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- Herausgeber: John Wiley & Sons
- Kategorie: Wissenschaft und neue Technologien
- Sprache: Englisch
Reservoir management is fundamental to the efficient and responsible means of extracting hydrocarbons, and maximising the economic benefit to the operator, licence holders and central government. All stakeholders have a social responsibility to protect the local population and environment. The process of managing an oil or gas reservoir begins after discovery and continues through appraisal, development, production and abandonment; there is cost associated with each phase and a series of decision gates should be in place to ensure that an economic benefit exists before progress is made. To correctly establish potential value at each stage it is necessary to acquire and analyse data from the subsurface, the planned surface facilities and the contractual obligations to the end-user of the hydrocarbons produced. This is especially true of any improved recovery methods proposed or plans to extend field life. To achieve all the above requires a multi-skilled team of professionals working together with a clear set of objectives and associated rewards. The team's make-up will change over time, as different skills are required, as will the management of the team, with geoscientists, engineers and commercial analysts needed to address the issues as they arise.
This book is designed as a guide for non-specialists involved in the process of reservoir management, which is often treated as a task for reservoir engineers alone: it is a task for all the disciplines involved in turning a exploration success into a commercial asset. Most explorers earn their bonus based on the initial estimates of in-place hydrocarbons, regardless of the ultimate cost of production; the explorers have usually moved on to a new basin before the first oil or gas is produced! This book is not a deeply academic tome, rather the description of a process enlivened by a number of stories and case studies from the author's forty years of experience in the oil-patch.
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Table of Contents
Cover
Title Page
Copyright Page
Dedication Page
Preface
List of Abbreviations
1 Introduction
1.1 The Basics
1.2 Field Appraisal
1.3 Volumetrics
1.4 Drive Mechanism
1.5 Field Development
1.6 Reservoir Simulation
1.7 Field Production
1.8 Reservoir Monitoring and Surveillance
1.9 Improved Hydrocarbon Recovery
1.10 Cessation of Production: Field Abandonment
1.11 Summary
2 Reservoir Management Process
2.1 Field Appraisal
2.2 Field Development
2.3 Field Production
2.4 An Integrated Team Structure for Reservoir Management
2.5 Summary
3 Reservoir Description
3.1 Multi‐scale Data
3.2 Reservoir Structure
3.3 Reservoir Framework
3.4 Depositional Environment
3.5 Static Reservoir Properties
3.6 Dynamic Reservoir Properties
3.7 Reservoir Hydrocarbon Fluids
3.8 Summary
4 Building an Integrated Reservoir Model
4.1 Simulation Model Design
4.2 Designing the Modeling Grid
4.3 Facies Modeling
4.4 Property Modeling
4.5 Upscaling
4.6 Model Analysis and Uncertainty
4.7 Summary
5 Performance, Monitoring, and Forecasting
5.1 Natural Drive Mechanisms
5.2 Reservoir Monitoring
5.3 Production System
5.4 Resource and Reserves Estimation
5.5 Petroleum Resources Management System (PRMS)
5.6 Summary
6 Improving Hydrocarbon Recovery
6.1 Primary Recovery
6.2 Secondary Recovery
6.3 Tertiary Oil Recovery
6.4 Summary
7 Development Economics
7.1 Key Economic Criteria
7.2 Risk and Uncertainty
7.3 Summary
8 Tales of the Unexpected
8.1 Laggan and Tormore, Flett Basin, West of Shetland, UKCS
8.2 Dación Field, Maturín Basin, Venezuela
8.3 As‐Sarah Field, East Sirt Basin, Libya
8.4 Ceiba Field, Rio Muni Basin, Equatorial Guinea
8.5 Glenn Pool Field, Cherokee Basin, Oklahoma, USA
8.6 Schiehallion Field, Faroe–Shetland Basin, West of Shetland
8.7 North Burbank Field, Cherokee Basin, Oklahoma, USA
8.8 Nakhla Field, Hameimat Trough, East Sirt Basin, Libya
8.9 Forties Field, Central North Sea, UKCS
8.10 Leman Field, Southern North Sea, UKCS
8.11 Summary
Appendix 1: Guide to Reservoir Simulation
A.1 Phases of a Reservoir Simulation Study
A.2 Data Gathering
A.3 Upscaling
A.4 History Matching
A.5 Summary
References
Bibliography
Index
End User License Agreement
List of Tables
Chapter 1
Table 1.1 Recovery factors for different fields under differing production me...
Chapter 2
Table 2.1 Main elements of a field development plan (FDP) document.
Table 2.2 Make‐up of multidisciplinary subsurface team.
Chapter 3
Table 3.1 Data sources for modeling.
Table 3.2 Permeability ranges for different qualitative descriptions of perme...
Table 3.3 Typical pressure gradients and fluid densities.
