Shale gas reservoirs are gaining importance in United States as conventional oil and gas resources are dwindling at a very fast pace. The purpose of this study is twofold. First aim is to help operators with simple screening criteria which can help them in making certain decisions while going after shale gas reservoirs. A guideline chart has been created with the help of available literature published so far on different shale gas basins across the US. For evaluating potential of a productive shale gas play, one has to be able to answer the following questions: 1. What are the parameters affecting the decision to drill a horizontal well or a vertical well in shale gas reservoirs? 2. Will the shale gas well flow naturally or is an artificial lift required post stimulation? 3. What are the considerations for stimulation treatment design in shale gas reservoirs? A comprehensive analysis is presented about different properties of shale gas reservoirs and how these properties can affect the completion decisions. A decision chart presents which decision best answers the above mentioned questions. Secondly, research focuses on production data analysis of Barnett Shale Gas reservoir. The purpose of this study is to better understand production mechanisms in Barnett shale. Barnett Shale core producing region is chosen for the study as it best represents behavior of Barnett Shale. A field wide moving domain analysis is performed over Wise, Denton and Tarrant County wells for understanding decline behavior of the field. It is found that in all of these three counties, Barnett shale field wells could be said to have established pressure communication within the reservoir. We have also studied the effect of thermal maturity (Ro %), thickness, horizontal well completion and vertical well completion on production of Barnett Shale wells. Thermal maturity is found to have more importance than thickness of shale. Areas with more thermal maturity and less shale thickness are performing better than areas with less thermal maturity and more shale thickness. An interactive tool is developed to access the production data according to the leases in the region and some suggestions are made regarding the selection of the sample for future studies on Barnett Shale.

The increasing interest and focus on unconventional reservoirs is a result of the industry's direction toward exploring alternative energy sources. It is due to the fact that conventional reservoirs are being depleted at a fast pace. Shale gas reservoirs are a very favorable type of energy sources due to their low cost and long-lasting gas supply. In general, according to Ausubel (1996), natural gas serves as a transition stage to move from the current oil-based energy sources to future more stable and environment-friendly ones. By looking through production history in the U.S Historical Production Database, HPDI (2009), we learn that the Barnett Shale reservoir in Newark East Field has been producing since the early 90's and contributing a fraction of the U.S daily gas production. Zhao et al. (2007) estimated the Barnett Shale to be producing 1.97 Bcf/day of gas in 2007. It is considered the most productive unconventional gas shale reservoir in Texas. By 2004 and in terms of annual gas production volume, Pollastro (2007) considered the Barnett Shale as the second largest unconventional gas reservoir in the United States. Many studies have been conducted to understand better the production controls in Barnett Shale. However, this giant shale gas reservoir is still ambiguous. Some parts of this puzzle are still missing. It is not fully clear what makes the Barnett well produce high or low amounts of gas. Barnett operating companies are still trying to answer these questions. This study adds to the Barnett chain of studies. It tests the effects of the following on Barnett gas production in the core area (Denton, Wise, and Tarrant counties): * Barnett gross thickness, including the Forestburg formation that divides Barnett Shale. * Perforation footage. * Perforated zones of Barnett Shale. Instead of testing these parameters on each well production decline curve individually, this study uses a new technique to simplify this process. Decline Map Analysis (DMA) is introduced to measure the effects of these parameters on all production decline curves at the same time. Through this study, Barnett gross thickness and perforation footage are found not to have any definite effects on Barnett gas production. However, zone 3 (Top of Lower Barnett) and zone 1 (Bottom of Lower Barnett) are found to contribute to cumulative production. Zone 2 (Middle of Lower Barnett) and zone 4 (Upper Barnett), on the other hand, did not show any correlation or influence on production through their thicknesses.

