Gas-bearing Shale Formations Research Articles

Mitigating water blockage in shale matrix by acidizing or oxidizing treatment: Evidence from transport pathway change and diffusivity enhancement

A relatively large number of pH-sensitive minerals (e.g., calcite, dolomite, siderite) and redox-sensitive compositions (e.g., organic matter, siderite, pyrite, and chlorite) are present in gas-bearing shale formations. During hydraulic fracturing, some of these compositions can be dissolved under acidic or oxic condition and may generate critical transport pathways to bypass water blockage within the fracture-matrix interface. This paper reports the effects of 5% HCl or 15% H2O2 reactive fluids on transport pathway and methane diffusion capacity of Longmaxi shale samples. Experiments show that these sensitive minerals are distributed evenly throughout the shale matrix as dispersed or isolated grains. Reactivity differences between sensitive compositions and non-sensitive minerals cause heterogeneous dissolution at micrometer scale and generate substantial new pore space in the reaction zones, giving an overall pore volume increase by 4.6–6.6 vol % calculated using μCT data. Apart from dissolution pores, many oxidation-related microfractures with a spacing less than 10 μm are also observed in H2O2-treated shale. Due to resolution limitations of SEM and μCT imaging, these new transport pathways appearing as separated void spaces are actually connected by much smaller pores at nanoscale, leading to a greater than 3.7-fold increase in macropore diffusivity. Despite more water imbibition into the H2O2-treated shales, the largest increase in diffusivity is also observed post oxidizing treatment. Our study clearly demonstrates that the newly formed transport pathways can reduce the diffusion pathway length and tortuosity of nanopore systems, thereby significantly improving wet shales’ diffusivity. These observed changes in transport pathway and diffusivity indicate that acidizing or oxidizing treatment may be a possible method for mitigating water blockage within fracture-matrix interface of hydraulically fractured Longmaxi shale gas formation.

A novel approach to identify accessible and inaccessible pores in gas shales using combined low-pressure sorption and SAXS/SANS analysis

Resolving the pore attributes of gas bearing shale formations is key to precise estimation of the gas-storing capacity of a reservoir. Decades of research and development on the characteristics of shale pores have proven that both organic matter and clay minerals are capable of storing hydrocarbons in their pores by virtue of adsorption; however, very few studies have been able to quantitatively characterize the individual adsorption capacity of clay minerals and organic matter. The volume of the gas that is produced depends on the accessibility to the pores. Due to the very low permeability of shale, there is a significant difference between the accessible pore volume and total pore volume. By general convention, we often term the accessible pore volume as the total pore volume, whereas the total pore volume is usually quite higher than the accessible pore volume.This study attempts to address these two research gaps using Permian age Barakar Formation shales that were collected from two separate sites in the eastern part of India, from a depth range of 221 to 701 m. The shales had a moderately high content of clay (ranging between 25% and 70%) and an abundance of Type III kerogen. The mesopore size distributions were calculated from N2 adsorption isotherms using a combination of N2 upon silicate and N2 upon carbon density functional theory (DFT) model. It shows a 66–100% increase in the cumulative mesopore volume when compared to the conventional N2 upon carbon model. Micropore size distribution was calculated from CO2 adsorption isotherms using CO2 upon the carbon grand canonical Monte Carlo model, which shows a better fitting than the conventional DFT model. Further, a comparison between small-angle X-ray scattering and low-pressure N2 adsorption indicates a 3% to 15% higher fractal dimension of total pores than accessible pores. The ‘degree of connectivity’ of the shale pores was calculated based on the accessible and total pore volumes, which was found to decreasesteadily with depth. Finally, a correlation between the binding potential of the inorganic-organic constituents, and the surface fractal dimension was established using Monte Carlo simulation. We confirmed that the fractal dimension depends on the binding potential of the inorganic-organic matter, and the difference in the fractal dimension of accessible and inaccessible pores could be explained by the smoothening of accessible pores due to pore fluid invasion. This new combined and comprehensive approach will lead to a better understanding of CH4 and CO2 dynamics in shale pores.

