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Results
Dynamic Interfacial Tensions and Contact Angles of Surfactant-in-Brine/Oil/Shale Systems: Implications to Enhanced Oil Recovery in Shale Oil Reservoirs
Mirchi, Vahideh (University of Wyoming) | Saraji, Soheil (University of Wyoming) | Goual, Lamia (University of Wyoming) | Piri, Mohammad (University of Wyoming)
Abstract Unconventional shale oil resources have emerged as a significant source of fossil fuels in recent years. The oil contained in shales is held in natural microfractures, micropores, and inside nanopores of the organic matter. The strong capillary forces in these pores can bind the oil to the surface with strengths that are inversely proportional to the pore radius. In order to recover more oil from these pores, it is beneficial to reduce the capillary pressure by manipulating the interfacial tension and contact angle of oil/brine/shale systems using surfactant solutions. The main consideration in surfactant flooding is to optimize brine salinity and surfactant concentration while minimizing their adsorption on rock surfaces. Although the effect of some surfactants on recovery in shale oil reservoirs has been studied in the past, the mechanism is still unclear. Moreover, the limited data available in the literature is not representative of the actual reservoir conditions. The objective of this study is to elucidate the oil displacement mechanisms in shale oil by surfactant flooding. The phase behavior of several anionic surfactants was studied in the presence of crude oil at reservoir temperature (i.e. 80 °C). The results of these tests were used to screen the best surfactants. Dynamic interfacial tensions (IFT) and contact angles (CA) of selected surfactant-in-brine/oil/shale systems were measured by the rising/captive bubble technique using a state-of-the-art IFT/CA apparatus. The apparatus was thoroughly validated with various systems using the axisymmetric drop shape analysis technique. Using the same methodology, the effects of surfactant concentration (0.01 to 0.1 wt%) and brine salinity (0.1 to 5 M NaCl) on IFT and CA at ambient and reservoir conditions (i.e. 80 °C and 3000 psig) were studied. Surfactant adsorption on shale samples was also measured in brines at ambient conditions. Our data reveal that the most effective surfactant was able to reduce the oil-brine IFT from its original value (23 mN/m) down to 0.3 mN/m at reservoir condition. A reduction in the IFT value and an increase in the dynamic contact angle of oil drop on polished shale surface were observed with the addition of surfactant and salt to the system. A trend between these parameters, pressure, and temperature was also reported.
- North America > United States > Louisiana (0.46)
- North America > United States > Texas (0.28)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (7 more...)
Abstract Chemical enhanced oil recovery (EOR) provides the means to increase oil production through manipulation of the chemical and fluid properties within a given reservoir. The number of chemical EOR projects being developed, pilot tested, and commercially implemented is on the rise as a function of the relative decrease in chemical costs, advancements in chemical performance, more precise subsurface modeling, and recent stable oil pricing. The amount of calcium and magnesium (hardness) in the injection water plays a critical role in determining the type and dosage of alkali, surfactant, co-solvents and/or polymer (ASCP) used in a chemical EOR flood. The hardness dictates whether alkali can be used and affects the surfactant adsorption, achievable viscosity at specific polymer dosages, polymer stability, polymer choice as a function of thermal stability, as well as emulsion stability in the produced water. The ability to remove hardness and thereby use soft injection water with chemical EOR is a game changer, in that it can enable chemical floods that are otherwise uneconomic, infeasible or that are considered too risky. Soft water, invariably, comes at a cost related to treating the source water to remove calcium and magnesium. Source water for a chemical EOR flood is dictated by availability and environmental constraints and is usually limited to produced water, seawater or brine from deep aquifers. Occasionally, a surface water source is available. This paper reports on representative chemical EOR project case studies in seawater, brackish water and produced water applications at various sites and capacities. The cost of water softening is weighed against the reservoir and production benefits, culminating in a side-by-side economic analysis for each case study based on cost per incremental barrel of oil. The results can be used to guide the development of new chemical EOR projects in determining facility needs as a function of economics.
