Preliminary Analytical Results:
Haynesville Shale in Northern Panola County, Texas
Chris Bresch and James Carpenter
R. Lacy Services, LTD., 222 E. Tyler St., Longview, Texas 75601
As part of a preliminary evaluation program, Lacy Operations drilled three vertical Haynesville Shale wells positioned over a west-east expanse of 6.5 mi, 8 mi north of Carthage, Texas. The top of the Upper Jurassic Haynesville Shale lies at drilling depths ranging from 10,352 ft to 10,702 ft. The average thickness of the Haynesville Shale is 475 ft. The average Horner corrected temperature at the midpoint in the Haynesville Shale is 271 deg. F, corresponding to an average present-day geothermal gradient of 2.055 deg. F / 100 ft. Tmax values from whole cores range from 484 to 504, indicative of the dry gas window. The Haynesville Shale has TOC (total organic carbon) values between 2% and 4% with a 3% (wt) average (based on side wall core analyses), indicating an initially rich Type II kerogen source rock. Prior to maturation the Haynesville Shale would have had a significantly higher average TOC and high HI (hydrogen index) values. Favorable burial and thermal conditions caused most of the kerogen source potential to be converted to hydrocarbons and dead carbon (see Figure 1; notice low HI values). If one assumes a normal geothermal gradient (1.4-1.7 deg. F / 100 ft) at the time of maximum thermal exposure, then the Haynesville Shale experienced paleo-burial greater than ~18,000 ft—probably during the Cretaceous—with a corresponding paleo-temperature greater than ~360 deg. F. Of course there is great uncertainty, but the data suggest more than 7,500 ft of overburden has been removed.
Both rotary side wall cores and conventional 90 ft cores were cut for laboratory analyses. The conventional cores targeted the lower one third of the shale. Visual observations of cores show the Haynesville Shale to have consistency and color similar to charcoal, often with poker-chip partings. Visual healed calcite fractures have been observed in some of the SEM (scanning electron microscopy) photos taken of the cores. Maturation increases brittleness, can result in overpressuring, microfracturing and converts kerogen to dead carbon, reducing occlusion of porosity and increasing permeability. Dead carbon also contributes to reservoir capacity through gas adsorption. Uplift/removal of overburden may also lead to expansion-induced microfracturing.
A full suite of wireline logging was performed on the three vertical Haynesville wells, including a Quad Combo, sonic, and mass spectroscopy analysis tool. The results from the sonic log reveal that the Haynesville is fairly isotropic with an average fracture gradient of 0.91 psi/ft and a preferred maximum stress orientation of approximately N76°E. Using the mass spectroscopy tool the elemental composition of the Haynesville is divisible into two main components. The lower two thirds of the Haynesville consists of shale (average <40% rock volume), mainly illite and marginal amounts of montmorillonite, along with calcite and quartz clastic material that occupied the majority of the remaining rock volume. The upper one third of the Haynesville is more ductile due to its increase of argillaceous material. Total porosity and permeability is lower, making this upper portion of the reservoir a lower priority at this time. Results from the SEM analysis show that the calcite component mainly consists of bivalve fragments, pellets, rhombohedral masses, coccoliths and diagenetic calcite filled fractures. SEM results also show that the occurrence of quartz can be attributed to remnant silt size detrital grains, diagenetic siliceous nodules along with the replacement of calcite in both fossil fragments and microfractures. Figure 2 is an SEM image of the Haynesville Shale reservoir, and Figure 3 shows an ammonite cast fossil from one of the conventional cores.
In the quality portions of the shale reservoir the effective porosities range between 6% and 10% with permeabilities of 300 to 600 nanodarcies. Lacy Operations decided to run existing data through rock mechanical modeling processing to help determine where the rock is most brittle and where the optimum fracture aperture width could be obtained. The results indicate that the stimulation should concentrate on intervals of higher silica content where both fracture conductivity and width would be maximized.
Bresch, C., and J. Carpenter, 2009, Preliminary analytical results: Haynesville Shale in northern Panola County, Texas: Gulf Coast Association of Geological Societies Transactions, v. 59, p. 121-124.