Geologic Assessment of Undiscovered Conventional 

Oil and Gas Resources—Middle Eocene Claiborne 

Group, United States Part of the Gulf of Mexico Basin 

By Paul C. Hackley

U.S. Geological Survey Open-File Report 2012–1144

U.S. Department of the Interior

U.S. Geological Survey
ii

U.S. Department of the Interior

KEN SALAZAR, Secretary

U.S. Geological Survey

Marcia K. McNutt, Director

U.S. Geological Survey, Reston, Virginia 2012

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Suggested citation:

Hackley, P.C., 2012, Geologic assessment of undiscovered conventional oil and gas resources—Middle 

Eocene Claiborne Group, United States part of the Gulf of Mexico Basin: U.S. Geological Survey Open–File 

Report 2012–1144, 87 p., available only at http://pubs.usgs.gov/of/2012/1144/.

Any use of trade, product, or firm names is for descriptive purposes only and does not imply 

endorsement by the U.S. Government. 

Although this report is in the public domain, permission must be secured from the individual 

copyright owners to reproduce any copyrighted material contained within this report.
iii

Contents

Abstract ......................................................................................................................................................................... 1

Acknowledgments.......................................................................................................................................................... 2

Introduction.................................................................................................................................................................... 2

Assessment Unit and Petroleum System Concepts................................................................................................... 3

Data Sources and Discovery History Analysis ........................................................................................................... 4

Regional Geologic and Structural Setting ...................................................................................................................... 4

Structural Setting........................................................................................................................................................ 7

Stratigraphy.............................................................................................................................................................. 15

Paleogeography, Sediment Source Areas, and Depositional Systems .................................................................... 20

Elements of the Petroleum System.............................................................................................................................. 23

Source Rocks and Thermal Maturation.................................................................................................................... 23

Migration of Hydrocarbons ....................................................................................................................................... 27

Reservoir Rocks....................................................................................................................................................... 28

Lower Claiborne - Queen City Sand and Reklaw Formation ................................................................................ 28

Middle Claiborne – Sparta Sand and Cook Mountain Formation.......................................................................... 30

Upper Claiborne – Yegua and Cockfield Formations............................................................................................ 31

Traps and Seals....................................................................................................................................................... 33

Influence of the Louann Salt .................................................................................................................................... 35

Overview of Claiborne Exploration and Production History.......................................................................................... 35

Resource Assessment................................................................................................................................................. 36

Comparisons with the 1995 Assessment ................................................................................................................. 38

Geologic Model ........................................................................................................................................................ 39

Stable Shelf.......................................................................................................................................................... 39

Expanded Fault Zone ........................................................................................................................................... 41

Slope and Basin Floor.......................................................................................................................................... 42

Data Supporting the Geologic Model.................................................................................................................... 43

Lower Claiborne Stable Shelf Gas and Oil (50470120)............................................................................................ 43

Lower Claiborne Expanded Fault Zone Gas (50470121)......................................................................................... 50

Lower Claiborne Slope and Basin Floor Gas (50470122)........................................................................................ 52

Lower Claiborne Cane River (50470123)................................................................................................................. 54

Upper Claiborne Stable Shelf Gas and Oil (50470124)............................................................................................ 54

Upper Claiborne Expanded Fault Zone Gas (50470125)......................................................................................... 57

Upper Claiborne Slope and Basin Floor Gas (50470126)........................................................................................ 60

References Cited......................................................................................................................................................... 62

Appendix A .................................................................................................................................................................. 74

Appendix B .................................................................................................................................................................. 76

Appendix C.................................................................................................................................................................. 78

Appendix D.................................................................................................................................................................. 80

Appendix E .................................................................................................................................................................. 82

Appendix F .................................................................................................................................................................. 84

Appendix G.................................................................................................................................................................. 86
iv

Figures

1 Map of Gulf Coast States showing petroleum province boundaries, outline of Upper JurassicCretaceous-Tertiary Composite total petroleum system (in part), Claiborne Group outcrop, and 

the upper Wilcox Group shelf margin................................................................................................................ 3

2. Generalized stratigraphic section of the northern Gulf of Mexico Coastal Plain showing 

potential hydrocarbon source rock intervals ..................................................................................................... 5

3. Map showing Upper Jurassic-Cretaceous-Tertiary Composite total petroleum system (TPS) for 

the Gulf of Mexico Basin................................................................................................................................... 6

4. Stratigraphy of the Claiborne Group. ................................................................................................................ 8

5. Map showing study area (onshore U.S. Gulf Coast and State waters) showing Claiborne Group 

outcrop, Wilcox and Claiborne expansion faults, and outline of major structural features ................................ 9

6. Map showing study area showing approximate locations of Claiborne Group oil and gas

reservoirs....................................................................................................................................................... 10

7. Histogram of depth to top of Claiborne Group reservoirs, Texas and Louisiana............................................. 11

8. Map showing Claiborne Group isopach map constructed from the IHS Energy Group (2005b) 

database 

using data current through 2004 and from the Paleo-Data, Inc. (1989) Tenroc Regional 

Geologic database.......................................................................................................................................... 12

9. Dodge and Posey (1981) cross section 1-1’ in the Houston Embayment ....................................................... 13

10. Dodge and Posey (1981) cross section 21-21’ in the Rio Grande Embayment .............................................. 14

11. Dodge and Posey (1981) cross section 18-18’ in the Rio Grande Embayment .............................................. 15

12. Bebout and Gutiérrez (1983) cross section R-R’ in southeastern Louisiana illustrating thinning 

of the Claiborne, thickness of the Neogene, and the abrupt steepening of the Cenozoic section 

over the Cretaceous shelf margin in the eastern part of the basin.................................................................. 16

13. Map showing depth to the top of Claiborne (Yegua Formation) constructed from the IHS Energy 

Group (2005b) database using data current through 2004 and from the Paleo-Data, Inc. (1989) 

Tenroc Regional Geologic database............................................................................................................... 17

14. Spontaneous potential and resistivity log response of the lower Claiborne section in eastern Texas 

illustrating eastward loss of the Queen City Sand.......................................................................................... .18

15. Graphic representation of the Cook Mountain problem .................................................................................. 20

16. Map showing depositional systems of the lower Claiborne Group.................................................................. 21

17. Map showing depositional systems of the upper Claiborne Group ................................................................. 22

18. Map showing hydrocarbon families of the U.S. Gulf Coast............................................................................. 24

19. Events chart summarizing the major elements of the Upper Jurassic-Cretaceous-Tertiary Composite 

total petroleum system of the Gulf Basin ........................................................................................................ 25

20. Map showing present-day thermal maturity of the top of the Wilcox Group.................................................... 26

21. Conceptualized migration of oil and gas in southern Louisiana ...................................................................... 28

22. Sand isolith (top) and facies (bottom) map for the lower Claiborne Queen City Sand, Texas Coastal 

Plain................................................................................................................................................................ 29

23. Sand isolith map for the upper Claiborne Yegua Formation, Texas Coastal Plain.......................................... 32

24. Cross section through Shanghai Field, Wharton County, Texas, in the expanded downdip 

Yegua trend .................................................................................................................................................... 34

25. Map and diagrammatic showing cross section of the Conroe Field, Montgomery County, Texas .................. 37

26. Conceptualized geologic model used for this assessment ............................................................................. 40

27. Gas accumulation sizes for the Upper Claiborne Stable Shelf Gas and Oil Assessment Unit 

(AU) (50470124) plotted as a function of discovery year................................................................................ 41
v 

28. Schematic block diagram illustrating location and type of depositional environments and assessment 

unit elements of the geologic model ............................................................................................................... 42

29. Map showing spatial distribution of Claiborne reservoirs that are <8,000 feet depth-to-top and >8,000 

feet depth-to-top ............................................................................................................................................. 44

30. Plots of pressure as a function of depth for Claiborne reservoirs with pressure data (data from NRG 

Associates, 2006, including initial reservoir, initial shut-in well head, and initial shut-in bottom hole 

pressures)....................................................................................................................................................... 45

31. Map showing extent of lower Claiborne assessment units (AU) ..................................................................... 46

32. Gas and oil discovery curves for the Lower Claiborne Stable Shelf Gas and Oil assessment 

unit (AU) ......................................................................................................................................................... 47

33. Gas discovery curve and wildcat wells for the Lower Claiborne Expanded Fault Zone 

assessment unit (AU) ..................................................................................................................................... 51

34. Map showing extent of upper Claiborne assessment units (AU)..................................................................... 55

35. Oil discovery curve and wildcat wells for the Upper Claiborne Stable Shelf Gas and Oil assessment 

unit (AU) ......................................................................................................................................................... 56

36. Gas discovery curve and wildcat wells for the Upper Claiborne Expanded Fault Zone 

assessment unit (AU) ..................................................................................................................................... 59

Table

1. Mean and fractile estimates of undiscovered resources in the Claiborne Group. ........................................... 49

1 

Geologic Assessment of Undiscovered Conventional 

Oil and Gas Resources—Middle Eocene Claiborne 

Group, United States Part of the Gulf of Mexico Basin

By Paul C. Hackley

Abstract

The Middle Eocene Claiborne Group was assessed using established U.S. Geological 

Survey (USGS) assessment methodology for undiscovered conventional hydrocarbon resources as 

part of the 2007 USGS assessment of Paleogene-Neogene strata of the United States part of the 

Gulf of Mexico Basin including onshore and State waters. The assessed area is within the Upper 

Jurassic-Cretaceous-Tertiary Composite total petroleum system, which was defined as part of the 

assessment. Source rocks for Claiborne oil accumulations are interpreted to be organic-rich 

downdip shaley facies of the Wilcox Group and the Sparta Sand of the Claiborne Group; gas 

accumulations may have originated from multiple sources including the Jurassic Smackover and 

Haynesville Formations and Bossier Shale, the Cretaceous Eagle Ford and Pearsall(?) Formations, 

and the Paleogene Wilcox Group and Sparta Sand. Hydrocarbon generation in the basin started

prior to deposition of Claiborne sediments and is ongoing at present. Emplacement of hydrocarbons 

into Claiborne reservoirs has occurred primarily via vertical migration along fault systems; longrange lateral migration also may have occurred in some locations. Primary reservoir sands in the 

Claiborne Group include, from oldest to youngest, the Queen City Sand, Cook Mountain 

Formation, Sparta Sand, Yegua Formation, and the laterally equivalent Cockfield Formation. 

Hydrocarbon traps dominantly are rollover anticlines associated with growth faults; salt structures 

and stratigraphic traps also are important. Sealing lithologies probably are shaley facies within the 

Claiborne and in the overlying Jackson Group. 

A geologic model, supported by spatial analysis of petroleum geology data including 

discovered reservoir depths, thicknesses, temperatures, porosities, permeabilities, and pressures, 

was used to divide the Claiborne Group into seven assessment units (AU) with distinctive structural 

and depositional settings. The AUs include (1) Lower Claiborne Stable Shelf Gas and Oil 

(50470120), (2) Lower Claiborne Expanded Fault Zone Gas (50470121), (3) Lower Claiborne 

Slope and Basin Floor Gas (50470122), (4) Lower Claiborne Cane River (50470123), (5) Upper 

Claiborne Stable Shelf Gas and Oil (50470124), (6) Upper Claiborne Expanded Fault Zone Gas 

(50470125), and (7) Upper Claiborne Slope and Basin Floor Gas (50470126). Total estimated 

mean undiscovered conventional hydrocarbon resources in the seven assessment units combined 

are 52 million barrels of oil, 19.145 trillion cubic feet of natural gas, and 1.205 billion barrels of 

natural gas liquids. 

A recurring theme that emerged from the evaluation of the seven Claiborne AUs is that the 

great bulk of undiscovered hydrocarbon resources comprise non-associated gas and condensate 

contained in deep (mostly >12,000 feet), overpressured, structurally complex outer shelf or slope 
2 

and basin floor reservoirs. The continuing development of these downdip objectives is expected to 

be the primary focus of exploration activity for the onshore Middle Eocene Gulf Coast in the 

coming decades.

Acknowledgments

Discussions with the USGS National Oil and Gas Assessment review committee 

(T.R. Klett, C.J. Schenk, R.R. Charpentier, and R.M. Pollastro) during the geologic review and 

assessment meetings guided the analysis of numbers and sizes of undiscovered reservoirs in the 

Claiborne Group. S.A. Kinney provided GIS support and processing of geospatial information 

related to the delineation of the assessment units, and for the structure and depth maps of the 

Claiborne across the basin. J.L. Coleman conceptualized the geologic model, and M. Merrill helped 

with drafting the geologic model figure. M.S. Hopkins assisted in delineating data subsets from the 

commercial databases. Critical reviews by S.M. Condon and J.L. Coleman of the USGS and 

T.E. Ewing of Frontera Exploration Consultants, Inc., greatly improved the quality and clarity of 

this report. For their leadership and for the sharing of their ideas and geologic experience, the 

author is indebted to the other members of the Gulf Coast Basin assessment team (L.H. Biewick, 

J.L. Coleman, S.M. Condon, R.F. Dubiel, D.O. Hayba, A.W. Karlsen, M.A. Keller, M.D. Lewan, 

P.H. Nelson, O. Pearson, J.K. Pitman, J.L. Ridgley, E.L. Rowan, S.M. Swanson, and P.D. 

Warwick). N. Kvehnle of Big Joe Operating Company, G. Hepner of McGowan Partners, S. Maley 

of Badger Oil, and J. King of Josey Oil shared their insights regarding Claiborne and other Gulf 

Coast hydrocarbon production. 

Introduction

The U.S. Geological Survey (USGS) currently is assessing undiscovered oil and gas 

resources of priority basins within the United States as an update to the comprehensive 

1995 national assessment of oil and gas resources (Gautier and others, 1996), which is available 

from http://energy.cr.usgs.gov/oilgas/noga/1995.html. The purpose of this report is to present the 

results of a geologic assessment of the undiscovered conventional oil and gas resources of the 

Middle Eocene Claiborne Group in the United States part of the Gulf of Mexico Basin, including 

onshore and State waters. This report updates the previous report by Hackley (2008), and some of 

the material contained herein was summarized in the report by Hackley and Ewing (2010). 

The Claiborne Group geologic assessment was conducted as part of a geologic assessment 

of Paleogene-Neogene strata of the onshore United States part of the Gulf of Mexico Basin (Dubiel 

and others, 2007). The area of the Gulf Basin assessed in this report includes the Western Gulf 

(Province 5047; Schenk and Viger, 1996a), East Texas (Province 5048; Schenk and Viger, 1996b), 

and the Louisiana-Mississippi Salt Basins (Province 5049; Schenk and Viger, 1996b) petroleum 

provinces that were assessed in 1995 (fig. 1). These petroleum provinces were arbitrarily combined 

into one and numbered 5047 for this assessment. The study area of this report extends 

northeastward from the border with Mexico on the southwest, through south-central Texas, and 

eastward into Louisiana, Mississippi, Alabama, and includes a small portion of the Florida 

panhandle, an area totaling approximately 245,000 square miles. The assessment was conducted 

using the established methodology of the USGS National Oil and Gas Assessment Project 

(Klett and others, 2003), in conjunction with literature review and discovery history analysis of

proprietary oil and gas production and well databases (IHS Energy Group, 2005a, b), and oil and 

gas field and reservoir databases (NRG Associates, 2006).
3 

Figure 1. Map of Gulf Coast States showing petroleum province boundaries, outline of Upper JurassicCretaceous-Tertiary Composite total petroleum system (in part), Claiborne Group outcrop (from Schruben 

and others, 1994), and the upper Wilcox Group shelf margin (from Galloway and others, 2000).

Assessment Unit and Petroleum System Concepts

In this report, assessment units (AU) were used in place of the play concept that was used in 

the 1995 national assessment. The application of the AU concept is part of the petroleum system 

approach (described below) to resource assessment (Magoon and Dow, 1994). An AU is 

“a mappable part of a total petroleum system in which discovered and undiscovered oil and gas 

accumulations constitute a single relatively homogeneous population such that the methodology of 

resource assessment is applicable” (Klett, 2004, p. 599). In other words, an AU comprises a threedimensional volume of rock which contains discovered and undiscovered hydrocarbon resources 

that are relatively similar in terms of their geological occurrence, exploration strategy, and risk 

characteristics (Ahlbrandt, 2000). Using AUs in place of the play concept may not necessarily 

result in quantitative differences in the volumes of undiscovered resources (Klett, 2004), but it 

supplies a common basis for resource assessment methodology within the USGS (Condon and 

Dyman, 2006). 

The petroleum system approach to resource assessment (Magoon and Dow, 1994) includes 

an analysis of “genetically related petroleum generated by a pod or by closely related pods of 

mature source rock” (Condon and Dyman, 2006, p. 2). In this assessment, a composite total 

petroleum system was defined: the Upper Jurassic-Cretaceous-Tertiary Composite (Warwick and 

others, 2007). The term “composite” indicates that hydrocarbons reservoired in Gulf Coast Tertiary 

units were generated from more than one source rock, primarily Jurassic basinal units including the 
4 

Smackover and Haynesville Formations and the Bossier Shale, the Cretaceous Eagle Ford and 

Pearsall(?) Formations, and the Paleogene Wilcox Group and Sparta Sand, although other Gulf of 

Mexico strata also may have hydrocarbon source potential (fig. 2). The composite total petroleum 

system includes all of the geologic elements such as source, reservoir, seal, and overburden rocks, 

which control the processes of generation, migration, and trapping of hydrocarbon resources 

(Magoon and Dow, 1994; Klett, 2004). A map showing the outline of the Upper JurassicCretaceous-Tertiary Composite total petroleum system of the Gulf of Mexico Basin comprises the 

total geographic extent of source and reservoir rocks (fig. 3). The outline of the petroleum system is 

roughly coincident with the outline of the structural limits of the Gulf of Mexico Basin as defined 

by Salvador (1991a), with some exceptions. 

Data Sources and Discovery History Analysis

The Claiborne petroleum geology interpretations presented in this report are based on 

discovery history analysis of the spatial distribution of wells and known hydrocarbon reservoirs 

within a geographic information system (GIS). Spatial locations of Claiborne wells from IHS 

Energy Group (2005a, b) and Claiborne hydrocarbon reservoirs from NRG Associates (2006) were 

examined using ESRI (Environmental Systems Research Institute, Inc) ArcMap 9.1–9.3. Data from 

these commercial databases are subject to proprietary license restrictions, and the USGS cannot 

publish, share, or serve any data from these databases. However, derivative representations in the 

form of graphs, figures, and summary statistics may be prepared and are presented in this report. 

Other geologic data used in this assessment include the locations of Claiborne outcrop (Schruben 

and others, 1994; Warwick and others, 2002), major structural features of the Gulf Basin, faults, 

and salt (Ewing and Lopez, 1991; Lopez and Orgeron, 1995), geochemical data (Hood and others, 

2002), Cenozoic depositional systems and shelf margins (Galloway and others, 2000), regional 

cross sections, (Dodge and Posey, 1981; Bebout and Gutiérrez, 1982, 1983; Eversull, 1984; 

Galloway and others, 1994), Claiborne isopach and structure maps (constructed from proprietary 

data contained in the IHS and NRG Associates databases), oil and gas field executive reference 

maps (Geomap, 1995a-c), and tectonic maps (Ewing and others, 1990). As an example of the 

spatial analysis, separation of Claiborne production well and reservoir data into AUs with different 

geologic characteristics (stable shelf versus expanded fault zone) was completed through an 

evaluation of discovered reservoir depths, porosity-permeability-pressure-temperature 

characteristics, and reservoir thicknesses, in comparison with the distribution of reservoirs in the 

GIS. In addition to analysis of Claiborne petroleum geology within the GIS, the interpretations 

contained in this report are based on data and interpretations contained in the voluminous published 

literature on Gulf of Mexico petroleum geology and from conversations and correspondence with 

industry personnel involved with production from Claiborne reservoirs. 

Regional Geologic and Structural Setting

Opening of the Gulf of Mexico Basin began during the Late Triassic due to lithospheric 

attenuation associated with the breakup of the Pangean supercontinent (Goldthwaite, 1991; 

Salvador, 1991b). Emplacement of oceanic crust in the now deep, central portions of the Gulf 

Basin occurred by the Late Jurassic (Buffler, 1991). Earliest basin fill was made up of continental 

red beds associated with horst and graben structures (Eagle Mills Formation in the subsurface; 

fig. 2), followed by extensive evaporite deposition of the Callovian (Jurassic) Louann Salt (fig. 2) 

during a period of restricted basin circulation (Salvador, 1991b). Creation of hydrocarbon 
5 

Figure 2. Generalized stratigraphic section of the northern Gulf of Mexico Coastal Plain showing potential 

hydrocarbon source rock intervals (from Hackley and Ewing (2010); modified after Warwick and others 

(2007), Salvador and Quezada Muñeton (1991), Nehring (1991), Palmer and Geissman (1999), and 

Humble Geochemical Services and others (2002)). L. = Lower, Mid. = Middle, Up. = Upper, 

Tria. = Triassic, Pal. = Paleocene, Plei. = Pleistocene, Holo. = Holocene, Quat. = Quaternary, vertical 

lines = unconformity, wavy line = disconformity, jagged line = interfingering, dashed line = uncertain.
6 

Figure 3. Upper Jurassic-Cretaceous-Tertiary Composite total petroleum system (TPS) for the Gulf of

Mexico Basin. The letters (A-O) refer to the following notes on how the TPS boundary was drawn. 

