This thesis investigates the impacts of diagenesis on the Late-Cretaceous Eagle Ford Formation (Fmn) in south-west Texas. This was achieved utilising many techniques such as of outcrop and core analysis, standard petrographic techniques (including cathodoluminescence [CL] and scanning electron microscopy [SEM]), and geochemical analysis (x-ray diffraction [XRD], stable isotope analysis of C and O within inorganic minerals and Rock Eval pyrolysis). The bulk of diagenetic products and textures were identified via petrographic techniques, with geochemical analysis confirming interpretations based on visual observations. This thesis shows the Eagle Ford Fmn is a calcareous, organic-rich mudstone containing eight distinct lithofacies, which have all been directly impacted by burial diagenesis. The Lower Eagle Ford Fmn mainly comprises of dark organic and clay-rich lithofacies which represent a classic source rock with interbedded carbonate rich lithofacies. The Upper Eagle Ford Fmn is organic and clay-poor, with the bulk of lithofacies carbonate dominated and heavily cemented. An initial anoxic, open marine depositional environment which transitions into an oxic deepening environment is inferred during deposition of the Eagle Ford Fmn. Early, microbial derived redox reactions have precipitated authigenic calcite and pyrite within the Eagle Ford Fmn. Authigenic calcite infills and preserves biogenic debris (mainly planktonic and benthic foraminifera), with pyrite framboids post-dating the carbonate cements. Kaolinite infilling biogenic debris is also a common occurrence indicating it is also an early diagenetic product. Smectite is converted to mixed layer I/Sand illite during deep burial processes at similar depths and temperatures to hydrocarbon generation and expulsion. Authigenic quartz cements precipitate within primary porosity and on top of carbonate cements. Chlorite is observed as the last mineral precipitated in the Eagle Ford Fmn, often pseudomorphed from kaolinite within the micritic matrix. Diagenesis has had the greatest impact on porosity distribution in the Eagle Ford Fmn. The organic, clay-rich lithofacies contain little intra/inter-crystalline porosity with the bulk observed as clay-held or organic porosity. Meanwhile the carbonate-rich lithofacies contain mainly intra-crystalline porosity. Concretions are a common feature observed in the Lower Eagle Ford Fmn outcrops. Four concretion types were identified and studied using a variety of petrological and geochemical techniques. Diagenesis plays a major role in all concretions types. However, primary factors such as sea level fluctuation, sediment input and tectonic activity also have key impacts on the formation of concretions.

According to the 2011 Energy Information Agency (EIA) global assessment, Mexico ranks 4th in shale gas resources. The Eagle Ford shale is the formation with the greatest expectation in Mexico given the success it has had in the US and its liquids-rich zone. Accurate estimation of the resource size and future production, as well as the uncertainties associated with them, is critical for the decision-making process of developing shale oil and gas resources. The complexity of the shale reservoirs and high variability in its properties generate large uncertainties in the long-term production and recovery factors of these plays. Another source of uncertainty is the limited production history. Given all these uncertainties, a probabilistic decline-curve analysis approach was chosen for this study, given that it is relatively simple, it enables performing a play-wide assessment with available production data and, more importantly, it quantifies the uncertainty in the resource size. Analog areas in the US Eagle Ford shale were defined based on available geologic information in both the US and Mexico. The Duong model coupled with a Markov Chain Monte Carlo (MCMC) methodology was used to analyze and forecast production of wells located in the previously defined analog sectors in the US Eagle Ford shale. By combining the results of individual-well analyses, a type curve and estimated ultimate recovery (EUR) distribution for each of the defined analog sectors was obtained. These distributions were combined with well-spacing assumptions and sector areas to generate the prospective-resources estimates. Similar probabilistic decline-curve-analysis methodology was used to estimate the reserves and contingent resources of existing wells. As of March 2013, the total prospective resources (P90-P50-P10) for the Eagle Ford shale in Mexico (MX-EFS) are estimated to be 527-1,139-7,268 MMSTB of oil and 17- 37-217 TSCF of gas. To my knowledge, this is the first oil estimate published for this formation in Mexico. The most attractive sectors based on total estimated resources as well as individual-well type curves are located in the southeast of the Burgos Basin and east-west of the Sabinas basin. Because there has been very little development to date, estimates for reserves and contingent resources are much lower than those for prospective resources. Estimated reserves associated with existing wells and corresponding offset well locations are 18,375-34,722-59,667 MMSCF for gas and zero for oil. Estimated contingent resources are 14-64-228 MSTB of oil and 8,526-13,327- 25,983MMSCF of gas. The results of this work should provide a more reliable assessment of the size and uncertainties of the resources in the Mexican Eagle Ford shale than previous estimates obtained with less objective methodologies.

