Shale Gas Basins Research Articles

Semi-Analytical Reservoir Modeling of Non-Linear Gas Diffusion with Gas Desorption Applied to the Horn River Basin Shale Gas Play, British Columbia (Canada)

Adsorbed gas may account for a significant part of the gas resources in shale gas and coalbed methane plays. Understanding gas sorption behaviors and integrating gas desorption into analytical reservoir modeling and an associated transient performance analysis are important for evaluating a system’s gas desorption ability and further analyzing its CO2 injectability, utilization, and storage capacity. However, gas desorption, along with other pressure-dominated gas properties, increases a system’s non-linearity in theoretical studies. Few studies on analytical modeling have integrated the gas desorption feature into a non-linear system and validated the model’s accuracy. In this study, the desorbed gas due to pressure decay was treated as an additional source/sink term in the source-and-sink function methods. This method was combined with the integral image method in a semi-analytical manner to determine the amount of gas desorption. Fundamental reservoir and gas properties from the Horn River Basin shale gas play were chosen to evaluate the methodology and the performance of the associated production well. The results were compared with the commercial fine-gridding numerical simulation software, and good matches were achieved. The results showed that the desorbed gas released from rock will supply free-gas flow when the pressure significantly decreases due to gas production. The production wellbore pressure can be maintained at a higher level, and the production rate was higher than in cases where gas desorption was not considered, depending on the operating conditions.

Enhancing pressure gradient prediction in multi-phase flow through diverse well geometries of North American shale gas fields using deep learning

To ensure the efficient operation of production wells and to avoid flow assurance issues, accurately predicting pressure gradients, Δp/ΔL, in wells is crucial. This study explores the relationship between Δp/ΔL and production well geometries. The data from 29,047 wells across five shale gas basins is utilized: Bakken, Barnett, British Columbia, Marcellus, and Delaware. These basins have distinct shale gas reservoir properties and diverse well geometries. Each well's geometry was characterized by ten parameters, and k-medoids clustering was applied to identify geometry patterns. However, this method overlooked minor geometric variations impacting Δp/ΔL. An adaptive factorization network model, a deep learning approach, was employed to address this. This model demonstrated significant predictive accuracy, as evidenced by high determination coefficients, R2, comparing actual and predicted Δp/ΔL in test data (overall 0.904; Bakken 0.840; Barnett 0.848; BC 0.844; Marcellus 0.872; Loving-Delaware 0.914; Reeves-Delaware 0.880). The method's reliability in forecasting Δp/ΔL is supported by its R2 values of ∼0.8 and the mean absolute percentage error of ∼5 %, indicating its applicability in newly developing basins. This methodology offers reliable Δp/ΔL predictions for all possible well geometry scenarios in shale gas fields but also eliminates the need for additional multi-phase flow simulations, enhancing design and production plan.

A numerical study of complex fractures propagation path in naturally fractured gas shale: Reorientation, deflection and convergence

Shale gas reservoir is characterized as the naturally fractured formation, which is benefit for complex hydraulic fracture network generation. The propagation path is crucial to determine the reservoir stimulation result, and evaluate the quality of complex hydraulic fracture network. To investigate the propagation path of complex hydraulic fracture in gas shale, the hybrid combined discrete fracture network-finite element method (DFN-FEM) model is involved. Combining a linear hardening and a non-linear softening process, a non-linear traction-separation law is proposed to describe the fracture damage evolution. Validated with open-reported laboratory experiments, the hydraulic-natural fracture (HF–NF) interaction criterion is depicted under four geomechanical and injection factors. Based on a field-scale model of Sichuan basin shale gas reservoir, the complex hydraulic fractures propagation process is simulated with rock deformation and stress shadow. Several propagation path indexes are defined with fracture morphology to discuss the effect of representative geomechanical, injection and multi-clustering parameters. The results show that the tension fractures are predominant to hydraulic fractures propagation path and shear the natural fractures, due to the combined influence of natural fractures network and interference between clusters. The horizontal stress contrast and the injection fluid viscosity is governing to the propagation path and morphology, rather than the friction coefficient and injection rate. Multi-clustered hydraulic fractures converge into a dominant fracture due to the attraction with a short clusters-spacing, while the exclusion is observed along the propagation path with the increase of clusters number.

