Browsing by Subject "Shale gas"
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Item A lattice model for gas production from hydrofractured shale(2016-12) Eftekhari, Behzad; Patzek, Tadeusz W.; Marder, Michael P., 1960-; Olson, Jon E; Sepehrnoori, Kamy; Espinoza, David NNatural gas production from US shale and tight oil plays has increased over the past 10 years, currently constitutes more than half of the total US dry natural gas production, and is projected to provide the US with a major energy source in the next several decades. The increase in shale gas production is driven by advances in hydraulic fracturing. Recent studies have shown that gas production from hydraulically fractured shales has to come from a network of connected hydraulic and natural fractures, and that if one takes the shale permeability to be 10 nD, then the characteristic spacing of the fracture network will be about 1.5 − 3 m. The precise nature of the characteristic spacing, as well as other production and formation properties of the fracture network, are questions which motivated the present dissertation. This dissertation studies (1) the topology of the fracture network, (2) the mechanics of how the fracture network evolves in time during injection and (3) how fracture network geometry affects production. We use percolation theory to study fracture network topology. Fracture are placed on the bonds of a two–dimensional square lattice and follow a power law length distribution. We analytically obtain the scaling of connectivity for power law fracture networks, and numerically compute the percolation threshold as a function of the exponent. We develop a hydrofracture model which makes it possible to simulate initiation and propagation of hydraulic fractures, as well as the interaction between hydraulic and natural fractures. The model uses the Reynolds lubrication approximation to describe fluid flow through the fractures and relies on analytical estimates to predict the stress response. We develop a diffusion model to compute gas production from hydraulically fractured shales. The model uses a random walk algorithm and takes the fracture network as the absorbing boundary to the gas transport equation. We show that scaling the cumulative production versus time data from the diffusion model with respect to characteristic scales of production maps the production versus time plots onto a single scaling curve. Using the model, we identify, or define, characteristic spacing for fracture networks.Item Accounting for Adsorbed gas and its effect on production bahavior of Shale Gas Reservoirs(2010-10-12) Mengal, Salman AkramShale gas reservoirs have become a major source of energy in recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these reservoirs comes from desorption. Ignoring a major component of production, such as desorption, could result in significant errors in analysis of these wells. Therefore it is important to understand the adsorption phenomenon and to include its effect in order to avoid erroneous analysis. The objective of this work was to imbed the adsorbed gas in the techniques used previously for the analysis of tight gas reservoirs. Most of the desorption from shale gas reservoirs takes place in later time when there is considerable depletion of free gas and the well is undergoing boundary dominated flow (BDF). For that matter BDF methods, to estimate original gas in place (OGIP), that are presented in previous literature are reviewed to include adsorbed gas in them. More over end of the transient time data can also be used to estimate OGIP. Kings modified z* and Bumb and McKee?s adsorption compressibility factor for adsorbed gas are used in this work to include adsorption in the BDF and end of transient time methods. Employing a mass balance, including adsorbed gas, and the productivity index equation for BDF, a procedure is presented to analyze the decline trend when adsorbed gas is included. This procedure was programmed in EXCEL VBA named as shale gas PSS with adsorption (SGPA). SGPA is used for field data analysis to show the contribution of adsorbed gas during the life of the well and to apply the BDF methods to estimate OGIP with and without adsorbed gas. The estimated OGIP?s were than used to forecast future performance of wells with and without adsorption. OGIP estimation methods when applied on field data from selected wells showed that inclusion of adsorbed gas resulted in approximately 30 percent increase in OGIP estimates and 17 percent decrease in recovery factor (RF) estimates. This work also demonstrates that including adsorbed gas results in approximately 5percent less stimulated reservoir volume estimate.Item Assessing the viability of compressed natural gas as a transportation fuel for light-duty vehicles in the United States(2011-08) Kennedy, Castlen Moore; Webber, Michael E., 1971-; Groat, CharlesRecent optimistic revisions to projections for recoverable natural gas resources in the United States have generated renewed interest in the possibility of greater utilization of natural gas as a transportation fuel. Against a backdrop of significant policy challenges for the United States, including air quality concerns in urban areas, slow economic growth and high unemployment, and a rising unease with regard to an increasing dependence on foreign oil; natural gas offers the nation’s transportation sector an opportunity to reduce mobile emissions, lower fuel costs, create jobs and reduce dependence on imported oil. While the current focus for expanded use of natural gas in the transportation sector emphasizes heavy duty and fleet vehicles, there may also be potential for increased use for passenger vehicles. Inconvenience, with regard to refueling, and high incremental vehicle costs, however, are seen as major obstacles to greater adaptation. This analysis examines the benefits and drawbacks of natural gas vehicles from the passenger vehicle perspective and includes data from a cross-country road trip. The report includes a review of market trends and possible development scenarios and concludes with recommendations to minimize the potential challenges of greater adaptation of natural gas vehicles in the passenger vehicle market.Item Challenges and strategies of shale gas