Features of conducting of geological exploration on shale gas in Volyno-Podillia at the regional stage of studying

Features of structural conditions of occurrence, gas accumulation, lithofacies, petrophysical and geochemical parameters, shielding factor, character-bearing shale gas saturation are fundamentally different from traditional gas deposits. Stratigraphic shale formation considered as a potential gas deposit. Considering this specificity its allocation and mapping must be executed at an early stage. To delineate gas bearing shale formations of Volyno-Podillia and allocation the most perspective areas offered a complexation of regional seismic survey 2D for great depths (two longitudal profiles of north-western stretch as it continued from the Lublin basin in Poland and 5 crosssections from southwest to the northeast with its total length of about 1500 linear kilometers) with electric prospecting methods of different modifications, caused polarization, electromagnetic methods of regional seismic exploration grids profiles, large-scale atmogeochemical shooting and other direct methods. As the completion of regional stage must be drilling of vertical parametric pilot wells with solid coring from perspective shale strata, laboratory studies of organic matter, of katagenesis, lithofacies and mineralogical composition of shales, their petrophysical and geochemical properties, modeling and testing perspective shale strata using multistage hydrogaps. Prospects of further exploration and it’s complex based on the results geologic-economic evaluation of perspective of petrogas of the region and obtaining results of works start-up phase.

Wormhole Formation During Acidizing of Calcite-Cemented Fractures in Gas-Bearing Shales

SummaryA relatively large number of calcite-cemented fractures are present in gas-bearing shale formations. During hydraulic fracturing, some of these fractures will be reactivated and may become important flow paths in the resulting stimulated fracture network. On the other hand, the presence of carbonate lamina on fracture surfaces will have a hindering effect on the transport of shale gas from the matrix toward the wellbore. We investigate numerically the effect of low-pH reactive fluids on such fractures, and show that dissolution of the cement proceeds in a highly nonuniform manner. The morphology of the emerging flow paths (“wormholes”) strongly depends on the thickness of the calcite layer. For thick carbonate layers, a hierarchical, fractal pattern appears, with highly branched wormhole-like channels competing for an available flow. For thin layers, the pattern is much more diffuse, with less-pronounced wormholes that merge easily with each other. Finally, for intermediate thicknesses, we observe a strong attraction between shorter and longer wormholes, which leads to the formation of islands of carbonate lamina surrounded by the dissolved regions. We argue that the wormhole-formation processes are not only important for the increase of shale-gas recovery, but also can be used for retaining the fracture permeability, even in the absence of proppant.

Experimental Investigation of the Geochemical Interactions between Supercritical CO2 and Shale: Implications for CO2 Storage in Gas-Bearing Shale Formations

Interactions between injected CO2 and shale formation during the process of CO2 sequestration with enhancing shale gas recovery (CS-EGR) may alter the physical and chemical properties of the rock, affecting the efficiency of CO2 storage as well as CH4 production. To better understand these interaction-induced changes in shale properties, two shale samples selected from a marine Longmaxi formation and terrestrial Chang-7 member of the Yanchang formation were first reacted with supercritical CO2 (scCO2) in a laboratory batch reactor at 80 °C and 15 MPa with different time intervals, and then characterization methods were designed to access the geochemical changes including optical microscope (OM), X-ray diffraction (XRD), element analysis (EA), low-pressure gas adsorption (LPGA), and Fourier transform infrared spectroscopy (FTIR). The results indicate that the nanopore structure system of the two shale samples was significantly changed after scCO2–shale interaction due to the scCO2-induced extraction of hyd...

