Ebrahim Fathi

Carbon Dioxide Storage Capacity of Organic-Rich Shales

This paper (SPE 134583) was accepted for presentation at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 20–22 September 2010, and revised for publication. Original manuscript received for review 28 June 2010. Revised manuscript received for review 28 September 2010. Paper peer approved 5 October 2010. Summary This paper presents an experimental study on the ability of organic-rich-shale core samples to store carbon dioxide (CO2). An apparatus has been built for precise measurements of gas pressure and volumes at constant temperature. A new analytical methodology is developed allowing interpretation of the pressure/volume data in terms of measurements of total porosity and Langmuir parameters of core plugs. The method considers pore-volume compressibility and sorption effects and allows small gas-leakage adjustments at high pressures. Total gas-storage capacity for pure CO2 is measured at supercritical conditions as a function of pore pressure under constant reservoir-confining pressure. It is shown that, although widely known as an impermeable sedimentary rock with low porosity, organic shale has the ability to store significant amount of gas permanently because of trapping of the gas in an adsorbed state within its finely dispersed organic matter (i.e., kerogen). The latter is a nanoporous material with mainly micropores (< 2 nm) and mesopores (2–50 nm). Storage in organic-rich shale has added advantages because the organic matter acts as a molecular sieve, allowing CO2—with linear molecular geometry—to reside in small pores that the other naturally occurring gases cannot access. In addition, the molecular-interaction energy between the organics and CO2 molecules is different, which leads to enhanced adsorption of CO2. Hence, affinity of shale to CO2 is partly because of steric and thermodynamic effects similar to those of coals that are being considered for enhanced coalbed-methane recovery. Mass-transport paths and the mechanisms of gas uptake are unlike those of coals, however. Once at the fracture/matrix interface, the injected gas faces a geomechanically strong porous medium with a dual (organic/inorganic) pore system and, therefore, has choices of path for its flow and transport into the matrix: the gas molecules (1) dissolve into the organic material and diffuse through a nanopore network and (2) enter the inorganic material and flow through a network of irregularly shaped voids. Although gas could reach the organic pores deep in the shale formation following both paths, the application of the continua approximation requires that the gas-flow system be near or beyond the percolation threshold for a consistent theoretical framework. Here, using gas permeation experiments and history matching pressure-pulse decay, we show that a large portion of the injected gas reaches the organic pores through the inorganic matrix. This is consistent with scanning-electron-microscope (SEM) images that do not show connectivity of the organic material on scales larger than tens of microns. It indicates an in-series coupling of the dual continua in shale. The inorganic matrix permeability, therefore, is predicted to be less, typically on the order of 10 nd. More importantly, although transport in the inorganic matrix is viscous (Darcy) flow, transport in the organic pores is not due to flow but mainly to molecular transport mechanisms: pore and surface diffusion.

Multiscale Gas Transport in Shales With Local Kerogen Heterogeneities

On the basis of microand mesoscale investigations, a new mathematical formulation is introduced in detail to investigate multiscale gas-transport phenomena in organic-rich-shale core samples. The formulation includes dual-porosity continua, where shale permeability is associated with inorganic matrix with relatively large irregularly shaped pores and fractures, whereas molecular phenomena (diffusive transport and nonlinear sorption) are associated with the kerogen pores. Kerogen is considered a nanoporous organic material finely dispersed within the inorganic matrix. The formulation is used to model and history match gaspermeation measurements in the laboratory using shale core plugs under confining stress. The results indicate significance of molecular transport and strong transient effects caused by gas/solid interactions within the kerogen. In the second part of the paper, we present a novel multiscale perturbation approach to quantify the overall impact of local porosity fluctuations associated with a spatially nonuniform kerogen distribution on the adsorption and transport in shale gas reservoirs. Adopting weak-noise and meanfield approximation, the approach applies a stochastic upscaling technique to the mathematical formulation developed in the first part for the laboratory. It allows us to investigate local kerogenheterogeneity effects in spectral (Fourier-Laplace) domain and to obtain an upscaled “macroscopic” model, which consists of the local heterogeneity effects in the real time—space domain. The new upscaled formulation is compared numerically with the previous homogeneous case using finite-difference approximations to initial/boundary value problems simulating the matrix gas release. We show that macrotransport and macrokinetics effects of kerogen heterogeneity are nontrivial and affect cumulative gas recovery. The work is important and timely for development of newgeneration shale-gas reservoir-flow simulators, and it can be used in the laboratory for organic-rich gas-shale characterization.

Mass Transport of Adsorbed-Phase in Stochastic Porous Medium with Fluctuating Porosity Field and Nonlinear Gas Adsorption Kinetics

