Permeability estimation in tight and shale reservoirs is challenging because little or no flow will occur without hydraulic fracture stimulation. In the pressure falloff following a fracture calibration test (FCT), radial flow after the fracture closure can be used to estimate the reservoir permeability. However, for very low permeability, the time to reach radial flow can exceed any practical duration. This study shows how to use the reservoir pressure to estimate the maximum reservoir permeability when radial flow is missing in the after-closure response. The approach is straightforward and can also be used for buildup tests. It applies whenever the well completion geometry permits radial flow before the pressure response encounters a real well drainage limits. Recent developments have blurred the boundary between fracture calibration test analysis and classic pressure transient analysis. Adapting the log-log diagnostic plot representation to the FCT analysis has made it possible to perform before and after closure analysis on the same diagnostic plot. This paper also proposes a method for diagnosing abnormal leakoff behavior using the log-log diagnostic plot as an alternative method for the traditional G-function plot. The results show the relationship between reservoir permeability and pressure can be used effectively for both estimation of the permeability upper bound when there is no apparent radial flow and for confirming the permeability estimated from apparent late time radial flow. Numerous field examples illustrate this simple and powerful insight.

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.

This study is a statistical analysis of the sandstone distribution within the Arkansas Jackfork Group which is a passive margin fan complex. Passive margin fan systems are typically associated with long fluvial transport, fed by deltas, wide shelf, efficient basin transport, that result in a bypassing system. Passive margin fans are generally fine-grained, mud rich, and well sorted. These fans can be separated into three units (upper, middle, and lower fan) based on their location within the fan and how the sediments are deposited. Five outcrops from the Arkansas Jackfork Group have been chosen for this study and each were divided into different facies dependent on sandstone percentages in certain bed sets. The amount of sandstone for each facies was calculated and a statistical approximation for each outcrop was determined. Sandstone distribution curves were made for each outcrop to show a graphic representation of how the sandstone is dispersed. After analyzing different upper, middle, and lower fan outcrops, it is clear there is an obvious change in the sandstone percentage and distribution. The upper fan deposit has an overall sandstone percentage of approximately 77.5% and is deposited in beds that are mainly amalgamated; 10-30m thick. Sandstone is deposited moderately even and is quite concentrated throughout the exposure. The middle fan outcrops contain approximately 72.6% sandstone and show similar patterns, except that the amalgamated sandstone beds are not as thick, 5-15m and contain more shale in between layers. As expected the lower fan outcrop is completely different in both sandstone percentage and distribution. The lower fan has approximately 65.4% sandstone. The distribution of sandstone is more concentrated in each of the individual units, or systems, but the overall complex has two systems separated by a massive marine shale bed, 33.5 m, that contains virtually no sand.

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.

Reserves estimation in unconventional (low/ultra-low permeability) reservoirs has become a topic of increased interest as more of these resources are being developed, especially in North America. The estimation of reserves in unconventional reservoirs is challenging due to the long transient flow period exhibited by the production data. The use of conventional methods (i.e., Arps' decline curves) to estimate reserves is often times inaccurate and leads to the overestimation of reserves because these models are only (theoretically) applicable for the boundary-dominated flow regime. The premise of this work is to present and demonstrate a methodology which continuously estimates the ultimate recovery during the producing life of a well in order to generate a time-dependent profile of the estimated ultimate recovery (EUR). The "objective" is to estimate the final EUR value(s) from several complimentary analyses. In this work we present the "Continuous EUR Method" to estimate reserves for unconventional gas reservoirs using a rate-time analysis approach. This work offers a coherent process to reduce the uncertainty in reserves estimation for unconventional gas reservoirs by quantifying "upper" and "lower" limits of EUR prior to the onset of boundary-dominated flow. We propose the use of traditional and new rate-time relations to establish the "upper" limit for EUR. We clearly demonstrate that rate-time relations which better represent the transient and transitional flow regimes (in particular the power law exponential rate decline relation) often lead to a more accurate "upper" limit for reserves estimates — earlier in the producing life of a well (as compared to conventional ("Arps") relations). Furthermore, we propose a straight line extrapolation technique to offer a conservative estimate of maximum produced gas which we use as the "lower" limit for EUR. The EUR values estimated using this technique continually increase with time, eventually reaching a maximum value. We successfully demonstrate the methodology by applying the approach to 43 field examples producing from 7 different tight sandstone and shale gas reservoirs. We show that the difference between the "upper" and "lower" limit of reserves decreases with time and converges to the "true" value of reserves during the latter producing life of a well.

