Decision Reports

Decision 97.01

Table Of Contents


List of Figures

Figure 1 Hibernia Field Location

Figure 2 Pool and Zone Designation Hibernia Formation

Figure 3 Pool and Zone Designation Avalon Formation

Figure 4 Avalon Wells to be Drilled During Appraisal Period

Figure 5 Proposed Area of Avalon Development Well Locations – 1985 Development Plan

Figure 6 Proposed Hibernia Reservoir Well Locations 1985 Development Plan

Figure 7 Proposed Hibernia reservoir Well Locations and Outline of Gas and Water Flood Areas. 1996 Development Plan Amendment

Figure 8 Proposed Avalon Well Locations

Figure 9 Oil Production Forecast


List of Tables

Table 1 Original Oil-in-Place Estimates Reference Case

Table 2 Original Gas-in-Place Estimates Reference Case

Table 3 Summary of Vertical Stacked Core Flood Tests

Table 4 Oil Reserve Estimates and Recovery Factors Hibernia and Avalon “B” Pools

Table 5 Recoverable Reserves and Recovery Factors Hibernia and Avalon Reservoir


Decision 97.01

1.0
Summary

On July 10, 1996, the Hibernia Management and Development Company (the Proponent) submitted The Amendment to the Hibernia Development Plan, July 1996 (the Amendment) for the approval of the Canada-Newfoundland Offshore Petroleum Board (the Board). This report constitutes the Board’s conditional approval of the Proponent’s proposals.

The Amendment describes changes to the Proponent’s original geological and geophysical interpretation and the depletion plans for the Hibernia and Avalon reservoirs. In addition, changes are proposed in the well construction and completion technology to be used. Among other things, the proposed changes affect the production timing and rates in the various pools and estimates of recovery efficiency and petroleum reserves.

The Board has reviewed the Amendment to determine whether the proposed modifications 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 resulting from the public review by the Hibernia Environmental Assessment Panel. Since the amendments now being proposed deal with changes in the production schedule and with aspects of the project located below the seafloor, they do not affect the approved Hibernia Benefits Plan, nor raise any new environmental issues. Therefore, the Board has concluded that neither revision of the environmental impact assessment for the project, nor further public review is required.

The Board has determined that the submission of the Amendment satisfies Condition 2 (i) of its Decision 86.01 regarding the original Hibernia Development Plan, which required the submission of a revised plan for development of the Avalon reservoir. The Board’s disposition of the Proponent’s proposals concerning the Avalon reservoir is part of this decision.

The Board accepts the geological and geophysical interpretations presented by the Proponent for the Hibernia and Avalon reservoirs, recognizing that considerable uncertainty remains regarding the characterization of the Avalon reservoir, particularly in the northwest and southwest portions of the field where no delineation wells have been drilled. The Board also accepts the Proponent’s general approach to development of the Hibernia and Avalon reservoirs. This approach provides for early development of portions of the Avalon reservoir to resolve some of the uncertainty regarding reservoir conditions prior to preparing a comprehensive development plan for this reservoir. However, the Board has restricted development of the Avalon reservoir to those wells necessary for appraisal purposes and requires the Proponent to submit a firm plan for delineation of the northwest and southwest areas of the Avalon reservoir following the initial five-year appraisal period.

In addition, prior to initiating production from the ‘A’ pools of the Hibernia reservoir, the Proponent must submit its depletion plan to the Board for approval. Prior to proceeding with the water flood scheme in the Hibernia reservoir ‘B5’ pool, it must reassess its alternative depletion schemes and obtain the approval of the Chief Conservation Officer for the scheme to be implemented. In the Hibernia reservoir ‘G’ gas flood block, the Board has restricted the oil production rate to a maximum rate of 1190 STm3/d per well until it can be demonstrated that a higher production rate will not be detrimental to oil recovery. The Proponent is also required to maintain average reservoir pressure in those fault blocks containing a gas cap to 1000 kPa above dew point pressure and, in other fault blocks, to at least 500 kPa above the bubble point pressure.

While the Board accepts the production forecasts for oil and natural gas liquids presented by the Proponent, it notes the difficulties inherent in attempting to predict production rates and that many aspects of forecasting uncertainty will be resolved early in the production life of the Hibernia Field. The Board believes that the reserve estimates presented by the Proponent are conservative and do not characterize the ‘upside’ oil and natural gas liquids reserve potential of the Hibernia Field. Because a knowledge of this potential is important in assessing the Proponent’s long-term approach to recovery of the field’s reserves, the Proponent is required to submit a report by the end of 1999 detailing the range of oil and natural gas liquids reserve estimates for each pool and reservoir. The Board also requires the Proponent to submit annually an oil production forecast for the upcoming year for each pool for the information of the Chief Conservation Officer and, one year following commencement of gas compression, a revised forecast of natural gas liquids production.

The well construction and operation and the production operations and maintenance philosophies presented by the Proponent are considered acceptable. However, the Board believes that an opportunity exists to deplete a portion of the Avalon reservoir, not currently proposed to be developed, by recompleting Hibernia reservoir wells. Therefore, the Board has required the Proponent to evaluate this potential and report its findings to the Board.

The Proponent has made significant progress in satisfying many of the conditions set out in the Board’s Decision 86.01 and Decision 90.01. The status of these conditions is reviewed in Chapter 4.

Conditions 3 (i) and (iii) of Decision 86.01 dealt with gas conservation. The Board wishes to record that during 1996 it conditionally approved the Proponent’s drilling schedule and the volumes of gas to be flared during start-up and transition to steady state operations, which will extend over the first eighteen months of production, pursuant to a separate submission by HMDC on this subject made pursuant to the Production and Conservation Regulations.

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 kilometres, and is estimated by the Proponent to contain some 98 106 m3 of recoverable oil in two separate reservoirs, the Hibernia and the Avalon.

Early in 1986, 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 Board has monitored the evolution of the Hibernia project through regular meetings with the Proponent and through the review of engineering reports and other supporting studies submitted to the Board.

On March 30, 1990, Mobil submitted the Hibernia Development Plan Update (the Update) which incorporated proposed modifications to the original conceptual design of the structure topsides and other new information concerning the overall field development. Additionally, the Proponent reported it had chosen a specific site for the construction of the gravity base structure (GBS) and assembly of the topside structure. The Board reported its decision conditionally approving the Update in August, 1990 (Decision 90.01).

On July 10, 1996 the Proponent submitted The Amendment to the Hibernia Development Plan (the Amendment) incorporating proposed changes to the original depletion plans for the Hibernia and Avalon reservoirs for the Board’s approval. The proposed changes to the original development plan submitted in July, 1996 include:

  • 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;
  • Revised designs for well construction and completion.

As the proposed amendments deal with the aspects of the project located below the seafloor, the Board determined that the amendments do not affect the approved Hibernia Benefits Plan and fall within the scope of activities considered by the Hibernia Environmental Assessment Panel. The Board has determined, therefore, that revisions to the environmental impact assessment of the project and further public hearings are not required for its consideration of the Amendment.

Approval of the Amendment by the Board is required 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).

This report constitutes the Board’s conditional approval of the revisions presented in the Amendment. It also includes a review of the status of the conditions which the Board attached to its approval of the original benefits and development plans in 1986 and to the update of these plans in 1990.

