SPE 118055

Enhanced Oil Recovery Pilot Testing Best Practices G.F. Teletzke, R.C. Wattenbarger, and J.R. Wilkinson, SPE, ExxonMobil Upstream Research Company

Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 3–6 November 2008. 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 Enhanced oil recovery (EOR) implementation is complex and successful applications need to be tailored to each specific reservoir. Therefore, a systematic, staged evaluation and development process is required to screen, evaluate, pilot test, and apply EOR processes for particular applications. Pilot testing can play a key role in this process. Prior to field testing, pilot objectives need to be clearly defined and well spacing, pattern configuration, and injectant volumes determined. This paper outlines a staged approach to EOR development and focuses specifically on pilot testing best practices. These best practices were derived from ExxonMobil’s extensive piloting experience, which includes over 50 field pilot tests covering the full range of enhanced oil recovery processes. Topics covered include: 1) determining whether a pilot is needed and defining pilot objectives, 2) considerations for successful pilot design, 3) types of pilots and their advantages and disadvantages, 4) tools and techniques for assessment of key reservoir mechanisms, and 5) minimizing uncertainty in pilot interpretation. Key issues that are often addressed by pilots are discussed, including areal sweep and conformance, gravity override, viscous fingering, and loss of mobility control. Also included are aspects of instrumentation and measurements in pilot injection, production, and monitoring wells. Several ExxonMobil piloting examples are used to illustrate the best practices, including a single-well injectivity test, an unconfined pilot with observation wells, a small-scale confined pilot, and a large-scale multi-pattern pilot.

Staged Process for EOR Project Evaluation and Development The complexity and cost of EOR requires a disciplined work process for project evaluation, design, and implementation. To put pilot testing best practices in perspective, Figure 1 outlines a staged workflow that ExxonMobil has used for evaluation and design of EOR projects. The role of field tests and pilots in this process is highlighted in the yellow box.

EOR evaluation starts with screening-level data collection, candidate process selection, injectant source identification, and screening economics. If these are favorable, design and implementation of an EOR project then requires in-depth analysis of the most promising processes. In addition to standard laboratory tests, specialized fluid characterization and reservoir-conditions coreflood tests using in-situ fluids and a range of injectants are performed to customize a process for each reservoir. Reservoir characterization studies are conducted concurrently to identify the key geologic controls on field-scale sweep efficiency. The laboratory experiments and reservoir characterization studies are then used as input to geologic and dynamic reservoir simulation modeling of the process at various scales to evaluate options, define a preferred process design, and provide input to screening-level development and facilities planning. If anticipated rates, recoveries, and economics are favorable, pilot testing in the target field is often undertaken to resolve uncertainties and fine-tune operational and execution details. Additional laboratory, reservoir characterization, and simulation work may be undertaken after pilot testing to further resolve uncertainties, as indicated by the feedback loop in Figure 1. If the technical and commercial outlook is still positive, this is then followed by commercial scale implementation. Stakeholder reviews, indicated by stars, are held after each stage of this process. Additional detail on the staged evaluation process, as applied to polymer flooding, is provided by Kaminski et al. (2007) Pilot Objectives Defining clear pilot objectives is the first step in designing and executing a successful pilot. Pilots are conducted to address key technical and business uncertainties and risks associated with applying an EOR technology in a specific field. The benefits of piloting, however, need to be weighed against the time and expense of piloting and against other available alternatives. Conducting a pilot is one of several options for reducing risk that might include additional data gathering/appraisal or phased development. If there are better alternatives to address uncertainty and risk, then a pilot may not be required. Clearly stating the key uncertainties and pilot objectives early in the evaluation process helps determine if a pilot is the best approach for addressing these risks and help guide pilot design and execution.

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Care should be taken when developing pilot objectives to ensure that the pilot is appropriately used as a component of an overall long-term field development strategy. Pilots should not be a “trial and error” test of various field recovery processes; rather they are selectively applied to field test recovery processes that have been technically and economically evaluated beforehand. Additionally, the recovery process to be field tested should be optimized through both laboratory and reservoir simulation studies in order to maximize oil recovery at the lowest possible cost. Prior to field testing, the most appropriate well spacing, pattern configuration, length and orientation of wells, injectant, and injection strategy (e.g, continuous gas injection, WAG, SWAG, etc.) should be defined. Pilots are not run simply to gain experience with application of technology, although training of operators may be an important component of the pilot testing program. With these comments in mind, specific piloting objectives may include the following:

• Evaluate the EOR process recovery efficiency in the field of interest

• Assess effects of reservoir geology on process performance, particularly sweep efficiency

• Improve field production forecasts to reduce technical and economic risk

• Obtain data to calibrate reservoir simulation models for full-field predictions

• Identify operational issues and concerns for full-field development

• Assess the effect of development options on recovery, e.g., well spacing, processing rate, and completion strategy

• Guide improvements in current operating strategy to improve economics/recovery Considerations for Successful Pilot Design Once pilot objectives have been clearly defined, sufficient time and effort need to be expended in designing a pilot to ensure that the pilot objectives can be achieved. Time spent up front in pilot design and optimization usually leads to earlier full-field implementation. Poorly designed pilots could potentially lead to the wrong conclusion or even to no conclusions at all. A poorly designed and executed pilot may lead to incorrectly condemning an appropriate EOR process or incorrectly promoting an inappropriate EOR process; both of which will result in sub-optimal field development. By their nature, pilots are a scaled-down version of the full commercial implementation of an EOR process. This scaling-down is done to reduce key uncertainties for decision making in as timely and cost-effective manner as possible. When designing a pilot, care should be taken to both understand and minimize the impact of the scaled-down nature of the pilot. Reduced well spacing, judicious placement of observation wells, and elevated injection rates are techniques that have been used to provide information on process recovery performance in a reasonable time frame. However, it is important that the pilot be designed to be scalable to the conditions for full-field application. Pattern configuration, well design, the chosen injectant, and process operations should allow for confidence in scale-up to the field-wide implementation of the process. Finally, the pilot location should be chosen to ensure as much as possible that it can be well characterized and is representative of the broader EOR target. Reservoir simulation and geologic modeling, which incorporate the best available reservoir description and are history-matched to pilot performance, are the effective tools for designing and interpreting pilot performance and translating that performance to field-scale predictions. A properly designed pilot should ensure that the pilot area is sufficiently characterized and sufficient pilot data are collected to underpin reservoir modeling. Without proper pilot design, however, reliable data for history matching field performance will not be gathered, and therefore confident assessment of field-scale performance will be at risk. EOR pilots should typically be designed to provide insight on both the local displacement efficiency of the injectant at the pore scale and volumetric sweep efficiency at the reservoir scale. A frequent challenge is to obtain a volumetric sweep efficiency that adequately captures the improved local displacement efficiency observed in the laboratory. With these comments in mind, the following are the requirements for a successful pilot test: • Pilot objectives should be clearly defined in advance. The key questions to be answered before doing a pilot are: 1) what

