Field Appraisal Basics PDF [PDF]

Zitiervorschau

BHP Petroleum

Fundamentals of Field Appraisal and

Methods for Improving Appraisal Decisions by C G McKinley

Contributions from: J R Allen M Bhatia P Behrenbruch R A Hogarth

February 1998 DRAFT VERSION 2.0

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0

Contents 1

Introduction

3

2

Fundamentals of Field Appraisal

4

2.1

Development Concept

4

2.2

Development Concept Maturity

7

2.3

Economics

8

2.4

Economic Maturity

10

2.5

Appraisal Requirements

12

2.6

Appraisal Costs

15

3

Methods for Improving Appraisal Decisions

17

3.1

Appraisal Strategy

17

Maturity Crossplot Developing an Appraisal Strategy Scale and Confidence Appraisal

17 18 23

Appraisal Measures

24

Reserves Accounting Segmentation Risked Reserves Definitions

24 25 25 27

3.3

Sensitivity Analysis

30

3.4

Forward Modelling

30

Monte Carlo Forward Modelling Appraisal by Objectives Value of Information

30 35 36

3.2

4

Conclusions

41

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0

1. Introduction Field appraisal is an activity which has received growing attention in the industry over the last few years, as operators strive to improve project economics by reducing cycle times and pre-development costs. Within BHPP, a number of key exploration areas have entered the appraisal phase, and our ability to efficiently bring these projects to development could have considerable impact on the performance of the company over the short to medium term. This paper discusses the fundamentals of field appraisal, challenging some of our traditional views, and describes a number of methods which may be used to make more objective judgements and improve the decision making process. Its purpose is to generate discussion across the company and provide some guidelines as to how we might improve our approach to field appraisal, recognising the differences which can exist in appraising discoveries in different geographic areas due to geological, cultural or political constraints.

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Field Appraisal: Technical Guidelines

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2. Fundamentals of Field Appraisal Field appraisal is driven by our perception of the economic risk of developing a resource with our current knowledge. In the ideal world, if we were certain that a discovery could be developed economically, there would be no need to gather additional information and a project could proceed immediately. Any remaining risks and uncertainty would be addressed during field development and production. However, in most cases, there is considerable risk and uncertainty in the size and value of a hydrocarbon discovery, which prevents us from moving immediately to develop the field. Field appraisal involves the acquisition of additional technical information, typically seismic or well data. These data, when integrated with our existing knowledge of the field, are expected to reduce the level of risk and/or uncertainty towards an acceptable level. The decision to proceed with a development project involves two fundamental considerations. We must select a development concept, and we must ensure that the economics of the preferred development are robust. That is, we must satisfy ourselves that the selected development has a high likelihood of making a satisfactory return on investment, or in the worst case is unlikely to lose money - all based on an imperfect view of the size of the resource and the cost of development. 2.1 Development Concept “Where and when will what volumes of which fluids be produced?” Only when we have a reasonable answer to this question can we consider development options, facilities design and costs. Hence, the choice of development concept is influenced by four key factors. Location The proximity of existing infrastructure, including production and processing facilities and export routes, play an important role. Concept selection is also influenced by local factors such as bathymetry or topography, climate and the areal extent of the field. Legislative, environmental or political requirements may also exist. Timor Sea, Australia -a floating production, storage and offloading (FPSO) concept was developed for a number of small oilfields offshore northern Australia due to their remote location and lack of existing infrastructure

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Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0 Wytch Farm, UK - the onshore area of the Wytch Farm oilfield was developed in the mid 1980’s from several onshore drill sites tied back to a central processing facility. The field extends offshore into shallow waters and the original development concept for this area was a manmade gravel island with drill site, full processing facilities and pipeline to shore. The proposed island was located only 3km from the major tourist resort of Bournemouth and within the Poole Harbour Marine Park. Due to these environmental constraints, this development concept was rejected. The offshore reserves have subsequently been developed using ultra extended reach drilling from an existing onshore site - with stepouts of up to 10km. Volumes The size of the resource generally influences the scale of the development. A well defined estimate of the reserves to be developed is often critical to concept selection and maximising the value of the project. A poorly constrained estimate of reserves and production can result in facilities which are either too large - spare capacity, wasted capital - or too small - constrained production, modification costs. Ula, Norway - the Ula oilfield is trapped in massive Jurassic sands in a simple dome structure, and appraised by three crestal and one downdip well, which encountered a clear oil-water contact on the western flank. Development of 150 MMstb reserves was sanctioned using three linked steel platforms for drilling/processing/accommodation, with an export pipeline via the nearby Ekofisk field. The facilities were designed to handle up to 100 Mbd oil production. The first three downdip wells on the eastern flank , which were planned as peripheral water injectors, all encountered a full oil column. Further drilling confirmed a deeper oil-water contact, and upgraded reserves to 450 Mmstb. If this volume had been expected during facilities design, processing capacity would have been doubled to optimise offtake rates. Despite expensive modifications which eventually took production up to 140 Mbd, the field remained facilities constrained throughout its five year plateau period and lost in excess of $100 million in potential project value. Fluids The type(s) of fluids to be produced, including variations in amount or composition over time, impact process design, material selection, production handling requirements, injection or compression capacity and export options. Gyda, Norway - the 200 Mmstb Gyda oilfield development, like others in the area, was designed to recover low GOR oil trapped in a faulted anticline structure. During production, a large southern extension of the field was discovered. This highly productive reservoir contained high GOR oil which could not be optimally developed due to gas handling facilities constraint. During main field decline, the area was eventually brought onstream - six years after discovery.

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Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0 Natuna, Indonesia - the giant Natuna gas field is ideally located for Asian LNG export markets and contains over 200 Tscf gas-in-place. However, the gas contains over 30% CO2, which requires additional processing and gas disposal facilities, and the use of special alloys in construction significantly increasing capital and operating costs. As a result, Natuna remains uncompetitive and undeveloped. Productivity In addition to understanding the size of the resource, we must understand how and when reserves will be produced. The number and size of facilities will be influenced by productivity - well numbers, flow rates and gas/water cut development over time, pressure depletion or maintenance requirements - and may constrain how the field is produced. The economic viability of a discovery depends on the field having sufficient productivity to minimise well numbers and optimise the offtake rate. Offshore and Onshore Fields, UK, US and Australia - Figure 1 plots reserves versus well rate for a number of fields in the UK, US and Australia. Most of the offshore UK fields are economically viable, despite the high development threshold, because they are typically large and highly productive. Although Field A and Field B are similar in size, Field B - an Eocene heavy oil field - has not been developed due to low productivity. The offshore US fields are generally smaller, with lower well rates, but most are economically viable due to a lower development threshold. Even extremely small fields, such as Field C, may be developed if productivity is high. In general, onshore fields have a lower development cost and even small, low productivity reservoirs may be successfully developed. In Australia, onshore fields with reserves of only 2-3 Mmstb and well rates less than 1 Mbd are economic. However, even for these small fields it is important to have an accurate estimate of productivity prior to the development decision. Field D was developed on the assumption that well rates would be 2 Mbd. Early production wells were only able to produce 0.5 Mbd, and the field failed to make an economic return. Whilst many fields in a given play or area will have similar productivity characteristics, we must remember that anomalous fields exist and can provide the opportunity for both outstanding success and failure. Field E, located only 30km from Field D, has unusually large reserves and high productivity - making it one of the most profitable oilfields in Europe. In some cases, the productivity of a reservoir may be improved by the application of horizontal well technology (Figure 2). If a reservoir has good effective vertical permeability, a horizontal well may increase productivity by a factor of 3-5+, and delay water coning and/or gas cusping. However, in reservoirs with poor effective vertical permeability, a horizontal well may give little or no increase in productivity

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Field Appraisal: Technical Guidelines

Well Productivity (1): Development Thresholds 100

50

Offshore UK Field E

Offshore US

Field C

20

Onshore UK Onshore Australia

10

Field A Well Rate (Mbd or MMcfd)

Field D

Development Threshold Offshore UK

1

Field B Offshore US

Onshore UK

Onshore Australia

0.1 1

10

100

1000

Reserves / Technically Recoverable Volume (MMboe) 6 August, 1999C:/appraisal.ppt December, 1997

Figure 1

PERT - Australia/Asia Region BHP Petroleum

Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Well Productivity (2): Horizontal Wells

Kv/Kh=1.0 40

30

Productivity Index (stb/d/psi)

Kv/Kh=0.1

20

Kv/Kh=0.001

10

Vertical Well PI

0 0

400

800

1200

1600

2000

2400

2800

Horizontal Well Length (m) 6 August, 1999C:/appraisal.ppt December, 1997

Figure 2

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PERT - Australia/Asia Region BHP Petroleum

as the pressure support required to maintain well rates may be insufficient. A substantial productivity benefit is required to offset the incremental cost of a horizontal well - typically 30 - 100% more than an equivalent vertical well. Horizontal wells may also be successfully employed where access and sweep, rather than productivity, is the critical factor. A single horizontal may penetrate and drain several isolated fault blocks or, combined with extended reach drilling technology, recover hydrocarbons from peripheral areas of a field which would not otherwise be developed. Griffin Field, Australia - the Birdrong reservoir in the Griffin field is a heterogeneous, low productivity reservoir. Development using vertical wells (PI = 3) is uneconomic. However, the reservoir has been successfully been developed using three high angle to horizontal wells which have improved well productivity by a factor of 3-5. 2.2 Development Concept Maturity The stages which lead towards the selection of a single development concept can be described in terms of the development concept maturity of a discovery (Figure 3). Concept Uncertain The development concept for a discovery is considered to be uncertain when we are unable to identify, with a reasonable degree of certainty, a realistic development option. This may be due to lack of key information - the size of the resource, fluid types and reservoir productivity may be unknown or ill defined - or technological barriers, such as development in ultradeep water or ultra high pressure areas. Appraisal to identify development concepts may be justified, with acquisition of new information aimed at removing uncertainties. Multiple Options In many cases, where we have more information, or technology is not a barrier, there may be multiple options - two or more identified, realistic concepts for development of a discovery. Typically, we carry these options because the range or possible reserves is wide, and each option is often best suited to a particular field size and offtake. Appraisal to eliminate development options may be justified, with the acquisition of additional information aimed at narrowing the reserves range. In some cases, where the field reserves and potential production are well defined, we may still have alternatives due to several tie-in options or export routes. In the latter, more refined development cost estimates and economics evaluation may be required.



Field Appraisal: Technical Guidelines

Development Concept Maturity

Concept Maturity

Concept 1

Concept 2

Concept 3

Justification

Concept Uncertain

"

"

"

Identify development concepts

Multiple Options

✖

✔

✔

Eliminate development option

Single Selection

✖

✔

✖

Optimise development plan

" ✔ ✖ 6 August, 1999C:/appraisal.ppt December, 1997

Figure 3

Constrain development Reduce concept risk and/or uncertainty

Unidentified Identified Excluded

PERT - Australia/Asia Region BHP Petroleum

Single Selection In order to make a development decision, we must make a single selection for our development concept. This may be done by choosing our preferred option from a number of options, in the light of additional information which refines our understanding of the field. In some circumstances, there may always be only one development option available due to specific infrastructure, geographic or legislative considerations. Appraisal to optimise the selected development concept may be justified, although it is often difficult to justify the additional appraisal expenditure against the improvement in economic value - which may result from better definition of throughput capacity or process design etc. 2.3 Economics “What volumes will be produced when, at what price, and for what costs including taxes?” Only when we have a reasonable answer to this question can we evaluate the economics of a development option. Hence, the economics of field development is influenced by five key factors, some of which may be controlled or influenced by an operator, and some of which are generally outside our control. Reserves Whilst the size of the in-place resource is predetermined and outside our control, an operator can maximise both the volume and value of reserves recovered from a field. This requires a sound understanding of in-place volumes, reservoir heterogeneities, productivity and recovery mechanisms. Prudent reservoir management and the successful implementation of secondary or tertiary recovery methods can both accelerate and increase field reserves. Prudhoe Bay, Alaska - the giant Prudhoe Bay oil and gasfield was discovered in 1967, and developed in the 1970’s with estimated reserves of 9600 Mmstb. The initial field development plan was based on gravity drainage, with pressure support from gas re-injection into the large gas cap. In the last ten years, a number of pilot and full scale enhanced oil recovery (EOR) projects have been implemented including a downdip pattern waterflood and water-alternating-gas (WAG) injection. New technologies such as horizontal wells and coiled tubing sidetracks have also been employed to economically access bypassed oil zones. As a result reserves have been upgraded to over 12000 Mmstb, despite little change in estimated in-place volumes. The use of the term reserves refers only to volumes which are, or have the potential to be, economically recoverable. Volumes which could technically be recovered, but are considered uneconomic, are referred to as technically recoverable volumes.