A, coincides with the outcrop contact between Upper and Lower Cretaceous rocks (Schruben and others, 

1994); this line may be somewhat arbitrary, as the area may include some Interior Platform Paleozoicderived oil that has migrated into Cretaceous reservoirs and is not part of the Gulf of Mexico TPS. 

B, includes both Maverick and Sabinas Basins, which have Gulf of Mexico Basin source and reservoir 

rocks (Eguiluz de Antuñano, 2001; Scott, 2003). C, excludes Sierra Madre Oriental, which has 

stratigraphic equivalents to Gulf of Mexico Basin source and reservoir rocks but probably has experienced 

too much structural deformation and erosion to retain any significant hydrocarbon volumes (Ewing, 1991). 

D, includes the Magiscatzin Basin, which has production from units of the main Tampico-Misantla Basin 

and contains similar strata and structural styles as found in the Gulf of Mexico Basin (Nehring, 1991; 

USGS World Energy Assessment Team, 2000). E, excludes Tuxla Uplift, an Upper Cenozoic volcanic 

area (Ewing, 1991). F, includes the Pimienta-Tamabra TPS (USGS World Energy Assessment Team, 

2000). G, includes north Yucatan because hydrocarbons are present in Chicxulub Crater cores 

(Rosenfeld, 2003). H, excludes the Maya Mountains, a metamorphic orogenic complex (Ewing, 1991; 

Ewing and Lopez, 1991). I, includes the south Yucatan because of the occurrence of isolated oil and gas 

production and shows (Rosenfeld, 2003). J, line drawn along major sea-floor crustal structural boundary 

between oceanic crust in the Yucatan Basin and back-arc Cuban basins and oceanic crust in the Greater 

Antilles Deformed Belt (Ewing, 1991; Rodriguez and others, 1995; James, 2004; Schenk and others, 

2005). K, includes north Cuba, where there are the same source rocks as in South Florida and the deepwater Gulf of Mexico (Schenk and others, 2000, 2005; French and Schenk, 2004). L, follows an arbitrary 

limit to the TPS in the Gulf of Mexico Basin. M, follows an arbitrary line drawn to separate the Bahamas 

from the Florida Platform (Ewing, 1991). N, follows the Smackover-Austin-Eagle Ford TPS boundary of 

Condon and Dyman (2006); however, the potential occurrence of source rocks and hydrocarbons in this 

area is highly speculative. O, the Mississippi Embayment includes Tertiary and Cretaceous coal beds as 

potential sources of biogenic gas, although there is no known hydrocarbon production from this area. For 

additional information on construction of the TPS outline see French and Schenk (2005).
7 

migration pathways and trapping structures by diapiric and related evacuation movements of the 

Louann Salt due to sediment loading is one of the controlling aspects of Gulf Coast petroleum 

geology (Halbouty, 1979; Wescott and Hood, 1994). Cenozoic basin fill comprises almost 

exclusively terrigenous clastics originating from North America, except for areas of carbonate and 

evaporate deposition, which occurred on the Florida and Yucatan Platforms, and in parts of 

Mississippi, Alabama, and Georgia (Galloway and others, 1991). Strata are well to poorly lithified, 

depending on age, depth of burial, fluid flow, and hydrochemistry and dip gently to moderately (on 

domal margins) basinward (except where they dip northward off structural culminations). Gulf 

strata in the United States generally are undeformed except for the effects of syndepositional 

growth faulting and salt tectonics. 

Clastic depositional centers migrated from southwest to northeast across the northern part of 

the basin during the Cenozoic (Thompson and others, 1990; Mello and Karner, 1996; Galloway and 

others, 2000), controlled by tectonism and the climatic conditions prevailing on the continent 

(Galloway, 2005). In the particular focus of this report, Middle Eocene clastic deposition of the 

Claiborne Group includes progradational sand-rich wedges that grade basinward into marine 

mudrocks. Progradational strata of the Claiborne, including the Queen City Sand, Sparta Sand, and 

the Yegua and Cockfield Formations, are separated by marine shales (Reklaw, Weches, Cook 

Mountain Formations) deposited during regional transgression and flooding of the continental 

margin (fig. 4) (Davies and Ethridge, 1971; Ramos and Galloway, 1990; Galloway and others, 

2000). In terms of total sediment volume input to the basin and input rate, the Claiborne Group is a 

comparatively minor unit compared to other intervals of the Gulf of Mexico Cenozoic stratigraphy 

(Galloway and others, 2000; Galloway, 2002). In particular, Frio strata overlying the Claiborne 

dominate the Paleogene Gulf in volume and rate of sediment input (Galloway, 2002, 2005), as well 

as in historical oil and gas production (Nehring, 1991). 

Structural Setting

The distribution of the Claiborne Group lies across all of the major structural features of the 

northern part of the Gulf of Mexico Basin (fig. 5). Proceeding northeastward from the United 

States-Mexico border in the downdip basinward subsurface, these include the Rio Grande 

Embayment, the San Marcos Arch, the Houston Embayment, and the South Louisiana Salt Basin. 

Updip, in the northern part of the basin, Claiborne outcrop lies athwart the East Texas Basin and 

the Sabine Uplift, from which most of the Claiborne is eroded. The outcrop belt follows the 

Mississippi Embayment northward through Louisiana into Arkansas and southern Missouri before 

wrapping south through the Jackson Purchase area of western Kentucky and into western 

Tennessee (fig. 1). The outcrop parallels Cretaceous strata around the southern end of the 

Appalachians southward through Mississippi and eastward into Alabama, then wrapping 

northeastward through southern Georgia out of the Gulf Basin and into the Atlantic Coastal Plain. 

The Claiborne is present in the subsurface south of the outcrop belt across the entirety of the 

onshore part of the Gulf Basin, except on the Wiggins Uplift in southern Mississippi (fig. 5) and 

potentially on the crests of some salt domes. In the subsurface of the northern and eastern parts of 

the basin, the distribution of the Claiborne Group is influenced by the structures of the North 

Louisiana Salt Basin, the Monroe Uplift and La Salle Arch, and the Mississippi Salt Basin. The 

downdip limit of the Claiborne has not been well delineated by drilling; few complete penetrations 

of the Claiborne Group occur basinward of the upper Wilcox shelf margin (fig. 1) (T.E. Ewing, 

Frontera Exploration Consultants, Inc., written commun., 2008). 
8 

Figure 4. Stratigraphy of the Claiborne Group. A, stratigraphic column showing main hydrocarbon reservoir 

rocks, bounding shale packages, and relative volumes of sediment input to the northern Gulf of Mexico 

during the Paleogene (from Galloway and others, 2000). Fm. = Formation, Fms. = Formations, 

Grp. = Group, Paleo.=Paleocene, Olig. = Oligocene. B, regional stratigraphic nomenclature for the 

Claiborne Group in south Texas, southeastern-northeastern Texas, and in Louisiana (from Guevara and 

García, 1972; Sams, 1990; Wescott and Hood, 1994; Schenk and Viger, 1996a; Hosman, 1996; and 

Warwick and others, 2002). Names in parentheses are or were used locally. The Yegua/Cockfield 

Formations and Sparta and Queen City Sands are sand-rich conventional oil and gas reservoirs at the 

historical depths of exploration and production in the northern Gulf of Mexico Basin. However, downdip, 

organic-rich shaley facies of Wilcox Group and the Reklaw Formation, Queen City Sand, Sparta Sand, 

Cook Mountain Formation, Yegua Formation, and Cockfield Formations of the Claiborne Group all have 

been postulated potential source rocks at depth and therefore are indicated with “S?”. 
9 

Figure 5. Map of study area (onshore U.S. Gulf Coast and State waters) showing Claiborne Group outcrop, 

Wilcox and Claiborne expansion faults, and outline of major structural features. Claiborne Group outcrop 

is from Schruben and others (1994); major structural features and faults are from Ewing and Lopez 

(1991); Wilcox shelf edge is from Galloway and others (2000).

The majority of Claiborne oil and gas production is from fields in the three major downdip 

structural provinces, the Rio Grande Embayment, the Houston Embayment, and the South 

Louisiana Salt Basin (fig. 6). One exception to this trend is hydrocarbon production from the Sparta 

Sand in central Louisiana and southern Mississippi on the downdip margin of the La Salle arch and 

the North Louisiana Salt Basin. Although some downdip Claiborne gas production is from over 

14,000 feet (ft) in depth in Jefferson County, Tex., the main productive trend is from depths of 

6,000 to 9,000 ft across Texas and Louisiana (fig. 7). Claiborne production across the onshore Gulf 

Coast region primarily is gas, but oil accumulations are present as well, particularly in the updip 

part of the trend. 

Movement of salt diapirs and other salt features primarily impacts the structure of the 

Claiborne Group in the subsurface of the Houston Embayment and South Louisiana Salt Basin. 

Claiborne hydrocarbon resources associated with salt commonly are found in anticlinal folds and 

domes over deeper salt (Katy, Conroe, Bammel, Raccoon Bend, Tomball fields, Texas) and in 

stratigraphic pinchouts against and over salt diapirs (Esperson Dome, Hockley fields, Texas) 

(fig. 6). The Houston Embayment contains approximately 60 known shallow salt diapirs and a few 

known or inferred salt pillows (Ewing, 1991). Many of the shallower salt diapirs are rootless or 
10

Figure 6. Map of study area showing approximate locations of Claiborne Group oil and gas reservoirs 

(white circles). Reservoir locations are from NRG Associates (2006). Claiborne Group outcrop is from 

Schruben and others (1994); major structural features are from Ewing and Lopez (1991). Claiborne Group 

and other reservoirs discussed in the text are shown as blue circles. Elm Grove, Spindletop, and Jennings 

fields are discussed herein but were not assessed with Claiborne Group reservoirs, as these fields 

produce primarily from other intervals. Co.=County.

rooted into salt welds (T.E. Ewing, Frontera Exploration Consultants, Inc., written commun., 

2008). Large areas of welds in the Weches horizon are interpreted to indicate a post-Wilcox canopy 

which deflated under Yegua progradation in southeast Texas (T.E. Ewing, Frontera Exploration 

Consultants, Inc., written commun., 2008). The South Louisiana Salt Basin contains mostly small, 

cylindrical, shallow salt diapirs, but more extensive salt ridges and massifs are present, particularly 

in the southern areas of thick Pliocene-Pleistocene sediment deposition (Ewing, 1991). Salt 

tectonics have strongly influenced upper Claiborne hydrocarbon systems in southeast Texas and 

western Louisiana, where salt movement may have disrupted trap formation and shaped sand 

distribution (Ewing, 2008). The salt basins are separated from the Rio Grande Embayment by the 

San Marcos Arch, which is defined by a southeastward bowing of the outcrop pattern through strata 

as young as Eocene (Ewing, 1991). 

The Rio Grande Embayment contains a few salt domes, but overall, salt is a minor 

component of the Cenozoic structural style of the province (Ewing, 1991). Ewing (2008) suggested 

that deep-seated salt movements may have played some role in Claiborne hydrocarbon systems in 
11

Figure 7. Histogram of depth to top of Claiborne Group reservoirs, Texas and Louisiana. Data are from 

NRG Associates (2006).

the Rio Grande Embayment but did not indicate specific instances. In the western and southwestern 

part of the embayment, Laramide compression has developed a series of low-amplitude northwesttrending folds (Ewing, 1991). These folds primarily modify the structure of Mesozoic strata but 

occur as far to the east as western Starr County in the Claiborne outcrop belt (Ewing, 2008). 

The Claiborne Group ranges greatly in overall thickness, varying from less than 700 ft in 

southeastern Louisiana (Bebout and Gutiérrez, 1983) to over 5,500 ft in south Texas (Dodge and 

Posey, 1981). The overall sedimentation style was dominated by offlapping progradational wedges 

where stratigraphic units dip toward the basin and thicken basinward, with maximum thickening 

basinward of the major depocenters of underlying units (Galloway and others, 1991). An isopach 

map generated as part of this assessment from stratigraphic tops in the IHS database (IHS Energy 

Group, 2005b) shows that the thickest Claiborne section is in south Texas (fig. 8). However, data 

quality in south Texas may be negatively impacted by a paucity of downdip penetrations for the 

tops of units below the Claiborne. In general, as with other Cenozoic stratigraphic packages, the 

Claiborne thickens downdip into the Gulf of Mexico Basin over a relatively narrow margin on 

contemporary growth faults, eventually thinning basinward where sediment supply became scarce. 

For example, the regional cross sections constructed by Dodge and Posey (1981) show the 

Claiborne to be approximately 2,500 ft thick in northern Tyler County, in the Houston Embayment 
12

Figure 8. Claiborne Group isopach map constructed from the IHS Energy Group (2005b) database using 

data current through 2004 and from the Paleo-Data, Inc. (1989) Tenroc Regional Geologic database.

Tops data from IHS Energy Group (2005b) were combined with paleontologic data from Paleo-Data, Inc. 

(1989) in ArcMap 9.1 (Environmental Systems Research Institute, Inc), and a kriging process was used to 

create a surface grid for formation tops. Isopach thicknesses were determined by subtraction of surface 

grids or by the subtraction of individual data points where sufficient tops data were present in the 

databases. Insufficient tops data are available in the IHS and Tenroc databases east of the MississippiAlabama State boundary to extend the Claiborne Group isopach farther eastward confidently.

of northeast Texas, thickening southward to approximately 3,750 ft in southern Jasper County 

(their cross section 1-1’; fig. 9). In the Rio Grande Embayment, the Claiborne thickens 

southeastward by over 1,300 ft across Webb County (their cross section 21; fig. 10), and by almost 

3,000 ft from McMullen into Live Oak County (their cross section 18; fig. 11). Eastward into 

Louisiana, the Claiborne is approximately 1,875 ft thick in southern Avoyelles Parish on cross 

section I-I’ of Eversull (1984) before thickening basinward on growth faults to approximately 

2,775 ft thick in the deepest complete Claiborne penetration, as depicted on cross-section H-H’ of 

Bebout and Gutiérrez (1982) (southward continuation of cross section I-I’). Cross-section R-R’, 

farthest east in Louisiana (Bebout and Gutiérrez, 1983), shows the Claiborne to be approximately 

100 ft thick in St. Tammany Parish, rapidly thickening basinward to approximately 700 ft in St. 

Bernard Parish (fig. 12). The cross sections constructed by Dodge and Posey (1981), Bebout and 

Gutiérrez (1982, 1983), and Eversull (1984) were based on 1970s-era and earlier drilling; 

development of the downdip expanded Yegua section beginning in the 1980s indicates that the 
13

Figure 9. Dodge and Posey (1981) cross section 1-1’ in the Houston Embayment. On this section, new 

drilling (postdating the data used by Dodge and Posey, 1981) documents a thicker downdip Yegua (upper

Claiborne) section than shown (T.E. Ewing, Frontera Exploration Consultants, Inc., written commun., 

2008). The approximate onset of oil generation at 0.6 percent vitrinite reflectance (Ro) corresponds to the 

present-day down-hole temperature of 200 °F (93 °C) using the general relationship of Ro to temperature 

established by Barker and Pawlewicz (1986) from worldwide basins. Faults are generalized and represent 

zones constituted by multiple individual faults. The line representing the onset of overpressure

presumably extends across the entire section through the Wilcox Group; the data for the representation of 

overpressure on this cross section are from the original publication and are based on mud weights. The 

annotation for the wells includes the operator name in the first line, the well name and number in the 

second line, and the township, range, and section in the third line. Fm. = Formation, Co. = County,

Lbr. = Lumber.
14

Figure 10. Dodge and Posey (1981) cross section 21-21’ in the Rio Grande Embayment. The approximate 

onset of oil generation at 0.6 percent vitrinite reflectance (Ro) corresponds to the present-day down-hole 

temperature of 200 °F (93 °C) using the general relationship of Ro to temperature established by Barker 

and Pawlewicz (1986) from worldwide basins. Faults are generalized and represent zones constituted by 

multiple individual faults. The data for the representation of overpressure are from the original publication.

The annotation for the wells includes the operator name in the first line, the well name and number in the 

second line, and the township, range, and section in the third line. Drilling still has not determined the 

downdip extent of the Claiborne section (T.E. Ewing, Frontera Exploration Consultants, Inc., written 

commun., 2008), although seismic reflectors have been interpreted at the top of the Claiborne in the 

deepwater Gulf (Fiduk and others, 1999). Fm. = Formation, Grp. = Group, Co. = County.

Claiborne Group is somewhat thicker downdip than revealed in the published regional cross 

sections (T.E. Ewing, Frontera Exploration Consultants, Inc., written commun., 2008). 

A structure map of the top of the Claiborne Group constructed from IHS tops data 

(IHS Energy Group, 2005b) indicates that depth to the top of the Claiborne rapidly increases 

basinward of the underlying upper Wilcox shelf margin, which is at 9,000 to 10,000 ft from central 

Texas eastward into Louisiana (fig. 13). In south Texas, along the Rio Grande Embayment axis 

(Galloway and others, 2000), the depth to the top of the Yegua (top formation of the Claiborne 

Group) is at approximately 3,000–6,000 ft at the upper Wilcox shelf margin, where the depth to the 

top of the Claiborne also rapidly increases basinward. The large difference in the depth to top of the 

Yegua at the upper Wilcox shelf break indicates that comparatively more post-Yegua sediment has 

been deposited in Louisiana along the Mississippi Embayment axis, as the nexus of major 

depocenters gradually migrated northeastward during the Neogene (Galloway and others, 2000; 
15

Figure 11. Dodge and Posey (1981) cross section 18-18’ in the Rio Grande Embayment. The approximate 

onset of oil generation at 0.6 percent vitrinite reflectance (Ro) corresponds to the present-day down-hole 

temperature of 200 °F (93 °C) using the general relationship of Ro to temperature established by Barker 

and Pawlewicz (1986) from worldwide basins. Faults are generalized and represent zones constituted by 

multiple individual faults. The data for the representation of overpressure are from the original publication.

The annotation for the wells includes the operator name in the first line, the well name and number in the 

second, and the township, range, and section in the third. Fm. = Formation, Grp. = Group, Co. = County.

Galloway, 2005). In several places within the Houston Embayment and the South Louisiana Salt 

Basin, the top of the Claiborne shallows substantially over salt domes (fig. 13). 

Stratigraphy

The Claiborne Group was deposited over the period of approximately 49 to 37 million years 

ago (Ma) in the Middle Eocene (Lutetian-Bartonian Stages) (Galloway and others, 2000; Witrock 

and others, 2003). In much of Texas, the Claiborne is stratigraphically divided into lower, middle, 

and upper packages of primarily progradational sandstones that are separated from each other by 

packages of primarily transgressive shales and mudstones (fig. 4). 

At the base of the Claiborne, the transgressive Reklaw Formation is characterized by thin 

interbedded sandstones and shales overlying the massive sands of the Carrizo Sand (fig. 4). Early 

workers placed the Carrizo Sand in the Wilcox Group (Trowbridge, 1923); however, the Carrizo 

Sand more recently has been considered the basal unit in the Claiborne Group (Eargle, 1968). The 

Carrizo Sand was assessed separately from the Claiborne Group in this work and is included with 
16

Figure 12. Bebout and Gutiérrez (1983) cross section R-R’ in southeastern Louisiana illustrating thinning of 

the Claiborne, thickness of the Neogene, and the abrupt steepening of the Cenozoic section over the 

Cretaceous shelf margin in the eastern part of the basin. The approximate onset of oil generation at 

0.6 percent vitrinite reflectance (Ro) corresponds to the present-day down-hole temperature of 200 °F 

(93 °C) using the general relationship of Ro to temperature established by Barker and Pawlewicz (1986) 

from worldwide basins. The data for the representation of overpressure are from the original publication.

The annotation for the wells includes the operator name in the first line, the well name and number in the 

second, and the township, range, and section in the third. Fm. = Formation, Fms. = Formations, 

Grp. = Group. Inset shows the line of section for figure 21 of this publication.
17

Figure 13. Depth to the top of Claiborne (Yegua Formation) constructed from the IHS Energy Group (2005b) 

database using data current through 2004 and from the Paleo-Data, Inc. (1989) Tenroc Regional 

Geologic database. Tops data from IHS Energy Group (2005b) were combined with paleontologic data 

from Paleo-Data, Inc. (1989) in ArcMap 9.1 (Environmental Systems Research Institute, Inc), and a 

kriging process was used to create a surface grid for formation tops. The top surface grid was subtracted 

from the elevation at surface to create the depth-to-top grid. The Claiborne Group outcrop is from 

Schruben and others (1994); salt is from Ewing and Lopez (1991); shelf margins are from Galloway and 

others (2000). Insufficient tops data are available in the IHS and Tenroc databases east of the 

Mississippi-Alabama State boundary to extend the Claiborne Group isopach farther eastward confidently.

the assessment of the Wilcox Group (Warwick and others, 2007), primarily because it cannot be 

separated from the Wilcox Group in the subsurface based on lithology alone. 

