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.

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.