sensitivity 3. Number of flowlines in the riser 4. Number and spacing of wells in the well cluster 5. Operational versatility of the support vessel 6. Rig/riser interface tensioning 7. Riser handling in the moonpool area 8. Emergency connect/ disconnect 9. Location op. and serv. of choke manifold 10. Wireline and major workover 11. Technical downtime 12. Repair and maintenance 13. Risk of damage from dropped objects

Rigid risers A

B

C

D

Flexible risers E

F

G

H

I

J


50

14. Removal at end of field life 15. Capital investment 16. Installation and removal costs 17. Operation and maintenance costs Note: The larger the circle, the more attractive the feature

D. A single string rigid riser. E. A rigid ribbon riser. F. Catenary flexible single well risers. G. Catenary flexible riser with comingled flow. H. Balmoral field design riser. I. Mobil flexible design riser. J. Catenary flexible riser with subsea tower. The headings 1–17 have been chosen to represent the attributes normally associated with riser systems. Headings 1 and 2 relate to the sensitivity to the environment, 3–5 technical suitability, 6–14 technical aspects and 15–17 economic aspects. Rigid riser systems have been used exclusively in the North Sea because of their cost and the fact that the location of all the chokes on the surface vessels gives easy access for all operational requirements. The Balmoral field will be the first deviation from the use of rigid risers in the North Sea and should yield significant operational data about flexible risers in severe environments. The assessment shows that, taken overall, flexible risers would seem to be preferable to rigid solutions. Certainly in relation to marginal fields, where satellite wells will be a feature of the production system, the use of flexible risers may become standard. However, the disadvantages of having control equipment located subsea have so far restricted the use of flexibles. 2.3 SUBSEA EQUIPMENT Introduction The oil industry has always believed in the use of tried and true technology when designing field developments. One of the cornerstones of oilfield production system design philosophy has been the requirement to put as much production equipment as possible ‘in the dry’. This philosophy is well founded in good design practice with such factors as access, safety, environmental protection and easy operational maintenance being cited as reasons for this dry equipment requirement. The giant North Sea platforms, whose function is to house all the equipment associated with production operations, are a testament to the enduring nature of the ‘all in the dry’ design philosophy. The industry took its first step into subsea production equipment in the 1950 s when an ordinary land production tree was installed a few feet underwater. Since then major


51

advances have taken place in subsea equipment development and several subsea production systems are in existence or under test which will greatly extend the range of application of this technology. As with offshore loading systems, which are examined in detail in Section 2.5, subsea production equipment has become a feature of marginal field development schemes. There are four basic elements in a subsea production system, i.e. template, wells, manifold and control system. The specific configurations of these elements are defined by the reservoir characteristics and the other components of the development scheme, particularly the riser. 2.3.1 Subsea Template A subsea template is simply a large tubular steel structure designed to accommodate a number of wellhead assemblies and christmas trees for wells which may be either production wells or injection wells. The purpose of the template is to provide a base through which the subsea wells are drilled; it also spaces and aligns wellhead equipment (Fig. 2.11). Templates may be either of unitised or modular construction. A unitised template is generally used when six or more wells have to be drilled; the template is fabricated from large tubular members and incorporates a receptacle for each well and a three or four point levelling system. Drilling equipment guidance is achieved through the use of integral guide posts or retrievable guide structures. The unitised template is normally used where the number of wells

FIG. 2.11. 21 Well subsea template. required has been fixed and/or several slots can be left empty for future use. Templates are usually fabricated at a dockside facility and are normally of ‘passive’ or non-buoyant construction (Fig. 2.11).


52

The modular template system consists of a template structure made up of several interlocking modules, and is used where greater flexibility in the drilling programme is required. The template is normally piled to the sea bed. Before piling begins the template must be levelled. Once the template has been levelled and piled the well drilling programme may proceed. Wells which are drilled through a template are called cluster wells. 2.3.2 The Wells The first general classification of wells, wellhead equipment and christmas trees is whether they are subsea or surface. For the purpose of this section we will consider only subsea configurations. The second general classification is more or less self explanatory: subsea wells can be clustered or satellite. Clustered wells are generally drilled through a template while satellite wells can be offset by anything up to 8 km from the point at which the crude is processed. The third general classification is between wet and dry subsea wells. Wet wells are those in which the christmas tree and associated equipment is open to the marine environment while dry subsea wells are normally encased in a habitat which is at atmospheric pressure. The fourth and final classification refers to the method of intervention in the well in order to carry out various maintenance operations. Wells may be worked over (or maintained) by wireline, i.e. direct intervention from the production support or a service vessel, or by through-flow-line (TFL) methods, i.e. various tools are pumped into the well via the production support and the riser system to carry out maintenance operations. (TFL methods will be examined in detail in a later section.) The wellhead assembly and christmas tree consist of a structure housing the valves and controls necessary to monitor and control well fluid flow. The choice between cluster or satellite wells or indeed a combination of the two is usually dictated by the reservoir characteristics. The first requirement of any development plan is that it ensures the most efficient depletion of the reservoir. Cluster wells are normally deviated wells drilled through a subsea template which may, or may not, be located directly below the production support. If the field cannot be drained by a cluster system then a wholly satellite or cluster/satellite combination must be used. A limitation with satellite wells is the requirement that the reservoir should be sufficiently pressured in order to ensure flow between the tree and the production support. This requirement limits the distance a satellite well may be situated from the production support. It is unlikely that a cluster system would be capable of efficiently draining a shallow reservoir.


53

FIG. 2.12. Subsea wellheads. Four different types of subsea completion trees are shown in Fig. 2.12. The wet/nonTFL tree which was used on the Castellon field is suitable for use in shallow water and requires diver assistance for installation and maintenance. Both the dry and wet/TFL trees are suitable for use in an environment where weather vulnerability makes wireline operations uncertain. The latest development in subsea wellheads is the ‘insert tree’ concept developed by Shell International Petroleum in cooperation with Cameron Iron Works. The normal subsea tree can stand as much as 10 m above the sea bed which makes it vulnerable to external damage from trawler boards etc. The insert tree concept is an attempt to lower substantially the profile of the tree by putting as much of the tree equipment as is possible downhole. The tree currently stands at 4.3 m above the sea bed and is covered by a hemispherical cap which further reduces the likelihood of damage. The tree incorporates TFL as its maintenance system. A test tree has already been installed in Brunei and is operating satisfactorily. 2.3.3 The Subsea Manifold The subsea manifold is the interface between the subsea production equipment and the production riser system. The manifold acts as the subsea point at which production/injection flowlines and transport/export pipelines are gathered. The manifold or riser base may be a part of the well template. The manifold is a tubular steel structure which is rigidly fixed by piles to the sea bed; it is designed for a specific application and cannot easily be adapted to other development configurations.


54

Because they are integrally linked there is a trade-off between riser and manifold design. If the riser is required to be simple the manifold must be designed to comingle the flows of the various production wells or disperse the flow of the various production wells and/or disperse the flow to a series of injection wells. The more complex the manifold design the more controls will be required. Conversely if the riser system is designed to incorporate individual well risers this substantially reduces the complexity of the manifold. The design of the riser system and the manifold are thus inextricably linked. Other factors which influence manifold design are the nature of the product (oil/gas/condensate), the number and location of the wells, the maximum allowable pressure drop, the maximum flowrate required, the maintenance system employed (TFL or non-TFL) and the need for pipeline pigging/scraping from the floating unit. Manifolds, like christmas trees, can be either wet or dry. In the wet configuration the manifold is open to the marine environment while in the dry configuration the manifold is located in a chamber, the interior of which is maintained at atmospheric pressure. The manifold incorporates a further function which is of great importance. The riser base is usually located on the manifold and is surmounted by an assembly which permits the remote disconnection or connection of a number of lines. This element of the manifold is extremely important for marginal field systems employing floating production supports and has been the subject of considerable study in the past five years. 2.3.4 The Garoupa Subsea Production System Garoupa, which is located 260 km east north-east of Rio de Janeiro, is the world’s largest subsea production system using equipment installed in dry, atmospheric chambers located on the sea bed at water depths ranging from 118 to 165 m. The system is currently producing some 23200 b/d of oil (Fig. 2.13). The system consists of two major components, the wellhead cellar (WHC), a dry 1atmosphere pressure chamber which houses the production tree and control equipment, and a dry 1-atmosphere manifold centre. The Garoupa wells were drilled and completed by a conventional semi-submersible. The wells were completed in such a way as to leave them live. After setting the downhole safety valve and locking the tubing plugs the BOP stack was removed and the wellhead cellar was keelhauled to place it in position beneath the drilling slot of the semisub. The WHC was then picked up by the drillpipe and lowered to the ocean floor where it was mated with the conductor pipe, using the same profile as the BOP stack. The WHC was made fast by actuating the hydraulic connector.


55

FIG. 2.13. Garoupa. The various disassembled parts of the production tree, valves, crossovers etc. are stowed within the WHC awaiting installation and commissioning. The upper part of the WHC is fitted with a vertical cylinder, called a teacup, which contains a recall buoy and cable spool to permit later access through the service capsule. The upper rim of the teacup serves as a mating flange. The WHC is also fitted with two bullnose ports for flowline pull in and connection. Once the WHC installation is complete the semi-submersible may move to another location and continue its drilling programme. Commissioning of the WHCs was completed by crews who accessed the WHC by means of the service capsule. The manifold centre is cylindrical in cross-section: 5 m diameter and 24 m long. It contains a 12 in. header for comingling flows from all wells, chokes for individual well control, a 4 in. header for testing individual wells, and a pigging system. Provision has been made for future gas lift operations. The manifold centre sits on a 400 ton base which is equipped with a variable ballasting system to control buoyancy during tow out and installation. Access to the manifold centre is by means of the same teacup arrangement as used in the WHCs. The Garoupa field subsea production system has been in operation since 1979 and has helped establish the concept of subsea production. The technological step taken in this


56

project, i.e. removing production equipment from a dry surface environment to a dry subsea environment, was logical and correct. The operation of the system has been carefully monitored by Petrobras and figures presented show that the manifold centre has been available for production 98% of the time. Down time for the WHCs has varied from unit to unit with an average time on production of 96%. These figures would seem to indicate that the subsea production system was not a limiting factor in field down time. 2.3.5 The Grondin Experimental Station The Grondin subsea experimental station was installed by Elf Aquitaine during 1976/77 in 61 m of water 1500 m north-east of the fixed platform complex on the Grondin field operated by Elf Gabon. The station was designed and installed in order to test techniques which would be required in a deep water subsea production system. Although designed to be diverless and operated and maintained remotely the station was located well within diving range and its operation could be carefully monitored. The subsea station included three subsea wells situated on a template with the necessary manifolding and flowlines. Operations were conducted from the barge Anguille. The most interesting aspect of this development was the robot manipulator which was developed by the Matra Company specifically for this project. The manipulator is mounted on rails which surround the template structure and can be located to carry out maintenance tasks on any well. The subsea station was used to test the overall diverless subsea production concept as well as carrying out an extensive test programme on individual components such as the manipulator system, the hydraulic power unit, umbilicals, electrical and hydraulic connectors, guidelines and safety valves. Although some problems were encountered in the test programme, particularly with the initial remote manipulator system, the Grondin subsea production project marked an important technological step in establishing the subsea production concept and in demonstrating the suitability of the various elements for subsea operation. 2.3.6 The Exxon Submerged Production System (SPS) The Exxon submerged production system (SPS) was, along with the Grondin test station described above, an important technological step in proving subsea technology. In common with the Grondin system the SPS was designed to operate in deep water but is just as applicable to marginal field situations. The SPS was constructed by Exxon and installed in 52 m of water in the West Delta Block 73 field off the Louisana coast. The Exxon concept consists of a large buoyant template which is used to accommodate a preassembled and tested production manifold and a pump/separator unit. After installation of the structure directional wells were drilled through slots in the template and the christmas trees were connected to the preinstalled manifold. The remotely controlled manifold is designed to gather production, to distribute pumpdown tools, to control secondary recovery operations by distributing gas, lift gas and injected fluids, and to permit maintenance and pigging of the manifold


57

equipment. The pump/separator maintains a low pressure in the production header by separating the produced liquids from the gas and by pumping the liquids to the surface. The well fluids are transmitted to a production support vessel via an articulated production riser which was initially located some distance from the manifold. Maintenance of the Exxon SPS is carried out by a remotely controlled manipulator which is lowered from a surface service vessel when required. A series of tests were carried out to establish the operating qualities of the various components and the system as a whole. The tests succeeded in establishing subsea production technology and led to many design improvements in various items of equipment. 2.3.7 The Frigg North East Subsea Development The Frigg North East subsea development is a natural extension and utilisation of the technology developed by Elf Aquitaine on their Grondin test station. The heart of the Frigg N.E.development is a subsea template which weighs 350 tons, is 30 m long, 17 m wide and 8 m high. The template has provisions for six deviated wells and a manifold. Since Frigg is a gas field the subsea system is extremely sensitive to leakages, and therefore novel gas detection devices, using underwater sonar to detect changes in water density, have been installed. The subsea production system was diver installed but has been designed to operate without diver intervention throughout its five year design life. Divers will be used to make periodic inspections. However, since every element of the system is removable, repair and maintenance will be carried out by removing the faulty module and repairing it on the surface. The template was installed and has been in position on the sea bed since June 1981. The six production wells were drilled in 1982 and production began in November 1983. 2.3.8 The Central Cormorant Underwater Manifold Centre The Central Cormorant underwater manifold centre (UMC) is an extension of the technology developed by Exxon on its SPS programme. The UMC is similar in appearance to the SPS but offers additional features such as being able to serve either wells drilled directly through the template, or remote satellite wells tied-in to the manifold using flowlines and spool-pieces. The UMC can accommodate up to nine wells and provides four functions: —a template through which wells are drilled and satellite wells tied in, —a fluid collection and delivery system, —a sea water distribution centre for injection into the reservoir, —a subsea equipment maintenance system. The UMC is installed in 152 m of water, weighs 2200 tonnes, is 52 m long by 42 m wide and 15 m high. The UMC utilises a remote maintenance vehicle (RMV) to carry out maintenance without the need for divers.


58

This development constitutes the current state of the art in subsea production systems since it includes all the elements, e.g. production, delivery, control, maintenance and reservoir pressure maintenance, associated with offshore operations. The structure was installed in May 1982, drilling began in October 1982, and production started in mid1983. The operational experience with the UMC should establish the viability of subsea manifold systems. 2.3.9 The Skuld Concept The Skuld project is an extension of the Elf technology tested in Grondin and utilised in Frigg N.E. The objectives of the Skuld project are: —to demonstrate the feasibility of installing and maintaining a subsea production station from the surface without using divers; —to investigate the possibility of controlling the station from an installation 30 km away; —to demonstrate the subsea system’s reliability over a long period. The subsea station consists of a template with wells drilled through slots and con0nected to a manifold; it will be installed at a depth of 10 m near the Norwegian Underwater Technology Centre (NUTEC) at Gravdal. The test period is one year, which will be used to simulate a 20 year life. The main technological advance to be tested will be in the area of control. The subsea station is controlled by an operator, who by means of a computer sends coded messages to the station through an under-water cable. These messages activate the hydraulic pressure system, to open and close valves. Operations are monitored on a computer screen and there is two-way communication between operator and station. The project began in mid-1984 and terminated in mid-1985. 2.3.10 The Poseidon Concept All the subsea production systems considered to date involve the need for a production support nearby or, in the case of Skuld, 30 km distant. The Poseidon concept takes subsea production further by considering the possibility of operating subsea production stations at distances of up to 200 km from the point where the crude is processed. The Poseidon concept is presently under study by Total and IFP, and involves the use of booster stations along the export pipeline in order to flow the wellhead products to the nearest landfall. The desirability of such a system, eliminating as it does the costly production support, is evident. One of the major problems associated with this concept is that of dealing with twophase flow operations. However, IFP have been researching into two-phase flow for seven vears and have built a sophisticated test facility at Boussins in the South of France. One of the results of this programme has been the development of two-phase flow pumping equipment which will be incorporated in the Poseidon booster station design. The Poseidon research programme is currently underway and, if successful, would constitute a substantial advancement in subsea production technology. The proposed system consists of the following elements:


59

—Satellite or cluster wells, fitted with subsea wellheads. If down-hole pumping is required the new two-phase pump will be used. —Flowlines linking the wells to a central station; in the case of satellite wells flowlines will be doubled to permit pigging. —A central subsea station performing the following functions: *connection of flowlines and isolation of wells with cut-off valves; *gathering of the production; *expedition to shore of the two-phase flow by means of the newly developed pumps; *control of pipeline pigging and inhibitor injection at the wellhead; *connection of the pipeline to the station. —A multiphasic pipeline. —A remote control system, comprising a coast/station link-up. —Electricity supply system for the subsea station. The entire system is of modular design and maintenance will be carried out by a surface service vessel capable of retrieving modules. The advantages of the system are: —lower investment, —greater versatility, because of modular design, —greater safety, —lower processing costs. 2.3.11 Subsea Control System Subsea production systems present unique problems in the area of wellhead and manifold control system design. There are two basic methods for controlling wellhead equipment—hydraulic and electrical control. Hydraulic control systems, including direct, piloted and sequenced hydraulic, have the advantage that they are the simplest, most reliable and lowest cost type of control system depending, as they do, on the flow of hydraulic fluid to actuate the command. However, a significant disadvantage of hydraulic control systems for oil and gas operations is the slow response time, i.e. the time between the command being given and the action being carried out. The response time is a function of the distance to be travelled by the fluid. Therefore, in the case of subsea wells being controlled from a production support up to 8 km away these response times tend to be unacceptable for what may be emergency operations. Also, hydraulic control bundles tend to be bulky items and should be avoided if possible. Electrical control has the advantage of very short response times but has proven unreliable in practice. Because of the inherent weakness in each control method a hybrid system has been devised which utilises the strengths of each individual method. The electro-hydraulic multiplexed controls normally used for subsea operations involve the signal from the support to the subsea equipment being transmitted electrically, a control pod situated on the subsea equipment converts the incoming electrical signal into a hydraulic signal, and the hydraulic signal actions the command. In this way response time over a totally hydraulic system is substantially improved and the reliability of the


60

hydraulic system is utilised where it is needed most, i.e. subsea. Control pods are normally designed and installed for easy removal if repairs are required. Disadvantages include high cost, complexity, increased maintenance and limited experience. 2.3.12 Subsea Equipment Repair and Maintenance Each subsea production system must be designed with repair and maintenance considerations very much to the fore. The ‘all in the dry’ design mentality of the oil industry can be undoubtedly attributed to repair and maintenance considerations. It is only logical, therefore, that the first steps in subsea technology were taken in water depths where manned intervention was possible. As water depths increased designers began to look at ways of making manned intervention possible or unnecessary. This leads to the first categorisation of maintenance systems: those in a dry habitat such as in the Garoupa field development; tasks performed by divers (under saturation or in atmospheric diving suits); and those systems maintained by remote manipulators where subsea units are constructed modularly, and modules can be retrieved for maintenance without affecting the continuing operation of the subsea unit. The dry habitat system is the equivalent of surface repair and maintenance. Personnel are usually transferred to the 1 atmosphere habitat from a special submersible service unit. This is the system employed for the Garoupa field described earlier. Consequently the service vessel must always be available and represents a significant operational cost. The most developed method of effecting repair and maintenance of subsea equipment is the use of divers, either under saturation or in atmospheric diving suits. This type of system is depth limited and requires divers on standby. There is a considerable problem associated with this limitation, i.e. the evacuation of divers enclosed in pressure chambers from a production support. Anticipating a move to very deep water where manned intervention will be impossible, the oil industry has expended no little effort in developing remotely controlled repair and maintenance methods. The two most advanced subsea production systems, the Central Cormorant UMC and Skuld, both use the remote control method. The UMC is maintained by a remote maintenance vehicle (RMV) designed to change out the electric/hydraulic control units and critical manifold valves; the RMV also carries out visual inspections. The RMV is carried to location by a special service vessel, is winched down to the UMC and latches itself onto the railway track which runs through the centre of the manifold. The RMV then propels itself along the track until it is opposite the module which needs to be replaced. Control of and power supply to the RMV are through electrical umbilicals running back to the surface vessel. All operations are monitored by TV camera, using underwater lighting. Remote maintenance systems and remote operated vehicles (ROV) seem to be the future requirement for subsea production systems, and experience gained from the operation of the UMC RMV and the Skuld project should lead to the establishment of this technology.


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2.3.13 Intervention in the Wells There are two basic methods of intervention in wells—wireline and through flowline (TFL). The operations to be carried out include, but are not limited to: the servicing of safety systems, setting and retrieving of plugs, running down-hole pressure and temperature surveys, wax cutting and caliper surveys to monitor corrosion. Operation by wireline requires the production support for wells drilled directly beneath it and a service vessel for satellite wells or cluster wells remote from the support. The method of intervention involves the necessary tools being lowered on the end of a wireline through a workover riser from a surface vessel. This is the normal method of intervention from fixed structures. Where satellite developments form part of the field production scheme, a service vessel is required to carry out wireline operations. In order to eliminate the need for a service vessel the through flowline (TFL) system of down-hole intervention has been developed. In the TFL system the service tool, i.e. the tool which will carry out the specific down-hole operation, is latched to a carrier tool. The carrier is then pumped down the hole to the desired location. The service tool carries out the operation which is required, the pneumatic flow path is reversed and the service tool with its associated carrier string is pumped back to the surface. The TFL system was designed and developed as a consequence of the proliferation of underwater completed wells. Use of TFL requires some design changes in the production wellhead. The tool string starts at the platform in a vertical position, but since satellite wells are some distance from the production support the tool changes little by little from the vertical to the horizontal by means of a gradual bend in the riser service line. At the wellhead the requirement is for the tool string to enter the well vertically, and therefore the string must go from the horizontal to the vertical. The 90° shift is accomplished by putting a long loop in the flowline at the wellhead. The loop must be large enough to accommodate the tool string as it passes through and gives the characteristic shape to the TFL tree. TFL technology has become generally accepted and has reached a high level of sophistication. For example, satellite wells tied-in to a manifold can be serviced selectively by means of a diverter tool located at the manifold. The diverter allows the service personnel to select the well they wish to service and diverts the tool string at the manifold into the flowline of that particular well. 2.3.14 Technical Progress in Subsea Equipment The use of subsea components in offshore field developments can now be considered as established technology. Many fields worldwide incorporate satellite wells (whether wet or dry) and a greater level of confidence is available for systems employing subsea templates and manifolds. TFL techniques, although not widely used to date, have been accepted as a viable method for down-hole intervention. One of the major problems associated with the viability of subsea production systems is the lack of understanding of the two-phase flow mechanism. This lack of understanding has thus far limited the distance of satellite wells to approximately 18 km from the point at which the crude is processed.


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TABLE 2.5 List of Fields Employing Subsea Production Technology Satellite

Completions Satellite to subsea or riser

Completions manifold

Template and long life systems

Beryl

(4)

Argyll

(8)

Cormorant Central

Casablanca

(2)

Buchan

(7)

Grondin

(2)

Claymore

(3)

Castellon

(1)

Frigg N.E.

(6)

Dorado

(2)

Cormorant Emilio

(1)

Espoir

(5)

Lavinia

(1)

Nilde

(1)

Magnus

(7)

Tazerka

Murchison

(3)

N.Hewitt

(2)

Ninian

(1)

Tartan

(6)

Total

30 trees

Total

Total

(9+)

17 trees

(6/8) 30 trees

Source: The Oilman, March 1983.

Two major research programmes, one in France and one in Norway, are underway with a view to gaining a better picture of the two-phase flow mechanism. The empirical information obtained by these programmes has led to the development of computer programs which can predict two-phase flow patterns. This type of information is necessary for two-phase flow pipeline design. The French research programme has led to the development of a pump capable of handling two-phase flows. The use of a two-phase flow pump would permit the possibility of production from satellite wells or fields far distant from the point of crude oil processing. A major problem area for subsea production systems is undoubtedly associated with the control and repair and maintenance functions. Research programmes are currently underway to improve wellhead control systems, particularly by employing more accurate transducers. Skuld and other subsea test stations can be used to establish repair and maintenance procedures, and will inevitably lead to improvements in equipment design. Marginal field developments, especially those small fields associated with larger finds, will make substantial use of subsea production technology. The development plans accepted for the Texaco Highlander field and Hamilton’s Duncan field shows industry and government acceptance of subsea technological advances. The research and field


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testing stage of this technology is coming to a close and the experience with the existing producing systems should form the cornerstone of the future designs. The Poseidon concept opens up new and exciting horizons for subsea production and will lead to a further refinement of technology. 2.4 STORAGE Introduction Crude oil storage in relation to marginal field developments invariably means offshore storage. In other sections, particularly those on production supports and loading systems, most of the components used for offshore storage are examined. Offshore storage is normally required because there is inevitably a question of down time (time during which a system is not operational) associated with offshore loading concepts. The normal method of crude evacuation is by shuttle tankers which may be loaded directly from a loading system or via a storage vessel. If no storage is provided and adverse weather prevents shuttle tanker loading, the platform supervisory personnel have no option but to shut down field production. The field reservoir characteristics are not always consistent with this stop-start type of production so some element of buffer storage must be considered. The exception to this rule has been Argyll field which has been subject to this stop-start production rhythm but has suffered no damage as a result. Several aspects of crude oil evacuation must be examined before a suitable buffer storage system is selected. Among the factors to be considered are: —storm occurrence interval and persistancy, —throughput of oil, —distance of the field from port of discharge, —speed of the shuttle tanker, —number and capacity of the shuttle tanker(s), —efficiency of discharge port equipment, —loading system maintenance down time (hoses, hawser, etc.). The environmental factors will, of course, have a bearing on the type of storage structure selected but the factors listed above govern the quantity of storage required. Four basic structures suitable for offshore storage include: —tanker, —barge, —articulated column, —spar. 2.4.1 Tanker Based Storage Systems Tanker based storage systems are the most popular method of providing buffer storage for marginal fields. The reason for this popularity has been the easy availability of all sizes of tankers since the mid-1970 s overbuild situation. However, while the tanker,


64

because of its geometry, is eminently suitable as a means of buffer storage, there is a considerable amount of conversion work required to turn an ocean going tanker into a stationary storage vessel. For instance the Fako, a 90 000 dwt. storage tanker on the Kole field, off Cameroon, required the following conversion jobs: —mooring system design and installation on site, —hull reinforcement for anchorlines, —chain tensioning machine installation, —installation of mooring fenders and mooring bollards, —transformation of boilers for gas burning direct from the field, —cargo crude oil transfer control and safety systems including dewatering by wash tanks, —electric power generation including the fitting of an extra turbo alternator and diesel alternator, —electrical supply by submerged cable to the platform, — the provision of hydraulic hose handling cranes and utility winches, —store and spare parts handling system on deck, —inert gas system, —PLEM (pipeline end manifold), —hoses between PLEM and storage tanker, —crude oil metering system, —provision of a helideck, — modification to crew accommodation, —cathodic protection, —the provision of additional fire protection. The technology of tanker storage has advanced considerably during the past fifteen years and experience has shown that loading down time has been exclusively associated with tanker loading equipment and weather rather than the vessels themselves. Tanker storage is suitable for most environmental conditions with systems installed in the North Sea, South East Asia, West Africa, the Mediterranean, South America and offshore California. 2.4.2 Barge Based Storage Systems The barge is perhaps the simplest floating geometric shape consisting, in its most basic configuration, of a hollow steel box. Barges as production supports were already examined in Section 2.1. Barge storage has not been used extensively, principally because of the availability of tankers of all sizes. The systems employed to date have incorporated a small amount of storage, approximately 10000 bbls. This has been a function of the factors mentioned above rather than a limitation of barge technology itself. The Arco Ardjana IIAPCO Cinta, a specially built barge with 1000000 bbls storage, has been in service since 1972 offshore Indonesia. 2.4.3 Articulated Column Storage Systems


65

Articulated columns have already been considered as production supports and will later be extensively examined as loading systems. The storage capacity of the articulated column is a byproduct of the column’s geometry. The articulated column can have a very substantial (depending on the design) underwater tubular structure which has both buoyancy and stability functions. This structure, which can be considered as hollow, can be arranged into a series of storage compartments which can be used for buffer storage if tanker loading is interrupted. The Maureen Articulated Loading Column, which is examined in detail later, is a steel concrete hybrid structure 148 m high with a column outside diameter of 10 m. The column has been designed to incorporate a buffer store of 650000bbis. 2.4.4 SPAR Storage Systems The SPAR concept is based on the use of a large buoy structure, with a substantial underwater element, for offshore loading. The SPAR concept in general and the Brent SPAR in particular are examined in detail in the section on loading systems. The Brent SPAR is designed to store 300000 bbls of oil in six segmented tanks. 2.4.5 Conclusions Offshore storage capacity is generally sought in those circumstances where loading system down time can lead to production shut-in. The various concepts on offer are based on well proven technology and can easily be adapted to whatever loading system has been selected. Several loading system designs, particularly SPAR type structures, have the inherent capability to act as buffer storage. When used simply as buffer storage, all the systems examined above have proven operationally successful and have in no way been a limiting factor in the overall production system’s performance. 2.5 OFFSHORE LOADING SYSTEMS Introduction A notable feature of all marginal field and early production systems is the use of an offshore loading facility for crude oil export. Unless the marginal field is close to shore or in the vicinity of an existing pipeline system with spare capacity, offshore loading constitutes the optimum solution, both in terms of technology and cost. Offshore loading technology has been developed from the use in the 1960 s of buoys for crude oil transfer from tankers to refinery tank storage. The development of this technology was necessitated by the inability of very large crude carriers (VLCCs) to dock at existing port facilities due to draft limitations. The extension of the technology to encompass the offshore loading of crude oil was developed in order to eliminate the requirement for sea-bed pipelines and booster stations and thereby reduce investment costs.


