Saeid Enayatpour

FreezeFrac Improves the Productivity of Gas Shales

With rapid depletion of conventional petroleum supplies an d due to energy security concerns, the world is increasingly turning its attention to unconventional hydrocarbon reservers such as oil shales, gas shales, tight gas sands, coalbed methane, an d gas hydrates. Despite the abundant unconventional reservers, the produc ti n is still hindered by many obstacles including lack of te chnology and knowledge of the physics of flow in tight porous media. Flowin g the tightly-locked hydrocarbon to the well in such formati ons, unlike the conventionals, requires a large number of interconnecting pathways for flow. The existing in-situ cracks in rock have to be connected in order for the hydrocarbon to flow into the well bore. In this paper we go over the basic mechanisms of rock fra ture in micro and Macro levels and then study the two parameters wh ose variations could reduce the effective stress and lead to rock fracturing. We then discuss the effect of inhomogeneity on t he fracture load and show that the dominant load for thermal f racturing is the tensile stress. There are three governing equations of s tress, heat transfer, and flow which should be solved in a coup led fashion, for which we are using the finite element software packages. A s uming that thermal cracks increase the permeability of ro ck in the near wellbore zone by 10-10,000 times, we show the impact of r ock stimulation by thermal shock on cumulative production o f gas from a sample case of a wellbore placed in a tight formation. T he improved recovery for the sample case is 16%. Introduction Injection of cold fluids into reservoir rock, induces therma l cr cks. This has been observed in the injection of cold CO2 i nto reservoir rock for sequestration purposes and from extensive studies of thermal loading on rock properties (Kim and Kemeny, 2009; Izadi and Elsworth, 2013; Keaney et al., 2004). Successful productio n of oil and gas from shales with nano-Darcy range permeabili ty calls for understanding of the complex behavior of the rocks. To bette r design the production, we utilize the finite elements analy sis (FEA) of the coupled physics (thermal, flow and stress deformation) b ehind these behaviors. Fracture mechanics started with the works of Inglis (Inglis , 1913) and Griffith (Griffith, 1921). They showed the effect o f size of a component in the strength of that component. Inglis stud ied the stresses around a crack and found out that the stress a the crack tip of an elliptical crack is a function of the curvatur e of the crack tip and the size of the crack. We introduce a meth od for manipulation of rock strength that makes the rock more susce ptibl to a ramified pattern of fracture. There are two distin ct analysis classes for quantifying the well productivity enhancement : the Finite Elements and Discrete Elements methods, (FEM an d DEM). Our simulation tool in this paper is the FEM. Currently, the popular industry approach to production fro m tight formations, is massive hydraulic fracturing, to cre ate extensive surface area exposed to flow. Our numerical investigations i n this paper indicate that, hydraulic fracturing can be impr oved by taking advantage of the combined effect of the fracturing fluid temp rature and reduced effective stress on flow properties to cr eate a larger surface area and a more ramified pattern of conductive flow pat hways. Unlike pore pressure diffusion, heat diffuses easily in sha les. Moreover, rocks in general are very weak in tension, and as a result, thermal reduction of the near wellbore region can lead to significant tensile stresses in the rock, leading to drast ic permeability enhancements. Simulation results for production from hori zontal gas wells stimulated by thermal shocks for three hour s in a zone of two feet radius around the wellbore exhibit a 16% enhancemen t in recovery. Thermal stimulation of rock in the near wellbo re zone could also facilitate the hydraulic fracturing process whe re the earth stresses are isotropic. This paper looks into the geomechanical challenges of produ cing tight formations and highlights a few rock properties w hich have the most significant role in the success of matrix stimulation of tight formations. During production of hydrocarbon, both c omponents of a reservoir rock: fluid and rock matrix, undergo pressure and deformation through their compressibilities. This paper h ighlights the methods of improving the injectivity/productivity of well s placed in tight formations, through inducing thermal shoc ks in reservoir rock. The efficiency of the thermal shock relies on the large s tiffness and the complex structure of shale. The large stiff ness and the complexity of shale matrix is not an obstacle to producing ti ght formations. In fact, the method of thermal shock that we p ropose in this paper, heavily relies on the large stiffness of reservo ir ock. We have shown that the stiffer the rock, the easier th thermal fracture initiation (Enayatpour and Patzek, 2013). There are shale r es rvoirs with extremely stiff matrix around the world, for example in China (Lau and Yu, 2013), for which thermal shock and creatio n of thermal strains required for fracturing could work effic iently; hence, thermal shock is the potential candidate to stimulat e matrix and enhance recovery in such tight and stiff shale fo rmations. What makes the matrix stimulation process successful, is th e grain disintegration process which in turn depends on the c omplex structure of shale. The numerical simulations in this paper r carried out using Finite Element method. Here we solve th e coupled system of equations for flow, stress, and temperature diffus ion in rock to study how fast and how far the reservoir heat dif fuses. Once we obtain the zone of thermally frozen rock around the wellbo re, we can determine the permeability enhancement in this zo ne which leads to improved recovery. In this paper, we have not invest igated the permeability enhancement aspect of the study; ra ther, we have assumed that, when thermal cracks are created around the wel lbore and connected to natural fractures, permeability cou ld increase 10 to 10,000 times with respect to initial permeability of fo rmation. Studying this assumption is the subject of our futu re research works. Rock Fracture To improve the wellbore injectivity/productivity, we util ize the physical matrix stimulation as opposed to matrix aci dizing; therefore, we have to deal with stresses between rock grains and study th e parameters which impact intergranular effective stresse s in rock. We then look into the mechanism and effect of rock fracturing du e to freezing the reservoir rock in the near wellbore zone. To disintegrate the rock constituents in an effort to increase permeability by opening pathways for flow, we should increase the fluid pres sure so as to reduce the effective stress or the grains contact pressure. This is not quite feasible in tight formations; however, we c ould resort to a novel method of reducing the effective stress through induc ing thermal strains by freezing the reservoir rock. In this m ethod, the cold fracturing fluid or a freezing agent in the fluid, reduces the r ese voir temperature in the near wellbore zone for certain p eriod of time, for instance 30 minutes to 3 hours depending on rock properti es. The contraction of the laterally-confined reservoir roc k, results in thermal strains and tensile stresses. These tensile stress es, reduce the effective stress from the minimum horizontal stress toT0: the rock tensile strength, as shown in Figure 3. Once the minimum horizontal stress in rock reaches the tensile strength of ro ck, the rock starts to rupture. Let’s start with a brief introduction to mechanism of rock fr acturing in tight formations. The total overburden pressur e on rock is taken by matrix and fluid in the pores of the rock. The former is called the effective stress of rock and the latter is calle d fluid pressure or pore pressure. The effective stress is the conta ct pressure between grains, in other words, it is the compone nt which is holding the rock grains together. To initiate the rupture in rock, the effective stress has to decline and go from compres sive to tensile stress. Once the grains are under tensile stress, they start to get separated. The fracture in rock is a function of the loading and the rock s trength. The rock strength is a function of the compressive l oad; therefore, any reduction in the effective stress leads to lo wering the rock strength and making the rock more prone to rup tu e. The rock grains are bonded by cementing agents, as a result, crac ks in rock could initiate from each single grain (inter-gran ular rupture) or from the interface of each two grains (interface rupture) . Depending on the strength of rock grains and bonds, either o f the rupture zones could dominate the fracture of rock. In macro-scale st udies, there are two modes for rupturing the rock: shear and t e sile. These are shown in Figure 1. It should be noted that, in realit y, due to inhomogeneity in rock properties, any loading woul d result in both modes of failure. Figure 2 exhibits a simple model of a ho mogenous rock (A), and an inhomogenous rock (B) which are bot h fixed at ends and then frozen. Due to thermal stresses, both sa mples tend to exhibit contraction, consequently, due to the presence of fixed boundaries which simulate the rock lateral confinement , thermal strains are developed. Notice that in (B), both she ar and tensile stresses are developed; however, the dominant mode is shear . At the moment, we base our studies on tensile failure mode fo r rock matrix stimulation and take only this component into consid eration. Bear in mind that, rock stimulation could potentia lly benefit even more from shear failure as well, which is not investigated in this paper. In micro-scale; however, the tensile mode is the dominant mode; therefore, we focus on this type of failure. T

