Tuscaloosa marine shale may be untouched Gulf Coast oil play

Chacko J. John Bobby L. Jones Reed Bourgeois Brian J. Harder
Louisiana State University
Baton Rouge
James E. Moncrief
Consulting Geologist
Lafayette, La

The Tuscaloosa marine shale section lies between sands of the upper and lower Tuscaloosa sections and varies in thickness from 500 ft in southwestern Mississippi to more than 800 ft in the southern Florida Parishes of southeastern Louisiana (Fig. 1 [64,867 bytes]).

The primary zone of interest, a high log resistivity (5 ohms) zone at the base of the above referenced shale section, varies in thickness from zero to 325 ft over the area and is found at the shallowest depth of about 10,000 ft in the study area.

Two wells are known to have produced from the marine shale in southeastern Louisiana, with one having produced over 20,000 bbl of oil the past 19 years.

Preliminary evaluations indicate that the Tuscaloosa marine shale may contain a potential reserve of about 7 billion bbl of oil. Horizontal drilling could maximize production and minimize environmental impacts.

Until this study by Basin Research Institute at Louisiana State University, no information had been published on the Tuscaloosa marine shale as regards its potential as a significant hydrocarbon resource.

Stratigraphy

Sands and shales of the Tuscaloosa Group (Fig. 2 [29,113 bytes]) are over 1,000 ft thick1 and represent a complete depositional cycle.² The study area comprises the Florida Parishes and the counties of Southwest Mississippi and extends westwards through central Louisiana to the Texas line.

It is generally located between the Cretaceous and Wilcox production in north Louisiana and southern Mississippi and the Miocene production in South Louisiana.¹ The Tuscaloosa in this area also represents the lowest formation of the Gulfian Cretaceous series.³

The Tuscaloosa Group is comprised of three units. The lower Tuscaloosa represents a transgressive stage of the depositional cycle² and consists of an arenaceous and argillaceous lower unit represented on the stratigraphic chart (Fig. 2) as the massive sand and the stringer sands.

The marine shale forms the middle Tuscaloosa unit and represents the inundated phase of the depositional cycle. The marine shale is mostly gray to black, fissile and sandy at some locations thickening downdip. In McComb field, Pike County, Miss., the marine shale is 500 ft thick increasing to 800 ft in south-central Washington Parish, La.

The upper Tuscaloosa sands and clays represent the regressive phase of the depositional cycle. It is difficult to distinguish the upper Tuscaloosa from the overlying Eutaw formation due to their lithologic similarity.¹

Previous work

The purpose of this article is to bring industry attention to what may be a very significant potential reserve of hydrocarbons contained in the Tuscaloosa marine shale (TMS).

Operators and drillers have long known the TMS to contain oil and gas under sufficient pressure to release them into the mud and/or onto the pits, occasionally with attention-getting pressure, but not much progress has been made or much interest shown by industry in evaluating and testing the TMS.

One of the earliest geoscientists who noted TMS hydrocarbon potential was the late Alfred C. Moore.⁴ He wrote in unpublished notes in 1969 that the TMS was believed to be the "source bed" for most of the underlying lower Tuscaloosa oil trapped in sand bars draped over and around structural highs between Brookhaven (Lincoln County) and Gillsburg (Amite County) oil fields.

Moore evaluated over 50 dry wells in the general area and concluded that the TMS was fractured and that the fractures were interconnected. He also stated that there was significant fracturing of the TMS, probably by pressure increases from oil generation. Meissner⁵ believed that overpressuring from oil generation in the Bakken shale is related to the vertical fracturing.

Moore's unpublished records, provided by Dwight "Clint" Moore, his son, also contained core information from the Callon Petroleum 2 Cutrer well, in 55-1s-7e, Tangipahoa Parish, La. The analysis of 110 section plugs from the cored interval 11,550-653 ft showed a range of figures from lowest to highest, as follows:

Permeability from less than 0.01 to 0.06 md;
Porosity from 2.3-8.0%;
Oil from 0.7-4.3 vol %;
Gas from 0.2-1.3 vol %;
Water from 31.8-88.2%.

