PEH:Reservoir Management Programs

Publication Information

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume V – Reservoir Engineering and Petrophysics

Edward D. Holstein, Editor

Copyright 2007, Society of Petroleum Engineers

Chapter 20 – Reservoir Management Programs

E.D. Holstein, Consultant and E.G. Woods, Consultant

Pgs. 1599-1622

ISBN 978-1-55563-120-8
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Reservoir management has been in place in most producing organizations for several years. Several authors have described how reservoir management is structured; however, the type, quality, and consistency of programs vary. This chapter defines reservoir management and suggests how to maintain an effective, ongoing program that can be sustained and continually updated to represent the changing needs of an organization or resource.

Reservoir management consists of processes that require the interaction of technical, operating, and management groups for success. The complexity of the problem and size of the asset dictate the type and number of personnel assigned to the task. Commitments can vary from part-time assignments for technical and operating staff members to the full-time use of multifunctional and, in some instances, multiorganizational teams. Personnel changes, altered priorities, insufficient surveillance data, and lack of documentation, however, can reduce the effectiveness of reservoir management programs.

Methods for assessing the effectiveness of reservoir management programs, including identifying strengths and areas for improvement, are needed to approach the topic from a quality perspective (i.e., benchmark to an ideal, best-practice standard). Making these assessments on a systematic, regular basis can be effective in developing a common terminology that improves communication and in ensuring a comprehensive review and a more complete listing of improvement opportunities. Reservoir management assessments are also effective in providing a comparison with ideal or best practices that result in a more innovative environment and in establishing a method of documentation and measurement to determine how well reservoir management is being sustained despite changes in personnel and priorities. This chapter includes a method for assessing the quality of a reservoir management program.

Reservoir Management Processes

Fig. 20.1 illustrates reservoir management processes. The processes are divided into those stewarded by the reservoir management team (RMT) and those guided by the supervisors and managers associated with reservoir management who comprise the reservoir management leadership team (RMLT). The arrows in the RMT box show work flow and how data and opportunities are captured.

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  Fig. 20.1 – Reservoir management processes.

Reservoir Management Team

The RMT members are the technical and operating personnel who perform reservoir management tasks. Fig. 20.2 shows the skills represented by the team members. The RMT is a multifunctional team, and organizational structure should not be inferred from this illustration. A team with all the skills shown could be a permanent part of an organization; however, it is more likely that the team would meet on a regular basis with individual members being assembled as needed from groups within an organization. In-house skills may need to be supplemented with outside personnel. The objective of the team is to bring together the skills needed to describe the reservoir, prepare depletion plans (including economic justification of projects), drill the wells, design and maintain wellbores, design and maintain production equipment, and conduct the day-to-day operations of producing the field according to the depletion plan. The team also meets to provide the information needed to upgrade and improve the depletion plan. A major focus of the team is to obtain reliable data on a timely basis to analyze production performance.

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  Fig. 20.2 – Reservoir management team skills.

Data Management. This process represents the organizing of raw and interpreted data into a readily accessible form. It is not intended to imply what type or quantity of data is needed. Those issues are addressed in other processes.

Data Captured. This information includes raw data such as seismic records, well logs, conventional and special core analyses, fluid analyses, static pressures, pressure-transient tests, flowing pressures, periodic well production tests, and monthly produced volumes of oil, gas, and water. Interpreted data could include seismic time maps, seismic conversion of time-to-depth maps, seismic attribute maps, log analyses, formation tops, structure and isopach maps, cross sections, geologic models, and simulation models.

How much information and how to capture this information varies with the size of the database, size of the resource, and the remaining life of the resource. Hand-kept records and hard copies of information may be adequate for small resources. However, digital databases should be considered for all resources for the systematic acquisition of data, the growing usability of software for data interpretation, and the value of having data available to individuals in a distributed network.

Quality Assurance. Processes for the timely capture and quality maintenance of data also should be established. Personnel may be required for this specific purpose. While this assignment may be a drain on limited manpower, the benefits of readily available, high-quality data will save time spent in reorganizing, checking, and reinterpreting data each time a study is conducted. The time savings more than returns the cost of quality data capture. Studies of work output indicate that as much as 50% of the time spent on a project can be consumed by finding and organizing data that is not maintained in a readily accessible, high-quality format.

Reservoir Description. This process is the development of an up-to-date, detailed description of the reservoir that incorporates available data and technology into a fieldwide interpretation consistent with observed historical reservoir performance. Variations and risks in the description should be included. Again, the effort that goes into this description depends on the size of the remaining resource.

Geophysical, geological, and engineering interpretations are expected to produce information on the distribution of hydrocarbons in place and reserves. These interpretations include field and regional structure maps, including fluid-contact locations and the size of aquifers; isopach and porosity maps; the number of flow units or individual producing zones; the depositional environment including information on diagenetic changes and vertical and areal barriers to flow (or lack thereof); and variations in fluid saturations and permeabilities. The expected variability in these values should be included in these assessments. Descriptions from hand-drawn maps and correlations may suffice for small resources; however, in most cases, a geologic model is developed to capture these interpretations, with more complex models being needed for larger resources. The power of PCs and their software makes it more attractive to develop geologic models for all resources. (See the chapters on reservoir petroleum geology, geophysics fundamentals and outputs, and petrophysics in this section of the Handbook for information on geophysical, geological, and petrophysical interpretations and how they are used to develop a reservoir description. See the chapters on reservoir geophysics and geostatistics in the Emerging and Peripheral Technologies section of this Handbook for information on emerging technologies that can improve reservoir description.)

Original In-Place Volumes. Initially, the geologic model is used to estimate the amount and distribution of original in-place hydrocarbon volumes. These estimates include the range of uncertainties in rock properties, fluid saturations, and geologic interpretations and the resulting range in estimated in-place volumes.

Fluid-Flow Characteristics. The mapping of depositional environments, flow barriers, and flow test and core data aid in understanding the productivity and recovery trends in the reservoirs. This understanding is important in optimizing well placement and spacing and in recovery process selection.

Updating. Periodic collaboration between geoscientists and engineers is needed to include new seismic data and interpretations, well data, and performance characteristics into the geologic model. This work produces a better description of reservoir contents, reduces uncertainty, and establishes a basis for improved future development and reservoir operations.

Depletion Plan Development and Updating. Depletion plans define how to use primary drive mechanisms to deplete hydrocarbon resources and how, when, or if these mechanisms should be supplemented for additional recovery. The plan includes projected ultimate recoveries; producing rates of oil, gas, and water; and changes in reservoir pressure. As information is gained from field performance, the depletion plan is updated periodically to include any changes needed to better reflect how to optimize the depletion strategy. Specific parts of the plan include drilling schedules, well placement, individual well and total field offtake rates, total and well injection volumes, and wellbore utilization plans.

Determining the Primary Drive Mechanism. Determining the primary producing mechanism is the first step in selecting a depletion strategy. The chapters on oil reservoir primary drive mechanisms and gas reservoirs in this section of the Handbook describe primary drive mechanisms for oil and gas reservoirs, recovery potential, and methods to determine drive mechanism. This information can be used to project oil-, gas-, and water-producing rates, reservoir pressure trends, and ultimate recovery.