66

One of the major drawbacks of a mooring buoy loading system is its sensitivity to environmental conditions. During storms or high sea state conditions, tankers are unable to moor safely and therefore production must be suspended, sometimes for extended periods, until the weather improves sufficiently to resume operations. A solution to this problem is to provide crude oil storage capacity, generally in the form of a permanently moored tanker, so that production stoppages are eliminated. The technology has, therefore, evolved on two fronts. First, the development of ‘mooring’ buoy technology and, second, the adaptation of the buoy technology to the provision of some level of buffer storage. There are four basic configurations of offshore loading systems with variations applicable to specific development criteria. The following is a list of the systems including, where possible, a specific field application. (a) Catenary anchor leg mooring (CALM)—Buchan field, derivatives include: —exposed location single buoy mooring (ELSBM)—Auk field, —SPA—Brent field, —single buoy storage (SBS)—Ashtart, Tunisia, —turret moored tanker. (b) Single anchor leg mooring (SALM)—Thistle field, derivatives include: —single anchor leg storage (SALS)—Castellon and Tazerka. (c) Articulated loading column (ALC)—Maureen and Beryl. (d) Fixed tower—Cayo Arcas. 2.5.1 Offshore Loading System Design Considerations There are five major factors to be taken into account in the design of an offshore loading system: (a) environmental conditions, (b) reservoir and crude characteristics, (c) maintenance/operational continuity, (d) forces exerted by the selected transport, (e) storage requirements. Environmental conditions fall into two general categories, water depth and weather conditions. Water depth can act as a limiting factor in the choice of feasible loading systems; for example the SBS is usually limited to a water depth of 150 m because of inherent problems posed by the catenary chain anchoring subsystem. The loading system must be capable of surviving the 100 year storm conditions as well as meeting minimum wave height operational criteria. Reservoir and crude characteristics translate themselves into three design parameters, i.e. throughput, type of products and operational pressures. The rate of production has an obvious effect on system design, particularly the sizing of the export lines. Because offshore loading systems are usually used in the case of


67

marginal field or early production, product lines are normally in the range of 8 in. to 12 in. The swivel associated with the loading system must be designed to accommodate the fluids and withstand their pressures. The transferred fluids may consist of processed crude, live crude oil and gas directly from the well, natural gas for fuel, hydraulic fluids for valve control, treated associated water and liquid petroleum gas (LPG). The swivel must also be designed to handle the various pressures associated with the fluids being transported. These pressures may vary from 225–275 psi for processed crudes to much higher pressures for live crude and hydraulic lines (1200–2000 psi). Most of the offshore loading systems are designed for 100% occupancy, that is they must be available continuously for fluid transfer. The overall design of the system must reflect this criterion. In addition, routine and preventative maintenance procedures, excluding hoses and hawsers, must be designed for execution with the tanker on the mooring. Once the export or storage tanker has been selected the forces it will exert on the loading system can be calculated and the system designed to accommodate those loads. 2.5.2 Catenary Anchor Leg Mooring (CALM) A CALM loading system consists of a circular mooring buoy secured by a series of catenary anchor chain legs terminating at fixed anchor points on the sea bed. Flexible floating hoses connect the underside of the buoy to a pipeline end manifold (PLEM) on the sea bed and the buoy to the tanker manifold respectively. Tankers are moored to the buoy via a hawser arrangement which attaches to the buoy mooring arm (Figs. 2.14 and 2.15). This concept has been in existence for over 25 years and some 260 installations have been made worldwide, although not all the installations are located in an offshore environment. Table 2.6 indicates the main characteristics of some CALM systems. The advantages of the CALM system are: —Multiple fluid streams can be transferred while the moored vessel rotates around the buoy in response to sea and weather conditions (‘weathervane’). —Mooring forces are minimised as the tanker assumes a position of least resistance to the environmental forces (wind, wave and currents).


FIG. 2.14. CALM.

FIG. 2.15. Rigid yoke CALM.

68


69

TABLE 2.6 Main Characteristics of some CALM Terminals Terminal

Location

Water depth (m)

Tanker size (dwt.)

Flow rate (m3/hour)

Oil piping size (in.)

Buoy diameter (m)

Rospo Mare Adriatic Sea (Italy)

22

35000

50 1×12

9

Abu al Bukhoosh

Persian Gulf (Abu Dhabi)

28

230000

530 2×10

12

Panama (2 buoys)

Chiriqui Lagoon (Panama)

23

Up to 150000

9500 2×20

11

Victoria

Gulf of Guinea

57

50 to 280000

5000 2×20

12

Pampo

Campos Basin (Brazil)

125

50000

250 1×8

13

Source: EMH.

—The system is flexible. —Tankers can be moored and released rapidly. —The buoy is reusable after the field has been depleted. —Swivel is located on the buoy for easy dry access. Some disadvantages are: —Mooring can only take place in relatively benign conditions making the export system the limiting factor for production. —Accidents have occurred during mild weather when the tanker has drifted onto the buoy and led to damage of the floating hoses. The Buchan CALM Buoy Because of the marginal nature of the field, the Buchan development discounted the use of a dedicated pipeline as an export system for the field. Several offshore loading systems were considered before a decision was taken to install a CALM system in 112 m of water. Based on the environmental data and the requirement that the terminal should survive a 50 year storm, model tests showed that the buoy would have to be 15 m in diameter by 4.6 m deep moored by six anchor chains, each about 407 m in length. The novelties associated with this particular CALM include: —The entire crude flow system is designed to handle efficiently the passage of a 12 in. pig. This capability is necessary because of the high wax content of Buchan crude


70

which posed the threat of wax build up should the flow be curtailed and the crude allowed to cool. —Two tankers are dedicated to the field minimising the risk of production shut-down. —The hook-up and departure procedure is designed so that no assistance from small craft is required. —A self aligning quick hose connector is being used to attach and detach the floating hose from the buoy’s pipearm. This system greatly simplifies installation and maintenance by limiting the need for divers and calm sea conditions. —The buoy’s deck equipment includes a chain jack for retensioning any of the buoy’s six anchor chains. With this equipment, the anchor chains can be retensioned to the appropriate catenary shape while avoiding the need for crane barges and other costly installation equipment (see Chapter 5). 2.5.3 Exposed Location Single Buoy Mooring (ELSBM) An ELSBM is a direct extension of CALM technology to more environmentally severe locations. The mooring systems of the two configurations is the same with the ELSBM being conventionally moored by a series of chains. However, because larger motions are experienced at the exposed location, the submerged section of the buoy is substantially increased. The buoy is normally unmanned but is large enough to include some level of emergency accommodation. The Auk ELSBM The Auk ELSBM is located in 84 m of water 2 km from the Auk platform. It is moored to the sea bed by 8 anchors each weighing 15 tons and which are set around the buoy in a circle with a 460 m radius. The system is very much like that described for the CALM with the exception of the buoy structure which can be divided into a sub- and superstructure. The substructure consists of three separate sections tapering from a diameter of 22 m at the top, through a mid-section of 12 m diameter to a bottom section of 8.6 m diameter. The total draught of the structure is 52 m. The water plane area is of fender type construction in order to protect the structure from impact damage. The central shaft of the substructure is 130 cm in diameter and is normally filled with water. The annular space around this shaft permits access through the various decks to the base of the structure by means of ladders and hatches. The buoyancy, ballast and trim tanks are arranged around this annular space. The total underwater weight of the substructure varies from 9.5 to 13.5 tons depending on the level of water ballast. The total displacement of the structure is 3950 tonnes. The superstructure is connected to the substructure via the turntable section. Apart from the space structure which carries the helicopter deck (suitable for Sikorski S-61), the superstructure also includes the mooring trunk hose reels and cable drum for the loading hoses, the reel for the mooring hawser, the emergency and control cabin, the generator room, air compressor and diesel storage. The maximum operational criteria for a tanker moored to the Auk ELSBM are:


71

Wind speed:

25 m/s

Significant wave height:

4.5 m

Main wave period:

9.0 s

The Auk ELSBM was installed in 1975.

FIG. 2.16. SPAR concept. 2.5.4 SPAR The SPAR concept has been developed and utilised exclusively by Shell. SPAR is another adaptation of CALM technology incorporating some of the features of the ELSBM with the ability to store crude oil. However, the structure as a whole is considerably larger than any loading buoy. The storage concept requires that the main storage tanks are kept full of either crude oil or sea water or a combination of both (Fig. 2.16). The Brent SPAR The SPAR concept was originally designed to handle crude from the Brent ‘A’ Platform with a maximum throughput design capacity of 100000 BOPD using the SPAR storage or 250000 BOPD direct through-put from the platform. The SPAR sits in 140 m of water


72

and is located 2.9 km from Brent ‘A’. The structure can be divided into two sections, the substructure and the superstructure. The substructure is 29.1 m in diameter and 93 m high and is divided into 18 tanks, six storage tanks and twelve buoyancy tanks. It floats below the water surface at a design draught of 109 m. The draught of the structure is controlled during all loading operations so that structural stability is maintained. The substructure is surmounted by a column which connects the underwater storage vessel with the superstructure. The column is 17 m in diameter and 32 m high and protrudes above the surface. A free floating central shaft of 3.4 m diameter extends from the superstructure to the base of the substructure. The superstructure is 26 m in diameter and 12 m high. It contains four decks and supports a turntable with cargo crane, loading swivel, helicopter platform and mooring arrangements. The superstructure also includes accommodation for 30 people, 12 normal crew with additional space for personnel required for diving operations or major overhauls. Processed crude is received continuously from the nearby platforms and is transferred to the SPAR unit from a pipeline end manifold located directly below the structure. The structure is held in. position by six anchor chains and wires terminating at six 1000 tonne concrete gravity anchor blocks. The SPAR is kept at constant draught by keeping the storage tanks filled. If crude is not available for filling the tanks sea water is used. Loading from the Brent SPAR is usually suspended when sea states exceed 8 m and wind speed 40 knots. The Brent SPAR was installed in June 1976. 2.5.5 Single Buoy Storage (SBS) The SBS concept is similar to the CALM except that the tanker is moored permanently to the buoy by means of a yoke or rigid arm (Fig. 2.17). There are several advantages of using this system instead of a conventional CALM system: —The use of a yoke or rigid arm permits the replacement of floating hoses by hard piping. —The hawsers, which are major maintenance items, are eliminated. —Routine maintenance of system components such as the swivel and bearing is made easier by provision of a walkway along the yoke. —Because there is a rigid connection between the buoy and the tanker, out-of-phase motions due to environmental loading are reduced. —The yoke decreases the degree of freedom of the tanker which improves its behaviour. SBS installations made to date have been in the Mediterranean, the Philippines, South East Asia, West Africa, the Middle East and Brazil.


73

FIG. 2.17. Single buoy storage (SBS). 2.5.6 Turret Moored Tanker The turret moored tanker concept is relatively recent and no systems have yet been built. The concept is an extension of the SBS concept and involves the connection of the mooring system directly to the bow of the tanker (Fig. 2.18). The mooring structure consists of a riser tower and a yoke collar which is below the surface and is directly connected to the bow extension, protrudes above the surface and is connected to the bow of the tanker. The production manifold, subsea production control system and the manifold control system are located at the top of the riser tower safely out of the splash zone. The mooring chains are supported by a chain table which is anchored conventionally to the sea bed by a spread chain system. The structure itself requires no buoyancy since it is an integral part of the tanker. A contract has been awarded for the world’s first turret moored tanker. It


74

FIG. 2.18. Turret moored tanker. will be used in conjunction with the 140000 dwt. tanker based floating production system on the Jabiru field in 120 m water depth in the South Timor Sea. 2.5.7 Single Anchor Leg Mooring (SALM) The single anchor leg mooring, or SALM, was developed initially to extend the operational depth of CALMs. There are two SALM configurations. The first uses a single chain anchor leg and fluid transfer is accomplished from a subsea product distribution unit. The second configuration uses a single tubular riser and fluid transfer is accomplished from a production distribution unit at the top of the tubular riser. Combinations of the basic configurations are possible. There are seven basic elements in the SALM unit—a mooring hawser, a floating buoy, a swivel and U-joint which connects the buoy to the chain or riser element, a riser chain or single tubular riser, product hoses, a product distribution unit and a mooring base. The dynamic behaviour of the SALM differs markedly from that of the CALM. The SALM behaves as an inverted pendulum and the required restoring force is provided by the buoyancy of the buoy body as the mooring forces displace the terminal laterally from the vertical. In


75

FIG. 2.19. SALM concept. contrast, the restoring forces in a conventional CALM are functions of the weight and spacing of the catenary draped anchor chains supported above the sea bed by the displaced buoy body. As with all mooring buoy designs the buoy in the SALM incorporates a 360° swivel in the horizontal plane which allows the loading vessel to weathervane so as to take up the position of least resistance to the combined forces of wind, waves and current (Fig. 2.19). The advantages of the SALM system are: —It is applicable to a wide range of water depths. —Because a gravity or piled base is used to locate the riser/mooring system a wide range of soil conditions are acceptable. —The major elements of the system can be reused. —Mooring forces are minimised as the tanker weathervanes about the buoy. The main disadvantage is that the product swivel is generally located underwater, and hence divers are required for maintenance and repair. The Fulmar SALM Three alternative export options were evaluated for the Fulmar field in the North Sea. They were: direct field loading of tanker; construction of new pipeline to shore; and tie into an existing line. The latter two options were rejected due to cost and lack of spare capacity respectively. A loading feasibility study showed that a SALM was the ideal solution for holding the required 210000 dwt. tanker on station in the 14.4 m significant wave height. The environmental design criteria were the following: Significant wave height

14.4 m


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Maximum wave height

26.8 m

Dominant wave period

16.4 s

1-minute mean wind

43.9 m/s

1-hour mean wind

37.5 m/s

Surface current velocity

2.6 knots

The primary components of the Fulmar SALM are the buoy, rigid arm, product swivel, base and the mechanical articulations which connect them. The anchor leg of the Fulmar SALM is a rigid buoy connected to the base by an articulated joint and connected at the top directly to the rigid arm through a triaxial universal joint and mooring swivel. The buoy weighs 1829 tonnes and the outside diameter ranges from 8 m at the lower end to 15.9 m at the maximum diameter down to 5.5 m at the top. The buoy is sub-divided into 18 compartments to provide damage stability and a 3 m diameter central column provides access to the various compartments for inspection and maintenance. The rigid arm is a box truss triangular structure. The arm weighs 800 tonnes and measures 61 m in length and is 30.5 m at the hinged connection to the tanker. The arm carries all the rigid fluid lines necessary to carry out fluid transfer. The base is of gravity/piled design and consists of a steel hexagonal structure with a pile located at each corner. The piles were driven to a depth of 29 m and were then grouted to the pile sleeves in order to resist the environmentally imposed loads. The universal joint which weighs 360 tonnes connects lugs on the bottom of the buoy to those on the base structure via two 1560 mm diameter by 7.9 m long tubular pins and a coupler sleeve assembly. The Fulmar SALM stands in 82 m of water and is capable of handling approximately 180000 b/d of crude oil and loading tankers at a rate of 40000 b/h. The structure was installed in May 1981. 2.5.8 Single Anchor Leg Storage (SALS) The single anchor leg storage system or SALS is a variation of the SALM described above. The system is based upon a single vertical riser between the sea bed anchor point and the storage/production vessel mooring yoke. The yoke incorporates a submerged buoyancy tank or tanks for maintaining a permanent tension force to the riser regardless of sea state or loading conditions. As in the case of the SALM the articulated single chain riser (or single tubular riser) is connected by means of universal joints at both the top and the bottom ends (Fig. 2.20).


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FIG. 2.20. SALS concept. A swivel at the top of the upper universal joint allows 360° rotation for weathervaning of the production/storage vessel. The main difference between the SALM and SALS systems is the use of a mooring yoke in the former and a mooring hawser in the latter. The length of the mooring yoke is determined from the behavioural characteristics of the storage vessel in various loading conditions during the most severe sea states anticipated. The geometry of the yoke, in turn, determines the forces acting upon the structure and its points of attachment. The Castellon SALS One of the first applications of the SALS concept was the development of the Castellon field offshore Spain. The development utilised a tanker as a production support and the process system included water separation, degassing and gas disposal. The design criteria were the following: Location:

Western Mediterranean off the coast of Spain

Water depth:

117 m

Well data:

20000 b/d of sour crude oil with a gas/oil ratio of 100 scf/bbl and a pressure of 1000 psi

Storage capacity:

350000 bbls

Survival conditions: (100 year storm)

Significant wave height

8.5 m

Current

25 knots

Wind (1 hour mean)

66 knots


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The system consists of the following elements: (a) Anchor base—the anchor base is a welded box structure with a steel weight of about 80 tons and dimensions of 10×8×2.5 m. Four 60 m long, 75 cm diameter piles pin the structure at its corners with the lower universal joint being located at the centre. Ballast material was added to the base in order that the combined weight of the base, piles and lower universal joint counterbalanced the 400 ton pretension in the riser induced by the buoyancy tank incorporated in the mooring yoke. (b) Universal joints—the universal joints were of conventional design and weighed approximately 35 tons. (c) Anchor leg—the anchor leg is made up of forged steel links, 6 m long and 22 cm in diameter. End links are aligned alternately at 90° and joined by 30 cm diameter steel pins. The weight of the anchor leg is about 1 ton/m. The anchor leg has a dual role: it transmits the mooring force to the piled base and acts as a tensioned support for the riser and hydraulic control lines. (d) Mooring yoke—the yoke is a rigid box truss triangular structure composed of welded tubular steel members. The yoke also has a dual function, first to provide a stable mooring platform for the loading vessel and, second, to provide a support structure for the submerged buoyancy tank. This 18 m long by 8 m diameter buoyancy tank is divided by watertight bulkheads into three chambers each of which is equipped with bilge, sounding and purging pipework. The overall length of the mooring yoke from hinges to turntable centre is about 50 m. Load out weight of the mooring yoke including the buoyancy tank was about 500 tons. (e) Crude flow path—flexible 4 in. dia. jumper hose spans the lower universal joint and is attached by standoffs up the length of the anchor leg to the upper universal joint. The fluid then passes through the internal passages of the universal joint pin joints, and then through the main fluid swivel to hardline pipework along the rigid mooring yoke. The Castellon SALS system was designed for a 20 year service life and preventative maintenance activities are restricted to cleaning, inspection for damage and corrosion and lubrication of the mooring and fluid product swivel assemblies. The system has been operational since 1977. 2.5.9 Articulated Loading Column (ALC) An articulated column is a single vertical structure which is connected to its anchoring base by means of an articulated joint. Free rotation around the bottom universal joint horizontal axes ensures the compliance of the structure with environmental forces while buoyancy in the upper portion of the column provides the necessary restoring force (Fig. 2.21). Table 2.7 shows the characteristics of some North Sea ALCs. The concept consists of the following elements: —The base, which is located on the sea bed and acts as an anchor for the column; the base design is a function of the size of column and the sea bed soil conditions. —The cardan joint, which is situated on top of the base and permits the column to oscillate, i.e. to follow the movements of wind, wave and currents instead of resisting them.


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—The principal buoyancy section, which is submerged and stabilises the structure.

FIG. 2.21. Articulated loading column. TABLE 2.7 North Sea Articulated Loading Columns Name and site

Owner

Delivery year

Water depth (total height) (m)

Beryl ‘A’

Mobil

1975

117 147

30.5 MWH 15 s Wind 65 m/s

80 000 dwt.

Statfjord ‘A’

Mobil

1978

145 182

30 MWH 15 s

100 000 dwt.

Beryl ‘B’

Mobil

1982

118 170

30.2 MWH 15 s

90 000 dwt.

Maureen

Phillips

1982

105 140

30 MWH

Gullfaks ‘1’

Statoil

1985

140

31 MWH

Gullfaks ‘2’ Source: EMH.

1986

Design conditions

Tanker size

150 000 dwt.


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—The marine compartment which is a tubular section connecting the buoyancy chamber with the superstructure. This section is in communication with the surface of the water and is designed to reduce the wave action forces on the structure and in consequence the articulation. —The superstructure, containing the various pieces of equipment necessary to assure the various functions of the column, particularly a helipad to allow column maintenance. The columns may be fabricated in steel or concrete or a combination of the two. The Maureen Articulated Loading Column The Maureen ALC, which is made principally from concrete, is the first permanently buoyant concrete structure in the North Sea. The column is designed to operate in all but the most severe weather conditions; the design is based on a 20 year operational life and the ALC is capable of loading 85000 dwt. tankers at a rate of 20000 b/h. Tankers may remain moored and loading in wind speeds of up to 50 knots with significant wave heights of 6 m and maximum wave heights of 11 m. The Maureen ALC is unmanned with all mooring and loading operations being controlled from the tanker. The gravity base is H shaped in plan, measuring 29 m by 36 m, with two buoyancy tanks, necessary to provide neutral buoyancy during installation, each 9.2 m in diameter and 27.7 m long. The base weighs 4168 tonnes. The universal joint weighs 65 tonnes and incorporates duplicate 24 in. flow paths which provide continuity between the base crude oil circuits and the risers fixed to the exterior of the column. The column weighs a total of 3232 tonnes (3078 tonnes of concrete and 154 tonnes of steel) and measures 91.25 m long, 9.2 m in diameter with a wall thickness of 31 cm. At 8.2 m above sea level the column is topped by a 12.3 m steel chimney 5.6 m in diameter which supports the rotating head. The rotating head weighs some 242 tonnes. Sufficient stand-off distance between the column and the tanker is achieved by cantilevering the loading hose on a fixed boom projecting 36 m from the centre of the column. The mooring hawser is 112.5 m long with a 200 tonnes breaking load capacity. The Maureen ALC was installed in 100 m of water in August 1982, after a 600 mile tow from the construction site at Loch Kishorn. 2.5.10 Yoked Tower The yoked tower is a direct derivation of the ALC. There is little change in the column architecture except for a rigid yoke articulated at both ends which replaces the flexible hawser, thus eliminating the need for an oil loading boom. 2.5.11 Catenary Anchored Tower (CAT) The catenary anchored tower (CAT) is a further adaptation of the ALC technology. When water depth conditions are such that the concept of an articulated column stabilised by a buoyancy tank is not applicable (water depths below 80 m), the column may be stabilised by chain legs anchored to the sea bed.


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The tanker is moored to the articulated column through a rigid yoke or a hawser depending on the environmental conditions at the site. The CAT concept is applicable to water depths ranging from 40 to 80 m in severe environmental conditions. 2.5.12 Fixed Tower The fixed tower is a permanently located structure with a gravity or piled base on which is located the transfer equipment already described, i.e. the rotating head, the boom with loading hoses and the mooring hawser.

FIG. 2.22. Fixed tower. While the concept is not based directly on articulated column technology, the structure itself may be architecturally similar to a column but is firmly fixed to the site. The fixed tower requires some form of fendering to absorb tanker contact (Fig. 2.22). The system substantially reduces the relative motion between the loading terminal and the tanker; however, there are limitations in terms of abandonment, initial cost, and site conditions, i.e. water depth and wave height.


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The Cayo Arcas Fixed Tower The Cayo Arcas fixed tower was installed in 1982 in 41 m water depth in the Gulf of Campeche by Pemex. The tower is designed to load 285000 dwt. tankers which are moored by hawser. The structure consists of a central column supported by a piled base structure. The rotating head sits on the central shaft and supports a boom and loading hoses. One of the features of the fixed tower is the use of a large ‘bicycle

TABLE 2.8 Factors Affecting Choice of Offshore Loading System Storage

Environmental conditions

Water depth (m)

Loading system

−50 Fixed system Benign

50–150 CALM 100+ ALC −50 Fixed tower

No

50–150 ELSBM Severe

70–175 SALM 100–200 ALC

−25 Fixed tower 50–150 SBS Benign

40–80 CAT 80–200 SALS/SPAR

Yes

−50 Fixed tower 40–80 CAT Severe

50–200 SPAR/SALS 80–200 ALC

wheel’ fender. This type of fender is necessary because of the possibility of collision between the fixed tower and the tanker. Since the tower is a permanently located structure, it is much more vulnerable to collision than moored or articulated structures.


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2.6 PROCESSING FACILITIES The processing facilities for an offshore development can vary from a simple separation and disposal system to a highly complex processing plant utilising miles of interconnecting pipework and dozens of processing vessels.

FIG. 2.23. Block diagram of possible systems on an offshore production platform. Figure 2.23 shows some possible combinations of process plant which may be required offshore. The following list of systems is not exhaustive and by no means would every development use them all. The possibilities include, but are not limited to: —gathering system, —separation system, —oil treatment and disposal system, —gas treatment and disposal system, —water treatment and disposal system, —safety systems, —utility systems. 2.6.1 Gathering System (Manifolding) The total production of reservoir fluids from the various wells must be combined prior to passing through the treatment facilities. The various flowlines from the individual wells are manifolded into one or more large diameter pipes, called production headers. Each production header then carries all or part of the total production to one of the separation trains, which are the first of the separation systems. Each well must be tested periodically which involves diverting the flow to a testing system. Therefore each well is also


84

connected to a test header. If the field involves wells which flow at different pressures, a few wells may have insufficient pressure to flow into the first stage of separation. In this case a low pressure header is provided for these wells, which bypasses the first or high pressure separator and flows directly to a separator operating at a lower pressure. As explained in Section 2.3, manifolding may take place at the sea bed or at the surface, on the production support. Manifolding on the sea bed has the advantage of simplifying the riser configuration and the associated high pressure swivel arrangements. Manifolding on the surface, on the other hand, has the advantage of having all the associated valves and pipework easily accessible and eliminating the considerable expense associated with diver and ROV systems normally required for subsea systems. The topside weight associated with manifolding on the surface is a significant item for submersible based production systems. The current trend is towards subsea manifolding. This is being facilitated by the continuing development of ROVs which can undertake all the routine maintenance and inspection work. 2.6.2 Separation System Each well produces oil, gas and water in varying proportions and one of the primary functions of a production system is to separate the well fluids into their individual phases. The principal of separation lies in the fact that oil, water and gas have differing densities; gas is lightest, and water is heaviest. Process separators must be modified to minimise the effects of vessel roll and pitch on their operation. This is achieved by the installation of baffles at the oil/gas interface in horizontal separators to reduce the effect of sloshing and by the use of curved weirs which have a profile that ensures their flow characteristics are unchanged for all expected angles of roll. In the case of the Cadlao process facilities, the separators were designed to operate satisfactorily with a roll of 15° (half amplitude). In practice roll motions of 10° have been experienced without shutdown. In harsh environments roll motions tend to be less significant than in milder environments—thus roll motions should not pose any insurmountable problems for floating separators. Research has also been carried out on the effect of vessel motions on the operation of vertical distillation columns. It appears that, while permanent inclination does adversely affect vessel efficiency, the random motions due to the sea should have only a minor effect if suitable modifications are made to the internal trays. 2.6.3 Gas Treatment and Disposal Associated gas is normally flared in floating production systems. However, gas on a floating production system may also have one or more of the following uses: —fuel gas for power generators, —re-injection gas for reservoir pressure maintenance, —sales gas if it can be piped to shore.


85

Even if associated gas is re-injected or used to some other purpose, a gas disposal system must be installed to handle the full volume in the event of a production upset. Flare booms, which are normally used on fixed platforms, are being used successfully on production semi-submersibles. The flare on the production platform on the Argyll field is mounted on top of the derrick. On the Castellon FPSO, water cooled incinerators are used to burn 2 mmscf/d gas. A ground flare installation is employed on the Cadlao FPSO to burn 6.5 mmscf/d gas. The designers claim that designs have been completed for similar ground flares having capacities up to 50 mmscf/d. For this quantity of throughput the stack would be 11 m diameter and 22 m high.

Chapter 3 Existing Marginal Field Technology INTRODUCTION In this section we will examine those systems which have already been used to exploit hydrocarbon deposits and which could have widespread applications to marginal field development. The list of developments includes fields which have permanent marginal field systems installed as well as those which have utilised some form of marginal field technology as an early production system. For example field developments in Brazil have incorporated some elements of early production but since the systems used have marginal field applications they have been reviewed for this section. Thirty-nine field developments worldwide have been reviewed: 7 utilise or utilised a jack-up as a production support, 19 a semi-submersible, 6 a monohull (barge or tanker) and a further 7 utilised technologies which are relevant to marginal fields. A data sheet and field development layout for each of the 39 fields reviewed appears later in this section. Before proceeding with a global examination of the fields already developed it is perhaps opportune to review criteria for marginal field development systems. In general such systems should incorporate all of the following features: —early production, —reduced capital investment, —maximum return on investment, —maximum flexibility for offshore development, —proven technology, —minimum abandonment costs, —method to test the reservoir, —method to produce marginally economic field. We now proceed to an examination of the fields reviewed using the above criteria. 3.1.1 Early Production The standard time required to develop a field conventionally is somewhere between three and seven years depending on the location and the type of production system chosen. The majority of the 39 fields reviewed show a significant improvement on these figures. However, some large discrepancies do occur, for example Badejo and Bicudo in the Campos Basin of Brazil began producing in the year in which they were discovered

TABLE 3.1

Existing marginal field technology

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Existing Fields Utilising Marginal Field Technology Date

Field

Location

Operator

Production support

1971

Ekofisk

North Sea

Phillips

Jack-up

1974

Bekapi

Borneo

Total

Barge

1975

Handil

Borneo

Total

Barge

1975

Argyll

North Sea

Hamilton

Semi-sub

1977

Castellon

Spain

Shell Espana

Tanker

1977

Enchova E.

Brazil

Petrobras

Semi-sub

1978

Dorado

Spain

Eniepsa

Semi-sub

1978

Saltpond

Ghana

Agri-Petco

Jack-up

1979

Enchova E.

Brazil

Petrobras

Semi-sub

1979

Garoupa N.

