Table Of Contents

• 1.0 SUMMARY

• 2.0 BACKGROUND
  • 2.1 Introduction
  • 2.2 Regulatory Framework
  • 2.3 History of the Hibernia Project
    • 2.3.1 Discovery and Licensing
    • 2.3.2 Development Plan Approval and Project Agreements
    • 2.3.3 The Project Since 1990

• 3.0 THE PRESENT APPLICATION
  • 3.1 Background
  • 3.2 Administration of Production Rates
  • 3.3 The Application
  • 3.4 The Board’s Review

• 4.0 CONCLUSION
  • 4.1 Hibernia Development Plan Amendment Decision 00.01

• APPENDIX A
  • OUTSTANDING CONDITIONS FROM DECISIONS 97.01, 90.01 AND 86.01

• • APPENDIX B
    • GLOSSARY

List of Figures

• • • Figure 1 Hibernia Field Location
    • Figure 2 Hibernia Reservoir “B” Pool Fault Blocks
    • Figure 3 Hibernia Field Pool and Zone Designations Hibernia Formation
    • Figure 4 Ben Nevis/Avalon Reservoir Fault Blocks and Proposed Well Locations
    • Figure 5 Comparison of the Proponent’s Production Forecasts
    • Figure 6 Proposed Hibernia Field Production Forecast

List of Tables

• • • Table 1 Hibernia Reservoir: Original Oil-in-Place Estimates
    • Table 2 Hibernia Reservoir Gas Cap: Original Gas-in-Place Estimates
    • Table 3 Comparison of Average Reservoir Properties: 1996 Development Plan and the Current Model
    • Table 4 Hibernia Field Reservoir Simulation: Comparison of Cumulative Oil Recovery at Production Rates of 21 600, 28 600 and 31 800 m³/d after 25 years production
    • Table 5 Hibernia Reservoir Comparison of Oil Recovery Efficiency after 25 years
    • Table 6 Comparison of Oil Recovery after 25 years: High Rate Case and 1996 Amendment

1.0 SUMMARY

On June 10, 1999, the Hibernia Management Development Company (the Proponent) applied to the Board for approval of a revision to the reservoir management strategy for the Hibernia field previously approved by the Board in its Decision 97.01. The requested revision would allow the Proponent to increase the authorized maximum annual average daily oil production rate (the plateau production rate) from the field in order to fully utilize the capacity of the processing facilities on the Hibernia platform.

On January 24, 2000, the Proponent also applied for approval to increase the currently authorized annual oil production rate of 21 450 m ³ /d (135,000 barrels/day) to 27 000 m³/d (170,000 barrels/day) immediately and to increase the rate further to 28 600 m³/d (180,000 barrels/day) after successfully testing the minor equipment modifications scheduled to be completed in March 2000.

The effect of these proposals would be to increase the authorized maximum annual production from about 7.8 million cubic metres (49.2 million barrels) to 10.4 million cubic metres (65.6 million barrels). The Canada Newfoundland Offshore Petroleum Board (the Board) deemed the Proponent’s requests to be an application to amend the Hibernia Development Plan previously approved by the Board ( the Application). The Board’s approval of such an amendment is a Fundamental Decision pursuant to the Canada-Newfoundland Atlantic Accord Implementation Acts and, therefore, requires the approval of the Federal Minister of Natural Resources Canada and the Provincial Minister of Mines and Energy.

This Report constitutes the Board’s approval of the Proponent’s application to amend the Hibernia Development Plan. The Proponent is authorized to increase annual oil production from 21 450 m³/d (135,000 barrels/day) to 27 000 m³/d (170,000 barrels/day) immediately and to increase the rate further to 28 600 m³/d (180,000 barrels/day) after successful testing of the minor equipment modifications that are scheduled for completion in March 2000.

The Proponent stated that the rate increase that it was seeking would not adversely affect oil recovery from the field and submitted a technical report entitled “Technical Support for Hibernia Field Rate Increase” in support of its position. The Proponent also submitted the following reports in support of its request “Hibernia Plant Capacity and Expansion Study Offshore Test Program Definition Volumes 1 and 2” and “Hibernia Management and Development Company: 1998 Annual Production Report”.

The Board has reviewed the Proponent’s Application to determine whether the proposed production increase would affect the environmental impact predictions made in the Proponent’s 1985 Hibernia Environmental Impact Statement, or any of the conditions established by the Board in Decision 86.01. Because the Application involves only a change to the average daily oil production rate approved in Decision 97.01, and does not involve any major modification to the facilities themselves, the Board has determined that it does not affect the approved Hibernia Benefits Plan nor raise any new environmental issues. The Board notes that the higher production rate will not result in any increase in the volume of gas flared. Therefore, the Board has concluded that neither revision of the environmental impact assessment for the project, nor further public review is required.

The Board assessed the information provided by the Proponent and concluded that the field could be produced at the higher rate proposed without any adverse effect on oil recovery. In considering the Application, the Board required the Proponent to:

• • 1. Submit the results of its tests to confirm the capability of the production facilities to handle the higher production rate;
    2. Demonstrate that both gas compression systems were able to operate on a continuous basis; and,
    3. Demonstrate that the Hibernia platform could operate on a continuous basis at the current design capacity of 24 000 m³/d (150,000 barrels/day).