The drilling and completion schedule and the number and placement of wells are a function of several factors:

• The total field offtake rate and individual well rates that can be sustained without ultimate loss of recovery.
• The number of wells and rates that are practical considering constraints such as the number of well slots on a drill pad or an offshore platform; the installed facility capacity; individual well capacities with the tubulars, completion techniques, and artificial lift used; and any regulatory limits on spacing and/or producing rates.
• The location of the wells for efficient drainage, that is, spaced evenly to contact all portions of the reservoir or targeted to specific areas because of reservoir geometry, quality variations, or invading water or gas. The amount of the reservoir that can be contacted is affected by limits on lateral drilling reach from existing platform or drill pads.

Infill drilling also should be considered at some point to sustain rates or contact portions of the reservoir inadequately drained with existing completions. The chapter on water injection in this section of the Handbook describes the benefits of infill drilling.

Horizontal/Multilateral Wells. Horizontal and multilateral wells increasingly are being used to contact more of the reservoir, to achieve higher rates with fewer wells, and to minimize coning of gas and/or water. Continuing technologic improvements are making horizontal wells an increasingly more cost-effective way to develop certain portions of a reservoir. The chapter on fluid flow through permeable media in this section of the Handbook covers performance characteristics of horizontal wells. It is now possible to simulate this performance with relatively simple models to determine the benefits of planning such wells for depletion of a reservoir. Horizontal wells are particularly effective in producing zones that have good vertical permeability, well-managed contact movements, and large drainage areas. These wells also have been effective in fractured formations in which the horizontal well intersects more fractures than a vertical wellbore and, therefore, drains a greater volume of the reservoir. Horizontal wells are not as well suited to zones with low vertical permeability, rapidly moving contacts, and small remaining volumes to be drained. Where vertical permeability is low, high-angle wells may be more appropriate to contact the vertical interval and still provide a large drainage area.

The Need for Improved Recovery Projects. Improved recovery mechanisms refer to the injection of fluid (i.e., water, water with additives, hydrocarbon gas, nonhydrocarbon gas, steam, or air for in-situ combustion) to augment or replace the primary drive mechanism. Table 20.1 presents screening criteria for selecting improved recovery processes.

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  Table 20.1

The chapters on water injection; immiscible gas injection; foam, polymer, and resin injection; miscible processes; steam; and in-situ combustion in this section of the Handbook describe the characteristics and potential for several injection schemes in oil reservoirs. The chapter on gas reservoirs in this section of the Handbook explains the benefits of injection into gas caps and gas reservoirs. Historically, a field development progressed from primary production to fluid injection, such as water or immiscible gas, and then, in some instances, a second type of fluid injection, such as a miscible injection project, was needed. It is now important to determine the need for injection projects as early as possible to minimize depletion times, provide space for necessary equipment, avoid retrofitting facilities, and avoid other costly intermediate steps.

Wellbore Utilization Plan. This plan identifies the intermediate and final drainage points in each zone and outlines how each well will be used to deplete each producing zone and reservoir in a field. The plan includes guidelines on when to rework completions to sustain production by avoiding unwanted, excessive gas or water volumes. Where multiple producing zones exist, the plan should describe the zones to be completed in each well and provide guidelines on when to recomplete and the sequence of those recompletions to provide efficient recovery in each zone and minimize overall depletion time of the total resource.

Data Acquisition. The depletion plan should include the type of data to be acquired during the development stages of the reservoir and during the early, middle, and final production phases. Such data plans should include the type and number of open- and cased-hole logs; number, location, and frequency of static and transit pressure tests; number and location of fluid samples; number and location of cores and analyses to be made; type, location, and frequency of production logs; frequency of individual well tests; and capture of monthly produced volumes of oil, gas, and water and monthly injected volumes. The chapters on petrophysics, production logs, single well chemical tracer testing, interwell tracer tests, and measurement of reservoir pressure in this section of the Handbook contain more information on these data.

Reservoir Models. Most depletion plans are based on some type of reservoir model.

Model Types. Reservoir models are basic tools for addressing reservoir management questions and issues. In selecting a model, it is normally desirable to select the simplest model that will give reliable results (i.e., selecting a model that will adequately discriminate among alternatives and lead to an optimal decision, although absolute results may not be precise). Several types of models of varying complexity are available that may be adequate for different uses. These models include analog, decline curve, analytical (material-balance, Darcy-law, Buckley-Leverett, pressure-transient), small numerical (well, cross-sectional, pattern-element, 3D-segment), and large-scale, full-field models. See the chapter on reservoir simulation in this section of the Handbook for details on building reservoir simulation models. Other chapters in this section also contain guidelines for models specific to the subject of the chapter.

Reservoir Issues. The first step in model selection is to identify the questions to be answered and their relative importance. The following issues must be addressed during this step.

• Exploration prospect forecast of oil, gas, and water production.
• Annual forecasts of oil, gas, and water production.
• Monthly tanker scheduling and storage requirements.
• Pressure maintenance requirements.
• Evaluation of alternative recovery processes: gas-cap expansion; natural waterdrive; and water, gas, or other fluid injection.
• Operational guidelines for pressure levels, injection volumes and distribution, and individual well and field total production targets.
• Well performance predictions: coning, artificial lift requirements.
• Stimulation evaluation.
• Gas- and water-handling requirements.
• The need for and timing of reservoir depressuring.

Model Description. A second consideration in model selection is deciding which primary forces will dominate reservoir performance. It must be determined whether viscous, gravity, or capillary forces, as reflected in coning, gas overrun, water underrun, or pressure drop, will dominate reservoir and well performance.

Model Data. Most models require at least some data describing fluid properties and reservoir description and may require multiphase flow (relative permeability and capillary pressure) and well performance [coning correlations, gas/oil ratio (GOR), water/oil ratio (WOR)] functions. Based on experience, certain simplifying assumptions may be acceptable. For example, if the reservoir description is dominated by a fining or coarsening upward depositional sequence, this may be more important than capturing the areal variation in reservoir description.

Case Design. Careful thought should be given to identifying cases to be run with the model to avoid running all combinations of the variables being studied, a number that can run in the several thousands for even modest-sized resources. In some cases, this may involve starting with a simple model to test the importance of some variables. For example, before building a full-field model, it can be helpful to build well, cross-sectional, 3D-segment, or pattern-element models.

Small Models. Coarse-grid 2D or 3D simulation models are useful for making a distributed volumetric balance in cases in which reservoir fluid migration and/or significant pressure gradients are issues. 3D models are useful for doing a multizone volumetric balance in which there is fluid migration between zones through commingled wellbores, along fault planes, or across fault planes by sand-on-sand contact. Also, these models are useful for regional aquifer modeling in which aquifers are irregular in shape, heterogeneous, or subject to pressure interference between fields.

Large Models. Large simulation models with more than 100,000 gridblocks are now constructed for many medium and large fields. The models usually are based on a detailed geologic model that may contain one million or more gridblocks. Methodologies are now in place to convert these geologic models into a more manageable reservoir model while retaining a good representation of the variation in reservoir characteristics. See the chapter on reservoir simulation in this section of the Handbook for more information on building and running reservoir models.

Implement and Operate. These are the specific activities required to implement and sustain the depletion plan.