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 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. When regulations have not yet been promulgated but their development is sufficiently advanced that further substantial changes are unlikely, it is the Board’s policy to make compliance with the latest draft of those regulations a condition of its approvals.

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. The Production and Conservation Regulations establish the requirement that before production operations may commence, the operator must, as part of the documentation supporting its application for authorization, provide the Board with a Certificate of Fitness issued by a Certifying Authority recognized by governments. During 1989, four organizations, the American Bureau of Shipping, Bureau Veritas, Det Norske Veritas (Canada) Ltd. and Lloyd’s Register of Shipping were recognized to issue such certificates for facilities proposed to be installed offshore Newfoundland. The choice of a Certifying Authority rests with the Proponent for the project.

2.3
History of the Hibernia Project

2.3.1
Discovery and Licensing

The Hibernia field was discovered in 1979 by the Chevron et al Hibernia P-15 well. Between 1979 and 1984, nine further wells were drilled by Mobil, as operator for the participants, to delineate the field. The discovery well was officially declared to be 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.

Prior to 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 was 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:

Mobil Oil Canada Ltd.28.125%
Chevron Canada Resources Ltd.21.875%
Petro-Canada20.00%
Canada Hibernia Holding Co. Ltd.8.5%
Murphy Atlantic Offshore Oil Company Ltd.6.5%
Chevron Hibernia Holding Company Ltd.5%
Mobil Canada Hibernia Holding Company Ltd.5%
Norsk Hydro Canada5%

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. Upon the appointment of the Board in December, 1985 these plans were referred to it for review and decision. The Board conditionally approved the Proponent’s plans in its Decision 86.01.

Following the 1985 application for approval of the Hibernia Development Plan, world oil prices declined sharply from the high levels of the early eighties. This decline led to reconsideration by the Hibernia partners of the economics of the development and was followed by extensive negotiations between the partners and both governments concerning fiscal and financial considerations.

These negotiations culminated with 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.

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) which incorporated proposed modifications to the original conceptual design of the structure topside, the location of the construction site for the gravity base structure and other new information concerning the overall field development. The Board conditionally approved the Update in August, 1990.

Since approval of the 1990 Update, HMDC has conducted a second 3-D seismic survey over the Hibernia field and has undertaken a thorough review of the geology, geophysics and reservoir characteristics which form the basis of the Development Plan Amendment. The Company has also made significant progress in satisfying the conditions approval set out in Decisions 86.01 and 90.01.

Major construction activities at the Bull Arm site were completed in November of 1996 and the topsides and GBS were mated in March 1997. Work continues on commissioning of the facilities in preparation for tow-out to the field in June, 1997. Two dedicated, ice-reinforced shuttle tankers are under construction, the first of which is scheduled to be available at the Field in October, 1997.

In September 1996, Mobil, Chevron and Petro-Canada announced plans to construct a terminal at Whiffen Head in Placentia Bay to transship oil produced at Hibernia and other fields on the Grand Banks. This plan is under review by Federal and Provincial authorities.

3.0
The Hibernia Development Plan Amendment

3.1
Introduction

Since the Hibernia Oil Field Development Plan was submitted in 1985, a 3-D seismic survey has been conducted over the field. Also, significant advances have taken place in the technologies for subsurface reservoir interpretation, drilling and well completion. These advances and new information from the seismic survey have led to a better understanding of the Hibernia structure and identified opportunities to produce additional reserves. The Hibernia Development Plan Amendment sets out the Proponent’s current interpretation of the geology, geophysics and the reservoir characteristics of the field and its proposed approach to recovery of the oil reserves in the Hibernia and Avalon reservoirs.1

The Board has reviewed the Amendment against the relevant statutes and regulations. These require that:

  • The resource be produced in accordance with good oil field practice, having proper regard for the efficient recovery of the resource and the prevention of waste;
  • The facilities which are installed be designed to take into account the environmental conditions to which they may be exposed, so as to maintain their integrity throughout the possible life of the field;
  • A responsible approach be taken to environmental protection in the design of the facilities and in the planning for contingencies; and,
  • The safety of personnel be a primary consideration in the design of facilities, the choice of equipment, the development of operating procedures and contingency planning.

3.2
The Amendment

The Proponent requests approval for the following changes from the development plan approved in Decisions 86.01 and 90.01.

  • Integrated Hibernia-Avalon Development ( Addressing Condition 2(i) to 2(iii)) – Initial development will focus on drilling high quality wells in the Hibernia “B” pools to build up production levels to the platform’s peak production capability within three years from commencement. Aggressive appraisal development of the Avalon Reservoir will begin as soon as sustainable production capacity has been established from the Hibernia reservoir. A balanced development and depletion strategy will be implemented for both the Avalon and Hibernia Reservoirs.
  • Avalon Development (Addressing Condition 2(i) to 2(iii) – The proposed Avalon Reservoir Development is based in part on new seismic interpretations, a re-assessment of existing well data, new simulation studies and application of the latest drilling and completion technologies. A comprehensive development plan, which details well locations, production levels, potential reserves and timing and extent of the reservoir development is, at this time, not fully defined. HMDC will submit a complete Avalon Development Plan five years after the first Avalon appraisal wells are drilled. At that time, having acquired detail log, core, fluid, pressure and production data, HMDC will be able to better define the Avalon potential. Given encouraging results from the appraisal program, additional Avalon areas will be evaluated and developed through extended reach and possibly subsea drilling. The outlying Avalon reservoirs are a key element of our future delineation drilling and offer the potential to extend the platform plateau production period.
  • Implementation of Hibernia Reservoir Water Floods and Gas Floods – Potential Hibernia well locations have been identified assuming that all minor faults are sealing with each fault block having a planned development that includes injectors and producers. Each block of the Hibernia “B” sands will be individually established as either a water flood or gas flood. Water injectors are needed almost immediately for pressure support of producers. Gas injection wells are needed for conservation of produced gas and for pressure maintenance.
  • Maximum Well Rates ( Addressing Decision 86.01 Section 3.35 – Production Mechanisms) – Well producing rates exceed target rates identified in Decision 86-01. Target well production rates are 3200 STm3/D ( 20,000 STB/D ) for both gas and water flood producers. The maximum water injection rate is 6400 m3/Day/Well. Reservoir quality in areas targeted for initial development may support initial producing well rates of 6400 STm3/D (40,000 STB/D ) and injection well rates of 11100 m3/D (70,000 STB/D ) with appropriate well and facility design. Early high rate production from both gas and water flood wells drilled during an initial production ramp period will not have any appreciable impact on recovery since production rates from these wells will be reduced (prorated ) once full development is established.
  • Commingled Production of Zones 1 and 2 of the Hibernia “B” Pool ( Addressing Decision 86.01 Section 3.3.5 – Production Mechanisms ) – Initially, the majority of Zones 1 and 2 within the Hibernia “B” pools will be perforated and placed on commingled production or injection. Any distinguishable breaks between net pay intervals will not be perforated, allowing for future mechanical or chemical profile control at the production well.
  • Gas Conservation ( Addressing Condition 3 (i) to 3 (iii)) – Every effort will be made to conserve produced gas over the life of the project, as increased injection will enhance recovery levels in the gas flood. However, there will be a period, prior to completing the first gas injector, when gas will need to be flared if any significant volumes of oil are to be produced. Additionally, intermittent gas to flare as a result of process up sets and downtime will be identified in an application for approval to flare gas. Total volume and rates will be identified, as well as technical justification in support of the plan.
  • Miscible Flood Feasibility (Addressing Condition 1(i) and 1(ii)) – A Hibernia miscible flood feasibility assessment will be completed within a year of obtaining representative fluid samples from the zones to be gas flooded. The first gas injector, drilled within six months after first oil, will provide the representative samples needed to determine an optimum injection stream.
  • Well Construction and Completion – a) All potential Hibernia locations can be reached with platform wells using current extended reach drilling technology. Initial Avalon development will also rely on platform wells, with any subsea development being contingent upon results of Avalon production performance. b) A monobore type completion design will be used for both Hibernia production and injection wells permitting required well intervention to be performed using relatively inexpensive non rig methods, such as slickline electric wireline or coil tubing. The use of conventional wells also allows practical and cost effective well profile control.

