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surfactant
In the shale business, the closest thing now to enhanced oil recovery (EOR) is improved techniques. During an earnings call last November an analyst asked EOG Resources executives about their enhanced completion technique which EOG reported was adding 20% to first-year well production in the Permian. Improved completions have allowed operators to significantly increase early production year after year, but after that, steep declines are a given. Back in 2016, EOG was talking about how it was increasing oil production significantly by injecting millions of cubic feet of gas a day into wells in the Eagle Ford. It triggered an EOR field-testing boom by competitors hoping to match reported reserve increases of โ30 to 70%.โ In a 2017 JPT story, Deepak Devegowda, a petroleum engineering professor at the University of Oklahoma, said, โThis is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR.โ Now the only mention of the acronym EOR on EOGโs website is an item in its corporate history timeline for 2016: โWe commercialized the first enhanced oil recovery process, or EOR, in shale.โ In recent years, reported shale EOR work has been mostly in the form of occasional papers describing production uplift by companies selling ways to increase production by injecting gas or chemicals. EOR effectiveness isnโt the issue, according to Todd Hoffman, a petroleum engineering professor at Montana Tech University who wrote two papers evaluating EOGโs methods cited in two Chevron papers. โThe EOG field work showed us that these projects can produce significant additional oil and be economically positive,โ he said. The problem is that drilling and fracturing wells delivers โhigher economic returns than the EOG-style EOR projects with the huge compressors, high gas rates, and high injection pressures.โ Last year in the middle of this EOR drought, Chevron did something different. It delivered two papers revealing a major company-scale effort to find ways to use chemical and gas injections to economically produce more oil. The papers presented at the 2023 Unconventional Resources Technology Conference (URTeC) reported on field tests of surfactants and natural gas injection on Permian Basin wells which delivered sufficiently encouraging results to justify an expanded testing program. (URTeC 3870505 and URTeC 3871386). Chevron described a systematic effort by its corporate technical unit and its Mid-Continent business unit to rethink shale EOR methods based on the unconventional nature of flow through fractured reservoirs and the economic realities in a business where new EOR technology is competing with the profitable status quo. Its methods challenge accepted notions about the role of EOR. In SPEโs disciplines, EOR normally falls under the production topic, โmarginal aging fields.โ What Chevron tested is better described by the topic, โwell interventions.โ Rather than looking at these techniques as a way to eke out the last barrels from old wells, the papers describe methods that can be deployed earlier in the life of these short-lived wells.
- North America > United States > Texas (0.25)
- North America > United States > New Mexico (0.25)
- North America > United States > Montana (0.25)
- North America > United States > Oklahoma (0.24)
- 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)
- (24 more...)
The oil and gas industry is at a critical juncture in addressing the pressing need to balance operational efficiency with environmental stewardship. With the world's growing emphasis on climate change and sustainability, the industry is tasked with the dual objectives of refining operational efficiency and simultaneously diminishing its carbon footprint. This balancing act has become a strategic imperative crucial for the long-term viability of the industry. In light of the recent COP28 agreement, which emphasizes a "swift, just, and equitable energy transition," the role of low-emission enhanced oil recovery (EOR) and operational optimization becomes increasingly significant. This period of transition, which may span several decades, demands a pragmatic approach where the existing hydrocarbon resources are used as efficiently and responsibly as possible.