results are needed to facilitate full-field investment and operating decisions, and 2) when are results needed? • The pilot should be designed and operated to meet the objectives, aided by a predictive reservoir simulation model. The

pilot should be able to distinguish between local reservoir/well effects and general process mechanisms. • Available reservoir characterization information should be reviewed to define key geologic factors that may affect

injectivity and sweep efficiency and to identify a pilot site having representative geology. Additional geologic studies may be required in advance of the pilot to define the reservoir description to a sufficient level of accuracy.

• A surveillance and monitoring plan should be developed that ensure that data are of high quality and that all needed data are obtained on a timely schedule. Data should be gathered on operational factors such as downtime and backpressure.

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• The pilot should be designed and operated to ensure that it is interpretable. It is important that surrounding operations do not affect pilot results. In addition, high-integrity well completions are essential to understand and control sweep efficiency in the reservoir. Finally, a reliable injectant supply is required.

Types of Pilots and Their Advantages and Disadvantages Before discussing the types of pilots, it is important to clarify the distinction between “data gathering”, “pilot” and “phased implementation.” The following is offered as a simple distinction: • Data Gathering: The primary purpose of data gathering is to collect field data to address specific key uncertainties that

could have significant impact on a business decision. Example: If injectivity is a key uncertainty in assessing feasibility of a waterflood, then conduct a field test(s) to measure injectivity under a defined set of conditions.

• Pilot: The primary purpose is to validate the performance of a particular EOR process in the field. Example: Laboratory tests and simulation studies indicate that a CO2 WAG project is likely to yield the highest recovery and best overall economic value among recovery processes considered. Before making a huge investment required for a large-scale application, a pilot is conducted at a well spacing scalable to that expected for full-scale application.

• Phased Implementation: The primary purpose is to manage uncertainty by implementing a project in phases with appropriate adjustments in scope and optimization of design between phases. Example: A new reservoir development with limited injectant supply planned as phased development with the scope of the second phase (wells, facilities, recovery process, etc.) adjusted to incorporate learnings from the first phase.

With these definitions in mind, the types of pilots can be grouped into four configurations: 1. Non-producing pilot, 2. Small-scale unconfined pilot, 3. Small-scale confined pilot, 4. Multi-pattern producing pilot. While each pilot configuration has its place and purpose, it is generally true that a more complex, and therefore more costly, configuration will yield more data and be easier to scale up to commercial conditions. Therefore, a balance must be struck between the risks of a commercial project and the cost of insurance provided by data from a pilot. Figure 2 illustrates factors that should be considered when selecting pilot type and scale. Two extreme cases are shown. In the first case, the recovery process is well understood because it has been proven commercially in other fields, the reservoir is well understood because there is a nearby analog or existing application in the same field, and there is low economic and injectant supply risk. In this case, commercial application without pilot testing may be considered, with some additional data gathering or phased implementation to manage risk, as discussed above. In the second case, the recovery process is untested, the reservoir is complex or not understood, and there is significant economic and injectant supply risk. In this case, small-scale pilots, followed by a larger commercial demonstration pilot, are frequently used to manage risk prior to commercial application. Cleary, a range of alternatives between the two extreme cases are possible. The following is a discussion of pilot designs that have been used to gather the necessary performance data to make commercial-scale implementation decisions, particularly for gas injection and water-alternating-gas (WAG) processes. Both producing and non-producing pilot designs have been used successfully. Figure 3 summarizes the non-producing configurations. Non-Producing Pilots The simplest design is a single-well injectivity test to determine the ease at which gas can be injected into the formation and to evaluate injectivity losses resulting from water-alternating gas processes. By adding an observation well, the vertical sweep and the local displacement efficiency of the gas at the observer location can be determined. Addition of a second observer permits the assessment of the vertical sweep over the distance separating the two observers. The locations of the observation wells will need to account for both reservoir heterogeneities and near-well pressure gradients (drift) that may result in the injected fluids moving away from rather than towards the observation wells. As gas injectants are frequently less dense than the in situ oil, observation wells will provide valuable information on gravity override that may lead to poor sweep efficiency. One key to successful gas flooding processes is achieving high volumetric sweep efficiency. Placement of multiple observers around the injector permits an assessment of not only the vertical sweep efficiency at the injectors but also the areal sweep efficiency. The product of the vertical and areal sweep efficiencies gives an estimate of the volumetric sweep efficiency for the pattern. Figure 4 summarizes the advantages and disadvantages of non-producing pilots. This type of pilot may be useful for providing quick and inexpensive estimates of injectivity and vertical sweep efficiency, but does not provide quantitative data on overall volumetric sweep efficiency and ultimate recovery efficiency. In addition, it provides no operational experience with handling and recycling produced fluids and is extremely sensitive to fluid drift.

