Wilson, Tawnya (Pioneer Natural Resources) | Handke, Michael (Pioneer Natural Resources) | Loughry, Donny (Pioneer Natural Resources) | Waite, Lowell (Pioneer Natural Resources) | Lowe, Brandon (Pioneer Natural Resources)
Over the last decade, the growth of unconventional resource development in the Midland Basin has significantly increased the disposal of produced water volumes. Disposal into the historic Grayburg-San Andres (GYBG-SNDR) reservoir has resulted in a dynamically changing pore pressure environment relative to deeper producing formations which is important to consider when planning drilling operations throughout the basin. A deep understanding of the GYBG-SNDR geology is imperative for reservoir management to ensure that produced water disposal does not hinder oil and gas production operations. This study describes the geologic controls on porosity and permeability distributions in GYBG-SNDR across the Midland Basin by utilizing core, modern well log suites, 3D seismic data, and saltwater disposal (SWD) well data.
In 2017, Pioneer acquired more than 1,000 feet of core in three wells over the GYBG-SNDR injection interval which were used to describe the depositional and diagenetic facies and calibrate a petrophysical model for a basin-wide well log dataset. The resultant log curves were used to construct maps describing the abundance and regional distribution of each lithology, which validated and further refined the depositional model. Observations resulting from the integration of the lithology maps, 3D seismic data, well log correlations and core were used to divide the basin into three distinct areas based upon the dominant lithologies and stratigraphic architecture. The three areas are separated by two major shelf margins representing a significant sea level drop at that time. These basin-wide trends provide a regional geologic framework in which to analyze SWD well performance.
Numerous geologic maps were created and tested against quality-checked and normalized SWD well performance data. Despite some scatter in the data (due to the differences in how the wells are operated, completed, and maintained) a positive linear correlation was found between SWD well performance and permeable dolomite footage. Additionally, anhydrite is most abundant in the northeastern part of the basin and is qualitatively associated with a decrease in permeable dolomite thickness, and therefore performance. Mapped matrix permeability is enhanced by fracture permeability related to syndepositional margin collapse and reactivation of older faults during the Laramide Orogeny. These features are documented throughout the Midland Basin using proprietary 3D seismic datasets and have been shown to be conduits for fluid flow resulting in dissolution and further dolomitization in some areas.
Sinclair, Steven W. (Pioneer Natural Resources) | Crespo, Luis (Pioneer Natural Resources) | Waite, Lowell (Pioneer Natural Resources) | Smith, Kevin (Pioneer Natural Resources) | Leslie, Caitlin (Baylor University)
Any complete resource assessment of unconventional resources in a basin must include accurate delineation of marginal areas. In the northern Midland Basin, organic-rich Late Pennsylvanian/Early Leonardian mudrocks are bounded to the east, north, and west by predominantly shallow-water carbonate platform and reef deposits comprising the Eastern shelf and Glasscock Nose, Horseshoe Atoll, and Central Basin Platform. Allochthonous deep-water carbonate and siliciclastic gravity flow deposits derived from platform areas also limit hydrocarbon reserves as well as act as potential drilling hazards in certain areas. These bounding platform regions and associated deep-water flow deposits contain a complex structural and stratigraphic history that complicates resource assessment in marginal areas. A detailed mapping project of marginal regions of the northern Midland Basin utilizing available digital well logs closely tied to available 2D and 3D seismic data was therefore initiated in order to more accurately assess the resource potential of Late Pennsylvanian – Early Leonardian mudrocks of the basin.
