Reservoir Management Process:

 

The modern reservoir management process involves goal setting, planning, implementing, monitoring, evaluating, and revising plans.

The modern reservoir management process involves establishing a purpose or strategy and developing a plan, implementing and monitoring to plan, and evaluating the results. None of the components of reservoir management is independent of others. Integration of all these is essential for successful reservoir management.

The most important aspect of reservoir management deals with the strategies for depleting the reservoir to recover petroleum by primary and applicable secondary and enhanced oil recovery methods.

Development and depletion strategies will depend upon the reservoir ‘s life stage. In case of a new discovery, we need to address the question of how to best develop the field (well spacing, number of wells, recovery schemes, primary, and subsequently secondary and tertiary).

1.  Data Acquisition, Analysis and Management:

Reservoir management starting from developing a plan, implementing the plan, monitoring and evaluating the performance of the reservoir requires a knowledge of the reservoir that should be gained through an integrated data acquisition and analysis program. Data analyses require a great deal of effort, scrutiny, and innovation. The key steps are: 

•  Plan, justify, time, and prioritize.
• Collect and analyze.
• Validate /store (data base).

An enormous of data are collected and analyzed during the life of a reservoir. An efficient data management program-consisting of collecting, analyzing, storing and retrieving -is needed for sound reservoir management. It poses a great challenge.

Throughout the life of a reservoir, from exploration to abandonment, an enormous amount of data is collected. An efficient data management program consisting of acquisition, analysis, validating, storing, and retrieving plays a key role in reservoir management. It requires planning, justifying, prioritizing, and timing

Data Acquisition and Analysis (Copyright ©1992, SPE )

Data Types:

 

The types of data collected before and after production are shown in table lists the data under the various broad classification including the timing of acquisition and analyses. It is emphasized that the multidisciplinary professionals need to work as an integrated team to develop and implement an efficient data management program. 

Classification	Data	Acquisition Timing	Responsibility
Seismic	Structure, stratigraphy, faults, bed thickness, fluids, interwell heterogeneity	Exploration	Seismologists, Geophysicists
Geological	Depositional environnement, Diagenesis, lithology, Structure, faults, and fractures	Exploration, Discovery & development	Exploration &development geologists
Logging	Depth, lithology, thickness, porosity, fluid saturation, gas/oil, water/oil and gas /water contacts, and well-to-well correlations	Drilling	Geologists, petrophysicists and engineers
Coring	Routine analysis: depth, lithology, thickness, porosity, permeability, and residual fluid saturation SCAL: Relative permeability, capillary pressure, pore compressibility, grain size, and pore size distribution.	Drilling	Geologists, drilling and reservoir engineers, and laboratory analysts
Fluid	Formation volume factors, compressibilities, viscosities, Gas solubilities, chemical, compositions, phase behavior, and specific gravities	Discovery, delineation, development, and production	Reservoir engineers and laboratory analysts
Well Test	Reservoir pressure, effective permeability, thickness, stratification, reservoir continuity, presence of fractures or faults, productivity and injectivity, indices, and residual oil saturation	Discovery, delineation, development, production and injection	Reservoir and production engineers
Production & Injection	Oil, water, and gas production rates, and cumulative productions, gas and water injection rates and cumulative injections, and injection and production profiles	Production & injection	Production & reservoir engineers

Data acquisition and Analysis:

Multidisciplinary groups (geophysicists, geologists, petrophysicists, drilling, reservoir, production and facilities engineers) are involved in collecting various types of data throughout the life of a reservoir. Land and legal professionals also contribute to the data collection process. Most of the data, except for the production and injection data, are collected during delineation and development of the fields.

An effective data acquisition and analysis program requires careful planning and well -coordinated team efforts of interdisciplinary geoscientists and engineers throughout the life of the reservoir. On one hand, there may be the temptation to collect lots of data; and on the other hand, there may be the temptation to short -cut data acquisition to reduce costs. Justification, priority, timelines, quality, and cost-effectiveness in data acquisition should be the guiding factors in data acquisition and analysis. It will be more effective to justify to management data collection if the need for the data, the costs , and benefits  are clearly defined .

