Cairn Oil & Gas, Vedanta Limited has implemented full field Polymer Flooding in Mangala Field and is currently injecting nearly 400,000 bpd of polymerized injection water with average polymer concentration of ~2500 ppm. Partially hydrolysed polyacrylamide (HPAM) Polymer is mixed with source water to create a mother solution of 15,000 ppm concentration at Central Polymer Facility (CPF) and is distributed through a pipeline network to 15 well pads where it is diluted to achieve a viscosity of ~30 cP for injection. Artificial lift in Mangala is either by Jet Pump or Electrical Submersible Pump (ESP). In producers, a wide range of polymer concentrations are observed in the produced brine. Maximum polymer concentration measured is ~972 ppm and average polymer concentration is ~280 ppm. Recently, during well intervention activities, it is frequently observed that polymer like waxy deposits are obstructing the free movement of wire-line tools. During jet-pump redressing, polymer deposition was observed in the Body X-over (Reservoir liquid path), check valve assembly, throat and spacer nozzle to throat inside jet-pump. In addition, an agglomerated polymer substance was also observed in the slick line tool string. A general observation is that after a jet pump change, production rate increases sharply followed by rapid decline. This requires Jet Pump Change Out (JPCO) job at regular intervals (every 20 days in few wells). Furthermore, semi soft to hard polymer deposits have been observed in surface facilities i.e. injection water booster pumps, injection water filters and heat exchangers. Laboratory analysis of the samples collected indicated that the deposit consists of Hydrocarbon, Inorganic Scales and polymer agglomeration. Based on further studies it is observed that the degree of hydrolysis of the polymer deposit significantly increases between 50-80% in Jet pump deposits and up to 90% in heat exchanger samples. Increasing degree of hydrolysis reduces the polymer cloud point below reservoir temperature and heat exchange skin temperature. Solution to the problem can be identified by controlling the degree of hydrolysis in fresh polymer below 25 mol% and cloud point greater than 120°C, addition of scale inhibitor to the system upstream of scale formation, removal of deposit with a combination of oxidizer and chelant; other options continue to be studied.

Enhanced Oil Recovery is important stage of life cycle of a field and often it is implemented with challenges. In the chemical EOR, challenges and surprises are expected in production chemistry and production facilities operations. Partially hydrolyzed polyacrylamide used widely for controlling mobility ratio so that Operator is able to recover maximum possible oil. With complex water chemistry and rich in positively charged divalent ions, flooded polymer having negative charge interacts with divalent ions of produced water. Back produced sheared polymer interacts with divalent ions to form semi hard to hard scales poses challenges of the reliability of production facilities. Other important limitations to be noted in CEOR phase are using production chemicals to control scale, emulsion and microbial treatment under Hydrogen Sulphide and waxy crude environment. This paper discusses about the requirement of preparedness and how to overcome challenges of EOR operations and in handling the back produced polymer in following areas: Selection of production chemicals to be compatible to polymer so that no or minimal degradation or loss of viscosity due to polarity of chemicalsPerformance of production chemicals in the presence of polymerSolids loading in production system Emulsion and produced water treatmentSuitability of produced water treatment facilities Revised scaling and fouling control with back produced polymer with rich divalent ions present in produced waterStrategizing chemical management system to suit polymer flood and polymerized back produced water treatment regime

Deposition of elastic fouling material on equipment for processing and transportation of crude was observed after EOR polymer breaking through to producing wells of the Aishwarya field. The objective of the study included analyzing polymer containing deposits, concluding on mechanism of precipitation and developing the solution for fouling control based on the novel laboratory test procedure. Aishwarya field is in north-west part of India. Fatehgarh group is the main reservoir unit. Artificial lift in Aishwarya is mainly by ESP. An opportunity to improve the recovery of Aishwarya field via better displacement of oil was envisaged through implementation of EOR polymer flood. HPAM (partially hydrolyzed polyacrylamide) polymer injection was initiated in September 2017. Failures of ESP pumps, significant fouling of strainers of liquid transfer and PWRI pumps, pressure increase in Aishwarya production line which necessitate increased pigging frequency was observed soon after polymer breaking through to producing wells. Detailed analysis of produced water containing back produced polymer and elastic deposits collected from different equipment were performed. Specific test methods have been selected for such analysis including SEC, XRF, XRD, SEM/EDS, FTIR, NMR etc. It was found that Aishwarya deposits contain high concentration of precipitated polymer (to 36%) and polymer was completely hydrolyzed, degree of hydrolysis or DOH at 100%. Chemical nature of polymer was evaluated as Calcium Carboxylates. DOH of returned polymer in Aishwarya produced water was measured upto 79%, significant increase from the initial 25%. Such high DOH significantly dropped tolerance of HPAM to divalent cations and increases potential for precipitation with Calcium in Aishwarya brine having relatively high concentration of Calcium and high value of the relative hardness, the ratio of divalent cations to total cations. Fast increase of DOH was attributed to the relatively high temperature of the Aishwarya reservoir (up to 77 deg C at the OWC zone). Novel test method, accelerated aging test, has been used to investigate the long-term stability of the applied HPAM and more thermally stable polymers containing monomers of acrylamide tertiary butyl sulphonic acid (ATBS) for Aishwarya conditions. Laboratory tests represented 200 – 400 days travelling time at the Aishwarya reservoir temperature. The test results indicated on significantly better viscosity retention and higher polymer thermal stability, represented by the polymer cloud point, of ATBS co-polymers than HPAM for Aishwariya field conditions as more suitable polymer type for polymer flooding than HPAM.