- Research Report (0.48)
- Overview (0.34)
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)
Abstract Test results from mixtures of anionic-cationic surfactants significantly broaden the application scope for conventional chemical Enhanced Oil Recovery methods; these mixtures produced ultra low Critical Micelle Concentrations (CMC) as well as ultra-low interfacial tension (IFT) and high oil solubilization that promote high oil recovery. Mixtures of anionic and cationic surfactants with molar excess of anionic surfactant for EOR applications are described herein. Physical chemistry properties, such as surface tension, CMC, surface excess and area per molecule of individual surfactants and their mixtures were measured by Wilhelmy Plate Method. Morphologies of surfactant solutions, both surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP), were studied by Cryo TEM. Phase behaviors were recorded by visual inspection including with crossed polarizers at different surfactant concentrations and different temperatures. Interfacial tensions between normal octane, crude oil and surfactant solution were measured by spinning drop tensiometer method. Properties of interfacial tension, viscosity and thermal stability of surfactant, surfactant-polymer, and alkaline-surfactant-polymer 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, polymer, SP and ASP. The core flooding experiments were conducted with water made of a simulated formation brine having approximately 5000 ppm TDS, and with a crude oil from a Sinopec reservoir.
- North America > United States (1.00)
- Asia > China (0.67)
- Asia > Middle East > Saudi Arabia (0.28)
- Overview > Innovation (0.50)
- Research Report > New Finding (0.46)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Adsorption of a Switchable Cationic Surfactant on Natural Carbonate Minerals
Cui, Leyu (Rice University) | Ma, Kun (Rice University) | Abdala, Ahmed A. (Petroleum Institute University) | Lu, Lucas J. (Rice University) | Tanakov, Ivan (Rice University) | Biswal, Sibani L. (Rice University) | Hirasaki, George J. (Rice University)
Abstract A switchable cationic surfactant, e.g., tertiary amine surfactant Ethomeen C12, has been previously described as a surfactant that can be injected in high pressure 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 high pH and limited solubility. However, when the surfactant solution in brine is equilibrated with high pressure CO2, the pH is about 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 increase in divalent (Ca and Mg) and trivalent (Al) cations. This is due to 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 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 adsorption of C12 or even cause surfactant precipitation.
- North America > United States > Texas (1.00)
- Asia (0.68)
- Geology > Mineral > Carbonate Mineral > Calcite (0.68)
- 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 (0.67)
Switchable Amine Surfactants for Stable CO2/Brine Foams in High Temperature, High Salinity Reservoirs
Elhag, Amro S. (The University of Texas at Austin) | Chen, Yunshen (The University of Texas at Austin) | Chen, Hao (China University of Petroleum) | Reddy, Prathima P. (The University of Texas at Austin) | Cui, Leyu (Rice University) | Worthen, Andrew J. (The University of Texas at Austin) | Ma, Kun (Rice University) | Hirasaki, George J. (Rice University) | Nguyen, Quoc P. (The University of Texas at Austin) | Biswal, Sibani L. (Rice University) | Johnston, Keith P. (The University of Texas at Austin)
Abstract Ethoxylated amine surfactants of the form C12-14N(EO)x have been characterized for foam generation to improve the sweep efficiency for CO2 enhanced oil recovery (EOR) up to 120 °C in the presence of high salinity brine of 22%TDS. 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 below 6. Potentiometric titration of two surfactants with 2 or 15 EO groups was conducted at 90 °C to test the switchability of the surfactant from nonionic to cationic forms at different pH values. Ethoxylated amine with 2 EO groups showed more affinity for protonation when compared to 15 EO due to the hinderance effect of the larger molecule that covers the ionizable nitrogen head. For C12-14N(EO)2, viscous C/W foams were produced by injecting the surfactant either in the CO2 phase or the brine phase, which indicates good surfactant transport to the interface in either case. The optimum foam quality was observed at 90% and 95% when the surfactant was injected from brine phase or CO2 phase, respectively. C12-14N(EO)2 was effective in lowering the interfacial tension between water and CO2 at 120 °C and 22%TDS from ~ 40 mN/m to 5 mN/m with CMC value of 0.038 mM. This significant reduction in interfacial tension enhances foam generation and foam stability.
