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Collaborating Authors
Results
Geochemical Modeling to Evaluate the Performance of Polymer Flooding in a Highly Sour Sandstone Heavy Oil Reservoir
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Kamal, Dawood Sulaiman (Kuwait Oil Company) | Garcia, Jose Gregorio (Kuwait Oil Company) | Delshad, Mojdeh (UEORS) | Britton, Christopher (UEORS) | Fortenberry, Robert (UEORS)
Abstract The Umm Niqa Lower Fars (Heavy Oil Field) oil reservoir has very favorable properties of high permeability, low temperature, and moderate oil viscosity for polymer flooding and work is progressing towards implementing a polymer pilot in this target reservoir. Nonetheless, Heavy Oil Field contains high salinity water, it is shallow with concerns about injectivity limitations, and high concentrations of H2S (up to 5 mol% in reservoir fluids) which may adversely impact the effectiveness of the injected polymer solutions. A comprehensive laboratory and numerical modeling was initiated to address some of these issues. One potential concern is the degradation of polymer in the co-presence of H2S and possible oxygen introduced with polymer solution injection. This study is aimed at evaluating the impact of H2S on polymer performance in the Heavy Oil Field reservoir via geochemical simulations based on laboratory data. Previously performed polymer rheology and transport experiments were history matched and model parameters were developed for subsequent simulations. Transport behavior of both HPAM type and biopolymers was modeled incorporating two new features of viscous fingering and filtration models. This was then followed by a geochemical simulation study to assess and potentially de-risk the presence of H2S near the wellbore assuming that all oxygen in the injection water (if any) is rapidly consumed by reservoir rock minerals and oil. The parameters developed for the rheology of the polymers were very robust and represented the effects of salinity and polymer shear thinning over a wide range of polymer concentrations for each polymer. These parameters were then used to conduct simulation studies on waterflooding and polymer flooding in the presence of near wellbore H2S. Sensitivity simulations to relative permeability/wettability, oil viscosity, polymer concentration were also conducted to identify the impact on injectivity of polymer solution. The use of the newly added viscous fingering and filtration models was necessary in some cases to correctly model the transport behavior of unstable displacements. Geochemical evaluation showed that injecting H2S-free water over a period of ~3 months can significantly reduce H2S concentration in the near-wellbore region (~30 ft) due to stripping from the oil phase. This is advantageous for the injected polymer because even if small oxygen concentration is co-injected with the water, there would be no H2S present to cause polymer degradation. This study presents a practical approach to de-risk the deployment of polymer flooding in a highly sour shallow sandstone heavy oil reservoir. The findings of this study will be evaluated in a one-spot EOR pilot soon.
- North America > United States > Texas (0.46)
- Asia > Middle East > Kuwait (0.29)
- North America > United States > Oklahoma (0.28)
- North America > United States > Colorado (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.61)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Stability of Biopolymer and Partially Hydrolyzed Polyacrylamide in Presence of H2S and Oxygen
Al-Murayri, Mohammed Taha (KOC) | Kamal, Dawood Sulaiman (KOC) | Garcia, Jose Gregorio (KOC) | Al-Tameemi, Naser (KOC) | Driver, Jonathan (UEORS) | Hernandez, Richard (UEORS) | Fortenberry, Robert (UEORS) | Britton, Christopher (UEORS)
Abstract There are many oil reservoirs worldwide with substantial amount of H2S but otherwise very favorable conditions for polymer flooding such as low temperature, high permeability, and moderate to high oil viscosity. However, there is a legitimate concern about the chemical stability of polymers when there is dissolved oxygen in the injection water or injection facility and its high concentrations of H2S in the reservoir. Several synthetic polymers and biopolymers were selected for stability testing under a wide range of conditions. We focused on identifying the concentration limits for co-presence of H2S and oxygen for which the synthetic and biopolymers are stable for an extended period, using different, widely available brine compositions. Experiments were conducted with and without standard polymer protection packages to evaluate their effects on stability and degradation under sour conditions. Viscosity of polymer solutions with varying concentrations of H2S and oxygen were measured and compared with the oxygen free or H2S free solution viscosities for a period of 6 months. Several methods of safely introducing H2S to the polymer solution were investigated and compared. The laboratory results indicated that biopolymers were stable at all the concentrations of oxygen and H2S concentrations studied. Three synthetic polymers tested showed some degradation in the presence of oxygen and H2S but were stable when either species is absent. The results indicated that oxygen is the limiting reagent in the degradation reaction with partially hydrolyzed polyacrylamide (HPAM) polymers under normal reservoir conditions. We observed little-to-no difference in degradation between samples with 10 or 100 ppm H2S at 500 ppb oxygen concentration, so H2S is not the limiting reagent under these conditions. Additionally, HPAM exposed to 10 ppm H2S and intermediate levels of oxygen (~0.5 ppm) only partially degrades, while samples exposed to H2S and ambient oxygen completely degrade. We anticipate these results will be useful for operators evaluating the potential of polymer flooding in sour reservoirs to follow a stricter polymer preparation at the surface facility to minimize oxygen concenration.