Implementation Plan. This plan is developed with input from several engineering disciplines. The drilling engineers design drilling schedules, wellbore trajectories, and casing and cementing programs to locate wells at the required location for the lowest effective cost. The subsurface engineers design tubulars, completion techniques, stimulation processes, and artificial lift equipment required for target well rates. They also design workover procedures as needed. The facilities engineers design equipment needed initially to handle produced and injected fluids and provide plans for upgrades and additions when required. For offshore locations, the platform design engineers provide adequate sizing to accommodate wells and facilities within budget and physical restraints. The reservoir engineers assist in optimizing the drilling schedule to conform to available facility capacity and injection requirements, in providing well rate forecasts to aid well design, and in providing multiple production scenarios to aid facility design.

There is interdependence between depletion and implementation plans. Iteration normally is required to find the optimum combination of reservoir depletion objectives, equipment and completion constraints, and economic guidelines that result in optimum field development. For example, favorable mobility-ratio waterdrive reservoirs tend to have low sensitivity to rate of recovery; therefore, there is an economic tradeoff between the facility capacity and the time that the reservoir operates at a facility-constrained capacity (plateau rate).

Operating Plan. This plan guides operations personnel in implementing and accomplishing the depletion plan and can be strengthened by making operations part of the reservoir management team. Also, by establishing lines of direct communication between technical and operations staffs, early recognition of problem areas with individual well or facility performance will result in expedited solutions.

Survey of Performance. A periodic and systematic review of field performance, once the field has been placed on production, should be practiced. The types of activity vary with the type and size of resource and stage of depletion. At a minimum, frequent (daily to weekly) review of trends in individual well producing or injection rates, gas/oil ratios or gas/liquid ratios, water cut, wellhead pressure, and artificial lift performance should be required. Assuming the planned data are being captured, controlled for quality, and stored in a database, such reviews can be augmented by software packages that process data quickly, analyze performance trends, and generate exception reports.

Reservoir Performance Reviews. Surveillance includes periodic comparison (every 1 to 5 years) of performance (rates, pressures, recovery levels, injection volumes, contact movements, etc.) with the projections contained in the depletion plan. Significant deviations should trigger an update to the depletion plan to reflect the new information, to identify additional data needs, and to outline additional work programs needed to improve recovery and sustain rates. Reservoir reviews primarily should be an in-house assessment; however, the inclusion of experts not directly involved in day-to-day surveillance should be considered to provide another view and an independent source of ideas.

Rank, Justify, and Fund Opportunities. Opportunities that can increase the economic value of the reservoir will be an outgrowth of the initial development plan, the development and updating of the depletion plan, and surveillance activities. Assessing the economic benefits of each opportunity and obtaining the necessary management approvals is the next step.

Opportunities may involve investments in new wells, processing equipment, and improved recovery projects or changes to reservoir depletion strategies. Such assessments include recognition and evaluation of risks and benefits for programs to acquire data, improve recovery, increase production rates, or reduce operating costs. Outputs are a range of outcomes for each opportunity reflecting the associated risks for that opportunity and any alternative solutions. The natural outcome of such assessment is an up-to-date ranked list of opportunities. Outputs are recommendations to fund projects and/or implement changes to the depletion plan. The final phase is to obtain management approval for project funding consistent with budget and personnel resource constraints.

Additional Needs for Advancing Ideas. In the analysis of some opportunities, additional data, studies, or technology may be required to reduce the risks to an acceptable level. Additional data acquisition might include additional seismic, delineation drilling, or fluid analyses. Studies could include reinterpretation of seismic data or an in-depth reservoir study including complex geologic and reservoir simulation models. Acquiring technology could be by purchase or through liaison with a research organization in which the needs of the project are considered in planning research activities.

Reservoir Management Leadership Team

This group includes supervisors and managers responsible for allocating resources and creating an environment conducive to effective reservoir management.

Human Resources. The first objective of the RMLT is to assess and provide the personnel needed for successful reservoir management. This task involves the following procedures.

• Assess. Determine skills required to develop and manage a reservoir, and then judge the current staff's proficiency and need for improving such skills.
• Develop. Providing the training and work experiences needed to improve skills. Training includes in-house schools and seminars plus programs offered by third parties. Mentoring should be considered. This also includes the development of local training programs to meet specific needs not being met cost-effectively by more general programs.
• Deploy. Allocating supervisory, operations, and technical staff members consistent with established priorities and skill requirements to maximize the value of a resource. The process should consider the long-term benefits of skill development.

Achieving a Quality Program. The RMLT should have methods in place for determining the quality of the reservoir management program and how it can be improved to meet expectations. The quality model should be flexible to fit the needs of an organization. The needs most likely will vary from resource to resource depending on size, maturity, and perceived chance for developing additional investment opportunities.

• Align. There should be a process in place to ensure that all persons involved in reservoir management understand its importance, their role, and the quality objectives.
• Measure. Some process for systematically measuring the quality of a reservoir management program needs to be developed. Such a process would identify components of the program and the relative importance of each. A method of measuring how well each component is being accomplished needs to include the strengths in the current program that should be retained and areas that need improvement.
• Improve. Plans for improvements that lead to higher quality programs would include procedural issues, organizational structure changes, and the identification of skill needs. Such plans would also include goals for implementing the improvements.
• Recognize. A vital part of the quality program is the continuing recognition of both individual and team accomplishments. Whatever form of recognition is invoked, it offers an opportunity to reward good work and to reinforce the fact that management is dedicated to a good reservoir management program.

Stewardship. This process involves the periodic review and discussion of reservoir management activities and accomplishments with management and between groups.

• Communicate. These activities would involve various RMT and RMLT members and appropriate management. The primary purpose of these reviews is to describe reservoir management organization, future work plans, and historical performance of resources and to obtain management feedback on their expectations and support for continued reservoir management activities.
• Share. A corollary activity is the sharing of experiences between teams to identify best practices and company-wide improvement needs.

Measuring Reservoir Management Performance

Two questionnaires have been designed to survey and measure the quality of reservoir management performance. One is for RMT activities, and the second is for RMLT activities. Tables 20.2 and 20.3 show suggested questions for the surveys. The questions are a guideline of what could be included in the surveys.

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  Table 20.2

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  Table 20.2

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  Table 20.3

The surveys are self-assessment tools for the RMT and RMLT groups. The strengths of the surveys are the systematic consideration of all reservoir management activities, improved communication and understanding of the multifunctional issues by the team, identification of strengths to be sustained and areas for improvement, and a method for measuring improvement with subsequent surveys.

Conducting a Survey

Participants. As dictated by the specific situation, operating, supervisory, and technical persons would be included in the assessment. In some instances, it may be desirable to have outside experts participate in the assessment to obtain different views on specific areas in which weaknesses are suspected.

Frequency. The size and importance of a resource affects the timing and frequency of surveys. Considering the effort and personnel required for an effective survey, annual or less frequent timing may be appropriate.

Questionnaire Format and Scoring. Fig. 20.3 shows the suggested format for capturing assessments as they are made. Only the section of RMT questions on database processes is included in this example. This form would be developed for each major process of the RMT and RMLT.

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  Fig. 20.3 - Suggested format for capturing assessments.

A performance rating for each question is to be judged on a four-point scale ranging from "seldom equals" to "essentially always equals" as compared with a best-practice standard that is determined by the group doing the assessment. Best-practice standards tend to be somewhat subjective, but experience has shown there is good agreement among knowledgeable persons participating in surveys. Best practice will depend on the field or fields involved. A prime asset that represents a significant resource with a long remaining life would be held to different standards than smaller resources or mature fields in an advanced stage of development.

