Perapon Fakcharoenphol

The Effect of Osmotic Pressure on Improve Oil Recovery from Fractured Shale Formations

Shale swelling during drilling is attributed to osmotic pressure, where low-salinity water enters the shale pores to cause swelling. Low-salinity water injected into high-salinity Bakken formation could similarly enter the matrix pores to displace oil by counter-current flow observed in core experiments. As a result, we believe, low-salinity water can potentially enhance oil recovery from oil-wet Bakken formation. In this paper, we report experimental and numerical modeling studies we conducted to evaluate the potential of lowsalinity waterflooding in Bakken. For laboratory experiments, we used horizontal core plugs drilled parallel to the bedding plane. The mathematical included osmotic pressure, gravity and capillary effects. In the mathematical model, the osmotic pressure mass transfer equations were calibrated by matching time-dependent salinities in a published laboratory osmotic pressure experiment. We also modeled oil recovery for a Bakken core using our osmotic pressure mass transport model. The results indicate that osmotic pressure promotes counter-current flow of oil from both the water-wet and oil-wet segments of the core. Introduction Osmosis is the transport of water molecules flow from low-salinity side of a semi-permeable membrane to the high-salinity side to equalize the concentration of the dissolved salts. This causes an increase of pressure on the higher-salinity side, called osmotic pressure (π), Fig. 1. In subsurface environment, high-clay shale sediments can behave as a semi-permeable membrane, thus causing osmotic water transport (Kemper; 1961, Milne et al.; 1964, Young and Low; 1965, Chenevert; 1970, Olsen; 1972, Greenberg et al.; 1973, Marine and Fritz; 1981, Fritz; 1986, Van Oort et al.; 1994, and Keijzer; 2001).

Coupled Geomechanical and Reactive Geochemical Model for Fluid and Heat Flow: Application for Enhanced Geothermal Reservoir

A major concern in development of fractured reservoirs in Enhanced Geothermal Systems (EGS) is to achieve and maintain adequate injectivity, while avoiding short-circuiting flow paths. The injection performance and flow paths are dominated by the permeability distribution of fracture network for EGS reservoirs. The evolution of reservoir permeability can be affected by rock deformation, induced by the change in temperature or pressure around the injector, and chemical reactions between injection fluid and reservoir rock minerals. Thus the change in permeability due to geomechanical deformation and mineral precipitation/dissolution could have a major impact on reservoir long-term performance. A coupled thermal-hydrologicalmechanical-chemical (THMC) model is in general necessary to examine the reservoir behavior in EGS. This paper presents a numerical model, TOUGH2-EGS, for simulating coupled THMC processes in enhanced geothermal reservoirs. This simulator is built by coupling mean stress calculation and reactive geochemistry into the existing framework of TOUGH2 (Pruess et al., 1999) and TOUGHREACT (Xu et al., 2004a), the well-established numerical simulators for geothermal reservoir simulation. The geomechanical model is fully-coupled as mean stress equations are solved simultaneously with fluid and heat flow equations. After solution of the fluid, heat, and stress equations, the flow velocity and phase saturations are used for reactive geochemical transport simulation in order to sequentially couple reactive geochemistry at each time step. We perform coupled THMC simulations to examine a prototypical EGS reservoir for permeability evolution at the vicinity of the injection well. The simulation results demonstrate the strong influence of rock deformation effects in the short and intermediate term, and long-term influence of chemical effects. It is observed that the permeability enhancement by thermalmechanical effect can be counteracted by the chemical precipitation of minerals, initially dissolved into the low temperature injected water. We analyze the sensitivity of temperature of injected water on the coupled geomechanical and geochemical effects, and conclude that the temperature of injected water could be modified to maintain or even enhance the reservoir permeability and the injection performance. Introduction The successful development of enhanced geothermal systems (EGS) highly depends on the reservoir fracture network of hot dry rock (HDR) and its hydraulic properties, especially the reservoir permeability. The geomechanical processes under subsurface reservoir condition are prevalent in the EGS applications. For example, Tsang (1999) investigated and claimed that hydraulic properties of fracture rocks are subjected to change under reservoir mechanical effects. Rutqvist et al. (2002) presented the correlations between reservoir in-situ stress and the porosity, permeability and capillary pressure. It is also well known that the EGS production processes, such as the cold water injection and steam or hot fluid extraction, have strong thermo-poro-elastic effects on EGS reservoirs. On the other hand, the strong impacts of geochemical reaction on the EGS reservoirs have been observed in the commercial EGS fields and studied for carbon dioxide (CO2) based geothermal system in the past few years. Kiryukhin et al. (2004) modeled the reactive chemical process based on the field data from tens of geothermal fields in Kamchatka (Russia) and Japan. In addition, Xu et al. (2004b) presented the reactive transport model of injection well scaling and acidizing at Tiwi field in Philippines. Montalvo et al. (2005) studied the calcite and silica scaling problems with exploratory model for Ahuachapan