The Proponent completed the high production rate testing to confirm the Hibernia platform capacity in December 1999 and provided the results of the tests to the Board in January 2000. In addition, the Proponent provided information confirming that the Hibernia platform has been producing at its design capacity and that both gas compression systems have been operating on a continuous basis since November 4, 1999.

Having considered the information provided by the Proponent in support of the Application, the Board approved the proposed production rate increase, subject to the condition that its approval will be reviewed and may be suspended or revoked should the Proponent’s operations depart significantly from those projected in the Application or if reservoir performance differs significantly from that predicted in the Proponent’s document entitled “Technical Support for Hibernia Field Rate Increase”.

In its January 24, 2000 submission, the Proponent also requested a change in certain operating limits established by the Board in the interest of safety. The Proponent stated that a complete review of the production system indicated that a peak maximum flow rate of 31 800 m³/d (200,000 barrels/day) could be achieved through the Hibernia platform and requested that the maximum safety related capacity of the platform be increased in two stages to that level. At that level, the estimated annual system operating efficiency of between 90 to 95 percent yields a potential daily production rate of between 28 600 and 30 200 m³/d (180,000 to 190,000 barrels/day).

While the Board does not consider this matter falls within the scope of the development plan, this report records, for the purpose of completeness, that it approved the Proponent’s request on February 16, 2000.

2.0 Background

2.1 Introduction

The Hibernia field is located on the northeastern Grand Banks approximately 315 km southeast of St. John’s, Newfoundland, in a water depth of about 80 metres (Figure 1). The field covers an area of about 223 square kilometers, and, at that time it was initially proposed for development, the Proponent estimated that it contained some 98 10⁶ m³ (520 Million barrels) of recoverable oil in two separate reservoirs, the Hibernia and the Avalon.

Early in 1986, the Canada-Newfoundland Offshore Petroleum Board (the Board) considered an application by Mobil Oil Canada Ltd., (Mobil) on behalf of the participants in the Hibernia field for approval of its Hibernia Benefits Plan and its Hibernia Development Plan. The Board reported its decision conditionally approving both plans in its June 1986, Decision 86.01. Since then, the Proponent has twice sought approval for amendments to the approved Development Plan, on March 30, 1990 and July 10, 1996. The Board conditionally approved both applications in Decision 90.01 and Decision 97.01 respectively. Section 2.3 of this report provides a historical overview of the Hibernia project.

On June 10, 1999, the Hibernia Management Development Company (the Proponent) requested the Board’s approval for a revision to the reservoir management strategy for the Hibernia field approved by the Board in Decision 97.01 to increase the authorized plateau oil production rate for the field in order to take advantage of the capacity of the processing facilities installed on the Hibernia platform.

On January 24, 2000, the Proponent requested approval to increase the currently authorized average daily oil production rate from 21 450 m³/d (135,000 barrels/day) to 27 000 m³/d (170,000 barrels/day) immediately and to increase the rate further to 28 600 m³/d (180,000 barrels/day) following the successful testing of minor equipment modifications that were scheduled to be completed in March 2000. The effect of approving these proposals would be to increase the authorized maximum annual production from about 7.8 million cubic metres (49.2 million barrels) to 10.4 million cubic metres (65.6 million barrels).

The Canada Newfoundland Offshore Petroleum Board (the Board) deemed the Proponent’s requests to be an application (the Application) to amend the Hibernia Development Plan previously approved by the Board. The Board’s approval of such an amendment is a Fundamental Decision pursuant to Sections 139(5) of the Canada-Newfoundland Atlantic Accord Implementation Act and 134(5) of The Canada-Newfoundland Atlantic Accord Implementation Newfoundland Act (the Acts) . As such, it requires the approval of the Federal Minister of Natural Resources Canada and the Provincial Minister of Mines and Energy.

The Proponent’s application involves a change in the authorized average annual daily oil production rate. It does not involve any major modifications to the facilities. The Board therefore determined that the proposed changes do not affect the approved Hibernia Benefits Plan or raise any new environmental issues and concluded that neither a revision of the environmental impact assessment for the project nor a further public review is required.

This report constitutes the Board’s conditional approval of the Proponent’s application to increase the currently authorized average daily oil production rate of 21 450 m³/d (135,000 barrels/day) to 27 000 m³/d (170,000 barrels/day) immediately and to increase that rate further to 28 600 m³/d (180,000 barrels/day) after successful completion of the testing of minor equipment modifications that are currently in progress.

In its January 24, 2000 submission, the Proponent also requested that the maximum safety related capacity of the platform be increased in two stages to 31 800 m³/d (200,000 barrels/day). While the Board does not consider that this matter falls within the scope of the development plan, for purposes of completeness, it is recording in this report that it conditionally approved this change on February 16, 2000.

Figure 1: Hibernia Field Location

2.2 Regulatory Framework

Pursuant to the Acts , the Board is responsible for the administration of legislation governing hydrocarbon exploration and production in the Newfoundland offshore area. Those intending to undertake oil and/or gas developments are required to obtain the Board’s approval of their plans. An application for such approval must be accompanied by a Canada-Newfoundland Benefits Plan and a Development Plan.

