Although existing models for analysing single-phase flowback water production at the onset of flowback in tight oil and gas reservoirs provide estimates of fracture volume, they are not applicable to shale gas reservoirs. This is because flowback data from shale gas wells do not show this single phase region. Instead, they show a surprising trend of immediate gas breakthrough. This paper attempts to (1) understand the fundamental reasons for this early gas breakthrough, (2) develop a representative mathematical model that describes this behaviour and (3) estimate the effective fracture volume and equivalent fracture half-length by history matching the early-time two-phase flowback data. From the diagnostic plots generated from of rate/pressure data of 8 multi-fractured horizontal wells completed in the Muskwa Formation, the gas-water ratio (GWR) plots indicate the presence of initial free gas in the complex fracture network. This conclusion is backed by the imbibition experiments conducted on shale samples collected from the same formation showing the presence of gas-saturated natural fractures. The linear diffusivity equation is solved for early-time two-phase gas/water flow in the hydraulic fractures. The primary drive mechanism at the onset of flowback is initial free gas expansion within the fracture network. Secondary drive mechanisms considered include fracture water expansion and fracture closure. The driving forces are modeled by an effective compressibility term analogous to the total compressibility in conventional multiphase flow formulations. Also, two-phase water/gas flow is handled by an explicitly determined relative permeability function of time. Eventually a new pseudo-time function is defined to account for the changes in gas properties and relative permeability with time. Rate normalized pseudo-pressure versus pseudo-time plots give a straight line when applied to field data, thus the solution can be used to characterize hydraulic fractures in a manner similar to conventional well testing methods.

Because today's oil and gas industry recognizes the value of coalbed methane (CBM) resources, CBM exploration and development activities, once uniquely North American, are now under way on a global scale. Many publications address technically recoverable resources (TRR) of CBM in small geographic areas. However, there is little publicly information about the magnitude of TRR for coalbed methane on a global scale. Uncertainty exists in geologic and engineering data and, consequently, in the results of calculations made with these data. The uncertainty of the problem begs for a probabilistic solution. Our objective was to determine distribution of CBM TRR worldwide. To achieve this goal, we developed a computer program, called Unconventional Gas Resource Assessment System (UGRAS). The program integrates a Monte Carlo technique with an analytical reservoir simulator. The combination provides an excellent means to predict production profiles for a wide variety of reservoir characteristics and producing conditions. Using UGRAS, we established the probabilistic distribution of original gas-in-place (OGIP), TRR and recovery factor (RF) for selected coals in U.S. and derived a representative recovery factor distribution for CBM reservoirs. CBM recovery factors follow a log-logistic distribution, with a P50 of 38%. We extended the distribution of gas recovery factors gained from our analyses of U.S. coals to estimate global CBM TRR. Global technically recoverable CBM is estimated to be 500 (P90) to 3,000 (P10) Tcf, with a P50 value of 1,600 Tcf. UGRAS is a robust tool that may be used to evaluate and rank coalbed methane gas resources worldwide. Results of this work verify the existence of significant technically recoverable coalbed methane resources worldwide and can guide industry to better target its exploitation efforts in coals, worldwide.

The Haynesville Shale is one of the largest unconventional gas fields in the US. It is also one of the deepest, with wells reaching more than 10,000 feet below ground. This uncommon depth and overpressure leads to initial reservoir pressures of up to 12,000 psi. These pressures are uniquely high among shale gas reservoirs, and require special treatment. We show that the methods developed by Patzek, et al., PNAS, 110, 19731-19736, can scale all individual wells' gas productions to fit upon a single, universal curve. Haynesville wells can take months or years for flowing tubing pressure to stabilize, so we modified the type curves to take this into account. Furthermore, we introduce a PVT solver in order to calculate gas properties at up to reservoir pressures. When we apply the scaling theory to 2,199 individual well productions in the Haynesville, we find 1,580 wells which have entered exponential decline due to pressure interference. We use a simple physical model to determine the time to interference for wells with geologic parameters typical of the Haynesville, and use this to determine a field-wide permeability from the wells where we have observed pressure interference. From this, we arrive at time to interference for the remainder of Haynesville wells, and use this to arrive at production forecasts for all individual wells.