Detailed Imaging of a Seismogenic Fault That Potentially Induced the Two 2019 Weiyuan Moderate Earthquakes in the Sichuan Basin, China

Abstract Induced earthquakes are becoming a significant issue. Several destructive induced earthquakes (Ms ≥5.0) have occurred in shale gas fields located at the southwestern Sichuan basin, China, in the recent years. Specifically, two moderate earthquakes with magnitudes of Ms 5.4 (occurred on 8 September 2019) and 5.2 (occurred on 18 December 2019) exceeded the largest earthquake ever recorded in the Weiyuan. It remains unclear which seismogenic faults were responsible for the two moderate events due to insufficient knowledge of the subsurface structure and contradictory hypocenter depths obtained from different seismological methods. In this study, mainshock locations, focal mechanisms, and precise relocations of microseismicity were used to map the 3D geometry of the seismogenic fault. The result shows that the two moderate earthquakes occurred on the same fault. High-resolution seismic reflection profiles indicate several preexisting faults at various depths and a potential seismogenic fault. No large-scale faults are identified in the sedimentary cover above the Cambrian at the shallow centroid depth of these earthquakes. However, the seismic reflectors show phase discontinuous feature, indicating the existence of preexisting faults in the basement. A preexisting fault in the basement is consistent with a seismogenic fault that may have induced the two moderate earthquakes. Our study suggests that poroelastic stress propagation is likely responsible for the basement fault reactivation. The rupture on a stressed basement fault was triggered and produced two moderate earthquakes in a short period during hydraulic fracturing. The previous strategy of avoiding direct injection of fluids into preexisting faults to reduce seismic risk in operation region is not enough to avoid the possibility of the coupled poroelastic stress triggering deep fault rupture. We need to reevaluate the potential seismic risk of shale gas development in Weiyuan, the southern Sichuan basin shale gas field considering the preexisting faults in sedimentary and in basement and the effect of the fully coupled poroelastic stress field.

An effective integration optimization algorithm for regional fracturing design and drilling placement

Hydraulic fracturing horizontal well technology has a pivotal role in exploiting unconventional resources, but it often requires considerable investment. Integrated optimization of the fracturing design, horizontal well, and drilling platform placement in the whole region is an efficient way to reduce cost and increase economic benefits. However, it is difficult to quickly complete these optimizations because traditional reservoir numerical simulation requires extensive resources in terms of labor, time, and computation. Therefore, we proposed a new algorithm, named Gaussian Process Regression-Bilevel Programming Genetic-Critical Circle Intersection Momentum Shift (GPR-BPG-CCIMS) algorithm to effectively co-optimize the fracturing design, horizontal well and drilling platform placement in the whole region. BPG algorithm shares the merits of Bilevel Programming (BP) and genetic algorithm (GA), which is used for optimizing the horizontal well and fracturing parameters. CCIMS algorithm is applied to optimize the drilling platform placement by merging and shifting drilling platform positions. GPR model is a production proxy model based on machine learning to improve optimization efficiency. The proposed algorithm was applied to a real shale gas reservoir to verify the effectiveness of the algorithm. The results showed that the GPR model exhibited great prediction accuracy by providing the high coefficient of determination (R2 = 0.999), the high percentage of accuracy-precision (PAP = 99.017) and the low root mean square error (RMSE = 0.022). The optimal fracture half length, cluster spacing, fracture fluid per meter, horizontal section length, well location, and drilling platform location were obtained by GPR-BPG-CCIMS algorithm. Compared with the actual net present value (NPV), the optimized NPV was increased by 181 million dollars. The proposed algorithm successfully co-optimizes the engineering parameters of the whole region in a short consumption time, which effectively supports the development scheme design and decision-making. The optimization framework can be extended to other shale gas basins.