Overlying the basal shales of the Reklaw Formation (called Bigford Formation near the 

outcrop in south Texas) is the Queen City Sand (Kennedy, 1892), an important hydrocarbon 

reservoir in south Texas and across the border into the Burgos Basin of northeastern Mexico. The 

Queen City Sand is described as transitional with the underlying Reklaw Formation (Ramos and 

Galloway, 1990) and is disconformably overlain by transgressive shelf muds of the Weches 

Formation. The Queen City Sand is present only as far northeast as the Texas-Louisiana border 

(Guevara and García, 1972). The name Mount Selman Formation also was used as a Queen City 

Sand equivalent in Texas (Kennedy, 1892; Trowbridge, 1932) but is no longer in use. The name 

El Pico Clay was applied by Eargle (1968) to lignitic claystones of the Queen City Sand interval in
18

Figure 14. Spontaneous potential and resistivity log response of the lower Claiborne section in eastern Texas 

illustrating eastward loss of the Queen City Sand (from Ricoy and Brown (1977); see Ricoy (1976) for 

original data). Dashed line illustrates division between prodelta and shelf/delta-plain facies. Co. = County.

south Texas. Overlying the Queen City Sand in Texas are mudstones of the regional transgressive 

Weches Formation. The entire lower Claiborne section thins eastward into Louisiana, where the 

Queen City Sand is absent and the time-equivalent Cane River Formation comprises marl and distal 

shelf shales (fig. 14). Due to the width of the lower Claiborne shelf and the great distance from 

contemporary primary sediment supply on the Rio Grande Embayment axis, the Cane River 

Formation is less than 30 ft thick in some places in the subsurface in southern Louisiana(Vincent 

and Ewing, 2000). Vincent and Ewing (2000) described the regional-scale, log-based stratigraphic 

architecture of the lower Claiborne from southeast Texas through east-central Louisiana, 

demonstrating a pattern of low-angle, sigmoidal, clinoform downlaps separated by regional 

flooding surfaces. Lower Claiborne units prograded across the narrower shelf in south and central 

Texas out into slope environments. However, because of distance from sediment supply and a 

wider shelf in Louisiana, the lower Claiborne strata thin, downlap, and condense toward the east, 

where marl of the Cane River Formation rests by regional disconformity on the upper Wilcox 

Group (Vincent and Ewing, 2000). 

The middle section of the Claiborne Group in Texas and Louisiana is composed of the 

hydrocarbon-bearing, progradational Sparta Sand (Spooner, 1926) and the overlying Cook 

Mountain Formation (Kennedy, 1892), which consists of glauconitic marine shale and marl at 

outcrop (Ewing, 1994). The name Crockett Formation (Stenzel, 1939) locally was used as an 

equivalent to the Cook Mountain Formation. The Sparta Sand is present throughout the Gulf Coast 

of Texas and Louisiana; however, most Sparta hydrocarbon production is from northern Louisiana. 

The thickness of the Sparta Sand is less than 700 ft in all of Texas (Ricoy and Brown, 1977). In 
19

south Texas, the Cook Mountain Formation is reported to have considerably different character 

than in east Texas (Gardner, 1938; Patterson, 1942; Eargle, 1968), where it is composed of 350 to 

450 ft of chocolate brown and gray clay (Wendlandt and Knebel, 1926). In south Texas and into 

Mexico, the Cook Mountain Formation is described as consisting chiefly of glauconitic sands and 

sandstone (Trowbridge, 1932; Kane and Gierhart, 1935). 

Ewing (1994) presented a discussion of “the Cook Mountain problem,” which can be 

summarized as a historical inconsistency as to what constitutes this unit in the subsurface. At 

outcrop, the Cook Mountain Formation is a “diverse assemblage of marine-shelf and marginal 

marine environments associated with the maximum transgression between Sparta and Yegua 

prograding delta complexes” (Ewing, 1994, p. 227), that is, an easily recognized regional boundary 

between middle and upper Claiborne nonmarine sandy units, the Sparta Sand and the Yegua 

Formation, respectively. However, in the downdip subsurface, the overlying Yegua Formation 

becomes marginally marine and contains Ceratobulimina eximia in its lower portions, the first 

occurrence of which traditionally is used to designate Cook Mountain Formation in the updip 

subsurface. Therefore, the precise division between the Cook Mountain and Yegua Formations 

becomes uncertain in the downdip subsurface. In practical terms, this biostratigraphic pick results 

in the misidentification of Yegua Formation sand reservoirs, which yield Ceratobulimina as “Cook 

Mountain” in the NRG Associates (2006) database, and precludes a separate analysis of middle and 

upper Claiborne petroleum geology based on the NRG Associates (2006) data. The problem is well 

illustrated in figure 6 of Ewing (1994), reproduced here as figure 15. Figure 15 shows three ways to 

identify the Cook Mountain Formation: (1) as a genetic unit, including strata deposited in the time 

intervening between deposition of the Sparta Sand and the Yegua Formation, (2) as a 

lithostratigraphic unit, including facies identified as Cook Mountain at and near the outcrop, and 

(3) as a biostratigraphic unit including all Ceratobulimina-bearing strata in the subsurface. In part,

because Cook Mountain and Yegua Formation reservoirs are inseparable in the NRG Associates

(2006) database, the Claiborne was divided into Lower (primarily Queen City Sand), and Upper 

(Sparta Sand, Yegua and Cook Mountain Formations) AUs for this assessment, rather than Lower, 

Middle, and Upper AUs, as the stratigraphic division would have it. 

The upper Claiborne section is composed of the sand-rich Yegua Formation across Texas, 

which is equivalent to the Cockfield Formation in Louisiana and Mississippi (Mancini and Tew, 

1994; Johnston and others, 2000). The upper Claiborne section is referred to as the Gosport Sand in 

Alabama (Mancini and Tew, 1994). Some workers consider the uppermost sands in the Texas 

Yegua Formation as an informal “Cockfield Zone” (Hardin and Clark, 1968), on the basis of the 

presence of the foraminifera Nonionella cockfieldensis. Persistent strike-elongate sand lenses in the 

upper Yegua Formation of south Texas have been given informal and local names including the 

Bruni, O’Hern, Pettus, and Rosenburg Sands (West, 1963). These local sand names sometimes are 

used to code the producing formation in the NRG Associates (2006) database, resulting in multiple 

formation codes for upper Claiborne Yegua Formation oil and gas production. Ewing (2008) 

described the lower Yegua Formation of south Texas as a strandplain system and upper Yegua 

Formation strata as a barrier bar system pinching out updip into lagoonal facies. Davies and 

Ethridge (1971) reported that the south Texas Yegua Formation outcrop principally is composed of 

claystones, with thin limestones and sandstones. In central Texas, the Yegua Formation comprises 

almost one-half of the thickness of the Claiborne Group at outcrop, where it is 1,100 ft thick 

(Davies and Ethridge, 1971). Ewing and Vincent (1997a) presented a regional correlation of Yegua 

and Cockfield Formation strata from Texas into Louisiana. An important observation made by 

these workers is that the lower Yegua Formation cycles lose sand eastward and condense into a 
20

Figure 15. Graphic representation of the Cook Mountain problem. The Cook Mountain Formation is shown as 

(1) CM1 – a genetic unit, time-correlative with the outcrop Cook Mountain; (2) CM2 – a lithostratigraphic 

unit, representing the formally defined Cook Mountain Formation; and (3) a biostratigraphic unit, 

representing Ceratobulimina-bearing strata time-correlative with outcropping Cook Mountain and lower 

Yegua Formation (from Ewing, 1994). See text for additional explanation.

thin (<100 ft thick) marly shale unit called the “Sparta Lime” (not equivalent to the underlying 

Sparta Sand).

The Claiborne Group is overlain by the regionally transgressive Moodys Branch Marl of the 

lowermost Jackson Group (Cooke, 1918). The thin (10–100 ft) Moodys Branch Marl primarily 

consists of marine glauconitic sands and marl (Tew, 1992) and represents Upper Eocene sea level 

transgression across a maximum flooding surface following deposition of the sand-rich upper 

Claiborne Group (Galloway and others, 2000). 

Paleogeography, Sediment Source Areas, and Depositional Systems

Following deposition of the mostly fluvial Carrizo Sand during the Early Eocene, regional 

transgressive shelf muds of the Reklaw Formation blanketed the northwest Gulf of Mexico margin

beginning at about 49 Ma (Galloway and others, 2000). This period of sea level transgression and 

sediment starvation in the northern Gulf of Mexico records a temporary cessation of major uplift in 

the southern Rocky Mountains and Sierra Madre. These conditions persisted for the remainder of 

the Middle-Late Eocene during Claiborne Group deposition, interrupted by periodic pulses of brief, 

rejuvenated sediment input (Galloway, 2005). Local sandstones in the transgressive Reklaw 

Formation are glauconitic, in contrast to the underlying nonmarine Carrizo Sand, which locally

contains interbedded lignites (Shellman, 1985). Subsidence in the Gulf of Mexico Basin primarily 

was load driven rather than tectonic; therefore, changes in relative sea level were a result of eustatic 

fluctuations, assuming that compaction remained relatively constant (Winker, 1982; Galloway and 

Williams, 1991). 
21

Figure 16. Depositional systems of the lower Claiborne Group (from Galloway and others, 2000). Claiborne 

outcrop is from Schruben and others (1994). Possible erosion of Claiborne in Mississippi is from 

O’Donnell (1974) and Dockery (1976).

Recording a pulse of Laramide uplift in the Sierra Madre, deposition of the lower Claiborne 

Queen City Sand was focused into the Rio Grande Embayment and Norma depositional axes 

(fig. 16), where wave-dominated platform delta systems prograded into the Gulf of Mexico. 

Prodelta muds from the Norma and the Rio Grande Embayment axes prograded over the northwest 

margin as much as 20 miles (mi) locally (Galloway and others, 2000). In addition, rapid creation of 

accommodation space on the shelf allowed for the growth of inner-shelf deltas and some sediment 

deposition far landward of the contemporary shelf margin (Galloway and Williams, 1991). To the 

northeast of the primary sediment focus in southern Texas, a smaller, lobate, fluvial-dominated 

Houston delta system was present in southeastern Texas (Galloway and others, 2000). Into 

Louisiana and to the east, a muddy shelf covered the entire north-central basin area, represented by 

the condensed Cane River Formation of Louisiana. Claiborne Group deposition did not advance the 

shelf margin appreciably over the underlying upper Wilcox Group shelf break in Louisiana. 

Overlying the Queen City Sand, condensed, glauconitic shales of the Weches Formation record 

primarily marine deposition at the lower-middle Claiborne transition during a period of regional 

transgressive flooding. This interval marks an extended period of low sediment influx and the lapse 

of uplift in the western continent (Galloway and others, 2000). 
22

Figure 17. Depositional systems of the upper Claiborne Group (from Galloway and others, 2000). Claiborne 

outcrop is from Schruben and others (1994). Possible erosion/nondeposition of Claiborne in Mississippi 

and Alabama is from O’Donnell (1974) and Dockery (1976).

During approximately 44–40 Ma, the Sparta Sand was deposited in the north-central part of 

the basin primarily along the Mississippi Embayment axis, the dominant axis of sediment input 

during this period. Sparta Sand deposition was platform restricted and occurred far landward of the 

contemporary shelf edge. As a result, Middle Claiborne Group deposition did not appreciably 

advance the shelf margin over the earlier Queen City Sand, leaving the outer shelf relatively 

sediment starved (Galloway and Williams, 1991). 

The upper Claiborne Group depositional episode from approximately 40–37 Ma occurred as 

a result of renewed uplift in the Mexican Cordillera. Deposition of the Yegua Formation caused 

basinward migration of the shelf edge throughout Texas. The Liberty Delta complex in the Houston 

Embayment and the Falcon Delta in the Rio Grande Embayment axis were the primary points of 

sediment dispersal (fig. 17). The rapid progradation of the Liberty Delta and accumulation of 

sediment at the shelf margin resulted in subregional mass wasting and subsequent deposition of 

reservoir sandstones far downdip of the shelf margin (Edwards, 1991; Hull, 1995; Ewing and 

Vincent, 1997b; Swenson, 1997; Galloway and others, 2000). 
23

Elements of the Petroleum System

The Gulf of Mexico Basin is one of the world’s most important petroleum provinces 

(Nehring, 1991). As such, diverse research has been directed at understanding the generation,

migration, and trapping of its hydrocarbon resources (Koons and others, 1974; Laplante, 1974; 

Nunn and Sassen, 1986; Evans, 1987; Walters and Dusang, 1988; Sassen and others, 1988; Sassen 

and Moore, 1988; Sassen, 1990; Thompson and others, 1990; Price, 1991; Gregory and others, 

1991; McDade and others, 1993; Zimmerman and Sassen, 1993; Echols and others, 1994; Wagner 

and others, 1994; Wenger and others, 1994; Wescott and Hood, 1994; Losh, 1998; Zimmerman, 

1999; Nelson and others, 2000; Fillon, 2001; Gatenby, 2001; Hood and others, 2002; Lewan, 2002; 

Cathles, 2004, Mancini and others, 2006, among many others). Collectively, these workers have 

demonstrated that Gulf of Mexico Basin hydrocarbons are sourced from a number of stratigraphic 

intervals, including the Oxfordian Smackover Formation and Kimmeridgian-Tithonian Bossier 

Shale and Haynesville Formation (Jurassic), possibly the Aptian Pearsall Formation (Lower 

Cretaceous), the Turonian Eagle Ford Formation (Upper Cretaceous), and the Thanetian-Ypresian

Wilcox Group and Sparta Sand (Tertiary) (fig. 2). 

Organic matter maturation and the generation and migration of hydrocarbon resources from 

a particular source interval are dependent on location within the Gulf Basin. Most reservoired 

Claiborne hydrocarbons are interpreted to be sourced from the lower Tertiary section 

(fig. 18; McDade and others, 1993; Hood and others, 2002). As described earlier, the conventional 

hydrocarbon resources contained in the approximately 700 known Claiborne Group reservoirs 

across the study area are considered to be part of the Upper Jurassic-Cretaceous-Tertiary 

Composite total petroleum system that was defined for this assessment (fig. 3). Ideas regarding 

elements of the Upper Jurassic-Cretaceous-Tertiary Composite total petroleum system, including 

the timing of generation and accumulation of hydrocarbons in the Claiborne Group, are 

summarized in the events chart presented in figure 19. 

Source Rocks and Thermal Maturation

Strong evidence directly linking the charge of Claiborne oil reservoirs to a particular source 

interval is lacking due to the relative infrequency of Tertiary source rock penetrations in the Gulf 

Coast. However, several authors have postulated that the downdip, deeply buried marine portions 

of the Paleocene-Eocene Wilcox and Claiborne groups could potentially be good source rock 

candidates of appropriate maturity for oil and gas generation (Schenk and Viger, 1996a, b; Sassen 

and others, 1988; Sassen, 1990). Thermal maturity of the Paleogene section would be enhanced by 

deep burial under the Miocene-Pleistocene in southern Louisiana, where McDade and others 

(1993) reported that the top of the Claiborne Group rapidly deepens basinward from 9,000 to 

17,500 ft over the Cretaceous-Wilcox shelf edge. Work by Zimmerman (2000) indicated that the 

Eocene section was covered by >30,000 ft of Neogene sediments for much of coastal Louisiana and 

was buried to more than 35,000 ft in southeastern coastal Louisiana. In fact, Zimmerman (2000) 

predicted that thermal destruction of Eocene-hosted hydrocarbons was occurring throughout much 

of southern Louisiana (south of the Cretaceous-Wilcox shelf edge) due to hostile burial conditions 

at depths greater than about 27,000 ft. Warwick (2006) constructed a present-day thermal maturity 

map for the top of the Wilcox, based on vitrinite reflectance data, illustrating that the Paleogene is 

thermally mature for hydrocarbon generation across much of the northern Gulf Basin nearing the 

present-day coastline (fig. 20). Additional information on the modeling of Wilcox thermal 

maturation has been presented by Rowan and others (2007). 
24

Figure 18. Hydrocarbon families of the U.S. Gulf Coast (from Hood and others, 2002). Claiborne Group 

outcrop is from Schruben and others (1994); Wilcox Group shelf margin is from Galloway and others 

(2000). This diagram shows families of reservoired oil and gas that originated from common source rocks, 

as compared to figure 3, which shows the boundary of the Upper Jurassic-Cretaceous-Tertiary Composite 

total petroleum system that was defined for this assessment. Miss. = Mississippi. The uncolored areas in 

the figure were not assigned to a hydrocarbon family in Hood and others (2002). 

Characterization of crude oils from Wilcox and older Tuscaloosa and Smackover reservoirs 

in Louisiana and Mississippi illustrates that the oils contained in the younger reservoirs are 

geochemically distinct from those reservoired in the older reservoirs (Sassen and others, 1988). In 

particular, workers in Louisiana have demonstrated oil-source rock correlations using the 

biomarker 18α-oleanane (not present in crude oils from Mesozoic sources), confirming that oils 

sourced from Wilcox-Sparta strata have charged Wilcox reservoirs in south Louisiana (Walters and 

Dusang, 1988; McDade and others, 1993). 

The Paleocene-Eocene Wilcox and Sparta contain mostly terrestrial gas-prone kerogen in 

the updip environment in central Louisiana and southwest Mississippi and only become more oil 
25

Figure 19. Events chart summarizing the major elements of the Upper Jurassic-Cretaceous-Tertiary 

Composite total petroleum system of the Gulf Basin (modified from Condon and Dyman, 2006). The 

critical moment is defined as the point in time that best represents the generation, migration, and 

accumulation of most of the hydrocarbons in the Upper Jurassic-Cretaceous-Tertiary Composite total 

petroleum system. As relates to the Claiborne Group, this is in the latter part of the Middle Eocene when 

the sand-rich Yegua and Cockfield reservoirs were deposited. E = Early, M = Middle, L = Late, 

TR = Triassic, Paleo. = Paleocene, Olig. = Oligocene, Po = Pliocene, P = Pleistocene, Quat. = Quaternary.

prone downdip (Sassen and others, 1988; Gregory and others, 1991). McDade and others (1993) 

reported mixed terrestrial and marine organic matter (Type II/III mixed kerogen) with low 

hydrogen indices of about 100 milligrams hydrocarbon per gram (mg HC/g) of total organic carbon 

(TOC) for >90 percent of 1,100 lower Tertiary marine shales from south Louisiana collected from 

depths of 9,000 to 16,000 ft. TOC contents for these samples were in the range 0.5 to 2.0 percent. 

The remainder of their samples (McDade and others, 1993) ranged to as high as 6.0 percent TOC 

and contained more oil-prone Type II organic matter with hydrogen indices of 200 mg HC/g TOC 

or more. Gregory and others (1991) reported a modest correlation between fluorescence intensity 

and hydrogen index for Sparta and Wilcox samples and concluded that the organic material was 

dominantly terrestrial Type III but was deposited in a marine environment. Gregory and others 

(1991) reported that Sparta samples were thermally immature and Wilcox Group samples were 

thermally mature for oil generation. Hood and others (2002) suggested that regional differences in 

the types of lower Tertiary organic matter deposited in the Gulf Basin were responsible for 

variations in the distribution of oil versus gas. In particular, Hood and others (2002) pointed out 

that more marine Type II source rocks in Louisiana appeared to produce a greater proportion of oil, 

whereas terrestrially sourced organic matter produced more gas-prone hydrocarbons in 

Texas (fig. 18).

Analyses of sidewall cores collected from a deep offshore well drilled east of the modern 

Mississippi delta revealed good source rock potential for thermally immature lower Tertiary strata 

(Wagner and others, 1994). Samples from the lower Tertiary had TOC contents of 0.9 to

3.3 percent with some hydrogen indices >500, indicative of a marine Type II kerogen (Wagner and 

others, 1994). The authors concluded that lithologies similar to those drilled could be thermally 
26 

Figure 20. Present-day thermal maturity of the top of the Wilcox Group (from Warwick, 2006). Claiborne 

outcrop is from Schruben and others (1994); Wilcox Group shelf margin is from Galloway and others 

(2000).

mature for oil generation locally due to shallower water depths, increased overburden thickness, 

and higher heat flow. A one-dimensional (1-D) burial history model for southern Louisiana 

indicates that Eocene source rocks entered the oil window at 25.7 Ma (Oligocene), reached peak oil 

generation at 14.9 Ma (middle Miocene), and entered the wet gas window in the late Miocene 

7.3 Ma (Nelson and others, 2000). Thermal history modeling by McDade and others (1993) also 

indicated that the Paleogene section was thermally mature for oil generation in southwestern 

Louisiana and that Lower Cretaceous and Jurassic source rocks were overmature across 

southern Louisiana. 

Some Tertiary-sourced oil (Hood and others, 2002) production from the Sparta Sand in 

northern Louisiana is far removed from the possible locations of thermally mature potential lower 

Tertiary source rocks, which would occur south of the Cretaceous shelf break (Sassen, 1990). In 

this case, very long range lateral migration must have occurred if the Sparta oils are indeed sourced 

by lower Tertiary rocks. Otherwise, vertical migration from Turonian and Tithonian source rocks 

may be a possibility in this area (Sassen, 1990). 