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 Product Price In general, product prices are controlled by global energy demand, economic cycles and political events. However, an operator can have some influence over price by developing hydrocarbon types which are in demand, attracting a price premium, sound marketing and active hedging against unfavourable price and/or forex movements. Kutubu, PNG - the Kutubu oilfield development in the remote highlands of Papua New Guinea, produces light, sweet crude from the prolific Toro reservoir. Oil is exported via pipeline to a marine terminal in the Gulf of Papua and offloaded directly to tankers for transport to refineries. The crude is ideally suited to most refining processes, being easy to breakdown with no significant residues, and is in demand from refineries on the east coast of Australia and west coast US. As a result, Kutubu crude consistently attracts a premium over the regional marker, Indonesian Tapis crude. Capital and Operating Costs The cost of appraising, developing and producing a discovery is often a major factor in field economics, particularly in remote or offshore environments. The cost of appraisal can vary considerably, depending on geographic location and the level of confidence required to reach a development decision. Development costs may be minimised through innovative design, synergy with existing facilities and efficient project management and execution. During production, efficient operation and the tie-in of satellite developments to extend field life and reduce operating costs plays an increasingly important role. Elang/Kakatua, Australia - the Elang/Kakatua development, offshore northern Australia has minimised development costs by leasing an FPSO facility which BHPP used previously on the Skua field. Griffin Area, Australia - the main Zeepaard reservoirs in the Griffin and Chinook Scindian fields, offshore western Australia, are prolific producers which are now entering decline. Rising unit operating costs may be curtailed by further development of the overlying Birdrong reservoir. Two new horizontal wells and workover of an existing well to provide pressure support is expected to boost production and extend the economic life of the field. Fiscal Regime Although there is often little room to alter the fiscal regime within which a development occurs, there can be opportunities to amend fiscal terms to take account of changing levels of risk or economic return. Entry into unexplored or high risk areas, or the development of sub-economic satellite fields in a mature basin, may attract tax or other financial concessions.

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Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0 Marginal Field Development, UK - the giant North Sea oilfields developed in the 1970’s and early 1980’s have been very profitable under a benign UK fiscal regime. However, in the late 1980’s the number of smaller field developments began declining as operators faced the relatively high costs and risks of these marginal projects. The petroleum industry actively lobbied the British government, highlighting the changing risk/reward balance and requesting lower taxes and other incentives to develop these resources. In the early 1990’s the government announced sweeping changes in the treatment of marginal fields, encouraging many new small field developments which have taken the UK to a second peak in oil production in the late 1990’s. Cycle Time Reducing the time between discovery and first production, and accelerating production without loss of reserves, can significantly increase the economic value of a project (Figure 4), provided that the main risks and uncertainties have been correctly identified and managed. In some cases, the commercial pressure to reduce cycle time may compromise genuine appraisal requirements, and may then result in loss of value through inappropriate development or production. In practical terms, reduced cycle times require an early, clear direction and fully aligned partnerships between joint venturers, contractors and government. Foinaven, UK - Foinaven, discovered in 1990, is the first deep water Atlantic development, off the west coast of Scotland. Following encouraging results from early appraisal wells, the field was sanctioned for fast track development using an FPSO facility. It was recognised from the outset that this approach may not lead to the optimal development, but a rapid return on the substantial investment was essential to project economics. Both appraisal and detailed facilities design were undertaken simultaneously, with modifications as a result of new information being incorporated where possible. As a result, this frontier project has gone from discovery to first oil in seven years. Whilst this in itself is a remarkable achievement and success, more production history will be needed to determine whether the project will succeed. Given the lack of control we have over product prices or fiscal regime, an operator may improve the economics of a development by increasing reserves, reducing development costs and shortening cycle times (Figure 5). 2.4 Economic Maturity The degree of economic risk, based on the viability of a development across a range of possible scenarios, can be described as the economic maturity of a discovery (Figure 6).

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Field Appraisal: Technical Guidelines

Cycle Time

80

Cum Cash Flow ($m)

Cum Cash Flow ($m)

80

40

0

6.0 years

13.5 years

-40

40

0

3.5 years

11.0 years

-40

4.0 years

2.0 years

-80

-80 0

4

8

12

0

Time (yr)

8

12

Time (yr)

NPV10 = $16.9 m 5 August, 1999C:/appraisal.ppt December, 1997

4

NPV10 = $28.0 m Figure 4

PERT - Australia/Asia Region BHP Petroleum

Uneconomic A discovery is considered to be uneconomic if it fails to make an acceptable return from any scenario, including upside cases. No further appraisal is justified, as additional information is unlikely to make the project economic at this time. A substantial change in economic conditions e.g. oil price or fiscal terms, or a technological breakthrough which lowers development cost e.g. compact LNG, is required. Feasible A discovery is considered to be economically feasible if it makes an acceptable return from upside scenarios, even though the most likely view is that development is uneconomic.

Appraisal to establish an economic project may be justified, with acquisition of new information aimed at proving the upside potential of the discovery. Viable A discovery is considered to be economically viable if the most likely scenario makes an acceptable return, even though downside scenarios may be uneconomic. Appraisal to provide downside protection may be justified, with acquisition of new information aimed at removing risks and adding proven reserves. Robust A discovery is considered to be economically robust if it makes an acceptable return from any scenario, including downside cases. A discovery can be economically robust for at least one development option, even though other development options have not been eliminated. In these cases, further appraisal to constrain the development concept may be justified. Even when a discovery is fully mature - robust, single selection - further appraisal to optimise the development plan may be justified if the improved value of the project is greater than the cost of continued appraisal. In practical terms, however, this type of appraisal is often difficult to evaluate and support. The economic maturity of a discovery can change without any further appraisal, due to breakthrough of technological barriers or improved economic assumptions e.g. higher oil price or discount rate. Key changes in the maturity of a discovery are also linked to the BHPP tollgate process.



Field Appraisal: Technical Guidelines

Shifting the Balance

Developable Reserves

Efficient Process Clear Direction Partnerships

Product Price

Negotiation Skills Facilities Design Government Influence Well Numbers Efficient Operation Satellite Tie-In Product Quality In Place Volumes Marketing Reservoir Productivity Recovery Factor Near Field Exploration

Cycle Time

Capital and Operating Costs

5 August, 1999C:/appraisal.ppt December, 1997

Fiscal Regime

Figure 5

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Field Appraisal: Technical Guidelines

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Field Appraisal: Technical Guidelines

Economic Maturity

Economic Maturity

Downside Most Likely

Upside

Uneconomic

✖

✖

✖

No appraisal justified

Feasible

✖

✖

✔

Establish economic project

Viable

✖

✔

✔

Provide downside protection

Robust

✔

✔

✔

Optimise development plan

✔ ✖ 6 August, 1999C:/appraisal.ppt December, 1997

Figure 6

17

Constrain development Reduce concept risk and/or uncertainty

Economic Uneconomic

PERT - Australia/Asia Region BHP Petroleum

Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Development Concept and Economic Maturity Project Identification

Project Definition Blackback

Single Selection

Development Concept Maturity

Multiple Options

SE Mananda

Scott Reef

Moran

Sunrise Area

Lambert

BayuUndan Gas

BSFN-ROD

Bayu Undan Liquids

Concept Uncertain Ultra Deepwater GOM

Uneconomic

Neptune

Feasible

Viable

Robust

Economic Maturity 5 August, 1999C:/appraisal.ppt December, 1997

Figure 7

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PERT - Australia/Asia Region BHP Petroleum

New discoveries which are potentially economic or existing, uneconomic discoveries which become economically feasible, may be considered to have entered the project identification phase. Discoveries which are highly mature - those with a high probability of being economic based on one or two clearly identified, workable development concept(s) - may be selected for further study and progression towards development - this represents the start of the project definition phase. 2.5 Appraisal Requirements The appraisal requirements for two discoveries of similar size, with similar risks and uncertainties may differ markedly due to a number of external factors. In considering an appropriate level and cost of appraisal we must also consider the following: Market - Oil or Gas? Oil is an easily transported product which is freely traded on the world market at spot prices. In contrast, gas is usually sold by long term contract to consumers - power generators, heavy industry or domestic users - who demand security of supply. Gas supply may be via an onshore gas pipeline system or via LNG export, involving expensive, complex processing facilities and shipping fleet. For many gas developments, appraisal must be more thorough to ensure that contract volumes are met, and high facilities costs are justified. NW Shelf Project, Australia - the NW Shelf Project exports over 7 mtpa LNG to Japanese energy companies. These buyers demand security of supply over the 20 year period of the sales contract, and a high degree of confidence in gas reserves was required prior to signing a sales contract in the mid 1980’s. During early appraisal, reserves from two giant gasfields, North Rankin (8 Tscf) and Goodwyn (4 Tscf), were thought to be sufficient to meet a gas sales contract. However, in order to prove P90 reserves of 10-12 Tscf, both fields were extensively appraised. The nearby Angel discovery, which is still not developed, was also appraised to meet the proven reserves target and provide some form of contingency. Location - Onshore or Offshore? The cost of development offshore is typically an order of magnitude more expensive, and less flexible, than onshore development unless an onshore location is particularly remote or inaccessible. As a result, appraisal in offshore situations generally needs to be more thorough before a development decision can be taken. For offshore subsea developments, the option to use appraisal wells for later production or injection may influence or limit well location and data acquisition. Onshore Projects - whilst many onshore developments are relatively low cost, some major onshore projects have proved to be as expensive, or more expensive, than a similar sized offshore development. These include: Cusiana/Cupiagua, Colombia - high well costs, steep terrain Kutubu, PNG - remote location, mountainous terrain Prudhoe Bay, Alaska - remote location, arctic climate Infrastructure - None or Existing? The cost of the first development in an area may