Development of a sequence stratigraphic framework for the basin margins offers a framework that simplifies some complex basin margin relationships. Mapping and correlation of flooding surfaces, some of which correspond to existing Wolfcamp lithostratigraphic tops, and closely tying these stratigraphic surfaces to seismic response provides a more complete picture of the nature, timing, and extent of the “mid-Wolfcamp” unconformity in the Midland Basin. Seismic analysis combined with correlation of closely-spaced well logs indicates a complex history of the Glasscock Nose including periods of rapid progradation, mass wasting, erosion, and delivery of large quantities of clastic and carbonate material to slope and basin. The Central Basin Platform margin displays variable geometry in time and space but was generally aggradational during Penn-Wolfcamp time, sourcing extensive debris flows within the upper Wolfcamp interval. Seismic data augmented by well control shows clear evidence of both structurally- and stratigraphically- controlled thinning and truncation of upper Wolfcamp units along the western and eastern margins of the basin. Detailed isopaching of these units, together with mapping of carbonate percentage maps utilizing normalized gamma-ray log curves, greatly helps refine the assessment of total hydrocarbon resource in areas proximal to the shelves.
Illich, Harold (Pioneer Natural Resources USA, Inc.) | Waite, Lowell (Pioneer Natural Resources USA, Inc.) | Tinnin, Beau (Pioneer Natural Resources USA, Inc.) | Covarrubias, Edgardo (Pioneer Natural Resources USA, Inc.)
Gas and liquids produced from the Eagle Ford Formation (Cenomanian-Turonian), Edwards Formation (Middle Albian), and Wilcox Group (Late Paleocene-Early Eocene) represent resource and conventional petroleum plays that occur along the Lower Cretaceous shelf margins of South Texas. The interrelationship or independence of these petroleum systems is of considerable interest to workers seeking to expand production in the region. Gases and co-produced liquids were collected for the intervals and used as a basis of this work.
The Eagle Ford is an authentic resource play (source and reservoir for hydrocarbons). Wilcox gases and oils have been interpreted to have a source younger than the Eagle Ford, probably Paleogene Wilcox shales and/or the Midway Shale, but little data have been presented in support of this conclusion for the South Texas onshore area. The origin of gases in the Edwards reservoirs is less apparent but several possibilities can be suggested: Eagle Ford on the expanded side of the margins (southeast of the margins); Edwards basinal facies also occurring southeast of the margins; and/or older intervals such as the Pearsall shale (Aptian). Onshore, southeast of the Lower Cretaceous shelf margins, only the Eagle Ford and Tertiary intervals have been demonstrated to have significant source potential.
Gas chromatographic and isotope data were collected, analyzed, and interpreted for fifty-five Edwards, forty-nine Eagle Ford, and six Wilcox gases distributed along the Lower Cretaceous shelf margins from Lavaca County (northeast) to La Salle County (southwest). The gas data are used to conclude that the Eagle Ford is its own source and a Tertiary source provides gases and oils to the Wilcox. The main source for the Edwards is probably the Eagle Ford occurring on the expanded southeast flank of the Lower Cretaceous Shelf margins. Gases and oils in the Edwards occurring northeast of the shelf margin “cross-over” (gases from Karnes, DeWitt, and Lavaca counties) are interpreted to be mixtures of Eagle Ford and Tertiary gases (gas-gas mixing). This conclusion is supported by the occurrence of oleanane-bearing biomarkers in the geochemistry of condensates from Edwards reservoirs.
Introductions and Objectives
In the last decade, exploration and development of “resource” plays has provided an opportunity to study the geochemistry of oils and gases that are native to the formations from which they are produced. It is the goal of this presentation to acquire an increasingly robust knowledge of South Texas shelf margin petroleum systems and develop additional interpretive schemes useful in the study of such systems. Specifically, the probable sources for hydrocarbons in the Edwards, Eagle Ford, and Wilcox will be studied and processes that have acted to modify the hydrocarbon geochemistry identified. Emphasis in this study is placed mainly on the gases from these systems. The distribution of gases in South Texas used in this project is shown in Figure 1.
