The paper discusses the alkaline surfactant polymer (ASP) flood pilot design including formulation development, pilot area selection, well and pattern type, slug size and sequence, slug viscosity etc for the Bhagyam field. It also discusses the various lab, well and reservoir surveillance techniques planned for the baseline, ASP flood monitoring, residual oil saturation and incremental recovery estimates from the pilot. The Bhagyam is an onshore field in the Rajasthan state of western India and is part of Mangala-Bhagya m- Aishwariya (MBA) development in the Barmer basin. The main producing unit is Fatehgarh multi -storied fluvial sand stone. Reservoir quality is excellent with permeability in the range of 1 to 10 Darcy and porosity in the range of 25-30%. The crude oil is moderately viscous (15 to 500 cP) and highly active with TAN (total acid number) value of ~2 mgKOH/gm. All the reservoir and fluid properties together with low salinity (5000 ppm) and moderate temperature (54 degC) makes it an ideal candidate for polymer and ASP EOR methods. The field has been developed with downdip water injection and post successful evaluation of long term polymer injectivity test, it is currently under full-field polymer flood implementation. The details of polymer flood injectivity and full-field expansion plans are discussed by Sharma et. al. 2016 and Shankar et. al. 2018. EOR assessment has been part of the field development planning process from start. Multiple phase behaviour studies and corefloods have been conducted to screen the surfactant and generate necessary parameters for the simulation studies. The formulation consists of combination of sulfate and sulfonate based surfactants. The focus of the pilot area selection has been to utilize the existing well s to maximum possible extent, reduce the geological uncertainty and minimize the interference from ongoing activity in the field. A normal 4 spot pilot with ~150m spacing has been selected together with two observation well for time lapse saturation monitoring and one coring well towards end of pilot for saturation determination. Dynamic models have been used to design slug size, sequence, viscosity and estimate incremental oil potential. Multiple tracer surveys together with distributed pressure measurements and interference tests are planned to establish connectivity and calibrate model. Initial estimates of pilot incremental oil recovery is in the range of 15-25% of stock tank oil intial in-place (STOIIP) over the polymer flood. Overall pilot design aims at collecting all the necessary data for reducing uncertainty for full-field expansion in a short time frame.

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 paper describes the experience of polymer injection pilots from both subsurface, surveillance and facilities perspective. It also discusses the optimization approach for revising the full field polymer plans. Bhagyam is an onshore oil and gas field in Rajasthan, India. The main producing unit is Fatehgarh multi-storied fluvial sand stone of Paleocene age. The oil is moderately viscous (20 cP to 400 cP) with a vertical viscosity gradient. Reservoir quality is excellent with porosity in the range of 25-30% and permeability of 1 to 10 Darcy. Bhagyam was developed as an edge water injection drive with 153 development wells and put on production in 2012. Polymer flood was recognized early in field life as a viable secondary recovery process. Bhagyam has several characteristics suited for polymer flood like high initial oil saturation, high rock permeability, low reservoir temperature, low connate water and low water salinity. A full field polymer development plan was envisaged in 2013 with a combination of pattern polymer flooding and peripheral polymer injection in water leg. But the field performance under water flood was way below expectations. Along with the fall in crude prices in 2014, the project turned economically unviable. Two polymer injection pilots were done to de risk the polymer flood. A multi-disciplinary team worked to optimize the pilot and full field development plan and improve the modeling of water flood. The two pilots used skid mounted polymer preparation units installed at the well pad and focused on data gathering. An online viscometer and special sampler with chemical stabilizers were used for polymer viscosity measurements. PLT, IFOs and polymer quality parameters like filter ratio, viscosity etc were also regularly measured. A revamped reservoir model was built for the field which helped better characterize the water flood performance. The tests were successful with the wells injecting at or better than expected rates. The offset response was good with WOR drop and oil rate increase in many nearby producers. The conformance of some injectors was successfully managed with selective completions installed. To reduce costs, additional well drilling count was reduced by focusing on high net pay areas, reducing polymer consumption by cutting back on water leg polymer injection, and optimizing polymer viscosity. Pipeline requirements were reduced and polymer injection facilities modified from centralized to skid based. The optimization significantly reduced costs compared to the earlier plan. The economic viability of the project was established at lower oil prices and the modeling efforts along with pilots helped significantly reduce the uncertainty associated with the project.

