The Bhagyam Field development is part of the Mangala- Bhagyam -Aishwariya (MBA) development in the Barmer Basin, Rajasthan, India. The Bhagyam field is a shallow field with ~12B dip, containing good quality fluvial sand(s), medium gravity crude with a viscosity gradient (vertically) in the oil column and low water salinity (~5000 ppm). The field is currently being developed using down-dip water injection. The effectiveness of the waterflood will be limited by the adverse mobility ratio and reservoir heterogeneities. A polymer injectivity test was conducted in two wells with two main objectives: (1) to establish injectivity within the designed surface pressure, and (2) establish the ability to prepare polymer solutions of the desired viscosity using produced water for re-injection (PWRI). Operationally, the test was conducted using a skid mounted unit with regular monitoring facilities in place. Surveillance activities included frequent spinner surveys, bottom-hole pressure measurements, fall-off tests and offset production well tests. Rigorous monitoring of injection water quality, polymer solution quality was carried out. An inline viscometer was used for continuous polymer viscosity monitoring. This was supplemented by periodic sample viscosity measurements using special samplers with chemical stabilizers. The test was conducted in two wells and important lessons have been learnt which would be incorporated during full-field implementation of a polymer flood in Bhagyam. The injectivity test establishes that polymer injection is viable in Bhagyam Fatehgarh reservoirs. A history matching exercise was carried out using a sector model extracted from our full-field simulation model. The effect of production and injection in offset wells was captured in the sector model. Local grid refinement enabled us to adequately capture polymer rheology. The modelled rheology was found to be in close agreement with laboratory data. The production history of the wells in the sector and vertical injection profile of the injector well was incorporated. We obtained a good history match of the injection bottom-hole pressures. This paper presents details of the polymer injectivity tests including bottom-hole pressure measurements, fall-off tests and production logging which were conducted during the tests. As PWRI was utilized for preparing polymer solution, the effect of additives to the polymer solution viscosity was also analyzed. The test included use of not so commonly used equipment like inline viscometer, special samplers with chemical stabilizers, preparation of high concentration mother solution and injection of heated polymer solution.

The Aishwariya Oil Field located in Barmer Basin of Rajasthan India having STOIIP of ∼300 MMBBLS was initially developed with down-dip edge water injection. The main reservoir unit, Fatehgarh Formation, has excellent reservoir characteristics with porosities of 20-30% and permeability of 1 to 5 Darcys. The Fatehgarh Formation is subdivided into Lower Fatehgarh (LF) and Upper Fatehgarh (UF) Formations, of which LF sands are more homogenous and have slightly better reservoir properties. The oil has in-situ viscosity of 10-30 cP. Given its adverse waterflood mobility ratio, the importance of EOR was recognised very early. Initial screening studies identified that chemical EOR (polymer and ASP) was preferred choice of EOR process. Extensive lab studies and simulation work was conducted to develop the polymer flood concept. A polymer flood development plan was prepared targeting the LF sands of the field utilizing the lessons learnt from nearby Mangala Field polymer implementation project. The polymer flood in Aishwariya Field was implemented in two stages. In the first stage, a polymer injectivity test was conducted in 3 wells to establish the potential for polymer injection in these wells. The injection was extended to 3 more wells and continued for ∼4 years. Significant water cut drop was observed in nearby wells during this phase of polymer injection. In the next stage, polymer flooding was extended to the entire LF sands with drilling of 14 new infill wells and conversion of 8 existing wells to polymer injectors. A ∼14 km long pipeline was laid from the Mangala Central Polymer Facility to well pads in the field to cater to the requirement of 6-8 KBPD of ∼15000 ppm polymer mother solution. The philosophy of pre-production for extended periods was considered prior to start of polymer injection for all wells as it significantly improved injection (reduced skin) and conformance. Full field polymer flood project was implemented, and injection was ramped up to the planned 40-50 KBPD of polymerized water within a month owing to good injectivity and polymer solution quality. A detailed laboratory, well and reservoir surveillance program has been implemented and the desired wellhead viscosity of 25-30 cP has been achieved. Initial response shows significant increase in oil production rate and decrease in water-cut. This paper presents the polymer laboratory studies, initial long term injectivity test results, polymer flood development concept and planning, simulation studies and field implementation in LF Formation in Aishwariya Field.

