Finding the right hydraulic fracturing method is key for unlocking the unconventional gas resources contained in the Lower Pennsylvanian Bend group sands and shales of the Palo Duro basin in West Texas.
One company trying to exploit this potential is Bankers Petroleum Ltd., a Calgary-based oil and gas exploration and production company.
The company has acquired under lease about 260,000 net acres from Vintage Petroleum LLC and plans to increase this to 300,000 net acres.
Palo Duro basin
The Palo Duro basin is about 260 miles northwest of the Fort Worth basin Barnett shale play. Improved fracture stimulation technologies transformed the Barnett shale into the largest producing natural gas field in Texas, estimated to contain 1 tcf of recoverable gas in the 45,000-acre core area. Table 1 compares the Palo Duro basin with other organic shale areas. Bankers says the Palo Duro basin gas play currently encompasses four counties: Briscoe, Floyd, Motley, and Hall. The play targets Pennsylvanian-aged shales that are at 7,000-10,500 ft depths.
The entire Palo Duro basin covers 22,700 sq miles in the Texas Panhandle, eastern New Mexico, and Oklahoma. North of the basin is the Amarillo uplift, to the south is the Matador arch, and to the east and west are minor structural highs that separate it from the Hardeman and Tucumcari basins.
The central portion of the province does not currently produce oil or gas in commercial quantities, but Bankers says production does exist along the Matador arch, as well as along the northern border south of the Amarillo uplift in Mississippian, Pennsylvanian, and Permian rocks.
Basin assessment
To date, several companies have drilled wells in the basin and Bankers expects that it will be another 9-12 months before it ascertains the viability of the basin for producing gas.
Bankers says the discovery well for the Bend group was the Cogdell well drilled by Legacy Petroleum Corp. in mid-2003 (Fig. 1). The well, completed in the Bend group in three intervals including some sands, was stimulated with small fracture treatments in each interval. The reported combined flow rate was 2.8 MMcfd.
Bankers believes this 3-day test was insufficient to asses the well and has used this test only to confirm that the basin contains producible hydrocarbons. The well was subsequently shut-in for more than 400 days while the property changed hands.
Upon reentry, the new operator, Vintage Petroleum LLC, needed to swab water from the well and found that a bridge plug isolating the Bend group from the Morrow sands had failed. Bankers believes water from the Morrow covering the productive perforated interval had damaged the reservoir and was the cause for the zone producing only 60-120 Mcf after it was isolated with a new bridge plug and cleaned up.
Another well is the area is Echols, for which one estimate indicates that the gas in place is 130 bcf/section. Echols was Vintage’s first follow-up well and was fracture stimulated in the Bend group.
Bankers says flow back showed some crushed proppant frac sand and black sludge determined to be Magnetite, apparently caused by a reaction of the frac fluid with the minerals in the reservoir. Bankers currently is analyzing and trying to reverse engineer what reaction took place so as to prevent such reactions in the future.
Even with these problems and after partial recovery of the frac fluid the well slowly started to produce gas, which increased to 120 Mcfd as more of the frac fluids were recovered. Gas flow stopped as water entered the casing at about 4,500 ft, about 3,500 ft above the Bend group completion. A cement squeeze failed to shut in the water, and Bankers attributes the failure to the difficulty of doing squeeze jobs in 5½-in. casing.
The Burleson Ranch well is another Vintage drilled well with an estimated gas in place of 130 bcf/section. Vintage fracture stimulated the Bend group but also pumped 2,000 bbl of acid ahead of the frac.
Bankers says the mineralogy from logs and cores indicates that the zone has much pyrite and chlorite that would have reacted badly with the acid. The well did produce some gas after a substantial amount of frac fluid was recovered during 3½ months. Production increased to 24 Mcfd before the well was shut in due to the sale of Vintage.
Tyner Resources Ltd.’s Tyner Stephens well, with an estimated 116 bcf/section in place, is the most successful well to date in the area. A Tyner press release says that after fracture stimulation the Bend shale produced between 400 Mcfd and the absolute open flow of 1.5 MMcfd, after recovery of 2,300-4,000 bbl of frac fluid.
The current gas flow is 340 Mcfd at a 40-psi wellhead pressure and 1.15 Mcfd at 12 psi. Tyner says the well was perforated in a 150-ft vertical section with four 12-ft sections in the primary Bend group target. The lower 12-ft section penetrated a sand interval that was not fraced to ensure that no fracture stimulation energy was dissipated in the sand, according to Tyner.
The company’s reentry program isolated the shale perforations and monitored a flow test of the shale for 4 days, while implementing a low-pressure pipeline simulation at the surface. Tyner says the isolated shale zone flowed 250 Mcfd of 1,400-btu gas without any production decline during the test.
Tyner expects to meet pipeline-btu gas specifications by stripping off about 28 bbl of NGL at the pipeline connections. The test also yielded 20 bo/d.
The lowest perforation in the sand interval produced 200 Mcfd also of 1,400-btu gas. Tyner expects this sand interval, when successfully fraced, to produce an additional 0.8-1.4 MMcfd.
Tyner fraced its Broseh well with 804 bbl of KCl treated water, 1.36 MMcf of nitrogen, and 82,405 lb of Carobilite 20/40 sand. Perforations screened off while pumping 3-ppg sand, leaving 51,405 lb of sand in the formation.
Since completing the frac, Tyner says the well has recovered 1,100-1,500 bbl of frac fluids and after a 48-hr shut-in, the wellhead pressure was 1,100 psi, while after 12 hr it was 480 psi. The pressure blows off in 4 hr with an open choke.
The company is swabbing 40-45 b/d of fluid and experiences shut-in pressure increase daily, with a good gas blow after each swab run.
Bankers currently is evaluating various stimulation designs for its Misener well because the well is slightly different from other wells in that it is more fractured. The well has one to two fractures/ft throughout the Bend group. A Schlumberger FMI log shows that these are fairly large ½-1 mm fractures.
Bankers plans to stimulate and test the Granite Wash sands and the Bend shale in this well separately. The deepest Granite Wash sands tested have shown little water. These are 600 ft below the identified Bend shale test interval.
Bankers may use gelled-diesel fracs, straight slickwater fracs, as well as cross-linked gelled-water fracs for stimulating this well.
It plans to restimulate the Cogdell well after stimulations in the Misener well. Along with the original tested interval in the Cogdell well, Bankers also will test what it considers the sweet spot in the shale in this well.
After Cogdell, Bankers will move to its Jones No. 1 well that it drilled to test the Bend shale.
Bankers says that by pursuing this basin methodically and scientifically and acquiring knowledge from the previous stimulations and tests, it will find a way to produce gas from the basin economically.
