U.S. Department of the Interior

U.S. Geological Survey

Scientific Investigations Report 2012–5159

Geologic Models and Evaluation of Undiscovered 

Conventional and Continuous Oil and Gas Resources—

Upper Cretaceous Austin Chalk, U.S. Gulf Coast
Front Cover. Photos taken by Krystal Pearson, U.S. Geological Survey, near the old Sprinkle

 Road bridge on Little Walnut Creek, Travis County, Texas.
Geologic Models and Evaluation of 

Undiscovered Conventional and Continuous 

Oil and Gas Resources—Upper Cretaceous 

Austin Chalk, U.S. Gulf Coast

By Krystal Pearson

Scientific Investigations Report 2012–5159

U.S. Department of the Interior

U.S. Geological Survey
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:

Pearson, Krystal, 2012, Geologic models and evaluation of undiscovered conventional and continuous oil and gas 

resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast: U.S. Geological Survey Scientific Investigations Report 

2012–5159, 26 p.
iii

Contents

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

Introduction.....................................................................................................................................................1

Geologic Setting and Stratigraphy..............................................................................................................2

Reservoir Properties......................................................................................................................................6

Source Rocks and Thermal Maturity..........................................................................................................7

Traps, Migration, and Timing.......................................................................................................................9

Assessment Unit Definition and Assessment Methodology ................................................................15

Austin-Tokio-Eutaw Updip Oil and Gas Assessment Unit (50490130) ........................................15

AU Description ...........................................................................................................................15

Geological Analysis of Assessment Unit Probability...........................................................16

Charge (1.0)........................................................................................................................16

Rocks (1.0)..........................................................................................................................16

Timing and Preservation (1.0) .........................................................................................16

Number of Undiscovered Accumulations ....................................................................16

Sizes of Undiscovered Accumulations .........................................................................16

Austin Pearsall-Giddings Area Oil Assessment Unit (50490168).................................................17

AU Description ...........................................................................................................................17

Geological Analysis of Assessment Unit Probability...........................................................19

Charge (1.0)........................................................................................................................19

Rocks (1.0)..........................................................................................................................19

Total Assessment Unit Area (Acres) .............................................................................19

Area per Cell of Untested Cells Having Potential for Additions to 

Reserves (Acres).................................................................................................19

Percentage of Total Assessment Unit Area Untested................................................20

Number of Untested Cells with Potential for Additions to Reserves (Percent)......20

Total Recovery per Cell (MMBO) ...................................................................................20

Success Ratios (Percent)................................................................................................20

Austin-Eutaw Middip Oil and Gas Assessment Unit (50490131) .................................................20

AU Description ...........................................................................................................................20

Geological Analysis of Assessment Unit Probability...........................................................21

Charge (1.0)........................................................................................................................21

Rocks (1.0)..........................................................................................................................21

Timing and Preservation (1.0) .........................................................................................21

Number of Undiscovered Accumulations ....................................................................21

Sizes of Undiscovered Accumulations .........................................................................21

Austin Downdip Gas Assessment Unit (50490132) ........................................................................22

AU Description ...........................................................................................................................22

Geological Analysis of Assessment Unit Probability...........................................................22

Charge (1.0)........................................................................................................................22

Rocks (1.0)..........................................................................................................................22

Timing and Preservation (1.0) .........................................................................................22

Number of Undiscovered Accumulations ....................................................................22

Sizes of Undiscovered Accumulations .........................................................................23
iv

Results ...........................................................................................................................................................23

Summary........................................................................................................................................................23

Acknowledgments.......................................................................................................................................24

References Cited..........................................................................................................................................25

Figures

1. Map for the Gulf Coast region showing the Upper Jurassic-Cretaceous-Tertiary 

Composite Total Petroleum System...........................................................................................2

2. Location map showing assessment units.................................................................................3

3. Stratigraphic column for Upper Cretaceous rocks in the study area..................................4

4. Location map showing assessment units and major Austin Chalk fields ...........................5

5. Major geological components of the study area, including total petroleum 

system boundary, fault zones and other structural features, Austin Chalk 

outcrops, and locations of cross sections ...............................................................................7

6. Distribution of oils that have been typed as Cretaceous in age across the 

study area ......................................................................................................................................9

7. Map showing Austin Chalk production and top (Ro = 0.6 percent) and base 

(Ro = 1.2 percent) of the oil window for the Eagle Ford Shale.............................................10

8. Distribution of oils that have been typed as Jurassic in age across the study 

area ...............................................................................................................................................11

9. Burial history diagram for Giddings field ................................................................................12

10. Burial history diagram for Brookeland field ...........................................................................13

11. Cross section A-A’ showing geologic strata and structural features................................14

12. Events chart for the Austin Chalk Petroleum System...........................................................15

13. Cross section B-B’ showing geologic strata and oil and gas production

 in Giddings field..........................................................................................................................17

14. Cross section C-C’ showing geologic strata and oil and gas production 

in Giddings field...........................................................................................................................18

15. Cross section D-D’ showing geologic strata and oil and gas production in 

Chittim and Pearsall fields.........................................................................................................19
Abstract 

The Upper Cretaceous Austin Chalk forms a lowpermeability, onshore Gulf of Mexico reservoir that produces 

oil and gas from major fractures oriented parallel to the underlying Lower Cretaceous shelf edge. Horizontal drilling links 

these fracture systems to create an interconnected network that 

drains the reservoir.

Field and well locations along the production trend are 

controlled by fracture networks. Highly fractured chalk is 

present along both regional and local fault zones. Fractures 

are also genetically linked to movement of the underlying 

Jurassic Louann Salt with tensile fractures forming downdip 

of salt-related structures creating the most effective reservoirs. 

Undiscovered accumulations should also be associated with 

structure-controlled fracture systems because much of the 

Austin that overlies the Lower Cretaceous shelf edge remains 

unexplored. 

The Upper Cretaceous Eagle Ford Shale is the primary 

source rock for Austin Chalk hydrocarbons. This transgressive 

marine shale varies in thickness and lithology across the study 

area and contains both oil- and gas-prone kerogen. The Eagle 

Ford began generating oil and gas in the early Miocene, and 

vertical migration through fractures was sufficient to charge 

the Austin reservoirs.

Introduction 

The U.S. Geological Survey (USGS) completed a geologic assessment of the undiscovered, technically recoverable 

oil and gas resources in the Austin Chalk and Tokio and Eutaw 

Formations of the U.S. Gulf Coast region (Pearson and others, 

2011). The assessment was based on the geologic elements 

and petroleum processes used to define a total petroleum 

system (TPS), which in this study is the Upper JurassicCretaceous-Tertiary Composite TPS (fig. 1), and includes 

petroleum source rocks (source-rock maturation and petroleum 

generation and migration), reservoir and seal rocks (sequence 

stratigraphy and petrophysical properties), and petroleum traps 

(trap formation, timing, and seals). 

Separate assessment units (AU) are defined to evaluate 

the potential in regions with differing geologic conditions 

or different production profiles. These evaluations permit 

resource prediction in both conventional and continuous AUs. 

Geologic factors such as trap type and local geology, as well 

as exploration trends, are used to predict these totals (Pearson 

and others, 2011).

Using this petroleum-system framework, the USGS 

defined four AUs within the Upper Jurassic-CretaceousTertiary Composite TPS: Austin-Tokio-Eutaw Updip Oil and 

Gas AU, Austin-Eutaw Middip Oil and Gas AU, Austin Downdip Gas AU, and Austin Pearsall-Giddings Area Oil AU 

(fig. 2) (Pearson and others, 2011).

The study area of this assessment spans a wide region 

that includes parts of Texas, Louisiana, Arkansas, Mississippi, 

Alabama, and Florida (figs. 1 and 2). Its extent is broadly 

defined by the bounding fault zones to the north and east, the 

U.S.-Mexico border to the west, and the extent of State waters 

to the south in the Gulf of Mexico. 

The Upper Cretaceous Austin Chalk (fig. 3) is a historically well-known onshore oil and gas play that extends across 

south-central Texas into southern Louisiana. Production data 

plotted from IHS Energy Group (2009a) indicate that hydrocarbon production trends within the formation are subparallel 

to the underlying Lower Cretaceous shelf edge (fig. 2). Recent 

drilling has expanded this traditional reservoir belt farther east 

into Louisiana as well as downdip of the Lower Cretaceous 

shelf edge. 

The Austin Chalk is classified as a biomicrite, according 

to Folk (1959), composed primarily of coccoliths (Dawson 

and others, 1995). This low-permeability, low-porosity rock 

requires large, connected fracture systems to store and produce 

hydrocarbons. Most of the large fractures parallel regional 

strike with few dip-oriented fractures. This single dominant 

joint set requires the presence of many smaller, intersecting 

local fractures to maintain fluid flow in the reservoir. The clay 

component of the formation also affects fracture intensity and 

connectivity. Although termed a chalk, marls are prevalent, 

alternating with chalk layers to form a heterogeneous package. 

Geologic Models and Evaluation of Undiscovered 

Conventional and Continuous Oil and Gas Resources—

Upper Cretaceous Austin Chalk, U.S. Gulf Coast

By Krystal Pearson
2 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

Individual fractures within the chalk layers may terminate at 

marl layers that are one-tenth the thickness of the chalk 

(Haymond, 1991) contributing to the complex and disconnected nature of these fracture systems.

Early drilling within the Austin Chalk focused on simple, 

vertical wells that drained oil and gas from the local fracture 

systems near the well. In the 1970s, hydraulic fracturing of the 

reservoir was initiated, which enhanced and connected these 

fracture systems to ultimately create a larger drainage area. A 

second advance in oil and gas production arrived in 1984, with 

the advent of horizontal drilling. First utilized in Pearsall and 

Giddings fields (fig. 4) to produce oil and gas from the Austin, 

this new technique allowed for the drainage of multiple vertical fracture systems, thus enhancing the ultimate recovery 

from a single well from three to five times that of a comparable 

vertical well (Haymond, 1991).

Geologic Setting and Stratigraphy

The Upper Cretaceous (Coniacian to Campanian) Austin 

Chalk is known by different names in the literature across the 

study area, such as the Austin Chalk Formation or the Austin 

Chalk Group (fig. 3). The name Austin Chalk will be used to 

reference the unit in this paper. The Austin Chalk was deposited during a world-wide sea-level highstand (Vail and others, 

1977) (fig. 3). Across what is now Texas, carbonate deposition 

occurred in a shallow-marine setting, in paleowater depths 

that ranged from 30 ft or less to more than 300 ft, indicating 

that deposition was below normal wave base on the inner to 

middle shelf as well as in much deeper water (Dravis, 1979). 

Paleowater depths likely deepened to the south and east, basinward of the Lower Cretaceous shelf edge (fig. 2). Trace fossil 

Fgure 1. Map for the Gulf Coast region showing the Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System (TPS). 

TPS boundary is shown in blue. Province boundaries are shown in red; numbers refer to a U.S. Geological Survey coding system.

