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Collaborating Authors
Results
Towards More Representative Workflows for Designing Robust Surfactant EOR Formulations
Wartenberg, Nicolas (Solvay - The EOR Alliance) | Blaizot, Dylan (Solvay - The EOR Alliance) | Mascle, Matthieu (IFP Energies nouvelles - The EOR Alliance) | Mouret, Aurélie (IFP Energies nouvelles - The EOR Alliance) | Rousseau, David (IFP Energies nouvelles - The EOR Alliance)
Abstract Designing robust EOR surfactant formulations implies performing a number of experiments related to the impact of variable parameters such as injection brine composition and reservoir temperature from near wellbore to in-depth zones. Performance evaluation assays are commonly employed in parametric studies, ahead of the time-consuming coreflood tests. Phase diagram in tubes and spinning drop tests are commonly used, but they do not easily allow deriving representative values of the o/w IFT and can lead to contradictory outcomes. In this work, we addressed the crucial question of the methods implemented to estimate the IFT in bulk tests and we investigated a model case where the robustness of a surfactant formulation was assessed versus temperature. In the first part, we compared, at optimal salinity, the IFT as classically evaluated by the Huh relationship in tubes to the IFT as determined in a spinning drop tensiometer between, respectively, the microemulsion and the water and oil phases in equilibrated and non-equilibrated situations. In the second part, we evaluated the robustness of a surfactant formulation in terms of IFT versus temperature variation by phase diagrams and spinning drop methods and performed simplified oil recovery coreflood tests, using the CAL-X high throughput device. Results showed that IFT discrepancies up to one order of magnitude exist between the Huh estimation and the spinning drop results as well as between the different strategies for determining the spinning drop IFT. Such discrepancies can be interpreted from a scientific point of view, but they highlight the need to discriminate between the IFT determination methods in view of representativeness regarding the actual oil recovery mechanisms in the reservoir. The tests campaign for the temperature robustness, performed in the 40-90°C temperature range, showed, again, discrepancies between the two bulk methods. Namely, Winsor III situation was observed from 60°C to 90°C in the phase diagrams with an optimum at 70°C whereas ultra-low IFT was observed only at 60°C in the spinning drop tests. The coreflood tests revealed that very good oil recoveries were achieved from 40°C to 90°C, with evidence of formation of oil banks leading to final oil saturation as low as 5% only from 60°C to 90°C. These outcomes suggest that, for cases where the various phases are clearly distinguishable in tubes, phase diagrams should be selected as preferred bulk assays. However, these tests provide only coarse estimates of the IFT, which makes performance prediction based on capillary desaturation curves challenging. For this reason, high throughput coreflood tests could also be included in surfactant formulation design workflows to better forecast for the formulation performances.
- Asia > Middle East (0.46)
- North America > Canada (0.28)
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)
Evaluating the Effect of Temperature on Surfactant Phase Behavior and Aqueous Stability to Forecast Optimum Salinity at High Temperature
Pinnawala Arachchilage, Gayani W. (Chevron Energy Technology Company) | Spilker, Kerry K. (Chevron Energy Technology Company) | Tao, Emily Burdett (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Linnemeyer, Harold (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Conducting surfactant phase behavior experiments above 100°C is challenging and requires specialized methods to minimize health and safety risks. Shifts in optimal salinity can be correlated to temperature. However, data above 100°C is sparse and the correlations have not been extensively validated above 110°C. In addition, aqueous stability changes with temperature and is often not characterized. We systematically present shifts in optimal salinity and aqueous stability with temperature and use results from both experiments to optimize co-solvent concentrations at high temperatures
- Asia (0.46)
- North America > United States > Oklahoma (0.18)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Optimizing Water Chemistry to Improve Oil Recovery from the Middle Bakken Formation
Wang, D.. (University of North Dakota) | Dawson, M.. (Statoil Gulf Services LLC) | Butler, R.. (University of North Dakota) | Li, H.. (Statoil Gulf Services LLC) | Zhang, J.. (University of North Dakota) | Olatunji, K.. (University of North Dakota)
Abstract With the recent dramatic drop in oil price, production from ultra-tight resources, like the Bakken formation, may drop substantially. Since expenditures for drilling, completion, and fracking have already been made, existing wells will continue to flow, but oil rates will decline—rapidly in many cases. In a low oil-price environment, what can be done to sustain oil production from these tight formations? We are testing a surfactant imbibition process to recovery oil from shales. We measured surfactant imbibition rates and oil recovery values in laboratory cores from the Bakken shale. After optimizing surfactant formulations at reservoir conditions, we observed oil recovery values up to 10–20% OOIP incremental over brine imbibition. However, whether or not surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil production rates in a field setting—which requires that we identify conditions that will maximize imbibition rate, as well as total oil recovery. In this paper, we describe laboratory evaluations of oil recovery using different core plugs. These recovery studies involved (1) surfactant formulation optimization on concentration, salinity and pH, (2) characterization of phase behavior, (3) spontaneous imbibition, and (4) forced imbibition (flooding) with gravity drainage assistance. In preserved cores, we observed: (1) Formulations using 0.1% surfactant concentration at 4% TDS salinity showed favorable oil recoveries (up to 40% OOIP). (2) Generally, surfactant formulations at optimal concentration and salinity were stable at high temperature (115°C). (3) Injectivity/permeability enhancements up to 75 percent occurred after acidification using acetic acid or HCl. (4) Wettability alteration is the dominant mechanism for surfactant imbibition. Of course, actions that increase fracture width will aid gravity drainage and oil recovery. This information is being used to design and implement a field application of the surfactant imbibition process in an ultra-tight resource.
- North America > United States > North Dakota (1.00)
- North America > Canada > Saskatchewan (1.00)
- North America > Canada > Manitoba (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- (4 more...)
Predicting Microemulsion Phase Behavior for Surfactant Flooding
Jin, Luchao (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Jamili, Ahmad (University of Oklahoma) | Li, Zhitao (The University of Texas at Austin) | Luo, Haishan (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Shiau, Ben (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Abstract The surfactant screening process to develop an optimum formulation under reservoir conditions is typically time consuming and expensive. Theories and correlations like HLB, R-ratio and packing parameters have been developed. But none of them can quantitatively consider both the effect of oil type, salinity, hardness and temperature, and model microemulsion phase behavior. This paper uses the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior based on the ambient conditions and surfactant structures. By using HLD equation and quantitatively characterized parameters, four optimum surfactant formulations are designed for target reservoir with high accuracy compared to experimental results. The microemulsion phase behavior is further predicted, and well matched the measured equilibrium interfacial tension. Its predictability is then reinforced by comparing to the empirical Hand's rule phase behavior model. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model. The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)