Due to suppressed natural gas price in the past several years in North America, liquid-rich retrograde gas reservoir development has been the main focus for many gas reservoir operators in Canada. Due to the subsurface complexity of PVT behavior for condensate, liquid (condensate) production forecast has been a challenge for operators. In addition, many liquid-rich retrograde reservoirs have also encountered extremely low permeability, which makes the liquid production forecast an even more challenging task for operators. Today, the most common methodologies to analyze production performance for retrograde gas reservoirs are limited to either numerical (simulation) or empirical (such as Arps’ decline). However, for numerical analysis, original PVT properties, special core analysis (SCAL) and pressure history are required as input data, which are usually very costly to obtain and they are, therefore, routinely ignored by operators. This paper presents a simple way to predict condensate production from the gas production by means of readily available early years’ production data. This simple methodology includes a new specialized plot to find related parameters for condensate production forecast without any costly PVT and pressure history data. Moreover, a set of diagnostic plots has been developed to identify the degree of the blockage to the gas production from the near wellbore oil-bank. This new methodology has been tested on more than one hundred horizontal wells that have been producing retrograde gas from several Western Canadian formations, such as the Notikewin, Glauconite, Montney, Falher as well as the Eagle Ford formation in the United States. All such tests were carried out by using only the early part of the production data to history-match the later part of the production history. The results have shown good agreement with the forecast based on the new methodology. Both synthetic and real well examples will be presented in this paper to illustrate the use of this new methodology.

Shale gas production has been gaining worldwide attention over the past several years. This is due to the economic gas reserves using two current advanced technologies that are horizontal drilling and multistage hydraulic fracturing. Shale has a high total organic content (TOC) that may adsorb significant amount of natural gas. In addition, laboratory and theoretical calculations indicate that organic-rich shales adsorb CO 2 preferentially over CH 4 . Hence, the extent of organic matter in shale plays an important role in determining the feasibility of CO 2 injection with potential benefit of enhanced gas recovery (EGR). The performance of CO 2 injection and CH 4 recovery in shale reservoirs is a complex function of several engineering parameters including fracture half-length, fracture conductivity, and fracture height, operating parameters such as injection volume and injection time, and geologic parameters including reservoir permeability, porosity, and thickness. Nevertheless, the effects of the above uncertain parameters on the process of CO 2 -EGR are not clearly understood and systematically studied. Therefore, it is absolutely critical to quantify uncertainties and investigate the most important influential parameters controlling this process. In this paper, we employ numerical reservoir simulation techniques to model multiple hydraulic fractures and multi-component Langmuir isotherms. Two scenarios for CO 2 injection are investigated when the primary gas production decreases to the economic limit: (1) CO 2 flooding in two horizontal wells, and (2) CO 2 huff-n-puff in a horizontal well. A series of reservoir simulations based on Design of Experiment (DOE) are performed on the best scenario to investigate the critical parameters that control this CO 2 -EGR process in the Barnett Shale. This work enables operators to plan ahead of time and optimize a tertiary shale gas production process by considering the different investigated influential parameters.

Lately, the United States of America has experienced tremendous growth in shale plays development. To date, more than 5,000 wells have been drilled and completed in more than 20 fields. Worldwide, exploration and development of shale plays has also increased. Currently, due to low gas prices, operating companies are shifting resources to explore and develop condensate or oil producing shale plays. In 2010, exploration of gas-rich and possible liquid-rich shale reservoirs began in northern Mexico. The main challenges were to demonstrate the availability of reserves and set the foundation for future development of these plays, with the information gathered in a few exploratory wells. Wells were aimed at the upper cretaceous Eagle Ford formation and at the Jurassic Pimienta formation. As of July 2012, six horizontal exploratory wells were drilled and completed, implementing in four of them a two stage integrated workflow to achieve the objectives set. The drilling stage used a petrophysical and geomechanical static model to identify the most prospective interval in the reservoir, define the best drilling azimuth direction and landing point, and reduce drilling risk. Real-time geosteering was implemented to achieve the targeted navigation window. In the completion stage, a reservoir-centric completion and stimulation software, which integrates petrophysical and geomechanical data, was used to optimize the completion and stimulation design. Results were evaluated using various techniques, including micro seismic monitoring, production history matching, production logging and well testing. This study presents the details of the workflow implemented and the lessons learned in each well. The main lessons learned were: 1. Proper well landing was key to achieving predicted production and booking of reserves; 2. Anisotropic geomechanical models were the most appropriate for simulating hydraulic fracturing treatments; 3. Conventional hydraulic fracturing models do not always represent the behavior of fractures in the unconventional formations evaluated; 4. Production rates along the lateral of the well can vary significantly with single stages producing up to 20% of the total well production. The conclusions and lessons learned in this study have formed the bases and will be important to the subsequent development of the different shale plays in Mexico—and around the world.