Geomechanics evolution integrated with hydraulic fractures, heterogeneity and anisotropy during shale gas depletion

Due to reservoir depletion, the reservoir geomechanical parameters, such as stresses, permeability, are changing during shale gas production. A coupled flow-geomechanics model was built to investigate time-lapse geomechanical responses in production before infill well placement of Sichuan Basin shale gas reservoir. In the modelling, hydraulic fractures were simulated from microseismic data and mapped from a geological model to build the flow model. An interface code was improved to build the geomechanical model properties from the geological model, as well as communicates the data between finite difference grids in the reservoir simulator and finite element grids in the geomechanical simulator. In addition, the anisotropy of physical properties and rock mechanical properties was integrated in the flow model and the geomechanical model. Stress-dependent porosity and permeability models were embedded as well. Case studies show that stress evolution and re-orientation are affected by both the trajectory and fractures of producing wells, as well as the heterogeneity of geomechanical properties. Besides, the effect of parallel wells production should be taken into consideration based on the wells-spacing.

Evaluation of the Accumulation Conditions and Favorable Areas of Shale Gas in the Upper Palaeozoic Marine-Continental Transitional Facies in the Daning-Jixian Area, Ordos Basin

This study focuses on the organic-rich mud shale in the Upper Palaeozoic transitional facies in the southeastern margin of the Ordos Basin. It systematically analyzes the shale gas accumulation conditions of the organic-rich mud shale in the Lower Permian Shanxi-Taiyuan Formation, including the thickness, distribution, organic matter type and content, thermal maturity, reservoir space, gas-bearing property, and rock brittleness. The results show that the thick dark mud shale contains a high organic matter content, is a suitable kerogen type for gas generation, and exhibits moderate thermal evolution, providing excellent conditions for hydrocarbon accumulation. Residual primary pores formed by shale compaction, secondary pores formed by organic matter hydrocarbon generation, clay mineral transformation and dissolution, and fractures provide suitable reservoir spaces for shale gas. The shale in the study area has a higher gas content than the shale strata in the marine basins of the United States. In addition, the content of brittle minerals such as quartz is higher, and Poisson’s ratio is lower, facilitating the subsequent transformation. The accumulation conditions indicate the high potential of the study area for shale gas exploration and development. The geological analogy method is used to compare the study area with five major shale gas basins in the United States. The results indicate that the shale gas resources of the Shanxi-Taiyuan Formation in the study area are in the range of 2800– 3200 × 10 8 m3. The primary controlling factors affecting shale gas reservoirs in this area are the abundance of organic matter, thermal maturity, shale thickness, and quartz content. Favorable areas are predicted based on these factors.

Shale gas resources across the world: A future source of energy

Unconventional natural gas resources are very important for ensuring energy security. It is a concern that conventional natural gas resources will be unable to meet growing supply requirements. This concern has prompted a scramble to secure long-term natural gas supplies. In a high oil and gas price environment, unconventional resources are viewed as important and economically attractive components of future natural gas supplies. Shale gas is natural gas produced from shale formations. Gas shales are organic-rich shale formations. Shale gas is a dry gas composed of methane. Various factors which have contributed to its rapid development are mainly advancements in horizontal drilling, hydraulic fracturing, and, perhaps most importantly, the rapid increase in natural gas prices in the last several years as a result of significant variation in supply and demand. India has a high potential for shale reserves. According to the available data, a comprehensive shale gas pilot project carried out in the Damodar Valley Basin has made an initial gasin- place estimate of 300 to 2,100 trillion cubic feet (TCF) in Indian shale gas basins, which is around 300 times higher than the Krishna Godavari Dhirubhai 6 (KG-D6) basin, by far the largest gas field in the country. In this paper, a brief review of shale gas reserves across the world and their government policies has been explained.