Western Gulf 47

East 

Texas 

Basin 

48 Louisiana-Mississippi 

Salt Basins 49

Florida 

Peninsula

50

Miami

Tampa

Austin

Dallas

Houston

Atlanta

Memphis

Wichita

Nashville Raleigh

Charlotte

Fort Worth Birmingham

Louisville

San Antonio

New Orleans

St. Louis

Oklahoma City

Corpus Christi

TEXAS

FLORIDA

GEORGIA

OKLAHOMA

KANSAS

ALABAMA

LOUISIANA

SOUTH CAROLINA

COLORADO

MISSISSIPPI

ARKANSAS

MISSOURI

ILLINOIS

TENNESSEE

KENTUCKY

NORTH CAROLINA

VIRGINIA

MEXICO

UNITED

STATES

GULF OF MEXICO

ATLANTIC

OCEAN

 104° 102° 100° 98° 96° 94° 92° 90° 88° 86° 84° 82° 80° 78°

24°

26°

28°

30°

32°

34°

36°

38°

0 100 200 MILES

0 100 200 300 KILOMETERS
Geologic Setting and Stratigraphy 3

assemblages indicate normal marine salinity with deposition 

in an open marine environment. Dominant trace fossils include 

Planolites, Thallassinoides, and Chondrites (Dawson and 

Reaser, 1990). 

The widespread chalk deposition across the carbonate 

shelf shows only gradual lateral facies changes with few 

major facies recognized in Texas (Scholle, 1977). In parts of 

the East Texas Basin, northern Louisiana, southern Arkansas, 

and southern Alabama, however, sandstone sourced from 

fluvial systems to the north in the Mississippi Embayment is 

the dominant facies. The sandy facies equivalents in eastern 

Texas, Louisiana, and western Alabama are the Tokio and 

Eutaw Formations (Salvador and Quezada Muñeton, 1991) 

(fig. 3). These formations grade basinward into carbonate 

partial time-equivalent units, specifically the lower parts of the 

Austin Chalk and the Selma Group (Clark, 1995; Liu, 2005). 

The study area includes the regions with Austin Chalk deposition as well as its clastic equivalents to the east.

The Austin Chalk ranges in thickness from 150 to 800 ft 

and has many named members. In a broader and more regionally applicable sense, however, it has been divided into three 

main units: the lower chalk, the middle marl, and the upper 

chalk (fig. 3). The upper and lower chalks contain less clay 

and are therefore better reservoirs because they are more 

brittle, leading to higher fracture density (Hovorka and Nance, 

1994).

Hovorka and Nance (1994) described the three main 

Austin units in detail. The lower chalk consists of a number 

of lithofacies, including alternating chalk and marl, with the 

chalk intervals having a greater thickness than the intervening 

Austin Pearsall-Giddings 

Area Oil AU

50490168 Austin Downdip Gas AU

50490132

Austin-Tokio-Eutaw Updip Oil and Gas AU

50490130 TEXAS

FLORIDA

OKLAHOMA

ALABAMA

LOUISIANA

MISSISSIPPI

ARKANSAS

MEXICO

GULF OF MEXICO

UNITED 

STATES

Sweet spot

Austin-Eutaw Middip 

Oil and Gas AU

50490131

Oil production

Gas production

TPS boundary

AU boundaries

LC shelf edge

Sweet spot

EXPLANATION

0 50 100 MILES

0 100 KILOMETERS

102° 100° 98° 96° 94° 92° 90° 88° 86°

34°

32°

30°

28°

26°

Figure 2. Location map showing assessment unit (AU) areas within Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum 

System (TPS); numbers refer to a U.S. Geological Survey coding system. AU boundaries are shown in bold black. Location of Austin 

Chalk oil and gas production (IHS Energy Group, 2009a), shown in green and red, respectively, are plotted on the basis of quarter-mile 

area cells. Sweet spot (where production is, or is expected to be, elevated compared to the surrounding area) is outlined in gold 

inside the Austin Pearsall-Giddings Area Oil AU. Lower Cretaceous (LC) shelf edge after Martin (1980) and Ewing and Lopez (1991).
4 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

marls. Hovorka and Nance (1994) suggested that these alternations are transgressive in nature. Also present are chalks with 

thin, dark, and locally laminated marls that contain as much 

as 3.5-percent total organic carbon (TOC) as well as disseminated pyrite, indicating dysaerobic depositional conditions. 

Transgressive marls deposited under normal oxygen levels, 

as well as marly chalks that grade into chalks, are interpreted 

as highstand deposits in the lower chalk (Hovorka and Nance, 

1994).

The middle marl contains a zone of alternating and cyclic 

burrowed chalk and light-colored marl. This unit has much 

higher clay content and, as such, most of the layers should be 

termed “chalk-marl” or “marl” rather than “chalk.” Authigenic clay that formed as an alteration product of volcanic 

ash is also present. This unit is interpreted as initially regressive, with the younger strata deposited during a transgression 

(Hovorka and Nance, 1994).

In the upper chalk, the cyclicity of chalks and marls 

becomes less regular and defined. There is a marked increase 

in winnowed packstone units toward the top of the unit. The 

entire member is interpreted as a highstand deposit, with 

decreased water depths basinward of the shoreline and falling 

Campanian

Santonain

Coniacian

Turonian

Maasrichtian

Cenomanian

U

U

U

U

U

U

M

M

M

M

M

L

L

L

L

L

L

Stage

65.5

70.6

83.5

85.8

89.3

93.5

99.6

Series Ma

UPPER CRETACEOUS

Buda Manness Sh

Eagle Ford

Woodbine

Taylor Group Navarro Group Grayson

Buda Maness

East

Texas

Basin

Tokio

Saratoga

Marlbrook

PecanGap

Brownstown

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lower

Middle

Upper

Austin Group Nacatoch

Arkadelphia

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Global

sea level

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

Eagle Ford

Buda

DelRio

Olmos

Escondido

South

Texas 

Lower

Middle

Upper

Austin Chalk

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

SanMiguel

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . .

Present-day sealevel

Louisiana

Eagle Ford

Tuscaloosa

Upper

Washita units

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Taylor Group Brownstown

Marlbrook

Ozan

Annona

Tokio

Navarro Group Nacatoch

Arkadelphia

Saratoga

Mississippi

Tuscaloosa Upper Washita units

Mooreville

Demopolis

Eutaw

. . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . .

Lower

Middle

Upper

Ripley

Prairie

Bluff 

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Area, lithostratigraphic unit, and lithology Chronostratigraphic

unit

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lithology

Higher

Lower

Selma Group

Lithology Lithology Lithology

Anacacho

Upson

. . . . . . . . . . . .

Figure 3. Stratigraphic column for Upper Cretaceous rocks in the study area (modified from Vail and others, 1977; Wooten and 

Dunaway, 1977; Dawson and Reaser, 1990; Wescott and Hood, 1994; Mancini and others, 2006a,b). Reservoir rocks: Austin Chalk and 

Tokio and Eutaw Formations. Source rocks: Eagle Ford Shale and Smackover Formation (not shown). Seal rocks: Anacacho, Upson, 

Brownstown, and Mooreville Formations and Taylor Group. Global sea-level curve shows a prominent sea-level rise during the 

Cenomanian. U=upper, M=middle and L=lower. 
Geologic Setting and Stratigraphy 5

sea level (Hovorka and Nance, 1994). A diverse faunal assemblage indicates normal marine conditions. The top surface of 

the Austin Chalk is locally a bored hardground that is generally interpreted as the common by-product of sediment bypass 

(Hovorka and Nance, 1994). 

Updip Austin strata, as described by Dawson and others 

(1995), were deposited in shallow water, above storm wave 

base during normal marine conditions. These light-colored, 

organic-poor chalks are similar to other “shelf-sea” or 

“onshore” chalks of Cretaceous age and were likely deposited 

in shallow water. Regionally, these are described as “progradational highstand deposits” (Vail and others, 1977). As these 

chalks were deposited in shallow marine water, they are 

heavily bioturbated.

Downdip Austin strata are much darker than the updip 

strata because of a deeper water depositional environment and 

increases in clay and pyrite contents. These are termed “far 

offshore” chalks and exhibit little bioturbation. Microstylolites 

and clay seams are common. Breccia horizons are apparent 

and are interpreted to indicate shallow water deposits that 

were transported downslope (Dawson and others, 1995).

Sediments deposited farthest from the shoreline are 

referred to as deep downdip strata (Dawson and others, 1995). 

These have been interpreted as basinal marine deposits that 

accumulated in paleowater depths greater than 300 ft (Dravis, 

1979) or outer ramp and slope deposits (Dawson and others, 

1995). A scarcity of skeletal debris, the presence of pyrite, 

and the absence of bioturbation all indicate these strata were 

deposited under oxygen-deficient conditions, although alternations of lighter colored chalks with darker colored marls 

indicate that oxygen levels varied. In addition, the rock is not 

completely devoid of trace fossils, which indicates that complete anoxia was not established.

Clark (1995) described the depositional environments, 

diagenesis, and porosity of the Tokio Formation (fig. 3). This 

unit comprises sublitharenitic to litharenitic sandstone with 

34°

32°

30°

28°

26°

Luling-Branyon

Gwinville

Buchanan

Giddings

Brookeland

Pearsall

Masters Creek

Chittim

Heidelberg

Smackover

0 50 100 MILES

0 100 KILOMETERS

TEXAS

FLORIDA

OKLAHOMA

ALABAMA

LOUISIANA

MISSISSIPPI

ARKANSAS

TENNESSEE

MEXICO

Austin Downdip 

Gas AU

Austin-Eutaw Middip 

Oil and Gas AU

Austin Pearsall-Giddings 

Area Oil AU

Austin-Tokio-Eutaw 

Updip Oil and Gas AU

102° 100° 98° 96° 94° 92° 90° 88° 86°

UNITED 

STATES

GULF OF MEXICO

Field locations

Oil production

Gas production

AU boundaries

LC shelf edge

EXPLANATION

Figure 4. Location map showing assessment units (AUs) and major Austin Chalk fields (yellow). Location of Austin Chalk oil and 

gas production (IHS Energy Group, 2009a) shown in green and red, respectively, are plotted on the basis of quarter-mile area cells. 

Lower Cretaceous (LC) shelf edge after Martin (1980) and Ewing and Lopez (1991).
6 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

lithics sourced from volcanism in Alabama and Louisiana. 

The unit includes sandstone and shale sequences with friable 

well-sorted sandstones, mudstones, conglomeratic sandstones, 

and thin discontinuous coals. Although the Tokio is divided 

into four zones (RA, S3, S2 and S1), the 100-ft-thick basal RA 

zone, which is dominantly sandstone, forms the best reservoir 

unit in the formation.

The Tokio Formation is 210 ft thick in Haynesville field 

in northern Louisiana. Depositional environments across the 

study area include distributary channels (overlying the Eagle 

Ford Shale or Group), prodelta, transgressive marine settings, 

shallow marine bars, shoreface to barrier or beach complexes, 

and marsh or tidal flats and channels. Bioturbation, storm 

deposits, soft-sediment deformation, rip-up clasts, volcanic 

clasts, and glauconite are all present (Clark, 1995).

