Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Unconventional and Complex Reservoirs
Abstract Historical production data from unconventional oil wells show rapid decline, that leads to low ultimate recovery. With more and more production wells entering low rate period, itโs critical to conduct well stimulation to recover more from existing wells. Alternate application scenarios for production enhancement is during parent pressure up operations. Operators usually pump large volume water to parent well to prevent frac-hit while performing hydraulic fracturing. EOR application can be easily combined into this process to achieve multiple goal the same time. Microbial EOR has been developed as an environmentally friendly EOR technology. The objective of this paper is to present the full cycle of a MEOR process, from microbiology theory, to prove concept though lab experiments, then to implementation in field. The lab laboratory experiments are to investigate the mechanism that the microbes can be stimulated and effective to clean up near wellbore fractures. The field trials are to demonstrate the effectiveness of MEOR to shale wells. Field results show that MEOR can be an economical effective approach to add reserves to shale wells at low cost. Additional value of microbial technology is that it doesnโt change oil and water quality in production, then there is no treatment cost as other stimulation methods.
- Europe (0.47)
- North America > United States > Texas (0.35)
- Geology > Geological Subdiscipline (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (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...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Microbial methods (1.00)
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 recoveryโboth 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 160ยฐF 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 โhuff-and-puffโ 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 EORโboth 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)
Comprehensive Evaluation of a Novel Recrosslinkable Hyper Branched Preformed Particle Gels for the Conformance Control of High Temperature Reservoirs
Song, Tao (Missouri University of S & T) | Ahdaya, Mohamed (Missouri University of S & T) | Zhao, Shuda (Missouri University of S & T) | Zhao, Yang (Missouri University of S & T) | Schuman, Thomas (Missouri University of S & T) | Bai, Baojun (Missouri University of S & T)
Abstract The existence of high conductivity features such as fractures, karst zones, and void space conduits can severely restrict the sweep efficiency of water or polymer flooding. Preformed particle gel (PPG), as a cost-effective technology, has been applied to control excessive water production. However, conventional PPG has limited plugging efficiency in high-temperature reservoirs with large fractures or void space conduits. After water breakthrough, gel particles can easily be washed out from the fractures due to the lack of particle-particle association and particle-rock adhesion. This paper presents a comprehensive laboratory evaluation of a novel water-swellable high-temperature resistant hyper-branched re-crosslinkable preformed particle gel (HT-BRPPG) designed for North Sea high-temperature reservoirs (130 ยฐC), which can re-crosslink to form a rubber-like bulk gel to plug such high conductivity features. This paper systematically evaluated the swelling kinetics, long-term thermal stability and plugging performance of the HT-BRPPG. Bottle tests were employed to test the swelling kinetic and re-crosslinking behavior. High-pressure resistant glass tubes were used to test the long-term thermal stability of the HT-BRPPG at different temperatures, and the testing lasted for over one year. The plugging efficiency was evaluated by using a fractured model. Results showed that this novel HT-BRPPG could re-crosslink and form a rubber-like bulky gel with temperature ranges from 80 to 130 ยฐC. The elastic modulus of the re-crosslinked gel can reach up to 830 Pa with a swelling ratio of 10. In addition, the HT-BRPPG with a swelling ratio of 10 has been stable for over 15 months at 130 ยฐC so far. The core flooding test proved that the HT-BRPPG could efficiently plug the open fractures, and the breakthrough pressure is 387.9 psi/ft. Therefore, this novel BRPPG could provide a solution to improve the conformance of high-temperature reservoirs with large fractures or void space conduits.
