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.

Fractured reservoirs have been traditionally idealized using dual-porosity models. In these models, all matrix and fractures systems have identical properties. However, it is not uncommon for naturally fractured reservoirs to have orthogonal fractures with different properties. In addition, for hydraulically fractured reservoirs that have preexisting natural fractures such as shale gas reservoirs, it is almost certain that these types of fractures are present. Therefore, a triple-porosity (dual-fracture) model is developed in this work for characterizing fractured reservoirs with different fractures properties. The model consists of three contiguous porous media: the matrix, less permeable micro-fractures and more permeable macro-fractures. Only the macro-fractures produce to the well while they are fed by the micro-fractures only. Consequently, the matrix feeds the micro-fractures only. Therefore, the flow is sequential from one medium to the other. Four sub-models are derived based on the interporosity flow assumption between adjacent media, i.e., pseudosteady state or transient flow assumption. These are fully transient flow model (Model 1), fully pseudosteady state flow model (Model 4) and two mixed flow models (Model 2 and 3). The solutions were mainly derived for linear flow which makes this model the first triple-porosity model for linear reservoirs. In addition, the Laplace domain solutions are also new and have not been presented in the literature before in this form. Model 1 is used to analyze fractured shale gas horizontal wells. Non-linear regression using least absolute value method is used to match field data, mainly gas rate. Once a match is achieved, the well model is completely described. Consequently, original gas in place (OGIP) can be estimated and well future performance can be forecasted.

The Copper Creek thrust fault in the southern Appalachians places Cambrian over Ordovician sedimentary strata. The fault accommodated displacement of 15-20 km at 100-180 °C. Along the hanging wall-footwall contact, microstructures within a ~2 cm thick calcite and shale shear zone suggest that calcite, not shale, controlled the rheology of the shear zone rocks. While shale deformed brittley, plasticity-induced fracturing in calcite resulted in ultrafine-grained (<1.0 μm) fault rocks that deformed by grain boundary sliding (GBS) accommodated primarily by diffusion creep, suggesting low flow stresses. Optical and electron microscopy of samples from a transect across the footwall shale into the shear zone, shows the evolution of rheology within the shear zone. Sedimentary laminations 1 cm below the shear zone are cut by minor faults, stylolites, and fault-parallel and perpendicular calcite veins. At vein intersections, calcite grain size is reduced (to ~0.3 μm), and microstructures include inter-and-intragranular fractures, four-grain junctions, and interpenetrating boundaries. Porosity rises to 6 percent from <1 percent in coarse (25 μm) areas of calcite veins. In coarse-grained calcite, trails of voids follow twin boundaries, and voids occur at twin-twin and twin-grain boundary intersections. At the shear zone-footwall contact, a 350 μm thick calcite band contains coarseand ultrafine-grained layers. Ultrafine-grained (~0.34 μm) layers contain microstructures similar to those at vein intersections in the footwall and display no lattice-preferred orientation (LPO). Coarse-grained layers cross-cut grain-boundary alignments in the ultrafine-grained layers; coarse grains display twins and a strong LPO. Within the shear zone, ultrafine-grained calcite-aggregate clasts and shale clasts (5-350 μm) lie within an ultrafine-grained calcite (<0.31 μm) and shale matrix. Ultrafinegrained calcite (<0.31 μm) forms an interconnected network around the matrix shale. Calcite vein microstructures suggest veins continued to form during deformation. Fractures at twin-twin and twin-grain boundary intersections suggest grain size reduction by plasticity-induced fracturing, resulting in <1 μm grains. Interpenetrating boundaries, four-grain junctions, and no LPO indicate the ultrafine-grained calcite deformed by viscous grain boundary sliding. The evolution of the ultrafine-grain shear zone rocks by a combination of plastic and brittle processes and the deformation of the interconnected network of ultrafine-grained calcite by viscous GBS enabled a large displacement along a narrow fault zone.