While the permeability and porosity figures appear to be quite low, this is the well that produced some 2,500 bbl of oil from the TMS from perforations at 11,584-644 ft. The cores were predominantly described as silty shale and sometimes calcareous.

The information also contained lithologic descriptions of cores from the Sun 1 Spinks well, in 7-2n-7e, Pike County, Miss., in the TMS section at 10,750-11,067 ft. The upper 120 ft of the core was described as shale, with the section below being shale and siltstone with cross-bedding and fracturing, with oil shows. On Dec. 1, 1971, Moore (unpublished notes) wrote:

"Visible fractures containing live oil are apparent in the diamond cores commencing at 10,940 ft. Frequency of the fractures increases steadily with depth and are most extensive between 11,000 ft and 11,055 ft (40% of diamond core lengths contain visible fractures)."

This information would indicate some enhanced porosities and permeabilities in areas where fracturing may be present. Obviously, more fracturing would be expected in areas of stress where folding, faulting, or movement of the shale may have occurred. It would appear that none of the wells produced or tested and are located on proven structures, so it is suggested that locations at or near the apex of the structure may have considerably greater fracturing.

Moore, in his 1970-74 unpublished notes, observed from his evaluation of wells in the area penetrating the TMS that they generally had an abnormal pressure of 6,200 psi in the TMS, whereas the normal pressure for the upper and lower Tuscaloosa in the area ranged from 4,400-5,200 psi.

Drillers of wells in the area increased mud weights to create a hydrostatic pressure equal to 6,200 psi while drilling through the TMS section in order to prevent blowouts. Moore was of the opinion that wells completed in the TMS would be capable of commercial oil production. He estimated that the geographic area commencing in western Washington Parish and extending through northern Tangipahoa, southern Pike, northern St. Helena, southern Amite, northeast Feliciana, and southern Wilkinson was underlain by the TMS "Fracture Fairway" covering about 750,000 acres based on isopach and subsurface studies.

Moore in 1974 estimated the recoverable reserves from the TMS to range from 3-10 billion bbl of oil. Later, in 1978, he revised and increased his estimate of area to be over 1 million acres. In his calculations he used an average thickness of saturated rock of 160 ft, which computed to 160 million acre-ft. He also used an oil in place estimate of 300 bbl/acre-ft, which computed to 48 billion bbl of oil in place in the TMS. He believed that at least 5% of oil in place could be recovered by present and near future technology.

Jones and Moncrief (co-authors of this article) had also carried out preliminary investigations of the occurrence of hydrocarbons in the TMS zone prior to becoming knowledgeable of Moore's earlier work. They determined that the overall shale interval between sands of the upper Tuscaloosa and those of the lower Tuscaloosa section varies from about 500 ft at McComb field, Miss., to more than 800 ft in central Tangipahoa Parish, La.

The primary zone of interest bears high log resistivity (5+ ohms), a fact also noted by Moore, and lies at the base of the above referenced shale section and varies from zero to 325 ft in thickness over the prospective area of interest. Both these investigations (i.e., Moore and Jones & Moncrief) independently confirm the resource potential of the TMS and the viability of commercial production from it.

Schmoker and Hester⁶ studied log formation resistivities in the upper Devonian-lower Mississippian Bakken formation of the Williston basin, North Dakota. They concluded that an abrupt resistivity increase on the electrical logs was an indication of oil generation and was not due to change in the physical properties of the shale.

Marine shale

The writers in this study have tried to generally delineate the location and depth of the TMS within the study area (Fig. 1) and determine more specifically where the shale shows electrical log characteristics (higher resisitivity) that make it of potential commercial value.

The type log and standard used for this study were from the Texas Pacific Oil Co. 1 Winfred Blades well in Tangipahoa Parish, La. (Fig. 3 [109,166 bytes]). This is the only well producing oil from the TMS. The well has produced more than 20,000 bbl of oil with no water from selective perforations at 11,073-644 ft since completion in 1978.

