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A chronostratigraphic framework was developed for the subsurface Eagle Ford of South Texas in conjunction with a log-based regional study that was extended across the San Marcos Arch and into East Texas using biostratigraphic and geochemical data to constrain log correlations of 12 horizons from 1729 wells in South and East Texas. Seven regional depositional episodes were identified by the study. The clayrich Maness Shale was deposited during the Early Cenomanian in East Texas and northern South Texas where it correlates to the base of the Lower Eagle Ford. After a fall in sea-level, East Texas was dominated by the thick siliciclastics of the Woodbine Group, whereas in South Texas deposition of the organic-rich EGFD100 marls of the Lower Eagle Ford began during the subsequent Lewisville transgression. A shift in depositional style to the limestones and organic-rich shales of the Eagle Ford Group occurred in East Texas during the Middle-Late Cenomanian EGFD200 and EGFD300 episodes produced by the continued rise in sea-level. Erosion along the Sabine Uplift shifted the focus of deposition in East Texas southward to the Harris delta and deposited the “clay wedge” of northern South Texas during the EGFD400 episode. The introduction of an oxygenated bottom-water mass onto the Texas shelf produced the considerable decrease in TOC preservation that marks the Lower/Upper Eagle Ford contact. This event coincided with the onset of Oceanic Anoxic Event 2 (OAE2) and the Cenomanian-Turonian Boundary sea-level high, which starved much of the Texas shelf of sediment. The only significant source of sediment was from the south; within the study area, the EGFD500 interval is essentially absent north of the San Marcos Arch. Deposition recommenced on much of the Texas shelf during the Late Turonian EGFD600 episode with the Sub-Clarksville delta of East Texas and the carbonate-rich Langtry Member of South Texas and eastern West Texas. Bottom-waters became oxygenated at approximately 90 Ma, initiating the transition from the Eagle Ford Group to the Austin Chalk.
Abstract Known as a world-class source rock for years, the Eagle Ford Shale became a world-class oil reservoir early in the second decade of the 21st century. Oil production from the Eagle Ford grew from 352 barrels of oil per day (BOPD) in 2007 to over 1.7 million BOPD in March 2015. Since then, the play has been a victim of its own success. Production from shale oil in the United States has helped contribute to a glut in world oil supply that led to a precipitous drop in oil prices beginning in the summer of 2014. As prices fell from over $100 per barrel in July 2014, to less than $30 per barrel in January 2016, production from the Eagle Ford declined over 500,000 BOPD. Anyone interested in the geology behind this remarkable play and the new ideas that reshaped the global energy supply should read AAPG Memoir 110.
Front Matter
Introduction
Abstract The 130-year history of study of the Cenomanian–Turonian Eagle Ford and Woodbine Groups of Texas has created a complicated and often confusing nomenclature system. Deciphering these nomenclatures has frequently been hindered by outdated biostratigraphic studies with inaccurate age interpretations. To resolve these issues, a comprehensive compilation and vetting of available biostratigraphic, geochemical, and lithologic data from Eagle Ford and Woodbine outcrops and subsurface penetrations was undertaken, which was then tied to a large network of wells in both south and east Texas. Composite sections were built for four outcrop areas of central and north Texas (Dallas, Red River, Waco, Austin), five outcrop areas from west Texas (Langtry, Del Rio, Big Bend, Chispa Summit, Quitman Mountains), four subsurface areas from south Texas (Webb County, Atascosa County, Karnes County, DeWitt/Gonzales Counties), and two cross sections from the east Texas subsurface (basin center and eastern margin). The resulting datasets were utilized to construct age models and characterize depositional environments, including paleoceanography. In agreement with previous studies, the total organic carbon (TOC)-rich Lower Eagle Ford was interpreted to have been deposited under anoxic to euxinic conditions and the Upper Eagle Ford under dysoxic to anoxic conditions. The Oceanic Anoxic Event 2 (OAE2) interval is missing at