Shellman (1985) suggested that shales in the Paleocene Midway Group may also be 

potential source rocks in the Tertiary Gulf of Mexico Basin; pyrolysis study of Midway samples 

from Mississippi and Louisiana by Sassen (1990) confirms moderate source potential. There do not 

appear to be any potential source rock intervals in the northern half of the Gulf of Mexico Basin 

higher in the section than the Lower Oligocene (Dow, 1977). This is due in part to the high rates of 
27

deposition, which limited the overall proportion of organic matter contained in the sediments, and 

the recent age of deposition, which limits thermal maturity (Nunn and Sassen, 1986; Nehring, 

1991). In addition, despite predictions of good preservation potential for Type II kerogen in anoxic 

intraslope basins (Dow, 1984), studies of the type of organic matter contained in upper Tertiary 

strata indicate that most is of terrestrial origin with little potential for oil generation (Fang and 

others, 1989).

As part of the Gulf of Mexico assessment, a regional thermal maturation history of the 

Wilcox was reconstructed based on 1-D burial history models of 53 wells in the Texas Coastal 

Plain (Rowan and others, 2007). Their work indicated that the downdip portions of the basal 

Wilcox entered the oil window in the Early Eocene, and the maturation front has since gradually 

moved updip during deposition of Cenozoic overburden. At the present day, hydrocarbon 

generation is complete in the basal Wilcox but is ongoing farther updip. The farthest updip portions 

of the Wilcox, north of the Wilcox shelf margin, are undermature for hydrocarbon generation 

(Claypool and Mancini, 1989; Mancini and others, 1999, 2006; Warwick, 2006; Rowan and 

others, 2007).

Regional burial history modeling by Lewan (2002) in the onshore central Gulf Coast area

(eastern Texas, Louisiana, southern Mississippi) demonstrated cracking of Smackover oil to gas 

beginning as long ago as 89 Ma in some locations and continuing to the present. Gas generated by 

cracking of Smackover oils could have charged Claiborne reservoirs from their deposition until 

present. According to the Lewan (2002) study, Turonian strata in southern Louisiana mostly are 

undermature for gas cracking; however, cracking of Turonian oil may charge gas to Claiborne 

reservoirs in the downdip portions of the basin. In the Lewan (2002) study, four locations at the 

downdip coastal portion of the study area indicated gas generation via cracking of Turonian oil. 

Migration of Hydrocarbons

Migration of oil and gas in the Cenozoic Gulf of Mexico Basin dominantly is short-range 

vertical, occurring along the abundant growth faults associated with sediment deposition, or along 

faults associated with salt movement and emplacement (Nunn and Sassen, 1986; Sassen and others, 

1988; Sassen, 1990; Nehring, 1991; Price, 1991; Schenk and Viger, 1996a, b; Losh, 1998). 

Migration of oil and gas from deep mature mudrocks probably also has occurred up stratal collapse 

zones created by salt evacuation (Hood and others, 2002). Dominantly vertical migration is 

responsible for the distribution of hydrocarbon families seen in the Hood and others (2002) study; 

in general, hydrocarbons from a particular source are reservoired above the areas where that source 

is mature. Lateral migration of up to 3 mi may also constitute an important migration pathway; 

medium distance or longer (> 30 mi) migration probably is rare (Nehring, 1991). However, Sassen 

and others (1988) and Sassen (1990) suggested long-range lateral migration (up to 100 mi) of 

Wilcox crude oils from mature downdip marine source facies was necessary to charge Wilcox 

reservoirs in central Louisiana (fig. 21). Wescott and Hood (1994) also invoked long-range lateral 

migration of hydrocarbons to charge reservoirs in the East Texas Salt Basin. As described above, 

migration and emplacement of Tertiary-sourced oils into Sparta Sand reservoirs of north-central 

Louisiana is best explained as a consequence of long-range lateral migration from thermally mature 

Tertiary sources south of the Cretaceous shelf break. Work by Cathles and colleagues (summarized 

in Cathles, 2004) demonstrated that a high volume of the hydrocarbons currently being generated 

in the deep Gulf of Mexico offshore source strata simply flow through the system and are expelled 

directly into the overlying waters, where they are evidenced as hydrocarbon seeps on the seafloor 

and slicks upon the water surface (Hood and others, 2002). The Cathles (2004) studies further 
28

Figure 21. Conceptualized migration of oil and gas in southern Louisiana (from Sassen, 1990). Location of 

section is shown in figure 12. This cartoon cross section is based on the I-I’ and H-H’ cross sections 

constructed by Eversull (1984) and Bebout and Gutiérrez (1982), respectively. Grp. = Group, 

Fm. = Formation, Undiv. = undivided, km = kilometer. 

demonstrated that offshore reservoirs are filling from the current and geologically recent flowthrough patterns of hydrocarbon migration. In addition, Cathles (2004) observed the gas washing of 

oil, which occurred through the removal of n-alkanes. This characteristic may help to delineate the 

location of potential gas reservoirs in exploration by systematic analysis of oil compositions. Work 

by Gatenby (2001) empirically demonstrated that the largest oil and gas accumulations in the 

deepwater Gulf of Mexico offshore occur proximally above the depth at which gas and oil become 

cosoluble and that no commercial accumulations of oil occur below the depth at which oil and gas 

phase-separate. Gatenby (2001) also pointed out that the greater the magnitude of the vertical 

change of oil in gas solubility, the greater the size of the accumulation. This suggests that vertically 

migrating hydrocarbons are emplaced in response to changes in temperature and pressure 

conditions and explains the relationship between hydrocarbon pay and the top of overpressure in 

the Gulf of Mexico Basin (Leach, 1993). 

Reservoir Rocks

Lower Claiborne - Queen City Sand and Reklaw Formation

The Queen City Sand is thickest in south Texas (fig. 22), where strike-oriented, coastal 

barrier reservoir sands accumulated as part of a highly destructive wave-dominated delta system 

(Guevara and García, 1972). Reservoir facies generally are downdip from the sand maxima and 

interfinger with prodelta muds. Lobate sand geometries in eastern Texas are interpreted to indicate 

a highly constructive delta system. Sandy facies of the Queen City pinch out eastward toward 
29

Figure 22. Sand isolith (top) and facies (bottom) map for the lower Claiborne Queen City Sand, Texas 

Coastal Plain (from Guevara and García, 1972).

Louisiana, where the overlying Weches Formation and underlying Reklaw Formation merge into 

the condensed Cane River marl (Guevara and García, 1972). Most of the updip fluvial facies of the 

Queen City were removed by erosion (Guevara and García, 1972). The Queen City is relatively 

unaffected by salt tectonics in the south Texas Rio Grande Embayment, as compared to upper 

Claiborne strata farther northeast in the salt-rich Houston Embayment. There are no Queen City 

reservoirs reported north of the San Marcos Arch (NRG Associates, 2006), although there are some 

producing wells listed north of the arch in the IHS database (IHS Energy Group, 2005b). 

According to Galloway and Williams (1991), Queen City deposition did not build shelfedge deltas; instead, inner-shelf delta sediments accumulated on the shelf platform far landward of 

the contemporary shelf edge. This was due to rapid creation of accommodation space by the 

subsidence of the shelf, possibly in a compensative response to fluvial bypass of the shelf by the 

upper Wilcox and loading of the shelf edge by upper Wilcox prograding deltas. In effect, this 

tectonic influence on deposition could reduce the potential for a downdip Queen City play. Since 

the bulk of Queen City sediments accumulated landward of the shelf margin, the inference is that 

no sands were transported into slope, basin floor, and other distal environments by the foundering 

or subsidence of shelf edges, stormwater retreat, or lowstand fan deposition. However, the more 

regional approach used by Galloway and others (2000), with the inclusion of deeper wells, 

illustrated substantial advancement of the Queen City shelf margin, implying significant transport 

of sandy sediments to the shelf edge and beyond (W.E. Galloway, The University of Texas at
30

Austin, written commun., 2006). Regardless, the current collective understanding among 

exploration geologists of the nature and location of the Queen City shelf margin in south Texas 

is considered poor at best (T.E. Ewing, Frontera Exploration Consultants, Inc., written 

commun., 2008). 

Evaluation of the NRG Associates (2006) database indicates good reservoir quality for 

updip Queen City reservoirs, with reported average porosity ranging from 16 to 33 percent and 

reported average permeability ranging from 16 to 1,240 millidarcies (md). For the approximately 

10 downdip Queen City reservoirs contained in the NRG Associates (2006) database, only one 

average porosity value of 19 md is reported, consistent with the range of 19 to 25 percent reported 

by Burnett (1990) for the Mestena Grande field (fig. 6) in southern Texas. Burnett (1990) reported 

that measured permeabilities typically ranged from 15 to 35 md at Mestena Grande, with a 

maximum reported value of 80 md. 

Reservoirs generally are normally pressured in updip Queen City reservoirs, consistently 

following the Gulf of Mexico hydrostatic pressure line of 0.465 pounds per square inch per foot 

(psi/ft) (Dickinson, 1953). Schenk and Viger (1996a) reported that Queen City reservoirs are 

overpressured in more distal, downdip areas, consistent with the report by Burnett (1990) on the 

Mestena Grande field. Analysis of NRG Associates (2006) data indicates that all of the Queen City 

reservoirs in the downdip environment (8,000–12,000 ft) are overpressured (>5,000 psi). 

Shellman (1985) described Reklaw Formation oil fields in Fayette, Gonzales, Wilson, and 

Atacosa Counties, Tex., where oil is produced from transgressive shoreline sands deposited as the 

Reklaw sea advanced over the coastal plain. Sams (1990) presented a sequence stratigraphic 

analysis of the Reklaw transgression in the same general geographic area. Oil-charged reservoirs 

with local names including the Mackhank, Luling, Slick, and Second and First Reklaw/Atkinson 

Sands (Sams, 1990) are at depths of 1,800 to 2,200 ft (Shellman, 1985). Shellman (1985) described 

this trend as composed of better quality sandstones to the northeast, with poorly developed and 

discontinuous sands to the southwest. In the Elm Grove field of Fayette County (fig. 6), Shellman 

(1985) described six 5- to 50-ft-thick reservoir intervals, separated by impermeable shales 2 to 15 ft 

thick. Reklaw sandstones have average porosity of 26 percent and permeability of <10 to 900 md 

(Shellman, 1985). Isolated clean sand lenses may have higher porosity and permeability; 

conversely, shaley laminations may negatively impact reservoir character. Compaction in 

transgressive Reklaw sandstones does not significantly impact porosity because of the shallow 

burial depths (Shellman, 1985). Composition of transgressive Reklaw sands is 60 percent finegrained monocrystalline quartz, with a pore throat diameter of 70 micrometers (μm) (Shellman, 

1985). Clays comprise 22 percent of the textural framework, and clay migration is believed to 

contribute to production problems (Shellman, 1985). 

Middle Claiborne – Sparta Sand and Cook Mountain Formation

Ricoy and Brown (1977) described the depositional systems of the Sparta Sand in Texas, 

where a highly constructive delta dominated in east Texas and a highly destructive delta system 

dominated in south Texas. Sediment dispersal by fluvial processes was in the direction of dip in the 

highly constructive delta environment, and sandstone geometries generally are perpendicular to 

depositional strike with a lobate areal geometry. Facies recognized include delta plain distributary 

sandstones and interdistributary mudstones, delta-front sandstones, and prodelta mudstones. In 

central Texas, a strandplain-barrier bar system with sand geometries parallel to regional strike was 

built from sands transported longshore from the principal sediment input axes in south and east 

Texas. Well logs indicate that the Sparta Sand in Texas is a single sandstone unit with a maximum 
31

thickness of 100 ft, thinning downdip into shelf mud facies (Ricoy and Brown, 1977). In south 

Texas, the Sparta was deposited in a highly destructive delta system, characterized by sandstone 

maxima parallel to depositional strike, with a variety of depositional environments recognized, 

including coastal barrier sandstones, lagoonal mudstones, and prodelta and shelf mudstones (Ricoy 

and Brown, 1977). Sediment dispersal here and in the strandplain environment was parallel to 

strike. Galloway and Williams (1991) showed that Sparta accumulation rates were lower near the 

contemporary shelf edge, as compared to all other Gulf of Mexico Basin Cenozoic sequences, 

which had the highest accumulation rates near the shelf edge, decreasing landward.

Production from Sparta Sand reservoirs occurs in central Louisiana along the Mississippi 

Embayment axis (fig. 1), with several reservoirs scattered into central and south Texas. Nehring 

(1991) reported that Sparta reservoirs are at depths of 2,000 to 11,500 ft in Louisiana and are 

generally between 3 to 220 ft thick. Nehring (1991) reported that reservoir quality is good, with 

porosity generally ranging from 21 to 34 percent and permeability ranging from 60 to >1,000 md. 

This is consistent with the reservoir quality reported for the 11,500-ft-deep Fordoche oil field 

(fig. 6) in Point Coupee Parish (Krutak and Kimbrell, 1991). The absence of Sparta production in 

Texas is assumed to be the result of low sediment supply, which resulted in (1) thin prodelta muds, 

which would have acted as source beds, (2) a lack of growth faults to provide traps because of the 

thin delta front/prodelta facies, and (3) a lack of reservoirs of sufficient thickness compared to the 

overlying Yegua and the underlying Queen City Sand (Ricoy and Brown, 1977). 

Cook Mountain reservoirs listed in the NRG Associates (2006) database are distributed 

evenly across central and east Texas, with a scattering (Crockett reservoirs) in south Texas. There 

are no Cook Mountain reservoirs reported in Louisiana in the NRG Associates (2006) database. 

Many of the Cook Mountain reservoirs and production wells (IHS Energy Group, 2005a) in Texas 

are on the Yegua trend (described below), suggesting that many may in fact be 

Ceratobulimina-bearing lower Yegua Formation sands (Ewing, 1994) rather than the glauconitic 

marine sands of the Cook Mountain, as described at outcrop in southern Texas by Trowbridge 

(1932) and Kane and Gierhart (1935). 

Upper Claiborne – Yegua and Cockfield Formations

Depositional environments of the upper Claiborne Yegua and Cockfield Formations vary

greatly, from fluvial to deltaic, strandplain, bar, and shelf and slope systems (Nehring, 1991; 

Ewing, 2008). Basinal reservoir facies also may be present below the depths of current drilling 

(T.E. Ewing, Frontera Exploration Consultants, Inc., written commun., 2008). In the highconstructive Liberty Delta system of the Houston Embayment, lobate, strike-normal delta front 

strata include thick sand-rich sequences vertically bounded by thin to thick marine muds 

(Fisher, 1969). In the south Texas Falcon delta, Yegua hydrocarbon reservoirs are an extensive 

strandline-barrier bar complex characterized by strike-parallel named sands including the Pettus, 

Rosenburg, Bruni, and O’Hern. The lower part of the Yegua primarily consists of strandplain 

facies, and the upper Yegua consists of barrier bar facies (Ewing, 2008). Fisher (1969) reported 

800 to 1,000 ft of net sand in the upper Claiborne of south Texas and over 1,000 ft in the Houston 

Embayment (fig. 23).

The Yegua and Cockfield Formations are the only units in the Claiborne consistently 

reported to produce from a downdip shelf-slope facies. This probably is due to the high rate and 

volume of sediment input (Hull, 1995), which resulted in accumulation of sediments at the shelf 

margin, over-steepening of the upper slope, and the eventual foundering of the shelf edge, 

transporting reservoirs sands downdip (Edwards, 1991). In addition to catastrophic failure of the 
32

Figure 23. Sand isolith map for the upper Claiborne Yegua Formation, Texas Coastal Plain (from Fisher, 

1969).

shelf edge, listric down-to-the-basin expansion-growth faults at the outer shelf and upper slope 

created significant accommodation space to receive sands in the downdip environment. Winker 

(1982) described the numerous stratigraphic and structural complexities that resulted from rapid 

expansion at the shelf margin, including large amounts of missing section due to faulting, marked 

deviations from the regional dip, the characteristic expansion across faults, and rapid facies 

changes. The resultant hydrocarbon reservoirs at and beyond the expanded and (or) foundered shelf 

edge are highly productive but not easy to predict (Ewing and Vincent, 1997b). 

Fisher (1969) described the updip Yegua as composed of high-constructive delta systems 

characterized by multilateral fluvial sand units up to 200 ft thick, up to 30 mi in width, with 

thickness axes oriented normal to regional strike. According to Ewing (1994), the updip Yegua 

trend is more marine in character than the Yegua at outcrop but still contains a high proportion of 

fluvial channels and nonmarine shales. Downdip, sand reservoirs represent a number of 

environments, including channeled turbidite deposits on the outer shelf or upper slope, and thick 

strike-elongate sands interpreted as barrier bar complexes (Ewing and Fergeson, 1991). Miller 

(1993) reported that the shelf-margin downdip Yegua sandstones were deposited by gravity-flow 

mechanisms on a slope fan of a lowstand systems tract. 

Whitten and Berg (1987) described 240 ft of downdip shaley sandstone Yegua core located 

about 20 mi basinward of thicker and more abundant fluvial Yegua sandstones in Jackson County, 

Tex. (fig. 17), as thin bedded, on average 2 ft, ranging 0.5 to 9 ft. Bioturbation was not present. 

Massive sandstones graded upward into thinly laminated to rippled sandstones to interlaminated 

sands and shales to complete the Bouma (1962) turbidite sequence. Whitten and Berg (1987) 

interpreted the sediment provenance to be the same as the overlying Oligocene Frio, on the basis of 

compositional similarities. 
33

Lock and Voorhies (1988) reported that the downdip Yegua and Cockfield reservoirs in 

southwestern Louisiana typically have a laterally consistent log response, high shale-to-sand ratios, 

and contain relatively thin sands, all inconsistent with deposition in a deltaic setting and more 

likely characteristic of open-shelf facies. The sand bodies have geometries consistent with 

deposition by retreating storm surge waters. On the basis of their location, Lock and Voorhies 

(1988) interpreted the downdip Yegua and Cockfield sands to be of a shelf or deep-water origin

deposited in a lowstand slope fan depositional environment. 

Ewing and Fergeson (1991) reported on the structure and stratigraphy of downdip Yegua 

gas-condensate fields in Wharton County, Tex., where the reservoir intervals are enclosed in thick 

marine shales and are overlain by overpressured Jackson Group shales. Ewing and Fergeson (1991) 

described a highly variable stratigraphy in the downdip environment, where the sands are thick in 

some areas and absent in others. 

Downdip Yegua reservoirs are overpressured (Whitten and Berg, 1987; Ewing and 

Fergeson, 1991). The Arco No. 1 Hoffpauir well in south-central Calcasieu Parish (fig. 17) 

penetrated 7,000 ft of overpressured shales before reaching downdip Yegua turbidite sands (Lock 

and Voorhies, 1988). The updip trend is normally pressured (Swenson, 1997). 

Reservoir quality for Yegua sandstones is good to excellent, with porosity ranging from 

10 to 38 percent and permeability from 20 to 3,000 md (Nehring, 1991). In south Texas, Yegua 

reservoirs have porosity of 23 to 33 percent and permeability of 40 to 800 md (Nehring, 1991, 

citing Galloway and others, 1983, and Kosters and others, 1989). Whitten and Berg (1987) reported 

that average porosity of downdip shaley sandstone Yegua core was 29 percent, and average 

permeability was 356 md in Jackson County, Tex. Miller (1993) reported slightly poorer reservoir 

quality, with average porosity at 16 percent and a permeability range of 1 to 20 md for deep Yegua 

sandstones deposited basinward of the shelf margin. Evaluation of the NRG Associates (2006) 

database indicates updip Yegua reservoirs have median porosity of 30 percent and median 

permeability of 400 md. Downdip reservoirs have slightly lower median porosity of 27 percent and 

median permeability of 175 md. Whitten and Berg (1987) interpreted intergranular secondary 

porosity as seen in thin sections of downdip Yegua sands to be a result both of dissolution of 

cements and of network detrital grains. Clays formed through diagenesis of feldspars are absent, 

interpreted to be a result of flushing from the overpressured hydraulics. 

Traps and Seals

An evaluation of the NRG Associates (2006) database indicates that the traps containing 

Claiborne-reservoired hydrocarbon accumulations predominantly are described as structural, in 

most cases rollover anticlines downthrown to growth faults. Schenk and Viger (1996a) reported 

that lower Claiborne Queen City traps primarily are structural and occur on reactivated Wilcox 

growth faults and faulted anticlines. In the updip Claiborne depositional environment, many of the 

trapping faults may be reactivated older Wilcox growth faults. In the downdip Claiborne 

environment, the trapping faults are contemporary Claiborne growth faults (Ewing and Fergeson, 

1991). An examination of the complex trapping structures created by growth faulting indicates that 

rollover anticlines, upthrown closures, and downthrown closures all play some role in trapping 

Claiborne hydrocarbon accumulations (fig. 24). Syndepositional growth faulting would have 

generated hydrocarbon traps since the beginning of Claiborne deposition, as hydrocarbon 

generation from underlying strata was ongoing. (See earlier section “Source Rocks and 

Thermal Maturation.”) 
34

Figure 24. Cross section through Shanghai Field, Wharton County, Texas, in the expanded downdip Yegua 

trend (from Ewing and Fergeson, 1991). Shown are the different structural trapping styles common in 

Claiborne expanded fault zone reservoirs.