development(2012-05) Lee, Sunje; Groat, Charles G.The objective of this paper is to help new investors and project developers identify the challenges of shale gas E&P and to enlighten them of the currently available strategies so that they can develop the best project plan and execute it without suffering unexpected challenges. This paper categorizes the challenges into five groups and concentrates on shale-gas-specific challenges. It excludes conventional oil and gas development challenges because by and large these five major challenge groups seem to decide the success and failure of most shale gas projects. The five groups are the identification of shale gas potentials, the technical challenges in well design and stimulation strategies, the economic challenges such as high cost of new technologies, the environmental challenges concerning the hydraulic fracturing water, and the international challenges of performing projects outside the US. The strategies are yet to be well established and are still evolving rapidly. Hence, before starting a shale gas project, shale gas developers need to perform extensive and intensive check-ups on the challenges and on current available strategies as well as to stay up to date thereafter on new strategies.Item Comparative study for the interpretation of mineral concentrations, total porosity, and TOC in hydrocarbon-bearing shale from conventional well logs(2012-08) Adiguna, Haryanto; Torres-Verdín, Carlos; Balhoff, MatthewThe estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile. Many operating companies have turned their attention to neutron capture gamma-ray spectroscopy (NCS) logs for assessing in-situ mineral composition. The NCS tool converts the energy spectrum of neutron-induced captured gamma-rays into relative elemental yields and subsequently transforms them to dry-weight elemental fractions. However, NCS logs are not usually included in a well-logging suite due to cost, tool availability, and borehole conditions. Conventional well logs are typically acquired as a minimum logging program because they provide geologists and petrophysicists with the basic elements for tops identification, stratigraphic correlation, and net-pay determination. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method. This thesis introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. The second step examines various methods that can provide good initial values for the inversion. For example, a reliable prediction of kerogen concentration can be obtained using the ΔlogR method (Passey et al., 1990) as well as an empirical correlation with gamma-ray or uranium logs. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties. Two synthetic examples with known mineral compositions and petrophysical properties are described to illustrate the application of inversion. The impact of shoulder-bed effects on inverted properties is examined for the two inversion modes: depth-by-depth and layer-by-layer. This thesis also documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and NCS logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition.Item Detection and quantification of rock physics properties for improved hydraulic fracturing in hydrocarbon-bearing shales(2012-12) Montaut, Antoine Marc Marie; Torres-Verdín, Carlos; Spikes, KyleHorizontal drilling and hydraulic stimulation make hydrocarbon production from organic-rich shales economically viable. Identification of suitable zones to drill a horizontal well and to initiate or contain hydraulic fractures requires detection and quantification of many factors, including elastic mechanical properties. Elastic behavior of rocks is affected by rock composition and fabric, pore pressure, confining stress, and other factors. Rock fabric refers to the arrangement of the rock’s solid and fluid constituents. The objective of this thesis is to quantify rock fabric properties of hydrocarbon-bearing shales affecting elastic properties, including load-bearing matrix, anisotropic cracks, and shape of rock components. Once rock fabric is validated with sonic logs, results can be used to identify suitable zones to drill a horizontal well, initiate hydraulic stimulation, and contain fracture propagation. We develop a method to estimate elastic properties based on rock composition. The differential effective medium (DEM) theory is invoked to model rock elastic properties with a load-bearing component in which remaining minerals and pores are added as spheres or ellipsoids. The method can be combined with the self-consistent approximation (SCA) to construct a load-bearing matrix made of two solid phases. Anisotropic inclusions are added via Hudson’s model. Subsequently, Gassmann’s theory is invoked to saturate the rock with fluids and determine low-frequency elastic properties for comparison to sonic logs. Rock fabric properties remain constant in a vertically homogeneous formation. In vertically heterogeneous strata, the depth interval of interest is divided into rock types, based on rock solid composition, and each rock type is associated with a specific fabric. Quantification of rock fabric properties is a non-unique process, and one should take into account as much petrophysical and geological information as possible to ensure physically viable results. Our simulation and interpretation method is implemented in two wells in both the Haynesville and Barnett shales. Averages of relative errors between estimated velocities and sonic logs are less than 4% in the four wells. Simulations in the Haynesville shale are isotropic, and therefore indicate that rock fabric may not be the main cause of mechanical anisotropy in cases where such behavior is inferred from field data. Rock fabric properties are constant with depth in both wells. Consequently, identification of suitable zones to drill a horizontal well or to contain fracture propagation is not based on rock fabric; it is deduced from Young’s modulus. Simulated Poisson’s ratio is shown to be more sensitive to errors in velocities than Young’s modulus and is therefore not used in the interpretation. Favorable depth intervals for gas production exhibit sizeable volumes of gas and organic content. In the Barnett shale, the two wells exhibit different rock fabrics. Such a behavior indicates that the formation