Thermal Shock in Reservoir Rock Enhances the Hydraulic Fracturing of Gas Shales

prohibited. Summary Thermal shock occurs when a material’s temperature is changed over a short period of time such that constituent parts of the material deform by different amounts. The deformation of material due to thermal load can be manifested through strain and stress. As the temperature diffuses from hydraulic fracture into reservoir, the temperature changes with x coordinate and the stress/strain can be obtained from the Equation (6). Once the stress at any point exceeds the strength of material, the body fails in one of the three modes of tension, compression or shear. A thermal load on rock, results in the creation and extension of cracks, crushing the grains, or sliding the grain interfaces. In this paper we look into the possibility of stimulating the rock matrix beyond hydraulic fracturing stimulation by cooling down the rock. The physics of temperature reduction in a solid dictates that when a solid is laterally fixed and undergoes temperature reduction, a thermal stress gradient is induced in the solid body. In rock, this thermal stress gradient leads to a differential contraction of the rock, which in turn creates openings, referred to as thermal cracks. We numerically solve the nonlinear gas diffusivity equation, using finite element method and show that the thermal cracks in rock have the potential to improve the productivity of wells placed in tight formations by 20%.

Evaluation of surfactant flooding using interwell tracer analysis

Surfactant flooding is an important enhanced oil recovery (EOR) method, especially in carbonate oil reservoirs where water flooding may not have an effect on oil recovery as much as for sandstone reservoirs. This is because of the initial wettability of most carbonate reservoirs that is mixed- or oil-wet. Since surfactant flooding has a great impact on both fluid–fluid and rock–fluid interactions, it can be an efficient EOR method for these kinds of reservoirs. Surfactants affect fluid–fluid interactions by reducing interfacial tension (IFT) between water and oil phases and rock–fluid interactions by wettability alteration. The objective of this paper is the evaluation of these two surfactant mechanisms in non-fractured carbonate reservoirs using UTCHEM, the University of Texas chemical compositional simulator. In this paper, first, the laboratory data of two surfactant spontaneous imbibition tests for carbonate cores are successfully matched with modeled data to evaluate the mechanisms of surfactant flooding. Second, the field-scale surfactant flooding is simulated using the experimental data from spontaneous imbibition tests. Several cases are modeled in order to study the effect of surfactant flooding in terms of decreasing IFT and wettability alteration. Since the formation brine salinity in most reservoirs is more than the optimum salinity of surfactant phase behavior, the benefit of combining surfactant and low-salinity water is also investigated. Finally, tracer test simulation is performed to estimate the average oil saturation within the swept pore volume at the end of each recovery mode.