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Collaborating Authors
Oil & Gas
Enhanced Oil Recovery Experiments in Wolfcamp Outcrop Cores and Synthetic Cores to Assess Contribution of Pore-Scale Processes
Kamruzzaman, Asm (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Kneafsey, Timothy J (Lawrence Berkeley Laboratory) | Reagan, Matthew T (Lawrence Berkeley Laboratory)
Abstract This paper assesses the pore- and field-scale enhanced oil recovery (EOR) mechanisms by gas injection for low permeability shale reservoirs. We performed compression-decompression laboratory experiments in ultratight outcrop cores of the Permian Basin as well as in ceramic cores using n-dodecane for oil. The EOR assessment strategy involved determining the quantity of oil produced after injection of helium (He), nitrogen (N2), methane (CH4), and methane/carbon dioxide (CH4/CO2) gas mixtures into unfractured and fractured cores followed by depressurization. Using the oil recovery volumes from cores with different number of fractures, we quantified the effect of fractures on oil recovery—both for Wolfcamp outcrop cores and several ceramic cores. We observed that the amount of oil recovered was significantly affected by the pore-network complexity and pore-size distribution. We conducted laboratory EOR tests at pore pressure of 1500 psia and temperature of 160°F using a unique coreflooding apparatus capable of measuring small volumes of the effluent oil less than 1 cm. The laboratory procedure consisted of (1) injecting pure n-dodecane (n-C12H26) into a vessel containing a core which had been moistened hygroscopically and vacuumed, and raising and maintaining pressure at 1500 psia for several days or weeks to saturate the core with n-dodecane; (2) dropping the vessel pressure and temperature to laboratory ambient conditions to determine how much oil had entered the core; (3) injecting gas into the n-dodecane saturated core at 1500 psia for several days or weeks; (4) shutting in the core flooding system for several days or weeks to allow gas in the fractures to interact with the matrix oil; (5) finally, producing the EOR oil by depressurization to room pressure and temperature. Thus, the gas injection EOR is a ‘huff-and-puff’ process. The primary expansion-drive oil production with no dissolved gas from fractured Wolfcamp cores was 5% of the initial oil in place (IOIP) and 3.6% of IOIP in stacked synthetic cores. After injecting CH4/CO2 gas mixtures, the EOR oil recovery by expansion-drive in Wolfcamp core was 12% of IOIP and 8.2% of IOIP in stacked synthetic cores. It is to be noted that the volume of the produced oil from Wolfcamp cores was 0.27 cm while it was 6.98 cm in stacked synthetic cores. Thus, while synthetic cores do not necessarily represent shale reservoir cores under expansion drive and gas-injection EOR, these experiments provide a means to quantify the oil recovery mechanism of expansion-drive in shale reservoirs. The gas injection EOR oil recovery in Wolfcamp cores with no fractures yielded 7.1% of IOIP compared to the case of one fracture and two fractures which produced 11.9% and 17.6% of OIP, respectively. Furthermore, in the no-fracture, one-fracture, and two-fracture cores, more EOR oil was produced by increasing the CO2fraction in the injection gas mixture. This research provides a basis for interpreting core flooding oil recovery results under expansion drive and gas injection EOR—both in presence and absence of interconnected micro- and macro-fractures in the flow path. Finally, the CO2 injection results quantify the CCUS efficacy in regard to the amount of sequestered CO2 from pore trapping in the early reservoir life. For the long-term CO2 trapping, one needs to include the chemical interaction of CO2 with the formation brine and rock matrix.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.89)
- Overview (0.67)
- Research Report (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Abstract Wettability alteration considered as the principal mechanism has attracted more attention for low salinity waterflooding effect. It was significantly affected by electrokinetic interactions, which occurred at the interfaces of rock/brine and crude oil/brine. The mineral impurities of natural carbonate releasing ions have an important impact on the electrokinetics, which could lead to wettability shift subsequently. In this study, the effect of dolomite and anhydrite as the main impurities in natural carbonate, which caused wettability alteration, was evaluated using triple-layer surface complexation and thermodynamic equilibrium models coupled with extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. The electrokinetics of crude oil and carbonate in brines were predicted by the triple-layer surface complexation model (TLM) based on zeta potential, while thermodynamic equilibrium model was mainly used for analyzing the carbonate impurities on wettability alteration. The equilibrium constants of reactions were determined by successfully fitting the calculated zeta potentials with measured ones for crude oil and carbonate in different solutions, which were validated for zeta potential prediction in smartwater. The disjoining pressure results show that there is a repulsion between crude oil and carbonate in Na2SO4 brine (Brine3) or smartwater (Brine4) equilibrating with calcite when comparing to that in MgCl2 (Brine1) and CaCl2 (Brine2), indicating the water-wet condition caused by the presence of sulphate ions. Moreover, the equilibrium of carbonate impurities with smartwater increases the repulsion between oil and carbonate. When the sulphate ion concentration in the adjusted smartwater exceeds a certain value, the effect of carbonate impurities on wettability alteration is not significant. Finally, the influence of smartwater pH on the interaction between oil and carbonate was evaluated with or without considering the equilibrium of carbonate impurities.
