SPE 132704

Planning, Execution & Surveillance of Enhanced Oil Recovery Projects B. Sinanan, M. Budri, M.O.R.E Consulting Ltd.

Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the Trinidad and Tobago Energy Resources Conference held in Port of Spain, Trinidad, 27–30 June 2010. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Trinidad and Tobago’s onshore acreage has seen many stages of development. Currently, most onshore fields are well into their mature phase with the application of various forms of artificial lift being applied. Secondary recovery, through water-flooding, has been used in some fields with limited success whilst tertiary recovery methods, namely steam injection, have been more successful. These projects have been few and far between since there is a significant amount of acreage still to be considered for Enhanced Oil Recovery (EOR). An analysis of historical data has suggested that the application of modern day EOR screening, reservoir characterization tools and simulation would address some of the uncertainties that posed problems in the past.

An increasing number of mature oilfield acreage is being leased out by the state to private investors/operators. These entities must be prepared to efficiently exploit these mature blocks by optimizing current production operations, performing recompletions, in-fill drilling but most importantly by adding significant reserves through EOR projects. Many modern considerations within the feasibility stage through to health, safety and environment application must now be adhered to, for successful approvals from government regulators.

This paper provides a detailed outline of the different stages and processes that companies can follow or modify, to suit their reservoir management style, in pursuing successful EOR outcomes. This paper also addresses the importance of EOR screening, project management and surveillance techniques. Processes and recommendations developed from this work can be applied by any oilfield company who wishes to begin or expand their EOR project. Introduction

Trinidad and Tobago’s land oil production is primarily derived from its onshore acreage, located in the southern region of Trinidad. The exploitation of Trinidad’s onshore acreage for over a century has resulted in many mature fields. Several of these mature fields have been leased out to private investors/operators by the state since continued production from these fields has been deemed uneconomical. Many of these fields have the potential to become once again economically viable, once suitable production optimization strategies and techniques are implemented. Optimization strategies such as performing recompletions, in-fill drilling and various artificial lift techniques have all been attempted and tested, yielding encouraging results.

Optimization strategies, whilst necessary have become ineffective in adding significant reserves; a more robust approach, such as EOR needs be considered to fully exploit the remaining hydrocarbons in place. Trinidad & Tobago has implemented many EOR projects in the past. These include immiscible carbon dioxide floods, steamfloods, cyclic steam stimulation and microbial enhanced oil recovery (MEOR) methods. The results of various attempted EOR projects have been promising and indicate that EOR has an important role in the development and production of Trinidad’s hydrocarbon resources, since the country is currently seeking a strategy to develop an estimated 1.5 billion barrels of heavy oil reserves.

In 1966, the first EOR project implemented in Trinidad and Tobago was a thermal oil recovery project consisting of a small cyclic steam stimulation pilot in the Palo Seco Field1. Over the past decades, several steamfloods have been implemented in

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other onshore fields such as Central Los Bajos, Guapo, North Fyzabad and Apex-Quarry/Coora/Quarry. The most recent to be implemented was the Upper Morne L’Enfer thermal recovery project in 2005. Despite its successes, these thermal recovery projects faced several challenges including:

• Injectivity reduction • Heat losses • Injection quality and supply problems • Gravity override of steam • Sand production • Well bore integrity damage • Well spacing and pattern configuration issues

Solvent EOR methods have also been implemented in Trinidad. Four (4) immiscible carbon dioxide (CO2) pilot floods were

implemented by the Petroleum Company of Trinidad and Tobago (Petrotrin) within the Forest Reserve and Oropouche fields2. Three (3) floods were conducted at Forest Reserve targeting the Upper Cruse Sands, Lower Forest Sands and the Upper Forest Sands2. One (1) flood was conducted in Oropouche targeting the AO 08 Sand2. Predicted ultimate recoveries at Forest Reserve ranged from 4.7% - 9% OOIP and 4% at Oropouche2. Despite increases in oil recovery, the projects experienced several challenges. Some of these included:

