Background and geologic model for the 2024 U.S. Geological Survey assessment of undiscovered conventional petroleum resources in the Norphlet Formation, U.S. Gulf Coast

Counts, John W.- · 2026 · Report

The Upper Jurassic Norphlet Formation is a stratigraphic unit located in the subsurface of the United States Gulf coastal plain and offshore Gulf of America

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U.S. Department of the Interior U.S. Geological Survey Scientific Investigations Report 2026-5032 Energy Resources Program Background and Geologic Model for the 2024 U.S. Geological Survey Assessment of Undiscovered Conventional Petroleum Resources in the Norphlet Formation, U.S. Gulf Coast

Cover image.  A natural gas production platform (Norphlet Formation, Mary Ann Field) rises from the waters of Mobile Bay, Alabama. Photograph by John Counts, U.S. Geological Survey.

Background and Geologic Model for the 2024 U.S. Geological Survey Assessment of Undiscovered Conventional Petroleum Resources in the Norphlet Formation, U.S. Gulf Coast By John W. Counts Energy Resources Program Scientific Investigations Report 2026-5032 U.S. Department of the Interior U.S. Geological Survey

U.S. Geological Survey, Reston, Virginia: 2026 For more information on the USGS—the Federal source for science about the Earth, its natural and living resources, natural hazards, and the environment—visit https://www.usgs.gov. For an overview of USGS information products, including maps, imagery, and publications, visit https://store.usgs.gov/or contact the store at 1-888-275-8747. Any use of trade, firm, or product names is for descriptive purposes only and does not imply endorsement by the U.S. Government. Although this information product, for the most part, is in the public domain, it also may contain copyrighted materials as noted in the text. Permission to reproduce copyrighted items must be secured from the copyright owner. Suggested citation: Counts, J.W., 2026, Background and geologic model for the 2024 U.S. Geological Survey assessment of undiscovered conventional petroleum resources in the Norphlet Formation, U.S. Gulf Coast: U.S. Geological Survey Scientific Investigations Report 2026-5032, 24 p., https://doi.org/10.3133/sir20265032. Associated data for this publication: Counts, J.W., 2024, USGS National and Global Oil and Gas Assessment Project—Norphlet Formation, assessment unit boundaries, assessment input data, and Fact Sheet data tables: U.S. Geological Survey data release, https://doi.org/10.5066/P132OJPA. ISSN 2328-0328 (online)

Contents Figures

1.  Diagrams showing generalized stratigraphic relationships of Jurassic and Cretaceous units from the eastern United States Gulf coastal plain showing the Norphlet Formation in context with other units, and a more detailed diagram showing generalized facies relationships for a portion of the stratigraphic

2.  Bar chart showing the number of wells spud per year since the initial Norphlet Formation discovery well at Pelahatchie field at Pelahatchie field in 1967

3.  Map showing general distribution of known Norphlet Formation oil and gas

4.  Map showing a paleogeographic reconstruction of central Pangea, including the major continental masses of Laurentia and Gondwana, at the time of

5.  Schematic diagram showing generalized facies relationships and interpreted depositional environments within the Norphlet Formation and adjacent

6.  Maps of Norphlet facies showing the consistency in Norphlet Formation

7.  Geophysical logs and interpreted lithology from a representative well log of the Norphlet Formation interval and overlying units from the Pearl River Valley

8.  Diagram showing representative burial history profile of rock units for south

9.  Diagrams showing examples of petroleum-trapping mechanisms in the

10.  Maps indicating increasingly restrictive boundaries that assisted in determining boundaries of U.S. Geological Survey 2024 assessment Norphlet Conversion Factors U.S. customary units to International System of Units Multiply By To obtain Length foot (ft) meter (m) mile, nautical (nmi) kilometer (km) Volume barrel (bbl; petroleum, 1 barrel=42 gal) cubic meter (m3) cubic foot (ft3) cubic meter (m3) Pressure pound per square inch (lb/in2) kilopascal (kPa) International System of Units to U.S. customary units Multiply By To obtain Length meter (m) foot (ft) kilometer (km) mile (mi) Area square centimeter (cm2) square inch (in2) square kilometer (km2) square mile (mi2) Temperature in degrees Celsius (°C) may be converted to degrees Fahrenheit (°F) as follows: °F (1.8 × °C) + 32. Supplemental Information A millidarcy (mD) is a unit used to measure permeability equal to 1/1000 of a darcy. A darcy is the volume in cubic centimeters of water of 1 centipoise viscosity flowing in 1 second through an area of 1 milliliter under a pressure gradient of 1 atmosphere per square centimeter (cm2) per centimeter (Lohman and others, 1972).

Abbreviations AAPG American Association of Petroleum Geologists AU assessment unit BBO billion barrels of oil BBOE billion barrels of oil equivalent BOEM Bureau of Ocean Management BCFG billion cubic feet of gas GR gamma ray Ma mega-annum MMBNGL million barrels of natural gas liquids MMBO million barrels of oil NGL natural gas liquids Ro vitrinite reflectance TCFG trillion cubic feet of gas TPS Total Petroleum System USGS United States Geological Survey

Background and Geologic Model for the 2024 U.S. Geological Survey Assessment of Undiscovered Conventional Petroleum Resources in the Norphlet Formation, U.S. Gulf Coast By John W. Counts Abstract The Upper Jurassic Norphlet Formation is a stratigraphic unit located in the subsurface of the United States Gulf coastal plain and offshore Gulf of America (Gulf of Mexico). The Norphlet consists of clastic sediments derived from the southern Appalachian highlands, and was deposited in a continental dryland setting on the margins of the early Gulf of America rift basin. The formation contains a variety of sedimentary facies, including facies representing updip alluvial fans, wadis, red beds, and a widespread erg, or eolian sand sea. The erg facies form the primary reservoirs from which hydrocarbons sourced from the overlying Smackover Formation are produced. Development of the Norphlet began in earnest in the late 1960s, with new discoveries, including large fields at Flomaton, Hatters Pond, and Mobile Bay, continuing through the 2000s-2010s with the discovery of major oil fields in the offshore Desoto Canyon area. Onshore, Norphlet hydrocarbon traps typically are faulted salt anticlines, although many fields also have a stratigraphic trapping component because of the preservation of dune-scale bedforms. Thermal maturity across the Norphlet play varies significantly with depth, resulting in oil production transitioning downdip to natural gas liquids production, then dry gas production; production depths reach to greater than 21,000 feet. A 2024 U.S. Geological Survey assessment divided the Norphlet into four conventional assessment units defined by the type and frequency of trapping mechanisms, sedimentology, and thermal maturity of each area, with little potential for hydrocarbon development observed west of the Mississippi River. Although petroleum resources in the Norphlet were revised downward, it is probable that significant resources remain to be discovered. Plain Language Summary Understanding how rocks that contain oil and gas were formed and how they changed through geologic time is important for estimating undiscovered oil and gas. The Norphlet Formation is a complex rock unit that lies entirely underground in the United States Gulf Coast region. Some rocks in the Norphlet were originally deposited as dunes in a large, sandy desert, and are good oil and gas reservoirs. Some Norphlet Formation rocks were broken up by the movement of salt deposits under the Norphlet. This movement and other faulting helped form areas where oil and gas generated from overlying rocks was trapped in the Norphlet. Shallower parts of the Norphlet generally contain oil, and deeper, higher temperature parts of the Norphlet generally contain gas. The Norphlet Formation has seen less petroleum development as compared to some of the more accessible rocks in the same region because it is harder to drill for oil or gas in deeper, hotter rock. The U.S. Geological Survey estimates that about 16 million barrels of oil, 348 billion cubic feet of gas, and 19 million barrels of natural gas liquids remain undiscovered in the Norphlet Formation. Introduction The Norphlet Formation is a regionally extensive, predominantly continental clastic deposit present in the subsurface of the Gulf coastal plain area of the southern United States of America, primarily in Mississippi, Alabama, and Florida. The formation conformably overlies the Louann Salt and disconformably overlies the Werner Formation, the Eagle Mills Formation, or Paleozoic basement rocks (Salvador, 1991) (fig. 1). The age of the Norphlet is generally thought to be Late Jurassic (Salvador, 1987, 1991), specifically Oxfordian (161.5 to 154.8 mega-annum [Ma]; refer to Cohen and others, 2013) because the overlying Smackover Formation contains upper Oxfordian ammonites (Hudec and others, 2013). However, some authors regard the Norphlet as primarily Callovian (Mancini and others, 2002) (165.3 to 161.5 Ma). The Norphlet Formation is not exposed in outcrop and is only known from subsurface well penetrations. Both the depth to the top of the formation (less than 5,000 feet [ft] to greater than 21,000 ft) and the thermal maturity vary spatially, with downdip areas to the southwest being deeper and hotter

