Oilfield chemistry

Overcoming Challenges in Chemical EOR During Polymer Breakthrough

The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer.


In chemical enhanced oil recovery (EOR), challenges are expected regarding production chemistry and production-facilities operations. Partially hydrolyzed polyacrylamide (HPAM) is used widely for controlling mobility ratios. Complex in water chemistry and rich in positively charged divalent ions, flooded polymer, having a negative charge, interacts with divalent ions of produced water (PW). The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer.


The Mangala field in northwest India, discovered in January 2004, is part of the Barmer Basin. The primary reservoir unit in this field is the Fatehgarh group, a high-quality quartzose sandstone reservoir having high net-to-gross ratio, high porosity (21–28%), and multidarcy permeability (200 millidarcy to 20 darcy) with an average permeability of approximately 5 darcy. The reservoir contains waxy crude with gravity ranging from 20 to 28 °API. A primary recovery efficiency of less than 10% stock-tank oil initially in place is estimated on the basis of simple depletion; thus, the base field-­development plan envisaged implementation of waterflooding from the start of production to maintain reservoir pressure and sweep reserves. Detailed laboratory studies have established that aqueous-based chemical EOR processes are best suited for these viscous oil fields.

Full-field polymer flooding has been implemented in the Mangala field, with an injection at the time of writing of nearly 400,000 B/D of polymerized injection water (IW) with average polymer concentration of approximately 2,500 ppm. HPAM is mixed with source water to create a mother solution of 15,000-ppm concentration at a central polymer facility and is distributed through a pipeline network to 15 well pads, where it is diluted with IW to achieve a viscosity of approximately 30 cp for injection. Artificial lift is achieved either by jet pump or electrical submersible pump. Average water cut is 80% at the time of writing.

Challenges and Remediation

Compatibility of Production Chemicals and Injected Polymer. Introduction of certain production chemicals to IW has shown polymer-viscosity reduction and filtration-ratio increase. This could cause increasing polymer-specific consumption in achieving the targeted viscosity of IW, reduce injector effectiveness, and affect propagation of HPAM through the reservoir during flooding.

Some production chemicals performing effectively in the nonpolymer-flooded systems could not be used for treatment of PW and IW used for mixing with the polymer. Additional criteria have been introduced into the chemical-selection process for polymer flooding to ensure no viscosity losses and other side effects exist regarding incompatibility of polymer with production chemicals.

Cationic reverse emulsion breaker (REB) was used in the field for treating PW to IW specifications. However, cationic REBs were excluded from the list of chemicals for future applications because of major incompatibility related to interaction with anionic HPAM molecules; this caused phasing out of the returned polymer from the water phase.

Glutaraldehyde biocides were used for treatment of IW tanks. However, significant deterioration of biocide performance has been noted. Replacing glutaraldehyde with another chemistry allowed renewed control of the bacteria growth in the tanks.

Water Treatment Effectiveness. Increasing concentrations of suspended solids affected efficiency of water treatment in the gas flotation tanks and depurators under the REB treatment program. Treatment of polymer containing IW improved significantly with the introduction of additional PW tanks to increase retention time.

Equipment Fouling With Polymer-Containing Deposits. The depositing of elastic materials on equipment after polymer has broken through to producing wells has been observed. Figs. 1 through 3 demonstrate equipment fouled with deposited materials. Significant concentrations of polymer have been identified in these deposits.

Fig. 1—Elastic deposits on pump strainer.
Fig. 2—Elastic deposits at the outlet plate of the heat exchanger.
Fig. 3—Elastic deposits on the jet pump.


Issues of polymer precipitation with calcium should be addressed to ensure flow assurance and that asset integrity is not compromised because of polymer phasing out in solid form from the bulk of the liquid. This type of fouling cannot be treated by most scale inhibitors because of a different mechanism of solids formation. Therefore, specific approaches are considered for treatment—namely, application of antifoulants to keep the precipitated material in dispersed form in the bulk of the liquid or chelating of multivalent cations in water to prevent bonding with hydrolyzed polymer.

Inorganic Scale Inhibition. Significant concentrations of inorganic scale (up to 40%) were observed in PW and IW heaters treated by phosphonate-based scale inhibitor. On the basis of X-ray fluorescence analysis and inorganic carbon concentration, the inorganic part of the deposits was determined mainly to consist of calcium carbonate scale. This observation indicated compromised scale control because of deficiencies of treatment, in which scale inhibitor had been injected upstream of the heaters. The effect of HPAM should be taken into consideration for selection of scale inhibitors for treatment of brine containing polymer.

From dynamic-scaling-loop results, scale inhibitor (phosphonate type, 50 ppm) was seen to control scale precipitation in the absence of polymer. However, with the polymer in the brine at a temperature exceeding the cloud point of polymer, the test tube was blocked faster than with the blank sample. This indicates the importance of taking the effect of polymer into account during selection of chemicals preventing scaling and fouling.

Corrosion Control in the Presence of Returned Polymer. An increase in corrosion rates of extracted coupons has been observed. Many coupons featured deposits on the surface, with clear evidence of localized corrosion. Very often, deposits removed from coupon surfaces contained blackish, hard particles of iron sulfide, indicating corrosion caused by growth of sulfate-reducing bacteria (SRB). Some of these deposits were highly elastic in nature.

Swabbing from coupons for SRB serial dilution indicted high concentrations of sessile bacteria [103–105 colony-forming units (cfu)/mL]. It should be noted that SRB tests on planktonic bacteria yielded significantly lower readings (up to 102 cfu/mL).

Corrosion-rate increase coincided with the raising of suspended solids and the presence of sessile bacteria on the metal surfaces. This indicates a need for applications of chemicals capable of suppressing corrosion in the fouled system having elevated concentrations of suspended and deposited solids.

Considerations for Selection of Production Chemicals in Polymer-­Flooded Fields.

  • Some chemicals may negatively affect polymer viscosity.
  • Atypical or new products may be required for inhibiting or dispersing polymeric deposits.
  • High rates of treatment during polymer flooding often are seen.
  • Specialized treatments should be considered, such as soaking with polymer-dissolution chemistry to address precipitated polymer.
  • Extensive maintenance programs should be anticipated and implemented.
  • Understanding of polymer cycle injection is important.
  • A robust chemical-management system must be in place.


  • Compatibility and polarity are important for polymer-flooding production chemicals to avoid polymer-viscosity loss.
  • Crude dehydration is relatively unaffected.
  • Water clarification is affected significantly, even with no brine viscosity increase at the time of writing.
  • Solids loading is the most-severe issue with backproduced polymer and is not predicted by the model.
  • Solid deposit components mainly are hydrocarbons, calcium carbonate, polymer, and iron sulfide, with proportions varying from location to location. Thus, different treatment programs may be required for fouling control in different parts of the system.
  • Conventional scale inhibitors alone will not suffice for scaling management. A combination of inhibitors, antifoulants, dispersants, and chelating chemicals is required for effective scaling and fouling control.
  • More industry focus must be placed on understanding the effect of returned polymer on the treatment of produced liquid.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194689, “Challenges in Selection and Use of Production Chemicals With Chemical EOR Operations During Polymer Breakthrough Phase,” by Robert Zagitov, Panneer Selvam Venkat, and Ravindranthan Kothandan, Cairn Oil and Gas, et al., prepared for the 2019 SPE Oil and Gas India Conference and Exhibition, Mumbai, 9–11 April. The paper has not been peer reviewed.