- Europe > France (0.17)
- Asia > Middle East (0.17)
The oil and gas industry is at a critical juncture in addressing the pressing need to balance operational efficiency with environmental stewardship. With the worldโs growing emphasis on climate change and sustainability, the industry is tasked with the dual objectives of refining operational efficiency and simultaneously diminishing its carbon footprint. This balancing act has become a strategic imperative crucial for the long-term viability of the industry. In light of the recent COP28 agreement, which emphasizes a โswift, just, and equitable energy transition,โ the role of low-emission enhanced oil recovery (EOR) and operational optimization becomes increasingly significant. This period of transition, which may span several decades, demands a pragmatic approach where the existing hydrocarbon resources are used as efficiently and responsibly as possible. In the quest to optimize operations and reduce carbon footprint, three innovative technical papers present a cohesive story of advancement through modeling and machine learning. These papers underscore the industryโs shift toward more efficient practices, each contributing a crucial piece to the larger puzzle of EOR.The first paper introduces an advanced modeling approach for fractured reservoirs, a significant development in tight rock simulations that simplifies fracture heterogeneity characterization and enhances computational efficiency, crucial for optimizing asset development decisions in shale and tight oil resources. Building on the theme of efficiency, the second paper pivots to the realm of surfactants, exploring their role in wettability alteration within unconventional liquid-rich reservoirs. This research provides a systematic approach for screening thermally stable surfactants under reservoir conditions, crucial for improving hydrocarbon recovery without unnecessary field trials. The final piece of this narrative is a study using machine learning to predict gas-injection parameters in EOR processes. This approach addresses the lack of extensive gas-injection laboratory data, demonstrating the power of data-driven predictions in enhancing operational efficiency and decision-making. These papers weave a compelling narrative of technological innovation, highlighting the role of advanced modeling and machine learning. As the oil and gas industry progresses in its vital mission to supply the worldโs energy needs, the pivotal role of technology innovation becomes increasingly evident. Advanced technologies focused on operational optimization and reducing carbon emissions are essential in reinforcing the industryโs adaptability and resilience in the context of this rapidly evolving energy landscape. Recommended additional reading at OnePetro: www.onepetro.org. SPE 215083 An Analytical Tool to Predict Fracture Extension and Elastic Desaturation for Polymer Field Projects by M.B. Abdullah, The University of Texas at Austin, et al. SPE 216822 First Pilot Design of Low-Tension-Gas (LTG) Flooding in Carbonate Field in North Oman by Mohammed Al-Abri, Petroleum Development Oman, et al. SPE 213037 Field-Scale Multistage and Multiobjective Optimization of Rate and Concentration for Polymer Flooding by Ruxin Zhang, Texas A&M University, et al.
- Asia > Middle East > Oman (0.47)
- North America > United States > Texas > Travis County > Austin (0.25)
Surfactant Enhanced Oil Recovery Improves Oil Recovery in a Depleted Eagle Ford Unconventional Well: A Case Study
Ataceri, I. Z. (Texas A&M University) | Saputra, I. W. R. (Texas A&M University) | Bagareddy, A. R. (Texas A&M University) | Elkady, M. H. (Texas A&M University) | Schechter, D. S. (Texas A&M University) | Haddix, G. W. (Third Wave Production LLC (Corresponding author)) | Brock, V. A. (Third Wave Production LLC) | Raney, K. H. (Third Wave Production LLC) | Strickland, C. W. (Third Wave Production LLC) | Morris, G. R. (Auterra Operating LLC)
Summary A simple huff โnโ puff (HnP) injection and flowback using a nonionic surfactant solution to drive enhanced oil recovery (EOR) in a depleted Eagle Ford โblack oilโ unconventional well has been executed and analyzed. The pilot injection was performed in December 2020, with pressures below the estimated fracture gradient. More than 12,300 bbl of surfactant solution were injected into the 6,000-ft lateral. In January 2021, the well was put back on production with oil and water flow rate data being gathered and samples collected. Within 3 months of the well being put back onto production after surfactant stimulation, the well produced at oil rates over five times what it had produced before stimulation. The current oil rates (through October 2022; 22 months after stimulation) are still twice the prestimulation rates. Using a long-term hyperbolic fit to historical data as the โmost likelyโ production scenario in the absence of stimulation as a โbaseline,โ incremental recovery was estimated using the actual oil production data to date. Economic analysis with prevailing West Texas Intermediate (i.e., WTI) prices at the time of production and the known costs of the pilot result in project payout time less than 1 year and project internal rate of return in excess of 80%, with only incremental production to date. These results prove the potential for technoeconomic viability of HnP EOR techniques using surfactants for wettability alteration in depleted unconventional oil wells. The well was chosen from a portfolio of unconventional Eagle Ford black oil window wells that were completed in the 2012โ2014 time frame. The goal of the test was to demonstrate successful application of laboratory work to the field and economic viability of surfactant-driven water imbibition as a means of incremental EOR. The field design was based on laboratory work completed on oil and brine samples from the well of interest, with rock sampled from a nearby well at the same depth. The technical and economic objectives of the field test were to (1) inject surfactant solution to contact sufficient matrix surface area that measurable and economically attractive amounts of oil could be mobilized, (2) measure the amount of surfactant produced in the flowback stream to determine the amount of surfactant retained in the reservoir, and (3) prove the concept of using wettability alteration in conjunction with residual well energy in a depleted well to achieve economically attractive incremental recovery. Surfactant selection was completed in the laboratory using oil and brine gathered from potential target wells, and rock from nearby wells completed in the same strata. Several surfactant formulations were tested, and a final nonionic formulation was chosen on the basis of favorable wettability alteration and improved spontaneous imbibition recovery. The design for the pilot relied on rules of thumb derived from unconventional completion parameters. Rates, pressures, and injectant composition were carefully controlled for the single-day โbullheadโ injection. Soak time between injection and post-stimulation restart of production was inferred from laboratory-scale imbibition trials. Post-stimulation samples were gathered, while daily oil and water rates were monitored since production restart. Flowback samples were analyzed for total dissolved solids (TDS), ions, and surfactant concentration.