Temporal changes in domestic water well methane reflect shifting sources of groundwater: Implications for evaluating contamination attributed to shale gas development

Regulatory agencies routinely assess the presence of stray gas release from unconventional gas wells by sampling for methane in nearby groundwater after the well is drilled or if citizens complain about methane in their water. We studied whether methane concentrations in groundwater naturally vary through time in a shale gas basin where unconventional development and hydraulic fracturing has not yet occurred, to test the assumption that pre-drilling observations of well water quality can be reliable measures for assessing impacts of later gas drilling. We collected groundwater samples from 11 domestic wells in New York monthly for 13 months for methane and ion concentrations in a highly gas productive part of the Appalachian basin where fracking has been banned. Changing methane concentrations correlated with changes in chloride and bromide, indicating changing mixtures of shallow freshwater and deeper formation brine extracted by the wells through time. The hydrogeologic setting of a water well can cause variability in methane concentrations that may mimic stray gas but cannot be attributable to gas drilling. For this reason, before and after testing has limited utility to distinguish impacts of gas drilling from other causes of changing methane concentrations unless that testing includes sampling a comprehensive set of ions multiple times prior to drilling.

An integrated approach to evaluate the unconventional hydrocarbon generation potential of the Lower Goru Formation (Cretaceous) in Southern Lower Indus basin, Pakistan

Southern Lower Indus basin is an oil and gas prone basin, which is important for producing hydrocarbon in Pakistan. Due to limited Rock-Eval pyrolysis data availability in the prospective shale gas basin, the organic facies geochemical characteristics study is a challenging task for researchers. The primary objective of this study is an evaluation of the Lower Goru Formation organic facies hydrocarbon potential by geochemical data and its subsurface facies distribution study by well tops and seismic data. The study area is situated at the Southern Lower Indus basin of Pakistan that is considering the prospective shale gas basin with immense unconventional hydrocarbon potential. In the present study, Rock-Eval pyrolysis data analysis along with the integration of both seismic and well tops data were conducted for investigation of source rock generation potential of organic facies variability within the Lower Goru Formation. The geochemical approaches used in the current study show that the Lower Goru Formation encountered in, bears fair to excellent total organic carbon (TOC) content values of 0.50–3.60% in Well-A and 0.10–4.69% in Well-B. Additionally, the results of Rock-Eval pyrolysis data show that interbedded shales of the Lower Goru Formation contain different types of kerogen (III, II–III, and II) with variable generation potential of oil and gas.

Induced earthquake damage assessment methodology for potential hydraulic fracturing sites: Application to Manaus, Brazil

The number of seismic events induced by the exploitation of unconventional oil and gas reservoirs has escalated considerably in the last decade. This has raised concerns in several sectors of society, and in consequence, research efforts have been launched to ascertain the risk associated with induced seismicity. This article presents a procedure to quantify potential damages caused by induced seismicity to the built infrastructure of a region. The technique adapts the probabilistic seismic hazard analysis framework to the features of induced seismicity. The risk is then evaluated by the probability of exceeding economic loss. Estimates of potential injuries or loss of life caused by buildings’ interior components are fundamental policymaking inputs, but were not considered in this initial study which is focused on assessing direct damage. In a future study, however, these factors will be addressed. The procedure is applied in a case study in Manaus, a city located on a large shale gas basin which is potentially exploitable. The results of the study indicate that the tectonic parameter ( b) of the adjusted Gutenberg–Richter model is a governing driver in the loss analysis. Two damage mitigation strategies are proposed: one that limits volume injected setting loss thresholds and other that restricts injection locations based on damage modeling estimates. Insights from the case study emphasize that these type of activities should be avoided near urban areas where seismic standard anticipates low natural seismicity, and with a high proportion of poorly built residential infrastructure. The study contributes to the literature a technique to inform the decision-making associated with establishing unconventional oil and gas exploitation projects that is applicable to several places and situations.