• Unreliable CO2 Supply • Outdated Equipment • Channeling of Injected Gas • Bypassing of Oil • Limited Pressure Data and Gas Measurements • Corrosion • Sand Production

As more mature onshore oil leases are awarded, operators will quickly come to realize that sustainability means that they must learn from past experiences and explore their injection options sooner than later. The process from planning to surveillance involves the project management of many skill sets and liason with the state through the national oil company and the Ministry of Energy and Energy Industries (MOEEI). This work intends to frame theses skill sets and relationships by the use of tables and process flowcharts and will work seamlessly if followed. EOR: A Multidisciplinary Team Effort

The entire EOR process from design to monitoring and surveillance requires input from many skilled individuals across the entire organization. It involves not only reservoir engineering, but other disciplines (figure 1) including geology, civil, drilling and completions, utilities, electrical, production, project management, HSE, surveying, legal, inspectorate and finance. The various disciplines are integrated to form a multidisciplinary team with each member bringing his/her own experience and technical expertise to achieve the ultimate goal of designing and implementing an economical and effective EOR project. Formation of the team, selection of team members, appropriate motivational tools and composition of the team should be carefully considered3. Once a team has been formed and becomes functional, team effort must be sustained. One model of team approach is as follows:

• Functional management nominates team members to work on a specific EOR project under consideration • The team selects a team leader whose responsibility is to coordinate all activities and keep the manager informed. • The team consists of representatives from geology and geophysics, various engineering functions, field operations,

drilling, finance etc. • Team members prepare a plan and define their goals and objectives by involving all functional groups. The plan is then

presented to the manager and after receiving the manager’s feedback, appropriate changes are made. The plan is then distributed for all members to follow.

• The team members’ performance evaluation is conducted by their functional heads with input from the team leader and the manager

• Teams are rewarded with recognition/cash rewards upon timely and effective completion of their tasks. • As the project goals change, the team composition changes to include members with the required expertise.

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The table below shows the structure of the functional departmental structure required to manage typical EOR projects:

Production Operations

Drilling Operations

Technical Support

Finance & Legal

Project Utilities

Operations

Leads In house manager

In house or contracted services

In house or consultant services

In house managers

In house or contracted services

Core Staff

Field Production Personnel

Rig workover Supervisors and Crew

Administrative

Support

Security

HSE

Contracted Rig

Service Engineers

and Technicians

HSE

Engineers: Reservoir Drilling

Completion Petrophysicist

Geologist:

Geophysicist Model Builders Ops Geologists

Lawyers

Procurement Specialist

HR

Accountants

Clerical

Engineers: Mechanical

Electrical Civil Surveyors Draughting

HSE Specialist

Table 1: Structure of Multidisciplinary Team

Planning of EOR Projects

Planning is the most crucial stage in any EOR project. During this stage important engineering and economic decisions regarding the selection and profitability of EOR methods are made. There are three (3) major areas of study that should be incorporated into the planning of any EOR project. These include: the Pre-Feasibility Stage, the Feasibility Stage and the Approval Stage. Implementation and surveillance follows these stages and are also discussed in this paper. Pre Feasibility

This stage involves engineering and geological input in selecting the most appropriate EOR method required for a particular horizon of interest. Upon selecting a horizon, representative data of reservoir fluid and rock properties should be collected and analyzed if not found in past reports. The data gathered includes, but is not limited to, reservoir fluid and rock fluid properties such as API gravity, formation type, depth, oil viscosity, thickness, temperature, pressure, oil saturation, composition and permeability ,which are used in an EOR screening criteria to select the most optimum EOR method.

