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Collaborating Authors
Results
Fast Permeability Estimation of an Unconventional Formation Core by Transient-Pressure History Matching
Chen, Zeliang (Rice University) | Wang, Xinglin (Rice University) | Jian, Guoqing (Rice University) | Zhang, Leilei (Rice University) | Dong, Pengfei (Rice University) | Singer, Philip M. (Rice University) | Hirasaki, George J. (Rice University)
Summary Unconventional resources are of great importance in the global energy supply. However, the ultralow permeability, which is an indicator of the producibility, makes the unconventional production challenging. Therefore, the permeability is one of the critical petrophysical properties for formation evaluation. There are many existing approaches to determine permeability in the laboratory using core analysis. The methods can be divided into two categories: steadyโstate and unsteadyโstate approaches. The steadyโstate approach is a direct measurement using Darcy's law. This approach has disadvantages because of the accuracy in the measurement of low flow rate and the long run time. The unsteadyโstate approach includes pulse decay, oscillating pressure, and Gas Research Institute methods. These approaches are complicated in terms of setups and interpretations. Both steadyโstate and unsteadyโstate approaches typically have a constraint on the maximum differential pressure. We propose a novel unsteadyโstate method to determine the permeability by transientโpressure history matching. This approach involves simulation and experiments. On the experiment side, the ultralowโpermeability core undergoes 1D CO2โflooding experiments, during which the transient pressure is monitored for history matching. On the simulation side, the transientโpressure history is simulated using the finiteโvolume method incorporating realโgas pseudopressure and table lookup to deal with the nonlinearity in fluid properties and singularity during phase transition. The free parameter permeability in the simulation is adjusted for history matching to determine the rock permeability. Our new unsteadyโstate approach is developed for fast and convenient permeability estimation for unconventional formation cores. This approach is a valuable addition to existing permeability measurement methods.
- Geology > Geological Subdiscipline (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.68)
Evaluation of a Nonionic Surfactant Foam for CO2 Mobility Control in a Heterogeneous Carbonate Reservoir
Jian, Guoqing (Rice University) | Alcorn, Zachary (University of Bergen) | Zhang, Leilei (Rice University) | Puerto, Maura C. (Rice University) | Soroush, Samaneh (Rice University) | Graue, Arne (University of Bergen) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George J. (Rice University)
Summary In this paper, we describe a laboratory investigation of a nonionic surfactant for carbon dioxide-(CO2-) foam mobility control in the East Seminole field, a heterogeneous carbonate reservoir in the Permian Basin of west Texas. A method of high-performance liquid chromatography-evaporativelight-scattering detector (HPLC-ELSD) was followed for characterizing the surfactant stability. The foam transport process was studied in the absence and the presence of East Seminole crude oil, with test results showing that strong CO2-foam forms in either a bulk-foam test or foam-flow test. An oxygen scavenger, carbohydrazide, was found effective for controlling the stability of the surfactant up to 80ยฐC and total dissolved solid of โผ34,000 ppm. Moreover, a phosphonate scale inhibitor was investigated and found to be compatible with the oxygen scavenger to accommodate a surfactant solution in a gypsum-oversaturated reservoir brine. During the oil-fractional flow test, an emulsion appears to form, causing a noticeable pressure increase; however, emulsion generation failed to cause a significant phase plugging in the test. Also, a STARSโข (Computer Modelling Group Ltd., Calgary, Alberta, Canada) foam model was applied to obtain the foam parameters from the foam-flow experiments at steady-state conditions. The insights from laboratory experiments better enable translation of the foam technology to the field.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.24)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock (0.95)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
Ultralow-Interfacial-Tension Foam-Injection Strategy in High-Temperature Ultrahigh-Salinity Fractured Oil-Wet Carbonate Reservoirs
Dong, Pengfei (Rice University) | Puerto, Maura C. (Rice University) | Ma, Kun (Total) | Mateen, Khalid (Total) | Ren, Guangwei (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George J. (Rice University)