is laterally heterogeneous. Rock physics models should therefore be extrapolated from one well to another with caution. Simulations assume anisotropic elastic behavior and suggest the presence of compliant horizontal pores in one case. Natural vertical fractures are observed on electric image logs in the remaining case and are modeled with Hudson’s theory. This behavior suggests that rock fabric causes mechanical anisotropy in the formation. Heterogeneity of the Barnett shale rock fabric is inferred from the necessary use of rock typing to adequately reproduce sonic logs in both wells. Intervals with large porosity and high gas saturation identify suitable zones to perform hydraulic stimulation. Among such zones, rock types that exhibit stiff load-bearing matrices (comprising mostly calcite, for example) indicate suitable depths to drill horizontal wells or to contain hydraulic fractures. Intervals with dense layering of different rock types are unsuitable for fracture propagation and should be avoided during hydraulic-fracturing operations.Item Developing an optimization model for a cap and trade system to control methane emissions in the oil and natural gas industry : application to the Permian Basin(2016-12) Correa Vivar, Luciano Livio; Fisher, W. L. (William Lawrence), 1932-; Dyer, James S; Scanlon, Bridget RDevelopment of unconventional oil and natural gas in the U.S., particularly the exploitation of shale gas, has been highly controversial with significant geopolitical implications. It is unquestionable that this so-called “golden era” of natural gas has brought not only significant new technologies and economic growth but has also raised important environmental concerns, including air pollution from methane emissions. Methane (CH₄) emissions from the oil and natural gas industry have been of critical and increasing concern for public policy. New evidence (Zeebe, et al. 2016) has confirmed record high levels of carbon dioxide (CO₂) in 66 million years, with CH₄ emissions considered a significant risk for global warming and climate change. For this reason, the U.S. Environmental Protection Agency (EPA) issued in 2016 a new “methane rule” to control emissions from the oil and gas industry by obligating the use of specific abatement measures to reduce pollution. This study analyzes the application of an optimization model to represent a market-based strategy of a cap and trade system as an alternative approach to regulating emissions. This option is more efficient than traditional command and control regulations at achieving the same levels of methane reduction in the oil and gas sector, and this hypothesis is verified by applying the optimization model to a sample of oil and gas production facilities operating in the Permian Basin. In spite of all the political-scientific efforts and discussions, we are still far from the knowledge needed to achieve a public policy strategy that balances sustainability with economic development, and I hope this research helps to reduce that gap.Item Developments in modeling and optimization of production in unconventional oil and gas reservoirs(2015-05) Yu, Wei; Sepehrnoori, Kamy, 1951-; Chin, Lee; Delshad , Mojdeh; Mohanty, Kishore K; Patzek, Tadeusz WThe development of unconventional resources such as shale gas and tight oil exploded in recent years due to two key enabling technologies of horizontal drilling and multi-stage fracturing. In reality, complex hydraulic fracture geometry is often generated. However, an efficient model to simulate shale gas or tight oil production from complex non-planar fractures with varying fracture width along fracture length is still lacking in the petroleum industry. In addition, the pore size distributions for shale gas reservoirs and conventional gas reservoirs are quite different. The diffusivity equation of conventional gas reservoirs is not adequate to describe gas flow in shale reservoirs. Hence, a new diffusivity equation including the important transport mechanisms such as gas slippage, gas diffusion, and gas desorption is required to model gas flow in shale reservoirs. Furthermore, there are high cost and large uncertainty in the development of shale gas and tight oil reservoirs because of many uncertain reservoir properties and fracture parameters. Therefore, an efficient and practical approach to perform sensitivity studies, history matching, and economic optimization for the development of shale gas and tight oil reservoirs is clearly desirable. For tight oil reservoirs, the primary oil recovery factor is very low and substantial volumes of oil still remain in place. Hence, it is important to investigate the potential of CO₂ injection for enhanced oil recovery, which is a new subject and not well understood in tight oil reservoirs. In this research, an efficient semi-analytical model was developed by dividing fractures into several segments to approximately represent the complex non-planar fractures. It combines an analytical solution for the diffusivity equation about fluid flow in shale and a numerical solution for fluid flow in fractures. For shale gas reservoirs, the diffusivity equation of conventional gas reservoirs was modified to consider the important flow mechanisms such as gas slippage, gas diffusion, and gas desorption. The key effects of non-Darcy flow and stress-dependent fracture conductivity were included in the model. We verified this model against a numerical reservoir simulator for both rectangular fractures and planar fracture with varying width. The well performance and transient flow regime analysis between single rectangular fracture, single planar fracture with varying width, and single curving non-planar fracture were compared and investigated. A well from Marcellus shale was analyzed by combining non-planar fractures, which were generated from a three-dimensional fracture propagation model developed by Wu and Olson (2014a), and the semi-analytical model. Contributions to gas recovery from each gas flow mechanism were analyzed. The key finding is that modeling gas flow from non-planar fractures as well as modeling the important flow mechanisms in shale gas reservoirs is significant. This work, for the first time, combines the complex non-planar fracture geometry with varying width and all the