The Benefits Plan describes how the Proponent intends to meet the statutory requirements pertaining to industrial and employment benefits for Canadian businesses and individuals, and in particular, for those resident within the Province of Newfoundland. The Development Plan contains a detailed description of the project. Approval of the Benefits Plan is a pre-condition to approval of the Development Plan. The Acts also require a Proponent to obtain the Board’s approval for amendments to previously approved Plans. The Board may attach such conditions to its approvals, as it considers appropriate.

The Acts also require that a person wishing to conduct any work or activity in relation to the exploration or drilling for, or the production, conservation, processing, or transportation of petroleum in the offshore area must obtain the Board’s prior authorization in writing.

2.3 History of the Hibernia Project

2.3.1 Discovery and Licensing

The Hibernia field was discovered in 1979 by the drilling of the Chevron et al Hibernia P-15 well. Between 1979 and 1984, Mobil, as operator for the participants, drilled nine additional wells to delineate the field. The discovery well was officially declared a Significant Discovery in October 1985. The Board declared the Hibernia field to be a Commercial Discovery in January 1990 and issued a 25-year Production License in respect of the field on March 21, 1990.

Before September 1988, Columbia Gas Development of Canada Ltd. held a 5.4674% interest in the field, which it subsequently sold to Chevron. In February 1992, Gulf Canada Resources announced its intention to withdraw from the Hibernia project. By March 1993, Gulf’s 25% share had been acquired by the Canada Hibernia Holding Corporation (8.5%), Murphy Oil (6.5%), Mobil (5%) and Chevron (5%). In December 1996, Norsk Hydro acquired a 5 % interest in the Hibernia field from Petro-Canada.

The current participants are:

2.3.2 Development Plan Approval and Project Agreements

On September 15, 1985, Mobil, on behalf of the Hibernia partners filed its Hibernia Benefits Plan and its Hibernia Development Plan with the Federal and Provincial Governments. These plans were referred to the Board for review and decision in December 1985. The Board conditionally approved the Proponent’s plans in its Decision 86.01.

Shortly after the 1985 application for approval of the Hibernia Development Plan was submitted, world oil prices declined sharply from the high levels of the early eighties. This decline led the Hibernia partners to reconsider the economics of the development. Extensive negotiations between the partners and both governments concerning fiscal and financial considerations followed. These negotiations culminated in the signing of a Statement of Principles by the partners and the Federal and Provincial Governments on July 18, 1988. That document established their agreement-in-principle on the fiscal and the financial terms applying to the Hibernia project and specified certain undertakings on the part of the Hibernia partners concerning construction of the topside facilities and the execution of design work for the project. Late in 1988, the Hibernia participants formed the Hibernia Management and Development Company Ltd. (HMDC) to construct and operate the Hibernia facilities. The provisions of the Statement of Principles were included in a Binding Agreement signed in September 1990. The conclusion of this agreement allowed the Project to proceed.

2.3.3 The Project Since 1990

On March 30, 1990, HMDC, on behalf of the Hibernia participants, submitted a document entitled Hibernia Development Plan Update (the Update) for the Board’s approval. The Update incorporated proposed modifications to the original conceptual design of the structure topside, a change in the location of the construction site for the gravity base structure, and other new information concerning the overall field development. The Board and Ministers conditionally approved the Update in August 1990. Decision 90.01 records the Board’s approval.

Following approval of the 1990 Update, HMDC conducted a second 3-D seismic survey over the Hibernia field and conducted a thorough review of the geology, geophysics and reservoir characteristics that formed the basis of the Development Plan Amendment. On July 10, 1996, HMDC submitted, for the Board’s approval, an amendment to the Hibernia Development Plan incorporating proposed changes to the original depletion plans for the Hibernia and Avalon reservoirs. The proposed changes included;

• • • The timing of development of the Avalon reservoir,
    • Integrated development production of the Hibernia and Avalon reservoirs,
    • Revised Hibernia water and gas flood programs,
    • Higher production rates from individual wells,
    • Commingled production of two zones in the ‘B’ pools of the Hibernia reservoir,
    • Revised estimates of reserves, recovery efficiencies, and production, and
    • Revised designs for well construction and completion.

The Board and Ministers conditionally approved the changes to the Development Plan in March 1997. Decision 97.01 records the Board’s approval.

Major construction activities at the Bull Arm site were completed in November 1996, the topsides and GBS were mated in March 1997 and towed out to the field in June 1997. The participants built two dedicated ice-reinforced shuttle tankers to transport oil from the field. The first development well was spudded in the field in July 1997, and first oil production began on November 17, 1997.

3.0 The Present Application

3.1 Background

In the Hibernia Development Plan submitted in 1985, the Proponents presented an oil production forecast with a plateau oil production level equivalent to an annual average daily rate of 17 500 m³/d (110,000 b/d). The production forecast was based on likely reserves of 83 10⁶m³ (520 Million barrels) for the Hibernia Reservoir and Ben Nevis/Avalon reservoirs, the depletion scheme presented in the plan, and the proposed production facility’s design capacity of 23 848 m³/d (150,000 b/d). In constructing the forecast, the Proponent considered anticipated downtime and assumed each production well would operate at an annual average rate of 1 590 m³/d (10,000 b/d) with an overall operating efficiency of 90 percent. Also, because of uncertainty respecting reservoir performance and because reservoir areas with less favorable quality would be drilled following the attainment of peak production, well efficiency was estimated at 81 percent after the production build-up period.

