Richard F. Sigal

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.

A Fully-Coupled Free and Adsorptive Phase Transport Model for Shale Gas Reservoirs Including Non-Darcy Flow Effects

Accurate modeling of gas through shale-gas reservoirs characterized by nano-meter pores where the effects of various non-Darcy flow regimes and the adsorbed-layer are important is presented and demonstrated by several examples. Quantification of gas transport may be accomplished using the transport equation that is valid for all flow regimes. This equation though needs further modification when transport is through a media where the gas is adsorbed onto the pore wall. In the presence of adsorption, there is a pore pressure dependent loss of porosity and cross-sectional area to free gas transport. The apparent gas permeability correction is accomplished for various flow regimes using the Knudsen number by consideration of the reduction of the cross-sectional area to free gas transport in the presence of adsorption. We show that transport in the adsorbed layer may contribute significantly in the total gas transport in these nanopores. An effective transport model is presented to account for the impact of adsorption through two mechanisms. First, we modify the transport equation to account for the pore-pressure dependent-reduction in the volume available to free gas transport; second, we model transport through the adsorbed layer using Fick’s law of diffusion. The coupled model is then compared to conventional transport models over a wide range of reservoir properties and conditions.

Microscopic Dynamics of Water and Hydrocarbon in Shale-Kerogen Pores of Potentially Mixed-Wettability

Distribution of alkanes and water in organic pores of shale, referred to as kerogen, is essential information required for estimation of shale-reservoir oil- and gas-in-place, adsorption of hydrocarbon, and fate of frac-water. A practical modeling approach is presented for proper description of the kerogen pore systems with different mixed wettability, surface roughness, tortuous paths, and material disorder. Three kerogen models, namely activated kerogen, kerogen free of active sites, and grapheme-slit pore, with proper surface-oxidized functional groups and high-temperature-and-pressure maturation, are constructed by simulation. Distribution of octane and water in the organic pores of these models is predicted by molecular dynamics simulation. Comparison of results reveals the importance of accurate characterization of kerogen pore systems by particular pore morphology, surface activation, and pore size. The improved kerogen models provided here are shown to determine the placement, distribution, and trapping of frac-water in shale depending on the maturity of the kerogen within organic-rich shales. Copyright 2013, Society of Petroleum Engineers.

A methodology for blank and conformance corrections for high pressure mercury porosimetry

High pressure mercury porosimetry measurements suffer from two well-known systematic errors—blank errors and conformance errors. Blank errors result in an apparent mercury intrusion due to differential compaction of the mercury, sample and measurement apparatus. Conformance errors result from the mercury not completely filling the measurement container at the start of the measurement. A methodology for blank corrections that uses two calibration tables, one built from the experimentally determined apparent intrusion when a measurement is made with no sample present and one built from the apparent intrusion for a single non-porous sample, has been developed. These tables allow the blank effect to be calculated for a non-porous sample of the same material of any size. In principle, the blank material can be numerically constructed to match the mineralogy of the sample. The methodology is illustrated by using quartz blanks to correct measurement curves of two small low permeability samples. The conformance correction problem does not seem to be amenable to a generally applicable objective methodology. If the sample volume is accurately known, it can be used to perform a correction.

A pore scale study describing the dynamics of slickwater distribution in shale gas formations following hydraulic fracturing

Hydraulic fracturing with slickwater to stimulate shale gas wells is routinely employed to enable increased contact with larger reservoir volumes and has the advantages of lower cost, the ability to create larger and more complex fractures, less formation damage and easier cleanup. However, a common observation is that during flow back only 10 to 20% of the frac water is recovered, even though a typical stimulation job requires several million gallons of water. Although there have been some attempts to address this phenomenon, the associated theories are lacking in scientific rigor. Due to the nanoporous nature of shales where pore proximity effects and strong inter-molecular interactions may dominate, a fundamental pore-level analysis is employed in this work to better understand and leverage the dynamics of the physiochemical processes during and after fracturing. By varying pore size in organic and inorganic pores in shales, we study the dynamics of water and gas molecules, as well as that of ions. The results of our study demonstrate that the mechanics of water entrapment and the water and ions distribution are strongly linked to the pore-surface mineralogy. Understanding the placement and distribution of frac water in both organic and inorganic pores in shales will potentially help in improved forecasting of well performance and address concerns related to the contamination of groundwater resources. Copyright 2013, Society of Petroleum Engineers.