Table 3.4 Typical properties of the major reservoir hydrocarbons.
Chapter 4
Table 4.1 The requirement for building a 3D reservoir model increases with pe...
Chapter 5
Table 5.1 Notional oil and gas recovery factors based on primary recovery mec...
Table 5.2 Reserves definitions as recommended in the petroleum resources mana...
Table 5.3 Contingent resources definition as recommended in the petroleum resour...
Table 5.4 Prospective resources definition as recommended in the petroleum re...
Chapter 6
Table 6.1 Primary, secondary, and tertiary recovery methods.
Table 6.2 Three main groups of tertiary recovery methods.
Chapter 7
Table 7.1 The time value of money expressed in terms of interest and inflatio...
Table 7.2 Different biases affecting risk decisions.
Appendix 1
Table A.1 Conversion of laboratory capillary pressure data to reservoir condi...
Table A.2 Typical uncertainty ranges of common history matching parameters.
Table A.3 Typical constraints for reservoir prediction runs.
List of Illustrations
Chapter 1
Figure 1.1 Oilfield life cycle from discovery to abandonment with a typical ...
Figure 1.2 Effective reservoir management should always be proactive, antici...
Figure 1.3 The Glenlivet Field, West of Shetland, showing the seismic respon...
Figure 1.4 The Hyde Field, UK Southern North Sea, showing the main structura...
Chapter 2
Figure 2.1 Stages in the life of an oil or gas field from exploration to aba...
Figure 2.2 Stage gates in a development plan and the questions that need to ...
Figure 2.3 Facility engineering approach to project planning to ensure quali...
Figure 2.4 Ideal arrangement and interactions of a multidisciplinary asset t...
Figure 2.5 “Big Loop”: automated workflow allied with machine learning‐based...
Chapter 3
Figure 3.1 The scales of investigation of different types of data found in a...
Figure 3.2 Depth measurement and well path trajectory terminology.
Figure 3.3 Examples of simple structural and stratigraphic trapping mechanis...
Figure 3.4 Representation of the seismic response at lithological interfaces...
Figure 3.5 The impact of only using development wells in depth conversion; t...
Figure 3.6 Depth reference terminology used in well correlation.
Figure 3.7 Examples of different types of genetic units that can be modeled ...
Figure 3.8 (a) Porosity: the relationship between volume of pore space and t...
Figure 3.9 Relative permeability of a rock sample to water and oil liquid ph...
Figure 3.10 (a) Description of capillary pressure based on a simple experime...
Figure 3.11 The pressure gradients that are to be expected in the subsurface...
Figure 3.12 Typical oil, gas, and water gradients displayed against depth an...
Figure 3.13 Standard phase diagram depicting liquid and gas phases of differ...
Chapter 4
Figure 4.1 Conceptual models: depictions of the sedimentological, stratigrap...
Figure 4.2 Reservoir modeling workflow: the elements are presented as a trad...
Figure 4.3 An example of a 3D reservoir model showing inclined faults and st...
Figure 4.4 An example of the parallel workflow modeling adopted by many comp...
Figure 4.5 Grid orientation and axes nomenclature used in geocellular modeli...
Figure 4.6 Horizon, zone, and sub‐grid nomenclature used in geocellular mode...
Figure 4.7 Classification and impact of different types of horizons used in ...
Figure 4.8 Comparison between lithostratigraphic correlation and sequence st...
Figure 4.9 Types of heterogeneity at different scales from the microscopic t...
Figure 4.10 Examples of different object shapes that can be modeled to repre...
Figure 4.11 Grid resolution aligned to the major structural features creates...
Figure 4.12 When a grid is aligned to the primary flow direction, a better g...
Figure 4.13 The SmartModel concept promotes building the geocellular and sim...
Figure 4.14 Different types of simulation grids for use in dynamic flow inve...
Figure 4.15 An example of an indicator simulation model of an alluvial flood...
Figure 4.16 An example of truncated Gaussian simulation using trends to mode...
Figure 4.17 An example of fluvial channel objects to model connectivity: mos...
Figure 4.18 Sand body width to thickness measurements classified by depositi...
Figure 4.19 The representative elementary volume (REV) concept and the scale...
Figure 4.20 Total property modeling (TPM) avoids the need to apply NTG until...
Figure 4.21 (a) Schematic diagram of an ideal variogram with an explanation ...
Figure 4.22 Physics of the reservoir: representation of the fluid distributi...
Figure 4.23 Net : gross (NTG) terminology: whichever approach you take be co...
Figure 4.24 Upscaling of reservoir properties is dependent on sampling metho...
Chapter 5
Figure 5.1 Schematic of the primary drive mechanisms found in an oil or gas ...
Figure 5.2 The phase behavior of the main types of hydrocarbon reservoirs. T...
Figure 5.3 Typical response of oil (red) and gas (green) to the decline in r...