2    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation (Mink and others, 1989; Dixon and others, 1989). Updip areas are oil mature, although gas and natural gas liquids (NGL) are produced in conjunction with oil throughout much of the play (S&P Global Commodity Insights, 2023). Petroleum in the Norphlet Formation is mainly thought to be sourced from the overlying Smackover Formation (Sassen, 1990), making the petroleum system unusual within the Western Gulf Basin Province because most other reservoirs are sourced from below. In western Mississippi, the Norphlet Formation produces high-purity carbon dioxide from some areas surrounding the Jackson Dome volcanic intrusion (Dockery and others, 1997) Production of the carbon dioxide was, at least in part, related to the thermal breakdown of carbonates during emplacement of the magma body during the Late Cretaceous magmatic intrusion, which may have swept the system of hydrocarbons (Zhou and others, 2012). Glen Rose Formation Pearsall Formation Hosston Formation Cotton Valley Group Haynesville Formation/Gilmer Limestone Norphlet Formation Louann Salt Trinity Group Sligo Formation Buckner Formation Smackover Formation Regional unconformity Cotton Valley Group Hosston Fm. Norphlet Formation Schuler Formation Basement Buckner Formation Louann Salt Smackover Formation Limestone of the Haynesville Formation Knowles limestone Gilmer Limestone Shale of the Haynesville Formation Bossier Formation Cretaceous Jurassic Fm. NOT TO SCALE NOT TO SCALE Carbonates Erosion or nondeposition Sand Silt Shale Gypsum Paleozoic basement; mixed lithologies Salt Contact—Dashed where approximate Unconformity Interfingering contact Pinnacle reef development Formation EXPLANATION Generalized eastern U.S. Gulf coast plain stratigraphy Figure 1.  Diagrams showing generalized stratigraphic relationships of Jurassic and Cretaceous units from the eastern United States Gulf coastal plain showing the Norphlet Formation in context with other units, and a more detailed diagram showing generalized facies relationships for a portion of the stratigraphic column, including the Norphlet. Generalized stratigraphic column on left modified from Salvador and Quezada Muñeton (1991); generalized detailed facies relationships on right modified from Hammes and others (2011) and Goldhammer (1998). Some units in the facies relationship diagram are not shown in the stratigraphic column because of scale or the nature of the facies relationships.

Introduction    3 The Norphlet was first drilled in 1935 and formally named in 1947 (Godo, 2017). Petroleum production began in 1967 when the Pelahatchie prospect in Mississippi yielded high-pressure oil. To date, approximately 30-50 Norphlet fields, comprising approximately 200-400 wells (fig. 2), have been designated in Alabama, Florida, Mississippi, and Texas (S&P Global Commodity Insights, 2023), although these fields are concentrated in Mississippi and Alabama (fig. 3). Most of these fields are considered small producers, with less than 1 to 5 million barrels of oil (MMBO) recovered. The largest oil field producing from the formation is the Flomaton Field on the Alabama-Florida border, from which 10 MMBO had been recovered by 1984 (Godo, 2017). In the late 1970s, exploration in south Alabama led to development of wells in shallow water in and around Mobile Bay, where Norphlet sands were discovered to produce dry natural gas at high rates from wells drilled to greater than 21,000 feet deep. Norphlet reserves in this area have been estimated to be 4.9 to 8.1 trillion cubic feet of gas (TCFG; Mancini and others, 1987), with over 5.5 TCFG produced from the Norphlet (S&P Global Commodity Insights, 2023). More recently, Norphlet reservoirs have proven productive in the offshore Gulf of America (Gulf of Mexico) area. Discoveries in the Desoto Canyon area (fig. 3) from 2003 to 2017 resulted in Norphlet oil wells with the largest cumulative production volumes for the Norphlet through 2023 (Godo, 2017, 2019; S&P Global Commodity Insights, 2023). Total cumulative production from all Norphlet wells to date is approximately 66 MMBO and 6 TCFG. Maximum drilling activity in the Norphlet reached a peak in the 1990s and early 2000s, but other recent offshore and onshore drilling and production activity prompted the creation of a new assessment for the Norphlet Formation (Counts, 2024). U.S. Geological Survey (USGS) assessments estimate the numbers and sizes of fields of a minimum size, defined as 0.5 MMBO or 3 billion cubic feet of gas (BCFG) within a given area, or assessment unit (AU). The assessment methodology assigns probabilities and ranges to potential field numbers and sizes, as detailed in Charpentier and Klett (2007). The USGS released assessments of the Norphlet Formation in 1996 and 2011. The first assessment examined the Norphlet Formation as part of a wider Gulf Coast assessment project (Schenk and Viger, 1996), and divided the formation into six conventional AUs that extended from the Florida Panhandle to eastern Texas. The AUs included an updip oil AU; oil and gas AUs centered around the Mississippi Interior Salt Basin; and two downdip gas AUs in the Alabama, Mississippi, and Florida panhandles. The area where hydrocarbons are generally absent immediately around Jackson Dome was not included in the assessment, although the area where production does occur around the Jackson Dome flank was separated into its own small AU. The westernmost AU in southeast Arkansas and east Texas was not assessed quantitatively. The second assessment of the Norphlet by the USGS in Dubiel and others (2011) only utilized three AUs: a Salt Basins and Updip AU, a Deep Gas AU, and a South Texas Gas AU. This assessment resulted in undiscovered mean petroleum accumulations of approximately 53 MMBO in oil fields and 34 MMBO from gas fields in the Salt Basins and Updip AU only; and 1.5, 1.7, and 0.2 TCFG from the Salt Basins and Updip AU, the Deep Gas AU, and the South Texas Gas AU, Year Number of wells spud Figure 2.  Bar chart showing the number of wells spud per year since the initial Norphlet Formation discovery well at Pelahatchie field in 1967 through 2019. Data from S&P Global Commodity Insights (2023); reported numbers of wells spud may be inexact because of the way production is reported.

4    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation East Mississippi 33° 32° 31° 30° 29° 92° 91° 90° 89° 88° 87° 86° 85° 150 KILOMETERS 150 MILES EXPLANATION Anticline—Arrows show direction

of plunge from axis Plunging anticline—Arrows show

direction of plunge from axis Approximate downdip limit of the

Mississippi Interior Salt Basin Peripheral fault system Gas field and identifier Hatters Pond LOUISIANA MISSISSIPPI ALABAMA FLORIDA GEORGIA Hatters Pond Flomaton South Alabama Monroe Uplift Mobile Graben Manila Sub-basin Choctaw Ridge Complex Conecuh Sub-basin Pensacola Arch Baldwin Arch Southern Platform Middle Ground Arch Apalachicola Embayment Apalachicola Embayment Conecuh Ridge Complex Wiggins Arch Jackson Dome Mississippi Interior Salt Basin Jackson Dome Mobile Bay Desoto Canyon Jackson Dome Flank GULF OF AMERICA Base from Natural Earth 1:10,000,000-scale digital data, 2024 U.S. Geological Survey digital data, 2024 Geographic coordinate system North American Datum of 1983 Figure 3.  Map showing general distribution of known Norphlet Formation oil and gas accumulations. Only significantly developed areas are shown; other small fields exist outside of these areas, and each of the delineated red areas may contain multiple individual fields. Production data from S&P Global Commodity Insights (2023); structural features from Mancini and others (2003, 2004).