Managing Shut-in Time to Enhance Gas Flow Rate in Hydraulic Fractured Shale Reservoirs: A Simulation Study

Some shale gas and oil wells undergo month-long shut-in times after multi-stage hydraulic fracturing well stimulation. Field data indicate that in some wells, such shut-in episodes surprisingly increase the gas and oil flow rate. In this paper, we report a numerical simulation study that supports such observations and provides a potentially viable underlying imbibition and drainage mechanism. In the simulation, the shale reservoir is represented by a triple-porosity fracture-matrix model, where the fracture forms a continuum of interconnected network created during the well simulation while the organic and non-organic matrices are embedded in the fracture continuum. The effect of matrix wettability, capillary pressure, relative permeability, and osmotic pressure, that is, chemical potential characteristics are included in the model. The simulation results indicate that the early lower flow rates are the result of obstructed fracture network due to high water saturation. This means that the injected fracturing fluid fills such fractures and blocks early gas or oil flow. Allowing time for the gravity drainage and imbibition of injected fluid in the fracture-matrix network is the key to improving the hydrocarbon flow rate during the shut-in period. Introduction Some shale gas and oil wells undergo month-long shut-in times after multi-stage hydraulic fracture stimulation. Field data indicate that in some wells, such shut-in episodes surprisingly increase the gas and oil flow rate. For example, Fig. 1 shows the effect of an extended shut-in on production of a multi-stage hydraulically fractured well in Marcellus shale (Cheng, 2012). The well was flowed back, after hydraulic fracture stimulation, for a short period before it underwent a six-month shut-in period. When the well was reopened after six months of shut in, gas production rate increased and water production rate decreased significantly. The question is what caused this apparent anomaly? Water load recovery and flowback behavior Field experience indicates that water load recovery could be as low as 5% of the total injection volume in Haynesville shale to as high as 50% of that in Barnett and Marcellus shales (King, 2012). Number of mechanisms could contribute to the lowrecovery, including extra-trapped water due to changing in natural fractures width that increasing during injection and decreasing during production periods (Economides et al., 2012), water imbibition into shale matrix by capillary pressure (Cheng, 2012). Flow back water analyzed by Haluszczak et al. (2013) indicates that formation brine in shale basin could be higher than 150,000 ppm, Fig. 2b. As the typical fracturing fluid comprises low-salinity water, in many cases it is in the range of 1,000 ppm, significant salinity contrast would be expected. This major salinity difference could lead to substantial chemical potential differences creating large osmotic pressure and driving filtrate from natural fractures into shale matrix block.

Non-Darcy displacement in linear composite and radial aquifer during CO2 sequestration

This paper presents Buckley-Leverett type analytical solutions for non-Darcy displacement of two immiscible fluids in linear and radial composite porous media. High velocity or non-Darcy flow commonly occurs in the vicinity of the wellbore because of smaller flowing cross-sectional areas. However, the effect of such non-Darcy flow has been traditionally ignored. To examine the physical behaviour of multiphase immiscible fluids in non-Darcy displacement, an extended Buckley-Leverett type of solution is discussed. There exists a Buckley-Leverett type solution for describing non-Darcy displacement in a linear homogeneous reservoir. This work extends the solution to flow in linear and radial composite flow systems. We present several new Buckley-Leverett type analytical solutions for non-Darcy flow in more complicated flow geometries of linear and radial composite reservoirs, based on non-Darcy flow models of Forchheimer and Barree-Conway. As application examples, we use the analytical solutions to verify num...