McGlue, Michael M. (Department of Earth and Environmental Sciences, University of Kentucky) | Baldwin, Patrick W. (Department of Earth and Environmental Sciences, University of Kentucky) | Waite, Lowell (Pioneer Natural Resources Company) | Woodruff, Olivia P. (Pioneer Natural Resources Company) | Ryan, Patrick T. (Department of Earth and Environmental Sciences, University of Kentucky)
The geological characteristics of the Wolfcamp D shale (Midland Basin) are unique relative to overlying Wolfcampian and Leonardian basinal deposits. Well log-based intrabasinal correlations to biostratigraphically dated (fusulinids) shelf carbonates suggest that the age of Wolfcamp D is late Pennsylvanian. The late Pennsylvanian was a dynamic interval of Earth's history, and the imprint of tectonic, climatic, and eustatic changes was strong on sedimentary processes and the organization of depositional environments in the Midland Basin. Orogenic belts flanked the Midland Basin to the south and east, and together with basement uplifts to the north and west, provided sources of siliciclastic sediment to available accommodation space. Because much of Gondwana was positioned over the South Pole, icehouse climatic conditions prevailed, which led to large-scale sea level fluctuations. Cyclic variability in sea levels helped to produce shelf cyclothems that have been recognized throughout much of the U.S. Midcontinent and Appalachian regions. Wolfcamp D represents a deep basinal expression of time-equivalent deposits which are an important unconventional reservoir target. At least 11 basinal cyclothems ranging from 7-10 m thick have been identified and correlated based on gamma ray and resistivity log response. Basinal cyclothems are particularly characteristic of Wolfcamp D but may also extend upward into the overlying Wolfcamp C2. Wolfcamp D cyclothems in the basin axis consist of lithofacies that stack in a repetitive and frequently predictable arrangement. Common lithofacies encountered in the cores are black organic-rich siliceous shales, grey organic- poor clayey shales, grey carbonates and brown-grey dolomites. Energy dispersive x-ray fluorescence profiles collected on core from the across Midland Basin provide further insights on mineralogy and paleoceanographic transitions during Wolfcamp D time. High frequency variability in aluminum, silica, calcium and iron likely reflect the influence of sea level on depositional patterns and processes. Concentrations of certain trace elements (including molybdenum and chromium) exhibit a positive correlation with total organic carbon, which suggests the potential for restricted bottom water circulation and a redox front positioned above the sediment-water interface. Future research will clarify microfacies characteristics and integrate additional geochemical information to better constrain the evolution of basinal cyclothems, which may ultimately have implications for completion strategies and well performance.
The Wolfcamp Shale of the Midland Basin in West Texas is emerging as one of the nation's premier liquids-rich unconventional resource plays. Multiple target zones within the very thick mudrock unit, include, from youngest to oldest, the Wolfcamp -A, -B, -C, and Wolfcamp-D. This presentation focuses on the geologic characterization of the lowermost portion of the Wolfcamp B zone, designated here as the Wolfcamp B3. Utilizing a robust, integrated geologic, engineering, and drilling data set, we discuss how the presence of thin, yet laterally extensive, carbonate stringers impact drilling performance of the unit and how these thin beds may be identified utilizing various 3D seismic inversion methods. Data from core, mud logs, wire-line logs, seismic, and drilling performance allow drill-bit rate of penetration (ROP) to be correlated to gamma-ray log response, seismic impedance, Young's modulus and formation brittleness. As a consequence, drilling performance of individual horizontal wells may be optimized by implementation of detailed, multipoint well planning and application of precise geo-steering.
A time-based approach to source rocks and associated fine-grained units employing a framework of large-scale stratigraphic sequences provides a high-level scoping tool to pinpoint the temporal position of potential organic-rich, core mudrock facies throughout Phanerozoic time. Utilizing a composite global eustacy curve taken from published sources, a total of 45 second-order flooding intervals are noted, 16 of which correspond to times of larger, more extensive, extrabasinal transgressions. Each of the 45 flooding events is associated with development of an organic-rich, core mudrock facies that has potential to serve as a local to interregional source kitchen for unconventional mudrock plays. Individual second-order core mudrock units may vary widely in terms of generative potential owing to differences in global to local geologic conditions at time of depositional and to differing post-depositional histories. Individual 2nd-order intervals must therefore be carefully assessed using a variety of geologic, geochemical, and petrophysical methods in order to define present-day resource potential.