Certain types of data such as core derived information, initial fluid properties, fluid contacts, and initial  reservoir pressure can only  be obtained at an early development stage . Coring , logging , and initial reservoir fluid sampling  should be made  at appropriate times using  the proper procedure and analyses . Normally, all wells are logged; however , an adequate  number of wells  should be cored to validate  the log data  .Initial  bottom -hole  pressure measurements should be  made , preferably at each well and at selected “key wells “ perdiocally . Key wells represent 25% of the total wells. It is beneficial to measure pressures in all wells at least every two to three years to aid in calibrating reservoir models.

It is essential to establish the specification of what and how much data need to be gathered and the procedure and frequency to be followed .

An efficient Data Flow Diagram (Copyright ©1992,SPE)

DATA VALIDATION:

Field data are subjected to many errors (sampling, systematic, random, etc.). Therefore, the collected data need to be carefully reviewed and checked for accuracy as well as for consistency.

In order to assess validity , core and logs analyses data should be carefully correlated and their frequency distributions made to identify different geologic facies .Log data should be carefully calibrated using core data for porosity and saturation distributions , net sand determination , and geological zonation of the reservoir .The reservoir fluid properties can be validated by using the equation of state calculations and empirical correlations .The reasonableness of geological maps should be established by using the knowledge of depositional environment. The presence of faults and flow discontinuities as evidenced in a geological study can be investigated and validated by pressure interference and pulse and tracer tests.

   

DATA STORING AND RETRIEVAL:

 

The reconciled and validated data from the various sources need to be stored in a common computer database accessible to all interdisciplinary end users. As new geoscience and engineering data are available, the database will require updating. The stored data are used to carry out multipurpose reservoir management functions including monitoring and evaluating the reservoir performance.

DATA APPLICATION:

 

A better representation of the reservoir is made from 3D seismic information. The cross- well tomography provides interwell heterogeneity.

Geological maps such as gross and net pay thickness, porosity, permeability, saturation, structure, and cross-section are prepared from seismic, core and log analysis data. These maps, which also include faults, oil -water, gas -water and gas-oil contacts, are used for reservoir delineation, reservoir characterisation, well locations, an estimate of original oil and gas in place.

The more commonly used logging systems are:

·         Open Hole Logs:   

 

-       Resistivity, Induction, Spontaneous Potential, Gamma ray,

-       Density, Sonic Compensated Neutron, Sidewall neutron

-       Porosity, Dielectric, and Caliper.

·         Cased Hole Logs:

-       Gamma ray, Neutron (except SNP, Carbon /Oxygen, Chlorine, Pulsed Neutron and caliper.

The well log data that provide the basic information needed for reservoir characterization are used for mapping, perforations, estimates of original oil and gas in place, and evaluation of reservoir perforation.

Production logs can be used to identify remaining oil saturation in undeveloped zones in existing production and injection wells. Time-lapse logs in observation wells can detect saturation changes and fluid contact movement. Also, log -inject -log can be useful for measuring residual oil saturation.

Core analysis is classified into conventional, whole-core, and sidewall analyses. The most commonly used conventional or plug analysis Involves the use of a plug or relatively small sample of the core to represent an interval of the formation to be tested. Whole core analysis involves the use of most of the core containing fractures, vugs, or erratic porosity development. Sidewall core analysis employs cores recovered by sidewall coring techniques.

Unlike log analysis, core analysis gives direct measurement of the formation properties, and the core data are used for calibrating well log data . These data can have a major impact on the estimates of hydrocarbon in place, production rates, and ultimate recovery.

The fluid properties are determined in the laboratories using equilibrium flash or differential liberation tests. The fluid samples can be either subsurface sample or a recombination of surface samples from separators and stock tanks. Fluid properties can be also estimates by using correlations.

Fluid data are used for volumetric estimates of reservoir oil and gas in place, reservoir type, (oil, gas, or gas condensate), and reservoir performance analysis. Fluid properties are also needed for estimating reservoir performance, wellbore hydraulics, and flowline pressure losses.

