Russell T. Johns

Effect of Capillary Pressure on Phase Behavior in Tight Rocks and Shales

Phase behavior is important in the calculation of hydrocarbons in place and in the flow of phases through the rocks. Pore sizes can be on the order of nanometers for shale and tight-rock formations. Such small pores can affect the phase behavior of in-situ oil and gas because of increased capillary pressure. Not accounting for increased capillary pressure in small pores can lead to inaccurate estimates of ultimate recovery, and of saturation pressures. In this paper, capillary pressure is coupled with phase equilibrium equations, and the resulting system of nonlinear fugacity equations is solved to present a comprehensive examination of the effect of small pores on saturation pressures and fluid densities. Binary mixtures of methane with heavier hydrocarbons and a real reservoir fluid from the Bakken shale are considered. The results show that accounting for the impact of small pore throats on pressure/volume/temperature (PVT) properties explains the inconsistent gas/oil-ratio (GOR) behavior, high flowing bottomhole pressures, and low gas-flow rate observed in the tight Bakken formation. The small pores decrease bubble-point pressures and either decrease or increase dew-point pressures, depending on which part of the two-phase envelope is examined. Large capillary pressure also decreases the oil density in situ, which affects the oil formation volume factor and ultimate reserves calculations. A good history match for wells in the middle Bakken formation is obtained only after considering a suppressed bubblepoint pressure. The results show that the change in saturation pressures, fluid densities, and viscosities is highly dependent on the values of interfacial tension (IFT) (capillary pressure) used in the calculations.

Development of Miscibility in Four-Component CO2 Floods

A rigorous tie-line extension criterion for the minimum miscibility pressure (MMP) is derived for dispersion-free, 1D displacements in four-component systems in which CO 2 displaces oil containing dissolved methane. The key tie-lines required for application of the MMP criterion are obtained by a simple graphical construction. A simplified technique for construction of solutions is demonstrated for the CO 2 /methane/butane/decane system. The new technique makes solution of certain four-component problems not much more difficult than solution of a Buckley-Leverett displacement of oil by water

Three–Phase Flash in Compositional Simulation Using a Reduced Method

CO2 flooding at low temperatures often results in three or more hydrocarbon-phases. Multiphase compositional simulation must accurately simulate such gas floods. Drawbacks of modeling three hydrocarbon-phases are the increased computational time and convergence problems associated with flash calculations. Use of a reduced method is a potential solution.

Effect of Capillary Pressure on Fluid Density and Phase Behavior in Tight Rocks and Shales

Pore sizes can be on the order of nanometers for shales and tight rock formations. Such small pores can affect the phase behavior of insitu oil and gas owing to increased capillary pressure. In this paper, capillary pressure is coupled with phase equilibrium equations and the resultant system of nonlinear equations is solved. Effects of small pores on the dew point and bubble point curves, as well as on interfacial tension and fluid densities are investigated. Both binary mixtures of methane with heavier hydrocarbons and real fluids are considered.

Compositional Modeling of Dissolution-Induced Injectivity Alteration During CO 2 Flooding in Carbonate Reservoirs

Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during carbon dioxide (CO2) flooding, which may significantly affect well injectivity, well integrity, and oil recovery. Reactions can cause significant scaling in and around injection and production wells, leading to high operating costs. Dissolution-induced well-integrity issues and seabed subsidence are also reported as a substantial problem at the Ekofisk field. Furthermore, mineral reactions can create fractures and vugs that can cause injection-conformance issues, as observed in experiments and pressure transients in field tests. Although these issues are well-known, there are differing opinions in the literature regarding the overall impacts of geochemical reactions on permeability and injectivity for CO2 flooding. In this research, we develop a new model that fully couples reactive transport and compositional modeling to understand the interplay between multiphase flow, phase behavior, and geochemical reactions under reservoir and injection conditions relevant in the field. Simulations were carried out with a new in-house compositional simulator on the basis of an implicit-pressure/explicitcomposition and finite-volume formulation that is coupled with a reactive transport solver. The compositional and geochemical models were validated separately with CMG-GEM (CMG 2012) and CrunchFlow (Steefel 2009). Phase-and-chemical equilibrium constraints are solved simultaneously to account for the interaction between phase splits and chemical speciation. The Søreide and Whitson (1992) modified Peng-Robinson equation of state is used to model component concentrations present in the aqueous and hydrocarbon phases. The mineral-dissolution reactions are modeled with kinetic-rate laws that depend on the rock/brine contact area and the brine geochemistry, including pH and water composition. Injectivity changes caused by rock dissolution and formation scaling are investigated for a five-spot pattern by use of several common field-injection conditions. The results show that the type of injection scheme and water used (fresh water, formation water, and seawater) has a significant impact on porosity and permeability changes for the same total volume of CO2 and water injected. For continuous CO2 injection, very small porosity changes are observed as a result of evaporation of water near the injection well. For water-alternating-gas (WAG) injection, however, the injectivity increases from near zero to 50%, depending on the CO2 slug size, number of cycles, and the total amount of injected water. Simultaneous water-alternating-gas injection (SWAG) shows significantly greater injectivity increases than WAG, primarily because of greater exposure time of the carbonate surface to CO2-saturated brine coupled with continued displacement of calcite-saturated brine. For SWAG, carbonate dissolution occurs primarily near the injection well, extending to larger distances only when the specific surface area is small. Formation water and seawater lead to similar injectivity increases. Carbonated waterflooding (a special case of SWAG) shows even greater porosity increases than SWAG because more water is injected in this case, which continuously sweeps out calcite-saturated brine. The minerals have a larger solubility in brine than in fresh water because of the formation of aqueous complexes, leading to more dissolution instead of precipitation. Overall, this research points to the importance of considering the complex process coupling among multiphase flow, transport, phase behavior, and geochemical reactions in understanding and designing schemes for CO2 flooding as well as enhanced oil recovery at large.

