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Reservoir management

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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.


Reservoir management has been in place in most producing organizations for several years. Several authors[1][2][3][4][5][6][7][8] 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. The following situations, however, can reduce the effectiveness of reservoir management programs:

  • Personnel changes
  • Altered priorities
  • Insufficient surveillance data
  • Lack of documentation

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. 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.

The reservoir management process must be tailored to individual fields depending on:

  • Size
  • Complexity
  • Reservoir and fluid properties
  • Depletion state
  • Regulatory controls
  • Economics

Case studies of reservoir management benefits

In the discussion of field histories on the pages linked below, 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
  • All vertical wells

Examples demonstrating benefits of reservoir management program:

Reservoir management team

Fig. 1 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
  • 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.

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
  • 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
  • Simulation models

How much information and how to capture this information varies with:

  • Size of the database
  • Size of the resource
  • Remaining life of the resource

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
  • Number of flow units or individual producing zones
  • Depositional environment including information on diagenetic changes and vertical and areal barriers to flow (or lack thereof)
  • 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 Reservoir geology, Reservoir geophysics overview and petrophysics for information on geophysical, geological, and petrophysical interpretations and how they are used to develop a 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
  • 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.


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 accomplishes the following:

  • Produces a better description of reservoir contents
  • Reduces uncertainty
  • 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
  • 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
  • Wellbore utilization plans

Determining the primary drive mechanism

Determining the primary producing mechanism is the first step in selecting a depletion strategy. This information can be used to project:

  • Oil-, gas-, and water-producing rates
  • Reservoir pressure trends
  • Ultimate recovery

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

  • Total field offtake rate and individual well rates that can be sustained without ultimate loss of recovery.
  • 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.
  • 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.

Horizontal/multilateral wells

Horizontal and multilateral wells increasingly are being used to:

Continuing technologic improvements are making horizontal wells an increasingly more cost-effective way to develop certain portions of a reservoir. The page on fluid flow through permeable media 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 the following:

  • Good vertical permeability
  • Well-managed contact movements
  • 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 these features:

  • Low vertical permeability
  • Rapidly moving contacts
  • 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.

Need for improved recovery projects

Improved recovery mechanisms refer to the injection of fluid to augment or replace the primary drive mechanism. Such fluids include:

  • Water
  • Water with additives
  • Hydrocarbon gas
  • Nonhydrocarbon gas
  • Steam
  • Air for in-situ combustion

Table 1 presents screening criteria for selecting improved recovery processes.

The pages on water injection; immiscible gas injection; foam, polymer, and resin injection; miscible processes; steam; and in-situ combustion describe the characteristics and potential for several injection schemes in oil 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
  • 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:

  • 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
  • Capture of monthly produced volumes of oil, gas, and water and monthly injected volumes

The pages on petrophysics, production logs, single well chemical tracer testing, interwell tracer tests, and measurement of reservoir pressure 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)
  • Large-scale, full-field models

See Reservoir simulation for details on building reservoir simulation models.

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
  • Need for and timing of reservoir depressuring

Model description and data

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.

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
  • 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.

Implement and operate

Implementation plan

This plan is developed with input from several engineering disciplines.

  • Drilling engineers design drilling schedules, wellbore trajectories, and casing and cementing programs to locate wells at the required location for the lowest effective cost.
  • Subsurface engineers design tubulars, completion techniques, stimulation processes, and artificial lift equipment required for target well rates. They also design workover procedures as needed.
  • 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.
  • 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 the following should be required:

  • Trends in individual well producing or injection rates
  • Gas/oil ratios or gas/liquid ratios
  • Water cut
  • Wellhead pressure
  • Artificial lift performance

Surveillance includes periodic comparison (every 1 to 5 years) of performance with the projections contained in the depletion plan. The performance factors reviewed include:

  • Rates
  • Pressures
  • Recovery levels
  • Injection volumes
  • Contact movements
  • Etc.

Significant deviations should trigger an update to the depletion plan to:

  • Reflect the new information
  • Identify additional data needs
  • 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:

  • Initial development plan
  • Development and updating of the depletion plan
  • 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
  • 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.

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.


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.


  1. Eden, A.L. and Fox, M.J. 1988. Optimum Plan of Depletion. Presented at the SPE California Regional Meeting, Long Beach, California, 23-25 March 1988. SPE-17458-MS.
  2. Hickman, T.S. 1995. A Rationale for Reservoir Management Economics. J Pet Technol 47 (10): 886-890. SPE-26411-PA.
  3. Raza, S.H. 1990. Data Acquisition and Analysis for Efficient Reservoir Management. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 23-26 September 1990. SPE-20749-MS.
  4. Satter, A., Varnon, J.E., and Hoang, M.T. 1994. Integrated Reservoir Management. J Pet Technol 46 (12): 1057–1064. SPE-22350-PA.
  5. Stiles, L.H. and Magruder, J.B. 1992. Reservoir Management in the Means San Andres Unit. J Pet Technol 44 (4): 469-475. SPE-20751-PA.
  6. Thakur, G.C. 1990. Implementation of a Reservoir Management Program. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 23-26 September 1990. SPE-20748-MS.
  7. Torvund, T. 1989. The Oseberg Reservoir Management Planning: A Case History From the Oseberg Field. Presented at the Offshore Technology Conference, Houston, Texas, 1-4 May. OTC-6140-MS.
  8. Wiggins, M.L. and Startzman, R.A. 1990. An Approach to Reservoir Management. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 23-26 September 1990. SPE-20747-MS.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

Duhon, Howard. 2015 "Managing Project Complexity." Web Events. Society of Petroleum Engineers,

See also

Assessing reservoir management