Stratigraphy, Sedimentology, and Depositional Environments    5 respectively. Also, 64, 3, and 8 million barrels of natural gas liquids (MMBNGL) were assessed from the Salt Basins and Updip AU, the Deep Gas AU, and the South Texas Gas AU, respectively. In the offshore Gulf of America, the Norphlet Formation has been assessed by the Bureau of Ocean Energy Management (BOEM), which examines the U.S. Outer Continental Shelf on a five-year cycle. In 2011, 2017, and 2021, the BOEM assessed the Norphlet as having the most undiscovered, technically recoverable reserves in the Gulf of America Outer Continental Shelf for all Mesozoic strata (BOEM, 2011, 2017, 2021). In 2021, the BOEM assessment indicated mean values of 3.36 billion barrels (BBO) of oil, 6.18 TCFG, and 4.45 billion barrels of oil equivalent (BBOE) (BOEM, 2021). The BOEM (2021) assessment numbers indicated significant offshore potential for hydrocarbon production from the formation, although the Outer Continental Shelf area is outside of the assessment domain of the USGS, which is limited to onshore and within the three-nautical-mile State Waters boundary. Stratigraphy, Sedimentology, and Depositional Environments In Oxfordian time, the Gulf of America was an incipient rift basin that was initiated during the active separation of the continents of Laurentia and Gondwana earlier in the Jurassic (Worrall and Snelson, 1989) (fig. 4). Continental sediments of the Norphlet Formation were deposited on the margins of this basin, onlapping the high-relief Appalachian Mountains to the north and grading into marine carbonates in the basin center to the south (Mancini and others, 1985a). Norphlet deposition was approximately coeval with the latest Oxfordian thermal maximum, a period of warm temperatures within the otherwise cool interval during the Late Jurassic- Early Cretaceous (Scotese and others, 2021). This period of warming, combined with the low-latitude paleogeography of central Pangea during this time led to the development of a dryland environment, including a large erg (sand sea) that formed the heart of the Norphlet play. Deposition generally took place over Paleozoic basement or relatively thin Triassic sediments, with nondeposition and erosion on basement highs on the rift shoulder and concomitant thickening in the topographic lows. The presence of these highs, including the Wiggins, Pensacola, and Middle Ground arches, resulted in the irregular updip margin of the formation that is observed in the modern extent of the Norphlet (Hunt and others, 2017). Additional irregularity in the thickness of the formation is a product of both syn- and post-depositional salt movement. The thick Louann Salt that was deposited across the area early in the process of rift formation is upwardly mobile in onshore areas and laterally mobile in parts of the offshore areas. Salt movement is especially prevalent in the Mississippi Interior Salt Basin, where many salt diapirs penetrate into Cenozoic strata across the basin (Thieling and Moody, 1997). Both large, regional-scale fault systems near the northeastern margin of the formation and smaller fault systems present throughout the formation that are (often associated with salt movement) also affect the thickness and structure of the Norphlet Formation (Mancini and others, 1985b; Marzano and others, 1988). Various lithofacies have been recognized in the Norphlet, including a shale at the base of the formation, a conglomeratic sandstone, "red beds," (terrestrial clastic facies) quartzose eolian sandstone, and sandstone formed from marinereworked sands (Badon, 1975; Wilkerson, 1981; Pepper, 1982; Mancini and others, 1985a) (fig. 5). Most of these sediments except for the basal shale were deposited in a variety of dryland continental environments (fig. 6). Underlying many of the continental facies that form the majority of the unit is a dark, basal shale (fig. 5), composed of laminated, argillaceous material (Badon, 1975). Little is known about this basal Norphlet lithofacies; it has been hypothesized to have been deposited in isolated lagoons or bays and predates most of the Norphlet Formation deposition (Mancini and others, 1985a). Other Norphlet Formation facies lie above the basal shale. On the northeastern updip side of the formation, poorly sorted, immature, conglomeratic sandstones occur in the areas that are nearest to Appalachian bedrock (Pepper, 1982). These sandstone facies are interpreted as alluvial fan and wadi (dryland ephemeral river) deposits that originated from igneous and metamorphic basement rocks that were exposed in high relief during deposition of the Norphlet (fig. 5). Within these deposits are granule- to cobble-sized clasts of chert, shale, quartzite, granite, and rhyolite (Lisi, 2013). These deposits are poorly sorted, and have a high clay content and a wide range of grain sizes in the clasts, indicating that deposition was the product of debris flow processes, likely in a subaerial environment (Mancini and others, 1985a). These poorly sorted, immature, conglomeratic sandstones span the breadth of the formation from Florida to Mississippi, are generally considered to be of poor reservoir quality, and are not considered prospective for hydrocarbons. Adjacent to and downdip (to the southwest) from these poorly sorted, immature sandstones are sediments that were deposited in slightly more distal environments from the exposed basement rocks. These deposits are generally finer-grained and better-sorted sandstones that interfinger with updip alluvial fan deposits to the north and eolian dune deposits to the southwest. These sands are interpreted as having been part of a broad, alluvial plain with associated fluvial deposits representing dryland rivers that drained the highlands and transitioned into the Norphlet erg system (Mancini and others, 1985a; Marzano and others, 1988). Paleosol development, including weathering and iron oxidation, occurred on these fluvial and alluvial deposits, forming "red bed" sandstones that compose much of this facies (fig. 5). Like its updip equivalent, this facies is generally considered to contain lower quality reservoir rocks that are "tight" (low permeability) and not productive, although bettersorted dune sands may occur locally.

6    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation The primary facies for which the Norphlet Formation is known is downdip from the alluvial fan, wadi, and alluvial plain environments. The erosion of the Appalachian structural front in conjunction with warm, arid conditions and favorable winds created a vast accumulation of eolian sands across hundreds of square kilometers (fig. 5). This erg environment in the Gulf Coast region only appeared during Norphlet deposition, and is comparable to the environment found in the modern Namib Desert in southern Africa (Douglas, 2010). Modern erg facies consist of shifting dunes composed of loose, fine- to medium-grained quartzose sand that dominate the region, often in forms defined by the prevailing wind directions. Many of these dune forms remain preserved in the Norphlet subsurface with original dune morphologies (for example, linear, barchan, or star-shaped dune forms) visible in seismic data, and with cross-stratification (typically inclined up to 20-30 degrees) preserved in cores (Hunt and others, 2017). In the Mobile Bay area, preservation of Norphlet dune morphologies was enhanced by differential subsidence into the underlying salt (Mankiewicz and others, 2009; Ajdukiewicz and others, 2010). Other sedimentary structures and subfacies are also preserved, such as fine sediments representing wet interdune areas that can be found between dune forms, as well as microfacies within dunes themselves, such as windripple and avalanche facies that are products of specific eolian processes (Ajdukiewicz and others, 2010). These small-scale facies changes that occurred during depositional processes can have a first-order effect on the porosity and permeability Approximate paleo-equator Norphlet Formation depositional area Yucatan Plate Gondwana Pangea Laurentia N Appalachian Mountains Incipient Gulf of America Ancestral Rocky Mountains Panthalassa Figure 4.  Map showing a paleogeographic reconstruction of central Pangea, including the major continental masses of Laurentia and Gondwana, at the time of Norphlet Formation deposition. Modified from Scotese (2016).