important gas flow mechanisms to efficiently analyze field production data from Marcellus shale. We analyzed several core measurements for methane adsorption from some area in Marcellus shale and found that the gas desorption behaviors of this case study deviate from the Langmuir isotherm, but obey the BET (Brunauer, Emmett and Teller) isotherm. To the best of our knowledge, such behavior has not been presented in the literature for shale gas reservoirs to behave like multilayer adsorption. The effect of different gas desorption models on calculation of original gas in place and gas recovery prediction was compared and analyzed. We developed an integrated reservoir simulation framework to perform sensitivity analysis, history matching, and economic optimization for shale gas and tight oil reservoirs by integrating several numerical reservoir simulators, the semi-analytical model, an economic model, two statistical methods, namely, Design of Experiment and Response Surface Methodology. Furthermore, an integrated simulation platform for unconventional reservoirs (ISPUR) was developed to generate multiple input files and choose a simulator to run the files more easily and more efficiently. The fracture cost was analyzed based on four different fracture designs in Marcellus shale. The applications of this framework to optimize fracture treatment design in Marcellus shale and optimize multiple well placement in Bakken tight oil reservoir were performed. This framework is effective and efficient for hydraulic fracture treatment design and production scheme optimization for single well and multiple wells in shale gas and tight oil reservoirs. We built a numerical reservoir model to simulate CO₂ injection using a huff-n-puff process with typical reservoir and fluid properties from the Bakken formation by considering the effect of CO₂ molecular diffusion. The simulation results show that the CO₂ molecular diffusion is an important physical mechanism for improving oil recovery in tight oil reservoirs. In addition, the tight oil reservoirs with lower permeability, longer fracture half-length, and more heterogeneity are more favorable for the CO₂ huff-n-puff process. This work can provide a better understanding of the key parameters affecting the effectiveness of CO₂ huff-n-puff in the tight oil reservoirs.Item Eagle Ford shale : evaluation of companies and well productivity(2016-08) Chavez Urbina, Grecia Alexandra; King, Carey Wayne, 1974-; Lake, Larry W.Unconventional resources, particularly shale reservoirs, are a significant component in oil and gas production in the United States as they represent (as of May 2015) 48 and 58 percent, respectively, of the total oil and gas produced. However, there has been a deceleration on oil and gas production in general because of low market prices. The drastic decline in oil and gas prices that started in 2014 has companies struggling to continue their operations, resulting in negative financial outcomes for 2015 for most companies. The present work examines the financial results of three companies, EOG Resources, Pioneer Natural Resources, and Chesapeake Energy, along with their particular well productivity using the Logistic Growth model to forecast production in one of the most prolific shale plays in the United States, the Eagle Ford. This work also examines the economic feasibility of drilling new wells when oil prices are low using a discounted cash flow model for each company. The financial analysis shows that from the three companies, Pioneer Natural Resources has the best financial results; its high cash-flow-to-debt ratio, and low debt and debt-to-equity ratios make it an attractive company to invest in. In contrast, Chesapeake has the worst results which represents high risk for investors, and EOG has moderate results that still make it a good company to invest in. The discounted cash flow model demonstrate that under the cost assumptions and estimated production used in this work, EOG gets the best results from their wells located in the Eagle Ford with break-even prices bordering the 40 $/bbl compared to the other companies with break-even prices above 87 $/bbl for Pioneer and 89 $/bbl for Chesapeake. From the discounted cash flow model, it can also be concluded that none of the companies in the analysis is expected to gain revenue from drilling new wells if oil prices are under 40 $/bbl, and that companies that are quick to respond to the low prices by reducing their drilling and completion costs can significantly improve their well economics.Item Evidence of Pressure Dependent Permeability in Long-Term Shale Gas Production and Pressure Transient Responses(2012-12-11) Vera Rosales, Fabian 1986-The current state of shale gas reservoir dynamics demands understanding long-term production, and existing models that address important parameters like fracture half-length, permeability, and stimulated shale volume assume constant permeability. Petroleum geologists suggest that observed steep declining rates may involve pressure-dependent permeability (PDP). This study accounts for PDP in three potential shale media: the shale matrix, the existing natural fractures, and the created hydraulic fractures. Sensitivity studies comparing expected long-term rate and pressure production behavior with and without PDP show that these two are distinct when presented as a sequence of coupled build-up rate-normalized pressure (BU-RNP) and its logarithmic derivative, making PDP a recognizable trend. Pressure and rate field data demonstrate evidence of PDP only in Horn River and Haynesville but not in Fayetteville shale. While the presence of PDP did not seem to impact the long term recovery forecast, it is possible to determine whether the observed behavior relates to change in hydraulic fracture conductivity or to change in fracture network permeability. As well, it provides insight on whether apparent fracture networks relate to an existing natural fracture network in the shale or to a fracture network induced during hydraulic fracturing.Item Evidence of Reopened Microfractures in Production Data of Hydraulically Fractured Shale Gas Wells(2012-10-19) Apiwathanasorn, SippakornFrequently a discrepancy is found between the stimulated shale volume (SSV) estimated from production data