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 be high if export pipeline and terminal facilities are required. With no guarantee of subsequent developments, appraisal requirements may be greater to reduce risks on the higher cost of greenfield facilities. In contrast, second stage developments may have the benefit of existing pipeline networks or facilities, and even small satellite fields may be tied-in economically. In these circumstances, little or no appraisal of a discovery may be required e.g. tie-in of discovery well for immediate production to nearby field. However, it is often the owners of the first stage developments and infrastructure who make better economic returns, as they often benefit from lucrative pipeline tariffs and extended field life from the early fields. Kutubu, PNG - the 300 MMstb Kutubu oil development, in the Papuan highlands, was Papua New Guinea’s first petroleum project. At the time of project sanction, no other commercial discoveries had been made and the project therefore had to bear the full cost of infield facilities, 400km overland pipeline to the Gulf of Papua, and marine export terminal. The development cost of $1 billion was supported by a high level of confidence in reserves from over 30 exploration and appraisal wells on the structure. Cooper/Eromanga Basin, Australia - the 40 MMstb Jackson oilfield in southwest Queensland is one of Australia’s largest onshore oilfields supplying oil via pipeline to a refinery in Brisbane. Following the development of Jackson, many small 1-5 MMstb discoveries in the area were successfully developed, with production from the discovery well transported via road to Jackson for processing and export. Timing - Single Stage or Phased Development? Many development schemes, usually larger ones, require the building and installation of all facilities prior to first production. In some circumstance, particularly onshore, a field may be developed in phases, with limited initial expenditure, and the benefit of production history before committing further capital. In these cases, full field appraisal may not be complete before the initial development decision is made. Don/Deveron, UK - Don and Deveron are small, complex oilfields located close to the giant Thistle oilfield in the northern North Sea. Early appraisal wells had shown the fields to be highly faulted, with a number of isolated reservoirs containing a variety of fluid types. Extensive appraisal to resolve these uncertainties would erode the value of these marginal fields. Instead, they were developed in several phases to mitigate the outstanding concerns. The initial development comprised an extended reach platform well on Deveron and two subsea wells on Don. The Deveron well was a success, and was followed up by two further wells to boost production. Although early production from Don was encouraging, economic rates could not be sustained and the second phase of the development was cancelled. Economy - High or Low Price Forecasts? The current economic climate, and forecasts of future market demand and price forecasts can have significant influence on appraisal requirements. These may influence the assumptions we make in our economic analysis, and the amount of capital available for both appraisal and 20

Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0 development activities. Although technical appraisal requirements do not change with economic climate, the pressure to limit appraisal spending in times of low prices or demand may be considerable. The irony of the economic cycle is that fields which were appraised during high oil prices, often realise low prices during peak production and vice versa. Hutton, UK - the Hutton oilfield in northern North Sea was appraised and developed in the early to mid 1980’s, during a period of high oil prices. The development used the world’s first tension leg platform (TLP) and capital costs were very high. The field came onstream in 1986, one year before a major and sustained oil price fall. Full life cycle economics for the field are marginal to subeconomic and had the field been considered for development a few years later, the project would not have gone ahead. Ettrick, UK - the Ettrick oilfield is a small, marginally economic oilfield in the central North Sea, which was extensively appraised during the early 1980’s. The project was considered for development during the late 1980’s - when oil prices ranged from $10-14/bbl - and was rejected, requiring higher to make an acceptable return on investment. Had the project gone ahead, the field would have delivered most of its production during the mid 1990’s, when average oil prices were well above the economic threshold. These differences are highlighted by comparing the hypothetical appraisal of two similar discoveries, in terms of size, risks and uncertainties. Discovery A is an onshore oil field in an established producing area, 15 km from the nearest oil processing and export facilities. Current reserves estimates range from 100 to 1000 MMstb. The operator has opted for a phased development option, with an initial 50 Mbd production facility with the potential to add further capacity up to a maximum of 300 Mbd. Recent and forecast oil prices are high due to constrained supply. The appraisal requirements for Discovery A are minimal, and the initial development may be economically robust after only two or three wells. Further appraisal will be required before or during the development of later phases. Discovery B is an offshore gas field in a undeveloped basin, 500 km from shore. Current reserves estimates range from 600 to 6000 Bscf. The operator has opted for a single stage LNG project and secured a 15 year, 3 mtpa export contract. Recent and forecast gas prices are low due to gas market oversupply. In the case of Discovery B, appraisal requirements are signficant as the operator must prove up sufficient reserves to met the gas sales contract, and ensure that downside scenarios remain economic despite the high capital cost of the development. It may take 10+ wells to reach this level of confidence. This may be difficult to justify in the prevailing economic climate.

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DRAFT VERSION 2.0 2.6 Appraisal Costs The cost of appraising a discovery can vary considerably, depending on the types of data required, geographic location and the level of confidence needed to reach a development decision. Technical information obtained during appraisal can be broadly divided into two categories - remotely sensed and direct information. Basic remotely sensed information, such as satellite images or airborne gravity and magnetics data may be acquired cheaply - typically less than $0.2 million - and may be useful in determining the structural size and complexity of a discovery in onshore environments. Reflection seismic data is the most common form of remotely sensed data used to appraise hydrocarbon discoveries. The scale of seismic operations can range from a few infill 2D lines to closely spaced 3D surveys covering the entire area. The cost of seismic acquisition depends not only on the size of the survey, but the environment in which the data is acquired. Small onshore surveys in easily accessible terrain may cost only a few hundred thousand dollars. Offshore, acquisition is generally easy and costs are generally related to the size of the survey and the level of activity and competitiveness in the local area - costs can vary from less than $1 million to more than $10 million. In rugged or inhospitable onshore areas, the acquisition of 3D seismic data can be time consuming and expensive, costing $20+ million in some instances. Reprocessed seismic data may also be considered an appraisal tool, as the enhanced imagery may significantly reduce risk or uncertainty. For example, the number of appraisal wells required may be less, if a predictive reservoir model based on seismic attributes is confirmed by later well results. Direct information is obtained from wells, and includes information which can be used to refine our understanding or both the static, or in-place, resource and the dynamic, or production, potential. Well costs, like seismic, vary greatly depending on the environment, well length and amount of data acquired. Onshore appraisal wells may be drilled to shallow objectives for less than $0.5 million. In more remote and rugged areas, where logistic support of drilling operations is a large proportion of costs, and in areas of complex geology, onshore wells can cost in excess of $30 million. In offshore environments, drilling of simple shallow wells as part of an ongoing programme may cost $1-2 million. Contracting a specialist rig to drill a deep high pressure and/or temperature appraisal well in a remote offshore area can cost upwards of $30 million. The amount of data acquired in a well also influences appraisal costs, although in most instances the cost of data acquisition is a fraction of the cost of drilling to the target. Whilst it is important to consider ways of minimising data costs - only acquiring 22

Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0 information which will significantly impact the development decision - it is important to recognise the prohibitive expense of returning to acquire information which was not collected in earlier wells. Well data types which are commonly used to improve the static reservoir description include well logs, core and biostratigraphic data, fluid samples and static pressure data. The dynamic reservoir description can be improved with laboratory core measurements and production data from MDT and well testing. However, well test data can be expensive to acquire - a short term drill stem testing (DST) can add $1-5 million to the cost of a well. In complex reservoirs, a more accurate estimate of long term productivity may be gained from extended well testing (EWT). The ability to perform an EWT is influenced by the location of the discovery and local environmental regulations. In onshore oil and gas fields, temporary connection of the well to nearby infrastructure may permit extended testing. Offshore, EWT has been limited to oil reservoirs, with production via a contracted testing, storage and offlaoding tanker. Although this can be a very expensive operation, the cost of an EWT is generally offset by the sale of production. In the early stages of appraisal it is relatively easy to justify appraisal expenditure given the large reduction in risk or uncertainty and, if successful, large improvement in project value which additional information will provide. In later stages of appraisal, as each new piece of data has less influence on the development concept and economics, it becomes important to recognise the point at which further appraisal expenditure may erode the value of a project. If a development does not proceed, usually due to unacceptable technical, commercial or political risks, the cost of appraising the field may have to be written off - although many fiscal regimes provide tax or other financial concessions for expenditure writedowns.

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Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0

3. Methods for Improving Appraisal Decisions Making appraisal decisions - which well(s) to drill, what data types to acquire - is a subjective process. It involves judgements based on experience, knowledge and technical analysis. Traditionally, we have used our judgement to assess the impact of new technical data on our geological models, reservoir description, estimates of resource size etc. Often, gaps in technical knowledge are filled simply to improve our understanding, without considering whether this significantly impacts the choice or design of development concept, or project economics. In many cases, our decisions have become too subjective, focussed on technical information and knowledge, and considering only the immediate future - not the entire appraisal process. There are a number of simple methods, both qualitative and quantitative, which may be used to improve the quality of appraisal decisions we make. These methods emphasise the need for a clear appraisal strategy, simple quantitative analyses to support our decision making and measures to evaluate the success of appraisal activities. 3.1 Appraisal Strategy At the end of the appraisal process, we aim to have an economically robust development ready for project sanction and execution. To develop an effective appraisal strategy we must clearly understand where we stand today, what is required to achieve our goal, and some measure of our progress along the way. Maturity Crossplot Traditionally, we categorise the current status of field appraisal with a few generic terms - post-discovery, early appraisal, late appraisal - and describe the level of risk and uncertainty by estimating a reserves range using deterministic or probabilistic volumetrics. Appraisal requirements are generally determined by assessing what technical information is needed to address the major risks and uncertainties. We tend to look one step ahead at a time, and use experience to judge which well location will have the biggest impact on the in-place or reserves range. A simple method of portraying the current status of a discovery is in terms of its development concept maturity and economic maturity, as described previously. By plotting each discovery on a simple crossplot of the two measures (Figure 7), we create a clear understanding of where we stand today and the direction we must move in to reach a development decision. In most cases, the preferred development concept for a discovery is selected before the project is economically robust. On the maturity crossplot, most fields tend to move vertically, then to the right. Of course, in acquiring the information needed to select a development concept, we may also improve the economics of the project by finding larger volumes or adding proven reserves. 24

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 The illustrated example plots the maturity of a number of undeveloped discoveries in BHPP portfolio. In some cases, further appraisal must focus on both selecting a development concept and improving economics e.g. Neptune. In other cases, such as Moran, the development concept is well defined and the project requires additional volumes or greater confidence in the discovered volume to proceed. Developing an Appraisal Strategy The strategy we adopt in appraising a discovery often depends as much on external, non-technical factors as it does on technical considerations and experience. Influences such as economic climate, corporate priorities - both our own and our partners - and political factors must be considered. In general, appraisal strategy consists of two elements - direction and pace. The direction, or focus, of our appraisal efforts depends on the business goal we are trying to achieve, and may change over time. A clear vision of the desired outcome at the beginning of the appraisal process is essential - standalone oil rim development within five years, low cost tieback to existing facilities within two years, prove significant gas potential within three years, or exit area. The pace of appraisal, whilst inherently linked to our business goals, is more often driven by budgetary considerations, partnership issues, rig availability and legislative requirements. In some areas of the world, operators must appraise a discovery and declare commerciality within a relatively short period - or lose the acreage. Colombia - fiscal terms in recently awarded licences to explore foldbelt plays in the Colombian foothills include a limited five year period to declare field commerciality. Only proven volumes within a given radius of successful wells are considered - inferred volumes updip from a dry hole are not include in the commercial area. This regime has required back-to-back appraisal drilling with several rigs - to ensure sufficient areal well coverage - and few downdip delineation wells - to ensure few dry holes. In these circumstances, appraisal activity may be fast paced and not always optimal. In other cases, lack of strategic direction and alignment between partners may delay appraisal, eroding the potential value of any project. Some common appraisal strategies are briefly described below. A Conventional appraisal strategy is not driven by commercial or legislative pressures to reduce cycle time. Acquisition of additional information is carefully planned, with sufficient time between activities to fully evaluate data. 3D seismic data is generally acquired after one or two wells. A discovery well on the crest of the structure is usually followed by a downdip well to delineate fluid contacts, and lateral stepouts to evaluate the areal extent of the field. Appraisal tends to be thorough, with all major technical uncertainties addressed before a development decision is made. A Fast Track appraisal strategy is driven by commercial or legislative pressures to 25