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Producing Pilots Pilots that incorporate production wells, otherwise known as "oil-in-the-tank" pilots, provide the most direct data on oil recovery, fluid transport through the reservoir, and pressure drop between injectors and producers. Important factors to consider when designing and interpreting producing pilots include: • Drift: is the pattern acting as a truly confined flow system? • Balance: are the relative rates of injectors and producers allocated to maximize areal sweep efficiency in the pilot area? • Isolation: is the zone taking injection the only zone that is producing? The cost of running a pilot that is truly confined, balanced, and isolated may be considerable since offset production may need to be curtailed. This is especially important in systems with gas or light oil where pressure gradients across the pilot site may result in significant fluid flux that will compromise pilot interpretation. A compromise may have to be struck between the best possible data and a situation that can be simulated later with reasonable confidence. Another opportunity provided by a producing pilot is the experience with separation and handling of produced fluids. Small-scale facilities can be constructed, and easily modified, to gain experience with separation and recycling of fluids. If the pilot is successful, then the experience gained with facilities design will translate into cost savings associated with construction of the commercial facilities. Observation wells provide a means of monitoring fluid movement at various points intermediate to the injector and producer. Valuable information on conformance, fluid transport in the reservoir, and fluid mobilities can be gained from observation wells. Methods for data acquisition from observation wells typically include logging, sampling, and pressure measurements. Figure 5 summarizes some representative producing pilot configurations. Producing pilots provide not only an understanding of the injectivity of fluids into the formation, but more importantly, some quantitative data on the production potential of the recovery process, and subsequently a rough estimate of oil recovery. Single, inverted five-spot patterns are often used to provide such information. Observation wells are often included to evaluate the vertical sweep and displacement efficiency at the observers, vertical and areal sweep at a distance, fluid mobilities within the formation, and to estimate oil recovery.

As indicated in Figure 6, although unconfined producing pilots can provide some production experience rapidly and at relatively low cost, the swept volume can be difficult to evaluate and performance may not be representative of a repeated pattern and difficult to scale. In addition, they are sensitive to fluid drift and can take as long to run as a true pattern flood.

Better recovery estimates can be obtained by using a single, normal five-spot pattern. In this design, water or gas is injected at the four corners of the pattern to provide confinement of the oil within the pattern, and therefore improved estimates of recovery compared to an unconfined pattern. To reduce pilot duration, confined pilots are typically run at a closer well spacing than planned for commercial application. Advantages and disadvantages of such small-scale confined pilots are summarized in Figure 7. This type of pilot can provide good estimates of oil displacement and, when coupled with the use of observation wells, vertical sweep efficiency as a function of distance from the injection well at modest cost. In addition, detailed data on pressure gradients, fluid mobilities, and fluid transport can be obtained that enable rigorous calibration of simulation models. However, the small size of the pattern may not sample representative heterogeneities, reflect the balance of a repeated pattern flood, scale to wider well spacings, or indicate long-term problems. For improved confidence in scaling pilot results to potential full-field applications, repeated, inverted five-spot patterns have sometimes been used. This arrangement provides the best estimates of oil recovery and sweep efficiency, the best data for calibrating simulation models, and the most direct scale-up to commercial operations. However, this type of pilot will have the longest duration and will require extensive evaluation time. Naturally, piloting costs increase with the number of patterns placed on test. Advantages and disadvantages of large-scale, multipattern pilots are summarized in Figure 8.

Assessment of Key Reservoir Mechanisms The specific tools used to assess key reservoir mechanisms will depend on the EOR process being pilot tested. For illustrative purposes, this section will focus on the key reservoir mechanisms associated with gas injection EOR. Figure 9 summarizes three significant problems can arise in horizontal gas injection and water-alternating-gas (WAG) EOR projects (Healy et al. 1994). This figure focuses on problems associated with horizontal floods as these make up the majority of gas injection EOR pilots that have been conducted to date. First, in some situations, it may not be possible to inject water and gas at the desired rates. Reservoir variables that control injectivity are effective permeabilities and near-wellbore damage. Water injectivity has been a problem in some floods, especially in low-permeability reservoirs. If injectivity is a potential problem, it can be evaluated in the design phase through careful laboratory measurements, and by conducting pilot injectivity tests. A second problem is that gas can channel through high-permeability “thief” zones, leading to poorer-than-expected sweep efficiency. Channeling is controlled by permeability distribution. Gas channeling can be evaluated in the design phase by doing thorough geological and reservoir description studies along with small-scale reservoir simulation studies that properly

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account for the governing geologic heterogeneities. Also, the sweep experienced in a prior waterflood will provide a strong indication of the degree of channeling to be expected in a gas injection project. Thus, an accurate reservoir description combined with history matching prior waterflood performance can help evaluate the potential for channeling in the gas flood. The final potential problem is that gas, which is usually less dense than oil or water, can gravity override or flow to the top of a reservoir unit as it moves away from injection wells. When this occurs, it will sweep only the very top portion of the zone. Gas override is highly sensitive to vertical permeability as well as the lateral extent of barriers to vertical flow. Again, geological and reservoir description studies and perhaps pilot tests can help to identify conformance problems and thus avoid a surprise. Because gravity override is sensitive to the viscous-to-gravity ratio (VGR), it is important to operate a gas injection or WAG pilot at water and gas throughput rates and well spacing that result in a VGR comparable to that which could be achieved in a commercial-scale project (Stone 1982, Jenkins 1984).

As indicated previously, the key mechanisms to be assessed during pilot testing of gas injection processes include injectivity, gravity override, channeling, viscous fingering, and areal sweep. Figure 10 summarizes the data needed for interpretation of each mechanism and monitoring tools and techniques that can be used to acquire the required data. Understanding injectivity changes requires measurement of not only the injectivity index, but also the permeability distribution and fluid mobilities near the injection well. Frequent measurements of injection rates and bottom-hole pressures are used to provide high-resolution injectivity data. Flow profiles, fall-off tests, and step-rate tests have been used to characterize the near-well permeability distribution and fluid mobilities. Permanent downhole monitoring tools are now being used routinely to obtain high-resolution real-time temperature and pressure data. To properly assess gravity override, the change in oil saturation with depth and distance behind the passing gas displacement front and the effective pattern vertical permeability are needed. Time-lapse logging, coring behind the flood front, and either vertical or cross-layer pulse tests have been used to provide this information. Cased-hole logging tools used for time-lapse logging include nuclear logs (steel and non-metallic casing) for gas saturation and total porosity and induction logs (non-metallic casing) for water saturation. Fitz and Ganapathy (1993) provide an example of quantitative monitoring of fluid saturation changes during a gas injection EOR project. Post-flood core wells have been used to measure vertical conformance and remaining oil saturation. In some cases, spot fluid samples for composition have been collected at observation wells, but usually after critical log data have been obtained. Channeling and loss of mobility control or viscous fingering are the other key mechanisms affecting sweep efficiency. In addition to assessing the change in oil saturation behind the flood front, the GOR and water cut behavior of producers over time, inter-well tracers (radioactive or chemical), and pressure surveys are commonly used to estimate the degree of channeling and viscous fingering. Careful and regular sampling of produced fluids, flowing and static bottomhole pressure surveys, and time-lapse logging are available techniques for acquiring such data. Lastly, flood conformance or areal sweep is needed to compliment the channeling and gravity override data and determine the volumetric sweep efficiency within the pattern. Swept pore volume can be determined by carefully tracking the movement and breakthrough of tracers at production wells and keeping accurate records of oil, water, and gas production Pilot Interpretation Successful pilot interpretation requires advance planning. It is essential that a detailed reservoir simulation model of the pilot area (with appropriate boundary conditions) be built in advance to optimize the pilot design and monitoring program, anticipate data needed for history matching the pilot, enable timely interpretation of pilot, and to assess the need for selective use of additional observation wells and post-flood coring. The geology of pilot area and a good understanding of the target oil distribution are critical inputs to the simulation model. Pilot wells should be cored and logged, if at all possible. Core, log, and pressure transient data should be integrated into a consistent reservoir description. The following pilot design and operational best practices help to minimize uncertainties in test interpretation and facilitate history matching of pilot results: • Production facilities, well completions, tubulars, and artificial lift should be representative of the anticipated commercial-