3.3
The Board’s Review

3.3.1
Geology and Geophysics

Since submission of the Hibernia Development Plan Update 1990, the Proponent has completed a detailed review of the geology and geophysical information from the 3-D seismic program and submitted reports on these studies to the Board as part of its pooling proposal for the Hibernia and Avalon reservoirs. Based on the Proponent’s submissions and the Board’s staff interpretations, the Board’s Chief Conservation Officer designated twelve pools and two zones in the Hibernia formation and eight pools and five zones in the Avalon formations. These pools and zones are shown in Figures 2 and 3 and form the basis for discussion in the remainder of this report.

The Board believes the Proponent’s interpretation of the Hibernia formation is reasonable and acknowledges the extensive studies conducted on the Avalon formation. However, considerable uncertainty remains in the interpretation of data regarding the formations comprising the Avalon reservoir. This uncertainty can only be resolved by further drilling to acquire the necessary data. This is particularly true in the southwest and northwest areas of the reservoir.

3.3.2
Reservoir Targets

Prospective target reservoirs exist in the Avalon, Hibernia, Catalina and Jeanne d’Arc formations. The Proponent states that highly productive and high quality sandstones of the ‘B’ pools in the Hibernia reservoir are the principal targets for early development. The Hibernia ‘A’ pools may be produced concurrently with the deeper lying Hibernia ‘B’ pools or they may also be produced on their own prior to re-using the Hibernia development well slots. In the Avalon formation, prospective reservoirs have been identified in the Avalon ‘A’, ‘B’ and ‘C’ pools. The Avalon reservoir is relatively more complex, both structurally and stratigraphically, than the Hibernia reservoir. The Proponent proposes limited development of the Avalon reservoir at this time and states that the Catalina sandstones will be further delineated during Hibernia development drilling since more data is required to confirm the assumptions made about their continuity. The sandstones of the Jeanne d’Arc formation, which underlie the Hibernia formation, were found to be overpressured in the wells which penetrated them to date. Evaluation of the Jeanne d’Arc reservoirs is not proposed until the plateau production period in the field’s life is reached.

The Board has conducted an independent review of prospective reservoirs and believes the Proponent has presented a reasonable characterization of those targets in the Hibernia field. Some of the reservoirs, such as Hibernia, are well delineated. However, the majority require more data to assess fully their development potential and optimize development plans. The Board believes that all of these reservoirs have potential for development.

3.3.3
Original Oil and Gas-In-Place

The Proponent has re-evaluated the petrophysical data collected during delineation drilling and presented revised estimates of geologically mapped, original oil-in-place, non-associated gas-in-place, and solution gas-in-place. The oil-in-place estimate for the field has increased from the 1990 estimates by about 31 million m3, the majority of which is attributed to the Catalina reservoir. A summary of the current oil-in-place estimates is provided in Table 1 with the corresponding estimates from the 1990 Development Plan Update. The Proponent also conducted a sensitivity analysis of the original oil-in-place estimates for the Hibernia and Avalon reservoirs. The original oil-in-place at the 90% and 10% probably of occurrence was

estimated to be 200 106m3 and 286 106m3 respectively for the Hibernia reservoir and 228 106m3 and 396 106m3 respectively for the Avalon reservoir.

A summary of the Proponent’s revised original gas-in-place estimates for its reference case is provided in Table 2 with the 1990 estimates shown for comparison. According to the Proponent’s estimates there is a small increase in the original gas-in-place estimate of about 9.5 109m3 from that reported previously. The Proponent also noted that along with the 10.07 109m3 of gas cap gas in the Hibernia reservoirs, there is 7.55 106m3 of C5+ liquids.

Table 1
Original Oil-in-Place Estimates
Reference Case (106 m3)
Reservoir Target19901996
Avalon297301.2
Hibernia214220.8
Catalina2.022
Jeanne d’Arc0.080.08
Total Field513.08544.08
Table 2
Original Gas-in-Place Estimates
Reference Case(109 m3)
Reservoir TargetSolution GasFree GasTotal Gas
199019961990199619901996
Avalon24.831.724.831.7
Hibernia46.558.918.8*10.0765.368.97
CatalinaNANA3.8**2.53.82.5
Total Field71.390.622.612.5793.9103.17

* Gas Cap
** Non-Associated

The Board has conducted a review of the available data and has concluded that the estimates presented by the Proponent are reasonable. However, the Board notes that the inferred oil-water contact in the Avalon reservoir at 2602 metres subsea, as indicated by log analyses in the I-46 and J-34 wells, is not supported by the pressure data for these wells which suggest that the oil-water contact could be 300 to 400 metres deeper. Other areas of uncertainty which may significantly affect the oil and gas-in-place estimates include: resolution of the oil-water and gas-oil contacts in the Hibernia reservoir; confirmation of the southwest extension of the Avalon reservoir oil accumulation; definition of the seismicly interpreted G-55 wedge; and determination of the oil-water contact and petrophysical cutoff parameters in the Avalon reservoir. The Board believes that these uncertainties should be resolved as early as possible in the producing life of the field so that any adjustments to the development plan which are necessary to maximize recovery can be made at an early date.

3.3.4
Reservoir Engineering

In Chapter 4 of the Amendment, the Proponent presented its proposed depletion and production strategy, its revised production and reserves forecasts and its proposed reservoir management strategy. The Proponent also discussed the depletion processes for each pool proposed to be developed, production rate sensitivity and the timing of subsea development. The Proponent has created an integrated reservoir simulation model for the Hibernia ‘B’ pools and the Avalon ‘B’ pools, excluding Zone 1, and a separate model for Zone 1 of the Avalon ‘B’ pools.

Since the original Hibernia Development Plan was submitted in 1985, new geological and reservoir information has become available and there have been many advances in analytical technology. The Board acknowledges that the Proponent has conducted an extensive review of its depletion and production strategies and has incorporated the latest technology and analytical procedures in its analyses. The Board feels, however, that to model the Avalon ‘B’ pools properly, the integrated model for the Avalon ‘B’ pools should be updated to incorporate Zone 1 because the Proponent has stated that all zones in these pools are in communication.

The Board’s review has identified four aspects of the application that require further attention. These are the depletion and production strategy, depletion process, production forecast and reserves estimate.