and the SSV expected from injected water and proppant volume. One possible explanation is the presence of a fracture network, often termed fracture complexity, that may have been opened or reopened during the hydraulic fracturing operation. The main objective of this work is to investigate the role of fracture complexity in resolving the apparent SSV discrepancy and to illustrate whether the presence of reopened natural fracture network can be observed in pressure and production data of shale gas wells producing from two shale formations with different well and reservoir properties. Homogeneous, dual porosity and triple porosity models are investigated. Sensitivity runs based on typical parameters of the Barnett and the Horn River shale are performed. Then the field data from the two shales are matched. Homogeneous models for the two shale formations indicate effective infinite conductivity fractures in the Barnett well and only moderate conductivity fractures in the Horn River shale. Dual porosity models can support effectively infinite conductivity fractures in both shale formations. Dual porosity models indicate that the behavior of the Barnett and Horn River shale formations are different. Even though both shales exhibit apparent bilinear flow behavior the flow behaviors during this trend are different. Evidence of this difference comes from comparing the storativity ratio observed in each case to the storativity ratio estimated from injected fluid volumes during hydraulic fracturing. In the Barnett shale case similar storativity ratios suggest fracture complexity can account for the dual porosity behavior. In the Horn River case, the model based storativity ratio is too large to represent only fluids from hydraulic fracturing and suggests presence of existing shale formation microfractures.Item Geologic setting and reservoir characterization of Barnett Formation in southeast Fort Worth Basin, central Texas(2014-08) Liu, Xufeng; Fisher, W. L. (William Lawrence), 1932-; Loucks, R. G.The Mississippian Barnett Formation is a prolific shale-gas reservoir that was deposited in the Fort Worth Basin, Texas. Many previous studies of the Barnett Formation have been conducted in the main production area; few studies have been made of the Barnett Formation in the southern part of the basin, which is a less productive area. In the present research, several cores from the Barnett Formation in Hamilton County, southeast Fort Worth Basin, are studied in detail. Two vertical, continuous cores from Hamilton County, Texas, were studied to delineate the depositional setting, lithofacies, pore types, and reservoir quality of the Barnett Formation in the area. Five lithofacies were defined by analysis of the two cores: (1) laminated clay-rich silty and skeletal peloidal siliceous mudstone; 2) laminated skeletal silty peloidal siliceous mudstone; 3) nonlaminated silty peloidal calcareous mudstone; 4) laminated and nonlaminated skeletal calcareous mudstone; and 5) skeletal phosphatic packstone to grainstone. As indicated from this study, the dominant organic matter type is a mixture of Type II (major) and Type III (minor) kerogen having a mean TOC content of approximately 4%. Analysis of Rock Eval data shows that most of the interval is within the oil window; calculated Ro is approximately 0.9%. Organic geochemistry shows that the hydrocarbon generation potential of the abundant oil-prone kerogen was excellent. Mineralogical analysis reveals that the two types of siliceous mudstone, which are similar in composition to the siliceous mudstone in the main producing area in the northern Fort Worth Basin, are good for hydraulic fracturing and production, but they are also limited by their marginal thickness. Organic matter pores, which are the dominant pore types in these two cores, are consistent with pore types found in currently producing wells in the Newark East Field. This research also suggests that the deposition of Barnett Formation was controlled largely by basinal geometry, suspension settling, and slope-originated gravity-flow events. Skeletal deposits and carbonate-silt starved ripples suggest gravity-flow deposits and bottom-current reworking during deposition. Redox-sensitive elements and degree of pyritization both indicate anoxic/euxinic conditions during the deposition of the Barnett Formation.Item The impact of cluster drilling technology on well productivity and profitability : a case study of the Fayetteville Shale play(2015-05) Hwang, Allen Thomas; Tinker, Scott W. (Scott Wheeler); Ikonnikova, SvetlanaHorizontal drilling and hydraulic fracturing in shale formations have led to a boom in the U.S. production of natural gas. After the commercial viability of the resource was proven, producers have been focused on innovative completion techniques to increase production and profit. While locations with high resource density and original gas in place can produce sufficient natural gas to make wells economical at relatively low prices, locations with low resource density appear non-viable. The objective of this study is to present an analysis of a new technology--cluster drilling--in the Fayetteville Shale development, highlighting the effect technology may have on well profitability. Inspired by the Fayetteville Shale-Production Outlook performed by the Bureau of Economic Geology (BEG) and funded by the Alfred P. Sloan Foundation, this study uses production history data, separating wells drilled as a cluster from analog non-cluster wells, to investigate changes in costs, production, and profitability. The study's well economics were analyzed with a discounted cash flow model that reflects how a change in a well production profile and drilling and completion costs will affect its profitability. The study uses individual well estimated ultimate recovery (EUR) projected using methods and well economics parameters reported by earlier studies of the play and investor presentations. The analysis produced several important results. First, on a per-well basis, non-cluster wells are, perhaps surprisingly, expected to recover more natural gas than cluster wells. Wells in the non-cluster drilling pattern outperform cluster wells in both productivity and profit. However, the well density of cluster drilling results in a higher