Instow: A Full-Field, Multipatterned Alkaline-Surfactant-Polymer Flood—Analyses and Comparison of Phases 1 and 2

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An alkaline-surfactant-polymer (ASP) project in the Instow field, Upper Shaunavon Formation in Saskatchewan, Canada, was planned in three phases. The first two multiwell pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 37% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 55% PV ASP solution. Polymer solution injection for the polymer drives of both phases continues in both phases with Phase 1 and Phase 2 injected volumes being 55 and 42% PV as of August 2019, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.2% to a peak of 13.0% for Phase 1 and Phase 2 oil cut increased from 1.8% to a peak of 14.8%, approximately eightfold. Oil rates increased from approximately 3200 m3/m (20 127 bbl/m) at the end of water injection to a peak of 8300 m3/m (52 220 bbl/m) in Phase 1 and from 1230 m3/m (7 736 bbl/m) to 6332 m3/m (39 827 bbl/m) in Phase 2. Phase 1 pattern analysis indicates that the PV of ASP solution injected varied from 13% to 54% PV of ASP. Oil recoveries after the start of ASP solution injection in the different patterns ranged from 2.3% original oil in place (OOIP) up to 21.3% OOIP with lower oil recoveries generally correlating with lower volumes of ASP solution injected. Wells in common to the two phases of the project show increased oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Total oil recovery as of August 2019 is 60% OOIP for Phase 1 and 62% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost was approximately CAD 26/bbl, resulting in the decision to move forward with Phase 2.

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... AS flooding is generally conducted in combination with polymer flooding to improve macroscopic sweep efficiency. However, an efficient screening of surfactant and alkali for an alkaline-surfactant-polymer (ASP) flood recipe governs the success of the EOR project [26,27]. An ASP pilot project consisting of four injectors and one producer was initiated in Mangala field, India, in 2014 and continued for 10 months [28]. ...
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Chemical flooding, such as alkaline-surfactant (AS) or nanoparticles-surfactant (NS) flooding, is an enhanced oil recovery (EOR) technique that has been increasingly utilized to enhance the oil production rate and recovery factor while reducing chemical adsorption. The AS/NS flooding process involves the injection of a mixture of surfactant and alkali/nanoparticles solutions into an oil reservoir to reduce the interfacial tension between the oil and water phases by surfactant and lower surfactant adsorption by alkali or nanoparticles (NPs) to improve the residual oil recovery. In this study, the AS/NS flooding is evaluated for a Kazakhstani oilfield by systematically screening the chemical constituents involved. Field A in Kazakhstan, one of the oldest fields in the country, has been waterflooded for decades and has not produced even 50% of the original oil in place (OOIP). Currently, the water cut of the field is more than 90%, with a high residual oil saturation. Therefore, besides polymer flooding to control mobility, chemical EOR is proposed as a tertiary recovery method to mobilize residual oil. This study aimed to screen chemicals, including surfactant, alkali, and NPs, to design an effective AS/NS flooding program for the target field. The study focused on conducting laboratory experiments to identify the most effective surfactant and further optimize its performance by screening suitable alkaline and NPs based on their compatibility, stability, and adsorption behavior under reservoir conditions. The performance of the screened chemicals in the porous media was analyzed by a set of coreflood experiments. The findings of the study indicated that alkali agents, particularly sodium carbonate, positively affected surfactant performance by reducing its adsorption by 9–21%. The most effective surfactant combination was found, which gave Winsor type III microemulsion and the lowest interfacial tension (IFT) of 0.2 mN/m. The coreflood tests were conducted with the screened surfactant, alkali, and NPs. Both AS and NS tests demonstrated high residual oil recovery and microemulsion production. However, NS flooding performed better as the incremental oil recovery by NS flooding was 5% higher than standalone surfactant flooding and 9% higher than AS flooding. The results of this screening study helped in designing an efficient chemical formulation to improve the remaining oil recovery from Field A. The findings of this study can be used to design EOR projects for oil fields similar to Field A.