Schlumberger log analysts believe the oil is primarily coming from the higher resistive section at 11,460-645 ft. Current owners said the well is producing 1.2-2 b/d of oil with no water.

The second well to have some production from TMS is the Callon 2 Cutrer, in 55-1s-7e, about 7 miles northwest of the Texas Pacific 1 Blades and about 7 miles east-southeast of Gillsburg field, Amite County, Miss. It encountered the top of TMS at 11,520 ft measured depth and was perforated at 11,544-678 ft. It produced about 2,500 bbl of oil from TMS before being plugged in 1991.

We examined and correlated hundreds of electric logs from the 1940s to recent. High resistivity (5 ohms or more) or a dramatic increase in resistivity (3.5 ohms or more) required consideration. In determining net thicknesses, high resistive sections that were not separated by more than 20 ft of low resistive shales were counted.

There seems little doubt that the highly resistive section of the TMS is hydrocarbon laden. It is also obvious that some permeability and porosity exist, but how much of each would be of great importance in dealing with economic aspects. Unfortunately, little is known about porosity and permeability of the TMS. Basically our knowledge is limited to knowing that two wells produced enough volume of oil to warrant attention, and the information available from well logs or cores.

To determine TMS regional extent, we constructed a west-east strike section S-1 (Fig. 4 [62,002 bytes]) and seven north-south dip sections D-1 to D-7 (Fig. 5 [47,644 bytes], Fig. 6 [47,926 bytes], Fig. 7 [49,736 bytes], Fig. 8 [52,700 bytes], Fig. 9 [42,961 bytes], Fig. 10 [42,226 bytes], Fig. 11 [40,979 bytes]).

D-1 reflects the regional updip thinning of the resistive TMS in northern Washington Parish, its downdip thickening to 100 ft towards the south in Washington, and then a regional downdip fading of the section farther south in Tangipahoa Parish (Fig. 5). Along D-2 the lower resistive TMS section has a maximum thickness of 185 ft in southwestern Tangipahoa Parish and thins to 9 ft in Pike County, Miss. (Fig. 6). It dips from 10,225 ft in Pike County to 12,155 ft in Tangipahoa Parish.
D-3 traverses what may be considered "the heart of the potentially productive area" (Fig. 7). The thinnest part of the TMS section here is about 65 ft and is found at the north end of the cross-section in Amite County. It thickens to more than 220 ft so the south.
D-4 traverses the "golden trend" of good, thick, resistive TMS section (Fig. 8). The Humble Oil & Refining Co. well in Adams County, Miss., cut a thick 135 ft resistive TMS section at 10,100 ft, shallower than in most other areas. The thickest resistive TMS section of 305 ft is seen in the Pennzoil 1 Laborde well in Point Coupee Parish at 16,190 ft.
D-5 fairly well demonstrates our belief that shale encountered above 10,000-10,500 ft does not have resistivity necessary to indicate hydrocarbon content in the study area (Fig. 9). The resistive TMS section thins towards the north end but thickens towards the south.
D-6 shows the beginning of the overall thinning of the Eagle Ford-TMS section in the western study area (Fig. 10). The resistive TMS section is missing (not developed) in some wells on this cross-section.
D-7 again shows the thinning of the overall interval of the Eagle Ford to the TMS section, possibly influenced by the Sabine uplift to the north (Fig. 11). Another notable factor is the lower resistivity demonstrated at the base of the section in comparison with wells farther east in the study area.

The TMS has for many years and by many geologists been thought to be the "source rock" for the production from the Tuscaloosa sand reservoirs. This has been substantiated by geochemical analyses of oil from two wells in the study area, the Canadian Delta (formerly Norcen) A-1 Calhoun (upper Tuscaloosa sand) at Gillsburg field, Amite County, Miss., and the Longleaf (formerly Texas Pacific) 1 Blades well at Silvercreek field, Tangipahoa Parish, La. DGSI, Houston, performed the analyses for LSU Basin Research Institute. Echols⁷ provides a more detailed discussion of the geochemical analyses.