- Geology > Mineral (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- 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 > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (5 more...)
Summary In the placement process of the cement slurry, treatment fluids such as the spacer are pumped ahead of the cementitious slurry to minimize the contamination of the slurry by drilling fluid and ensure superior bonding to the casing and formation. The spacer discussed in this work can harden with time and act as a settable spacer. This characteristic can be an advantage for well integrity if some spacer pockets are left in the annulus. Rheological compatibility of different mixtures of the spacer with oil-based drilling fluid (OBDF) has been studied using a rheometer, and the resulting R-factor, which indicates the degree of compatibility between fluids, has been calculated. An increase in the flow curve was observed for the mixture of the fluids. However, based on the R-index, these fluids are compatible with displacement in the wellbore. A nonionic surfactant, typically used in conventional spacers acting as an emulsifier and a water-wetting agent, was used in the hardening spacer design. The results show that the addition of OBDF to hardening spacer containing surfactant can increase viscoelasticity. Hardening spacer containing surfactant can successfully reverse the OBDF emulsion. By performing a small-scale mud displacement experiment, we observed that surfactant can improve the wall cleaning efficiency of the spacer while having minimal impact on the bulk displacement.
- Europe (1.00)
- North America > United States > California (0.28)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
A New Adaptive Implicit Method for Multicomponent Surfactant-Polymer Flooding Reservoir Simulation
Batista Fernandes, Bruno Ramon (The University of Texas at Austin (Corresponding author)) | Sepehrnoori, Kamy (The University of Texas at Austin) | Marcondes, Francisco (Federal University of Cearรก) | Delshad, Mojdeh (The University of Texas at Austin)
Summary In the oil industry, chemicals can improve oil production by mobilizing trapped and bypassed oil. Such processes are known as chemical-enhanced oil recovery (CEOR). Surfactants and polymers are important chemicals used in CEOR with different mechanisms to improve oil recoveries, such as reduction in residual saturation, oil solubilization, and mobility control. However, both surfactant and polymer may increase the cost of oil production, making optimizing these processes essential. Reservoir simulators are tools commonly used when performing such field optimization. The simulation of surfactant flooding processes has been historically performed with the implicit pressure explicit composition (IMPEC) approach. The injection of surfactants requires modeling the brine/oil/microemulsion phase behavior along with other processes, such as capillary desaturation and retention. The microemulsion phase behavior and the complex relative permeability behavior can lead to convergence issues when using fully implicit (FI) schemes. Only recently, the FI approach has been efficiently applied to simulate this process using new modeling. The adaptive implicit method (AIM) can combine the benefits of the FI and IMPEC approaches by dynamically selecting the implicitness level of gridblocks in the domain. This work presents a new AIM in conjunction with recently developed models to mitigate discontinuities in the microemulsion relative permeabilities and phase behavior. The approach presented here considers the stability analysis method as a switching criterion between IMPEC and FI. To the best of our knowledge, the approach presented here is the first AIM to consider the brine/oil/microemulsion three-phase flow in its conception. The new approach uses the finite volume method in conjunction with Cartesian grids as spatial discretization and is applied here for field-scale problems. The new approach is tested for polymer flooding and surfactant-polymer (SP) flooding for problems with several active cells ranging from about a hundred thousand to almost a million. The AIM approach was compared with the FI and IMPEC approaches and displayed little variation in the computational performance despite changes in the timestep size. The AIM also obtained the fastest performance for all cases, especially for SP flooding cases. Furthermore, the results here suggest that the gap in performance between the AIM and FI seems to increase as the number of gridblocks increases.