Monitoring CO2 storage and enhanced gas recovery in unconventional shale reservoirs: Results from the Morgan County, Tennessee injection test

Permanently sequestering carbon dioxide (CO2) in gas-bearing shale formations is beneficial in that it can mitigate greenhouse gas emissions as well as enhance gas recovery in production wells. This is possible due to the sorption properties of the organic material within shales and their greater affinity for CO2 over methane (CH4). The phenomenon of preferentially adsorbing CO2 while desorbing CH4 has been proven in unconventional coalbed methane reservoirs successfully, and is feasible for shale formations. The objective of this paper is to explore the potential for enhanced gas recovery from gas-bearing shale formations through a successful small-scale ‘huff-and-puff’ injection of CO2 into a targeted shale formation. Approximately 510 short tons of CO2 were successfully injected into a horizontal production well completed in the Chattanooga Shale formation in Morgan County, Tennessee. After the injection phase, the well was shut-in to allow for the CO2 to equilibrate within the target formation. After the soaking phase was completed, the well was flowed back and returned to normal production. During this flowback phase, gas composition and flow rate were frequently monitored. Results indicated that there was a significant increase in gas flow rate during the first five months of the flowback phase. There was also a significant increase in gas quality, such that the percent composition of NGLs (natural gas liquids), including ethane, propane, and butane, increased. The results from this injection test confirm the injectivity and storage potential of CO2 in organic shales formations while enhancing gas recovery.

Predicting Water Resource Impacts of Unconventional Gas Using Simple Analytical Equations.

The rapid expansion in unconventional gas development over the past two decades has led to concerns over the potential impacts on groundwater resources. Although numerical models are invaluable for assessing likelihood of impacts at particular sites, simpler analytical models are also useful because they help develop hydrological understanding. Analytical approaches are also valuable for preliminary assessments and to determine where more complex models are warranted. In this article, we present simple analytical solutions that can be used to predict: (1) the spatial extent of drawdown from horizontal wells drilled into the gas-bearing formation, and rate of recovery after gas production ceases; (2) the potential for upward transport of contaminants from the gas-bearing formation to shallow aquifers during hydraulic fracturing operations when pressures in the gas-bearing formation are greatly increased; and (3) the potential downward leakage of water from shallow aquifers during depressurization of gas-bearing formations. In particular, we show that the recovery of pressure after production ceases from gas-bearing shale formations may take several hundred years, and we present critical hydraulic conductivity values for intervening aquitards, below which the impact on shallow aquifers will be negligible. The simplifying assumptions inherent in these solutions will limit their predictive accuracy for site-specific assessments, compared to numerical models that incorporate knowledge of spatial variations in formation properties and which may include processes not considered in the simpler solutions.

Techno-economic assessment of industrial CO2 storage in depleted shale gas reservoirs

The long-term storage of carbon dioxide (CO2) via injection into deep geologic formations represents a promising technological pathway to reducing greenhouse gas emissions to the atmosphere. Geologic storage in deep saline aquifers has been studied extensively, and the injection of CO2 for enhanced oil recovery (EOR) from conventional (porous and permeable) formations has been practiced for decades. This study is focused on developing a preliminary assessment of the economic feasibility of storing CO2 in depleted unconventional natural gas-bearing shale formations. Using a surrogate reservoir model (SRM) and a flexible environment for techno-economic analysis, this paper presents site-scale estimates of long-term CO2 sequestration costs in depleted shale gas formations and discussion of the likely major cost drivers. This analysis focuses on the transportation of CO2 from industrial point sources in the Pennsylvania Marcellus Shale region, and the transition of Marcellus wells from production to CO2 injection. This approach couples techno-economic analysis with reservoir simulation models to estimate costs associated with transportation, injection, CO2 separation and post-injection monitoring of CO2 storage permanence from large industrial point sources in depleted shale-gas reservoirs. We also consider potential revenue from incremental CH4 recovery (effectively enhanced gas recovery) in reservoir scenarios where such production is significant. The techno-economic model boundary includes pipeline transport from an industrial source (excludes the cost of capture of CO2 at that source), site preparation and CO2 flooding operations, and long-term monitoring and post-injection site care (PISC) at the storage site. Under an operational scenario where a Marcellus shale gas well is in primary production for 42years prior to the initiation of CO2 injection, it is estimated that CO2 could be transported and stored at a levelized cost of $40–$80 per metric tonne, in present value terms. These costs are shown to be highly sensitive to assumptions regarding well spacing, bottomhole pressure, CO2 transport distance and the future price of natural gas. In most of the scenarios considered, transportation and injection costs were dominant factors, while CO2 separation, pore space acquisition and post-injection site care/monitoring did not significantly influence levelized costs.