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 reduce cycle time. This strategy is often adopted in proven areas, with a good knowledge of local geology and existing, nearby infrastructure providing the opportunity for low cost development. In some cases, fast track developments may not be appraised at all, with simple tie-back of the discovery well to adjacent facilities. Major risks and uncertainties may not be fully understood or addressed, although the potential rewards from early development may outweigh these risks. If fast track appraisal is forced by licence terms, an operator may speed up appraisal by drilling wells simultaneously, and acquiring 3D seismic early. This approach may be inefficient as the results from one well may have influenced the location or objectives or another. Recently, there have been a number of fast track developments which have proven to be sub-optimal or unsuccessful because key data e.g. 3D seismic was not acquired prior to the development decision. Cossack, Australia - the 200 MMstb Wanaea oilfield, offshore northwest Australia, was discovered in 1989. The smaller Cossack oilfield, located just 5km to the northeast, was discovered in 1990. In early 1991, with just one well and recently acquired 3D seismic data still being processed, the field was sanctioned for fast track development using a converted tanker FPSO facility to deliver early production prior to development of Wanaea. During project execution, interpretation of the 3D dataset revealed a much smaller, more faulted structure. Two appraisal / development wells were hurriedly drilled on the flanks of the field, both of which encountered the reservoir deep to prognosis. Reserves were downgraded from 80 MMstb to 30 MMstb, and fast track development eventually cancelled. Cossack has been subsequently developed as an integral part of the Wanaea project. A Sales Contract appraisal is driven by the need to prove a specific volume of reserves, usually gas, to enter into a long term sales contract. In many cases, a large volume of gas is required and the early stages of appraisal are focussed on determining whether the discovery is sufficiently large to be attractive. If early signs are positive, the later stages of appraisal are focussed on proving up P90 reserves as efficiently as possible. If the discovery is too small, exploration and appraisal of other structures in the area may be needed, and gas gathering infrastructure developed. NW Shelf Project, Australia - the NW Shelf Project exports over 7 mtpa LNG to Japanese energy companies. These buyers demand security of supply over the 20 year period of the sales contract, and a high degree of confidence in gas reserves was required prior to signing a sales contract in the mid 1980’s. During early appraisal, reserves from two giant gasfields, North Rankin (8 Tscf) and Goodwyn (4 Tscf), were thought to be sufficient to meet a gas sales contract. However, in order to prove P90 reserves of 10-12 Tscf, both fields were extensively appraised. The nearby Angel discovery, which is still not developed, was also appraised to meet the proven reserves target and provide some form of contingency.

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Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0 An Equity appraisal strategy is driven by the need to establish and maximise equity position in a discovery which is located in one or more licence areas. Generally, the initial discovery in one licence will be rapidly followed by a well in the other licence aimed at confirming the mapped extension, and giving the second operator a negotiating position. Although early appraisal may be done independently, later stages are often planned and executed jointly, as part of the unitisation process. The location of, and data acquired in, appraisal wells may have an impact on equity split and both operators will aim to acquire information in areas which they perceive will strengthen their position, and not drill to reduce uncertainty in areas which may weaken equity. These factors must be recognised when making a development decision, because key uncertainties may not have been addressed during appraisal due to equity sensitivity. There is also a risk that excessive equity driven appraisal might erode overall project value. Bayu-Undan, ZOCA - the Bayu-Undan gas condensate field is located in the Zone of Cooperation (A) between Indonesia and Australia. The field was discovered by well Bayu-1 in licence PSC 91-13, which was rapidly followed by well Undan-1 in adjacent licence PSC 91-12. Despite eight further appraisal wells, aimed largely at resolving major technical uncertainties and risks, large uncertainties in in-place volumes and areal extent of the field remain. On the flanks of the field, further appraisal to resolve these issues, either prior to or during development, is unlikely as negative results may provide conclusive data which impacts the equity position of either PSC. A Long Term appraisal strategy is driven by market demands and current technology limits. In some cases, a discovery may be economically feasible or viable, but cannot be developed due to lack of market or immature technology - development may not be possible for five to ten years or more. Ideally, no appraisal should be undertaken until a clear market opportunity or technological breakthrough occurs. However, licence terms may require a specific level of expenditure or activity, and appraisal may occur in a number of phases over many years. This often leads to frequent review of data, without any real gains, and loss of corporate knowledge as the team working the field changes. Sunrise-Troubadour, Australia - the Sunrise-Troubadour area, offshore northern Australia, contains significant gas condensate resources which have been intermittently explored and appraised since the 1970’s. The fields lies in a remote area, with no existing infrastructure, and development has been hindered by technical risks and high costs in a competitive Asian gas market. However, the combination of proximity to market, low retention costs and low political / fiscal risk make these fields an attractive long term option as demand for energy in the region is predicted to grow.

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 A Development Utility appraisal strategy is driven by a desire to minimise development costs and re-use existing exploration and appraisal wells in field development. This strategy is often adopted in remote or inaccessible areas with high well costs. Whilst this approach may lead to a cheaper development, it can also compromise the appraisal programme - in terms of well locations and data acquisition. For example, downdip wells to test the hydrocarbon-water contact may not be drilled as these wells often have little development utility. In wells which are targetted as future producers, well test data may not be acquired as this could affect the completion and/or suspension design. Kutubu, PNG - the Kutubu oilfield complex in the remote highlands of Papua New Guinea was appraised by over 30 wells, costing $5-15 million each. In early appraisal, no conscious effort to locate wells for future development use was made. However, in the later stages of appraisal a number of wells were relocated or sidetracked to maximise their utility as producers. Over 40% of appraisal wells have been re-used in development. A Near Field Exploitation appraisal strategy is driven by a desire to improve or extend production from an existing field by developing additional volumes from nearby discoveries. It is important to undertake the exploration and appraisal of adjacent structures early enough to ensure their development before end of mainfield life is reached. This is not always easy to achieve as the focus and impetus to develop satellite resources may not come until production is in steep decline. Potential tie-ins may also be owned by other parties with different priorities Perseus, Australia - the giant North Rankin and Goodwyn gas condensate fields, which supply gas from Triassic reservoirs to the NW Shelf LNG Project, were discovered and appraised during the 1970’s and 1980’s. North Rankin began production in 1984, and in 1991 an extended reach platform well was drilled to appraise a Jurassic gas accumulation in the graben between the two fields which was discovered during early appraisal. Estimated reserves were 0.5 to 1.0 Tscf. The well was successful, and brought immediately on stream, providing valuable production data over the next four years. Over this time, reservoir pressure declined slowly and the potential for significant upside volumes was recognised. Four appraisal wells were drilled in the mid 1990’s, proving up a resource of 5.0+Tscf which could now drive future NW Shelf Project expansion. 1/3-3 Discovery, Norway - the 10-20 Mmstb 1/3-3 discovery lies 8km north of the 200 MMstb Gyda field, central North Sea. It was discovered in the 1980’s, and no further appraisal was undertaken due to its small size. Gyda started production in 1990, and after an erratic two year plateau entered steep decline in the mid 1990’s. Only then, did attention focus on the possibility of further appraisal and subsea tie-back of 1/3-3. Unfortunately, the opportunity to capture these reserves may have been missed due to the long lead time between a development decision and peak production, and the impending end of Gyda field life.

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Field Appraisal: Technical Guidelines

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DRAFT VERSION 2.0 A Field Cluster , or Area Wide Development, appraisal strategy may be applied to undeveloped resources where there is insufficient volumes in any one structure to justify economic development. In these cases, appraisal of two or more structures may occur in parallel, reducing the cycle time from discovery to development, but also compromising the ability of one appraisal programme to learn from, or influence, the other. The scale of field clusters can range from joint development of two or three small, adjacent fields to regional hydrocarbon gathering projects. Elang-Kakatua, Australia - the 10 MMstb Elang oilfield, offshore northern Australia, was discovered and appraised in the mid 1990’s. The field has insufficient reserves for standalone development, but with an additional 5 MMstb volume discovered at nearby Kakatua, the cluster is to be developed using a leased FPSO vessel. It is expected that the 1 MMstb will also be developed using these facilities. ETAP, UK - the Eastern Trough Area Project (ETAP) is a $2.6 billion dollar development of oil, gas condensate and gas fields in the central North Sea. It involves 3 operators and 8 fields, none of which was economically developable on its own. Many of the larger gas fields were discovered and appraised in the 1970’s and early 1980’s, but it was only with the addition of significant liquid volumes from a number of smaller discoveries in the late 1980’s that the project became economically viable. A Production Led appraisal strategy is driven by the need to understand the production history and future potential of a producing asset. Although we usually think of appraisal as an activity which precedes development, extensive appraisal may continue throughout the life of a field. In most cases, production led appraisal is linked to improving or extending production from an asset which we have owned for many years. However, it may also apply to producing or abandoned fields which have been acquired for field redevelopment. Appraisal may involve the deepening or sidetrack of existing wells to evaluate the potential of long ignored reservoirs, or extensive well intervention, workover and testing to understand the habitat of bypassed hydrocarbons. Pedernales, Venezuela - Pedernales is a giant oilfield in eastern Venezuala, containing over 1000 Mmstb of heavy oil, which has been inefficiently developed - producing only 60 MMstb from over 60 vertical wells in 60 years. Redevelopment of the field is underway, involving workover and long term testing of existing wells, and drilling of horizontal appraisal / production wells to evaluate productivity. If successful, the field will be redeveloped using modern well construction and completion technologies.

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DRAFT VERSION 2.0 Beatrice, UK - Beatrice was one of the first North Sea oilfields to be developed, located just a few kilometres offshore northeast Scotland. Oil is produced from Middle Jurassic reservoirs, although an early appraisal well had also encountered hydrocarbon shows in deeper Devonian sands. Late in field life, and following a number of successful Devonian discoveries in adjacent licences, an abandoned production well was deepened to appraise Devonian potential. Unfortunately, the well failed to encounter commercial volumes in the Devonian.

Ula, Norway - the Ula oilfield contains 450 Mmstb trapped in Jurassic sands in a simple dome structure. The discovery well encountered an oil column in deeper Triassic sands on the crest of the field, although downdip appraisal wells proved the accumulation to be of limited size and extent. The development of coiled tubing drilling technology has dramatically lowered the cost of infield appraisal and development, and in 1996 a production well was deepened to evaluate Triassic reservoir continuity and productivity. Scale and Confidence Appraisal For most appraisal strategies, there are two distinct phases of appraisal - an early stage aimed at establishing the scale of the resource and, if successful, a later stage designed to increase confidence in the proven resource leading to a development decision (Figure 8). Scale appraisal is typified by an incomplete understanding of the major factors which dictate the resource size and hence, the choice of development concept. Many segments remain untested and fluid types or contacts may be unknown or ill defined. Success or failure in any one well can dramatically alter our perception of reserves,. As a result, this period of appraisal is characterised by a fluctuating reserves range and unstable mean volumes. The primary aim of scale appraisal is remove those major uncertainties which control the gross size of resource, and therefore constrain or stabilise mean volumes. It is not necessarily aimed at increasing proven volumes or reducing the reserves range. In mature basins, where the local geology and expected field sizes are well understood, scale appraisal may require only one or two wells to confirm the expected model. In new or poorly explored areas, many wells may be required before the scale of the resource is defined - particularly in areas of structural or reservoir complexity Confidence appraisal is characterised by a generally narrowing reserves range and more stable mean volume. The primary aim of confidence appraisal is to establish the economic viability of the resource, increasing proven reserves in the most efficient manner - leading to a reduction in appraisal well numbers and an earlier development decision. As in any appraisal campaign, surprises will occur and our perception of mean reserves and associated range alter. However, the magnitude of these fluctuations

30



Field Appraisal: Technical Guidelines

Scale and Confidence Appraisal

Scale Scale

Confidence Confidence

Development Development

Large

Risked Reserves / Value

Medium

Small

Decision

Decision

No. of Wells / Time / Cost C:/appraisal.ppt December, 1997

Figure 8

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should be significantly less than in the early stages. Larger changes during confidence appraisal imply that scale appraisal issues were not fully addressed. 3.2 Appraisal Measures Being able to measure, both predictively and retrospectively, the impact of appraisal activities is a critical part of the decision making process. These measurements can be based on: In-place Volumes - provide a simple way of estimating the impact of appraisal, especially if there is limited information or there are manpower or time constraints. This approach may be used for screening studies, but has limited use in decision making as it takes no account of recovery from the field, or production rates. Reserves - is the most commonly used basis for measuring the impact of appraisal. It represents a reasonable compromise between the need to have some understanding of the recoverable volumes, to consider development concepts, and the additional time and effort required to generate production or value Production Profiles - are rarely used to measure the impact of appraisal. If production profiles are generated, there is little additional effort required to perform an economic evaluation. Hence, most studies will either use reserves or value as the basis of measurement. Economic Value - allows us to assess the full impact of appraisal - on facilities costs, cycle time etc. - as well as on reserves or production. Although this approach requires additional manpower and time, all major appraisal decisions should be supported by and reviewed using key economic measures - changes to net present value, rate of return, capital efficiency etc.. Reserves Accounting Sound reserves accounting has become increasingly important as many of our corporate performance measures are based on volume additions through exploration and appraisal. Within the industry, many different ways of calculating and classifying reserves have developed. Some operators use only deterministic calculation methods and adhere strictly to US SEC or SPE reserves classifications. Others use a variety of probabilistic calculation methods, and have developed unique in-house reserves classifications and reporting guidelines. Within BHPP, we increasingly use common probabilistic methods to estimate the reserves range, but have no standard approach to defining the volumes attributable to each exploration or appraisal well. A recurring problem has been the “overbooking” of reserves attributable to early appraisal wells, which can require a decrease in booked volumes, if the results of later wells are below expectation. By adopting a standard step-wise approach to reserves accounting during appraisal we can facilitate comparison between discoveries, and ensure progressive growth in booked reserves.