Several essential geological and geochemical issues regarding shale gas research in China

Recently, shale gas research and industrial production in China have been significantly developed, which has enriched the theory of natural gas geology in China and increased the supply of domestic natural gas production. In the future, shale gas will obtain great achievements among the developments of the natural gas industry in China. The following four geological and geochemical issues about the exploration and research of shale gas have great significance: (1) China has to break through the single economic shale gas formation. The United States found at least thirty sets of economic shale gas formations in 29 basins. To date, only one basin in China (Sichuan Basin) has found one set of economic shale gas formation (Wufeng-Longmaxi formations). (2) In regards to the interval RO value of the economic shale gas formations and segment RO value of the gas fields, the interval RO values are 3.31% for the economic shale gas formation in China. However, it is 4.1% for that in the USA. The segment RO values are 2.34% for the gas fields in China and 3.5% for that in the USA. So the values are small in China, but big in the USA. Several shale gas fields derived from sapropelic sources in the United States were found in the oil generation window with RO = 1.0%–1.3%. Therefore, shale gas exploration in China also needs to pay attention to this stage. At the same time, attention should be paid to the exploration of shale gas derived from humic sources. (3) When it comes to the continuous high-yield period of the gas field, the world's first commercially developed shale gas field (Barnett) shows a high-yield forecast of 10 × 109 m3 per year for about twenty years. The development of the shale gas field in China is still in the construction stage. (4) In terms of the role of fracture in shale gas preservation and development, the fault has a dual effect on the enrichment of shale gas. In the United States, tectonic in the shale gas basin is stable, and faults are few, while structures in China in the shale gas basin are active, and faults are developed. Therefore, faults have more harm than good to the shale gas in China, which caused the fragmentation of the continuously distributed Wufeng-Longmaxi formations, limiting the area of the gas field.

Rare Earth Elements Occurrence and Economical Recovery Strategy from Shale Gas Wastewater in the Sichuan Basin, China

Global demand for rare earth elements (REEs), which are central to many modern high-tech industries, is increasing rapidly. For the first time, we discovered and determined the REEs concentrations in Sichuan Basin shale gas flowback and produced water (FPW). The total REEs in shale gas FPW investigated in this work ranged from 4.5 to 118.3 μg/L. Europium (Eu) was found in all samples (0.92–79.62 μg/L). Our study suggests that there was approximately 4.2 tons of Eu2O3 in FPW worldwide in 2016, and that this value could increase to 16.8–111.7 tons in 2030. We discussed potential methods for Eu recovery from FPW and further research needs to facilitate recovery of REE. The results suggest that wastewater from oil and gas extraction constitutes a promising resource for REEs, especially for Eu.

Northeast British Columbia Liard Basin: A seismic stratigraphy study

The Liard Basin is a highly prospective shale gas basin located in northeast British Columbia that is largely underrepresented in public literature. We used available-for-purchase 2D seismic data in the area to create a high-level, regional stratigraphic interpretation of the basin, providing the first seismically controlled overview of the basin structure and stratigraphy. The basin is characterized by two distinct, opposing wedges of sediment in the Mesozoic and Paleozoic sections: the Mesozoic with northeastward thinning and the Paleozoic with southwestward thinning. The wedging of the Upper Devonian-Lower Mississippian (Tournasian) section is dominated by multiple large packages of clinoforms, which progress into the basin from northeast to southwest and are predominantly seen in the seismic sequence stratigraphy. These distinct packages of clinoforms indicate changing sediment sources over time. In contrast, there are no clinoforms seen in the Mesozoic section, which may be a limitation of the orientation of the 2D seismic data that we used. Our result from the seismic interpretation is an updated interpretation of the Upper Devonian-Lower Mississippian stratigraphy of the Liard Basin, including an updated stratigraphic cross section for the area.

Compartmentalisation and groundwater–surface water interactions in a prospective shale gas basin: Assessment using variance analysis and multivariate statistics on water quality data

AbstractAn environmental concern with hydraulic fracturing for shale gas is the risk of groundwater and surface water contamination. Assessing this risk partly involves the identification and understanding of groundwater–surface water interactions because potentially contaminating fluids could move from one water body to the other along hydraulic pathways. In this study, we use water quality data from a prospective shale gas basin to determine: if surface water sampling could identify groundwater compartmentalisation by low‐permeability faults; and if surface waters interact with groundwater in underlying bedrock formations, thereby indicating hydraulic pathways. Variance analysis showed that bedrock geology was a significant factor influencing surface water quality, indicating regional‐scale groundwater–surface water interactions despite the presence of an overlying region‐wide layer of superficial deposits averaging 30–40 m thickness. We propose that surface waters interact with a weathered bedrock layer through the complex distribution of glaciofluvial sands and gravels. Principal component analysis showed that surface water compositions were constrained within groundwater end‐member compositions. Surface water quality data showed no relationship with groundwater compartmentalisation known to be caused by a major basin fault. Therefore, there was no chemical evidence to suggest that deeper groundwater in this particular area of the prospective basin was reaching the surface in response to compartmentalisation. Consequently, in this case compartmentalisation does not appear to increase the risk of fracking‐related contaminants reaching surface waters, although this may differ under different hydrogeological scenarios.

