Ali Trabelsi
Independent geological consultant
Lubbock, Tex.
Canyon sands are Upper Pennsylvanian deposits found in the Val Verde basin and on the Permian Basin eastern shelf, Texas (Fig. 1), and occur in a thick clastic sequence overlying the Strawn limestone.
These sandstones are considered to have been deposited during Missourian time and are formally named after the Canyon group deposited on the eastern shelf.
The Canyon sand has provided commercial gas production for over 30 years.
Canyon gas reservoirs, occurring at depths of 2,000-8,000 ft, have yielded almost 2 tcf of gas.1 The area of this producing sand covers more than 10 counties in south central Texas. 2
DEPOSITIONAL
ENVIRONMENTS, LITHOLOGY
In the eastern part of Edwards County, Tex., relatively thick intervals of Canyon sand represent prograding deltaic deposits and consist of stacks of lenticular beds. In general the most prolific gas areas coincide with the local and/or regional distribution of sandstone (e.g., point bars, stream mouth bars, and channels).
Coal beds up to 30 ft thick (Fig. 2) occur in the eastern part of Edwards County (e.g., blocks P, P 1/2, VA, and E). These coal beds possibly represent ancient marshes and swamps, some of which cover more than 22,000 acres. No commercial gas has been produced from these coal beds.
In the Val Verde basin (Val Verde, Sutton, and western Edwards counties, Tex.) conventional cores obtained from the 1 and 3 Berger wells in Sutton County and the 10 Shanklin well in Edwards County display a suite of sedimentary structures, facies associations, and biogenic features indicative of deposition by turbidity currents.
In this area Canyon sands represent stacks of prograding submarine fans. Sedimentary structures exhibited by cores include parallel laminae, small scale cross bedding, graded beds, climbing ripples, load structures, rip up clasts (Fig. 3), microfaults, and occasional sand dikes. Biogenic characteristics include deepwater trace fossil assemblages (Scolicia and Palaeodicton), mixed assemblages of shallow and deepwater fauna, and debris of carbonized plant fragments.
Hamlin et al.3 indicated that in western Sutton County, Canyon Sands comprised coalesced submarine forming systems forming a slope apron. Deltaic sandstones occur locally along the shelf margin, shales cover most of the outer shelf.
On the upper slope, channel fill sandstones are discontinuous at 0.5 1.5 mile well spacing and are enclosed in thick slope shales. Fan lobes that include a proximal channelized part and a distal thin bedded part are best developed on the lower and adjacent basin floor.
In Edwards County Canyon sand is mostly fine to moderately fine grained sublitharenites and litharenites according to rock grain content. Estimated quartz content ranges from 77 85% Rock fragments consist of limestone, siltstone, and shale clasts, quartzites, phyllites, and slates.
Detrital clay occurs in Canyon sands as shale laminae, rip up clasts, and wisps (Fig. 4). Clay grains are ubiquitously present in amounts reaching more than 20% of the rock matrix.
Jacka4 suggested that detrital clay grains may have been deposited as coarse clay floccules or could represent granular size particles that resulted from breaking of mat like segregations that normally formed wisps. Limestone clasts were derived from lithified limestones that probably outcropped on the shelf during low stands of sea level.
RESERVOIR DESCRIPTION
Data used in the reservoir characterization of the Canyon sand are derived from three wells in Epperson field in Edwards County.
Canyon sand is a tight reservoir. Horizontal permeability for shaly sandstone measured from cores is less than 0.1 md (about 0. 06 md). Most permeable streaks within clean sand intervals average 1.2 md.
Measured effective porosity (based on core and log analysis) of Canyon clean sandstone intervals reaches up to 10%. Most of the porosity, is classified as intergranular. Porosity is probably formed from leaching of feldspar grains and clay clasts.
The producing intervals in the Canyon sands vary from clean sand to shaly sandstone (registering up to 65 APIU on the gamma ray log).
In general, productive sand and shaly sandstone intervals produce gas with a small amount of water. However, there are instances where some Canyon clean sandstone intervals with better porosity and permeability contain large amounts of water (wet zones). Hence, gas cannot be commercially produced from these sandstones.
A good example of such a nonproductive sand interval occurs in Epperson and Rocksprings West fields in Edwards County. A clean sand interval about 75 ft thick occurring at a relatively shallow depth (2,000 2,400 ft) is permeable and has about 12% porosity; however, this interval contains large amounts of water (water saturation is about 70%).
DIAGENETIC CEMENTS
The predominant cements in Canyon sand are quartz overgrowth and siderite.
Quartz overgrowth is predominant in all sand intervals except wherein siderite films are well developed and dense, forming rims around quartz grains (Figs. 5, 6) to preclude significant precipitation of quartz overgrowth.