It was observed that many hydraulically fractured horizontal shale gas wells exhibit transient linear flow behavior. A half-slope on a type curve represents this transient linear flow behavior. Shale gas wells show a significant skin effect which is uncommon in tight gas wells and masks early time linear behavior. Usually 70-85 percent of frac water is lost in the formation after the hydraulic fracturing job. In this research, a shale gas well was studied and simulated post hydraulic fracturing was modeled to relate the effect of frac water to the early significant skin effect observed in shale gas wells. The hydraulically fractured horizontal shale gas well was described in this work by a linear dual porosity model. The reservoir in this study consisted of a bounded rectangular reservoir with slab matrix blocks draining into neighboring hydraulic fractures and then the hydraulic fractures feed into the horizontal well that fully penetrates the entire rectangular reservoir. Numerical and analytical solutions were acquired before building a 3D 19x19x10 simulation model to verify accuracy. Many tests were conducted on the 3D model to match field water production since initial gas production was matching the analytical solutions before building the 3D simulation model. While some of the scenarios tested were artificial, they were conducted in order to reach a better conceptual understanding of the field. Increasing the water saturation in the formation resulted in increasing water production while lowering gas production. Adding a fractured bottom water layer that leaked into the hydraulic fracture allowed the model to have a good match of water and gas production rates. Modeling trapped frac water around the fracture produced approximately the same amount of water produced by field data, but the gas production was lower. Totally surrounding the fracture with frac water blocked all gas production until some of the water was produced and gas was able to pass through. Finally, trapped frac water around the fracture as combined with bottom water showed the best results match. It was shown that frac water could invade the formation surrounding the hydraulic fracture and could cause formation damage by blocking gas flow. It was also demonstrated that frac water could partially block off gas flow from the reservoir to the wellbore and thus lower the efficiency of the hydraulic fracturing job. It was also demonstrated that frac water affects the square root of time plot. It was proven by simulation that the huge skin at early time could be caused by frac water that invades and gets trapped near the hydraulic fractures due to capillary pressure.

Hydraulic fracturing of transverse isotropic reservoirs is of major interest for reservoir stimulation and in-situ stress estimation. Rock fabric anisotropy not only causes in-situ stress anisotropy, but also affects fracture initiation from the wellbore. In this study a semi-analytical method is used to investigate these effects with particular reference to shale stimulation. Using simplifying assumptions, equations are derived for stress distribution around the wellbore's walls. The model is then used to study the fracture initiation pressure variations with anisotropy. A sensitivity analysis is carried out on the impact of Young's modulus and Poisson's ration, on the fracture initiation pressure. The results are useful in designing hydraulic fractures and also can be used to develop information about in-situ rock properties using failure pressure values observed in the field. Finally, mechanical and permeability anisotropy are measured using Pulse Permeameter and triaxial tests on Pierre shale.

The purpose of this study is to identify and analyze the geochemical facies of the Hushpuckney Shale using XRF scanning data and the bioturbation indices, which will contribute to a better understanding of the biogeochemical environment prevalent during the deposition of the Hushpuckney Shale. The Hushpuckney Shale Member of the Swope Formation (Kasimovian Stage) preserved in KGS Spencer core 2 - 6, consists of a black shale submember overlain by bioturbated gray shale. Millimeter-scale core description and analysis of XRF scanning data enables identification of geochemical facies within the study core and contributes to understanding the environment of shale deposition. The XRF spectrometer produces X-ray image of the core and abundance values of selected major and trace elements, including iron (Fe), calcium (Ca), sulfur (S), molybdenum (Mo), zinc (Zn), vanadium (V), chromium (Cr), copper (Cu), nickel (Ni), titanium (Ti), zircon (Zr), potassium (K) and phosphorous (P). Canfield and Thamdrup's (2009) classification of geochemical environments is used to recognize oxic/aerobic, manganous-nitrogenous, ferruginous and sulfidic facies within the black shale submember. A modification of Droser and Bottjer's (1986) semi-quantitative field classification of bioturbation is used to identify facies variations within the gray shale submember. Abundance of apatite nodules and lamina in the black shale submember of the study core suggest that black shale sediments accumulated slowly in a sediment-starved basin. A high abundance of sulfide-scavenged elements, including Mo, Zn, V, Ni and Cr, identifies the sulfidic facies in the black shale submember, and indicates deposition in an oxygen-depleted environment with a high concentration of hydrogen sulfide. The overlying ferruginous facies has lower abundances of sulfide-scavenged elements and lacks cryptic Fe-laminations. The uppermost black shale submember facies, the manganous-nitrogenous facies, has cryptic Fe laminations and a relatively high P/Ca ratio. Abundance of cryptic iron laminations and apatite nodules and lamina indicates the syngenetic deposition of iron and phosphate due to Fe-P coupling mechanism. The gray shale submember is burrowed, indicating deposition under oxygenated conditions. Bioturbation indices reveal the variations in the intensity and nature of burrows within the gray shale, which corresponds to the changes in the depositional environment that may be related to the rise and fall of sea-level.