Figure 5.4 Reservoir fluid response under solution gas drive: as the reservo...
Figure 5.5 Recovery profile of a reservoir with an active aquifer drive: the...
Figure 5.6 With a gas cap drive, as reservoir pressure declines the producin...
Figure 5.7 Under a compaction drive mechanism, when the threshold pressure i...
Figure 5.8 Advances in downhole monitoring have resulted in advanced closed‐...
Figure 5.9 Typical types of well bore completions as described in the text....
Figure 5.10 Industry standard oilfield terminology for resources and reserve...
Figure 5.11 Use of an area depth map is the oldest form of volumetric estima...
Figure 5.12 A standard approach to describing resources using deterministic ...
Figure 5.13 The different indirect methods of reserve estimation using analo...
Figure 5.14 An example of analogy based on past well production data. The ma...
Figure 5.15 Decline curve analysis based on historical production. The rate ...
Figure 5.16 Material balance is regularly applied in gas fields under a fixe...
Figure 5.17 Schematic of the reservoir simulation process from model build, ...
Figure 5.18 Petroleum Reserves Management System (PRMS) (SPE [PRMS] 2018) te...
Chapter 6
Figure 6.1 Oilfield life cycle from discovery to abandonment with a typical ...
Figure 6.2 Scales of measurement from core data through log, seismic, and we...
Figure 6.3 Pressure decline observed from the reservoir to the stock tank. T...
Figure 6.4 Extended reach drilling (ERD) at Wytch Farm to exploit the deeper...
Figure 6.5 Typical water flood patterns used in onshore field developments....
Figure 6.6 Subsurface regions of a typical steam flood operation showing the...
Chapter 7
Figure 7.1 Oilfield life cycle showing the production profile from buildup t...
Figure 7.2 Comparison of the internal rate of return (IRR) on investment for...
Figure 7.3 Cash flow time diagram showing the net cash outflow at the start ...
Figure 7.4 Range of uncertainty in reserves of time of compared with the sta...
Figure 7.5 Different statistical distributions that may be used in stochasti...
Chapter 8
Figure 8.1 Laggan–Tormore Field location map with predevelopment well locati...
Figure 8.2 The west of Shetland gas export route from Laggan–Tormore to Sull...
Figure 8.3 Structure map of the As‐Sarah oilfield, Libya, showing the active...
Figure 8.4 Top reservoir structure of the Ceiba Field and the mud‐filled cha...
Figure 8.5 Glenn Pool production profile showing both annual and cumulative ...
Figure 8.6 (a) Self Unit well location map.(b) Increase in production in...
Figure 8.7 Predevelopment structural and stratigraphic elements of the Schie...
Figure 8.8 Map of North Burbank and adjacent fields showing the distribution...
Figure 8.9 Production history of North Burbank Field showing significant eve...
Figure 8.10 Depth structure map of the Nahkla Field top reservoir showing th...
Figure 8.11 Postfracture stimulation production improvement seen in selected...
Figure 8.12 Main stratigraphic units of the Forties Field based on well pene...
Figure 8.13 Forties Field platform and well locations with distribution of m...
Figure 8.14 Forties Field oil and gas production from 1975 to 2015, showing ...
Figure 8.15 Leman Field outline with major structural features highlighted t...
Figure 8.16 Production history of the Leman Field with typical life cycle fr...
Appendix 1
Figure A.1 Typical simulation study workflow.
Figure A.2 The relationship between capillary pressure, height, and permeabi...
Figure A.3 Typical relative permeability curves for saturation data of oil‐w...
Figure A.4 Typical relative permeability curves for saturation data of conso...
Figure A.5 Examples of Cartesian and corner point grid models incorporating ...
Figure A.6 Grid resolution aligned to the major structural features creates ...
Figure A.7 Example of grid alignment when both geocellular and simulation gr...
Figure A.8 Comparison of four‐point and nine‐point formulations of the flow ...
Figure A.9 Numerical dispersion is created when the simulation grid requires...
Figure A.10 Upscaling of reservoir properties is dependent on the sampling m...
Figure A.11 Permeability upscaling is a more challenging task and may requir...
Figure A.12 Examples of two common averaging methods: (a) arithmetic‐harmoni...
Figure A.13 Different boundary conditions that can be applied to pressure so...
Figure A.14 Examples of different upscaling regions: local, regional and glo...
Figure A.15 A comparison of resampling and direct sampling methods for cell ...
Figure A.16 Simplified history matching workflow from an initial pressure ma...
Guide
Cover Page
Reservoir Management
Copyright
Dedication
Preface
List of Abbreviations
Table of Contents
Begin Reading
Appendix 1 Guide to Reservoir Simulation
References
Bibliography
Index
WILEY END USER LICENSE AGREEMENT
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Reservoir Management
A Practical Guide
Steve Cannon
Principal ConsultantSteve Cannon GeoscienceUK
This edition first published 2021© 2021 John Wiley and Sons Ltd
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The right of Steve Cannon to be identified as the author of this work has been asserted in accordance with law.