In areas impacted by salt tectonics, including the Houston Embayment and the Louisiana 

Salt Basins, traps against salt and (or) against faults created by salt movement are common. Broad 

stratal upwarping over deep-seated salt also is an important hydrocarbon trapping mechanism and 

is responsible for the two largest Claiborne discoveries, the Katy and the Conroe fields (fig. 6) of 

the Houston Embayment (described below). Salt movement is ongoing at present (Peel, 2007), 

suggesting that Claiborne hydrocarbon traps could be created in the present day.

Shellman (1985) described hydrocarbon accumulation in the updip Reklaw trend as fault 

controlled, citing down-to-the-basin faulting contemporaneous with sediment deposition. Shellman 

(1985) also described en echelon compensating antithetic up-to-the-coast faults, which are smaller 

than the major growth faults. In at least one case in Fayette County (fig. 6), up-to-the-coast faulting 

has created seals for the transgressive Reklaw sandstones by juxtaposing reservoirs with shale 

barriers (Shellman, 1985). Traps in the south Texas Yegua trend are both stratigraphic and 

structural, ranging from sand pinchouts to growth faults, due to the strandplain-barrier bar system 

depositional environment (West, 1963; Nehring, 1991). 

Little has been reported regarding the quality of seals for Claiborne hydrocarbon 

accumulations. It typically is assumed that the permeability barrier created by sand-shale 

juxtaposition is sufficient to retard fluid movement. Nehring (1991) and Schenk and Viger (1996a) 

simply described seals for the lower, middle, and upper Claiborne units as shales of the same units. 

In addition, Nehring (1991) listed shales of the Jackson Group as seals for upper Claiborne 

Yegua reservoirs.
35

Influence of the Louann Salt

Evacuation and allochthonous flow of the Jurassic Louann Salt due to sedimentary loading 

have had a dramatic influence on the petroleum geology of the Gulf of Mexico Basin (McBride,

1998; McBride and others, 1998; Stover and others, 2001). In particular, the growth 

and emplacement of salt diapirs lead to the creation of complex structures which serve as petroleum 

migration pathways and traps (Halbouty, 1979). Stratigraphic units around salt dome margins are 

faulted by salt intrusion, creating fault traps, and are dragged upwards at the salt-rock contact, 

creating stratigraphic traps. Salt domes also may have mushroom-shaped caps, creating traps under 

overhanging edges (Schenk and Viger, 1996a). Upward migration of salt diapirs, which detach 

from the underlying autochthonous “mother salt,” leaves behind complexly faulted stratal collapse 

zones which may also facilitate migration (Hood and others, 2002). 

Salt evacuation and the creation of trapping features in concert with petroleum generation in 

the Gulf of Mexico potentially have been creating hydrocarbon accumulations since the Late 

Cretaceous (McBride, 1998; Stover and others, 2001), and possibly since shortly after the 

Callovian deposition of the Louann (Ewing, 1991). In the East Texas Basin, salt movement was 

initiated during the Late Jurassic, with diapirs forming during the Early Cretaceous (Ewing, 1991). 

Likewise, salt movement in the North Louisiana Salt Basin was initiated in the Late Jurassic 

through Cretaceous (Ewing, 1991). One-dimensional burial modeling by Lewan (2002) predicted 

Smackover oil generation as far back as 144 Ma adjacent to the Mississippi Salt Basin; this Upper 

Jurassic oil could have been trapped in structures created by salt movement. Elsewhere in the Gulf

of Mexico, burial history models of Nelson and others (2000) predicted salt extrusion during the 

Eocene in south Louisiana, followed by evacuation through the Miocene. In the offshore area of 

Louisiana, salt extrusion did not occur until the Miocene (14.5 Ma) (Nelson and others, 2000).

Maximum salt growth occurred following shelf margin progradation (Ewing, 1983). 

Salt piercement diapirs have affected all of the Claiborne Group strata occurring in the 

Houston Embayment and Louisiana Salt Basins. According to Ewing (1991), shallow salt diapirs in 

the South Louisiana Salt Basin are small and cylindrical. In the Houston Embayment, salt diapirs 

reach near the surface, with tops generally less than 2,000 ft deep (Halbouty, 1979; Ewing, 1991). 

Diapirs frequently are aligned along major growth-fault trends, suggesting that preexisting domes 

influenced the initiation of faults and tended to control their location (Winker, 1982). Salt 

movement history is a critical component of understanding Claiborne hydrocarbon systems, 

particularly in the upper Claiborne Yegua of the Houston Embayment, where salt withdrawal may 

have influenced sand distribution and (or) trap integrity (Ewing, 2008). 

Overview of Claiborne Exploration and Production History

The first production of a commercial Claiborne oil accumulation in Texas occurred in 

1866 when L.T. Barrett brought in the No. 1 Isaac C. Skillern in Nacogdoches County (fig. 6), near 

the town of Oil Springs (Handbook of Texas Online, 2001). The discovery well flowed oil, water, 

and gas from a depth of 106 ft from a lower Claiborne sand and marked the discovery of the 

Nacogdoches field, the first Texas oil field. The Nacogdoches field still is marginally productive 

today, with stripper wells pumping oil from depths of 100 to 600 ft on seven active leases in 

2004 (NRG Associates, 2006). 

Oil discoveries made by searching for bubbling gas springs located over the region’s 

numerous salt domes resulted in the 1901 discovery of the Spindletop and Jennings fields, in east 

Texas and southwestern Louisiana, respectively, and ushered in the great Gulf Coast oil boom of 
36

the early 1900s. More advanced exploration strategies led eventually to the discovery of giant 

Claiborne-reservoired oil fields over salt structures, including the oil- and gas-prone Conroe field 

35 mi north of Houston in 1931 (fig. 25), and the nearby gas-condensate Katy field (fig. 6) in 

1935 (Nehring, 1991). These early Claiborne discoveries primarily were made with geophysical 

prospecting techniques such as the torsion balance and with refraction and reflection seismograph 

surveys (Macelwane, 1940; Weatherby, 1940). The Conroe field grew quickly to over 19,000 acres 

and produced 65,000 barrels of oil per day (BO/day) in 1932, the third largest U.S. oil field at the 

time (American Oil and Gas Historical Society, 2005). Production primarily was from an upper 

Claiborne Cockfield Formation sand of 60 ft average thickness at approximately 5,050 ft average 

depth (Michaux and Buck, 1936). Conroe produced less than 2,000 BO/day in 2003; cumulative 

production through 2003 totaled about 730 million BO (NRG Associates, 2006). Development of 

the gas-condensate resources contained in the Katy field were slowed for a decade by the lack of a 

market for gas, and even 10 years after discovery, 85 percent of the daily allowable 450 million 

cubic feet of gas (MMCFG) production was being reinjected into the upper Claiborne reservoirs 

(Allison and others, 1946). Production was from six different Yegua and Cockfield sand zones at 

depths of 6,250 to 7,450 ft spread across a productive area of approximately 30,000 acres (Allison 

and others, 1946). Cumulative gas production at Katy through 2004 totaled around 5.9 trillion 

cubic feet of gas (TCFG) (however, see Kosters and others, 1989) with proved reserves of about 

13.4 billion cubic feet of gas (BCFG) still in the ground (NRG Associates, 2006). 

Upper Claiborne discoveries have continued mostly uninterrupted since the 1930s, with the 

development of 8,000- to 12,000-ft- deep downdip gas-condensate objectives beginning in the early 

1980s (Nehring, 1991; Ewing and Fergeson, 1991; Ewing, 2008). In particular, the advent of threedimensional (3-D) and amplitude versus offset (AVO) seismic techniques improved exploration 

success in the complicated lowstand depositional environment where small (<200 acres), isolated 

reservoir sands are highly compartmentalized by syndepositional growth faults and intervening 

shaley strata (Ewing and Fergeson, 1991; Ewing and Vincent, 1997b; McCuen and West, 1998; 

Ewing, 2001, 2008). 

Exploration and discoveries in the lower Claiborne Queen City and Reklaw trends of south 

Texas spanned the decades of the 1950s through the 1980s (Nehring, 1991), with the discovery of 

deeper, downdip gas-condensate objectives in the 9,000- to 10,000-ft depth range occurring in the 

1990s through the 2000s (NRG Associates, 2006). Application of 3-D seismic and AVO techniques 

also has contributed to better characterization of the non-associated gas accumulations in the deep, 

downdip objectives of the lower Claiborne, including Queen City reservoirs across the Rio Grande 

into the Burgos Basin of northern Mexico (Burnett, 1990; Tellez and others, 2002).

Resource Assessment

Based on source rock-reservoir rock elements of the petroleum system, the distribution of 

known fields and wells (IHS Energy Group 2005a, b; NRG Associates, 2006), and a geologic 

model describing the Cenozoic Gulf of Mexico depositional style, the Middle Eocene Claiborne 

Group was divided into seven conventional gas and oil assessment units. The lower Claiborne 

section includes four assessment units: Lower Claiborne Stable Shelf Gas and Oil (50470120), 

Lower Claiborne Expanded Fault Zone Gas (50470121), the hypothetical Lower Claiborne Slope 

and Basin Floor Gas (50470122), and the hypothetical Lower Claiborne Cane River (50470123). 

The upper Claiborne section includes three assessment units: Upper Claiborne Stable Shelf Gas and 

Oil (50470124), Upper Claiborne Expanded Fault Zone Gas (50470125), and the hypothetical 

Upper Claiborne Slope and Basin Floor Gas (50470126). The numbers in parentheses assigned for 
37

Figure 25. Map and diagrammatic cross section of the Conroe Field, Montgomery County, Texas (from 

Michaux and Buck, 1936). Lease names are shown in the plan view. Vertical exaggeration on cross 

section is approximately 20x. U = upthrown, D = downthrown.
38

each AU are a unique internal numerical identifier used in the USGS oil and gas assessment 

project. Summaries of the assessment unit characteristics and the input data used for resource 

assessment are tabulated in appendices A-G.

The geologic rationale for the seven Claiborne units used in this assessment can be 

summarized as follows. The Claiborne Group is stratigraphically divided into lower, middle, and 

upper sandstone reservoir facies (Queen City, Sparta, and Yegua/Cockfield) by regional 

transgressive marine facies rocks (Weches, Cook Mountain), creating three natural stratigraphic

divisions (fig. 4A). For simplicity and because the lower Claiborne Queen City Sand is not present 

in the eastern part of the basin, the middle Claiborne Sparta and Cook Mountain strata were lumped 

with the upper Claiborne Yegua/Cockfield to create a twofold stratigraphic division: lower 

Claiborne Queen City and Reklaw reservoirs versus upper Claiborne Sparta, Yegua, Cook 

Mountain, and Cockfield reservoirs. Further justifying this division is the fact that Cook Mountain 

and Yegua reservoirs are inseparable in the NRG Associates (2006) database, from the point of 

analysis. In addition to the twofold stratigraphic division of Claiborne AUs, each of the upper and 

lower Claiborne was further divided into depositional facies of stable shelf, expanded fault zone, 

and slope and basin floor AUs (described in the “Geologic Model” section below). This resulted in 

the creation of six AUs to characterize the petroleum geology of the Claiborne. A seventh and final 

Claiborne AU, the hypothetical Lower Claiborne Cane River AU, was necessary so as to include 

the marine shelf facies of the lower Claiborne in the eastern part of the basin, from which there is 

no current or historical hydrocarbon production. 

To complete the discovery history analysis that guided the estimation of undiscovered field

numbers and sizes as presented herein, the assessment team first defined the geographic boundaries 

of the seven Claiborne AUs. The geologic rationale for the placement of the geographic boundaries 

of each AU is presented below. To assign reservoirs from the NRG Associates (2006) database to 

each AU, polygons representing the AU boundary were used in a GIS to clip Claiborne reservoirs. 

This step resulted in a spatial assignment of Claiborne reservoirs to the seven different AUs. In a 

final step, reservoirs were divided stratigraphically between the upper and lower Claiborne, so that 

each AU contained a determined 3-D volume of strata containing a certain number of Claiborne 

reservoirs. The characteristics (number of reservoirs, discovery year, size, gas-oil ratio, and so on) 

of those reservoirs as described in the NRG Associates (2006) database then were used to guide 

discovery history analysis for each AU, resulting in estimated numbers and sizes of undiscovered 

fields as per the methodology described in Klett and others (2003). Estimated numbers and sizes of 

undiscovered fields were used in a Monte Carlo simulation to calculate mean and fractile 

undiscovered resource volumes (Charpentier and Klett, 2005).

Comparisons with the 1995 Assessment

The 1995 oil and gas assessment of the Gulf Coast Basin (Schenk and Viger, 1996a, b) 

included four plays composed exclusively of Claiborne strata: 4724, Middle Eocene Sandstones 

Downdip Gas (Queen City and Cook Mountain reservoirs); 4725, Middle Eocene Sandstones 

Updip Fluvial Oil and Gas (Queen City, Reklaw, and Sparta reservoirs); 4726, Yegua Updip 

Fluvial-Deltaic Oil and Gas (Yegua and Cockfield reservoirs); and 4727, Yegua Downdip Gas 

(Yegua and Cockfield reservoirs). The 1995 assessment also included some Claiborne reservoirs 

with strata of other ages in two additional plays: 4701, Houston Salt Dome Flank Oil and Gas; and 

4945, Wilcox Salt Basins Oil. In contrast, this assessment places known Queen City and Reklaw 

reservoirs into the two updip Lower Claiborne AUs (50470120, 50470121), and all other known 

Claiborne reservoirs (Cook Mountain, Sparta, Yegua, and Cockfield) are placed into the two updip 
39

Upper Claiborne AUs (50470124, 50470125). The 3-D volumes of rock placed into the three 

hypothetical Claiborne AUs of this assessment (50470122, 50470123, 50470126) were not 

considered in the 1995 assessment. Reservoirs that were included in the 4701 Houston Salt Dome 

Flank Oil and Gas and the 4945 Wilcox Salt Basins Oil plays of the 1995 assessment are included 

in the Upper Claiborne Stable Shelf Gas and Oil AU (50470124) of this assessment. 

Geologic Model

Assessment of undiscovered resources in the Paleogene Gulf of Mexico Basin was based on 

a geologic model that describes the progradation of structural and depositional systems of reservoir 

rocks in “stable shelf,” “expanded fault zone,” and “slope and basin floor” environments (fig. 26A).

This model is developed from the detailed analyses of Cenozoic depositional systems in the Gulf 

Basin that illustrated recurring depositional and structural themes for all of the clastic stratigraphy 

(Winker, 1982; Galloway, 1989; Galloway and others, 2000; Galloway, 2005). In particular, each 

Paleogene clastic package illustrates either a period of dominant progradation into the Gulf of 

Mexico (Wilcox, Vicksburg, Frio) or progradation interrupted by periods of regional highstand and 

deposition of transgressive shale (Claiborne, Jackson). During dominantly progradational periods, 

deposition occurred in stable shelf environments on the landward margin of the basin, in expanded 

fault zone environments at the contemporary shelf edge, and in slope and basin floor environments 

basinward of the contemporary shelf edge. This motif is repeated in each of the progradational 

clastic packages, resulting in a stepping-out effect of the three environments into the Gulf of 

Mexico during deposition of each overlying stratigraphic package. 

Within individual stratigraphic packages (for example, the Wilcox or Claiborne Groups), 

the boundaries between the structural-depositional environments are time transgressive (fig. 26B).

For example, during progradation of clastic packages into the Gulf of Mexico, the shelf margin 

gradually advances basinward, in effect bringing stable shelf structural-depositional environments 

over the previously deposited expansion zone within the same stratigraphic package (the Wilcox or 

Claiborne Group). In other words, the real boundaries between the structural-depositional 

environments overlap in plan view and overlap in the depth range of reservoirs. For the purposes of 

the assessment and for the analysis of exploration and production history of individual AUs, this 

overlap has the unintended consequence of misplacing discovered reservoirs which lie near the 

structural-depositional boundary between the stable shelf and expanded fault zone environments. 

Thus, characteristics of two AUs may be unintentionally lumped at their margins into one dataset. 

Some evidence of this overlap is present in the analysis of 50470124, the Upper Claiborne Stable 

Shelf Gas and Oil AU. In figure 27, gas accumulation sizes for 50470124 are plotted as a function 

of discovery year. Following development of the expanded downdip Yegua trend in the early 

1980s, a jump in accumulation sizes from the established downward-tailing trend of the stable shelf 

environment is recorded as a result of the time-transgressive overlap of the two depositional 

environments at their margins. 

Stable Shelf

Each of the three conceptualized environments of the geologic model contains a distinct set 

of predictable features. In the landward stable shelf environment, relatively shallow (mostly 

<8,000 ft in Claiborne) reservoirs are characterized by minimal expansion due to growth faulting 

and primarily consist of highstand and transgressive systems tracts, including regional fluvialdeltaic complexes, delta mouth and barrier bars, shelf sandstones, and incised valley fill (fig. 28).

Reservoir facies have high and predictable lateral continuity. Traps generally are against 
40

Figure 26. Conceptualized geologic model used for this assessment. A, Two-dimensional geologic model 

illustrating sequence of stable shelf, expanded fault zone, and slope and basin floor environments 

(from Warwick and others, 2007). The beige polygons labeled “Stable Shelf (SS),” “Expanded Fault Zone

(EFZ),” and “Slope and Basin Floor (SB)” represent the environments of the Claiborne Group and 

correspond to the descriptors “no to minimum expansion,” “maximum expansion,” and “minimum to 

moderate expansion,” respectively. The green polygons represent the environments of the overlying 

Jackson Group and Vicksburg Formation, and the blue polygons represent the environments of the 

underlying Wilcox Group. B, Time-transgressive nature of geologic model environments showing the 

overlap of environments and therefore the overlap of assessment unit (AU) characteristics at 

their boundaries. 
41

Figure 27. Gas accumulation sizes for the Upper Claiborne Stable Shelf Gas and Oil Assessment Unit (AU) 

(50470124) plotted as a function of discovery year. Accumulations are divided into thirds by year of 

discovery. Note that the median size of the third one-third of discovered reservoirs is larger than the 

median size of the second one-third. The growth in sizes of discovered reservoirs beginning in the early 

1980s is a result of inclusion in this AU of reservoirs discovered as part of the development of the 

middip-downdip Yegua expanded fault zone trend (Ewing, 2008). The regional-scale nature of this 

assessment precludes precise division of the AUs at their boundaries, resulting in AUs which contain 

characteristics of more than one environment. Data are from NRG Associates (2006), plotted by T. Klett, 

USGS. BCFG, billion cubic feet of gas.

reactivated growth faults which sole out in the underlying strata. Less frequent are back-barrier 

pinchout stratigraphic traps (except in south Texas Claiborne back-barrier facies environments). 

Reservoirs are normally pressured, usually produce both oil and associated gas, and typically have 

a high water cut. This is a mature Claiborne exploration and production trend, with few remaining 

undiscovered fields and little potential for field growth via infill. 

Expanded Fault Zone 

The expanded fault zone environment occurs over a relatively narrow area in plan view, 

bracketing the contemporary Claiborne shelf edge basinward of the stable shelf. Reservoirs are 

characterized by maximum stratigraphic expansion over syndepositional growth faults. Cumulative 

reservoir thickness is large; individual sands typically are thicker, although not always, than those 

in the stable shelf environment. Reservoir sandstones consist of deep (mostly 8,000–14,000 ft) 

highstand and lowstand systems tracts including delta mouth and delta front facies, incised valley 

fill, outer shelf storm retreat sands, and upper slope sands occurring in turbidite deposits and slump 

blocks (fig. 28). Reservoir facies have low and hard-to-predict lateral continuity. Traps are 

associated with the ubiquitous contemporary growth faults, including rollover anticlines and 

upthrown and downthrown fault closures. Reservoirs are overpressured and flow chiefly nonassociated gas and condensate. A few oil fields also are present. Fields are highly 
42

Figure 28. Schematic block diagram illustrating location and type of depositional environments and 

assessment unit elements of the geologic model (from Edwards, 1991).

compartmentalized and smaller in areal extent compared to the stable shelf. For the Claiborne, this 

is a late frontier to mature exploration and production trend with a high likelihood for new 

discoveries and excellent potential for existing field infill.

Slope and Basin Floor

The slope and basin floor environment occurs downdip of the expanded fault zone and is 

characterized by minimal expansion of Claiborne reservoir sands due to the distal nature of 

deposition from contemporaneous shelf edge growth faulting. Deep reservoir sandstones (mostly 

>12,000 ft) consist of lowstand systems tracts including slope turbidite fans and channels, slope 

apron fans, shelf slump sands, incised valley fill, and blanket sand deposits on the basin floor 

(fig. 28). Reservoir facies can be laterally continuous, but their locations are a challenge to predict 

or project from shallower, overlying strata or from updip environments. Traps include stratigraphic 

pinchouts at sand body margins, complicated by structural offset resulting from growth faults 

which sole out from the overlying expansion zone. Reservoirs are overpressured, high-temperature, 

and flow non-associated gas and condensate. Reservoir quality is a risk factor, due to porositypermeability loss from increasing burial depth (Dutton and Loucks, 2008). Recent Paleogene 

discoveries in the distal offshore Gulf of Mexico indicate that the deep basinal Claiborne Group 

contains very little sand in the present-day deepwater environment (Meyer and others, 2005). 