all locations north of Atascosa County; when present it is characterized as having been deposited under oxic to suboxic conditions. High abundances of radiolaria and calcispheres identified within recrystallized medial to distal limestones of the Lower Eagle Ford indicated limestone formation during periods of enhanced water-column mixing and increased primary productivity, in contrast to proximal limestones composed of planktonic foraminifera and inoceramid prisms concentrated by bottom currents. Standardized nomenclature systems and age models are proposed for each of the outcrop and subsurface areas. Proposed changes to existing nomenclatures include reassignment of the Tarrant Formation of the Eagle Ford to the Lewisville Formation of the Woodbine in the Dallas area and the Templeton Member of the Lewisville Formation to the Britton Formation of the Eagle Ford in the Red River area. The proposed term “Waller Member” of Fairbanks (2012) for the former Cloice Member of the Lake Waco Formation in the Austin area is recognized with a new stratotype proposed and described, although the Waller Member is transferred to the Pepper Shale Formation of the Woodbine. The Terrell Member is proposed for the carbonate-rich section at the base of the Boquillas Formation in the Langtry and Del Rio areas, restricting the Lozier Canyon Member to the organic-rich rocks underlying the Antonio Creek Member. The south Texas subsurface is divided into the Upper Eagle Ford and Lower Eagle Ford Formations, with the clay-rich Maness Shale Member at the base of the Lower Eagle Ford and the foraminifera grainstone dominated Langtry Member at the top of the Upper Eagle Ford. Use of the term “middle Eagle Ford” for the clay-rich facies south of the San Marcos arch is not recommended.
Regional Depositional Episodes of the Cenomanian–Turonian Eagle Ford and Woodbine Groups of Texas
Abstract Twelve stratigraphic intervals originally defined in the Eagle Ford of south Texas were mapped across the San Marcos arch into the Maness Shale, Woodbine, and Eagle Ford of east Texas. The maps are based on well log correlations of 1729 wells across 22 counties in south and east Texas using biostratigraphic, geochemical, and lithologic data from 99 wells as seed points for the correlations. These mapped intervals were tied to a regional chronostratigraphic framework developed using data from the outcrops of west, central, and north Texas and cores from the subsurface of south and east Texas. Seven regional depositional episodes were identified across the Texas shelf for the Woodbine and Eagle Ford Groups based on the isopach maps, outcrop data, and paleoenvironmental interpretations. The clay-rich Maness Shale was deposited during the Early Cenomanian in east Texas and northern south Texas where it correlates to the base of the Lower Eagle Ford. After a relative fall in sea level, east Texas was dominated by the thick siliciclastics of the Woodbine, whereas in south Texas deposition of the organic-rich EGFD100 marls began during the subsequent transgression. A shift in depositional style to the limestones and organic-rich shales of the Eagle Ford occurred in east Texas during the Middle Cenomanian produced by the continued rise in sea level, correlating to the EGFD200 marls of south Texas and the carbonates of the Lozier Canyon Member (restricted) of the Eagle Ford Group in west Texas. During the EGFD300 interval deposition transitioned to the organic-rich marls and limestones of the Lozier Canyon and Antonio Creek Members of the Eagle Ford Group in west Texas and the Templeton delta became active in northern east Texas. Erosion along the Sabine uplift shifted the focus of deposition in east Texas southward to the Harris delta and deposited the “clay wedge” of the EGFD400 in northern south Texas. Although the lower part of the EGFD500 episode was deposited during OAE2, it is characterized by low total organic carbon (TOC) due to the presence of oxygenated bottom waters, and the Cenomanian–Turonian boundary sea-level high produced a regional hiatus. Deposition recommenced on much of the Texas shelf during the Late Turonian EGFD600 interval with the Sub-Clarksville delta of east Texas and the carbonate-rich Langtry of south Texas and eastern west Texas. Bottom waters became oxygenated at approximately 90 Ma, initiating the transition from the Eagle Ford to the Austin Chalk.