Production forecasting in shale (ultra-low permeability) gas reservoirs is of great interest due to the advent of multi-stage fracturing and horizontal drilling. The well renowned production forecasting model, Arps? Hyperbolic Decline Model, is widely used in industry to forecast shale gas wells. Left unconstrained, the model often overestimates reserves by a great deal. A minimum decline rate is imposed to prevent overestimation of reserves but with less than ten years of production history available to analyze, an accurate minimum decline rate is currently unknown; an educated guess of 5% minimum decline is often imposed. Other decline curve models have been proposed with the theoretical advantage of being able to match linear flow followed by a transition to boundary dominated flow. This thesis investigates the applicability of the Stretched Exponential Production Decline Model (SEPD) and compares it to the industry standard, Arps' with a minimum decline rate. When possible, we investigate an SEPD type curve. Simulated data is analyzed to show advantages of the SEPD model and provide a comparison to Arps' model with an imposed minimum decline rate of 5% where the full production history is known. Long-term production behavior is provided by an analytical solution for a homogenous reservoir with homogenous hydraulic fractures. Various simulations from short-term linear flow (~1 year) to long-term linear flow (~20 years) show the ability of the models to handle onset of boundary dominated flow at various times during production history. SEPD provides more accurate reserves estimates when linear flow ends at 5 years or earlier. Both models provide sufficient reserves estimates for longer-term linear flow scenarios. Barnett Shale production data demonstrates the ability of the models to forecast field data. Denton and Tarrant County wells are analyzed as groups and individually. SEPD type curves generated with 2004 well groups provide forecasts for wells drilled in subsequent years. This study suggests a type curve is most useful when 24 months or less is available to forecast. The SEPD model generally provides more conservative forecasts and EUR estimates than Arps' model with a minimum decline rate of 5%.