A Unified Mathematical Model for Unconventional Reservoir Simulation

Unconventional hydrocarbon resources from low-permeability formation, i.e., tight sands and shales, are currently received great attention because of their potential to supply the entire world with sufficient energy for the decades to come. In the past few years, as a result of industry-wide R&D effort, progresses are being made towards commercial development of gas and oil from such unconventional resources. However, studies, understandings, and effective technologies needed for development of unconventional reservoirs are far behind the industry needs. Unconventional reservoir dynamics is characterized by highly nonlinear behavior of multiphase flow in extremely lowpermeability rock, coupled by many co-existing, processes, e.g., non-Darcy flow and rock-fluid interaction within tiny pores or micro-fractures. Quantitative characterization of unconventional reservoirs has been a significant scientific challenge currently. Because of complicated flow behavior, strong interaction between fluid and rock as well as multi-scaled heterogeneity, the traditional Darcy-law-and-REV-based model may not be applicable for describing flow phenomena in unconventional reservoirs. In this paper, we will discuss a general mathematical model proposed for unconventional reservoir simulation. We will present a unified framework model to incorporate various nonlinear flow and transport processes using a multi-domain, multi-continuum concept to handle multi-scaled heterogeneity of unconventional formation. Specifically, we will use extended or modified Darcy law to include the following processes: (1) non-Darcy flow with inertial effects; (2) non-Newtonian behavior (i.e., threshold pressure gradient for flow to occur); (3) adsorption and other reaction effect; and (4) rock deformation. The proposed modeling methodology has been implemented into a general reservoir simulator and will be demonstrated for its application in analyzing well tests in fractured vuggy reservoirs, non-Darcy flow, and non-Newtonian flow in porous and fractured reservoirs. Introduction Significant progress has been made in the past decade in producing gas and oil from unconventional petroleum resources, including low-permeability shale oil and gas reservoirs, and tight gas formations. However, low gas/oil recovery rate from such unconventional resources remains as the main technical difficulty. For example, gas recovery rate from these unconventional resources is estimated at 10-30% of GIP, much lower from conventional gas reservoirs. Gas and oil production or flow in such extremely low-permeability formations is complicated by flow condition and many co-existing processes, such as severe heterogeneity, Klinkenberg effect (Klinkenberg, 1941), non-Darcy flow behavior, adsorption/desorption, strong interactions between fluids (gas and water) molecules and solid materials within tiny pores, as well as microand macrofractures of shale and tight formations. Currently, there is little in basic understanding on how these complicated flow behavior impacts on gas flow and the ultimate gas recovery from such reservoirs. There is a general lack in technologies or approaches available for effective gas production from unconventional reservoirs (MIT, 2010), except two technologies: horizontal drilling and hydraulic fracturing, which seems to work (Denny, 2008; Bybee, 2008; King, 2010). In particular, there are no effective and applicable reservoir

Non-Darcy Displacement in Linear Composite and Radial Flow Porous Media

This paper presents Buckley-Leverett type analytical solutions for non-Darcy displacement of two immiscible fluids in linear and radial composite porous media. High velocity or non-Darcy flow commonly occurs in the vicinity of wellbore because of smaller flowing cross-sectional area, however, the effect of such non-Darcy has been traditionally ignored. To examine physical behavior of multiphase immiscible fluid nonDarcy displacement, an extended Buckley-Leverett type of solution is discussed. There exists a Buckley-Leverett type solution for describing non-Darcy displacement in a linear homogeneous reservoir. This work extends the solution to flow in linear and radial composite flow systems. We present several new Buckley-Leverett type analytical solutions for non-Darcy flow in more complicated flow geometry of linear and radial composite reservoirs, based on non-Darcy flow models of Forchheimer and Barree-Conway. As application examples, we use the analytical solutions to verify numerical simulation results as well as to discuss non-Darcy displacement behavior. The results show how non-Darcy displacement in linear and radial composite systems are controlled not only by relative permeability, but also non-Darcy coefficients, characteristic length, injection rates, and as well as discontinuities in saturation profile across the interfaces between adjacent flow domains. Introduction Multiphase flow and displacement occurs in a large variety of subsurface systems ranging from gas, oil, and geothermal reservoirs, vadose zone hydrology, and soil sciences. In oil and gas industry, fluid displacement has long been used as an effective EOR process. Buckley and Leverett [1942] established the fundamental principle for flow and displacement of immiscible fluids through porous media in their classic study of fractional flow theory. Their solution involves the displacement process of two incompressible, immiscible fluids in a one-dimensional, homogeneous system without considering capillary effect. The solution, then, has been extended in many aspects e.g. including capillary effects [Yortsos and Fokas, 1983; Chen, 1988; Mc-Whorter and Sunada, 1990], heterogeneous reservoir, linear composite,Wu [1993]. The effects of non-Darcy or high-velocity flow regimes in porous media have long been noticed and investigated for porous media flow (e.g., Tek et al., 1962; Scheidegger, 1972; Katzand Lee, 1990;Wu, 2002).