Several EOR screening criteria are currently available in literature. Many screening criteria are often developed by companies based on knowledge obtained from past field experiences. However, in instances where this type of knowledge is unavailable, a popular screening criteria proposed by Taber et al is often used. Taber et al (1997) proposed an EOR screening criteria for eight (8) methods: gas injection (nitrogen, hydrocarbon and carbon dioxide), water injection (micellar/polymer plus alkaline/surfactant polymer (ASP), polymer flooding, gel treatments) and thermal/mechanical recovery (combustion, steam, surface mining) methods4. The EOR screening criteria was developed from analyzing reservoir and fluid characteristics obtained from several successful EOR projects as well as incorporating the theories involved in oil recovery mechanisms. The proposed screening criteria identified nine (9) important fluid and reservoir properties required to select the optimum EOR method4. These included:

• Oil Gravity • Viscosity • Composition • Oil Saturation • Formation Type

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• Net Thickness • Average Permeability • Depth • Temperature

Today, there are several commercial computer programs available, that can perform EOR screening and forecasting. SELECTEORTM, developed by the Alberta Research Council and EORgui®, from Petroleum Solutions, are just two (2) examples of EOR screening and analytical forecasting software that are commonly used. These programs are can identify appropriate EOR methods and rank them. Cumulative production, rates, gas oil ratios and water cuts can also be forecasted. The forecasted production data is then used to conduct preliminary studies to determine the economic viability of the project. Once the project is shown to be economical, an application for a certificate environmental clearance (CEC) should be made. A CEC is a certificate issued to an applicant by the Environmental Management Authority (EMA), which certifies the environmental acceptability of a proposed project5. Applicants are asked to provide an environmental assessment of the proposed activity, highlighting potential environmental hazards and to propose mitigation strategies. If all conditions are fulfilled a CEC may be granted allowing work at the site to commence. If the CEC application has been denied, the applicant should review the environmental assessment of the project to ensure that all the requirements for the CEC are met, before reapplying. However, if the preliminary studies indicate that the project will be uneconomical, the project is put on hold, until favorable economic conditions exist. The figure below is a workflow summarizing the steps involved in the ‘Pre-Feasibility’ process.

Figure 1: Pre-Feasibility Process

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Feasibility Once the optimum EOR method is selected, an in depth feasibility analysis is conducted. This stage involves

characterizing the reservoir and modeling the EOR process using a numerical reservoir simulator. Reservoir characterization integrates all available data to define the geometry, distribution of physical parameters, and flow properties of a petroleum reservoir. The goal is to accurately and quantitatively model reservoir architecture, connectivity, and flow properties such as porosity, permeability, and fluid saturations. This may involve expertise in sedimentology to define reservoir lithology and geometry, definition of flow units and boundaries within the reservoir. A mathematical model of the reservoir is created from this characterization study. The formulation of this model requires geological, rock properties, fluid properties and well data. Fanchi (2001) highlighted a comprehensive list of data required, as well as available data sources, for a reservoir simulation study6:

Figure 2: Data Required For a Reservoir Simulation Study6

Today, there are several commercial computer programs available for building reservoir models and conducting numerical EOR simulation studies. After conducting simulation the simulated reservoir behavior is then compared with the actual past reservoir behavior. If both are inconsistent the reservoir model is fine tuned by incorporating more acquired data, and the process is repeated until both appear consistent. Upon developing a representative reservoir model, the EOR process chosen needs to be modeled. This requires various scenarios and sensitivities to be performed. For the particular EOR method under consideration, various scenarios are simulated to determine critical parameters such as the optimum number of wells, well placement, well pattern configurations and injection rates.

For each scenario, the oil production is forecasted at various economic conditions such as the variation in oil prices, to simulate potential future revenue. For each scenario, a detailed breakdown of the project’s capital expenditure (CAPEX) and operational expenditure (OPEX) costs are determined. The CAPEX and OPEX forecasted revenue, aids in selecting the best scenario that will allow oil recovery to be economically maximized by the selected EOR method of interest. The workflow shown below summarizes the entire ‘Feasibility’ process.