The well test data are very useful for reservoir characterization and reservoir performance evaluation. Pressure build-up or falloff tests provide the best estimate of the effective permeability -thickness of the reservoir in addition to reservoir pressure, stratification, and presence of faults and fractures. Pressure interference and pulse tests provide reservoir continuity and barrier information. Multiwell tracer tests used in waterflood and in enhanced oil recovery projects give the preferred flow paths between the injectors and producers. Single well tracer tests are used to determine residual oil saturation in waterflood reservoirs. Repeat formation tests can measure pressure in stratified reservoirs indicating a varying degree of depletion in the various zones.

Production and injection data are needed for reservoir performance evaluation.

 

General Geological Activities in Reservoir Description and Input from Engineering Studies.

Fundamentals of Reservoir Management - Synergy and team

 

Although the synergism provided by the interaction between geology and reservoir engineering has been quite successful, reservoir management has generally been unsuccessful in recognizing the value of other disciplines (e.g., geophysics, production operations, drilling, and different engineering functions).

The prime objective of reservoir management is the economic optimization of oil and gas recovery, which can be obtained by the following steps:

• Identify and define all individual reservoirs in a particular field and their physical properties.

• Deduce past and predict future reservoir performance. 

•  Minimize drilling of unnecessary wells. 

•  Define and modify (if necessary) wellbore and surface systems. 

•  Initiate operating controls at the proper time. 

•  Consider all pertinent economic and legal factors.

Thus, the basic purpose of reservoir management is to control operations to obtain the maximum possible economic recovery from a reservoir based on facts, information, and knowledge. The engineering system of concern to the petroleum engineer as being composed of three principal subsystems:

•  Creation and operation of wells.    

•  Surface processing of the fluids. 

• Fluids and their behavior within the reservoir.

The first two subsystems depend on the third because the type of fluids (oil, gas, and water) and their behavior in the reservoir will dictate how many wells to drill and where, and how they should be produced and processed to maximize profits.  

The suggested reservoir management approach emphasizes interaction between various functions and their interaction with management, economics, proration, and legal groups. 

The reservoir management model that involves interdisciplinary functions has provided useful results for many projects.

1. When should reservoir management start? 

The ideal time to start managing a reservoir is at its discovery. However, it is never too early to start this program because early initiation of a coordinated reservoir management program not only provides a better monitoring and evaluation tool, but also costs less in the long run. Most often reservoir management is not started early enough, and the reservoir, wells, and surface systems are ignored for a long time. Many times, we consider reservoir management at the time of a tertiary recovery operation. However, it is critical and prerequisite for an economically successful tertiary recovery operation to have a good reservoir management program already in place. 

What, how, and when to collect data? 

To answer this question, we must follow an integrated approach of data collection involving all functions from the beginning. Before collecting any data, we should ask the following questions:

-       Are the data necessary, and what are we going to do these data? What decisions will be made based on the results of the data collection?

-    What are the benefits of these data, and how do we devise a plan to obtain the necessary data at the minimum cost ?

 

The reservoir management team must prepare a coordinated reservoir evaluation program to show the need for the data requirement, along with their costs and benefits. It must be emphasized that early definition and evaluation of the reservoir system is a prerequisite to good reservoir management. The team members must convince the management to obtain necessary data to evaluate the reservoir system. In addition, the team should participate in making operating decisions. 

What kinds of questions should be asked if we want to ensure the right answer in the process of reservoir management?

Some example questions follow:

•  What does the answer mean ?  

• Does the answer fit all the facts; why or why not ? 

• Were the assumptions reasonable ? 

• Are the data reliable ? 

• Are additional data necessary? 

• Has there been an adequate geological study ? 

•  Has the reservoir been adequately defined ?

Setting a reservoir  management strategy requires knowledge of the reservoir , availability of technology , and knowledge of the business , political and environmental climate .Formulating  a comprehensive management  plan  involves depletion  and development strategies  , data acquisition  and analyses , geological and numerical model studies , production  and reserves forecasts, facilities requirements, economic optimization, and management approval . 

Implementing the plan requires  management support , field personnel  commitment , and multidisciplinary, integrated teamwork . 

Success of the project depends upon careful monitoring /surveillance and thorough, ongoing evaluation of its performance. If the actual behavior of the project does not agree with the expected performance, the original plan needs to be revised , and the cycle (implementing , monitoring , and evaluating  ) reactivated .