3.3.4.1
Depletion and Production Strategy

The Proponent proposes to focus initial development on drilling wells into the Hibernia reservoir to bring production to rated platform capacity as soon as possible. After sustained production is reached, a balanced depletion strategy for Avalon and Hibernia reservoir development is proposed. The Proponent presented its general objectives for the ramp-up, plateau and decline phases of the project and stated that its production strategy incorporates aggressive appraisal development of the Avalon reservoir as early as possible in the development schedule to help resolve uncertainties regarding this reservoir.

During the ramp-up phase, lower risk and high productivity areas of the Hibernia ‘B’ pools will be targeted. Prior to initiating water injection, the Proponent proposes to draw down reservoir pressure to investigate fault sealing and aquifer support. Avalon production is proposed early in the plateau stage during which time drilling will target areas of higher uncertainty in the Hibernia and Avalon reservoirs. During the decline phase, the Proponent proposes to optimize production from the Hibernia and Avalon reservoirs so that facilities will not be underutilized, and to use available platform capacity to produce secondary reservoir targets and satellite fields.

The Proponent states that a comprehensive development plan for the Avalon reservoir cannot be formulated at this time because of the limited understanding of the reservoir characteristics and because the results of the appraisal program are essential to establish a long-term development strategy. Appraisal of the Avalon reservoir is proposed to begin once production capacity from the Hibernia reservoir, sufficient to maintain production at rated platform capacity, is established.

The Proponent also states that development of the southwest and northwest areas of the Avalon reservoir will likely require subsea wells since these areas lie outside the platform’s drilling range using currently available technology. Subsea development is expected to begin toward the end of the plateau period.

The Proponent states that a report detailing the results of the Avalon appraisal program and an update to the Hibernia Development plan will be submitted five years after first oil production which will occur about two years after the start of Avalon appraisal drilling. This report will provide a comprehensive development plan for the Avalon reservoir.

The Avalon reservoir well locations that are tentatively scheduled for the appraisal development program period are shown in Figure 4. The Proponent proposes to focus initially on the ‘N’ fault block area because:

  • Simulation studies indicate this block has the greatest potential for high productivity and water flood establishment;
  • Many of the basic uncertainties regarding the Avalon reservoir can be addressed by drilling in this area; and,
  • The ‘B1’ and ‘B3’ pools can be evaluated through use of creative well trajectory planning.

All pools within the range of extended reach drilling from the GBS are targets, except the Avalon ‘B5’ pool which carries small reserve estimates. The Proponent also states that additional Avalon reservoir areas will be evaluated and developed through extended reach and subsea drilling if the results from the appraisal program are encouraging.

The Board agrees with the Proponent’s proposal to focus initially on Hibernia reservoir development and specifically on the Hibernia ‘B’ pools. The Board also notes that a depletion plan has not been finalized for the Hibernia ‘A’ pools. The need to investigate fault sealing and aquifer support prior to injecting water into the Hibernia reservoir is also agreed, because these factors may influence the number of wells required and therefore need to be investigated early. The Board considers the general objectives stated by the Proponent for each production phase to be reasonable.

The 1985 Development Plan proposed development for the Avalon reservoir in the ‘B3’ pool area, shown in Figure 5. Production from this area was to begin eight years after the start of production to maintain plateau production at the plateau level. The Board rejected the development plan proposed for Avalon reservoir at that time, stating that it expected the Proponent to continue to evaluate the potential of the Avalon reservoir and to consider ways to exploit the reservoir earlier than proposed in the development plan.

Since the 1985 Development Plan was submitted, the Hibernia partners have represented to the Board that commercial quantities of oil exist in the Avalon formation in the southwest portion of the Hibernia field. On the basis of the evidence presented, the Board included this area in the commercial discovery declaration for the Hibernia field.

The Proponent’s strategy for Avalon reservoir development includes an appraisal stage designed to resolve uncertainties and acquire the information required to devise a comprehensive development plan for the Avalon reservoir. The strategy proposes earlier development and a larger development area than was proposed in the 1985 Development Plan. However, the Board believes there are still two major areas of uncertainty which need to be addressed in order to prepare a comprehensive development plan for the Avalon reservoir. These are the production performance of the reservoir under water flood conditions, and the delineation of the reservoir in the southwest and northwest areas of the Hibernia structure to establish more precisely the extent of the hydrocarbon accumulation and determine reservoir characteristics.

The Amendment contains no firm commitment to drill in the northwest area, a concern noted in Decision Report 86.01, nor the southwest area of the Avalon reservoir. While the Proponent proposes to drill well AOPN5 to probe the southwest area, this well alone will not adequately appraise the southwest and further drilling, in the area beyond the present range of extended reach drilling, will be needed. The Board believes delineation drilling will be necessary to prepare a comprehensive development plan for the Avalon reservoir.

In conclusion, the Board accepts the strategy for the Avalon development to be followed during the appraisal period but notes that the development plan update to be submitted following the appraisal period must include a firm plan to delineate the northwest and southwest areas of the Avalon reservoir.

Condition 97.01.1
It is a condition of approval of the Amendment that:

  1. Prior to initiating 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.

3.3.4.2
Depletion Processes

In the 1985 Hibernia Development Plan, the Proponent proposed to deplete those Hibernia reservoir fault blocks containing a gas cap by a combination of down-dip water injection and up-dip gas injection (Figure 6). The Proponent now proposes to modify the depletion scheme so that each of those fault blocks will be developed using either water or gas flood to maintain reservoir pressure (Figure 7). About two thirds of the Hibernia ‘B’ pools will be exploited using a bottom-up water flood scheme and parts of the ‘B5’ and ‘B6’ pools will be exploited using gas flood, with lean gas being injected close to the gas-oil contact. The well locations have been selected assuming all minor faults are sealing. The projected number of injection wells may be reduced if the data acquisition program indicates that there is communication across the faults. The Proponent estimates that the theoretical recovery efficiency for the water flood and gas flood could approach 50%. However, the currently projected production profile is based on recovery of about 45% and 40% from the water and gas flood areas, respectively. A determination of the volume of gas required to flood the designated gas flood areas and the assessment of the gas supply provided by the Proponent shows there is a balance between gas available and the volume of gas required.

The ‘H’ and ‘I’ fault blocks within the Hibernia ‘B5’ pool were excluded from the areas planned for gas flood at this time because of differences in the properties of fluids encountered in the K-18 and B-08 delineation wells. The Proponent plans to obtain and analyze additional fluid samples when new wells are drilled into these reservoir units before making a final decision as to whether a water or gas flood scheme will be chosen.

It is proposed to conserve gas by initiating injection into the Hibernia ‘B5’ pool prior to starting oil production from this pool. This will overpressure the pool and could lead to a loss of oil reserves into the water leg. The Proponent estimates the potential loss to be 0.2% of the oil-in-place in this pool but also states that its gas displacement studies have indicated that, for the Hibernia reservoir, a higher reservoir pressure will improve the overall recovery process and leave less residual oil.

To support this conclusion, the Proponent presented the results of gas displacement studies conducted by Chevron Petroleum Technology Co. on its behalf and stated the centrifuge gas/oil tests indicate a residual oil saturation to gas displacement of 10%. Vertical stack core flood tests were also used to determine the behavior of gas and water displacing reservoir oil. A summary of the results of these tests is provided in Table 3. The test results show that lean separator gas displaces oil more efficiently than gas from the gas cap.

