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Results
Abstract The goal of this work is to develop alkaline-surfactant-polymer (ASP) formulations for a shallow, clayey sandstone reservoir. Commercially available surfactants were used in the phase behavior study. The gas-oil-ratio (GOR) was low; the phase behavior and coreflood study was conducted with the dead oil. The surfactant formulation systems were tested in tertiary ASP core floods in reservoir rocks. Many surfactant formulations were identified which gave ultralow IFT, but the formulation with only one surfactant (at 0.5 wt% concentration) in presence of one co-solvent was selected for corefloods. The cumulative oil recovery was in the range of 94-96% original oil in place (OOIP) in the corefloods. The surfactant retention was low (0.15 mg/gm of rock) in spite of the high clay content. The study showed that 0.5 PV of ASP slug and 2700 ppm of the polymer were required to make the flood effective. The use of alkali and preflush of the soft brine helped minimize surfactant retention.
- Asia > Middle East (1.00)
- Asia > China > Heilongjiang Province (0.28)
- North America > United States > Missouri (0.28)
- Geology > Mineral (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (6 more...)
Characterization of Carboxylate Surfactant Retention in High Temperature, Hard Brine Sandstone Reservoirs
Pinnawala, Gayani (Chevron Energy Technology Company) | Davidson, Andrew (Chevron) | Taylor, Isbell (Chevron Energy Technology Company) | Yang, Hyuntae (Chevron Energy Technology Company) | Slaughter, Will (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Large hydrophobe Carboxylate surfactants (MW above 1000) are a relatively new class of surfactants developed for surfactant flooding during chemical enhanced oil recovery (EOR) processes. The presence of carboxylate groups and alkoxylate groups in the molecules provides stability and salinity tolerance at high temperature and in high salinity environments. Many high temperature reservoirs have injection and reservoir brine containing high concentrations of divalent ions making them prime targets for using carboxylate surfactants. Much of the earlier literature showed successful carboxylate applications at high pH during alkali-enhanced flooding, as the high pH stabilizes the carboxylate groups. Such processes are not feasible in the presence of hardness at high temperatures. We present an approach where we use an alkali buffer wherein the pH is adjusted from highly basic to near neutral. Under such conditions we demonstrated low retention and high performance in terms of phase behavior and coreflood oil recovery.
- Geology > Mineral (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.89)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
Field Trial for Wettability Alteration Using Surfactants: Formulation Development In Laboratory to the Implementation and Production Monitoring in an Offshore Reservoir
Rohilla, Neeraj (Dow Chemical International Pvt. Ltd.) | Katiyar, Amit (The Dow Chemical Company) | Rozowski, Pete M. (The Dow Chemical Company) | Gentilucci, Adrianno (The Dow Chemical Company) | Patil, Pramod D. (Rock Oil Consulting Group) | Pal, Mayur (North Oil Company) | Saxena, Prabhat (North Oil Company)
Abstract Wettability Alteration (WA) as an Enhanced Oil Recovery (EOR) technique is screened for an oil wet carbonate offshore reservoir in this study. Surfactants can be used to change the rock wettability from oil-wet to water-wet conditions and can lead to unlocking significant incremental oil from oil-wet tight pores. A thorough lab program was designed to develop a wettability altering surfactant formulation and was validated with corefloods and spontaneous imbibition tests at reservoir conditions. Surfactant injection trials at smaller scale were conducted first which were successful. Currently, an ongoing long term surfactant injection pilot is operating to evaluate incremental oil gains. An optimal surfactant formulation is developed on the basis of favorable phase behavior at reservoir conditions, the ability to alter wettability to a more water-wet state and cause minimal chemical losses on reservoir minerals in the form of adsorption. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and in some cases up to 120 °C) and high salinity tolerance (> 12 % TDS and up to 22% TDS in some low temperature cases). The field implementation was done in a systemetic step wise manner to mitigate the risk in implementing such a technology field wide. The first step was to de-risk the long term injection and see if there is any injectivity impairment due to surfactant injection. The current injection trial showed improvement in injectivity that is indicative of changes in wettability. More importantly, there has been no evidence of any injectivity impairment, which paves the way for long term surfactant injection in the field.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
Development of Surfactant Formulation for Harsh Environment
Pinnawala, Gayani (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Spilker, Kerry (Chevron Energy Technology Company) | Linnemeyer, Harold (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Good phase behavior is critical for identifying high performance surfactant formulations for coreflood recovery. For conventional CEOR projects, good phase behavior entails high solubilization parameters, rapid equilibration to low viscosity microemulsions and aqueous stability of aqueous surfactant mixtures. For reservoirs with harsh conditions, i.e high temperature (> 90°C), high salinity (>50,000 ppm TDS), high divalent ions (> 1500 ppm TDS), high GOR (>150) and presence of H2S, developing formulations with good phase behavior is challenging. Several carbonate reservoirs have conditions as outlined above and the scarcity of formulations that are stable in the above-described conditions makes surfactant applications challenging. We present results that show the development of surfactant formulations that show good behavior under harsh conditions. We validate the performance with a combination of phase behavior, thermal stability, and coreflood experiments and show that high-performance surfactants can be developed for harsh reservoir conditions.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
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, David (Total) | Klimenko, Alexandra (Total) | Jouenne, Stephane (Total) | Passade-Boupat, Nicolas (Total) | Cordelier, Philippe (Total) | Morel, Danielle (Total) | Bourrel, Maurice (Total)
Abstract 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).
- Asia > Middle East (0.88)
- North America > United States > Montana > Roosevelt County (0.25)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)