Brazil

Petrobras

Semi-sub

1979

Casablanca

Spain

Chevron

Semi-sub

1980

Nilde

Italy

Agip

Tanker

1980

Sul del Pampo

Brazil

Petrobras

Semi-sub

1980

Pampo

Brazil

Petrobras

Semi-sub

1981

Pampo Linguado

Brazil

Petrobras

Semi-sub

1981

Cadlao

Philippines

Amoco

Tanker

1981

Badejo

Brazil

Pétrobras

Jack-up

1981

Lavinia

Italy

Agip

—

1982

Bicudo

Brazil

Petrobras

Semi-sub

1982

Buchan

North Sea

BP

Semi-sub

1982

Garoupinha

Brazil

Petrobras

Semi-sub

1982

Bonito

Brazil

Petrobras

Semi-sub

1982

Tazerka

Tunisia

Shell

Tanker

1982

Parati

Brazil

Petrobras

Jack-up

1982

Espoir

Ivory Coast

Phillips

Jack-up

1982

Emilio

Italy

Agip

—

1983

Corvina

Brazil

Petrobras

Semi-sub

1983

Pirauna

Brazil

Petrobras

Semi-sub

1983

Central Cormorant

North Sea

Shell

UMC


88

1984

Saleh

UAE

Gulf

Jack-up

1984

Hutton

North Sea

Conoco

TLP

1984

NE Frigg

North Sea

Elf Norge

Articulating

1984

RJS-236

Brazil

Petrobras

Semi-sub

1984

RJS-150

Brazil

Petrobras

Jack-up

1984

Parati

Brazil

Petrobras

Semi-sub

1985

RJS-90

Brazil

Petrobras

Semi-sub

1985

Scapa

North Sea

Occidental

UMC

1985

Highlander

North Sea

Texaco

UMC

1986

Balmoral

North Sea

Sun Oil

Semi-sub

while the Hutton field, which incorporated novel tension leg platform technology, was discovered as early as 1973 but only began producing in 1984. Generally it is true to say that where no novel technology is involved and where the operator has gained some experience of early production systems the time to first oil can be greatly reduced. The Brazilian experience is worth examining. The first field in Brazil produced using early production technology was Garoupa North which, although discovered in 1974, was not produced until 1979. Some improvement with respect to time was experienced with the Pampo field which took three years from discovery to first oil. This experience has led to the remarkable situation where fields discovered in Brazil after 1980 have been brought on-stream in the year of their discovery. There are two factors which greatly influence the ability of systems based on conventional supports, e.g. jack-up, semi-sub and monohull, to produce early oil. They are (a) the ability to pre-drill development wells, and (b) the availability, at short notice, of production supports. In most of the cases examined several, if not all, of the production wells were drilled prior to the arrival of the production support. Where drilling had not been completed, satellite wells were added to the system as necessary. The very short times to first oil being achieved in Brazil can in large measure be attributed to the practice of Petrobras of completing exploration wells as producers. The importance of the availability of a suitable production support to early production cannot be overstated. This is a major factor in the performance of Petrobras. An examination of the data for each field shows that as supports are decommissioned from one field they are swiftly employed in the production system of another field. Since few companies find themselves having a series of fields coming on-stream sequentially, as does Petrobras, they must address two problems. First, the procurement or lease of a support which has generally up to then been involved only in drilling, and second, the conversion of that support for production operations. At best this operation can take up one to two years and at worst considerably longer. The experience of BP on Buchan shows the perils involved with converting a drilling support to a production support. The semi-submersible Pentagone design drilling rig, Drillmaster, was selected for conversion to the production platform. Work began on the conversion at the Olsen Group’s Lewis offshore yard in Stornoway, Lewis in October 1978. For various reasons the conversion proved to be more complex and involved more


89

extensive rebuilding than had been anticipated. Statutory regulations had changed since Drillmaster had been built and extensive modifications were required. The Pentagone design made such changes difficult and in some cases involved cutting through decks and bulkheads. All these factors increased costs and caused delays. Although the modifications had been scheduled to take 11 months, Buchan Alpha was not towed out to the field until September 1980, a year later than anticipated. Therefore, while on average the 32 fields using conventional supports improved time to first oil, the availability of suitable supports and a degree of experience are prerequisites to successful operations. 3.1.2 Reduced Capital Investment Some 32 of the 39 field developments reviewed utilised an existing drilling support or tanker converted for production operations. Savings were thus made on front end engineering as well as the purchase or lease of the second hand production support. Another area of significant saving is marine operations, i.e. installation and hook-up which are substantially shorter for a marginal field production system than for a development involving a fixed platform. However, the most significant impact on capital investment occurs when the support and/or the production equipment is leased. While leasing is not an option for fixed platform developments, jack-ups, semi-subs and tankers are freely available for long-term leasing. This considerably reduces the amount of capital investment made by the operator. 3.1.3 Maximum Return on Investment There are two factors associated with the systems reviewed which would seem to conform to this criterion. First, the time to first oil is reduced and, second, there is a lease option for supports and production facilities. An economic analysis of marginal field developments carried out showed that time to first oil is one of the most significant parameters in offshore marginal field developments. A one year improvement in time to first oil in the North Sea can improve the rate of return by up to 8% for a 60000 b/d field and 5% for a 30000 b/d field. The option to lease short-term both production support and facilities provides the operator with the opportunity to pay a significant proportion of his costs of field development from his oil revenues as they accrue. This factor greatly improves the profitability of the venture and leads to a maximisation of return on investment. 3.1.4 Maximum Flexibility for Offshore Operations The field developments reviewed demonstrate the flexibility of the various components for marginal field operations. There are of course constraints on jack-ups in terms of water depth and payload, although payload should not be a limiting factor in the case of small fields. In general the production supports are floating and are therefore substantially more flexible than fixed installations. Most types of vessel have been utilised:


90

—barges (Handil, Bekapi), —jack-ups (Ekofisk, Saltpond, Badego etc.), —semi-subs (Hamilton, Enchova, Dorado etc.), —tankers (Castellon, Nilde, Cadlao etc.). The riser systems have included —tubular (Argyll, Buchan, Nilde etc.), —flexible (Castellon), —arced flexibles (Cadlao), —articulated column (Garoupa). Export is rarely by pipeline but normally via a storage tanker and a shuttle system. The loading systems utilise tankers (a) catenary moored, (b) associated with a single anchor leg mooring, (c) associated with a catenary anchor leg mooring, (d) associated with an articulated column, (e) loading in tandem, and (f) loading side-by-side. Wellheads can be dry or wet, drilled through templates or satellites. In fact the systems reviewed run the complete spectrum of the technologies envisaged for marginal field development. The flexibility of the technologies is demonstrated again via the Brazilian experience where totally different systems have been utilised to develop fields in the same basin. 3.1.5 Proven Technology Because of the inherent problems associated with the profitability of marginal fields, all areas of uncertainty must be clarified before the development begins. This is particularly true of technology selection. Each individual marginal field development is unique and may have some particular aspect of technology which is quite unique or novel, but an effort is usually made to utilise or adapt technologies already proven in larger field developments. With respect to the 39 fields reviewed, 32 may be said to have used proven technology in that each individual component of the system had been proven technology before the start of the development. However, the engineering maxim that the sum of the parts is sometimes less than the whole generally holds. Field development schemes must be viewed as integrated systems and not just as a series of components put together. Therefore, although one tries to maximise the level of proven technology in any development there is always the possibility of encountering probems of technological fit. Having said this, it is, however, apparent that the field operators do in fact opt for tried and true technology when developing marginal schemes. Marginal and early production systems have been in operation since 1971 and since then a large amount of experience has been gained. That experience is evident in the number of fields presently under consideration for development, and in the speed with which recently discovered fields have been brought on stream. 3.1.6 Minimum Abandonment Costs


91

Since there are few if any fixed installations associated with marginal field developments the abandonment costs tend to be minimised. In general production supports are floating and anchored, crude export is via tanker and not pipeline. Therefore the only fixed installations are the subsea wellheads which can be abandoned. Many oil company economists tend to ignore abandonment costs since in most cases they appear only after 20 years of field life and have therefore a negligible effect on the discounted cash flow of the project. However, abandonment costs are real and substantial and any development system which reduces them reflects positively on project profitability. 3.1.7 Method to Test the Reservoir We have already discussed one of the areas of uncertainty in marginal field development under point 3.1.5 on Proven Technology. A second area of uncertainty in marginal fields is reservoir performance. The economics of marginal fields are usually so finely balanced that changes in basic economic conditions such as capital expenditure, operating costs, production levels and recoverable reserves can have a major effect on the profitability of the venture. Capital expenditure and operating costs are defined by technological selection whereas production levels and recoverable reserve estimates are sometimes derived on the scantiest of information. If a field is marginal because of the uncertainty over the level of reserves, a period of production will give additional reservoir information and will reduce uncertainty thereby leading to improved decision making. For example the Enchova field in Brazil was developed in three phases. Two phases were early production schemes which not only produced a revenue stream, but also provided additional reservoir data which led to an improved development plan for the field. To date, 50 m barrels has been considered as the minimum recoverable reserve to justify a field development. If the distribution in the Table 1.1 is accurate, the cumulative effect of the production of the fields with reserves of less than 50 m barrels could in theory equal that of the production of all the fields in the 200–500 m barrel range. The possibility of a significant resource has been established and many would argue that 32 successful developments and 7 developments of real technological innovation should be sufficient to establish the validity of the technology. The Buchan field with an ultimate recoverable reserve of 50 m barrels is set to produce an internal rate of return of 15.7% which is higher than Maureen, Alwyn North, Clyde, Hutton, Magnus and Brae among recent developments. When one considers the problems encountered by BP, particularly the one year delay, the economics of a semisubmersible based production system should be apparent. However, technological selection is not the only ingredient in making marginal fields economic. The fiscal system in operation in any specific country can have a significantly greater impact on the profitability of marginal fields than technology alone. 3.1.8 Conclusion


92

The 39 developments reviewed for this section show that marginal field technology has been in existence since 1971 and has been steadily evolving since that time. The 32 developments utilising some form of conventional production support have established the technological viability of producing marginal fields while the remaining 7 developments have taken a first step in demonstrating the technologies which may be used to develop marginal fields in the future. Marginal fields will form an important segment of the petroleum resources of the future whether they are located in existing oil provinces or in new areas. The technology has now evolved to the stage where proven systems do exist which may be adapted for use in most circumstances. The field data sheets show the wide range of reservoirs which have to be produced while the environments have varied from the relatively benign regions of Brazil and Ghana to the harsh environment of the North Sea. 3.2. JACK-UP SYSTEMS Date:

1971–1974

Field:

Ekofisk

Location:

North Sea Norwegian sector, block 2/4, 300 km SW of Stavanger

Operator:

Phillips Petroleum

Environmental conditions:

Water depth—70 m

Reservoir characteristics:

Crude gravity—36° API, sulphur 0.21 wt%, gas/oil ratio 1 547 sef/bbl, reservoir pressure 7135 psi @ 10 489 ft, res. temperature 131°C.

No. of wells:

4

Well completion:

Wet, satellite, subsea

Well recovery: Production rate:

42 000 b/d

Production support:

Jack-up

Support data:

Gulf Tide

Riser type:

1.6 m dia. caisson containing

in. flowlines and 2×10 in. export lines

Riser data: Export details:

Crude was exported via two CALM buoys

Remarks:

This system has been replaced since 1974 by a permanent production system comprising five steel platforms and one concrete storage tank


93

FIG. 3.1. Ekofisk early production. Date:

1978

Field:

Saltpond

Location:

Offshore Ghana, 50 km west of Accra

Operator:

Agri-Petco


Water depth—30 m, prevailing winds are south-westerly between force 4 and 12


Crude gravity—39° API, sulphur 0.99 wt%

No. of wells: Well completion

6 wells drilled, only 4 producers Dry, surface


1 200 b/d (1983)

Production support:

Jack-up

Support data:

Mister Louis


94

Riser type: Riser data: Export details:

The crude is loaded via an export line to a conventionally moored storage tanker (capacity 420 000 bbls)

Remarks:

The production level of this field is very low; however, the quality of the crude and the government policy towards exploitation has made production possible; Agri-Petco have been searching for sometime for a joint venture partner in order to implement phase II of the development which incorporates some gas injection

FIG. 3.2. Saltpond. Date:

1981

Field:

Badejo

Location:

Campos basin, 60 km from the coast

Operator:

Petrobras



Water depth—94 m


Crude gravity—32 API (Avg.), porosity 10–15%

No. of wells:

4

Well completion:

2 dry, 2 wet satellites

95


7 400 b/d

Production support:

Jack-up

Support data:

Penrod 62

Riser type:

4 rigid, 2 flexible


Crude offloading is via a CALM buoy and shuttle tanker, tanker size is approximately 53000 dwt

FIG. 3.3. Badejo early production system.


Date:

1982–1984

Field:

Parati

Location:

Offshore Brazil

Operator:

Petrobras


Water depth 94 m


Crude oil gravity—25–28° API, Gas/oil ratio 436 scf/bbl

No. of wells:

4

96

Well completion: 2 dry, 2 wet satellite Well recovery: Production rate:

7 000 b/d

Production support:

Jack-up

Support data:

Petrobras III

Riser type:

1 rigid, 3 flexible


Crude offtake is via a floating hose from the production jack-up directly to a conventionally moored 30 000 dwt shuttle tanker

Remarks:

This was an early production system


97

FIG. 3.4. Parati early production system. Date:

1982

Field:

Espoir

Location:

Offshore Ivory Coast

Operator:

Phillips Petroleum


Water depth—130 m


Net thickness of reservoir interval—90 m, crude oil gravity—29–33° API, gas/oil ratio varies from 350 to 1 800 scf/bbl

No. of wells:

4

Well completion:

Wet, satellites


10 000 b/d


98

Production support:

Jack-up

Support data:

Dan duke

Riser type:

Rigid, integral

Riser data:

12×3 in. flowlines 1×12 in. export line

Export details:

Crude is offloaded from a 12 in. export line into a 230 000 dwt. VLCC Phillips Enterprise via a catenary anchor leg rigid arm mooring (CALRAM); the buoy is pin-connected to the tanker during loading

Remarks:

FIG. 3.5 Espoir.


99

Date:

1984

Field:

Saleh

Location:

Offshore UAE, 26 miles from the coast

Operator:

Gulf Oil


Water depth—100 m


Gross thickness of reservoir interval—145.9 m, porosity—10.9–24.9%, 17.9% (Avg.), crude oil gravity 45.5° API, gas/liq. ratio 4 701 scf/bbl.

No. of wells:

3

Well completion:

Dry, wellhead platforms


5 000 b/d (early 1984)

Production support:

Jack-up

Support data:

Zapata Offshore’s Heron


Crude oil from the field moves through a 12 in., 21 mile pipeline to a permanently moored storage tanker, the 230 000 dwt. Afran Zodiac

Remarks:

This development constitutes an early production system for the field where the rhythm of production should increase from 5 000 b/d (Jan. 1984) to an anticipated 23 000–26 000 b/d (late 1984)


100

FIG. 3.6. Saleh field early production system. Date:

August, 1984

Field:

RJS—150

Location:

Offshore Brazil, Campos Basin

Operator:

Petrobras


Water depth—18 m

Reservoir

Crude oil gravity—37° API, gas/oil ratio—400 scf/bbl


101

characteristics: No. of wells:

1

Well completion:

Dry

Well recovery:

1 800 b/d

Production rate:

1 800 b/d

Production support:

Jack-up

Support data:

Petrobras III

Riser type:

1 Rigid


Oil via floating hose to permanently moored 30 000 dwt tanker.

Remarks:

Two wet satellite wells are planned. These wells will be connected to the support by means of flexible risers.

FIG. 3.7. RJS—150.


102

3.3 SEMI-SUBMERSIBLE SYSTEMS Date:

1975

Field:

Argyll

Location:

North Sea, block 30/24, longitude 3 E, latitude 56 N

Operator:

Hamilton


Water depth—80 m


Gas/oil ratio—160 scf/bbl, crude gravity—38° API, 0.2% sulphur, 6.0% wax

No. of wells:

4 plus 2 later

Well completion: Wet, subsea Well recovery: Production rate:

19000 b/d

Production support:

Semi-sub

Support data:

Transworld 58

Riser type:

Rigid non-integral

Riser data:

1×10 in. central, 4×4 in. production, 2×4 in. service

Export details:

Loading is by means of shuttle tanker moored to a catenary anchor leg mooring system (CALM)

Remarks:

Argyll was the first oil field to be produced by a floating production system; the initial system was intended to be temporary in order to gain reservoir information; however, the marginal nature of the field forced the operator to decide on a retention of the floating system.


103

FIG. 3.8. Argyll field layout. Date:

1979–1980

Field:

Enchova East, phase I

Location:

Brazil

Operator:

Petrobras


Water depth—100 m, current 3.5 knots


Crude gravity—23° API, sulphur—0.75 wt%, gas/oil ratio 477 scf/bbl, gross thickness of reservoir interval 42 m and 77 m

No. of wells:

1

Well completion:

One surface tree plus a subsea test tree and tubing string run inside a drilling riser and BOP to a deck tree

Well recovery:

—


Production rate:

6 300 b/d

Production support:

Semi-sub

Support data:

Penrod 72

Riser type:

Flexible and tubing string inside drilling riser and BOP

104


Offloading was accomplished by means of a 53 000 dwt. shuttle tanker conventionally anchored and fed by a floating hose

Remarks:

This phase of the development constituted an early production system on a marginal field in order to improve the field economics

FIG. 3.9. Enchova and Enchova Leste I.


105

Date:

1979–1983

Field:

Enchova East phase 2

Location:

Brazil

Operator:

Petrobras


Current 3.5 knots


0.75 wt%, gas/oil ratio 477 scf/bbl, gross thickness of reservoir interval 42 m and 77 m

No. of wells:

4

Well completion: Test plus 3 wet subsea satellites Well recovery:

—

Production rate:

14 100 b/d

Production support:

Semi-sub

Support data:

Penrod 72

Riser type:

1 tubing string inside the drilling riser plus 3 flexible bundles

Riser data:

2×4 in. flexible production lines, 3×2.5 in. flexible gas lift/kill lines, 1×8 in. flexible export line, 1×8 in. flexible production line

Export details:

Offloading of crude was accomplished through 53 000 dwt. shuttle tankers utilising a CALM buoy

Remarks:

The second phase of the development included the use of a second production support Penrod 72 connected to Sedco 135D by a flexible line; eventually Sedco 135D and its storage tanker were removed and the field was produced using Penrod 72 alone, production level in 1983 was 7 000 b/d


106

FIG. 3.10. Enchova Leste II. Date:

1977

Field:

Dorado

Location:

Offshore Spain, 20 km from Tarragona

Operator:

Eniepsa


Water depth—93 m, Hmax=16 m, T=12.5 s


Crude oil gravity 21° API, sulphur 0.6 wt%, gas/oil ratio—315 scf/bbl, gross thickness of reservoir interval—100 m

No. of wells:

3

Well completion: Wet, subsea with deck tree Well recovery: Production rate:

10 000 b/d

Production support:

Semi-sub

Support data:

Sedco 1

Riser type:

Rigid individual


107

Riser data:

3×4 in. production

Export details:

Evacuation was by a 4-point conventionally moored 33 000 dwt. tanker, connected to the semi-sub by a 4 in. dia. floating hose; a 6 in. pipeline has been installed

Remarks:

The development of this field took place in two phases—in phase 1 production was from one well only via a subsea test tree and tubing string run inside the drilling riser and BOP to the deck tree; in phase 2 two additional wells were drilled equipped with Regan subsea wellheads; only two wells are currently producing

FIG. 3.11. Dorado. Date:

1979

Field:

Garoupa North

Location:

Offshore Brazil

Operator:

Petrobras


108


Water depth—120 m


Net thickness of reservoir—110 m (Avg.), crude oil gravity 31°API, sulphur 0.14 wt%

No. of wells:

Initially 1 with 2 wells added later

Well completion:

Test plus 2 wet subsea satellites

Well recovery: Production rate: Production support:

Semi-sub

Support data:

Sedco 135D

Riser type:

Tubing string inside drilling riser plus 2 flexible bundles


Offloading via a shuttle tanker conventionally anchored and connected by flexible hoses to the production support

Remarks:

(See Fig. 2.13; now replaced by fixed platform)

FIG. 3.12. Garoupa North.


109

Date:

1979–1981

Field:

Casablanca

Location:


Operator:

Chevron


Water depth—120–130 m


Crude oil gravity—34° API, sulphur 0.2 wt%, gas/ oil ratio 65 scf/bbl, gross thickness of reservoir interval—200 m

No. of wells:

2

Well completion:

Wet, subsea


15 000 b/d

Production support: Semi-sub Support data:

Alfortunada

Riser type:

2 flexible bundles

Riser data:

1×6 in. flexible production line, 1×4 in. flexible production line, 4×1 in. flexible lines. 1×12 in. flexible export line

Export details:

The crude is delivered via an export pipeline

Remarks:

The field was developed in three phases—phase 1: early production using an Aker H3 as support; phase 2: described above; phase 3: a fixed production system


110

FIG. 3.13. Casablanca. Date:

1980

Field:

Sul del Pampo

Location:

Offshore Brazil

Operator:

Petrobras


Water depth—113 m


Net thickness of reservoir interval—28 m, crude oil gravity 31–31.5° API, high sulphur (2000 ppm), 6% CO2


No. of wells:

5

Well completion:

1 dry, 4 wet satellites

111


23 500 b/d


Sedco Staflo

Riser type:

1 rigid, 4 flexible


Crude offtake via a CALM buoy to 53 000 dwt. shuttle tankers

Remarks:

Although this system was for early production it encompassed many facilities associated with a full system, particularly the processing facilities

FIG. 3.14. Sul de Pampo early production system.


112

Date:

1980

Field:

Pampo

Location:

Offshore Brazil

Operator:

Petrobras’


Water depth—120 m


Gross thickness of reservoir interval—38 m and 210 m, porosity 21–27%, water saturation 21%, crude oil gravity—21° API

No. of wells:

1

Well completion:

Production via a subsea test tree and tubing string run inside a drilling riser and BOP to a deck tree


8 000 b/d


Sedco 135D

Riser type:

Tubing string inside drilling riser and BOP

Riser data: Remarks:

This system was temporary and Sedco 135D was transferred to Bicudo when the Pampo well was incorporated into the Linguado system; replaced by fixed platform

Date:

1981

Field:

Pampo Linguado

Location:

Offshore Brazil

Operator:

Petrobras


Water depth—110 m


Crude oil gravity—20–30° API

No. of wells:

4

Well completion:



20 000 b/d

Production support:

Semi-sub

Support data:

Transworld 61

Riser type:

1 tubing string inside the drilling riser and 3 flexible bundles


113


Crude export was via a floating hose to a conventionally moored 12 000 dwt. shuttle tanker

Remarks:

FIG. 3.15. Linguado early production system.


114

FIG. 3.16. Linguado early production system phase II. Date:

1982

Field:

Bicudo

Location:

Offshore Brazil

Operator:

Petrobras


Water depth—130 m


Gross thickness of reservoir interval—30 m (Avg.), porosity 25% (Avg.), crude oil gravity 23.5° API

No. of wells:

6

Well completion:

1 test plus 5 wet subsea satellites


20 000 b/d


115

Production support:

Semi-sub

Support data:

Sedco 135D

Riser type:

1 tubing inside drilling riser plus 4 flexible bundles

Riser data:

4×4 in. flexible production lines, 4×2 in. flexible gas lift/kill lines, 1×3 in. flexible export line

Export details:

The field development utilises two CALM buoys to load shuttle tankers

Remarks:

Bicudo has been developed using the same philosophy as Enchova—in fact the same production support, Sedco 135D, was used in each case

FIG. 3.17. Bicudo early production system. Date:

1982

Field:

Buchan

Location:

North Sea, 154 km ENE of Aberdeen

Operator:

British Petroleum


116




Extent 29 km, 411 m thickness, 7% porosity, 34.8° API gravity oil, gas/oil ratio 280 scf/bbl recoverable oil 50 m barrels, 56–60 m with gas lift

No. of wells:

8 consisting of 5 template wells and four satellite wells

Well completion:

Wet subsea provided by Sedco Hamilton Production Systems

Well recovery:

Gas lift installed

Production rate: 48 000 b/d Production support:

Semi-sub

Support data:

Pentagone type (Drillmaster)

Riser type:

Rigid non-integral

Riser data:

1×12 in. central, 8×4 in. production, 2×4 in. service, 8×2 in. gas lift

Export details:

Loading is via a CALM buoy which was designed by Press-Imodco Terminals Limited; the buoy measures 15 m in diameter with a draught of 2.7 m; it is anchored by six 105 mm chains, 400 m long; a hawser and a flexible floating hose from the buoy permits mooring and loading of the 60 000 dwt tankers, both of which are designed to swivel through 360° which allows the tanker to weathervane round the buoy

Remarks:

The gas lift risers will be installed integrally with the associated production riser.


117

FIG. 3.18. Buchan field layout. Date:

1982

Field:

Garoupinha

Location:

Offshore Brazil

Operator:

Petrobras


Water depth—113 m


Net thickness of reservoir interval—8 m, crude oil gravity—25–33° API, gas/oil ratio 4 739 scf/bbl

No. of wells:

3

Well completion:



6 000 b/d

Production support:

Semi-sub

Support data:

Sedco 135F

Riser type:

1 tubing string inside drilling riser plus 2 flexible bundles

Riser data:


Export details:

118

Crude is offloaded via a floating hose to conventionally moored 12 000 dwt. shuttle tankers

Remarks:

FIG. 3.19. Garoupinha early production system. Date:

1982

Field:

Bonito

Location:

Offshore Brazil

Operator:

Petrobras


Water depth—8 m


Crude gravity 27° API, gas/oil ratio 1 212 scf/bbl. net thickness of reservoir interval—28 m

No. of wells:

12

Well completion:

Wet, subsea, 7 template, 5 satellite


28 000 b/d

Production support:

Semi-sub


Support data:

Penrod 71

Riser type:

Flexible bundles

119


Crude offtake via a CALM buoy to 53 000 dwt. shuttle tankers

Remarks:

The associated gas is compressed to shore through the Enchova field fixed platform

FIG. 3.20. Bonito early production system. Date:

1983

Field:

Corvina

Location:

Petrobras


120


Water depth—226 m


Gross thickness of reservoir interval—30 m, net thickness of reservoir interval—21 m, crude oil gravity—27.8° API

No. of wells:

5

Well completion:

Wet, 4 satellites


16 000 b/d

Production support:

Semi-sub

Support data:

SS Petrobras IX

Riser type:

1 rigid, 4 flexible


Crude is offloaded via a CALM buoy to 53 000 dwt. shuttle tankers

Remarks:

This is a classic early production system for a field which has been on production since August 1983.


121

FIG. 3.21. Corvina early production system. Date:

1983

Field:

Pirauna

Location:

Offshore Brazil

Operator:

Petrobras


Water depth—243 m


Gross thickness of reservoir interval—35 m, net thickness of reservoir interval—20 m, porosity—30%, crude oil gravity—28° API, gas/oil ratio 315 scf/bbl

No. of wells:

5

Well completion:

Wet, satellites


122


22 000 b/d


SS Petrobras XV

Riser type:

5 flexible


Oil via CALM buoy, gas via pipeline

Remarks:

Early production system in operation since December 1983.

FIG. 3.22. Pirauna early production system.


123

Date:

June, 1984

Field:

RJS—236

Location:


Operator:

Petrobras


Water depth 99–111 m


Crude oil gravity 28/32° API, Gas oil ratio 737 scf/bbl

No. of wells:

3

Well completion:

2 wet


8 200 b/d

Production support:

Semi-sub

Support data:

Transworld 61

Riser type:

1 rigid, 2 flexible

Riser data: Export details: Remarks:

Oil export via CALM’s on Badejo and Linguado fields


124

FIG. 3.23. RJS-236 field layout. Date:

December, 1984

Field:

Parati RJS—194

Location:


Operator:

Petrobras




Crude oil gravity—28° API, gas/oil ratio—438 scf/bbl

No. of wells:

6

Well completion:

Wet


19400 b/d (estimated)

Production support:

Semi-submersible

Support data:

Neptune 7


Riser type:

125

1 rigid, 5 flexible


Oil via floating hose to permanently moored 30000 dwt tanker

Remarks:

This is the second phase of the Parati field development

FIG. 3.24. Parati RJS-194 field layout. Date:

December, 1984

Field:

RJS—90, Viola

Location:


Operator:

Petrobras




Crude oil gravity 24–27° API, gas/oil ratio, 227–300 scf/bbl

No. of wells:

5

Well completion:

Wet


126


12000 b/d (estimated)

Production support:

Semi-submersible

Support data:

Zephyr I

Riser type:

5 flexible


Oil via floating hose to permanently moored 30000 dwt tanker

Remarks:

FIG. 3.25 RJS-90 Viola field layout. Date:

1986

Field:

Balmoral

Location:

North Sea UK sector block 16/21A, 233 km north east of Scotland

Operator:

Sun Oil


127


Water depth—145 m


Net thickness of reservoir interval—144.7 m, porosity—18–29%, permeability 800 md (Avg.), crude oil gravity—39.3° API, sulphur 0.2 wt%, gas/oil ratio 230 scf/bbl (Avg.)

No. of wells:

13 producers, 6 injectors

Well completion:

Wet

Well recovery:

Six water injection wells to be drilled

Production rate:

35 000 b/d

Production support:

Semi-sub

Support data:

Gotaverken Arendal GVA 5000

Riser type:

Flexible

Riser data:

1×10 in. export, 2×6 in. water injection, 2×8 in. flowlines, 3×4 in. service lines

Export details:

Balmoral crude will be exported by pipeline, a 14 in. diameter export line into the main Brae/Forties line to shore

Remarks:

The Balmoral subsea template measures 100 ft square, is 33 ft high and weighs 840 tons; it has 14 well slots, and provision for 5 manifolds, 3 of which are being installed initially


FIG. 3.26. Balmoral field layout.

128


129

This page intentionally left blank. 3.4 MONOHULL BASED SYSTEMS Date:

1974

Field:

Bekapi

Location:

Offshore Borneo, 100 km to the north east of Balikpapan

Operator:

Total


Water depth—35 m


Net thickness of reservoir bearing interval—105 m, porosity—25–35%, permeability—1000 md (Avg.), water saturation—35%, crude oil gravity— 40.3° API, sulphur 0.08 wt%

No. of wells:

1

Well completion: Dry, located on wellhead platform Well recovery: Production rate: Production support:

Barge

Support data:

L39

Riser type:

Rigid integral

Riser data:

1×6 in.