Stratigraphy, Sedimentology, and Depositional Environments    7 of Norphlet sediments, with porosity values reaching as high as 21 percent and permeability of 500 millidarcies (mD) in avalanche deposits, and as low as 4 percent porosity and permeability of 0.07 mD in interdunes (Taylor and others, 2004). Changes in facies type can occur over a vertical scale of tens of feet, potentially compartmentalizing reservoirs at a small scale. However, the net thickness of sands in some areas may be greater than 400 feet in some Mobile Bay Norphlet dunes. Eolian sediments in the Norphlet Formation of south Alabama and Mobile Bay are arkosic, subarkosic, and lithicarkosic with discontinuous illite rims (Ajdukiewicz and others, 2010). In Mississippi, dune sands in the Norphlet are arkoses and graywackes with approximately 85-90 percent quartz content (Badon, 1975). Evidence from detrital zircon U-Pb geochronology indicates that these sediments were mainly sourced from Laurentian bedrock, with large zircon populations that have ages centered around the Grenville (1,300-950 Ma), Taconic-Acadian (490-350 Ma), and in some wells, Alleghenian (330-260 Ma), times (Lisi, 2013; ages as defined in Thomas and others, 2017). These detrital zircon populations are characteristic of an Appalachian detrital zircon signature. A suite of Neoproterozoic-Cambrian zircon ages also indicates partial contribution from Gondwana, likely the Suwanee terrane, which is now attached to the North American craton and entirely buried beneath the coastal plain (Lisi, 2013). Norphlet deposition ended in the Late Jurassic, with the overall time interval represented by the formation likely encompassing only a few million years. The continued movement and breakup of Pangea outside of the "horse latitudes" (calm, dry areas with high atmospheric pressure that lie between tropical trade wind belts and more temperate areas) led to the cessation of the winds that were critical for eolian deposition (Peterson, 1988). A global sea-level rise also played a role, leading to a marine transgression that reworked sands at the top of the Norphlet (fig. 5), resulting in the Denkman Sandstone unit (Tyrrell, 1973), and ultimately, the deposition of the Smackover Formation that blanketed the entire Gulf Coast in carbonates (Mancini and others, 2019). Variability in sand content can be interpreted using readings from gamma-ray and other geophysical logs from wells in the Norphlet, where interpreted transitions from muddier to cleaner sands likely indicate small-scale changes in the environment as dunes and wadis shifted through time (fig. 7). NOT TO SCALE Updip Downdip Louann Salt Marginal marine shale Marginal marine shale Paleozoic basement (Appalachian orogen) Reworked marine sands Dune and interdune (eolian) sands Alluvial and wadi sands, redbeds Alluvial fan conglomerates and sands Carbonates of the Smackover Formation Norphlet Formation facies belts Figure 5.  Schematic diagram showing generalized facies relationships and interpreted depositional environments within the Norphlet Formation and adjacent formations in the United States Gulf coastal plain area. Modified from Wilkerson (1981) and Mancini and others (1985a).

8    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation EXPLANATION Sabkha/coastal sand sheet Eolian erg Eolian erg margin Fluvial wadi Lake Eolian fore-erg Carbonate Shelf Sediment-starved or erosion Contact B Shiloh EXPLANATION Smackover Sea Alluvial fan sediments Wadi and Eolian sediments Dune and interdune sediments Appalachian Foreland Basin Ancient Appalachian Mountains Mesozoic Rift Basin Suwanee terrane Contact Selected Norphlet field and identifier LOUISIANA ALABAMA FLORIDA GEORGIA GULF OF AMERICA Mobile Bay Vicksburg Shiloh Base from Natural Earth 1:10,000,000-scale digital data, 2024 U.S. Geological Survey digital data, 2024 Geographic coordinate system North American Datum of 1983 100 KILOMETERS 100 MILES 32° 30° 28° 90° 88° 86° 32° 90° 88° 86° 30° Base from Natural Earth 1:10,000,000-scale digital data, 2024 U.S. Geological Survey digital data, 2024 Universal Transverse Mercator, zone 16 north North American Datum of 1983 100 KILOMETERS 100 MILES EXPLANATION Basement Alluvial Fluvial Eolian (sheetsand) Eolian (dune) Marine carbonate shale Uninterpreted Contact LOUISIANA GULF OF AMERICA MISSISSIPPI ALABAMA FLORIDA GEORGIA A N Figure 6.  Maps of Norphlet facies showing the consistency in Norphlet Formation mapping over several decades. Patterns, facies names, and interpretations have been retained from the original maps with minor spelling standardization. A, Modified from Marzano and others (1988); B, Names on the map indicate oil and gas fields or prospects; modified from Lovell (2010); C, State lines not available in original data; modified from Snedden and Galloway (2019). These maps were used to assist in delineating assessment unit boundaries.

Stratigraphy, Sedimentology, and Depositional Environments    9 16,100 16,000 16,200 14,500 14,600 14,700 14,800 14,900 15,000 15,100 15,200 15,300 15,400 15,500 15,600 15,700 15,800 15,900 16,300 16,400 GR GR DPHI (DPOR) NPHI (NPOR) LITH res. Fm. 10-inch res. 2,000 90-inch res. 2,000 NPHI (NPOR) −5 DPHI (DPOR) −5 10 ohm LITH Fm. Buckner and Haynesville Formations, undivided Smackover Formation Norphlet Formation EXPLANATION Lithologic unit Contact Neutron-density crossover Perforation Gamma ray Density porosity Neutron porosity Lithology Resistivity Formation Depth in feet Sandstone Shale Carbonate Anhydrite Figure 7.  Geophysical logs and interpreted lithology from a representative well log of the Norphlet Formation interval and overlying units from the Pearl River Valley Authority 13-10-1 well, API 23089201290100, Madison County, Mississippi. Data provided by the Mississippi Oil and Gas Board and digitized by the U.S. Geological Survey. Well log data are available at: https://ws.ogb.state.ms.us/ MSOGBOnline/DataMining.html?EntityType=Well&EntityKeyName=WellID&EntityKeyValue=2308920129&DETAILSONLY=True.