Permeability of the Tokio ranges from under 1 millidarcy 

(mD) to more than 3 darcies, but chlorite rims and clay 

cements appear to have caused a general reduction in permeability (Clark, 1995). Total porosity ranges from 20 to 32 percent, with averages of 26 percent in volcaniclastic sandstones 

and 30 percent in quartzose sandstones. Secondary porosity 

was created from dissolution of plagioclase and calcite and 

pitting or etching of quartz grains. Early burial diagenesis 

cements caused reduced porosities and permeabilities and may 

have inhibited compaction (Clark, 1995).

The Eutaw Formation (fig. 3) reaches thicknesses of 

350 to 400 ft in western and central Alabama where it lies on 

the eastern edge of the study area. It was deposited during 

a marine transgression and comprises two members: (1) the 

lower, unnamed member that contains micaceous, glauconitic 

crossbedded sand with silty clay and carbonaceous clay and 

(2) the upper, Tombigbee Sand Member that includes massive, 

glauconitic, micaceous, silty sandstone (Liu, 2005). The 

Tombigbee Member grades downdip into chalk and marl beds 

of the Selma Group, and the lower member grades into glauconitic sands and carbonaceous shales. The Eutaw Formation 

accumulated in nearshore- and marginal-marine environments, 

such as isolated barrier islands and lagoons with tidal deltas 

and tidal inlets.

Reservoir Properties

The Austin Chalk is a low-porosity, low-permeability 

carbonate with a dual pore system. It has a micro-porous 

matrix with micropores ranging in size from 5 to 7 microns 

(Dawson and others, 1995) and a moderately interconnected 

fracture system. Matrix porosity commonly ranges from 3 to 

10 percent (Dawson and others, 1995) and generally decreases 

with depth (Dravis, 1979). Permeability also decreases with 

depth, and it is typically near 0.5 mD and locally around 0.1 

mD (Dawson and others, 1995). Because of such low porosity 

and especially low permeability, production must rely heavily 

on fracture porosity and permeability. Water saturations are 

generally high, from 45 to 80 percent, and residual oil saturations range from 10 to 50 percent (Dawson and others, 1995). 

Tectonic fracturing within the Austin increases local 

permeabilities to over 2 darcies (Dawson and others, 1995). 

Fracture density and connectivity are highly variable, however, depending on proximity to faults (fig. 5), mineralogical 

variations (such as an increase in clay content), bed thickness, and the distribution of post-fracture cements. Fracture 

densities of more than 20 microfractures per foot have been 

observed in core (Snyder and Craft, 1977).

Near-vertical fractures are abundant in the area of study 

with widths of 0.1 mm to 4 mm (Dawson and others, 1995). 

Bleeding oil or oil staining is common along fractures, which 

indicates that fracture networks provide migration pathways 

for hydrocarbons. Two or three generations of intersecting 

fractures are generally present with the earliest tending to 

be partially or completely cemented with calcite. A second 

orthogonal set typically remains uncemented, and a third set 

consists of “gash fractures” that are associated with stylolite 

development (Dawson and others, 1995).

Most fractures in the Austin Chalk were created in 

response to the downwarping of the Gulf Coast basin, paired 

with associated faults and localized uplifts (fig. 5) that tend to 

parallel regional strike of rock units. Where associated with 

major faulting, fractures tend to be concentrated on downthrown fault blocks and within grabens (Dawson and others, 

1995). This creates a fracture network that typically communicates in a strike direction rather than in a dip orientation 

leading to variable gas-oil ratios at the updip and downdip 

limits of production.

As noted earlier, lithologic variation, specifically 

increases in marl or clay content, directly affects fracture 

density and connectivity. The upper and lower chalks contain 

more abundant and larger fractures than the middle marl 

(fig. 3). Fractures can terminate at a marl or shale bed that is 

much thinner than the adjacent chalk layer (Haymond, 1991). 

Therefore, thin alternating layers of chalk and marl likely 

have minimal communication. In addition, vertical, parallel 

fractures have moderately large spacing and generally few 

intersections (Wiltschko and others, 1991), which leads to 

reservoir compartmentalization.

Diagenetic processes can greatly influence the reservoir 

properties of the chalk. The Austin Chalk underwent considerable physical compaction that reduced primary porosity by 60 

to 80 percent (Grabowski, 1981). Solution compaction also 

occurred in the unit producing stylolites, microstylolites, and 

concentrations of insoluble material such as clays and organic 

carbon (Grabowski, 1981). 

Dawson and others (1995) described the Austin Chalk as 

an “argillaceous, compacted, foraminiferal biomicrite” where 

the micrite matrix is composed of coccolith fragments. The 

conversion of aragonite and high-magnesium calcite to the 

more stable low-magnesium calcite occurred post-deposition 

(Scholle, 1977). Additional calcite emplacement probably 

contributed to some porosity loss. Maximum burial depth 

affects degree of physical compaction and remains the main 
Source Rocks and Thermal Maturity 7

factor that controlled porosity loss or preservation (Dawson 

and others, 1995).

Source Rocks and Thermal Maturity

The Upper Cretaceous (Cenomanian to Turonian) Eagle 

-

ture across the study area, such as the Eagle Ford Formation 

or simply Eagle Ford, will be used to reference the unit in this 

report. It is a mixed siliciclastic-carbonate unit that was deposited during a 2nd order eustatic transgression that contains 

superimposed, higher frequency 3rd order cycles (Dawson, 

2000). Thickness varies over the region ranging from just 35 ft 

As sea levels rose 60 to 100 ft, marine shales and carbonates 

-

ern part of the study area (Dawson, 2000). A major depocenter 

for the Eagle Ford Shale is centered in northeastern Texas 

downdip and carbonate content increases (Dawson, 2000). As 

such, this creates a source rock with variable lithology and 

hydrocarbon generation potential. Dawson (2000) divided 

the Eagle Ford into two stratigraphic units. The lower, overall 

transgressive unit, consists of laminated shales that exhibit 

minor bioturbation. Transgressive and condensed strata of this 

unit were deposited in a poorly oxygenated marine setting 

below storm wave base. Few faunal species are recognized, 

and these lower shales tend to be oil-prone. An upper regressive unit contains high-frequency cycles of shale, limestone, 

Figure 5. Major geological components of the study area, including the Upper Jurassic-Cretaceous-Tertiary Composite Total 

Petroleum System (TPS) boundary, fault zones (FZ) and other structural features, Austin Chalk outcrops, and locations of cross 

sections. Locations of Austin Chalk oil and gas production (IHS Energy Group, 2009a), shown in green and red, respectively, are 

plotted on the basis of quarter-mile area cells. ETB = East Texas Basin, NLSB = North Louisiana Salt Basin, MSB = Mississippi Salt 

Basin. Structural features modified from Martin (1980) and Ewing and Lopez (1991). Austin outcrop modified from Schruben and 

others (1998) and King and Beikman (1974a,b).

ETB

NLSB

MSB

D ́

D

C

C ́ B

B ́

A

A ́

0 50 100 MILES

0 100 KILOMETERS

34°

32°

30°

28°

26°

102° 100° 98° 96° 94° 92° 90° 88° 86°

TEXAS

FLORIDA

OKLAHOMA

ALABAMA

LOUISIANA

MISSISSIPPI

ARKANSAS

MEXICO

UNITED 

STATES

GULF OF MEXICO

TENNESSEE

Structures

Diapirs

Oil production

Gas production

Fault zones

TPS boundary

Austin Chalk outcrop

Cross sections

Basins

EXPLANATION Pearsall

arch

BALCONES FZ

LULING FZ

MILANO FZ

MEXIA FZ

YUGUA FZ

anticline

Chittim

VICKSBURG FZ

FRIO FZ

KARNES FZ

MT ENTERPRISE FZ

TALCO FZ SOUTHERN ARKANSAS FZ

PICKENS FZ

GILBERTOWN FZ

STATE LINE FZ

TEPETATE FZ

Adams County high

hcra ellaS aL

TUSCALOOSA FZ

San marcos arch

FRIO FZ

Angelina-caldwell flexure
8 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

and carbonaceous quartzose siltstone. These strata were deposited in a higher energy, more oxygenated setting above storm 

wave base. A more diverse faunal assemblage is present, and 

the unit tends to be gas-prone. 

Dawson (2000) recognized and described six microfacies 

in the Eagle Ford. These include bituminous claystones and 

shales, pyritic fissile shales, phosphatic shales, bentonitic 

shales, fossiliferous shales, and silty shales. The primary 

microfacies acting as source rocks are bituminous claystones 

and shales, as well as phosphatic shales. Bituminous claystones and shales were deposited in a restricted, distal-marine, 

oxygen-depleted environment and are interpreted as transgressive deposits (Dawson, 2000). TOC is approximately 5 weight 

percent and pyrite is locally present. These strata lack bioturbation, fossils, and diagnostic sedimentary structures. Dawson 

(2000) proposed that the phosphatic shales (also known as 

“condensed shales”) were deposited below wave base in an 

oxygen-depleted environment. These shales show a large 

abundance yet low diversity of planktonic fossils, as well as a 

low abundance of benthic fossils. TOC is approximately 2 to 

4 weight percent, pyrite and glauconite contents are elevated, 

and bioturbation is sparse.

Robison (1997) examined the source rock potential and 

characteristics of the Eagle Ford. Based on percentages of oilprone kerogen (fluorescent amorphinite plus exinite), the strata 

are of source rock quality in eastern Texas. Most samples 

contain a mixture of hydrogen-enriched Type II kerogen and 

hydrogen-poor Type III kerogen making the Eagle Ford prone 

to both oil and gas production. TOC ranges from 1 to almost 

10 weight percent. Plotting TOC content versus sulfur content, 

Robison (1997) suggested a normal marine depositional 

setting for the formation, as opposed to an oxygen-depleted 

environment as interpreted by Dawson (2000).

A map of distribution of oils typed as Cretaceous (mostly 

Turonian) across the study area by Hood and others (2002; 

shown here as fig. 6) shows that oil produced from the historic 

Austin Chalk trend is likely sourced from the Eagle Ford 

because it is low sulfur marine in type and Turonian in age. 

Turonian source rocks in Louisiana and Mississippi may actually be in the Tuscaloosa Group (fig. 3) because these strata 

are a partial time-equivalent of the Eagle Ford.

In general, the Eagle Ford possesses good to excellent 

source rock characteristics and probably generated large quantities of hydrocarbons in its present-day oil-generation window 

location (fig. 7), as well as where it was previously within the 

oil window. The most productive intervals are transgressive, 

consisting of a condensed interval of marine shales that were 

deposited in oxygen-depleted environments. Kerogen type 

is dominantly oil-prone, and source rock quality varies both 

laterally and vertically.

Robison (1997) and others considered the Austin Chalk to 

be at least partially self-sourcing. Grabowski (1981) examined 

the source rock potential of the formation and reported that 

TOC was as much as 3.5 weight percent with higher values 

in deeper and more distal samples. Far updip chalks contain 

little organic carbon. Amorphous and sapropelic Austin oils 

contain Type II kerogen, produced from planktonic and algal 

organic matter. Grabowski (1981) placed the onset of petroleum generation at a burial depth around 5,000 ft based on an 

increase in extractability of hydrocarbons from samples below 

this depth. Similarly, where those hydrocarbons decrease, 

the onset of gas generation occurs at approximately 9,000 ft. 