Shale gas has become increasingly important to United States energy supply. During recent decades, the mechanisms of shale gas storage and transport were gradually recognized. Gas desorption was also realized and quantitatively described. Models and approaches special for estimating rate decline and recovery of shale gas wells were developed. As the strategy of the horizontal well with multiple transverse fractures (MTFHW) was discovered and its significance to economic shale gas production was understood, rate decline and pressure transient analysis models for this type of well were developed to reveal the well behavior. In this thesis, we considered a “Triple-porosity/Dual-permeability” model and performed sensitivity studies to understand long term pressure drawdown behavior of MTFHWs. A key observation from this study is that the early linear flow regime before interfracture interference gives a relationship between summed fracture half-length and permeability, from which we can estimate either when the other is known. We studied the impact of gas desorption on the time when the pressure perturbation caused by production from adjacent transference fractures (fracture interference time) and programmed an empirical method to calculate a time shift that can be used to qualify the gas desorption impact on long term production behavior. We focused on the field case Well A in New Albany Shale. We estimated the EUR for 33 wells, including Well A, using an existing analysis approach. We applied a unified BU-RNP method to process the one-year production/pressure transient data and performed PTA to the resulting virtual constant-rate pressure drawdown. Production analysis was performed meanwhile. Diagnosis plots for PTA and RNP analysis revealed that only the early linear flow regime was visible in the data, and permeability was estimated both from a model match and from the relationship between fracture halflength and permeability. Considering gas desorption, the fracture interference will occur only after several centuries. Based on this result, we recommend a well design strategy to increase the gas recovery factor by decreasing the facture spacing. The higher EUR of Well A compared to the vertical wells encourages drilling more MTFHWs in New Albany Shale.

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.

The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. Some operators are successfully producing shale oil using the same strategy. Due to its higher viscosity and eventual 2-phase flow conditions when the formation pressure drops below the oil bubble point pressure, shale oil is likely to be limited to lower recovery efficiency than shale gas. However, the recently discovered Eagle Ford shale formations is significantly over pressured, and initial formation pressure is well above the bubble point pressure in the oil window. This, coupled with successful hydraulic fracturing methodologies, is leading to commercial wells. This study evaluates the recovery potential for oil produced both above and below the bubble point pressure from very low permeability unconventional shale oil formations. We explain how the Eagle Ford shale is different from other shales such as the Barnett and others. Although, Eagle Ford shale produces oil, condensate and dry gas in different areas, our study focuses in the oil window of the Eagle Ford shale. We used the logarithmically gridded locally refined gridding scheme to properly model the flow in the hydraulic fracture, the flow from the fracture to the matrix and the flow in the matrix. The steep pressure and saturation changes near the hydraulic fractures are captured using this gridding scheme. We compare the modeled production of shale oil from the very low permeability reservoir to conventional reservoir flow behavior. We show how production behavior and recovery of oil from the low permeability shale formation is a function of the rock properties, formation fluid properties and the fracturing operations. The sensitivity studies illustrate the important parameters affecting shale oil production performance from the stimulated reservoir volume. The parameters studied in our work includes fracture spacing, fracture half-length, rock compressibility, critical gas saturation (for 2 phase flow below the bubble point of oil), flowing bottom-hole pressure, hydraulic fracture conductivity, and matrix permeability. The sensitivity studies show that placing fractures closely, increasing the fracture half-length, making higher conductive fractures leads to higher recovery of oil. Also, the thesis stresses the need to carry out the core analysis and other reservoir studies to capture the important rock and fluid parameters like the rock permeability and the critical gas saturation.

Identification of favorable production zones in hydrocarbon-bearing shale often requires the quantification of in-situ mechanical properties. These properties are also necessary for the optimal design of hydro-fracturing operations. Rock elastic properties are affected by volumetric concentrations of mineral constituents, porosity, fluid saturations, and total organic carbon (TOC). Rapid depth variations of rock properties often encountered in shale gas formations make conventional petrophysical interpretation methods inadequate to estimate volumetric concentration of mineral constituents. We introduce a new method to assess elastic properties of organic shale based on the combined quantitative interpretation of sonic, nuclear, and resistivity logs. In-situ elastic properties of organic shale are estimated by (a) improving the assessment of volumetric concentrations of mineral constituents, (b) implementing reliable rock physics models and mixing laws for organic shale, and (c) numerically reproducing wideband frequency dispersions of Stoneley and flexural waves. An example of the application of the method is described in the Haynesville shale gas formation. Estimates of mineral concentrations, porosity, and fluid saturations are in agreement with available laboratory core measurements and X-Ray Diffraction (XRD) data. Calculated layer-by-layer P- and S-wave velocities differ by less than 15% from measured velocities thus confirming the reliability of the method. Finally, based on the new interpretation method developed in this thesis, correlations are found between mineral concentrations, TOC, porosity, and rock elastic properties, which can be used in the selection of optimal production zones. / text

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. / text