- Europe > Norway > North Sea (0.34)
- Europe > United Kingdom > North Sea (0.25)
- Europe > North Sea (0.25)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock (0.88)
- Geology > Geological Subdiscipline (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Europe > United Kingdom > North Sea > Central North Sea > Utsira High > PL 006 > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Conformance Improvement in Fractured Tight Reservoirs Using a Mechanically Robust and Eco-Friendly Particle Gel PG
Wei, Bing (Southwest Petroleum University) | Mao, Runxue (Southwest Petroleum University) | Tian, Qingtao (Southwest Petroleum University) | Xu, Xingguang (China University of Geosciences) | Wang, Lele (Southwest Petroleum University) | Tang, Jinyu (United Arab Emirates University) | Lu, Jun (The University of Tulsa)
Abstract Conformance control in tight reservoirs remains challenging largely because of the drastic permeability contrast between fracture and matrix. Thus, reliable, durable and effective conformance improvement methods are urgently needed to increase the success of EOR plays in tight reservoirs. In this work, we rationally designed and prepared a mechanically robust and eco-friendly nanocellulose-engineered particle gel (referred to NPG) toward this application due to the superior stability. The impacts of superficial velocity, NPG concentration and particle/fracture ratio on the transport behavior in fracture were thoroughly investigated. We demonstrated that the mechanical properties of NPG such as strength, elasticity, toughness and tensile strain were substantially promoted as a result of the interpenetrated nanocellulose. During NPG passing through fracture model, it produced a noticeably greater flow resistance in comparison with the control sample (nanocellulose-free), suggesting the better capacity in improving the conformance of fractured core. It was found that the generated pressure drop (ฮP) was more dependent on the particle/fracture ratio and NPG concentration.
- North America > United States (1.00)
- Asia > China (0.68)
- Asia > Middle East > UAE (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Abstract As the unconventional shale development matures, the industry has been actively seeking new ways to unlock incremental value beyond primary depletion. In particular, the miscible gas injection EOR via huff-and-puff technique has garnered interest in recent years. However, the pilot tests in the field have shown lower recoveries than initially predicted by laboratory and simulation studies. The objective of this study was to develop a systematic approach to upscale the EOR results from laboratory scale to field scale and better predict recoveries. One of the issues with existing laboratory and modeling studies is the assumption of constant-pressure or constant-rate boundary conditions at the fracture interface during the soaking stage, which is rarely achieved. A mathematical model is developed to represent this scenario better by modeling mass diffusion of a limited volume of well-stirred fluid in a non-porous body (remaining injected gas in the fracture network at the end of injection phase as compressed gas) into a porous medium (matrix). The matrix is characterized as an ensemble of rock pillars separated by fracture discontinuities to represent field conditions better. The rock pillars are of different thicknesses, with their thickness gradually increasing, moving away from the main fracture cluster. And finally, the concept of Dynamic Penetration Volume, which controls the amount of contacted oil by the EOR agent, is explored further as a function of the micro-fracture distribution function. Ultimately, this information was used to derive an updated a priori equation to better predict recovery factors of EOR processes in the field. For upscaling, we integrated concepts from both geomechanics and fluid flow. We used an existing correlation relating the fracture frequency & distribution observed in the lab-scale experiments to the fracture density in the field. By doing so, we can upscale the micro-fracture distribution to their field-scale counterparts. Although diffusion is the main transport & recovery mechanism, this study found that the fracture geometry created near-wellbore, i.e., fracture spacing & distribution, has a first-order effect on the efficacy of the huff-and-puff process in the field. It was also observed that by varying the soaking times of each cycle, the issue of penetration length could be resolved (as it increases as a function of โtime). Additionally, focusing on understanding the near-wellbore fracture geometry would help operators optimize their gas injection schemes. The updated upscaling equation will help understand the huff-and-puff process better and predict the expected recoveries in the field more accurately. Additionally, it would help operators adjust and optimize soaking times for the process using a mechanistic approach.
- North America > United States > Texas (1.00)
- North America > Canada (0.93)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing (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)
- (2 more...)