In July 1996, HMDC on behalf of the Hibernia partners, submitted for the Board’s approval, an amendment to the Hibernia Development Plan, which included among other revisions, a new production forecast. The revised production forecast provided for a plateau oil production level equivalent to an annual average daily rate of 21 450 m³/d (135,000 b/d). This forecast was based on a maximum daily production capacity of 23 848 m³/d (150,000 b/d) and an overall system (production, loading and shipping) efficiency of about 91 percent. HMDC also proposed to produce the initial Hibernia development wells at a rate of up to 6 400 m³/d in those fault blocks where water flood would be used for pressure maintenance, and at rates of 3 400 m³/d in those fault blocks where gas flood would be used.

The Board conditionally approved the amendment in March 1997 (Decision 97.01). Among the conditions that the Board attached to its approval, was a restriction on the oil production rate for wells in the G fault block. These wells were limited to a maximum rate of 1 190 m³/d, until such time as it could be demonstrated to the Board’s Chief Conservation Officer that a higher production rate would not adversely affect oil recovery. In addition, the Board required the Proponent to monitor well performance closely in the high rate wells through production and cased hole logging.

3.2 Administration of Production Rates

The authorization of oil and gas production rates is an important aspect of the Board’s responsibilities under the Acts. The rates proposed by operators are assessed by the Board to ensure they are within safe operating limits for the facilities and will not adversely affect oil and gas recovery. In addition, the Board monitors production from fields and reservoirs to ensure that levels are consistent with the approved annual production rates and that good oilfield practices are being observed. The Board believes it is important for all stakeholders to understand clearly how certain rates are defined and administered.

The Board administers the following rates:

Maximum Safety Related Capacity:

The Maximum Safety Related Capacity is the maximum oil or gas rate at which the platform may be operated. It is determined taking into account the safe operating limits of pressure relief, blow-down and flare systems, piping and equipment vibration and noise limits, cavitation, corrosion and erosion parameters, and the need to provide a safety margin above the maximum daily production rate authorized for the facility to allow for operational upsets. The maximum safety related capacity is expressed in cubic metres per day and is established by the Board’s Chief Safety Officer. This rate may not be exceeded.

Facility Maximum Daily Production Rate:

The Facility Maximum Daily Production Rate is the oil or gas production rate at which the facility can maintain stable production operations with sufficient reserve capacity to accommodate operational upsets without exceeding the Maximum Safety Related Capacity of the platform. Typically, this is the design production rate for the processing facility and it may be revised after production begins based on operating experience. There may be minor excursions above this rate during production operations, but these would only be of short duration.

The Board’s Chief Safety and Chief Conservation Officers approve the Facility Maximum Daily Production Rate. In approving this rate, these officers ensure that both safety and resource management issues are considered. The Board monitors production activities on a daily basis to ensure compliance. This rate is expressed in cubic metres per day.

Annual Oil Production Rate:

The Annual Oil Production Rate is the maximum annual oil or gas off-take rate authorized for a reservoir or field. It is approved by the Board as part of the Development Plan. This rate is defined by the plateau level of the production forecast and is based on the depletion strategy adopted for the field. This rate is usually expressed as an annual average daily production rate, in cubic metres per day. In approving this rate, the Board must be satisfied that it will not adversely affect oil or gas recovery and any increase in this rate requires an amendment to the development plan. Such amendments also require the approval of both Ministers. After a period of production from the field, depletion of the reservoirs will cause this rate to decline. The Board may also reduce this rate for safety purposes or to prevent waste.

Well Rates:

The Board requires operators to assess the impact of production rate of development wells on recovery efficiency and submit the results of these assessments to it for review. The Board may set production rate limitations on wells to prevent waste. These limitations are reviewed, and may be varied, as production information is acquired. The Board’s Chief Conservation Officer approves well rate limitations.

3.3 The Application

On June 10, 1999, the Proponent requested the Board to approve a revision to the Hibernia reservoir management strategy to allow an increase in the average daily oil production rate (i.e., the annual oil production rate). The Proponent stated that a complete review of the systems installed on the Hibernia platform indicated the maximum daily rate that can be achieved through the plant is 31 800 m³/d (200,000 b/d) and that overall system operating efficiency is expected to be between 90 and 95 percent. The Proponent therefore projects that it is feasible to achieve an average daily oil production rate of between 28 600 and 30 200 m³/d (180,000 and 190,000 b/d). The Proponent also stated that the increase in annual oil production that would result from production at the higher rate would not adversely affect recovery from the field, and submitted the following reports in support of its request: “Technical Support for Hibernia Field Rate Increase”, “Hibernia Plant Capacity and Expansion Study Offshore Test Program Definition Volumes 1 and 2”, and “Hibernia Management and Development Company: 1998 Annual Production Report”.

Subsequently, on January 24, 2000, the Proponent requested approval to increase the currently authorized average daily oil production rate of 21 450 m³/d (135,000 barrels/day) to 27,000 m³/d (170,000 barrels/day) immediately and to increase the rate further to 28 600 m³/d (180,000 barrels/day) following completion of testing of minor equipment modifications to the facilities scheduled to be completed in March 2000.