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Library of Congress Cataloging‐in‐Publication Data
Name: Cannon, Steve, 1955– author.Title: Reservoir management : a practical guide / Steve Cannon.Description: Hoboken, NJ : Wiley‐Blackwell, 2021. | Includes bibliographical references and index.Identifiers: LCCN 2020036606 (print) | LCCN 2020036607 (ebook) | ISBN 9781119619369 (hardback) | ISBN 9781119619413 (adobe pdf) | ISBN 9781119619437 (epub)Subjects: LCSH: Gas reservoirs.Classification: LCC TN880 .C36 2021 (print) | LCC TN880 (ebook) | DDC 622/.3385–dc23LC record available at https://lccn.loc.gov/2020036606LC ebook record available at https://lccn.loc.gov/2020036607
Cover Design: WileyCover Image: © Steve Cannon
To my parents, Bill and Biddy Cannon, to whom I owe so much and more!
Preface
I am a geologist by profession, a petrophysicist by inclination, and a reservoir modeler by design, but I have always wanted to be a reservoir engineer; they get paid more as a rule and usually end up as project managers! In 2018, while on holiday, I received an email asking me to deliver a course in India on reservoir management. My initial response was that I did not have the necessary skills and that the course organizer should look for an experienced reservoir engineer. As I relaxed in the sun I started to think about a new project during the latest oilfield downturn, and I had the idea for a book on reservoir management, but one that would follow the same principles as my guides to petrophysics and reservoir modeling: a geologist's view on the topic. Fortunately, Wiley‐Blackwell were keen for me to submit a proposal, which I duly did, but with the proviso that I might find out that I was out of my depth!
Researching which publications were available, I realized that Integrated Petroleum Reservoir Management: A Team Approach by Satter and Thakur (1994) was around 25 years old and that nothing newer was available; there were innumerable peer reviewed articles in the journals covering most of the aspects of reservoir management and a number of commercial and academic courses but no single book: here was my opportunity! This book is not a deeply academic tome but rather the description of a process enlivened by a number of stories and case studies that I have come across over 40 years of experience in the oil patch. At one time I had a working title of ‘Tales of the Unexpected’ but I realized Roald Dahl had beaten me to it!
A word of caution; my formal training in the oil industry was a series of courses given by my employer through the 1980s, Shell (UK) Exploration & Production Ltd. (Shell Expro). I studied production geology, petrophysics, and reservoir engineering (PE101) and was taught that oil was always red and gas was green in maps, well sections, and cross plots. The rest of the industry uses these colors the other way around, but I remain true to my training and the company that pays me a small monthly pension. ‘There is a right way to do something, a wrong way and the Shell way’ is as valid today as ever!
I am deeply grateful to all the reservoir engineers I have worked with over the years who have had the patience to explain how an oil or gas field should be managed: gently, with due reverence for its uncertain and sometimes unknowing response to your ministrations and demands, just like your life partner in fact! In particular, I would like to thank Steve Griffith, Alun Griffiths, Steve Flew, Pat Neve, Andrew Evans, Dave Ponting, Steve Furnival, Dan O'Meara, Jez Christiansen, Christian Masini, and Neil Ementon.