10    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation Petroleum System Source Rocks and Seals Unlike most reservoirs found in the Gulf Coast area, oil and gas in the Norphlet Formation is sourced from an overlying unit, the Smackover Formation. Oil and gas from Norphlet reservoirs have been geochemically typed to the Smackover (Claypool and Mancini, 1989), and the Norphlet does not have much self-sourcing potential (Sassen and others, 1987). Where source rocks overlie rather than underlie a reservoir, there are specific conditions that must be met to facilitate the downward migration of hydrocarbons. As summarized in Godo (2019), these conditions include not only basic aspects of the petroleum system, such as sufficient permeability of the reservoir and thermal maturity of the source rock (in this case, a minimum vitrinite reflectance [Ro] value of 0.9), but also a relatively underpressured reservoir that promotes the movement of petroleum against a typical lithostatic pressure gradient, creating a pressure sink. This type of pressure sink is associated with highly permeable sandstones with lateral continuity (Godo, 2019). Without high permeability in a reservoir, downward oil charging is unlikely to occur. There are unsuccessful plays, such as the Petersburg and Fredericksburg plays in the offshore Gulf of America (Godo, 2019), that have all of the components needed for petroleum accumulation except for high permeability. The Smackover Formation is present in the subsurface across the entire Gulf Coast region and is composed primarily of carbonates that were deposited in a variety of marine environments from deep to shallow marine waters (Whidden and others, 2023). The formation varies considerably across the basin, with carbonate lithologies that typically are several hundreds of feet thick (Mancini and Benson, 1980). In places, fluvial-deltaic clastics were deposited within the carbonate sequence and resulted in increased formation thickness (Birdwell and others, 2024). Source-rock properties also vary spatially and vertically, but overall, are favorable to hydrocarbon generation. Laminated algal carbonate mudstones may contain high total organic carbon (TOC) values, with many of these rocks having TOC values of greater than 1 percent (Counts and others, 2021). The rocks deposited during the time of maximum flooding that are found near the middle of the formation represent the most prospective source rocks (Godo, 2019). Mancini and others (1999) reported Smackover TOC values from Oehler (1984) of up to 2.54 percent in Mississippi. Kerogen in the basinal areas of the Mississippi Interior Salt Basin region typically is amorphous or algal, although updip areas may contain herbaceous kerogen that is more prone to gas generation (Oehler, 1984; Sassen and others, 1987; Wade and others, 1987; Claypool and Mancini, 1989). Sassen (1990, p. 265) noted that oils produced from the Smackover in Alabama and Florida "reflect an origin from kerogen with a terrestrial component preserved in a less anoxic environment" as compared to oils that are produced from the Smackover to the west in Texas and Louisiana, which indicate an anoxic, algal-derived origin. In the Mississippi Interior Salt Basin, basinal Smackover Formation source rocks entered the "oil window" (when heat and pressure combined generate oil from kerogen) during the Early Cretaceous, and updip regions entered the oil window by the Late Cretaceous (Mancini and others, 1999). Both updip and basinal areas had continued petroleum generation into the Cenozoic. Similarly, Smackover source rocks for the deep gas fields of south Alabama also entered the oil window in the Early Cretaceous (fig. 8; Mancini and others, 2003; Mankiewicz and others, 2009). Areas on the northernmost updip side of the Norphlet eolian facies in Mississippi and Alabama (for example, those in the Nancy and Prairie Branch Fields of Clarke County, Mississippi) are only within the early oil maturity window (Ro values of 0.6-0.8 percent). Thermal maturity increases downdip, and much of the Norphlet Formation in the Mississippi Interior Salt Basin and south Alabama areas are in the peak oil to late oil windows. In the Mobile Bay area, gas has been generated since approximately the Campanian- Maastrichtian (Dixon and others, 1989); modern temperatures in the formation surpass 200 degrees Celsius (°C) and Ro values reach greater than 2.5-3.0 percent, indicating a thermal maturity that is in the dry gas window. This thermal maturity is indicated by examining past production from this area, where fewer liquids have been produced to date compared to gas volume (S&P Global Commodity Insights, 2023). Reservoir Properties and Diagenesis Most porosity in the Norphlet Formation is preserved primary porosity, although the formation contains a variety of cement types that have significant effects on petroleum reservoir capacity (Kugler and McHugh 1990; Schmoker and Schenk, 1994; Taylor and others, 2004; Ajdukiewicz and others, 2010). Varied amounts of quartz, illite, halite, dolomite, pyrite, and chlorite cements are found in the Norphlet and in conjunction with other diagenetic processes such as dissolution, and pressure solution or stylolitization, can affect porosity and permeability. While diagenetic processes were detrimental to reservoir quality in the formation, other processes, such as chlorite cementation, were important for the preservation of porosity by inhibiting deposition of later porosity-occluding cements. Some studies have concluded that where initial porosity in the Norphlet was high because of favorable depositional processes, early chlorite coatings on the surfaces of eolian or erg-deposited sand grains preserved primary porosity that created favorable petroleum reservoir conditions (Dixon and others, 1989; Ajdukiewicz and others, 2010). Other cement types in the Norphlet generally destroyed porosity, including late-stage dolomite, albite, quartz, calcite, and pyrite cements. Louann evaporites below the Norphlet Formation are highly prone to dissolution and were the probable source of many of the Norphlet cements (Kugler and McHugh, 1990), including halite (Schenk and Schmoker, 1993).

Petroleum System    11 Trap Formation Salt movement is responsible for trapping hydrocarbons in almost all Norphlet accumulations (Tew and others, 1991). The structure of Norphlet fields shows three- or four-way closures that are often associated with normal faulting and salt movement adjacent to the fault (Mancini and others, 1985a). Published maps and descriptions of Norphlet fields, including the Pelahatchie, Copeland, Chavers Creek, Sizemore Creek, Flomaton, and Hatters Pond fields (Mancini and others, 1985a; Ginger and others, 1995), show anticlinal structures where Norphlet sands within the eolian and wadi facies are cored by salt domes (fig. 9A-C). Other trap types are also present in the formation (fig. 9D-G). In the Mississippi Interior Salt Basin, salt movement is complex and occurs at a variety of scales, leading to other potential trap styles associated with salt movement (fig. 9D). In the Mobile Bay area, which includes multiple fields, trapping geometries are also complex. Individual linear dune structures may be compartmentalized because of facies changes (for example, lower porosity interdune facies between eolian dune forms), separation by salt walls due to differential subsidence of dunes into the underlying Louann evaporites, normal faulting, or a combination of these trapping mechanisms (fig. 9E, G; Mankiewicz and others, 2009). Updip and north of the Mississippi Interior Salt Basin, where salt movement is not as prevalent, structures created by basement highs may also assist in trapping hydrocarbons in Norphlet reservoirs (fig. 9F). Offshore in the Gulf Coast area, salt tectonic movement fundamentally differs from that observed in onshore provinces in several ways, including the presence of allochthonous salt canopies that are not observed onshore (Pilcher and others, 2014). Large salt rafts that have moved laterally downdip as far as 25-30 kilometers from their original location, combined with faulting and lithologic changes, create opportunities for compartmentalization and trapping of hydrocarbons (Godo, 2017; 2019; Snedden and Galloway, 2019). Therefore, because of the differences in salt tectonics, new offshore discoveries are unlikely to affect play concepts within onshore areas. Assessment Parameters Conventional Versus Continuous Assessment Units USGS petroleum assessments have used a set of standardized but qualitative criteria to determine whether oil and gas plays can be defined as conventional or continuous Selma Group Eutaw Formation Paluxy Formation Mooringsport Formation Hosston Formation Cotton Valley Group Haynesville Formation Smackover Formation Norphlet Formation Tuscaloosa Formation Tertiary strata Unit tops Subsurface depth, in feet Age, in millions of years 5,000 10,000 15,000 20,000 0 API 01-129-20012 EXPLANATION Contact Sandy shale Shaley sandstone Limestone Sandstone Shale Figure 8.  Diagram showing representative burial history profile of rock units for south Alabama well McClure 5-12 #1, API 0112920012. Modified from Mancini and others (2003).

12    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation −18,250 −18,200 −18,150 −18,100 −18,050 −18,500 −18,550 −18,450 −18,400 −18,350 −18,300 −18,000 −17,950 −17,900 −17,850 −17,800 −17,750 −17,700 −17,650 −17,600 −17,550 1 KILOMETER 1 MILE 1.5 KILOMETER 1.5 MILE EXPLANATION Contour line Contour line Fault Fault Well penetration Well penetration Contour line Fault Well penetration Evaporites N A N EXPLANATION −15,700 −15,650 −15,600 −15,550 −15,500 −15,450 −15,400 −15,350 −15,300 −15,250 −15,200 −15,150 −15,100 −15,050 −15,000 B N −12,800 −12,700 −13,000 −12,900 −13,200 −13,100 −13,400 −13,300 −13,500 −13,600 −13,600 −13,500 −13,400 −13,700 −12,000 −11,900 −12,200 −12,100 −12,400 −12,300 −12,500 −12,600 −12,600 −12,500 −12,400 EXPLANATION Fault block A Fault block B Fault block C Fault block A Fault block B Fault block C Top of Norphlet Formation structure

map of strata—Contour interval 100

feet. Datum is sea level Top of Norphlet Formation

structure map of strata—

Strat interval 50 feet.

Datum is sea level Top of Norphlet Formation

structure map of strata—

Strat interval 50 feet.

Datum is sea level 2 KILOMETERS 2 MILES Figure 9.  Diagrams showing examples of petroleumtrapping mechanisms in the Norphlet and Smackover Formations. A-C, Structure maps of faulted, salt-cored anticlines found in A, Hatters Pond (refer to figure 3 for location); contours depict top of Smackover Formation in feet below sea level; modified from Ginger and others (1995); B, Flomaton (within labeled area "Florida- Alabama" in fig. 3) contours depict top of Norphlet Formation in feet below sea level; modified from Mancini and others (1985a); and C, Pachuta Creek/Nancy/East Nancy/Prairie Branch fields (within northernmost "East Mississippi" polygon in fig. 3); contours depict top of Smackover Formation in feet below sea level; modified from Badon (1973). D, Schematic cross-section depiction of salt structures in the Mississippi Interior Salt Basin, indicating where potential traps may occur; modified from Montgomery and Ericksen (1997). E, Gross porous isochore map of Norphlet sand dunes illustrating linear dune forms where higher porosity reservoir facies may be separated by lower porosity interdune fines, forming a stratigraphic trap. This map shows depth from surface to the top of a unit, indicating relative thickness (thick to thin). Modified from Ajdukiewicz and others (2010), copyright American Association of Petroleum Geologists (AAPG) 2010, reprinted by permission of the AAPG, whose permission is required for further use. F, Schematic cross section diagram depicting trapping mechanisms in North Excel field (within westernmost polygon labeled "South Alabama" in fig. 3); modified from Dean (1998). G, Schematic cross section diagram of dominant lithologies in the Norphlet and other units showing a combination trapping mechanism caused by tight interdune facies and differential subsidence of dune forms, Mobile Bay area; modified from Mankiewicz and others (2009).

