Introduction

The San Miguel Formation of the Campanian Taylor Group, and the Olmos and Escondido Formations of the Campanian-Maastrichtian Navarro Group, consist of shale and sandstone beds that are distributed across and beneath the southern part of the Texas Gulf Coastal Plain, from the San Marcos Arch to the United States-Mexico border in Texas (fig. 1). This area encompasses the Maverick Basin, which is between the United States-Mexico border in Texas and the Frio River line (fig. 1). The formations are known from decades of research (Weise, 1979; Tyler and Ambrose, 1986; Condon and Dyman, 2006), as well as petroleum exploration that extends back to at least the 1930s (IHS Markit, 2022). Minimum estimates of cumulative liquid and gas production for the three formations are at least 170 million barrels of oil (MMBO) and 520 billion cubic feet of gas (BCFG), 130 MMBO and 2,800 BCFG, and 6.8 MMBO and 120 BCFG, respectively.

The undiscovered oil and gas resources within these formations were last assessed by the U.S. Geological Survey (USGS) in 2003 (Condon and Dyman, 2006). The mean undiscovered resource estimates were 33.22 MMBO, 1,682 BCFG, and 34.26 million barrels of natural gas liquids (MMBNGL), and the bulk of the resources (particularly the gas and natural gas liquids) was located in downdip parts of the area of investigation. Since that time, the widespread use of horizontal drilling and hydraulic fracturing has led to an increase in production rates on a per-well basis in these formations (IHS Markit, 2022). For the 2023 assessment, petroleum system elements for these formations were both adapted from previous work and updated based on new information and analysis methods.

Total Petroleum System and Geologic Model for Assessment

The San Miguel, Olmos, and Escondido Formations are part of the Upper Jurassic–Cretaceous–Tertiary Composite Total Petroleum System in onshore lands of the Texas Gulf Coast region. The primary petroleum source rock for the formations is the Eagle Ford Shale. Evidence for this includes updip-to-downdip gradients in oil American Petroleum Institute (or API) gravity that are directly correlated with thermal maturity patterns in the underlying Eagle Ford Shale (Alaniz and others, 2016), similar spatial gradients in gas-to-oil ratios (hereafter GOR) outside of the Maverick Basin (Doolan and others, 2024), and USGS analysis of biomarkers in oils produced from the San Miguel Formation (also refer to Zumberge and others, 2016).

The timing of petroleum generation and migration probably varied spatially but generally occurred during the Paleogene (Condon and Dyman, 2006; Alaniz and others, 2016). The Eagle Ford Shale is likely overpressured beneath the San Miguel, Olmos, and Escondido Formations in the assessment area (IHS Markit, 2022; refer to methods of Burke and others, 2013). Potential migration pathways from the Eagle Ford Shale include regional normal fault networks (the Balcones, Luling, and Charlotte-Jourdanton fault zones; fig. 1) and (or) fracture networks in strata that lie between source and reservoir formations (Stowell, 2001). The USGS also interprets a phase of secondary migration during inversion of the Maverick Basin, based on regional geologic observations, new apatite fission track analysis (Craddock and others, 2017), USGS one-dimensional basin modeling, and regional GOR patterns (Doolan and others, 2024), and this event may have facilitated the development of heavy oil deposits in the province (Ewing, 2011).

The San Miguel, Olmos, and Escondido Formations were deposited atop a continental margin with offshore bathymetry inherited from the Early Cretaceous (Goldhammer and Johnson, 2001; Snedden and Galloway, 2019). Strata record a variety of continental margin depositional environments, ranging from nonmarine environments updip to shallow- and even deep-marine environments downdip (Weise, 1979; Snedden and Kersey, 1982; Tyler and Ambrose, 1986; Snedden, 1991; McGovern, 2015). Net sandstone thicknesses in each of the three formations are in the range of tens to hundreds of feet (Weise, 1979; Tyler and Ambrose, 1986; Condon and Dyman, 2006). Gross formation thicknesses are in the range of hundreds to about one thousand feet.

Historically, wells were perforated within the zones of the thickest oil-bearing sandstone bodies, and updip field-averaged porosity was reported to be between 20 and 30 percent (Weise, 1979; Tyler and Ambrose, 1986; Condon and Dyman, 2006; Nehring Associates, Inc., 2018). Updip fields have both structural and stratigraphic traps (Tyler and Ambrose, 1986; Nehring Associates, Inc., 2018). The shale beds that interfinger with the sandstone reservoirs are seals for petroleum accumulations. Across the updip area, oil-water or gas-water contacts are observable in well geophysical logs, and the petroleum accumulation style is conventional.

