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Collaborating Authors
Akkutlu, I. Yucel
Insights Into Mobilization of Shale Oil by Use of Microemulsion
Bui, Khoa (Texas A&M University) | Akkutlu, I. Yucel (Texas A&M University) | Zelenev, Andrei (CESI Chemical-Flotek) | Saboowala, Hasnain (CESI Chemical-Flotek) | Gillis, John R. (CESI Chemical-Flotek) | Silas, James A. (CESI Chemical-Flotek)
Summary Molecular-dynamics simulation is used to investigate the nature of two-phase (oil/water) flow in organic capillaries. The capillary wall is modeled with graphite to represent kerogen pores in liquid-rich resource shale. We consider that the water carries a nonionic surfactant and a solubilized terpene solvent in the form of a microemulsion, and that it was previously introduced to the capillary during hydraulic-fracturing operation. The water has already displaced a portion of the oil in place mechanically and now occupies the central part of the capillary. The residual oil, on the other hand, stays by the capillary walls as a stagnant film. Equilibrium simulations show that, under the influence of organic walls, the solvent inside the microemulsion droplets enables not only the surfactant but also the complete droplet to adsorb to the interfaces. Hence, delivering the surfactant molecules to the oil/water interface is achieved faster and more effectively in the organic capillaries. After the droplet arrives at the interface, the droplet breaks down and the solvent dissolves into the oil film and diffuses. This process is similar to drug delivery at nanoscale. Using nonequilibrium simulations based on the external force-field approach, we numerically performed steady-state flow measurements to establish that the solvent and the surfactant molecules play separate roles that are both essential in mobilizing the oil film. The surfactant deposited at the oil/water interface reduces the surface tension and acts as a linker that diminishes the slip at the interface. Hence, it effectively enables momentum transfer from the mobile water phase to the stagnant oil film. The solvent penetrating the oil film, on the other hand, modifies flow properties of the oil. In addition, as a result of selective adsorption, the solvent displaces the adsorbed oil molecules and transforms that portion of the oil into the free oil phase. Consequently, the fractional flow of oil is additionally increased in the presence of solvent. The results of this work are important for understanding the effect of microemulsion on flow in organic capillaries and its effect on shale-oil recovery.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Joan Field > Acl Joan 16-33-92-11 Well (0.89)
- North America > Canada > Alberta > George Field > Anderson Dunvegan 2-1-82-5 Well (0.89)
Permeability of Organic-Rich Shale
Wasaki, Asana (Texas A&M University) | Akkutlu, I. Yucel (Texas A&M University)
Summary Measured permeability of an organic-rich shale sample varies significantly with applied laboratory conditions, such as the confining pressure, temperature, and the measurement fluid type. This indicates that the measured quantity is influenced by several mechanisms that add complexity to the measurement. The complexity is mainly caused by stress dependence of the matrix permeability. Also, it is because organic-rich shale holds significant volumes of fluids in sorbed (adsorbed, dissolved) states; sorption can also influence the permeability through its own storage and transport mechanisms. The stress-dependence and sorption effects on permeability could develop under the reservoir conditions and influence the production, although we currently do not have a predictive permeability model that considers their coexistence. In this work, this is accomplished by considering that the shale matrix consists of multiple continua with organic and inorganic pores. Stress dependency of the permeability comes along with slit-shaped pores, whereas the sorption effects are associated with nanoscale organic capillaries. A simple conceptual flow model with an apparent shale permeability is developed that couples the molecular-transport effects of the sorbed phase with the stress dependence of the slit-shaped pores. The simulation results show the impact of the permeability model on the production. Sensitivity analysis on the new permeability model shows that the stress dependence of the overall transport is significant at high pore pressure, when the effective stress is relatively low. Diffusive molecular transport of the sorbed phase becomes important as the stress gets larger and, hence, the slit-shaped pores close. The constructed apparent-permeability vs. pore-pressure curves show the dominance of the molecular transport as an increase in permeability characterized by appearance of a minimum permeability value at the intermediate values of the pressure. One can use the new permeability model easily in history matching a well performance and optimizing its production.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Unlike flow of fluid in conventional reservoirs, the fluid transport in unconventional reservoirs involves kerogen pore structure with much smaller capillaries. This, in turn, leads to large capillary wall surface area and, consequently, to a significant physical adsorption effect. Measurements are needed to understand the nature of flow inside kerogen structures. However, direct measurements are difficult and have large uncertainties related to kerogen isolation. Non-equilibrium molecular dynamics simulation allow numerical study of fluid transport inside model nano-capillaries representative of kerogen matrices. In this work two different molecular simulation methods are used to study steady-state flow of methane and of methane-butane mixture: External Field Non-Equilibrium Molecular Dynamics (EF- NEMD), the main flow simulation method, and Dual Control Volume Grand Canonical Molecular Dynamics (DCV-GCMD), the simulation method used to verify the results. The flow inside the capillary is simulated under various conditions, e.g., capillary diameter, temperature, average pressure, fluid composition and capillary wall morphology. Based on the simulation results we observe that fluid flow velocity and mass flux are significant near the capillary surfaces where adsorption takes place. Hence, Hagen-Poiseuille equation based on the no-flow condition at the wall significantly under-estimates the fluid flow in nanocapillary. The dependence of surface transport velocity, as well as flow enhancement, are determined quantitatively. The results confirm a previous study by Riewchotisakul and Akkutlu (2015) indicating the presence of a mobile adsorbed-phase in the organic capillaries based on molecular simulation of steady-state methane flow using a moving piston model.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