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 Segmentation Segmentation , or the division of a field into a number of geographic areas, can be used as a basis for reserves accounting and to plan the appraisal programme. The basis for subdivision of a discovery into segments (regions or areas) is usually related to structure or anticipated well spacing, although other criteria such as simple geometry, areas of common risk or cultural features are equally valid (Figure 9). Segmentation may be both areal and vertical, with over- or underlying reservoirs which have common features sharing the same segments (Figure 10). There are no hard and fast rules regarding the definition or number of segments (Figure 11), although too many segments - more than eight to ten - can result in complicated calculations and a tendency towards a narrower reserves range when added. The goal is to divide the field into a workable number of geographic areas which can be systematically appraised, and reserves volumes added. Each segment carries a risk - the chance of success - in addition to an uncertainty in the range of possible volumes. The definition of success can vary, but is usually defined as the discovery of hydrocarbons which are likely to have commercial significance in the foreseeable future. Risk is expressed as a value between 1.0 (proven success) and 0.0 (proven failure). Risked Reserves Reserves estimates for a segment or discovery may be made using deterministic or probabilistic methodologies. Deterministic volumes are based on one or more discrete scenarios in which one value is assigned for each input parameter, producing a single reserves volume for each scenario. The inputs which we consider to be our best estimates are combined to calculate deterministic most likely reserves. One or more of these most likely input parameters may be systematically varied to create a number of deterministic upside and deterministic downside cases. Probabilistic volumes are based on statistical, or Monte Carlo, modelling in which a range of values is assigned for each input parameter, producing a range of reserves volumes. Each input parameter is described by a number of discrete values and associated probabilities. A parameter distribution or probability density function is statistically fitted to these data to create a continuous range of values. Different distributions may be used to fit the data, including normal, lognormal and beta functions. The choice of function can significantly impact the reserves range, and care should be taken to ensure the fitted distribution is appropriate. The parameter distributions are combined in a Monte Carlo model, which samples each distribution and calculates volume many times - typically 1000 to 10000 - to generate a range of possible reserves. Deterministic estimates should be used to constrain and sense check the results of Monte Carlo modelling. 33



Field Appraisal: Technical Guidelines

Basis of Segmentation

2

1

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C:/appraisal.ppt December, 1997

Economic

Regulatory Figure 9

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Field Appraisal: Technical Guidelines

Areal and Vertical Segmentation

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Figure 10

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DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Reality... and if all else fails Good Seismic Imaging Poor Seismic Imaging

+ + +

+

+ +

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+ +

+ +

+

+ + 1 + 1 +

+ +

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Figure 11

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PERT - Australia/Asia Region BHP Petroleum

The reserves range is described by an expectation or exceedence curve which plots volume (V) against the probability of exceeding volume V- from the minimum value (P100) to the maximum (P0). Unrisked volumes do not include any risk associated with an undrilled segment, and are used to describe the potential reserves for each segment. Risked volumes are calculated by combining the unrisked reserves with the segment risk. This is, in effect, a discounting process to take account of the possibility that the segment may contain no hydrocarbons. In deterministic calculations, the risked volume is simply the unrisked value multiplied by the risk:

Unrisked Reserves Risk Risked Reserves

= = =

100 Mmstb 0.50 50 Mmstb

In probabilistic calculations, the expectation curve is adjusted to reflect the risk of failure i.e. V = 0, and the probability distribution of the entire reserves range (P100 to P0) factored, or compressed, to fit the remaining probability (Figure 12). Volumes at specific confidence levels, or percentiles, are usually quoted to describe the reserves range. Unrisked reserves percentiles are identified by the prefix “P” and are usually quoted at P90, P50 and P10 levels, although P85 and P15 volumes are quoted in preference to P90 and P10 in some companies. Mean (average), median (middle or P50) and mode (most likely or ML) values are also used. Risked reserves percentiles are identified by the prefix “RP” and are usually quoted at RP90, RP50 and RP10 levels. Risked mean Rmean, risked median Rmedian or RP50, and risked mode RML, values are also used. Both unrisked and risked expectation curves for two or more segments may be combined using probabilistic addition to determine the reserves range for part or all of a discovery. In probabilistic addition, the level of dependency between segments must be included - the degree to which a higher or lower outcome in one segment will result in a similar outcome in another. Dependency can vary from total positive (+1.0) to neutral (0.0) to total negative (-1.0). If no dependency is applied, outcomes will be added together randomly (Figure 13). In total positive dependency, high outcomes will always be combined with high outcomes, and vice versa - the resulting reserves range will be wider, and equivalent



Field Appraisal: Technical Guidelines

Unrisked and Risked Expectation Curves 100

Failure

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Figure 12

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DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Independent Addition (0.0) 100

100

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Figure 13

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Field Appraisal: Technical Guidelines

Total Positive Dependent Addition (+1.0) 100

100

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Figure 14

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Field Appraisal: Technical Guidelines

Total Negative Dependent Addition (-1.0) 100

100

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Figure 15

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to arithmetic addition (Figure 14). With negative dependency, high outcomes will be combined with low outcomes, and vice versa - the resulting reserves range will be narrower (Figure 15). Discoveries may also be combined in this way to estimate the reserves range for a complex of fields or an entire basin. Definitions The potential volume is the unrisked deterministic most likely reserves for a segment, estimated prior to drilling. The discovered volume is the deterministic most likely reserves for a segment, estimated after drilling. As each segment is drilled out, discovered volumes are added together arithmetically to build up the discovered volume for the field. When all segments are drilled out, the discovered volume will equal the deterministic most likely reserves for the field. The proven volume is the P90 reserves for a segment, estimated after drilling. As each segment is drilled out, P90 volumes are added together probabilistically to build up the proven volume for the field. When all segments are drilled out, the proven volume will equal P90 reserves for the field. The risked proven volume is the risked RP90 reserves for a segment. RP90 volumes for all segments, drilled and undrilled, are added together probabilistically to estimate the risked proven volume for the field. This takes into account the probability that some volumes are present in undrilled segments. When all segments are drilled out, the risked proven volume will equal P90 reserves for the field. The definitions used in our reserves databases differ from the above, and are based on US Securities Exchange Commission (SEC) definitions of proven (1P), probable (2P) and possible (3P) reserves. However, probabilistic volumetric results may be broadly equated to these definitions as follows:

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0

US SEC Reserves

BHPP Probabilistic Reserves

Proven

1P

Risked Proven

RP90

Probable

2P

Risked Mean

RMean

Possible

3P

Risked Upside

RP10

These definitions ensure that both discovered and proven volumes will be progressively added, and that adverse drilling results will not require a major downward revision in volumes. This is illustrated by using worked examples for a hypothetical oil field. Example 1 - Mid Case Outcome (Figures 16-18) This example shows a 100 MMstb oil prospect, with a predrill reserves range of 25 100 - 400 MMstb. The prospect is divided into four structural segments, based on seismic mapping, each of which is assessed to have a chance of success (risk) of 0.25. The pre-drill risked reserves range is 6 - 25 - 100 MMstb. Obviously, no volumes have been discovered or proven. Well 1 is drilled in the central segment, and discovers oil. The post-drill reserves for this segment is estimated to be 15 - 40 - 130 MMstb, although the oil-water contact has not been confirmed in the well. The segment now has a risk of 1.0, and the risks in other segments have been adjusted due to the results of well 1. The discovered volume is 40 MMstb - the mean reserves for the drilled segment, although the proven volume is only 15 MMstb. Well 2 is drilled downdip of the first well, in the same segment, to delineate the oilwater contact. Following the well, the discovered volume remains unchanged, but the proven volume has increased to 25 MMstb. Wells 3 to 5 are each drilled in a new segment, adding discovered and proven volumes on each occasion. The total discovered and proven volumes at the end of appraisal are 100 MMstb and 65 MMstb respectively. At this time the P90, RP90 and proven volumes are the same.

Example 2 - Upside Outcome (Figures 19-21) This example uses the same prospect, with the same discovery well results as Example 1.

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 Well 2, however, finds a deeper than expected oil-water contact, increasing the discovered volume to 60 MMstb, and proven volume to 35 MMstb.

Wells 3 to 5 are each drilled in a new segment and confirm the existence of a deeper oil-water contact across the field. The total discovered and proven volumes at the end of appraisal are 150 MMstb and 90 MMstb respectively. Again, the final P90, RP90 and proven volumes are the same. Example 3 - Downside Outcome (Figures 22-24) This example uses the same prospect, with the same results as Example 1 in the first three wells. Well 4, however, fails to encounter hydrocarbons. The discovered volume remains unaltered at 65 MMstb. Note how, in this example, the proven volume actually increases slightly due to better control in depth conversion and reservoir distribution the well provides despite its failure. The risk on the undrilled segment has also changed. Well 5 also fails to encounter hydrocarbons, and the discovered and proven volumes remain unchanged at 65 MMstb and 45 MMstb respectively. Even though the unrisked and risked mean volumes for the field have fallen significantly with the results of later wells, the discovered and proven volumes have been unaffected by the adverse results. Example 4 - Mixed Outcome (Figures 25-27) This example uses the same prospect, with the same results as Example 3 in the first three wells, with upside outcomes.. Well 4, however, fails to encounter hydrocarbons. Even though the unrisked mean volumes fall from 150 to 120 MMstb, the discovered volume remains unaltered at 95 MMstb. Note how, in this example, the proven volume actually increases slightly due to better control in depth conversion and reservoir distribution the well provides despite its failure. The risk on the undrilled segment has also changed. Well 5 finds only a small volume of hydrocarbons, further reducing the unrisked mean to 100 MMstb. However, the discovered volumes increases slightly to 100 MMstb, adding the small volume which has been found. Proven volume also increases to 60 MMstb, the same as the total P90 and RP90 volume. In all cases, whatever has happened to our perception of mean field volumes, the discovered, proven and risked proven volumes have increased or held steady.