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Figure 3: Feasibility Process Approval

Upon fulfillment of the economic criteria, a summary and detailed documention of the project is presented to management for approval. Once approval has been granted by management, the next step is to seek approval from external regulatory agencies such as the EMA, state oil company and from the Ministry of Energy and Energy Industries (MOEEI). If the CEC has been granted from the EMA, the project is then sent to the MOEEI for approval. The MOEEI seeks to assess whether or not the project is suitable to perform its intended operations in the country7. This assessment focuses on the physical facility to ensure that the final facility is properly built and requires expert judgment on the civil, mechanical, electrical and processing infrastructure. It also looks at the adequacy of the systems required to manage and support the human interface with the facility and includes operating procedures, training and competence, authority and accountability, contingency and emergency response plans, etc. The following is a list of the MOEEI requirements for approval7:

• Design premise and basis for the major project • Codes and standards used to develop the project • Description of the project • Materials used for construction

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• Site layout. • Details of fire fighting and gas detection provisions. • Technical integrity report on all infrastructures that are to be reused as part of final project. • Hydro test certificate for tanks, piping and pipelines. • Proof of acceptance of fire plan by fire services and internal HSE department • Bund design and capacity & drainage and storm water management provisions. • Emergency response plan • Oil spill contingency plan • Emergency shutdown provisions • Standard operating procedures for the project • Action plan showing status of all CEC requirements

However, if the project is not approved, it should be documented and placed in storage for later use. The workflow shown below clearly and concisely reiterates the steps involved in the ‘Approval’ process.

Figure 4: Approval Process

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Implementation of EOR Projects Once the bid for approval has been successful, the next step is implemention of the EOR project. This stage involves the

drilling of new wells or conversion of poorly producing wells into injectors and performing workovers on production wells. The optimum number of wells and well pattern configurations are drilled. New wells may be required or in some cases poorly producing wells or abandoned wells may be converted to injector wells to minimize costs. Workovers are also performed on production wells to increase the chance of success for the particular EOR project.Any additional information obtained from the drilling of new wells and workovers should be incorporated back into the model and the EOR process should be reviewed and modified accordingly.

In addition to wells, surface facilities responsible for separating and treating the produced hydrocarbons are also installed to separate and treat the produced hydrocarbons. One consequence of producing hydrocarbons is the large volumes of associated produced water. The handling and treatment of the large volumes of produced water is one of the most common problems encountered in EOR projects. Produced water cannot be disposed of in its natural state since it often contains traces of hydrocarbons that are toxic to the environment. As a result, there are strict environmental regulations that must be adhered to regarding the proper disposal of produced water. Within recent time, there have been many studies aimed at determining possible uses for produced water. Some of the more common uses that have been identified include8:

• It can be a primary water source for secondary pressure maintenance and flooding. • It can be can be treated and used in steamflooding projects. • It can be treated and used for power generation or refining. • It can be used in dust control and fire control • It can be used treated and used for irrigation

The figure below highlights the major steps involved in the implementation of EOR projects.

Figure 5: Implementation Process

Monitoring & Surveillance of EOR Projects Monitoring and surveillance of EOR projects involves continually assessing the performance of the operation. Surveillance is a team effort of management, operations, engineering, geologic and service groups9. It involves the monitoring of the reservoir, wells, enhanced oil recovery operations as well as the surface operations9. Monitoring and surveillance of these critical areas allow us:

• To determine whether or not the enhanced oil recovery processes are working and also whether they are conforming to the requirements of the field development plan.

• To identify problems that may be encountered throughout the life of the recovery operations. • To collect and analyze data, which gives us a better understanding of the characteristics of the reservoir and the various

processes that are taking place. • To maximize the recovery of hydrocarbons in place

Surveillance is more specifically the use of problem well analysis to define wells or fields that have production and operating problems9. Once the problems have been identified, appropriate action must be taken9. The conclusion of this effort should result in one of the following recommendations9:

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• Continue to produce the well(s) with no change • Collect additional data • Workover and/or stimulation • Equipment change • Operations procedure change(s) • Recompletion • Implement other recovery techniques • Shut in and abandonment

Sound reservoir management requires constant monitoring and surveillance of reservoir performance as a whole to determine whether the performance is conforming to the management plan3. In order to carry out the monitoring and surveillance program successfully, coordinated efforts of the various functional groups working on the project are needed3.