scale development. • Several good base-line logs and possibly a single-well tracer test should be run in wells before the test begins and at

regular time intervals to verify reproducibility of the log measurements and ensure accurate determination of saturation changes during time-lapse logging at observation wells. Having logging tools dedicated to the project also helps to ensure reproducibility.

• An adequate period of steady baseline injection and production should be achieved prior to initiating the EOR process. This will reduce uncertainty in interpretation of injectivity, saturation changes, and incremental oil production

• Fluid drift should be minimized so that pilot area acts as a truly confined system. This can be accomplished by regulating rates in the surrounding patterns or locating the pilot in an area without strong pressure gradients.

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• The relative rates of injectors and producers should be allocated to maintain pattern balance and maximize areal sweep efficiency in the pilot area.

• Steady and uninterrupted injection and production rates should be maintained. This is important to maintain the desired VGR, maintain pattern balance, and minimize the effects of external influences.

• Injection and production zones should be isolated so that only the targeted production zone is taking injection. • An adequate volume of EOR fluid should be injected to reduce uncertainty in interpretation of sweep efficiency,

saturation changes and incremental oil production. Experience indicates that the volume of EOR fluid injected needs to be at least 20% of the pattern hydrocarbon pore volume before the pilot can be adequately interpreted.

• The original pilot operating and monitoring plan should be continued until sufficient data are acquired to validate simulation models; do not attempt to optimize based on early results.

Assessing incremental oil recovery over waterflood should be a key objective of a pilot. This can be accomplished in several ways, each of which has advantages and disadvantages: • In cases where the waterflood is very mature (>90% water cut), an increase in oil cut can provide a direct measure of

improved recovery. A disadvantage is that this may delay the pilot or the waterflood may only contact part of the target zone.

• In cases where the waterflood is less mature, the baseline waterflood recovery can be estimated by using a reservoir simulation model to history match the pilot area and extrapolate the pre-pilot waterflood production trend. This requires an adequate pre-pilot waterflood period to reduce uncertainty in the history match and extrapolation.

Pilot Examples The best practices described above were derived from ExxonMobil’s extensive piloting experience, which includes over 50 field pilot tests covering the full range of enhanced oil recovery processes. Table 1 is a list of representative ExxonMobil pilot tests that have previously been described in the open literature. Four ExxonMobil pilot tests are used below to illustrate 1) definition of pilot objectives, 2) design of pilots to meet the objectives, 3) tools and techniques for assessment of key reservoir mechanisms, and 4) integrated interpretation of pilot data aided by reservoir simulation. Single-Well Injectivity Test This example is a low permeability sandstone reservoir located in Wyoming, USA. Average reservoir permeability is 6.6 md, average formation thickness is 50 ft, and the reservoir is being waterflooded on a vertical well spacing of 80 acres. The concern was that injectivity would be low during miscible CO2 WAG injection. Therefore, an injectivity test was done to determine injectivity before, during, and after CO2 injection and to estimate field-scale injectivity to assist prediction of miscible process performance. The test consisted of three months of baseline water injection followed by two months of CO2 injection before returning the well to water injection. The radius of investigation of the test was approximately 100 ft. Bottomhole injection pressures and surface injection rates were monitored continuously during the test to determine injectivity index changes during injection of water and CO2. Pressure fall-off tests were done and injection flow profiles were measured during both the baseline water injection and CO2 injection to characterize the permeability distribution and changes in fluid mobilities in the near-well region. Step-rate tests were also done to confirm that the formation was not fractured.

The results of the test were used to calibrate a radial simulation model of the near-well region. Results of the radial model were used to guide the construction of a full-field simulation model, which was then used to evaluate WAG injection process options.

Unconfined Pilot with Observation Wells Evidence of gravity segregation between water and an enriched hydrocarbon gas was observed in a tertiary horizontal miscible WAG flood at the Judy Creek Beaverhill Lake ‘A’ Pool. The gas override resulted in bypassing of potential miscible reserves and decreased ultimate oil recovery. An unconfined producing pilot was undertaken by Imperial Oil Resources, a majority indirectly owned affiliate of ExxonMobil, to verify the existence and extent of gravity override, quantify the factors affecting vertical sweep efficiency, identify optimum well spacing and pattern size, and determine residual oil saturations to water and enriched hydrocarbon gas (Pritchard et al. 1990). Results of the pilot were used to calibrate a mechanistic reservoir simulation model, which was subsequently used to guide optimization of pattern configuration and WAG operating strategies (Pritchard and Neiman 1992). The field is a limestone reef reservoir located about 200 km northwest of Edmonton, Alberta, Canada. Its average horizontal permeability is 43 md and average thickness is 68 ft. Gravity override was a concern because the reservoir has good vertical permeability. The pilot was situated in a location that 1) was representative of the reef margin facies that was the primary target of the hydrocarbon miscible flood, 2) would ensure an interpretable pilot, and 3) would be an economic venture on its own by accessing unswept reservoir.