- Asia (0.94)
- North America > United States > Texas (0.16)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract The current study is focused on the effects of the individual key ions (Ca, Mg, (SO4)) along with a few of other common ions (Na and Cl) on carbonate rock by only injecting water with controlled amount of individual or combined ions into the selected carbonate rock at reservoir temperature. A low field NMR technique has been a tool of choice for the current work since it allows monitoring the physical and chemical alteration of rock surface after interacting with fluids which contain specific types and amount of ions. In addition, since NMR is non-destructive measurement, the effect of various types of fluids with the identical rock sample before, during, and after core flooding test can be monitored repeatedly. NMR results indicate that the water-rock interaction changes when injecting different types of ions. The interaction a of key divalent key ions, Ca, Mg, and (SO4), on the carbonate rock surface are observed with relatively weak reactivity of Ca compare to the other two. At the reservoir temperature, 90°C, the reactivity of Mg with the carbonate rock is greater than that of Ca. The reactivity of multivalent anion (SO4) is also significant with carbonate rock surface, but it will induce surprising behavior on NMR response. The fundamental understandings acquired by the current study, effects of key ions in carbonate rock with single-phase fluid will be one of the key building blocks to develop rigid understanding of more complicated multi-phase fluid interaction with various types of reservoir rocks, and eventually draw conclusions on how these ions change rock wettability.
- Europe (1.00)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
Abstract During a polymer flood, polymer retention can have a major impact on the rate of polymer propagation through a reservoir, and consequently, on oil recovery. A review of the polymer-retention literature revealed that iron and high-surface-area minerals (e.g., clays) dominate polymer retention measurements in permeable rock and sand (>100 md). A review of the literature on inaccessible pore volume revealed inconsistent and unexplained behavior. A conservative approach to design of a polymer flood in high-permeability (>1 darcy) sands would assume that inaccessible pore volume is zero. Laboratory measurements using fluids and sands associated with the Sarah Maria polymer flood in Suriname suggested polymer retention and inaccessible pore volume values near zero. A procedure was developed using salinity-tracer and polymer concentrations from production wells to estimate polymer retention during the Sarah Maria polymer flood in the Tambaredjo reservoir. Field calculations indicated much higher polymer retention values than lab tests, typically ranging from ~50 to 250 μg/g. Field cores necessarily represent an extremely small fraction of the reservoir. Because of the importance of polymer retention, there is considerable value in deriving polymer retention from field results, so that information can be used in the design of project expansions.
- Europe (0.93)
- North America > United States > Oklahoma (0.46)
- North America > United States > Texas (0.46)
- (3 more...)