Declining reservoir pressure and rate in the Jonah field has led to the common problem of liquid loading. As fluids accumulate the downhole pressure increases which decreases the available drawdown that allows fluids to flow into a wellbore. Jonah wells are completed in the 2000 - 3500-ft thick Lance Formation, using 8-16 hydraulic fracturing stages. With initial end of tubing (EOT) depths set above the top perforation for most wells, this left approximately 1500-3000 feet (gross pay) of perforations below the EOT. With lifting velocities significantly greater in larger diameter casing than tubing, a liquid column was developing below the EOT and engineering and operational attention was needed to improve field performance. Improving on the operational efficiency involved the implementation of recommended actions from a cross-functional well by well review group that received input and support from all Jonah asset members. The approach focused on how to improve liquid removal and optimize gas production from wells identified as liquid-loaded. In addition to installing plunger lift systems and injecting soaps, in 2008 a program was started to lower production tubing in wells by approximately 50-70% into perforations; the purpose was to reduce the column of fluid in the wellbore by helping more efficiently unload fluids using the reduced critical flow rate in the tubing and allowing plungers deeper access to the column of liquid covering the perforated interval. This paper discusses the results of lowering the EOT of over 100 gas producing wells in the Jonah field. The wells showed an average sustained uplift of approximately 105 mcfd, with undiscounted payout of less than 12 months. In addition, on wells that have had the tubing lowered, their decline curves appear to flatten out, offsetting anticipated double digit decline. Practical methods of selecting candidate wells and the new EOT are presented and discussed.

During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.

Over the last few decades, shale gas has become an increasingly important global source of natural gas, especially in the United States. According to Polczer (2009) and Krauss (2009) , shale gas will greatly expand worldwide and is expected to supply as much as half the natural gas production in North America by 2020. Due to extremely low shale matrix permeability, shale is considered an unconventional source of gas and requires fractures to provide a flow path to the wellbore. Due to uncertainties in quantifying the gas-in-place and identifying flow behavior; estimating the ultimate recoveries in shale gas reservoirs requires new techniques. In this paper, we used four approaches to estimate the ultimate recovery in shale gas wells: two empirical methods (conventional and modified decline curve analysis), analytical modeling and numerical modeling. All four approaches were applied on wells from four different shale plays (Barnett, Haynesville, Marcellus and Woodford).

We investigate coupled flow and geomechanics in gas production from extremely low permeability reservoirs such as tight and shale gas reservoirs, using coupled dynamically porosity and permeability during simulation. The intrinsic permeability is a step function of the status of material failure, and is updated every time step. We investigate the reservoirs with vertical and horizontal primary fractures, employing the single and double porosity models. We modify the multiple porosity constitutive relations for modeling double porous continua for flow and geomechanics. The numerical results indicate that production of gas causes redistribution of the effective stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs away from the primary fractures as well as near the fracture tips, which indicates generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which in turn causes a change in distribution of geomechanical variables. When the double porosity flow model is used, we observe a faster evolution of the enhanced permeability area than that obtained from the single porosity model because of the higher permeability of the fractures in the double porosity model. Additionally, we find that the complicated physics for stress sensitive reservoirs cannot properly be captured by uncoupled or decoupled methods, and thus tightly coupled flow and geomechanical models are highly recommended to accurately describe the reservoir behavior during gas production in tight and shale gas reservoirs.

This paper presents a new method for history matching production of shale gas wells and future forecasting. The method is based on linear dual porosity analytical solutions which includes horizontal wells with multistage fractures. A linear dual-porosity model assumes hydraulic fractures as a secondary porosity system and conduit to flow. Homogeneous matrix blocks are sources of primary porosity that feed fluids to the hydraulic fractures. A Systematic analysis was done to determine the main parameters affecting transient flow regimes. Since main flow regimes observed in the field are Bilinear and Linear, more attention was given to those regimes to match with the field data. Analytical solutions are modified for gas properties and desorption of gas from matrix surface. Besides constant bottomhole pressure production, variable bottomhole pressure cases are also included in this paper. The proposed method was applied to history match the production of shale gas wells from the Barnett, Woodford, and Fayetteville plays. The main parameters found from history matching are effective matrix and fracture permeabilities and fracture half-length. In wells with successful matches, future production can be forecast with some confidence.