A procedure to model the impact of reservoir CO2 on chemical EOR (polymer/ASP) flood performance has been developed. The work which was initially developed for polymer flood modelling has been further extended and a simple approach has been presented to model the impact of reservoir CO2 on ASP flood performance. Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. The oil is moderately viscous and aqueous based chemical EOR techniques like polymer/ ASP flooding are being considered for production enhancement. The presence of high CO2 may impact aqueous based flooding processes planned in Aishwariya field. Three unconventional mechanisms occur in the reservoir: i). With injection of water, CO2 is stripped out of oil over time, this leads to increase in oil viscosity. ii). Since CO2 decreases pH of the system, polymer in-situ viscosity is decreased. iii). CO2 reacts with sodium carbonate (alkali) in aqueous medium leading to reduction in pH which may have an impact on ASP performance. An advanced processes simulator was used initially to model the impact of CO2 on polymer flood performance. For simplicity, solution gas was assumed to be entirely composed of CO2. Waterflood followed by polymer injection was simulated in the model. CO2 was defined as an aqueous component instead of conventional oleic component allowing for modelling polymer viscosity dependence on CO2 concentration. In order to model the impact of CO2 on ASP performance, reaction of CO2 with alkali was included in the model. The ASP simulation run could now capture all three unconventional mechanisms occurring in the reservoir due to presence of CO2: increase in oil viscosity, reduction in polymer viscosity and consumption of alkali due to reaction with CO2. Different simulation runs were then carried out both with and without the reaction of CO2 with alkali and the results were compared. Impact of grid refinement on the flood performance was also studied. The developed approach could mechanistically capture the impact of CO2 on ASP performance in Aishwariya field. It was also observed that grid refinement has a major impact on the results; fine grid simulation is required to properly evaluate the impact of CO2 on ASP performance as it can appropriately capture impact of dilution and reaction based on CO2 concentration (moles) available. The paper presents a step by step approach of modelling the impact of in-situ CO2 on ASP flood performance. The suggested approach helped in evaluating the impact of CO2 on polymer/ASP flood performance and adjusting the injection slug design appropriately.

Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. A procedure was developed earlier to model the impact of reservoir CO2 on waterflood, polymer flood and ASP flood (Mishra and Pandey 2017, 2018) in this field. Another observation is that in such a system with very high amount of CO2, produced gas rate does not follow conventional trend. Conventionally, gas is dissolved in oil and produced gas is the gas released out from the oil. However, in a system like Aishwariya with very high amount of CO2 in dissolved gas, produced gas is the cumulative of gas released out from both liquid streams i.e., oil and water. Interestingly, gas can continue to produce even after no more oil is being produced from the system. A live oil coreflood was carried out to generate produced gas rate profile under Aishwariya reservoir conditions. The objective of this work was to validate the modelling procedure developed to predict the produced gas rate in such a system with very high amount of CO2 in reservoir fluid. A live oil coreflood experiment was carried out using 12 inches long Bentheimer core under Aishwariya reservoir pressure and temperature conditions. After saturating the core with live oil, the core was water flooded with brine for ~3.7 pore volumes. Produced gas volume was measured at different times so as to generate gas production profile. Two different simulation techniques were used to simulate the experiment and match the gas production profile. First technique was using a compositional simulator with EOS based PVT while the other technique was using an "advanced processes simulator" modeling the component distributions based on partitioning coefficients. Both methods could successfully capture the production of gas from both liquid streams; oil and water and a reasonable match for the produced gas could be obtained. The approach developed to simulate impact of CO2 on different aqueous based flooding processes in Aishwariya field was validated by matching the coreflood experiment carried out under actual Aishwariya reservoir conditions. It helped to confirm confidence in performance prediction of aqueous based flooding mechanisms planned in Aishwariya field despite the presence of significant amount of CO2. The paper presents history match of unconventional produced gas profile of a coreflood carried out under Aishwariya field conditions with very high amount of dissolved CO2. The proposed method can be applied to estimate produced gas rate in other fields with very high amount of CO2 in reservoir fluid.