The four-point scale should be adequate for differentiating the quality for various activities. Scales with five to ten increments were considered to be too fine and beyond the capability of this process, while fewer increments would not allow enough difference between poor and excellent.

Each participant rates each question, the scores are tabulated, and the team works to reach consensus on each question. While the scoring system could be viewed as a numerical result (1 to 4) to determine an overall outcome for each field or resource reviewed, the descriptions are intended to indicate qualitative results that are more appropriate for determining strengths that are to be retained, barriers preventing execution of the process, and areas that require improvement. Also, some questions would have more importance than others and should be weighed accordingly.

Evaluation and Use of the Score. The initial assessment of a resource establishes a baseline and highlights areas of good practices and activities needing improvement. Subsequent reviews will show if targeted improvements are being accomplished while maintaining strengths. Over time, reviews also indicate where changes in emphasis are appropriate considering the changing maturity and needs of a resource. Another use of the results is the exchange of results between different RMT and RMLT groups with a focus on how strengths were accomplished and what has been implemented to improve the process.

Examples of Reservoir Management Benefits

In the following discussion of field histories, the reader should be aware that the small well spacing in some fields would not be optimal considering current technology and economic conditions. Some well spacings were driven by factors such as shallow reservoirs with low well costs, multioperator competitive operations, regulatory depth-acreage-based well allowables, oil price controls with two-tier pricing systems, and all vertical wells.

Sandstone Reservoir With Combination Drive Supplemented With Gas and Water Injection

Background and Geographical Information. This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.

Program Used. The primary recovery mechanism was a combination of a strong, directional waterdrive in the eastern part of the field, solution-gas drive in the western part of the field, and gas-cap expansion. Initial screened openhole completions resulted in uneven water advance caused by permeability differences between zones. A workover program converted all wells to selective, single-zone completions that allowed better control of aquifer advance. The directional waterdrive resulted in gas-cap tilting to the west despite return of all produced gas to the gas cap and extraneous water production on the east side. Water injection around the downdip periphery of the western part of the field was used to waterflood the western area, equalize pressure between east and west areas, and prevent gas-cap tilting. Because of low dip, recovery by gas-cap expansion was a less efficient recovery mechanism.

When field oil production declined to 4,500 B/D with 98% water cut and an average GOR of 30 Mcf/bbl, gas sales were necessary to maintain acceptable profitability. When gas-cap depressuring was initiated, remaining oil production was thought to be coming from low permeability, thin intervals that would be affected minimally by accelerated water influx accompanying depressuring. Oil production is expected to continue well beyond the time the gas cap is depleted. Gas will be trapped behind advancing water, but reservoir-pressure decline will result in percolation of liberated dissolved gas from the residual oil in the water-invaded zone. This analysis came from a tank-type reservoir simulation model. To date, reservoir pressure has declined from 2,150 to 1,525 psi because the aquifer has been unable to offset the increased withdrawal rates.

Frac packing has provided sand control and near-wellbore stimulation. Conventional gravel packing also has been used when water proximity has been a concern. Plugback workovers and additional well conversions will be used to achieve maximum gas recovery. Original development was on 20-acre spacing. Selective infill drilling has been used to improve the sweep of injected water and to drain isolated parts of various zones.

Recovery Performance. The combined recovery factor for all the recovery mechanisms is 66% of OOIP. A contributing factor to this high recovery is a mixed wettability rock yielding waterdrive residual oil saturation of 12 to 13%, based on single-well chemical-tracer tests.

Field Surveillance and Management. There have been several major reservoir studies of the field during its history to determine and upgrade the depletion strategy. There also has been a sustained surveillance program to monitor reservoir performance. Surveillance has focused on maintaining liquid injection-production balance, monitoring area pressures, and the use of cased-hole logging to monitor gas/oil contacts (GOCs). Several segment and individual well simulation models have been used throughout the life of the field to better understand the waterfront movement, to adjust injection and offtake locations, and to mitigate bypassing of oil. Cased-hole logging programs (neutron or pulsed neutron) are now conducted at 3-month intervals to monitor the uneven water advance. Reservoir pressure is measured monthly. Pulsed-neutron logs are proving very valuable in locating bypassed oil in the shaley sand sections. Pressure maintenance by waterdrive and injection has permitted wells to produce by natural flow/artificial lift. This allowed cost-effective tubing logging and pressure surveillance.

Sandstone Reservoir With Strong Waterdrive and Crestal Gas Injection

Background and Geological Information. Production from this field is from several Upper Cretaceous sandstone formations. The producing zones are in pressure communication in the gas cap and aquifer but separate in the oil column. The structure is a complexly faulted anticline with a major fault separating the west and east flanks. There is minor communication across the fault. Gross thickness is 384 ft, and net-to-gross thickness is 0.7. Reservoir dip is 6° with somewhat higher dips upstructure. A tar layer exists at the original oil/water contact in the western flank of the field. The tar is 50 ft thick on the north flank and 100 ft thick on the south flank.

Porosity averages 27%, and zone permeability averages range from 1000 to 3000 md. The oil viscosity was 4 cp in the main oil column but grades higher near the tar and oil/water contact.

Program Used. The field was developed and produced competitively by several operators until unitization. The primary producing mechanism was a strong waterdrive that led to some gas-cap shrinkage despite an early gas return program. Performance analysis indicated a recovery efficiency of 65% by water displacement vs. 75% by gas displacement-gravity drainage. Formation of the unit allowed initiation of crestal gas injection. Water is being produced from down-structure wells to aid in moving the GOC downdip. Gas-cap pressure has been increased, water influx has been virtually eliminated, and the waterdrive recovery efficiency has been replaced with better gas-drive gravity-drainage efficiency.

A double displacement process (DDP) is under way to displace water-invaded portions of the original oil column with gas. The objective is to create a gravity-stable gas front that allows the ROS after waterdrive to be remobilized, drain to the base of each zone, and be captured in down-structure producing wells.

Down-structure oil production is from multiple zones. Wells are produced primarily from a single zone to maintain control of producing GOR and WOR. Recompletions to other sands are performed based on well performance, cased-hole logging results, and surveillance maps.

Recovery Performance. The recovery by waterdrive and gas injection is 63% OOIP. The DDP is expected to add another 6% of OOIP for a total of 69%.

Field Surveillance and Management. There have been several major reservoir studies of the field to determine and upgrade depletion strategies. The DDP was studied extensively with regional and detailed fault-block models before starting the field project. A recent sequence stratigraphy study located remaining oil and provided an improved basis for surveillance of the DDP. These studies have been used to guide infill drilling that has resulted in significant additional capture reserves. In addition, an aggressive well recompletion program has been essential in obtaining expected production and recovery performance.

A sustained surveillance program has been in place throughout the life of the field. Data on oil, gas, and water production are collected routinely each month, and annual cased-hole logging and pressure surveys are conducted. Fluid-contact mapping and material-balance models are used to monitor and balance gas-injection rates to offset fluid production and aquifer influx. The annual fieldwide cased-hole logging program to monitor fluid contacts is a very important surveillance tool in judging the effectiveness of the displacement process. Gas coning is one of the biggest operational challenges. Daily surveillance of GORs by field personnel and active involvement of the engineering staff combine to maintain maximum oil production rates. Water has swept heavier oil from deeper depths to shallower depths, reducing well productivity and slowing the gravity drainage process. Frequent measurements of oil gravities are used to understand and predict producing characteristics.