However, the data presented by Meyer and others (2005) are for a well almost 200 mi offshore 
43

Texas; the shelf margin bypass predicted by Swenson (1997) would deliver sands directly into 

Claiborne slope and basin floor environments. 

In the Claiborne, the slope and basin floor environment is a hypothetical exploration and 

production trend with very high potential for new discoveries. To date, high per-well costs, coupled 

with the fact that the major operators currently are investing primarily in offshore exploration, have 

significantly limited development in this frontier area.

Data Supporting the Geologic Model

Aspects of the geologic model described above were drawn from the voluminous literature 

describing Cenozoic patterns of sediment deposition in the Gulf Basin (Winker, 1982; Ewing and 

Fergeson, 1991; Edwards, 1991; Galloway and others, 2000; Galloway, 2005). For this assessment, 

an analysis of the petroleum geology data contained in the NRG Associates (2006) database was 

performed to see if the data contained therein support the geologic model. To make the analysis, 

Claiborne reservoir data in the NRG Associates (2006) database were first divided into upper and 

lower Claiborne stratigraphic units (previously described) and then separated by depth-to-reservoir 

into those >8,000 ft and <8,000 ft deep. Eight thousand feet was chosen as a regional 

approximation of the break between stable shelf and onset of the expanded fault zone. This is 

somewhat simplified; in south Texas the onset of the expanded zone is closer to 7,500 ft, whereas 

in south Louisiana the expanded zone is deeply buried under the Oligocene-Miocene and is closer 

to 9,000 to 10,000 ft. However, 8,000 ft was selected as the most appropriate depth in the regional 

approach taken herein. 

As depicted in figure 29, Claiborne reservoirs >8,000 ft deep spatially occur at the 

basinward margin of discovered Claiborne hydrocarbon accumulations and bracket the 

contemporary shelf margins of Galloway and others (2000). As described above, some reservoirs 

>8,000 ft deep occur in the stable shelf environment in southern Louisiana, where the expanded 

fault zone is more deeply buried, and some reservoirs <8,000 ft deep occur in the expanded zone in 

south Texas (fig. 29). Data from the NRG Associates (2006) database indicate that the deeper, 

more basinward reservoirs are at higher average temperature and pressure and have lower average 

porosity and permeability. In general, reservoirs >8,000 ft deep are overpressured (fig. 30). This is 

perhaps the best indicator of occurrence in the expansion zone; industry experience indicates that 

all discovered expanded fault zone reservoirs in the Claiborne are overpressured (T.E. Ewing, 

Frontera Exploration Consultants, Inc., written commun., 2008). NRG Associates (2006) data also 

indicate that basinward reservoirs produce lighter petroleum products than landward reservoirs 

(median 51° API gravity versus 44° API gravity). Finally, basinward reservoirs, which are 

interpreted to have been deposited in the zone of maximum expansion, have a greater average 

reservoir thickness (57 ft; n = 183) than the landward reservoirs (33 ft; n = 510), which are 

interpreted to have been deposited on the contemporary shelf. Although relatively simplistic, this 

basic analysis confirms the first-order prediction of the geologic model, namely, reservoir 

expansion at the contemporary shelf edge. 

Lower Claiborne Stable Shelf Gas and Oil (50470120)

The Lower Claiborne Stable Shelf Gas and Oil AU lies entirely within Texas, extending 

northeast from the international border to within about 20 mi of the Louisiana border, 

encompassing an area of about 25.4 million acres (fig. 31). The AU boundaries were defined on the 

north, northwest, and west by the outcrop limit in Texas. These boundaries were placed slightly 

basinward of the limit of Claiborne outcrop to account for the presence of very shallow historical 
44

Figure 29. Spatial distribution of Claiborne reservoirs that are <8,000 feet depth-to-top and >8,000 feet depthto-top. Claiborne Group outcrop is from Schruben and others (1994); upper Wilcox and Claiborne (Queen 

City and Yegua) shelf margins are from Galloway and others (2000); location of Claiborne reservoirs is 

from NRG Associates (2006).

and current oil production. Sand input to the basin was limited to the Rio Grande Embayment 

during this time and, therefore, the eastern AU boundary was placed near the Texas-Louisiana 

boundary. On the southwest, the AU boundary was drawn at the international border. To the 

southeast, the AU boundary corresponds to the underlying upper Wilcox shelf margin, which 

matches the updip limit of the adjacent Lower Claiborne Expanded Fault Zone AU (50470121). 

Noncommercial to minor production is located in the area of the Queen City sand maxima, 

probably due to lack of thick shale seals and thinning of potential source beds (Guevara and García, 

1972). Hydrocarbon products predominantly are gas and medium to light oil. 

The Lower Claiborne Stable Shelf Gas and Oil AU is an established exploration and 

production trend with 16 oil and 39 gas accumulations that exceed the minimum size considered in 

this assessment (0.5 MMBO and 3 BCFG for oil and gas accumulations, respectively). The median 

grown size of discovered gas accumulations, when divided into thirds (by early, middle, and late 

initial dates of discovery) is 13.4, 7.7, and 5.2 BCFG (fig. 32A), indicating moderate and consistent 

decline with time, and for discovered oil accumulations is 1.5, 2.8, and 1.6 MMBO (fig. 32B). The 

increase in grown sizes between the first and second thirds of discovered oil accumulations may 

reflect early discovery of shallow, smaller accumulations drilled on obvious structures 
45

Figure 30. Plots of pressure as a function of depth for Claiborne reservoirs with pressure data (data from 

NRG Associates, 2006, including initial reservoir, initial shut-in well head, and initial shut-in bottom hole 

pressures). Data are divided into reservoirs that are <8,000 feet deep and >8,000 feet deep; 8,000 foot 

depth is a regional approximation to the onset of overpressure in the Claiborne Group and is only an 

approximate depth for the boundary between stable shelf and expanded fault zone reservoirs. The 

regional-scale nature of this assessment precludes precise division of the stable shelf and expanded fault 

zone reservoirs, resulting in the overlap of pressure characteristics shown here. Gulf hydrostatic pressure 

line is from Dickinson (1953). Deeply buried Sparta Sand reservoirs in Louisiana indicate mostly normally 

pressured stable shelf conditions. psi = pounds per square inch.
46

Figure 31. Map showing extent of lower Claiborne assessment units (AU). Claiborne Group outcrop is 

from Schruben and others (1994); Wilcox Group shelf margin is from Galloway and others (2000). 

Co. = County.

(e.g., Nacogdoches field, 1866; Roma field, 1929; figs. 31 and 32B), followed later (1950s) by 

larger discoveries at greater depths. “Grown” size indicates that a reserve growth function was 

applied to the known hydrocarbon volumes in discovered reservoirs (for an explanation of 

methodology see Attanasi and Root, 1994). Grown discovered oil accumulations total 40.5 MMBO 

and grown discovered gas accumulations total 831 BCFG for this AU. The AU was considered to 

contain one or more undiscovered hydrocarbon accumulations on the basis of having adequate 

charge, reservoir rocks, and favorable timing of geologic events (generation, migration, and 

accumulation of petroleum resources). 

The number of undiscovered oil accumulations is estimated to be a minimum of one, a 

maximum of 15, and a mode of 5. At the maximum, 15 undiscovered oil accumulations were 

predicted; however, the mode of 5 undiscovered accumulations reflects that this area is maturely 

explored. Sizes of oil accumulations were estimated to be a minimum of 0.5 MMBO (minimum 

cutoff size considered in this assessment), a maximum of 3 MMBO, and a median of 1 MMBO. 

The maximum size of 3 MMBO was selected to allow for the possibility that an undiscovered field 

could equal approximately 40 percent of the grown size of the largest discovered oil accumulation. 

The median size of 1 MMBO was selected as consistent with the sizes of accumulations discovered 

over the last 40 years and considering decline between the median of the second and third thirds of 
47

Figure 32. Gas and oil discovery curves for the Lower Claiborne Stable Shelf Gas and Oil assessment unit 

(AU). A, Grown gas accumulation sizes for the Lower Claiborne Stable Shelf Gas and Oil AU (50470120) 

plotted as a function of discovery year. B, Grown oil accumulation sizes for the Lower Claiborne Stable 

Shelf Gas and Oil AU (50470120) plotted as a function of discovery year. Data from NRG Associates 

(2006), plotted by T. Klett, USGS. BCFG = billion cubic feet of gas, MMBO = million barrels of oil.
48

discovered accumulations (2.8 and 1.6 MMBO, respectively, fig. 32B). Reservoir depths for oil 

accumulations are expected to range between 400 and 8,000 ft. . 

Numbers of undiscovered gas accumulations were estimated to be a minimum of 1, a 

maximum of 30, and a mode of 10. The maximum number of 30 undiscovered gas accumulations 

was selected to account for the possibility of new discoveries at the least explored, deepest 

downdip basinward margin of the AU, near the boundary with the Lower Claiborne Fault Zone AU 

(50470121). The mode of 10 undiscovered accumulations was selected because a similar number of 

fields have been discovered in the AU in the last three decades, indicating good potential for future 

gas accumulation discoveries. Sizes of undiscovered gas accumulations were estimated to be a 

minimum of 3 BCFG (minimum cutoff size considered in this assessment), a maximum of 

40 BCFG, and a median of 4 BCFG. The maximum size was selected to allow for the possibility 

that an undiscovered field could equal 25 percent of the largest discovered field. The median of 

4 BCFG for undiscovered gas accumulations reflects a value consistent with the size of discoveries 

made in the last three decades and incorporating decline from the median size of the last third of 

discovered reservoirs (5.2 BCFG, fig. 32A). Reservoir depths for gas accumulations are expected

to range between 900 and 8,000 ft. 

Mean estimates of undiscovered resources for the Lower Claiborne Stable Shelf Gas and 

Oil AU from Monte Carlo simulation are 7 MMBO, 88 BCFG, and 2 million barrels of natural gas 

liquids (MMBNGL) (table 1). Table 1 also shows estimated hydrocarbon resources for the F95, 

F50, and F5 fractiles (F95 equals a 95 percent chance of at least the amount tabulated; other 

fractiles are defined similarly). 

The most recently discovered hydrocarbon reservoir in the assessment unit was the Cuatro 

de Julio field (fig. 31) in 2000. This is one of the deepest and most basinward reservoirs in the 

assessment unit and one of seven gas discoveries in the last 20 years. The last oil discovery in the 

AU was in 1980. This AU also contains the Nacogdoches field (fig. 31), discovered in 1866 and the 

first oil field in Texas. 

An estimated 19,970 new field wildcat wells penetrate the top of the Yegua in this AU, for 

an approximate high-side exploration density of 1 wildcat well for every 2.0 mi2

 (assuming the 

wells reach the lower Claiborne at total depth; see below for additional explanation). Moderate 

potential for undiscovered hydrocarbon reservoirs is expected to be found in deep gas 

accumulations occurring in structural traps located near the basinward margin of the AU, as well as 

some small oil accumulations in stratigraphic traps.

The number of new field wildcat wells reaching the top of the Claiborne for this AU and the 

other AUs described below was determined as follows. For each AU, the total depth of the new 

field wildcat wells coded in the IHS database was compared in a GIS with a structural top-ofClaiborne grid (fig. 13) constructed from stratigraphic tops information also contained in the IHS 

database. New field wildcats that did not penetrate the top of the Claiborne were discarded. At the 

downdip margin of the top-of-Claiborne grid, data quality is degraded by fewer penetrations; 

therefore, top-of-Vicksburg and top-of-Frio grids also were used (adding approximate Claiborne 

thicknesses) to estimate wildcat penetrations to the top of the Claiborne, particularly for the 

hypothetical Lower and Upper Claiborne Slope and Basin Floor AUs. This exercise overestimates 

the level of exploration because many of the wildcats do not penetrate the complete Claiborne 

section, but it is arguably the best approach available for the regional nature of this assessment. 

A low-side approach to estimating the numbers of new field wildcat wells testing the entire 

Claiborne section would be to use top-of-Wilcox penetrations. However, in some of the Claiborne 

AUs, particularly in the downdip areas of the hypothetical AUs, the number of top-of-Wilcox 
49

Table 1. Mean and fractile estimates of undiscovered resources in the Claiborne Group.

[MMBO = million barrels of oil, BCFG = billion cubic feet of gas, NGL = natural gas liquid, MMBNGL = million barrels of natural gas liquids]

Total Petroleum Systems (TPS) and 

Assessment Units (AU)

Field 

Type

Total Undiscovered Resources

Oil (MMBO) Gas (BCFG) NGL (MMBNGL)

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Upper Jurassic-Cretaceous-Tertiary Composite, 

TPS 504701

Lower Claiborne Stable Shelf Gas and 

Oil, AU 50470120

Oil 3 7 13 7 7 19 40 21 0 0 1 0

Gas 21 63 124 67 0 2 3 2

Lower Claiborne Expanded Fault 

Zone Gas, AU 50470121

Oil 1 3 8 4 6 16 43 19 0 1 3 1

Gas 351 942 1,767 987 13 37 76 39

Lower Claiborne Slope and Basin 

Floor Gas, Au 50470122

Oil 0 0 0 0 0 0 0 0 0 0 0 0

Gas 573 3,195 8,044 3,620 21 124 338 145

Lower Claiborne Cane River, AU 

50470123

Oil

Not quantitatively assessed Gas

Upper Claiborne Stable Shelf Gas and 

Oil, AU 50470124

Oil 4 12 23 13 12 36 78 40 0 1 2 1

Gas 97 357 858 402 3 10 25 11

Upper Claiborne Expanded Fault 

Zone Gas, AU 50470125

Oil 8 26 53 28 39 128 287 142 3 9 21 10

Gas 1,417 4,386 9,096 4,740 95 307 698 341

Upper Claiborne Slope and Basin 

Floor Gas, AU 50470126

Oil 0 0 0 0 0 0 0 0 0 0 0 0

Gas 1,706 8,147 19,632 9,107 116 569 1,489 655

Total Total Mean Oil 52 Total Mean Gas 19,145 Total Mean NGL 1,205 
50

penetrations is very low or zero. Because of this fact, a poorly constructed top-of-Wilcox grid 

results; thus, comparing total depth of new field wildcats to the grid is dubious. Therefore, the highside approach of using the top-of-Yegua grid was accepted as the best compromise in determining 

exploration density for this assessment. 

Lower Claiborne Expanded Fault Zone Gas (50470121)

The Lower Claiborne Expanded Fault Zone Gas AU lies entirely within southern Texas, 

extending northeast from the international border to Wharton County, where it tapers out against 

the Lower Claiborne Stable Shelf Gas and Oil AU, about 65 mi southwest of Houston (fig. 31). The 

AU covers an area of about 2.3 million acres. The boundary on the northwest is defined by the 

southern boundary of the Lower Claiborne Stable Shelf Gas and Oil AU (50470120), 

corresponding to the updip limit of reservoir expansion over the underlying upper Wilcox shelf 

margin. The southwestern boundary was drawn at the international border. To the east, the AU 

boundary is limited by distance from sand input in the Rio Grande Embayment, and a more 

conservative eastern boundary than chosen herein may be considered in the area of Bee County 

(fig. 31) (T.E. Ewing, Frontera Exploration Consultants, Inc., written commun., 2008). On the 

southeast, the AU boundary is constituted by the theoretical downdip limit of expansion, 

representing the distal limit of the prograding lower Claiborne shelf margin and approximately 

corresponding to the updip limit of the overlying upper Claiborne expansion zone. 

The Lower Claiborne Expanded Fault Zone Gas AU is a frontier exploration trend with 

10 discovered gas accumulations that exceed the minimum size considered for this assessment 

(3 BCFG for gas accumulations). Grown discovered gas accumulations total 404 BCFG. The 

median grown size of discovered gas accumulations, when divided into halves (by early and later 

initial dates of production), is 9.7 and 35.1 BCFG, indicating an increase in the size of discovered 

gas accumulations with time (fig. 33A). There are no discovered oil accumulations in the AU 

greater than the minimum cutoff size (0.5 MMBO). The AU was considered to contain one or more 

undiscovered hydrocarbon accumulations on the basis of having adequate charge, reservoir rocks, 

and favorable timing of geologic events. 

The number of undiscovered oil accumulations is estimated to be a minimum of one, a 

maximum of five, and a mode of two. The maximum of five and mode of two for undiscovered oil 

accumulations were selected to reflect the fact that this is an overall gas-prone AU, while not 

discounting the possibility that some small undiscovered oil accumulations may be present in subtle 

structural traps. Sizes of oil accumulations were estimated to be a minimum of 0.5 MMBO 

(minimum cutoff size), a maximum of 15 MMBO, and a median of 1 MMBO. The maximum 

number of 15 MMBO was selected because (1) the AU is under-explored and (2) the assessment 

team wanted to emphasize that sand delivery in the Rio Grande Embayment to lowstand systems 

tracts in the lower Claiborne may provide for substantial untested reservoir acreage in the downdip 

environment. The median value of 1 MMBO was selected to be consistent with and slightly lower 

than the median size (1.6 MMBO) of the most recently discovered fields in the updip Lower 

Claiborne AU (50470120). Reservoir depths for oil accumulations are expected to range between 

8,000 and 14,000 ft. 

Numbers of undiscovered gas accumulations were estimated to be a minimum of 5, a 

maximum of 50, and a mode of 25. The maximum of 50 was selected because this is a relatively 

under-explored frontier area with only three decades of activity. The mode of 25 was selected to 

reflect the consistent and steady nature of discoveries since the trend was opened in the early 
51

 

Figure 33. Gas discovery curve and wildcat wells for the Lower Claiborne Expanded Fault Zone assessment 

unit (AU). A, Grown gas accumulation sizes for the Lower Claiborne Expanded Fault Zone AU (50470121) 

plotted as a function of discovery year. B, Cumulative grown gas volumes for the Lower Claiborne 

Expanded Fault Zone AU (50470121) plotted as a function of the cumulative number of new-field wildcat 

wells. Data from NRG Associates (2006), plotted by T. Klett, USGS. BCFG = billion cubic feet of gas.
52

1980s. Sizes of undiscovered gas accumulations were estimated to be a minimum of 3 BCFG 

(minimum cutoff size), a maximum of 700 BCFG, and a median of 20 BCFG. The maximum 

estimated field size of 700 BCFG is larger (approximately 3.5 times) than the grown size of any 

field discovered to date. However, the relatively low exploration density and the substantial depth 

to discovered reservoirs indicate that wide areas of the AU are untested as yet, from which is 

inferred significant uncertainty in the maximum undiscovered reservoir size. Cumulative 

discovered gas volumes in the AU show a strong increase as a function of the cumulative number 

of new field wildcat wells (fig. 33B), hinting at the possibility for large discoveries with additional 

exploration. Finally, all of the discovered fields in the AU still are in production, indicating the 

potential for significant reserve growth for as-yet undiscovered reservoirs. The estimated median 

undiscovered field size of 20 BCGF reflects a decline from the median of the second half of 

discovered reservoirs (35.1 BCFG). Reservoir depths for gas accumulations also are expected to 

range between 8,000 and14,000 ft. Mean estimates of undiscovered resources for the Lower 

Claiborne Expanded Fault Zone Gas AU from Monte Carlo simulation are 4 MMBO, 1,006 BCFG, 

and 40 MMBNGL (table 1).

The first discovery in the downdip Queen City was the Mestena Grande field (fig. 31) in 

1981. This field and the nine other discovered gas fields in the AU all are deeper than 9,000 ft. Five 

discoveries have been made in the past decade. All discovered accumulations are overpressured, 

occur in structural traps, and all currently are in production. An estimated 770 new field wildcat 

wells penetrate the top of the Yegua in this assessment unit for an approximate high-side 

exploration density of 1 wildcat for every 4.7 mi2

. However, as pointed out in the previous section, 

many of these wildcats do not encounter the lower Claiborne section. 

The potential for discovery of new gas fields in this AU is high, based on the potential depth 

to undiscovered reservoirs, overpressured conditions which moderate porosity reduction 

(Winker, 1982), the relatively low level of exploration, and the fact that more sandstones may be 

present downdip of the established trends (Schenk and Viger, 1996a). Undiscovered accumulations 

are expected to be deep gas in structural traps. The expanded reservoir facies will occur in lowstand 

systems tracts including lowstand deltas, delta front and distal shelf sands, incised valley fill, and 

upper slope sands. 

Lower Claiborne Slope and Basin Floor Gas (50470122)

The Lower Claiborne Slope and Basin Floor Gas AU is located basinward of the other two 

Lower Claiborne AUs, extending from their southwestern boundaries to the State waters limit 

(fig. 31). The AU occupies an area of about 15.8 million acres, the great bulk of which is in Texas. 