... Although some chemicals have been applied in the full field, others have only been tested in the pilots or in the laboratory. Polymer flooding is the most widely applied CEOR method with projects in the Daqing [12], Dalia Angola [13], and Mangala [14,15] fields, followed by surfactant-polymer (SP) flooding in the Bohai Bay [16] field, alkaline-surfactant-polymer (ASP) flooding in the Instow [17] and Marmul [18] fields, and low salinity waterflooding in the Clair Ridge [19] field. Further field case studies are described in more detail in [20][21][22][23][24][25][26][27][28]. ...
A wide range of enhanced oil recovery (EOR) methods has been proposed to accelerate the recovery of remaining oil in subsurface reservoirs. One important class of methods is water-based chemical EOR (CEOR). The existing screening workflows for CEOR assessment and selection for a particular field focus primarily on the subsurface performance evaluation while a holistic, full-cycle assessment that considers all surface and subsurface challenges is missing. Some of the pre-injection/injection challenges of a CEOR method are the high cost of chemicals, preparation, transportation, storage, scaling, corrosion, and low injectivity. Some of the production/post-production issues include environmental problems of toxic chemicals, separation, treatment, recycling, and safe disposal of the produced chemicals. All of these necessitate the deployment of complex surface facilities which are in turn affected by issues such as the location of the field (e.g., offshore, onshore, close to roads) and the age of the existing facilities. A further important consideration is the overall lifecycle carbon footprint associated with the CEOR deployment and operation. These challenges may overshadow the significant technical benefits of CEOR for extracting the remaining oil while addressing them can accelerate the deployment of CEOR to target fields. In this review paper, a full-cycle review and analysis of different CEOR methods is presented. The technical, economical, surface, subsurface, and environmental challenges, together with the determining factors for success, are critically reviewed. The outcome of this integrated investigation can then be used as a basis for the development of a holistic CEOR screening workflow.
Conference Paper
Objectives/Scope This paper demonstrates the potential of alkali surfactant polymer (ASP) within the Central California Oil Fields, which covers Kern, Tulare, and Fresno Counties. Typically, enhanced oil recovery (EOR) screening is performed across a wide range of processes and is applied to individual reservoirs on a case-by-case basis. This study focuses on a single EOR ASP process across multiple fields and pools specific to Central California. Methods, Procedures, Process Reservoir characteristics and Canadian analogs were used to screen for the ASP potential in Central California. Reservoir characteristics data were digitized and taken from what is locally known as the "Gold Book" of Central California (Volume 1, 1998, published by the California Division of Oil & Gas, subsequently renamed CalGEM (California Geologic Energy Management Division). The book contains data for 137 oil and gas fields with 605 pools. Various ASP screening methods and analogs were applied to this dataset. Candidates were then ranked for detailed future analyses. Results, Observations, and Conclusions Screening resulted in the identification of 166 of the 605 pools that passed the Taber and Delamaide screening methods and compared well to analogous Canadian successful commercial ASP projects. Fields were then ranked according to various reservoir properties, size of potential recovery, and location (access to chemicals). The top five, with supporting data, are shown. Graphs and maps were used to illustrate the top-ranked pools along with their locations. Novel/Additive Information The results of initial screening and ranking of Central Californian pools illustrate its potential for ASP applications. Although there have been some ASP studies and pilots conducted in the San Joaquin Basin oil fields, the results are not in the public sphere. Some data have been published by CalGEM on two successful ASP pilots in the Shallow Oil Zone of the Elk Hills Oil Field, California. This study was performed to show possible application of ASP in 166 pools within the 605 pools in the San Joaquin Basin by using publicly available information to identify oil fields that warrant further detailed investigations of oil chemistry, core analysis, reservoir simulation, risk assessments, and in-depth economic studies.