Heavy oil creates oil/water separation problems, which leads to injection of contaminants in saltwater disposal wells. This results in the need for frequent saltwater disposal well cleanout workovers. Keeping the surface-handling facilities clean minimizes these workovers. Techniques include regularly scheduled tank inspections and cleanouts, appropriate internal tank piping/oxygen exclusion, well-managed water chemistry surveillance and chemical programs, and the use and maintenance of appropriate transfer pumps. Periodic backflowing of gas-injection wells has had a significant positive impact in maintaining high levels of injectivity and minimizing gas-injection pressures.

Sandstone Reservoir With Strong Waterdrive and Selective Well Completion Strategy

Background and Geological Information. This field produces from a series of stacked sandstone reservoirs situated in an angular unconformity trap consisting of an eroded 2 to 6° monocline and an oil/water contact common to all zones. The original oil column was 400 ft thick and contained a 43°API, highly undersaturated crude. Porosity averages 22%, and permeability averages 3 darcy.

Program Used. The primary recovery mechanism is strong waterdrive. All wells are now gas lifted, although this was not necessary in early field life. Wells have typically been drilled through multiple sands, which have been produced sequentially and, in some cases, comingled. Initial development was on 300-acre spacing. Two subsequent infill-drilling programs have been carried out to drain thin zones and areas in the extreme updip portions of the reservoir. The platform is currently constrained by water-handling capacity and, when wells reach high water cut, they are typically cycled on and off so that total production matches facilities limits.

Recovery Performance. The estimated recovery factor is approximately 75% of OOIP. Good rock and fluid properties plus good lateral continuity have contributed to this high recovery through gravity-stable displacement of oil by the invading water. Estimated S_or in invaded sections of the reservoir is 10% of pore volume (PV).

Field Surveillance and Management. Cross section and 3D computer models have been used to study reservoir behavior and upgrade the depletion strategy. A sustained surveillance program includes logging to monitor displacement and regular field performance reviews by the geoscience and engineering team members.

Sandstone Field With Waterflood, Gas Injection, and Miscible Projects

Backgound and Geological Information. The field is a structural stratigraphic trap that has been divided into several vertical zones. Complex, systematic depositional and diagenetic changes resulted in a dual pore system that was further impacted by structural and hydrocarbon histories, resulting in a highly variable vertical and areal distribution of net pay, porosity, and water saturation. Porosity values range from 10 to 30% with an average of 22%. Average well-zone permeabilities ranged from 100 to 1800 md with a field average of 500 md.

Program Used. The primary depletion mechanisms were gas-cap drive along with a very weak waterdrive (rock properties deteriorate rapidly off structure) and potential solution-gas drive. Waterflooding was planned as part of the initial field development to prevent significant pressure depletion.

Waterflooding was started in conjunction with an infill-drilling program that reduced spacing to 80 acres per well. Inverted seven- and nine-spot injection patterns were applied to areas of the oil column not overlain by the gas cap. A small enriched-hydrocarbon miscible injection project was later expanded to additional areas of the field.

Horizontal wells have been used extensively in areas close to the GOC to capture reserves from relatively thin oil columns that were previously uneconomic because of severe coning problems. A gas-cap cycling project has been expanded three times. A few 40-acre-spaced wells were drilled in areas of poor drainage, especially where locally large shale sections prevent good continuity. However, a more economical approach has been to drill 1,500- to 2,000-ft horizontal sidetracks, which can realize up to 85% of the 40-acre well recovery but at less than one-third the cost.

Recovery Performance. Estimated ultimate recovery is 60% OOIP with a miscible contribution of 10% OOIP in affected areas. The contribution of reservoir management to these high recovery levels is difficult to quantify. Initial estimates of recovery were in the range of 40 to 45% of OOIP. It is clear that a continuing effort to discover improved depletion techniques has added significantly to ultimate recovery.

Field Surveillance and Management. The unit collects surveillance data to manage the reservoir effectively. This includes day-to-day production tests, production/injection profiles for wells, and bottomhole-pressure surveys across the field. Additionally, repeat cased-hole neutron logs are taken to monitor gas movements across the reservoir. On new wells, a comprehensive suite of openhole logs is obtained to provide geologic information and to supplement production data and surveillance. The unit actively collected special reservoir surveillance data from pressure-pulse and pressure-transient well tests, repeat formation tests, and specially obtained cores. Both single-well chemical-tracer tests and log-inject-log tests have been conducted, and specialized core data have been obtained in the waterflood areas to measure and improve the effectiveness of the waterflood/miscible EOR project. Additionally, gas samples are collected routinely from flood area production wells to measure returned miscible injectant to further optimize and improve the miscible EOR project and from gravity-drainage area wells to monitor movement of injected cycle gas. Many different simulation models have been developed and updated over time.

There are frequent discussions, at both the technical and managerial levels, of surveillance techniques, operating strategies, reservoir and facility management programs, and future capital projects. Committees, forums, and teams continue to evolve to facilitate and improve these exchanges. In addition, corporate resources bring technical expertise and a worldwide perspective to the development decisions.

Steeply Dipping Sandstone Reservoir With Gravity Stable Miscible Project

Background and Geological Information. This field was formed by a piercement salt plug that breached a regional fault system. The reservoir is composed of unconsolidated sands that dip away from the salt dome at 65 to 85°. The reservoir is divided into several fault blocks. Within each block, the sand is relatively homogeneous. Porosity averages 26.5%, and permeability averages 1.3 darcy. Oil gravity is 38° API.

Program Used. This project is operated as a gravity-stable, hydrocarbon-miscible flood. The injection rate corresponds to a velocity of roughly one-half the critical velocity required for gravity-stable operations. A volume, corresponding to 17% PV, of enriched gas (natural gas liquids plus solution gas) was injected. This was followed by injection of solution gas alone. When injection is completed, blowdown of the gas cap is expected to recover approximately 90% of the enriched gas and a significant portion of the injected solution gas, thus reducing the effective cost of the solvent.

3D reservoir simulations were carried out to examine four depletion scenarios: primary depletion by gravity-stable gas-cap expansion, waterflooding at constant pressure, gravity-stable immiscible gas injection at constant pressure, and gravity-stable hydrocarbon miscible flood at constant pressure. Maintaining constant pressure improves recovery by eliminating shrinkage of oil over the course of displacement. Core flood experiments gave recoveries similar to those predicted by the simulations. Miscible residual oil saturation in core floods was 7% of PV. Slimtube experiments were also carried out to determine the level of enrichment required to achieve miscibility at a given pressure level. A minimum miscibility pressure (MMP) was selected that was consistent with the volume of enriching natural gas liquids available for the project.

Recovery Performance. Primary production occurred through gas-cap expansion. Approximately 6.2% of OOIP had been recovered when miscible gas injection began. Estimated ultimate recovery is 50% of OOIP for primary recovery in both sands, 74% for total recovery after miscible flood in one sand, and 86% for total recovery after miscible flood in a second sand. These recovery levels were determined by tracking gas fronts with pulsed-neutron capture logging and material-balance calculations. These recovery levels are consistent with simulations that were carried out during planning of the miscible project. To date, conformance has been excellent, with field recoveries similar to those seen in core floods.