Table 3
Summary of Vertical Stacked Core Flood Test Results
TestResidual Oil Saturation
(from Material Balance) %
Residual Oil Saturation
(from Extract Analysis) %
Water flood39.72
Separator Gas Flood12.0711.50
Gas Cap Gas Flood14.9212.01

The Proponent states that a potential exists to increase gas flood recovery by enriching the injection gas stream to make it miscible with the reservoir oil and that a miscible flood feasibility study will be completed soon after representative fluid samples can be obtained from the reservoir zones scheduled to be gas flooded.

The Proponent has examined the sensitivity of oil recovery efficiency to well production rates under water flood and gas flood conditions and states that its studies indicate that the water flood blocks did not exhibit any sensitivity to well production rates up to 6400 STm3/d. However, the studies indicate that oil recovery from the ‘C’ gas flood block exhibits minor sensitivity to production rates up to 3400 STm3/d and that recovery from the ‘G’ gas flood block may be reduced by about 5% at higher production rates.

For the Avalon reservoir development, the Proponent is proposing a water flood scheme using the well locations as shown in Figure 8 and has stated that the water flood configuration will be refined as additional well construction and production data are obtained. Also, the depletion strategy will be reviewed based on the results of appraisal development.

The Board feels that the revised depletion scheme proposed for the Hibernia reservoir pools is reasonable. The Board notes that, for reservoir management purposes, it will be easier to control and monitor the movement of fluids with the revised scheme and that independent studies suggest that oil recovery may be better in the gas flood than in the water flood areas. If this is confirmed by production data, application of gas flood to other Hibernia ‘B’ pools will have to be examined in due course. The Board concurs with the Proponent that potential exists for a miscible flood in the Hibernia reservoir and with the need to obtain representative fluid samples to assess its feasibility.

Regarding the Hibernia ‘B5’ pool ‘H’ and ‘I’ fault blocks, the success of a water flood scheme in these blocks will depend on there being no communication across the fault separating these areas from the gas flood area and there being no significant gas cap in these fault blocks. The Board believes that there is a reasonable possibility that a gas cap may exist in the ‘H’ and ‘I’ fault blocks and that there may be communication with the gas flood area. The Board notes that the Proponent plans to review available information before making a final decision on the flood mechanism. In light of the uncertainty, the Board requires the Proponent to present the results of its review, which must address the existence of a gas cap in the ‘H’ and ‘I’ fault blocks and communication across the faults in the area and its proposed course of action to the Chief Conservation Officer for his concurrence, prior to proceeding with the depletion scheme for these blocks.

The gas flood end points (i.e., the residual oil left in the formation) estimated by the Proponent were a concern to the Board during its review of the 1985 development plan review. In Decision Report 86.01 the Board stated “The Board intends to ask the Proponent to conduct additional analytical studies to establish gas flood end points and to file those results with the Board before production begins.” The Board has reviewed the study conducted by the Chevron Petroleum Technology Company on behalf of the Proponent and believes this work is thorough and supports the proposition that gas flood can be an effective displacement mechanism in the Hibernia reservoir. The study satisfactorily addressed the relevant concerns raised in Decision Report 86.01.

The Board concurs with the Proponent’s proposal to conserve gas by injecting it into the Hibernia ‘B5’ pool prior to initiating production. This situation is expected to last about two and one-half months. The potential reduction in recovery caused by forcing the oil zone into the aquifer is small and will likely be offset by the volume of gas conserved and the improvement of the gas flood displacement efficiency at higher pressures.

The Board examined the Proponent’s rate sensitivity studies and agrees that the recovery efficiency in the water flood areas does not appear to be sensitive to oil production rates below 6400 STm3/d per well. Also the ‘C’ gas flood block shows little rate sensitivity up to well oil production rates up to 3400 STm3/d per well. However, the oil recovery efficiency does appear to be sensitive to production rate in the ‘G’ gas flood block. The Board believes that the production rate in this block should be restricted to 1190 STm3/d per well, as prescribed in Decision Report 86.01, until evidence can be presented to support the proposition that a higher rate will not adversely affect recovery.

The Board notes that the Hibernia reservoir gas cap is very rich in natural gas liquids. It is therefore important that the reservoir pressure in these areas be maintained above the dew point pressure so that these liquids can be recovered. To ensure this is possible, the pressure in the gas cap regions of the reservoir, specifically the Hibernia ‘B5’ and ‘B6’ pools, should be maintained at or above 1000 kPa above the dew point pressure.

The Board concurs with the Proponent’s proposal to water flood the Avalon reservoir. However, it notes that the well locations shown in Figure 8 could change significantly based on the results of the appraisal program. For this reason only the location of the wells to be drilled during the appraisal period will be approved at this time, since the revised development plan to be submitted at the end of that period will likely change the well locations.

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 proposed 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.

3.3.4.3
Production Forecast

In the Amendment, the Proponent presents an oil, gas and water production forecast for the field (Figure 9) that shows plateau oil production averaging 21 620 STm3/d for six years compared to plateau production of 17 500 STm3/d for nine years presented in the 1985 Development Plan. In addition to oil production, natural gas liquids recovery from the associated gas is forecast to average about 376 STm3/d during the plateau period. The assumptions used to construct the forecast were provided. Based on 1994 estimates of capital and operating expenditures, the Proponent states that an economic limit will be reached when the overall production rate declines to about 5000 STm3/d. This is expected to occur some seventeen years after production begins, i.e., at the end of 2014 AD.

The Board believes that the forecast presented by the Proponent is representative of the production that may be expected from selective development of the Hibernia and Avalon reservoirs. However, the forecast includes only the Hibernia ‘B’ pools and a reduced area of the Avalon ‘B’ pools. Development of potential reserves from the Hibernia ‘A’ pools, Catalina and Jeanne d’Arc reservoirs and development of an expanded area in the Avalon reservoir will change the production profile. The Board also believes that the economic limit of 5000 STm3/d may be conservative. Further efficiencies could reduce the economic limit and the additional reserves available from other reservoir units may significantly extend the life of the field.

The Board acknowledges the natural gas liquids forecast provided by the Proponent. These liquids are a valuable resource and every effort must be made to maximize their recovery. The estimate provided for the natural gas liquids produced from processing the gas stream is based on a process simulation study and will need to be updated once production experience has been acquired.

While the Board accepts the forecasts for oil and natural gas liquids production presented by the Proponent and notes the difficulties inherent in attempting to predict production rates at this time, it is important for the Board to have as accurate a prediction as is possible of the volumes of oil, gas and NGL’s which the Proponent anticipates will be recovered from the field in order to discharge its duties regarding resource conservation. Many areas of uncertainty in the present forecasts will be resolved by the data which will become available early in the life of the field. This will enable more accurate estimates to be developed.

Condition 97.01.3
It is a condition of approval of the Hibernia Development Plan 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.

3.3.4.4
Reserves

The Proponent presented its estimates of reserves and recovery efficiencies for the Hibernia and Avalon ‘B’ pools. These are shown in Table 4. The Proponent states that historically, capital and operating expenditures reviews have established that an economic limit for fields with similar profiles is reached after roughly seventeen years of production.

