15th March 2017
As the "easy oil" disappears, options for future production will be based on “Unconventional Reservoirs” (Tight/Shale Oil), on the implementation of best management practices and application of Improved Oil Recovery processes (IOR) predominantly on Heavy, Extra Heavy Oil and Tar Sands. While much of the recent discussion on where the marginal barrel of new oil will come from focuses on unconventional plays, it misses the equally large upside from already discovered fields, in the form of IOR.
This article discusses the nature of IOR projects, identifying reasons why insufficient attention is paid in the design of IOR pilots, reducing the potential of booking additional reserves, leading the industry to come up short in the contribution that this activity could bring.
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In 2011, then-president of the Society of Petroleum Engineers Alain Labastie1 wrote:
“The current ultimate average recovery factor for oilfields, on a worldwide basis, is about 35%. This means that about two-thirds of the oil that has been discovered is left within the reservoir. We have under our feet, in well-known locations, enormous prospects for booking new reserves. Increasing the average ultimate recovery factor from 35% to 45% would bring about 1 trillion barrels of oil”. In the case of unconventional oil reservoirs, the average recovery factor is between only 5% and 10% 2, meaning there is enormous potential for producing more oil from conventional and shale oil reservoirs around the world.
Primary oil recovery is obtained using the natural energy of the reservoir and it is strongly dependent on factors such as the viscosity of the oil, the pressure in the reservoir, the strength of any aquifer, and the geological and petrophysical characteristics of the reservoir near the well (porosity, permeability, etc.). These factors lead to variations in recovery from well to well. Primary recovery ends when the pressure in the reservoir around the oil well becomes too low to sustain commercial production rates, either natural flow or mechanically assisted flow using artificial lift (gas lift, electro-submersible pumps, etc.), in most cases this occurs when only less than 20% of original hydrocarbons in situ have been produced. Improved recovery can increase recovery efficiencies significantly in ideal circumstances.
Improved Oil Recovery (IOR) is a broad term referring to any process designed to increase the recovery factor (RF) by supplementing natural reservoir recovery processes (primary recovery). The "Petroleum Resources Management System" (PRMS)3 gives the following definition: “Improved recovery is the additional petroleum obtained, beyond primary recovery, from naturally occurring reservoirs by supplementing the natural reservoir performance. It includes waterflooding, secondary or tertiary recovery processes, and any other means of supplementing natural reservoir recovery processes”. This definition refers mainly to what used to be termed secondary recovery and tertiary recovery and applies to conventional and unconventional reservoirs. Enhanced Oil Recovery (EOR) is generally considered to include tertiary recovery processes only. This is illustrated in Figure 14. More details about this concept are discussed in the paper by Stosur5.
Some examples of IOR processes include:
• Water injection (for pressure maintenance and oil sweep)
• Immiscible gas injection (dry gas, carbon dioxide, nitrogen, alternating injection with water)
• Miscible flooding (carbon dioxide, nitrogen, hydrocarbon, solvent)
• Near-wellbore conformance (when it is applied to injectors in order to modify and improve the injection profiles)
• Chemical flooding
• Thermal recovery
• Well stimulation
• Microbial (MEOR)
These processes could be supported by additional technologies or activities aimed at well productivity improvement (which are not IOR processes), such as horizontal wells, infill drilling, artificial lift, hydraulic fracturing, etc.
Figure 1. Improved Oil Recovery and Enhanced Oil Recovery Definition
More than merely “any practice after primary recovery”, IOR means the sequential strategic and systematic combination of recovery processes to maximize the economic life and recovery factor of oil reservoirs. This sequence of recovery processes and technologies should be integrated into the field development plan, which represents the strategies oriented to reach the maximum recovery with the maximum profitability from the oil field (Figure 2). There are few publications with descriptions about the meaning of field development plans from the IOR perspective, but one comprehensive reference is the book written by Alvarado and Manrique, published in 20106.