Summary Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such as oilโwet surface wettability, high reservoir heterogeneity, and high brine salinity. We present the feasibility and injectionโstrategy investigation of ultralowโinterfacialโtension (IFT) foam in a highโtemperature (greater than 80ยฐC), ultrahighโformationโsalinity [greater than 23% total dissolved solids (TDS)] fractured oilโwet carbonate reservoir. Because a salinity gradient is generated between injection seawater (SW) (4.2% TDS) and formation brine (FB) (23% TDS), a frontalโdilution map was created to simulate frontalโdisplacement processes and thereafter it was used to optimize surfactant formulations. IFT measurements and bulkโfoam tests were also conducted to study the salinityโgradient effect on the performance of ultralowโIFT foam. UltralowโIFT foamโinjection strategies were investigated through a series of coreflood experiments in both homogeneous and fractured oilโwet core systems with initial oil/brine twoโphase saturation. The representative fractured system included a wellโdefined fracture by splitting the core sample lengthwise. A controllable initial oil/brine saturation in the matrix can be achieved by closing the fracture with a rubber sheet at high confining pressure. The surfactant formulation achieved ultralow IFT (magnitude of 10 to 10 mN/m) with the crude oil at the displacement front and good foamability at underoptimal conditions. Both ultralowโIFT and foamability properties were found to be sensitive to the salinity gradient. UltralowโIFT foam flooding achieved more than 50% incremental oil recovery compared with waterflooding in fractured oilโwet systems because of the selective diversion of ultralowโIFT foam. This effect resulted in a crossflow near the foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/highโsalinity brine flowing back to the fracture ahead of the front. The crossflow of oil/highโsalinity brine from the matrix to the fracture was found to create challenges for foam propagation in the fractured system by forming Winsor II conditions near the foam front and hence killing the existing foam. It is important to note that Winsor II conditions should be avoided in the ultralowโIFT foam process to ensure good foam propagation and high oilโrecovery efficiency. Results in this work contributed to demonstrating the technical feasibility of ultralowโIFT foam in highโtemperature, ultrahighโsalinity fractured oilโwet carbonate reservoirs and investigated the injection strategy to enhance the lowโIFT foam performance. The ultralowโIFT formulation helped to mobilize the residual oil for better displacement efficiency and reduce the unfavorable capillary entry pressure for better sweep efficiency. The selective diversion of foam makes it a good candidate for a mobilityโcontrol agent in a fractured system for better sweep efficiency.
- Asia (1.00)
- North America > United States > Texas (0.46)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (4 more...)
Mixtures of Anionic/Cationic Surfactants: A New Approach for Enhanced Oil Recovery in Low-Salinity, High-Temperature Sandstone Reservoir
Li, Yingcheng (Sinopec Shanghai Research Institute of Petrochemical Technology) | Zhang, Weidong (Sinopec Shanghai Research Institute of Petrochemical Technology) | Kong, Bailing (Sinopec Henan Oil Field Company) | Puerto, Maura (Rice University) | Bao, Xinning (Sinopec Shanghai Research Institute of Petrochemical Technology) | Sha, Ou (Sinopec Shanghai Research Institute of Petrochemical Technology) | Shen, Zhiqin (Sinopec Shanghai Research Institute of Petrochemical Technology) | Yang, Yiqing (Sinopec Shanghai Research Institute of Petrochemical Technology) | Liu, Yanhua (Sinopec Henan Oil Field Company) | Gu, Songyuan (Sinopec Shanghai Research Institute of Petrochemical Technology) | Miller, Clarence (Rice University) | Hirasaki, George J. (Rice University)
Summary Test results indicate that a lipophilic surfactant can be designed by mixing both hydrophilic anionic and cationic surfactants, which broaden the design of novel surfactant methodology and application scope for conventional chemical enhanced-oil-recovery (EOR) methods. These mixtures produced ultralow critical micelle concentrations (CMCs), ultralow interfacial tension (IFT), and high oil solubilization that promote high tertiary oil recovery. Mixtures of anionic and cationic surfactants with molar excess of anionic surfactant for EOR applications in sandstone reservoirs are described in this study. Physical chemistry properties, such as surface tension, CMC, surface excess, and area per molecule of individual surfactants and their mixtures, were measured by the Wilhelmy (1863) plate method. Morphologies of surfactant solutions, both surfactant/polymer (SP) and alkaline/surfactant/polymer (ASP), were studied by cryogenic-transmission electron microscopy (Cryo-TEM). Phase behaviors were recorded by visual inspection including crossed polarizers at different surfactant concentrations and different temperatures. IFTs between normal octane, crude oil, and surfactant solution were measured by the spinning-drop-tensiometer method. Properties of IFT, viscosity, and thermal stability of surfactant, SP, and ASP solutions were also tested. Static adsorption on sandstone was measured at reservoir temperature. IFT was measured before and after multiple contact adsorptions to recognize the influence of adsorption on interfacial properties. Forced displacements were conducted by flooding with water, SP, and ASP. The coreflooding experiments were conducted with synthetic brine with approximately 5,000โppm of total dissolved solids (TDS), and with a crude oil from a Sinopec reservoir.