- North America > United States (0.68)
- Europe (0.46)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Sulfate (0.79)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.51)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
Abstract We have investigated the interfacial properties at a brine-hydrocarbon boundary with the prospect of understanding the crystallization process that takes place when certain electrolytes are present in the brine and when certain surfactants are present in the hydrocarbon phase. This was done in an optical force tensiometer setup with a so-called buoyant droplet configuration. It is only specific combinations (that is not all surfactants not all electrolytes) that form crystals and we aim at utilizing this specificity to form crystal plugs in particular sections of an oil reservoir, for example in zones with high flow that can then be reduced by the crystal plugs. The treatment can potentially be tailored based on the predominant acid-type in a mixture. The current study reveals several (at least three) different modes of crystal formation. The electrolyte-surfactant combination that gives rise to the most clear-cut formation of crystals directly at the interface is involving Zn or Cu and dodecanoic acid (C11H23COOH). Several of the systems under study appears to be forming crystals within the hydrocarbon phase and that these crystals more the likely are a result of the surfactant associated diffusive transfer of cations into the hydrocarbon phase. The next short-term goal is to induce crystals when the hydrocarbon phase is (potentially spiked) crude oil to tailor the discoveries towards the longer-term goal: In-situ deep conformance control field applications.
Abstract Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping, dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geological traps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden. Maximizing storage while minimizing overburden stress in the near term depends on residual trapping in the swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiency and capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foam applications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both properties reduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foam generation, better injectivity, and better prospects for long-distance foam propagation at low pressure gradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil, as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency while reducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helps equalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reduces gravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, either through pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-design strategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research on CO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Oklahoma (0.68)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- 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)
- (43 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract The wettability alteration is the most prominent mechanism for a favorable effect of low salinity water flooding in enhanced oil recovery. It has been accepted that the surface charge at crude oil/brine and rock/brine interfaces significantly influences the interaction of the crude oil with rock surface and thus wettability changes. In this study, the interface characteristics were coupled with a solute transport model to simulate low salinity waterflooding in carbonate and sandstone reservoirs. The ionic transport and two- phase flow of oil and water equations were solved and coupled with IPhreeqc for geochemical calculations. The dissolution and precipitation of minerals were considered thorough thermodynamic equilibrium reactions in IPhreeqc. In addition, a triple layer surface complexation model was employed in IPhreeqc to predict electrokinetic properties of crude oil/brine and rock/brine interfaces. The wettability alteration was calculated based the adsorbed polar components of crude oil on minerals’ surface, which changes the relative permeability. The coupled model able to predict the spatiotemporal variation of ionic profiles, surface and zeta potentials, dissolution and precipitation of minerals, total disjoining pressure, and wettability index in addition to oil recovery for the injection of brines. The validity of the coupled model results was tested against PHREEQC in a single-phase flow without the presence of oil. Moreover, the modelling results were compared with the published experimental data for a single-phase flow in carbonate cores. A very good agreement between experimental data and modelling results was obtained. Furthermore, the coupled model was applied to predict ionic concentration, pH profile, and oil recovery in both carbonate and sandstone cores and verified with experimental data. The modelling results reproduce well the experimental data, suggesting that model captures the geochemical and interface reactions. Finally, the coupled model can be used to optimize brine composition for improved oil recovery in carbonate and sandstone reservoirs.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
Abstract This paper presents a new wettability alteration model based on surface complexation theory and an extensive experimental dataset. The objective is to provide a general correlation for contact angle calculation that (1) captures the main mechanisms that impact rock-brine-oil wettability and (2) minimizes the number of parameters used to tune with experimental data. We compile a set of 141 zeta-potential and contact-angle measurements from the literature. We study the oil/rock surface-complexation reactions and model the electrostatic behavior of each data point. We develop a new wettability model that estimates the contact angle and consists of five terms based on the Young-Laplace equation. We use the Nelder-Mead optimization algorithm to determine the model-parameter values that produce the best fit of experimental observations. The contact angle estimates produced by our model are also verified against those calculated by Extended-Derjaguin-Landau-Verwey-Overbeekand (EDLVO) theory and are validated using UTCOMP-IPhreeqc to simulate five limestone Amott tests from the literature. The Blind-testing test reveals that our model is predictive of the experimental data (R = 0.81, RMSE = 12.5). While reducing the tuning parameters by half, our model is comparable to and–in some cases–even superior to the EDLVO modeling in predicting the contact angle measurements. We argue that EDLVO modeling has 10+ parameters, and the individual errors associated with each parameter could lead to wrong predictions. Amott-test simulations show excellent agreement between the proposed wettability-alteration model and experimental data. The rock's initial wettability was measured to be strongly oil-wet, with a negative Amott index and recovery factor around 5%, corroborating the calculated contact angle of 160 degrees. The recovery factor increases to about 20-35% as the rock becomes more water-wet after interaction with engineered water (contact angle changes to 90-64 degrees). Further analysis indicates the proposed model's capability to capture significant wettability-alteration trends. For example, we report increased water-wetting as brine ionic strength decreases, depicting the low-salinity effect. In addition, our model resulted in better convergence in some of the simulated core floods compared to EDLVO modeling. We conclude that our physics-based and data-driven model is a practical and efficient approach to predict rock-brine-oil wettability.
