Gas-bearing Shale Research Articles

Estimation of shear wave velocity from wireline logs in gas-bearing shale

Abstract Gas-bearing shale is one of the most important unconventional reservoirs. Shear wave velocities are essential for prestack AVO analysis, fracture identification, and fluid typing. Moreover, the recent studies of shear wave prediction mostly focused on conventional sandstones, wet shale, sandstone or carbonate rock may not be suitable for gas-bearing shale. Firstly, according to core analysis results of gas-bearing shale, petrophysics model is proposed. Then, shear wave prediction method based on Gasmann's theory, spatial averaging model, and elastic moduli of dry rock were studied in detail. Especially, point to organic shale with low porosity, Krief, Nur, and Pride models are selected to calculate the elastic moduli of dry rock, respectively, and the best critical porosity in Nur model and consolidation coefficient in Pride model are determined, which is virtual to gas-bearing shale. Pride model is finally optimized as the most suitable model through comparison of error analysis. Meanwhile, to implement the estimation of shear wave from well logs, a corresponding log interpretation method for gas-bearing shale is also studied. In case study, calculated volumetric concentrations of minerals are in good agreement with X-ray diffraction (XRD) analysis of cores. The final shear wave velocity also matches well with dipole sonic imaging (DSI) log. Therefore, the whole approach is verified correct and suitable for estimation of shear velocity or slowness in gas-bearing shale.

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.

Diagenesis and kerogen release in oil- and gas-bearing shales

The microstructure of pore space in sedimentary rocks and its evolution during reaction with pore- or fracture-contained fluids is a critically important factor controlling fluid flow properties in geological formations, including the migration and retention of water, gases and hydrocarbons. The size, distribution and connectivity of these confined geometries (pores, fractures, grain boundaries), collectively dictate how fluids of various chemistries migrate into and through these micro- and nano-environments, wet, and ultimately react with the solid surfaces. In order to interpret the time-temperature-pressure-fluid flow history of any geological system, the physical and chemical "fingerprints" of this evolution preserved in the rock must be fully explored over widely different length scales from the nanoscale to the macroscale. We are experimentally investigating these reaction-controlled changes in rock microstructure by conducting in-situ heating experiments on samples of the Garfield oil shale. Oil shale, an organic-rich fine-grained sedimentary rock, contains significant amounts of kerogen (a solid mixture of organic chemical compounds) from which liquid hydrocarbons can be extracted. Pyrolysis (heating shale in the absence of oxygen) converts the kerogen in the oil shale to shale oil (synthetic crude oil) and oil shale gas and a solid residue. Through SANS, we clearly observe these kerogen and oxidation release at lower temperatures followed by pore structure reordering and finally enlargement at higher temperatures. These results are compared with preliminary results tracking the natural diagenesis of the commercially-important Eagle Ford shale formations across the oil/gas boundary.

셰일가스 자원을 중심으로 한 중국의 에너지·광물자원 조사·탐사·개발 기술 정책분석

The Chinese government and its agencies were trying in order to solve the unstability of resource supply and demand. Ministry of Land and Resources of China(MLR) carried out a lot of national-level policy and planning for estimating the domestic mineral and energy resources potential and recoverable reserves, as the Chinese land and resources survey plan(1999~2010), the Chinese mineral resource survey and exploration plan(2008~2020), announcement for shale gas industry policies of China, the Chinese shale gas resources evaluation and selection project for its development priority areas(2012), and the plan for Chinese shale gas development(2011~2015). The two large sedimentary basins of Chinese shale gas reserves are Sichuan and Tarim basins with excellent potential, accounting for majority of the estimated national reserves. Recoverable gas-bearing shale of China was surveyed to be widespread. The volume of recoverable shale gas reservoirs in China has been estimated to be around 31 trillion cubic meters(1,115 trillion cubic feet). China is one of only three countries with the US and Canada to produce shale gas in commercial quantities. China is concentrating on technology development to enhance commercial production of shale gas, and on survey and exploration activities to increase its recoverable reserves. The trends related to shale gas development and R&D activities in China to respond to changes in international oil market should be actively monitored based on analysis of Chinese policies and technology.

Lattice Boltzmann simulation of shale gas transport in organic nano-pores.