Effectively the Proponent is seeking the Board’s approval to increase the annual oil production rate in two stages from 7.8 million cubic metres (49.2 million barrels) to 10.4 million cubic metres (65.6 million barrels).

Production rates are addressed in Part V of the Newfoundland Offshore Area Petroleum Production and Conservation Regulations. More specifically, Section 34 states that:

An operator shall produce petroleum from a pool or field in accordance with good production practices to achieve maximum recovery of petroleum from the pool or field and at the applicable rate specified in the approved development plan for that pool or field.

The applicable rate specified in the approved Hibernia Development Plan is the annual oil production rate. This rate determines the average daily production rate for any calendar year in the production forecast. It is based on the approved depletion scheme for the pool or field.

The Board has reviewed the Proponent’s Application to determine whether the proposed production increase would affect the environmental impact predictions made in the Proponent’s 1985 Hibernia Environmental Impact Statement, or any of the conditions established by the Board in Decision 86.01. Because the Application involves only a change to the average daily oil production rate approved in Decision 97.01, and does not involve any major modification to the facilities themselves, the Board has determined that it does not affect the approved Hibernia Benefits Plan nor raise any new environmental issues. The Board notes that the higher production rate will not result in any increase in the volume of gas flared. Therefore, the Board has concluded that neither revision of the environmental impact assessment for the project, nor further public review is required.

In its January 24, 2000 submission, the Proponent also requested that the maximum safety related capacity of the platform be increased in two stages to 31 800 m³/d (200,000 barrels/day). While the Board does not consider this matter is within the scope of the development plan, for purposes of completeness, it is recording in this report that it conditionally approved this change on February 16, 2000.

3.4 The Board’s Review

In support of its request for approval of an increase in the average daily production rate, the Proponent updated its geological and geophysical interpretations and its reservoir simulation model for the Hibernia reservoir to incorporate the drilling and production data acquired from wells Hibernia B-16 1 through 11. Figure 2 depicts the location of these wells in the field. As no new information was available for the Ben Nevis/Avalon reservoir, the reservoir simulation model for that reservoir remained unchanged from that presented in the 1996 development plan amendment. According to the Proponent, the quality of the Hibernia reservoir is better than was predicted in the 1996 Amendment. This will enable oil production to be sustained at higher rates than previously expected.

The Proponent also stated that its reservoir simulation studies compared cumulative oil recovery on a pool-by-pool and fault block basis for peak average oil production rates of 21 600 m³/d (135,000 b/d), 28 600 m³/d (180,000 b/d) and 31 800 m³/d (200,000 b/d) and that the results of the studies indicate the rate increase will not adversely affect cumulative recovery from the field.

In the Application, the Proponent presented revised original oil-in-place and gas cap gas-in-place estimates for the Hibernia Reservoir based on a new reservoir model. This model incorporates structural and reservoir properties reflecting data obtained from the drilling and operation of wells B-16 1 to B-16 11. Table 1 provides a comparison of the oil-in-place estimates for the Hibernia Reservoir contained in the 1996 Development Plan Amendment with the estimates contained in this Application. Table 2 provides a comparison of the gas-in-place estimates.

The Proponent’s original oil-in-place estimate has decreased by about 6.5 percent, and the original gas cap gas-in-place estimate has increased by about 70 percent compared to the estimates provided in the 1996 Development Plan Amendment. Most of the increase in the gas cap gas-in-place estimates is attributed to the A4/B4 pools where the B-16 2 well confirmed a gas cap in the Q fault block (Figures 2 and 3). As is discussed later and shown in Table 6, the Proponent’s reduction in the original oil-in-place estimates is more than offset by the increased oil recovery that results from better reservoir quality than was originally anticipated.

Figure 2: Hibernia Reservoir ‘B’ Pool Fault Blocks

The Proponent stated that data from the development wells demonstrated that the reservoir quality is better than indicated by the original appraisal wells. The reservoir model was changed to reflect the new data. Table 3 presents a comparison of average reservoir properties contained in the 1996 Development Plan Amendment with those used in the current model.

Table 1: Hibernia Reservoir: Original Oil-in-Place Estimates (10⁶m³)

Table 2: Hibernia Reservoir Gas Cap: Original Gas-in-Place Estimates (10⁹m³)

Figure 3: Hibernia Field Pool and Zone Designations Hibernia Formation

Table 3: Comparison of Average Reservoir Properties: 1996 Development Plan and Current Reservoir Model

In its 1998 Annual Production Report, the Proponent provided a comprehensive review of production from the Hibernia field and of the performance of each of the producing fault blocks. According to the Proponent, the well performance data clearly indicate that the reservoir has the capability to produce at a higher rate than was originally estimated. Also, the rate at which water can be injected in the injection wells has been higher than expected, and the water injection facilities have proven themselves capable of sustaining higher injection rates than those planned in 1996.

The Board has reviewed the information provided by the Proponent and concurs that the reservoir quality appears to be better than originally estimated. It also concurs with the Proponent’s statements concerning production and injection well performance.