- North America > United States > Texas (1.00)
- Asia (0.93)
- Overview (0.54)
- Research Report > New Finding (0.46)
Application of Foamers in Unconventional Oil Well with Low Water Cut
Villanova, Joanna (PECOM Energรญa S.A.) | Luliano, Florencia (Pan American Energy) | Lรณpez, Jimmy (PECOM Energรญa S.A.) | Emiliani, Verรณnica (Pan American Energy) | Bragagnolo, Marcos (Pan American Energy) | Blanco, Adriana (Pan American Energy)
Abstract Coiron Amargo Sureste is a Pan American Energy area located in the Neuquen basin which currently has 13 unconventional oil wells under production. One of these producing wells presents an unstable production pattern which is associated with the presence of slugging. In fact, the present work focusses on the application of strategies to improve its extraction system. A pilot test for injecting a foaming agent suitable for high cut crude oil through a capillary system was carried out at an estimated depth of 2750 m. The chemical treatment implementation, as well as its control, monitoring, and evaluation, were combined in an operational strategy specifically designed for this purpose. Firstly, the initial step was a laboratory test following an adaptation of the standard ATSM-D892 in which a Nonionic/Amphoteric surfactant was selected. Subsequently, the designed product was tested in a 15-day field trial in which daily data involving oil production and foam breakdown was continually collected. The selected product was injected through a batch mode having the well closed for 12 hours to recover pressure. Afterward, a continuous dosage of 250 ppm concentration was injected through the downhole capillary system. Obtained results showed an average oil production increase of 1.7 m/d (10.7 bpd) during the surfactant injection. Due to these significant results, the surfactant was continuously injected for several months until the artificial lift method was changed. Introduction During the regular life cycle of oil and gas wells, there is a common reduction in the bottom hole pressure (BHP) over time that leads to produce liquid loading problems. It means that the well doesnโt have proper liquid production since gas velocity is not strong enough to mobilize that liquid phase, leading to its accumulation on production tubing. The application of foaming chemicals is a common strategy in gas wells with liquid loading problems since these products, by reducing the critical velocity of the gas phase, facilitate the transport of liquids to the surface. Simultaneously, this reduction in critical velocity helps to lower relative density of accumulated fluids and, therefore, reduced back pressure. This foaming chemicals are commonly applied through different ways: downhole capillaries for continuous injection; liquid batch; or solid bars directed into the production tubing.
Abstract Binary surfactant systems have demonstrated superior oil recovery capabilities in enhanced oil recovery (EOR) applications compared to single surfactant systems. This is due to their ability to form mixed micelles, which exhibit lower interfacial tension (IFT) and greater solubilization capacity than single surfactant systems. Thus, understanding their interactions and properties is crucial for maximizing their beneficial effects and determining their synergism. Therefore, in this study, we conducted a systematic experimental study involving eight surfactants and six binary surfactant mixtures at various ratios to determine their critical micelle concentrations (CMCs). Additionally, we applied Rubingh's Regular Solution Theory to characterize the behavior of these binary surfactant mixtures and to assess potential interactions among the surfactants. Our findings reveal a consistent synergistic phenomena in all binary surfactant systems, with the concentration of non-ionic surfactants playing a crucial role. Increasing the non-ionic surfactant concentration improved synergistic interactions, resulting in low CMC when combined with anionic, cationic, and zwitterionic surfactants. However, an excess concentration of the cationic surfactant exhibited "weak" synergistic effects, which can be attributed to its relatively smaller hydrophobic tail. Introduction Carbonate reservoirs, constituting more than 60% of the world's hydrocarbon reserves, are of significant importance for efficient oil production (Adibhatla & Mohanty, 2006). These reservoirs often exhibit a high degree of heterogeneity, complex pore structures, and substantial presence of impurities. Some carbonate formations are further complicated by high reservoir temperatures and high salinity conditions (Lu et al., 2014). These pose significant challenges in reservoir characterization, production, and management. Consequently, oil recovery in these reservoirs frequently falls below 40% (Hรธgnesen et al., 2005). Historically, surfactants have been utilized in enhanced oil recovery (EOR) applications, displaying promising outcomes (Ahmadi & Shadizadeh, 2013; Ivanova et al., 2020). Surfactants, being amphiphilic molecules, effectively reduce the interfacial tension (IFT) between oil and water that in turn enables the mobilization of trapped oil within the reservoir and its displacement towards production wells (Bello et al., 2022). However, a significant limitation in the application of single surfactants in carbonate formations arises from the presence of impurities like clay minerals and the physiochemical conditions of the aqueous medium, such as salinity and pH, which can influence the surface charge of the rock, and might lead to unfavorable results (Pal et al., 2018). This calls for the exploration of alternative strategies, such as binary surfactant solutions. Binary surfactant systems involve the combination of two distinct surfactants, each with its unique properties and behaviors.