API gravities for the Austin range from less than 20 degrees 

to more than 60 degrees. Grabowski (1981) attributed API 

gravity variation to the extent of hydrocarbon migration, with 

higher API gravities indicating increased migration distances. 

On the other hand, oils with API gravities less than 30 degrees 

may have undergone biodegradation, as they tend to be present 

in shallow wells.

In addition to the Eagle Ford, other rocks may be source 

rocks for the Austin Chalk in the study area. The Jurassic 

(Oxfordian) Smackover Formation was deposited over much 

of the eastern portion of the study area and varies in lithology and sulfur content (fig. 8). Geochemical oil-typing of 

oil samples from Louisiana and Mississippi indicate that the 

Smackover Formation is likely the primary source rock (Hood 

and others, 2002). This source rock, like those in the western 

portion of the study area, contains both Type I and Type II 

kerogen, implying contribution from both algal and some 

terrigenous material (Sassen, 1990).

Burial history plots were constructed for two wells that 

produce oil from the Austin Chalk (figs. 9 and 10). Input 

parameters including formation tops, lithology, organic carbon 

content (percent), paleowater depth, sediment-water interface 

temperature, paleoheat flow, vitrinite reflectance, temperature, 

and erosion were used to create the models. The first well 

(fig. 9) is located in Giddings field (fig. 7) where the Eagle 

Ford is the dominant source rock. Here, the Austin is approximately 570 ft thick with a formation top depth at 6,730 ft. The 

Eagle Ford is 300 ft thick and lies just beneath the Austin. 

Using Woodford kinetics (low sulfur) for this modeling, the 

top and base of the oil window were estimated using vitrinite 

reflectance (Ro) values of 0.6 percent and 1.3 percent, respectively. The Eagle Ford is currently within the oil window 

(fig. 9); the Eagle Ford in this area began generating oil 

approximately 10 million years ago (Ma), and the top of the 

formation entered the oil window approximately 4 Ma. The 

top of the Eagle Ford at present has a Ro value of 0.61 percent, 

indicating that the upper portion of the formation has only 

been generating oil for a short time (approximately 4 million 

years).

A second study well (fig. 10) is located within Brookeland field (fig. 7) and was also modeled using the same input 

parameters, source rock, kinetics, and Ro values for estimating 

the oil window. Here, the Austin is approximately 470 ft thick 

with a formation top depth of 11,300 ft. Figure 10 shows that 

at present the Eagle Ford is within the oil window with a Ro

value of 1.03 percent, and it began generating oil approximately 37 Ma. The Eagle Ford is much thinner in the Brookeland area than in Giddings field with a thickness of only 

60 ft. Therefore, Ro values are given as a formation average, as 

opposed to the top of the formation, as in the previous well.
Traps, Migration, and Timing 9

Traps, Migration, and Timing

Well and production data from IHS Energy Group 

(2009a, b) and field data from NRG Associates (2007) were 

analyzed to assess the trap types and production trends associated with the Austin Chalk and Tokio and Eutaw Formations. 

Numerous trap types exist in the Austin Chalk play with many 

fields exhibiting a combination of trap types. Cross section 

A-A' (fig. 11) provides a display of the various trap types 

across the region. Reservoirs in the updip region of the play 

are commonly sealed by normal fault traps with hydrocarbons 

accumulating on the downthrown side of faults. These faults, 

largely the Balcones, Luling, and Mexia-Talco fault zones in 

Texas, and the Pickens, Gilbertown, and Southern Arkansas 

fault zones farther to the east, are in long, en-echelon systems 

that are subparallel to the Austin outcrop belt (fig. 5). Because 

of the en-echelon nature of these faults, oil fields appear somewhat separated in map view, and a single field rarely extends 

beyond the end of a given fault segment. Well and production 

data (IHS Energy Group, 2009a, b) indicate that most of these 

faults have been explored, and the potential for undiscovered 

hydrocarbons is low for this trap style in the updip portion of 

the play area.

The low-porosity, low-permeability character of the reservoir itself provides another common trap type. Unconnected 

intergranular porosity provides much of the storage capacity 

of Austin Chalk reservoirs with the unfractured rock matrix 

itself serving as both top and lateral seals. The USGS defines 

these reservoirs as continuous because they tend to be regional 

in extent, exhibit diffuse boundaries and low permeabilities, 

and lack obvious seals, traps, and hydrocarbon-water contacts 

(Schmoker, 1999). These are in contrast to conventional 

Figure 6. Distribution of oils that have been typed as Cretaceous age across the study area (modified from Hood and others, 2002). 

Subtypes coded by color and number.

1 1 2

3

4

5

5

6 2

7

3

5

8

7

Cretaceous (Turonian) low sulfur marine 

Cretaceous (Turonian) low sulfur marine and lower Tertiary (Eocene) marine 

Cretaceous (Turonian) low sulfur marine and lower Tertiary (Eocene) terrestrial 

Cretaceous (Turonian) low sulfur marine and Jurassic (Tithonian) moderate to high sulfur marine 

Cretaceous (Turonian) low sulfur marine and Jurassic (Tithonian) marine calcareous

Cretaceous undifferentiated

Cretaceous undifferentiated and lower Tertiary (Eocene) terrestrial

Cretaceous (Turonian) low sulfur marine and Jurassic (Oxfordian) high salinity carbonate

34°

32°

30°

28°

26°

5

5

TEXAS

FLORIDA

OKLAHOMA

ALABAMA

LOUISIANA

MISSISSIPPI

ARKANSAS

TENNESSEE

102° 100° 98° 96° 94° 92° 90° 88° 86°

MEXICO

GULF OF MEXICO

UNITED 

STATES

0 50 100 MILES

0 100 KILOMETERS

EXPLANATION

1

2

3

4

5

6

7

8
10 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

reservoirs in which traditional hydrocarbon traps, such as 

faults, structures, and stratigraphic pinch outs, are present. 

Conventional reservoirs are also defined by the USGS as 

having well-delineated hydrocarbon-water contacts and typically display high matrix permeabilities (Schmoker, 1999). 

A modest portion of the study area likely contains continuous 

reservoirs. This region, including Pearsall, Giddings, and 

several smaller fields in between, most likely includes multiple 

trap types where broad structures and low-permeability rocks 

both contribute to the accumulation of oil and gas.

Other trap types across the study area include anticlines, 

rollover anticlines, stratigraphic pinch outs through facies 

change, and growth faults. Structural traps such as anticlines 

tend to be associated with the movement of the Jurassic 

Louann Salt and are concentrated in the East Texas Basin, the 

North Louisiana Salt Basin, and the Mississippi Salt Basin 

(fig. 5).

Fractures associated with fault zones in the region likely 

coincided with movement along those faults during the Oligocene and early Miocene (Dawson and others, 1995). The Eagle 

Ford Shale entered the oil window sometime in the early 

Miocene (Dawson and others, 1995), and thermal maturity 

models (figs. 9 and 10) indicate it is still generating oil and gas 

(fig. 7). This is critical because this time frame postdates the 

creation of fractures allowing for the emplacement of oil and 

gas into these systems immediately after generation 

(fig. 12). The Austin Chalk itself probably entered the oil 

window sometime during the Miocene, which is an important 

component if the Austin possesses the other necessary qualities to be self-sourcing (that is, sufficient TOC). Hydrocarbon 

generation and migration in the Smackover Formation began 

in the Early Cretaceous and has continued to the present 

(Mancini and others, 2003). Salt movement likely began in 

the Late Jurassic, soon after deposition, and continued through 

the Paleogene in the onshore Gulf Coast creating salt-related 

structures (fig. 5) and fractures. This salt movement allowed 

oil and gas to migrate into these salt-related traps. 

Vertical migration pathways are required to charge the 

Austin Chalk reservoirs. The Eagle Ford lies directly beneath 

the Austin allowing for hydrocarbons to migrate upward 

though localized fracture networks. Hydrocarbons in rocks 

that are updip and continuous with those in the oil window 

probably followed bed-parallel routes (Dawson and others, 1995) through either the Eagle Ford or the Austin itself. 

Figure 7. Map showing Austin Chalk production and top (Ro=0.6 percent) and base (Ro=1.2 percent) of the oil window for the Eagle 

Ford Shale (J. Pitman, written commun., 2010). Location of Austin Chalk oil and gas production (IHS Energy Group, 2009a), shown in 

green and red, respectively, are plotted on the basis of quarter-mile area cells. Ro = vitrinite reflectance.

0.6% Ro

1.2% Ro

Top oil window

EXPLANATION

34°

32°

30°

28°

26°

Giddings well

102° 100° 96° 90° 98° 94° 92° 88° 86°

Brookeland well

TEXAS

FLORIDA

ALABAMA

LOUISIANA

MISSISSIPPI

ARKANSAS

MEXICO GULF OF MEXICO

UNITED 

STATES

0 50 100 MILES

0 100 KILOMETERS

Base oil window

Oil production

Gas production

Burial history wells
Traps, Migration, and Timing 11

Figure 8. Distribution of oils that have been typed as Jurassic age across the study area (modified from Hood and others, 2002). 

Subtypes coded by color and number. The main contributor to Jurassic-sourced oils produced from the Austin Chalk is likely the 

Oxfordian high salinity carbonate (subtype 9) because it is generally spatially associated with Austin Chalk production in the region.

1

2

3

4

5

5 6

7

8 8 8 8

9

9

9

10

4

11

11

12

12

12

12

11

Jurassic (Tithonian) moderate-to-high sulfur marine

Jurassic (Tithonian) moderate-to-high sulfur marine and lower Tertiary (Eocene) marine

Jurassic (Tithonian) moderate-to-high sulfur marine and Cretaceous (Turonian) low sulfur marine

Jurassic (Tithonian) moderate-to-high sulfur marine and Jurassic (Oxfordian) high salinity carbonate

Jurassic (Tithonian) marine calcareous

Jurassic (Tithonian) marine calcareous and lower Tertiary (Eocene) marine

Jurassic (Tithonian) marine calcareous and Cretaceous (Turonian) low sulfur marine

Jurassic (Tithonian) marine calcareous and Triassic (Eagle Mills Formation) lacustrine

Jurassic (Oxfordian) high salinity carbonate

Jurassic (Oxfordian) high salinity carbonate and Cretaceous (Turonian) low sulfur marine

Jurassic (Oxfordian) high salinity carbonate and Jurassic (Tithonian) marine calcareous

Jurassic (Oxfordian) high salinity carbonate and Triassic (Eagle Mills Formation) lacustrine

100° 95° 90°

34°

32°

30°

28°

26°

24°

22°

EXPLANATION

MEXICO

GULF OF MEXICO

TEXAS

FLORIDA

OKLAHOMA

ALABAMA

LOUISIANA

MISSISSIPPI

ARKANSAS

TENNESSEE

UNITED 

STATES

0 50 100 MILES

0 100 KILOMETERS

10

1

2 

3

4

5

6

7

8

9

11

12
12 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

Figure 9. Burial history diagram for Giddings field. Stars indicate locations at the top of the Eagle Ford Shale where 

vitrinite reflectance (Ro) values were calculated. Roman numerals designate stratigraphic units that are equivalent in all 

plots. Note the top of the Eagle Ford entered the oil window approximately 4 million years ago (Ma) and currently has a 

Ro value of 0.61 percent. Data from IHS Energy Group (2009a,b). Input parameters from Wygrala (1989) and Sweeney and 

Burnham (1990). mW/m2 = megawatts per square meter.