The pilot pattern configuration is shown in Figure 11. The test consisted of six months of baseline water injection followed by one year of WAG injection with enriched hydrocarbon gas at a volumetric WAG ratio of 1.0. This WAG ratio was

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accomplished by one week of enriched hydrocarbon gas injection at an average rate of 2000 reservoir m3/day followed by three weeks of water injection at an average rate of 660 reservoir m3/day. These rates were chosen to achieve the same VGR as the planned commercial operation. The gas was injected at a higher rate than the water to maximize vertical sweep at the injector and be representative of the vertical injection profile of a commercial operation. A lower water injection rate was used to reduce the total average fluid rate and thus achieve the target VGR. The monitoring program included: • Induction resistivity and neutron logging to determine oil, water, and gas saturation changes at a fiberglass-cased

observation well (Georgi et al. 1991). The observation well was placed within the expected WAG commingled zone based on pre-pilot reservoir simulation modeling. The location was chosen so to confirm the expected size and shape of the WAG commingled zone (Figure 12).

• Production and injection profile logs for monitoring changes in fluid production rates and fluid entry horizons. These consisted of a suite of spinner, density, capacitance, and temperature tools.

• Water and solvent tracer for defining the areal distribution of injected water and gas. A gas-phase tracer (sulfur hexafluoride) and liquid phase tracer (tritiated toluene) were used to monitor fluid movement.

Conclusions of the pilot, based on an integrated interpretation of the monitoring data, were that 1) a definite oil bank was formed by the miscible process, 2) gravity override was consistent with the simulation model predictions, and 3) a reduction in pattern size would improve sweep efficiency and ultimate oil recovery. The calibrated simulation model was used to define an optimized injection strategy comprising: 1) injection of an initial high-rate bank of the enriched gas prior to WAG injection, 2) tapering the WAG ratio, 3) proper timing of lean chase gas injection, and 4) tailoring of WAG cycle length and bank size to pattern geology. Small-Scale Confined Pilot The initial pilot of the solids-stabilized emulsion (SSE) heavy oil recovery process developed by ExxonMobil was conducted at the Celtic field in Saskatchewan, Canada. The SSE process involves the generation and injection of solids-stabilized water-in-oil emulsion to more favorably displace viscous oils (Kaminsky and Wattenbarger 2008). After several years of laboratory and theoretical development, the SSE recovery process was deemed ready for piloting in the field. The objectives of the pilot were (1) to gain operational experience with the SSE process, (2) to confirm the ability to generate and inject a solids-stabilized emulsion in the field, (3) to confirm the in situ stability of the injectant, and (4) to confirm improved reservoir displacement. After review of several potential pilot locations, the Celtic field was chosen because its reservoir characteristics matched the desirable target characteristics for the SSE process, it had existing infrastructure, and it was well-characterized with historic performance data.

The Celtic SSE pilot was designed as an isolated five-spot pattern with four corner injection wells, a central producing well, and three observation wells (see Figure 13). Use of a full, isolated pattern minimized interference with existing operations and ensured that oil recovery during the pilot came from within the pilot pattern. Initial characterization of the pilot included: logging, coring, extensive coreflood analysis, a new method to measure steady-state relative permeabilities for heavy oil systems, fluid characterization, geologic modeling, and reservoir simulation. Initial reservoir modeling studies were conducted prior to the pilot to confirm that the chosen well spacing and three-year piloting period would be sufficient to gather necessary injection, production, and observation-well data to meet pilot objectives. Falloff tests were conducted periodically to further characterize the pilot area and to evaluate changes in well injectivity. The reservoir surveillance program included: close monitoring of injection and production rates, continuous measurement of bottomhole pressures and temperatures, producer sampling and analysis, tracers, and observation well logging. Fiber-optic sensors were placed in each of the observation wells to measure pressure response. Temperature logs were run in the observation wells on a routine basis to help detect the arrival of the slightly heated injected fluid. Carbon-oxygen and induction logs were run less frequently to detect changes in fluid saturation. Water-phase and injector-specific oil-phase tracers were added to the injected fluid to help track the movement of the injected fluids and to aid in the determination of in situ stability. Regular sampling and an in-line viscometer was used to control the quality of the injectant. These quality controls were helpful in identifying and correcting initial start-up problems with injectant preparation. At the end of the three-year pilot, a post-flood well was drilled to take core from the swept region of the flood. The ability to generate and inject solids-stabilized emulsion in the field was demonstrated early on in the pilot. Integrated analysis of the post-flood core-well results and extensive surveillance data allowed estimation of the in situ stability of the injectant and displacement performance, which were found to be consistent with prior laboratory corefloods and performance estimates.

Large-Scale Multi-pattern Pilot The first pilot of the liquid-assisted steam enhanced recovery (LASER) process was tested in the H22 pad of the Cold Lake field in Alberta, Canada (Leaute 2002, Leaute and Carey 2005). The LASER process, developed by Imperial Oil, involves the addition of an intermediate hydrocarbon solvent to steam injected in later cycles of cyclic steam stimulation (CSS) operation. Laboratory physical models, theoretical analysis, and reservoir simulations provided the confidence to test this novel recovery concept in the field.

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The primary objectives of the LASER pilot were to validate the improvement in cycle bitumen recovery over the base CSS process and to determine the amount of solvent recovery. Due to the variability in CSS well performance, both between wells and in individual wells over time, a large-scale multi-pattern pilot design was chosen. In this design, LASER was applied to several wells in the H22 pad and its performance was compared to that of a neighboring control pad (H21), where CSS was applied without the addition of solvent. The H22 and H21 pads were chosen for the pilot and control because they had nearly identical pad-level performance through the first six cycles of CSS and because their performance and reservoir characteristics were representative of future LASER targets (see Figure 14). Starting in 2000, solvent was introduced in the seventh and eight cycles into eight wells of the H22 pad, with extensive well-level and pad-level analysis of injection and production data. Frequent sampling, in-line measurement, and analysis of produced well streams allowed for accurate determination of the solvent production. A key element of the sampling protocol was to measure the solvent in both produced liquid and vapor streams. Statistical analysis along with reservoir simulation and history-matching were used to estimate improvements in cycle bitumen recovery, confirm understanding of the process, and estimate performance in future cycles and in commercial application.