- Europe (1.00)
- Asia > China (1.00)
- North America (0.93)
- Asia > Middle East > Saudi Arabia (0.28)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Effects of Hardness and Cosurfactant on Phase Behavior of Alcohol-Free Alkyl Propoxylated Sulfate Systems
Puerto, Maura C. (Rice University) | Hirasaki, George J. (Rice University) | Miller, Clarence A. (Rice University) | Reznik, Carmen (Shell Global Solutions) | Dubey, Sheila (Shell Global Solutions) | Barnes, Julian R. (Shell Global Solutions) | van Kuijk, Sjoerd (Shell Global Solutions)
Summary The effect of hardness was investigated on equilibrium phase behavior in the absence of alcohol for blends of three alcohol propoxy sulfates (APSs) with an internal olefin sulfonate (IOS) with a C15โ18 chain length. Hard brines investigated were synthetic seawater (SW), 2SW, and 3SW, the last two with double and triple the total ionic content of SW with all ions present in the same relative proportions as in SW, respectively. Optimal blends of the APS/IOS systems formed microemulsions with n-octane that had high solubilization suitable for enhanced oil recovery at both โ25ยฐC and 50ยฐC. However, oil-free aqueous solutions of the optimal blends in 2SW and 3SW, as well as in 8 and 12% NaCl solutions with similar ionic strengths, exhibited cloudiness and/or precipitation and were unsuitable for injection. In SW at 25ยฐC, the aqueous solution of the optimal blend of C16โ17 7 propylene oxide sulfate, made from a branched alcohol, and IOS15โ18, was clear and suitable for injection. A salinity map prepared for blends of these surfactants illustrates how such maps facilitate the selection of injection compositions in which injection and reservoir salinities differ. The same APS was blended with other APSs and alcohol ethoxy sulfates (AESs) in SW at โ25ยฐC, yielding microemulsions with high n-octane solubilization and clear aqueous solutions at optimal conditions. Three APS/AES blends were found to form suitable microemulsions in SW with a crude oil at its reservoir temperature near 50ยฐC. Optimal conditions were nearly the same for hard brines and NaCl solutions with similar ionic strengths between SW and 3SW. Although the aqueous solutions for the optimal blends with crude oil were slightly cloudy, small changes in blend ratio led to formation of lower phase microemulsions with clear aqueous solutions. When injection and reservoir brines differ, it may be preferable to inject at such slightly underoptimum conditions to avoid generating upper phase, Winsor II, conditions produced by inevitable mixing of injected and formation brines.
- Asia (1.00)
- North America > United States (0.46)
- Europe > Netherlands (0.28)
- Geology > Mineral > Sulfate (1.00)
- Geology > Geological Subdiscipline (0.70)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Adsorption of a Switchable Cationic Surfactant on Natural Carbonate Minerals
Cui, Leyu (Rice University) | Ma, Kun (Rice University) | Abdala, Ahmed A. (Petroleum Institute, Abu Dhabi) | Lu, Lucas J. (Rice University) | Tanakov, Ivan (Rice University) | Biswal, Sibani L. (Rice University) | Hirasaki, George J. (Rice University)
Summary A switchable cationic surfactant (e.g., tertiary amine surfactant Ethomeen C12) was previously described as a surfactant that one can inject in high-pressure carbon dioxide (CO2) for foam-mobility control. C12 can dissolve in high-pressure CO2 as a nonionic surfactant and equilibrate with brine as a cationic surfactant. Here, we describe the adsorption characteristics of this surfactant in carbonate-formation materials. The adsorption of this surfactant is sensitive to the equilibrium pH, the electrolyte composition of the brine, and the minerals in carbonate-formation materials. Pure C12 is a nonionic surfactant. When it is mixed with brine, the solution has a high pH and limited solubility. However, when the surfactant solution in brine is equilibrated with high-pressure CO2, the pH is approximately 4; the surfactant switches to a cationic surfactant and becomes soluble. Thus, the adsorption is also a function of pH. The adsorption of C12 on calcite at low pH is low (e.g., 0.5 mg/m). However, if the carbonate formation contains silica or clays, the adsorption is high, as is typical for cationic surfactants. The adsorption of C12 on silica decreases with an increase in divalent (Ca and Mg) and trivalent (Al) cations. This is because of the competition for the negatively charged silica sites between the multivalent cations and the monovalent cationic surfactant. An additional effect of the presence of divalent cations in the brine is that it reduces the dissolution of calcite or dolomite in the presence of high-pressure CO2. The dissolution of calcite and dolomite is harmful because of formation damage and increased alkalinity. The latter raises the pH and thus increases the adsorption of C12 or even causes surfactant precipitation.