Permeability is a key parameter for investigating the flow ability of sedimentary rocks. The conventional model for calculating permeability is derived from Darcy's law, which is valid only for continuum flow in porous rocks. We discussed the feasibility of simulating methane transport characteristics in the organic nano-pores of shale through the Lattice Boltzmann method (LBM). As a first attempt, the effects of high Knudsen number and the associated slip flow are considered, whereas the effect of adsorption in the capillary tube is left for future work. Simulation results show that at small Knudsen number, LBM results agree well with Poiseuille's law, and flow rate (flow capacity) is proportional to the square of the pore scale. At higher Knudsen numbers, the relaxation time needs to be corrected. In addition, velocity increases as the slip effect causes non negligible velocities on the pore wall, thereby enhancing the flow rate inside the pore, i.e., the permeability. Therefore, the LBM simulation of gas flow characteristics in organic nano-pores provides an effective way of evaluating the permeability of gas-bearing shale.

Modelling the Deployment of CO2 Storage in U.S. Gas-bearing Shales

Abstract The proliferation of commercial development in U.S. gas-bearing shales helped to drive a twelve-fold increase in domestic gas production between 2000 and 2010, and the nation's gas production rates continue to grow. While shales have long been regarded as a desirable caprock for CCS operations because of their low permeability and porosity, there is increasing interest in the feasibility of injecting CO2 into shales to enhance methane recovery and augment CO2 storage. Laboratory work published in recent years observes that shales with adsorbed methane appear to exhibit a stronger affinity for CO2 adsorption, offering the potential to drive additional CH4 recovery beyond primary production and perhaps the potential to store a larger volume of CO2 than the volume of methane displaced. Recent research by the authors on the revenues associated with CO2-enhanced gas recovery (CO2-EGR) in gas-bearing shales estimates that, based on a range of EGR response rates, the average revenue per ton of CO2 for projects managed over both EGR and subsequent storage-only phases could range from $0.50 to $18/tCO2. While perhaps not as profitable as EOR, for regions where lower-cost storage options may be limited, shales could represent another “early opportunity” storage option if proven feasible for reliable EGR and CO2 storage. Significant storage potential exists in gas shales, with theoretical CO2 storage resources estimated at approximately 30-50 GtCO2. However, an analysis of the comprehensive cost competitiveness of these various options is necessary to understand the degree to which they might meaningfully impact U.S. CCS deployment or costs. This preliminary analysis shows that the degree to which EGR-based CO2 storage could play a role in commercial-scale deployment is heavily dependent upon the offsetting revenues associated with incremental recovery; modeling the low revenue case resulted in only five shale-based projects, while under the high revenue case, shales accounted for as much as 20 percent of total U.S. storage in the first 20 years of deployment. Interestingly, even in this highest revenue case, there appear to be no negative-cost projects that would be profitable in a no-policy environment as modeled under the assumptions employed. While this reflects a very first look at the potential for shales, it is clear that more laboratory and experimental work are needed to reduce uncertainty in key variables and begin to differentiate and identify high-potential shales for early pilot study.

A NOVEL WIRELINE LOGS BASED APPROACH FOR ASSESSMENT OF MINERAL CONCENTRATIONS IN ORGANIC SHALE

It is usually difficult to establish a petrophysical model or empirical formula for the assessment of mineral concentrations in oil- or gas-bearing shale. The radial basis function (RBF) network can be used to construct the mapping between well logs and mineral concentration. In this work, the basic principle of RBF is discussed in detail, including network structure, basis function, and network training method. The nearest neighbor algorithm is selected for the network training. Then, one case study for the mineralogy analysis is applied to show how to construct an optimum RBF network. The Gaussian spread in RBF is investigated to improve the mineral composition prediction accuracy through leave-one-out cross validation and optimum wireline logs as inputs are chosen. Finally, the concentrations of minerals such as quartz, feldspars, calcite and pyrite as well as clay minerals are calculated, and they are all in good agreement with X-ray Diffraction (XRD) measurement results. Furthermore, the errors analysis indicates that the RBF method is effective and applicable for the assessment of mineral concentra- tions in organic shale.

Methods and key parameters for shale gas resource evaluation

Methods and key parameters of shale gas resources evaluation are studied so as to accurately assess the potential of shale gas resources. In much-explored areas, the volume method, followed by the analogy method, is recommended for evaluation; in less-explored areas, the analogy method is recommended. The concept of “gas-bearing shale system” is put forward and taken as an evaluation unit to calculate the thickness of shale. It refers to the lithologic assemblage sealed by upper and lower tight layers in one pressure system, composed of organic carbon-rich shale and the interbeds of sandstones and carbonates, featuring the logging responses of gas-bearing shale, with tight rocks at top and bottom, and the continuous thickness of gas-bearing interval being more than 30 m and no obvious water layer. According to exploration degree and available data, different methods may be selected to calculate the thickness of gas-bearing shale system. The logging data and the content of organic carbon are used in the areas with high degree of exploration and abundant data, while field geological profile, seismic profile, depositional characteristics and other data are considered in areas with low or ultra-low degree of exploration.