EXPLANATION

Immature (< 0.6% Ro)

Oil zone (0.6-1.3% Ro)

Age (Ma) Burial depth (feet)

8,000

6,000

4,000

2,000

0

50 100 150 200 250 0.10 1.00 10.00

Temperature ( ̊F) Easy Ro (%)

(Sweeney and Burnham, 1990)

Oil

Boundary parameters

Age (Ma)

80 70 60 50 40 30 20 10 0

L Taylor Group

U Taylor Group

Navarro Group

Tertiary 

undifferentiated 

and 

Midway

Group

Feet Fahrenheit Mw/m2

40

60

80

60

75

90

200

-200

 0

90 80 70 60 50 40 30 20 10 0

Paleowater depth

Sediment-water interface temperature

(Wygrala,1989)

Heat flow

300

IV

III

II

I

IV

III

II

I

0.6% Ro

Austin Chalk

Eagle Ford Shale 0.61% Ro

V

VI

V

VI

Immature

Mesozoic (part)

Cretaceous (part)

Cenozoic

Paleogene Neogene and Quaternary

Mesozoic (part)

Cretaceous (part)

Cenozoic

Paleogene Neogene and Quaternary

Source rock

Reservoir rock

IV

III

II

I

V

VI

Burial depth (feet)

0

8,000

6,000

4,000

2,000

90
Traps, Migration, and Timing 13

Figure 10. Burial history diagram for Brookeland field. Stars indicate locations where Ro values were calculated 

(approximately in the middle of the formation). Roman numerals designate stratigraphic units that are equivalent in all 

plots. Note the Eagle Ford Shale entered the oil window approximately 37 million years ago (Ma) and currently has a Ro

value of 1.03 percent. Data from IHS Energy Group (2009a,b). Input parameters from Wygrala (1989) and Sweeney and 

Burnham (1990). mW/m2 = megawatts per square meter.

Age (Ma) Burial depth (feet)

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0

50 100 150 200 250 0.10 1.00 10.00

0

Temperature ( ̊F) Easy Ro (%)

(Sweeney and Burnham, 1990)

Immature Oil Gas

Boundary parameters

Age (Ma)

14,000

12,000

10,000

8,000

6,000

4,000

2,000

90 80 70 60 50 40 30 20 10 0

Feet Fahrenheit Mw/m2

40

60

80

60

75

90

200

-200

 0

90 80 70 60 50 40 30 20 10 0

Paleowater depth

Sediment-water interface temperature

(Wygrala,1989)

Heat flow

0.6% Ro

1.03% Ro

300

VI V IV

III

II

I

VI V IV

III

II

I

Mesozoic (part)

Cretaceous (part) Cenozoic Paleogene Neogene and Quaternary

Mesozoic (part)

Cretaceous (part)

Cenozoic

Paleogene

Woodbine Formation

Eagle Ford Shale

Austin Chalk

Taylor Group

Midway Group

Tertiary

undifferentiated

and 

Wilcox

Group

Source rock

Reservoir rock

Neogene and Quaternary

VI V IV

III

II

I

EXPLANATION

Immature (< 0.6% Ro)

Oil zone (0.6-1.3% Ro)
14 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

Figure 11. Cross section A-A’ (located in fig. 5) showing major stratigraphic units and structural features (modified from Salvador, 

1991). The Austin Chalk falls within the Upper Cretaceous (Ku) shown in light green. Line of section spans from the Oklahoma-Texas 

border to the Texas coastline. Oil migration has likely occurred in the Austin Chalk and sourced from the Eagle Ford Shale downdip. 

Note the various trap types shown; accumulations may have formed near salt structures or faults zones such as the Talco. Vertical 

scale in kilometers (km) from original plate; vertical exaggeration is 10 times. S.L., sea level; AU, assessment unit.

O

K

L

A

H

O

M

A

T

E

X

AS

EAST TEXAS BASIN

TALCO FAULT

ZONE

ANGELINA-CALDWELL

FLEXURE 

Coastline

Js

Ju

Kl

Ku Pal-Eoc

Eoc Olig

Mio

Plio

Tertiary–Neogene (Mio=Miocene, Plio=Pliocene)

Tertiary–Paleogene (Pal=Paleocene, Eoc=Eocene, Olig=Oligocene)

Upper Cretaceous

Lower Cretaceous

Upper Jurassic

Middle Jurassic salt

Lower Jurassic and Upper Triassic “red beds” and volcanics

Pennsylvanian–Upper Mississippian 

EXPLANATION

5

10

KM

S.L.

Austin-Tokio-Eutaw Updip Oil and Gas AU Austin- Eutaw Middip

Oil and Gas AU

Austin Downdip

Gas AU 

BOGGY CREEK DOME

BROOKS DOME

HAYNESVILLE DOME

MT. SYLVAN DOME

0 25 50 MILES

0 50 KILOMETERS

A ́ A

Tp

Tn

Tn

Tp

Ku

Kl

Ju

Js

J


M

*M

J
Assessment Unit Definition and Assessment Methodology 15

However, hydrocarbons sourced from the Jurassic Smackover 

Formation require complex pathways to charge the reservoirs, 

such as upward migration along salt structures, vertical movement through nonsealing faults, or slow migration through 

intervening formations. Any hydrocarbons that are selfsourced require short migration pathways into nearby traps 

unless fractures enhance the production of a continuous play, 

in which case conventional traps are not essential.

Assessment Unit Definition and 

Assessment Methodology

Austin-Tokio-Eutaw Updip Oil and Gas 

Assessment Unit (50490130)

AU Description

The Austin-Tokio-Eutaw Updip Oil and Gas Assessment Unit (AU) (fig. 2) is a conventional AU in which fields 

produce from traditional types of traps. As noted above, oil 

and gas production is associated with sealing faults and salt 

structures. Major fields in this play include Buchanan and 

Luling-Branyon in Texas, Smackover in Arkansas, and Heidelberg and Gwinville in Mississippi (fig. 4).

The northern boundary of this AU is defined by the updip 

extent of the reservoir rock in the western portion of the AU. 

Farther north, the Talco and Pickens fault zones (fig. 5) delineate the edge of the AU because it is unlikely that hydrocarbons 

have migrated updip of these sealing fault zones. Between fault 

zones in the eastern portion of the AU, the northern boundary 

is located along the approximate extent of Smackover source 

rocks in the subsurface (Hood and others, 2002). The western 

boundary lies on the U.S.-Mexico border. The southern extent 

is just south of the Luling and Mt. Enterprise fault zones and 

north of the Milano fault zone. It is also north of larger regional 

structures, such as the Angelina-Caldwell flexure, La Salle arch, 

and Adams County high (fig. 5).

In the western portion of this AU, the major source rock 

is the Eagle Ford with possible minor self-sourcing from the 

Austin. Where the Eagle Ford is immature, as is the case in 

most of the western region, oil has migrated updip from areas 

where the source is within the oil window (fig. 7). In the eastern portion of the AU, where the Eagle Ford is not of source 

rock quality, the Smackover likely is the source for most of 

the oil and gas with a small amount probably derived from the 

Austin itself (Hood and others, 2002).

Reservoir characteristics of the Austin in this AU vary 

from west to east, coinciding with a facies change from 

dominantly chalks of the Austin to sandstones of the Tokio and 

Eutaw Formations. Porosity type changes from fracture porosity in the west to dominantly matrix porosity in the sandstones 

to the east. Porosity is lower in the chalk facies and generally higher in the sandstones. Permeability follows a similar 

pattern with very low values common to the west and much 

higher permeabilities to the east (NRG Associates, 2007).

Trap styles across the AU vary from fracturing and 

growth faults in the western part of the AU to normal faults, 

anticlines, and facies changes in the salt basins of the eastern 

part. Drive type also varies, although solution gas drive is 

the most common, particularly in anticlinal traps. There is 

water drive in about one-third of reservoirs in this AU, most 

Figure 12. Events chart for the Austin Chalk Petroleum System (modified from Dawson and others, 1995; Zimmerman, 1997; Mancini 

and others, 2003). Source rocks include Smackover Formation, Austin Chalk, and Eagle Ford Shale. Salt-related fractures (from salt 

movement) formed sometime after emplacement of the Louann Salt during the Jurassic. Hydrocarbon (HC) generation and migration is 

likely still occurring in the Eagle Ford Shale (see figs. 9 and 10) and also in the Smackover Formation. Pal., Paleocene; Plio., Pliocene; 

Ma, million years ago.

90 80 70 60 50 40 30 20 10 0 Ma

Critical factors

Source

deposition 

Reservoir

deposition

Seal

deposition

Fracture

development 

HC generationmigration 

Late Cretaceous Pal. Eocene Oligocene Miocene

? ?

? ?

Salt-related fractures

Trap

development ?

Smackover Formation

Eagle Ford Shale

160 150 140 130 120 110 100

Late Jurassic Early Cretaceous Plio.
16 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

commonly associated with normal and growth faults. Traps 

and drive mechanisms such as these indicate conventional 

accumulations because they generally have oil-water contacts.

The Austin-Tokio-Eutaw Updip Oil and Gas AU is 

dominated by regional fault zones (fig. 5) and small anticlines 

associated with salt basins; few large-scale anticlinal-type 

structures exist in this AU. Because the traps tend to be small, 

undiscovered fields are expected to have low resource volumes as well. New fields may be discovered along undrilled 

fault segments and salt structures. Grabens between sealing fault segments may also have potential for future discoveries because they provide another means for trapping 

hydrocarbons.

Geological Analysis of Assessment Unit 

Probability

The AU probability represents the likelihood that at least 

one undiscovered field of minimum size or larger exists in the 

AU. Assessment unit probability is the product of the probabilities (out of 1.0) of charge, rocks, and timing and preservation. 

The likelihood that this AU contains at least one accumulation 

greater than the minimum field size of 50 million barrels of oil 

equivalent (MMBOE) is estimated to be 100 percent based on 

the following interpretation of petroleum system elements.

Charge (1.0)

The large number of known and produced accumulations 

in the AU indicates that a sufficient charge is present, and 

furthermore, the Eagle Ford and Smackover are prolific source 

rocks in the region. Although the Eagle Ford oil window (fig. 7) 

lies south of the AU, numerous pathways exist for oil and gas 

to charge the reservoir.

Rocks (1.0)

Austin Chalk and Tokio and Eutaw sandstone reservoirs 

are proven to have sufficient reservoir quality to host and 

produce oil and gas. The strata cover the entire AU with thicknesses that range from 150 ft to as much as 1,200 ft. Reservoir 

quality varies, however, with reservoirs in some regions having higher shale content and lower fracture connectivity and 

density.