- Geology > Mineral > Carbonate Mineral > Calcite (0.67)
- Geology > Mineral > Silicate > Phyllosilicate (0.49)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.48)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.66)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (0.94)
Switchable Nonionic to Cationic Ethoxylated Amine Surfactants for CO2 Enhanced Oil Recovery in High-Temperature, High-Salinity Carbonate Reservoirs
Chen, Yunshen (Department of Chemical Engineering, University of Texas at Austin) | Elhag, Amro S. (Department of Chemical Engineering, University of Texas at Austin) | Poon, Benjamin M. (Department of Chemical Engineering, University of Texas at Austin) | Cui, Leyu (Department of Chemical and Biomolecular Engineering, Rice University) | Ma, Kun (Department of Chemical and Biomolecular Engineering, Rice University) | Liao, Sonia Y. (Department of Chemical Engineering, University of Texas at Austin) | Reddy, Prathima P. (Department of Chemical Engineering, University of Texas at Austin) | Worthen, Andrew J. (Department of Chemical Engineering, University of Texas at Austin) | Hirasaki, George J. (Department of Chemical and Biomolecular Engineering, Rice University) | Nguyen, Quoc P. (Department of Petroleum and Geosystems Engineering, University of Texas at Austin) | Biswal, Sibani L. (Department of Chemical and Biomolecular Engineering, Rice University) | Johnston, Keith P. (Department of Chemical Engineering, University of Texas at Austin)
Summary To improve sweep efficiency for carbon dioxide (CO2) enhanced oil recovery (EOR) up to 120ยฐC in the presence of high-salinity brine (182 g/L NaCl), novel CO2/water (C/W) foams have been formed with surfactants composed of ethoxylated amine headgroups with cocoalkyl tails. These surfactants are switchable from the nonionic (unprotonated amine) state in dry CO2 to cationic (protonated amine) in the presence of an aqueous phase with a pH less than 6. The high hydrophilicity in the protonated cationic state was evident in the high cloudpoint temperature up to 120ยฐC. The high cloud point facilitated the stabilization of lamellae between bubbles in CO2/water foams. In the nonionic form, the surfactant was soluble in CO2 at 120ยฐC and 3,300 psia at a concentration of 0.2% (w/w). C/W foams were produced by injecting the surfactant into either the CO2 phase or the brine phase, which indicated good contact between phases for transport of surfactant to the interface. Solubility of the surfactant in CO2 and a favorable C/W partition coefficient are beneficial for transport of surfactant with CO2-flow pathways in the reservoir to minimize viscous fingering and gravity override. The ethoxylated cocoamine with two ethylene oxide (EO) groups was shown to stabilize C/W foams in a 30-darcy sandpack with NaCl concentrations up to 182 g/L at 120ยฐC and 3,400 psia, and foam qualities from 50 to 95%. The foam produces an apparent viscosity of 6.2 cp in the sandpack and 6.3 cp in a 762-ฮผm-inner-diameter capillary tube (downstream of the sandpack) in contrast with values well below 1 cp without surfactant present. Moreover, the cationic headgroup reduces the adsorption of ethoxylated alkyl amines on calcite, which is also positively charged in the presence of CO2 dissolved in brine. The surfactant partition coefficients (0 to 0.04) favored the water phase over the oil phase, which is beneficial for minimizing losses of surfactant to the oil phase for efficient surfactant usage. Furthermore, the surfactant was used to form C/W foams, without forming stable/viscous oil/water (O/W) emulsions. This selectivity is desirable for mobility control whereby CO2 will have low mobility in regions in which oil is not present and high contact with oil at the displacement front. In summary, the switchable ethoxylated alkyl amine surfactants provide both high cloudpoints in brine and high interfacial activities of ionic surfactants in water for foam generation, as well as significant solubilities in CO2 in the nonionic dry state for surfactant injection.
- Asia (1.00)
- North America > United States > California (0.46)
- North America > United States > Texas > Travis County > Austin (0.29)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Mineral > Carbonate Mineral (0.34)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Summary In a layered, 2D heterogeneous sandpack with a 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil in place (OOIP) because of injected water flowing through the high-permeability zone, leaving the low-permeability zone unswept. To enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT). Once IFT was reduced to ultralow values, the adverse effect of capillarity retaining oil was eliminated. Gravity-driven vertical countercurrent flow then exchanged fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foam flood was 94.6% OOIP, even though foam strength was weak. Recovery with chemical flood (incremental recovered oil/waterflood remaining oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous-force-dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental to foam generation. However, the addition of lauryl betaine to NI (NIB) at a weight ratio of 1:2 (NI:lauryl betaine) made the new blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT-reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1D homogeneous sandpacks and in an oil-wet heterogeneous layered system with a 34:1 permeability ratio.