Water footprint of hydraulic fracturing in Northeastern British Columbia, Canada

The method of hydraulic fracturing used to exploit unconventional shale gas has raised public concerns over the volumes of freshwater that are extracted for injection operations as well as the volumes of wastewater generated as a by-product of gas production. Using data from the British Columbia Oil and Gas Commission, this paper examines the volumes of produced and injected water from hydraulically fractured gas wells in Northeastern British Columbia. The two major producing shale gas basins in the province are the Montney and the Horn River. In this study, these are divided into several sub-basins based on existing geological and reservoir engineering applications. For each sub-basin the average volumes of wastewater- and injected water per well are calculated and then normalized to cumulative gas production. Ratios of injected water: gas production and wastewater: gas production are then applied to estimated volumes of remaining gas reserves in each sub-basin in order to calculate a total water footprint of future exploitation. These extrapolated water footprints were further elaborated into three scenarios of wastewater recycling rates: 0, 40, and 100% re-use. This study also compares the quality and quantity of wastewater produced from hydraulically fractured wells to their conventional counterparts in the province. Based on these calculations, the total future freshwater withdrawal and wastewater production volumes for all basins range from 1.65 to 3 billion, and 0 to 1.35 billion cubic metres, respectively. Volumes of freshwater withdrawal are relatively modest compared to other industries when considering the size of Northeastern British Columbia and the time-scale of extraction. In general, hydraulically fractured wells in Northeastern British Columbia produce volumes of wastewater that are equal to or lower than those required for injection. Unconventional gas wells often produce far less wastewater than their conventional counterparts.

Water impact of an optimal natural gas production and distribution system: An MILP model and the case-study of Mexico

This study presents a mathematical programming approach for evaluating the exploitation and distribution of shale gas from potential reserves at a national level, depending upon existing infrastructure and water availability. The study describes an MILP model that simultaneously integrates water management with the design and planning of the supply chain, from basins to distribution markets and fresh water supply from available watersheds. The model is applied to a case based on the potential exploitation of shale gas basins in Mexico. The parameters of the model are mostly taken from the databases of the country, processed through the geographic information system ArcGIS. The solution provides the optimal decisions for exploitation and distribution, as well as for freshwater source selection and optimal wastewater management. Water management strategies include disposal, wastewater treatment in municipal plants and onsite treatment. The negative impact of water consumption of the optimal exploitation systems is assessed based mainly on the estimation of the water stress index. Results show that the shale gas exploitation would favor the energy independence of the country, but the availability of freshwater for some municipalities would be compromised.

Influence of tectonic stress regime on the magnitude distribution of induced seismicity events related to hydraulic fracturing