Other cementing diagenetic minerals occur only in trace amounts. These cements include calcite, dolomite chlorite, dickite, and albite.
Hamlin et al.3 reported that the highest porosity in Canyon sandstones occurs in association with abundant siderite, and my petrographic examination of hundreds of Canyon sandstone thin sections supports this finding.
Hamlin et at. indicated that siderite cement formed soon after deposition and hence provided siderite cemented sandstone intervals with a rigid framework so that loss of porosity by mechanical compaction and occlusion of intergranular porosity by the precipitation of quartz overgrowth 3 during burial was arrested.
RESERVOIR SIMULATION
Because of the low permeability of the Canyon sand, this sand requires acidizing and hydraulic fracture stimulation treatment to produce gas at economic rates (500-800 Mcfd/well).
Acid solubility tests show that Canyon sandstone cemented with quartz overgrowth has a maximum acid solubility of 5.35% in 15% HCI and 25.5% in 12:3 regular mud acid (RMA). Test on Canyon clean sandstone samples cemented with siderite shows that these samples have a maximum acid solubility of 19.4% in 15% concentrated HCI and 36.6% in regular 12:3 RMA.
Based on these tests it is clear that RMA is preferred in acidizing the Canyon sand pay zones. The fluids used in fracture simulation treatments vary widely and include gelled oils, 3% gelled acid, linear gelled water, crosslinked gelled water, and foams of either carbon dioxide or nitrogen.
In the past the degree and the design of stimulation, including the type of fracturing fluid, has been a judgment call at best. A case study of 28 hydraulically fractured wells in Edwards County was conducted to determine the actual effect of gelled and foamed fluids on well performance. A comparison of post frac well production indicates that eight wells treated with 75% quality nitrogen foam have performed much better tha the other 20 wells treated with gelled fluids (encapsulated breaker gel).
The use of 75% quality nitrogen foam allows the pumping or emplacement of less gelling agents into a tight and low pressure reservoir such as the Canyon sand. Nitrogen also energizes the reservoir and helps in the cleaning or the recovery of the frac fluids much faster. Pferdehirt et al.2 indicated that foamed fluids may leave behind almost no measurable residue. The gelling agents commonly used in hydraulic fracturing treatments possess molecular sizes too large to penetrate into the matrix of low permeability formations.4
TRAPS
The hydrocarbon trap styles of most of the fields in Edwards County Rocksprings West, Epperson, Sawyer, and Campanero are either combination types (stratigraphic and structural) or stratigraphic (both lithofacies and porosity permeability pinchouts).
In Epperson and Rocksprings West fields the majority of gas production is from stacks of several point bars that occur at 1,800 3,000 ft. Production from some wells in these fields can exceed 2 MMcfd of gas.
During air drilling of these productive point bars, gas flares that range from 50 80 ft are encountered. The height or size of these flares serves as a natural drillstem test. In conjunction with the gas kicks and crossovers these flares constitute strong criteria in identifying optimum pay zones for completion and production.
The ability to explore for other possible Canyon sand gas plays or fields in the Val Verde basin and eastern shelf can be increased by detailed subsurface mapping and understanding of regional and structural and depositional architecture of the Canyon group.
Good quality seismic data in the area, especially 3D, with other geophysical tools also can greatly help in discovering new Canyon sand gas plays that can be profitable for intermediate and small gas companies.
ACKNOWLEDGMENTS
I thank M. Soheili and A. Abbas for their help during preparation of this manuscript. I also thank M. Foukar for his support.
REFERENCES
- Bebout, D.G., and Garrett, C.M., Jr., Upper Pennsvlvanian and Lower Permian slope and basinal sandstone, in Kosters, E.C., and others, Atlas of major Texas gas reservoirs, Universit%. of Texas at Austin, Bureau of Economic Geology,, 1989, pp. 116 118.
- Pferdehirt, D.J., Brown, J.E., and Rucker, L.R., New stimulation techniques improve Canyon sand gas production: a case study,, SPE 20133, 1990, pp. 391 400.
- Hamlin, H.S., Cliff, S.J., and Dutton, S.P., Stratigraphy and diagenesis of Sonora Canyon deepwater sandstones, Val Verde basin, Southwest Texas, University of Texas at Austin, Bureau of Economic Geology, 1992, pp. 209 220.
- Jacka, personal comniunication, 1991.
- Brannon, H.D., and Pulsinelli, R.J., Breaker concentration, required to improve the pcrmeability of proppant packs damaged by concentrated linear and borate crosslinked fracturing fluids SPE 20135, 1990, pp. 409 416.
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