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.

Expanded production of hydrocarbons by means of horizontal drilling and hydraulic fracturing of shale formations has become one of the most important changes in the North American petroleum industry in decades, and the Eagle Ford (EF) Shale play in South Texas is currently one of the largest producers of oil and gas in the United States. Since 2008, more than 5000 wells have been drilled in the EF. To date, little research has focused on landscape impacts (e.g., fragmentation and soil erosion) from the construction of drilling pads, roads, pipelines, and other infrastructure. The goal of this study was to assess the spatial fragmentation from the recent EF shale boom, focusing on La Salle County, Texas. To achieve this goal, a database of wells and pipelines was overlain onto base maps of land cover, soil type, vegetation assemblages, and hydrologic units. Changes to the continuity of different ecoregions and supporting landscapes were then assessed using the Landscape Fragmentation Tool as quantified by land area and continuity of core landscape areas (those degraded by “edge effects”). Results show an increase in ecosystem fragmentation with a reduction in core areas of 8.7% (~333 km²) and an increase in landscape patches (0.2%; 6.4 km²), edges (1.8%; ~69 km²), and perforated areas (4.2%; ~162 km²) within the county. Pipeline construction dominates sources of landscape disturbance, followed by drilling and injection pads (85%, 15%, and 0.03% of disturbed area, respectively). This analysis indicates an increase in the potential for soil loss, with 51% (~58 km²) of all disturbance regimes occurring on soils with low water-transmission rates and a high runoff potential (hydrologic soil group D). Additionally, 88% (~100 km²) of all disturbances occurred on soils with a wind erodibility index of approximately 19 kt/km²/yr or higher, resulting in an estimated potential of 2 million tonnes of soil loss per year. Depending on the placement of infrastructure relative to surface drainage patterns and erodible soil, these results show that small changes in placement may significantly reduce ecological and hydrological impacts as they relate to surface runoff. Furthermore, rapid site reclamation of drilling pads and pipeline right-of-ways could substantially mitigate potential impacts. / text

The vast shale gas and tight oil reservoirs in North America cannot be economically developed without multi-stage hydraulic fracture treatments. Owing to the disparity in the density of natural fractures in addition to the disparate in-situ stress conditions in these kinds of formations, microseismic fracture mapping has shown that hydraulic fracture treatments develop a range of large-scale fracture networks in the shale plays. In this thesis, an approach is presented, where the fracture networks approximated with microseismic mapping are integrated with a commercial numerical production simulator that discretely models the network structure in both vertical and horizontal wells. A novel approach for reservoir simulation is used, where porosity (instead of permeability) is used as a scaling parameter for the fracture width. Two different fracture geometries have been broadly proposed for a multi stage horizontal well, orthogonal and transverse. The orthogonal pattern represents a complex network with cross cutting fractures orthogonal to each other; whereas transverse pattern maps uninterrupted fractures achieving maximum depth of penetration into the reservoir. The response for a vii single-stage fracture is further investigated by comparing the propagation of the stage to be dendritic versus planar. A dendritic propagation is bifurcation of the hydraulic fracture due to intersection with the natural fracture (failure along the plane of weakness). The impact of fracture spacing to optimize these fracture geometries is studied. A systematic optimization for designing the fracture length and width is also presented. The simulation is motivated by the oil window of Eagle Ford shale formation and the results of this work illustrate how different fracture network geometries impact well performance, which is critical for improving future horizontal well completions and fracturing strategies in low permeability shale and tight oil reservoirs. A rate transient analysis (RTA) technique employing a rate normalized pressure (RNP) vs. superposition time function (STF) plot is used for the linear flow analysis. The parameters that influence linear flow are analytically derived. It is found that picking a straight line on this curve can lead to erroneous results because multiple solutions exist. A new technique for linear flow analysis is used. The ratio of derivative of inverse production and derivative of square root time is plotted against square root time and the constant derivative region is seen to be indicative of linear flow. The analysis is found to be robust because different simulation cases are modeled and permeability and fracture half-length are estimated. / text