Hydraulic fracturing is today the primary means of initiating, increasing, and maintaining well productivity in unconventional shale gas reservoirs. However, hydraulic fracturing is attracting public concern over its rapid growth in use and environmental footprint, including potential hazards such as induced seismicity. To mitigate these concerns, there is a need to better understand the level of hazard present with respect to the magnitudes of the events possible, recognizing that these are not equal across different shale gas plays due to regional differences in the geological conditions or even within the same shale gas play due to local differences.An empirical study is presented here along with a series of numerical simulations to investigate the influence of the tectonic stress regime on the magnitude and magnitude distribution of induced seismicity events related to hydraulic fracturing practices. A database of determined earthquake focal mechanisms was first used to determine the tectonic stress regime for different North American shale gas basins. Next, induced events associated with hydraulic fracturing operations were identified to determine the magnitude distributions and b-values for these different shale gas basins. To support these empirical analyses, 3-D numerical modelling was performed to further investigate the mechanistic responses and event magnitudes under different simulated stress regimes. The empirical analysis results show that thrust faulting stress regimes have lower b-values than strike-slip stress regimes and therefore are more susceptible to larger induced seismicity events. The numerical simulations show that this is related to the stresses acting on a thrust fault (relative to the fault dip angle) being higher and more concentrated across a larger slip area. Slip in this case, and the stored strain energy being released, was observed to occur as a single large magnitude event. In contrast, numerical simulations for the other faulting types showed the stresses to be more distributed across the fault plane. This results in multiple slip events involving smaller slip areas and therefore with smaller event magnitudes, assuming all other factors are kept the same.

Development of reservoir economic indicator for Barnett Shale gas potential evaluation based on the reservoir and hydraulic fracturing parameters

The general economics or productivity potential of shale gas projects are strongly related to the reservoir characteristics and completion quality. This study proposed a framework for the development of an economic indicator for evaluating the economics of a shale gas project based on the reservoir parameters, hydraulic fracturing parameters, and various gas price scenarios. Nine key parameters were selected as the most influential factors through a sensitivity analysis study: the reservoir pressure, reservoir thickness, porosity, permeability, initial gas saturation, adsorbed gas content, fracture half-length, fracture conductivity, and fracture spacing. A total 87 simulation cases were modeled and simulated based on the key parameters, whose ranges were based on the Barnett shale reservoir properties to define the relationship between the net present value (NPV) of a well along with the reservoir properties and hydraulic fracturing qualities. An indicator-based multivariate exponential function was then developed in terms of the key parameters. A strong correlation was observed between the economic indicator (SREI) and the NPV of a shale gas project. The parameters in the developed indicator were then divided by their base values to develop a dimensionless indicator. The dimensionless economic indicator was incorporated with a range of gas prices from $2 to $8 USD/Mcf to develop a dynamic economic indicator called the SREI_D. The results showed that value of SREI_D should be greater than 1.088 for a gas well in Barnett shale reservoir to be economically feasible, which shows a positive NPV. The results from the cross-validation test indicated that SREI_D can properly describe the relationship between the NPV of a shale gas well and the reservoir parameters and hydraulic fracturing parameters. The proposed economic indicator is a useful tool for identifying sweet spots in a shale gas reservoir. Furthermore, the use of SREI_D is efficient and convenient, and the proposed indicator can be used to identify the economic feasibility of a shale gas well for various gas price scenarios without calculating the NPV. The results of this study can be extended as a general economic indicator for major shale gas basins in the USA or in other countries.

Integrated Seismic (IS) for Shale Gas Exploration and Management

Seismic integration has been a successful accessory in every data interpretation project. For shale gas exploration design, development and implementation, high-resolution seismic data are necessitated. In this context, every exploration project needs multi-disciplinary datasets and their integration that can minimize the ambiguity of the interpretative outcomes. What are the integrated solutions for imaging and interpreting shale gas and how do they impact our shale prospect business? How do we organize and standardize our integrated workflows to address issues of exploration, field development, including drilling campaigns of the unconventional reservoirs? So far, the conventional reservoirs of many worldwide basins did produce even without integrated workflows. With the increase in intricacy in structural and stratigraphic settings, in particular with the fractured shale environments, exploration and field development plans have become multifaceted, complicating the field operations. How do we take on the exploration, development and drilling campaign decisions using the integrated seismic solutions? How do we suggest the “integrated solutions” to our valued operators and service providers? Why are the conventional technologies failures and setbacks? How can we guide and recommend the petroleum companies on appropriate technologies and the reserve computations in shale environments? We come up with an “Integrated Seismic” (IS) strategy, addressing the issues and challenges. The applicability and feasibility of IS in various exploration projects including their execution and implementation in worldwide shale gas basins are discussed. IS has been playing a vital role, making huge impacts on the integrated interpretation projects, especially during prospect identification and risk evaluation stages.