Field Surveillance Management. Routine pressure measurements, pulsed-neutron capture logs, and pressure-transient testing were used to monitor reservoir performance, contact movements, and identify areas of good and poor communication. Pressure initially was allowed to decline to slightly above the MMP and was then maintained by scheduling injection volumes equal to production. Pressure maintenance became a challenge because of increasing GOR, which resulted in watercut increases and reservoir pressures below the MMP in some areas. Pressures were then increased and maintained by curtailing production from high GOR wells.

Pressure communication between injectors and producers has been good in reservoir A. In reservoir B, pressure communication between injectors and producers has been somewhat hindered by faults and shale barriers that act as baffles.

Low Permeability Sandstone Waterflood

Background and Geological Information. The reservoir is a series of Cretaceous-age, prograding delta clastic sediments consisting of laminated fine-grained sands and shales that are trapped stratigraphically by overlying shales. Reservoir averages are approximately 50 ft of gross pay, 15% porosity, and 20 md permeability.

Program Used. The primary recovery mechanism was solution-gas drive. The field was converted to waterflood in 1961 with an inverted nine-spot injection pattern. Subsequently, a portion of the field was converted to line-drive water injection for improved sweep efficiency and increased water injection capacity.

Recovery Performance. Under primary recovery, the field produced 5% of OOIP. Incremental recovery to date under waterflood has been an additional 17% of OOIP. An ultimate recovery efficiency of 26% of OOIP is forecast.

Field Surveillance and Management. Exploitation of the reservoir is focused currently on reperforating underperforming wells and infill drilling into portions of the reservoir that are shown to be poorly swept. Continuous rebalancing of water injection is proving effective in displacing oil from uncontacted layers.

Sandstone Reservoir With Solution-Gas Drive and Water- and Gas-Injection Projects

Background and Geological Information. The highly faulted structure produces from six different productive horizons. The depositional settings range from deepwater marine turbidite fans through near shore and delta san facies to fluvial deposits. Reservoir quality ranges from high permeability (350 md) in highly continuous tidal shoals to fair quality (100 md) in moderate continuity fluvial channels. The reservoir has been developed from two separate platforms and has an extensive subsea development of satellite fields. More than 140 wells have been drilled from two platforms since initial development in 1976 with well lengths varying from 9,800 to 19,000 ft. Six subsea fields have been developed with 28 subsea producing wells. There are 28 reservoirs that are managed separately.

Program Used. The primary recovery mechanism in the majority of these reservoirs was solution-gas drive with weak aquifer support, although some of the satellite fields have strong bottomwater drives. The main reservoir was developed from the two platforms: the Alpha platform began production in 1976, followed by the Bravo platform in 1984. Crestal gas injection and peripheral water injection were used in both areas in the main reservoir to maintain reservoir pressure and displace the oil zone. The secondary reservoir formations were developed with solution-gas drive mechanisms with water and gas injection applied where economically viable. The Alpha main reservoir achieved a 52% oil recovery factor. Gas-cap blowdown started in 1993. The pressure maintenance schemes continue to be used in the Bravo and Satellite fields.

Recovery Performance. The expected recovery in the main formation is expected to exceed 50% of the OOIP on both the Alpha and Bravo platforms, with the average recovery factor for all sands expected to reach 39% of the OOIP. The cumulative recovery to date of 33% of the OOIP compares with the 15 to 20% expected under primary depletion.

Field Surveillance and Management. Reservoir management in this complex field relied on a multidisciplinary team approach. The complex geological and structural natures of the fields are represented in detailed geological models. Improvements in the structural imaging of the fields through the use of ocean-bottom cable seismic and detailed sequence stratagraphic work has improved the understanding of the fields. Black oil reservoir simulation models have been built for all the major producing reservoirs. These models have sufficient detail to represent the geological and structural complexity properly. A surveillance program for each reservoir unit is defined so that cost effective and minimum production deferral interventions can be planned in advance. Asset development and depletion plans are defined for each field/reservoir unit that define the depletion plan and integrates study plans with surveillance and drilling activities. An opportunity list is developed that is reviewed routinely by the multidisciplinary asset team to ensure appropriate prioritization of resources. Reservoir surveillance data is combined with classical reservoir engineering techniques to create surveillance maps for each of the reservoir flow units. Surveillance techniques combined with simulation results are used to ensure quality forecasts and robust infill-drilling targets. Infill wells typically have a full suite of MWD logs and modular formation dynamics testers. More complex horizontal wells tend to have less comprehensive data gathering because of cost and the risk of losing the hole.

Sandstone Reservoir With a Polymer Injection Project

Background and Geological Information. Production is from three sandstone zones of a Cretaceous-age formation. Productive area of the polymer project was 3,560 acres. Gross thickness was 230 ft, and net-to-gross thickness averaged 0.3. Porosity averages 27%; permeability varies by zone and is less than 100 md in two of them and 170 md in the third, most extensive one. Oil gravity was 20°API, and viscosity varied from 18 to 24 cp. T_R was 150°F.

Program Used. The primary depletion mechanism was solution-gas drive. The field was developed competitively on 40-acre spacing. A unit was formed, and waterflooding began with a staggered line drive. Injection water with a salinity of only 3,500 ppm total dissolved solids (formation water 150,000 ppm) was used without any apparent damage caused by clay swelling or sloughing.

The adverse mobility ratio (see the chapter on foam, polymer, and resin injection in this section of the Handbook for a discussion on mobility ratios) was recognized early in the waterflood and polymer injection begun in 1976. Polymer concentrations were targeted to improve the mobility ratio by a factor of 16 (reduced to 0.5). The injection of polymer was targeted to reduce the cycling of water through previously water-swept oil sands and to divert injected-brine polymer into noncontacted zones to displace additional oil.

Recovery Performance. Waterflooding increased oil rates from 300 to 2,000 BOPD. The rate had declined to 1,600 BOPD when polymer injection began. The rate of oil production decline subsequently was reduced in several wells. Primary plus waterflooding recovery factor was 23% of OOIP. Subtle changes in production decline rates and WOR make it difficult to determine the incremental recovery from polymer injection. An incremental increase of 1 to 3% of OOIP has been estimated. Lower injectivity resulted when polymer was added.

Field Surveillance and Management. Surveillance activities focused on maintaining injectivity and pattern balancing. Well stimulations and cleanout were needed. 2D cross-section simulation was used to manage the injection volumes and distribution of polymer and to design the optimum concentrations of the final polymer injection. Rates were adjusted to inject an average of 20% PV of 600 ppm polyacrylamide polymer solution.

Carbonate Field With Waterflood and Miscible Projects

Background and Geological Information. This field produces primarily from a Jurassic-age limestone-dolomite section that has a simple plunging anticline structure. The updip trap is formed by a combination of facies change from dolomite to dense limestone and a bounding fault. The formation is layered and has been divided into 18 correlative zones.

Program Used. The field was developed competitively by several operators. When production began, the reservoir pressure declined rapidly under a fluid-expansion drive. The field was unitized, waterflooding began, and pressure decline was arrested. Miscible N₂ injection was started eight years later. N₂ was selected rather than methane or CO₂ because of cost and supply considerations.

The field was developed initially with 89 wells on 160-acre spacing. Selective infill drilling in poorer sections of the reservoir (both areally and vertically) improved the sweep of injected water. The need for fieldwide infill drilling to 80-acre spacing was tested with five wells and shown to be uneconomical because little extra recovery was achieved.