Remarks:

The field was produced using a wellhead platform connected to the production barge L39 by a 4 in. flexible line; the crude was offloaded using two 1500 tonne shuttle barges, round trip loading, unloading and return was approximately 48 hours


130

FIG. 3.27. Bekapi early production system. Date:

1975

Field:

Handil

Location:

In the Mahakam delta, 70 km north east of Balikpapan

Operator:

Total




Porosity—38%, permeability—high, crude oil gravity 30.8° API, sulphur 0.09 wt%

No. of wells:

4

Well completion:

Dry, clustered


33 000 b/d

Production support:

Barge

Support data:

L50


131


Crude offtake via three 1500 tonne barges

Remarks:

In 1976 two supplementary wells were drilled and barge L39 (demobilised from Bekapi) was added as a second production support

Date:

1977

Field:

Castellon

Location:


Operator:

Shell Espana


Water depth—117 m, wind—100yr 1 min mean 40.2 m/s, 1yr, 1 min mean 24.7 m/s, waves—100yr Hmax 15.9 m. Tass 13 s, Hs 8.5 m, Tz 10.6 s.


Crude oil gravity—35–35.5° API, sulphur 0.35 wt% viscosity 5.99cst at 38°C, gas/oil ratio 75 scf/bbl

No. of wells:

1

Well completion:

Wet, subsea Cameron type

Well recovery:

None

Production rate:

6 000 b/d

Production support:

Tanker

Support data:

60 000 dwt.

Riser type:

Flexible

Riser data:

1×4 in. production

Export details:

The storage production loading tanker is moored to a single anchor leg system (SALS) with crude transfer being effected to a second 15000 dwt. tanker moored alongside

Remarks:

The development consists of a remote subsea wellhead connected by flowline to a manifold and thence by means of a flexible riser to a production/storage/loading tanker; this simple type of system has demonstrated that even a very small field located in benign environmental areas can be economically produced


132

FIG. 3.28. Castellon. Date:

1980

Field:

Nilde

Location:

The Sicily Channel 57 km south west of the island of Sicily

Operator:

Agip

Environmental conditons:

Water depth—96 m, maximum wave height—18.3 m, sign. wave height 10.0 m, wave period—13 s, wind velocity—175 km/h, tidal current at 10 m depth— 1.2 m/s


Wellhead flowing pressure 700 psi, crude gravity—38.9° API

No. of wells:

1

Well completion: Wet, subsea Well recovery:

None

Production rate:

8000 b/d

Production support:

Tanker

Support data:

84000 dwt.

Riser type:

SALS rigid riser


133

Riser data:

1×6 in. production

Export details:

Offtake of the crude is accomplished by shuttle tanker loading side-on to the production/storage/ loading tanker

Remarks:

The Nilde field has been developed with the aid of a single anchor leg storage system (SALS); this system gave some trouble initially leading to the yoke being fractured; production had to be stopped but was resumed in 1982

FIG. 3.29. Nilde. Date:

1981

Field:

Cadlao

Location:

Offshore Philippines

Operator:

Terminal Installations for Amoco


Water depth—97 m


Crude gravity—48° API, reservoir depth—5 800 ft, net thickness of reservoir bearing interval—18.2 m, porosity 16% (Avg.), permeability low, sulphur 0.66 wt%, gas/oil ratio 160 scf/bbl

No. of wells:

2

Well completion:

Wet, subsea


134


5500 b/d

Production support:

Tanker

Support data:

127000 dwt.

Riser type:

Flexible

Riser data:

2×6 in. production 2×6 in. service

Export details:

Offtake is by tandem (bow to bow) tanker berthing

Remarks:

The production/storage/loading tanker on this field is held on station by a rigid yoke attached to a single buoy storage system (SBS) which is itself anchored by 6 in. chains connected to pilings driven into the sea bed; after field depletion this system can be relocated to another similar field

FIG. 3.30 Cadlao. Date:

1982

Field:

Tazerka

Location:

Offshore Tunisia 56 km from the north east coast

Operator:

Shell Tunirex


Water depth—140–175 m, wind: 100yr 1 min mean 46.4 m/s, 1yr 1 min mean 27.3 m/s, waves: 100yr Hmax 12.2 m, Tass 11.0 s, Hs 6.7 m, Tz 9.0 s


Crude gravity 30° API, gross thickness of reservoir interval 100 m, gas/oil ratio 300 scf/bbl

No. of wells:

4


Well completion:

Wet, subsea

Well recovery:

Water injection, gas lift

135

Production rate: 10 000 b/d Production support:

Tanker

Support data:

210 000 dwt.

Riser type:

Rigid with flexible jumper hoses at the base of the SALS

Riser data:

4×3 in. production, 2×2 in. gas lift

Export details:

Offloading takes place with the aid of shuttle tanker berthing side-by-side

Remarks:

Tazerka is the first field to use a high pressure multipath fluid swivel in conjunction with a manifold chamber; the system was designed by SBM for Shell and permits the versatility of oil production, water injection and gas lift for up to eight wells; the development utilises six swivels located at the top of the SALS and permits operations in any combination of wells; Vetco supplied innovative wireline services (non-TFL), diver assisted satellite trees which are remotely controlled hydraulically from the tanker


FIG. 3.31. Tazerka.

136


137

3.5 OTHER RELEVANT SYSTEMS Date:

1981

Field:

Lavinia

Location:

East of Sicily

Operator:

Agip


Water depth—77 m


Gross thickness of the reservoir interval—300 m

No. of wells:

1

Well completion:

Wet, subsea Vetco type with hydraulic remote control


5000 m3/day

Production support:

Production support is located ashore

Support data: Riser type: Riser data: Export details:

Gas is exported to the onshore production unit by pipeline

Remarks:

Because this field is located so close to shore the single well is treated much in the same way as a satellite well in an offshore development


138

FIG. 3.32. Lavinia. Date:

1982

Field:

Emilio

Location:

Offshore Italy in the Adriatic, 30 km from the coast

Operator:

Agip


Water depth—90 m


Gross thickness of reservoir bearing interval—600 m, net thickness of reservoir bearing interval—360 m, porosity—4–28%, permeability—low, crude oil gravity—3.5–11.6° API

No. of wells:

1

Well completion:

Wet, subsea, Cameron type, the glycol system is fail safe

Well recovery:


Production rate:

500000 m3/day of gas and condensates

Production support:

Production equipment is located ashore

139

Support data: Riser type: Riser data: Export details:

Gas is exported to the onshore production unit by pipeline

Remarks:

Similar development to Lavinia

FIG. 3.33. Emilio.


140

Date:

1983

Field:

Central Cormorant

Operator:

Shell UK Exploration


Water depth—152 m


Crude gravity—35° API, sulphur content—0.6–1.1%, wax 7.2%, gas/oil ratio— 500–600 scf/bbl

No. of wells:

9–5 production, 4 injection

Well completion: Wet TFL subsea, satellites, McEvoy on the manifold, Vetco for the satellites Well recovery:

Water injection planned

Production rate:

50 000 b/d (planned)

Production support:

Underwater manifold centre (UMC)

Support data:

Weight 2200 tonnes, dimensions 52×42×15 m


Two 8 in. production lines carry crude from the underwater manifold centre (UMC) to the Cormorant A platform; because the UMC and the platform are so far apart a special insulated pipe has had to be developed to prevent the oil in the pipeline from cooling too much, causing wax and hydrate formation

Remarks:

Central Cormorant is the first practical demonstration of subsea manifold technology developed by Exxon in the SPS (subsea production system) programme of the late 1970 s; another important aspect of this development is the incorporation of TFL (through flowline) servicing of the wells


141

FIG. 3.34. Central Cormorant UMC. Date:

1984

Field:

Hutton

Location:

North Sea, blocks 211/27 and 211/28

Operator:

Conoco


Water depth—147 m


Crude gravity—33° API, sulphur—0.7%, no wax, gas/oil ratio—130 scf/bbl

No. of wells:

32 of which 13 are producers

Well completion:

Deck, dry

Well recovery:

Water injection and gas lift

Production rate:

85 000 b/d

Production support:

Tension leg platform


142

Support data:

Purpose built by Highland Fabricators

Riser type:

Rigid individual

Riser data:

32×9 in.

Export details:

Oil will be transferred by pipeline to Brent while the gas will be flared

Remarks:

The Hutton field is the first application of a tension leg platform to an oil field development; the platform weighs 22 400 tonnes and is anchored in tension to four bases on the sea bed by 16 tubulars (4 at each corner); although not a marginal field, Hutton will act as a full scale test of tension leg technology and may have marginal field applications in the future


143

FIG. 3.35. Hutton tension leg platform.


144

Date:

1984

Field:

North East Frigg

Location:

2 20 E, latitude 60 N, 18 km NE of Frigg

Operator:

Elf Norge


Water depth—100 m


Gross thickness of reservoir interval—200 m, porosity—28%, permeability— 1250 md, con-densate/gas ratio—1 bbl/mmcfg (single welldata)

No. of wells:

6

Well completion: Wet, cluster; each well is connected to a subsea gas manifold Well recovery: Production rate:

5MMm3/day of gas

Production support:

Articulated column

Support data:

Designed by EMH, normally uninhabited


Gas is exported to the TCP 2 Frigg field platform via a 16 in. gas line

Remarks:

North East Frigg is a marginal field whose recoverable reserves are not sufficient to justify the costs involved in a traditional development scheme; the scheme adopted leans heavily on technology already developed by Elf at their Grandin test station in Gabon; field life is estimated to be 5 years


145

FIG. 3.36. North East Frigg. Date:

September, 1984

Field:

Scapa

Location:

UK North Sea, block 14/19, 112 miles NE of Aberdeen

Operator:

Occidental


Water depth 130 m


Gravity 32.5° API, 42 m barrels recoverable reserves. Gas oil ratio—2 scf/bbl, Gas gravity—78.

No. of wells:

6

Well completion:

Wet, template

Well recovery: Production rate: Production support: Support data: Riser type: Riser data:

10 000 b/d (peak 24 000 b/d in 1988)


146

Export details:

Oil is piped via two flowline bundles to the Claymore platform for processing

Remarks:

Total cost of this development is £150 m

FIG. 3.37. Scapa. Date:

1985

Field:

Highlander

Location:

North Sea UK sector block 14/20

Operator:

Texaco


Water depth—140 m

Reservoir

Crude oil gravity—34–35° API porosity—15% net thickness of reservoir


147

characteristics:

interval—131.3 m and 47.2 m, sulphur 0.3 wt%, gas/oil ratio—140 scf/bbl

No. of wells:

Initially 3

Well completion:

Wet, cluster, subsea

Well recovery:

Water injection and gas lift planned

Production rate:

Initially 13 500 b/d

Production support:

Subsea manifold

Support data:

Weight 100 tonnes, 140×45×30 ft

Riser type:

N/A

Riser data:

N/A

Export details:

5 lines are planned between the field and the near-by (14 km) Tartan platform, one 12 in. for bulk crude, three 3 in. for test crude, gas lift and water injection and a 4 in. utilities line

Remarks:

Highlander is due for installation in early 1985 with limited production beginning late in the second quarter of the year; production should eventually rise to 20 000 b/d and the recoverable reserves have been estimated at 30 million barrels


FIG. 3.38. Highlander field layout.

148

Chapter 4 Current and Future Marginal Field Development Concepts In Chapter 2 we discussed the various separate elements that may be incorporated into a marginal field development system. To a large extent, within the design parameters of the particular field, these are interchangeable (e.g. the various types of production supports may be used in conjunction with different types of riser systems etc.). However, in order to appreciate the interaction of the various elements it is useful to consider the technology in terms of the overall systems which may be employed in an offshore development. In this chapter we will consider the various production concepts which are currently being employed in marginal field type applications in moderate water depths (150 m) and harsh environments (North Sea or equivalent). We will also review several promising concepts/designs which are currently being proposed for marginal field applications in deepwater environments. Systems which may operate quite satisfactorily in the tropics may be quite unsuitable when considered for duty in a North Sea type environment. North Sea type installations must be designed to withstand higher maximum waves. They must also be capable of operating in an environment which experiences waves of significant height for most of their design life without suffering from fatigue problems. Different design wave heights for various offshore areas are shown in Table 4.1. A comparison between North Sea and Gulf of Mexico wave environment is shown in Fig. 4.1. If one ignores the field developments which employ ‘conventional’ technology (i.e. steel template jackets or gravity concrete or steel platforms with pipelines to shore etc.) the most common production concept used in the North Sea type environment is based on the semi-

TABLE 4.1 Comparison of 50 Year Design Wave at Different Offshore Locations

Hmax (m) Water depth (m)

Celtic Sea Kinsale Hd.

North Sea Buchan

Campos Bicudo

Spain Castellon

Tunisia Tazerka

Philippines Cadlao

26

26

12

15

18

17

100

112

140

117

140

90

sub production support. Other concepts in current use employ subsea production, the articulating column and the tension leg platform. A system employing a converted jack-


150

up rig was used successfully for a period on the Ekofisk development. Production tanker based concepts have not as yet been used in North Sea environments. However, the use of tankers for crude oil storage and for transportation to shore is now commonplace. When one reviews the concepts which are currently being proposed there is a plethora of ideas, varying from minor modifications of existing systems to quite futuristic proposals. The concepts which are reviewed

FIG. 4.1. Comparison of North Sea environment and a mild environment. Illustration: waves of 4 m are exceeded 22% of the time at NS latitude 61° N but only 2% of the time in the Gulf of Mexico. This has implications for weather down time of loading systems and floating production installations. here include a number of promising ideas which could be adopted within the next 5–10 years. They include the following systems, among others: —SWOPS (single well oil production system), —IMFP 300 (integrated and modular floating production system), —MACC (manifold and control column), —Seaplex, —Floating oil patch, —KbE subload,

Current and future marginal field development concepts

151

—TAPS (turret anchored production system), —CONPROD. Each of these systems can be seen as a development of one or more basic production supports—semi-submersibles, tankers, jack-up units, towers and subsea units. They are considered in that order; thus the concepts which are based on the semi-submersible, for instance, are considered together, generally progressing from the conventional to the more futuristic, and similarly for the other types of support. Tables showing the typical characteristics and criteria of the various systems enable general comparisons to be made between them. It should be emphasised that the various specific systems discussed here are merely several among many hundreds of designs and concept proposals which have been produced by oil company in-house engineering teams, offshore design consultants and offshore contractors. However, we feel that most of the ideas which are currently being considered for marginal field applications are covered by the representative sample discussed below. 4.1 CONCEPTS BASED ON THE USE OF A SEMI-SUB PRODUCTION SUPPORT The basic production system consists of a conventionally moored semi-submersible housing the production facilities, which is linked to a subsea system by a riser. The subsea system consists typically of a template with a number of satellite wells feeding to a riser base which may incorporate a subsea manifold. Oil flows to the processing facilities on the semi-sub and returns to the sea bed whence it is pumped to an offshore storage or loading system (see Chapter 2). The concept has several inherent advantages: —Accelerated production from the reservoir, since the well can be pre-drilled in advance of the production installation being taken offshore. —Onshore and inshore construction of the semi-submersible production installation is less costly than offshore construction and hook-up of conventional structures. —The production semi-sub can be taken inshore for inspection and repairs. —The production semi-sub can be re-used once the reservoir has been depleted. Thus the production semi-sub can be leased for the production period. However, the concept also has a number of significant drawbacks. These principally relate to the deck load capacity of semi-subs, the disposal of associate gas, the reliability of the riser system and the operational down time attributable to the offloading system. There are a number of offshore developments which employ a converted semisubmersible as the production support. With the exception of the Argyll and Buchan developments in the North Sea, these are all situated in moderate environments. The Argyll field commenced production in 1975. It was the first oil field to be developed using a floating production system. The Buchan field commenced production in 1982. See Chapter 5 for technical details of these installations and information on their operating history.


152

When the Argyll production facility was installed on the field it was not intended as a permanent production facility—rather it was considered a production test facility. Its design was the result of drilling experience with semi-submersibles and the production support consisted of a converted drilling unit. The Buchan field development can be seen as the natural successor to Argyll. While similar in concept, it represents the extension of the floating production principle to a field with more subsea completions, but no radical departures in new technology. In terms of field size, however, it comes close to the limit of what can be achieved by the conversion of a standard drilling rig. The Balmoral field, which is currently being developed by Sun Oil in block 16/2/A in the North Sea, is scheduled to commence production in 1986. This represents a further development of the semi-submersible production concept. A purpose built production platform based on Gotaverken Arendal GVA 5000 semi-submersible has been designed with process facilities of 65000 b/d capacity. The Balmoral production platform is intended to provide processing facilities for the satellite Glamis structure and possibly other oil reservoirs in the area also. The Balmoral development is significant in that it demonstrates the significant topside weight capacity that is now possible with current semi-submersible designs (up to 5000 tons on the GVA 5000 series). The GVA 5000 has two twin decks which will house process facilities and water injection equipment as well as providing for future gas lift compressors. The Balmoral field development is significant in that it will be the first time that flexible production risers will be used in a severe North Sea type environment. The flexible riser offers significant attractions over the rigid riser to operators using a semisubmersible production support. There are advantages at the vessel/riser interface where the necessity for heave compensation equipment is eliminated and almost instantaneous disconnection is possible without difficulty. The flexible risers do not need to use the moonpool, leaving it free from workovers which can be accomplished without interrupting production. In addition the flexible riser places less demands on deck space and loading. Unlike the rigid system it needs no tensioning, thereby increasing available topside weight capacity. A flexible riser should never need to be stored on board which further increases available deck space and weight capacity. (See Chapter 2 for details of the Balmoral riser and see Chapter 3 for a description of the Balmoral field development.) Thus the Balmoral development should provide a significant advance to the semisubmersible production concept and useful operational experience of the behaviour of flexible risers in harsh environments. New proposals for further development of the basic production semi-sub concept are tending to concentrate on increasing deck load capacity, simplifying the riser system and improving the mooring and offloading systems. 4.1.1 The ‘Highlander 6000’ Floating Production Vessel The Highlander 6000 is fairly typical of the new designs for large, conventional production semi-submersibles. It has been produced by Scottish FPV Builders, a joint venture between Brown & Root/Wimpey Highlands Fabricators Ltd and Mitsui Engineering and Shipbuilding Co. The Highlander floating production vessel (FPV) has been specifically designed for low cost development of North Sea fields in the 100–200


153

m water depth range. The unit has been designed to maximise ease of fabrication and minimise construction time while meeting all North Sea safety regulations and maintaining motion characteristics which are comparable with other semi-submersibles. The unit incorporates an integrated truss type deck of the ‘Hideck’ type which is designed for wet mating of the hull and deck in a similar manner to that of the Hutton field TLP in 1984. The large deck area is a significant advantage since it reduces the height of the topsides and so optimises the location of the centre of gravity which in turn maximises the deck loading capacity. Table 4.2 shows the main characteristics and criteria which have been established for a vessel, with production payload of 6000 tonnes, operating in 150 m water depth in the North Sea. The topsides of the vessel contain all the production facilities, services and accommodation. The deck sides are cladded with lightweight panels for weather protection. Accommodation is designed for 80 persons in single or two berth cabins and hotel facilities. Outside the Norwegian sector, this can be upgraded to 120 persons without change to the major structure, as a result of the less onerous accommodation requirements outside Norway. A moonpool is located in the centre of the deck. It is designed for handling workover and side track drilling and control umbilical

TABLE 4.2 Highlander 6000 Main Characteristics and Criteria Number

Dimensions

Columns

8

10 m dia.

24.6 m

Pontoons

2

12.8 m width×75 m long

6.4 m

Main+cellar

75 m×55 m

10.0 m

Deck

Height

Dry

Operating

Deck weight (tonnes)

7500

10000

Hull weight (tonnes)

7800

21000 (inc. ballast etc.)

Displacement (tonnes) Draught (metres)

Transit

Operating

Survival

20300

31000

27100

6.1

20.0

15.0

Design operating conditions 100 year storm survival conditions Waves (Hs×period)

9.4 m×12.4 s

16.6 m×16.6 s

Surface Current (knots)

1.6

2.6

Hour Mean Speed (knots)

51.0

73.0

tensioning equipment. The main deck of the structure contains the following items: —workover derrick, —wellhead workshop,


154

—helideck (suitable for a Boeing 234—Chinook helicopter), —flare boom, —some process plant, —deck cranes for all onloading and offloading and for material handling on board, including maintenance operations, —riser headers and dry break couplings for the flexible risers, —material stowage, —totally enclosed motor propelled survival craft (escape capsules) with launch and recovery davit systems and other life saving appliances. The Highlander 6000 production capacity obviously depends on the characteristics of any particular field as illustrated by the following weight constant options: Option I Option 2 Option 3 Option 4 Oil production rate (b/d)

35000

100000

50000

100000

30

30

150

0

Produced water treatment (b/d)

35000

0

20000

35000

Water injection (b/d)

40000

60000

0

100000

Gas compression (mmscfd)

A conventional 12 line 95 mm chain catenary mooring with high holding anchor piles is designed to keep the unit on location within the allowable offsets even in storm conditions. Hydraulically operated mooring chain tensioning systems are located on the columns. Riser disconnections should not be required in any intact condition. The Highlander concept of a large conventional semi-submersible production platform is not unique. Several other similar designs have been proposed by designers and contractors. These include: —the Gotaverken Arendal 5000 series and 12000 series (with 12500 tonnes topside capacity); —the EPM—T2000 ‘Cybele’ design; —the CFEM five legged ‘Penta 7000’ floating production platform; —the Santa Fe ‘Sea hawk’ design.

TABLE 4.3 Some Production Semi-Submersible Designs System name

Seahawk

Penta 7000

Cybele

Designer

Santa Fe

CFEM

EPM

Water depth

100–500 m

200–550 m

150 m plus

Oil production

40000 b/d

120000 b/d

10000 b/d

90 mmscfd

140 mmscfd

Assumed field data

Gas production GOR

3

1200 ft /bbl


Gravity (API)

25–40

Gas lift

At up to 2400 psi

Possible

Water injection

60000 b/d

Possible

Reservoir pressure

32000 psi

No.of wells

155

150000 b/d

16

Dimensions Length

84 m

88 m

92 m

Width

64 m

116 m

92 m

42 m

41 m

Height to main deck Depth

7m

4m

8m

No.of columns

6

5

8

Draft (operating)

9.8 m

22.5 m

25 m

Displacement (operating)

23580 tonnes

28000 tonnes

35200 tonnes

Variable deck load

2900 tonnes 7000 tonnes

9300 tonnes

Fixed and variable deck load Mooring

Chain, 8 point

wire cables, 10pt

Accommodation

108 personnel

120 personnel

Weight of structure

10600 tonnes

11300 tonnes

None

45000 bbl

Wind (1 min.)

100 knots

100 knots

Waves (height and period)

30 m×14 s

31 m×15 s

Surface current

2.5 knots

2.5 knots

Crude storage capacity

None

Environment Normal operation Wind

70 knot

Waves (Hs)

30 ft

Surface current

2 knot

Survival

See Table 4.3 for details of these current production semi-submersible designs. Indeed, it is worth noting that semi-submersible designs exist which are proposed as being suitable for quite large fields in very deep water—the Santa Fe drilling DP-120 vessel concept would have a deck load capacity of 7000 tonnes and a production capacity of 100000240000 b/d in water depths of 300–1600 ft.


156

4.1.2 The IMFP 300 Semi-submersible The IMFP 300 is a design which takes the semi-submersible production concept a stage further in that it incorporates oil storage and offloading of product as well as production in a single modular structure. It is a design concept which has been developed by Integrated & Modular, a joint venture between CFEM (Compagnie Francais d’Enterprises Metalliques) and PPT (Progressive Production Technology), a joint subsidiary of Technip Geoproduction and IFP. The IMFP 300 is aimed at early production and production of marginal fields in water depths of 100 m to 500 m. The main components of the system consist of: —A modular semi-submersible structure which integrates in a single unit production facilities, oil storage and an offloading system. —A conventional catenary mooring system. —A flexible riser system which facilitates redeployment in a wide range of water depths. —A circular monohull design which obviates the necessity for the unit to weathervane. Thus the unit only needs to employ a low pressure swivel for crude offloading and gas flaring. The IMFP 300 concept attempts to overcome the principal limitations of the current generation of production semi-submersibles and production/storage tankers. In water depths over 120 m current production/storage tankers need to be permanently moored by a sophisticated system such as an articulated riser. These units cannot, therefore, be redeployed in a wide range of water depths, thus limiting their versatility and reusability in marginal field applications. The weathervaning facilities needed for production tanker systems have to incorporate multiple path, high pressure swivels, which can be a source of maintenance problems. A sketch of the IMFP 300 is shown in Fig. 4.2. The production facilities remove gas and water from the crude oil and the oil is stabilised. The stabilised oil is pumped from the production deck to the peripheral storage tanks. Oil entering these storage tanks displaces a corresponding volume of oily sea water which is ejected into the sea through an oily water treatment unit. The IMFP 300 requires a constant draught to be maintained in all storage conditions, and thus the total weight of oil in the storage tanks plus the sea water in the ballast tanks must be the same for all storage conditions. The IMFP 300 vessel can be anchored by its own conventional mooring system in a variety of water depths from 100 m to 500 m, thus facilitating redeployment. Mooring lines are composed of short sections of chains with wire ropes. Mooring winches are not provided for. Lines are pulled with jacks and stoppers are used. Table 4.4 shows the main characteristics and criteria for one version of the unit. The top sides of the vessel and central shaft contain all the production facilities, services and accommodation for 40 personnel. The available production capacity depends on the reservoir characteristics but is illustrated by the following options: —oil production (b/d)—25000;


FIG. 4.2. IMFP 300. —Gas separation (mmscfd)—20; —Produced water treatment (b/d)—12500, water cut 0% to 50%, max. gas/oil ratio 840 scf/bbl, no sand, crude oil/water emulsions and foaming problems to limit of treatment by chemical injection; —Number of subsea wells—6; —Oil offloading rate (b/h)—12000.

157


158

4.2 CONCEPTS BASED ON THE USE OF A TANKER PRODUCTION SUPPORT The basic production system consists of a conventionally moored tanker which houses the production facilities and which is linked to a subsea system by a single point mooring (see Chapter 2). The subsea equip-ment consists, typically, of a number of satellite wells feeding to a manifold and riser.

TABLE 4.4 IMFP 300 Main Characteristics and Criteria Number Dimensions

Height

Central shaft

1

13.0 m dia.

65.0 m

Peripheral cylinders

8

7.8 m dia.

62.0 m

Deck

107 m

Flare height above deck

Deck weight (tonnes)

34 m

Number Dimensions

Draught (m)

Environment

Height

Storage

1500

Total dry weight of structure and equipment (tonnes) Displacement (tonnes)

105000 bbl

30 m×30 m

Total height (without flare)

Weights and draught

Storage

12500 40000 77.0

Annual return period

100 year storm survival conditions

5.0 m×9.5 s

7.6 m×11.1 s

Surface current (knots)

2.3

3.3

Bottom currents (knots)

0.2

0.2

Waves (Hs×period)

Oil flows to the processing facilities on the tanker, where the oil is degassed, and buffer storage is provided on the tanker. Offloading of the oil is by shuttle tanker which takes oil from storage to shore. The concept has several inherent advantages: —Accelerated production from the reservoir, since the wells can be predrilled in advance of the production installation being taken offshore. —The tanker conversion can be completed in shipyards or inshore thus avoiding expensive offshore construction and hook-up. —The production unit may also house very large storage capacity and afford a stable terminal for offloading the produced oil into shuttle tankers.


159

—Offshore loading from tanker storage is less prone to the weather and mechanically induced down time which has plagued some loading systems in harsh offshore environments. —The large deck areas and virtually unlimited deck load capacity of tanker based production units eliminates the problem of topside weight control, which remains one of the main problems in the design of semi-submersible type units. —The unit can be taken inshore for inspection and repairs. —The tanker and its topside facilities can be redeployed once the reservoir is depleted. Thus the tanker has all the advantages of the semi-sub concept with the addition of providing oil storage and being an integral offloading terminal. The related production equipment considerations are about the same as for those of a semi-submersible. However, the concept also has a number of significant drawbacks when considered in the context of North Sea type environments. These principally relate to the mooring and the riser systems. The tanker itself may be moored in a spread mooring of multiple fixed anchor points on the sea bed. This type of arrangement fixes the orientation of the tanker and can be used only in shallow, protected waters where mild winds, waves and currents prevail. The alternative method of mooring a tanker is by its bow or stern with a single point mooring. The single point mooring system (SPM) (see Chapter 2) minimises the environmental load on the tanker by allowing it to weathervane to the orientation of least resistance to the combined forces of wind, wave and current. This, of course, results in the possibility of the ship rotating freely about its mooring. Consequently any continuous delivery of fluids through a pipeline or hoses to, or from, the ship must pass through the buoy and, in fact, be concentric with respect to the axis of rotation of the whole system to avoid interferences or entanglements. The piping conduit itself must also be equipped with a swivel to permit the tanker to weathervane. If multiple conduits are required, they must have multiple concentric swivels. Swivels to accommodate multiple concentric passages have been developed. Similar systems have been used for many years for loading and unloading crude oil tankers at terminals. However, these several hundred existing SPM systems were designed for handling tanker-ready crude at terminals. The use of a SPM moored tanker as the production support facility for early or marginal field production systems presents an entirely different set of circumstances. In this situation the live well bore fluids of gas, oil, water and sand is being handled. The gas and oil may both be sour (i.e. contain H2S). The pressure may be the well flowing pressure of several thousand pounds per square inch. This is all in contrast to the stabilised and treated crude oil at a maximum pumping pressure of 200 psi normally seen in tanker loading service. There are a considerable number of offshore developments which employ a converted tanker as production support (see Chapter 3 for the technical details and information on their operating history). However, without exception, these are all currently operating in moderate offshore environments. Nevertheless, tanker based systems for a North Sea type environment are being proposed and built as we shall see below.