Conference Paper
Chemical flooding is one of the classical EOR methods, together with thermal methods and gas injection. It is not a new method; indeed, the first polymer flood field pilots date back to the 1950s while the first surfactant-based pilots can be traced back to the 1960s. However, while both gas injection and thermal methods have long been recognised as field proven and are being used at a large scale in multiple fields, it is not the case for chemical EOR. Although there have been over 500 polymer flood pilots recorded, and almost 100 surfactant-based field tests, large scale field applications are few and far between. This situation seems to be evolving however, as more and more large scale chemical projects get underway. This paper proposes to review the status of chemical EOR worldwide to determine whether it is finally coming of age. The status of chemical EOR projects worldwide will be reviewed, focusing on recent and current large-scale field developments. This will allow to establish what is working and where the industry is still encountering difficulties. This review will cover North America, South America, Europe, the Middle East, Asia and Africa. It is clear that polymer flooding is now indeed becoming a well-established process, with many large-scale projects ongoing or in the early stages of implementation in particular in Canada, Argentina, India, Albania and Oman in addition to China. Strangely enough, the US lags behind with no ongoing large-scale polymer flood. The situation is more complex for surfactant-based processes. At the moment, large-scale projects can only be found in China and – although to a lesser extent – in Canada. The situation appears on the brink of changing however, with some large developments in the early stages in Oman, India and Russia. Still, the economics of surfactant-based processes are still challenging and there is some disagreement between the various actors as to whether surfactant-polymer or alkali-surfactant polymer is the way to go. This review will demonstrate that polymer flooding is now a mature technology that has finally made it to very large-scale field applications. Surfactant-based processes however, are lagging behind due in part to technical issues but even more to challenging economics. Still there is light at the end of the tunnel and the coming years may well be a turning point for this technology.
Several alkaline-surfactant/polymers (ASP) were used to recover oil in the Cambridge field in Crook County, WY. ASP provided ultralow interfacial tension and optimal phase behavior by using surfactant concentration of 0.1 wt%. For alkali concentrations of 0.75-2 wt%, interfacial-tension values in the order of 10 -3 dynes/cm were achieved between Cambridge crude oil and solutions of 0.1 wt%-active surfactant plus sodium carbonate. Ultimate oil recovery from the ASP flood of the Cambridge field was 60.9% original oil in place (OOIP) compared with the numerical-simulation-waterflood predicted recovery of 34.1% OOIP. The essential factors in the success of ASP flooding include reservoir engineering, injected-fluid design, numerical simulation, and facilities design and construction.
Mitigating production decline is a challenging task that every oil company will be faced with at some point over the life of an oil reservoir. However, depending on the existing reservoir fluid and rock characteristics, saturation distribution, and the level of heterogeneity of the reservoir rock, Enhanced Oil Recovery (EOR) programs can be implemented to alleviate the decline in oil rate and improve overall recovery. This paper presents an example of a how a mature waterflooded field in southwestern Saskatchewan, Canada could be revitalized using Alkaline-Surfactant-Polymer (ASP) flooding. In this study, laboratory tests were undertaken to select effective chemicals and optimize concentrations that would yield the highest potential oil recovery. Subsequent radial coreflood experiments demonstrated a wide range of potential recovery that depended on slug size and chemical concentration. A detailed numerical simulation of the optimum core displacement was performed in order to calibrate the interaction of the EOR agent with the reservoir rock and fluids, and ultimately upscaled to the full field numerical model Reservoir simulation sensitivity runs were conducted in order to identify an optimum field development strategy using the selected ASP fluid. The results from this optimized development strategy were compared to the waterflood base case to demonstrate the potential upside of the chemical flood. This paper also presents a holistic roadmap for developing EOR projects from initial concept to field implementation and beyond.