An integrated and comprehensive program needs to be developed for successful monitoring and surveillance of the project3. The engineers, geologists, and operations personnel should work together on the program with management support3. The extent of the surveillance program usually depends on the nature of the project3. Ordinarily, the major areas of monitoring and surveillance involving data acquisition and management include oil, water and gas production by wells, gas and water injection by wells, systematic and periodic static and flowing bottom hole pressure testing of selected wells, production and injection tests, injection and production profiles, recording of workovers and results; and anything else that aids surveillance3. The table below shows a list of data that is usually obtained during surveillance of EOR projects:

Table 2: Surveillance Data3

The data acquired from surveillance programs can be analyzed using the following tools9: • Production Curves • Flood Front Map or Bubble Maps • Contour Maps • Areal Sweep Efficiency Maps • Cross Plots • Hall Plots

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Figure 6: Monitoring & Surveillance Process

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Conclusion

• A mutidisciplinary team is essential for the various stage completion in any secondary or tertiary project. • The planning stages involves (a) pre-feasability, (b) feasability and (c) approvals which is then followed by the (d)

implementation stage and the (e) surveillance stage. • The simplified process charts can be adopted for use by lease and farmout operators who wish to embark on EOR type

projects. Nomenclature BOPD – Barrels of Oil per Day CAPEX – Capital Expenditure CEC – Certificate of Environmental Clearance CO2 – Carbon Dioxide EMA – Environmental Management Authority EOR – Enhanced Oil Recovery MEOR – Microbial Enhanced Oil Recovery MOEEI – Ministry of Energy & Energy Industries OOIP – Oil Originally In Place OPEX – Operating Expenditure Bibliography/References 1. Khan, J. & Parag, D.: “Twenty-Five Years of Oil Recovery by Steam Injection,” paper SPE/DOE 24198 presented at the

SPE/DOE Eighth Symposium on Enhanced Oil Recovery held in Tulsa, Oklahoma, April 22-24, 1992

2. Mohammed-Singh, L. J. & Singhal, A. K.: “Lessons from Trinidad’s CO2 Immiscible Pilot Projects 1973-2003,” paper SPE 89364 presented at the 2004 SPE/DOE Fourteenth Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, U.S.A., 17–21 April 2004.

3. Satter, A. & Thakur, A. G.: Integrated Petroleum Reservoir Management, PennWell Publishing Company, Tulsa, Oklahoma (1994)

4. Martin, F. D., Seright, R. S. & Taber, J. J.:”EOR Screening Criteria Revisited - Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects,” SPE Reservoir Engineering (August 1997) 189.

5. The Environmental Management Authority: A Guide to the Application for a Certificate of Environmental Clearance. from http://www.ema.co.tt/docs/appForms/CEC/cec_application_guide.pdf

6. Fanchi, J. R.: Principles of Applied Reservoir Simulation, second edition, Gulf Professional Publishing, Houston, TX (2001) 169.

7. Republic of Trinidad & Tobago Ministry of Energy and Energy Industries: Technical Guidance Document – GD 05: Verification Scheme for Hydrocarbon Production and Processing Facilities, from http://www.energy.gov.tt/content/GD_Verification_Scheme_For_Hydrocarbon_Facilities.pdf

8. Elcock, D., Puder, M. G., Redweik Jr., R. J. & Veil, J. A.: A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas and Coal Bed Methane, U.S. Department of Energy, National Energy Technology Laoratory (2004).

9. Allen, T.O. & Roberts, A.P.:Production Operations 2: Well Completions, Workover and Stimulation, fourth edition, Oil and

Gas Consultants International Inc., Tulsa, Oklahoma, U.S.A (2000).

10. Hong, K. C.: Steamflood Reservoir Management, PennWell Publishing Company, Tulsa, Oklahoma (1994)