Abstract The geochemistry of oils and gases, as well as sediments from which they are derived, is fundamental knowledge. The current study produces a subregional to regional characterization of the geochemistry of Eagle Ford oils and sediments in the context of a meaningful stratigraphic framework. The study area includes the main and most important producing areas of the Eagle Ford shale oil play. The lower part of the Eagle Ford is shown to be the organically richest part of the group. This is demonstrated by the general literature, reference to work completed by colleagues of this volume, and presentation of data for a core from an important Eagle Ford producing area. This interval is lower-middle Cenomanian in age. It depositionally predates the Oceanic Anoxic Event 2 (OAE2) that occurs at the Cenomanian–Turonian boundary. Elevated organic richness in the lower Eagle Ford that varies along strike suggests organic accumulation is partly controlled by localized, semipermanent circulatory patterns. Multivariate statistical classification using biomarkers and carbon isotopes from a large number of oils in Cretaceous reservoirs closely related to the Eagle Ford resulted in the identification of eight compositionally distinct families, three of which occur in the main part of the Eagle Ford shale oil-producing area: Family 2, Family 3, and Family 7. Average data for each family are compared to a large set of global oils representing a variety of depositional environments and depositional times. Comparison of the south Texas oils to the cosmopolitan dataset indicates that Family 3 oils were derived from shales deposited in distal marine settings. Family 7 oils compare favorably with oils derived from carbonate-rich source rocks and Family 2 oils from compositionally intermediate marl-rich sediments. Maturity-sensitive data from the oil families were submitted to principal component analysis. Seventy-five to ninety-four percent of the variability in these datasets was contained in the first or primary principal component (Factor 1). The level of correlation suggested these Factor 1 values could be converted to equivalent vitrinite reflectance values (%VRE). This was accomplished and the VRE for the oils mapped. Oil maturities obtained by this process are consistent with maturity trends obtained from regional considerations. When assessing source rock thermal maturity using pyrolysis techniques (e.g., Rock-Eval), it is useful to measure pyrolysis parameters both before and after solvent extraction, especially at or near peak oil maturity levels. The certitude that oils in this study are derived from the Eagle Ford, as opposed to the Austin Chalk or some third source, comes from several observations. Some Family 2 oils come directly from completions in the Eagle Ford. Family 7 oils come from the First Shot field area and Family 3 oils from Giddings are derived from Eagle Ford/Boquillas Shales based on positive oil-source correlations. Several source scenarios can be imagined given two proven Eagle Ford sources (lower-middle Cenomanian and Turonian) and three organic facies represented by oils. It is possible that one or more organofacies are active sources within each chronostratigraphic interval.
Abstract Although typically considered with a focus on high-resolution petrography, shale porosity should not be thought of as a stand-alone petrographic feature. Shale and mudstone porosity is the outcome of a long succession of processes and events that span the continuum from deposition through burial, compaction, and late diagenesis. For the Eagle Ford Shale this journey began with accumulation in intra-shelf basins at relatively low latitudes on a southeast-facing margin during early parts of the late Cretaceous. To understand the factors that generated and preserved porosity in this economically important interval, a scanning electron microscope study on ion-milled drill-core samples from southern Texas was conducted to understand the development of petrographic features and porosity and place them in stratigraphic context. The studied samples show multiple pore types, including pores defined by mineral frameworks (clay and calcite), shelter pores in foraminifer tests and other hollow fossil debris, and pores in organic material (OM). In many instances, framework and shelter pores are filled with OM that has developed pores due to maturation. Large bubble pores in OM suggest that hydrocarbon liquids were left behind in or migrated into these rocks following petroleum generation and that the bubbles developed as these rocks experienced additional thermal stress. These larger OM pores indicate deeper seated interconnection on ion-milled surfaces and in three-dimensional image stacks. The largest pores occur in the infills of foraminifer tests. The framework of crushed carbonate debris in planktonic fecal pellets shows intermediate levels of porosity, and the silicate-rich matrix that encloses framework components has the smallest average porosity. The distribution of pore types is not uniform. Our hypothesis is that facies association is an important factor that determines bulk porosity and influences reservoir performance. The observed variability in the attributes of the described distal, medial, and proximal facies associations is thought to translate into significant variability of rock properties such as total organic carbon and porosity. In turn, this variability should control the quality and distribution of the intervals that are optimum sources and reservoirs of hydrocarbons in the Eagle Ford Shale. The medial facies association most likely has the best porosity development when a favorable combination of more commonly abundant calcareous fecal pellets and organic material versus clay content is present. The systematic arrangement of facies associations into parasequences provides the basis for testing and predicting the best development of optimal reservoir facies within a sequence-stratigraphic framework in the Eagle Ford Shale.