During the past decade, the worldwide demand for energy has continued to increase at a rapid rate. Natural gas has emerged as a primary source of US energy. The technically recoverable natural gas resources in the United States have increased from approximately 1,400 trillion cubic feet (Tcf) to approximately 2,100 trillion cubic feet (Tcf) in 2010. The recent declines in gas prices have created short-term uncertainties and increased the risk of developing natural gas fields, rendering a substantial portion of this resource uneconomical at current gas prices. This research quantifies the impact of changes in finding and development costs (FandDC), lease operating expenses (LOE), and gas prices, in the estimation of the economically recoverable gas for unconventional plays. To develop our methodology, we have performed an extensive economic analysis using data from the Barnett Shale, as a representative case study. We have used the cumulative distribution function (CDF) of the values of the Estimated Ultimate Recovery (EUR) for all the wells in a given gas play, to determine the values of the P10 (10th percentile), P50 (50th percentile), and P90 (90th percentile) from the CDF. We then use these probability values to calculate the technically recoverable resource (TRR) for the play, and determine the economically recoverable resource (ERR) as a function of FandDC, LOE, and gas price. Our selected investment hurdle for a development project is a 20 percent rate of return and a payout of 5 years or less. Using our methodology, we have developed software to solve the problem. For the Barnett Shale data, at a FandDC of 3 Million dollars, we have found that 90 percent of the Barnet shale gas is economically recoverable at a gas price of 46 dollars/Mcf, 50 percent of the Barnet shale gas is economically recoverable at a gas price of 9.2 dollars/Mcf, and 10 percent of the Barnet shale gas is economically recoverable at a gas price of 5.2 dollars/Mcf. The developed methodology and software can be used to analyze other unconventional gas plays to reduce short-term uncertainties and determine the values of FandDC and gas prices that are required to recover economically a certain percentage of TRR.

Water production is a challenge in production operations because it is generally costly to produce, treat, and it can hamper hydrocarbon production. This is especially true for gas wells in unconventional reservoirs like shale because the relatively low gas rates increase the economic impact of water handling costs. Therefore, we have considered the following questions regarding water production from shale gas wells: (1) What is the effect of water production on gas production? (2) What are the different water producing mechanisms? and (3) What is the water production potential of a new well in a given gas shale province. The first question was answered by reviewing relevant literature, highlighting observed deficiencies in previous approaches, and making recommendations for future work. The second question was answered using a spreadsheet based Water-Gas-Ratio analysis tool while the third question was investigated by using artificial neural networks (ANN) to decipher the relationship between completion, fracturing, and water production data. We will consequently use the defined relationship to predict the average water production for a new well drilled in the Barnett Shale. This study also derived additional insight into the production trends in the Barnett shale using standard statistical methods. The following conclusions were reached at the end of the study: 1) The observation that water production does not have long term deleterious effect on gas production from fractured wells in tight gas sands cannot be directly extended to fractured wells in gas shales because the two reservoir types do not have analogous production mechanisms. 2) Based on average operating conditions of well in the Barnett Shale, liquid loading was found to be an important phenomenon; especially for vertical wells. 3) A neural network was successfully used to predict average water production potential from a well drilled in the Barnett shale. Similar methodology can be used to predict average gas production potential. Results from this work can be utilized to mitigate risk of water problems in new Barnett Shale wells and predict water issues in other shale plays. Engineers will be provided a tool to predict potential for water production in new wells.