Rigorous Evidence Slim for Determining Health Risks From Natural Gas Fracking

HYDRAULIC FRACTURING, COMmonly called fracking, allows access to previously inaccessible natural gas reserves. Fracking in the United States is being touted as a panacea, creating much-needed jobs following a brutal recession, reducing dependence on foreign energy supplies, and lowering emissions of greenhouse gases that might contribute to global warming. As this natural gas production ramps up, however, there are few scientific findings on the effects of fracking on the environment and animal and human health. Moreover, anecdotal evidence suggests it may cause harm by contaminating well and ground water and releasing gases into the air. Some public health and community leaders are calling for a moratorium on fracking while scientists determine the risks, industry devises methods to minimize them, and regulatory agencies develop guidelines to ensure that risks remain minimized. Countering this cautious approach is the gas production industry, which argues that fracking has been conducted for more than 60 years on more than a million wells without any major environmental or health disasters; governments, which foresee additional revenue by taxing this gas production; workers looking for jobs; and consumers and businesses seeking cheap energy. A report by the American Petroleum Institute offers a glimpse into the financial stakes surrounding fracking (http: //tinyurl.com/8xoz3ky). The report suggests that over the next decade, development of the Marcellus shale formation, which is found underground in Pennsylvania, New York, Ohio, West Virginia, Maryland, and Virginia, could generate almost 300 000 new jobs, more than $6 billion in tax revenue, and nearly $25 billion in value added to the economy by 2020. And additional natural gasbearing shale is found throughout the country, especially in Texas, North Dakota, and Wyoming. Fracking involves drilling a hole, usually thousands of feet into the ground, to reach shale formations where natural gas is trapped. Water, sand, and a proprietary mix of chemicals are then injected into the shale, fracturing the rock and releasing the natural gas, which is captured when it flows up and out of the hole. While fracking has been around a while, recent developments in the technology now allow creating a bore hole and then drilling into the shale horizontally, releasing a greater amount of natural gas from each well. But that greater release comes at a cost. Instead of using thousands of gallons of water mixed with sand and chemicals to release the gas, the new wells use millions of gallons. It is those millions of gallons of then-polluted water and the greater amounts of natural gas and potential air pollutants that cause some to worry about health ramifications. For example, a Pennsylvania study looked at 41 products used in fracturing operations and found that 73% had between 6 and 14 different adverse health effects. These included skin, eye, and sensory organ damage; respiratory distress such as asthma; gastrointestinal tract and liver disease; brain and nervous system harms; cancers; and negative reproductive effects (Finkel ML and Law A. Am J Public Health. 2011; 101[5]:784-785). Bernard D. Goldstein, MD, professor emeritus of environmental and occupational health at the University of Pittsburgh’s Graduate School of Public Health, who is studying the health implications of fracking in the Marcellus shale, would like the industry and governments to slow their embrace of this novel method of natural gas extraction until there is a better understanding of potential environmental and health harms. “We’ve

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 …

Evaluation of variable gas saturation on acoustic log data from the Haynesville Shale gas play, NW Louisiana, USA

Many technical challenges must be overcome to ensure the economic development of a shale gas resource including: (1) making an accurate assessment of gas distribution and saturation, (2) identifying target zones that optimize the impact of hydraulic fracture stimulation and completion, and (3) drilling safe and cost-effective wells. In order to meet these challenges, it is necessary to characterize the physical and mechanical properties of the shales. Sonic logs provide important data about the rock and fluid properties that can be used for this characterization. One motivation for this work was to determine how sonic logs in gas-bearing shales can be used to characterize rock properties, derive mechanical properties, and estimate in-situ stresses.

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.

Comment – On maintaining high fluid pressures in older sedimentary basins: a new hypothesis or déjà vu?

Comment – On maintaining high fluid pressures in older sedimentary basins: a new hypothesis or déjà vu?

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.

Comparison of seismic upscaling methods: From sonic to seismic

The term “upscaling” used here means a prediction of elastic-wave velocities at lower frequencies from the velocities at higher frequencies. Three different methods of upscaling are considered, including the simple averaging, Backus averaging, and pair correlation function methods. These methods are applied to upscale the elastic-wave velocities measured at sonic frequencies ([Formula: see text], logging data) available for a well penetrating layers of gas-bearing shales and carbonates. As a result, a velocity distribution over depth for [Formula: see text] and [Formula: see text] is found in the frequency range of [Formula: see text]. The difference in the results obtained for a particular depth by the three theoretical methods in the surface seismic frequency bandwidth [Formula: see text] is [Formula: see text] for P-wave and [Formula: see text] for S-wave velocity. This difference is attributed to different theoretical backgrounds underlying these methods.