Gas-Oil Ratio GOR Characterization of Unconventional Wells in Eagle Ford
Zhao, Yajie (The University of Texas at Austin) | Nohavitza, Jack (EP Energy) | Williams, Ryan (EP Energy) | Yu, Wei (SimTech LLC) | Fiallos-Torres, Mauricio Xavier (SimTech LLC) | Ganjdanesh, Reza (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Abstract With the increased exploration and development of unconventional reservoirs, the complicated production mechanisms of unconventional wells have gradually become a hot topic among the oil and gas industry. Due to the ultra-low permeability and porosity, the fluid phase behavior in shale reservoirs significantly differs from the conventional fluid phase behavior, increasing the production forecasting complexity. A substantial effort to better understand the mechanisms is the ability to characterize the unconventional well gas-oil ratio (GOR) behavior. The GOR always plays a critical indicator to help predict long-term oil/gas production trends and develop appropriate production strategies. In this paper, GOR behavior was discussed based on an unconventional parent-child horizontal well set in the Eagle Ford shale formation. Subsequently, fracture hit intensity can be determined through the producing GOR characterization. Afterward, the historical production data were well matched. The long-term GOR trends (20 years) were then predicted with the calibrated reservoir model. Based on the simulation results, an interpretation of the fracture hit impact on GOR behavior, and the well productivity was established. This study provides some key insights into GOR behaviors, especially for the parent-child well GOR trends with considering the impact of fracture hits. The Eagle Ford GOR is strongly influenced by the flowing bottomhole pressure. Meanwhile, the GOR trends of both parent and child wells are extremely sensitive to fracture hits, strong correlations between GOR and fracture hits are observed. Compared to the parent well, the flat GOR period of the child well is much shorter due to pressure depletion. The existence of a child well also reduces the rising speed of the parent well with a lower plateau. In addition, the long-term production prediction shows that fracture hits negatively influenced both well performances, where the child well has a more severe production loss than the parent well. Through the findings presented in this work, a better understanding of the unconventional well GOR behaviors can be obtained. The analysis approaches proposed in this paper provide valuable insights into GOR characterization and contribute to the production forecasting from unconventional plays. The results can help to improve the efficiency of reservoir management, field development, and economic valuation in future projects.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.76)
- Geology > Petroleum Play Type > Unconventional Play (0.55)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
- 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 > Formation Evaluation & Management (1.00)
- (2 more...)
Abstract Conventional in-situ upgrading techniques use electric heaters to heat oil shale. However, the efficiency of electrical heating method is very slow which requires preheating more than a year. Most conventional heating technologies focused on converting the oil shale, not shale oil reservoirs. The shale oil matrix is very tight and the pore scale is in micro to nano-meter. In this paper, it has been attempted to inject air into hydraulically fractured horizontal wells to create in-situ combustion of shale oil in ultra-low permeability formations. Heat is introduced into the formation through multistage fractured horizontal wells, which enhances the contact area of exposed kerogen. The main focus of this paper is to evaluate the technical feasibility of recovering shale oil resources by air injection. It involves the application of hydraulic fracturing technology to enhance the kerogen exposure to oxygen. Heat flows from the fracture into shale oil formation, gradually converting the solid kerogen into mobile oil and gas, which can be produced via fractures to the production wells.
