David S. Schechter

Natural fractures in the Spraberry Formation, Midland basin, Texas: The effects of mechanical stratigraphy on fracture variability and reservoir behavior

Horizontal cores from sandstone-siltstone reservoirs in the Spraberry Formation (Midland basin, west Texas) have documented two systems of dramatically different yet dynamically compatible natural fractures, in reservoirs separated vertically by only 145 ft (44 m). Each system is capable of producing a different degree of the northeast-trending permeability anisotropy recognized in Spraberry reservoirs. One fracture system consists of two vertical fracture sets with an apparent conjugate geometry (striking north-northeast and east-northeast). The other system consists of evenly spaced, northeast-striking vertical fractures, nearly bisecting the acute angle of the first system. Although lithologically similar, differences in quartz-overgrowth and clay content in the layers resulted in a yield strength of the lower bed that is only half of that of the upper layer, producing different fracture systems in the two reservoirs despite their proximity. Such differences in the mechanical properties, due to variations in diagenetic and depositional histories of the strata, are probably widespread within the formation. They have the potential to cause significant vertical and lateral variation in the Spraberry fracture system across the basin. Low present-day in-situ stresses in the reservoirs allow the fractures to open, to become more conductive, and even to propagate, under very low injection pressures.

Experimental Investigation of Enhanced Recovery in Unconventional Liquid Reservoirs using CO2: A Look Ahead to the Future of Unconventional EOR

The poor rock quality and matrix permeability several orders of magnitude lower than conventional oil reservoirs observed in unconventional liquid reservoirs (ULR) presents many uncertainties on the storage capacity of the rock and the possibility of enhancing recovery. The technological advances in multiple stage hydraulic fracturing and horizontal drilling have improved the overall profitability of oil shale plays by enhancing the matrix – wellbore connectivity. The combination of these technologies has become the key factor for the operators to reach economically attractive production rates in the exploitation of ULR, causing a lot of focus on their improvement. However, as the reservoir matures, primary production mechanisms no longer drive oil to the hydraulic fractures, making the improvement of matrix – wellbore connectivity insufficient to provide economically attractive production rates. Therefore, the need to develop enhanced recovery techniques in order to improve the displacement of the oil from the matrix, maintain profitable production rates, extend the life of the assets and increase ultimate oil recovery becomes evident. This study presents experimental results on the use of CO2 as an enhanced oil recovery (EOR) agent in preserved, rotary sidewall reservoir core samples with negligible permeability. To simulate the presence of hydraulic fractures, the ULR cores were surrounded by high permeability glass beads and packed in a core holder. The high permeability media was then saturated with CO2 at constant pressure and temperature during the experiment. Production was monitored and the experiment was imaged using x-ray computed tomography to track saturation changes inside the core samples. The results of this investigation support CO2 as a promising EOR agent for ULR. Oil recovery was estimated to be between 18 to 55% of OOIP. We provide a detailed description of the experimental set up and procedures. The analysis of the x-ray computed tomography images revealed saturation changes within the ULR core as a result of CO2 injection. A discussion about the mechanisms is presented, including diffusion and reduction in capillary forces. This paper opens a door to the investigation of CO2 enhanced oil recovery in ULR.

Modeling Fluid Flow Through Single Fractures Using Experimental, Stochastic and Simulation Approaches

A fracture is usually assumed as a set of smooth parallel plates separated by a constant width. However, the flow characteristics of an actual fracture surface would be quite different, affected by tortuosity and the impact of surface roughness. Though several researchers have discussed the effect of friction on flow, their efforts lack corroboration from experimental data and have not converged to form a unified methodology for studying flow on a rough fracture surface.

Impact of Surfactants for Wettability Alteration in Stimulation Fluids and the Potential for Surfactant EOR in Unconventional Liquid Reservoirs

