The Mangala field in India was the first major oil discovery in the Barmer Basin having a STOIIP of nearly 1.3 billion barrels in multiple stacked fluvial reservoirs. It contains medium gravity (20-28 °API), waxy, viscous crude (9-17 cP) in high permeability (1-25 Darcy) clean sandstone reservoirs. The field was discovered in 2004 and brought online in 2009, one of the fastest from discovery to production phase. Hot water injection was started within few months of first production to sweep and maintain pressure. The hot water was essential considering wax appearance temperature (59 degC) close to reservoir temperature (65 degC). The hot water is also used as power fluid for jet pump (main lift system in field) and for annulus circulation in case of shutdown to avoid oil congealing. Jet pump application is the largest in the world with ~160 active wells lifting ~400,000 blpd reservoir liquid with ~500,000 bbls of power fluid. Plateau production of 125k bopd was achieved within 14 months from production start, which is one of the fastest among large onshore fields. The initial average oil rates in wells were ~2000-15000 bopd. Given the high well productivity, the field plateau rate was revised to 150k bopd within a year of achieving 125kbopd. Due to adverse mobility ratio with water, EOR screening and lab study was started right after discovery. Chemical EOR was identified as the most suited with polymer in the first phase followed by surfactant-based flood. Considering the EOR importance, a 5-spot polymer pilot was started almost simultaneously with the start of the field production. Basis pilot results, full-filed polymer flood was started from 2015 which is again one of the fastest EOR implementations. The polymer flood is one of the largest in world with 165 tons/day polymer consumption through ~500000 bwpd of polymerized water injection. Polymer flood reversed the production decline and is expected to give ~8% incremental recovery of STOIIP (~100 MMbbls) by 2030. Following polymer, a successful ASP pilot was conducted in the same wells/pattern which resulted in 20-25% incremental recovery of pilot STOIIP over polymer flood. Planning for large scale ASP implementation is underway. There have been several challenges and important learnings along the way including vertical conformance, areal VRR management, polymer development, degradation, viscosity and quality control over time, jet pump and ESP operations etc. Mangala field recovery has been quite fast with ~37% recovery within 13 years field life. Multiple infill campaigns have been conducted with ~280 wells drilled over 165 base development wells. The paper presents the development journey of Mangala from discovery to date with key achievements, many firsts, learnings and recommendations based on waterflood and polymer flood performance for other similar fields.

This paper describes a novel streamline-based rate allocation approach to maximize oil recovery from polymerfloods and its application to an ongoing polymerflood in the Mangala field, India which is one of the largest polymerfloods in the world. With over 130 injectors and producers, the field-scale optimization is challenging because of the long simulation times, operational constraints at the well, group and field level and changing field conditions. The FM-1 unit which is the main producing zone of the Mangala field comprises of multi-layered single storied fluvial channel sands of thickness ranging 3-10m with excellent flow characteristics. The gross thickness of FM-1 is about 90m. The sand is under a five-spot pattern polymerflood with a well spacing of aproximately 200m. A finite difference simulator is used for modeling the polymerflood performance with all relevant physics (mobility control, adsorption, residual resistance factor, polymer rheology/shear thinning, inaccessible pore volume and time-dependent degradation). Streamlines are generated from the flux field extracted from the finite difference simulation and are used to calculate pair-wise efficiency for each injector-producer streamline bundle. The pair-wise efficiency quantifies how much oil is recovered given a barrel of water injection. The streamline-based optimizer iteratively reallocates the fluids to injectors and producers by diverting the injected fluid to high efficiency pairs located in unswept oil regions. After optimization, injection efficiency plots as well as streamline/time of flight plots are used to examine and visualize the flow pattern changes leading to the improved flood performance. The reservoir model is first calibrated with 10 years of waterflood history. The polymer injection concentration and tapering schemes are determined based on extensive laboratory experiments. The optimization focuses on reallocating the well rates while maintaining the well, group and field level constraints. Two optimization scenarios were studied to examine the potential benefits of rate allocation: (1) optimization of rate allocation for both injectors and producers, (2) optimization of rate allocation for injectors only. Both the scenarios yield improved oil recovery (~5 MMSTB), accelerated production and reduced polymer usage (utility factor). The streamline and injection efficiency plots clearly reveal regions of improved sweep efficiencies, providing an intuitive explanation of the enhanced performance.

Summary The Mangala field contains medium-gravity viscous crude oil. Notably, it is the largest polymer flood in India and 34% of the stock tank oil initially in place (STOIIP) has been produced in 11 years. Mangala was put on full field polymer flood in 2015, 6 years after the start of field production on waterflood in 2009. Polymer flood added nearly 93 million barrels above the anticipated waterflood recovery in 6 years. Reservoir simulation models could replicate the initial Mangala polymer flood performance. However, the performance of the lower layers of Mangala (FM-3 and FM-4) continued to progressively deviate from modeling estimates. Importantly, the observed polymer breakthrough deviated significantly from predictions. As the polymer flood matured, the trend of field water cut with time indicated that in-situ polymer viscosity was equivalent to only 50 to 60% of the surface polymer viscosity. For better predictions and corrective actions, it was necessary to understand the nature of degradation, the progressively deteriorating field performance, especially of the lower layers, and the deviation of polymer breakthrough trends from predictions. Carefully designed in-situ polymer sampling, laboratory studies, and reservoir modeling studies helped connect the dots to understand the field performance. There are several excellent publications on accelerated aging studies and some on polymer sampling. This paper offers an opportunity to directly compare experimental results with field data. The procedures used and lessons learned during field sampling can be useful for other operators for management of polymer floods.