The northwestern boundary is defined by the limit of reservoir expansion as determined by sand 

input to the Lower Claiborne Expanded Fault Zone AU and by the upper Wilcox shelf margin to 

the northeast of the limit of lower Claiborne progradation. The eastern boundary is defined by the 

loss of sand influx, and the southeastern boundary is the limit of State waters. At its most 

northeastern limit, the AU contains about 60,000 acres in Louisiana. This is a somewhat liberal 

consideration, as most sand input during lower Claiborne time occurred in the area of the Rio 

Grande Embayment. A more conservative drawing of the boundary may limit the eastward limit of 

the AU to the area west of Bee County (fig. 31), as suggested above for the Lower Claiborne 

Expanded Fault Zone Gas AU (T.E. Ewing, Frontera Exploration Consultants, Inc., written 

commun., 2008). 

The Lower Claiborne Slope and Basin Floor Gas AU does not contain any discovered 

hydrocarbon reservoirs greater than the minimum cutoff of 0.5 MMBO (NRG Associates, 2006) 
53

and therefore is considered hypothetical in nature. However, the AU was defined and quantitatively 

assessed because of the high probability for the existence of undiscovered gas accumulations, due 

to the inferred presence of adequate source rocks, reservoirs, and the favorable timing of geologic 

events. The AU is not expected to contain any undiscovered oil accumulations, due to high thermal 

maturity. The Lower Miocene Slope and Basin Gas AU (50470141) and its Federal offshore 

extension and a scaled-down Wilcox Slope and Basin Floor Gas AU (50470118) (see Dubiel and 

others, 2007) were used as analogs to estimate the number and sizes of undiscovered gas

accumulations for the Lower Claiborne Slope and Basin Floor Gas AU. 

Numbers of undiscovered gas accumulations were estimated to be a minimum of 1, a 

maximum of 200, and a mode of 20. The maximum number of 200 accumulations was selected 

because of the relatively large size of the AU (15.8 million acres) and the absence of significant 

exploration to date. Sizes of undiscovered gas accumulations were estimated to be a minimum of 

3 BCFG (minimum cutoff size), a maximum of 1,500 BCFG, and a median of 20 BCFG. Great 

uncertainty in resource potential because of the absence of significant exploration activity resulted 

in selection of the maximum size of 1,500 BCFG for undiscovered accumulations. The presence of 

multiple discovered 100+ BCFG fields in the downdip upper Claiborne also points to the potential 

for large undiscovered reservoirs in the downdip environments of the lower Claiborne. Reservoir 

depths are expected to range between 12,000 and 30,000 ft. There is some overlap in the depth 

range of undiscovered reservoirs with the Lower Claiborne Expanded Fault Zone AU (50470121) 

to reflect the as-yet unexplored nature of the boundary between the two environments at around 

12,000 to 14,000 ft. Mean estimates of undiscovered resources for the Lower Claiborne Slope and 

Basin Floor Gas AU from Monte Carlo simulation are 3,620 BCFG and 145 MMBNGL (table 1).

Recent Wilcox discoveries in the deep water Gulf of Mexico attest to the potential for 

offshelf Paleogene hydrocarbon reservoirs in the Gulf Basin (French and others, 2006). Such basin 

blanket turbidite fan sandstones may have been delivered via incised canyon sediment conduits 

from the contemporary shelf margin (McDonnell and others, 2008). However, despite the presence 

of high-quality Wilcox reservoirs, work in the deepwater Gulf of Mexico illustrates a sand-poor 

Claiborne section in the distal offshelf downdip environment (Meyer and others, 2005). Exploration 

wells in the area of Wharton and Victoria Counties (fig. 31), which penetrated the top of Wilcox, 

did not find sand in the lower Claiborne, indicating either that no sand was delivered or that shelf 

bypass in this area resulted in nondeposition of reservoir facies (T.E. Ewing, Frontera Exploration 

Consultants, Inc., written commun., 2008). However, in south Texas, no significant exploration has 

penetrated the lower Claiborne section, and the presence of lowstand sands is entirely speculative. 

An estimated 860 new field wildcat wells penetrate the top of the Yegua in this assessment 

unit for an approximate high-side exploration density of 1 wildcat well for every 28.7 mi2. 

However, within the bounds of the AU there are no wells coded for lower Claiborne production in 

the IHS database, suggesting that the great majority (probably >95 percent, T.E. Ewing, Frontera 

Exploration Consultants, Inc., written commun., 2008) of the new field wildcats do not actually 

penetrate the top of the Claiborne. The potential for undiscovered hydrocarbon accumulations in 

this AU is expected to be moderate to high, based on the potential for sand delivery downdip to 

thin, dispersed reservoirs in distal lowstand systems tracts including mid-lower slope fans, 

turbidites, basin-floor fans, and distal gravity slide features. Reservoir quality may be a risk factor 

because of great burial depth (Dutton and Loucks, 2008), but overpressured conditions may

preserve porosity for dry gas accumulations occurring in structural traps associated with growth 

faults that sole out from the deposition of younger overlying strata. There are approximately 

180 discovered Expanded Fault Zone Vicksburg reservoirs in structural traps overlying this AU; 
54

projection of these structures to depth could result in discoveries in the hypothetical Lower 

Claiborne Slope and Basin Floor Gas AU. As described by Ewing and Fergeson (1991), downdip 

reservoirs in the upper Claiborne Yegua were discovered by drilling on structures projected from 

the overlying Frio. 

Lower Claiborne Cane River (50470123)

The boundaries of the Lower Claiborne Cane River AU are defined on the west at the limit 

of the other three Lower Claiborne AUs, on the south by the State waters boundary, and on the east 

by the petroleum province boundary (fig. 31). On the north the boundary is limited by outcrop and 

(or) the downdip limit of freshwater (freshwater contains <10,000 milligrams/liter total dissolved 

solids; Pettijohn, 1996). The downdip limit of freshwater was used to define in places the updip 

boundaries of the Lower Claiborne Cane River AU and the overlying Upper Claiborne Stable Shelf 

Gas and Oil AU (50470124), because the presence of meteoric water appears to retard biogenic

methane generation in coal beds of the Wilcox Group (Warwick, 2004; Warwick and others, 2008).

The AU encompasses an area of about 50 million acres. The Lower Claiborne Cane River AU does 

not contain any discovered hydrocarbon reservoirs greater than the minimum cutoff of 0.5 MMBO

(NRG Associates, 2006) and was not assessed on a quantitative basis. An estimated 18,300 new 

field wildcat wells penetrate the top of the Yegua in this assessment unit, for an approximate highside exploration density of 1 wildcat well for every 4.2 mi2

. 

In east-central Louisiana, approximately 75 wells are coded for past and present 

hydrocarbon production from the Cane River Formation (IHS Energy Group, 2005a); however, 

conversations and correspondence with industry representatives indicated that the wells in question 

were producing from upper sands of the Wilcox Group. Evaluation of the spatial distribution of a 

subset of these wells and their perforated depths confirmed that they are located in Wilcox oil fields 

and are perforated at depths conforming to Wilcox sands. Furthermore, previous workers have 

established that the lower Claiborne Group in the eastern Gulf of Mexico is constituted by thin 

shales deposited on an open muddy shelf, far from sand distribution centers (Guevara and García, 

1972; Payne, 1972; Galloway and others, 2000). Based on the data contained in the NRG 

Associates (2006) and IHS Energy Group databases (2005a, b), the high exploration density for 

underlying Wilcox targets, and the paucity of sandy facies, the Lower Claiborne Cane River AU is 

deemed a poor prospect for undiscovered conventional hydrocarbon accumulations. The potential 

for autogenic shale gas currently is unknown but herein is considered poor due to low Claiborne 

thermal maturity north of the Wilcox shelf break. The Lower Claiborne Cane River AU may be 

thermally mature for gas generation at depth south of the Wilcox shelf break; however, great 

drilling depths, the expected minimal thickness (or absence of the Claiborne section, O’Donnell, 

1974; Dockery, 1976), and unknown fracturing character may preclude exploration for shale gas 

systems in the near future. 

Upper Claiborne Stable Shelf Gas and Oil (50470124)

The Upper Claiborne Stable Shelf Gas and Oil AU has the largest areal extent of all 

Claiborne Group assessment units, extending from the international border in south Texas to 

Escambia County in the Florida panhandle (fig. 34) and encompassing an area of approximately 

50.4 million acres. The AU boundary is defined by the international boundary on the southwest and 

by outcrop on the north and west. Outcrop was used as the boundary on the north and west to 

account for some very shallow Texas oil production (IHS Energy Group, 2005a). The northeastern 

boundary is defined by the limits of scattered production in the Mississippi Embayment and by the 
55

Figure 34. Map showing extent of upper Claiborne assessment units (AU). Claiborne Group outcrop is from 

Schruben and others (1994); Wilcox Group shelf margin is from Galloway and others (2000). 

Co. = County. Locations/counties noted on figure are referred to in the text.

downdip limit of freshwater (Pettijohn, 1996) on the northeast. As described above, the downdip 

limit of freshwater was used as the boundary on the northeast to account for the possibility of 

shallow biogenic gas production. (Coal beds are present in the updip, terrestrial Claiborne section, 

Hackley and others, 2006.) The southeastern boundary is defined by the State water limit. The 

southern boundary in Louisiana is defined by the underlying relict Wilcox shelf margin, as there 

was no or very little shelf margin progradation in this area according to the interpretations of 

Galloway and others (2000). In Texas, the southern boundary is defined by the approximate 

underlying Wilcox shelf edge and the updip limit of the upper Claiborne expansion zone. 

The Upper Claiborne Stable Shelf Gas and Oil AU is an established exploration and 

production trend with 175 oil and 153 gas accumulations that exceed the minimum size considered 

for this assessment (0.5 MMBO and 3 BCFG for oil and gas accumulations, respectively). The 

median grown sizes of discovered gas accumulations, when divided into thirds (by early, middle, 

and late initial dates of production), are 14.5, 7.1, and 8.7 BCFG (fig. 27), respectively, and for 

discovered oil accumulations are 2.1, 1.7, and 1.2 MMBO (fig. 35A), respectively. The slight 

growth in median gas thirds between the second and third one-third is interpreted to represent 

spatial overlap between this AU and the downdip Upper Claiborne Expanded Fault Zone Gas AU 

(50470125), which has been developed more recently. The decline in median oil accumulation 

sizes indicates that this AU is mature for oil exploration. Grown discovered gas accumulations total 

10.09 TCFG and grown discovered oil accumulations total 1,660 MMBO. The AU was considered 
56

Figure 35. Oil discovery curve and wildcat wells for the Upper Claiborne Stable Shelf Gas and Oil 

assessment unit (AU). A, Grown oil accumulation sizes for the Upper Claiborne Stable Shelf Gas and 

Oil AU (50470124) plotted as a function of discovery year. B, Cumulative grown oil volumes for the Upper

Claiborne Stable Shelf Gas and Oil AU (50470124) plotted as a function of the cumulative number of 

new-field wildcat wells. Data from NRG Associates (2006), plotted by T. Klett, USGS. MMBO = million 

barrels of oil.
57

to contain one or more undiscovered hydrocarbon accumulations on the basis of having adequate 

charge, reservoir rocks, and favorable timing of geologic events.

The number of undiscovered oil accumulations is estimated to be a minimum of 1, a 

maximum of 30, and a mode of 10. The maximum and mode numbers were selected to account for 

the fact that although this is a highly mature area in terms of exploration, it also is a vast AU in 

terms of total area, and therefore there is some potential for the presence of undiscovered oil 

reservoirs, particularly in the less-explored downdip and deeper parts of the AU. Sizes of oil 

accumulations were estimated to be a minimum of 0.5 MMBO (minimum cutoff size), a maximum 

of 5 MMBO, and a median of 0.8 MMBO. The size of fields discovered in the AU over the last 

50 years is relatively constant, ranging between 0.5 and 10 MMBO (fig. 35A); the maximum size 

of 5 MMBO for undiscovered fields was selected to allow for the possibility that this consistent 

discovery trend would continue into the future. The median size of 0.8 MMBO was selected to 

account for decline from the last third of median discovered field sizes (1.2 MMBO) and to be 

consistent with data indicating that additional exploration will likely add little to cumulative 

discovered oil volumes (fig. 35B). 

Numbers of undiscovered gas accumulations were estimated to be a minimum of 4, a 

maximum of 75, and a mode of 15. Although this is a mature area in terms of exploration, it is a 

very large area, and the maximum and mode for undiscovered gas accumulations were chosen to 

reflect that the downdip and deeper parts of the AU have good potential for new discoveries. In 

addition, exploration for deeper objectives using 3-D seismic at the downdip margin of the AU has 

resulted in the discovery of many new reservoirs since the 1980s. Sizes of undiscovered gas 

accumulations were estimated to be a minimum of 3 BCFG (minimum cutoff size), a maximum of 

400 BCFG, and a median of 6 BCFG. The maximum size estimate of 400 BCFG was selected 

because there are multiple discovered 100+ BCFG reservoirs in this AU (fig. 27), as well as 

recently discovered (post-2000) reservoirs of similar size in the downdip Upper Claiborne 

Expanded Fault Zone AU (50470125). The median size of 6 BCFG was selected as being 

consistent with the median size of the discoveries made in the past three decades. 

Reservoir depths for undiscovered oil and gas accumulations are expected to range between 

1,000 and11,400 ft. The relatively greater lower cutoff depth used for this AU is to account for 

greater subsidence on the Louisiana shelf and the resultant thick Oligocene-Miocene section in this 

area. In particular, some of the deep (>10,000 ft) Sparta reservoirs in Louisiana are in the stable 

shelf environment despite being several thousand feet deeper than the 8,000 ft cutoff used in the 

previously described analysis of the geologic model used for this assessment. Mean estimates of 

undiscovered resources from Monte Carlo simulation for the Upper Claiborne Stable Shelf Gas and 

Oil AU are 13 MMBO, 442 BCFG, and 12 MMBNGL (table 1).

An estimated 40,000 new field wildcat wells penetrate the top of the Yegua in this AU, for 

an approximate high-side exploration density of 1 wildcat well per every 2.0 mi2

. The potential for 

new discoveries in thin highstand and transgressive systems tract reservoir sands in the fluvial, 

deltaic, delta mouth, strandline-barrier bar, and proximal shelf environments on the stable shelf is 

expected to be low due to the high level of exploration. Undiscovered accumulations probably are 

deep gas in structural traps near the basinward margin of the AU and possibly some small oil 

accumulations in subtle, shallow stratigraphic traps.

Upper Claiborne Expanded Fault Zone Gas (50470125)

The Upper Claiborne Expanded Fault Zone Gas AU is located basinward of the 

contemporary updip Upper Claiborne Stable Shelf Gas and Oil AU and extends from the 
58

international border to Mississippi State waters (fig. 34). The AU encompasses an area of about 

9.0 million acres. The boundary on the north and west is defined by the southern limit of the Upper 

Claiborne Stable Shelf Gas and Oil AU, which is controlled by the shelf margin of the underlying 

strata. In south to central Texas, the underlying shelf margin is defined by the limit of lower 

Claiborne Queen City progradation. In easternmost Texas and continuing east into Louisiana there 

was little or no Claiborne progradation (less toward the east), and the assessment unit brackets the 

underlying Wilcox shelf margin. The AU boundary on the south and southeast is the downdip limit 

of expansion. This typically is below the Vicksburg Fault Zone (T.E. Ewing, Frontera Exploration 

Consultants, Inc., written commun., 2008) and is the theoretical updip limit of the overlying 

Vicksburg Expanded Fault Zone AU as described in the geologic model used for this assessment. 

The eastern boundary is limited by State waters; however, this may be somewhat optimistic, as 

regional-scale studies have indicated that the expansion zone may not be present east of the 

Mississippi River, where the Claiborne is very thin and may be partially or completely removed by 

unconformity (O’Donnell, 1974; Dockery, 1976; T.E. Ewing, Frontera Exploration Consultants, 

Inc., written commun., 2008). 

The Upper Claiborne Expanded Fault Zone Gas AU is an established exploration and 

production trend with 11 oil and 97 gas accumulations that exceed the minimum size considered in 

this assessment (0.5 MMBO and 3 BCFG for oil and gas accumulations, respectively). About 

25 discoveries have been made in the last 10 years (NRG Associates, 2006). The median grown 

sizes of discovered gas accumulations, when divided into thirds (by early, middle, and late initial 

dates of production), are 23.5, 23.5, and 25.6 BCFG (fig. 36A), respectively, and for discovered oil 

accumulations (halves), are 2.4 and 1.9 MMBO, respectively. The similarity in median gas thirds is 

interpreted to represent spatial overlap between this AU and the updip Upper Claiborne Stable 

Shelf Gas and Oil AU (50470124), which has had a much longer development history. Total grown 

discovered gas resources are 3.9 TCFG; total grown oil resources are 41.3 MMBO. This AU was 

considered to contain one or more undiscovered hydrocarbon accumulations on the basis of having 

adequate charge, reservoir rocks, and favorable timing of geologic events. 

The number of undiscovered oil accumulations is estimated to be a minimum of 1, a 

maximum of 40, and a mode of 10. The maximum of 40 was selected because the deep distal parts 

of the AU are still frontier and essentially are an untested trend with many areas yet to be drilled. 

The mode of 10 was selected because this is an overall gas- and condensate-prone AU. Sizes of oil 

accumulations were estimated to be a minimum of 0.5 MMBO (minimum cutoff size), a maximum 

of 5 MMBO, and a median of 1.5 MMBO. At the maximum, 5 MMBO was selected to allow for 

the possibility of an undiscovered field 25 percent of the size of the largest discovered oil field in 

the AU. The median of 1.5 MMBO was selected to account for decline from the median size of the 

second half of discovered fields (1.9 MMBO). 

Numbers of undiscovered gas accumulations were estimated to be a minimum of 10, a 

maximum of 360, and a mode of 90. As with oil accumulations, the relatively high mode and 

maximum of undiscovered gas accumulations were assigned on the basis of the unexplored nature 

of the downdip and deeper parts of the AU, as well as because of its regional extent. Sizes of 

undiscovered gas accumulations were estimated to be a minimum of 3 BCFG (minimum cutoff 

size), a maximum of 400 BCFG, and a median of 20 BCFG. The 400 BCFG estimated maximum is 

based on the presence of multiple 100+ BCFG recently discovered fields, as well as continuing 

growth of cumulative discovered gas volumes with exploration (fig. 36B). The median of 20 BCFG 

is consistent with the recent trend in discovery size. 
59

Figure 36. Gas discovery curve and wildcat wells for the Upper Claiborne Expanded Fault Zone assessment 

unit (AU). A, Grown gas accumulation sizes for the Upper Claiborne Expanded Fault Zone AU (50470125) 

plotted as a function of discovery year. B, Cumulative grown gas volumes for the Upper Claiborne 

Expanded Fault Zone AU (50470125) plotted as a function of the cumulative number of new-field wildcat 

wells. Data from NRG Associates (2006), plotted by T. Klett, USGS. BCFG = billion cubic feet of gas.
60

Depths of undiscovered reservoirs are expected to range between 5,000 and 14,000 ft for oil 

accumulations and 5,000 and 16,000 ft for gas accumulations. The shallower cutoff of 5,000 ft (as 

opposed to 8,000 ft used in the analysis of the geologic model) is to include the possibility that 

some reservoirs deposited in the expanded fault zone environment have been brought shallower by 

salt diapirism, particularly in the Houston Embayment. Mean estimates of undiscovered resources 

from Monte Carlo simulation for the Upper Claiborne Expanded Fault Zone Gas AU are 

28 MMBO, 4,882 BCFG, and 351 MMBNGL (table 1). 

An estimated 2,040 new field wildcats penetrate the top of the Yegua in this AU for an 

approximate high-side exploration density of 1 wildcat well per every 6.9 mi2

. The AU is 

considered to have a high potential for new discoveries, primarily deep gas occurring in structural 

traps associated with contemporary growth-expansion faults. The relatively low exploration density 

implies that expanded reservoir sands in lowstand systems tracts including lowstand deltas, delta 

front and distal shelf sands, incised valley fill, and upper slope sands remain to be found. 

Overpressured conditions may preserve porosity for non-associated gas and condensate 

accumulations. Most new downdip Yegua wells flow 1–5 MMCFG/day with 35–500 barrels 

condensate (Ewing and Fergeson, 1991), and some wells in Jefferson County, Tex. (fig. 34), flow 

as much as 30 MMCFG/day (T.E. Ewing, Frontera Exploration Consultants, Inc., written commun., 

2008). However, the prediction of sand reservoirs in the downdip Yegua has proved difficult, and

this interval is composed mainly of shales in many exploration wells along the Texas coast 

(Swenson, 1997). Nonetheless, thick, high-quality downdip Yegua sands are present, interspersed 

with thick marine shales; in some areas thinner, high-quality sands as well as laminated sands are 

present with shales (Swenson, 1997; Ewing and Vincent, 1997b; T.E. Ewing, Frontera Exploration 

Consultants, Inc., written commun., 2008). Swenson (1997) postulated that an oversteepened shelf 

edge break northeast of the Jackson-Wharton County area may have caused shelf margin bypass of 

Yegua sands to slope mini-basins and basin floor fans. If this is the case, sand reservoirs would be 

present even farther downdip in the Upper Claiborne Slope and Basin Floor Gas AU (50470126). 