- North America > United States > Texas (0.68)
- Europe > Netherlands (0.67)
- Asia (0.67)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (9 more...)
Summary A systematic study was made of phase behavior of alkoxyglycidylether sulfonates (AGESs). These surfactants were screened with either NaCl-only brines or NaCl-only brines and n-octane at water/ oil ratio (WOR) ~1 for temperatures between approximately 85 and 120ยฐC. All test cases were free of alcohols and other cosolvents. Classical Winsor phase behavior was observed in most scans, with optimal salinities ranging from less than 1% NaCl to more than 20% NaCl for AGESs with suitable combinations of hydrophobe and alkoxy chain type [ethylene oxide (EO) or propylene oxide (PO)] and chain length. Oil solubilization was high, indicating that ultralow interfacial tensions existed near optimal conditions. The test results for 120ยฐC at WOR~1 have been summarized in a map, which might provide a useful guide for initial selection of such surfactants for EOR processes. Saline solutions of AGESs separate at elevated temperatures into two liquid phases (the cloud-point phenomenon), which may be problematic when they are injected into high-temperature reservoirs. An example is provided that indicates that this situation can be alleviated by blending suitable AGES and internal olefin sulfonate (IOS) surfactants. Synergy between the two types of surfactant resulted in transparent, single-phase aqueous solutions for some blends, but not for the individual surfactants, over a range of conditions including in synthetic seawater. Such blends are promising because both AGES and IOS surfactants have structural features that can be adjusted during manufacture to give a range of properties to suit reservoir conditions (temperature, salinity, and crude-oil type).
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Recent Advances in Surfactant EOR
Hirasaki, George J. (Rice University) | Miller, Clarence A. (Rice University) | Puerto, Maura (Rice University)
Summary In this paper, recent advances in surfactant enhanced oil recovery (EOR) are reviewed. The addition of alkali to surfactant flooding in the 1980s reduced the amount of surfactant required, and the process became known as alkaline/surfactant/polymer flooding (ASP). It was recently found that the adsorption of anionic surfactants on calcite and dolomite can also be significantly reduced with sodium carbonate as the alkali, thus making the process applicable for carbonate formations. The same chemicals are also capable of altering the wettability of carbonate formations from strongly oil-wet to preferentially water-wet. This wettability alteration in combination with ultralow interfacial tension (IFT) makes it possible to displace oil from preferentially oil-wet carbonate matrix to fractures by oil/water gravity drainage. The alkaline/surfactant process consists of injecting alkali and synthetic surfactant. The alkali generates soap in situ by reaction between the alkali and naphthenic acids in the crude oil. It was recently recognized that the local ratio of soap/surfactant determines the local optimal salinity for minimum IFT. Recognition of this dependence makes it possible to design a strategy to maximize oil recovery with the least amount of surfactant and to inject polymer with the surfactant without phase separation. An additional benefit of the presence of the soap component is that it generates an oil-rich colloidal dispersion that produces ultralow IFT over a much wider range of salinity than in its absence. It was once thought that a cosolvent such as alcohol was necessary to make a microemulsion without gel-like phases or a polymer-rich phase separating from the surfactant solution. An example of an alternative to the use of alcohol is to blend two dissimilar surfactants: a branched alkoxylated sulfate and a double-tailed, internal olefin sulfonate. The single-phase region with NaCl or CaCl2 is greater for the blend than for either surfactant alone. It is also possible to incorporate polymer into such aqueous surfactant solutions without phase separation under some conditions. The injected surfactant solution has underoptimum phase behavior with the crude oil. It becomes optimum only as it mixes with the in-situ-generated soap, which is generally more hydrophobic than the injected surfactant. However, some crude oils do not have a sufficiently high acid number for this approach to work. Foam can be used for mobility control by alternating slugs of gas with slugs of surfactant solution. Besides effective oil displacement in a homogeneous sandpack, it demonstrated greatly improved sweep in a layered sandpack.
- Europe (1.00)
- Asia (1.00)
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- Geology > Mineral (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.34)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
- North America > United States > Nebraska > Sloss Field (0.99)
- (4 more...)