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin > Lucaogou Formation (0.99)
- Asia > Russia > West Siberian Basin > Bazhenov Formation (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 9/28a > Crawford Field (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Abstract The Hydraulic Fracturing Test Site (HFTS) in the Permian-Midland basin has bridged the gap between inferred and actual properties of in-situ hydraulic fractures by recovering almost 600 feet of the whole core through recently hydraulically fractured upper and middle Wolfcamp formations. In total, over 700 hydraulically induced fractures were encountered in the core and described, thus providing indisputable evidence of fractures and their attributes, including orientation, propagation direction, and composite proppant concentration. This fracture data, along with the collected diagnostics, support testing and calibration of the next generation fracture models for optimizing initial completion designs and well spacing. In addition, with a massive number of existing horizontal wells in the Permian, the collected data is also useful for designing and implementing enhanced oil recovery (EOR) pilots to improve resource recovery from the existing wells. It is known from the literature that the primary recovery from the shale wells is typically about 5-10% of the original oil in place. Therefore, tremendous potential exists in the Permian to recover additional hydrocarbons by implementing appropriate EOR techniques on the existing wells. To explore this concept, Laredo Petroleum and GTI have agreed to perform HFTS Phase-2 EOR field pilot near the original HFTS, supported by funding from the U.S. Department of Energy and industry sponsors. The Phase-2 EOR field pilot involves injecting field gas into a previously fracture stimulated well in order to produce additional oil using huff-and-puff technique. During the course of the EOR experiment, a second slant core well was drilled near the injection/production well to capture and describe some of the fractures which served as a conduit for the injected gas field during the injection or "huff" period and the produced fluids during the production or "puff" period. The overreaching goals of the HFTS Phase-2 EOR experiment is to determine the effectiveness of cycling gas injection in increasing the oil and gas recovery from the Wolfcamp shale. Specific objectives included: 1. Drill, core, and instrument a second slant core well to describe the fracture network in the vicinity of an EOR injector/producer well 2. Perform laboratory experiments to determine the phase behavior, including black oil study, slim tube analysis, swell testing, etc. 3. Demonstrate how natural gas and/or CO2 increases the oil recovery from Wolfcamp shale through core flooding experiments 4. Determine if pre-existing stimulated horizontal wells can be re-pressurized above the miscibility pressure using the field gas 5. Perform numerical 3D reservoir simulations to predict EOR injection/production performance 6. Instrument offset wells and collect diagnostic data during the cyclic gas injection and production test. This paper describes the EOR field pilot along with the collected data and performed analyses noted above.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.77)
- Geology > Geological Subdiscipline (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (6 more...)
- 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 > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Information Technology > Modeling & Simulation (0.66)
- Information Technology > Communications > Networks (0.46)
Abstract This paper introduces a new approach for using solvents for enhanced oil recovery from organic-rich unconventional reservoirs. The heavy organic components in the reservoir rock, i.e. bitumen, are included in the phase behavior model using a cubic equation-of-state. The phase behavior of mixtures of methane, CO2, and dimethyl ether (DME) with reservoir hydrocarbons including bitumen was studied to better understand the interaction of each solvent with reservoir fluids including water in the case of DME. The phase behavior models were then used in an equation-of-state compositional reservoir simulator to explore the potential of each solvent to increase the oil recovery including otherwise immobile bitumen from a 3D heterogeneous reservoir.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (2 more...)
Abstract Classical waterflooding methods which rely on water displacing oil are not plausible in unconventional shale reservoirs because of the low permeability of such reservoirs because the pressure gradients required to push the water through the reservoir matrix rock is impractical. However, when the shale reservoir is stimulated via multistage hydraulic fracturing a large number of microfractures form which provides a preferred pathway when subsequently water is injected into the reservoir. If this water has low salinity compared to the salinity of the resident brine in the matrix pores, an osmotic pressure gradient establishes between microfractures and the matrix pores that would cause water to enter the matrix pores and pushing oil out. In oil-wet shale reservoirs, this osmotic pressure allows brine imbibition into the matrix that promotes counter-current flow of oil into the fractures. In our research, this phenomenon was studied via carefully designed osmotic imbibition experiments that used low- salinity brines. Furthermore, adding a simple surfactant, or a wettability altering chemical, not only could enhance imbibition of water into the matrix, it can also create a low-IFT environment that would break the oil droplets into smaller ones to facilitate oil movement out of the micro and macro fractures to enhance oil recovery from the matrix. To scale laboratory results and observations to the field conditions, a multi-component mass transport model that includes advective and diffusive transport of water molecules was developed and used to match experimental results. We will present the core imbibition and numerical modeling results that indicate that low salinity brine plus a dilute surfactant enhances oil production. This paper pertains to a research effort conducted to assess the potential of a new EOR method, which involves the use of a mixture of low-salinity brine and low-concentrations of a surfactant or wettability altering chemical. In what follows, we will present the core flooding and numerical modeling results pertaining to the research objective. The results are intended to be used as the basis for designing economic EOR field applications in unconventional shale reservoirs.
- North America > United States > Colorado (0.95)
- North America > United States > Texas (0.70)
- 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 (1.00)