In contrast, in the downdip area, oil-water and gas-water contacts are not demonstrable. Reservoir porosity is reduced in these areas; the highest reported values are in the range of 15 to 20 percent (Nehring Associates, Inc., 2018). Trap types are reported to be stratigraphic (Nehring Associates, Inc., 2018), and seals are the fine-grained beds that constitute most of the gross rock volume of these three geologic formations. The USGS interprets the petroleum accumulations as being continuous.

Assessment Units

The USGS defined three sets of assessment units (AUs) for each of the three formations. Each formation has an updip conventional oil and gas AU, and these are the Updip Escondido Conventional Oil and Gas AU, the Updip Olmos Conventional Oil and Gas AU, and the Updip San Miguel Conventional Oil and Gas AU. The plan-view boundaries are identical for all three (refer to fig. 1). The updip boundary for these AUs is approximately at the outcrop belt. The southwestern boundary is at the United States-Mexico border in Texas. The northeastern boundary is the San Marcos Arch; not only is this a significant structural boundary that affects the thickness of Upper Cretaceous stratal packages in the region, but it is also approximately the northeastward limit of sandstones in the formations. The downdip limit of the conventional AUs is based on the approximate boundary between conventional fields and fields that lack a clear oil-water or gas-water contact, as described above.

Each of the three formations has two sets of continuous AUs, including one set of continuous oil AUs and a second set of continuous gas AUs. The oil AUs are the Downdip Escondido Continuous Oil AU, Downdip Olmos Continuous Oil AU, and Downdip San Miguel Continuous Oil AU. The gas AUs are the Downdip Escondido Continuous Gas AU, Downdip Olmos Continuous Gas AU, and Downdip San Miguel Continuous Gas AU. The AUs within each set are also identical in plan view. The continuous oil AUs are located between the conventional AUs updip and the continuous gas AUs downdip. For the continuous oil AUs, the southwestern and northeastern boundaries are as described above. The downdip boundary was defined based on consideration of the position of the 1.3-percent vitrinite reflectance contour for the Eagle Ford Shale (Alaniz and others, 2016), as well as an approximately colocated line that divides areas of mixed oil and gas accumulations updip and gas-only accumulations downdip. However, the continuous oil AUs encompass several fields with gas-like GOR values, and, as such, the USGS expects a mix of hydrocarbon phases. Lastly, for the downdip, continuous gas AUs (identical in plan view), the updip, southwestern, and northeastern boundaries are defined based on the criteria outlined above. The downdip AU boundaries are approximately the position of the downdip Lower Cretaceous shelf margin (Snedden and Galloway, 2019), and an approximately 20-kilometer buffer is located downdip of this boundary based on observation of probable sandstone intervals in a few wells.

Previous USGS assessments (Condon and Dyman, 2006) have treated the downdip accumulations as being conventional but also noted the transitional nature between conventional and continuous accumulation types and implied that a clear delineation cannot be made in these strata. Our model involves petroleum migration from source rock into the reservoirs, and the reservoir formations must be sufficiently permeable for this to have occurred. Moreover, the USGS envisions the optimal reservoir areas to be spatially restricted to sandstone bodies owing to high permeability as well as a propensity to develop a fracture network during hydraulic fracturing. However, the lack of an identifiable gas-water or oil-water contact around the downdip edges of fields indicates the presence of a continuous petroleum accumulation within the two sets of downdip AUs. Most well completions in the past 5 years in the downdip areas have been horizontal wells with permeability stimulation through hydraulic fracturing, such that the interpretation of a continuous accumulation reflects the development methods being used through that time. Key input data for the AUs are provided in tables 1 and 2 and in Craddock (2025).

Undiscovered Resources Summary

The USGS quantitatively assessed nine AUs in the Western Gulf Basin Province of the U.S. Gulf Coast region for undiscovered oil and natural gas resources (tables 1, 2). The undiscovered resources are summarized in tables 3 and 4 and in Craddock (2025). The estimated mean total resources in the conventional AUs are 5 MMBO, 25 BCFG, and 0 MMBNGL (table 3). The estimated mean total resources in the continuous AUs are 361 MMBO, 10,978 BCFG, and 60 MMBNGL (table 4). These numbers are larger than previous estimates of the undiscovered resources in these AUs, owing to the interpretation of the resources as being continuous and the large size of the AUs.

For More Information

Assessment results and methodology information are also available at the USGS Energy Resources Program website, https://www.usgs.gov/programs/energy-resources-program.

San Miguel, Olmos, and Escondido Formations Assessment Team

William H. Craddock, John W. Counts, Colin A. Doolan, Marc L. Buursink, Celeste D. Lohr, Javin J. Hatcherian, Katherine L. French, Jared T. Gooley, Phuong A. Le, Tracey J. Mercier, Cheryl A. Woodall, and Christopher J. Schenk