Delineation of an Oil Window—An Integrated Approach
Abstract In 2006, Mark Papa, CEO of EOG Resources, Inc. directed EOG divisions to focus on identifying and leasing large acreage blocks in shale oil window fairways (Mark Papa, personal communication) in basins throughout the United States while subordinating all exploration for natural gas, and in particular, dry gas. The company’s strategic change to shale oil exploration occurred during what was referred to as a “wall of disbelief” (Birger, 2011) predicated on the premise that oil molecules could not flow through shale-dominated permeability systems. The EOG Garner 1054 C#1, drilled in November 1998, encountered hydrocarbons within the Eagle Ford Formation at a pressure gradient of 0.76 psi/ft, at a subsurface true vertical depth (TVD) of 9300 ft (2834.6 m). Although a wet gas producer, this well was a critical element in the rationale to obtain leases in the oil window of the Eagle Ford Formation. Predicated upon a technical analysis of additional vertical well production within the Eagle Ford Formation indicating the existence of a dual porosity, or matrix-supported flow network, and in conjunction with the generation of fairway criteria mapping, EOG initiated a leasing strategy resulting in the acquisition of 569,000 contiguous acres within the crude oil window fairway. Regional mapping of the Eagle Ford Formation was conducted to model structure, thickness, total organic carbon (TOC), thermal maturity (R o ), oil gravity, and hydrocarbon saturation as well as lithostratigraphic continuity, postulated environments of deposition, and mineralogical variations. An identified fairway situated between the Maverick Basin and the San Marcos arch, a syn-depositional graben system on the margin of a transgressed carbonate platform, was mapped as a relatively thick and laterally continuous stratigraphic section within the targeted R o , TOC, and favorable hydrocarbon saturation windows. X-ray diffraction (XRD) analysis revealed that while the silica content within the Eagle Ford Shale was low relative to the more topical Barnett Shale and other existing shale resource plays, the mineralogical constituents were that of a brittle carbonate with variable clay content replete with a deceptive gamma log signature as a consequence of elevated levels of uranium and thorium. Distinct structural settings displaying unique structural and stratigraphic attributes were recognized and mapped, all of which had remained within the oil generation window for the last 30 million years. Net rock volume increases associated with prolonged oil generation and expulsion were believed to increase the likelihood of catagenically induced micro-fracturing resulting in enhanced system permeability. Eight strategically located vertical delineation wells were drilled across a 15 by 120 mi (24.1 by 193.1 km) fairway located from Gonzales to LaSalle Counties. Conventional coring coupled with extensive electric logging suites and petrophysical evaluations provided an integrated regional understanding of the Eagle Ford Formation. Nanometer-scale imaging with focused ion beam (FIB) and field emission scanning electron microscopy (FESEM) of Eagle Ford core samples showed interconnected porosity systems and pore sizes capable of transmitting oil molecules. Initial production rates from EOG-operated horizontal delineation drilling confirmed the viability of the Eagle Ford Formation as an overpressured carbonate resource rock with system porosity and permeability capable of long-term economic oil production. The methods defined in this chapter were appropriate for the delineation of the oil window within the Eagle Ford of South Texas; however, hydrocarbon systems are unique and these methods may not be applicable for defining other plays within other basins.