Steve Cannon2021
List of Abbreviations
AAPG
American Association of Petroleum Geologists
AHD
Along hole depth
AI
Acoustic impedance
API
American Petroleum Institute
AVO
Amplitude versus offset
BBO
Billion barrels of oil
BHA
Bottomhole assembly
BHFP
Bottomhole flowing pressure
BHT
Bottomhole temperature
BOPD
Barrels of oil per day
BSW
Bulk solids and waste
CAPEX
Capital expenditure
CGR
Condensate–gas ratio
DCD
Downhole control devices
DFE
Drill floor elevation
DHS
Downhole sensors
DHVT
Downhole vibration tool
EMV
Expected monetary value
EOR
Enhanced oil recovery
EOS
Equation of state
ERD
Extended reach drilling
ESP
Electric submersible pumps
EUR
Estimated ultimate recovery
EWT
Extended well tests
FA
Forties Alpha
FB
Forties Bravo
FC
Forties Charlie
FDP
Field development plan
FEED
Front end engineering design
FFM
Full‐field model
FID
Final investment decision
FIPNUM
Fluid in‐place region numbers
FLAGS
Far‐north Liquids and Associated Gas System (North Sea gas pipeline)
FMT
Formation measurement tool (wireline formation tester)
FPS
Forties pipeline system
FPSO
Floating production, storage, and offloading
FUKA
Frigg UK Association pipeline
FVF
Formation volume factor
FWL
Free water level
GIIP
Gas initially in‐place
GOC
Gas–oil contact
GOR
Gas–oil ratio
GOSP
Gas–oil separation plant
GR
Gamma ray
GRV
Gross rock volume
GWC
Gas–water contact
HIIP
Hydrocarbons initially in‐place
ICD
Inflow control devices
ICV
Interval control valves
IMPES
Implicit pressure explicit saturation
IOR
Improved oil recovery
IRR
Internal rate of return
LPG
Liquid petroleum gas
LWD
Logging‐while‐drilling
MDT
Modular dynamic tester
MEG
Mono‐ethylene glycol
MEOR
Microbial enhanced oil recovery
MMbbls
Millions of barrels
MMboe
Million barrels of oil equivalent
MMscf/d
Million standard cubic feet per day
MNCF
Maximum negative cash flow
MPS
Multipoint statistical methods
MWD
Measurement‐while‐drilling
NMR
Nuclear magnetic resonance
NNM
Not normally manned
NPV
Net present value
NRI
Net revenue interest
NRV
Net rock volume
NTG
Net‐to‐gross
OBC
Ocean bottom cable
OBN
Ocean bottom node
OPEX
Operating expenditure
OWC
Oil–water contact
PDG
Permanent downhole gauges
PdVSA
Petroleos de Venezuela
PEBI
Perpendicular–bisectional grid system
PI
Production index
P/I
Profit‐to‐investment ratio
PLT
Production logging tool
PRMS
Petroleum Resources Management System
PSDM
Pre‐stack depth migration
PSA
Production sharing agreement
PVT
Pressure–volume–temperature
QC
Quality control
REV
Representative elementary volume
RFT
Repeat formation tester
SEG
Society of Exploration Geophysicists
SIS
Sequential indicator simulation
SPE
Society of Petroleum Engineers
SPEE
Society of Petroleum Evaluation Engineers
SSSV
Subsurface safety valve
STOIIP
Stock tank oil initially in‐place
TCFG
Trillion cubic feet of natural gas
TDT
Thermal decay time
TGSim
Truncated Gaussian simulation algorithm
THP
Tubing head pressures
TPM
Total property modeling
TST
True stratigraphic thickness
TTRD
Through tubing rotary drilling
TVD
True vertical depth
TVDSS
True vertical depth subsea
UKCS
United Kingdom continental shelf
UTM
Universal Transverse Mercator coordinate system
VFP
Vertical flow performance
VOI
Value of information
WAG
Water alternating gas
WFT
Wireline formation tester
WGR
Water–gas ratio
WOR
Water–oil ratio
WPC
World Petroleum Council
1 Introduction
Reservoir management is fundamental to the efficient and responsible means of extracting hydrocarbons, and maximizing the economic benefit to the operator, license holders, and central government. All stakeholders have a social responsibility to protect the local population and environment. The process of managing an oil or gas reservoir begins after discovery and continues through appraisal, development, production, and abandonment (Figure 1.1); there is cost associated with each phase and a series of decision gates should be in place to ensure that an economic benefit exists before progress is made. To correctly establish potential value at each stage it is necessary to acquire and analyze data from the subsurface, the planned surface facilities, and the contractual obligations to the end‐user of the hydrocarbons produced. This is especially true of any improved recovery methods proposed or plans to extend field life. To achieve all the above requires a multiskilled team of professionals working together with a clear set of objectives and associated rewards. The team’s make‐up will change over time as different skills are required, as well as the management of the team, with geoscientists, engineers, and commercial analysts needed to address the issues as they arise.
This book is designed as a guide for nonspecialists involved in the process of reservoir management, which is often treated as a task for reservoir engineers alone. It is a task for all the disciplines involved in turning an exploration success into a commercial asset. Most explorers earn their bonus based on the initial estimates of in‐place hydrocarbons, regardless of the ultimate cost of production; the explorers have usually moved on to a new basin before the first oil or gas is produced!
Figure 1.1 Oilfield life cycle from discovery to abandonment with a typical primary production profile in red. The period from discovery to first oil may be short or long depending on economic conditions and infrastructure limitations.
This chapter will look at the basics of reservoir management introducing the main terms and jargon, while subsequent chapters will go into more detail.
Chapter 2
reviews the life cycle of an oil or gas field after discovery, looks at field development plans, monitoring and data acquisition requirements, and discusses these issues in the light of a number of case studies.
Chapter 3
looks at the static and dynamic reservoir description around which the initial plans are built.
Chapter 4
reviews the construction of the integrated reservoir model.
Chapter 5
addresses reservoir performance and production forecasting, reviewing the dynamic estimation and uncertainty in future resources and reserves.
Chapter 6
discusses some of the ways to improve or enhance hydrocarbon recovery with examples used to describe the methods.
