The objective of this study was to test the performance of high-molecular weight polyethylene oxide (PEO) polymer in a low-permeability, oil-wet carbonate reservoir rock. Conventional HPAM polymers of similar molecular weight did not exhibit acceptable transport in the same rock, so PEO was explored as an alternative polymer. Viscosity, pressure drop across each section of the core, oil recovery, and polymer retention were measured. The PEO polymer showed good transport in the 23 mD reservoir carbonate core and reduced the residual saturation from 0.29 to 0.17. The reduction of residual oil saturation after polymer flooding using PEO was unexpected and potentially significant.
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.
KOC's Umm Gudair/Abduliyah Tayarat reservoir has large oil reserves but is a challenging target due to low formation permeability and high oil viscosity. This study is focused on feasibility assessment of hybrid thermal and chemical methods incorporating both laboratory and simulation results. A recent updated static geological model for West Kuwait fields was used as the basis to generate a full-field dynamic reservoir model with representative reservoir geometry, heterogeneity, and complexity. Carter-Tracy aquifers were added to model lateral and bottom aquifers. Laboratory data were incorporated to model physiochemical properties. Gridblocks were globally refined to gain better resolution for heavy oil and EOR simulations. The full-field reservoir model was used to systematically study the potentials of hybrid thermal and chemical EOR methods in comparison with conventional waterflood and chemical EOR methods. Our studies show that in order to produce oil at an economic rate, long horizontal wells on the order of kilometers or horizontal wells stimulated by acidizing, multistage fracturing, or multiple laterals should be deployed. Vertical wells yield low oil production rates due to limited contact areas and severe water coning. Aquifer water intrusion from the west side of reservoir overshadows the bottom aquifer and the edge east side aquifer due to the heterogeneity of reservoir permeability. A sector model was extracted from the full-field Eclipse model and further refined to avoid grid effects in simulation of EOR processes. Simulation results show that hybrid thermal and chemical methods (hot polymer/Surfactant-Polymer/Alkaline-Surfactant-Polymer flood) can effectively increase oil recovery from high-permeability, high-saturation sweet spots of the Tayarat reservoir. With the help of horizontal wells, hot polymer flood shows the best performance after 20 years of oil production and yields more than 30% of incremental oil recovery. Hot Surfactant-Polymer flood shows slightly lower cumulative oil recovery but sustained oil production rates and less production decline in the late stage of the flood. Phase 2 coreflood experiments confirmed that hot polymer flood can effectively enhance oil recovery. In summary, this research study identified sweet spots for oil recovery and EOR applications in the challenging Tayarat reservoir and demonstrated the potential of producing significant amount of oil with appropriate IOR (e.g., extended reach horizontal wells, multistage fractures, stimulation, etc.) and EOR (e.g., hybrid thermal and chemical methods) techniques.
Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding. Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions. Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs. In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.
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