Abstract In this paper we present the results of steady state methane flow in carbon tubes under reservoir conditions using nonequilibrium molecular dynamics simulations, which show that the organic capillaries in resource shales contain a mobile adsorbed phase. This mobility leads to a significant shift up in the flow velocity profile of the fluid across the diameter of the tube. The contribution of the adsorbed phase to transport is significant in capillaries with size less than 20 nm. A new permeability model is proposed which considers these observations. We use the bundle of capillaries approach and estimate that the permeability correction for organic pores of Marcellus shale has more than 50 % increase. Further research is required to consider the transport of the other hydrocarbons and their mixtures.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.34)
Abstract Much work has been done to demonstrate an economical impact of various fluid transport mechanisms on the long term behavior of shale gas production. These studies were elementary level and focused on identifying a dominant mechanism of production. They did not consider, however, the interaction of the fractures with the shale matrices in detail. In the near wellbore environment the fracture is the crucial component of transport, whereas the matrix is the place for storage. In this paper, using a new in-house reservoir flow simulator, we introduce the nature of this interaction and show that the transport in the tight matrix can be induced by carefully designing the well completions and by operating under the optimum production conditions. The simulator accounts for a hydraulic fracture coupled to shale matrix with an anistropic apparent permeability field, which is stress-sensitive and includes the effects of molecular transport phenomena. The fracture has a dynamic conductivity with a simple nonlinear deformation rule reflecting proppant embedment effect on the conductivity. Using a sector model, we predict short-term cumulative production trends. The results indicate that design of horizontal wells with multiple fractures should take into account the geomechanical and diffusional resistances associated with the gas transport in the matrices. Further, in-series nature of the production indicates that changes in fracture conductivity beyond its threshold value has negligible effect on the production trends. Therefore, production optimization efforts should instead focus to considerations to improve the flow rates in the matrix.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Recent studies have shown that the behavior of pure fluid in confinement deviates from its bulk state. This means that the vapor and liquid saturation curves, critical temperatures, pressures and densities of fluid in confinement are different from their well-documented bulk state values. While these single-component studies have been influential in our understanding of this peculiar phenomenon, the multi-component fluid phase behavior has yet to be investigated in depth. This is an important step, because production of liquids and natural gases from organic rich nanoporous shales involves fluids with a wide range of composition. Nanopore walls have significantly varying degrees of affinity to each component (selective adsorption). Consequently there will be large gradients across the pore width in not only density and pressure but also in concentration. This work is an investigation of phase changes of single and multi-component fluids in confinement with the help of molecular simulation. In the first part of this paper, phase diagrams of three single component (pure) fluids in confinement are constructed and studied. In the next part, a different methodology is utilized to construct phase diagrams of binary and ternary mixtures with light, intermediate and heavy hydrocarbon components. The methodologies are initially explained and verified by the bulk-state fluid behavior. This study shows that the behavior of single component fluids approaches its bulk state at a confinement of approximately 13nm width. Furthermore, the impact of confinement appears to be greater on the vapor saturation curve than on the liquid curve. In the case of multi-component fluids, the phase diagrams seem to shift more severely with the increase of the percentage of light component in the mixture. Contrast in concentrations of the light and heavy components, amplifies the confinement effect. More specifically, confined multi-component fluids with high percentage of light components such as methane and ethane are expected to exhibit more dramatic changes in phase behavior. Lastly, critical temperature and pressures of confined mixtures obtained from our molecular simulations are compared to those obtained from other mixing rules and equations, such as Peng-Robinson equation of state, which are extensively used for fluid in bulk state. The differences in values obtained show the necessity for the development of new approaches for considering hydrocarbon fluids in confinement. The observations undermine the current practice of assuming bulk fluid parameters for fluid in shale plays.