44



Field Appraisal: Technical Guidelines

Example 1: Mid Case Outcome (1) - 100 Mmstb No Wells

Well 1 0.25

0.40

5 - 20 - 50 (15)

5 - 20 - 50 (15)

0.25

1.00 10 - 50 - 150 (40)

5 - 30 - 100 (25)

15 - 45 - 130 (40)

5 - 25 - 100 (20)

5 - 30 - 100 (25)

0.25

0.25

5 - 25 - 100 (20)

0.80

0.80

Unrisked Risked Discovered Proven

25 - 125 - 400 0 - 0 - 100 0 0

Unrisked Risked Discovered Proven

30 - 120 - 380 15 - 89 - 310 40 15

Well 2 0.40 5 - 20 - 40 (15) 1.00 25 - 45 - 100 (40) Key 5 - 30 - 80 (25)

5 - 25 - 80 (20)

0.80

Unrisked Risked Discovered Proven

C:/appraisal.ppt December, 1997

P90 - Mean - P10 (Det ML) RP90 - Rmean - RP10

0.80

Figure 16

40 - 120 - 300 25 - 89 - 244 40 25

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 1: Mid Case Outcome (2) - 100 Mmstb Well 3

Well 4 0.40

0.50

5 - 20 - 40 (15)

5 - 20 - 35 (15)

1.00

1.00 30 - 45 - 100 (40)

10 - 25 - 60 (25)

30 - 45 - 100 (40)

5 - 25 - 80 (20)

15 - 25 - 50 (25)

0.90

10 - 20 - 50 (20)

1.00

1.00 1.00

Unrisked Risked Discovered Proven

50 - 115 - 280 45 - 93 - 248 65 40

Unrisked Risked Discovered Proven

60 - 110 - 235 55 - 100 - 218 85 55

Well 5 1.00 10 - 15 - 25 (15) 1.00 30 - 40 - 60 (40) Key 15 - 25 - 50 (25)

10 - 20 - 40 (20)

1.00

Unrisked Risked Discovered Proven

5 August, 1999C:/appraisal.ppt December, 1997

P90 - Mean - P10 (Det ML) RP90 - Rmean - RP10

1.00

Figure 17

46

65 - 100 - 175 65 - 100 - 175 100 65

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 1: Mid Case Outcome (3) 400

Proven Discovered Mean P10 P90 RP90 Rmean RP10

350

Risked Reserves / Value

300

250

200

150

100

50

0 0

1

2

3

4

5

Number of Wells / Time

C:/appraisal.ppt December, 1997

Figure 18

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PERT - Australia/Asia Region BHP Petroleum

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 2: Upside Outcome (1) - 100 to 150 Mmstb No Wells

Well 1 0.25

0.40

5 - 20 - 50 (15)

5 - 20 - 50 (15)

0.25

1.00 10 - 50 - 150 (40)

5 - 30 - 100 (25)

15 - 45 - 130 (40)

5 - 25 - 100 (20)

5 - 30 - 100 (25)

0.25

0.25

5 - 25 - 100 (20)

0.80

0.80

Unrisked Risked Discovered Proven

25 - 125 - 400 0 - 0 - 100 0 0

Unrisked Risked Discovered Proven

30 - 120 - 380 15 - 89 - 310 40 15

Well 2 0.40 5 - 25 - 40 (25) 1.00 30 - 70 - 120 (60) Key 5 - 40 - 100 (35)

5 - 35 - 100 (30)

0.80

Unrisked Risked Discovered Proven

C:/appraisal.ppt December, 1997

P90 - Mean - P10 (Det ML) RP90 - Rmean - RP10

0.80

Figure 19

48

45 - 170 - 370 30 - 130 - 300 60 30

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 2: Upside Outcome (2) - 100 to 150 Mmstb Well 3

Well 4 0.40

0.50

5 - 25 - 50 (25)

5 - 25 - 40 (25)

1.00

1.00 35 - 65 - 100 (60)

15 - 40 - 80 (35)

35 - 60 - 80 (60)

5 - 35 - 80 (30)

20 - 35 - 60 (35)

0.90

1.00

15 - 35 - 60 (30) 1.00

1.00

Unrisked Risked Discovered Proven

60 - 165 - 310 55 - 137 - 272 95 50

Unrisked Risked Discovered Proven

Well 5

75 - 155 - 240 70 - 143 - 220 125 70

1.00

15 - 25 - 35 (25) 1.00 35 - 60 - 80 (60)

20 - 30 - 50 (30)

20 - 35 - 60 (35)

Key 1.00 P90 - Mean - P10 (Det ML)

1.00

RP90 - Rmean - RP10

Unrisked Risked Discovered Proven

5 August, 1999C:/appraisal.ppt December, 1997

Figure 20

49

90 - 150 - 225 90 - 150 - 225 150 90

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 2: Upside Outcome (3) 400

Proven Discovered Mean P10 P90 RP90 Rmean RP10

350

Risked Reserves / Value

300

250

200

150

100

50

0 0

1

2

3

4

5

Number of Wells / Time

C:/appraisal.ppt December, 1997

Figure 21

50

PERT - Australia/Asia Region BHP Petroleum

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 3: Downside Outcome (1) - 100 to 65 MMstb No Wells

Well 1 0.25

0.40

5 - 20 - 50 (15)

5 - 20 - 50 (15)

0.25

1.00 10 - 50 - 150 (40)

5 - 30 - 100 (25)

15 - 45 - 130 (40)

5 - 25 - 100 (20)

5 - 30 - 100 (25)

0.25

0.25

5 - 25 - 100 (20)

0.80

0.80

Unrisked Risked Discovered Proven

25 - 125 - 400 0 - 0 - 100 0 0

Unrisked Risked Discovered Proven

30 - 120 - 380 15 - 89 - 310 40 15

Well 2 0.40 5 - 20 - 40 (15) 1.00 25 - 45 - 100 (40) Key 5 - 25 - 80 (20)

5 - 30 - 80 (25)

0.80

RP90 - Rmean - RP10

0.80

Unrisked Risked Discovered Proven

C:/appraisal.ppt December, 1997

P90 - Mean - P10 (Det ML)

Figure 22

51

40 - 120 - 300 25 - 89 - 244 40 25

PERT - Australia/Asia Region BHP Petroleum

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 3: Downside Outcome (2) - 100 to 65 Mmstb Well 3

Well 4 0.40

0.20

5 - 20 - 40 (15)

5 - 20 - 35 (15)

1.00

1.00 30 - 45 - 100 (40)

10 - 25 - 60 (25) 1.00

30 - 40 - 80 (40)

5 - 25 - 80 (20)

Unrisked Risked Discovered Proven

15 - 25 - 50 (25)

0.90 1.00

50 - 115 - 280 45 - 93 - 248 65 40

DRY

1.00

Unrisked Risked Discovered Proven

50 - 85 - 165 45 - 65 - 137 65 45

Well 5 1.00 DRY 1.00 30 - 40 - 60 Key DRY

15 - 25 - 50

1.00

1.00

Unrisked Risked Discovered Proven

5 August, 1999C:/appraisal.ppt December, 1997

Figure 23

52

45 - 65 - 110 45 - 65 - 110 65 45

P90 - Mean - P10 (Det ML) RP90 - Rmean - RP10

PERT - Australia/Asia Region BHP Petroleum

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 3: Downside Outcome (3) 400

Proven Discovered Mean P10 P90 RP90 Rmean RP10

350

Risked Reserves / Value

300

250

200

150

100

50

0 0

1

2

3

4

5

Number of Wells / Time

C:/appraisal.ppt December, 1997

Figure 24

53

PERT - Australia/Asia Region BHP Petroleum

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 4: Mixed Outcome (1) - 100 to 150 to 100 MMstb No Wells

Well 1 0.25

0.40

5 - 20 - 50 (15)

5 - 20 - 50 (15)

0.25

1.00 10 - 50 - 150 (40)

5 - 30 - 100 (25)

15 - 45 - 130 (40)

5 - 25 - 100 (20)

5 - 30 - 100 (25)

0.25

0.25

5 - 25 - 100 (20)

0.80

0.80

Unrisked Risked Discovered Proven

25 - 125 - 400 0 - 0 - 100 0 0

Unrisked Risked Discovered Proven

30 - 120 - 380 15 - 89 - 310 40 15

Well 2 0.40 5 - 25 - 40 (25) 1.00 30 - 70 - 120 (60) Key 5 - 40 - 100 (35)

5 - 35 - 100 (30)

0.80

RP90 - Rmean - RP10

0.80

Unrisked Risked Discovered Proven

C:/appraisal.ppt December, 1997

P90 - Mean - P10 (Det ML)

Figure 25

54

45 - 170 - 370 30 - 130 - 300 60 30

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 4: Mixed Outcome (2) - 100 to 150 to 100 MMstb Well 3

Well 4 0.40

0.20

5 - 25 - 50 (25)

5 - 25 - 50 (25) 1.00

1.00 35 - 65 - 100 (60)

15 - 40 - 80 (35) 1.00

35 - 60 - 80 (60)

5 - 35 - 80 (30)

Unrisked Risked Discovered Proven

20 - 35 - 60 (35)

0.90 1.00

60 - 165 - 310 55 - 137 - 272 95 50

DRY 1.00

Unrisked Risked Discovered Proven

60 - 120 - 190 55 - 95 - 150 95 55

Well 5 1.00 5 - 10 - 15 (10) 1.00 35 - 55 - 75 (55) Key DRY

20 - 35 - 55 (35) 1.00

5 August, 1999C:/appraisal.ppt December, 1997

1.00

Unrisked Risked Discovered Proven

Figure 26

55

60 - 100 - 145 60 - 100 - 145 100 60

P90 - Mean - P10 (Det ML) RP90 - Rmean - RP10

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Example 4: Mixed Outcome (3) 400

Proven Discovered Mean P10 P90 RP90 Rmean RP10

350

Risked Reserves / Value

300

250

200

150

100

50

0 0

1

2

3

4

5

Number of Wells / Time

C:/appraisal.ppt December, 1997

Figure 27

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PERT - Australia/Asia Region BHP Petroleum

3.3 Sensitivity Analysis Sensitivity analysis has been used for some time to identify which of the input parameters to volumetric calculation has the greatest effect on the volume range. In sophisticated probabilistic modelling software such as Crystal Ball or @Risk, sensitivity analysis can be automatically performed and the results displayed on a tornado plot - a horizontal bar chart showing the negative and positive contributions of each parameter in order of significance (Figure 28). This may be expressed as an absolute or percentage deviation from the mean, or statistical variance. If sensitivity analysis cannot be performed automatically, it can be calculated by systematically modifying the input data to the probabilistic model. The probability distribution for gross rock volume is combined with constant most likely values for all other parameters, and the reserves range noted. This process is repeated for each parameter in turn, and a summary plot of reserves range versus parameter produced. Economic sensitivities can also be performed, and the results displayed on a spider plot (Figure 29). By systematically increasing or decreasing inputs such as reserves, capital cost or oil price, the sensitivity of project value to each parameter can be established. Typically, the value of a project is most sensitive to changes in reserves and oil price. 3.4 Forward Modelling Traditionally, as in the above examples, we measure the impact of appraisal retrospectively - assessing the impact on reserves after a well has been drilled. More recently, a number of methods which attempt to predict the impact of appraisal have been developed. These include Monte Carlo forward modelling, appraisal by objectives and value of information (VOI) techniques. These approaches allow us to use quantitative analysis as part of the decision making process - allowing comparison of options, providing greater insight and strengthening our decisions. Monte Carlo Forward Modelling Generally, the justification for further appraisal of a discovery is driven by the need to obtain additional information - more control on structure, more core or fluid samples etc. When deciding where to position the next well(s), we consider the ability of each potential location to provide technical information. We also make subjective judgements as to the likely impact of each location may have on reserves - is it small or large? Whilst the need for more information and a "feel" for the worth of a well remain a key part of the appraisal decision making process, the process can be strengthened by attempting to quantify the impact of well(s) on the reserves range or economic value of the project. We place considerable time and effort into determining these based on current data; rarely do we consider how that range may change following appraisal wells. Although we make every effort to ensure that our predictions are accurate, experience shows that on many occasions the post-drill reserves expectation and range



Field Appraisal: Technical Guidelines

Sensitivity Analysis: Tornado Plot

GRV Recovery Factor Net:Gross Porosity FVF Oil Saturation

-80

-60

-40

-20

0

20

40

60

80

Reserves / Percent /Variance

5 August, 1999C:/appraisal.ppt December, 1997

Figure 28

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Sensitivity Analysis: Spider Plot 100

NPV ($m)

Capex

80

60

Opex 40

20

0 -100%

-80%

-60%

-40%

-20%

0% -20

20%

40%

60%

80%

100%

Parameter Change

-40

Oil Price -60

Reserves

-80

-100

5 August, 1999C:/appraisal.ppt December, 1997

Figure 29

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PERT - Australia/Asia Region BHP Petroleum

is significantly different from pre-drill-volumes. By determining what these differences could be for a number of future well locations and outcomes we can produce a series of comparative statements which can aid the decision making process. For example, Comparison of different outcomes at the same well location:

" If we drill well A and it comes in on prognosis, then the revised reserves range will be a - b - c." " If we drill well A and it comes in 50m high, with the expected fluid contact, then the revised reserves range will be x - y - z." " If we drill well A and it comes in on prognosis, but dry, then the revised reserves range will be p - q - r."