- Geology > Geological Subdiscipline (0.67)
- Geology > Mineral > Sulfide (0.60)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.55)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Improving ASP Performance in Carbonate Reservoir Rocks Using Hybrid-Alkali
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Kamal, Dawoud Suliman (Kuwait Oil Company) | Suniga, Pearson (Ultimate EOR Services) | Fortenberry, Robert (Ultimate EOR Services) | Britton, Chris (Ultimate EOR Services) | Pope, Gary A. (The University of Texas at Austin) | Liyanage, Pathma Jith (The University of Texas at Austin) | Jang, Sung Hyun (The University of Texas at Austin) | Upamali, Karasinghe A.N. (The University of Texas at Austin)
Abstract Waterflood oil recovery in many carbonate oil reservoirs is low due to both high residual oil saturations and low sweep efficiency because of high heterogeneity. An example is the Sabriyah Mauddud reservoir in Kuwait. Alkaline-surfactant polymer flooding (ASP) has great potential for enhanced oil recovery both because ASP flooding reduces residual oil saturation and because of the polymer improves sweep efficiency. Unfortunately, the initial ASP coreflood experiments using conventional alkali showed unacceptably high surfactant retention in the reservoir cores. Several approaches to reducing surfactant retention were tested. Numerous strategies such as the use of chelating agents, sacrificial agents and chemical gradients were tested to reduce retention. The most effective strategy used a hybrid-alkali (NaOH + Na2CO3) in addition to a hydrophilic polymer drive containing a novel co-solvent. In this approach injection pH was increased to 12.5, compared to 10.5 using only Na2CO3. Such high pH is undesirable in sandstones because of reactions with silica minerals, but theexperimental results described here suggest the process is suitable for carbonate reservoirs. With this approach, both low surfactant retention and high oil recovery were achieved in very tight reservoir cores (8-35 mD). This novel approach was validated in a live oil coreflood using preserved cores to represent the reservoir material in the most rigorous way possible. This significant decrease in surfactant retention makes ASP flooding in the Sabriyah Mauddud reservoir viable.
- Asia > Middle East > Kuwait (0.35)
- North America > United States > Texas (0.29)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.89)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Design and Demonstration of New Single-Well Tracer Test for Viscous Chemical Enhanced-Oil-Recovery Fluids
Fortenberry, Robert (Ultimate EOR Services) | Suniga, Pearson (Ultimate EOR Services) | Delshad, Mojdeh (Ultimate EOR Services) | Singh, Bharat (Kuwait Oil Company) | AlKaaoud, Hassan A. (Kuwait Oil Company) | Carlisle, Charlie T. (Chemical Tracers Incorporated) | Pope, Gary A. (University of Texas at Austin)
Summary Single-well-partitioning-tracer tests (SWTTs) are used to measure the saturation of oil or water near a wellbore. If used before and after injection of enhanced-oil-recovery (EOR) fluids, they can evaluate EOR flood performance in a so-called one-spot pilot. Four alkaline/surfactant/polymer (ASP) one-spot pilots were recently completed in Kuwait's Sabriyah-Mauddud (SAMA) reservoir, a thick, heterogeneous carbonate operated by Kuwait Oil Company (KOC). UTCHEM (Delshad et al. 2013), the University of Texas chemical-flooding reservoir simulator, was used to interpret results of two of these one-spot pilots performed in an unconfined zone within the thick SAMA formation. These simulations were used to design a new method for injecting partitioning tracers for one-spot pilots. The recommended practice is to inject the tracers into a relatively uniform confined zone, but, as seen in this work, that is not always possible, so an alternative design was needed to improve the accuracy of the test. The simulations showed that there was a flow-conformance problem when the partitioning tracers were injected into a perforated zone without confinement after the viscous ASP and polymer-drive solutions. The water-conveyed-tracer solutions were being partially diverted outside of the ASP-swept zone where they contacted unswept oil. Because of this problem, the initial interpretation of the performance of the chemicals was pessimistic, overestimating the chemical residual oil saturation (ROS) by up to 12 saturation units. Additional simulations indicated that the oil saturation in the ASP-swept zone could be properly estimated by avoiding the post-ASP waterflood and injecting the post-ASP tracers in a viscous polymer solution rather than in water. An ASP one-spot pilot using the new SWTT design resulted in an estimated ROS of only 0.06 after injection of chemicals (Carlisle et al. 2014). These saturation values were obtained by history matching tracer-production data by use of both traditional continuously-stirred-tank (CSTR) models and compositional, reactive-transport reservoir models. The ability of the simulator to model every phase of the one-spot pilot operation was crucial to the insight of modified SWTT design. The waterflood, first SWTT, ASP flood, and the final SWTT were simulated using a heterogeneous permeability field representative of the Mauddud formation. Laboratory data, field-ASP quality-control information, and injection strategy were all accounted for in these simulations. We describe the models, how they were used, and how the results were used to modify the SWTT design. We further discuss the implications for other SWTTs. The advantage of mechanistic simulation of multiple aspects of a one-spot pilot is an important theme of this study. Because the pore space investigated by the SWTTs can be affected by the previously injected EOR fluids (and vice versa), these interactions should be accounted for. This simulation approach can be used to identify and mitigate design problems during each phase of a challenging one-spot pilot.