Hydraulic fracturing has unlocked a tremendous resource across the United States and around the world—shale. However, these processes have also come with a myriad of potential environmental effects, including a substantial demand for water. Hydraulic fracturing can require anywhere between two and four million gallons per well. The need for such large quantities of water can produce severe stresses on local water resources. In response to this issue, operators have developed several ways to alleviate some of the stresses brought on by the extensive water use such as alternative sourcing and reuse technologies. Companies are driven to exercise these options and decrease their fresh water usage for hydraulic fracturing processes for multiple reasons, including changes in regulation, to gain support of local communities, and to increase efficiencies of operations. Whatever the motivation may be, there are a variety of options companies have at their disposal to reduce fresh water demands—dependent on specific formation characteristics, the qualities and quantities of available water, among others. The Eagle Ford shale is one of the most rapidly growing shale plays in the country. However, this formation is located in a fairly arid part of the country. Because of meager average rainfall totals, water availability to meet demand is an issue of great concern. Due to nearly exponential increases in shale production, stresses on local water supplies have dramatically increased as well. The objectives of this thesis are as follows: 1) to establish the enormous resource that has become available; while still recognizing the environmental impacts associated with development processes, focusing primarily on water requirements and associated wastewater production; 2) to break down current water demand for shale development, as well as wastewater management practices in the Eagle Ford, with a brief comparison to other shale plays across the country; 3) to obtain an understanding of operator motivation—what factors affect wastewater management strategies; and 4) to analyze techniques operators presently have at their disposal to reduce fresh water demands, specifically through the use of brackish waters and recycling/reuse efforts, and finally to quantify these efforts to evaluate potential fresh water savings. / text

Expansive clays are located world wide and cause billions of dollars in damage each year. Currently, the expansion is usually estimated using correlations instead of direct testing as direct testing is expensive and often takes over a month to complete. The purpose of this study was to determine if centrifuge technology could be used to characterize expansive clays through direct testing. Testing was performed in an centrifuge permeameter on compacted specimens of Eagle Ford clay. A framework was developed to analyze effective stresses in centrifuge samples and methods were proposed to determine the swell-stress curve of a soil from centrifuge tests. Standard free swell test were also performed for comparison. The swell-stress curve determined by centrifuge testing was found to match with the curve found from free swell tests after correcting for differences in testing procedures. The centrifuge tests were found to be repeatable and required several days for testing rather than weeks. / text

Grain assemblages in organic-rich mudrocks of the Eagle Ford Formation of South Texas are assessed to determine the relative contributions of intra- and extrabasinal sediment sources, with the ultimate goal of producing data of relevance to prediction of diagenetic pathways. Integrated light microscopy, BSE imaging, and X-ray mapping reveal a mixed grain assemblage of calcareous allochems, biosiliceous grains (radiolaria), quartz, feldspar, lithics, and clay minerals. Dominant fossils are pelagic and benthic foraminifers and thin-walled and prismatic mollusks; echinoderms, calcispheres, and oysters are present. Early-formed authigenic minerals, including calcite, kaolinite, dolomite, albite, pyrite, quartz, and Ca-phosphate, some reworked, add to the overall lithologic heterogeneity. Point counting of images produced using energy-dispersive X-ray mapping in the SEM provides observations at a scale appropriate to classifying the mudrocks based on the composition of the grain assemblage, although grains and other crystals of clay-size cannot be fully characterized even with the SEM. Each sample is plotted on a triangle, whose vertices correspond to terrigenous and volcanic grains (extrabasinal components), calcareous allochems, and biosiliceous grains. As a subequal mix of grains of intrabasinal and extrabasinal origins the detrital grain assemblage of the Eagle Ford, presents a formidable challenge to the task of lithologic classification of this unit, as neither conventional limestone nor sandstone classifications can be readily applied. The abundant marine skeletal debris in the Eagle Ford is accompanied by abundant calcite cementation and the dissolution and replacement of biosiliceous debris is accompanied by authigenic quartz, suggesting that mudrock grain classification has potential for yielding diagenetic predictions. / text