Comparison of the same outcome at different well locations:

" If we drill well B instead of well A and it comes in on prognosis, but dry, then the revised reserves range will be j - k - l."

Comparison of sequences of wells:

" If we drill wells A, B and C and they all come in on prognosis the RP90 reserves will not be economic.” " We need wells A or B to come in 20m high, or have a deeper fluid contact, to make the RP90 reserves economic.” “ If we drill wells C and D the RP90 reserves may increase more.”

This technique of modelling future wells to assess their impact is referred to as Monte Carlo forward modelling. It has been used to quantify the impact of a number of well locations, each of which is a candidate for the next well, and for sequences of wells. This has been used to prioritise drilling order and estimate appraisal well numbers and costs. Most studies which have used this method to date have been based on risked reserves. However, the same methodology can be applied to evaluations based on in-place volumes, or value.

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 It must be emphasised that the aim of this technique is not to reproduce every possible outcome or combination of outcomes. Nor is it necessary to encompass the absolute minimum or maximum outcomes which may occur. The aim is simply to develop a framework of realistic scenarios around which further discussion can take place. Key questions which forward modelling can help to answer include:

“ Do we need another appraisal well ?” “ How could this well change our expectation or proven reserves ?” “ How do we get from current proven reserve of x to an economic level of y ?”

An example of the quantitative output from forward modelling is presented (Figure 30). The horizontal axis shows success and failure outcomes for a hypothetical well location, referenced to the current base case. The vertical axis is the quantitative measure of full field risked reserves. The vertical bars represent the RP90 to RP10 reserves range and the circles represent the Rmean volume - red = base, green = success, blue = failure. Measures Using Monte Carlo forward modelling three separate parameters can be measured and compared for various well locations and outcomes (Figures 30, 31): Model Impact - The impact of an appraisal well is defined as the difference in Rmean reserves between success and failure cases. The greater the difference, the more impact that well has. In the example, Well A clearly has more effect on mean reserves than the other wells. This may be related to the ability of this well to differentiate models or remove risk. Proven Growth - Proven reserves growth is defined as the ability of a successful well to increase the RP90 value relative to the base case. In the example, Well C is the best well to achieve this objective. Upside Constraint - During appraisal knowing when to stop is an important consideration. Removal of upside potential is defined as the ability of a failed well to reduce the RP10 value relative to the base case. This is also referred to as a "drill-tokill" measure. In the example, Well B is the best well to achieve this objective. The emphasis placed on each of these measures tends to change with time (Figure 32). In scale appraisal, the ability of a well to impact expectation reserves and/or remove upside is generally more important than the need to increase proven volumes. During confidence appraisal, the emphasis often shifts to proven reserves

61



Field Appraisal: Technical Guidelines

Appraisal Drilling: Measures

RP10

Upside Constraint

Risked Reserves / Value

RMean

Model Impact

Proven Growth RP90

Base

5 August, 1999C:/appraisal.ppt December, 1997

Well X Success

Figure 30

Well X Failure

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Appraisal Drilling: Comparison of Measures

Model Impact

Well A

Proven Growth

Well C

Upside Well B Constraint

Risked Reserves / Value

Success Failure

Base

Well A

Well B

Well C

Well D

Scenario C:/appraisal.ppt December, 1997

Figure 31

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Appraisal Emphasis Project Identification

Project Definition Blackback

Single Selection

SE Mananda

Moran

Lambert

BSFN-ROD

Appraisal Emphasis

Development Concept Maturity

Multiple Options

Model Impact Scott Reef

Sunrise Area

BayuUndan Gas

Bayu Undan Liquids

Upside Constraint Proven Growth

Concept Uncertain Ultra Deepwater GOM

Uneconomic

Neptune

Feasible

Viable

Robust

Economic Maturity 5 August, 1999C:/appraisal.ppt December, 1997

Figure 32

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growth as we aim to improve the robustness of the project. Method For each model, a detailed summary of the hypothetical well results for success and failure outcomes is prepared. This includes information regarding the location, depth and relevant results of the well including thickness, reservoir property, pressure and fluid data. These summaries are used to ensure that the new Monte Carlo model honoured all available data as if the well had actually been drilled. For each model, outcome and well location(s), revised full field risked reserves are calculated. Depth structure maps are adjusted to tie the new well(s), if it is modelled to have come in high or low to prognosis. The minimum and maximum depth structure maps are also altered to take account of the new depth control the well(s) provides. If these maps are derived from the most likely structure map using "Low" and "High" depth error surfaces, new grids can be easily generated by posting zero error at the new well(s) and flexing the error surfaces to tie the additional data. Other approaches may require hand editing of the minimum and maximum depth structure maps to honour the new well(s). A range of new gross pay isochores can be generated, taking into account any new information the well(s) has provided regarding reservoir thickness and fluid contacts. The most likely reservoir property maps and property distributions for input to the Monte Carlo model must also be updated. The risks applied to each segment should also be adjusted, if appropriate. For example, a well may be modelled to encounter reduced pay in the eastern part of the field - requiring revision of the most likely N:G map, predicted N:G range, and an increased risk in the eastern segments. Having adjusted input parameters and risks, the volume range for each segment is recalculated and segments combined using probabilistic addition. The results can then be compared against the pre-drill base case, and other appraisal options and outcomes. Using Monte Carlo forward modelling it is important to limit the number of wells, sequences and models evaluated, as the process can become both manpower and time intensive. One or two alternative models, and three to five well locations usually provides a reasonable number of comparisons. Whilst this approach has most use during scale appraisal, providing quantitative comparisons of the impact of success or failure in a few key wells, it can also be applied in a simplified form to confidence appraisal. In projects where a high degree of confidence is required, e.g. large offshore oil or gas discovery in remote basin, it is important to estimate the number of wells and

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 appraisal costs at an early stage. By evaluating the impact of a complete sequence of appraisal wells on RP90 and RP10 volumes for the current model i.e. all future wells come in on prognosis, we can at least get an estimate of how many wells are required to prove a specific volume, or remove upside potential, if all goes to plan. From this benchmark, we can assume that better than expected results will require less wells, and failure or poor results will require more. If manpower and time permits, confidence appraisal requirements may also be assessed for upside and downside models. For each of these scenarios, a conceptual appraisal programme is developed. The programme addresses in logical order the remaining uncertainties including areal extent, reservoir distribution etc. The later stages of the programme includes "optional" appraisal wells which may be required e.g. to confirm structural elevation between wells and increase RP90 reserves to a level where a sales contract can be met. These conceptual programmes do not imply that every well must be drilled. The precise number of confidence appraisal wells also depends on many external factors. For example, appraisal well numbers for a standalone LNG development will depend on scheme size, contract terms, number of other pools, marketing initiatives etc. As for scale appraisal, the Monte Carlo model is updated to reflect the results of confidence appraisal wells. Given the large numbers of wells in most cases, not every well is modelled separately. Wells may be grouped together and error maps, parameter ranges amended after Well 5, Well 8, Well 12 etc. At each time step, the GRV range is updated to include the effect of greater structural control from additional wells. Minimum and maximum error maps are amended to include zero error at the new wells and new depth maps produced. In addition, the range of other volumetric parameters is assumed to narrow as time proceeds reflecting our improved understanding of reservoir property distribution, recovery mechanisms, sweep efficiencies etc as more data is gathered in numerous appraisal wells. The results may be plotted as risked reserves range versus well number or time (Figure 33), and used to estimate appraisal requirements for a given threshold or range of uncertainty. In this example, the analysis shows that eight wells are required to prove up 400 mmboe reserves. Of course, this approach is only an approximation and the actual number of wells required in this scenario may be more or less - perhaps it will take six to ten wells to meet our objective. If we needed to prove up 450 mmboe, the number of wells required increases to twelve to sixteen.

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Field Appraisal: Technical Guidelines

Confidence Appraisal 500

RP10

Rmean

RP90

400

300

Risked Reserves / Value 200

100

0 0

2

4

6

8

10

12

14

16

No. of Wells / Time / Cost 5 August, 1999C:/appraisal.ppt December, 1997

Figure 33

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Appraisal by Objectives This semi-quantitative method uses a simple decision matrix to weight the importance of each key objective, and rate the ability of each appraisal well location to address these objectives. The importance of each parameter in the reserves calculation, and development concept selection, is assessed using sensitivity analysis and the major controlling factors identified. In many cases, gross rock volume (GRV) will be the greatest uncertainty, but the factors which control this uncertainty may vary greatly. Rock volume may be poorly defined because of seismic data quality, velocity control, or ill-defined fluid contacts. Net:gross uncertainty may be introduced because of lack of information on areal reservoir distribution, or insufficient core data to define net pay cut-off, or both. By defining the objectives which must be met to remove the major uncertainties, we can then rate the suitability of each well location. For example, reducing the uncertainty in GRV may require discrimination of an ambiguous seismic time pick in part of a field, and definition of an oil-water contact. Some wells will be better located to achieve the first objective, and others may be more likely to achieve the second. Each objective is assigned an importance, or weighting, ranging from 1 (unimportant) to 5 (very important). The ability of each well location to meet each objective is also given a rating from 1 (unlikely to meet objective) to 5 (highly likely to meet objective). For each objective and each well location the two numbers are multiplied together, and the values added to determine a total value for each well location. The location with the highest value is considered to be most likely to provide maximum information and have the greatest reduction in uncertainty. Using the above example: Well A

Well B

Well C

Objective

Weighting

Rating

Value

Rating

Value

Rating

Value

SeismicPick

4

4

16

3

12

4

16

Delineate OWC

3

2

6

3

9

4

12

Total

22

21

28



Field Appraisal: Technical Guidelines

Appraisal by Objectives: Well 2 Decision Matrix

Location A Objective

Location B

Location C

Weight Rating Value Rating Value Rating Value

Prove up gross rock volume

3

3

9

4

12

5

15

Provide opportunity to test sands

2

3

6

4

8

4

8

Discriminate seismic pick in west

2

0

0

2

4

4

8

Determine lateral continuity of sands

1

3

3

2

2

5

5

Total Value (Weight x Rating)

C:/appraisal.ppt December, 1997

18

Figure 34

26

36

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Appraisal by Objective: Well 3 Decision Matrix

Location D Objective

Location E

Location F

Weight Rating Value Rating Value Rating Value

Prove up gross rock volume

3

5

15

4

12

1

3

Investigate distal sand quality

2

1

2

3

6

5

10

Investigate subcrop on flank

1

0

0

3

3

5

5

Investigate amplitude changes in 3D

2

0

0

4

8

5

10

Total Value (Weight x Rating)

C:/appraisal.ppt December, 1997

17

Figure 35

70

29

28

PERT - Australia/Asia Region BHP Petroleum

In this case, Well C has the highest value and should be prioritised. Two examples from a field case study (Figures 34,35) show the decision matrices that were constructed when deciding the location of the second and third wells on the structure. In this case, the decision to drill location C as the second well is clear. However, choosing between locations E and F for the third well is more difficult - as the total values are so close. Other factors such as cost, sidetrack potential, partner issues must be also considered. This emphasises the need to use several approaches when evaluating appraisal options, using our experience and judgments to integrate all available information and analyses, and make the final decision. Value of Information In the early stages of appraisal, measuring the impact of appraisal activities by changes in the reserves range is a reasonable approximation - it can be generally assumed that any increase or decrease in reserves will be reflected by a similar movement in value. However, in later appraisal improving the value of a project may not be so readily linked to reserves, and the possibility of eroding value through additional appraisal expenditure may arise. Assessing the value of information (VOI) is a method of evaluating the economic benefit of acquiring information against its cost, and can also be a useful way of justifying appraisal expenditure. Some VOI methods use full economic analysis, with probabilistic distributions for all input parameters including capex, opex and economic criteria. Other methods adopt a simplified decision tree approach, with a few specific scenarios and associated probabilities. Whatever the complexity of the method, the principle is to calculate an expected monetary value (EMV) for the project - taking account of the probability and value of each success outcome and the probability and cost of each failure. VOI compares the current EMV of a project, against predictions of EMV which take into account changes in value or risk which will occur with the acquisition of additional data. A full range of scenarios, both success and failure, should be included to capture the range of possible outcomes. For example, consider the appraisal of a small oilfield. Although four wells have already been drilled, a number of significant risks and uncertainties have been identified - the chance of having a successful development based on our current knowledge is estimated to be only 50%.

