Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Energy
Fluid – Fluid Interfacial Area and Its Impact on Relative Permeability - A Pore Network Modeling Study
Mukherjee, Sanchay (John and Willie Leone Department of Energy and Mineral Engineering, The Pennsylvania State University, USA) | Johns, Russell T. (John and Willie Leone Department of Energy and Mineral Engineering, The Pennsylvania State University, USA) | Foroughi, Sajjad (Department of Earth Science and Engineering, Imperial College London, UK) | Blunt, Martin J. (Department of Earth Science and Engineering, Imperial College London, UK)
Abstract Relative permeability (kr) is commonly modeled as an empirical function of phase saturation. Although current empirical models can provide a good match of one or two measured relative permeabilities using saturation alone, they are unable to predict relative permeabilities well when there is hysteresis or when physical properties such as wettability change. Further, current models often result in relative permeability discontinuities that can cause convergence and accuracy problems in simulation. To overcome these problems, recent research has modeled relative permeability as a state function of both saturation (S) and phase connectivity (X). Pore network modeling (PNM) data, however, shows small differences in relative permeability for the same S-X value when approached from a different flow direction. This paper examines the impact of one additional Minkowski parameter (Mecke and Arns, 2005), the fluid-fluid interfacial area, on relative permeability to identify if that satisfactorily explains this discrepancy. We calculate the total fluid-fluid interfacial areas (IA) during two-phase (oil/water) flow in porous media using pore network modeling. The area is calculated from PNM simulations using the areas associated with corners and throats in pore elements of different shapes. The pore network is modeled after a Bentheimer sandstone, using square, triangular, and circular pore shapes. Simulations were conducted for numerous primary drainage and imbibition cycles at a constant contact angle of 0° for the wetting phase. Simultaneous measurements of capillary pressure, relative permeability, saturation, and phase connectivity are made for each displacement. Fluid-fluid interfacial area is calculated from the PNM capillary pressure, the fluid location in the pore elements, and the pore element dimensional data. The results show that differences in the relative permeability at the same (S,X) point is explained well by differences in the fluid-fluid interfacial area (IA). That is, for a larger change in IA at these intersection points, the permeability difference is greater. That difference in relative permeability approaches zero as the difference in IA approaches zero. This confirms that relative permeability can be modeled better as a unique function of S, X, and IA. The results also show that an increase in IA restricts flow decreasing the nonwetting (oil) phase permeability. This decrease is caused by an increase in the throat area fraction compared to the corner area as the total area IA increases. The wetting phase relative permeability, however, shows the inverse trend, in that its relative permeability is greater when IA becomes larger owing to a greater fraction of the total area associated with the corners. The area IA, however, impacts the nonwetting phase relative permeability more than the wetting phase relative permeability. Corner flow improves the wetting phase relative permeability because the wetting phase is continuous there. Finally, a sensitivity analysis shows that relative permeability a is more sensitive to change in S than they are for IA for the case studied implying that if only two parameters are used to model relative permeability it is better to choose S and X.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
Improved Amott Cell Procedure for Predictive Modeling of Oil Recovery Dynamics from Mixed-Wet Carbonates
Kaprielova, Ksenia (King Abdullah University of Science and Technology) | Yutkin, Maxim (King Abdullah University of Science and Technology) | Gmira, Ahmed (Saudi Aramco) | Ayirala, Subhash (Saudi Aramco) | Radke, Clayton (University of California, Berkeley) | Patzek, Tadeusz W. (King Abdullah University of Science and Technology)
Abstract Spontaneous counter-current imbibition in Amott cell experiments is a convenient laboratory method of studying oil recovery from oil-saturated rock samples in secondary or tertiary oil recovery by waterflood of adjustable composition. Classical Amott cell experiment estimates ultimate oil recovery. It is not designed, however, for studying the dynamics of oil recovery. In this work we identify a flaw in the classical Amott cell imbibition experiments that hinders the development of predictive recovery models for mixed-wet carbonates. We revise the standard Amott procedure in order to produce smoother experimental production curves, which then can be described by a mathematical model more accurately. We apply Generalized Extreme Value distribution to model the cumulative oil production. We start with the Amott imbibition experiments and scaling analysis for Indiana limestone core plugs saturated with mineral oil. The knowledge gained from this study will allow us to develop a predictive model of water-oil displacement for reservoir carbonate rock and crude oil recovery systems.