Theory of Multicontact Miscible Displacement with Nitrogen

Analytical solutions for displacement of mixtures of methane, butane and decane by nitrogen or nitrogen/methane mixtures are used to explain conflicting experimental observations concerning the sensitivity of minimum miscibility pressures to changes in the compositions of an initial oil or the injection gas. The solutions presented show why some investigators have reported weak dependence of the minimum miscibility pressure (MMP) on methane concentrations while others have reported significant sensitivity. The analysis of displacement composition routes indicates that either observation can be correct for some ranges of initial and injection fluid compositions, and shows that the sensitivity behavior depends on the relative positions in composition space of three key tie lines, the initial, injection, and crossover tie lines.

A Mechanistic Model for Wettability Alteration by Chemically Tuned Waterflooding in Carbonate Reservoirs

Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to morewater-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidicoil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO 4 ) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2þ, Mg2þ) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2þ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO 4 (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/ kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

Pressure solution for sequential hydraulic tests in low-transmissivity fractured and nonfractured media

In the last decade, considerable effort has been applied to the characterization of low-permeability, heterogeneous formations. A primary reason for the increased activity is the importance of estimating formation properties for use in safety assessments at proposed nuclear waste disposal sites, such as those in Switzerland, Germany, Sweden, and the United States. Methods for determining formation properties (e.g., transmissivity, static head, storativity, and flow boundaries) are varied, but hydraulic testing is commonly used. Hydraulic tests in low-permeability media typically consist of a sequence of multiple test events such as slug, constant pressure, and pulse tests. Each single test event can significantly affect the measured pressure response of subsequent test events. The pressure response can also be affected by borehole mud pressures that occur prior to testing (i.e., pretest pressures) and other factors such as well bore storage, well bore skin, and well bore temperature. We present a new analytical solution that accounts for all of the aforementioned complexities. The solution technique treats a sequence of pretest pressures and multiple test events (slugs, pulses, and shut-ins) as one test sequence, thereby accounting for the influence of one test event upon another. The solution is derived so that only a kernel function, the constant-rate pumping test solution, is required for new flow models. Furthermore, the solution is presented for any flow dimension allowing for interpretation in fractured formations where linear, radial, and fractional flow may exist. We demonstrate the use of the solution by inverse modeling to estimate the flow model and parameters for an example hydraulic test conducted in Switzerland.

Comparison of Pressure-Transient Response in Intensely and Sparsely Fractured Reservoirs

In this paper a comprehensive analytical model is presented to quantify the pressure-transient behavior of a naturally fractured reservoir with a continuous matrix-block-size distribution and interporosity skin. Geologically realistic probability density functions of matrix block size are used to represent reservoirs of varying fracture intensity and uniformity. Drawdown and interference type curves are developed with rectangular probability density functions. The results obtained extend previous dual-porosity models by incorporating fracture spacing variability. In the absence of interporosity skin, intensely and sparsely fractured reservoirs show distinctions in the pressure response. Uniformity of a fractured reservoir also significantly affects pressure responses, irrespective of the degree of fracture intensity. The pressure response in a nonuniformly fractured reservoir with large block-size variability, for example, can exhibit a nonfractured (homogeneous) reservoir response. The results may be used to estimate matrix-block-size variability and the degree of fracture intensity from drawdown and interference well tests.

Analytical solutions for flow in porous media with multicomponent cation exchange reactions

Multicomponent cation exchange reactions have important applications in groundwater remediation, disposal of nuclear wastes as well as enhanced oil recovery. The hyperbolic theory of conservation laws can be used to explain the nature of displacements observed during flow with cation exchange reactions between flowing aqueous phase and stationary solid phase. Analytical solutions have been developed to predict the effluent profiles for a particular case of heterovalent cations (Na+, Ca2+ and Mg2+) and an anion (Cl−) for any combination of constant injection and constant initial composition using this theory. We assume local equilibrium, neglect dispersion and model the displacement as a Riemann problem using mass action laws, the charge conservation equation and the cation exchange capacity equation. The theoretical predictions have been compared with experimental data available at two scales—the laboratory scale and the field scale. The theory agrees well with the experimental data at both scales. Analytical theory predictions show good agreement with numerical model, developed using finite differences.