Assessing Well Performance in a Prolific Liquids-rich Shale Play—An Eagle Ford Case Study
Abstract A series of subsurface reservoir and geological properties are reviewed, specific to the Eagle Ford Shale of south Texas and compared with production trends. Currently, an area in excess of 7 million acres has been tested for Eagle Ford production potential by hydraulically fracture-stimulated, horizontal wellbores. The bulk of this area is suitably thick (>125 ft [38.1 m]), organic-rich (>2 wt. % total organic carbon), and attains a thermal maturity consistent with hydrocarbon generation for Type II kerogen (>435°C T max ). Production trends, highlighted by well performance analysis from over 1450 wells, point to a clear differentiation of an optimum fairway comprising a greater population of strong wells. This fairway represents approximately 10% of the aforementioned area. With this in mind, the significance of key geological properties and their heterogeneities are evaluated and discussed. Understanding well performance, and more importantly, the key drivers that govern well performance provide the motivation for this study. The results of this study highlight the fact that the best performing wells across the play (based upon initial 18-month cumulative production) are located within a narrow 7 mi (11.3 km) wide, SW–NE strike-orientated belt that extends across several counties spanning approximately 140 mi (225.3 km). This fairway in general parallels the ancestral lower Cretaceous shelf edges (Sligo and Stuart City) and is characterized by a thermal maturity window (460–500°C T max ) consistent with wet gas and condensate production. Structurally downdip of these margins the play transitions into dry gas. Moving updip to the north, lower levels of thermal maturity are encountered (i.e., early oil window) that deliver lower volume wells, presumably due to lower levels of kerogen conversion and transformation. Thermal maturity is one of the primary well performance drivers in the play. Across the central portion of the trend, within the optimum maturity window, local production sweet spots exist that are further delineated by a combination of higher reservoir pressure and the interaction of local depositional patterns that promote above-average accumulations of organic-rich facies. By contrast, a significant proportion of the poorer wells analyzed commonly display much higher values for clay content, even though many of these wells share favorable levels of thermal maturity, reservoir pressure, and moderate organic-richness. The elevated clay content (>30%) and resulting undesirable geomechanical properties restrict well performance. This is likely a function of limited stimulation effectiveness and/or proppant embedment. Clay content is the single most important metric that significantly degrades well performance, even when other parameters are favorable. This degradation can occur over a short distance (2-5 mi [3.2–8 km]) and is independent of most other variables. Wellbore-scale properties such as the occurrence of natural fractures appear to influence early time flow-back profiles, but have a modest influence on long-term well production. These variances represent smaller-scale perturbations that are superimposed upon the broader controls noted earlier.
Abstract With the onset of the shale revolution in the United States, understanding shale reservoir rock properties has become increasingly important. The criteria used to characterize these ultra-low-permeability shale reservoirs and their resource potential commonly include organic richness, thermal maturity, lithologic heterogeneity, formation brittleness, and porosity. Because the lateral continuity of these systems often changes rapidly over short distances, it is desirable to quantify changes in these criteria both vertically and laterally within the reservoir. Here we present three seismic techniques used to identify, characterize, quantify, and map spatial distributions and variations of key attributes. Using seismic attribute data calibrated to key wells, we focus the mapping of three key attributes over a large region in South Texas: mechanical facies (i.e., fracability), fracture intensity as it relates to reservoir pressure, and total porosity over a large region in south Texas. This approach to mapping source rocks may change the way ultra-low-permeability shale reservoirs are evaluated in the future.
Abstract Fine-grained mudrocks are enriched and/or depleted in a variety of major and trace elements, and the enrichment or depletion of these elements corresponds to specific depositional environments, sedimentary facies, mineralogy, and provenance. Chemostratigraphy employs major and trace elemental data to understand geochemical variability within sedimentary sequences. The results and interpretations of this type of analysis can aid in the identification of ideal acreage positions and/or defining horizontal well target zones when integrated with other datasets to determine reservoir quality. Major elements are used to calculate the brittle mineral fraction while redox-sensitive trace elements are used as paleodepositional proxies to recognize where organic carbon-rich intervals occur as a result of organic matter deposition and preservation. Well performance positively correlates with an increase in brittle minerals and an oxygen-poor (anoxic) paleoenvironment. Whole-rock inorganic elemental data were acquired from 36 vertical and horizontal Eagle Ford Shale wells from seven counties along the productive subsurface Eagle Ford trend in south Texas. This dataset elucidates vertical and lateral paleoredox conditions and facies variability within the organic-rich Eagle Ford Shale and how that variability can affect well performance. For this study, we employ the use of major and redox-sensitive trace elements as effective proxies for distinguishing and mapping facies changes. Elemental data mapped and correlated across multiple wells identify a significant facies change evident along strike of the Cretaceous shelf margins along with more subtle facies changes observed along dip of the trend.
Geological Controls on Matrix Permeability of the Eagle Ford Shale (Cretaceous), South Texas, U.S.A.