recovery factor for a given volume of rock, thus a more thorough extraction of the resource. Second, while a cluster pattern produces more gas from a unit of volume, equating to a higher recovery factor, that production comes at higher cost. The analysis reveals the requisite reduction in drilling and completion costs for cluster wells to match profit levels of non-cluster wells in a given lease. Finally, the analysis suggests an operator may choose to forego monetary efficiency, measured by the present value index (PVI), for higher gas recovery factor provided by cluster drilling.Item Industry evolution : applications to the U.S. shale gas industry(2014-05) Grote, Carl August; Tinker, Scott W. (Scott Wheeler); Ikonnikova, SvetlanaThe present study applies evolutionary and resource-based firm theories to three of the most prominent U.S. shale gas basins – the Barnett, Fayetteville, and Haynesville plays. Rather than broadly considering a host of factors that enabled what has often been labelled a shale gas revolution, an evolutionary approach recognizes the internal agents that have long been in place, but were triggered by technical and economic developments. As geologic understanding, along with innovation and competitive environments, evolves in each play so too does the entire shale gas industry. Building upon the Bureau of Economic Geology shale gas study funded by the Sloan Foundation, this study offers data-driven analyses to test theories of industrial evolution as applied to shale gas plays. Each of the three focus plays has undergone introductory and growth phases as well as a maturation phase in which there is an evident shakeout of operators. Industries are theorized to enter decline phases, yet none of the plays here have definitively declined. Certain economic signals, however, indicate that a decline is imminent, albeit variable in timing and pace. Conceptualizing the entire shale gas industry as an amalgamation of individual and evolving plays correctly describes how the industry is able to rejuvenate its growth trajectory through investment in emerging plays. Although heterogeneous geology, engineering capabilities, and economic environment, particularly natural gas prices, complicate the economics of shale gas extraction, an evolutionary approach proves to be a useful tool in describing the historical development of individual plays as well as the entire shale industry. Importantly, this application sheds light on the future development of valuable shale resources.Item Multi-frac treatments in tight oil and shale gas reservoirs : effect of hydraulic fracture geometry on production and rate transient(2013-05) Khan, Abdul Muqtadir; Olson, Jon E.The vast shale gas and tight oil reservoirs in North America cannot be economically developed without multi-stage hydraulic fracture treatments. Owing to the disparity in the density of natural fractures in addition to the disparate in-situ stress conditions in these kinds of formations, microseismic fracture mapping has shown that hydraulic fracture treatments develop a range of large-scale fracture networks in the shale plays. In this thesis, an approach is presented, where the fracture networks approximated with microseismic mapping are integrated with a commercial numerical production simulator that discretely models the network structure in both vertical and horizontal wells. A novel approach for reservoir simulation is used, where porosity (instead of permeability) is used as a scaling parameter for the fracture width. Two different fracture geometries have been broadly proposed for a multi stage horizontal well, orthogonal and transverse. The orthogonal pattern represents a complex network with cross cutting fractures orthogonal to each other; whereas transverse pattern maps uninterrupted fractures achieving maximum depth of penetration into the reservoir. The response for a vii single-stage fracture is further investigated by comparing the propagation of the stage to be dendritic versus planar. A dendritic propagation is bifurcation of the hydraulic fracture due to intersection with the natural fracture (failure along the plane of weakness). The impact of fracture spacing to optimize these fracture geometries is studied. A systematic optimization for designing the fracture length and width is also presented. The simulation is motivated by the oil window of Eagle Ford shale formation and the results of this work illustrate how different fracture network geometries impact well performance, which is critical for improving future horizontal well completions and fracturing strategies in low permeability shale and tight oil reservoirs. A rate transient analysis (RTA) technique employing a rate normalized pressure (RNP) vs. superposition time function (STF) plot is used for the linear flow analysis. The parameters that influence linear flow are analytically derived. It is found that picking a straight line on this curve can lead to erroneous results because multiple solutions exist. A new technique for linear flow analysis is used. The ratio of derivative of inverse production and derivative of square root time is plotted against square root time and the constant derivative region is seen to be indicative of linear flow. The analysis is found to be robust because different simulation cases are modeled and permeability and fracture half-length are estimated.Item Multi-phase fluid-loss properties and return permeability of energized fracturing fluids(2012-05) Ribeiro, Lionel Herve Noel; Sharma, Mukul M.; Sepehrnoori, KamyWith the growing interest in low-permeability gas plays, foam fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain nonetheless rudimentary in comparison to other fracturing fluid technologies because of our limited understanding of multi-phase fluid-loss and phase behavior occurring in these complex fluids. This report assesses the fluid-loss benefits introduced by energizing the fracturing fluid. A new laboratory apparatus has been specifically designed and built for measuring the leak-off rates for both gas and liquid phases under dynamic fluid-loss conditions. This report provides experimental leak-off results for linear guar gels and for N2-guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the rock permeability, the