Timing and Preservation (1.0)

Timing of geologic events for this AU indicates that 

fractures associated with fault zones probably coincided with 

movement along those faults during the Oligocene and early 

Miocene (Dawson and others, 1995). This predates when the 

Eagle Ford entered the oil window, in the early Miocene 

(fig. 12), which allows for the emplacement of oil and gas 

in the reservoir immediately after generation. In the eastern 

part of the AU, salt created the majority of traps, and salt 

movement likely began in the Late Jurassic. This allows for 

Smackover oil and gas, which began generation in the Early 

Cretaceous (Mancini and others, 2003), to migrate into these 

traps after they formed.

Number of Undiscovered Accumulations

Numbers of undiscovered oil and gas accumulations that 

exceed minimum size were predicted using the number of 

discovered accumulations, the number of wildcat wells, and 

drilling density (dry holes plus producing wells). There are 

41 discovered oil accumulations larger than minimum size 

in this AU, which means that a mode of 15 would indicate 

that approximately 75 percent of oil accumulations have been 

discovered. As this is a fairly mature oil play, a minimum of 

one accumulation was chosen. In addition, less than 10 wildcat 

wells were drilled in the last 20 years, which is somewhat 

indicative of a decrease in exploration interest. A predicted 

maximum of 30 accumulations would indicate that only 58 

percent of oil accumulations have been found. Future discoveries are expected to be associated with small salt structures 

and along undrilled fault segments; this would yield small 

production totals.

There are only six discovered gas accumulations larger 

than minimum size in this AU, and a mode of five accumulations would indicate that only 55 percent of all gas accumulations have been found, and that there is more potential for 

undiscovered gas accumulations in the AU than oil. This is 

partly because the potential for undrilled structures is higher 

in the portion of the AU that tends to be gas-prone, notwithstanding the fact that only one field has been discovered in the 

last 30 years. Like minimum oil accumulations, the minimum 

for gas accumulations was set at one. The maximum number 

of gas accumulations was placed at 15, indicating that only 

29 percent of gas accumulations have been found. As with oil 

accumulations, undiscovered gas accumulations would likely 

be related to small salt structures and along undrilled fault 

segments.

Sizes of Undiscovered Accumulations

Grown sizes of accumulations were assessed based on the 

distribution and trends through time of historical field sizes. 

Only two oil fields were discovered in the last 25 years; both 

totaled 1 million barrels of oil (MMBO) or less, so the median 

grown size of undiscovered oil accumulation was set at 

1 MMBO. The minimum size was placed at 0.5 MMBO 

because this is the USGS minimum assessment convention. 

Only one field discovered in the last 40 years has yielded more 

than 10 MMBO, so the maximum grown oil size was estimated at 10 MMBO.

The median for grown gas was estimated to be 6 billion 

cubic feet (BCF), which correlates to a median of 1 MMBO 

that was estimated for oil because the volume equivalence is 

roughly 6:1. This indicates that expected sizes of oil and gas 

accumulations are approximately equal. This median is twice 

the size of the minimum size of 3 BCF, which is the set grown 

size for gas accumulations according to USGS assessment 

convention. Only two fields have been discovered that 
Assessment Unit Definition and Assessment Methodology 17

exceed 40 BCF, and the most recent discovery only yielded 

15 BCF. Considering these facts, the maximum grown gas size 

was placed at 40 BCF, which is about one-third less than if the 

6:1 ratio was applied to the maximum grown oil size of 

10 MMBO; this would yield approximately 60 BCF.

Austin Pearsall-Giddings Area Oil Assessment 

Unit (50490168)

AU Description

The Austin Pearsall-Giddings Area Oil and Gas AU 

(fig. 2) is a continuous AU in which the chalk produces oil 

and gas in a continuous reservoir and where traditional trap 

styles such as anticlines and faults are not essential for the 

accumulation and production of oil and gas. A number of local 

structures in the AU, similar to those associated with Giddings 

field (figs. 13 and 14), are likely to enhance production. A 

continuous classification is common for reservoirs like the 

Austin because the extremely low matrix porosity and permeability of the chalk provide a means for trapping oil and gas. 

Where significant numbers of interconnected fracture systems 

exist, commonly associated with normal faults and structures, 

a “sweet spot” exists in the continuous AU. This sweet spot 

defines the region where production is, or is expected to be, 

elevated compared to the surrounding area. This AU includes 

Pearsall and Giddings fields, as well as the band of production 

between the fields. 

The northern boundary is defined by the southern boundary of the Austin-Tokio-Eutaw Updip Oil and Gas AU (fig. 2), 

where the Luling fault zone terminates (fig. 5). The western 

boundary lies on the U.S.-Mexico border, and the eastern 

boundary encompasses wells located on the east side of Giddings field (fig. 4). The southern boundary lies just south of 

Pearsall field, continues eastward, south of the main Austin 

production belt, and eventually extends through Giddings 

field. The location of the boundary in Giddings field coincides 

with the transition from oil- to gas-dominated reservoirs 

(fig. 4).

The Eagle Ford is thought to source the Austin in this 

part of the study area, and almost the entire AU lies above 

the Eagle Ford oil window in map view (fig. 7). This AU also 

produces moderate amounts of gas that likely migrated updip 

from the deeper Eagle Ford or Austin (figs. 13 and 14). (Note: 

The oil-over-gas pattern in Giddings field suggests that the 

reservoir is continuous and lacks a hydrocarbon-water 

contact.)

Fracture porosity makes up almost all of the porosity 

of the unit, and permeability ranges from very low to much 

higher values. Solution gas drive is dominant (NRG Associates, 2007), and traps are generally anticlines and interconnected fracture sets.

Although additional sweet spots may exist in the area, 

such as continued expansion of Chittim and Pearsall fields 

(figs. 4 and 15), future discoveries are difficult to predict. 

Figure 13. Cross section B-B' (located on fig. 5) showing stratigraphic units and oil and gas production in Giddings field. Note 

intersection point with cross section C-C' (fig. 14). Giddings field may be a broad structure where oil and gas have accumulated. 

Note that gas is dominant near the center of the cross section. Cross section is approximately 100 miles long. Vertical exaggeration 

is 20 times. Dashed lines indicate approximate formation boundaries where formation tops were absent from the data. Cross section 

created using data from IHS Energy Group (2009a, b). DEPTH

2

4

6

8

10

SW

SECTION C-C

NE

′

Buda Limestone Eagle Ford Shale

Austin Chalk

Lower Taylor Group

0

Giddings field

Upper Cretaceous undifferentiated

B B′ FEET

1,000

Oil production

Oil and gas production

Gas production

EXPLANATION
18 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

Figure 14. Cross section C-C' (location in fig. 5) showing stratigraphic units and oil and gas production in Giddings field. 

Note intersection point with cross section B-B'. Oil and gas likely migrated updip from the Eagle Ford Shale, as oil and gas 

are present updip of their respective windows. The upper part of the Taylor Group is shown terminated to the northwest and 

southwest because it was not present on well logs. Cross section is approximately 35 miles long. Vertical exaggeration is 10 

times. Cross section created using data from IHS Energy Group (2009a, b). DEPTH

C

SECTION B-B′

Giddings field

FEET

1,000

NW

Upper Cretaceous undifferentiated

Upper Taylor Group

Austin Chalk

C′

NW

2

4

6

8

10

0

Lower Taylor Group

Eagle Ford Shale

12

Oil production

Oil and gas production

Gas production

EXPLANATION
Assessment Unit Definition and Assessment Methodology 19

Small structures and faults may exist outside of the sweet spot 

leading to an expanded area of production. Should the remainder of the AU yield few viable trapping mechanisms, or have 

poor fracture permeability, future production would be limited 

to infill drilling of the established sweet spot. 

Geological Analysis of Assessment Unit 

Probability 

The likelihood that this AU contains at least one untested 

cell with a minimum total recovery of 0.002 MMBOE is estimated to be 100 percent based on the following interpretation 

of petroleum system elements.

Charge (1.0)

Field size and well density of Giddings and Pearsall fields 

(fig. 4) indicate that a sufficient charge is present. In addition, 

the Eagle Ford is the dominant source rock, and the Eagle Ford 

lies within the oil window for a majority of the AU (fig. 7).

Rocks (1.0)

The Austin Chalk has proven to be a viable reservoir 

rock in this AU. Although matrix permeability can be quite 

low, faults and structures create fractures that enhance the 

reservoir quality of the chalk (fig. 5). The Austin Chalk ranges 

in thickness from about 200 ft to as much as 1,000 ft. The 

Eagle Ford is currently within the oil window in Giddings field 

(fig. 9); the Eagle Ford in this area began generating oil 

approximately 10 Ma, and the top of the formation entered 

the oil window approximately 4 Ma. Fracturing in the Austin 

Chalk began in Late Cretaceous, and the subsequent generation of oil allows for the emplacement of oil into fractured 

Austin Chalk reservoirs.

Total Assessment Unit Area (Acres)

Mode acreage was calculated using GIS that was based 

on AU boundaries. Maximum and minimum acreage are equal 

to approximately ±5 percent of the mode. As this is a symmetrical distribution, the calculated mean equals the mode.

Area per Cell of Untested Cells Having Potential for 

Additions to Reserves (Acres)

Using horizontal well spacing (no vertical wells), the 

maximum number of existing wells per square mile was estimated to be four, which yields an area per cell of 160 acres. 

Allowing for the possibility of one additional well per cell in 

some cells (a total of five wells) would yield an area per cell 

of 128 acres; thus, 140 acres was used for the mode. As some 

cells only contain one or two wells, 240 acres was used for 

the maximum. In cells where wells with shorter laterals exist, 

there is the potential for up to six or seven wells. This would 

yield a minimum of approximately 100 acres. The uncertainty 

maximum and minimum means were calculated using the 

calculated mean ±20 percent.

Figure 15. Cross section D-D' (located in fig. 5) showing stratigraphic units and oil and gas production in Chittim and Pearsall fields. 

Most of the Pearsall-Giddings Area Assessment Unit lies within the oil window, so little updip migration of oil is required to charge 

Austin Chalk reservoirs, though updip gas migration has likely occurred. The lower part of Navarro Group-Taylor Group interval is 

shown terminated to the northwest because formation tops were not present in well logs. Cross section is approximately 85 miles

long. Vertical exaggeration is 10 times. Cross section created using data from IHS Energy Group (2009a, b).

2

4

6

8

10

12

DEPTH

NW SE

Eagle Ford Shale

Austin Chalk

Chittim and Pearsall fields

Upper Cretaceous undifferentiated Lower Navarro Group and Taylor Group

Buda Limestone

Del Rio Formation

Lower Cretaceous

 shelf edge

0

Chittim field Pearsall field

D D′ FEET

(1,000)

14

Oil production

Oil and gas production

Gas production

EXPLANATION
20 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

Percentage of Total Assessment Unit Area Untested

Mode was calculated using the number of tested cells 

(8,267) multiplied by an area per cell of 140 acres and dividing by the mode number of areas (7,649,000). Minimum 

and maximum are calculated in the same fashion using the 

uncertainty of mean minimum and maximum areas per cell 

of 130 and 190 acres, respectively. This yields minimum and 

maximum untested areas within 1 percent of the numbers 

shown below. As the distribution is essentially symmetrical, 

the calculated mean equals the mode.