Bhagyam is an onshore field in the Barmer basin, located in the state of Rajasthan in Western India. Fatehgarh Formation is the main producing unit, comprising of multi-storied fluvial sandstones. Reservoir quality is excellent with permeability in the range of 1 to 10 Darcy and porosity in the range of 25-30%. The crude is moderately viscous (15 – 500 cP) having a large variation with depth (15 cP – 50 cP from around 270 m TVDSS to 400 m TVDSS and then rising steeply to 500 cp at the OWC of 448m TVDSS). Lab studies on Bhagyam cores show that the reservoir is primarily oil wet in nature. Bhagyam Field was developed initially with edge water injection and with subsequent infill campaigns, prior to polymer flood development plan implementation, the Field was operating with 162 wells. Simple mobility ratio and fractional flow considerations indicate that improving the mobility ratio (water flood end-point mobility ratio is 30-100) in Bhagyam would substantially improve the sweep efficiency. Early EOR screening studies recommended chemical EOR (polymer and ASP flood) as the most suitable method for maximizing oil recovery. The lab studies further demonstrated good recovery potential for Polymer flood. Bhagyam's first Polymer flood field application started with testing in one injector which was later expanded to 8 wells. Extended polymer injection in these wells continued for four years. Observing a very encouraging field response, field scale polymer expansion plan was designed which included drilling of 28 new infill wells (17 P+ 11 I) and 24 producer-to-injector conversions. Modular skid-based polymer preparation units were installed to meet the injection requirements of the expansion plan. Infill producers were brought online in 2018 as per the plan but polymer injection was delayed due to various external factors. The production rate, however, was sustained without significant decline, aided by continuous polymer injection in initial 8 injectors, continuing water flood and good reservoir management practices. First polymer injection in field scale expansion started in Oct’20 and was quickly ramped up to the planned 80000 BPD in 4 months, supported by analyses of surveillance data, indicating very encouraging initial production response. Laboratory quality check program was designed to check quality of polymer during preparation and to ensure viscosity integrity till the well head. The paper discusses modular polymer preparation unit set-up and the additional installations designed to reduce pipeline vibrations during pumping of polymers., Experience gained while bringing online the polymer injection wells and the lab quality checks employed to ensure good polymer quality during preparation and pumping have also been discussed. The paper also discusses reservoir surveillance program adopted at the start of polymer injection like spinner survey, Pressure fall-off surveys and the stimulation activities that worked in improving the injectivity of polymer injectors. The paper further outlines the observations from the production response and the surveillance data collected to ensure good polymer flow in this multi-darcy reservoir.

A highly successful ASP flood pilot has been conducted in the Mangala oil field in the Barmer basin located in the Rajasthan state of western India. The field which contains paraffinic oil with ~15cP oil viscosity is currently under full field polymer flood. The field has a STOIIP of ~1300 mmbbls and has already achieved more than 30% recovery factor in 10 years of production since coming online in 2009. The ongoing polymer flood is performing satisfactorily and the objective of large scale ASP implementation is to arrest the projected production decline and improve the ultimate recovery from the field. A normal 5-spot ASP pilot was conducted in the topmost reservoir of the field during the year 2014-15. The ASP formulation contained surfactant combination of high molecular weight TSP-EO-PO-sulfate and high carbon number ABS. The pilot was highly successful with estimated incremental recovery by ASP injection of more than 20% of the pilot STOIIP over polymer flood. The water-cut in the pilot dropped from more than 90% to levels of 20-30%. Comprehensive modeling of the corefloods and the pilot performance helped to calibrate the chemical flood simulator which was used for the development of large scale implementation concept. Various produced fluid related studies helped to design the surface facility concept. Given that large volumes of chemicals will be used, work is ongoing to define the chemical procurement strategy. The sector level modeling studies indicated that closer spacing improves the response time and helps to maximize the reserves in a given time frame. The study identified that infill drilling to convert the existing 5-spot polymer flood pattern into a direct line drive pattern is an optimal concept. The modeling study in combination with the surface facility considerations helped to design the expansion approach. The slug size sensitivity suggested to use slightly bigger pore volume of ASP slug in the range of 0.4-0.6 PV taking into consideration heterogeneity uncertainties attached with flooding multiple sands in fluvial deposition. The facility studies using the pilot information and additional lab studies helped to design the surface facilities concept. Requirement of produced water reinjection and water softening of the water for ASP injection in combination with anticipated scaling and produced fluid separation issues posed significant challenges. The paper will present the development journey of a very large scale ASP implementation concept in the Mangala field with focus on modeling at core/pilot/sector/full-field scale. The uncertainties associated with modeling of complex mechanism of the process will also be discussed. A high level surface facility concept and chemical procurement strategy will also be presented. This would be one of the few case history of a very large scale ASP implementation planning project.