Shale gas currently provides 20% of domestic supply, is targeted by half of the gas-directed drilling rigs, and represents the large majority of domestic resources. However, modern shale plays, their development strategies and their engineering analysis are young by comparison to those of conventional reservoirs. Uncertainty in shale gas reserves has significant implications at both the micro and macro levels. Conventional reservoir engineering tools must be viewed as potentially inadequate (or even inappropriate) for the evaluation of shale gas performance primarily because of the extremely low aggregate permeability of these systems, but also because of other unique aspects of the systems. Reservoir modeling (simulation) has an important role as an assessment and prediction tool; however, the character of the reservoir (induced and enhanced natural fractures) must be considered, as well as the geological and fluid characteristics. Rate-transient analysis (modern decline analysis) techniques are also more rigorous and have been expanded and adapted to fit the uniqueness of shale gas production. Application of each method for shale gas is discussed, including methods and limitations. These two techniques more closely represent the physics of shale gas production, but their implementation is often prohibitive. By way of necessity, much engineering evaluation is performed using Arps decline curve analysis. This technique is argued by some to be inappropriate due to a lack of theoretical support and demonstrated tendency to over-estimate reserves in tight gas systems. Given the limitations, practical methods exist to reduce error associated with its use. A newer decline method, power-law exponential, is also investigated.

There have been over 14,000 wells drilled and completed in the Cotton Valley sand of east Texas and north Louisiana, with more than 7,900 drilled and completed since 2003. (IHS 2010) All of these wells require multistage hydraulic fractures to economically produce. Well over 180 operators have an actively producing Cotton Valley sand well. With so many operators, there are numerous completion approaches used to optimize Cotton Valley sand production, and these strategies are ever evolving over time. The ultimate question from anyone who owns a Cotton Valley sand well is how to best complete it. By looking in-depth at more than 400 vertical Cotton Valley sand wells completed since 2003, we determined the impact of various completion parameters on production. For comparison purposes, we obtained production data on all wells and their offsets from publicly available. Well production was compared in various ways including: (1) offset wells within a 1-mi radius of the subject well; (2) normalized to the perforated interval; (3) decline trends of various completion types; and (4) delineating well groups based on production maps. Injection rate, fluid type (i.e., slickwater versus crosslinked gel), fluid volume, proppant type, proppant amount, number of stages, etc. were objectively compared with resultant production data ranging from 1- to 5-year spans. Those completion parameters that have a significant impact on production are identified and examined, along with those factors that do not correlate to production. Completion practices that sustain a flatter decline trend are also analyzed. Trends in the data were examined to steer the key design parameters that impact production in the Cotton Valley sand. A brief section discussing applicability of the results to other formations, including shale, is also discussed. General recommendations for a Cotton Valley sand completion are made based on the correlative production results.

Production performance forecasting and the estimated ultimate recovery (EUR) evaluation are two of several uncertainties in the study of tight gas reservoirs. Using the Arps’ decline curve analysis to extrapolate the estimated ultimate recovery (EUR), based on the future production forecasting, is still a widely employed engineering tool in the oil and gas industry today. Tight gas reservoirs usually have a long transient/transitional flow period due to its low permeability. Simply by using the best fit "b" value to estimate the best EUR could generate an error as much as 100% from the true EUR. There has been a number of technical papers published dealing with this issue. This paper will present a new improved methodology to determine a more accurate "b" value to be used in the Arps’ decline curve analysis for tight gas reservoirs. This new approach, using a newly developed relationship between Q cum , Q cum, t →∞ , q t and t, is more rigorous and much easier to use in comparison with all other existing ones. This new improved methodology will not only make future production forecasting more accurate, but also estimate the original-gas-in-place (OGIP) controlled by the well much easier. In Western Canadian Deep Basin, there are many extremely "tight" gas reservoirs that consist of multiple stacked shorefaces. Permeability in each shoreface varies very significantly, generally with the upper shoreface having a better permeability and the middle and lower ones having a permeability as poor as 0.01 mD. By using a reservoir simulator, a number of simulation runs have been performed by the author to answer the following questions: Could Fetkovich's b-values recommendation (mostly b<= 0.4 ~ 0.5 for single gas layer, b>=0.5 for multi-layer without crossflow) still be applied to the tight gas reservoirs? In a multi-stacked shoreface reservoir, does the lower perm zone contribute to the overall production? Moreover, how and when will it influence the production profile? When using the Arps’ decline curve analysis, what are the reasonable b-values to be used for the tight/stacked gas reservoirs? Both synthetic production decline profiles generated from simulation runs and a field example are presented in this paper to illustrate this new proposed methodology and to answer the above three questions.