The Proponent has constructed a detailed reservoir simulation model for the Hibernia and Avalon Reservoirs. This model enables the Proponent to examine the behavior of the reservoirs under various production scenarios. This model was calibrated against the production data from the R, Q and W fault blocks in the Hibernia reservoir. No production data are yet available to calibrate the model for the Avalon reservoir. The model was then used to study the effects of production at three different peak production rates, 21 600, 28 600 and 31 800 m³/d (135,860, 180,000 and 200,000 b/d), respectively. Table 4 provides a summary of the oil recovery predicted by these studies for 25 years of production. Figure 4 shows the well locations in the Ben Nevis/Avalon reservoir used in these studies.

The Proponent’s simulation studies suggest that increasing the production rate will not adversely affect oil recovery. Indeed, the study results show a small increase in recovery associated with producing at the higher rate. However, the reason for this apparent increase is simple. While the same volume of oil can be expected to be recovered ultimately at all peak production rates; producing at a higher peak rate means larger volumes are recovered sooner. In this instance, the differences in the total volumes recovered are relatively small because the study period is long enough for virtually all of the recoverable oil to be produced in each case.

Table 4: Hibernia Field Reservoir Simulation: Comparison of Cumulative Oil Recovery at Production Rates of 21 600, 28 600 and 31 800 m³/d after 25 years Production

Figure 4: Ben Nevis / Avalon Reservoir Fault Blocks and Proposed Well Locations

Table 5 compares the predicted oil recovery efficiency for each fault block and region in the Hibernia and Avalon reservoirs after 25 years of production at each of the peak production rates examined. Figure 5 depicts the production profile for each case.

Table 5: Hibernia Reservoir: Comparison of Oil Recovery Efficiency after 25 years

Figure 5: Comparison of the Proponent’s Production Forecasts

Table 6 presents a comparison of the predicted oil recovery after 25 years of production, presented in the 1996 Development Plan Amendment based on a peak average daily oil production rate of 21 450 m³/d (135,000 b/d), with that predicted in the Application at the proposed peak average daily production rate of 28 600 m³/d (180,000 b/d). The simulation results indicate little difference in recovery between the base case presented in the 1996 Development Plan Amendment and the proposed high rate case.

The oil production forecast for the proposed rate of 28 600 m³/d (180,000 barrels/day) is presented in Figure 6.

Table 6: Simulated Oil Recovery after 25 years of Production: 1999 Application vs 1996 Amendment>

Figure 6: Proposed Hibernia Field Production Forecast

The Board has reviewed the Proponent’s reservoir simulation studies and the information submitted in support of the proposed rate increase and is satisfied that the simulation study was comprehensive in scope and incorporated the relevant data acquired from drilling and production activities. Bottom hole pressure data acquired from wireline and permanent down-hole pressure gauges and production history, were used to match the performance of the Hibernia reservoir to the model results. While reasonable matches with the production data from the W, Q and R fault blocks were achieved, the Board observed that only limited production data were available for history matching as no producing wells have experienced water production or a significant increase in gas/oil production ratio in response to the water and gas injection.

The Board concurs with the Proponent’s findings that the higher production rates do not appear to adversely impact oil recovery. However, because there is very limited production history to calibrate the model, and because fluids will move through the reservoirs more quickly at the higher production rate, the Board believes that it is necessary to increase the frequency of production logging efforts to monitor fluid movements and provide the data required to update the reservoir simulation model.

During its review, the Board also observed that the metering and production allocation system currently in use is introducing uncertainty in the reservoir simulation modeling. For proper reservoir management, it is essential to measure, or estimate where direct measurement is not possible, the volumes of fluids produced from and injected into a reservoir as accurately as possible. The Proponent has made significant progress in addressing problems with the metering systems. Modifications were made to the test separator arrangements to allow both separators to be used in testing high rate wells, new meters have been installed on the water injection wells and further improvements are planned during a shutdown scheduled March 2000. These changes, when implemented, should alleviate the Board concerns.

The Board observed that the Proponent’s simulation studies provide for depletion of the majority of the B pool fault blocks in the Hibernia reservoir and a selected area of the Ben Nevis/Avalon reservoir. The reservoir simulation studies did not specifically account for depletion of the oil and natural gas liquids in the following areas:

• • • The Hibernia reservoir B pools in fault blocks D, F, L, M, N, S, AA, DD, EE and FF which are estimated to contain about 20 10⁶m³ (128 Million barrels) of original oil-in-place;
    • The Hibernia A pools which are estimated to contain about 21 10⁶m³ (132 Million barrels) of original oil-in-place and which have not yet been approved for development;
    • Outlying areas of the Ben Nevis/ Avalon reservoir;
    • The Catalina and several smaller reservoirs; and,
    • The natural gas liquids associated with the gas cap and injection of the solution gas.

The Board notes that it is likely that some of these hydrocarbon resources will be exploited in the future to sustain the proposed plateau production rate of 28 600 m³/d (180,000 barrels/day). Therefore, the Board believes the Proponent’s oil production forecast is conservative.

When the Proponent first submitted the Application, the testing program to confirm the Hibernia platform’s production capacity and identify “bottlenecks” (i.e., modifications to facilities that are necessary to achieve the proposed production rate increase) had not been completed. In addition, the gas compression facilities had not been operating consistently and the platform had not achieved sustained production at its design capacity for any significant period.