Severe fouling of crude oil and produced water treatment equipment of Mangala Processing Terminal (MPT) with elastic deposits has been observed after EOR polymer breaking through to the producing wells. Fouling by polymer containing solids caused the system bottlenecking impacting on crude production rates and deterioration of water quality for injection due to increase of total solids loading. The objective of the study included developing the water treatment technology for removing the returned polymer, developing the pilot run for implementation of the technology and scaling up the process if the pilot shows success. Crude processed at MPT is produced from Mangala, Bhagyam and Aishwarya fields which are located at the north-west part of India. Full field polymer flooding has been implemented in the Mangala field from 2015. Fouling of downhole and topside equipment with elastic deposits has been reported soon after polymer breakthrough the same year. For reducing the fouling potential and solids loading, the concept of removing the returned polymer from produced water has been considered as beneficial. Removal of polymer through the chemical coagulation was considered for developing. Extensive laboratory and bench testing have been carried out. Based on the laboratory results, the pilot was developed and carried out on the flotation equipment available at MPT. In the laboratory and bench test for polymer coagulation, over 70% polymer removal was achieved with non-sticky flocks and minimal sludge. The tests also demonstrated reduced suspended solids, residual oil and filterability improvement of treated water. The pilot run confirmed effectiveness of the chemical coagulation process to remove polymer. Polymer removal > 70% was observed during the pilot. Oil removal from produced water at 60-80% was seen. Cloud point of polymer remaining in water increased from 60°C to > 110°C indicating on the significant potential reduction of remaining polymer to precipitate from treated water. The pilot results demonstrated on the applicability of the technology of chemical polymer removal at MPT and will be used for scaling up the treatment facilities.

The Rajasthan Field has been undergoing waterflood with produced water reinjection (PWRI) using makeup water with a moderate sulfate (≈500 mg/L) and negligible organic content since 2010. Initial analyses of the formation water indicated that the volatile fatty acid (VFA) content was quite low (≈ 20 mg/L), suggesting a priori that the levels of H2S biogeneration and production would not be problematic. However, after less than four years the H2S production rate from the field was over 1000 kg/day and the H2S concentration in the composite separator gas was about 200 ppmv. Consequently, studies were carried out using the H2S forecasting model previously discussed in four SPE papers to determine the cause for the high level of souring and to estimate future levels and trends of H2S production in the field. The mechanistic reservoir souring model considers H2S biogeneration due to water-soluble VFAs and/or primarily oil-soluble organics such as BTEX components, the effects of H2S-siderite geochemical reactions within the reservoir to scavenge H2S, flow of H2S (and other components) through the reservoir to the surface, and partitioning of H2S into the oil, water and gas phases within the reservoir and in the surface separators. Also included in the Rajasthan model were the use of power water to lift the well production since it affects partitioning at the surface; and, the effect of chemical H2S scavengers added in selected well flowlines to maintain H2S partial pressures at safe levels. The model determined that the observed H2S production was not possible even with complete consumption of the indigenous VFAs by sulfate-reducing bacteria and that only with the majority of their organic nutrients being provided by the BTEX-type components were the historical H2S production levels able to be matched. The model results have indicated that H2S production rates have already peaked in the field, primarily due to the reduction in makeup water which provides most of the sulfate being injected into the reservoir. Sulfate is the limiting microbial reactant since the oil-soluble organic supply is essentially infinite. This study has shown even in non-seawater waterfloods and with minimal organic acids in the formation water that reservoir souring can occur, resulting in the need to handle significant levels of H2S on the surface. The significance of oil-soluble organics as a potential SRB nutrient must be considered when planning a waterflood if sulfate is injected.