Theoretical fundamentals, critical issues, and adequate formulation of effective shale gas and condensate reservoir simulation

The issues of relevance to describing the storage and movement of hydrocarbon gas and condensate, and water through extremely low permeability shale formations are reviewed. The shale rock is viewed as a heterogeneous quad-media continuum system. Each system has different wettability, storage, transport, and connectivity characteristics. The hydrocarbon storage is considered as being in the free gas, adsorbed gas, and dissolved gas. The alteration of fluid properties and flow behavior under pore confinement are emphasized. For gas transport the effective mean-radii and apparent permeability as a function of pore-size distribution and gas adsorption are examined. The nonequilibrium fluid distribution effect produced by tortuous narrow flow paths is discussed. It is emphasized that these form the essential phenomena that must be taken into account for effective simulation of shale gas and condensate reservoirs.

A Pore Scale Study of Slickwater Systems in Shale Reservoirs: Implications for Frac-Water Distribution and Produced Water Salinity

Pore-level molecular dynamics simulation studies are conducted towards an understanding of poor recovery of fracwater, progressive increase in produced water salinity, and identification of potential trapping mechanisms for fracwater and its influence on long-term well productivity in shale gas and oil reservoirs. The kerogen pores of shales are respesented by two organic pore models. The first model containing only carbon is intended to mimic the nature of highly mature kerogen. The second model helps understanding of the fluid behavior in partially mature shales containining oxygenated functional groups with non-zero oxygen to carbon ratio. The maturation processes of these kerogen models are described by means of a molecular dynamics simulation. These models are shown to describe effectively the essential structural features obseved in SEM images which indicate surface roughness, tortuous paths, material disorders, and imperfect pore openings of kerogen pores, and are therefore superior to the frequently assumed graphene slit pore systems. The effect of maturation, pore surface mineralogy, and pore roughness on the wettability characteristics of organic kerogen pores is delineated. Distribution of saline water in organic and inorganic pores is described as a function of pore size and morphology. These pore-scale studies reveal important insights about the distribution of dissolved ions and water in organic pores, and the frac-water distribution and produced water salinity following hydraulic fracturing. Introduction Shale gas and oil development activities have continually undergone several stages of refinement and continues to be driven by our ability to create extensive multi-stage hydraulic fracture treatments along several thousands of feet of horizontal laterals. Although these efforts have largely progressed successfully, unfortunately, our current understanding of the complex interplay of hydrocarbons and water in organic and inorganic shale nanopores is rather limited. Among the key questions remaining unanswered are related to the explanation of the poor recovery of frac-water, the progressive increase in produced water salinity, and the potential trapping mechanisms for frac-water and its influence on long-term well productivity. Shale formations are characterized by extremely low permeabilities in the orders of nanodarcies. Therefore, hydraulic fracturing treatments in combination with horizontal well completions are necessary to contact large volumes of the reservoir and to enhance well productivity. There are several field observations linked to the recovery of frac-fluids such as slickwater and the salinity of produced water. Generally, the recovery of slickwater is very low, even though several million gallons of fluid is initially injected to hydraulically fracture the well. This recovery may range from as little as 5% in the Haynesville shale to as much as 50% in the Barnett and Marcellus shales (King 2012). Additionally, we generally observe an increasing salinity of produced water over time. Even though the original injected slickwater is fresh, the salt concentration can be as high as 80,000 to 100,000 ppm at later times (King 2010). A better understanding of these issues may enable us to design better fracture treatments, to URTeC 2013 Page 1284