Figure 2. Field Development Plan Scheme
At this point it is possible to introduce the connection between IOR, recovery factor (also called recovery efficiency), field development plan and reserves.
The PRMS defines reserves as “… those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.” In addition to this definition, it states that Contingent Resources are “…Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects but which are not currently considered to be commercially recoverable due to one or more contingencies… Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development”.
Regarding the classification of resources under the improved/enhanced recovery processes, the PRMS clearly specifies in section 2.3.4, Improved Recovery, the importance of the pilot test for classification of resources into reserves volumes: "The judgment on commerciality is based on pilot testing within the subject reservoir or by comparison to a reservoir with analogous rock and fluid properties and where a similar established improved recovery project has been successfully applied”. It is more specific in the following paragraph: “Incremental recoveries through improved recovery methods that have yet to be established through routine, commercially successful applications are included as Reserves only after a favorable production response from the subject reservoir from either (a) a representative pilot or (b) an installed program, where the response provides support for the analysis on which the project is based”. [Emphasis added]
These PRMS statements emphasize the importance of designing and implementing a representative pilot test to permit the movement of Contingent Resources to Reserves, or at least to narrow the range of uncertainty within the Contingent Resources class.
The PRMS defines a pilot as: “A small-scale test or trial operation that is used to assess the suitability of a method for commercial application.” This definition may be further expanded to say that a pilot is a field experiment in which the control and monitoring of input variables is less than in a laboratory-scale test but greater than in a conventional operation. It is a means to study the behavior of the overall response and recovery of a reservoir exposed to a given process. This response or behavior could then be extrapolated to a full field implementation to establish the technical and economic feasibility of the IOR process.
Because the PRMS is a set of principles, it does not provide any specific guidance for the design of pilots. Similarly, while the application guidelines7 document discusses the uses of pilots, there are no details on the criteria to be considered when designing and implementing a pilot.
Gaffney Cline & Associates (GCA) has seen many instances in which pilots fail to achieve their stated goals because of poor design. This short article summarizes some general recommendations based on past experience. The purpose is to emphasize the importance of investing appropriate resources in a sound design in order to achieve the desired objectives.
I. Design and Implementation of Pilot Tests for IOR Processes
1. Define the Objectives
Before beginning the design of the pilot, the objectives should be clearly defined. A pilot test should be designed to fulfill the purpose of gathering information about parameters or key variables that are considered important for understanding and modelling the process mechanism and performance and that will have an impact on both the technical recovery and economics. Some such factors are mentioned below:
• Microscopic displacement efficiency (ability to reduce residual oil saturation)
• Volumetric displacement efficiency (capacity for the displacing fluids to contact and mobilize the oil towards production wells)
• Interactions between the displacing fluid and the rock and reservoir fluids
• Ratio of injected to produced fluids
• Injectivity into the formation
• Recovery factor
• Operational issues
• Potential risks for full field implementation
• OPEX and CAPEX
2. Characterization of Pilot Area
Many times the failure of an IOR/EOR process implementation has been ascribed to the technology, but a deeper analysis shows that the main cause has been a misunderstanding of the geological and petrophysical complexities of the reservoir. Special attention should be given to a proper geo-technical description of the pilot area in order to build an accurate geological and fluid-dynamic model of the actual condition of reservoir to be evaluated. A proper understanding of the following reservoir characteristics is needed:
• Fluid contacts (gas-oil and oil-water)
• Barriers to flow such as faults or sedimentary features
• Areas of high permeability and preferential flow
• Pressures (bubble-point, initial, current)
• Description of the current state of fluid saturation in the reservoir
• Description of the physical and chemical conditions of the reservoir fluid (PVT, viscosity, composition of oil, water and gas, etc.)
• Continuity between injectors and producers
Inadequate knowledge of these factors will make it difficult or impossible to interpret the pilot’s results.