In 2007, the Barnett Shale in the Fort Worth basin of Texas produced 1.1 trillion cubic feet (Tcf) gas and ranked second in U.S gas production. Despite its importance, controls on Barnett Shale gas well performance are poorly understood. Regional and vertical variations of reservoir properties and their effects on well performances have not been assessed. Therefore, we conducted a study of Barnett Shale stratigraphy, petrophysics, and production, and we integrated these results to clarify the controls on well performance. Barnett Shale ranges from 50 to 1,100 ft thick; we divided the formation into 4 reservoir units that are significant to engineering decisions. All but Reservoir Unit 1 (the lower reservoir unit) are commonly perforated in gas wells. Reservoir Unit 1 appears to be clay-rich shale and ranges from 10 to 80 ft thick. Reservoir Unit 2 is laminated, siliceous mudstone and marly carbonate zone, 20 to 300 ft thick. Reservoir Unit 3 is composed of multiple, stacked, thin (~15-30 ft thick), upward coarsening sequences of brittle carbonate and siliceous units interbedded with ductile shales; thickness ranges from 0 to 500 ft. Reservoir Unit 4, the upper Barnett Shale is composed dominantly of shale interbedded with upward coarsening, laterally persistent, brittle/ductile sequences ranging from 0 to 100 ft thick. Gas production rates vary directly with Barnett Shale thermal maturity and structural setting. For the following five production regions that encompass most of the producing wells, Peak Monthly gas production from horizontal wells decreases as follows: Tier 1 (median production 60 MMcf) to Core Area to Parker County to Tier 2 West to Oil Zone-Montague County (median production 10 MMcf). The Peak Monthly oil production from horizontal wells is in the inverse order of gas production; median Peak Monthly oil production is 3,000 bbl in the Oil Zone-Montague County and zero in Tier 1. Generally, horizontal wells produce approximately twice as much oil and gas as vertical wells.This research clarifies regional variations of reservoir and geologic properties of the Barnett Shale. Result of these studies should assist operators with optimization of development strategies and gas recovery from the Barnett Shale.

In 2007, the Barnett Shale in the Fort Worth basin of Texas produced 1.1 trillion cubic feet (Tcf) gas and ranked second in U.S gas production. Despite its importance, controls on Barnett Shale gas well performance are poorly understood. Regional and vertical variations of reservoir properties and their effects on well performances have not been assessed. Therefore, we conducted a study of Barnett Shale stratigraphy, petrophysics, and production, and we integrated these results to clarify the controls on well performance. Barnett Shale ranges from 50 to 1,100 ft thick; we divided the formation into 4 reservoir units that are significant to engineering decisions. All but Reservoir Unit 1 (the lower reservoir unit) are commonly perforated in gas wells. Reservoir Unit 1 appears to be clay-rich shale and ranges from 10 to 80 ft thick. Reservoir Unit 2 is laminated, siliceous mudstone and marly carbonate zone, 20 to 300 ft thick. Reservoir Unit 3 is composed of multiple, stacked, thin (~15-30 ft thick), upward coarsening sequences of brittle carbonate and siliceous units interbedded with ductile shales; thickness ranges from 0 to 500 ft. Reservoir Unit 4, the upper Barnett Shale is composed dominantly of shale interbedded with upward coarsening, laterally persistent, brittle/ductile sequences ranging from 0 to 100 ft thick. Gas production rates vary directly with Barnett Shale thermal maturity and structural setting. For the following five production regions that encompass most of the producing wells, Peak Monthly gas production from horizontal wells decreases as follows: Tier 1 (median production 60 MMcf) to Core Area to Parker County to Tier 2 West to Oil Zone-Montague County (median production 10 MMcf). The Peak Monthly oil production from horizontal wells is in the inverse order of gas production; median Peak Monthly oil production is 3,000 bbl in the Oil Zone-Montague County and zero in Tier 1. Generally, horizontal wells produce approximately twice as much oil and gas as vertical wells.This research clarifies regional variations of reservoir and geologic properties of the Barnett Shale. Result of these studies should assist operators with optimization of development strategies and gas recovery from the Barnett Shale.

