Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates

Levitt, David; Klimenko, Alexandra; Jouenne, Stéphane; Chamerois, Manuel; Bourrel, M.

doi:10.2118/161633-ms

Abu Dhabi International Petroleum Conference and Exhibition 2012

DOI: 10.2118/161633-ms

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Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates

David Levitt

Alexandra Klimenko

Stéphane Jouenne

et al.

Abstract: The optimization of chemical floods for a low-permeability, high-salinity, high-temperature carbonate formation presents several unique design challenges, which may be overlooked in short coreflood experiments. Low permeability formations require the optimization of polymer molecular weight distribution such that both mobility reduction and injectivity are maximized. Mitigation of emulsion issues -possibly related to high surfactant adsorption -requires the optimization of surfactant concentration and slug siz… Show more

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Cited by 13 publications

References 47 publications

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Laboratory Study on Polymers for Chemical Flooding in Carbonate Reservoirs

et al. 2014

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As part of the screening process for chemical EOR, several polymers have been screened as co-injectants in a surfactant-aided water flood scheme. Due to their higher viscosity, polymers improve sweep efficiency and reduce the permeability of rock matrix, therefore help to improve oil recovery. Aimed at a representative carbonate reservoir in the Middle East, a polymer screening study has been conducted with respect to polymer solubility and viscosity retention in high salinity brines, equivalent to our reservoir parameters. The polymers have to pass through a stringent screening process to meet the harsh conditions encountered in the reservoir: high temperature, high salinities and carbonate nature. Salinity effect was studied in a range of brines that included shallow formation water, produced water, and connate water. Among the polymers studied, six were found compatible and have been short-listed. Based on rheological measurements and flow curves, the concentrations of polymers have been determined to achieve the target viscosity under reservoir conditions. Long-term stability and adsorption tests were conducted to ensure the efficiency of the polymer exposed to reservoir conditions. Oil displacement tests with a selected polymer showed an increased oil recovery factor of 11% by polymer flooding and 18% by surfactant-polymer flooding. This study demonstrates the potential application of polymers under extremely harsh reservoir conditions and their promise to be good additives for chemical flooding.

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Laboratory Study on Polymers for Chemical Flooding in Carbonate Reservoirs

et al. 2014

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Comprehensive Effects on the Propagation of Surfactant and Polymer Flow in Carbonate Porous Media

Cao

Wang

Han

et al. 2015

Day 3 Thu, August 13, 2015

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Chemical propagation in an Enhanced Oil Recovery (EOR) process involves various fluid-rock interactions, such as adsorption, dispersion, inaccessible pore volume (IPV), viscous fingering and chromatographic separation. In this paper, comprehensive effects on the propagation of surfactant and polymer in carbonate porous media were investigated experimentally and analytically in order to study the mechanism and quantify the contribution of each effect. Single phase flow tests of surfactant, polymer and surfactant-polymer mixture were conducted on reservoir carbonate core plugs at reservoir conditions (high temperature and high salinity). A convection-dispersion model was used to interpret the effluent chemical concentration profiles. The effect of different factors on chemical propagation was taken into account in the model. The dynamic adsorptions of two amphoteric surfactants at 2,000 mg/L concentration were 0.21 and 0.17 mg/g-rock, respectively. The dynamic adsorptions of a sulfonated polymer at 2,000 and 5,000 mg/L were 0.11 and 0.17 mg/g-rock, respectively. Surfactant and polymer were co-injected to evaluate their competitive adsorption, and the surfactant adsorption was reduced by about 50%. The dispersion coefficient of the chemicals in carbonate cores was in the magnitude of 10–3 cm2/s. Both dispersion and adsorption caused chemical concentration reduction during the propagation in porous media. IPV and viscous fingering occurred during polymer injection or the subsequente water injection. IPV affected the calculation of adsorption/desorption process of polymer injection and IPV value cannot be solely determined by the model simulation. Chromatographic separation took place in the surfactant/polymer co-injection scheme, which was predicted by the model as well. The model results were compared with the chemical flood simulator of UTCHEM.

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Designing and Injecting a Chemical Formulation for a Successful Off-Shore Chemical EOR Pilot in a High-Temperature, High-Salinity, Low-Permeability Carbonate Field

Levitt

Klimenko

Jouenne

et al. 2016

SPE Improved Oil Recovery Conference

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This article describes the formulation design, optimization, implementation, and lessons learned leading up to a successful 1-spot surfactant-polymer (SP) pilot in the Middle East. The target field is a high-temperature, high-salinity, low-permeability carbonate, and thus presents both great challenges and great potential for the application of chemical EOR technology. A surfactant-polymer (SP) formulation was optimized for these conditions based upon a novel, hydrophilicity-enhanced molecule for high-temperature, high-salinity reservoirs synthesized by Total R&D labs. Thermal stability tests, over 5000 microemulsion pipette tests, and more than 40 corefloods were performed during the screening and optimization process leading up to the 1-spot SP pilot. Additionally, a novel method was developed to optimize polymer molecular weight distribution, in order to decouple in-situ viscosity from near-wellbore injectivity. The final formulation consists of a 0.4 pore volume (PV) SP slug of 1.35% active surfactant, plus 1% clarifier, and SAV-225 polymer (SNF Floerger) in a 80 g/l brine corresponding to a hypothetical softened mixture of seawater and local aquifer water. This is followed by a polymer drive of AN-125 polymer (SNF Floerger) in softened seawater, such that a negative salinity gradient is imposed between the 230 g/l formation brine, 80 g/l SP slug, and 42 g/l seawater. The formulation was designed and implemented without need for a preflush. Residual oil saturation to chemicals (Sorc) in analog limestone cores was measured as 5%±2%, corresponding to a recovery factor (RF) of 90%±4%. Reservoir limestone contains significant heterogeneity on the core-scale, likely preventing the formation of an oil bank, and thus yielded lower recoveries (Sorc: 13%±2%, RF: 84%±4%). One-spot pilot recovery corresponded closely to recovery in analog cores (Sorc: 4%, RF = 90%, Al-Amrie et al., 2015), suggesting that the reason for the lower recovery in reservoir cores was in fact due to the short core length with respect to the mixing zone, as suggested in a previous publication (Levitt et al., 2012).

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Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates

Cited by 13 publications

References 47 publications

Laboratory Study on Polymers for Chemical Flooding in Carbonate Reservoirs

Laboratory Study on Polymers for Chemical Flooding in Carbonate Reservoirs

Comprehensive Effects on the Propagation of Surfactant and Polymer Flow in Carbonate Porous Media

Designing and Injecting a Chemical Formulation for a Successful Off-Shore Chemical EOR Pilot in a High-Temperature, High-Salinity, Low-Permeability Carbonate Field

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