Modeling and Simulation of Production from Commingled Shale Gas Reservoirs

The modeling and simulation of commingled production from multilayered shale-gas reservoirs is presented and the changing pressures and flow rates in various zones are simulated. An effective iterative numerical simulation is developed for the coupled wellbore and reservoir hydraulics calculations for multi-layered shale gas reservoirs. The performance of each layer communucating with the wellbore, in the absence or presence of formation cross flow, is evaluated and demonstrated by case studies. Changes in the permeability of shale with prevailing conditions is accounted for by considering the apparent gas permeability in shale depending on the pore proximity effects. This rigorous simulation method presented here enables an accurate evaluation of the pressure and production at each layer including the cross flow effects. Introduction Commingled production from wells completed in multi-layered reservoirs commonly exist in many fields, including the shale-gas reservoirs. Such reservoirs performance is usually monitored by means of the logging tools to obtain the downhole pressure and production measurements of different layers. Frequently, the temperature and noise logs are used to detect the wellbore crossflow, but no effective tool is available for measurement of the formation crossflow. Direct measurements usually require expensive and time-consuming approaches and interruption of production wells. Prediction of the flow rate and pressure profiles at separate zones and the contribution of each zone to overall well production is required for management of production from commingled reservoirs. The problem is more complicated when formation cross flow occurs between varios zones and because of permeability effects created in layers separating the pay zones by induced fractures resulting from stress deformation and other means. Stratified shale layers may also have different fluid and formation properties depending of their own sedimentary deposition processes and may involve different types of external boundary conditions, including full or partial water influx. Therefore, various stratified layers can have different contributions on well production performance, and well optimization and management. A rigorous phenomenological modeling is therefore required to rigorously quantify the contribution of each layer to the overall production and analyze the effect of cross flow for commingled shale gas reservoirs. Juell et al. (2011) used a backpressure equation to estimate the gas properties of multi-layer reservoir including wellbore crossflow. They assumed the well was produced at a constant bottom-hole flowing pressure. They compared the reservoir backpressure calculation and the results from the numerical simulator, and concluded that the backpressure equation can be used to predict the performance of layered reservoirs when coupled with material balance equation in the case of no-crossflow gas reservoirs. Also, solution of reservoir backpressure equation against reservoir material balance equation solution has been verified. Kuppe et al. (2000) developed a spreadsheet program to evaluate OGIP, layer productivity, and recoverable reserves for tight gas commingled reservoirs without crossflow using the p/z-plot method for two layer-reservoirs. They classified multi-layered reservoirs into two categories by grouping the high permeability layers into one composite layer and the low permeability layers into another composite layer. The p/z material balance method was used to determine the model layer properties. This method was successfully used for reservoirs with permeability in the range of 0.1 to 10 md to match and forecast the productivity index for various layers. Their study indicated that the material balance (p/z) technique is restricted and can be successfully used only under limited conditions, such as

History Matching and Production Data Analysis for Shale Gas and Oil Reservoirs: The Relevance of Incorporating

Recent research efforts have increasingly recognized the need for incorporating the correct physics to describe gas and liquids transport and phase behavior in nanoporous organic-rich shale reservoirs. However, current modeling schemes are restricted in their ability to model effects such as the influence of pore proximity on non-Darcy flow, fluid phase behavior, capillarity, heterogeneous wettability and multicomponent adsorption. Consequently, reservoir history matching, which is expected to provide insight in to the spatial distribution of rock and fracture properties, becomes less meaningful when these history-matched models are employed for reservoir performance predictions. In this work, we explore the range of over-corrections in fracture and shale matrix properties when the physics appropriate to shales is neglected. Comparisons are made for several case studies between the history matched models obtained with conventional numerical schemes and the correctly modified simulation models for shales. This investigative study reveals that the predictive capability of existing commercial simulation packages are severely compromised, thereby leading to inaccurate quantification of reserves, less success in the placement of productive wells and poor evaluations of project economics. The study described here underscores the need for the correct physics in order to quantify natural fracture densities and for improved estimation of the spatial distribution of reservoir properties and reservoir characterization in general. Introduction Production from low permeability shale gas reservoirs has become an important source of natural gas in US. During the period between 2007 and 2011, data show gross production from shale reaching 30 percent of total gross production in 2011 after comprising only 8 percent of gross production in 2007 (EIA, 2013). Transport in shales has been shown to be highly influenced by the presence of low permeability nano-pores, micro-cracks, larger fracture networks created during stimulation operation, adsorption of gas in the oil or gas wet organic matrix, non-darcy flow effects and the alteration of fluid properties due to the effect of confinement. Consequently, the development of realistic shale gas/liquid rich shale reservoir simulation models is currently a topic of active research worldwide. A realistic reservoir simulation model for shales is required to conceptualize field development strategies, evaluate reservoir performance, plan depletion strategies and evaluate facility requirements. Recent research efforts have increasingly recognized the need for incorporating the correct physics to describe gas and liquids transport and phase behavior in nanoporous organic-rich shale reservoirs. However, current modeling schemes are restricted in their ability to model effects such as the influence of pore proximity on non-darcy flow, fluid phase behavior, capillarity, heterogeneous wettability and multi-component adsorption. Gas shales primarily consist of four types of porous media; organic matter, inorganic matter, in-situ natural fracture networks and the hydraulic/induced fractures created during the stimulation operation. The organic matrix is mainly composed of kerogen and the inorganic matrix contains clay, quartz and calcite particles. The organic content in the shales is quantified in terms of the total organic carbon (TOC). TOC is measure of amount (in weight) of organic carbon present in the shale sample. TOC is generally reported in % by weight. Passey et al. (2010) showed that the grain density of organics is generally 50% to that of the rock minerals. Gas storage in organic matter is significant in