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4.2.1 Offshore Oil Production and Test Ship (PTS) Petrojarl/Golarnor The PTS is a ship shaped vessel designed for early production of crude oil and well testing. The design was undertaken by Tentech International, a Norwegian firm. The Norwegian owners of the vessel, K/S Petrojarl 1, a consortium of five Norwegian shipping companies, are currently having the vessel constructed at Nippon Kokan KK (NKK) in Japan and the vessel is scheduled for completion early in 1986 (Fig. 4.3). The operation of the vessel will be undertaken by a subsidiary of Det Nordenfjeldske D/S, Golarnor Production. See Table 4.5 for details of the main characteristics and criteria of the PTS. The vessel is turret moored in order to permit a heading into the prevailing seas at all times. The production equipment installed is

FIG. 4.3. Golarnor/Petrojarl PTS. capable of processing a wide range of reservoir fluid characteristics, up to 20000 b/d of liquids. Produced water is treated and discharged while gas produced will be burnt in a ground flare fitted aboard the vessel. The vessel will be kept on station over a subsea template by means of the turret mounted catenary mooring system. However, the vessel is also fitted with dynamic positioning thrusters to assist in position keeping. It is anticipated that dynamic positioning will be used exclusively in deep waters. Periodic discharge of produced crude oil will be via a loading arrangement to a shuttle tanker moored at the stern of the PTS by a hawser. The production riser, which can be installed by the ship and crew, is designed to remain connected in survival conditions. Two riser options are available: vertically tensioned or flexible in catenary with subsea buoy. The PTS will be initially equipped with a single well riser. However, a multiple well riser may be accommodated if required.


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TABLE 4.5 PTS Production Test Ship Assumed field data Water depth

100 m to 600 m

Oil production

2850 tonnes/day

Water cut

Up to high % (if required)

Export system

Offloading to shuttle tanker, over stern

PTS characteristics and criteria Dimensions

209 m long×32 m width

Draught

10 m

Displacement

50910 tonnes

Oil storage capacity

188700 STB of crude oil

Ground flare capacity

30.5 mmscfd

Mooring

8×1600 m long K-4 class anchor chains with 13.6 tonne anchors

Dynamic positioning

DP systems with hydroacoustic reference to transponders at seafloor. DP to provide heading control and reduce peak mooring line loads on turret system. 2×5600kw controllable pitch main thrusters. 4×1500kw fixed transverse thrusters, two forward and two aft.

The PTS has been designed to survive and remain on station in a North Sea storm of 100 year return period. The owners of the PTS intend to lease the vessel out to operators of offshore fields. It has been reported (August 1985) that Norske Hydro intend to charter the Petrojarl to carry out extended production trials on two wells on the Oseberg field offshore Norway. The PTS is a logical development of the production tanker concept from the mild offshore environments of the Mediterranean and Far East. Items of special interest, when extending the concept to North Sea type environments, involved fatigue loading, the mooring and riser systems and the topside arrangements. 4.2.2 The ‘SWOPS’ Oil Production System The SWOPS system is a design which takes the tanker floating production and storage concept a stage further in that it is a purpose built monohull which is designed for the development of small fields and extended well testing in a North Sea environment. It is a design concept which has been developed by BP Petroleum Ltd. The construction of the first SWOPS vessel is due to commence at the Harland & Wolff shipyard in Belfast. This vessel is scheduled to commence operation in the central North Sea during mid-1987. It


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is understood that it is initially intended to be deployed on a 30 mmbbl accumulation in UK sector in Block 16/28in almost 110 m of water, 200 km offshore. The main components of the SWOPS system consist of: —A dynamically positioned vessel fitted with integral process equipment and oil storage.

FIG. 4.4. SWOPS. —A conventional subsea well completed to accept the SWOPS riser. —A rigid riser system operated through a moonpool in the centre of the vessel’s hull. —An offshore loading system is not provided for. The SWOPS vessel shuttles back to an inshore terminal to offload the stored crude oil. See Table 4.6 for details of the main characteristics and criteria for SWOPS. The vessel is designed to maintain station and heading into the prevailing seas at all times by means of dynamic positioning (DP). The dynamic positioning also obviates the necessity for a conventional mooring system. Power for the DP system is provided by produced gas, thereby minimising the operating costs of the DP system and reducing the quantity of produced gas to be flared.


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The vessel does not have a drilling capability. The exploration or appraisal wells are completed in a conventional manner by a drilling vessel and the wellheads are capped with a SWOPS re-entry hub. The

TABLE 4.6 SWOPS System Assumed field data Water depth

75–200 m

Oil production (b/d)

3 000–15 000

Gas production (mmscfd)

6

Water production (b/d)

4000

Max. shut-in pressure

5 000 psi

Water/gas injection

None

Max. no. producing wells

2

Wellhead fluids

Negligible H2S, 10% weight max. wax content. 0°C pour point

SWOPS main characteristics and criteria Dimensions

251.5 m× 37.0 m width× 19.8 m depth

Displacement (at 11.0 m design draft)

76 440 tonnes

Tanks’ capacity crude oil storage

51 000 m3

ballast

39 000 m3

slops

6 500 m3

heavy fuel oil

2 600 tonnes

Transit speed

12–14 knots

Riser pipe

OD ×24.7 lb/ft Grade E SMLS API 5A drill pipe

Riser operating tension

90 000 lb/ft

Number of tensioners

4

Max. travel of tensioners

50 ft

Max. riser angle

±15°

Max environmental criteria for production Significant wave height, Hs

4.5 m

Winds

36.5 knots


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rigid riser, which incorporates a wellhead re-entry connector, is lowered to mate with the wellhead when the SWOPS vessel is on station. The design permits re-entry and connection of the production bore with the riser whatever the rotational orientation of the riser connector. The wellhead hydraulic controls are simultaneously connected with the production bore and riser. Oil produced from up to two wells can be comingled at the base of the riser. The rigid, tensioned riser consists of a series of conventional jointed tubulars with a universal joint at the lower end and a high pressure swivel at the upper end. Riser stresses are minimised by the universal joint which permits the vessel to oscillate under DP control. The riser is designed to permit production to continue in severe weather conditions, limited only by heave and the station keeping capability of the ship. The rigid riser is a less expensive option than a flexible riser. However, it requires much tighter DP control plus extra deck storage, space and a derrick and moonpool arrangement. Nevertheless, the rigid riser does permit wireline entry to the wellhead. The depth limitation of the current SWOPS design is more a function of the specific applications which BP have in mind for this vessel than an inherent limitation of the concept. A SWOPS vessel, designed for 500 m water depth, has been proposed by the designers. The installed production equipment has a design capacity of 15000 barrels a day. It is housed below the main deck and adjacent to the moonpool. The two-stage production process is straightforward. Incoming crude oil is cooled and its pressure reduced to separator conditions. At the first stage separator up to 80% of its gas content is removed and conditioned to fuel gas quality to feed the ship’s power generation system. After the second stage separator the crude is cooled to storage specifications and led directly to the ship’s cargo tanks. Produced water is fed to the oily water separation system where natural separation takes place. Any remaining gas is flared. The SWOPS vessel has a storage capacity of some 42000 tonnes of crude oil. The vessel will have a displacement of about 76000 tonnes. BP did consider converting an existing tanker (of about 50000 dwt.) as an alternative to a purpose built vessel but rejected the conversion option as they considered it to be unsatisfactory, both technically and commercially. The purpose built vessel also permitted BP to optimise their design. However, the economics of other small fields may dictate the use of a converted tanker deploying a flexible riser over the side or bow of the vessel. The SWOPS vessel which has now been commissioned will incorporate the rigid riser configuration described above. However, an alternative flexible riser design has also been proposed by BP for future applications of the concept. 4.2.3 The Floating Oil Patch The floating oil patch is a design concept which takes the production tanker a stage further in that it abandons the tanker shape in favour of that of a barge shaped hull, and the tandem hull design aims to reduce the wave induced motions of the unit. The concept has been developed by Worley Engineering. The floating oil patch is aimed at early production of marginal fields in all types of environments where rapid construction time and low capital costs are important criteria. The main components of the system are:


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—Two conventional barge shaped hulls, one supported beneath the other, leaving an interhull gap. —A turret mooring system with six catenary mooring lines which permits the unit to weathervane. —Multiproduct high pressure swivels in the turret to permit transfer of all well fluids to the process system. —A tensioned leg riser tower with subsea manifold which can be maintained by divers in the air diving range. The floating oil patch concept attempts to overcome the limitation of the current generation of floating production and storage vessels while still capitalising on the best features of the systems currently available. Converted tankers have the advantage of high payload capacity and large deck area. However, the mooring and riser systems pose problems in severe wave environments and, despite the availability of surplus tankers, few are suitable for conversion. Semi-submersibles have the advantage of satisfactory motion characteristics but they are expensive to build or convert and they tend to be weight sensitive. Jack-up units have the advantage of providing a stable platform but they are limited in regard to water depth and deck load capability. A sketch of the floating oil patch is shown in Fig. 4.5. A notable feature of the concept is the tandem hull design. The supporting members in the interhull gap are designed to promote conflicting currents and vortices in the water entrained between the hulls. The large power sink, thus created, consumes the wave energy thereby reducing the pitch, heave and roll motions of the vessel. Vessel motions are further dampened by a passive motion suppression system developed by the London Centre for Marine Technology and licensed by BPP Ocean Technology Ltd. This system consists of a series of open bottomed tanks along the sides of the upper hull which are valved to ensure that the natural frequency of the vessel is altered so that it never operates in the range of its two roll resonant states. The tandem hull design also reduces the water plane ratio of the vessel and so further reduces the motions, just as the same principle forms the basis of the steadiness characteristics of semi-submersible vessels. Periodic maintenance and inspection of the upper hull and interhull structures is facilitated by deballasting the lower hull for dry access to these areas. Process, utility and power generation equipment and systems are located on the main and lower deck levels and a ground flare is located at the aft end of the platform. Deck loading should not be a problem as the unit could accommodate up to 15000 tonnes payload. The subsea flowlines and control lines from production and injection wells are laid to anchor blocks below the tension leg riser tower and flexible transitions connect them to the rigid risers in the tower. The tower is tensioned by a buoyancy tank which is surmounted by a subsea manifold which can be maintained by divers in the air diving range. The flowlines are then routed down to sea-bed level where they are connected to a flexible riser system.


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FIG. 4.5. Oil patch. Crude oil storage is available in the lower hull of the unit and direct offloading is possible using shuttle tankers. Alternatively, of course, the stabilised crude may be transferred to an export pipeline. Accommodation facilities are provided for up to 100 persons in an accommodation block which also houses the control room and marine facilities. The dimensions and capacities of the oil patch concept are quite flexible and the designers have proposed a number of options with different production and load capacities. Table 4.7 shows the main characteristics and criteria for one version of the unit. 4.2.4 The TAPS System The barge based turret anchor production system (TAPS) is a design concept which aims to incorporate production facilities, storage and offloading capabilities in one barge type facility. The concept has been developed by Flotech Ltd, a joint venture between Taylor Woodrow and Seaforth Maritime Ltd. The TAPS system is aimed at production from marginal fields in all types of environment. Based on their studies the designers suggest that, with proper selection of the barge dimensions, minimum wave induced motions can be achieved. Indeed, they claim that a barge can be optimised to give less severe motions than those of current semi-submersibles. Additionally, the relatively simple hull shape permits rapid and economical construction.


167

TABLE 4.7 The Floating Oil Patch Assumed field data Water depth

150 m


20000 (36° API)

Gas production (mmscfd)

60

Water cut

33%

Gas/oil ratio

300 scf/bbl

Max. shut in pressure

2000 psi

Number of subsea wells

6

Export system

6 in. transfer to existing pipeline

Dimensions Upper hull

124.0 m×33.0 m×9.0 m deep

Lower hull

131.0 m×28.0 m×8.0 m deep

Interhull gap

3.5 m

Depth of subsea manifold

45.0 m below LAT

No.of mooring chains

6

Deck payload capacity

15000 tonnes

Environmental criteria The unit is designed to maintain normal operations in Beaufort force 8/9 weather conditions in Block 30 of the UK Sector North Sea and to survive the 100 year storm.

TABLE 4.8 TAPS System Assumed field data Water depth

300 m

100 m


70 000

45 000

22.4

22.5

Produced water (b/d)

60 000

48 000

Gas oil ratio (scf/bbl)

320

500

5 000

5 000

90 000

65 000

20

20

Gas products (mmscfd)

Max. shut in pressure (psig) Water injection rate (b/d) Gas injection rate (mmscfd)


No. producing wells

168

12

8

No. gas injection wells

8

7

No. water injection wells

2

0

TAPS main characteristics and criteria Dimensions 250 m×41 m×25 m depth Displacement (15 m draft)

142773 tonnes

Tank capacities (tonnes)

Crude oil storage

70 000

for 100 m depth unit

108 000


11 000


Slops

3600


Fuel

1000


Water ballast Produced water

Crude oil discharge rate: Turret structure

Mooring:

3 500 m3/h

Mass:

1 100 tonnes

Diameter:

18 m (300 m unit)

24 m (100 m unit)

9×127 m wire cable (300 m unit) 9×4 in. grade 4 chain (100 m unit)

Riser:

Tensioned (300 m unit) Flexible (100 m unit)

Max. variable deckload:

10000 tonnes (in addition to fixed loads such as power generation and accommodation) Accommodation: 130 persons Power generation:

Gas turbines 4×3.3 MW

Environmental criteria

Waves (Hs×period) Wind (3 s @ 10 m elevation) Surface current

300 m unit

100 m unit

18 m×16 s

14 m×15 s

55 m/s

52 m/s

1.45 m/s

1.45 m/s

The main components of the TAPS system consist of: —A barge shaped production, storage and offloading vessel which is turret moored just forward of midship.


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—Risers from a seabed template pass through the turret where they are checked and manifolded on the turret before passing through a medium pressure swivel to the process plant. — Export is by shuttle tanker using a tandem loading system (although pipeline export is, of course, also feasible). —The riser is designed to remain connected to the unit even through the survival storm. A sketch of the TAPS system is shown in Fig. 4.6. The system has been

FIG. 4.6. Turret anchor production system. designed for a range of water depths. The first design was for a field west of Shetland in 300 m but the latest design is for a unit for a field SE of Shetland in 100 m water depth. 4.2.5 Future Development of the Production Tanker Concept The main areas for research and development on tanker based floating production systems are as follows: —High pressure, multiple passage process and control swivels. The swivel is the heart of a weathervaning production system. Swivels are only as good as their high pressure seals. Thus much of the development work is concerned with testing sealing surfaces and assessing the effect of different fluid types, pressure and temperatures on the life of seals, etc. As the number of passages increases, with additional wells and with gas and water injection facilities, the size and complexity of the unit increases and consequently there is a dramatic increase in the size and length of individual sealing surfaces.


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—New connect and disconnect systems are being developed to permit operations in iceberg prone areas and to permit tankers to stay on station and to re-connect at much higher sea states. —Improved mooring systems and DP systems are being developed to enable tankers to weather the most extreme offshore environments. 4.3 CONCEPTS BASED ON THE USE OF A JACK-UP PRODUCTION SUPPORT The basic production system consists, typically, of a converted drilling jack-up unit which houses the production facilities with wellheads situated on the jack-up unit. Oil flows to the processing system and thence to a storage facility aboard an adjacent tanker. The jack-up has several inherent advantages: —The stable platform provided by the jack-up eliminates all the difficulties associated with the heave and lateral motions of floating units. —The units may be deployed at short notice and are ideal for early production systems. —The conversion to a production facility can be completed inshore, thus avoiding expensive offshore construction and hook-up. However, jack-up production units have several limitations which may become critical when considering them for duty in severe wave environments: —Jack-up units must, by their nature, be able to jack their deck into position above the prevailing waves. Thus the jacking capacity has a critical influence on the topside facilities which can be accommodated on the unit. —Most drilling jack-up designs are based on a combination of maximum wave, wind and gravity loads and, as such, are not entirely governed by fatigue considerations due to the variations in water depth, environmental conditions and operating loads experienced during the life of the unit. While the cyclic stresses may be high, the number of cycles at any given location on the leg will be low. Thus, a jack-up designed essentially for exploratory drilling will have a shorter fatigue life if it is operated at a single location for a long period of time. This is especially true in severe wave environments. —Jack-up units, being bottom founded, have quite strict depth limitations, especially in severe wave environments. —Jack-up units do not have any oil storage capability and so require an associated storage/transportation vessel or a pipeline to shore. Several fields worldwide currently employ converted jack-up units for production duties (see Chapter 3). However, only one such unit has been used in the North Sea. This was the Gulf Tide jack-up unit which was deployed on the Ekofisk field between 1971 and 1974. The unit is understood to have suffered fatigue damage during this—comparatively brief—period. A new class of harsh environment jack-up units have recently entered the North Sea drilling market. These units, which are designed for drilling, not production, give an


171

indication of the largest type of jack-up which is currently available. A sketch of the unit is shown in Fig. 4.7 and the main characteristics of these units are shown in Table 4.9.

FIG. 4.7. Harsh environment jack-up by Hitachi Zosen. TABLE 4.9 Harsh Environment Jack-up Drilling Units Unit Max water depth

Maersk harsh environmental unit

CFEM T2600C

Rowan ‘Gorilla’

105 m

91 mm

100 m

84.6 m

81.3 m

90.5 m

Dimensions Length


Breadth

172

90.0 m

93.9 m

89 m

Depth at side

9.5 m

8m

9.1 m

Design draft

4.8 m

5.15 m

Number of legs

3

3

156.8 m

130 m

503 ft

2

2

352.99 m2

Length of leg Spud tank area (each)

262 m

153.9 m

Hull weights (tonnes) Lightweight (excl. legs)

13 300

Normal lifting with full variable load

15 800

Variable load on board

2820

Max. load of hook, rotary setback Accommodation (persons)

2 500

680 90

90

80

Environmental conditions (in elevated conditions) Wave height (max.×period)

29.56 m× (for 300 ft) 92 17.5 s ft

60 s wind velocity

84 knots

82 knots

Surface current

1.66 m/s

1.5 knots

0.4 m/s

4.3.1 Seaplex Class 500–4 The Seaplex is a design concept which attempts to address the depth and storage limitations of jack-ups. The design was developed by Seaplex Corporation which is a subsidiary of Combustion Engineering Inc., C.G. Doris and Marathon le Tourneau. The Seaplex platform is a hybrid design especially aimed at development of small offshore reservoirs. It is a gravity type structure consisting of a very large steel jack-up attached to a concrete caisson. The main components of the system consist of: —A large jack-up with rectangular hull and four open truss legs. —A concrete caisson with a 500000 barrel capacity, which permits the structure to serve as a storage facility. —All necessary equipment, ancillary hardware and systems for drilling, production, processing and offloading. The steel jack-up is a modified mobile drilling unit with the production processing equipment on and within the hull. It is designed to accommodate the necessary drilling/production loads and to meet the fatigue requirements dictated by the application and design.


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FIG. 4.8. Seaplex. The reinforced and prestressed concrete caisson is the foundation base for the overall structure. When ballasted, it helps provide the necessary stability for operations in severe environments. During production operations the caisson, through the application of the oil/water displacement principle, is used for storing the produced crude oil, while during tow, installation and retrieval operations, it provides the controlled buoyancy to accommodate the total topside load, including the jack-up. For the North Sea type environment, the Seaplex concept incorporates two additional and separate elements for assisting in developing marginal fields. One is the unitised subsea drilling/production template for predrilling wells during the construction stage of the Seaplex; and the other, a truss type steel tower structure that provides both lateral and vertical support for the risers and well conductors. Jack-up payloads tend to be limited to something less than that usually desired by production personnel. However, by attaching the jack-up legs to the concrete caisson and


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by welding off the legs to the hull structure, the Seaplex is able to accommodate a 50– 150% greater payload than the free standing jack-up. The elevating units may be removed from the structure to provide additional payload capacity or left in place as a possible back-up to the welded connections. Typical specifications for the Seaplex class 500–4 are shown in Table 4.10.

TABLE 4.10 Seaplex Class 500–4 Typical Specifications Water depth (m)

122

152

Max. wave height×period

28 m×17.5 s

31 m×17.5 s

Current

(surface)

2.72 knots

2.72 knots

(bottom)

0.0 knots

0.0 knots


50000

50000

Maximum oil storage (bbl)

500000

500000 2

Available deck space

4088 m

4088 m2

Deek load (all fixed and variable)

27215 tonnes

18144 tonnes

4.4 CONCEPTS BASED ON ARTICULATED TOWERS 4.4.1 Subsea Riser Tower The subsea riser tower is a compliant riser system which can be utilised with any type of floating production vessel: ship, barge or semi-submersible based. It is designed for severe environment applications. The design has been developed by Foster Wheeler Petroleum Development. A typical application of the concept is shown in Fig. 2.10. The system consists of the following elements: —A riser top module. This supports all the equipment required for comingling of the well fluids (chokes, valves, pigging diverters, hydraulic accumulator banks and control instruments) from up to 16 wells, including water and gas injection wells. —Approximate weight of this module is 250 tonnes. —Four 40-m long buoyancy tanks and two ballast tanks. —A four-legged tubular latticed structure, of varied length to suit the water depth. —Conventional universal joint with self lubricated bushings and a base connection arrangement designed for diverters actuation. —The piled or gravity base section, which may include a wellhead template depending on the type of floating production unit. An integral base/template arrangement is proposed for tanker based systems and a separate arrangement is proposed for a semisubmersible system. See Chapter 2 for further details of this proposal.


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The manifold on the riser top module is situated 50 m below the water surface. This depth has been selected to ensure low dynamic excursion of the riser due to current induced vortex shedding. The vortex shedding forces are also reduced by the selection of four long slender buoyancy chambers and a lattice type structure. The subsea manifold can be accessed by air divers to accomplish simple and rapid operations (e.g. replace any piece if necessary, connect flexible to rigid lines, etc.). 4.4.2 MACC—nifold and Control Columns The MACC concept consists of a range of offshore systems based on articulated columns aimed specifically at marginal fields. It is a concept which has been developed by Taywood Engineering Ltd. Typical applications of the concept are shown in Fig. 4.9. These systems aim to offer the potential for uninterrupted offshore production including injection, for marginal fields in water depths to 200 m. The designers claim that the system is 14 months faster to peak oil production than fixed platform schemes. The availability of the system is equivalent to that of a fixed platform with a capital cost of at least 20% less. The system consists of an articulated column which is used to provide a high integrity fluid path from the well bore to deck level. By rating all the equipment on this fluid path at full reservoir pressure it is possible to locate all well control valves and chokes on the deck of the column. Safety on/off valves remain subsea, to be controlled by discrete hydraulics. The topsides production facilities and utilities require some form of support structure, i.e. either a semi-submersible, a purpose-built barge, or a converted tanker. The most appropriate structure to use for any particular development would depend largely on physical field parameters, and also on economic criteria. Taywood Engineering suggest that the following factors have the greatest influence on the decision to adopt a particular development system: —peak production, —gas/oil ratio, —number of wells required, —requirements for gas injection, —number of drilling centres required for correct well distribution. 4.4.3 MACC Moored Semi-submersible Scheme An enhancement scheme based upon the use of a semi-submersible yoked to an articulated column is considered suitable for the following field conditions: —fields requiring a large number of wells; —reservoirs requiring high pressure gas injection; —reservoirs requiring frequent workover; —crude export by pipeline. The details of a typical development would be as follows:


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—A semi-submersible production facility conventionally catenary-moored using piled anchors, and yoked to an articulated column. The vessel can thus maintain its position over the wells whilst working over or redrilling. In the event of failure of the catenary moorings, the semi-submersible will still remain safely moored to the column. The

FIG. 4.9. Articulated riser columns with topsides manifold linked to floating production platform and tanker FPSO.


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TABLE 4.11 MACC—Manifold and Control Column Assumed field data

MACC with tanker

MACC with Semi-sub Oilfield

Gas condensate field

Water depth

119 m

158 m

105 m


58000

50000

50000

GOR (scf/bbl)

310

500

6000

CO2

—

—

25%

No.wells production

10

15

15

Gas injection

—

—

270 mm scfd

No.wells injection

8

10

13

45000

50000

Water injection (b/d)

Total effective down time claimed by designers compared with other systems Down time

Column moored semi-sub

Fixed platform

Semi-sub with tensioned riser

Weather

0.5%

0.0%

25%

Repair/maintenance

0.5%

0.5%

1%

Total

1.0%

0.5%

26%

Average daily production (b/d)

49500

49750

37250

Down time

Column moored tanker

Fixed platform (no storage)

Semi-sub with tensioned riser

Weather

1.5%

0.0%

0.0%

Repair maintenance

0.4%

0.6%

1.2%

Export

1.5%

25.0%

25.0%

3.4%

25.6%

26.2%

48300

37200

36900

Total Average daily production

choice of purpose built or converted semi-submersible would depend on field conditions, such as gas/oil ratio, and future drilling requirements. —The wells are assumed to be drilled through a template located close enough to the column to allow wireline workover from the semi-submersible. Subsea valving is restricted to on/off safety valves with control by discrete hydraulics. All other wellhead controls (control valves and chokes) are mounted on the deck of the column for easy access.


178

—The articulated column is a conventional single articulation tower (similar to the Fulmar tower described in Chapter 2) acting as a riser support and mooring for the floating vessel. The column can be constructed in either structural steel or prestressed concrete depending on comparative costs. —The production platform would be a conventional large semi-submersible (e.g. GVA 5000) for low gas/oil ratio fields. For high GOR fields a heavy weight semi would need to be developed to carry the extra equipment required. 4.4.4 MACC Moored Tanker Scheme An enhancement system based upon the use of a tanker yoked to an articulated column is considered suitable for the following conditions: —fields requiring a small number of wells in the location of the production facilities; —fields requiring heavy production equipment; —fields requiring in-line product storage. The details of a typical development would be as follows: —Tanker production facility yoked to an articulated column, but free to weathervane about the column. The vessel can either be a converted VLCC, or a purpose built dumb barge. The choice between the two will depend on balancing the initial cost savings in purchasing and converting an existing VLCC against the improved fatigue life and motion response characteristics of a purpose built barge. —The wells are assumed to be drilled through templates set far enough from the radius of the tanker to allow heavy workover by a semi-submersible. Similar hydraulic well controls are adopted in this application to that of the semi-submersible system. They are, however, adapted to allow partial TFL work. The articulated column provides essentially the same function as that used in the semi-submersible development, by supporting manifolding and control facilities. The choice of structure material can again be made on performance and economic grounds. 4.4.5 MACC in Satellite Field Development Scheme The designers claim that a satellite field using an articulated column has lower capital cost and higher system availability than a UMC in water depths less than 200 m. The MACC also has the advantage of having above-water maintenance of most equipment. A typical development would have the following: —An articulated column (steel or concrete) with the control trees, TFL manifolds, hydraulic well control package, accommodation, flare etc. on board. —Individual well monitoring prior to manifolding. —Remote control from the control platform. 4.4.6 CONAT Bilfunder & Berger, in cooperation with MAN and Tyssen, developed the CONAT (Concrete Articulated Tower) production system for water depths of 300–400 m. It is


179

built of reinforced concrete, also sharing the skirt pile principle which is said to simplify installation, ensure protection against sea bed erosion and provide a heavy duty base for the ball joint. The heart of the articulated tower unit is an assembly which consists of a central universal tie joint inside a 1-atmosphere chamber formed by a twin hemispherical shell, with one half sliding within the other and

FIG. 4.10. CONAT. allowing a movement of up to 20°. The weight of the column is taken by the outer shell bearing against the inner, supported by PTFE bearings and lubricated by a closed-circuit 100 bar oil flow system with ‘dry run’ capability. Access for maintenance personnel is provided inside the ball and a pneumatic sealing system with multiple inflatable seals provides security. The joint maintains the correct hemisphere clearance and prevents rotation. The joint has been tested in the North Sea and offers maintenance free operation with the opportunity for access should any attention be required.


180

CONAT designs come in several different forms, including the multi-column offshore production platform (OPP) which exploits the parallel linkage in order to keep the platform level as it moves sideways under the influence of waves, wind or current. CONAT is applicable to various offshore requirements including single point moorings and loading terminals, production towers, yoke towers for production tankers, and control towers. The permanent negative buoyancy maintains a downward force on the ball joint and this ensures that, even should the joint break, the tower cannot float away. 4.5 CONCEPTS FOR DEEPWATER As oil discoveries are made in ever deeper waters new systems to produce these fields are constantly being proposed. Obviously fields in very deep waters and in iceberg and icefloe infested areas may be very large by the standards of more hospitable areas and still be in the marginal category because of the technological developments required to produce them or because of the huge cost involved. There are currently many concepts in various stages of refinement for developing these fields. The following is a selection of some of them. 4.5.1 Floating Concrete Caisson Vessel The floating concrete caisson vessel incorporating drilling, producing, storage and offloading systems is one of the concepts for development of hydrocarbons in deep water. The concept has been developed by Exxon Production Research who claim to have established the feasability of the concept for application in water depths ranging between 300 and 1000 m. The vessel concept depicted in Fig. 4.11 is sized to process 13500 tonnes (100000 barrels) per day of oil with its associated gas and water. The vessel is designed to accommodate the drilling equipment employed on a modern deepwater drill ship, store 81000 tonnes (600000 barrels) of crude oil, and offload to a shuttle tanker. The caisson vessel has the very large load carrying capability required to accommodate all the drilling and production facilities. It also has a hull form that experiences minimal drilling or production down time caused by severe weather. Other advantages include (1) the ability to maintain subsurface equipment with vertical access tools launched from the caisson, (2) the presence of permanent workover rig capability on the caisson, and (3) independence of pipelines. This concept of a caisson vessel has a central shaft with a diameter of 39 m, a secondary shaft 62 m in diameter, and a base with a diameter of 98 m. The present design draft is 120.5 m with a freeboard of 37.5 m. Exxon propose to use a clustered well system with the caisson which


181

FIG. 4.11. Caisson vessel system. can be maintained using their SPS technology. Guidelines can be used in shallower waters but will not be used in 1000 m depths. Two risers provide the capability for simultaneous drilling and production. Sufficient clearance must be provided to prevent the risers from contacting each other. Design of the production riser and swivels is similar to current designs for a 1000 m SALM and production risers. 4.5.2 Floating Concrete Monotower This concept, which was developed by Gulf/Norwegian Contractors, is somewhat similar in concept to the Exxon caisson above. 4.5.3 Deepwater Gravity Tower/Deepwater Gamma Tower These towers are design concepts which have been developed by C.G. Doris. The gravity tower features a concrete floater with a tubular steel truss column supported by a laminated rubber ball joint on a piled base foundation.