- North America > United States > California (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Indiana (0.25)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (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 > Reservoir Fluid Dynamics > Flow in porous media (0.94)
Abstract Water is accumulated near the fracture surface after fracturing, which will block oil flow out. The water blockage can be mitigated through the immediate well flow back or through shutting in the well before flow back. Which method is more effective? There are mixed results in the literature from field reports and experimental or simulation studies. This paper discussed the literature results and simulation data obtained from this study. It is found that the oil recovery mainly depends on the magnitude of pressure drawdown and the strength of imbibition. When the pressure drawdown is high, immediate flow back may lead to higher oil recovery than shutting in a well before flow back. When imbibition is strong, shutting in may be beneficial to enhance oil recovery through counter-current flow. Although many parameters of reservoir properties and operations may affect the shut-in effect, those parameters may be grouped into the pressure drawdown and imbibition strength. The parameters of matrix permeability, wettability, initial water saturation, and formation compressibility are discussed. Analysis and discussion of simulation data also suggest that the oil recovery is a linear function of pressure drawdown, but the relationship between oil recovery and capillary pressure is non-linear and more complex. The results and discussion from this study suggest that the immediate flow back may outperform the shut-in if a large pressure drawdown is applied. If a reservoir provides a strong imbibition condition, the shut-in may be beneficial. Surfactants may be chosen to enhance imbibition. The surfactants which alter the reservoir from oil-wet to water-wet may be preferred.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (10 more...)
Abstract Most carbonate reservoirs are oil-wet/mixed-wet and heterogenous at multiple scales. Majority of the injected water flows through the high permeability regions/fractures and bypass the oil in the matrix due the high negative capillary pressure (Pc). To enhance oil recovery from such reservoirs, the sign of the Pc should be changed by wettability alteration (WA) or the Pc should be reduced by lowering interfacial tension (IFT). In this study, surfactants which can either alter wettability or develop ultra-low IFT were identified through laboratory measurements for the target carbonate reservoir. The performance of these two types of surfactants was systematically evaluated at the core scale and scaled-up to the reservoir scale. A reservoir-scale model was developed to simulate injection-soak-production (ISP) tests and evaluate performance of the selected surfactants at the field scale. Experiments showed that quaternary ammonium cationic surfactants have excellent WA ability, while a series of propoxy sulfate anionic surfactants showed intermediate WA and ultra-low IFT. Spontaneous imbibition tests showed that WA surfactants have fast initial oil production, while ultra-low IFT surfactants has low initial oil rate but higher final oil recovery, which was validated by mechanistic simulation. Low IFT results in low Pc and slow imbibition, but also triggers gravity-driven drainage. For ultra-low IFT system, gravity drainage is more dominant than WA, and Pc-alteration is less important than relative permeability (Kr) alteration. As reservoir thickness increases, Kr-alteration is more important than Pc-alteration. Gravity drainage is expected to be scaled up by length of matrix (L), while Pc-driven imbibition is scaled by L. Field-scale simulation showed that low-IFT surfactant has better injectivity than WA surfactant during injection phase. In soaking phase, spontaneous imbibition by WA surfactant is much more significant than that by low-IFT surfactant. In production phase, post-waterflood achieved higher oil recovery from low-IFT surfactant treated matrix due to its low residual oil saturation and high oil relative permeability.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > United States > Wyoming > Bighorn Basin > Phosphoria Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- 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 > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Modeling of Chemical Tracers to Estimate Oil Volume Contacted and Sweep Efficiency in Porous Media Under Countercurrent Spontaneous Imbibition
Velasco-Lozano, Moises (The Hildebrand Department of Petroleum and Geosystems Engineering and the Center for Subsurface Energy and the Environment, The University of Texas at Austin, Austin, Texas, USA) | Balhoff, Matthew Thomas (The Hildebrand Department of Petroleum and Geosystems Engineering and the Center for Subsurface Energy and the Environment, The University of Texas at Austin, Austin, Texas, USA)
Abstract Modeling of chemical tracers is an important technique to estimate oil saturation in porous media. Although numerous models exist to analyze the flow of tracers in systems under dynamic conditions, modeling in capillarity-dominated systems has not been sufficiently examined. In tight porous media and the matrix of fractured reservoirs, spontaneous imbibition (SI) represents a key driving mechanism for fluid infiltration because the low permeability in these systems results in a negligible transport by advection. We present a new semi-analytical solution for the flow of tracers under countercurrent SI valid during the infinite-acting and boundary-dominated flow regimes. The model presented is derived from the analysis of fluid imbibition driven by capillarity and numerically solved as a function of water distribution and initial tracer concentration. We model ideal and partitioning tracers to investigate the average oil saturation in the contacted region by tracer and sweep efficiency of countercurrent SI as a recovery mechanism in porous media. To verify the applicability of our solution, we compared it against numerical simulation cases under flow conditions with diverse solute and phase properties. The concentration profiles exhibit a significant delay in displacement behind the imbibition front when hydrodynamic dispersion is ignored and for high partitioning coefficients, demonstrating the importance of determining these properties before conducting a field test. The solution presented is the first to examine countercurrent SI for the modeling of oil volume contacted by tracers in porous media. We consider the model can be extended for the analysis of the flow of tracers in systems such as fractured reservoirs to estimate oil saturation in the matrix medium, and those using chemical solutions that promote SI by altering wettability and capillary pressure.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