Summary A staged approach to EOR development focusing specifically on pilot testing best practices has been outlined. Topics covered include: 1) factors to consider when determining whether a pilot is needed and defining pilot objectives, 2) requirements for a successful pilot, 3) types of pilots and their advantages and disadvantages, 4) tools and techniques for assessment of key reservoir mechanisms, and 5) minimizing uncertainty in pilot interpretation. Application of these best practices enables the acquisition of accurate and definitive test data to 1) assess effects of reservoir geology on process performance, particularly sweep efficiency, 2) calibrate reservoir simulation models for full-field predictions, 3) improve field production forecasts, 4) reduce technical and economic risk, and 5) guide improvements in current operating strategy to improve economics/recovery. Several ExxonMobil pilot tests were used to illustrate the best practices and the role of pilots in the staged EOR development planning process. The case histories included a single-well injectivity test, an unconfined pilot with observation wells, a small-scale confined pilot, and a large-scale multi-pattern pilot. Nomenclature CSS = Cyclic Steam Stimulation EOR = Enhanced Oil Recovery LASER = Liquid-Assisted Steam Enhanced Recovery OSR = Oil/Steam Ratio SSE = Solid-Stabilized Emulsion SWAG = Simultaneous Water and Gas WAG = Water Alternating Gas Exxon Mobil Corporation has numerous subsidiaries, many with names that include ExxonMobil, Exxon, Esso and Mobil. For convenience and simplicity in this paper, the parent company and its subsidiaries may be referenced separately or collectively as "ExxonMobil." Abbreviated references describing global or regional operational organizations and global or regional business lines are also sometimes used for convenience and simplicity. Nothing in this paper is intended to override the corporate separateness of these separate legal entities. Working relationships discussed in this paper do not necessarily represent a reporting connection, but may reflect a functional guidance, stewardship, or service relationship Acknowledgement The authors would like to thank ExxonMobil Management for their support and permission to publish this paper. In addition, the authors would also like to thank the many current and former employees of ExxonMobil and its affiliates who have contributed to the development of the pilot testing best practices described in this paper. References Bragg, J.R., Gale, W.W., McElhannon Jr., W.A., Davenport, O.W., Petrichuk, M.D., Ashcraft, T.L. 1982. Loudon Surfactant Flood Pilot Test. SPE 10862 presented at SPE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 4-7 April. Bragg, J.R., Gale, W.W., and Canning, J.W. 1983. Loudon Surfactant Flood Pilot -- Overview and Update. SPE 11505 presented at Middle East Oil Technical Conference and Exhibition, Bahrain, 14-17 March. Buckles, R.S. 1979. Steam Stimulation Heavy Oil Recovery at Cold Lake, Alberta. SPE 7994 presented at SPE California Regional Meeting, Ventura, California, 18-20 April 1979. Choquette, S. P., Sampath, K., Northrop, P. S., Edwards, J. T., Laali, H., Rowland, B., Morrow, D. 1991. Esperson Dome Oxygen Combustion Pilot Postburn Coring Results. Paper 21774 presented at the SPE Western Regional Meeting, Long Beach, CA, 20-22 March.

SPE 118055 9

Djabbarah, N. F., Weber, S. L., Freeman, D. C., Muscatello, J. A., Ashbaugh, J. P., and Covington, T. E. 1990. Laboratory Design and Field Demonstration of Steam Diversion with Foam. SPE 20067 presented at the California Regional Meeting, Ventura, CA, April 4-6. Djabbarah, N. F., Weber, S. L., Skaufel, R. M., and Macfadyen, R. L. 1997. Field Applications of Steamfoam Technology at Mobil. Paper presented at Reserve Foam Mini-Workshop, Tromso, Norway, June 12-13. Fitz, D. E. and Ganapathy, N. 1993. Quantitative Monitoring of Fluid Saturation Changes Using Cased-Hole Logs. Paper XX, Transactions of the 34th Annual Logging Symposium held in Calgary, Alberta, June 13-16. Georgi, D.T. et al 1991. Wireline Log Contributions to the Evaluation to the Judy Creek Hydrocarbon Miscible Flood Pilot. Proceedings of the SPWLA Conference, Midland, TX, June. Healy, R.N., Holstein, E.D., and Batycky, J.P. 1994. Status of Miscible Flooding Technology. Proceedings of the 14th World Petroleum Congress, Stavanger, Norway. 407-416. Hoefner, M. L., and Evans, E. M. 1995. CO2 Foam; Results from Four Developmental Field Trials. SPERE 10 (4): 273-282. Huh, C., Landis, L.H., Maer Jr., N.K., McKinney, P.H., and Dougherty, N.A.1990. Simulation to Support Interpretation of the Loudon Surfactant Pilot Tests. SPE 20465 presented at SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 23-26 September. Hyatt, J.H., and Hutchison, D.A. 2005. Enhanced Oil Recovery in East Texas. SPE 93631 presented at 14th SPE Middle East Oil Show and Conference, Bahrain, 12-15 March. Jenkins, M. K. 1984. An Analytical Model for Water/Gas Miscible Displacements. SPE/DOE 12632, presented at the SPE/DOE Fourth Symposium on EOR, Tulsa, OK, April 15-18. Kaminsky, R.D., Wattenbarger, R.C., Szafranski, R.C., and Coutee, A.S. 2007. Guidelines for Polymer Flooding Evaluation and Development. Paper IPTC 11200 presented at the International Petroleum Technology Conference, Dubai, U.A.E., Dec. 4-6. Kaminsky R.D. and Wattenbarger, R.C. 2008. Solids-Stabilized Emulsions - A Novel Heavy Oil Recovery Technology. Paper presented at Session 16, First ISOPE Frontier Energy Resources Symposium (Vancouver, Canada), July 6-11, 2008. Leaute, R.P. 2002. Liquid Addition to Steam for Enhancing Recovery of Bitumen with CSS: Evolution of Technology from Research Concept to a Field Pilot at Cold Lake. Paper SPE/Petroleum Society of CIM/CHOA 79011, presented at ITOHOS/CHWT Symposium, Calgary, Alberta, Canada, November 4-7. Leaute, R.P. and Carey, B.S. 2005. Liquid Addition to Steam for Enhancing Recovery (LASER) of Bitumen with CSS: Results from the First Pilot Cycle. Paper 2005-161 presented at Canadian International Petroleum Conference (CIPC), Calgary, June 7-9.