Table 4
Oil Reserve Estimates and Recovery Factors
Hibernia and Avalon ‘B’ Pools
Reserves 106STm3 (Recovery Factor %)
Reservoir Pool
(Region)
Simulated
OOIP
106STm3
Recovery
After 17 yrs
106STm3
Recovery
After 20 yrs
106STm3
Recovery
After 25 yrs
106STm3
Recovery
After 30 yrs
HiberniaB118.94.2(22)4.9(26)5.8(31)6.4(34)
B246.920.9(45)21.2(45)21.5(46)21.6(46)
B315.15.2(34)5.4(36)5.7(38)5.9(39)
B458.826.8(46)27.9(48)29.0(49)29.7(51)
B570.420.5(29)21.6(31)23.8(34)25.5(36)
B69.93.9(39)3.9(39)3.9(39)3.9(39)
Subtotal219.081.5(37)85.0(39)89.8(41)93(42)
AvalonB2 (C,N)88.87.0(8)8.0(9)9.4(11)10.5(12)
B3 (H,J,K)13.00.0(0)0.0(0)0.0(0)0.0(0)
B3 (I)14.61.1(8)1.3(9)1.5(10)1.6(11)
B3 (E)54.05.9(11)7.2(13)9.4(17)11.1(21)
B4 (B)20.60.0(0)0.1(0)0.7(3)1.1(5)
Subtotal191.014.0(7)16.5(9)20.9(11)24.3(13)
Total410.095.5(23)101.5(25)110.7(27)117.3(29)

The Board has reviewed the basis for the Proponent’s current reserve estimates and recovery factors and those provided in the 1990 Development Plan Update. These are summarized in Table 5.

The estimates provided by the Proponent are based on full development of the Hibernia reservoir but only partial development of the Avalon reservoir. The recovery factor and reserves estimates for the “most likely” case are higher than those previously presented for both the Hibernia reservoir and the proposed area of development in the Avalon reservoir.

Table 5
Recoverable Reserves and Recovery Factors – Hibernia and Avalon Reservoirs
Reserves 106STm3 (Recovery Factor %)
CategorySourceHibernia ReservoirProposed Area of Avalon DevelopmentHibernia Reservoir Plus Proposed Area of Avalon Development
DownsideProponent46(26)6(8)52
1990 DP46(26)6(8)52
LikelyProponent83(38)15(8)98
1990 DP71(33)12(11)83
UpsideProponent97432120118
1990 DP97432120118

Information presented by the Proponent in support of the production forecast suggests it is reasonable to expect an economic life for the Hibernia field of about 25 years, corresponding to a reserve estimate of approximately 111 106m3. While higher reserves estimates have been presented by the Proponent for the Avalon reservoir, the recovery factors appear to be conservative. The Board believes it should be possible to achieve recovery factors equivalent to those presented in the 1990 Development Plan Update and may approach those estimated by the former Newfoundland and Labrador Petroleum Directorate (NLPD) and reported in Decision 86.01. The Board also notes that the reserve estimates presented by the Proponent are for the proposed Avalon appraisal area only. Potential development of the northwest and southwest areas of the Avalon reservoir could add significantly to the reserves estimates. The NLPD estimated the upside reserve potential for the Hibernia and Avalon reservoirs to be 181 106m3 and 143 106m3, respectively.

The Board notes that the Proponent has estimated that about 1.76 106m3 of natural gas liquids can be extracted from the gas stream. These are not accounted for in its reserve estimates. According to a report prepared by the NLPD, the potential natural gas liquids reserves for the Hibernia field were estimated to range from 13 106m3 to 24 106m3. These are in addition to the oil reserves. The Board believes this estimate is reasonable.

Potential development of the Catalina and Jeanne d’Arc reservoirs could also provide additional reserves. The Proponent’s original oil-in-place estimate for the Catalina reservoir has increased from 2.0 106m3 in the 1990 Development Plan Update to 22.0 106 m3. This revised estimate is slightly higher than the NLPD oil-in-place estimate of 18.6 106m3 reported in Decision Report 86.01. No reserve estimates were presented by the Proponent for the Catalina reservoir but the NLPD estimated these reserves to range from 0.87 106m3 to 8.23 106m3. The Jeanne d’Arc reservoir is very small with oil-in-place estimated to be 0.08 106m3 and 0.40 106m3 by the Proponent and NLPD respectively.

The Board believes the Proponent’s reserve estimates for the field are very conservative and do not reflect the upside reserve potential of the field. In order to establish a context within which to consider the Proponent’s proposals for long-term development of the field, it is important that the Board have the Proponent’s assessment of the range of reserves that may be recovered from the entire field.

The Board recognizes there are uncertainties associated with estimating potential reserves. However, many of these should be resolved early in the production phase when additional information will be acquired regarding the Avalon and Catalina reservoirs during the drilling of development wells into the Hibernia reservoir. Production testing will provide further information on the characteristics of the reservoirs and the potential for natural gas liquids recovery. In addition, account must be taken of potential reserves in the southwest extension of the Avalon reservoir and in the Catalina reservoir. The Board believes the Proponent will be in a position to produce a good estimate of the potential reserves of the field after it has the benefit of the data from a period of production experience.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-offs used to generate the estimates.

3.3.5
Well Construction and Operations

The Board believes the expected production and injection rates projected by the Proponent, for both high and average rate Hibernia reservoir wells and for the Avalon wells, are reasonable for the purposes of well design. The proposed drilling schedule is stated to have been designed to resolve uncertainty and respond to new information as it becomes available, while trying to maintain production at a reasonable level.

The Board concurs in general with the Proponent’s proposed well drilling schedule and the approach to well design and operations, noting that details of the well construction program will require its approval pursuant to the relevant regulations. The Proponent has recognized that an opportunity exists to deplete a portion of the Avalon reservoir, not currently proposed to be developed, by recompleting selected Hibernia reservoir wells.

The Proponent is also proposing revisions to the well completion design and practices set out in the 1985 Development Plan. These include the use of monobore completions, commingled production from Zones 1 and 2 of the Hibernia reservoir and higher production rates, particularly for the early Hibernia wells. The Board concurs with the proposed monobore completions proposed for the Hibernia reservoir. This technology represents a significant advance in completion technology since the 1985 Development Plan was submitted and will reduce production costs and assist in increasing the volume of oil that can be recovered.

The Board also believes that oil recovery can be increased by controlling the production profile of individual wells. The 5% incremental recovery indicated in the Proponent’s reservoir studies appears reasonable. However, the Board notes that profile control is not planned for the early Hibernia reservoir wells and that it is planned to produce these wells at rates much higher rates than the average Hibernia wells. While the Board is satisfied that operating these wells for a limited time under such conditions, as proposed by the Proponent, will not be detrimental to recovery, the well performance must be closely monitored through production and cased hole logging to observe the production profile and fluid saturations in these wells.

Regarding the Avalon reservoir, the Board concurs with the Proponent’s proposed approach to completion design and practice. By the end of the appraisal period, the Board feels the Proponent will have the information necessary to optimize its completion design and practices for this reservoir.

The Board concurs with the Proponent’s proposed Hibernia well operations philosophy, the proactive approach to identify potential problems with wax deposition and sand production and the measures proposed to mitigate or address these problems.