Using an upscaling approach based on small perturbation theory, the authors have previously investigated the influence of local heterogeneities in matrix porosity on Darcy flow and Fickian-type pore diffusion in the presence of linear non-equilibrium gas adsorption Fathi and Akkutlu, J. Transp. Porous Med. 80, 281–3044 (2009). They identified non-trivial macro-transport and -kinetics effects of the heterogeneity which significantly retard gas release from the matrix and influence the ultimate gas recovery adversely. The work was a unique fundamental approach for our understanding of gas production and sequestration in unconventional reservoirs; however, it was simplified and did not consider (i) the presence of nonlinear sorption kinetics and (ii) a transport mechanism for the adsorbed phase. In this article, we incorporate the nonlinearity and surface diffusion effects of the adsorbed-phase into their formulation and apply the same upscaling approach to further study the heterogeneity effects. Gas sorption involves the so-called Langmuir kinetics, which is reduced to the well-known Langmuir isotherm in the equilibrium limit. It is found that the nonlinearity participates into both macro-transport and -kinetics, promoting primarily the surface diffusion effects. Whereas surface diffusion, although commonly ignored during modeling subsurface phenomena, brings an intricate nature to the gas release dynamics. Through macro-transport effect of the heterogeneity, it increases ultimate gas recovery and, through the macro-kinetics effect of the heterogeneity, it significantly decreases the time needed to reach the ultimate recovery. As the consequence of these effects, it is shown that the gas–matrix system practically does not reach the equilibrium adsorption limit during any stage of the matrix gas release.

Fully Coupled Finite Element Model to Study Fault Reactivation during Multiple Hydraulic Fracturing in Heterogeneous Tight Formations

Multiple hydraulic fracturing is a proven stimulation technique to improve hydrocarbon production especially in tight, unconventional hydrocarbon bearing reservoirs. A two dimensional (2D) plane strain model, based on linear elastic fracture mechanics (LEFM), has been developed to study multiple fracture propagation and their impact on reactivation of underground discontinuities such as faults. New model solves coupled non-local relationship between fracture width and net pressure in the fracture and non-linear dependence of fluid flow on fracture width and its linear dependence on pressure gradient using finite element method. In this paper, multiple hydraulic fracturing with different number of fractures, fracture spacing and reservoir rock properties are considered. It is found that the number of hydraulic fractures and their spacing significantly impacts fractures geometry and ultimately production performance. The impact found to be more pronounced in heterogeneous reservoir with multiple layers. Slip-tendency analysis performed to investigate the possibility of fault reactivation and discontinuities failure in surrounding areas. Simulation results clearly show dynamics of stable and unstable zones around the hydraulic fracturing area. Discontinuities failure in reactivation zones leads to increase the permeability of formation therefore improving hydraulic fracturing performance. This study is a unique approach for our further understanding of multiple hydraulic fracturing, and it is important for the development of sound numerical hydraulic fracturing optimization models.

Fracture Treatment Design

The chapter starts with defining the terms and quantities required for fracture treatment design such as absolute volume factor, slurry and clean frac fluid rates, slurry density, clean and slurry volume for frac stages, stage proppant, sand per foot and water per foot on both stage and well levels, and sand-to-water ratio. For each one of these properties, actual examples are presented and the solution to the problem is explained in detail. Next, a slick water frac schedule is presented with an actual field example. A foam frac schedule and corresponding calculations are presented, including foam and nitrogen volumes, blender sand concentrations, and clean and slurry rate calculations with and without proppants. For each topic, actual field examples and solutions to the problem are discussed step by step.

Hydraulic Fracturing Chemical Selection and Design

This chapter begins with the introduction of different chemicals added to hydraulic fracturing fluid, such as friction reducer (FR), FR breaker, biocide, iron control, and scale inhibitors. The application of linear gel, gel breaker, buffers, cross-linker, and surfactant is also explained. The importance and application of each added component is detailed. Experimental techniques required for chemical selection and optimization, such as a flow loop test is presented. This chapter also provides examples to calculate the friction pressure.

Hydraulic Fracturing Fluid Systems

This chapter starts with a detailed discussion on slick water and cross-linked gel fluid systems and their applications. Next, hybrid fluid systems and their applications in hydraulic fracturing of shale reservoirs are explained. An introduction on foam fracturing including detailed discussions on foam quality and foam stability is also presented. Finally, the concept of tortuosity is explored ending with typical slick water frac steps including acidizing, pad, proppant, and flush stages.

Rock Mechanical Properties and In Situ Stresses

This chapter opens with basic definitions of Young’s modulus, Poisson’s ratio, fracture toughness, and brittleness and fracability ratios. Next, vertical and minimum and maximum horizontal stress, and Biot’s coefficient are explained. This chapter continues with various states of stress and ends with detailed discussions on transverse and longitudinal fractures. Different examples in each subsection on calculating the rock mechanical properties and in situ stresses are provided.

Introduction to Unconventional Reservoirs

This chapter introduces unconventional resources and their importance in improving quality of life. Basic concepts and terms used in the oil and gas industry are introduced and defined, and then expanded to different gas types, natural gas transportation, and usage. Next, the chapter explains the major differences between conventional and unconventional hydrocarbon resources and various characteristics of different unconventional resources such as coalbed methane, tight sands, shale gas, and gas hydrates reservoirs. At the end of the chapter, detailed discussions on shale gas reservoirs, their pore structure, mineralogy, and rock characteristics are presented.

Shale Initial Gas-in-Place Calculation

This chapter introduces the most recent techniques in calculating the original gas in place (OGIP) of organic-rich shale reservoirs. The chapter introduces gas distribution in different pore structures of shale gas reservoirs and different techniques used for OGIP calculations. The effect of adsorbed gas volume and adsorbed layer thickness on OGIP calculations is then discussed. The chapter also outlines analytical and numerical techniques of adsorbed gas density measurements. Examples are presented that clearly show the steps required for OGIP calculations. Finally, the concept of recovery factor is discussed and sample practice is provided.