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 The operator is contemplating another appraisal well prior to committing to development of the field - to reduce uncertainty in the reserves range, and increase the chance of a successful project. For clarity, the example is based on the following assumptions and a definitive outcome - the project results in either total success or total failure. Of course, in reality there could be many outcomes - we may achieve only partial success, and steps would be taken to mitigate against total failure.

Well Cost Development Cost Revenue

$5 million $40 million $100 million

A simple decision tree may be used to estimate the value of information (Figure 36). If we decide not to drill the well, we must also decide whether or not to develop the field. The EMV of not developing the field is zero - $0.0 million - we neither spend money or make money. No Well, No Development

EMV

( 0.0 x 1.0 )

=

$0.0 million

If we decide to develop the field, there are two possible outcomes - a successful development or failure. The net present value (NPV) of the success outcome is $60 million - revenue minus development cost. The failure outcome has an NPV of $-40 million - no revenue minus development cost. No Well, Development

EMV =

( 60 x 0.50 ) + ( -40 * 0.50 ) =

$10.0 million

This higher EMV indicates that, if we do not drill a well, we are more likely to maximise value by proceeding with the development than doing nothing - the benefits of success outweigh the cost of failure. If we decide to drill the well, the well results will have an impact on the project. If the well is successful, the chance of a successful project is estimated to increase to 70%. However, if the well has poor results, the chance of a successful project falls to 30%.

72



Field Appraisal: Technical Guidelines

Value of Information: Decision Tree (1) Drill Well X?

16.0

6.0

Yes Well Result

25.0

0.70

0.30

Success

25.0

Decision Node

No

Decision Path Outcome Node

-5.0

Failure

Develop Field? Yes

10.0

Positive Outcome

Develop Field?

-5.0

-15.0

No

Yes

Negative Outcome

Develop Field?

-5.0

10.0

No

Yes

0.0 No 0.70

Project Result 0.70 Success

Project Result

0.30 Failure

Final Prob

0.49

0.21

Well Cost Dev Cost Revenue

5 40 100

5 40 0

NPV

55

-45

5 August, 1999C:/appraisal.ppt December, 1997

0.30 Success

Project Result

0.70 Failure

0.09

0.21

5 0 0

5 40 100

5 40 0

-5

55

-45

0.50 Success

75

0.50 Failure

0.50

0.50

5 0 0

0 40 100

0 40 0

0 0 0

-5

60

-40

0

Figure 36

Probability Net Present Value

25.0

Expected Monetary Value

6.0

Value of Information

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To estimate the overall value of the decision, we must also assess the chance of the well itself being successful - in this example it is estimated to be 70%. Whatever the well results, we still have the option to develop or not develop the field. This creates six branches to this side of the decision tree:

1

Successful Well

Develop Field

Successful Development

2

Successful Well

Develop Field

Failed Development

3

Successful Well

No Development

4

Failed Well

Develop Field

Successful Development

5

Failed Well

Develop Field

Failed Development

6

Failed Well

No Development

Consider first the value of not proceeding with a development, having drilled the well. Regardless of the outcome of the well the EMV of not developing the field is $-5.0 million - the cost of the well. Well, No Development

EMV

( -5.0 x 1.0 )

=

$-5.0 million

If the well has positive results, increasing the likelihood of a successful development, the EMV of the decision to proceed with development is $25 million. The reduced NPV of the success outcome, and the higher cost of failure reflects the cost of the well. Successful Well, Development

EMV =

( 55 x 0.70 ) + ( -45 * 0.30 ) =

$25.0 million

This higher EMV indicates that, if we have a successful well, we are more likely to

Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0 maximise value by proceeding with the development than doing nothing - the benefits of success outweigh the cost of failure. If the well has negative results, decreasing the likelihood of a successful development, the EMV of the decision to proceed with development is $-15 million. Failed Well, Development

EMV =

( 55 x 0.30 ) + ( -45 * 0.70 ) =

$-15.0 million

This lower EMV indicates that, if we have a failed well, we are more likely to maximise value by stopping the project than proceeding with the development - the cost of failure outweighs the benefits of success. The EMV from drilling the well can be calculated by combining the higher EMVs from each of the two main branches - well success and failure.

EMV =

( 25 x 0.70 ) + ( -5 * 0.30 )

=

$16 million

The difference in EMV between the two main branches of the decision tree, in this case Well versus No Well, represents the value of information. A positive VOI supports the decision to acquire further information. In this example, the EMV from drilling the well is $6 million higher than the EMV from no well. This supports a decision to drill the well.

VOI

=

( 16 EMV Well

6) = EMV No Well

$6 million

However, this type of analysis is very sensitive to probabilities we assign to each outcome model, and sensitivities should always be run to test the robustness of our decisions. For example, another person may estimate the chance of a successful project following positive well results to be only 60%, rather than 70%. This would result in a decrease in EMV on the left side of the decision tree, and a negative VOI - leading to a different appraisal decision (Figure 37). Similarly, an increase in well cost from $5 million to $11 million results in a decrease in EMV on the left side of the decision tree, and a neutral VOI - leading to an unclear appraisal decision (Figure 38).

75



Field Appraisal: Technical Guidelines

Value of Information: Decision Tree (2) Drill Well X?

9.0

-1.0

Yes Well Result

15.0

0.70

0.30

Success

Probability of a successful project reduced from 0.70 to 0.60

15.0

Decision Node

No

Decision Path Outcome Node

-5.0

Failure

Develop Field? Yes

10.0

Positive Outcome

Develop Field?

-5.0

-15.0

No

Yes

Negative Outcome

Develop Field?

-5.0

10.0

No

Yes

0.0 No 0.70

Project Result 0.60 Success

Project Result

0.30 Failure

Final Prob

0.49

0.21

Well Cost Dev Cost Revenue

5 40 100

5 40 0

NPV

55

-45

5 August, 1999C:/appraisal.ppt December, 1997

0.30 Success

Project Result

0.70 Failure

0.09

0.21

5 0 0

5 40 100

5 40 0

-5

55

-45

0.50 Success

75

0.50 Failure

0.50

0.50

5 0 0

0 40 100

0 40 0

0 0 0

-5

60

-40

0

Figure 37

Probability Net Present Value

25.0

Expected Monetary Value

6.0

Value of Information

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Value of Information: Decision Tree (3) Drill Well X?

10.0

0.0

Yes Well Result

19.0

0.70

19.0

Decision Path Outcome Node

Failure

Develop Field? Yes

Decision Node

No

-11.0

0.30

Success

Well cost increased from 5 to 11 million

10.0

Positive Outcome

Develop Field?

-11.0

-21.0

No

Yes

Negative Outcome

Develop Field?

-11.0

10.0

No

Yes

0.0 No 0.70

Project Result 0.60 Success

Project Result

0.30 Failure

Final Prob

0.49

0.21

Well Cost Dev Cost Revenue

11 40 100

11 40 0

NPV

49

-51

5 August, 1999C:/appraisal.ppt December, 1997

0.30 Success

Project Result

0.70 Failure

0.09

0.21

11 0 0

11 40 100

11 40 0

-11

49

-51

0.50 Success

75

0.50 Failure

0.50

0.50

11 0 0

0 40 100

0 40 0

0 0 0

-11

60

-40

0

Figure 38

77

Probability Net Present Value

25.0

Expected Monetary Value

6.0

Value of Information

PERT - Australia/Asia Region BHP Petroleum

Recalculation of predicted EMV changes for a range of probabilities, rather than a single value allows us to understand and communicate the effect differing perceptions of risk may have on our decisions. Using the above example, we can determine predicted EMV changes for variations in both well cost and chance of success (Figure 39). In this case we assume that well cost could vary from $2 million to $18 million, and the chance of well success may be between 50% and 90%. These ranges can be used to define a risk envelope. Based on our most likely assumptions, the appraisal well can slightly increase project value. However, if the well cost was higher - or chance of success lower - value would be eroded. Within the risk envelope, only 55% of the outcomes are positive, providing a measure of the risk cover, or economic robustness of our decision. If we repeat the analysis for other combinations, such as well success and project success (Figure 40), we can assess the risk cover for other aspects of the decision. In this case, 75% of outcomes are positive.



Field Appraisal: Technical Guidelines

Value of Information: Sensitivity Analysis (2) 30 25 20 Positive Outcomes 55%

15

Predicted VOI ($ million)

10

Most Likely Case

5 0 90% -5 70% Negative Outcomes 45%

-10

Well X Chance of Success

50%

-15 2

6

10

14

18

Well Cost ($ million) 5 August, 1999C:/appraisal.ppt December, 1997

Figure 39

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Field Appraisal: Technical Guidelines

February 1998

DRAFT VERSION 2.0



Field Appraisal: Technical Guidelines

Value of Information: Sensitivity Analysis (1) 30

90% Positive Outcomes 75%

25

70%

20

Well X Chance of Success

15

Predicted VOI ($ million)

10

Most Likely Case

50%

5 0 -5 -10 -15 50%

Negative Outcomes 25%

60%

70%

80%

90%

Development Project - Chance of Success

5 August, 1999C:/appraisal.ppt December, 1997

Figure 40

80

PERT - Australia/Asia Region BHP Petroleum

4. Conclusions Understanding the fundamentals of appraisal and the many factors which can control or influence our appraisal decisions is an important part of BHPP’s business. The pressure to reduce cycle time, whilst increasing the value of projects, requires us to make faster, better decisions. The various guidelines and methods described in this paper can be used to improve our decision making processes. It is recommended that: a clearly defined and documented appraisal strategy is developed for each economically feasible discovery. This should include a description of the business goals and drivers, development concept maturity and economic maturity, and the key factors controlling the direction and pace of appraisal, the concept of field segmentation is used for all discoveries in the calculation of unrisked and risked reserves ranges, the proposed definitions of discovered, proven volumes and risked proven volumes are adopted and used consistently in reserves accounting and external reserves reporting, all future appraisal decisions are supported by quantitative analyses demonstrating the potential impact of appraisal on reserves, or project value. Wherever possible, alternative options and well locations should be evaluated and compared, and the rationale for choosing the preferred option(s) clearly documented. Objectives should be clearly defined and prioritised.

C G McKinley February 1998