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 recompleting 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.

3.3.6
Production Operations and Maintenance

The Board believes that the expected well production rates for initial production wells and the forecast maximum well capacity for injection wells are achievable for selected wells. Current information indicates that only wells in the Hibernia water flood area may be produced at the high rates proposed without adversely affecting ultimate recovery. The Board notes the Proponent plans to “debottleneck” the production facilities to increase oil production capacity. While this action would be typical of experience in other fields internationally, the details of such changes and any increase in the production rate from the field beyond that already approved will need further approval by the Board.

The Board reviewed the need for additional filtration of sea water to be injected into the reservoirs based on the information presently available and agrees with the Proponent that thermal fracturing is likely to occur in the completed formations surrounding the injection wells, thereby mitigating the need for fine filtration. The studies and evaluation program proposed to be undertaken by the Proponent should identify whether fine filtration sea water is required in the future. The Board notes provision has been made in the design of the platform for future installation of equipment for this purpose if it necessary.

In Decision Report 86.01, Condition 7 (ii) required that “before finalizing the design of facilities the Proponent submit for the Board’s approval a plan for reinjection of produced water in the event that effects monitoring program should disclose unacceptable environmental damage resulting from that source”. The Board acknowledges that provision for the future installation of produced water injection facilities has been incorporated into the design of the Hibernia topsides.

4.0
Conclusion

4.1
Hibernia Development Plan Amendment
Decision 97.01

The Board approves the proposed Amendment subject to the conditions set out below and the conditions contained in its Decision Reports 86.01 and 90.01, the status of which are summarized in Sections 4.2, 4.3 and 4.4.

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-offs used to generate the estimates.

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 recompleting 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.

4.2
Hibernia Development Plan Update
Decision 90.01

The Board has reviewed the status of the four Conditions attached to its 1990 approval of the Hibernia Development Plan Update. The present status of these conditions is summarized below:

Condition 90.01.1

It is a condition of the Board’s approval of the Hibernia Development Plan Update that:

  1. Upon the appointment of the engineering contractor for the project, the Proponent provide for the information of the Board and the Certifying Authority a copy of its updated consequence analysis document;
  2. Upon its completion, the Proponent provide for the information of the Board and the Certifying Authority the report issuing from its formal Hazard and Operability Study; and
  3. Six months prior to the date scheduled for the installation of the production platform at Hibernia, the Proponent submit, for the Board’s approval, the Safety plan required by the draft Production and Conservation Regulations.

Status:

Condition 1 (i) Satisfied.
The proponent’s Concept Safety Evaluation (CSE) Report was submitted to the Board and to the Certifying Authority, Lloyd’s Register, during the fourth quarter of 1991.Condition 1 (ii) Satisfied.
An overview of the results of the Hazard and Operability study was submitted to the Board in October 1993. The Proponent provided the Board with access to the detail study results at its offices. In September 1994, the Board reviewed these results, satisfied itself that they had been provided to the Certifying Authority, and informed the Proponent, in November 1994, that it considered the Condition to have been satisfied.

Condition 1 (iii) Satisfied.
The safety plan is included within the Proponent’s Operational Plan which is currently under review by the Board.

Condition 90.01.2

It is a condition of the Board’s approval of the Hibernia Development Plan Update that prior to the final selection of the offshore loading facilities, the Proponent seek the Board’s approval for the specific system it proposes to install.

Status:

Satisfied.
During 1994, the Proponent provided the Board with information concerning the specific offshore loading system it plans to install. The Board reviewed the information, and gave its approval in July 1994.

Condition 90.01.3

It is a condition of the approval of the Hibernia Development Plan Update that:

  1. the Proponent provide a functional specification of the marine support vessels for the Board’s approval before finalizing their design
  2. an assessment of the proposed ice-strengthening criteria for these vessels be performed by an independent third party acceptable to the Board.

Status:

Satisfied.
In late 1992, a third party study assessment of the ice strengthening criteria was conducted for the Proponent by German and Milne, a consultant approved by the Board. The consultant made a number of recommendations concerning ice strengthening, all of which were incorporated into the functional specification for the support vessels. Functional specifications for the marine support vessels were submitted to the Board and conditionally approved the functional specification in August, 1994.

Condition 90.01.4

It is a condition of the Board’s approval of the Hibernia Development Plan Update that 6 months prior to the tow-out of the production platform to the Hibernia field, the Proponent provide the Board with the evidence of financial responsibility required by the draft Production and Conservation Regulations.

Status:

Continued.
In May 1993 the Board outlined to the Proponent financial responsibility requirements it would have to meet at each major milestone in the project. These requirements have been met to date and consultations between the Proponent and the Board regarding these matters are continuing as the project progresses.

4.3
Hibernia Benefits Plan
Decision 86.01 Status

The Board has reviewed the status of the five conditions attached to its 1986 approval of the Hibernia Benefits Plan. The present status of those conditions is summarized below:

Condition #1

That the Proponent consider all reasonable alternatives to provide for maximum Canadian participation in shuttle tanker construction, and inform the Board of the results of these investigations.

Status:

Satisfied.

Condition #2

That, prior to the start of production, the Proponent submit a training and staffing plan reflecting the maximum reasonable employment and training of residents of Newfoundland.

Status:

Satisfied.
A plan was submitted in June 1996 and approved by the Board in March, 1997 after additional information was provided by the Proponent.

Condition #3

That the Proponent re-examine the feasibility of assembling and outfitting the main support frame in Newfoundland and provide further documentation to enable the Board to evaluate the matter.

Status:

Rescinded.
Condition no longer applicable because of elimination of main support frame from design concept.

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.

4.4
Hibernia Development Plan
Decision 86.01 Status

The Board has reviewed the status of the seventeen condition attached to its 1986 approval of the Hibernia Development Plan. The present status of those conditions is summarized below:

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:

Continued.
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 feasibility study.

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 #4

That the Proponent conduct a study on the estimation of extreme winds caused by mesoscale events and submit the results of the study to the Board prior to using them for design purposes.

Status:

Satisfied.
In 1988, the Proponent indicated that quantitative estimation of mesoscale effects was not feasible, and proposed a conservative methodology for estimation of design wind speeds averaged over short periods. The Board consulted the Atmospheric Environmental Service and concluded that the proposed methodology was reasonable. See Decision 90.01 Section 4.3.7.3).

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:

Continued.
The Proponent has designed its facilities that export lines will be capable of being flushed. The Board noted in its Decision 90.01 that the potential for flushing risers to tankers appears to exist, and reiterated this Condition. Procedures for flushing the loading risers have not yet been submitted for the Board’s approval.

Condition #6

That the Proponent re-evaluate the seismic design criteria, taking into account the recent and ongoing studies related to seismic risk on the eastern Canadian Continental Shelf, and submit the results of this re-evaluation to the Board for approval prior to using the results of the study for design purposes.

Status:

Satisfied.

Condition #7

  1. That produced water which is to be discharged be treated to comply with the regulatory requirements existing at the time; and
  2. that before finalizing the design of facilities the Proponent submit for the Board’s approval a plan for the re-injection of produced water in the event that the effects monitoring program should disclose unacceptable environmental damage resulting from that source.