The goal of the present work is to improve shale reservoir stimulation treatment by using ultra light weight proppants in fracturing fluids. Slickwater has become the most popular fracturing fluid for fracturing shales in recent times because it creates long and skinny fractures and it is relatively cheap. The problem with slickwater is the high rate of settling of common proppants, e.g. sand, which results in propped fractures which are much smaller than the original fractures. Use of gels can help in proppant transport but introduce large formation damage by blocking pores in nano-darcy shales. Gel trapping in the proppant pack causes reduction in permeability of the proppant pack. The light weight proppants which can easily be transported by slickwater and at the same time be able to provide enough fracture conductivity may solve this problem. Three ultra light weight proppants (ULW1, ULW2, and ULW3) have been studied. The mechanical properties of the proppant packs as well as single proppants have been measured. Conductivity of proppant packs has been determined as a function of proppant concentration and confining stress at an average Barnett shale temperature of 95oC. The crush strengths of all the three proppant packs are higher than typical stresses encountered (e.g., Barnett). ULW1 and ULW2 are highly deformable and do not produce many fines. ULW3 has a higher Young’s modulus and produces fines. Conventionally, the proppant conductivity decreases with decreasing proppant concentration and increasing confining stress. But in cases of ULWs, for a partial monolayer, conductivity can be as large as that of a thick proppant pack. The settling velocity is the lowest for ULW1, intermediate for ULW2 and the highest for ULW3. This work contributes new mechanical, conductivity, and settling data on three ultra light weight proppants. Application of light weight proppants in stimulation treatments in shale reservoirs can lead to large propped fractures, which can improve the productivity of fractured shale reservoirs. / text

Horizontal drilling and hydraulic fracture stimulation have enabled the economic development of unconventional resource plays. An average horizontal well in the Barnett Shale requires 3 to 4 million gallons of fresh water, 90% of which is used for hydraulic fracture stimulation. While the water consumption of Barnett Shale operations is less than 1% of total Region C consumption, extended drought conditions and competing demands for water resources are placing pressure on operators to reduce terminal water consumption. Strategies which reduce water requirements associated hydraulic fracture stimulation without compromising the efficiency and cost of energy production are essential in developing a comprehensive policy on energy-water management. Recycling and reuse technologies were evaluated on the basis of performance, cost, and capacity to treat reclaimed flowback water and oilfield brine. Recycling flowback fluids for future hydraulic fracture applications is the most practical repurposing of oilfield waste. The low TDS content of flowback derived from water-based fracs permits multiple treatment options. Mobile thermal distillation technology has emerged as the prevailing technique for recycling flowback water, yielding maximum water savings and reduced operating costs. The estimated cost of recycling flowback water by thermal distillation is $3.35/bbl. Compared to the current cost of disposal, recycling provides an opportunity to minimize waste and reduce the fresh water requirements of hydraulic fracture stimulation at an incremental cost. The stewardship role of the Texas Legislature is to protect the water resources of the state and to facilitate the Regional Water Planning Process, ensuring future water needs are met. The support and participation of the Legislature and other planning entities is critical in advancing the energy-water nexus. As operators pursue innovative water management practices to reduce terminal water consumption in the oilfield, the Barnett Shale positions itself as a model for sustainable water use in the development of unconventional shale resources. The cost of recycling and reuse technology limits the participation of small and mid-size operators who possess the greatest market share of the Barnett Shale. Funding for research and implementation of water-conscious strategies such as shared recycling facilities, CO2 capture and storage, and pipeline infrastructure would create multi-user opportunities to promote conservation and reduce net consumption of fresh water supplies. Through the integration of technology and policy, terminal water consumption in the Barnett Shale can be greatly diminished. / text

The 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. / text

The relationship between shale gas development and budgetary and microeconomic externalities was studied. The extraction activity in the Barnett shaleformation provided a case study for assessing per-well highway infrastructure damage and water usage. The creation of a predictive model based upon the Barnett was applied to the Marcellus formation. The results showed support for the hypothesis that shale gas development creates negative externalities that amount to unfunded mandates and freerider problems for states and localities. Implications and policy solutions, including the case for a Pennsylvania natural gas fund, are discussed. / McAnulty College and Graduate School of Liberal Arts; / Graduate Center for Social and Public Policy / MA; / Thesis;