Chapter 7
focuses on the economic aspects of a successful field development and how active reservoir management through the field life can improve the returns on investment.
Chapter 8
considers the way in which the reservoir management plan evolves with time from project sanction to abandonment. We will look at some of these issues in the real world of field development and secondary recovery projects through a series of case studies.
Throughout the book there are relevant examples from real reservoir management projects and field developments across the major hydrocarbon basins of the world. I have also included an Appendix that covers the basics of dynamic reservoir simulation, which is the main tool used by those involved in reservoir management studies.
1.1 The Basics
The main objectives of reservoir management may be summarized as follows:
Maximizing the ultimate recovery of reserves from an oil or gas field
Reducing the commercial risk associated with development plans
Minimizing
operating expenditure
(
OPEX
) and
capital expenditure
(
CAPEX
)
Increasing hydrocarbon production from wells
Increasing the value of reserves through time (
net present value
–
NPV
)
To maximize the economic recovery of hydrocarbons requires the identification and characterization of all potential reservoirs in a field so that the optimum development plan can be proposed. This requires a reservoir management plan designed on the basis of location and size of the field, the geological complexity of the reservoir, the type and distribution of the reservoir rock and fluids, the drive mechanism, regulatory controls and contractual limitations, and economics. Different management plans are required for onshore and offshore locations, and also for gas‐filled ‘tanks of sand’ and poorly connected oil reservoirs, especially when natural depletion results in economically low recovery.
To achieve these objectives requires the integration of static and dynamic models of the reservoir together with gross uncertainties associated with a complex natural system, as well as models of surface facilities designed to optimize production from the field, economic models of OPEX, CAPEX, and price fluctuations throughout field life. The uncertainty associated with each of these inputs leads to a range of potential rewards; determining the relative value of these outcomes is the task of the whole team at the time of evaluation and prior to any investment being made.
The life cycle of an oil or gas field begins after discovery with a clear appraisal plan, to delineate the field, upon which the development program is designed, costed, and approved. Inevitably, surprises will occur during development drilling that require a change to the plan, but these should have been considered and included in the budget. An oil or gas field only begins to make money once production has started: most oil companies expect a return on investment within three to five years of this date. Thereafter, the thoughts move toward improving overall returns through innovative secondary recovery techniques or increasing ultimate recovery using more esoteric tertiary methods. Effective reservoir management should always be proactive, anticipating decline, and investing to maintain production and improve recovery through to abandonment (Figure 1.2). Reacting to decline after it has started may limit the solutions available and ultimately cost more. Both of these phases are often invoked to delay the ultimate stage of the life cycle, cessation of production and then abandonment, the costs of which should also have been included in the original development plan.
Figure 1.2 Effective reservoir management should always be proactive, anticipating decline, and investing to maintain production and improve recovery through to abandonment. Reacting to decline after it has started may limit the solutions available and ultimately cost more.
1.2 Field Appraisal
As soon as an oil, condensate, or gas field is discovered there is internal and external pressure to monetize what will have been a significant investment in the exploration phase. The appraisal plan is drawn up to try to reduce the major uncertainties in the reservoir description and thus increase confidence in the value of the potential project. A lot will depend on the data collected during the exploration phase: was the reservoir cored and logged to determine rock properties? was a well test carried out and fluid samples collected? was the well suspended or abandoned? Many operators never core or test an exploration well; they delay data gathering to the next phase. In an onshore location this may be understandable, but offshore, where the well cost is much greater, collecting the basic data may ease the subsequent decision on appraisal.
Most fields require one or more appraisal wells to build confidence before investment. In the early days of North Sea exploitation, before modern 3D seismic was available, after making a discovery, several appraisal wells would be drilled to delineate a field. In one case, a well was drilled to the north and south of the discovery and a platform located in the center: the first well drilled to the east crossed a fault that put the reservoir into the aquifer. This near disaster was corrected by locating a second platform 2 km to the west so the whole field could be successful accessed; this was before the days of extended reach wells.
An appraisal program should meet three criteria:
Information gathered must be relevant and have the potential to change your belief about a given uncertainty.
The data must have a material impact on decision‐making.
The cost of acquisition must be less than its value (
VOI
–
value of information
).
Additional 2D/3D seismic acquisition can be expensive if required for onshore appraisal, and drilling may be less costly. Drilling a well may allow the acquisition of additional core data, well logs, or drill stem tests.
The commonest way of looking at these criteria are to develop decision trees to address the different possible outcomes and their impact on the development. Ideally, appraisal will move smoothly into development planning, and thus reduce the cycle time from discovery to first production. A development team will be put together combining subsurface professionals, facilities engineers, commercial specialists, economists, and legal experts to review each aspect of the proposed project.