Petroleum System    13 F NOT TO SCALE Paleozoic basement HV FCS BUC SM NOR HV FCS SM NOR EXPLANATION Cotton Valley Formation Haynesville Formation BUC Buckner Anhydrite Smackover Formation Norphlet Formation Contact 5 KILOMETERS 5 MILES E EXPLANATION FEET −5,000 −10,000 −15,000 −20,000 Downdip Updip Turtle structure Piercement dome High-relief salt anticline Intermediate salt anticline Low-relief salt pillow Peripheral salt ridge SM UK LK LK LK LK LK LK UK UK UK UK UK Hosston HV HV CV (Jurassic) NOR SM SM SM NOR NOR HV HV NOR Paleozoic basement D EXPLANATION Smackover Formation Norphlet Formation Cotton Valley Group Haynesville Group of Montgomery and Ericksen, 1997 Cenozoic Upper Cretaceous Lower Cretaceous Contact Faults Dominant lithologic unit Upper Cretaceous and Lower

Cretaceous boundary within

the Hosston Formation Fault—Arrows show

relative motion SM HV UK LK NOR Louann Salt Thin Sand and shale (lower CV) Interbedded shale and anhydrite (HV) Sand (FCS) Sand (NOR) Anhydrite (BUC) Shaley carbonates (SM) Shaley sand (NOR) Sand and shale (upper CV) Thick Frisco City Sand Member of the

Haynesville Formation Figure 9.—Continued

14    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation (that is, basin-centered, unconventional) resources for many years (Spencer, 1989; Schmoker, 2002; Bartberger and others, 2003). Several key aspects of the Norphlet petroleum system indicate that hydrocarbon accumulations within Norphlet reservoirs may be better assessed as conventional rather than continuous accumulations, including: well-defined stratigraphic or structural traps or both (Mancini and others, 1985a); high porosity and permeability (Dixon and others, 1989); hydrocarbon-water contacts and variable or increasing water production (for example, Story, 1998); and normal pressure, although some fields may be overpressured, such as those in and around Mobile Bay (Nehring Associates Inc., 2018). While these key features do not preclude future development of the Norphlet Formation as a continuous resource, the unit lacks many of the properties associated with continuous plays, including the internal generation of hydrocarbons (self-sourcing). The petroleum resources in the Norphlet Formation have primarily been exploited using vertical or directional wells. Although Norphlet operators have used lateral drilling to test the extent of oil discoveries (Godo, 2017), only two horizontal boreholes have been recorded onshore. Both of these horizontal boreholes were drilled in the 1980s or 1990s, predating modern horizontal drilling and hydraulic fracturing techniques. Only one of these boreholes has available data that show a very short horizontal length of approximately 400 feet (S&P Global Commodity Insights, 2023). Thus, there is little evidence suggesting that the Norphlet could successfully be developed via horizontal drilling. The features of the Norphlet petroleum system suggest that a conventional model may be more appropriate for assessing the formation. An assessment of the Norphlet Formation was conducted in late 2023 (Counts and others, 2024) and followed the methodology outlined in Charpentier and Klett (2007). Assessment Units: Extents and Boundaries Possibility of Western Norphlet Reservoirs In previous USGS Norphlet Formation assessments, some assessment units were located wholly or partially to the west of the Mississippi River. In the 2024 assessment, these regions west of the Mississippi River were not included because there is no evidence of reservoir-quality Norphlet facies in these areas (Counts and others, 2024). The Smackover Formation, which is the source rock for the Norphlet to the east of the Mississippi River, is present in the subsurface across the Gulf Coast rim into Texas and into Mexico, and is thermally mature, potentially high in TOC, and is the likely source of petroleum for many Upper Cretaceous plays (Getz, 2012). However, the Norphlet eolian facies that form the core of the Norphlet play are not known in the United States outside of Alabama, Mississippi, and Florida. The facies relationships are observed in facies maps utilized by the USGS (Pearson, 2011) and by other authors (Newkirk, 1971; Snedden and Galloway, 2019). Available log data for the Norphlet west of the Mississippi are sparse, with few wells penetrating below the Smackover. The few logs available from the Norphlet show an increase in gamma ray (GR) response compared to the GR response recorded from the Smackover, indicating an increase in clay content. The data from well logs that are available from south Texas (Budd and Loucks, 1981) indicate that the NOT TO SCALE G EXPLANATION Sand dunes of the Norphlet

Formation—Water-saturated Sand dunes of the Norphlet

Formation—Gas accumulation Carbonates of the Smackover

Formation Baffling interdune Sealing interdune Contact Gas-water contact Louann Salt Figure 9.—Continued

Petroleum System    15 Norphlet formation is only tens of feet thick, and sediments were deposited in sabkha, wadi, or other non-prospective dryland coastal environments. The Norphlet lithology in this area was confirmed by examining photographs from isolated deep cores collected from the Norphlet (for example, the Winkler #1 core; refer to Budd and Loucks, 1981; Erlich and others, 2022). The lack of reservoir facies in the western part of the Norphlet Formation is likely due to unique conditions in the eastern Gulf Coast during deposition of the Norphlet, where prevailing wind directions and exposed highlands combined with the arid climate to create the Norphlet erg (Parrish and Peterson, 1988; Hunt and others, 2017). Assessment Unit Boundaries Petroleum system assessment units (AUs) were determined by assigning progressively smaller boundaries to key aspects of the potential Norphlet petroleum system (Counts and others, 2024). The predefined geographic limits of USGS Energy Resources Program assessments form the southern and southwestern extent of potential AUs at the United States-Mexico border and the boundary between State and Federal waters three nautical miles from the nearest coastline (USGS, 2023). Geologically, the first and broadest of the AU boundaries in the assessment area is the limit of the Gulf Coast Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System, or TPS (fig. 10A; Coleman, 2007). This TPS boundary defines the maximum possible extent of most of the stratigraphic units involved in Gulf Coast petroleum production, and encompasses all of the source, reservoir, and seal rocks involved in hydrocarbon generation and trapping in the TPS area. Within this TPS boundary, a series of progressively restrictive criteria were used to further constrain AU extents, resulting in increasingly smaller geographic limits for the possible AU extents. The depositional limits of the Smackover Formation source rock eliminated a large portion of the furthest updip areas of the Norphlet Formation in the Gulf Coast TPS from possible AUs, including the majority of the Mississippi embayment, Georgia, and most of Florida except for a small part of the panhandle. Downdip constraints on the AU were then imposed by defining the limits of "technically recoverable" reserves, as described in the USGS assessment methodology guidelines (U.S. Geological Survey National Oil and Gas Resource Assessment Team, 1995; Schmoker and Klett, 2007). While these limits are dependent upon many factors, the Norphlet "technically recoverable" constraints follow the boundaries that Whidden and others (2023) determined for the Smackover Formation because the boundaries they defined are not substantially different for the stratigraphically adjacent Norphlet sands. These boundary extents were defined by bottom-hole temperatures of less than 260 °C and bottom-hole pressures of less than 25,000 pounds per square inch. Neither the temperature or pressure boundaries meaningfully constrain the extent of the Norphlet AUs because both the updip Smackover depositional limits and downdip technically recoverable limits are outside the depositional extent of the continental Norphlet facies. Norphlet sedimentary environments and corresponding facies have been mapped relatively consistently over several decades (fig.6; Cagle and Khan, 1983; Marzano and others, 1988; Dixon and others, 1989; Ajdukiewicz and others, 2010; Lovell, 2010;; Henry, 2016; Hunt and others, 2017; Snedden and Galloway, 2019), and these maps were used to determine both depositional limits that form the primary constraint on the overall boundaries of the Norphlet AUs and in delineating individual AUs (fig. 10C). Assessment Units: Geological Summary Norphlet Updip Oil Assessment Unit The Norphlet Updip Oil AU encompasses the majority of the updip, most proximal to source continental Norphlet facies that occur in a relatively narrow SE-NW-trending belt on the northeast margin of the formation (fig. 10C). These facies include alluvial fans, wadis, and red beds, with rock types often consisting of immature, muddy sandstones and conglomerates, with some interfingering eolian deposits consisting of sandstones on the southwestern margin of the AU. The irregular updip boundary is defined by where the Norphlet pinches out on Paleozoic bedrock, and is strongly affected by basement topography where the Norphlet thickens in basement lows, and thins or is absent on positive basement features. This AU limit also generally coincides with the onset of oil generation (0.6 percent Ro) in much of the Smackover Formation as mapped by Whidden and others (2023) (fig. 10A). To the northwest, the Norphlet Updip Oil AU extends to the approximate limit of mapped continental facies in the Norphlet, and to where the formation may be too thin for a field of minimum size. The southeastern boundary is limited by the extent of the State Waters boundary, and the downdip (southwestern) boundary coincides approximately with the northeastern boundary of the Mississippi Interior Salt Basin, the onset of gas generation in the Smackover (approximately 2.0 percent Ro; Dembicki, 2022), and, in places, the regional peripheral fault system that roughly parallels strike of the Norphlet Formation in parts of Mississippi. Production from this unit is primarily oil, but existing wells also coproduce natural gas. Some of the fields in this AU include the Ollie, Excel North, Fletcher Branch, Nancy, and Watts Creek fields, among others. Play concepts in the Norphlet Updip Oil AU depend on the availability of reservoir-grade facies and trap creation. Because this AU does not contain the main body of the Norphlet erg, clean, sandy, eolian deposits are only located where the northeasternmost margin of the erg interfingers with more proximal continental facies and erg facies cross the AU border. The large Flomaton field in this AU (cumulative production approximately 100 BCFG, 22 MMBO NGL; Nehring Associates Inc., 2018) produces from erg facies, although facies from several other environments are also