- Asia > Middle East > Kuwait (0.90)
- North America > United States > Texas (0.68)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Upper Marrat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sabiriyah Mauddud (SAMA) Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > SAMA Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Tracer test analysis (1.00)
Abstract Developing robust, low cost surfactant-polymer (SP) solutions for use in offshore oilfields has historically proven difficult. The objective of this study was to develop and test a practical EOR process for injecting surfactant-polymer mixtures in seawater followed by a polymer drive in seawater – we call this approach the chemical gradient. The main target for this approach is offshore applications for platforms with space and facility limitations where alternative sources of injection brine are not available or very limited, making it difficult to use a conventional salinity gradient design. A proposed strategy for modeling the chemical gradient is also included in this work. The conventional way to design a surfactant-polymer (SP) flood is to use a salinity gradient. This is the simplest, most efficient and most robust design approach. This means the surfactant-polymer slug is injected at its optimum salinity and then followed by a polymer drive at a lower salinity, usually about 70% of the slug salinity. This can be done by blending brines with different salinities, desalinating or softening an available injection brine and other means. However, sometimes none of these alternatives are practical using an existing offshore platform. We designed a high-performance SP flood requiring only seawater as the injection brine. We added a very small amount of a hydrophilic surfactant to the polymer drive following the surfactant/polymer slug to create a chemical gradient equivalent to a salinity gradient to improve robostness. We tested the design in an outcrop coreflood experiment and observed excellent performance including high oil recovery and propagation of the chemicals in a sharp bank.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
One-Spot Pilot Results in the Sabriyah-Mauddud Carbonate Formation in Kuwait Using a Novel Surfactant Formulation
Carlisle, Charlie (Chemical Tracers, Inc.) | Al-Maraghi, Eissa (Kuwait Oil Company) | Al-Saad, Bader (Kuwait Oil Company) | Britton, Chris (Ultimate EOR Services) | Fortenberry, Robert (Ultimate EOR Services) | Pope, Gary (The University of Texas at Austin)
Abstract Kuwait Oil Company has recognized the implications of the recent technological advances that are very likely to transform the oil industry and make chemical enhanced oil recovery methods such as alkaline-surfactant-polymer (ASP) flooding a hallmark of enhanced oil recovery. An ambitious program to apply chemical EOR to both sandstone and carbonate oil reservoirs in Kuwait is already underway. In this paper, we present the first field results of this effort. First we discuss the approach used to design a novel surfactant formulation for a high-salinity, high-temperature, highly heterogeneous carbonate reservoir, the Sabriyah-Mauddud in Kuwait, and the evaluation of the ASP process in three one-spot ASP pilots (i.e., three two-stage single well chemical tracer tests). We summarize the results of the surfactant laboratory experiments used to select the final ASP formulation and we present detailed results and interpretation of the subsequent single-well chemical tracer test (SWCTTs) results using ASP chemicals as well as details of the field operation including quality control measurements performed in the field lab. The residual oil saturations measured before and after the injection of the ASP slug and polymer drives clearly show that the chemical solution was effective in mobilizing and displacing residual oil saturation following injection of water. The injectivity of high molecular weight polyacrylamide polymer was excellent despite the low permeability of the formation.
- North America > United States (1.00)
- Asia > Middle East > Kuwait (1.00)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geology > Geological Subdiscipline (0.48)
- Geology > Mineral (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Upper Marrat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sabiriyah Mauddud (SAMA) Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > SAMA Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Tracer test analysis (1.00)