Scanning electron microscopy of Ar-ion milled samples from the Eagle Ford Formation, South Texas shows that the character and abundance of porosity changes significantly across burial conditions as a result of compaction, cementation, bitumen generation, and generation of secondary porosity within organic matter (OM). Samples displaying a range of compositions and maturities are imaged and quantified to provide insight into the effects of these processes. Porosity in low-maturity samples (Ro~0.5%) is volumetrically dominated (0.1% -12.5% bulk volume, average 6.2%) by relatively large, mostly interparticle, primary mineral-associated pores (median sizes range 35.9-52.7 nm). Larger pores are generally associated with coccolith debris that is commonly aggregated into pellets. Porosity and pore size correlate directly with calcite abundance and inversely with OM volumes. OM is dominantly detrital kerogen "stringers" that range in size and have spatial distributions and character suggestive of detrital origin. Destruction of primary porosity in low-maturity samples has occurred due to compaction of ductile kerogen and clays and, to a minor degree, as a result of cementation and infill of early bitumen. Smaller, secondary OM-hosted pores (median size range 11.1-14.9 nm) volumetrically dominate porosity (0.02%-3.6% bulk volume, average of 1.36%), in most high-maturity samples (Ro~1.2%-1.3%). Mineral-associated pores are present, but are typically smaller (median size range from 20.3-40.6 nm) and less abundant (0.0%-10.0% bulk volume, average of 2.5%) than at low maturity. Abundant mineral-associated porosity is present locally in samples where incursion of primary pore space by bitumen has not occurred. OM within high-maturity samples is distributed more evenly throughout the rock fabric, occupying spaces similar in size and morphology to primary interparticle pores, coating euhedral crystals (probable cements), and filling intraparticle porosity. These observations, and positive correlation between calcite and OM volumes (OM-hosted pore volume included) in samples with dominantly OM-hosted pore networks, suggests that a large portion of OM within high-maturity samples is diagenetic in origin and has filled primary pore space. Destruction of primary porosity in high-maturity samples has occurred through cementation, bitumen infill, and, possibly greater compaction. Additional porosity, however, has been generated through maturation of OM. / text

Heightened industry focus on the Upper Cretaceous (Cenomanian-Turonian) Eagle Ford has resulted from recent discoveries of producible unconventional petroleum resource in this emerging play. However, little has been published on the facies and facies variabilities within this mixed carbonate-clastic mudrock system. This rock-based study is fundamental to understanding the controls, types, and scales of inherent facies variabilities, which have implications for enhanced comprehension of the Eagle Ford and other mixed carbonate-clastic mudrock systems worldwide. This study utilizes 8 cores and 2 outcrops with a total interval equaling 480 feet and is enhanced by synthesis of thin section, XRD, XRF, isotope, rock eval/TOC, and wireline log data. Central Texas Eagle Ford facies include 1) massive argillaceous mudrock, 2) massive argillaceous foraminiferal mudrock, 3) laminated argillaceous foraminiferal mudrock, 4) laminated foraminiferal wackestone, 5) cross-laminated foraminiferal packstone/grainstone, 6) massive bentonitic claystone, and 7) nodular foraminiferal packstone/grainstone. High degrees of facies variability are observed even at small scales (50 ft) within the Eagle Ford system and are characterized by pinching and swelling of units, lateral facies changes, truncations, and locally restricted units. Facies variability is attributed to erosional scouring, productivity blooms, bottom current reworking, and bioturbation. At the 10-mile well spacing scale and greater, the data significantly overestimates intra-formational facies continuity but is successful in defining the following four-fold stratigraphy: The basal Pepper Shale is an argillaceous, moderate TOC, high CGR and GR mudrock. The Waller Member is a newly designated name used in this study for an argillaceous and foraminiferal, high TOC, massive mudrock with a generally moderate CGR and GR profile. The Bouldin Member is a high energy, carbonate-rich (foraminiferal), low TOC, low and variable CGR but high GR zone. Finally, the South Bosque Formation is an argillaceous and foraminiferal, moderate TOC, massive and laminated mudrock with a moderate CGR and GR signature. GR logs alone are inadequate for determination of facies, TOC content, depositional environment, and sequence stratigraphic implications. Using integrated lithologic, isotopic, and wireline log data, cored wells in the study area are correlated across the San Marcos Arch. Geochemical proxies (enrichment in Mo, Mn, U, and V/Cr) indicate that maximum basin restriction occurred during deposition of the Bouldin Member. Bottom current activity influenced depositional processes and carbonate sediment input was driven by water column productivity. These primary controls on Eagle Ford stratigraphy and character are independent from eustatic fluctuation, rendering classical sequence stratigraphy unreliable. / text