A New Thermally Stable Synthetic Polymer for Harsh Conditions of Middle East Reservoirs. Part I. Thermal Stability and Injection in Carbonate Cores.

Abstract

A great number of Middle East fields have too harsh reservoir conditions (high temperature, high salinity) for conventional EOR polymers used as mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable. At temperatures above 70°C, acrylamide moieties hydrolyze to acrylate groups which ultimately may lead to precipitation and total loss of viscosifying power. Thermal stability can be improved by incorporating specific monomers such as ATBS or NVP. However, their polymerization reactivity can cause some compositional drift and limit their molecular weight / viscosifying power. Compared to HPAM, they will require a higher dosage and higher cost. In this study, we present thermal stability and propagation behavior of a new class of synthetic polymers with high thermal stability. In harsh conditions of Middle East brines, with salinity ranging from sea water to 220 g/L TDS, they present excellent thermal stability until temperature as high as 140°C. Adsorption and mobility reduction were evaluated through coreflood experiments using carbonate cores and Clashach sandstone cores, with permeability ranging between 100mD and 700mD. Mobility and permeability reductions indicate a good propagation in both types of rocks. The development of this new polymer is a major breakthrough to overcome the current limits of polymer EOR applications in harsh reservoir conditions. Moreover, molecular weights can be tailored from low to high molecular weights depending on reservoir permeability. Further work is needed to evaluate resistance to mechanical degradation, salt tolerance and adsorption in carbonates and sandstones.

Analysis and Simulation of Polymer Injectivity Test in a High Temperature High Salinity Carbonate Reservoir

“…The polymer is produced by SNF, Andrézieux-Bouthéon, France. The molecular weight of the samples used is about 8 million g/mol, but the product has been produced in a range of molecular weights [ 13 , 14 , 15 ].…”

“…Most of the proposed screening criteria for polymer flooding applications in the literature suggest a temperature below 100 °C and formation water salinity below 100,000 ppm for a successful implementation [ 11 ]. Recent studies have shown that stability of HPAM could be improved by introducing 2-Acrylamido-2-Methyl Propane Sulfonate (AMPS) as a copolymer [ 13 , 14 , 15 , 16 , 17 , 18 ]. They reported excellent thermal stability and salinity tolerance of SAV10, a high-AMPS-content acrylamide polymer manufactured by SNF, at temperatures between 120 and 140 °C and salinities up to 244,000 ppm.…”

Updated Perceptions on Polymer-Based Enhanced Oil Recovery toward High-Temperature High-Salinity Tolerance for Successful Field Applications in Carbonate Reservoirs

“…Dupuis et al produced comparable results in their investigations on these polymers [ 169 ]. Furthermore, various rheological investigations of ATBS-based polymer and injectivity on three carbonate rock samples revealed that these polymers need to be salinity tolerant [ 170 ].…”

“… Investigations into the capabilities of Superpusher SAV10 (which had significantly more than 35 mol% ATBS and no NVP) and Superpusher SAV333 (which was functionalized with ATBS and 30–45% NVP) in a hard brine (TDS of 84,500 ppm and 6000 ppm hardness) at a temperature of 140 C revealed that SAV10 could retain over 60% of its viscosity after a 6-month period, while SAV333 maintained over 90% of its viscosity. Dupuis et al [ 169 ] made similar discoveries while studying these polymers. …”

Polymers for application in high temperature and high salinity reservoirs – critical review of properties and aspects to consider for laboratory screening

“…We emphasize that for carbonates in harsh reservoirs the restoration is particularly important since the carbonate rock can become more oil-wet when exposed to increased concentration of divalent cations in the brine. Thus, aging in reservoir oil aims to preserve injectivity and reduce the retention on the rock surface (Dupuis, et al, 2017).…”