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.

This paper presents the results of a multi-scenario approach that involves the simulation of chemical EOR processes (polymer- and surfactant-based) for the Ratqa Lower Fars heavy oil (200-1000 cP) field in Kuwait, in order to evaluate the viability of implementing an appropriate chemical EOR strategy. Both technical and economic results are discussed. The approach used involves the simulation of various chemical EOR scenarios (injection of chemical slugs with different durations and concentrations) using several wells patterns (inverted 5-spot, inverted 9-spot, inverted 7-spot with vertical wells, line-drive with horizontal wells) covering various sizes in terms of area. Preliminary simulations of depletion and waterflooding scenarios were also conducted, as base cases to be compared to. Hundreds of EOR scenarios were hence simulated and compared using economic indicators such as the final recovery factor and the cost of chemicals per additional barrel of oil produced, compared to the waterflooding base case scenario. The analysis of the different simulated scenarios shows that due to injectivity issues (low maximum injection pressure to prevent the shale cap rock from being fractured), inverted patterns (inverted 9-spot and especially inverted 7-spot) had to be considered to enhance overall performance and reach promising recovery factors using chemical EOR methods. It is also shown that the impact of the pattern area for the same pattern type (inverted 7-spot configuration) is of paramount importance to the final recovery factor obtained after a fixed simulation duration (20 years in the present case). While the overall efficiency of each EOR process - in terms of recovery factor as a function of the injected solution expressed in pore volume - is kept similar when varying the pattern area, the pattern size is directly linked to the final recovery. Indeed when the pattern area is increased, a smaller volume (in terms of pore volume) of chemical solution can be injected in a fixed timeframe. Finally, the use of simplified economic indicators allowed comparing different EOR processes (polymer and surfactant-polymer) and potential patterns in order to find the most promising configuration in preparation for field implementation. The proposed approach is new as it presents and discusses for the first time the results of a detailed simulation study to evaluate the potential application of chemical EOR processes at the Ratqa Lower Fars heavy oil field in Kuwait. The results of this study are promising and clearly demonstrate the potential applicability of chemical EOR processes in similar heavy oil reservoirs.

Umm Gudair/Abduliyah Tayarat reservoir is a challenging EOR target because of its high oil viscosity, low permeability, and carbonate mineralogy. A previous feasibility study indicated that a hybrid EOR thermal and chemical method combined with IOR techniques could produce significant amount of oil from this reservoir. The objective of this study was to identify the most viable reservoir-specific EOR/IOR approach taking into account techno-economic considerations. With the latest well logging data, production history, and petrophysical measurements, the Tayarat reservoir simulation model was revisited. Consequently, this simulation model was updated and calibrated to reflect field and lab observations. In addition, lab tests that demonstrated good transport and oil recovery performances of a selected polymer in low permeability reservoir cores were modeled to provide parameters for field-scale scoping simulations. Sensitivity studies were conducted to evaluate the effects of injection temperature, viscous fingering, well configuration, etc. A simple economic analysis was conducted to demonstrate the economic benefits of the proposed hybrid EOR/IOR method. Calibrated by history matching the actual production data, the Tayarat reservoir model included a barrier zone that would prevent influx from a bottom aquifer. A better match was obtained by assuming that the reservoir is strongly water wet, which is consistent with the latest laboratory imbibition and contact angle measurements. Reservoir transmissibility was increased to represent possible fractures/microfractures in the carbonate reservoir. Scoping simulations based on a selected sweet spot of the Tayarat reservoir showed that primary recovery was ineffective due to the lack of a bottom aquifer, and waterflood recovered significantly more oil. A hybrid thermal/chemical EOR process was more effective when a preflush of hot water was considered to heat up a portion of the reservoir ahead of chemical injection. When viscous fingering was neglected, oil recovery could be erroneously as high as 50% more compared to the case when viscous fingering was modeled. Simulation results showed that about 19% of OOIP could be recovered using the hot waterflood followed by hot polymer flood, i.e. about 130% higher than conventional waterflood corresponding to a water cut of 95%. The chemical cost for incremental oil produced with our most promising approach was $10/bbl of incremental oil. This integrated laboratory and simulation study should provide meaningful insights into tackling challenging low permeability and/or heavy oil carbonate reservoir using novel chemical EOR techniques.

Um Gudair Minagish Oolite reservoir (UGMO), in Kuwait, is a high temperature mature carbonate field. It is also naturally water-flooded by a strong bottom active aquifer. Specifics challenges for Polymer (P) or Surfactant-Polymer (SP) chemical enhanced oil recovery (cEOR) are faced in high temperature carbonated reservoirs such as UGMO's field. P and SP process selection prior multiwell evaluation is addressed by a well-crafted laboratory approach. This involves extensive laboratory work including coreflood experiments to select the most effective processes in terms of oil recovery and cost-effectiveness. Softened sea water through nanofiltration two passes was considered as the most appropriate water source to be used in a SP cEOR process. Polymer was selected based on classical workflow relying on bulk measurements such as solubility, stability and viscosity, and on coreflooding experiments to characterize polymer injectivity and in-depth propagation. The selected polymer was also tested for compatibility with surfactant. SP formulation was designed and evaluated following a dedicated workflow in order to achieve low interfacial tension (IFT), high solubility, oil recovery and promising economics in reservoir conditions. The most favorable SP formulation regarding economics, surface facility modifications, operating costs and performances were evaluated through coreflood tests. The best SP formulation was selected based on chemicals in-depth propagation in reservoir core, incremental oil recovery and surfactant adsorption. The process was then optimized through additional corefloods to reduce chemicals dosage while keeping high oil recovery performances. Finally, the robustness towards both, rock and field variation conditions, was tested and confirmed. P and SP process were designed and proved to be both promising for UGMO's field. SP while using more chemicals than P process leads to a far better oil recovery as final oil saturation is decreased from 42% (P process) to 11% (SP process). As surfactant adsorption is a key parameter for both SP process efficiency and cost efficiency, several surfactant adsorption mitigation strategies were tested. Injection of a non-ionic surfactant after the main surfactant flood proved to efficiently manage surfactant adsorption despite of the very challenging conditions, allowing to reach very low adsorption level of 60 μg/g. Reservoir simulations showed afterwards that both P or SP process designed were economical at commercial pilot scale. Applied laboratory study on high temperature carbonate UGMO oil reservoir in Kuwait provides useful insights that can be used on other chemical EOR projects in such challenging conditions. This allows to select the most appropriate P or SP process and injection strategy while having reduced surfactant adsorption to very low levels in highly challenging conditions and enhanced profitability.