foam quality, and the pressure drop are investigated. Analysis of dynamic leak-off data provide an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore-scale. This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leak-off into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. Our conclusions not only confirm, but add to the findings of McGowen and Vitthal (1996) for linear gels, and the findings of Harris (1985) for nitrogen foams.Item Numerical modeling of complex hydraulic fracture development in unconventional reservoirs(2014-12) Wu, Kan; Olson, Jon E.; Balhoff, Matthew T.Successful creations of multiple hydraulic fractures in horizontal wells are critical for economic development of unconventional reservoirs. The recent advances in diagnostic techniques suggest that multi-fracturing stimulation in unconventional reservoirs has often caused complex fracture geometry. The most important factors that might be responsible for the fracture complexity are fracture interaction and the intersection of the hydraulic and natural fracture. The complexity of fracture geometry results in significant uncertainty in fracturing treatment designs and production optimization. Modeling complex fracture propagation can provide a vital link between fracture geometry and stimulation treatments and play a significant role in economically developing unconventional reservoirs. In this research, a novel fracture propagation model was developed to simulate complex hydraulic fracture propagation in unconventional reservoirs. The model coupled rock deformation with fluid flow in the fractures and the horizontal wellbore. A Simplified Three Dimensional Displacement Discontinuity Method (S3D DDM) was proposed to describe rock deformation, calculating fracture opening and shearing as well as fracture interaction. This simplified 3D method is much more accurate than faster pseudo-3D methods for describing multiple fracture propagation but requires significantly less computational effort than fully three-dimensional methods. The mechanical interaction can enhance opening or induce closing of certain crack elements or non-planar propagation. Fluid flow in the fracture and the associated pressure drop were based on the lubrication theory. Fluid flow in the horizontal wellbore was treated as an electrical circuit network to compute the partition of flow rate between multiple fractures and maintain pressure compatibility between the horizontal wellbore and multiple fractures. Iteratively and fully coupled procedures were employed to couple rock deformation and fluid flow by the Newton-Raphson method and the Picard iteration method. The numerical model was applied to understand physical mechanisms of complex fracture geometry and offer insights for operators to design fracturing treatments and optimize the production. Modeling results suggested that non-planar fracture geometry could be generated by an initial fracture with an angle deviating from the direction of the maximum horizontal stress, or by multiple fracture propagation in closed spacing. Stress shadow effects are induced by opening fractures and affect multiple fracture propagation. For closely spaced multiple fractures growing simultaneously, width of the interior fractures are usually significantly restricted, and length of the exterior fractures are much longer than that of the interior fractures. The exterior fractures receive most of fluid and dominate propagation, resulting in immature development of the interior fractures. Natural fractures could further complicate fracture geometry. When a hydraulic fracture encounters a natural fracture and propagates along the pre-existing path of the natural fracture, fracture width on the natural fracture segment will be restricted and injection pressure will increase, as a result of stress shadow effects from hydraulic fracture segments and additional closing stresses from in-situ stress field. When multiple fractures propagate in naturally fracture reservoirs, complex fracture networks could be induced, which are affected by perforation cluster spacing, differential stress and natural fracture patterns. Combination of our numerical model and diagnostic methods (e.g. Microseismicity, DTS and DAS) is an effective approach to accurately characterize the complex fracture geometry. Furthermore, the physics-based complex fracture geometry provided by our model can be imported into reservoir simulation models for production analysis.Item Policy challenges to China's shale gas industry(2016-05) Clayton, William Travis; Busby, Joshua W.; Tsai, Chien-hsinAs a result of China’s significant position in the petroleum market, contributions to greenhouse gas emissions, and domestic pollution, Chinese policy makers and industry leaders are increasingly highlighting China’s vast reserves of shale gas. Although there is growing production of shale gas in China’s Sichuan Basin, China’s state targets for shale gas development are still unmet. Thus, this work analyzes China’s shale gas policy, which is implemented through tools such as the petroleum sharing agreement, tax regimes, pipeline access, pricing system, regulatory structures, and international programs. Data in this paper is derived from published reports by industry experts. In addition, I carried out 10 expert interviews for this project, with interviews in Houston and by telephone. This paper evaluates specific qualities that attract shale gas investment and reinforce a mutualistic relationship between petroleum companies and the government, and judges the qualities that harm this relationship and are hindering shale gas development. For example, China’s use of the sliding scale royalty, support for joint ventures, and research and development programs contribute to shale gas development. However, possible hindrances to China’s shale gas revolution include the production sharing agreement structure, the monopolization of conventional reserves by China’s national oil companies, the lack of competitive pipeline access, the unclear and excessive overlap of regulatory agencies, and several environmental concerns related to hydraulic fracturing. As a result, China’s shale gas revolution will likely be led by its National Oil Companies for the near future.Item Process Design, Simulation