This study implies a survey of a somewhat unexplored Cambrian carbonate formation in the Argentine Precordillera (AP) located in western Argentina, close to the city of San José de Jáchal. The carbonate platform of the AP is a unique piece of the South American geology and is in this study partly surveyed and compared with the Stephen Formation of northern Canada, a middle Cambrian unit renowned for its contents of exceptionally well preserved soft bodied fossils named the Burgess Shale biota. The investigated formation consists of an olistolith among the several Los Túneles Olistoliths at the Western Precordillera. The olistolith originates from the Cambrian Period and lies embedded in younger material with an age and history up for debate by several paleontologists and biostratigraphers. Shallow investigations have shown that these rocks may have similar properties to rocks of the Stephen Formation. There are only a few known rock assemblages on Earth showing Burgess Shale-type (BST) preservation and if the Los Túneles Olistolith proves to possess BST preservation it would be of great substance for the geological researchers of Argentina. The olistolith has in this study been explored by gathering samples in field and dissolving them in acid to investigate possible fossil content. The aim is thus to ascertain whether or not the Los Túneles Olistolith may contain especially well preserved fossils. This is the first study ever made of the microfauna in a middle Cambrian unit in the whole of South America, and hence it will tell if further investigations would be of interest. This survey determines that the Los Túneles Olistolith actually consists of three olistoliths encased in matrix, do not contain BST preservation and that further studies are not probable to show otherwise. The fossil findings, such as Chancelloriidae Chancelloria, Hexactinellida Recticulosa and Mollusca Hyolitha establish that the three Los Túneles Olistoliths originate from middle Cambrian while the matrix surrounding the olistolith is determined to be of Devonian age. / Den här studien är den första undersökningen någonsin som fokuserar på mikrofauna i sedimentära avlagringar från mellersta kambrium i Sydamerika. Studien utreder en tidigare bara ytligt utforskad kalkstensformation i västra Argentina, nära staden San José de Jáchal, i den argentinska precordilleran. Formationen, med namnet Los Sombreros Formationen, innehåller olistoliter från kambrium som undersökts och jämförts med den välkända Stephen Formation från norra Kanada, en formation som är känd för att innehålla exceptionellt välbevarade mjukdelar av fossil, kallat the Burgess Shale Biota. Syftet med studien är att fastställa huruvida Los Túneles Olistoliterna har potential att innehålla välbevarade fossil samt att utreda ifall ytterligare undersökningar är av intresse eller ej.                       Studien fokuserar på vad som tidigare trotts vara en av olistoliterna bland Los Túneles Olistoliterna, som är en del av Los Sombreros Formationen, men som i denna studie visat sig egentligen vara tre olika olistoliter som avsatts intill varandra. Tidigare ytliga undersökningar har visat att dessa olistoliter skulle kunna innehålla liknande fossil som the Stephen Formation. Det finns bara ett fåtal platser i världen där så pass exceptionellt välbevarade fossil tidigare hittats och om Los Túneles Olistoliterna skulle visa sig vara ett nytt fynd skulle det vara av betydelse för den fortsatta geologiska forskningen i Argentina. Genom insamling av prover som upplösts i syra och sedan undersökts i mikroskop har slutsatsen dragits att Los Túneles Olistoliterna inte innehåller Burgess Shale Biota och att ytterligare undersökningar förmodligen inte kommer visa annorlunda resultat. Fossilfynden som har gjorts, så som Chancelloriidae Chancelloria, Hexactinellida Recticulosa och Mollusca Hyolitha fastställer att de tre Los Túneles Olistoliterna härstammar från mellersta kambrium medan omkringliggande material kommer från Devon. / Este estudio se enfoca en un área poco explorada de una formación que aloja olistolitos carbonaticos del Cámbrico y Ordovícico situado en la Precordillera de Argentina en el oeste del país, cerca de San José de Jáchal, Provincia de San Juan. La plataforma carbonatada de la precordillera es una parte única de la geología de Sudamérica y es en esta investigación parcialmente estudiada y comparada con la Formación Stephen en el norte de Canadá, una unidad del Cámbrico Medio famosa por su contenido de fósiles excepcionalmente bien preservados llamado the Burgess Shale biota.                       La investigación se ha enfocado en un olistolito entre los varios que aparecen en el sector Los Túneles en el norte de la Precordillera de San Juan, oeste de Argentina. De este olistolito sa ha recuperado macrofauna indicativa del período Cámbrico. Este olistolito está alojado en rocas clásticas cuya una edad que es todavía un tema de debate entre paleontólogos y bioestratigrafos. Investigaciones superficiales han mostrado que estas rocas pueden tener los mismos atributos que las rocas de la Formación Stephen. Solo hay unas pocas formaciones sedimentarias en la Tierra que mantienen preservación del tipo de Burgess Shale (BST) y si el olistolito de estudio de la sección de Los Túneles presenta preservación de BST va a tener gran importancia para la Geología de Argentina. El estudio ha incluido un muestreo de campo de varios olistolitos, posterior tratamiento químico (desagregación física y química de las calizas en ácido para investigar possible contenido de microfósiles), y finalmente”picking” bajo lupa binocular para rescatar micropiezas fósiles. El objetivo de este es comprobar si el olistolito de la sección de Los Túneles puede tener fósiles especialmente bien preservados. Este estudio es el primer estudio de la micro fauna del Cámbrico medio en el conjunto de Sudamérica y de ahí que lo indicará si estudios adicionales serían de interés.                       Este investigación determina que el olistolito en Los Túneles Olistolitos en realidad consiste en tres olistolitos encerrados en matriz, contiene fósiles sin una preservación BST y por tanto estudios adicionales no son requeridos para demostrar lo contrario. Los hallazgos fósiles, por ejemplo Chancelloriidae Chancelloria, Hexactinellida Recticulosa y Mollusca Hyolitha, establezca que los tres olistolitos de Los Túneles Olistolitos son de Cámbrico Medio y la matriz que rodea a los olistolitos de periódo Devónico.

This 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. / text

Horizontal 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. / text