The precise nature and location of the boundary between the expanded fault zone and the slope and 

basin floor environments have not been completely revealed by exploration to date, although some 

discovered reservoir sands in the expanded fault zone are representative of upper slope 

environments (T.E. Ewing, Frontera Exploration Consultants, Inc., written commun., 2008). 

Upper Claiborne Slope and Basin Floor Gas (50470126)

The Upper Claiborne Slope and Basin Floor Gas AU lies basinward of the contemporary 

upper Claiborne expansion zone (fig. 34). The AU encompasses an area of about 22.8 million 

acres. The boundary on the north and west is defined by the southern boundary of 

AU 50470125 (the theoretical updip limit of Vicksburg expansion), and on the south and east by 

the State waters boundary.

The Upper Claiborne Slope and Basin Floor Gas AU does not contain any discovered 

hydrocarbon reservoirs greater than the minimum cutoff of 0.5 MMBO (NRG Associates, 2006) 

and therefore is considered hypothetical in nature. However, the AU was defined and quantitatively 

assessed because of the high probability for the existence of undiscovered gas accumulations 

greater than the minimum size cutoff, due to the inferred presence of adequate source rocks, 

reservoir rocks, and the favorable timing of geologic events. No oil accumulations are expected for 

this AU, due to high thermal maturity. The Lower Miocene Slope and Basin Gas AU (50470141) 

and its Federal offshore extension AU and a scaled-down Wilcox Slope and Basin Floor Gas AU 
61

(50470118; Dubiel and others, 2007) were used as analogs for estimating the numbers and sizes of 

undiscovered gas accumulations in the Upper Claiborne Slope and Basin Floor Gas AU. 

Contact with industry personnel (2006–2008) indicates that there currently is no production 

from the slope and basin floor environments of the Claiborne downdip of the expanded fault zone. 

However, deep wells have encountered sands in the Claiborne section out to nearly the present 

shoreline (T.E. Ewing, Frontera Exploration Consultants, Inc., written commun., 2008). Despite the 

presence of sand, lack of sufficient gas charge has been a problem in making these exploration 

wells economic to date, possibly due to salt movement and trap disruption (T.E. Ewing, Frontera 

Exploration Consultants, Inc., written commun., 2008). 

Numbers of undiscovered gas accumulations in the Upper Claiborne Slope and Basin Floor 

AU were estimated to be a minimum of 5, a maximum of 500, and a mode of 50. The maximum of 

500 was selected because of the vast size of the AU and the absence of significant exploration to 

date. The mode of 50 was scaled down from Wilcox and Miocene analogs, due to lower volumes of 

sand delivery. Sizes of undiscovered gas accumulations were estimated to be a minimum of 

3 BCFG (minimum cutoff size), a maximum of 1,500 BCFG, and a median of 20 BCFG. The 

maximum size of 1,500 BCFG was selected because of the high degree of uncertainty in this 

frontier environment and because of the presence of multiple 100+ BCFG discovered reservoirs in 

the updip Upper Claiborne Expanded Fault Zone AU (50470125). Depths to undiscovered gas 

accumulations are expected to range between 12,000 and 30,000 ft. As described for the lower 

Claiborne, the boundary between the expanded fault zone and the slope and basin floor 

environment has not been explored, and therefore the predicted depth to undiscovered 

accumulations overlaps between this AU and the updip Upper Claiborne Expanded Fault Zone AU 

(50470125). Mean estimates of undiscovered resources from Monte Carlo simulation for the Upper 

Claiborne Slope and Basin Floor Gas AU are 9,107 BCFG and 655 MMBNGL (table 1).

An estimated 820 new field wildcats penetrate the top of the Yegua in this AU for an 

approximate high-side exploration density of 1 wildcat well per every 43.7 mi2

. Approximately 

20 wells in the AU are coded for upper Claiborne production in the IHS database. However, 

conversations and correspondence with industry personnel (2006–2008) indicate that at least some 

of the wells in question are in fact producing from younger intervals and therefore are miscoded. 

Based on this information, it is assumed that the exploration density is even lower than predicted by 

the high-side new field wildcat exercise. The potential for new discoveries in this AU is expected to 

be very high due to the very low level of exploration and the inferred presence of adequate 

reservoir rocks in distal lowstand systems tracts including mid-lower slope fans, turbidites, basinfloor fans, and distal gravity slide features. As described above for the Lower Claiborne Slope and 

Basin Floor Gas AU (50470122), reservoir quality may be a risk factor although it is expected that 

overpressured conditions would preserve porosity for dry gas accumulations. Undiscovered 

reservoirs primarily would be in structural traps associated with the growth faults that sole out from 

the deposition of overlying strata. Given current high natural gas prices, instability of world 

markets, and renewed interest in developing domestic supplies, we expect that significant resources 

will be devoted by Gulf of Mexico operators in the coming decades to the exploration and 

production of overpressured downdip gas accumulations in the Claiborne Group and in the other 

Cenozoic clastic packages described in this volume. 
62

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Fort Bend Counties, Texas: American Association of Petroleum Geologists Bulletin, v. 30, no. 2, 

p. 157–180. 

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73

Appendixes A-G 
SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: P.C. Hackley Date: 22-Jan-07

Region: North America Number: 5

Province: Western Gulf Number: 5047

Total Petroleum System: Upper Jurassic-Cretaceous-Tertiary Composite Number: 504701

Assessment Unit: Lower Claiborne Stable Shelf Gas and Oil Number: 50470120

Based on Data as of: NRG 2006 (data current through 2004), IHS 2005 (data current through 2005)

Notes from Assessor: NRG reservoir growth factor

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Gas

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 16 Gas: 39

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 1.46 2nd 3rd 2.84 3rd 3rd 1.56

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 13.39 2nd 3rd 7.72 3rd 3rd 5.21

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 1 mode 5 maximum 15

Gas Accumulations: minimum (>0) 1 mode 10 maximum 30

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1 maximum 3

Gas in Gas Accumulations (bcfg): minimum 3 median 4 maximum 40

Appendix A. Input data for the Lower Claiborne Stable Shelf Gas and Oil Assessment Unit (50470120). Seventh Approximation 

Data Form for Conventional Assessment Units (Version 6, 9 April, 2003). Abbreviations: AU = assessment unit; cfg/bo = cubic 

feet of gas per barrel of oil; mmboe = million barrels of oil equivalent; accums. = accumulations; mmbo = million barrels of oil; 

bcfg = billion cubic feet of gas; min. = minimum; max. = maximum; bngl/mmcfg = barrels of natural gas liquids per million cubic 

feet of gas; bliq/mmcfg = barrels of liquid per million cubic feet of gas; bo/mmcfg = barrels of oil per million cubic feet of natural 

gas; % = percent; m = meters.

IDENTIFICATION INFORMATION

74
Appendix A. Input data for the Lower Claiborne Stable Shelf Gas and Oil Assessment Unit (50470120) continued. 

Assessment Unit (name, no.)

Lower Claiborne Stable Shelf Gas and Oil, 50470120

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 1400 2800 4200

NGL/gas ratio (bngl/mmcfg) 11 22 33

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 12.7 25.4 38.1

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 19 38 46

Sulfur content of oil (%) 0 0.1 0.2

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 24 1030 1610 1690 2520

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0 0.5 1.1

CO2 content (%) 0.2 1.6 2.8

Hydrogen-sulfide content (%) 0 0 0

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 280 1660 1900 2250 3660

75
SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: P.C. Hackley Date: 23-Jan-07

Region: North America Number: 5

Province: Western Gulf Number: 5047

Total Petroleum System: Upper Jurassic-Cretaceous-Tertiary Composite Number: 504701

Assessment Unit: Lower Claiborne Expanded Fault Zone Gas Number: 50470121

Based on Data as of: NRG 2006 (data current through 2004), IHS 2005 (data current through 2005)

Notes from Assessor: NRG reservoir growth factor

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Gas

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 0 Gas: 10

Established (>13 accums.) Frontier (1-13 accums.) X Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2nd 3rd 3rd 3rd

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 9.7 2nd 3rd 35.1 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 1 mode 2 maximum 5

Gas Accumulations: minimum (>0) 5 mode 25 maximum 50

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1 maximum 15

Gas in Gas Accumulations (bcfg): minimum 3 median 20 maximum 700

Appendix B. Input data for the Lower Claiborne Expanded Fault Zone Gas assessment unit (50470121). Seventh Approximation 

Data Form for Conventional Assessment Units (Version 6, 9 April, 2003). Abbreviations: AU = assessment unit; cfg/bo = cubic 

feet of gas per barrel of oil; mmboe = million barrels of oil equivalent; accums. = accumulations; mmbo = million barrels of oil; 

bcfg = billion cubic feet of gas; min. = minimum; max. = maximum; bngl/mmcfg = barrels of natural gas liquids per million cubic 

feet of gas; bliq/mmcfg = barrels of liquid per million cubic feet of gas; bo/mmcfg = barrels of oil per million cubic feet of natural 

gas; % = percent; m = meters.

IDENTIFICATION INFORMATION

76
Appendix B. Input data for the Lower Claiborne Expanded Fault Zone Gas assessment unit (50470121) continued. 

Assessment Unit (name, no.)

Lower Claiborne Expanded Fault Zone Gas, 50470121

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 2560 5125 7690

NGL/gas ratio (bngl/mmcfg) 35 70 105

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 20 40 60

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 35 49 55

Sulfur content of oil (%) 0 0.1 0.4

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 1524 2438 4267

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0 0.5 2.4

CO2 content (%) 0.5 1.2 3.4

Hydrogen-sulfide content (%) 0 0.1 0.2

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 1524 2957 4267

77
SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: P.C. Hackley Date: 23-Jan-07

Region: North America Number: 5

Province: Western Gulf Number: 5047

Total Petroleum System: Upper Jurassic-Cretaceous-Tertiary Composite Number: 504701

Assessment Unit: Lower Claiborne Slope and Basin Floor Gas Number: 50470122

Based on Data as of: NRG 2006 (data current through 2004), IHS 2005 (data current through 2005)

Notes from Assessor: NRG reservoir growth factor. Lower Miocene Slope and Basin Gas, Assessment

Unit 50470141 and its Federal offshore extension and scaled-down Wilcox 

Slope and Basin Floor Gas, Assessment Unit 50470118 were used as analogs.

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Gas

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 0 Gas: 0

Established (>13 accums.) Frontier (1-13 accums.) Hypothetical (no accums X

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2nd 3rd 3rd 3rd

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 0 mode 0 maximum 0

Gas Accumulations: minimum (>0) 1 mode 20 maximum 200

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum median maximum

Gas in Gas Accumulations (bcfg): minimum 3 median 20 maximum 1500

Appendix C. Input data for the Lower Claiborne Slope and Basin Floor Gas assessment unit (50470122). Seventh 

Approximation Data Form for Conventional Assessment Units (Version 6, 9 April, 2003). Abbreviations: AU = assessment unit; 

cfg/bo = cubic feet of gas per barrel of oil; mmboe = million barrels of oil equivalent; accums. = accumulations; mmbo = million 

barrels of oil; bcfg = billion cubic feet of gas; min. = minimum; max. = maximum; bngl/mmcfg = barrels of natural gas liquids per 

million cubic feet of gas; bliq/mmcfg = barrels of liquid per million cubic feet of gas; bo/mmcfg = barrels of oil per million cubic 

feet of natural gas; % = percent; m = meters.

IDENTIFICATION INFORMATION

78
Appendix C. Input data for the Lower Claiborne Slope and Basin Floor Gas assessment unit (50470122) continued. 

Assessment Unit (name, no.)

Lower Claiborne Slope and Basin Floor Gas, 50470122

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo)

NGL/gas ratio (bngl/mmcfg)

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 20 40 60

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees)

Sulfur content of oil (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0 0.5 2.4

CO2 content (%) 0.5 1.2 3.4

Hydrogen-sulfide content (%) 0 0.1 0.2

Depth (m) of water (if applicable) 0 10 50

minimum F75 mode F25 maximum

Drilling Depth (m) 3658 4267 4877 6096 9144

79
SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: P.C. Hackley Date: 23-Jan-07

Region: North America Number: 5

Province: Western Gulf Number: 5047

Total Petroleum System: Upper Jurassic-Cretaceous-Tertiary Composite Number: 504701

Assessment Unit: Lower Claiborne Cane River Number: 50470123

Based on Data as of: NRG 2006 (data current through 2004), IHS 2005 (data current through 2005)

Notes from Assessor: Not quantitatively assessed.

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall):

What is the minimum accumulation size? mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: Gas:

Established (>13 accums.) Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2nd 3rd 3rd 3rd

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size:

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size:

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size:

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3):

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?:

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) mode maximum

Gas Accumulations: minimum (>0) mode maximum

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?:

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum median maximum

Gas in Gas Accumulations (bcfg): minimum median maximum

Appendix D. Input data for the Lower Claiborne Cane River assessment unit (50470123). Seventh Approximation Data Form

for Conventional Assessment Units (Version 6, 9 April, 2003). Abbreviations: AU = assessment unit; cfg/bo = cubic feet of 

gas per barrel of oil; mmboe = million barrels of oil equivalent; accums. = accumulations; mmbo = million barrels of oil; 

bcfg = billion cubic feet of gas; min. = minimum; max. = maximum; bngl/mmcfg = barrels of natural gas liquids per million cubic 

feet of gas; bliq/mmcfg = barrels of liquid per million cubic feet of gas; bo/mmcfg = barrels of oil per million cubic feet of natural 

gas; % = percent; m = meters.

IDENTIFICATION INFORMATION

80
Appendix D. Input data for the Lower Claiborne Cane River assessment unit (50470123) continued. 

Assessment Unit (name, no.)

Lower Claiborne Cane River, 50470123

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo)

NGL/gas ratio (bngl/mmcfg)

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg)

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees)

Sulfur content of oil (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)

Gas Accumulations: minimum mode maximum

Inert gas content (%)

CO2 content (%)

Hydrogen-sulfide content (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)

81
SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: P.C. Hackley Date: 23-Jan-07

Region: North America Number: 5

Province: Western Gulf Number: 5047

Total Petroleum System: Upper Jurassic-Cretaceous-Tertiary Composite Number: 504701

Assessment Unit: Upper Claiborne Stable Shelf Gas and Oil Number: 50470124

Based on Data as of: NRG 2006 (data current through 2004), IHS 2005 (data current through 2005)

Notes from Assessor: NRG reservoir growth factor

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Oil

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 175 Gas: 153

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2.12 2nd 3rd 1.71 3rd 3rd 1.15

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 14.49 2nd 3rd 7.14 3rd 3rd 8.7

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 1 mode 10 maximum 30

Gas Accumulations: minimum (>0) 4 mode 15 maximum 75

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 0.8 maximum 5

Gas in Gas Accumulations (bcfg): minimum 3 median 6 maximum 400

Appendix E. Input data for the Upper Claiborne Stable Shelf Gas and Oil assessment unit (50470124). Seventh Approximation 

Data Form for Conventional Assessment Units (Version 6, 9 April, 2003). Abbreviations: AU = assessment unit; cfg/bo = cubic 

feet of gas per barrel of oil; mmboe = million barrels of oil equivalent; accums. = accumulations; mmbo = million barrels of oil; 

bcfg = billion cubic feet of gas; min. = minimum; max. = maximum; bngl/mmcfg = barrels of natural gas liquids per million cubic 

feet of gas; bliq/mmcfg = barrels of liquid per million cubic feet of gas; bo/mmcfg = barrels of oil per million cubic feet of natural 

gas; % = percent; m = meters.

IDENTIFICATION INFORMATION

82
Appendix E. Input data for the Upper Claiborne Stable Shelf Gas and Oil assessment unit (50470124) continued. 

Assessment Unit (name, no.)

Upper Claiborne Stable Shelf Gas and Oil, 50470124

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 1550 3100 4650

NGL/gas ratio (bngl/mmcfg) 10 20 30

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 14 28 42

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 17 40 55

Sulfur content of oil (%) 0 0.1 0.4

Depth (m) of water (if applicable) 0 10 20

minimum F75 mode F25 maximum

Drilling Depth (m) 304 1170 1615 1981 3475

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0 0.5 8.4

CO2 content (%) 0.1 0.6 2.4

Hydrogen-sulfide content (%) 0 0.1 0.2

Depth (m) of water (if applicable) 0 10 20

minimum F75 mode F25 maximum

Drilling Depth (m) 304 1591 2100 2450 3475

83
SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: P.C. Hackley Date: 23-Jan-07

Region: North America Number: 5

Province: Western Gulf Number: 5047

Total Petroleum System: Upper Jurassic-Cretaceous-Tertiary Composite Number: 504701

Assessment Unit: Upper Claiborne Expanded Fault Zone Gas Number: 50470125

Based on Data as of: NRG 2006 (data current through 2004), IHS 2005 (data current through 2005)

Notes from Assessor: NRG reservoir growth factor

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Gas

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 11 Gas: 97

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2.43 2nd 3rd 1.89 3rd 3rd

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 23.48 2nd 3rd 23.5 3rd 3rd 25.56

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?:

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 1 mode 10 maximum 40

Gas Accumulations: minimum (>0) 10 mode 90 maximum 360

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?:

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1.5 maximum 5

Gas in Gas Accumulations (bcfg): minimum 3 median 20 maximum 400

feet of gas per barrel of oil; mmboe = million barrels of oil equivalent; accums. = accumulations; mmbo = million barrels of oil;

bcfg = billion cubic feet of gas; min. = minimum; max. = maximum; bngl/mmcfg = barrels of natural gas liquids per million cubic

feet of gas; bliq/mmcfg = barrels of liquid per million cubic feet of gas; bo/mmcfg = barrels of oil per million cubic feet of natural 

gas; % = percent; m = meters.

IDENTIFICATION INFORMATION

Appendix F. Input data for the Upper Claiborne Expanded Fault Zone Gas assessment unit (50470125). Seventh Approximation 

Data Form for Conventional Assessment Units (Version 6, 9 April, 2003). Abbreviations: AU = assessment unit; cfg/bo = cubic

84
Appendix F. Input data for the Upper Claiborne Expanded Fault Zone Gas assessment unit (50470125) continued. 

Assessment Unit (name, no.)

Upper Claiborne Expanded Fault Zone Gas, 50470125

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 2560 5125 7690

NGL/gas ratio (bngl/mmcfg) 35 70 105

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 36 72 108

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 35 49 55

Sulfur content of oil (%) 0 0.1 0.4

Depth (m) of water (if applicable) 0 10 20

minimum F75 mode F25 maximum

Drilling Depth (m) 1524 2987 4267

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0 0.5 2.4

CO2 content (%) 0.5 1.2 3.4

Hydrogen-sulfide content (%) 0 0.1 0.2

Depth (m) of water (if applicable) 0 10 20

minimum F75 mode F25 maximum

Drilling Depth (m) 1524 3353 4877

85
SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: P.C. Hackley Date: 23-Jan-07

Region: North America Number: 5

Province: Western Gulf Number: 5047

Total Petroleum System: Upper Jurassic-Cretaceous-Tertiary Composite Number: 504701

Assessment Unit: Upper Claiborne Slope and Basin Floor Gas Number: 50470126

Based on Data as of: NRG 2006 (data current through 2004), IHS 2005 (data current through 2005)

Notes from Assessor: NRG reservoir growth factor. Lower Miocene Slope and Basin Gas, Assessment

Unit 50470141 and its Federal offshore extension and scaled-down Wilcox 

Slope and Basin Floor Gas, Assessment Unit 50470118 were used as analogs.

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Gas

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 0 Gas: 0

Established (>13 accums.) Frontier (1-13 accums.) Hypothetical (no accums X

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2nd 3rd 3rd 3rd

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 0 mode 0 maximum 0

Gas Accumulations: minimum (>0) 5 mode 50 maximum 500

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum median maximum

Gas in Gas Accumulations (bcfg): minimum 3 median 20 maximum 1500

Appendix G. Input data for the Upper Claiborne Slope and Basin Floor Gas assessment unit (50470126). Seventh 

Approximation Data Form for Conventional Assessment Units (Version 6, 9 April, 2003). Abbreviations: AU = assessment unit; 

cfg/bo = cubic feet of gas per barrel of oil; mmboe = million barrels of oil equivalent; accums. = accumulations; mmbo = million 

barrels of oil; bcfg = billion cubic feet of gas; min. = minimum; max. = maximum; bngl/mmcfg = barrels of natural gas liquids per 

million cubic feet of gas; bliq/mmcfg = barrels of liquid per million cubic feet of gas; bo/mmcfg = barrels of oil per million cubic 

feet of natural gas; % = percent; m = meters.

IDENTIFICATION INFORMATION

86
Appendix G. Input data for the Upper Claiborne Slope and Basin Floor Gas assessment unit (50470126) continued. 

Assessment Unit (name, no.)

Upper Claiborne Slope and Basin Floor Gas, 50470126

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo)

NGL/gas ratio (bngl/mmcfg)

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 36 72 108

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees)

Sulfur content of oil (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0 0.5 2.4

CO2 content (%) 0.5 1.2 3.4

Hydrogen-sulfide content (%) 0 0.1 0.2

Depth (m) of water (if applicable) 0 10 50

minimum F75 mode F25 maximum

Drilling Depth (m) 3658 4938 9144

87