Abstract: Incorporating Reservoir Characterization into Optimized Production of Siliceous and Other Gas Bearing Shales 

Abstract: Incorporating Reservoir Characterization into Optimized Production of Siliceous and Other Gas Bearing Shales 

Pressure Analysis of an Unstimulated Horizontal Well With Type Curves

Summary Horizontal wells are effective alternatives to fractured vertical wells in several reservoir types, including low-permeability sandstones and shales. An understanding of fluid flow relationships is a prerequisite for efficient use of horizontal technology. The pressure-buildup data analyzed here were recorded in a horizontal completion in a low-permeability gas-bearing shale. The well was drilled and tested to verify laboratory and computer modeling research. After the general solutions were developed, the data were analyzed to describe reservoir properties and the effectiveness of the completion. Results of the type-curve analysis indicate that the contributing well length was shorter than the actual drilled length and that the contributing reservoir thickness was less than the typical net pay. Numerical modeling was used to verify the calculated parameters. Results fully support the well length and reservoir thickness determined through type-curve analysis, indicating that an unstimulated horizontal well completed in a heterogeneous formation may be insufficient to link the full vertical extent of the reservoir to the wellbore. Introduction The use of horizontal wells to exploit oil and gas reservoirs has continued to increase in recent years. One operator planned 30 horizontal wells as part of its 1989 drilling program. The target formation for much of this drilling program is the Bakken shale, which underlies several western counties in North Dakota's Williston basin. The Austin chalk play of south-central Texas is also host to a horizontal well drilling boom. Other areas where horizontal wells have been used to exploit petroleum-bearing rocks include Canada and Alaska's North slope. Most horizontal drilling has targeted oil-bearing formations, although interest in using horizontal wellbores to improve the economics of natural gas plays is increasing. The gas-bearing Devonian shale underlying southwestern West Virginia has been the target for several horizontal well operations. The U.S. DOE sponsored drilling, completion, and testing of the first horizontal well, the Recovery Efficiency Test No.1 (RET No.1), as part of the Unconventional Gas Research Program. This paper reports the analysis of the prestimulation pressure-buildup test for RET No.1 using general solutions (type curves). Families of general solutions for rate-constrained horizontal well flow were generated for field data analysis. The type curves include wellbore-storage effects, which mask the true reservoir response at early times. These effects can extend for considerable lengths of time, especially in very long horizontal wells and in those shut in at the wellhead. Joshi reported pressure responses of horizontal wells flowing at a constant rate. Mutalik et al. developed skin factors for rate-constrained problems involving horizontal wells. A finite-difference, 3D gas simulator was used to generate the pressure responses for this study. In the end, the field data were matched with a general pressure response to characterize the reservoir and the well.

Pain of terminal cancer patients in Xinjiang, China: A further study of social and ethical influence on pain

This study investigated the effects of the composition of gas-bearing shale on pore structures and various properties of Paleozoic–Permian transitional (marine–continental) mudstones and shales from the Xu-Huai district, southern North China, in the direction of progradation. The total organic content (TOC) in the Shanxi formation (SXF), Upper Shihezi formation (USF) and Lower Shihezi formation (LSF) shale samples varied widely, as determined via Rock-Eval pyrolysis. The USF shale TOC values (0.1–3.5%) are markedly lower than those of the SXF (0.3–6.3%) and LSF (0.1–8.6%). The SXF shales exhibit smaller BET (Brunauer–Emmett–Teller) specific surface areas (SSAs; 5.45–16.27 m2/g) compared to those of the LSF (6.36–27.97 m2/g) and USF shales (5.45–28.47 m2/g). The clay and quartz contents exhibit a significant negative correlation. The pore volume and N2-BET SSA increase with increasing clay content in the USF and LSF shales. The average pore size ranges from 2 to 20 nm, generally decreasing with decreasing quartz content. The composition, pore structure, and methane adsorption capacity were investigated by averaging the properties from each sample site to determine whether the variations are influenced by transitions along the direction of progradation. The results reveal that the clay content, TOC, SSA and pore volume increased in the progradation direction, whereas the quartz and average pore size decreased. The correlation between mineral composition and pore properties indicates that quartz has a greater effect on mesopores and macropores than on micropores; in contrast, clay generally controls micropores. The methane sorption capacity is correlated with TOC, exhibiting a prominent linear relationship. The increasing sorption volume in the progradation direction may be attributed to increases in SSA and pore volume related to the mineral composition.