Successful reservoir management requires synergy and team efforts. It is recognized more and more that reservoir management is not synonymous with reservoir engineering and / or reservoir geology. Success requires multidisciplinary, integrated team efforts. The team members must work together to ensure development and execution of the management plan.

All development and operating decisions should be made by the reservoir management team, which recognizes the dependence of the entire   system upon the nature and behavior engineer; in fact, a team member who considers the entire system, rather than just the reservoir aspect, will be a more effective decision maker. It will help tremendously if the person has a background knowledge of reservoir engineering, geology, production and drilling engineering, well completion and performance, and surface facilities.

 Team approach to reservoir management can be enhanced by the following:

•  Facilitate communication among various engineering disciplines, geology, and operations staff by: 
•    meeting periodically,
•   interdisciplinary cooperation in teaching each other’s functional objectives, and
•   building trust and mutual respect. Also, each member of the team should learn to be a good teacher.
• To some degree, the engineer must develop the geologist’s knowledge of rock characteristics and depositional environment, and a geologist must cultivate knowledge in well completion and other engineering tasks, as they relate to the project at hand.
• Each member should subordinate their ambitions and egos to the goals of the reservoir management team.
• Each team member must maintain a high level of technical competence.
• The team members must work as a well-coordinated. Reservoir engineers should not wait on geologists to complete their work and then start the reservoir engineering work.

In summary, the synergism of the team approach can yield a “whole greater than the sum of its parts “.

Today, it is becoming common for large reservoir studies to be integrated through a team approach. However, creating a team does not guarantee an integration that leads to success. 

Team skills, team authority, team compatibility with the line management structure, and overall understanding of the reservoir management process by all team members are essential for the success of the project. Also, must reservoir management teams be being assembled only at key investment times.  

One model of the team approach follows:

•  Functional management nominates team members to work on project team with specific tasks in mind. 

• The team reports to the production manager for this project. Also, the team selects a team leader, whose responsibility is to coordinate all activities and keep the production manager informed. 

• The team members consist of representatives from geology and geophysics, various engineering functions, field operations, drilling, finance, and so forth. 

• Team members prepare a reservoir management plan and define their goals and objectives by involving all functional groups. The plan is then presented to the production manager; and after receiving the manager’s feedback, appropriate changes are made. Next the plan is published and all members follow the plan. 

• The team members performance evaluation is conducted by their functional heads with input from the team leader and the production manager. The performance appraisal, in addition to various dimensions of performance, includes team work as a job requirement. 

• Teams are rewarded recognition /cash awards upon timely and effective completion of their tasks. These awards provide an extra motivation for team members to do well. 

•  As the project goals change (e.g. from primary development to secondary process), the team composition changes to include members with the required expertise .Also , this provides an opportunity to change / rotate team members with time . 

• Approvals for project AEE’s (Appropriation for Expenditures) are initiated by the team members.; however, the engineering /operations supervisor and /or production manager have the final approval authority. 

•  Sometimes conflicting priorities for the team members develop because they essentially have two bosses (i.e., their functional heads and the team leader). These conflicts are generally resolved by constant communication among the team leader, functional heads, and the production manager.

 

2. Technology and Technological Toolbox:

The success of reservoir management depends upon the reliability and proper utilization of the technology being applied concerning exploration, drilling and completions, recovery processes, and production. Many technological advances have been made in all of these areas.

Estimation of Oil & Gas Reserves

 

By definition, it is something kept back or saved for future something kept back or saved for future use a special purpose.

The term “Reserves” means different things to different people. To the oil & gas operators, reserves are volume of crude oil, natural gas, and associated products that can be reserved profitably in the future from subsurface reservoirs.

Reasons for Reserve Estimates :

Segments of the industry concerned with oil & gas reserves:

• Companies interested in exploration and development of oil and gas properties. 

•  Banks involved in the financing exploration, development, or purchase of oil and gas properties. 

• Agencies with regulatory or taxation authority over oil and gas operators. 

• Investors in oil and gas companies.

Depending on the scope of their operation, operators require reserve estimates:

• Sizing & design of equipment and facilities to process and transport them to market. 

•  Assigning the FDP and corresponding cost (Budget) 

• Establishing future production profiles 

• Quantifying impact of key uncertainties.