Reserve potential

Well logs have shown an average thickness of 93 ft of prospective TMS section within the 50 ft net resistive TMS contour. If this figure is used as a lower average thickness limit of the shale and if even only 40% of the resistive TMS section has fracture induced porosity and permeability, then there would still be a net effective section of about 37 ft that could potentially yield hydrocarbons.

If fracturing is not widespread and-or if porosities are low, then a conservative figure of 50 bbl/acre-ft could probably be assumed. Since the shale section within the 50 ft thickness contour covers an area of about 5,900 sq miles or 3,776,000 acres, it potentially could produce about 7 billion bbl of oil.

Using the horizontal drilling available today, it probably would be feasible to drill a carefully planned horizontal well in the TMS section. Such a well would increase the possibility of commercial production from the TMS and result in a significant increase in the recoverable reserves that could not have been technically or economically obtained with traditional vertical drilling.

Acknowledgments

The authors thank Dwight C. Moore; Larry Day and Gerald Howell of Longleaf Oil & Gas Co.; and Whitney Pansano of Canadian Delta Inc.

References

Howe, H.J., Subsurface geology of St. Helena, Tangipahoa, Washington, and St. Tammany parishes, La., GCAGS Transactions, Vol. 12, 1962, pp. 121-255.
Spooner, H.V., Jr., Basal Tuscaloosa sediments, east-central Louisiana, AAPG Bull., Vol. 48, 1964, pp. 1-21.
Forgotson, J.M., The basal sediments of the Austin Group and the stratigraphic position of the Tuscaloosa formation of Central Louisiana, GCAGS Transactions, Vol. 8, 1958, pp. 117-125.
Moore, Dwight "Clint," personal communication, 1997.
Meissner, F.F., A geological-mechanical basis for creating fractured reservoirs in the Bakken (abs.), in W.B. Hansen, ed., Geology and horizontal drilling of the Bakken formation, Montana Geological Society, Billings, Mont., 1991, p. 165.
Schmoker, J.W., and Hester, T.C., Formation resistivity as an indication of oil generation, Bakken formation of North Dakota and Woodford shale of Oklahoma, Log Analyst, Vol. 31, 1990, pp. 1-9.
Echols, John B., Geochemical analyses of Tuscaloosa oils, Basin Research Institute Bull., Vol. 7, 1997, pp. 23-24.

Adapted and condensed from an article published in Basin Research Institute Bulletin, Louisiana State University, August 1997.

The Authors

Chacko J. John is director of the Basin Research Institute and acting director and state geologist of the Louisiana Geological Survey, Louisiana State University, Baton Rouge. Previously he worked with Marathon Oil Co. at Lafayette and Houston as advanced geologist from 1980-86. He holds MS and PhD degrees in geology from the University of Delaware, Newark, Del., and BSc and MSc degrees from the University of Nagpur, India.

Bobby L. Jones is an oil and gas consultant in Baton Rouge. He began his career as a geologist with the Louisiana Department of Conservation and was later employed with the Office of Mineral Resources, Louisiana Department of Natural Resources, where he retired as chief geologist. He received his BS degree in geology from LSU.

James E. Moncrief has been a consulting geologist and independent operator since 1959, having operated wells in several states, with major concentration being in the Gulf Coast Province of South Louisiana. He holds BS and MS degrees in geology from LSU.

Reed Bourgeois is a computer analyst at Basin Research Institute, LSU. He has a BS degree in business from Nicholls State University, Louisiana.

Brian J. Harder is a research associate at Basin Research Institute. Before joining LSU in 1987, he worked for Gearhart Industries as an engineer in Oklahoma, North Texas, North Louisiana, and Mississippi. He has a BS degree in petroleum engineering from LSU.