The Effect of Water-Induced Stress To Enhance Hydrocarbon Recovery in Shale Reservoirs

Waterflooding has been an effective improved-oil-recovery (IOR) process for several decades. However, stress induced by waterflooding has not been well studied or documented. Water injection typically increases reservoir pressure and decreases reservoir temperature. The increase in reservoir pressure and decrease in reservoir temperature synergistically reduce the effective stress. Because of such decrease in stress, existing healed natural fractures can be reactivated and/or new fractures can be created. Similar effects can enhance hydrocarbon recovery in shale reservoirs. In this paper, we calculated the magnitude of water-injectioninduced stress with a coupled flow/geomechanics model. To evaluate the effect of water injection in the Bakken, a numerical-simulation study for a sector model was carried out. Stress changes caused by the volume created by the hydraulic fracture, water injection, and oil production were calculated. The Hoek-Brown failure criterion was used to compute rock-failure potential. Our numerical results for a waterflooding example show that during water injection, the synergistic effects of reservoir cooling and pore-pressure increase significantly promote rock failure, potentially reactivating healed natural macrofractures and/or creating new macrofractures, especially near an injector. The rock cooling can create small microfractures on the surface of the matrix blocks. In shale oil reservoirs, the numerical experiments indicate that stress changes during water injection can improve oil recovery by opening some of the old macrofractures and creating new small microfractures on the surface of the matrix blocks to promote shallow water invasion into the rock matrix. Furthermore, the new microfractures provide additional interface area between macrofractures and matrix to improve oil drainage when using surfactant and CO2 enhanced-oil-recovery techniques. These positive effects are particularly important farther away from the immediate vicinity of the hydraulic fracture, which is where much of the undrained oil resides.

A Fully-Coupled Geomechanics and Flow Model for Hydraulic Fracturing and Reservoir Engineering Applications

In this paper we present a practical fullycoupled geomechanics and flow model for application to hydraulic fracturing, especially in tight gas reservoirs, and other reservoir engineering applications. The mathematical formulation is consistent with conventional finitedifference reservoir simulation code to incl ude any number of phases, components and even thermal problems. In addition, the propagation of strain displacement front as a wave, and the relevant changes in stress with time, can be tracked through the wave component of the geomechanics equations. We show the development of an efficient finitedifferenc e computer code for rock deformation including thermal and wave propagation effects. The numerical approach chosen uses two different control volumes—one for fluid and heat flow and another one for rock deformation. The ultimate goal is to provide a tool to assess the effect of pore pressure, cooling or heating the reservoir, and propagation of a strain wave resulting from hydraulic fracturing on the reservoir rock frame. This information is crucial for determining the effect of shear stress on opening or closing of natural fractures during creation of hydraulic fractures, and changes in shearand compressionalwave velocities for seismic imaging purposes. A specific application of the product of this research is to simulate fracture propagation, gel cleanup and water block issues in hydraulic fracturing. The modeling results indicate significant change in shear stresses near hydraulic fractures as a result of hydraulic fracture face displacement perpendicular to the fracture face and not as much from pore pressure change because the filtrate does not travel very far into the reservoir. Similarly, temperature change effects are also very significant in changing stress distribution.

The Effect of Water Induced Stress to Enhance Hydrocarbon Recovery in Shale Reservoirs

Waterflooding has been an effective improved-oil-recovery (IOR) process for several decades. However, stress induced by waterflooding has not been well studied or documented. Water injection typically increases reservoir pressure and decreases reservoir temperature. The increase in reservoir pressure and decrease in reservoir temperature synergistically reduce the effective stress. Because of such decrease in stress, existing healed natural fractures can be reactivated and/or new fractures can be created. Similar effects can enhance hydrocarbon recovery in shale reservoirs. In this paper, we calculated the magnitude of water-injectioninduced stress with a coupled flow/geomechanics model. To evaluate the effect of water injection in the Bakken, a numerical-simulation study for a sector model was carried out. Stress changes caused by the volume created by the hydraulic fracture, water injection, and oil production were calculated. The Hoek-Brown failure criterion was used to compute rock-failure potential. Our numerical results for a waterflooding example show that during water injection, the synergistic effects of reservoir cooling and pore-pressure increase significantly promote rock failure, potentially reactivating healed natural macrofractures and/or creating new macrofractures, especially near an injector. The rock cooling can create small microfractures on the surface of the matrix blocks. In shale oil reservoirs, the numerical experiments indicate that stress changes during water injection can improve oil recovery by opening some of the old macrofractures and creating new small microfractures on the surface of the matrix blocks to promote shallow water invasion into the rock matrix. Furthermore, the new microfractures provide additional interface area between macrofractures and matrix to improve oil drainage when using surfactant and CO2 enhanced-oil-recovery techniques. These positive effects are particularly important farther away from the immediate vicinity of the hydraulic fracture, which is where much of the undrained oil resides.