Effect of low-concentration HCl on the mineralogy, physical and mechanical properties, and recovery factors of some shales

Oil and gas-bearing shale formations have received a great deal of interest in recent years because they could make a significant contribution to global hydrocarbon production. However, their development has been hindered by the complexity of drilling and completion strategies, which must be adapted in response to shale’s mineralogy and physical properties. Matrix acidizing is commonly used as a pre-flush to the hydraulic fracturing stimulation of shale formations. The process dissolves sediments and mud solids that inhibit the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons; in some plays it is used as the main stimulation technique (e.g. Monterey shale, California). The mineralogical, mechanical, and physical responses to matrix acidizing of several important North American shale formations have been evaluated, and the effect on their recovery factors are described. Samples of Eagle Ford, Mancos, Barnett, and Marcellus shale formations were exposed to 1, 2 and 3wt% HCl. Mass loss, compositional analysis, and X-ray diffraction based mineral assemblage characterization and quantification, show samples lost as much as 16wt% by mass when treated with 3wt% HCl for 3h. The majority of the mass loss was attributed to carbonate dissolution. Analysis of post-acid treated samples show increases in porosity relative to the starting materials, but the increases in porosity are not necessarily correlated with acid strength. Images of post-acid samples demonstrate the development of cracks and fractures in Mancos, Barnett, and Marcellus samples. In contrast, the Eagle Ford samples show a homogenously distributed decrease in density, which based on mineralogical and compositional characterization, is attributed to spatially near uniform dissolution of calcite. Eagle Ford samples showed the largest increase in oil recovery factors ranging from 38% to 71% with a significant reduction in Young’s modulus ranging from 25% to 82% when exposed to HCl solutions at 93°C.

School and Community Impacts of Hydraulic Fracturing Within Pennsylvania's Marcellus Shale Region, and the Dilemmas of Educational Leadership in Gasfield Boomtowns

Innovations associated with gas and oil drilling technology, including new hydraulic fracturing and horizontal drilling techniques, have recently led to dramatic boomtown development in many rural areas that have endured extended periods of economic decline. The Marcellus Shale play, one of the world's largest gas-bearing shale formations, lies beneath approximately two-thirds of Pennsylvania, including some of the state's most economically lagging rural areas. Spurred by a state-level policy environment favorable to unconventional gas extraction, drilling activity in the last five years has rapidly increased, often with profound social, economic, and environmental implications for communities. In this paper we use schooling as a particular analytic lens for understanding the dynamics of natural resource boomtown development, community change, and how these changes may affect educational and instructional decision making. Using data from interviews and focus groups with educators and administrators in Pennsylvania communities experiencing intensive natural gas development, we discuss the multiple organizational, curricular, and educational dilemmas school leaders face in the context of both rapid, unpredictable community change, and an educational policy environment unfavorable to place-sensitive educational responses to local change.