Abstract Permeability measurements made using innovative techniques on 36 intact samples from five wells in south Texas provide the basis for a dual-porosity reservoir simulation model for the Eagle Ford Shale (Upper Cretaceous). In the model, matrix storage feeds a network of progressively larger natural and induced fractures that carry hydrocarbons to the wellbore. The Eagle Ford consists almost entirely of interbedded marl and limestone. Across these rock types, permeability increases with increasing calcite content. The limestones are more permeable than the marls due to the presence of fractures. Permeability also increases with the degree of lamination but the mechanism is unclear. Finely laminated marls are more permeable than marls without any lamination. Scanning electron microscope microscopy shows that all of the intergranular pores in the Eagle Ford are lined or filled with solid hydrocarbon identified as both bitumen and pyrobitumen by visual kerogen analysis and solvent extraction. The bitumen is porous, but permeability is not related directly to the total organic carbon content.
Findings from the Eagle Ford Outcrops of West Texas and Implications to the Subsurface of South Texas
Abstract The Eagle Ford Group crops out in a series of spectacular cut-bank exposures within Lozier Canyon region in Terrell County (west Texas). These outcrops provide an unparalleled opportunity to examine the Eagle Ford Group and gain valuable insights into explaining and predicting the vertical and lateral variability, as well as the thickness changes that can occur regionally within an unconventional source rock play. In the subsurface of south Texas, the Eagle Ford Group is typically divided into an organic-rich Lower Eagle Formation and a carbonate-rich Upper Eagle Ford Formation. Both formations are petrophysically distinct, especially on gamma ray (GR) and sonic logs. When geochemically analyzed, the basal portion of the Upper Eagle Ford Formation also contains a unique positive carbon isotope δ 13 C excursion interpreted as the Ocean Anoxic Event 2 (OAE2). The peak of this isotope excursion is the assigned proxy for the base of the Turonian Stage. Within the Eagle Ford outcrops of west Texas a vertical succession of five informal lithostratigraphic units, referred to as units A to E from the base up, are fairly obvious. Unit A consists of interbedded grainstones and carbonate mudstones. Unit B is dominated by organic-rich black carbonate mudstones. Unit C consists of packstone beds interbedded with light gray carbonate mudstones. Unit D consists of bioturbated marls, while Unit E consists of grainstones interbedded with carbonate mudstones and bentonites. By incorporating petrophysical and geochemical data, the Lower and Upper Eagle Formations from the subsurface of south Texas can also be defined in the Eagle Ford outcrops of west Texas. Our work suggests that outcrop units A and B represent the Lower Eagle Ford Formation, while outcrop units C, D, and E represent the Upper Eagle Ford Formation. Similar to the subsurface of south Texas, a distinct positive carbon isotope δ 13 C excursion also occurs in the basal portions of the Upper Eagle Ford Formation (unit C) in outcrop. More detailed analysis of the outcrop and subsurface data from the Eagle Ford Group in west Texas indicates that the five informal lithostratigraphic units can be further divided into a vertical succession of 16 subunits. This more detailed vertical facies succession was used to define four genetically related depositional sequences each with distinctive geochemical and petrophysical characteristics which make them particularly suitable for regional subsurface mapping. For nomenclature simplicity, these four sequences are herein termed the lower and upper (allo-) members of the Lower Eagle Ford Formation and the lower and upper (allo-) members of the Upper Eagle Ford Formation. The lower member of the Lower Eagle Ford Formation is an organic-rich, high-resistivity, uranium-poor mudstone-dominated sequence. A distinctive clay-rich, low-resistivity zone also marks its base. This sequence appears to be the primary unconventional reservoir interval in the subsurface of south Texas. The upper member of the Lower Eagle Ford Formation can be characterized as a uranium- and bentonite-rich, mudstone-dominated sequence. The lower member of the Upper Eagle Ford Formation is a uranium-poor interbedded mudstone and limestone succession characterized by an overall (low) blocky GR pattern, the presence of a distinctive positive carbon isotope δ 13 C excursion, and a clay-rich, low-resistivity zone at its base. The upper member of the Upper Eagle Formation is a bentonite-bearing, low-TOC interval that is more bioturbated toward its base and interbedded toward its top. It is characterized by the presence of a high GR, low resistivity, and low velocity mudstone at its interpreted maximum flooding surface. Regional correlations of the four defined Eagle Ford depositional sequences (allomembers) reveal that the unconformities at the base of each of the four sequences, as well as the one at the base of the overlying Austin Chalk, modify the thickness and distribution of underlying strata. Thus any attempt to explain and predict the distribution and thickness variations of any of the four sequences (allomembers), especially the organic-rich lower member of the Lower Eagle Ford Formation, is highly dependent on the recognition and regional mapping of these unconformities.