3. Location of Pilot Area
The pilot area should be “representative of the field”, implying a compromise between those more prolific and less favored areas, the first giving too optimistic results and the second potentially leading to failure of the process. As stated in the PRMS8, for an analog: “Analogous reservoirs are defined by features and characteristics including, but not limited to, approximate depth, pressure, temperature, reservoir drive mechanism, original fluid content, reservoir fluid gravity, reservoir size, gross thickness, pay thickness, net-to-gross ratio, lithology, heterogeneity, porosity, permeability, and development plan. Analogous reservoirs are formed by the same, or very similar, processes with regard to sedimentation, diagenesis, pressure, temperature, chemical and mechanical history, and structural deformation.” General guidance9 is that “reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.” Therefore, the pilot area needs to be representative of the area of the field to be subject to the IOR process (field scale project area) in order to allow a representative extrapolation of its results to the field scale project. Such extrapolation should take into account the difference in the levels of control and monitoring in the pilot versus those that will be implemented during the field scale project.
4. Observation wells
Execution of a pilot test is a compromise between the need for information in the shortest possible time and the representativeness of the results. As the injector-producer spacing is reduced, the lifetime of the test is condensed, which is positive in terms of data capture, but the volumetric efficiency could be increased resulting in higher recoveries than would be achievable with greater spacing in the full-field project, potentially leading to false optimism.
Observation wells provide important information in a relatively short time (months rather than years) and sometimes continuously (monitoring temperature, pressure or other parameters in real time), so they are commonly used in pilot testing of improved and enhanced recovery processes. They are usually positioned around 30% to 50% of the injector–producer distance for vertical wells in order to capture information on the movement of the front of the injected fluid, as showed in the example of Figure 3. However, the location and numbers of observers will depend on the injector-producer pattern architecture, and for this reason it is recommended to make use of numerical simulation tools to define optimal placement. The importance of proper characterization in the pilot area, as stressed before, becomes more important for proper location of observation wells. The completion of the observer wells could be different from the producers of the pattern; for example, the use of fiberglass as material for casing could be considered to allow electric logging.
Figure 3: Examples of Arrangements with Observation Wells
5. Operating Condition of wells
A defective producing well can have disastrous consequences on the rate of recovery. A defective injector well could yield an erroneous interpretation of injectivity and / or result in failure of the pilot test. For these reasons it is crucial to ensure proper operating condition of each of the wells before starting the pilot.
6. Baseline Establishment
It is imperative to establish with sufficient clarity a production base line before starting the process implementation in order to permit the subsequent interpretation of the test (many pilot tests fail in this point). There should be a production decline that can be extrapolated with some confidence; in other words, the behavior of the reservoir must be established just prior to the application of the process to minimize interpretation difficulties due to factors not considered as coming exclusively from the action of the process under study. Some items to consider are:
• Rates of production / injection
• Artificial lift systems
• Workovers or any other intervention in the wells under study
• Operational condition of surface facilities such as compressors, pumps, valves, etc.
In general, any alteration in the steady state of the system means complications in the eventual interpretation of pilot results.
7. Data Gathering
The operator should pay careful attention to the collection and analysis of all necessary data, as this is the ultimate goal of the test: reservoir pressures, temperatures, saturations, rates, chemical composition of produced and injected fluids, injection pressures, performance of facilities, core analysis, etc.
8. Analysis of Results and Scaling
To facilitate the interpretation and analysis of the results, the construction of a numerical simulation model of the pilot area is recommended. The model will be used to design the test and then must be adjusted according to the results for designing the field scale process. It is recommended to consider the following activities:
• Construction of a dynamic model of the pilot area
• Numerical evaluation of critical parameters
• Specifying ideal parameters for field testing
• Design of pilot
• Development of protocol for the pilot operation
• Development of monitoring protocol
Current numerical models are unable to predict with accuracy complex scenarios about fluid or rock-fluid interactions due to incompatibility effects such as minerals, asphaltene or paraffin precipitation, combustion reactions, heat losses, adsorption of injected chemicals like polymers, etc. This requires detailed analysis with multidisciplinary groups that integrate information from all sources: field studies, laboratory, pilot, etc. It is recommended to consider the following activities:
• Gathering and analysis of data obtained from the pilot (in real time)
• Calibration of the numerical model to pilot scale
• Economic evaluation of the expansion of the pilot
• Enumeration and classification of risk variables
• Setting a numerical model calibration and scaling the model for the commercial project.