- Oceania > Australia > Queensland > Surat Basin > Eos Block (0.89)
- North America > United States > Gulf of Mexico > Western GOM > West Gulf Coast Tertiary Basin > Brazos (0.89)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Insights into Mobilization of Shale Oil using Microemulsion
Bui, Khoa (Petroleum Engineering Dept., Texas A&M University) | Akkutlu, I. Yucel (Petroleum Engineering Dept., Texas A&M University) | Zelenev, Andrei (CESI Chemical โ Flotek) | Saboowala, Hasnain (CESI Chemical โ Flotek) | Gillis, John R. (CESI Chemical โ Flotek) | Silas, James A. (CESI Chemical โ Flotek)
Molecular dynamics simulation is employed to investigate the nature of two-phase (oil-water) flow in organic capillaries. The capillary wall is modeled using graphite to represent kerogen pores in liquid-rich resource shale. We consider that the water carries a nonionic surfactant and a solubilized terpene solvent in the form of a microemulsion, and that it has previously been introduced to the capillary during hydraulic fracturing operation. The water has already displaced a portion of the oil in-place mechanically and now occupies the central part of the capillary. The residual oil, on the other hand, stays by the capillary walls as a stagnant film. Equilibrium simulations show that, under the influence of organic walls, the solvent inside the microemulsion droplets enables not only the surfactant but also the complete droplet to adsorb to the interfaces. Hence, delivering the surfactant molecules to the oil-water interface is achieved faster and more effectively in the organic capillaries. Once the droplet arrives at the interface, the droplet breaks down, the solvent dissolves into the oil film and diffuses. This process is similar to drug delivery at nano-scale. Using non-equilibrium simulations based on the external force field approach we numerically performed steady-state flow measurements to establish that the solvent and the surfactant molecules play separate roles that are both essential in mobilizing the oil film. The surfactant deposited at the oil-water interface reduces the surface tension and acts as a linker that diminishes the slip at the interface. Hence, it effectively enables momentum transfer from the mobile water phase to the stagnant oil film. The solvent penetrating the oil film, on the other hand, modifies flow properties of the oil. In addition, due to selective adsorption, the solvent displaces the adsorbed oil molecules and transforms that portion of the oil into the free oil phase. Consequently, the fractional flow of oil is additionally increased in the presence of solvent. The results of this work are important for understanding the effect of the microemulsion on flow in organic capillaries and its effect on shale oil recovery.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (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)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Measured permeability of an organic-rich shale sample vary significantly with applied laboratory conditions, such as the confining pressure, temperature and the measurement fluid type. This indicates that the measured quantity is influenced by several mechanisms that add complexity to the measurement. The complexity is mainly due to stress dependence of the matrix permeability. Also, it is due to the fact that organic-rich shale holds significant volumes of fluids in sorbed (adsorbed, dissolved) states, sorption can also influence the permeability through its own storage and transport mechanisms. The stress-dependence and sorption effects on permeability could develop under the reservoir conditions and influence the production, although we currently do not have a predictive permeability model that considers their co-existence. In this work this is accomplished by considering that the shale matrix consists of multiple continua with organic and inorganic pores. Stress-dependency of the permeability comes along with slit-shape inorganic pores, whereas the sorption effects are associated with nano-scale organic capillaries. A simple conceptual flow model with an apparent shale permeability is developed that couples the molecular transport effects of the sorbed phase with the stress-dependence of the inorganic matrix. Sensitivity analysis on the new permeability model shows that the stress-dependence of the overall transport is significant at high pore pressure, when the effective stress is relatively low. Diffusive molecular transport of the sorbed phase becomes important as the stress gets larger and, hence, the inorganic pores close. The constructed apparent permeability versus pore pressure curves show the dominance of the molecular transport as permeability improvement characterized by appearance of a minimum permeability value at the intermediate values of the pressure. The new permeability model can be used easily in history-matching a well performance and optimizing its production.