Wettability alteration in shale formations can be an important factor in improving the performance of hydraulic fracturing treatments. The use of surfactants in the frac fluid, at proper concentrations, has shown to change wettability in Unconventional Liquid Reservoirs (ULR) favoring the process of imbibition. This study evaluates and compares the efficiency of anionic and nonionic surfactants in recovering hydrocarbons in carbonate and siliceous preserved side-wall core. The techniques developed also open the door for investigation of low concentration surfactants for enhanced oil recovery (EOR) in ULR. Contact angle (CA) experiments were performed, using the captive bubble method, to measure the magnitude of wettability alteration on intermediate to oil-wet ULR core at reservoir temperature (165 °F). Different types of anionic and nonionic surfactants at field concentrations were used. The results showed that all surfactants lower the CA at the concentration tested. However, anionic surfactants showed better results as observed by lower contact angles. IFT measurements were also performed, using the pendant drop and spinning drop methods, at reservoir temperature using reservoir crude oil and anionic and nonionic surfactants at the same concentrations. The IFT reduction was similar for each type of surfactant compared to regular frac fluid without any surfactant, but anionic surfactant showed slightly better capability of reducing IFT than nonionic surfactants. Computed tomography (CT) scan methods were used to gauge the performance of these surfactants in improving oil recovery. The magnitude of penetration or imbibition into artificially-fractured ULR cores was studied for both anionic and nonionic surfactants. Frac fluids containing surfactants were mixed with a dopant salt to trace the movement of these fluids and measure the penetration numerically. Both, anionic and nonionic, surfactants have higher penetration magnitudes compared to slick water without surfactant. However, anionic surfactants displaced a higher observable amount of liquid hydrocarbon from the shale cores. This observation agrees qualitatively with the results observed in the CA experiments where anionic surfactants showed the lowest contact angles. From the results obtained, it can be concluded that anionic surfactants alter wettability in these ULR core, giving lower CA, better spontaneous imbibition and higher oil recovery than nonionic surfactants. These observed wettability changes induced by surfactants mixed in the frac fluids can improve matrix penetration with spontaneous imbibition which opens further discussions for EOR potential in shale formations. Introduction Production from unconventional liquid reservoirs (ULR) has become one the most important sources of energy in the United States. These ULR have the distinctiveness of being both rock source and reservoir with the characteristic of having low porosity and ultralow permeability. The use of horizontal wells with multiple high permeability hydraulic fractures has been a highly successful technique allowing these ultralow permeability reservoirs to create effective paths for hydrocarbons to flow towards the wellbore and to consequently produce at commercial flow rates. Adding surfactants into frac fluids can alter matrix wettability. This wettability alteration in shale formations can be an important factor on improving the performance of hydraulic fracturing treatments. The use of surfactants in the frac fluid, at proper concentrations, has shown to change wettability in ULR favoring the process of imbibition. Frac fluid imbibition and subsequent oil expulsion from the matrix into hydraulic fractures favors oil production, and this mechanism can be improved by adding surfactants which alter rock wettability or/and lower interfacial tension (IFT) (Chen et al. 2001). 2 SPE-169001-MS Capillary and gravity forces are responsible for imbibition process and are function of wettability, interfacial tension, density differences and pore radius (Chen et al. 2001; Mccaffery and Mungan 1970); however, for ultralow permeability reservoirs, capillary imbibition is the main recovery mechanism for producing hydrocarbons due to the reduced pore size, and hydraulic fractures enhance an effective matrix-fracture interaction in order to recover oil from the matrix (Babadagli et al. 1999). Wettability affects flow behavior and, when altered, imbibition mobilizes oil because of capillary pressure changes from negative to positive (Wang et al. 2012). To alter wettability, surfactants solutions are added to frac fluids to shift rock wettability to water-wet, this enhance imbibition by overcoming capillary forces and letting the water phase to penetrates into the matrix displacing oil in place (Shuler et al. 2011). Surfactants are amphiphilic compounds that have both a hydrophobic and a hydrophilic group. Based on their polar head group, surfactants are most commonly classified in cationic (positive charge), anionic (negative charge) and nonionic (no charge). In previous studies, cationic surfactants have shown improve oil recovery by wettability alteration in oil-wet chalk rocks (Austad et al. 1998; Sharma and Mohanty 2013; Zhang and Austad 2005); however, this type of surfactant requires high concentrations and is too expensive to economically be implemented on the field (Adibhatla and Mohanty 2008; Chen et al. 2001). In addition, anionic and nonionic surfactants have also been studied in fracture carbonates and chalk reservoirs effectively shifting wettability and reducing IFT, improving oil imbibition (Adibhatla and Mohanty 2008; Austad et al. 1998; Babadagli et al. 1999; Chen et al. 2001; Sharma and Mohanty 2013; Wang et al. 2012; Zhang and Austad 2005). The effectiveness of surfactants can be studied by measuring contact angle, IFT and the magnitude of penetration. Contact angle, in the presence of two immiscible fluids and a rock surface, is an appraisal of which fluid preferentially adheres to the rock and provides a measure for wettability of a specific surface (Anderson (b) 1986; Anderson 1986; Dake 1978; Mccaffery and Mungan 1970; Rajayi and Kantzas 2009). In water-oil-rock system in which water is the denser fluid, the rock is waterwet when the contact angle is from 0°-75°, intermediate-wet from 75°-105°, and oil-wet from 105°-180° (Anderson 1986). Cohesive forces among two immiscible liquid molecules are responsible for IFT. Contact angles and IFT are liable for altering capillary imbibition. However, an increase in surfactant concentration not always translates into more oil recovery, thus wettability and IFT alteration do not have a linear relationship with surfactant concentration (Adibhatla and Mohanty 2008). Contact angles can be measured by several methods such as captive bubble, sessile drop, tilting plate, and capillary rise, among others. In addition, IFT can be measured by pendant drop, sessile drop and spinning drop methods. In the petroleum industry, contact angle and IFT measurements are commonly done by the captive bubble and pendant drop method (Anderson (b) 1986; Rajayi and Kantzas 2009). Due to the nature of our experiments in which contact angles and ITFs are based in the deformation of a drop or bubble in another liquid, captive bubble, pendant drop and spinning drop methods were used. Computed-Tomography (CT) technology uses computer-processed x-rays to produce tomographic images of specific areas of the cores, allowing us to see inside them. CT scan methods combined with core-flooding can be used to analyze the penetration magnitude or imbibition of the fluids and the amount of produced oil from shale cores at reservoir conditions. Also, fracturing fluids mixed with a dopant salt enables us to trace the movement of these fluids and measure the penetration numerically. Various experiments have been conducted on the study of wettability and IFT alteration using surfactants based on spontaneous and forced imbibition in carbonate and sandstone reservoirs (Adibhatla and Mohanty 2008; Austad et al. 1998; Babadagli et al. 1999; Chen et al. 2001; Hirasaki and Zhang 2003; Sharma and Mohanty 2013; Shuler et al. 2011; Wang et al. 2012; Zhang and Austad 2005); however, these experiments have limited application on unconventional reservoirs due to their ultralow permeability and low porosity values. There is limited literature on the study of combined effect of wettability and the corresponding IFT alteration effect on imbibition process on core samples from unconventional plays. Wang et al. (2012) conducted wettability and imbibition experiments on cores obtained from the Middle Member in Bakken Shale using modified Amott Harvey methods to determine potential to imbibe and displace oil from shale cores. They concluded that some surfactants altered wettability from oil and intermediate-wet cores towards water-wet, and imbibe to displace more oil than brine alone improving oil recovery. Also, Shuler et al. (2001) performed experiments on Bakken Shale reservoirs providing the selection of a proper surfactant that matches local reservoir conditions and enhances oil displacement by imbibition method. This study combines the effect of wettability and IFT alteration and the corresponding impact on penetration magnitude or imbibition in ULR by conducting contact angle experiments, using the captive bubble method, IFT measurement, using the pendant drop and spinning drop methods, and CT scan technology to evaluate and compare the efficiency of anionic and nonionic surfactants in altering wettability and recovering hydrocarbons from carbonate and siliceous preserved side-wall shale cores at reservoir temperature. The results showed that surfactants can alter wettability on shale cores from oil and intermediate-wet to water-wet and reduce IFT with better performance by anionic surfactants over nonionic surfactants. Also, by CT scan methods we observed that surfactants improve pene