Number of Untested Cells with Potential for Additions to 

Reserves (Percent) 

Using the mode untested area of 83 percent (above), 

the tested area (that is, the area drilled) was estimated to be 

17 percent. Under the assumption that the majority of the 

tested area lies within the sweet spot, the percentage of area 

within the sweet spot that is tested was calculated. The sweet 

spot makes up 35 percent of the total area of the AU, so 

subtracting 17 percent (the tested area) from this number 

yields approximately 18 percent, which represents the untested 

area of the sweet spot. Dividing the untested area of the sweet 

spot (18 percent) by the untested area of the entire AU 

(83 percent), gives the percentage of untested area for the AU 

that lies within the sweet spot, which is approximately 

20 percent. Multiplying this by the predicted maximum future 

success ratio of 80 percent yields a minimum percentage 

of untested cells with potential for additions to reserves of 

approximately 16 percent. This assumes that future drilling 

will be limited to infill drilling within the sweet spot. If future 

drilling expands outside the sweet spot, additional cells will 

have potential for additions to reserves; thus, the mode was 

estimated to be 30 percent, approximately twice the minimum. 

The maximum percentage can be estimated by supposing 

that large portions of the area outside the sweet spot will 

yield additional reserves. A maximum area of 75 percent was 

estimated. The calculated mean was determined using the 

minimum, mode, and maximum.

Total Recovery per Cell (MMBO)

Total recovery per cell was estimated using estimated 

ultimate recovery (EUR) graphs that were broken down into 

the first, second, and third third of all horizontal producing 

wells in the AU that started production after 1996 and have 

production totals greater than minimum recovery. The third 

third shows a mean recovery per cell of approximately 

0.035 MMBO, and the second third shows a mean recovery 

per cell of approximately 0.1 MMBO. As future wells should 

have recoveries closer to that of the third third, a median total 

recovery per cell of 0.04 MMBO was assigned. A minimum 

of 0.002 MMBO was used because this is the stated minimum 

total recovery per cell. Using the third thirds EUR graph, 

the cells with the largest total recoveries in the AU produce 

approximately 0.5 MMBO, so this number was used for the 

maximum total recovery per cell. The calculated mean was 

calculated using the minimum, median, and maximum.

Success Ratios (Percent)

Historic success ratios were calculated based on the number of cells exceeding minimum recovery of 0.002 MMBOE 

(6,419) divided by the number of cells tested (8,267), which 

yields a success ratio of 78 percent. Success ratios for inside 

and outside the sweet spot were calculated in the same fashion 

yielding values of 81 percent for inside the sweet spot and 

31 percent outside of it. Using these numbers, future success 

ratio was calculated. If future drilling is limited to inside the 

sweet spot, then the success ratio would approximate that of 

the historic success ratio of the sweet spot. Therefore, a maximum success ratio of 80 percent was assigned. Assuming that 

future drilling will be slightly more successful than the past 

due to improved completion practices and some of the future 

drilling will occur inside the sweet spot, a minimum of 

40 percent was assigned, which is slightly higher than the 

historic success ratio outside of the sweet spot (31 percent). 

As this gives a symmetrical distribution, the calculated mean 

equals the mode.

Austin-Eutaw Middip Oil and Gas Assessment 

Unit (50490131)

AU Description

The Austin-Eutaw Middip Oil and Gas AU lies directly 

south of the central and eastern parts of the Austin-TokioEutaw Updip Oil and Gas AU, and to the southwest it lies 

south of the Austin Pearsall-Giddings Area Oil AU (fig. 2). 

This AU is primarily defined by a production belt that lies 

along and north of the Lower Cretaceous shelf edge (fig. 4). 

The northern boundary is just south of the Mt. Enterprise fault 

zone and to the north of larger regional structures, such as the 

Angelina-Caldwell flexure, La Salle arch, and Adams County 

high (fig. 5). It extends west to the U.S.-Mexico border and 

to the east to the State waters of Louisiana, Mississippi, 

Alabama, and Florida. The southern boundary is placed at 

the inferred extent of fractures associated with the Lower 

Cretaceous shelf edge.

Major fields in this AU include Masters Creek, Brookeland, and the southern portion of Giddings (fig. 4). Fields associated with the shelf edge make up nearly all of the discovered 

accumulations (fig. 4). The draping of the Austin Chalk over 

the shelf edge may contribute to an increase in fracture density 

and connectivity, leading to increased production. Faulting 

within this AU may also contribute to accumulations.

As with the other AUs containing Austin Chalk throughout Texas and western Louisiana, the Eagle Ford Shale is the 

primary source rock. In addition, preliminary thermal maturity 

models indicate that the Eagle Ford is in the oil window in 
Assessment Unit Definition and Assessment Methodology 21

central and eastern parts of the AU (fig. 7) (J. Pitman, written 

commun., 2010). The Eagle Ford in the western portion is 

probably still generating gas. Major gas fields sit within the oil 

window, however, indicating probable updip migration of gas 

through the Austin Chalk or Eagle Ford (Dawson and others, 

1995).

Reservoir characteristics differ from the Austin-TokioEutaw Updip Oil AU with good porosities and generally low 

permeabilities. There is both fracture and matrix porosity 

(NRG Associates, 2007).

Fractures provide the most common traps with anticlines 

and rollover anticlines providing the remainder. Water drive is 

the most common drive type and is present in Masters Creek 

field (Swift Energy Company, 2000) and possibly in some of 

its neighboring shelf-edge fields.

Because this AU is dominated by large fracture systems 

that are associated with the Lower Cretaceous shelf edge, 

undiscovered accumulations are predicted to be larger than 

those in the Austin-Tokio-Eutaw Updip AU where existing 

fields are associated with local faults and salt structures. 

Potential for undiscovered accumulations is moderate to excellent with future discoveries likely to be made in belts both 

updip and downdip of the shelf edge and extending both east 

and west of known accumulations.

Geological Analysis of Assessment Unit 

Probability

The likelihood that this AU contains at least one accumulation greater than the minimum field size of 50 MMBOE is 

estimated to be 100 percent based on the following interpretation of petroleum system elements.

Charge (1.0)

The large number of known and produced accumulations 

in the AU indicates that a sufficient charge is present. The 

Eagle Ford and Smackover are prolific source rocks in the 

region (figs. 6 and 8), with the former likely the most dominant, and both have sourced many accumulations. The Eagle 

Ford oil window lies in the southern portion of the AU, and 

many pathways exist for oil and gas to migrate updip into 

reservoirs in the northern part of the AU (fig. 2).

Rocks (1.0)

Austin Chalk and Eutaw sandstone reservoirs have 

proven to have sufficient reservoir quality to host and produce 

oil and gas. The strata cover the entire AU with thicknesses 

that range from 150 to 1,000 ft. Reservoir quality varies, however, with some regions having higher shale content and lower 

fracture connectivity and density.

Timing and Preservation (1.0)

Fractures associated with the Lower Cretaceous shelf 

edge may have developed soon after Late Cretaceous 

deposition. This predates the time when the Eagle Ford 

entered the oil window, in the early Miocene (fig. 12), which 

allows for the emplacement of oil and gas in the reservoir 

immediately after generation. In the eastern part of the AU, 

salt created the majority of traps, and salt movement likely 

began in the Late Jurassic. This would allow for Smackover 

oil and gas, which began generation in the Early Cretaceous 

(Mancini and others, 2003), to migrate into these traps after 

they formed.

Number of Undiscovered Accumulations

Numbers of undiscovered oil and gas accumulations 

that exceed minimum size were assessed using number of 

discovered accumulations, number of wildcat wells, and 

drilling density (dry holes and producing wells). There are 14 

discovered oil accumulations larger than the minimum size 

in this AU, which means that a mode of 10 accumulations 

would indicate that approximately 58 percent of oil accumulations have been discovered. A minimum of one accumulation 

was chosen because of moderate geologic uncertainty, such 

as number of existing undrilled structures. Approximately 25 

wildcat wells have been drilled in the last 20 years, which may 

suggest the play has potential. A maximum of 40 accumulations would indicate that only 26 percent of oil accumulations 

have been discovered, which also suggests this AU could have 

more potential for accumulations than the Austin-Tokio-Eutaw 

Updip Oil and Gas AU. In this AU, undiscovered accumulations could probably be associated with small salt structures 

and in fracture networks associated with the Lower Cretaceous 

shelf edge; this could yield small (salt structures) to moderate 

(shelf edge) production totals. 

There are only 8 discovered gas accumulations in this 

AU, and a mode of 15 indicates that only 35 percent of all gas 

accumulations have been discovered and that there is more 

potential for undiscovered gas accumulations than oil. This 

is because the highest potential for accumulations is highest 

along the shelf edge that should be mostly gas-prone. This 

is also supported by the fact that a number of accumulations 

discovered in the last 20 years are along the shelf edge. Like 

minimum oil accumulations, the minimum for gas accumulations was set at one. The maximum number of gas accumulations was placed at 60, indicating that only 12 percent of 

gas accumulations have been discovered. Most undiscovered 

accumulations are expected to be near the shelf edge, in or 

near the Eagle Ford gas window. As with oil accumulations, 

undiscovered gas accumulations could also be in relation to 

small salt structures in the eastern portion of the AU.

Sizes of Undiscovered Accumulations

Grown sizes of accumulations were predicted based 

on the distribution and trends with time of historical field 

sizes. Of the ten oil fields discovered in the last 20 years, 

most totaled between 1 and 20 MMBO; however, the median 

grown size of undiscovered oil accumulations was set at 1.5 

MMBO because the larger fields have probably already been 
22 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

discovered. The minimum size was placed at 0.5 MMBO, per 

USGS convention. Only one field discovered in the last 20 

years has yielded more than 20 MMBO, but the maximum 

grown oil size was estimated at 50 MMBO suggesting that one 

accumulation may exist that is larger than everything found 

except for Giddings field, which yields approximately 600 

MMBO.

The median for grown gas was estimated to be 9 BCF, 

which correlates to a median of 1.5 MMBO that was estimated 

for oil, as the volume equivalence for gas to oil is roughly 6:1. 

This indicates that expected sizes of oil and gas accumulations are approximately equal. This median is three times the 

size of the minimum size of 3 BCF, which is the set grown 

size for gas accumulations, per USGS convention. Only two 

fields exceed 100 BCF, and the most recent discovery yielded 

almost 80 BCF. The maximum grown gas size was placed at 

700 BCF, which suggests that the largest accumulation is yet 

to be discovered.

Austin Downdip Gas Assessment Unit (50490132)

AU Description

The Austin Downdip Gas AU lies directly south of the 

Austin-Eutaw Middip AU (fig. 2). Its northern boundary is at 

the inferred downdip extent of fractures that are associated 

with the Lower Cretaceous shelf edge. The western and eastern boundaries are defined by the U.S.-Mexico border and the 

State waters of Louisiana, respectively. The downdip extent is 

defined by the State waters of Texas.