Susquehanna River Basin Commission research related to natural gas development

The Susquehanna River Basin drains 27,510 mi2 (71,251 km2), covering parts of New York, Pennsylvania, and Maryland, and provides 50% of the freshwater inflow to the Chesapeake Bay. The Susquehanna River Basin Commission (SRBC) is a federal-interstate compact agency regulating surface and groundwater withdrawals, diversions, and consumptive uses of water, including those associated with natural gas development. Although specific black gas-bearing shale formations are already identified, including the Marcellus, Utica, Antes, Burket, Geneseo, Mandata, Middlesex, Needmore, and Rhinestreet, the SRBC regulatory activity is applicable to any and all gas-bearing formations (Figure 1). The SRBC does not regulate wastewater discharges or pollution incidents because these are already regulated by member jurisdictions of SRBC. Figure 1 Area in the Susquehanna River Basin containing natural gas shale formations, with locations of SRBC-approved water withdrawals for natural gas well development. As a water resource …

Shale-Gas Permeability and Diffusivity Inferred by Improved Formulation of Relevant Retention and Transport Mechanisms

A theoretically improved model incorporating the relevant mechanisms of gas retention and transport in gas-bearing shale formations is presented for determination of intrinsic gas permeability and diffusivity. This is accomplished by considering the various flow regimes according to a unified Hagen–Poiseuille-type equation, fully compressible treatment of gas and shale properties, and numerical solution of the non-linear pressure equation. The present model can accommodate a wide range of fundamental flow mechanisms, such as continuum, slip, transition, and free molecular flow, depending on the prevailing flow conditions characterized by the Knudsen number. The model indicates that rigorous determination of shale-gas permeability and diffusivity requires the characterization of various important parameters included in the present phenomenological modeling approach, many of which are not considered in previous studies. It is demonstrated that the improved model matches a set of experimental data better than a previous attempt. It is concluded that the improved model provides a more accurate means of analysis and interpretation of the pressure-pulse decay tests than the previous models which inherently consider a Darcian flow and neglect the variation of parameters with pressure.

Characterization of Hydraulically Induced Fracture Network in a Tight Gas Formation Using Treatment and Microseismic Data

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125237, "Characterization of Hydraulically Induced Fracture Network Using Treatment and Microseismic Data in a Tight Gas Formation: A Geomechanical Approach," by Wenyue Xu, Joël Le Calvez, and Marc Thiercelin, Schlumberger, prepared for the 2009 SPE Tight Gas Completions Conference, San Antonio, Texas, 15-17 June. The paper has not been peer reviewed. Large amounts of gas are produced from unconventional tight-gas-sand reservoirs (e.g., Cotton Valley, Lobo, Taylor Sand, and Wilcox formations) and gas-bearing shale formations (e.g., Barnett, Fayetteville, Marcellus, and Woodford). These plays are driven partly by technology and partly by economics. Modern well-log-evaluation techniques and completion methods are required to yield economical wells. In some cases, microseismic-monitoring campaigns are performed in these low-permeability environments to improve the understanding of the induced-fracture network and to go beyond the simple assumption of a symmetric biwing-fracture system. Introduction Use of traditional models, assuming single- or biwing-type induced fractures, has produced successful hydraulic fracturing in conventional reservoirs. However, these models cannot represent the complex nature of induced fractures in unconventional reservoirs with pre-existing fractures. The otherwise straightforward propagation of a simple wing-like hydraulic fracture tends to interact with nearby pre-existing natural fractures. There are indications of microseismic activity being related to stress effects and to actual fluid movement. In some cases, a volumetric hydraulic-fracturing process is indicated. Recent efforts have been made to map the pattern of induced-fracture networks on the basis of observed microseismic-event distribution. These interpretations were not constrained closely by accounting for the amount of pumped fluid and mechanical interactions between fracture and injected fluid as well as among nearby fractures. Fracture-Network Model To characterize the induced-fracture network better, a semianalytical pseudo-3D geomechanical model was developed on the basis of the conservation of injected-fluid mass and mechanical interactions between fractures and injected fluid as well as among the fractures. The hydraulically stimulated volume is represented by a horizontally expanding ellipse containing a simplified fracture network consisting of two sets of vertical planar fractures perpendicular to one another. This model provides a mathematically equivalent description of the process of hydraulic-fracture propagation and the characteristics of the induced fractures.