Status:

Satisfied.
Hydrocyclone equipment capable of meeting regulatory discharge limits for produced water will be installed. Also, engineering design provisions and platform space allocation have been made for re-injection facilities if required. In July 1993, the Board approved the proposed arrangements.

Condition #8

  1. That the Proponent allow in its design for the facilities to treat storage displacement water should treatment become necessary; and
  2. that the Proponent design its facilities so that fluid discharges will occur below the summer thermocline.

Status:

Condition 8(i) Satisfied.
Provision was made in the platform design for treatment equipment for this purpose if such is required. The Board approved the Proponent’s arrangements in May, 1993

Condition 8(ii) Satisfied.
The Proponent submitted to the Board evidence that the production platform’s fluid discharge outlets were located below the summer theromocline. The Board approved the Proponent’s arrangements in March, 1995.

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 #10

That the Proponent design all subsea facilities such that, upon termination of production, they will be capable of being covered or removed so that the area is returned to a fishable condition, and design the GBS so that it could be removed if the Authorities at that time so require.

Status:

Satisfied.
The Proponent conducted a number of studies to develop a procedure for the removal of the GBS. The project certifying authority has reviewed and accepted the procedure. The Proponent also submitted information acceptable to the Board regarding the removal of subsea crude loading facilities.

Condition #11

That oil-contaminated cuttings be discharged below the summer thermocline.

Status:

Satisfied.
The Proponent submitted evidence that it has placed the production platform’s shale chutes at a depth below that of the summer thermocline. The Board approved the Proponent’s arrangements in March, 1995.

Condition #12

That prior to production, the Proponent submit, for the Board’s approval, its plans for environmental compliance and effects monitoring programs.

Status:

Satisfied.
The Proponent submitted the design for its production phase Environmental Effects Monitoring EEM program in November 1995 and received Board approval in May 1996.

The Environmental Compliance Monitoring Plan, which incorporates detailed sampling and analytical procedures, was approved by the Board in March 1997.

Condition #13

That the Proponent provide instrumentation for structural and foundation integrity monitoring and the extent of such instrumentation be determined in consultation with the Certifying Authority and approved by the Board.

Status:

Satisfied.
Details of the integrity monitoring system have been finalized by the Proponent, reviewed and accepted by the Project Certifying Authority and were approved by the Board in August, 1996.

Condition #14

That prior to the installation of the facilities, the Proponent obtain the Board’s approval of detailed plans for worker safety.

Status:

Amended
See Condition 90.01.1.

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.

Condition #16

That prior to production, the Board will establish the dimensions of a fishing exclusion zone following consultation with the Department of Fisheries and Oceans, the fishing industry and the Proponent.

Status:

Satisfied.
The Newfoundland Offshore Area Petroleum Production and Conservation Regulations prescribe the size of the exclusion zones, or ‘safety zones’, surrounding offshore production installations as the greater of 500 metres from the perimeter of an installation, including its associated subsea facilities and loading system, or 50 meters from the perimeter of its anchor pattern.

HMDC has proposed a marginally larger safety zone in order to provide an additional 500-metre buffer surrounding the area which would be occupied by a shuttle tanker while connected to either of the two offshore loading systems. The total area of the proposed zone is approximately 6 square kilometres compared to the 104 square kilometres proposed in 1986. The Board considers the present proposal to be reasonable and expects a zone of this size to be promulgated pursuant to the Canada Shipping Act later this year.

HMDC has established a Fisheries Liaison Advisory Group, with membership drawn from fisheries interests active on the Grand Banks, as a forum for consultation on these and other matters. The Board participates in the Group.

Condition #17

That the Proponent, prior to production, submit to the Board for approval, an Environmental Protection Plan describing its systems, procedures, plans and agreements for environmental protection.

Status:

Continued.
The proponent has included the Environmental Protection Plan (EPP) in its Hibernia Operational Plan (HOP) which was submitted to the Board on November 29, 1996. The Board is reviewing the HOP and its supporting documentation in consultation with its advisory departments. The portions of the EPP which deal with Environmental Effects and Compliance Monitoring have already received approval (see Condition 12).

Appendix BGlossary
AquiferA porous rock that is water bearing.
Board, theIn this report, the Canada-Newfoundland Offshore Petroleum Board.
Bubble point pressureThe reservoir pressure below which dissolved gas begins to bubble out of the host oil at the prevailing temperature conditions.
Commingled productionProduction of petroleum from more than one pool through a common wellbore or flow line without separate measurement of petroleum.
Certifying AuthoritiesBodies licensed by the Board to conduct examination of designs, plans and facilities and to issue Certificates of Fitness.
Certificate of FitnessA certificate issued by a certifying authority stating that a design, plan or facility complies with the relevant regulations or requirements.
CompletionThe activities necessary to prepare a well for the production of oil and gas or injection of a fluid.
Delineation wellWell drilled to determine the extent of a reservoir.
Development wellWell drilled for the purpose of production or observation or for the injection or disposal of fluid into or from a petroleum accumulation.
Dew point pressureThe reservoir pressure below which liquids begin to condense out of a gas at the prevailing temperature conditions.
Enriched gas injectionA secondary recovery method for injecting gas which is either naturally rich in or is enriched with intermediate hydrocarbons such as propane, butane.
FaultIn the geological sense, a break in the continuity of rock types.
FlareTo burn off gases not otherwise required.
FloodingThe injection of water or gas into or adjacent to, a productive formation or reservoir to increase oil recovery.
Gas capThe layer of free gas above the oil zone of a reservoir.
Gas re-injectionProcess where gas is re-cycled by being returned under pressure to a producing formation in order to maintain reservoir pressure.
GBSGravity Base Structure. The concrete production structure fixed to the sea floor by its own weight and which supports the topsides facilities.
InjectionThe process of pumping gas or water into an oil-producing reservoir to provide a driving mechanism for increased oil production.
LoggingA systematic recording of data from the driller’s log, mud log, electrical well log, or radioactivity log.
Miscible floodA secondary or tertiary oil recovery method wherein two or more injection fluids are used, one behind the other, for example, gas and water, to mix with the oil and improve oil recovery characteristics.
NGLNatural Gas Liquid.
OOIPOriginal oil in place.
PetrophysicsStudy of reservoir properties from various logging methods.
PoolIs a natural underground reservoir containing or appearing to contain an accumulation of petroleum that is separated or appears to be separated from any such other accumulation
Produced waterWater associated with oil and gas reservoirs that is produced along with the oil and gas.
Production platformAn offshore structure equipped to produce and process oil and gas.
Production wellA well drilled and completed for the purpose of producing crude oil or natural gas.
Recoverable reservesThat part of the hydrocarbon volumes in a reservoir that can be economically produced.
ReservoirA porous, permeable rock formation in which hydrocarbons have accumulated.
Reservoir pressureThe pressure of fluids in a reservoir.
SandstoneA compacted sedimentary rock composed of detrital grains of sand size.
SeismicPertaining to or characteristic of earth vibration. Also, process whereby information regarding subsurface geological structures may be deduced from sound signals transmitted through the earth.

1The Board and the Proponent have agreed to refer to the reservoirs in the Ben Nevis, Upper Avalon, Lower Avalon, Eastern Shoals and Whiterose formations collectively as the “Avalon” reservoir.