The waterflood was implemented with a 3-to-1 line-drive pattern with low salinity water from a water-source well. Produced water is also injected. Peak water-injection rates reached 250 kBOPD. Three air-separation units produced nitrogen, which was reinjected. Peak injection rate was 86 Mcf/D. A water-alternating-gas (WAG) process is used.

There is no downhole corrosion treatment and no internal treatment of flowlines and pipelines. Flowlines and pipelines are protected cathodically and require selective remediation. Corrosion resistant alloy tubulars and flowlines are used to handle the 2% H₂S (originally 8% but reduced by N₂ contamination) sour gas produced from the field.

Recovery Performance. Primary recovery of 17% of OOIP was expected. Waterflooding increased this to 57%, and the miscible project added another 13% of OOIP.

Field Surveillance and Management. This field has had several periodic reservoir studies to update and refine the depletion strategy and a sustained surveillance program that includes acquisition of data needed to monitor reservoir behavior and injection efficiency. To obtain an accurate geologic description, the entire pay interval in virtually all the wells was cored. The reservoir surveillance program included the monitoring of production data, injection data, bottomhole pressures, flood balancing, WAG ratios, injection-to-withdrawal ratios, and profitability of each pattern. One of the tools used is a history-matched four-component compositional-simulation model that is based on a stochastic geologic model and advanced scale-up technology. The 3D model contains 100,000 gridblocks and 18 layers. Good matches of pressure and oil, water, and nitrogen production at the field and individual well levels were achieved with quality control of key input data and the use of extensive history-match experience.

Carbonate Field With Waterflood and Miscible Projects

Background and Geological Information. This field is a north/south trending anticline separated into north and south domes by a dense structural saddle running east and west near the center of the field. Deposition was in an intertidal-lagoon-bank sequence. Production comes from formations at depths ranging from 4,200 to 4,800 ft (subsurface). The formation is more than 1,400 ft thick. The upper 200 to 300 ft is productive, and the remaining is a water zone of relatively low permeability. The productive upper portion of the reservoir is divided further into the upper and lower reservoirs. The average porosity is 9%, and the average permeability is 20 md.

Programs Used.

Primary/Waterflood Depletion. The field was developed initially on 40-acre spacing with 300 wells. The primary producing mechanism was a combination of fluid expansion with a weak waterdrive. In 1963, a unit was created and peripheral water injection began into 36 wells. Production from the unit began declining in 1967 because of insufficient pressure support. A detailed engineering and geologic study identified a flow barrier that was inhibiting pressure support between the upper and lower reservoirs. Implementation of a three-to-one line drive provided the needed pressure support, and production increased. When production began to decline again in 1972, a subsequent reservoir study resulted in a technique to correlate gamma-ray/neutron logs with core data, thus better defining porosity distribution and OOIP. The study resulted in an infill-drilling program to 20-acre spacing, conversion of the injection scheme to an 80-acre inverted nine-spot pattern, and a better reservoir surveillance program.

Infill Drilling/Miscible Process. An oil viscosity of 6 cp makes the waterflood mobility ratio relatively high. From pressure cores and laboratory core floods, waterflood residual oil saturation was estimated to be 34% of PV. Combined, these two factors provided incentive for further infill drilling and evaluation of other recovery methods. A CO₂ miscible project was evaluated with laboratory investigations, a field pilot, and reservoir simulations.

The proposed CO₂ project consisted of 167 patterns on approximately 6,700 acres that encompassed 60% of the productive acres and 82% of the OOIP of the unit. Every attempt was made to use the original 40-acre wells and the 20-acre infill wells. Infill drilling to 10-acre spacing was an integral part of project development. All the WAG injectors and central producers were new 10-acre wells as a part of 40-acre inverted nine-spot patterns.

Within 2 years of project implementation, 205 infill producers and 158 infill injectors had been drilled. Re-evaluation of the project during implementation resulted in changes to project scope. The CO₂ project now consists of 173 patterns on approximately 7,830 acres.

Recovery Performance. Projected recovery from primary and waterflooding methods is 30% of the OOIP. Incremental recovery because of the miscible CO₂ flood is 15% of the OOIP.

Field Surveillance and Management. Throughout the years, a number of reservoir description and engineering studies have been conducted with the goal of developing better reservoir management strategies. A detailed, integrated surveillance and reservoir management program was implemented to achieve areal-flood balancing, vertical-conformance monitoring, production monitoring, injection monitoring, data acquisition and management, pattern-performance monitoring, and optimization. The following are some key objectives of field surveillance and management.

• Integrate all knowledge and data, such as seismic, core, log, laboratory work, and outcrop and field observations, into a fieldwide geologic model and keep it up to date.
• Monitor and understand field performance.
• Increase WAG frequency to minimize problems associated with premature gas breakthrough.
• Maintain a system-operating pressure between the reservoir-parting pressure and the MMP. Falling outside this narrow range would compromise ultimate recovery by fracturing the reservoir or eliminating the miscibility component of the flood.
• Manage the GOR to fit compression limitations for recycled CO₂.
• Update assessments of facility capacity.
• Maintain automated injection, production, and artificial lift monitoring systems to capture data needed to develop programs for maintaining flood-front pressure by balancing the WAG schedule, ratios, and CO₂ slug sizes.
• Implement proactive corrosion- and scale-treatment programs.
• Use new infill wells for injection purposes to minimize downhole mechanical problems.
• Maintain a continuous injection-well profiling program for flood management purposes.

Carbonate Field With Waterflood, Polymer, and Miscible Projects

Background and Geological Information. The field is a carbonate reef-mound complex of Late Pennsylvanian to Early Permian age with a formation composed of limestone with minor amounts of shale. It reaches a maximum thickness of 918 ft and averages 315 ft. Skeletal and oolitic grainstone shoals form the most significant reservoir facies. More than 90% of the porosity is secondary because of freshwater dissolution of unstable framework grains. Cores indicate the presence of fracturing and enhanced dissolution along fractures. Channeling of water and/or CO₂ is evident between many injector/producer pairs.

Program Used. Primary development was followed by a centerline waterflood that was converted subsequently to a five-spot waterflood with two infill-drilling campaigns. A polymer-augmented waterflood was implemented on the basis of data from the new wells. The possibility of enhanced natural gas liquids production was identified with compositional reservoir simulation studies. A CO₂ miscible WAG injection process was then initiated.

Recovery Performance. CO₂ -WAG injection is expected to result in an additional recovery of 12% of the OOIP, bringing the total estimated ultimate recovery to 64% of OOIP. The solvent extraction capability of CO₂ has resulted in an increase of up to 6,000 B/D in natural gas liquids production.

Field Surveillance and Management. Interdisciplinary teams composed of geoscientists; reservoir, production, and facilities engineers; and field operation staff conducted reservoir management. Cores from 30 of the wells were analyzed for stratigraphy and depositional sequences, and these interpretations provided the basis for a reservoir model that has been updated and enhanced throughout the life of the field. 3D geologic and simulation models are integrated into the surveillance process for flood optimization, workover and drill well planning, and WAG management.