Finally the design of a pilot test should provide some measure of "result scalability". This is feasible if certain conditions from the pilot test are met by the commercial scale:
• The fluid and reservoir properties and the values of the main variables are reasonably similar
• The behavior of production and fundamental variables during the pilot test should not differ significantly from those expected or predetermined, according to the tools of physical and mathematical modeling used to design the same. This will give some degree of confidence about the design of the commercial project using the same calibrated tools.
9. Economic Analysis
Economic analysis is critical for determining the commercial feasibility of the process under evaluation. It is necessary to identify the critical technical parameters that govern the profitability. A pilot test could end with the conclusion that, while the process can produce more oil, it will result in a negative cash flow. In that case the operator will avoid an expensive investment in the expansion of the process and will have the opportunity to look for other alternatives for increasing the production and hydrocarbon reserves.
Upon completion of the pilot test, most of the questions in relation to the technical and economic feasibility of the IOR process should have been addressed: a decision to proceed with a commercial project is based on favorable assessment of the process and its economic potential. Volumes associated with the commercial project can be classified from resources to reserves when the appropriate requirements have been satisfied, as noted in the PRMS in section 2.3.4:
“Improved oil recovery projects must meet the same reserves commerciality criteria as primary recovery projects. There should be an expectation that the project will be economic and that the entity has committed to implement the project in a reasonable time frame (generally within 5 years; further delay should be clearly justified”.
Later in the same section:
“These incremental recoveries in commercial projects are categorized into Proved, Probable, and Possible Reserves based on certainty derived from engineering analysis and analogous application in similar reservoirs”.
The pilot test becomes the analog for the rest of the field. However, since the parameters of the field will often differ from those in the pilot area, it is usually appropriate to assign a reasonably certain volume to Proved Reserves with some portion of the projected recovery being assigned to Probable and/or Possible Reserves.
II. References Recommended
For additional information about this topic, there are many technical articles with real cases and best practices for IOR/EOR pilot tests in the SPE (Society of Petroleum Engineers) literature. As an example, the author of this article was involved in an IOR team from PDVSA (Petroleos de Venezuela S. A.). This pilot was performed in the Maracaibo Lake area between the years 2000 and 2003 with the objective of investigating the feasibility to increase the recovery factor from mature offshore oil fields by applying the Water-Alternating-Gas (WAG) process (Figure 4). The design of the pilot test integrated most of the recommendations mentioned above. A reservoir study of the pilot area was carried out to build geological and numerical simulation models and integrate laboratory tests results. Preliminary runs were used to estimate the main parameters for the pilot test such as injection rates, WAG ratio (gas/water slug ratio), time of response, etc. After implementation of the pilot, every injection cycle was carefully monitored using the technology of chemical tracers for gas and water that allowed a better understanding of the efficiency of the studied process. Details of this test can be found in the following references:
• Alvarez C., Manrique E., Alvarado V., Saman A., Surguchev L. Eilertsen T. “WAG Pilot at VLE field and IOR opportunities for mature fields at Maracaibo Lake”. SPE 72099. SPE Asia Pacific Improved Oil Recovery. Malaysia. 2001.
• Hernandez C., Alvarez C., Saman A., De Jongh A., Audemard N. “Monitoring WAG Pilot at VLE Field Maracaibo Lake by Perfluorocarbon and Fluorined Benzoic Acid Tracers”. SPE-75259, 2002.
Figure 4: WAG Pilot Test in Lake Maracaibo (from SPE-72099).