Before making a decision on the proposed rate increase, the Board requested the Proponent to submit the results of its testing program for review. It also required the Proponent to demonstrate that both gas compression systems on the Hibernia platform were capable of operating on a continuous basis and that the platform was capable of operating continuously at the currently approved design capacity of 24 000 m³/d (150,000 barrels/day). The Board also held discussions with the Proponent respecting its production logging activities and the metering systems discussed above.

The Proponent completed the high rate testing program to confirm the capacity of the Hibernia platform and identify the modifications to facilities needed to achieve the proposed production rate increase in December 1999. The Board received results of the testing program in January 2000. In addition, since November 4, 1999, the Hibernia platform has been producing at its design capacity and both gas compression systems have been operating on a continuous basis.

The Board notes that there are currently seven producing wells in service on the Hibernia platform. This is significantly fewer than the fifteen that were estimated to be available at this time in the 1996 Development Plan Amendment. Production at the higher rates will require increasing the production rate at each of the wells that are in service. While the Board acknowledges that these wells are highly productive and should be capable of producing at the higher rates, the loss of any well because of water breakthrough or mechanical failure could impair the Proponent’s ability to achieve the proposed higher production rates in the short term. As additional production wells come into service, the average production rate required of each well will fall and the Proponent will have sufficient production capacity and operational flexibility to support production at the higher rate.

In the short term, the Board believes that production logs to assess the performance of production and injection wells should be run more frequently than is currently the practice and is discussing this issue with the Proponent.

4.0 Conclusion

4.1 Hibernia Development Plan Amendment Decision 2000.01

The Board approves the Proponent’s application to increase the average daily oil production rate to 28 600 m³/d (180,000 b/d) in the two stages proposed by the Proponent, subject to Condition 2000.01.01 set out below and the conditions contained in its Decision Reports 86.01, 90.01 and 97.01, the outstanding conditions of which are summarized in Sections 4.2, 4.3 and 4.4 below.

Under this approval, the maximum allowable oil production for the calendar year 2000 will be determined using the following daily average oil rates:

• • 1. 21 450 m³/d (135,000 barrels/day) from January 1, 2000 to the day immediately preceding the day upon which the Board’s approval for an increase to the annual oil production rate becomes effective pursuant to Section 32 of the Acts; and,
    2. 28 600 m³/d (180,000 barrels/day) from the date the Board’s approval for an increase to that rate becomes effective pursuant to Section 32 of the Acts.

For each calendar year thereafter, the maximum rate shall be the rate approved in (b) above.

Condition 2000.01.1

It is a condition of the Board’s approval that:

This approval may be suspended or revoked if the Board’s Chief Conservation Officer determines that the Proponent’s operations depart significantly from those projected in the Application or if reservoir performance differs significantly from that predicted in its document entitled “Technical Support for Hibernia Field Rate Increase”.

APPENDIX A
OUTSTANDING CONDITIONS FROM DECISIONS 97.01, 90.01 AND 86.01

A1
Hibernia Development Plan Amendment
Decision 97.01

The Board has reviewed the status of the five Conditions attached to its 1997 approval of the Hibernia Development Plan Amendment. These conditions, some of which require a continuing response and some of which relate to activities that have yet to occur, have not yet been satisfied.

Condition 97.01.1

It is a condition of approval of the Amendment that:

• • 1. Prior to initiating of production from the Hibernia ‘A’ pools, the Proponent submit its depletion plan therefor for the approval of the Board.
    2. The Development Plan update to be submitted following the appraisal period must provide a firm plan for delineation of the northwest and southwest areas of the Avalon reservoir.

Condition 97.01.2

It is a condition of approval of the Amendment that:

• • 1. Prior to proceeding with the water flood in the Hibernia reservoir ‘B5’ pool ‘H’ and ‘I’ fault blocks the Proponent reassess the depletion schemes for these blocks and obtain the approval of the Chief Conservation Officer for the scheme to be implemented.
    2. The oil production rate in the Hibernia reservoir ‘G’ gas flood block is restricted to a maximum rate of 1190 STm³/d per well until such time it can be demonstrated to the Chief Conservation Officer that a higher production rate will not be detrimental to oil recovery.
    3. The reservoir pressure in those fault blocks containing a gas cap shall be maintained at least 1000 kPa above the dew point pressure. In other fault blocks, the reservoir pressure shall be maintained at least 500 kPa above the bubble point pressure.

Condition 97.01.3

It is a condition of approval of the Amendment that:

• • 1. The proponent shall submit annually for the information of the Chief Conservation Officer a forecast of oil production from each pool for the coming year.
    2. One year following the commencement of gas injection, the proponent shall submit a revised forecast of the natural gas liquids production.

Condition 97.01.4

It is a condition of approval of the Amendment that before the end of 1999 the Proponent submit a report detailing the revised Hibernia Field reserve estimates. The report is to present the range of oil and natural gas liquids reserves, downside, most likely and upside, anticipated for each pool and reservoir and is to include an explanation of the uncertainties involved and economic cut-off used to generate the estimates.

Status:

Condition 4: Continued.

The Proponent has submitted a report and the Board has requested further information to satisfy the condition.