Glenlivet Field, West of Shetland A successful exploration well tested a seismic anomaly in 600 m of water during the summer drilling season (Horseman et al. 2014). Updip of the well the seismic response became tuned, reducing confidence in the in‐place gas volume. The vertical well was fully logged and cored over a third of the reservoir sands. Given good weather and time on the rig schedule the operator decided to drill an updip sidetrack to reduce the seismic uncertainty; the sidetrack confirmed a thick reservoir section to the edge of the anomaly, confirming the optimistic gas volume estimate. To gain access to an export pipeline a sample of the downdip aquifer was required; this sample would represent any produced water. So the operator decided to drill a second sidetrack and recover a water sample. Each sidetrack was logged to establish a reservoir correlation. There was no requirement to test the well because the core and log data confirmed a high deliverability reservoir; the gas in place could be drained by one well alone, and no further appraisal was required (Figure 1.3).
Figure 1.3 The Glenlivet Field, West of Shetland, showing the seismic response of the reservoir plus the discovery well and two sidetracks that were drilled to fully appraise the field prior to development.
Source: Courtesy of DONG Energy.
From these results a development plan was written that required the drilling of two vertical wells, each with sand screens to minimize sand invasion and downhole gauges to monitor gas production. Two new wells were planned so that neither well was over produced and there would still be a producer should either well fail. The ultimate production rates from the field would be dependent on the available capacity in the pipeline.
1.3 Volumetrics
The starting point for any field development is an estimate of the in‐place hydrocarbon volume. Is there enough oil or gas to make a development economically viable or do the hydrocarbons remain future resources and not reserves?
Conventional volumetric calculations to estimate hydrocarbons initially in‐place (HIIP) require a number of simple input parameters, most of which are in the remit of the petrophysicist. The input parameters are related in the following way:
Hydrocarbons initially in‐place:
where:
GRV
gross rock volume
NTG
net : gross
φ
porosity of net reservoir
(1 −
S
w
)
hydrocarbon saturation
B
formation volume factor
Gross rock volume (GRV) is the volume of rock between the top reservoir structure and the closing contour or hydrocarbon water contact.
Net : gross (NTG) is that part of the reservoir containing moveable fluids. In a 3D model this can be calculated from a facies model or by the application of a series of cut‐off values based on an effective porosity and/or permeability. The ratio of NTG to GRV gives the net rock volume (NRV).
Porosity is the capacity of a rock to store fluids; the pore volume of a reservoir model is the total of all cells with an effective porosity and is directly linked to the NRV. Cells with effective porosity may be defined by a facies model or by some cut‐off value.
Hydrocarbon saturation is the proportion of the pores filled with hydrocarbon rather than water; the volume of hydrocarbon plus the volume of water will be unity, Sh = (1 − Sw), where Sw is the proportion of water in the pore space. Only those cells that have been designated as being NRV will be counted in the summation to give the reservoir hydrocarbon volume.
Formation volume factor accounts for the increase in hydrocarbon volume between the reservoir and the surface; this is a function of the change in pressure between reservoir and surface conditions and depends on the fluid description.
There are a number of dynamic methods used to estimate HIIP such as decline curve analysis, material balance, or reservoir simulation; these will be discussed further in Chapter 5.
1.4 Drive Mechanism
Oil and gas reservoirs have a natural drive mechanism that provides the energy to move the hydrocarbons toward a producing well. The common natural drive mechanisms are water drive, gas expansion, solution gas drive, compaction drive, and gravity drainage. One drive mechanism initially dominates production, but a combination of mechanisms often occurs over the period of field life. Depending on the drive mechanism it is possible to estimate potential recovery factors ranging between 5 and 30% for oil fields and up to 80% for a gas field that depletes naturally (Table 1.1). To improve recovery for any field normally requires a secondary method to maintain the energy in the reservoir.
Table 1.1 Recovery factors for different fields under differing production methods. Rules of thumb!
Recovery factor
Low (%)
Medium (%)
High (%)
Oil field – by natural depletion and without aquifer support
10
15
20
Oil field – by efficient water or gas injection or strong aquifer support
30
50
60
Gas field – by natural depletion
60
70
80
1.5 Field Development
Having delineated the field and acquired the necessary reservoir and production information a development plan can be written. There will always be uncertainties in the reservoir description that will need to be considered in the development plan. The key elements are the number of wells required to drain the reservoir and the surface facilities needed to fulfill any contractual or legislative agreements. In the situation where gas is contracted on an annual basis it is possible to plan a simple rate of production per well to fulfill an agreed annual decline profile. However, if the gas market is liberated, such as in the UK, each well or group of wells is required to deliver production at hourly or daily rates to fulfill the needs of commercial and domestic users. In this latter case, having wells that can be switched on and off like a tap become essential. Oil production is managed on a different monetary basis where value is made on delivery to the refinery and the quality of the oil.