Murer, A. S., McClennen, K. L., Ellison, T. K., Larson, D. C., Timmer, R. S., Thomson, and M. A., Wolcott, K. D. 2000. Steam Injection Project in Heavy Oil Diatomite. SPEREE 3 (1): 2-12. Pritchard, D.W.L., Georgi, D.T., Hemingson, P., and Okazawa, T. 1990. Reservoir Surveillance Impacts Management of the Judy Creek Hydrocarbon Miscible Flood. Paper SPE/DOE 20228 presented at the SPE/DOE Seventh Symposium on Enhanced Oil Recovery in Tulsa, April 22-25. Pritchard, D.W.L., and Neiman, R.E. 1992. Improving Oil Recovery through WAG Cycle Optimization in a Gravity-Override-Dominated Miscible Flood. Paper SPE/DOE 24181 presented at the SPE/DOE Eighth Symposium on Enhanced Oil Recovery in Tulsa, April 22-24. Pursley, S.A., Healy, R.N., and Sandvik, E.I. 1973. A Field Test of Surfactant Flooding, Loudon, Illinois. JPT 25 (7): 793-802. Pursley, S.A., and Graham, H.L. 1975. Borregos Field Surfactant Pilot Test. JPT 27 (6): 695-700. Reppert, T.R., Bragg, J.R., Wilkinson, J.R., Snow, T.M., Maer Jr., N.K., and Gale, W.W. 1990. Second Ripley Surfactant Flood Pilot Test. Paper SPE 20219 presented at SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22-25 April. Saltuklaroglu, M. Wright, G. N., Conrad, P. R., McIntyre, J. R., and Manchester, G. J. 2000. Mobil’s SAGD Experience at Celtic, Saskatchewan. J. Canadian Petroleum Technlogy April: 45. Stiles, L.H., Chiquito, R.M., George, C.J., and Long, L.D. 1983. Design and Operation of a CO2 Tertiary Pilot: Means San Andres Unit. SPE 11987 presented at SPE Annual Technical Conference and Exhibition, San Francisco, California, 5-8 October. Stone, H. L. 1982. Vertical Conformance in an Alternating Water-Miscible Gas Flood. SPE 11130, presented at the 57th Annual Technical Conference of the SPE, New Orleans, LA, Sept. 26-29. Tweidt, L.I., Chase, W.D., Holowatuk, C.R., Lane, R.H., and Mitchell, C.M. 1997. Improving Sweep Efficiency in the Norman Wells Naturally Fractured Reservoir through the use of Polymer Gels: A Field Case History. paper SPE 38901 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, TX 5-8 October.

10 SPE 118055

Wood, Kelvin N., Lai, Francis S., and Heacock, Dennis W. 1993. Water Tracing Enhances Miscible Pilot. SPEFE 8 (1): 65-70. SI Metric Conversion Factors

°API 141.5 / (131.5 + °API) = g/cm3 cal × 4.184* E+00 = J cp × 1.0* E-03 = Pa·s °F (°F - 32) / 1.8 = °C psi × 6.894 757 E+00 = kPa scf × 2.831 685 E-02 = m3

STB × 1.589 873 E-01 = m3 *Conversion factor is exact.

SPE 118055 11

Table 1. Representative ExxonMobil EOR Pilot Tests

Field Date Type Pilot Process References Borregos 1965-66 5-Spot Surfactant Pursley (1975) Loudon 1969-70 5-Spot Surfactant Pursley, et al. (1973) Loudon 1980-81 5-Spot Surfactant Bragg et al. (1982, 1983) Loudon 1982-83 5-Spot Surfactant Reppert et al. (1990) Loudon 1982-86 40-Acre Multi-Pattern Surfactant Huh et al. (1990) Loudon 1982-86 80-Acre Multi-Pattern Surfactant Huh et al. (1990) Means San Andres 1982-83 Non-Producing CO2 Miscible Stiles, et al. (1983) Judy Creek ‘A” 1987 Unconfined pattern Hydrocarbon Miscible Pritchard, et al. (1990,

1992) Redwater 1988-89 Multi-Pattern Hydrocarbon Miscible Wood, et al. (1993) Slaughter 1991-92 Multi-Pattern CO2 Foam Hoefner and Evans

(1995) Greater Aneth 1992-94 Multi-Pattern CO2 Foam Hoefner and Evans

(1995) East Texas Basin 2001-2005 Single-Patten Gravity-stable immiscible gas

injection with horizontal wells Hyatt and Hutchison (2005)

Norman Wells 1986-90 Multi-Pattern Polymer Gel Twiedt et al. (1997) Cold Lake-Ethyl 1964- Multi-Pattern Cyclic Steam Stimulation Buckles (1979) Cold Lake-May 1972- Multi-Pattern Cyclic Steam Stimulation Buckles (1979) Cold Lake-Leming 1975- Multi-Pattern Cyclic Steam and Steam Drive

with Horizontal Wells Buckles (1979)

Cold Lake-H22 Pad 2002- Multi-Pattern LASER Leaute (2002), Leaute and Carey (2005)

South Belridge 1986-87 Multi-pattern Steam Foam Djabbarah et al. (1990, 1997)

South Belridge (Diatomite) 1992-96 Multi-pattern Steam Drive Murer et al. (2000) Esperson Dome 1984-87 Single Pattern In-Situ Combustion Choquette et al. (1991) Celtic 1996-99 Single-Well (Horizontal) SAGD Saltuklaroglu et al.

(2000) Celtic 1997-2001 Dual-Well (Horizontal) SAGD Saltuklaroglu et al.

(2000) Celtic 2002-2005 5-Spot SSE Kaminsky and

Wattenbarger (2008)

12 SPE 118055

Figure 1. Staged process for EOR project evaluation and development.