Development of shale gas reservoirs has become an integral part of the North American gas supply. The Marcellus shale formation contains large amount of natural gas resources and its proximity to high demand markets along the East Coast of the United State makes it an attractive target for energy development. The economic viability of such unconventional gas development hinges on the effective stimulation of the low permeability reservoir rocks. Horizontal wells with multi-stage hydraulic fracturing treatments are the stimulation method of choice and have been successful in shale gas reservoirs. However, the fundamental science and engineering of the process are yet to be fully understood and hence the stimulation method needs to be optimized. In this paper, we used numerical reservoir simulation techniques and quantified the effect of the following pertinent factors on the well performances and long-term gas recovery: multiphase flow, proppant crushing, proppant diagenesis, reservoir compaction, capillary pressure, and operating conditions. The knowledge generated in this study enables engineers to better design fracture treatments and operators to better manage the wells in the Marcellus shale gas reservoirs.

The development of unconventional resources such as shale gas is one of the most promising trends in U.S. energy supplies that could have great potential for enhancing our energy independence and reducing carbon emissions. Many experts have called shale gas an "energy game changer" that could dramatically alter the energy supply picture for North America and potentially the world as other countries are just beginning to determine the extent of their own unconventional resources and are closely watching developments in North America. At the same time, however, the hydraulic fracturing technology that is critical to unlocking the vast tracks of shale gas located throughout the United States has drawn intense criticism from environmentalists and lawmakers concerned about the potential impact of hydraulic fracturing on water supplies and the environment. As a result of numerous health and environmental concerns raised, legislation commonly known as the FRAC Act was introduced in the 111 th Congress (2009–2010) calling for greater federal regulation over hydraulic fracturing and disclosure of the chemicals used in hydraulic fracturing operations. Additionally, in March 2010, the U.S. Environmental Protection Agency (EPA) announced that it will conduct a comprehensive research study to investigate the potential adverse impacts that hydraulic fracturing may have on water quality and public health. While the FRAC Act did not reach the floor of the 11 th Congress, some members of the 112 th Congress (2010–2012) have recently expressed their intention to re-introduce the FRAC Act in 2011. In the meantime, hydraulic fracturing continues to draw criticism from environmentalists and EPAs scrutiny over the industry is intensifying as EPAs study starts to take shape. This presentation will provide an overview of the legal, policy and environmental challenges associated with shale gas development in the United States. The presentation will first address the existing federal and state laws pertain to shale gas development in the United States and will also provide an analysis of any pending legislation. This presentation also provides a detailed analysis of the current EPA Study and the various environmental concerns that have been raised pertaining to hydraulic fracturing.

We combine a new pore-scale model with a reservoir simulation algorithm to predict gas production in gas-bearing shales. It includes an iterative verification method of surface mass balance to ensure real-time desorption-adsorption equilibrium with gas production. The pore-scale model quantifies macroscopic petrophysical properties of formations using an algorithm of gas transport in porous media that simultaneously considers the effects of no-slip and slip flow, Knudsen diffusion, and Langmuir desorption. Subsequently, the reservoir model populates petrophysical properties derived from the pore-scale analysis at every numerical grid and at each time-step to calculate the production history and pressure distribution in the reservoir. This approach examines the contribution of different transport processes (i.e. advective flow, Knudsen diffusion, and desorption) to quantify their corresponding contributions to overall flow. Previously, we showed that slip flow and Knudsen diffusion play a significant role in explaining the higher-than-expected permeability observed in shale-gas formations with pore-throat sizes in the range of nanometers. It is shown that Langmuir desorption from organic-matter surfaces is important in the calculation of stored gas in gas-bearing shales. Modeling results show that gas desorption maintains the reservoir pressure via the supply of gas. In comparison to conventional reservoir descriptions, the contributions of slip flow and Knudsen diffusion increase the apparent permeability of the reservoir while gas production takes place. The effects of both mechanisms explain the higher-than-expected gas production rates commonly observed in these formations.