 

Uncertainties in Reserve Estimates :

Estimates of commercially recoverable hydrocarbons reserves are inherently uncertain (physical & commercial). 

• Physical uncertainties:  

-       Recovery from subsurface reservoirs depends largely on the heterogeneities of the reservoir rock.

-       Reservoir Extension

-      The type of reservoir drive mechanism, etc. 

•  Commercial uncertainties: 

-      The costs to acquire exploration and development rights (CAPEX)  

-     The costs to produce, process, and transport oil and gas to market (OPEX)

-      The market value of the volumes sold (Prices) 

Why is a reserves Definition Needed ?

·         Most of the parameters that define the reserves of a Reservoir cannot be measured directly, and must be determined indirectly through geological and reservoir engineering analysis and interpretations.

•   As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. 
•   The definitions of reserves are designed to promote uniformity and standard measurement of the assets, providing a structure to quantify risk and uncertainty through its categorization.

Visual definition of resources and reserves :

Determining the resource and reserves at any time is a difficult task , and the values will change over time .

The resource might be technically recoverable, economics will dictate how much is produced at a given time and price . Because global and local economics change more a less continually, the amount of resource that is actually extracted  or extractable will also vary with time . It  is this amount of the resource that can be considered the reserves , both proven and probable .

Proven   (P)	Discovered reserves which can be produced under current economic conditions (80% chance). Developed and undeveloped
Probable   (P+P)	Discovered reserves which have a reasonable probability of production with present technology and economics (50% chance).
Possible (P+P+P)	Reserves not yet discovered with less chance to be produced (20% chance).

 

 Reserves are :

•  Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward.
•  All reserve estimates involve some degree of uncertainty.
• The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.
• The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.
• Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.

 

1.  Proven Reserves:

·         Proven reserves are those reserves claimed to have a reasonable certainty (normally at least 90% confidence) of being recoverable under existing economic and political conditions, with existing technology. Industry specialists refer to this as P90 (having a 90% certainty of being produced). Proven reserves are also known in the industry as 1P.

• Proven reserves are further subdivided into "proven developed" and "proven undeveloped".
• Proven developed reserves are reserves that can be produced with existing wells and perforations, or from additional reservoirs where minimal additional investment (operating expense) is required.
• Proven undeveloped reserves require additional capital investment e.g., drilling new wells to bring the oil to the surface.
• Proven reserves can further be categorized on the basis of status of wells and reservoirs as developed and Undeveloped; producing and nonproducing. 

a.      Developed reserves:

Developed reserves are expected to be recovered from existing wells. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be subcategorized as producing or non-producing.

®    Producing:  

    Reserves subcategorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate.

®    Non-producing:

Reserves subcategorized as non-producing include shut-in and behind-pipe reserves.

Shut-in reserves are expected to be recovered from:

• completion intervals which are open at the time of the estimate but which have not started producing,
• wells which were shut-in for market conditions or pipeline connections, or
• wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

 b.      Undeveloped Reserves:

Undeveloped reserves are expected to be recovered:

•     from new wells on undrilled acreage,
•     from deepening existing wells to a different reservoir, or where a relatively large expenditure is required to: 
• recomplete an existing well or
• install production or transportation facilities for primary or improved recovery projects.

 2.      Unproven Reserves:

•      Unproven reserves are based on geological and/or engineering data similar to that used in estimates of proven reserves, but technical, contractual, or regulatory uncertainties make such reserves being classified as unproven.
•         Unproven reserves may be used internally by oil companies and government agencies for future planning purposes but are not routinely compiled. They are sub-classified as probable and possible

a.      Probable:

Probable reserves are attributed to known accumulations and claim a 50% confidence level of recovery. Industry specialists refer to them as P50 (having a 50% certainty of being produced). These reserves are also referred to in the industry as 2P (proven plus probable).

b.      Possible:

Possible reserves are attributed to known accumulations that have a less likely chance of being recovered than probable reserves. This term is often used for reserves which are claimed to have at least a 10% certainty of being produced (P10).

Reasons for classifying reserves as possible include varying interpretations of geology, reserves not producible at commercial rates, uncertainty due to reserve infill (seepage

from adjacent areas) and projected reserves based on future recovery methods. They are referred to in the industry as 3P (proven plus probable plus possible).