An excellent example was published by Petroleum Development Oman (PDO) in 2014. The paper presents an oil reserves estimation methodology after a successful polymer flood pilot test. The authors address the issue of the incremental oil reserves attributed to the IOR process based on the PRMS definitions, calculation of patterns’ STOIIP (Stock Tank Oil Initially in Place) and range of recovery factors extrapolated from different sources (simulations, pilot, core floods and analytical analysis).
• F. S. Al-Saadi, H. A. Al-Subhi, H. Al-Siyabi, Petroleum Development Oman. “Recovery Factor Estimation in EOR Polymer flood Project: Field Case”. SPE-169694-MS, 2014
About the issue of data gathering for a pilot test, the paper prepared by the Kuwait Oil Company and published by the SPE in 2016 is a good reference. The work describes the surveillance of the main parameters like temperature, pressure, saturation etc., for a Cyclic Steam Stimulation process (CSS) pilot in a heavy oil reservoir in Kuwait. The tools and methodology implemented are thoroughly described together with a comprehensive explanation of the test.
• Shaikha Al-Ballam, Hussain Al-Dashti, Dharmesh C. Pandey, Abdulla Al-Ballan and Wleed K. Al-Khamees, Kuwait Oil Company (KOC). “Well Surveillance Operation and Data Analysis in Thermal Viscous Crude Project in Kuwait-A Case Study. SPE-179058-MS, 2016.
It is important to mention three notable SPE publications dealing with good pilot design (With which this article has been sustained):
• G.F. Teletzke, R.C. Wattenbarger and J.R. Wilkinson, “Enhanced Oil Recovery Pilot Testing Best Practices”, SPE 118055, 2008.
• B.L. Adibhatla, R. C. Wattenbarger, “Staged Design of and EOR Pilot”, SPE IPTC 13346, 2008.
• Hoffman B. Todd and John G. Evans. “Improved Oil Recovery IOR Pilot Projects in the Bakken Formation”. SPE-180270-MS.
This last recommended reference (Todd and Evans) it is one of the most recent and interesting SPE papers about pilot tests in unconventional reservoirs. The authors summarize and analyze the results from IOR pilot tests performed in the Bakken in the course of the last eight years and additionally present methodologies for implementing future tests. At present the implementation of IOR processes in unconventional reservoirs is in a very early stage, but has the potential to recover substantial additional volumes of oil from mature unconventional reservoirs. The paper presented by Tovar et al represents a good example of recent experimental efforts focused on this area:
• Francisco D. Tovar, Øyvind Eide, Arne Graue and David S. Schechter “Experimental Investigation in Enhanced Recovery in Unconventional Liquid Reservoirs using CO2: A Look Ahead to the Future of Unconventional EOR”. SPE-169022-MS. 2014.
All these articles can be found at the OnePetro library: www.onepetro.org
The author appreciates the support received from GCA staff specialists in the preparation of this article: Rawdon Seager, Robert George, Alberto Finol and Ian Dunderdale.
 Alain Labastie. “Increasing Recovery Factors: A Necessity”. JPT August 2011 SEC “Modernization of Oil and Gas Reporting”, 210.4-10 (a) (2).
 B. Todd Hoffman “Comparison of Various Gases for Enhanced Recovery from Shale Oil Reservoirs”. SPE-154329. 2012
 2007: SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS)
 Weghorn R., Quintero L. EOR Internal Webinar”. Baker Hughes Incorporated, August, 2013
 Stosur G. “The Alphabet Soup of IOR, EOR and AOR: Effective Communication Requires a Definition of Terms”. SPE-84908. 2003.
 Alvarado V., Manrique E. “Enhanced Oil Recovery: Field Planning and Development Strategies”. Editorial ELSEVIER, 2010
 2011: SPE/WPC/AAPG/SPEE/SEG Guidelines for Application of PRMS
 Chapter 4.
 SEC “Modernization of Oil and Gas Reporting”, 210.4-10 (a) (2).
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