Drilling onshore is usually done on a regularly spaced pattern: initially widely spaced to allow for subsequent infill drilling or water‐flooding; these might be in the original plans or form a secondary phase of recovery. Offshore field developments require higher CAPEX including large platform structures and pipelines or storage facilities. The number of wells is often restricted by the surface facilities and wells must be engineered to maximize access to the reservoir.
Field developments are often staged or phased: a subtle distinction where staged plans are approved at time of commissioning whereas phased plans are based on the results of the initial development. In the past, many offshore fields were over engineered or displayed ‘gold plated’ solutions to basic issues. Those days are long gone, and every nut, bolt, and piece of pipe must be justified during the economic assessment of a project.
Hyde Field, Southern North Sea: Planning a new field development is a matter of looking at the potential resource and deciding how best to monetize that resource. When the UK gas market was liberated in the 1990s there was a ‘dash for gas’ by those companies with export infrastructure. Small fields that previously were uneconomic under fixed contracts suddenly became swing feeders to the existing system: wells that could be switched on and off as required. The Hyde Field was discovered in 1982 but was only brought to production in August 1993 when the economic risk could be mitigated through new technology: extended reach near horizontal wells (Steele et al. 1993). Extensive appraisal of a similar nearby accumulation indicated a number of important constraints on development: a partial gas column (~105 m); low permeability (1 mD mode); high water saturation (40%); low, natural flow rate (12 MMscf/d): effectively the field was in a transition zone. This information indicated that production wells would require some form of stimulation to achieve economic rates. Because of the partial gas column, horizontal drilling was chosen over hydraulically fractured deviated wells (Figure 1.4).
Figure 1.4 The Hyde Field, UK Southern North Sea, showing the main structural features plus the locations of the three extended reach wells drilled from a three‐slot subsea template.
To demonstrate that the field could be best exploited by this method, a pilot well was drilled and cored at the crest of the structure prior to drilling a horizontal sidetrack. The sidetrack was drilled and steered using LWD technology to maintain maximum penetration of the best quality reservoir layer: ultimately 420 m of productive reservoir was penetrated. The well was tested using a predrilled slotted liner to allow future use as a producer. The well tested at a rate of 69 MMscf/d, which was a significant increase on previous vertical/deviated wells. A second horizontal production well was drilled with similar results and the field was developed with a three‐slot subsea template and a not normally manned platform.
1.6 Reservoir Simulation
These days, no development manager would consider presenting a project to an investment board without the results of a reservoir simulation to support the assumptions made. Reservoir simulation is a numerical method of representing flow in a reservoir toward the production wells and on to the surface under a number of chosen scenarios. The model can be used to run production forecasts and for assessing uncertainty for each development scenario.
The numerical model usually comprises an upscaled geological model, fluid data (pressure–volume–temperature [PVT]), and relative permeability information and fluid distribution: these form the initial state model prior to running any simulation. Well completion and production information is required plus some knowledge of the surface facilities at least at the wellhead. From these initial simulation runs it is possible to predict rates of production, pressure decline, and ultimate recovery for a given scenario, thus determining the value of the development. Ultimately, the model can be used to ‘history match’ production and then for prediction. Like all models the results are nonunique and dependent on the quality of the reservoir description. The Appendix has a simplified description of the process of reservoir simulation.
1.7 Field Production
The facilities required to handle the produced hydrocarbons depend on the type of hydrocarbons and the location of the reserves: offshore or onshore. An onshore oil field can be produced to local storage tanks prior to truck or pipeline transportation to a refinery. Onshore gas may be piped directly into local energy generation plant or liquefied for transport. Offshore platform developments for oil and gas usually require a pipeline to an offshore or onshore gathering system for further processing. Further offshore, and in deeper water, floating production and storage vessels (FPSO) are often a preferred solution.
A large part of field development planning addresses these fundamental options and the economic benefits and consequences of one or the other. Before committing to a major deepwater gas development the partner companies will construct a risk assessment based around three options: a deepwater installation to process the gas prior to export, a shallow water processing platform and pipeline, or a subsea development and a pipeline to an onshore gas processing plant. The subsea development and pipeline to shore was selected in part because it allowed for significantly greater processing capacity and opportunity for future gas discoveries to be developed through this infrastructure.
Magnus Field, Northern North Sea:Magnus was discovered in 1974, but first oil was not until 1983. The field has an estimated 1.54 billion barrels of oil in‐place with reserves of around 870 million barrels: around 56% recovery. The field was developed through a single drilling and production platform: the largest single piece steel structure in the North Sea. Initially there were facilities for 17 oil production wells, five water injection wells, and nine spare slots, and the production capacity was 140 000 BOPD and 2.5 MMscf/d of gas. The oil is exported via a 91 km pipeline to the Ninian Central Platform and then to the Sullom Voe terminal on Shetland. Produced gas is exported to Brent A via
