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.

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.