182

FIG. 4.12. Doris deepwater gravity tower. In the gamma tower concept the concrete floater is replaced by steel buoyancy tanks, thus eliminating the need for a deepwater sheltered site for mating of the concrete to the steel jacket. The gamma tower is designed for areas like the Gulf of Mexico. Flexible piles have been incorporated in the gamma tower design as an alternative to the articulation on the fixed piled base which is specified for the deepwater gravity tower. The main characteristics from the preliminary design of a steel tower for 490 m water depth are summarised below:


183

FIG. 4.13. Doris gamma tower. Water depth

1600 ft (490 m)

Deck weight

15000 tonnes

Quantities Weight of buoyancy tanks

13800 tonnes

Weight of tower

27000 tonnes

Total steel weight

48800 tonnes

Solid ballast

28500 m3

Flexible piles

No.6 Dia. 42in Weight 3500 tonnes

Shear piles

No.18


184

Dia.92 in. Weight 3500 tonnes Extreme Environmental Conditions Wave

65 ft (19.8 m) 13.5 s

Wind (1 min.)

80 knots (41.2 m/s)

Current (surface)

2.6 knots (1.34 m/s)

The design includes six steel floatation tanks 110 m long and 12.5 m diameter. They are located inside the tower with the top end 20 m below the still water level. The steel tower is a hexagonal tubular truss frame with six main vertical legs on a 28 m radius. 4.5.4 T 300 Concrete Tripod Platform This is a platform concept which has been developed by Norwegian Contractors. It is considerably different from previous concrete platforms. The T 300 has a base tripod topped by a single monotower, The platform is being proposed for developing the Troll field in 340 m water depth in the Norwegian Trench. The Troll T 300 design would contain close to 750 000 tonnes of concrete and would float out with a displacement of 900000 tonnes and a draught of 225 m (see Fig. 4.14). 4.5.5 Tripod Tower Platform (TTP) This is a steel tripod concept which has been developed by Heerema/Aker. The structure is commendably simple, using a very large number of very large diameter structural members constructed using mild steel with low yield stress. A 15 m diameter central column is supported by three 8 m diameter inclined legs. There is little else to the structure. In the design which was proposed for the Troll field a horizontal bracing frame is added to aid inshore assembly. At location the structure is lowered onto a pre-installed driven pile foundation formed by four separate base pods interconnected by a frame. Each of the unstiffened tubular legs, which are 8 m diameter and 300 m long, would weigh 9500 tonnes. Altogether 85000 tonnes of steel would be used in a TTP for the Troll field, with another 20000 tonnes of piles. During tow out displacement would be about 150000 tonnes (see Fig. 4.14).


185

FIG. 4.14. T 300 and tripod tower platform Troll field versions. 4.6 EXTENDED WELL PRODUCTION TESTING Extended well test systems (EWT), for the extended flow testing of individual wells, have been used extensively in Brazil and Spain. The systems have produced up to 20000 b/d for up to one year without shutdown, albeit in calmer waters than North Sea conditions. The systems utilise proven and readily available equipment. The major advantage from the operator’s point of view is the additional reservoir and well productivity information which can only be obtained from extended testing of the reservoir. As discussed above the viability of marginal reservoirs is critically dependent on adequate knowledge of the reservoir and its production mechanism. However, in areas such as the North Sea, national authorities—who exercise a major degree of control through the licensing process—have traditionally considered that extended well testing should be limited to a period of less than 90 days, or about half a million barrels, in order to ensure that the overall recovery of a reservoir would not be affected by precipitate production. As a result extended well tests in the North Sea have been limited to satellite structures to fields which were already in production. There have been no stand alone extended well tests in the North Sea to date. This is likely to change in the near future as the fields under consideration get smaller, and less able to support a programme of delineation drilling. An extended well production test can be rapidly deployed: 25 to 30 weeks from commitment to proceed to start if production is feasible. A typical project schedule is shown in Table 4.12.


186

TABLE 4.12 Typical Extended Well Test Project Schedule Weeks 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Commit EWT system

×

Install process

×

Deliver subsea tree

×

Deliver mooring

×

Set SPM mooring

×

Well completion

×

Install loading hose

×

Moor tanker

×

Test system

×

Start production

×

TABLE 4.13 A List of Typical Equipment for an Extended Well Test Equipment

Availability (days)

1. Semi-sub drill rig

30

2. Subsea test tree with safety shut-in controls

45

3. Tubing to surface

30

4. Surface test tree

30

5. Manifold

45

6. Separator (15000 b/d)

45

7. Surge vessel

45

8. Pipeline

30

9. Gas burner

30

10. Safety shut-in control

30

11. Layout on drill rig

30

12. Tanker loading connection

30


187

13. Loading hose

45

14. Tanker SPM system

60

15. Tanker

40

FIG. 4.15. Extended well testing scheme. Source: Floatech. A list of typical equipment for an extended well test is shown in Table 4.13. A schematic of an extended well test system is shown in Figure 4.15. This information is based on an outline proposal by Sedco Inc. for an extended well production test for a North Sea location (September 1984), using the drill rig Sedco 704. The proposed period for operation of the system was from a minimum of one year to a maximum of five years. Additional wells could possibly be connected to the extended well test system to make it into an early production system. Extended Well Test Scenario 1. Prepare the semi-submersible for floating production. 2. Order flexible hose, tanker SPM mooring, packer, tubing and miscellaneous piping/valves. 3. Modify the rented production process equipment and subsea test tree. 4. Contract for tanker. 5. Install the rented process equipment and production safety equipment on the semisubmersible. 6. Fabricate tanker mooring system. 7. Install tanker mooring using work boats. 8. Anchor semi-submersible in position over existing producible wells. 9. Run BOP, connect and test.


188

10. Re-enter and complete the existing producible well. 11. Run/set/test subsea test tree and tubing to surface. 12. Perforate and test well. 13. During steps 5 through 12, complete the modification installation and testing of production equipment, and train the production crew. 14. During steps 8 through 12, complete the installation and testing of loading hose, and train the tanker crew. 15. After system check out, start production. 16. Flow well on a continuous basis and flare gas. Dispose of produced water into ocean after cleaning. 17. Flow directly to tanker moored 1.2 km from rig. 18. Use shuttle tankers from tanker mooring system to move oil to the market. 19. When sea states are projected to be 20 ft, tighten system and prepare for shutting in production wells. 20. When sea states reach 35 ft shut in production wells. Place on storm heading, release tanker and take tanker away from storm. When storm reaches 40 ft and is projected to 60 ft disconnect and pull riser and ride out storm. 22. Loading hose connected to tanker mooring buoy will ride out storm. 23. Tanker is reconnected when sea state drops to 15 ft 24. If waves reach 40 ft production riser is disconnected and pulled. Riser can be reconnected in 15 ft waves. 25. Reservoir information (bottom-hole pressure) etc. can be collected since vertical entry to the well is provided. 26. Additional wells can be added to the EWT system for reservoir testing or to increase field production during EWT system operations. 27. When the EWT system reaches economic limit, the entire facility can be removed. All the equipment can be reused. 28. If the economics of the field justify it, the EWT system can be converted to extend to fixed platform facilities.

Chapter 5 Construction and Operating History of North Sea Floating Production Systems INTRODUCTION Despite the fact that marginal field technology has been used extensively for many years (see Chapter 3) it is only comparatively recently that these systems have been used in North Sea type environments. As yet there is little operational experience of tension leg platforms (Hutton) or underwater manifold and control centres (Central Cormorant, NE Frigg). However, there are currently two floating production systems in the North Sea (Argyll and Buchan) which have been in production now for several years. It is worthwhile taking a fairly close look at the development and operating history of these two fields. Both fields illustrate the flexibility and adaptability of floating production systems and give a good insight into the phased development which is possible when using this type of technology. It is also instructive to look at how these systems have behaved in practice and the down time and reliability which has been experienced with these systems operating in North Sea conditions. 5.1 THE ARGYLL EXPERIENCE The Argyll field was discovered in 1971 in Blocks 30/24 and 30/25A, 190 miles south east of Aberdeen. The field has recoverable reserves of approximately 60 million bbl including the Duncan and East Duncan structures to the west of the main Argyll field. The field is situated in water depths of 76 m. Statistics relating to the Argyll field are shown in Table 5.1.

TABLE 5.1 Argyll Field Statistics Block:

30/24 UK North Sea

Operator:

Hamilton Oil Great Britain PLC

Partners:

28.8% 7.2%

Hamilton Oil Great Britain PLC Hamilton Brothers Petroleum (UK) Ltd

25.0%

RTZ Oil and Gas Ltd

12.5%

Blackfriars Oil Co. Ltd


2.5% 24.0% Discovery date:

August

190

Trans European Co. Ltd Texaco North Sea UK Ltd 1971 (Argyll) 1980 (Duncan)

Water depth:

76 m (250 ft)

Sea bed nature:

Clean sand

Reservoir depth:

2 743 m (9 052 ft) Zechstein and Rotliegendes

Recoverable reserves: (original)

55 mbbl (Argyll) 20 mbbl (Duncan)

Recovery factor:

20%

API gravity:

37°–38°

Gas/oil ratio:

300 scf/bbl

Sulphur content:

0.2%

Platform installations:

March 1975

Production start:

June 1975

Peak production:

43 000 (b/d) (1983)

Oil production in millions of tonnes:

2.4—from 1975 to end of 1977 0.7—1978 0.8—1979 0.8—1980 0.5—1981 1.0—1982 0.7—1983

Average gas flaring in 1983:

5 million cubic ft/day

The Argyll complex is interesting in that it has undergone a progression of significant modifications since its initial development. 5.1.1 First Stage of Development, 1975–1980 Because of the relative complexity of the Argyll geology, it was impossible to predict how the field would produce. Nor, in fact, were the full reserve potentials of the area established. These considerations led Hamilton Brothers to choose a test production facility for the initial

Construction and operating history of north sea floating production systems

191

FIG. 5.1. Argyll 1975–1980.——, flexible pipe; , rigid pipe. phase of development of the Argyll field. The programme was designed to place the field in production with minimum investment and to yield reservoir information required to determine future development policy. At the same time, this production test would yield sufficient revenue to assure profitable initial operation of the field. When Argyll came on stream estimated recoverable reserves were put at ‘between 10 million and 25 million barrels’ and its planned life was just five years. The system for the Argyll field stage I is shown in Fig. 5.1. Three subsea completions were initially connected by submarine flow-lines into a riser base system. Well fluids flowed by way of a subsea manifold through individual 4 in. nominal diameter lines in a production riser assembly, up to a gas-oil separation plant mounted on the deck of a semi-submersible rig. Separated gas was flared and the degassed crude pumped back to the sea bed through the 10 in. nominal diameter central riser member, then through a 7500 ft long, 10 in. submarine sales line. The 10 in. line was connected by a pipeline end manifold and 12 in. submarine hose which interfaced to a standard deepwater design CALM type SPM. Floating hose, tapering from 20 in. to 6 in. nominal bore, conveyed the crude from the SPM into export tankers for offloading at United Kingdom ports. The floating production facility was converted from the drilling rig (Transworld 58) into a production facility in a period of only six weeks. Some of the drilling equipment remained but drilling capability no longer existed after conversion. All available deck space was used for production equipment, separators, pumps, meters, etc. Plant layout was checked for weight and centre of gravity, so the vessel’s trim would not be adversely affected.


192

The gas/oil separation plant on the Transworld 58 was quite conventional. However, certain features were peculiar to this installation; vessels were insulated and heat traced to maintain a minimum operating temperature of 55°F at a designed maximum throughput of 70000 b/d. An inert gas generator provided the ability to purge the process vessels and pipework with an inert gas blanket whenever production was shut in. A special dual burner flare system with water spray cooling was developed to flare gas in normal service and burn off crude pumped out of the process plant in an emergency to achieve extreme storm survival status. The subsea trees incorporate a manual master valve that can be closed by a diver. The purpose of this valve is to give secondary closure of the tubing string in case of cutting in valve seats of automatic valves or to close the tubing for adjustments in the automatic system. The valves of the tree are designed to be diver replaceable. Above the manual valve is a hydraulically operated master valve and a similar wing valve. All hydraulically operated valves are opened and closed from the semi-submersible. These valves, like the downhole safety valve, are failsafe; they close if control pressure is released. Other valves in the system provide access to the annulus between the tubing and the casing. Three subsea wells (2, 3, 5) produced through the system from June 1975. Well number 6 was completed in 1976 giving four producers. Argyll was able to support an almost continuous programme of drilling and maintenance. The semi-submersible drill rig Ocean Kokuei conducted a long-term drilling programme of a few wells each year. As the early wells started to produce water, and oil production dwindled, a programme of recompleting wells in the less prolific reservoirs was undertaken. As further producing wells were discovered these were completed and tied into the Argyll manifold. Up to 7 satellite wells were producing at Argyll in the period prior to 1980. Of the seven wells currently producing only one of them was among the original four wells. All submarine flowlines laid in the Argyll field were initially heavy wall steel pipe with a coal tar/fibreglass coating incorporating a heavy duty woven outer wrap. Lines were laid directly on the sea bed without trenching or burial, since it was considered that self burial would occur because of the nature of the sea bed. However, in two separate incidents in 1981 two 3 km flowline bundles due to tie in a new satellite well sank during tow to the field from Scotland. The cause has never. been made public although it was widely rumoured to have been connected with the use of spiral welded carrier pipe. Since then, Hamilton has made extensive use of flexible pipe. The field shuttle tankers have been modified for self mooring and bow loading using a constant tension traction winch and 21 in. circumference nylon mooring line. Hoses are made fast for loading (after grappling the line) using Cam-Lock connectors. Mooring line and hose remain connected to the buoy when no tanker is on the SPM. The maintenance boat is not required to assist the tanker in mooring to the tanker loading buoy. There is a 4–5 day turn-around of the tanker leaving and returning to the buoy depending on the UK port of discharge. In January 1979, a crack developed in the subsea manifold in the 10 in. sales flowline pipe. The crack was located just below the upper frame in an area that prevented repair or replacement of the damaged pipe by divers. Apparently, the crack was caused by cyclical loads acting on the 10 in. flowline. Rig motions were transferred through the tensioning system and export riser to the riser connector on the manifold. The riser connector was supported on the manifold frame by a short 10 in. spool assembly which was bolted to the upper frame structure. These bolts


193

had loosened causing the 10 in. flowline below the upper frame to flex resulting in fatigue and ultimately a stress crack. A new manifold was designed by Sedco-Hamilton which was lighter and less complex than the original design. It was installed during the latter part of 1979. 5.1.2 The Duncan Development In 1980 the Duncan field was discovered 6 km to the west of Argyll, which necessitated the extension of the system to incorporate Duncan production. Initially the field was subjected to an extended production test from two satellite wells on Duncan. Production was via flexible flowlines to the Argyll manifold (see Fig. 5.2). Duncan reserves are currently estimated as being 18 million barrels. Phase I of the Duncan field development occurred in late 1983. It involved the installation of a large subsea base frame and manifold between the Duncan and Argyll fields, connecting four Duncan field producing wells to this manifold by subsea flowlines and transporting the

FIG. 5.2. 1980–1982 Argyll and Duncan production test.——, flexible pipe; , rigid pipe


194

FIG. 5.3. Autumn 1983: Duncan field development.——, flexible pipe; , rigid pipe. combined production stream by a subsea bulk line to the TW 58 production facility which was already processing Argyll crude (see Fig. 5.3). The Duncan manifold does not include a drilling template. Connection modules containing the valving systems, which control the flow of oil and water to and from the wells, are positioned around the manifold. They are designed as a single unit which can be installed or, if necessary, replaced by divers. Up to 23 modules can eventually be accommodated on the manifold. All maintenance on the manifold and wellheads will be undertaken by divers. All flowlines are flexible pipe. This was partly due to the thermal

TABLE 5.2 Statistics for the Drill Rig Deepsea Saga (prior to its Conversion to Production Platform Deepsea Pioneer) Construction

Built by Aker Group Bergen, Norway, 1974

Performance

Water depth:

1250 ft

Drilling depth:

25000 ft


Accommodation

90 persons

Helideck

84 ft diameter

Dimensions

Length:

355 ft

Breadth:

221 ft

Depth:

130 ft

Total variable load

2869 tonnes

Storage

Bulk mud and cement

8500cu. ft

Liquid mud

1280 bbl

Fuel

16326 bbl

Water for drilling

10200 bbl

Potable water

2300 bbl

Drilling equipment

195

National 1625 DE 3000 HP Pumps: 12-P-lbs Triplex Prime Movers: 4 Berger 8 800 hp Rotary Table: National C495 Derrick: EMSCO 160 ft

Cranes

2 No. National 52.5 tonnes @ 30 ft

Mooring

4 National E-500 Double Windlass 26000 lb Stevin Anchors

Positioning

Honeywell RS 505

Remarks

Self propelled

Source: Ocean Industry Directory of Marine Drill Rigs, September 1981.

insulation which can be incorporated into these lines, avoiding the necessity of burial and preventing oil becoming viscous during the numerous shutdowns which will be experienced. All operations are controlled hydraulically from the Argyll production platform. The flow-line and test line were added to the existing Argyll riser system. Duncan is currently (November 1984) producing from four wells; two further production wells and one water injection well are planned for 1985. 5.1.3 Third Stage of Development, 1985 Early in 1985 a new production support was installed on the field (see Tables 5.2 and 5.3). The newly converted semi-submersible Deepsea Pioneer is able to handle a peak output of 70000 b/d. In addition, the new facility has plant for injection of up to 60000 b/d of water at Duncan. As well as exchanging platforms at Argyll, the second and final


196

phase of work for Duncan called for installation of a new manifold (built by Merpro) beneath Deepsea Pioneer, and a flexible riser and flowlines for water injection. The modification of the Deepsea Pioneer for duties as a production installation included the following: —removal of mud pumps and tanks, —retention of derrick (needed for riser handling), —upgrading of safety systems, —upgrading of firewater systems, —installation of single separation train and oil water handling facilities,

TABLE 5.3 Argyll, Duncan (& Innes) Major Contractors Project services

Engineering: Bechtel

Platform

Design:

Kerr McGee Corporation

Contractors: Dover Oil & Gas, Aberdeen (TW 58) Conversion: Wilson Walton, Teesside (TW 58) Peterhead Engineering at Invergordon Service Base (Deepsea Pioneer) Loading buoy

CALM Buoy by SBM Inc. Modified, SBM Rotterdam, installed at Argyll October 1982.

Source: Scottish Petroleum Annual, 1975.


197

FIG. 5.4. Summer 1984; installation of new manifold.——, flexible pipe; , rigid pipe. —installation of two gas turbines for power generation, —installation of gas lift package, —installation of flare on top of derrick, —installation of side flare booms for oil disposal. Heating and ventilation requirements were kept to a minimum by keeping equipment out on deck in the open. Over 600 tonnes of redundant material was removed prior to the installation of the process equipment. The Deepsea Pioneer, with additional generating equipment, gas lift and water injection equipment will have 85–90 people permanently on board. (See Fig. 5.6 for an isometric view of the Deepsea Pioneer production facilities.) Facilities on Deepsea Pioneer were arranged so that gas lift equipment could be installed at a later date to enhance flow from Argyll. The gas lift package was installed on the Deepsea Pioneer at the end of May 1985. The finished gas lift module was 6.7 m×12 m×3.6 m high and weighed less than 150 tonnes.


198

FIG. 5.5. Autumn 1984; water injection added.——, flexible pipe; , rigid pipe. The total shut-down time associated with the installation of the gas lift facility was days to make the main process tie-ins and 19 hours when the process trains were shut down during installation of the compression unit. 5.1.4 Fourth Stage of Development—Innes The Innes field is located 11 km north-west of Argyll in Block 30/24. The field was discovered in 1983 when well 30/24–24 tested 9600 b/d oil from the reservoir. A step-out well east of the discovery was water productive, thus establishing that the oil accumulation is very small. Based on results of a second production test on well 30/24– 24 conducted in the spring of 1984, oil reserves were determined to be considerably lower than Duncan. Due to the availability of the Transworld 58, which was replaced by the Deepsea Pioneer at Argyll and Duncan, development of this small reservoir was deemed feasible. In the summer of 1984 a one well development proposal was submitted to the Department of Energy for their approval. The development plan proposed the use of the Transworld 58 after a rapid refit as a floating production facility for the field. The Transworld 58 refit included new flare booms, new product crude pumps and upgrading of the fire and gas detection/protection systems. The single discovery well will be used for production, with TW58 anchored directly over it and connected by a new riser system.


199

A special riser arrangement, attaching it directly to the subsea tree, was adopted at Innes. This involves a frame-to-transfer

FIG. 5.6. Layout of floating productions platform Deepsea Pioneer. 1, flare tip; 2, turbine control units (inside box girder); 3, instrument air package; 4, deaeration tower; 5, VAC skid; 6, LPKO drum; 7, HPKO drum; 8, control room; 9, AFFF package; 10, chemical injection skid; 11, fuel pods; 12, access and laydown area; 13, diving equipment and laydown area; 14, oily water separator; 15, combined metering unit and prover unit; 16, test separator 1 st stage separator; 17, 2nd stage separator and surge tank; 18, fuel


200

gas skid KO drum, heater and filter separator; 19, power generator; 20, lubrication oil cooler; 21, seawater injection pumps; 22, seawater lift pumps A and S; 23, firewater pumps; 24, firewater pumps day tank and air compressor; 25, existing emergency generator; 26, laydown area; 27, batteries and chargers; 28, existing diesel tank; 29, diesel oil filter coalescer unit; 30, pilot house; 31, coarse and fine filter units; 32, (future) gas lift compressors; 33, riser laydown area; 34, pipe rack; 35, export pumps; 36, helideck with accommodation under; 37, hypochlorite injection package; 38, crude dosing package.

FIG. 5.7. 1985-Argyll, Duncan, Innes.——, flexible pipe;. , rigid pipe.


201

riser stressed from the top of the tree to the wellhead below, avoiding the need for a separate base to handle the riser. Further wells may be possible at Innes although no decision has yet been made. The oil will be processed by TW 58, and then piped via a 6 in. coflexip line, to the Argyll manifold where it will go straight on to the loading buoy (see Fig. 5.7). 5.1.5 The Argyll Continuity of Production Table 5.4 summarises TW 58’s operating history at Argyll. The major influence on output is the ability of tankers to moor and load at the SBM. A high number of shut-downs does not necessarily mean poor productivity since the shut-downs may be very short. Waiting on weather typically accounts for around one-quarter of annual down time (see Fig. 5.8). Significant major one-off events have included repairs to the platform in 1978 and 1980/1981 and to the SBM in 1978/1979, and SBM faults generally which have caused at least a third of all down time in several years. Early in 1978 the platform came into Highland Fabricators dry dock at Nigg for repairs following discovery of a propagating crack in a hull weld. Production was broken for seven weeks. In November 1981 another seven week break in production was started when a weak link in one of the rig’s twelve anchor chains failed

TABLE 5.4 Argyll Production History Year

1978

1979

1980

1981

1982

1983

1984

Total down time (days)

39

33

33

49

34

25

(22)

Occasions riser pulled

6

3

5

4

6

4

(1)

19

16

22

21

17

38

(14)

Occasions loading shut-down Source: Offshore Engineer.


202

FIG. 5.8. Monthly output as a percentage of maximum monthly output for North Sea offshore loading systems (1983). Source: H.Pass. Foster Wheeler. during a storm close to design conditions, triggering progressive failure of the rest of the mooring pattern and a two day drift ending 40 km to the south-east. 5.2 THE BUCHAN EXPERIENCE The Buchan field was discovered in 1974 in a deep reservoir 154 km east-north-east of Aberdeen. The reservoir is a very dense fractured sandstone with recoverable reserves of over 50 million barrels, by conventional


203

TABLE 5.5 Buchan Field Statistics Block

21/1A UK North Sea. Also extending into Block No. 20/5A which is 100% licenced by Texaco North Sea UK Ltd.

Operator

BP Petroleum Development Ltd

Partners

24.58% BP Petroleum Development Ltd 12.71% Transworld Petroleum (UK) Ltd 5.76% Tricentrol Oil Corp. PLC 4.54% Goal Petroleum PLC 12.71% Clyde Petroleum PLC 12.71% Sulpetro (UK) Ltd 4.14% Charterhall Oil Ltd 0.90% Lochiel Exploration Ltd 12.71% Charterhouse 9.23% Texaco

Discovery date

August 1974. BP became operator on the Block in May 1977.

Water depth

118 m (390 ft)

Sea bed

Thin varying sand

Reservoir depths

2 900 m (9 600 ft) 3 200 m (10 500 ft)

Recoverable reserves (original)

58 million barrels (original) 29 million barrels (remaining) (31/12/83)

Recovery factor

10–30%

API gravity

33.5°

Gas/oil ratio

300 scf/bbl

Sulphur content

0.8%

Platform installation

September 1980

Production start

May 1981

Peak production

47 000 b/d

Oil production, in millions of tonnes

0.9—1981, 1.4—1982, 1.6—1983

Average gas flaring in 1983

9 million cubic feet/day

Source: BP


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TABLE 5.6 The Buchan Installations Platform (Light) displacement

13000 tonnes

Overall height

94.3 m

Drill deck to base of pontoons

45.5 m

Lower deck to base of pontoons

34.8 m

Normal draught

20.22 m

Survival draught

18 m

Operational displacement

19.404 tonnes

Deck area

2 326 m

Pontoon size

22 m dia.×7.5 m deep

Anchors Number of anchors

10

Length of mooring wires

3400 m

Diameter of wires

70 mm

Min. breaking load (new)

340 tonnes

Subsea Height of wellhead

10.3 m

Dimension of template

17.8×14.8 m

Distance of template to wells

1.6 km

B7 and B8 B4

2.5 km

CALM buoy Distance from platform

1.67 km

Length of underbuoy hose

128 m

Height of buoy

4.57 m

Diameter

15 m

Displacement

506 tonnes

Number of anchors

6

Length of anchor chains

400 m

Length of mooring hawser

69 m


205

Tankers Length

271 m

Dead weight

100700 tons

Capacity

76000 tonnes

Source: BP

methods, plus an additional 8–10 million barrels by gas lift. The field is situated in water depths of 112–118 m (see Tables 5.5–5.7). The key factors which influenced the development for Buchan were the complexity of the field’s geology, the relatively small amount of recoverable oil, the high probability that the field would have a relatively short life-span, and the requirement to commence production as quickly as

TABLE 5.7 Buchan Major Contractors Project services

Matthew Hall D&S Petroleum Consultants Worley Engineers Ltd

Platform

Design—semi-sub Drillmaster, Pentagone design Conversion—Lewis Offshore, Stornaway Modification for gas lift—Howard Doris, Loch Kishorn

Template

Design and fabrication—William Press Production Systems

CALM

Design and fabrication and installation—Press IMODCO/Comex Houlder

Topsides

Design—Matthew Hall Fabrication—Aker etc.

Steel

BSC

Installation

Template—Wharton Williams Flowlines—Santa Fe Marine Operations

Hookup/commissioning

Aker Offshore Contracting, BP

Production services

Sedco Hamilton Production Services

Source: Scottish Petroleum Annual, 1985.

possible. There were only two realistic options to be considered. First, the conventional method of a fixed production platform with wells drilled after installation. Second, a floating production platform with subsea wells drilled before the arrival of the platform. The second method had the advantage of low construction costs, of being able to go into production as soon as the platform was on station and, at the end of the field’s life, low abandonment costs.


206

The other major choice was in the method of transporting the oil from the field. Again there were only two real options: first, a pipeline connection from Buchan to the Forties pipeline system 46 km away or, second, an offshore tanker loading system. Cost was the determining factor in this choice and the tanker system was selected. The development comprises the following installations: —A floating oil production platform converted from Pentagone design semi-submersible exploration rig. —A production/export riser system to carry the oil to and from the platform consisting of one 12 in. export riser surrounded by eight

FIG. 5.9. Buchan field. 4 in. production risers and two 4 in. service risers, the whole bundle to be supported from the platform by an adjustable tensioning system to prevent buckling. (See Chapter 2 for details of the riser system.) —Seven producing subsea wells, six drilled through a steel template measuring 8×15 m, and one satellite well 1.6 km from the template. An eighth well completed in 1980, 2.5 km to the west in block 20/5A. —Two 4 in. flowlines and associated hydraulic control umbilicals connecting each satellite well to the template. One of the flowlines to carry oil and associated gas, the second to carry lift gas at a later date. The umbilicals to operate the wellhead valves. —A subsea manifold on the template linking the flowlines to the riser system. —A 15 m diameter catenary anchor leg mooring (CALM) buoy.


207

—A 12 in. submarine pipeline, 1.9 km long from the manifold on the template to the pipeline end manifold (PLEM) under the CALM buoy. The PLEM is connected to the buoy by a flexible hose. —Two 100000 ton tankers, especially modified for bow loading and dedicated solely to off-loading from the field. Tankers moored to the CALM buoy by a 21 in. diameter hawser. Oil loaded through a 12 in. floating hose. 5.2.1 Buchan Alpha A semi-submersible Pentagone design drilling rig, Drillmaster, was selected for conversion to the production platform on the criteria of stability, load capacity and available space. The conversion was scheduled to take eleven months and involved installing a gas/oil separation plant, two flare booms, an oil/water treatment plant, handling and tensioning systems for the production riser and a wireline riser, a metering skid for crude oil measurement, full saturation diving facilities and provision for the eventual installation of gas lift facilities. For various reasons, the conversion proved to be more complex and involved more extensive rebuilding than had been anticipated. The condition of the existing utility systems aboard Drillmaster, such as fire mains, cooling water, compressed air and the ballasting system, was found to be unsatisfactory which meant unplanned upgrading was required. Statutory regulations had changed since Drillmaster had been built and extensive modifications were required. The semi-submersible turned out to be 100 tonnes heavier than had been originally calculated, which meant equipment had to be moved or removed. The integrated Pentagone design made such changes difficult and in some cases involved cutting through decks and bulkheads. All of these factors caused delays and increased costs. To add to these complications, an extra two months delay and additional expenditure of £8 million were incurred as a direct result of the disaster which struck a rig of identical design, the Alexander Keilland. An extensive independent structural review led to a large amount of non-destructive testing of the structure and a number of minor modifications to the sub-structure. 5.2.2 The CALM Buoy and Subsea Installations The buoy was designed, fabricated and installed by Press-Imodco Offshore Terminals Ltd. It was the largest of its type ever produced, measuring 15 m diameter with chains 400 m long. The buoy is connected to the export line manifold by means of a flexible hose, of the ‘Lazy S’ design, with a buoyancy tank 21 m above the sea bed. 5.2.3 Process and Export Systems Oil and gas from the wells pass through a three-stage separation process. Water and gas are separated from the crude oil, the separated water passing through an effluent control system before being discharged overboard. All the gas produced is either flared or (from 1985) used for gas lift. Power generation is by diesel generators.