- Asia (0.68)
- Europe > Norway > Norwegian Sea (0.24)
Investigating the Effect of Surfactants on CO2 and Crude Oil Minimum Miscible Pressure Through Molecular Dynamics Simulation โ An Example of Crude Oil from the Chang 8 Reservoir
Dong, Zhenzhen (Xiโan Shiyou University) | Hou, Tong (Xiโan Shiyou University) | Yang, Zhanrong (Xiโan Shiyou University) | Zou, Lu (Xiโan Shiyou University) | Tian, Shihao (Xiโan Shiyou University) | Li, Weirong (Xiโan Shiyou University) | Lin, keze (China University of Petroleum (Beijing)) | Yi, Hongliang (Liaohe Oilfield) | Liu, Zhilong (EnerTech-Drilling & Production Co., CNOOC Energy Technology & Services Limited)
Abstract CO2 flooding is one of promising method to improve the recovery of tight reservoirs, which can realize the efficient development of unconventional oil and gas reservoirs and CO2 reduction at the same time, and is of great significance to the positive development of energy in China. Theory and practice show that the oil drive efficiency of CO2 miscible-phase is much higher than that of non-miscible-phase, but the existing CO2 drive technology, which is difficult to reach CO2 miscible-phase in many fields, has limited effect on improving the recovery of tight reservoirs. The composite system formed by CO2 and surfactant together is a new direction to explore CO2 flooding technology to improve the recovery of tight reservoirs. In this paper, a molecular system model of CO2 and crude oil is established for the characteristics of crude oil in the Chang 8 tight reservoir, and the molecular dynamics simulation technique is used to estimate the miscible pressure. Then, surfactant (C12PO6) was added to study the physical parameters such as intermolecular forces, interfacial tension and miscible pressure of surfactant-CO2-crude oil. Finally, the factors influencing the reduction of miscible pressure by surfactants were analyzed. The research results indicate that surfactants enhance the molecular interactions between CO2 and crude oil, reducing the minimum miscibility pressure by 9.36% at a temperature of 344K. The study reveals that the extent of this reduction in minimum miscibility pressure due to surfactants is influenced by temperature, with a 10% increase in their impact as the temperature increases from 323K to 363K. The research results reveal the interactions between multiple fluid molecules and particles at the molecular level, and reveal the microscopic mechanism of CO2 and surfactant composite system to reduce miscible pressure in tight reservoirs, which can help promote the development of CO2 enhanced recovery technology in tight reservoirs in China.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Information Technology > Mathematics of Computing (0.63)
- Information Technology > Software (0.46)
Feasibility of Foam-Enhanced Water-Gas Flooding for a Low-Permeability High-Fractured Carbonate Reservoir. Screening of Foaming Agent and Flooding Simulation
Derevyanko, V. K. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Bolotov, A. V. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Minkhanov, I. F. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Varfolomeev, M. A. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Usmanov, S. A. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Saifullin, E. R. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Egorov, A. N. (CJSC, Aloil, Bavly, Russian Federation) | Sudakov, V. A. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Zhanbossynova, S (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Sagirov, R. N. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation)
Abstract The carbonate reservoirs of the Alekseevskoye field (Russia, Republic of Tatarstan) are complicated by high heterogeneity and the presence of fractures, which make development difficult due to early water or gas breakthrough depending on the injected agent, as well as low of the productive horizon. To increase sweep efficiency and introduce fractured reservoirs into development, it is necessary to use gas enhanced oil recovery (EOR) technologies. To find the optimal technology in terms of technological complexity and efficiency, three technologies were compared: Water Injection (WI), Water-Alternating Gas (WAG), and Foam Assisted Water-Alternating Gas (FAWAG). Series of core-flooding tests were implemented under reservoir conditions on carbonate cores, and cores with artificial fractures, saturated with original reservoir fluids. For FAWAG method compatible with high-mineralization water surfactant was chosen. Total recovery factor for each test was calculated. It was equal to 33%, 76% and 53% respectively for WI, WAG and SWAG, on the original core models. Therefore, WAG and SWAG were chosen as most effective techniques to improve oil recovery for in comparison with CWI. In artificially fractured cores, the WAG method recovery rate was 40%; subsequent injection of a foaming active substance mixed with FAWAG formation water proved effective, increasing the oil recovery rate to 47% due to partial blockage of the fracture.
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.40)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.37)
- Europe > Russia > Volga Federal District > Bashkortostan > Alekseevskoye Field (0.99)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Romashkinskoye Field (0.94)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Fyodorovskoye Field (0.94)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Samotlorskoye Field (0.94)
- 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 > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)