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Summary Pore compressibility of a rock could be an important geomechanical consideration for accurate estimation of shale fluid storage capacity. It is, however, typically dependent on the stress conditions, and its value in a subsurface formation could change due to migration and withdrawal of the fluids or changes in the stress field. The pore compressibility is ignored during the routine measurements of porosity. In many other cases, it is oversimplified and assumed to be a constant value. In addition, the pore volume is comparatively small in shale formations. Consequently, the adsorbed and absorbed fluid phases can take up a significant portion of that volume and, hence lead to its reduction. Hence, shale fluid storage capacity measurements that do not consider the sorbed-phase correction may lead to inaccurate analyses. In this project, a laboratory analysis is performed using Iljik and Hasandong shales considering the pore compressibility and sorbed-phase corrections on the selected shale samples. The experimental method considers multiple-step helium gas uptake by a core plug sample under effective stress, Kang et al. (2011). Confining pressure is kept constant and change in pore compressibility is observed due to changes in pore pressure. Analysis of the pore compressibility data is based on Boyle's law as outlined by Santos and Akkutlu (2013). They have used a two-step pressure-volume data to obtain the compressibility as a constant. Here, for the South Korean samples, we extended the approach to multiple (typically five) pressure-step measurement to investigate the compressibility as a pressure-dependent coefficient under varying confining stress conditions. Next, mineralogy quantification and gas storage capacity measurements are performed on the samples using methane and carbon dioxide gases as the measurement fluid. Finally pressure pulse decay is analyzed for permeability as outlined in Akkutlu and Fathi (2012). Five shale plug samples have previously been selected for the analysis. The pore compressibility data shows strong nonlinearity to the changes in effective stress. The pore volume and sorption parameters are predicted in the presence of this nonlinearity. The laboratory analysis shows that no strong relationship has been found between the compressibility and the sample mineralogy. Measured permeability is low indicating seal rock features.
- Asia > South Korea (0.70)
- North America > United States > Texas (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract A significant part of the gas storage in organic shales is in nanometer-scale pores located in the organic material. These pores have gas species-specific adsorption on the surface of the pore walls and are in material that may have significant pore-volume dependence on pore pressure. In the smaller pores molecular-dynamic calculations for methane show that the storage model that consists of a single high density adsorbed gas layer and a free-gas component that obeys the equation-of-state for bulk methane is only an approximation. The volume of the adsorption layer, which reduces the pore volume available for free gas storage, is a function of gas species, temperature and pressure. This, along with pore-volume compressibility, requires that gas storage be measured with the reservoir gas under reservoir conditions on a solid core sample. The current methods that use ground-up samples to measure adsorption with the reservoir gas but pore volume with helium do not satisfy the requirements for an accurate gas-storage determination. To address these issues, a new methodology to measure total gas storage on a core sample at reservoir conditions is described. A method to model the measured storage as an adsorbed component and free component is developed. For methane, an equation to extract an average pore radius from the modeled adsorbed-state density is developed. The methodology is illustrated on a measurement on an organic-shale sample.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.94)