Summary Mangala field has been under polymer flood since 2015. The polymer flood has been more successful in accelerating recovery compared to waterflood. As the flood matured, field performance indicated that part of the injected polymer was degrading in the reservoir. Laboratory studies and polymer samples collected from the reservoir suggest that the most likely reason for the degradation is increased hydrolysis due to thermal aging. This degradation compels higher dosing of polymer to make up for the lost viscosity and increases operating costs. Polymer precipitation in the reservoir may also lead to loss of reservoir permeability. Literature surveys and preliminary laboratory studies showed that polymers with acrylamide-tertiary-butyl-sulfonic acid monomer units (referred to as ATBS polymers) could be a suitable option for Mangala. To evaluate the hypothesis, the team did a series of laboratory and coreflood studies. The studies include accelerated thermal ageing, rheology, dynamic adsorption, injectivity, waterflood with fresh and degraded samples, and compatibility studies with topside chemicals. Two hydrolyzed polyacrylamide (HPAM) polymers with different degrees of hydrolysis (DOH) and two ATBS polymers were evaluated. The selected ATBS polymer was then tested for compatibility with surface topside chemicals. The studies show that the classic 20 to 25% DOH HPAM suffers viscosity degradation and possible precipitation in Mangala reservoir conditions. ATBS polymers and a lower DOH HPAM provide superior results to the incumbent HPAM with an acrylamide (AM) (86)-ATBS (14) copolymer providing the best results. ATBS polymers were especially resistant to cloudpoint lowering and provide some superiority in shear degradation. The ATBS monomer was resistant to hydrolysis during the period of testing. Contrary to the published literature, ATBS polymers showed higher adsorption and their propagation through cores required a higher pressure drop. ATBS polymer seemed to plug a low-permeability section of the core stack. All polymers reach their peak viscosity at 30 to 40% hydrolysis and decline sharply after 40%, but viscosity and cloudpoints measured during accelerated aging are possibly conservative. A large-scale pilot of ATBS injection in Mangala is under way to validate the laboratory test results. ATBS polymer can be a suitable polymer for some layers of Mangala with a high residence time and permeability. The choice is driven by the economics of the incremental cost of ATBS for the benefits it offers. In some sands with shorter interwell spacing, a lower DOH HPAM may be a more cost-effective solution. The study results in this paper provide insights to operators to understand the reservoir performance of existing polymer floods and plan for future polymer floods.

Mangala field is under polymer-flood since 2015. The polymer-flood is very successful in accelerating recovery compared to waterflood. As the flood matured, field performance indicated that part of the injected polymer was degrading in the reservoir. Lab studies and polymer samples collected from the reservoir suggest that the most likely reason of degradation is increased hydrolysis due to thermal ageing. This degradation compels higher dosing of polymer to make up for the lost viscosity and increases operating costs. Polymer precipitation in the reservoir may also lead to loss of reservoir permeability. Literature survey and preliminary lab studies showed that polymers with Acrylamide-Tertiary-Butyl-Sulfonic acid monomer units (referred as ATBS polymers) could be a suitable option for Mangala. To evaluate the hypothesis, team did a series of lab and core flood studies. The studies include accelerated thermal ageing, rheology, dynamic adsorption, injectivity, water flood with fresh and degraded samples and compatibility studies with topside chemicals. Two HPAM polymers with different DOH and two ATBS polymers were evaluated. The selected ATBS polymer was then tested for compatibility with surface topside chemicals. The studies show that the classic 20-25% DOH HPAM suffers viscosity degradation and possible precipitation in Mangala reservoir conditions. ATBS polymers and a lower DOH HPAM provide superior results to the incumbent HPAM with an acrylamide (86)-ATBS (14) copolymer providing the best results. ATBS polymers were especially resistance to cloud point lowering and provide some superiority in shear degradation. ATBS monomer was resistant to hydrolysis in the period of testing. Contrary to published literature ATBS polymers showed higher adsorption and their propagation through cores required higher pressure drop. ATBS polymer seemed to plug a low permeability section of the core stack. All polymers reach their peak viscosity at 30-40% hydrolysis and decline sharply after 40%. However, viscosity and cloud points measured during accelerated ageing are possibly conservative. A large-scale pilot of ATBS injection in Mangala is underway to validate the laboratory test results. ATBS polymer can be a suitable polymer for some layers of Mangala with high residence time and permeability. The choice is driven by the economics of the incremental cost of ATBS for the benefits it offers. In some sands with shorter inter wells pacing, a lower DOH HPAM may work out to be a more cost-effective solution. The study results provide insights to operators to understand the reservoir performance of existing polymer-floods and plan for future polymer-floods.