208

Cooled, processed oil from Buchan Alpha is delivered to a tanker via the export riser to the export pipeline, through the pipeline end manifold (PLEM) and underbuoy hose to the CALM buoy, and via a floating hose to the moored tanker. The specially modified tankers are fitted with SPM mooring equipment and bow loading units. Loading at the maximum rate of 70 000 b/d, it would take a week to fill each of the 100 700 ton tankers (their capacity is reduced to 76 000 tonnes by their having segregated ballast tanks to eliminate the risk of pollution from discharge of oily ballast water). A converted anchor handling tug/supply vessel is on station to provide marine support, CALM buoy access for maintenance and the statutory safety/standby role. 5.2.4 Production History In general the system has operated well. There were fears that the riser system would pose problems due to its complex nature but this has not proved to be so. In practice BP shut down production and recover the production risers on a deteriorating forecast of wind and sea conditions of worse than 35–40 knots and of seas up to 12 m maximum. The export riser is not unlatched, in practice, until the platform heave reaches 5 m. However, reconnection may not start until heave is less than 0.5 m. During the first years of operation BP pulled the production riser five times due to adverse weather and the export riser only once. The platform itself has proved to be even more stable than was predicted. The anchor pattern and winching system has been able to keep the platform in position even in severe and winds gusting to 111 weather. In November 1981, in a storm with seas at knots, the maximum tension on the windward winches was 66 tonnes. The buoy has contributed rather more to lost time, especially in the early life of the system. Routine maintenance or replacement of worn parts can only be carried out in seas of 2 m or less, which are relatively rare in winter. Therefore, considerable care and judgement has to be used in deciding the timing of maintenance work, and the need to improve the reliability of critical components is emphasised. During the first year (May 1981–May 1982) the field was in production for 52% of the time as against the 67% which had been predicted. In the second year the field was in production 51% of the time. These figures are to some extent distorted by shutdowns for buoy repairs during January/February 1982 and for weather effects on wireline works in December 1982 and January 1983. If these periods are discounted the efficiency improves to the high fifties for the two years. BP say that the best they can expect to achieve from the existing system is about 62%– 63% operational efficiency, i.e. a maximum of up to 90% during June, July and August and 45% during December, January and February. Figure 5.8 clearly shows the susceptability of loading buoys to weather down time in North Sea environments and supports BP’s opinion that if they were designing the Buchan field again they would probably opt for a pipeline export system.

Chapter 6 Marginal Field Economics and Costs No review of marginal field technology would be complete without some discussion of the costs of the various development options. In this chapter we intend to review the question of capital and operating expenditures for small oil accumulations (i.e. 50–100 million barrels recoverable reserves) in a North Sea type environment, in water depths between 70 m and 150 m and with a production potential of up to 60000 b/d. The options for offshore development, as discussed in the earlier chapters, are well known to the industry; in terms of cost they fall broadly into the following order of decreasing cost. —Multi-platform development using fixed platforms with export via pipeline to shore. —Single fixed platform with export via pipeline to shore. —Single fixed platform with offshore loading. —A mobile platform with offshore loading or pipeline to shore. —A satellite to an existing production complex, developed by one of the following options: a. satellite developed with fixed platform, b. satellite developed with mobile platform, c. satellite developed with subsea system. The satellite option is currently the most common method of development of North Sea marginals. Once the field development option has been fixed the operators must look for the potential in cutting costs wherever possible within that option. Clearly no operator wishes to go to a level of expense greater than required. The need for more expensive equipment results from environmental limitations, the recovery of more oil, or the recovery of reserves at a faster rate. Fortunately for operators, the decision to follow a particular development option is not difficult. The value of a pipeline to shore versus offshore loading or the development of a field with one or two platforms is normally fairly clear. Only when new technology is considered as a possible solution to the problem are the decisions not quite so easy. While the figures presented in this chapter have relevance to all the options presented above we intend to concentrate on the mobile platform with offshore loading or a pipeline to shore. Such a system, using a mobile semi-submersible production platform or tanker and subsea completions, defines relatively clearly the smallest economic field that can be developed in isolation from existing installations (i.e. not as a satellite). Before looking at costs in detail it is worth emphasising that the figures here are all in mid-1985 US dollars unless otherwise indicated. They have been compiled from a variety of industry sources—contractors, designers and oil companies.


210

6.1 COST PARAMETERS: THEIR RELATIVE IMPORTANCE AND THEIR SENSITIVITY 6.1.1 Uncertainties Uncertainty is the great enemy of marginal field developments. Uncertainties occur in the area of costs and in the type and level of reserves and productivity. Despite industry’s determination to use proven technology where possible, the operator of a marginal offshore field will expect to break some new technological ground. Such pioneer work can be expected to be associated with some cost over-run. It is reflected in the statistics of the early North Sea developments where dramatic capital cost over-runs were commonplace (see Tables 6.1 and 6.2). Such levels of over-expenditure cannot be tolerated in a marginal field development, nor indeed should they be expected on quite that scale. Likewise the degree of confidence in recoverable reserves and productivity levels is more critical in a marginal field than in larger and more profitable fields. This can create a problem since it is difficult to justify costly delineation drilling and data collection on a reservoir which is clearly in the marginal category.

TABLE 6.1 Cost Increases (excluding Drilling) for Some Early North Sea Developments Projects

Date

Start estimate £000000

Costs £000000

Cost increase

Forties

May 1972

296

715

142%

Brent

July 1973

148

1140

670%

Sept. 1974

(393)

Beryl

Early 1973

70

161

130%

Ninian

Sept. 1975

585

1048

82%

Buchan

June 1977

129.7

March 1978

(135)

225

(66%)

1228

3289

168%

Sum (incl. first est. for Brent)

(190%)

73%

Source: SINTEF. Note: numbers in parentheses refer to revised cost eStimates. These major cost increases were due in large measure to the innovative developments which were required by the harsh North Sea environment. Project cost increases of this magnitude are not unexpected when innovative technology is being developed. Such cost increases would be currently quite exceptional in the North Sea. Indeed several of the largest recent projects have been completed on schedule and within budget. Innovative technological developments for marginal field applications would be expected to experience some cost over-runs initially.

Marginal field economics and costs

211

TABLE 6.2 Major Causes of Cost Increases Based on Cost Analysis of North Sea Oil and Gas Developments in the Early 1970 s Carried Out by SINTEF for Norwegian Petroleum Directorate 6.

Weakness in project execution

5.

Increased operator requirements

4.

New government requirements

3.

Unforeseen inflation

2.

Under estimation

1.

Start estimate

6.1.2 Recoverable Reserves One of the most striking features of marginal field economics is the necessity for a very high production-to-reserves ratio to enable rapid depletion of the field. If the volume of reserves and the levels of production can be relied on, then this characteristic is not necessarily a problem. The difficulty, however, is that, at a low level of reserves, the definition of reserve size must be expected to be poor. In any reservoir the major uncertainties lie at the periphery of the reserve. In a marginal reserve this peripheral area is almost always a relatively large fraction of the total. The limited number of delineation wells also prevents an understanding of lithological and stratigraphic trends in the vicinity of the reserve. This general uncertainty increases the down-side risk (the danger of less reserves or low rates of extraction) with a consequent reduction in expected rate of return. Thus it is vital for an operator to have an accurate prediction of the productivity of the wells and, in particular, the ability of the field to attain the required level of production in the early years of its life. In order to achieve this the operator requires a good understanding of the reservoir drive mechanisms and the need for artificial lift and secondary recovery. Well productivity should properly be established by means of a well testing and logging programme, not by drilling a multitude of wells. Only if severe changes in well productivity are expected over the relatively small area of a marginal field can drilling to establish well productivity


212

TABLE 6.3 Budget Estimate of Rental While Operating Item

$/day 38000a

Rig w/people Process equipment

2700

Subsea tree

500

Tanker and mooring

9300

System maintenance

3000

Miscellaneous

1500 Total

$55000

Note: Operator to provide boats/helicopter/fuel/well maintenance etc. during producing stage. Excludes rig time for well completion costs and based on rental, test tree and production process equipment. a Based on North Sea labour costs. Source: Sedco Inc.

be justified. The costs of logging, coring and production testing is always minimal when field development decisions are to be made. Thus thorough programmes for well data acquisition are normally undertaken as a matter of policy by operators. There are, however, particular cases where not only is productivity a problem but where recovery factors are in doubt or where reservoir limits are best established by an extended well test. Operation costs for an extended production test facility are considered in Tables 6.3 and 6.4. On the basis of the figures projected for such a scheme a sustained production of as little as 3000 b/d could be self financing on a day-to-day basis. Thus many uncertainties associated with recovery factors and productivity could be resolved at little cost beyond the delineation well. A disadvantage could be a delay in field development due to the extended test itself. The most promising route for reducing capital costs significantly would probably involve the use of floating production/storage/export facilities instead of separate semisubmersible production and floating storage units. As discussed in Chapter 3 this method of production is not currently operational in North Sea type environmental conditions. However, the technology is available and floating production/storage facilities will be available shortly for North Sea duties. 6.2 COST ELEMENTS FOR MARGINAL FIELD PRODUCTION SYSTEMS


213

In attempting to indicate orders of costs for different offshore developments, naturally it is necessary to specify the exact development type proposed. As indicated earlier each development is field specific and is dependent on such physical parameters as:

TABLE 6.4 Budget Estimate of Capital Investment Item A.

Prepare rig for process equipment and subsea test tree Equipment mobilisation

500 000

Rental services

100 000

Pipe/valves

40 000

Miscellaneous equipment

100 000

Labour

100 000

Safety gear

80 000

Miscellaneous contingency

80 000 Subtotal

B.

$

$1 000 000

Tanker loading equipment Loading hose

$1 000 000

Tanker mooring

600 000

Tanker modifications

100 000 $1 700 000

C.

System abandonment

$1 000 000 Total capital

$3 700 000

Note: Excluding rig time and well completion costs and based on rental, test tree and production process equipment. Source: Sedco Inc.

—the exact geological formation, size, structure, composition and depth, —total recoverable reserves, —reservoir drive mechanism, —oil/gas ratio and hydrocarbon composition, —ater depth and environmental criteria, —istance from shore, as well as the various economic uncertainties such as changes in the real price of oil, the inflation rate to be assumed, interest rates etc. Therefore it is futile to project general costs for development of a particular size or type of reservoir. In order to indicate orders of costs for various development schemes,


214

the costs of each separate element is provided. By selecting the required options for a field scenario and summing this, a total cost can be derived. In any offshore development the main capital expenditure elements are: —drilling and completion of production and injection wells, —flowlines, subsea template, manifold and riser, —offshore production facility with associated equipment, —export system, —dismantling costs at end of field life. The other main cost element for any offshore development is the annual operating expenditure. Let us now consider each of these costs in turn.

TABLE 6.5 Drilling and Completion Unit Costs Item

Unit costs ($)

Template tree

0.7–1.0 m

Satellite tree

0.9–1.2 m

6 well template

7.0–11 m

10 well template

9.0–13 m

20 well template

16–20 m

8 bore rigid riser

3.0 m

20 bore rigid riser

5.0 m

8 bore flexible riser

2.0 m

20 bore flexible riser

4.0 m

Wellhead (18 3/4 in.×10 000 psi)

0.3–0.5 m

Control system

4.0–6.0 m

Workover system

2.0–4.0 m

Drilling cost (45–60 days per well)

60 000–75 000 per day

6.2.1 Drilling and Associated Costs Costs for drilling and completion of deviated wells from floating production units vary in proportion to the number of days required to drill each well. This in turn is dependent on the depth of reservoir and the amount of deviation required. If a number of wells are required the drilling and associated costs could be a significant percentage of the total cost of an offshore development. See Table 6.5 for drilling and completion unit costs.


215

6.2.2 Cost of Production Support and Associated Equipment There are two options open to a developer when faced with a decision on the type of production support to be employed. Option Go for a purpose-built, latest generation of production supports of the type described in 1 Chapter 4. Option Purchase outright or lease an existing drilling unit and convert it for production? 2 Alternatively it may be possible to acquire an existing unit which has already been converted for production.

Let us now consider the cost implications of each option. Option 1: Build a New Generation Production Unit The following are costs and construction periods for some possible production supports. See Chapter 4 for typical performance details of these units. —SWOPS: The fabrication contract for this vessel was awarded to the Harland & Wolff shipyard in August 1984. The reported construction cost is £70–75 m with a further £40 m expected for subcontracted subsea equipment. —Petrojarl Production Test Ship: The reported construction cost of this vessel was £52 m (sterling, 1985). It is interesting that it was built as a speculative venture. The vessel did not have a definite work programme when the construction contract was placed. The reported day rate is approximately $85 000/day. —Highlander 6000: The cost of construction is estimated at £100 m (1985) excluding risers, subsea manifold and some mooring. Construction period from order to completion—21 months. —IMFP 300: The cost of construction is estimated at £80 m (1985) excluding the flexible risers and subsea equipment. —Floating Oilpatch: The cost of construction is estimated at £92 million (1984) including flexible risers and subsea tower and manifold. Construction period from order to completion—17 months. —TAPS System: The cost of construction is estimated at £220 million. Construction period from order to completion—26 months. —GVA 5000: The cost of construction is $80 m, approximately. Option 2: Convert an Existing Drill Unit A newly built harsh environment jack-up drilling unit (e.g. Rowan ‘Gorilla’ class) costs approximately $65 million to build. Current (mid-1985) day rates for these units are about $40 000. Older jack-up units have restricted available deck load capacity and water depth capability. Jack-up units, generally, have low fatigue endurance when considered for a semi-permanent production function. A newly built third generation semi-submersible (e.g. GVA 5000) costs approximately $80 m to build. Current (mid-1985) day rates for these units is about $50 000. Older


216

semi-submersible drilling units, with their more restricted deck load capacity and less stable motion characteristics, are obviously considerably cheaper to purchase or lease. The drill rig Deepsea Saga, an Aker H3 design built in 1976, was purchased in 1983 by Hamilton Bros Oil & Gas Ltd for production duty on the Argyll field (See Chapter 5) for a reported £19 million. Order of magnitude costs for the production and process equipment and for power generating equipment for installation on the drill unit are shown below. Clearly these costs are closely related to the amount of processing required, the reservoir parameters, power requirements for water injection and the suitability of the associated gas for power generation. Whether new equipment for power generation, life saving, safety, flare, utilities, etc. is required will depend on the age and condition of the equipment which is already installed on the unit. The Transworld 58 (Innes field) and Buchan Alpha (Buchan field) production units still use their original diesel generating equipment. A typical SPM arrangement for harsh environments would consist of (1) an export line from the production unit to the SPM; (2) one of the following SPM options: a CALM buoy, a SALM, an ELSBM, a SPAR or an ALP; (3) a shuttle tanker arrangement to transport the stabilised crude to shore. Unit costs for each of these items are given in Table 6.7. The Deepsea Pioneer (Argyll field) production unit had new gas turbines installed. The gas lift package installed on Argyll in June 1985 cost a reported £5 m. See Table 6.6 for process and power equipment estimating costs. Modification costs are notoriously difficult to predict despite the considerable numbers of units which have already undergone conversion. Cost over-runs are generally not due to the new process or generating equipment; they relate principally to the difficulties which are encountered if the rig is not exactly as shown on drawings etc. or if the condition of part of the structure or equipment requires unforeseen alterations to be undertaken. Modification costs and durations can be

TABLE 6.6 Process and Power Equipment Costs Throughput (b/d)

Production equipment ($ million)

Generating equipment if required ($ million)

20000

18.0

5.0

30 000

25.0

9.0

60000

39.0

14.0

optimised by careful selection of the rig in terms of rig power, variable deck load and deck arrangement. —Sedco Hamilton, who designed the conversion of the drill rig Transworld 58 for use on the Argyll field, claimed that the installation of the modularised process equipment on the units’ deck, in 1975, took only six weeks.


217

—The conversion of the drill rig Drillmaster for the Buchan field took 22 months (see Chapter 5). However, that conversion included several major delays that would not be typical or expected. —The conversion of the drill rig Deepsea Saga for use on the Argyll field took six months during 1984. This timescale would be considered to be a realistic estimate for most conversions. —The cost of installation of gas lift on Buchan Alpha, plus inspection and maintenance of that Pentagone semi-submersible, cost a reported £11.8 m in April 1985. Costs of towage to site and installation costs depend on distance and duration of tow as well as any special installation operations which may be required. Transworld 58, Buchan Alpha and Deepsea Pioneer employ a conventional and unmodified anchorage system. Many of the newer

TABLE 6.7 Unit Costs for Typical SPM Options in Harsh Environments 10 in. Export line to SPM Item

Cost ($000)

Cost of line

66/km

Lay cost

154/km

Survey

45

Umbilical

300

CALM buoy Item

Cost ($million)

Buoy

6

Install

5

Piled anchorage (if required)

4

Note: Piled anchorages are not employed in the Argyll or Buchan fields.

designs (see Chapter 4) provide for piled anchorages which would be considerably more expensive to install. 6.2.3 The Export System The options for offshore export systems are either a separate pipeline to shore, or to connect into an existing pipeline, or to use a single point mooring system (SPM) as described in Chapter 2. SALM


218

SALM for operation in a North Sea type environment would be dependent on the size of tanker and water depth. See the description of the Fulmar SALM in Chapter 2. Costs would be of the order of $60–$80 m/unit for a Fulmar type SALM/yoke installed. A Thistle type SALM would cost $20–$25 m installed. ELSBM and SPAR These units are large, complex and site specific (see Chapter 2). Their costs would be in the order of $35–$50 m for an ELSBM and $85–$115 m for a SPAR installed, depending on storage capacity. ALP Articulated loading platforms are large steel or concrete units (see Chapter 2) which are site specific. Cost estimates for these units would be of the order of $60–$80 m. Shuttle Tankers The size and type of tanker employed would depend on —daily production rate, —time to shuttle to and from offloading points, —environmental conditions at the SPM. The number of tankers employed will depend on the type of SPM used. Two dedicated shuttle tankers are normally used for CALM, SALM, ELSBM and ALP type offloading systems. A single tanker can be used for SPAR and SALM/yoke type systems. The options are to refurbish existing tankers or build new vessels. Cost of refurbishment, survey and adapt for shuttle duties would depend on the conditions of vessels purchased. Assume a five-year-old vessel costing $6–$7.5 m plus $2.2 m conversion costs.

FIG. 6.1. Pipeline diameter versus oil throughput.


219

6.2.4 Pipeline Size and Unit Costs The variation of pipeline diameters with crude oil throughput is graphed on Fig. 6.1. Typical pipeline requirements for various oilfield developments in North Sea type environments are shown in Table 6.8 with associated procurement and installation costs. 6.2.5 Decommissioning and Abandonment Costs Platform abandonment costs are still relatively unknown and any estimate of costs involved is necessarily very tentative at this stage as national and international regulations, governing the requirements for field abandonment, still remain to be drafted in many instances. The projected costs associated with the complete removal of fixed platforms have been projected by the Oil Industry International Exploration and

TABLE 6.8 Pipeline Size and Unit Cost Estimation Field reserves Peak oil Pipeline (millions of bbl flows internal dia. of oil) (b/d) (in.)

Pipeline costs, procurement, installation ($/inch mile)

Pipeline costs, procurement, installation ($/mile)

25

15 000

8.0

140 000

1 120 000

50

20 000

12.0

140 000

1 680 000

150

50 000

18.0

140 000

2 520 000

300

120 000

26.0

140 000

3 640 000

600

170 000

30.0

140 000

4 200 000

TABLE 6.9 Projected Cost of Complete Removal of Fixed Platforms Water depth (m)

Average cost ($m, 1983) Mild environment

Severe environment

0–40

1–4

8

40–75

1–4

20

75–150

180

150–250

N/A

200

250

75

N/A

Source: E&P Forum—Paper OTC 5076, 1985.


220

Production (E & P) Forum, as shown in Table 6.9. The cost of decommissioning marginal field developments will clearly be considerably less than that of removing fixed platforms—a considerable advantage when considering marginal field economics. A marginal field abandonment operation would involve the following activities: —abandon and decommission each well, —abandon the riser system, —abandon the mooring system, —abandon the flowlines, umbilicals, templates etc. The unit costs for these operations are suggested in Table 6.10. 6.2.6 Field Operating Costs Operating costs for a marginal offshore oilfield include the following items, in their approximate order of importance: —maintenance of the production platform, —maintenance of the SPM and riser, —personnel costs, —diving costs, —insurance, —helicopters, —supply vessels, standby vessels/anchor handling vessel, —fuel and chemicals, —well maintenance and workovers, —shore base costs. As a rule of thumb, annual offshore field operating costs are generally

TABLE 6.10 Well Abandonment Costs, Per Well Item

Cost

Semi-submersible, 20 days, $60 000/day

$1.20 m

Semi-submersible, 6 days weather down time, $60 000/day

$0.36 m

Semi-submersible, 3 days transit time, $60 000/day

$0.18 m

Materials (mud, cement, chemicals, etc.)

$0.15 m

Contingencies

$0.11 m

Total per well

$2.00 m

Other Field Abandonment Costs Item Abandon flexible riser system

Cost $0.6 m


221

Abandon moorings and tendons

$3.0 m

Abandon flowlines, umbilicals and template

$3.0 m

Abandon SPM and pipework

$3.0 m

Contingency and bargework

$3.0 m

10%–12% of the field development costs, excluding the export system. However, this may not be the most appropriate approach for a floating production system. An alternative, showing suggested operating costs excluding the export system versus oil throughput, is shown in Table 6.11. Current operating costs for the Buchan field are reported to be £24 m (1984). This includes the cost of leasing and operating shuttle tankers,

TABLE 6.11 Operating Costs for Floating Production Systems Oil production (’000 b/d)

Annual operating costs ($m)

10

25.0

20

27.0

40

33.0

60

36.0

80

38.0

Operating costs excluding the export system (i.e. costs of shuttle tankers).

£6.5 m. Ongoing capital costs have averaged £6.5 m/year excluding the major modifications which were undertaken in 1984/1985 which were associated with the installation of gas lift equipment on the installation. 6.2.7 Order of Magnitude Cost of an Extended Well Test in Severe Environments An extended well test as described in Chapter 4 could be an ideal method of delineating marginal reservoirs in severe environments. An extended well test system can be installed with minimum capital investment by using rented equipment. The following cost estimate is based on information supplied by Sedco Inc. for an extended well test in the North Sea based on using the semi-sub Sedco 704 (September 1984). It excludes rig time and well completion costs and is based on rental, test tree and production process equipment. Sedco claim that the cost estimate reflects the cost of previous similar installations. The proposal was for a minimum period of operation of one year.


222

6.2.8 Equipment to be Leased on a Day Rate Basis —semi-submersible drilling unit (complete with people, insurance, catering, etc.); —production process equipment (complete with people, insurance, safety shut-in etc.); —subsea test tree (complete with safety shut-in controls); —storage tanker (complete with crew/mooring and loading hose connection). See Table 6.3 for a budget estimate for these items. 6.2.9 Equipment to be Purchased—Capital Investment —mobilisation costs of semi-submersible etc.; —installation/testing of production process equipment; —installation/testing of tanker mooring/loading hose; —tanker mooring/loading hose. See Table 6.4 for a budget estimate for these items.

Bibliography Chapter 1 Carneiro, F.L.L.B., Ferrante, A.J. and Brebbia, C.A. Offshore Structures Engineering, Pentech Press, 1977. ‘Development of the Oil and Gas Resources of the United Kingdom 1984’, UK Department of Energy, HMSO. ‘Early Marginal Field Production Systems’, Fluor Corporation Report, July 1984. ‘Esso Offshore Technology’, Exxon Production Research Co., 1984. ‘Floaters Stage a Comeback in Cost Conscious Climate’, Offshore Engineer, May 1984, pp. 50–55. Floating Production, Veritas Offshore Publication, DnV 1985. Harris L.M. An Introduction to Deepwater Floating Drilling Operations, Petroleum Publishing Co., 1972. History of Petroleum Engineering, A Publication of the API, 1961. ‘Marginal Field Development—A Discussion Paper’, John Brown Engineering and Construction, July 1984. Parkinson, S.T. and Saren, M.A., ‘Offshore Technology: A Forecast and Review’, Financial Times Business Information. Ratzer, J.P.L., ‘The North Sea—The Future Outlook’, RINA Conference on Developments in Floating Production Systems, London, 1984. Shell Briefing Service, ‘The Offshore Challenge’. Snowden, D.P., ‘Floating Production Systems for North Sea Marginal Fields’, Offshore Technology Conference, May 1984. ‘The North Sea and British Industry: The New Opportunities’, The Economist Intelligence Unit, April 1984.

Chapter 2 Production Supports Biess Haar, A., ‘The Design Aspects of Production Facilities on Floating Production and Storage Units’, Proceedings of Marginal Field Conference, London, 1983. Booth, D., ‘Extending the Margins’, The Oilman, March 1983. Booth, D., ‘The Gorilla is Born’, The Oilman, November 1983. Carter, J.H.T. and Foolen J.A., ‘Tanker Based Floating Production Systems for Deep Water’, Deep Offshore Technology Conference, 19–22 October 1981, Palma de Mallorca. Carter, J.H.T. and Foolen, J.A. ‘Evolutionary Developments in Advancing the Floating Production Storage and Offloading Concept’, Journal of Petroleum Technology, 35(4), 695–700, April (1983). Eykhout, F. and Foolen, J.A., ‘An Integrated Floating Production Storage and Offloading— SALS—in 380 Feet Water Depth’, SPE 3142, Offshore Technology Conference, Houston, Texas, 1978.

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‘Floaters Stage a Quick Comeback in the Cost Conscious Climate’, Offshore Engineer, May (1984). Klein, P.J., ‘The Development of the SALS Floating Storage Cum Production Facility Offshore South East Asia’, Conference, 21–24 February 1978. McCloud, W.R. and Smulders, L.H., ‘An Analysis of Tanker-Based Floating Production Systems for Small Offshore Fields,’ Journal of Petroleum Tech., 34 (8), 1871–9 (1982). Magni, M. and Poldervaart, L., ‘SALS Unit for NILDE field’, Offshore, December 1979. Montoya, L.S. and Lopex-Fanjul, G.M., ‘Dorado Field Production System—A solution to individual permanent vertical access to several wells from a semi-submersible’, October 1981, 4041. Morrison, D.G., ‘Guyed Tower with Dynamic Mooring Properties’, Journal of Structural Engineering, 109 (11), November (1983). ‘Multi-well Tazerka Raises Marginal Development Hopes’, Offshore Engineer, March 1983. Perrett, G.R., ‘Floating Production Systems’, The Oilman, January 1983. Patel, M.H., ‘Technical Assessments of Floating Production Systems,’ Marginal and Deepwater Oilfield Development Conference, London 1984. Quintela, C. and Smulders, L.H., ‘Single Anchor Leg Storage/Production Terminal Offers Attractive Alternative to Production Platforms Offshore. Brazil’, 1978. Remery, G. and Beare, A., ‘Tanker Based Production’, The Oilman, January 1975. Smulders L. and Klein, P.J., ‘Castellon Sea bed Wells Flow to Process and Storage Tanker’, Oil and Gas Journal, 1 January 1978. Smulder, C.H. and Remery, G.F., ‘The Mooring of a Tanker to a Single Point Mooring by a Rigid Yoke’, OTC 3567 Offshore Technology Conference, Houston, Texas, 1979. Van Dam, J., ‘Alternative Production Facilities for Offshore Development’, Offshore North Sea Technology, Stavanger, 6 September 1978. Vosper, K.W. and Stevens, B.G., ‘Development Options for Small Gas Fields’, EUR 344 European Petroleum Conference, London, 25–28 October 1982. Williams, L.H. and Smulder, C.H., ‘The Cadlao Floating Production Storage and Offloading System (FPSO): A New Concept in Offshore Production’, Offshore South East Asia— Conference, 9–12 February 1982. Williams, L.H. and Pierce, D.M., ‘FPSO 11—A Second Generation Floating Production System for Offshore Philippines’, October 4274 Offshore Technology Conference, Houston, Texas, 1982.

Risers Cornelson, D.J. and Lawson, J.E., ‘New Approach to Riser Couplings Could Turn Weakness into Strength’, Offshore Engineer, March 1981. Dareing, D.W. and Huang, T., ‘Marine Riser Vibration Response Determined by Model Analysis’, Petroleum Engineer International, May 1980. Dumay, J.M. and Bouvard, M., ‘Introduction to the Concept of Flexible Risers’, Coflexip publication. Dumazy, C., ‘Articulated Column as a Production Riser in 300–400 m Water Depth’, The Oilman, September 1984. ‘Flexible Risers’, The Oilman, September 1984. ‘Flexible Steel Pipe for the Oil and Gas Industry’, Coflexip publication. Muller, D., Castela, A. and Schawann, J.C., ‘Production Riser is Key to Deep Sea Operations’, Oil and Gas Journal, 5 May 1980. Pettanati, C. and Dumay, J.M., ‘Flexible Dynamic Riser for Floating Production Facility in the North Sea’, Offshore Europe, 6–9 September 1983. Wybro, P.G. and Davies, K.B., Journal of Petroleum Technology ‘The Dorada Field Production Risers’, 34 (12) (1982).