- Research Report (0.67)
- Overview (0.48)
- Geology > Geological Subdiscipline (0.92)
- Geology > Mineral > Silicate > Phyllosilicate (0.68)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
Charge Control and Wettability Alteration at Solid-Liquid Interfaces
Mugele, Frieder (University of Twente and Ian Collins, BP) | Siretanu, Igor (University of Twente and Ian Collins, BP) | Kumar, Naveen (University of Twente and Ian Collins, BP) | Bera, Bijoy (University of Twente and Ian Collins, BP) | Wang, Lei (University of Twente and Ian Collins, BP) | de Ruiter, Rielle (University of Twente and Ian Collins, BP) | Maestro, Armando (University of Twente and Ian Collins, BP) | Duits, Michel (University of Twente and Ian Collins, BP) | van den Ende, Dirk (University of Twente and Ian Collins, BP)
Abstract Most solid surfaces acquire a finite surface charge upon exposure to aqueous environments due to desorption and/or adsorption of ionic species. The resulting electrostatic forces play a crucial role in many fields of science, including colloidal stability, self-assembly, wetting, and biophysics as well as technology. Enhanced oil recovery is an example of a large scale industrial process that hinges in many respects on these phenomena. In this paper, we present a series of experiments illustrating fundamental aspects of low salinity water flooding in well-defined model systems. We show how pH and ion content of the water phase as well as the presence of model polar components (fatty acids) in the oil phase affect the wettability (i.e. contact angle distribution) of oil-water-rock systems. Specifically, we discuss high resolution atomic force microscopy (AFM) experiments demonstrating the preferential adsorption of multivalent cations to mineral surfaces such as mica and gibbsite. Cation adsorption leads to increased and in some cases reversed surface charge at the solid-liquid interface. In the case of charge reversal, the adsorption process can trigger a wetting transition from complete water wetting in ambient oil (i.e. zero water contact angle) in the absence to partial wetting in the presence of divalent cations. While already dramatic for pure alkanes as base oil, adding fatty acids to the oil phase enhances the effect of divalent ions on the oil-water-rock wettability even more. In this case, contact angle variations of more than 70° can be observed as a function of the salt concentration. This enhancement is caused by the deposition of a thin film of fatty acid on the solid surface. AFM as well as surface plasmon resonance spectroscopy measurement in a microfluidic continuous flow cell directly demonstrate that adsorbed Ca ions promote secondary adsorption of acidic components from the oil phase. The combination of the effects discussed provides a rational scenario explaining many aspects of the success of low salinity water flooding.
Abstract The primary purpose of using surfactants in stimulating hydrocarbon rich gas reservoirs is to reduce interfacial tension, and/or modify contact angle and reservoir wettability. However, many surfactants either adsorb rapidly within the first few inches of the formation, or negatively impact reservoir wettability, thus reducing their effectiveness in lowering capillary pressure. These phenomena can result in phase trapping of the injected fluid adversely impacting oil and gas production. This study describes experimental and field studies comparing various common surfactants used in oil bearing formations including alcohol ethoxylates, EO-PO block copolymers, ethoxylated amines and a multi-phase complex nano fluid system to determine their impact on oil recovery and adsorption tendencies when injected through 5-foot and 1 ft sand columns. Ammot cell tests were used to evaluate imbibition of oil and water and a core flow apparatus was used to evaluate regained relative permeabilities. The results are correlated with surface energies of actual formation materials, oils and treating fluids. The results are used to select formulations containing surfactant, solvents and co-solvents to apply within the fracturing fluid to decrease adsorption, eliminate post treatment emulsions and improve oil and gas recovery in hydrocarbon rich gas wells.
- North America > Canada (0.69)
- North America > United States > Texas (0.46)
- North America > United States > West Virginia (0.28)
- (2 more...)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (11 more...)
Abstract Supercritical carbon dioxide (CO2) flooding is a widely used method in tertiary oil recovery; however, there are many challenges such as inefficient gas utilization, poor sweep efficiency and low oil recovery due to viscous fingering and gravity segregation. One recent development is the application of CO2 foam in order to reduce the CO2 mobility, especially in high permeability zones of the reservoir. However, the efficiency of the CO2 foam often decreases sharply during flooding as a result of contact with crude, adsorption of surfactants, high salinity in formation water and high reservoir temperature. Surfactant formulations which have better tolerance to these factors can greatly enhance the CO2 utilization, reduce the cost of surfactant, and improve the oil recovery. A series of formulations, including various surfactants and corresponding micro-emulsions, were evaluated as CO2 foaming agents in lab-based heterogeneous sandstone equipment at reservoir temperatures and pressures. This paper describes formulating high temperature CO2 foaming agent with co-surfactants and in a micro-emulsion system to improve crude, salt and temperature tolerance and minimize adsorption in order to place the foamer further into the formation.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- 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)
- (21 more...)