16    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation 100 KILOMETERS 100 MILES 92° 33° 32° 31° 30° 91° 90° 89° 88° 87° 86° 85° GULF OF AMERICA LOUISIANA GEORGIA FLORIDA ALABAMA MISSISSIPPI EXPLANATION Norphlet Alabama-Florida Oil and Gas AU Norphlet Alabama-Mississippi Deep Gas AU Norphlet Mississippi Interior Salt Basin Oil and Gas AU Norphlet Updip Oil AU Base from Natural Earth 1:10,000,000-scale digital data, 2024 U.S. Geological Survey digital data, 2024 Universal Transverse Mercator, zone 16 north North American Datum of 1983 Upper Jurassic-Cretaceous-Tertiary Composite

Total Petroleum System (part) ? MEXICO UNITED STATES THE BAHAMAS GULF OF AMERICA ATLANTIC OCEAN Figure B TEXAS NEW MEXICO LOUISIANA ARKANSAS TENNESSEE KENTUCKY OHIO VIRGINIA NORTH CAROLINA SOUTH CAROLINA GEORGIA FLORIDA ALABAMA WEST VIRGINIA ILLINOIS INDIANA MISSOURI MISSISSIPPI OKLAHOMA KANSAS COLORADO A 104° 38° 34° 100° 30° 26° 96° 92° 88° 84° 80° ? Upper Jurassic-Cretaceous-Tertiary Composite

Total Petroleum System (part) Uncertainty in the formation extents EXPLANATION Source rock liquids window Source rock gas window Source rock depositional limit Temporary or present drilling limit Offshore 3-mile limit 450 KILOMETERS 450 MILES Base from Natural Earth 1:10,000,000-scale digital data, 2024 U.S. Geological Survey digital data, 2024 Universal Transverse Mercator, zone 16 north North American Datum of 1983 GULF OF AMERICA TEXAS LOUISIANA ARKANSAS SOUTH CAROLINA GEORGIA FLORIDA ALABAMA MISSISSIPPI B Figure C 34° 94° 32° 30° 28° 92° 90° 88° 86° 86° 84° 200 KILOMETERS 200 MILES Upper Jurassic-Cretaceous-Tertiary Composite

Total Petroleum System (part) Source rock liquids window EXPLANATION Known depositional extent of prospective

Norphlet Formation facies Source rock gas window Source rock depositional limit Temporary or present drilling limit Offshore 3-mile limit Base from Natural Earth 1:10,000,000-scale digital data, 2024 U.S. Geological Survey digital data, 2024 Universal Transverse Mercator, zone 16 north North American Datum of 1983 Figure 10.  Maps indicating increasingly restrictive boundaries that assisted in determining boundaries of U.S. Geological Survey 2024 Norphlet assessment units (AUs). A, Limits of Upper Jurassic—Cretaceous Composite Total Petroleum System (TPS) and geographic/political borders used to determine the maximum possible extents of Norphlet AU; box indicates area shown in B. B, Known depositional extent of prospective Norphlet Formation facies (fig. 6); box indicates area in C. C, Final Norphlet AUs as used in Counts and others (2024).

