This paper discusses the design and implementation of a Single Well Chemical Tracer Test (SWCTT) to evaluate the efficacy of a lab-optimized surfactant-polymer formulation for the Raudhatain Lower Burgan (RALB) reservoir in North Kuwait. A SWCTT was designed upon completing extensive lab and simulation work as discussed in a previous publication (Al-Murayri et al. 2017 and Al-Murayri et al. 2018). SWCTT design work was aimed at confirming the optimal injection/production sequence determined at core flood scale in terms of minimal volumes, rates and duration. The main uncertainties were assessed using numerous sensitivity scenarios. Afterwards, the SWCTT was implemented in the field and the results were carefully analyzed and compared to previously obtained lab andsimulation results. The main objective of this SWCTT was to validate the efficacy of polymer and surfactant solutions in terms of residual oil saturation reduction and injectivity. This invovles comparing residual oil saturation estimates before and after chemical flooding while monitoring injection rates and corresponding wellhead pressures. The SWCTT injection sequence included the following steps:Initial water-flooding, followed by tracer injection, soaking and production to measure oil saturation post water flooding.Pre-flush followed by a main-slug (with 5,000 ppm of surfactant and 500 ppm of polymer) and a post-flush (with only polymer).Sea-water push, followed by tracer injection, soaking and production to measure oil saturation post chemical flooding. Simulation work prior to the execution of the SWCTT test showed encouraging oil desaturation results post chemical flooding within a distance of 10 ft from the well. However, upon analyzing the pilot results, it was realized that there is a gap between the actual SWCTT results and previously obtained lab andsimulation results. This paper sheds light on the design and implementation of the above-mentioned SWCTTwith emphasis on the potential reasons for the realized gap between actual field data and lab/simulation results. The insights from this study are expected to assist in further optimization of surfactant-polymer flooding to economically increase oil recovery from relatively mature reservoirs.

Geothermal energy development is of critical importance to meet the global challenge of energy transition. This work demonstrates that existing oil and gas industry tools can be used to evaluate the potential of geothermal energy production from mature oilfields using the heat contained in the produced fluids. This can contribute to a decarbonation strategy and be profitable since most of the costs (drilling, pumps…) are already supported by oil production operations. The only additional costs consist in surface facilities to convert thermal energy into electricity. The aim of the study is to evaluate the potential of a mature oil field to generate electricity and predict the evolution of energy potential with time considering the current development plan for the field. This plan was designed to maximize oil production in the field and did not consider possible electricity cogeneration from geothermal energy. The study was conducted in a sector of a mature oilfield including 15 producers currently producing about 10,000 barrels of liquid per day and with a 97% water-cut. A workflow was created to estimate the potential of electricity generation considering current and forecast liquid production rates, the nature of the secondary working fluid used in the Organic Rankine Cycle (ORC) and the minimum ejection temperature limits, defined by the operator, to avoid difficulties in surface separation processes. This paper describes the surface process used for thermal energy to electricity conversion, and presents the workflow used to estimate electricity generated from simulation results considering uncertainty tied to some fluids and rocks parameters.

EOR surfactants are usually formulated at the initial reservoir temperature. Is this a correct approach? Field data from three Single-Well Chemical Tracer pilots in North Africa are used to answer this question. The objectives are, first, to provide a realistic image of the temperature variations inside the water-flooded reservoir; second, to demonstrate the impact of such temperature variations on the surfactant performances; and last, to introduce a new methodology for estimating the target temperature window for surfactant formulations. During pre-SWCTT pilot tests, water injection, shut-in and back-production were performed. The bottom-hole temperature was monitored to evaluate the reservoir temperature changes (initially at 120°C) and to calibrate a thermal model. The thermal parameters were applied to the reservoir model to simulate 30 years of water injection (with its surface temperature varying between 20°C and 60°C) and to obtain a full picture of the temperature variations inside the reservoir. Multi-well surfactant injection was modelled assuming that the surfactant is only efficient within ±10°C around the design temperature. The impact of this assumption on the additional oil recovery was analyzed for several scenarios. The rock thermal transmissivity was found to be the key parameter for properly reproducing the observed data gathered in the North African pre-SWCTT tests. The measured temperature during the back-production phase demonstrated the accuracy of the thermal model parametrization. It proved that the heat exchange between the reservoir and the injected fluid is considerably less than what industry expects: the injected water temperature inside the reservoir remains far below the initial reservoir temperature even after 11 days of shut-in. When simulating various historical bottom-hole injection temperatures and pre-flush durations, the thermal model showed an average cooling radius of 275m, larger than the industry recommended well-spacing for the EOR 5-spot patterns. This was mainly due to the significant temperature difference between the historical injected water and the initial reservoir temperature. Several simulations were performed for 3 representative bottom-hole injection temperatures of 20°C, 40°C and 60°C, varying the surfactant design temperature range between the injection temperature and the initial reservoir temperature. The results showed that regardless of the injection temperature, the simulated additional oil recovery is highest when the design temperature range is close to the injection bottom-hole temperature. This is an important subject since in the EOR industry, the surfactants are usually formulated at the initial reservoir temperature and thus, the impact of the reservoir cooling on the surfactant efficiency is seldom considered. In a water flooded reservoir, the injected chemicals are unlikely to encounter the initial reservoir temperature. This results in a dramatic loss of surfactant performance especially when there is a considerable difference between the initial reservoir and the injected fluid temperatures.

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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.