Production Forecasting for Shale Gas Reservoir Wells using a Simulator that Honors the Microstructure of Shale Gas Reservoirs and the Physics of Fluids In Nano-Porous Media

Conventional reservoir simulators are proven inadequate for shale reservoir simulation because they incorrectly estimate drainage areas, recovery, and economic life of wells. This problem can be alleviated by rigorous modeling and simulation of shale gas reservoir production by considering the effect of heterogeneity, pore-wall slippage, gas rarefaction and desorption on production rate and drainage area of hydraulically-fractured horizontal wells. The present approach is shown to predict longer productive life of shale reservoir wells conforming to field observations. Introduction Ultra-low permeability shale gas wells are hydraulically fractured to enhance the productivity of wells by improving reservoir contact and providing high-conductivity pathways for movement of the gas. The horizontal well completions usually implement several stages of hydraulic fractures intersecting with wellbore at different locations along the lateral. Organic-rich shale gas reservoirs are characterized by a quad-porosity structure that consists of pores in organic material, inorganic material, and natural and stimulation fractures. Each has distinct petrophysical properties, and because of their nanometer pore scale, many of the standard equations and assumptions of the conventional simulators are incorrect. Effects of gas rarefaction, slippage, and desorption on transport through tight porous media, such as organic rich shale, and the heterogeneity of the organic distribution in shale formations are particularly important. The diameter of extremely narrow pores and flow paths encountered in tight shale formations is comparable to the size of gas molecules. Thus, gas transport occurring in tight formations does not necessarily follow Darcy’s law for all flowing conditions (Civan 2010, Andrade et al. 2010, Andrade et al. 2011, Michel et al. 2011a, Michel et al. 2011b, Sigal, 2013). Under these conditions, the slippage of gas molecules occurring at the pore walls is not negligible. Frequently, a semi-empirical model is resorted to correct the intrinsic permeability for accurate representation of slip, transitional, and free-molecular flows (Beskok and Karniadakis, 1999). Additionally, at these nanometer-size pores, the sorption phenomenon occurring in activated pore walls can significantly alter both porosity and permeability (Xiong et al., 2012, Sigal, 2013, Sigal et al., 2013). This paper simulates the shale gas reservoir production by proper modeling of the physics of fluids in nanometer scale porous media and the microstructure inferred by SEM studies. This is accomplished by incorporating the relevant features and modifications into a commercial simulator. Comparisons of well performance predicted by the simulation runs are presented for several reservoir conditions. Comparisons of results indicate simulations that fully honor the nature of the shale gas reservoir provide production histories, drainage details, and ultimate economic production that can be considerably different from those obtained on comparable models with currently available approaches. These differences result in part from not properly describing the complex pore geometry and fracture system, using storage models that do not properly account for adsorption, and transport models that do not properly account for adsorption and such effects as slippage and rarefaction. Comparison demonstrates the importance of considering the various effects encountered in nanometer-scaled porous materials for predicting the ultimate gas recovery and, ultimately, economics of production for shale-gas wells. The present robust approach incorporates the