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)
The Effect of Phase Distribution on Imbibition Mechanisms for Enhanced Oil Recovery in Tight Reservoirs
Wang, Mingyuan (The University of Texas at Austin) | Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin)
Abstract The main objective of this research was to investigate the impact of initial water on the oil recovery from tight matrices through surfactant-enhanced water imbibition. Two flooding/soaking experiments using fractured tight cores with/without initial water were performed. The experimental results were analyzed by the material balance for components: oil, brine, and surfactant. The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and surfactant). Results show that the surfactant enhanced the brine imbibition into the matrix through wettability alteration. The initial efficiency of the surfactant imbibition increased when brine was initially present in the matrix. The imbibition of brine was more efficient with no initial water in the matrix. A possible reason is that the presence of initial water in the matrix was able to increase the initial efficiency of the surfactant imbibition; however, the increased amount of surfactant in the matrix lowered the interfacial tension between the aqueous and oleic phases; therefore, the efficiency of brine imbibition was reduced. Another possible reason is that capillary force was lower in the presence of initial water in the matrix, resulting in weaker imbibition of brine. Although the two cases showed different characteristics of the mass transfer through fracture/matrix interface, they resulted in similar values of final water saturation in the matrix. Hence, the surfactant injection was more efficient for a given amount of oil recovery when there was no initial water in the matrix.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.32)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Abstract In this paper, we evaluate the idea of adding nanoparticles (NPs) in fracturing water to enhance its wetting affinity to oil-wet pores and to mobilize part of the oil during the extended shut-in periods. We analyzed the performance of two different nanoparticle additives (NP1 and NP2) on core plugs collected from the Montney Formation. Additive 1 is a colloidal dispersion with highly surface-modified NPs and additive 2 is a micellar dispersion with highly surface-modified silicon dioxide NPs, solvents and surfactants. The proposed methodology consists of the following steps: 1) Characterizing wettability of the candidate rock samples under different conditions of brine salinity and NP concentrations through dynamic contact-angle measurements, 2) Evaluating NP-assisted imbibition oil recovery during the shut-in period by conducting systematic counter-current imbibition tests, and 3) Evaluating pore accessibility by comparing the mean size of the particles formed in the NP solutions measured by dynamic light scattering (DLS) method with pore-throat size distribution of the core plugs obtained from scanning electron microscopy (SEM) and mercury injection capillary pressure (MICP) analyses. The dynamic contact-angle results show that the core plugs are oil-wet in the presence of reservoir brine and fresh water as base fluids, and water-wet in the presence of the NP solutions. Consistently, the measured oil recovery factor (RF) by the NP solutions is 5% to 10% higher than that by the base fluids, which can be explained by the wettability alteration by NPs. Comparing the mean particle size of the NP solutions with the pore-throat size distribution of the plugs evaluates pore accessibility of core plugs. From MICP and SEM analyses, most pores of the rock samples have pore-throat radius in the range of 4 to 100 nm. The mean particle size of NP1 in low-salinity water is less than 30 nm while that of NP2 in low-salinity water is around 40 nm. The NPs can pass through most of the pore throats under low-salinity conditions. This is supported by fast and spontaneous imbibition of the NP solutions into the oil-saturated core plugs, compared with the base cases without the NPs solutions. When salinity increases, the particle size for NP solutions increases to more than 200 nm. Therefore, fewer pores may be accessed by NPs under high-salinity conditions if the NP solutions are not optimized for such conditions.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.84)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
Visualization the Surfactant Imbibition at Pore Scale by Using of Fractured Micromodels
Yu, Fuwei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Jiang, Hanqiao (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Ma, Mengqi (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Xu, Fei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Su, Hang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Jia, Junjian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing)
Abstract Recovery in low permeability oil reservoirs is challenging because they are often high fractured and oil-wet. Microemulsion-forming surfactant solutions, which can replace oil from tight matrix by imbibition, have been verified as effective enhanced oil recovery fluids for tight reservoirs. To better understand the mechanisms of oil recovery from oil-wet, fractured rocks using microemulsion-forming surfactants, microfluidic experiments including single channel micromodel tests and fractured micromodel imbibition tests which could visualize the in-situ phase changes were conducted in this work. Through on our study, the priority of wettability alteration and phase change with a function salinity was clarified. Besides, the imbibition dynamics of microemulsion-forming surfactants at different salinities were provided, and further understanding about the equilibrium process of microemulsion during imbibition was obtained. Based our studies, we suggest a moderate salinity for microemulsion-forming surfactants enhanced imbibition recovery.
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)