Condition 97.01.5

It is a condition of approval of the Hibernia Development Plan Amendment that the Proponent evaluate the potential to exploit areas of the Avalon reservoir penetrated by Hibernia reservoir development wells and not proposed for development by re-completing selected wells. The results of the evaluation are to be presented in the Development Plan Update to be submitted to the Board following the Avalon reservoir appraisal period.

A2
Hibernia Development Plan Update
Decision 90.01

The Board attached four Conditions to its 1990 approval of the Hibernia Development Plan Update. These have all been satisfied.

A3
Hibernia Benefits Plan
Decision 86.01 Status

The Board attached five conditions to its 1986 approval of the Hibernia Benefits Plan. The following conditions have not been satisfied:

Condition #4

That as the project evolves, the Proponent provide to the Board comprehensive listings of all major contracts and purchase orders anticipated. The Board, in consultation with the Proponent, will determine which of these major contracts and purchase orders will be subject to Board review.

Status:

Satisfied/Ongoing.

The Proponent provides this information to the Board in accordance with the C-NOPB’s Procurement Reporting Guidelines: Hibernia Development Project.

Condition #5

That the Proponent provide advance notice of and information on major contracts and purchase orders to enable the Board to conduct its review. The review time required will be determined by the Board, in full consultation with the Proponent.

Status:

Satisfied/Ongoing.

The Proponent provides this information to the Board, in accordance with the C-NOPB Procurement Reporting Guidelines: Hibernia Development Project.

A4
Hibernia Development Plan
Decision 86.01 Status

The Board attached seventeen conditions to its 1986 approval of the Hibernia Development Plan. The following conditions have not been satisfied:

Condition #1

• • 1. That the Proponent at a very early stage in the development program, drill a well in the area of the B-08 gas cap, to obtain samples for laboratory analyses and define a gas-condensate-oil regime; and,
    2. that the Proponent undertake studies, concurrent with initial development drilling, to establish the feasibility of a miscible flood for the Hibernia reservoir.

Status:

The Proponent has undertaken to drill a well in the area of the B-08 gas cap early in the development and complete a miscible flood feasibility study.

Condition 1(i): Satisfied.
Condition 1(ii): Continued.

Condition #2

• • 1. That prior to any development of the Avalon Reservoir, the Proponent submit a revised plan for the Board’s approval;
    2. that during development of the Hibernia Reservoir, the Proponent evaluate the Avalon Reservoir by coring, logging and testing all prospective zones penetrated by wells drilled to the Hibernia Reservoir; and,
    3. that during the design of topside facilities, the Proponent give due consideration to sizing equipment and allocating space for production facilities and utilities, sufficient to accommodate additional production from the Avalon Reservoir concurrently with Hibernia production, should there be a requirement to produce the Avalon Reservoir prior to the time contemplated in the Development Plan, and that the Proponent report to the Board on its actions in this regard before the topside facilities design is finalized.

Status:

Condition 2(i): Satisfied.

The submission of the 1996 Hibernia Development Plan Amendment constitutes a revised plan for development of the Avalon reservoir.

Condition 2(ii): Continued.

Condition 2(iii): Satisfied.

In August 1991, the Board accepted the Proponent’s plans for satisfying this condition.

Condition #3

• • 1. That the Proponent file for approval by the Board, prior to commencement of development drilling, a specific drilling schedule designed to reduce gas flaring to limits acceptable to the Board;
    2. that in the unlikely event that reservoir conditions prevent gas-reinjection, the Proponent present to the Board for approval a plan for gas disposal; and,
    3. that the Proponent obtain the Board’s approval to flare those small volumes of gas needed for normal operations.

Status:

Conditions 3(i) and 3(iii): Satisfied.

In August 1996, the Board conditionally approved the Proponent’s drilling schedule and volumes of gas to be flared during start-up and transition to steady state operations.

Condition 3(ii): Continued.

The Proponent has informed the Board that it has evaluated the feasibility of gas re-injection, and considers it to be highly feasible. A plan for gas disposal will be necessary only if gas re-injection proves to be detrimental to the resource recovery.

Condition #5

• • 1. That the Proponent design the export lines and loading platforms so that they can be flushed of hydrocarbons if there is risk of damage to those facilities; and,
    2. that the design iceberg scour depth be determined by the Proponent and approved by the Board prior to the design of subsea well installations.

Status:

Condition 5(i): Satisfied.

The Proponent designed its facilities so that export lines will be capable of being flushed, and, in a May 1997 submission to the Board, described its proposed procedures for flushing the risers in the offshore loading system. The Board approved the proposed procedures in May 1997.

Condition 5(ii): Continued.

No subsea well installations have yet been proposed.

Condition #9
That the Proponent obtain specific approval from the Board for its plans for subsea installations prior to proceeding with the detailed design of these facilities.

Status:

Continued.

Condition #15
That the Proponent provide periodically to the Board, during the execution of the project, in a form to be prescribed, estimates of the expected capital cost for the project as a whole and for those major components which the Board shall request.

Status:

Satisfied/Ongoing.

On a semi-annual basis, the Proponent’s Canada-Newfoundland Benefits Department provides capital cost expenditure forecasts and associated estimates of Canada-Newfoundland content levels which are expected to be achieved.

APPENDIX B
Glossary