- Geology > Geological Subdiscipline (1.00)
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- North America > United States > Texas (0.89)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.67)
SmartWater Based Synergistic Technologies: A Next Recovery Frontier for Enhanced Oil Recovery
Ayirala, Subhash C. (Saudi Aramco) | AlSofi, Abdulkareem M. (Saudi Aramco) | AlYousef, Zuhair A. (Saudi Aramco) | Wang, Jinxun (Saudi Aramco) | Alsaud, Moataz O. Abu (Saudi Aramco) | AlYousef, Ali A. (Saudi Aramco)
Abstract In this work, the synergistic effects of SmartWater in polymer flooding, surfactant-polymer flooding, carbonated waterflooding, and foam assisted gas injection processes were explored. A suite of multiscale experimental data was analyzed to demonstrate and quantify the benefits of water chemistry synergies in these different enhanced oil recovery (EOR) methods. The multiscale experimental data analyzed comprised of polymer rheology, core floods, foam stability and rheology, besides evaluating the zeta potential results obtained from surface complexation modeling (SCM). SmartWater increased the oil recoveries by 5-7% in addition to reducing the polymer concentration requirements by one-third in polymer flooding. Synergizing SmartWater with surfactant-polymer flooding increased the oil recovery by 4% besides lowering the polymer and surfactant consumption by 50%. SmartWater has been found to synergistically combine with carbonated waterflooding to increase the CO2 dissolved volumes by 25-30% for effectively lowering the pH at both calcite/brine and crude oil/brine interfaces. The availability of more CO2 dissolved volumes in SmartWater can cause enhanced oil swelling, greater oil viscosity reduction, and increased wettability alteration through pH induced modification of surface charges for higher oil recovery. SmartWater increased the foam stabilities by 2-3 times, foam apparent viscosities by 1.5 times, and porous media foam pressure drops by 50% to ensure the propagation of more stable and viscous foams deeper into the reservoir for better mobility control. The findings of this study have a practical impact on how the industry can efficiently operate EOR projects. SmartWater-based synergistic technologies can reduce the costs due to lowered volume requirements of different EOR agents and they can also increase oil recoveries to result in more practical, efficient, and economical EOR projects in the field.
- Asia > Middle East (1.00)
- North America > United States > Oklahoma (0.15)
Abstract Injection of solvents (hydrocarbons in liquid and gas form or CO2 and their combinations) is an alternative method for heavy and extra heavy-oil recovery where thermal methods cannot be applied, like in thin reservoirs, wormholed reservoir after-CHOPS (cold heavy-oil production with sands), or fractured reservoirs. The solvents normally exist in their liquid or supercritical phase under reservoir conditions and may not be miscible with heavy oil at first contact. Coupling with the fact that diffusion into highly viscous fluids tends to be very slow and an interface exists in the first contact of liquid solvent and oil, displacement by capillary imbibition may take place. This displacement eventually improves the contact area between oil and solvent and results in enhancement of the mixing process by diffusion. To understand this phenomenon and fully capture the interaction of solvent and heavy oil in different rock systems, experimental investigations were conducted using sandstone and limestone core samples. The samples were saturated with different types of oils (viscosities ranging between 14 and 170,000 cP) and the solvents tested were heptane, propane, decane, CO2, and naphtha. To maintain the pressure of propane and CO2 above the saturation pressure, a specially designed high-pressure imbibition cell was used and the imbibition-diffusion process was visualized through the glass window of the cell. The color of the mixture and the amount and the shape of produced oil over time was used to analyze the mass transfer and flow behavior qualitatively and quantitatively by observing the evolution of oil production from core samples that were saturated with heavy oil and then immersed into solvents. We observed that in the solvent/heavy oil system, where molecular diffusion is a slow process, a dynamic interfacial tension IFT exists, but vanishes over time; when the CO2 is in the non-wetting phase the capillary force acts to retain the oil in porous media. As the IFT is reduced, capillary force is weakened and gravity governs the process. Hence, the fluid saturation in the porous media is totally determined by density and viscosity difference. If the wettability of the rock is altered during the process from oil-wet to more CO2 wet, because of oil-rock interaction, then it is possible for the porous media to spontaneously imbibe CO2.