Reservoir Simulation of Waterflood Pilot in Naturally Fractured Spraberry Trend

The Spraberry Trend Area in west Texas presents unusual problems for both primary production and waterflooding. Primary production under solution gas drive recovered less than 10% of the oil in place. After more than 40 years of waterflooding the current oil recovery is still less than 12%. In order to improve the reservoir performance in the Spraberry Trend Area, our studies focused on characterization, modeling and simulation of the Humble Waterflood Pilot. A pilot model was constructed using a three-phase, three-dimensional, dual porosity simulator (ECLIPSE). Lack of understanding of two key issues are addressed, stress-sensitive permeability and rock wettability. These parameters appear to have a dominant effect in reservoir performance. This study emphasized detailed analysis of the stress-sensitive option used in the simulator by developing a numerical model of solid deformation and stress-pressure dependent permeability using a fully implicit finitedifference scheme. The numerical modeling of spontaneous and forced imbibition experiments using Spraberry core plugs were also conducted to investigate the wettability of the Spraberry matrix. These analyses may be helpful for understanding reservoir behavior and reducing uncertain parameters. Several studies were conducted after successfully matching waterflood pilot performance. The waterflood pilot model

The effect of nanoparticle aggregation on surfactant foam stability

The combination of nanoparticles (NPs) and surfactant may offer a novel technique of generating stronger foams for gas mobility control. This study evaluates the potential of silica NPs to enhance the foam stability of three nonionic surfactants. Results showed that the concentration of surfactant and NPs is a crucial parameter for foam stability and that there is certain concentrations for strong foam generation. A balance in concentration between the nonionic surfactants and the NPs can enhance the foam stability as a result of forming flocs in solutions. At fixed surfactant concentration, the addition of NPs at low to intermediate concentrations can produce a more stable foam compared to the surfactant. The production of small population of flocs as a result of mixing the surfactant and NPs can enhance the foam stability by providing a barrier between the gas bubbles and delaying the coalescence of bubbles. Moreover, these flocs can increase the solution viscosity and, therefore, slow the drainage rate of thin aqueous film (lamellae). The measurements of foam half-life, bubble size, and mobility tests confirmed this conclusion. However, the addition of more solid particles or surfactant might have a negative impact on foam stability and reduce the maximum capillary pressure of coalescence as a result of forming extensive aggregates.

Simulation of Spontaneous Imbibition Using Rayleigh-Ritz Finite Element Method-ADiscrete Fracture Approach

Spontaneous imbibition plays a very important role in the displacement mechanism of non-wetting fluid in naturally fractured reservoirs. We developed a new 2D two-phase finite element numerical model, as available commercial simulators cannot be used to model small-scale experiments with different and complex boundary conditions. For the non-linear diffusion saturation equation we cannot apply Rayleigh-Ritz Finite Element Method (FEM). Traditionally, the way around it is to use Galerkin FEM or Mixed FEM formulation, iterative nature of those, makes them unsuitable for solving large-scale field problems. But if we truncate the non-linear terms, decouple and solve analytically the dependent variables from saturation – the primary variable, this non-linear FEM problem reduces to a simple weighted integral weak form, which can be solved with Rayleigh-Ritz method. The advantage of this method is that it is non-iterative, which reduces computation time. We compared our numerical models with the analytical solution of this diffusion equation. We validated a Finite Difference Method (FDM) numerical model using X-Ray Tomography (CT) experimental data, and then went ahead and compared the results of FEM model to that of FDM model. A two-phase field size example, using discrete fracture approach, was developed and its results compared with a commercial simulator.

A New Grid Block System for Reducing Grid Orientation Effect

Abstract The grid orientation effect (GOE) is a long-standing problem plagueing reservoir simulators that employ finite difference schemes. A rotation of the computational grids yields a substantially different solution under certain circumstances. A Cartesian grid with one axis parallel to the line joining an injector and producer gives a solution significantly different from a grid that has the axes oriented at 45° to this line. This article presents a new grid system that can reduce the grid orientation effect. This system involves using a unique grid-block assignment where rectangular grid blocks are interspersed with octagonal grid blocks. The boundaries are populated with triangular grid blocks. The entire domain consists of a “structured” grid block system referred to as the hybrid grid block (HGB).

Application of X-Ray CT for Investigation of CO and WAG Injection in Fractured Reservoirs

Fractured reservoirs have always been considered poor candidates for enhanced oil recovery. This is mainly due to the complexities involved in predicting performance in such reservoirs. A good understanding of multiphase flow in fractures is important to reduce oil bypass and increase recovery in these reservoirs. This paper presents CO2 flooding experiments in homogeneous and fractured rocks with in-situ saturation and porosity measurements using an X-Ray CT scanner. We found that injection rates played an important role in the recovery process, more so in the presence of fractures. At high injection rates we observed faster CO2 breakthrough and higher oil bypass than at low injection rates. But very low injection rates are not attractive from an economic point of view. Hence we injected viscosified water to reduce the mobility of CO2, similar to the WAG process. Breakthrough time reduced significantly and a much higher recovery was obtained. Saturation measurements were made from the CT scans and were found to be in good agreement with those obtained from effluent data.

CO 2 EOR Simulation in Unconventional Liquid Reservoirs: An Eagle Ford Case Study

......................................................................................................................ii DEDICATION .................................................................................................................. iv ACKNOWLEDGEMENTS ............................................................................................... v NOMENCLATURE .......................................................................................................... vi TABLE OF CONTENTS ............................................................................................... viii LIST OF FIGURES ............................................................................................................ x LIST OF TABLES ......................................................................................................... xiii