The Role of Integrated Reservoir Petrophysics in Horizontal Well Evaluations to Increase Production in the Eagle Ford Shale
Abstract Drilling horizontal wells is the common mode of operation for field development in low-permeability unconventional reservoirs such as the Eagle Ford Shale. Assumptions are made regarding the homogeneity of the reservoir as wells are drilled away from the vertical pilot well. It is assumed that the reservoir characteristics remain uniform and also that the structure is constant based on the dip of the beds in the pilot hole wellbore. Making such assumptions can lead to wells being placed out of zone and in rocks with much different reservoir quality and stress magnitude than those in the pilot hole, which can adversely affect the production potential of the well. With the high cost of drilling and completing these wells, it is generally economically beneficial to do some evaluation of the lateral to ensure proper placement of the well and also the optimal placement of completion zones along the lateral. Lateral measurements and petrophysical interpretations can be used to define variations in reservoir quality (RQ) and completion quality (CQ) along the wellbore, which can then be used to optimize the completion design, for example, placing perforation clusters in similar rocks to increase production when compared to peer wells completed with a geometric design. The next step in integration is correlating pilot and lateral wellbore measurements with the structural component. This process is defined as geology quality (GQ). After taking together, RQ, CQ, and GQ, a comprehensive design of a wellbore-specific completion treatment can be achieved. This methodology of integrating data from many sources provides a better understanding of the variability and structural challenges of these complex reservoirs.
Abstract The Eagle Ford play in south Texas extends along strike from the San Marcos arch in the northeast into the Maverick Basin along the international border with Mexico. The highest initial oil production is in a strike-parallel belt between the Karnes trough and the Cretaceous shelf margin. Three lithologies comprise the bulk of the Eagle Ford Shale in this area: argillaceous mudrock (shale), calcareous mudrock (marl), and limestone. The marls consist mainly of coccoliths and contain more total organic carbon (TOC) and have higher porosities than the other lithologies. The sand- and silt-sized grains in the marls and limestones consist predominantly of planktonic foraminifera, radiolarians, and calcispheres, with lesser amounts of inoceramid fragments and other carbonate grains. The limestones may be partly to entirely recrystallized. The strength and rigidity of the rocks increase with calcite content—the limestones are stronger and more rigid than the marls. Argillaceous mudrock (shale) comprises only a small portion of the Eagle Ford between the San Marcos arch and the Maverick Basin, but is more common in the lower part of the formation along strike to the northeast. Six unconformity-bounded stratigraphic intervals (depositional sequences) can be recognized and mapped within the Eagle Ford Shale between the San Marcos arch and the Maverick Basin. Significant changes in biostratigraphy and chemostratigraphy within the Eagle Ford take place at these sequence boundaries. The Cenomanian–Turonian boundary occurs within the lower part of the Upper Eagle Ford. Typically, the Upper Eagle Ford contains less vanadium, molybdenum, uranium, and TOC than the Lower Eagle Ford, indicating bottom-water oxygen levels were oxic rather than dysoxic or anoxic during deposition. The Eagle Ford as a whole and each of its major subdivisions thin across an area in southwestern Karnes County coinciding with a structural high on the underlying Buda Limestone. The percentage of limestone within the Eagle Ford and each of its major subdivisions increases over this area. Changes in thickness and facies within the Eagle Ford suggest the area above the high on the time-structure map was a topographic high on the seafloor. Furthermore, changes in bathymetry influenced facies distribution and ultimately production from the Eagle Ford Shale. However, changes in pore pressure and fracture intensity also occur across the high, confounding the effect of facies on production.