Staged Process for EOR Project Evaluation and Development

Stakeholder review / approvals

Lab Data

Reservoir Characterization

Reservoir Simulation

Pilot Testing

Flood Management

SurveillanceCommercial Project Plan• Field-wide project design and costs• Full-field or multiple segment models• Field-wide development/depletion plan & economics

Implementation, Surveillance, and Operations

Screen Candidate Processes• EOR process identification• Injectant sources • Screening economics

Evaluate Most Promising Processes In Depth• Fluid and rock property data collection / lab studies• Reservoir characterization studies• Mechanistic / fine-scale modeling• Screening-level development/depletion/facilities plan

Field Tests and Pilots to Address Key Uncertainties• Objectives and design• Data collection and interpretation• Facilities reliability and wellbore integrity verification

Figure 2. Factors to consider when selecting pilot size and type

Pilot Size Should be Consistent with Process / Reservoir Knowledge, Available Time, and Risk

Process Untested

Reservoir Complex or not Well Understood

Significant Economic / Injectant Supply Risk

Small-Scale Pilot

Large Demonstration Pilot

Commercial Application

Process Well Understood*

Reservoir Well Understood**

Low Economic / Injectant Supply Risk

Commercial Application

* Process has been proven commercially in other fields** Nearby analog or previous application in same field

Figure 3. Non-producing pilot designs

Pilot Types: Non-Producing

Single Well Injectivity Test

Determine: Injectivity

Injector Offset with Static Observer

Determine: InjectivityVertical sweep at observerDisplacement efficiency at observerReservoir description between injection and observation well

Injector Offset with Multiple In-Line Observers

Determine: InjectivityVertical sweep at observersDisplacement efficiency at observersVertical sweep vs. distanceReservoir description between injection and observation wells

Injector Offset with Multiple Areal Observers

Determine: InjectivityVertical sweep at observerDisplacement efficiency at observersAreal sweepReservoir description between injection and observation wells

SPE 118055 13

Figure 4. Advantages and disadvantages of non-producing pilots

Non-Producing Pilots

Advantages• Low cost• Quick estimate of oil mobilization vs.

distance• Estimate of vertical conformance• No production facilities required• Estimate of injectivity• Fast results

Disadvantages• No oil in tank• No operational experience with

production• No confirmation of swept volume• Limited data on mobility control,

overall conformance, chemical retention

• Extremely sensitive to fluid drift

Figure 5. Examples of producing pilots

Pilot Types: Producing

Single Inverted 5-Spot

Determine: Injectivity and productivityApproximate estimate of oil recovery

Single Normal 5-Spot

Determine: Injectivity and productivityImproved estimate of oil recovery

Single Inverted 5-SpotWith Observers

Determine: Injectivity and productivityEstimate of oil recoveryVertical sweep at observersDisplacement efficiency at observersVertical sweep vs. distanceAreal sweep

Repeated Inverted 5-Spot

Determine: Injectivity and productivityOil recovery from multiple confined patterns

Figure 6. Advantages and disadvantages of unconfined producing pilots

Unconfined Producing Pilots

Advantages• Estimate of injectivity• Low cost• Rough estimates of mobility control,

oil mobilization, chemical retention• Some production experience• Fast results

Disadvantages• Swept volume difficult to evaluate• Streamlines, pressure gradients, oil

recovery not representative of repeated pattern

• Performance difficult to scale• Sensitive to fluid drift• Takes as long to run as a pattern

flood

14 SPE 118055

Figure 7. Advantages and disadvantages of small-scale confined pilots

Small-Scale Confined Pilots

Advantages• Good estimate of oil displacement,

and vertical conformance vs. distance

• Detailed data on mobility control, pressure gradients, and chemical transport

• Data for simulator calibration• Easier to scale-up to commercial• Modest cost• Moderately fast results

Disadvantages• May not sample representative

heterogeneities• May not reflect pattern balance of

repeated pattern flood• May not scale to wider well spacings• May not indicate long-term problems

Figure 8. Advantages and disadvantages of large-scale, multipattern pilots

Large-Scale, Multipattern Pilot

Advantages• Best estimate of oil recovery and

sweep efficiency• Confirmed “oil-in-the-tank”• Best data for calibrating simulators• Easiest to scale-up to commercial

performance• Commercial-scale operating

experience and cost data

Disadvantages• Very expensive• Extensive evaluation time

Figure 9. Potential problems with WAG and gas injection processes

Potential Problems withWAG and Gas Injection Processes

Potential Problem

• Cannot inject gas or water at desired rates

Evaluation of Problem

• Lab measurements• Pilot injectivity tests

• Geological, reservoir description studies

• Simulation studies to test completion strategy and injection rate

• Pilot test for vertical sweep

• Geological, reservoir description studies

• Pulse (interference) testing prior to gas injection

• Waterflood history matching• Pilot tests for conformance

Gas

• Gas channels through high-permeability zones

Gas• Severe gravity override of gas occurs

Inje

ctiv

ity

Time

WaterGasWater

SPE 118055 15

Figure 10. Tools for key reservoir mechanism assessment

Tools for Key Reservoir Mechanism Assessment

Mechanism Data Needed for Interpretation Tools / Techniques

Injection rates Injectivity index

Bottom-hole pressure

Flow profiles

Fall-off tests

Injectivity

Permeability distribution near injection well

Step-rate tests

Time-lapse logging in monitoring wells

Oil saturation change with depth and distance from injector

Core after passage of flood front

Core data

Vertical pulse tests

Gravity override

Vertical permeability

Cross-layer pulse tests

Oil saturation change with depth and distance from injector

Time-lapse logging in monitoring wells

GOR or water cuts versus time at producers Sample producers for early breakthrough of injectant

Inter-well tracers Sample producers

Channeling / viscous fingering / loss of mobility control

Pressure surveys Flowing and shut-in pressures

Areal sweep / conformance Volume balance of oil, gas, water and tracers produced to determine swept pore volume

Sample producers for injected tracers

Figure 11. Judy Creek vertical sweep pilot configuration.

Figure 12. Simplified cross-section of Judy Creek VSP showing observation well location.

16 SPE 118055

Figure 13. Celtic SSE pilot configuration.

injection wellproduction wellobservation well

25ft

45ft

35ft

150 ft

N

40ft

OBS3

INJ4

INJ1

INJ2

INJ3

PRODOBS2 OBS1

Figure 14. Comparison of LASER (orange) and CSS (blue) performance for Cold Lake LASER Pilot. y

0

75

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450

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