Petroleum System    17 present (Keyes, 1971; Smith, 2021). Eolian facies are also present with other continental facies in the smaller fields of East Mississippi, for example, the Nancy East (Badon, 1975) field. The fields in this AU were created by petroleum trapping in faulted salt anticlines. While it is unlikely that a large, Flomaton-sized field remains to be discovered, the possibility exists for additional, smaller, salt-cored structures to be found along the southwestern margin of the AU. Further updip from the southwest margin, the underlying salt is not thick enough to become mobile and create significant traps. Accumulations in the updip part of this AU were formed by a different trapping mechanism, where cleaner sands, often eolian, were deposited in and adjacent to "ravines and valleys that were incised into pre-existing metamorphic basement knobs and ridges" (Dean, 1998, p. 24). Prediction of occurrences of these cleaner sand facies may be difficult and requires high-quality seismic data. However, several successful Norphlet petroleum discoveries in south Alabama (for example, the Excel North field) show that there are productive Norphlet sand facies in this AU. This trapping model of sand-filled basement ravines and valleys may also be present elsewhere along the trend where salt is not an important factor, and may indicate additional areas of the formation for exploration. Mean assessment values of undiscovered resources for the Norphlet Updip Oil AU were 3 MMBO and 1 BCFG in oil fields of minimum size (Counts and others, 2024). Norphlet Mississippi Interior Salt Basin Oil and Gas Assessment Unit The Norphlet Mississippi Interior Salt Basin Oil and Gas AU lies to the south of the western part of the Norphlet Updip Oil and Gas AU and corresponds in part to the Mississippi Interior Salt Basin (fig. 10). The presence of halokinetic features defines, in part, the extent of the Mississippi Interior Salt Basin (Mancini and others, 2003), and also the Norphlet Mississippi Interior Salt Basin Oil and Gas AU. In the Norphlet Mississippi Interior Salt Basin Oil and Gas AU, the Louann Salt underlying the Norphlet Formation is highly mobile, forming vertical diapirs that penetrate strata that are sometimes less than 1000 ft deep (Thieling and Moody, 1997). Salt movement may also create smaller antiformal structures that primarily affect sediments deposited in the Jurassic and Early Cretaceous. This AU primarily consists of sediments that represent dryland desert facies, including eolian dunes of the Norphlet erg, and the Norphlet Formation can be up to several hundred feet thick (Marzano and others, 1988). The alluvial fan facies and conglomerates found in the Norphlet Updip Oil and Gas AU have a low reservoir quality and are generally absent in the Mississippi Interior Salt Basin. This AU is bounded on the updip northern side by the Norphlet Updip Oil and Gas AU, and on the southeastern side by the Mississippi Interior Salt Basin border, where there is no extensive salt movement. The northwestern boundary is defined as where the Norphlet becomes significantly thinner, and the facies transition out of an eolian environment and into thinner sabkha facies near the Mississippi-Arkansas-Louisiana border. To the south, the AU border is defined primarily by a facies transition from an eolian to a marine environment, where eolian dunes grade into marine carbonates of the Smackover Formation. Conventional traps within the Norphlet Mississippi Interior Salt Basin Oil and Gas AU are primarily related to salt. Like the Norphlet Updip Oil and Gas AU, salt anticlines or faulted salt anticlines in reservoir-grade facies are the primary trap types for existing Norphlet fields (Mancini and others, 1985a; Tew and others, 1991). To date (2023), only two fields of minimum size (Pelahatchie and Prairie Branch fields, in Rankin and Clarke counties, respectively) have been developed in the AU. However, because of the ubiquity of salt movement, the presence of reservoir facies, and the size of the AU, there is the potential for undiscovered traps. Additional traps may be present on the margins of the peripheral fault system on the northern edge of the AU, as evidenced by the abundance of Smackover fields in this area, which may indicate the presence of structural trapping mechanisms (Mancini and others, 1985b). Elsewhere in the AU, small-scale diapiric rise without shallow penetration may create traps with or without a fault component. In the eastern part of the AU, large anticlines that developed between salt bodies, called turtle structures (Woehnker, 2018, and references therein), theoretically may provide a trapping mechanism. The Norphlet Formation in this AU has significant resource potential, but the lack of proven development as of 2023 creates uncertainty when attempting to assess the numbers and sizes of undiscovered fields. Taking uncertainty into account, the number and variety of possible trap types led to an assessment of mean undiscovered resources in this AU at 8 MMBO and 4 BCF in oil fields, and 50 BCFG and 8 MMBNGL in gas fields (Counts and others, 2024). Norphlet Alabama-Florida Oil and Gas Assessment Unit The Norphlet Alabama-Florida Oil and Gas AU lies to the southeast and along approximate strike to the Norphlet Mississippi Interior Salt Basin Oil and Gas AU and encompasses much of the same eolian erg facies as the Norphlet Mississippi Interior Salt Basin Oil and Gas AU (fig. 10C). However, Norphlet Alabama-Florida Oil and Gas AU lies outside the Mississippi Interior Salt Basin, with the AU boundaries delineated by the edge of the salt basin, the north-south-trending parts of the regional peripheral fault system, and the Mobile Graben (Mancini and others, 1985b). In contrast to the Norphlet Mississippi Interior Salt Basin Oil and Gas AU, salt derived from the Louann in the Norphlet Alabama-Florida Oil and Gas AU is less upwardly mobile, resulting in different frequencies and styles of trapping mechanisms. The differences in salt mobility and trapping mechanisms is the reason for the separation of these two AUs. Hatters Pond Field, which is the only field of minimum

18    Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation size within the Norphlet Alabama-Florida Oil and Gas AU, produces large amounts of NGL (S&P Global Commodity Insights, 2023.) In Hatters Pond Field, NGL is also produced from the Smackover Formation; Norphlet production in this area may be attributed to the Smackover in some databases (Nehring and Associates, 2018). Production of NGL in the Norphlet between areas of oil-prone production to the north (Updip oil and gas AU) and gas-prone production to the south (Alabama Deep Gas AU) illustrates the regional continuum of increasing thermal maturity to the southwest. Although not a specifically defined linear boundary, an approximated line between the areas of primarily NGL versus primarily dry gas production marks the southwestern boundary of the Norphlet Alabama-Florida Oil and Gas AU. The southeastern boundary of the Norphlet Alabama-Florida Oil and Gas AU corresponds to the Federal-State Water boundary and the northern-northeastern boundary abuts the Norphlet Updip Oil and Gas AU. The northwestern and western boundaries of the Norphlet Alabama-Florida Oil and Gas AU correspond to the boundaries of the Norphlet Mississippi Interior Salt Basin Oil and Gas AU and the Norphlet Alabama-Mississippi Deep Gas AU, respectively. East of Hatters Pond Field (fig. 3), the Norphlet formation thins out onto a basement high (the Baldwin High; Tew and others, 1991), decreasing the potential for a field of minimum size in this area. Hatters Pond Field is mainly formed by a faulted salt anticline (Higginbotham and others, 1990), although the field likely has other factors contributing to trapping (Benson and others, 1981), and known potential trapping mechanisms in this AU are limited to the recurrence of this type of feature. This AU is estimated to contain undiscovered resources with mean values of 5 MMBO and 2 BCFG in oil fields of minimum size, and 29 BCFG and 11 MMBNGL in gas fields (Counts and others, 2024). Norphlet Alabama-Mississippi Deep Gas Assessment Unit Petroleum reservoirs of the Norphlet Formation reach their maximum onshore depth in the Norphlet Alabama- Mississippi Deep Gas AU, located primarily in Baldwin and Mobile Counties, Alabama, and in the shallow waters of Mobile Bay. In this AU, the formation produces dry gas with little or no liquids because of a combination of high thermal maturity, depth, temperature, and pressure (Dixon and others, 1989; S&P Global Commodity Insights, 2023). Significant gas production occurs in the Norphlet Alabama-Mississippi Deep Gas AU. The southern boundary of this AU is placed at the Federal-State Waters line and is not based on geological criteria. Norphlet production and prospectivity continues into the offshore area beyond the boundaries of USGS assessments (Godo, 2019) in Federal Waters to the south in the Gulf of America. The Norphlet Alabama-Mississippi Deep Gas AU contains eolian facies in the majority of the AU that thin onto the Wiggins Arch to the northwest, resulting in an irregular northwestern boundary (Marzano and others, 1988). On the updip side, the formation is only in contact with the Norphlet Alabama-Florida Oil and Gas AU. In the Norphlet Alabama- Mississippi Deep Gas AU, trapping mechanisms in existing fields are combination structural-stratigraphic traps, with large and complex faults, differential subsidence into salt, and facies changes between dune (porous) and interdune (less porous or tighter) environments creating compartmentalization (Mankiewicz and others, 2009; Ajdukiewicz and others, 2010). Possible expansion into onshore, undeveloped areas of this AU is dependent upon continuation of a linear dune field found in the Norphlet in the Mobile area to the east, a concept that was tested in the past (Koen, 1993) without success (S&P Global Commodity Insights, 2023). The most recent USGS undiscovered resources assessment for the Norphlet estimated a mean value of 262 BCFG in this AU, with only gas fields present (Counts and others, 2024). Conclusions Unique conditions during the Late Jurassic in the southeastern United States resulted in a sedimentary deposit unlike any other in the region that now compose the Norphlet Formation. An arid climate, favorable wind directions, and sediment from the eroding Appalachian highlands combined to form a gigantic erg, or sand sea, analogous to the modern Namib desert, that spanned hundreds of square kilometers across Alabama, Florida, Mississippi, and into the Gulf of America. Preservation of high primary porosity in the erg sandstones of the Norphlet Formation was facilitated by early diagenetic processes of chlorite grain coatings and cements. High primary porosity found in the Norphlet erg facies hosts petroleum generated by overlying Smackover Formation carbonates. The Norphlet remains a viable petroleum exploration target across much of its depositional area even after decades of exploration and development. Because drilling in deep and sometimes high-temperature environments is challenging, the Norphlet Formation has experienced less petroleum development as compared to some of the more accessible strata in the same region. The U.S. Geological Survey 2024 assessment (Counts and others, 2024) estimated that a mean total resource of 16 million barrels of oil (MMBO), 348 billion cubic feet of gas (BCFG), and 19 million barrels of natural gas liquids (MMBNGL) remain undiscovered in fields of minimum size (0.5 MMBO or 3 BCFG) within all Norphlet Formation assessment units, representing a significant untapped resource in the Western Gulf Basin Province.

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Counts—Background and Geologic model for the assessment of undiscovered conventional resources in the Norphlet Formation—SIR 2026-5032 ISSN 2328-0328 (online) https://doi.org/10.3133/sir20265032

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