The production of natural gas from shales traces back to the first well drilled in New York in 1821. Over the past 25 years, access to this resource has grown. Recent advancements in drilling and completion technology has enhanced well production rates and production from shales has increased to where it currently supplies 20% of the gas produced by all gas wells in the United States. Well performance data from these shale plays has been compiled and analyzed to develop insight into these tight reservoirs. These results are compared and contrasted to determine similarities and differences among the plays. Comparisons with classical gas reservoirs and tight gas reservoirs are made to provide additional insight.

The current paper complements the Moridis et al. (2009a) review of the status of the effort toward commercial gas production from hydrates. We aim to describe the concept of the gas hydrate petroleum system, to discuss advances, requirement and suggested practices in gas hydrate prospecting and GH deposit characterization, and to review the associated technical, economic and environmental challenges and uncertainties, including: the accurate assessment of producible fractions of the GH resource, the development of methodologies for identifying suitable production targets, the sampling of hydrate-bearing sediments and sample analysis, the analysis and interpretation of geophysical surveys of GH reservoirs, well testing methods and interpretation of the results, geomechanical and reservoir/well stability concerns, well design, operation and installation, field operations and extending production beyond sand-dominated GH reservoirs, monitoring production and geomechanical stability, laboratory investigations, fundamental knowledge of hydrate behavior, the economics of commercial gas production from hydrates, and the associated environmental concerns.

Abstract Gas shales are economically viable hydrocarbon prospects that have proven to be successful in North America. Unlike conventional hydrocarbon prospects, gas shales serve as the source, seal, and the reservoir rock. Generating commercial production from these unique lithofacies requires stimulation through extensive hydraulic fracturing. The absence of an accurate petrophysical model for these unconventional plays makes the prediction of economic productivity and fracturing success risky. This paper presents an integrated approach to petrophysical evaluation of shale gas reservoirs, specifically, the Barnett Shale from the Fort Worth basin is used as an example. The approach makes use of different formation evaluation data, including density, neutron, acoustic, nuclear magnetic resonance, and geochemical logging data. This combination of logging measurements is used to provide lithology, stratigraphy and mineralogy. It also differentiates source rock intervals, classifies depositional facies by their petrophysical and geomechanical properties, and quantifies total organic carbon. The analysis is also employed to locate optimal completion intervals, zones preferable for horizontal sections, and intervals of possible fracture propagation attenuation. Resistivity image analysis complements the approach with the identification of natural and drilling induced fractures. We compare results from three different wells to show the effectiveness of the method for shale gas characterization. The methodology presented provides a means to understand the geomechanical and petrophysical properties of the Barnett Shale. This knowledge can be used to design a selective completion strategy that has the potential to reduce fracturing expenses and optimize well productivity. Though developed specifically for the Barnett Shale, the underlying ideas are applicable to other thermogenic shale gas plays in North America. Introduction Numerous organic-rich shale sections located in some North American basins have been proven as productive natural gas plays (Jarvie et al., 2007; Martini et al., 2003; Pollastro et al., 2003; Pollastro et al., 2007; Pollastro, 2007). They extend over large geographical areas and offer sustainable reservoirs with attractive exploration and development costs (Hill and Nelson, 2000). Economic production from these complex, kerogen-rich formations, which typically possess poorly-defined gas-water contacts, natural fractures, and very low matrix permeability, depends heavily on the completion technology implemented for recovery. The primary strategy used for stimulating production is hydraulic fracturing, the scale of which can pose a major cost and challenge to producers (Mayerhofer et al., 2006). The challenge is mainly related to the difficulties involved in monitoring and predicting the propagation of the fracturing process through the strata in order to recover potential reserves (Le Calvez et al., 2006; Mayerhofer et al., 2006; Moore and Ramakrishnan, 2006). This uncertainty can be traced to the varying geomechanical properties associated with the complex lithofacies inherent in many shale gas sections. For this reason, shale gas lithofacies and their relation to reservoir stratigraphy and productivity has recently become a focus of producers (Bowker, 2007; Hickey and Henk, 2007). As a result, the ability to define and categorize in situ the complex lithofacies associated with shale gas plays according to kerogen content, mineralogy, and geomechanical properties has the potential to aid in reducing the costs involved in hydraulic fracturing and at the same time improve hydrocarbon recovery.