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225

Subsea Equipment Arendt, H. and Brands, K., ‘Subsea TFL Systems—A Technological Update’, Offshore Technology Conference, 1979, OTC 3449. Booth, D., ‘Extending the Margins’, The Oilman, March 1983. Brands, K.W. et al., ‘The Insert Tree Completion System’, Offshore Technology Conference, 1981, OTC 4043. Burkhardt, J.A. and Anderson, R.E., ‘Submerged Production System—Progress Report of Offshore Pilot Test’, Offshore Technology Conference, 1977, OTC 2823. Calder, I.D., ‘Subsea Equipment Design to Enable Completion to a Floating Production Platform’, OE 1981, SPE 10398.1. Coltharp, E.D. and Coffelt, D.E., ‘Experience with Subsea Well Control Systems’, Offshore Technology Conference, Houston, 1981, OTC 4038. Ladedcy, V.H. et al., ‘Grondin Experimental Station—Diverless Experiments’, Offshore Technology Conference, Houston, 1981. ‘Le Champ Frigg Nord-Est’, Elf publication. Morton, A.W., ‘New Concepts Used in the Murchison Field Submerged Production System’, Offshore Technology Conference, 1981, OTC 4040. ‘N.E.Frigg—Subsea Production Nears as Column Floats Out’, Offshore Engineer, July 1983. Reimert, L.E., Gray, D.J. and Machado, Z.L., ‘A Ten Well Subsea Production System for the Enchova Field’, Offshore Technology Conference, Houston, 1979, OTC 3448. ‘Shell Looks to 600 m’, The Oilman, September 1984. ‘Subsea Completion’, Vetco publication. ‘Subsea Production Systems’, Vetco publication ‘The N.E.Frigg Project’, Elf publication. ‘The Skuld Project’, Elf publication. Wilson, R., ‘Subsea Satellite Wells Development and Practical Operational Experience in the North Sea’, Offshore Technology Conference, Houston, 1980, OTC 3731.

Loading Systems Buyzen, J.P.M., ‘Operational Experience with the Offshore Loading Units AUK—ELSBM and BRENT—SPAR’, Offshore Europe, Aberdeen, 1979, OE-79 SPE 8175.1. Chauvin, J.M., ‘Single Point Mooring Systems’, China Oil, 1983. Chauvin, J.M., ‘EMH Single Point Mooring Systems’, Offshore Australia, October 1984. Dallas, M., ‘Offshore Loading Systems Shuttle Tanker Installation’, European Offshore Petroleum Conference, London, 1980, EUR 209. Dupont, B. and Simon, J.M., ‘Packaged SPM and FPSO Units’, EMH 165. Eylshourt, F. and Foolen, J.A., ‘An Integrated Floating Production Storage and Offloading System—SALS in 380 ft Water Depth’, Offshore Technology Conference, Houston, 1978, SPE 3142. Gahtani, B.M. et al., ‘Five Years Optimising and Problem Solving at Saudi Arabia’s Tu’aymah SPM Terminal’, Offshore Technology Conference, 1979, OTC 3563. Gruy, R.H. and Kidg, W.L., ‘Marginal Field (Early Production): Options for Offshore Loading’. Gruy, R.H. et al. ‘The Loop Deepwater Port: Design and Construction of the Single Anchor Leg Mooring (SALM) Tanker Terminals’, Offshore Technology Conference, Houston, 1979, OTC 3562. Hays, D.L. et al., ‘Operation of an Articulated Oil Loading Column at the Beryl Field in the North Sea’, Offshore Technology Conference, 1979, OTC 3563. Klein, P.J., ‘The Development of the SALS Floating Storage Cum Production Facility’, Offshore South East Asia, Singapore, 1978.

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226

McNamara, J.F., ‘Offshore Export Systems’, New Technology and Offshore Oil, Dublin, April 1981. Maari, R., ‘Offshore Mooring Terminals’, SBM Inc. Mack, R.C. et al., ‘Fulmar, The First North Sea SALM/VLCC Storage System’, Offshore Technology Conference, Houston, 1981, OTC 4014. Magni, M. and Poldervaart, L., ‘SALS Unit Tapped for NILDE Field’, Offshore, December 1979. Marcello, J.T., Schneider, R. and Flory, J.F., ‘Tenth Anniversary Report—Single Anchor Leg Mooring Technology’, Offshore Technology Conference, Houston, 1980, OTC 3802. Miller, J.L., Hughes, H. and Dyer, R.C., ‘First Year’s Operation Experience of the Deepest SPM in the World’, Offshore Technology Conference, Houston, 1979, OTC 3561. Poranski, P.F., Gillespie, A.M. and Smulders, L.H., ‘The First Yoke Mooring for a VLCC in Open Ocean’, Offshore Technology Conference, Houston, 1979, OTC 3564. Quintela, C. and Smulders, L.H., ‘Single Anchor Leg Storage/Production Terminal Offers Attractive Alternative to Production Platforms’, Offshore South East Asia, 21–24 February 1978. Rees, T.E., Reber, M.A. and Seery, J.R., ‘Design, Installation and Field Operations of Offshore Tandem Loading System—Nido Field, Offshore Philippines’, Offshore Technology Conference, Houston, 1981, OTC 4012. Schultz, A.R. and Brown, R.J., ‘SPM and Floating Production System Technology Aids Marginal and Deepwater Developments’, R.J.Brown Associates publication, October 1980. Smulders, L.H., ‘The First Single Anchor Leg Storage/Production Terminal System’, Moscow Symposium, October 1978. Smulders, L.H. and Klein, P.J., ‘Castellon Seabed Wells Flow to Process and Storage Tanker’, Oil and Gas Journal, January 1978. Smulders, L.H. and Remery, G.F., ‘The Mooring of a Tanker to a Single Point Mooring by a Rigid Yoke’, Offshore Technology Conference, Houston, 1981, OTC 3567. Vilain, R.H., Pinto, J.L. and Guillaume, D.M.J., ‘A New Type of Single Point Mooring Developed and in One Year’, Offshore Technology Conference, Houston, 1980, OTC 3806.

Chapter 4 Abbot, P.A., Tulurea, D. and Hashins, J., ‘The Highlander 6000 Floating Production Vessel’, Conference on Marginal and Deepwater Oilfield Development, London, April 1983. ‘Advanced Concepts are Tailored to the Task’, The Oilman, August 1985. Behan, I., ‘IMFP 300—A Second Generation of FPSO’, Conference on Marginal and Deepwater Oilfield Development, London, April 1983. Carter, J.H.T. and Foolen, J.A., ‘Evolutionary Developments Advancing the Floating Production, Storage and Offloading Concept’, Journal of Petroleum Technology, April 1983. ‘Cybele Semi-Submersible Production Platform’, EPM/Technique 2000. Denise, J.P., ‘A Compliant Riser System for Floating Production Platforms’, Conference on Marginal and Deepwater Development, London, 1985. ‘Dorada Hosts Unique Subsea Unit’, Offshore, August 1980. ‘Floating Production Services’, Det norske Veritas, April 1985. ‘Floating Production System for Deep Hostile Environment’, Ocean Industry, June 1983. Hammet, D.S. and Johnson, J.S., ‘First Floating Production Facility—Argyll’, OTC Paper No. 282, Offshore Technology Conference, 1977. Hart, V.A., Montgomery, J.I. and Worley, M.S., ‘The Economic Evaluation of Hull Forms for Floating Production’, Paper SPE 13154 1984, SPE Technical Conference, Houston, 1984.

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Haynes, A.P., Jones, B. and Foster, K., ‘A Tanker Based Development Scheme for the Central North Sea’, Seminar on Design and Operational Aspects of Floating Production Systems, London, 1984. Homer, A., ‘Floating Units Cut Production Costs’, Offshore, May 1983. ‘IMFP 300—A New Concept of Proven Technology’, Integrated & Modular, 1984. Machado, E., ‘Petrobras Experience in Offshore Early Production Systems’, International Meeting on Early Production Systems, Rio de Janeiro, 1982. ‘Nippon Kokan Wins Contract for Offshore Oil Production Tanker’, Veritas, November/December 1984. Pass, H., ‘The Development of a Mobile Production System Incorporating a Compliant Production Riser’, Oyez Seminar, London, 1984. ‘Penta 7000, Designed with IFP, Floating Production Platform’, CFEM. ‘Santa Fe’s Deepwater Floating Production Systems’, Ocean Industry, June 1984. ‘Sea Plex Class 500–4 For Hostile Environments’, Sea Plex Corporation; ‘Sea Plex Retrievable Production Platform’; Sea Plex UK Ltd. ‘Sedco—Marginal Field Development Contractor’, Sedco Inc. ‘Semi Platform Planned for Balmoral Field’, Offshore, September 1983. ‘Severe Weather Jack-up’, The Oilman, May 1984. Smith, J.R. and Jordan, P.A., ‘Barge Mounted Production Systems for Floating Production Units’, Conference on Marginal and Deepwater Oilfield Development, London, 1985. ‘SWOPS Considered for Norwegian Sector’, Offshore Engineer, September 1984. ‘T 2005-C Mobile Jack-up Drilling Platform’, CFEM. ‘The Gorilla is Born’, The Oilman, November 1983. Worley, M.S. and Montgomery, J.I., ‘A New Concept in Floating Production Systems’, Seminar on Design and Operational Aspects of Floating Production Systems, London, September 1984. Also SPE 12986 European Petroleum Conference, London, October 1984.

Chapter 5 Argyll Field ‘Argyll, Hamilton Adapts to Exploit UK’s First Oil Field’, Offshore Engineer, January 1975. ‘Argyll’s Innovative Production Riser System’, Petroleum Engineer, October 1975. Bifani, R. and Smith, C.A., ‘The Argyll Field after a Decade of Production’, Offshore Europe, 1985. Elwes, P.J.G., ‘Argyll Field Development’, Petroleum Review, pp. 323–7. Haggard, M.E., ‘Argyll SBM Production’, Offshore Services, November 1975, pp. 84–6. Kirkland, K. and Johnson, J., ‘The Production Riser for the Argyll Field’, OTC Paper No. 2327, May 1975. Offshore Engineer, January 1984. Petroleum Times, 20 February 1976, pp. 8/22/23. ‘Producing Oil from a Semi-Submersible’, Ocean Industry, May 1975, pp. 59–64. Scottish Petroleum Annual, 1975, p. 39. The Oilman, March 1984. World Oil, September 1983.

Buchan Field ‘Buchan “Experiment” Termed Worthwhile’, Drilling Contractor, July 1984.

Bibliography

228

Darnborough, E., ‘The Buchan Field Development’, Paper EUR 230, European Offshore Petroleum Conference, 1980. Logan, B.L. and Rothwell, E.G., ‘Buchan Development Project—Conversion of a Drilling Rig into a Floating Production Platform’, Paper OTC 3958, Offshore Technology Conference, 1981. Mieras, A.A., ‘Operational Experience of the Buchan Field Floating Production and Offshore Loading System’, Paper SPE 12433, 5th Offshore South East Asia Conference 1983. Scottish Petroleum Review Annual, 1985, p. 51. ‘The Buchan Oil Field’, BP Petroleum Development Ltd. Williams, P.W., ‘Buchan—The First Nine Months’, Paper EUR 277, European Petroleum Conference, 1982.

Chapter 6 Bayly, C.H. and Cox T.F., ‘Conditions for Development of Smaller Discoveries in the North Sea’, European Petroleum Conference 1982. Hall, J.D., Conversion Techniques—Enhancing Recovery and Profitability of Marginal Offshore Fields, Marginal Oilfield Development Conference 1983. Kemp, A.G. and Rose, D., North Sea Economics Revised—Petroleum Economist April 1982. Moe, J., Technological Development and Cost Uncertainties, Offshore Gotenburg Marine Technology Conference 1981. Montague Smith, D.A., Finance for Marginal Oilfield Development—Enhancing Recovery and Profitability of Marginal Offshore Fields, Marginal Oilfield Development Conference 1983. Morrison, D.D. and Jolliffe, V., ‘North Sea Tax and Economics’, European Petroleum Conference 1982. Noroil July 1982 p. 21 North Sea Field Development. Noroil August 1982 p. 67 UK Field Development. Offshore, 1979, The Economics of Wet and Dry Subsea Completions. Offshore, March 1980 p. 61, Economical Marginal Fields. Parkinson, S.T. and Saren, M.A., Offshore Technology, A Forecast and Review, Financial Times Business Information. Smith, J.R., Carruthers R., Enhancing Recovery and Profitability of Marginal Offshore Fields, Marginal Oilfield Development Conference 1983.

Appendix 1 Conversion Factors The units of measurement used in the text reflect the amalgam of oilfield and engineering units which constitutes the accepted usage in the offshore industry. Length:

1 mm=3.937×10−2 in. 1 m=3.281 ft 1 km=6.214×10−1 miles (statute) =5.306×10−1 miles (nautical)

Area:

1 mm2=1.55×10–3 in.2 1 m2=10.76 ft2

Volume:

1 cm3=6.102×10−2 in.3 1 m3=35.31 ft3 Barrels (oil)=42.0 gallons (oil)

Mass:

1 kg=2.205 lb 1 tonne=1000 kg=0.984 imperial ton

Approximate equivalents: 1 tonne oil=425 therms 1 tonne=

barrels crude oil

5 million tonnes of crude oil per year=100000 barrels a day 100 million ft3 a day natural gas (mmcfd)=375 million therms per year 100 million m3 a day natural gas (mmcmd)=130 million therms per year

Appendix 2 Glossary of Terms Anchor buoy A floating marker used in positioning each anchor of a spread mooring pattern for a semi-submersible or drill ship. API gravity The universally accepted scale adopted by the American Petroleum Institute for expressing the specific gravity of oils: API gravity=(141.5/specific gravity at 60°F)−131.5. Blowout An uncontrolled flow of well fluids from the wellbore either at the wellhead or into the formation. Blowout preventers enable the driller to prevent damage at the surface while restoring the balance between the pressure exerted by the column of drilling fluid and formation pressure. Bottom hole assembly (BHA) The lower end of the drill string comprising the drill bit, drill collars, heavyweight drill pipe and ancillary equipment. Bumper sub A unit placed in the drill string of a floating rig to compensate for heave or vertical motion. Bundle A group of several parallel cables, hoses, lines, or tubing leading from platform controls to remote actuating units. Choke A gauged restriction inserted into a fluid flowline in order to restrict the flow rate. Compensators Hydraulically operated equipment that compensates for the upward and downward motion (heave) of a floating installation. Connectors Hydraulically controlled clamps to mate and secure marine riser segments, and choke and kill lines. One connector joins the lower ball joint of the marine riser to the BOP stack, and another secures the BOP stack to the wellhead. The use of connectors reduces the need for diver assistance. Christmas tree The assembly of valves, pipes and fittings—usually high pressure—used to control flow of oil and gas from the casing head. Directional drilling Although wellbores are normally planned to be drilled vertically, many occasions arise when it is necessary or advantageous to drill at an angle from the vertical. Controlled directional drilling makes it possible to reach subsurface points laterally remote from the point where the bit enters the earth. Downhole safety valve A valve fitted to the production tube of a well some distance below the sea bed in order to permit flow to be stopped in an emergency. Down time Time during which no production is possible due to adverse weather conditions, while downhole equipment is being changed, during well logging etc. Dry tree A subsea wellhead where the equipment is enclosed in a watertight chamber. Dynamic positioning The method of maintaining a floating offshore structure on location over the well by means of computer-controlled thruster motors, thus obviating the need for anchors and allowing production in water depths too great for anchoring. The motors respond constantly to any changes in the wind, currents, waves etc. to maintain the unit in a constant position.

Appendix 2

231

Flare An open flame used to burn off unwanted gas; see Flaring. Flare stack The steel structure on a rig or platform from which gas is flared; see Flaring. Flaring Burning off of gas produced in association with oil which, for technical or economic reasons, cannot be re-injected or shipped ashore. Gas-to-oil ratio (GOR) The volume of gas at atmospheric pressure produced in association with a unit volume of oil. Heave compensation Counteraction of vertical movement of the riser string. Heave compensators have a typical stroke of 5.5 m. Hundred year storm A combination of storm conditions (wave height and sustained wind speed) that should, on average, only occur once every hundred years in a particular area. Offshore structures are designed to withstand such storms. Manifold centre An arrangement whereby production from several wells may be combined in any way desired for forwarding through one or more pipelines. They are commonly used offshore in order to minimise the length of individual well flowlines while permitting the selection of individual wells for testing, segregation of different types of oil, or other purposes. Marine riser The pipe which connects an exploration rig, drilling platform or production platform to a subsea wellhead or subsea pipeline during drilling or production operations. Module The box or ‘package’ containing equipment for installation on a production platform. These modules, which may weigh up to 2000 tons each, are constructed ashore and installed as self-contained units on the structure, each one serving a specific purpose, e.g. crew module, control module, generator module etc. Multiphase flow Simultaneous flow of two or more fluid phases (e.g. gas, oil, water) in the same flow channel, whether pipeline, well tubing or reservoir rock. Because of the pseudo-elastic interfaces between phases, multiphase flow is relatively inefficient, e.g. with a given pipe and pressure difference, the flow rate of a mixture of oil and water is less than it would be with either alone (assuming similar viscosities). Pig A piece of equipment that is inserted into a pipeline and is carried along by the flow of oil or gas; used to clean or monitor the internal condition of the pipelines or to mark an interface between two different products. Pressure maintenance Injection of gas or water into a reservoir in order to maintain pressure. The aim is to maintain production rates, although the fluids injected often sweep additional oil to the wells, thus increasing recovery from an oil reservoir. Processing plant Special plant installed on a production platform or at a pipeline terminal to separate gas, oil and water from a mixture containing some or all of these components; also called treatment or separation plant. Proven reserves The estimated quantities of hydrocarbons which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions. Pumps Mechanical devices to transport liquids or gases from one vessel to another along pipelines. There are a wide variety of pumps of three general types: reciprocating, gear and centrifugal. The choice depends on the height to which the liquid is to be pumped (delivery head), quantity and nature of the liquid (viscosity, corrosive nature, etc.) and availability of prime movers (electric motors, turbines, etc.).

Appendix 2

232

Refractory Materials which can stand high temperatures and resist corrosion and abrasion. Particularly used for furnace linings. Reservoir A stratum in which oil or gas is present. Reservoir pressure The fluid pressure in an oil or gas reservoir. Saturation diving Diving for a length of time which results in a diver’s body absorbing a maximum of inert gases used in breathing at a given pressure level. Decompressing time and equipment are required. SBM Single buoy mooring, used for loading oil into tankers in the open sea. Also sometimes called single point mooring (SPM). The principle is that the tanker can moor to load oil whatever the direction of wind or current and swing at its mooring to present the least resistance to the prevailing conditions. ELSBM stands for exposed location single buoy mooring: a large SBM specially designed for exposed locations. Semi-submersible rig A floating drilling platform that is supported by underwater pontoons; generally used for exploration purposes but may be used for production. Shuttle tanker An oil tanker which makes regular round trips between a producing field and an onshore terminal or refinery. Significant waves Wave heights observed and recorded by experienced seafarers. A significant wave is equal in height to the average of the one-third highest waves under the same sea conditions. SPAR A type of single buoy mooring developed by Shell, incorporating storage facilities, so that in the event of weather conditions temporarily preventing tanker loading, production need not be shut off. Spread mooring A system of multiple anchors and lines distributing the loads imposed by currents, waves and winds. Pretensioning of anchor lines determines the initial line loadings. A continuous monitoring of individual line loads and automatic adjustments in tension increase the effectiveness of this station-keeping system. Subsea completion (sea bed completion) A method of completing a well or wells whereby equipment controlling oil-flow, normally mounted in a surface platform, is housed in a special construction on the sea floor. Subsea wellhead A wellhead installed on the sea floor and controlled remotely from a platform or floating production facility or from land. Template A design pattern with built-in guides for specific equipment and structure to assure their usefulness. Examples: template for installing well-conductor pipe; platform jacket with well slots, guides, sleeves for installation of piles; subsea production system with spacing to accommodate the wells it will produce. Tensioners Equipment used to maintain tautness or constant pulling stress on marine risers, guide lines, drill string, and applications of wire and control lines on floating vessels. Heave compensation is accomplished through air pressure vessels, control panel, air compressor, air dryer units, and idler sheaves. Thruster propeller A small propeller mounted underneath a floating structure or vessel to enable it to change or maintain its position. Turret A roller-mounted structure beneath the derrick of a floating drilling vessel to which anchor lines are attached. The vessel can be revolved 360° around the mooring plug by the bow and stern thrusters. VLCC Very large crude carrier: i.e. tanker between 160000 and 319 999 dwt.

Appendix 2

233

Water drive A recovery process in which oil or gas is driven out of a reservoir by the pressure of underlying water. Water injection A process whereby treated water is pumped into the reservoir rock in order to maintain the reservoir pressure. Wax Solid hydrocarbon which is present in some crude oils, especially in paraffinic crudes. Wax deposits in pipelines and equipment can cause mechanical problems. Weather window The part of the year when the weather can normally be expected to be suitable for carrying out offshore operations such as pipeline laying or platform installation. Wellhead The control equipment fitted to the top of a well casing, incorporating outlets, valves, blowout preventers, etc. Wellhead cellar In sea bed completions, a dry, steel structure enclosing the wellhead. The inside of the structure is at atmospheric pressure. To service the equipment, engineers are lowered in a capsule from a support vessel (the capsule also at atmospheric pressure), which docks with the cellar. The engineers can work in the cellar in shirt-sleeve conditions with fresh air and electrical power supplied by umbilical cord from the support vessel. Well logging A comprehensive record of all data collected during the drilling of a well, enabling a highly detailed picture of the strata to be built up. Wet tree A subsea wellhead where the equipment is exposed to the sea. Wireline Any line of wire or cable used for downhole operations. Two types are usually distinguished: piano and electric wireline. The former is a thin single-strand line of high tensile steel used to lower instruments or tools into a well, and/or to install, retrieve or operate ‘wireline equipment’, e.g. failsafe safety valves installed in tubing. Electric wirelines are normally used for surface recording instruments, e.g. those used for making electric logs. Workover The process whereby a completed production well is subsequently re-entered, and any necessary cleaning, repair and maintenance work done.

Index Abandonment costs, 262 Alexander Keilland, 30 Alfortunada, 51 Argyll field, 24, 122, 191, 231–44, 259, 260 production continuity, 242–4 stages of development 1 st (1975–80), 232–5 3rd (1985), 238–40 4th, 240–2 statistics, 232 Argyll riser system, 46 Articulated column, 24, 36–7 risers, 53 storage systems, 73 loading column (ALC), 75, 89–91 loading platform (ALP), 261 towers, 215–22 Auk ELSBM, 80 Badejo field, 110 Balmoral field, 158, 192 riser system, 50, 52 Barge based production support, 32–3 storage systems, 73 turret anchor production systems (TAPS), 208–10 Bekapi field, 33, 162 Bicudo field, 140 Bonito field, 146 Brent SPAR, 74, 81–2 Buchan Alpha, 30, 100, 248, 259, 260 CALM buoy, 79 field, 29, 100, 103, 142, 191, 244–50, 260, 264 installations, 245, 246–8 major contractors, 246 process and export systems, 249 production history, 249–50 statistics, 244 riser system, 47–9 Budget estimate, 254, 255

Index

236

Cadlao field, 168 process, 95 Caisson vessel, 222–3 CALM (catenary anchor leg mooring) buoy, 30, 31, 75–9, 248, 249 Campos Basin riser system, 51 Capital costs, 255 investment, 255, 265 Casablanca field, 132 riser system, 51–2 Castellon field, 59, 164 FPSO, 96 SALS, 87–9 Catenary anchored tower (CAT), 91 Catenary Anchor Leg Rigid Arm Mooring (CALRAM), 28 Cayo Arcas fixed tower, 92–3 Central Cormorant field, 178 underwater manifold centre (UMC), 64–5 Christmas trees, 58 Commercial fields, 1 CONAT (concrete articulated tower) production systems, 220–2 Concrete gravity platforms, 23 Control systems, subsea, 67 Conversion factors, 275 Corvina field, 148 Cost(s), 251–65 drilling and completion, 257 elements, 256–65 field operating, 255, 263–5 increases, 253 parameters, 252–6 process and power equipment, 259 production support, 257 Dan Duke, 28 Decommissioning costs, 262 Deepsea Pioneer, 238, 240, 241, 259, 260 Deepsea Saga, 237, 258, 260 Deepwater gamma tower, 223–4 gravity tower, 223–4 production concepts, 222–5 Denmark, future fields and prospects, 14 Development options, 251 Deviated drilling, 22 Dorado field, 128

Index

237

riser system, 47 Drilling costs, 257 Drillmaster, 30, 100, 248, 260 Duncan field, 71, 235–8 Dynamic positioning (DP), 203 Economics, 251–65 Ekofisk field, 27, 106, 212 Electrical control systems, 67 Emilio field, 176 Enchova field, 103 Leste I, 124 Leste II, 126 riser system, 48 Equipment leasing, 265 Espoir field, 28, 114 Exploration drilling, 16–17 Export system, 261 Exposed location single buoy mooring (ELSBM) system, 75, 80, 261 Extended production test facility, 255 well test systems (EWT), 227–30 general scenario, 229–30 severe environments, in, 265 Exxon submerged production system (SPS), 63–4 Fixed production platforms, 3, 22–4 tower, 91–3 Floating concrete caisson vessel, 222–3 concrete monotower, 223 drilling techniques, 21 oil patch, 205–7, 258 Flowlines, 25, 94 Frigg North East field, 24, 36, 37, 64, 182 Fulmar SALM, 85–6 Garoupa field, 68 North field, 130 subsea production system, 60–2 Garoupinha field, 144 Gas production, 19–25 treatment and disposal, 96 Gathering system (manifolding), 94–5 Gotaverken Arendal GVA 5000 semi-submersible, 191–2, 258 Grondin subsea experimental station, 62–3 Gulf Tide, 27, 212

Index

238

Guyed tower, 24, 37–9 Handil field, 164 Harsh environment jack-up units, 212 Highlander 6000 floating production vessel, 192–5, 258 Highlander field, 71, 186 Historical perspective, 15–25 Hutton field, 24, 36, 180, 193 Hydraulic control systems, 67 IMFP 300 semi-submersible production concept, 196–8, 258 Innes field, 240–2 Ireland, future fields and prospects, 15 Jack-up production support, 27–9, 211–15 Lavinia field, 174 LENA field, 24 Lewis offshore yard, 100 Loading systems, 74–93 design considerations, 75–6 MACC (manifold and control columns) concept, 216–18 moored semi-submersible scheme, 218–19 tanker scheme, 219–20 satellite field development scheme, 220 Manifolding. See Gathering system Marginal field(s) acceptable returns, 1 challenge of, 1–25 current and future development concepts, 188–230 data sheets, 104 definition, 1 development criteria, 97 early production, 99–100 elements of development scheme, 26–96 maximum flexibility for offshore operations, 101 maximum return on investment, 100–1 minimum abandonment costs, 102 reduced capital investment, 100 reservoir performance test, 103 technology characteristics of, 4 existing, 97–187 fields utilising, 98 proven, 102 what is meant by, 3–15 Maureen articulated column, 73, 90–1

Index Modification costs, 259 Monohull based systems, 161 Netherlands, future fields and prospects, 13–14 Nilde field, 166 North East Frigg field. See Frigg North East field North Sea floating production systems, 231–50 Norway, future fields and prospects, 11–13 Ocean Kokuei, 234 Oil production, 19–25 Operating costs, 255, 263–5 Pampo field, 136 Linguado field, 137 Parati field, 112 RJS-194, 154 Phillips Enterprise, 28 Piled steel structures, 23 Pipeline(s), 25 diameter versus throughput, 262 end manifold (PLEM), 30, 249 size and unit costs, 262 Pirauna field, 150 PLEM (pipeline end manifold), 30, 249 Poseidon concept, 65–6 Processing facilities, 93–6 Production test ship (PTS) Petrojarl/Golarnor, and, 200–2 headers, 94 support, 26–41 barge based, 32–3, 208–10 characteristics of, 40 costs, 257 design criteria for, 39–41 factors affecting choice of, 41 jack-up, 27–9, 211–15 semi-submersible concepts, 190–8 tanker based, 31–2, 198–210 future development of, 210 Productivity, 254, 255 Recoverable reserves, 252–6 Remote maintenance vehicles (RMV), 65, 68 operated vehicles (ROV), 68, 95 Rental, 254 Repair and maintenance, subsea equipment, 67–8

239

Index

240

Riser(s), 41–56 alternative designs, 52–4 articulated column, 53 bundle, 42 catenary flexible with subsea tower, 54 comparative assessment of, 54–6 composite systems, 43 connection package (RCP), 44 definition, 42 design criteria, 44–5 flexible, 45, 48, 49–52 joint, 43 lines within system, 43 operational requirements and systems, 45–9 ribbon, 52–3 stand, 43 test stump, 44 tower, subsea, 215–16 RJS-90 Viola field, 156 RJS-150 field, 118 RJS-236 field, 152 Saleh field, 116 SALM (single anchor leg mooring), 31, 75, 84–9, 261 Saltpond field, 108 Scapa field, 184 Seaplex class 500–4 design concept, 213–15 Sedco-704, 265 Semi-submersibles (SSM), 20, 29–31, 121 current production designs, 195 production support concepts based on, 190–8 Separation system, 95 Severe environments, 265 Ship shaped units, 20 Shuttle tankers, 261 Single anchor leg storage (SALS), 31, 32 buoy storage (SBS), 31, 82 point mooring (SPM), 31, 249 Skuld concept, 65 SPAR storage systems, 74, 81–2, 261 Storage systems, 71–4 articulated column, 73 barge based, 73 SPAR, 74, 81–2, 261 tanker based, 72–3 Subsea control systems, 67 equipment, 56–71 repair and maintenance, 67–8 technical progress in, 69–71

Index

241

manifold, 60 production technology, 70 riser tower, 215–16 template, 57–8 Sul del Pampo field, 134 SWOPS oil production system, 202–4, 258 T 300 concrete tripod platform, 225 Tanker based loading systems, 83–4 production support, 31–2, 198–210 future development of, 210 storage systems, 72–3 TAPS system, 258 Tazerka field, 32, 170 Tension leg platforms (TLP), 24, 33–6 Through flowline (TFL) method, 58, 69 Transworld 58, 234, 240, 259, 260 Tripod tower platform (TTP), 225 Turret anchor production system (TAPS), 208–10 moored tanker concept, 83–4 UK Continental Shelf, 4 UK offshore discoveries and development prospects, 5 Uncertainties, 252 Uncommercial fields, 1 Water depth records, 21, 24, 25 Wave design criteria, 188 Well intervention methods, 68–9 Wells and wellheads, 24, 58 West European offshore discoveries and development prospects, 5 West Germany, future fields and prospects, 14 Wireline operation, 69 Yoked tower, 91

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