Currently, there is no known Austin Chalk production in 

this AU; as such, estimating production, trap type, and field 

size and distribution is speculative. Faults and fault zones 

are prominent, existing just south of the shelf edge downdip 

toward the Gulf of Mexico (fig. 5). Given certain geologic 

conditions, such as fault timing and oil and gas migration, 

these faults could trap and yield large undiscovered accumulations. Any Eagle Ford-sourced accumulations will likely be 

gas because the entire AU lies south of the downdip extent 

of the Eagle Ford oil window (J. Pitman, written commun., 

2010). Traps are expected to include normal faults and saltrelated anticlines.

Undiscovered accumulations probably exist along 

undrilled growth faults and salt-related structures. As these 

trap types mimic those of the Austin-Tokio-Eutaw Updip 

Oil and Gas AU, one can expect field size and distribution 

to be somewhat similar, though less of this region has been 

explored. Therefore, the potential for undiscovered accumulations is considered to be moderate to high with small to 

moderate field sizes expected. If larger structures exist, such as 

those in the Austin-Eutaw Middip Oil and Gas AU, one could 

then expect correspondingly larger field sizes.

Geological Analysis of Assessment Unit 

Probability

The likelihood that this AU contains at least one accumulation greater than the minimum field size of 50 MMBOE is 

estimated to be 100 percent based on the following interpretation of petroleum system elements.

Charge (1.0)

The large number of known and produced accumulations in the Austin-Eutaw Middip Oil and Gas AU indicates 

that a sufficient charge is present in the region. The Eagle 

Ford has sourced many oil and gas accumulations updip of the 

Austin Downdip Gas AU. However, as the oil window also sits 

mostly updip, accumulations should be dominantly gas. 

Rocks (1.0)

Austin Chalk reservoirs have proven to have sufficient 

reservoir quality to produce oil and gas. The strata cover the 

entire AU with thicknesses that likely range from 150 to 

800 ft. However, as the Austin Chalk within the AU is essentially untested, reservoir quality is uncertain.

Timing and Preservation (1.0)

Normal faults associated with the movement and evacuation of the Louann Salt began moving shortly after salt deposition in the Late Jurassic and movement continued through the 

time of Wilcox Formation deposition (early Eocene). These 

faults in places detach in the Louann Salt and could provide 

traps for oil and gas. This fault movement predates when the 

Eagle Ford entered the oil window, in the early Miocene 

(fig. 12), which allows for the emplacement of oil and gas 

in the reservoir immediately after generation. In the central 

and eastern parts of the AU, salt structures (figs. 5 and 11) 

and their associated fractures and faults create the majority of 

traps. This also allows for the charging of the reservoir with 

oil and mostly gas of Eagle Ford origin.

Number of Undiscovered Accumulations

The number of undiscovered oil and gas accumulations 

that exceed minimum size were assessed using the AustinEutaw Middip Oil and Gas AU as an analog. There are 14 

discovered oil accumulations in that AU, and a mode of 10 

undiscovered accumulations was predicted. A mode of two 

accumulations was predicted for the Austin Downdip Gas AU, 

as oil accumulations should be rare because of the location 

of the base of the oil window. A minimum of one accumulation was chosen for this AU because of considerable geologic 

uncertainty largely owing to a lack of data. A maximum of 

40 accumulations was assessed for the Austin-Eutaw Middip 

Oil and Gas AU, and a maximum of 10 accumulations was 

assessed for the Austin Downdip Gas AU, again due to the 

updip oil window for the most part. In this AU, undiscovered 
Summary 23

accumulations would probably be found along sealing normal 

faults and along salt-related structures.

There are only 8 discovered gas accumulations in the 

Austin-Eutaw Middip Oil and Gas AU, and a mode of 15 

accumulations was chosen for that AU. For the Austin Downdip Gas AU, a mode of 50 accumulations was set because 

much of this region remains unexplored. Like minimum oil 

accumulations, the minimum for gas accumulations was set at 

one because of geologic uncertainty. The maximum number 

of gas accumulations was placed at 60 in the Austin-Eutaw 

Middip Oil and Gas AU; a maximum of 200 accumulations 

was chosen for the Austin Downdip Gas AU indicating that it 

has great potential for gas accumulations. As with oil accumulations, undiscovered gas accumulations would be related to 

normal faults and small salt structures.

Sizes of Undiscovered Accumulations

Grown sizes of accumulations were predicted based on 

the distribution and trends of time of historical field sizes for 

the Austin-Tokio-Eutaw Updip Oil and Gas AU, which was 

used as an analog. Forty-one oil fields have been discovered in 

that AU, and only four totaled more than 40 MMBO. Therefore, the maximum accumulation size for the Austin Downdip 

Gas AU was set at 40 MMBO. The minimum size was placed 

at 0.5 MMBO, and the median was set at 2 MMBO, which is 

double that of the Austin-Tokio-Eutaw Oil and Gas AU. This 

is because the Austin Downdip Gas AU is virtually unexplored, whereas the larger fields have already been discovered 

in the Austin-Tokio-Eutaw Updip Oil and Gas AU, so its mode 

drops to 1 MMBO.

The median for grown gas was estimated to be 12 BCF, 

which correlates to a median of 2 MMBO that was estimated 

for oil because the volume equivalence for gas to oil is 

roughly 6:1. This indicates that expected sizes of oil and gas 

accumulations are approximately equal. This median is four 

times the size of the minimum size of 3 BCF, which is the 

set grown size for gas accumulations, per USGS convention. 

Only two fields in the Austin-Tokio-Eutaw Oil and Gas AU 

exceed 100 BCF, but the most recent discovery yielded about 

15 BCF. The maximum grown gas size was placed at 

240 BCF, which also shows a 6:1 ratio with an oil size 

prediction of 40 MMBO.

Results

The USGS assessed undiscovered, technically recoverable oil and gas resources in the four AUs in the Upper 

Jurassic-Cretaceous-Tertiary Composite TPS (fig. 2) (Pearson 

and others, 2011). For conventional resources, means were 

estimated at (1) 20 million barrels of oil (MMBO), 53 billion 

cubic feet of gas (BCFG), and approximately 1 million barrels 

of natural gas liquids (MMBNGL) for the Austin-Tokio-Eutaw 

Updip Oil and Gas AU; (2) 45 MMBO, 677 BCFG, and 

66 MMBNGL for the Austin-Eutaw Middip Oil and Gas AU; 

and (3) 13 MMBO, 1.6 trillion cubic feet of gas (TCFG), and 

190 MMBNGL for the Austin Downdip Gas AU. The combined conventional resource mean totals for the Austin Chalk 

are 78 MMBO, 2.3 TCFG, and 257 MMBNGL. For continuous resources, the USGS estimated means of 879 MMBO, 

1.3 TCFG, and 106 MMBNGL for the Austin PearsallGiddings Area Oil AU (Pearson and others, 2011). 

Summary

The Upper Cretaceous Austin Chalk is a low-porosity, 

low-permeability reservoir with a dual pore system that relies 

mainly on interconnected fracture networks for production. 

Horizontal drilling enhances these networks to produce oil and 

gas. The Tokio and Eutaw Formations of Arkansas, Mississippi, Louisiana, and Florida are partial age equivalents of the 

Austin Chalk and represent a facies change from an environment of chalk deposition in the west to a sandier, more clasticrich sedimentary environment in the east. 

The downwarping of the Gulf Coast basin during the 

Oligocene and early Miocene created large strike-parallel 

fracture systems in association with faulting and localized 

arching over uplifts. Movement of the Jurassic Louann Salt 

also contributed to fracture genesis where fractures form in 

association with salt-related structures. General proximity to 

faults and fracture-creating structures is critical when analyzing the region’s oil and gas production as well as predicting 

undiscovered accumulations. 

The Eagle Ford Shale is the principal source rock for 

Austin Chalk hydrocarbons and is included in the Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System. 

This marine shale contains dominantly oil-prone kerogen and 

is thermally mature across much of the study area. Source rock 

quality can be inconsistent throughout the region, and some 

reservoirs may contain Jurassic-sourced hydrocarbons.

Generation of hydrocarbons from the Eagle Ford probably started sometime in the early Miocene. Migration of oil 

and gas into the Austin requires only direct upward migration. 

Hydrocarbons that migrated updip likely followed bed-parallel 

routes moving through either the Eagle Ford or the Austin 

Chalk. Hydrocarbons from other sources, such as the Smackover, require much more complex migration routes, such 

as along non-sealing faults associated with salt structures. 

Fracture generation predates the generation and migration of 

oil and gas allowing for the movement of hydrocarbons into 

reservoirs.

There are several trap styles in the Austin Chalk and 

Tokio and Eutaw Formations. Trapping mechanisms strongly 

control accumulation size and distribution where smaller 

localized traps such as fault segments and small salt-related 

structures lead to smaller, more distinct conventional accumulations. Large-scale fracture networks lead to continuous accumulations, and structures, such as broad anticlines, improve 

the production potential of continuous reservoirs.
24 Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast

The USGS conducted an assessment of undiscovered 

resources in the Austin Chalk for the onshore portion and State 

waters of the Gulf Coast region (Pearson and others, 2011). 

The study area was divided into four assessment units (fig. 2) 

that include Austin Chalk and the Tokio and Eutaw Formations (fig. 3). Assessment units were designated based on local 

geology, trap type, production trends, cumulative production, 

estimated ultimate recoveries, reservoir characteristics, and 

whether a region produces oil and gas in conventional or continuous reservoirs. 

Based on these criteria, undiscovered accumulations were 

assessed (Pearson and others, 2011). Undiscovered resources 

in the updip region of the study area are expected to have low 

resource volumes with few new field discoveries. The middip region probably has low to moderate potential for undiscovered hydrocarbons because much of the shelf edge area 

remains unexplored. Field sizes are expected to be moderate 

with the potential for many new field discoveries. In the 

downdip portion of the study area, the potential for undiscovered gas accumulations is moderate to high with small to 

moderate field sizes expected. The Pearsall-Giddings region 

(figs. 13 through 15) was assessed as a continuous accumulation. Future production may expand outside the sweet spot if 

additional fractures exist or may be limited to infill drilling if 

good fracture permeability does not exist outside this sweet 

spot. Overall, this AU has moderate to high potential.

Acknowledgments

I would like to thank Russell Dubiel, Ron Charpentier, 

Tom Judkins, and Dick Keefer for their constructive reviews. 

Chris Schenk, Troy Cook, and Tim Klett also greatly contributed to the assessment process.
References Cited 25

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Publishing support provided by: 

Denver Publishing Service Center

For more information concerning this publication, contact: 

Center Director, USGS Central Energy Resources Science Center 

Box 25046, Mail Stop 939 

Denver, CO 80225 

(303) 236-1647 

Or visit the Central Energy Resources Science Center Web site at: 

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Pearson—Undiscovered Oil and Gas Resources—Upper Cretaceous Austin Chalk, U.S. Gulf Coast—Scientific Investigations Report 2012–5159