Carbonate Waterflood With Stategic Well Placement

Background and Geological Information. The reservoirs in this field are part of a Devonian atoll reef and carbonate shoal complex consisting of limestone with traces of dolomite, pyrite, and anhydrite. The hydrocarbons are trapped stratigraphically by a calcareous shale seal. The reservoir averages approximately 200 ft of gross pay, 8% porosity, and 50 md permeability. Some stringers have permeabilities of 2000 to 3000 md, which result in high well productivities. Oil characteristics include a gravity of 44°API and a formation volume factor of 1.8 RB/STB. The reservoir depth averages 9,000 ft, and the initial water saturation was 14%.

Program Used. The primary recovery mechanism was solution-gas drive. In 1964, the field was converted to a downdip peripheral waterflood. Originally, the field was developed on 160-acre spacing. Selective infill drilling to 80- and 40-acre spacing has been used in updip portions of the field to develop areas of poor reservoir continuity that contain unswept oil.

Recovery Performance. Under primary recovery, the field produced 1% of OOIP. Recovery to date under waterflood has been an additional 45% of OOIP. An ultimate recovery efficiency of 49% of OOIP is forecast.

Field Surveillance and Management. The waterflood is being balanced in four discrete geologic regions or flow units to replace voidage and improve areal-sweep efficiency. The replacement ratio has averaged 100%.

Summary

Petroleum reservoir management is a dynamic process that recognizes the uncertainties in reservoir performance resulting from our inability to fully characterize reservoirs and flow processes. It seeks to mitigate the effects of these uncertainties by optimizing reservoir performance through a systematic application of integrated, multidisciplinary technologies. It approaches reservoir operation and control as a system, rather than as a set of disconnected functions. As such, it is a strategy for applying multiple technologies in an optimal way to achieve synergy, rather than being a technology in itself.

The reservoir management concepts in this chapter are keyed to RMT and RMLT teams. The RMT consists of experts in their field of technology who understand the impact of and are able to work with experts in other technologies. The RMLT is responsible for providing resources and determining customer needs. The effectiveness of the process depends on the timely acquisition, appropriate analysis, and use of high-quality data.

The reservoir management process must be tailored to individual fields depending on size, complexity, reservoir and fluid properties, depletion state, regulatory controls, and economics. The field cases discussed give some insight into how reservoir management has been applied and adapted to a variety of reservoir types and recovery processes.

Because reservoir management is a dynamic process tailored to individual fields and recovery processes, it is important to have timely assessments of how it is being applied. This helps ensure that best practices are being implemented, that the process is being improved continually and systematically, and that experience and technology is transferred among teams.

Nomenclature

h	=	thickness, L, ft
k	=	permeability, L2 , md
Sor	=	residual oil saturation, % PV
TR	=	reservoir temperature, T, °F
μ	=	viscosity, m/Lt, cp

References

General References

Reservoir Management, Vol. 48, 193-197. 1998. Richardson, Texas: Reprint Series, SPE.

Abdullah, M.A.Y. and Olsen, B.S. 1999. Tapis - New Opportunities from a Maturing Field. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, 20-22 April 1999. SPE-54339-MS. http://dx.doi.org/10.2118/54339-MS.

Chow, C.V. and Arnondin, M.C. 2000. Managing Risks Using Integrated Production Models: Process Description. J Pet Technol 52 (3): 54-57. SPE-57472-MS. http://dx.doi.org/10.2118/57472-MS.

Clayton, C.A.Cohen, M.F.Anis, M. et al. 1998. Ubit Field Rejuvenation: A Case History of Reservoir Management of a Giant Oil Field, Offshore Nigeria. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 27-30 September 1998. SPE-49165-MS. http://dx.doi.org/10.2118/49165-MS.

Day, S., Griffin, T., and Martins, P. 1998. Redevelopment and Management of the Magnus Field for Post-Plateau Production. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 27–30 September. SPE-49130-MS. http://dx.doi.org/10.2118/49130-MS.

de Carvajal, G., Banerjee, S., Carrizales, R. et al. 1997. Reservoir Management in the B-6/9, SVS-82, Lake Maracaibo, Venezuela - New Exploitation Policy for Maximizing Profit. Presented at the Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, Brazil, 30 August-3 September 1997. SPE-39052-MS. http://dx.doi.org/10.2118/39052-MS.

Gallagher, J.J., Kemshell, D.M., Taylor, S.R. et al. 1999. Brent Field Depressurization Management Presented at the Offshore European Oil and Gas Exhibition and Conference, Aberdeen, 7–10 September. SPE-56973-MS. http://dx.doi.org/10.2118/56973-MS.

Gringarten, A.C. 1998. Evolution of Reservoir Management Techniques: From Independent Methods to an Integrated Methodology. Impact on Petroleum Engineering Curriculum, Graduate Teaching and Competitive Advantage of Oil Companies. Presented at the SPE Asia Pacific Conference on Integrated Modelling for Asset Management, Kuala Lumpur, Malaysia, 23-24 March 1998. SPE-39713-MS. http://dx.doi.org/10.2118/39713-MS.

Hermansen, H., Thomas, L.K., Sylte, J.E. et al. 1997. Twenty Five years of Ekofisk Reservoir Management. Presented at the Annual Technical Conference and Exhibition, San Antonio, Texas, 5–8 October. SPE-38927-MS. http://dx.doi.org/10.2118/38927-MS.

Khataniar, S.K., Bora, A., and Borah, N.M. 1998. A Reservoir Management Case Study of the Nahorkatiya Oilfield. Presented at the SPE India Oil and Gas Conference and Exhibition, New Delhi, India, 17-19 February 1998. SPE-39568-MS. http://dx.doi.org/10.2118/39568-MS.

Langston, E.P., Shirer, J.A., and Nelson, D.E. 1981. Innovative Reservoir Management - Key to Highly Successful Jay/LEC Waterflood. J Pet Technol 33 (5): 783-791. SPE-9476-PA. http://dx.doi.org/10.2118/9476-PA.

Satter, A. and Thakur, G. 1994. Integrated Petroleum Reservoir Management: A Team Approach. Tulsa, Oklahoma: PennWell.

Schaaf, R.P. and King, G.R. 1997. Numbi Field: Adapting a Reservoir Management Strategy to Changing Reservoir Conditions. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October 1997. SPE-38925-MS. http://dx.doi.org/10.2118/38925-MS.

Selamat, S., Goh, S.T., and Lee, K.S. 1999. Seligi Depletion Management. Presented at the SPE Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, Malaysia, 25-26 October 1999. SPE-57251-MS. http://dx.doi.org/10.2118/57251-MS.

Tewari, R.D., Rao, V.M., and Raju, A.V. 2000. Development Strategy and Reservoir Management of a Multilayered Giant Offshore Carbonate Field. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 16-18 October 2000. SPE-64461-MS. http://dx.doi.org/10.2118/64461-MS.

Thakur, G.C. and Satter, A. 1998. Integrated Waterflood Asset Management. Tulsa, Oklahoma: PennWell.

SI Metric Conversion Factors

acre	×	4.046 856	E + 03	=	m2
°API		141.5/(131.5 + °API)		=	g/cm3
bbl	×	1.589 873	E − 01	=	m3
cp	×	1.0*	E − 03	=	Pa•s
darcy	×	9.869 233	E − 01	=	m2
ft	×	3.048*	E − 01	=	m
ft3	×	2.831 685	E − 02	=	m3
°F		(°F − 32)/1.8		=	°C
psi	×	6.894 757	E + 00	=	kPa

*

Conversion factor is exact.