An alkaline-surfactant-polymer flood was initiated in September 1987 in the Minnelusa Lower "B" sand at the West Kiehl Unit. Subsequent to unitization, two producing wells were drilled outside the Unit boundary. While this extended the productive geologic interpretation of the field, it did not effect the Unit interpretation of the alkaline-surfactant-polymer flood. Production from primary and chemical injection into State 31-36 through November 1991 resulted in 517,521 barrels of oil (82,279 m3) from the Unit wells, of which 456,361 barrels (72,555 m3) were from the area swept by injection into State 31-36. The two Kottraba wells (north of the Unit) have produced 180,686 barrels of oil (28,727 m3) as of November 1991. The original average oil saturation in the gross swept area was 71.8% PV (69.0% PV in stock tank barrels). The gross swept pore volume of the Unit is 1,294,800 barrels (205,857 m3). The oil recovery efficiency in the gross swept area as of November 1991 is 51.1% OOIP. Projected ultimate production from the gross swept area is 541,158 barrels of oil (86,037 m3) or 60.6% OOIP. Projected ultimate production from the Unit is 602,318 barrels of oil (95,761 m3). This compares with a primary plus waterflood oil recovery estimate of 39.9% OOIP recovery for the West Kiehl Unit gross swept area. Comparison of the oil recovery efficiency of the West Kiehl with other Minnelusa waterfloods and polymer floods suggests the West Kiehl has out performed these other Minnelusa floods. Using the Slider technique, the displacement efficiencies of the areas swept by the State 32-36 and State 42-36 in the Unit and Kottraba Federal 2515 were 71.3%, 52.7% and 58.1%, respectively. Comparative efficiency factors for a waterflood in the Hamm Unit and a polymer flood in the OK Field are 28.5% and 45.6%. The West Kiehl, OK Field, and Hamm Unit are all Lower "B" Minnelusa Fields. A total of 184,794 incremental barrels of oil (29,380 m3 ) are projected for the Unit at an incremental cost of $393,458 or $2.13 per incremental barrel of oil ($13.40 per m3). P. 423^
Screening criteria have been proposed for all enhanced oil recovery (EOR) methods. Data from EOR projects around the world have been examined and the optimum reservoir/oil characteristics for successful projects have been noted. The oil gravity ranges of the oils of current EOR methods have been compiled and the results are presented graphically. The proposed screening criteria are based on both field results and oil recovery mechanisms. The current state of the art for all methods is presented briefly, and relationships between them are described. Steamflooding is still the dominant EOR method. All chemical flooding has been declining, but polymers and gels are being used successfully for sweep improvement and water shutoff. Only CO2 flooding activity has increased continuously.
A tertiary pilot application of the alkaline/surfactant/polymer (ASP) process was initiated in Sept. 1994 in the west central area of Daqing oil field. The pilot pattern consists of four inverted five-spots, including four injectors, nine producers, and 2 observation wells, encompassing an area of 90 000 m2 and with a pore volume (PV) of 203 300 m3. The target layer is the Saertu II1.3 (SII1.3) sandstone, with an average porosity of 26% and permeability of 1.426 [m2. The crude-oil viscosity is 11.5 mPa • s at reservoir temperature and the connate-water salinity is 6800 mg/L. The pilot performance shows a pronounced response from ASP injection. The average pilot area oil production rate increased from 36.7 to 91.5 m3/d, while water cut decreased from 82.7% to 59.7%. For the central well Po5, which is surrounded by injection wells, the oil production rate increased from 3.7 to 27.1 m3/d, while water cut decreased from 84.0% to 45.8%. Numerical simulation results forecast that the oil recovery will be increased by 18.1% original oil in place (OOIP). Total pilot oil production as of March 1996 is 67 500 m3 of which 25 300 m3, or 18.3 % OOIP, is additional produced oil with the current oil cut of 29.7%.
Screening criteria are useful for cursory examination of many candidate reservoirs before expensive reservoir descriptions and economic evaluations are done. We have used our CO2 screening criteria to estimate the total quantity of CO2 that might be needed for the oil reservoirs of the world. If only depth and oil gravity are considered, it appears that about 80% of the world's reservoirs could qualify for some type of CO2 injection. Because the decisions on future EOR projects are based more on economics than on screening criteria, future oil prices are important. Therefore, we examined the impact of oil prices on EOR activities by comparing the actual EOR oil production to that predicted by earlier Natl. Petroleum Council (NPC) reports. Although the lower prices since 1986 have reduced the number of EOR projects, the actual incremental production has been very close to that predicted for U.S. $20/bbl in the 1984 NPC report. Incremental oil production from CO2 flooding continues to increase, and now actually exceeds the predictions made for U.S. $20 oil in the NPC report, even though oil prices have been at approximately that level for some time.
The Middle Jurassic of Southwestern Saskatchewan. Shining a Light on the Upper and Lower Shaunavon and the Roseray (SW Saskatchewan Stratigraphic Chart Modified from Saskatchewan Ministry of Energy and Resources, 2009)
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Polymer Flood of the Rapdan Pool
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The Middle Jurassic Shaunavon Formation of Southwestern Saskatchewan
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