and Integration of Dimethyl Ether (DME) Production from Shale Gas by Direct and Indirect Methods(2014-08-11) Karagoz, SecginAs the energy demand is increasing constantly, sustainable energy resources are needed to meet this demand and enable economic stability. In order to attain this goal, researchers continue to develop new technologies and methods in the field of sustainable energy. Over the last decade, the U.S has witnessed substantial growth in shale gas production. Consequently, shale gas has become a competitive feedstock for usage as energy and production of chemicals and petrochemicals. A valuable product which may be obtained from shale gas is dimethyl ether (DME). Dimethyl ether can be used in many areas such as power generation, transportation fuel, and domestic heating and cooking. Dimethyl ether is currently produced from natural gas, coal and biomass through synthesis gas as an intermediate. Recently, the attention to DME has increased because of its potential in addressing energy security and environmental problems. DME is produced conventionally through two steps (indirect process) which are methanol synthesis and dehydration of the methanol to DME. Another way to produce DME is the direct synthesis of DME from syngas. In order to use DME as a fuel alternative, it must be produced at low cost in large quantities. The purpose of this study is to develop a process synthesis, simulation, and integration of a shale gas-to-DME plant by direct and indirect methods. Techno-economic analysis is carried out to assess the profitability of the base-case processes under current market conditions. A sensitivity analysis is also conducted to evaluate the process profitability under variable market conditions. Finally, the both methods are compared in terms of the fixed capital cost, operating cost, return on investment, and CO_(2) and water impact. Indirect and direct process simulation of commercial DME plant was carried out by Aspen Plus. The shale gas feedstock was taken from one of the wells in Barnett shale play. The DME production capacities of the base cases for the direct and indirect processes were set to 3,250 tonnes per day. The direct and indirect process flowsheets were synthesized using five and seven main processing steps, respectively. Pinch analysis was used to conduct heat integration of the process. As a result of study, it was found that the direct method has advantage over the indirect method in terms of the fixed capital cost, operating cost, return on investment, and CO_(2) impact. The capital investment of the direct production method is 25% less than the indirect method. The direct method is more economically attractive than the indirect method. When a sensitivity analysis is considered, the prices of methanol and shale gas are the most important factors impacting the operating cost. The contribution of energy integration on the ROI of the direct method is approximately 2.25%. The ROI of the indirect method is improved by 1.83% after energy integration. In contrast to the other criteria, the indirect way has significant advantage over the direct way by producing almost 1760 ton/d water. The direct method produces less CO_(2) emission than the indirect method because it uses dry reforming to convert CO_(2) to syngas.Item Rock classification from conventional well logs in hydrocarbon-bearing shale(2011-12) Popielski, Andrew Christopher; Torres-Verdín, Carlos; Balhoff, MatthewThis thesis introduces a rock typing method for application in shale gas reservoirs using conventional well logs and core data. Shale gas reservoirs are known to be highly heterogeneous and often require new or modified petrophysical techniques for accurate reservoir evaluation. In the past, petrophysical description of shale gas reservoirs with well logs has been focused to quantifying rock composition and organic-matter concentration. These solutions often require many assumptions and ad-hoc correlations where the interpretation becomes a core matching exercise. Scale effects on measurements are typically neglected in core matching. Rock typing in shale gas provides an alternative description by segmenting the reservoir into petrophysically-similar groups with k-means cluster analysis which can then be used for ranking and detailed analysis of depth zones favorable for production. A synthetic example illustrates the rock typing method for an idealized sequence of beds penetrated by a vertical well. Results and analysis from the synthetic example show that rock types from inverted log properties correctly identify the most organic-rich model types better than rock types detected from well logs in thin beds. Also, estimated kerogen concentration is shown to be most reliable in an under-determined problem. Field cases in the Barnett and Haynesville shale gas plays show the importance of core data for supplementing well logs and identifying correlations for desirable reservoir properties (kerogen/TOC concentration, gas saturation, and porosity). Qualitative rock classes are formed and verified using inverted estimates of kerogen concentration as a rock-quality metric. Inverted log properties identify 40% more of a high-kerogen rock type over well-log based rock types in the Barnett formation. A case in the Haynesville formation suggests the possibility of identifying depositional environments as a result of rock attributes that produce distinct groupings from k-means cluster analysis with well logs. Core data and inversion results indicate homogeneity in the Haynesville formation case. However, the distributions of rock types show a 50% occurrence between two rock types over 90 ft vertical-extent of reservoir. Rock types suggest vertical distributions that exhibit similar rock attributes with characteristic properties (porosity, organic concentration and maturity, and gas saturation). This method does not directly quantify reservoir parameters and would not serve the purpose of quantifying gas-in-place. Rock typing in shale gas with conventional well logs forms qualitative rock classes which can be used to calculate net-to-gross, validate conventional interpretation methods, perform well-to-well correlations, and establish facies distributions for integrated reservoir modeling in hydrocarbon-bearing shale.