- North America > United States (0.68)
- Asia > Middle East (0.67)
- North America > Canada > Alberta (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Despite the plethora amount of research have been conducted on the Low Salinity Water Injection (LSWI) and the pertinent mechanisms, this Enhanced Oil Recovery (EOR) method still seems not to be well understood. Although the rock/fluid interactions are used to be highlighted as the main elements of chemical mechanism of LSWI, fluid/fluid interactions have been brought into attentions much more than anytime before. Formation of microdispersion within the crude oil phase leading to wettability alteration has been proposed repeatedly as the underlying mechanism of LSWI without clarifying the functional compounds of crude oil toward this EOR method. Discovering the responsible compounds of crude oils towards Low Salinity Water (LSW) and formation of microdispersion is demanding to achieve a reliable screening tool of oil reservoir toward LSWI. For this purpose, the crude oils and brines were contacted for an extended period of time until the oil/water interface reached an equilibrium state right before taking crude oil samples from the interface. The Karl Fischer titration (KFT) analyses were carried out to quantify the amount of microdispersion within the crude oil phase. The crude oil sample with the strongest propensity toward microdispersion formation was further investigated through Fourier Transform Infrared (FT-IR) spectroscopy and Negative Electrospray Ionisation (NESI) mode of Fourier Transform Ion Cyclotron Resonance mass spectroscopy (FT-ICR) to evaluate the chemical compositional changes taking place at the interface due to salinity effect. FT-IR analyses revealed the conjugated acidic compounds or the acidic asphaltenes within the crude oil to be the most functional compounds toward microdispersion formation. Consistently, the NESI mode of FT-ICR MS suggested the carboxylic acids (with C=O functional groups) promoting the formation of microdispersion when the crude oil is swept by LSW. Also highlighted was the structure of functional carboxylic acids during LSWI that appeared to be those compounds with DBE of 1, 2, and 3 and carbon number of C15-C20. The results of this study represent an important step toward understanding the mechanism responsible for the LSE. The knowledge will help the oil and gas industry in the task of evaluating and ranking oil reservoirs for EOR by LSWI.
- North America > United States (0.93)
- Europe > United Kingdom (0.68)
- Geology > Geological Subdiscipline (0.69)
- Geology > Mineral (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.62)
Abstract Injection of modified salinity brines modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks is relevant to improved oil recovery operations. Many reports in the literature relate the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which cause wettability alterations at the rock surface. Little attention seems to have been placed on fluid-fluid interactions as a potential mechanism in displacement processes. In this work, we investigate the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations are correlated to visual observations of displacement processes to investigate the role of crude oil snap-off. A series of microfluidic chips featuring pore throats that are 50μm in diameter are used to observe snap-off as a function of salinity in the displacing fluid. The flow experiments suggest that, in a water-wet constricted pore throat, SWS brines suppress crude oil snap-off as compared to FWS brine. This behavior is correlated to the higher surface elasticity of oil-SWS interface than that of oil-FWS interface. Higher surface elasticity suppresses the expansion of the thin water film coating pore throat walls and hence increases the capillary number at which snap-off of the crude oil phase is expected to occur. Moreover, water interacts with the polar components to form reverse micelles called microdispersions. These microdispersions are observed in the aged chip near the oil-brine interface in the pore-network of a microfluidic device. Similarly, in a vial test performed by Tetteh and Barati, (2019), microdispersion formation was only observed very close to the oil-brine interface, caused by the transport of water molecules into the oil phase. These microdispersions remobilize and redistribute the oil, and along with a slight change in wettability in the medium, they improve the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributable to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.
- Geology > Mineral (0.93)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.36)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)