A scientific approach heavy on data and analysis has driven the successful effort of Battlecat Oil & Gas to develop unproven Eagle Ford acreage outside the core of that prolific Texas shale play. Andrew Fisher, a company engineer, gave a detailed presentation recently to the SPE Gulf Coast Section’s Houston Northside Study Group on the technical and economic data behind Battlecat’s highly productive Bobcat No. 1 oil well in Gonzales County.
The Bobcat well came on stream in the second half of 2015 at an initial production rate of 375 B/D with an estimated ultimate recovery (EUR) level of 317,000 bbl. Completed horizontally with a hydraulically fractured 4,400-ft lateral section, Bobcat No. 1 ranked as the top EUR well in Gonzales County, per normalized lateral foot, at true vertical depths of 8,000 to 9,000 ft. The well ranked third in initial 6-month cumulative production with an output of 50,000 bbl.
Attracted by the outstanding well results being reported in the Eagle Ford,
Battlecat evaluated the potential for entering the play during 2014. With lease prices ranging from USD 20,000 to 30,000 per acre in the core area of Karnes, DeWitt, and southern Gonzales counties, with little opportunity to build a meaningful position there, the company instead looked toward less prospective acreage that lay beyond the core.
‘Low-Cost Entry’
“We really wanted to do that because of the low-cost entry,” Fisher said. “Our idea was to take a more advanced approach to design [the well], get a better understanding of the reservoir, to move updip into a little harder area.”
With the backing of private equity firm Lime Rock Resources, Battlecat in December 2014 leased 4,500 gross acres in Gonzales County. Situated on the edge of the volatile- and black-oil windows, the leasehold was considered fringe acreage by most Eagle Ford players. With relatively few well completions in the area, drilling faced greater uncertainty. And averaged data from wells that had been drilled indicated a significant risk of low EUR levels and poor prospective well economics.
Fisher cited differences in the thickness and quality of the area’s oil-bearing rock vs. the Eagle Ford core and emphasized that low gas/oil ratios, which hampered solution gas drive, had limited production in the area. However, some data were more promising but were obscured by the averages, which reflected the frequent reliance on suboptimal completion techniques, he said.
Averages Misleading
“There were a lot of understimulated wells, poorly drilled wells in this area that were really driving the averages down,” Fisher said. “But if you really dig down into the data, you can find a lot of economic wells in this area from operators who did a good job.
“There’s a lot more room for error in the core than up here,” he continued. “You can miss your target by 50 ft in the core, and the rock will make up for your mistakes. But if you miss your target by 50 ft here, you’re not going to make a well.”
An example of the area’s potential that Fisher cited was a 1977 vertical well that was not hydraulically fractured yet recovered 141,000 bbl over its life. “So what does it tell us about this area? It’s naturally fractured, and obviously there’s a lot of oil in place,” he said.
Looking at more recent area data, Fisher said, it was evident that higher EUR numbers were correlated with higher proppant weights per foot.
Data, Analysis, and Technology
To drill and complete the Bobcat well, Battlecat built its effort on data, analysis, and technology. The company purchased previously shot 3D seismic subsurface data to gain a thorough knowledge of the reservoir, plan its lateral, and locate its perforation clusters. Battlecat drilled a pilot hole, designed logs, took cores, and used geosteering to increase its understanding of the rock and fluid properties.
In drilling the well, the use of a cased-hole lateral log helped to integrate the engineering and completion strategy. An acoustic logging tool was used to detect small-scale fractures and faults to aid lateral steering decisions.
Drilling covered 15,000 ft measured depth in 18 days, including the pilot hole. “We weren’t trying to set any records here,” Fisher said. “We knew that the key was that we would land our wells perfectly.”
The drilled lateral length was 6,500 ft, but fracturing was scaled back to 4,400 ft to avoid breaching a fault on the edge of a nontargeted zone. Battlecat pumped a plug-and-perf, 21-stage slickwater fracture treatment at 1,700-lbm/ft fracture intensity and 2,500-gal/ft slickwater intensity at 85 bbl/min, with 215-ft stage spacing and seven clusters per stage.
Proppant Order Reversed
Real-time microseismic monitoring, used throughout to optimize the treatment, detected a problem in mid-course. With smaller, 100-mesh proppant being pumped in front of larger 40- to 70-mesh proppant, too much smaller proppant stayed near the wellbore, and the fractures created by the larger proppant were less extensive and complex than needed. Starting with stage 10, the proppant order was reversed, and the treatment began to achieve its design objectives, Fisher explained.
The “relax a frac” method, in which fracturing is briefly halted and then resumed, was used in later stages to increase the estimated stimulated volume. When the well began to produce, tracers were used to evaluate the production.
The Bobcat well’s performance exceeded company expectations, adjusted for lateral feet fractured. Battlecat originally projected an EUR equivalent to 60 bbl/ft for a well with a longer planned lateral to be fractured to its entire length. With a shorter lateral fractured to less than full length, the Bobcat well nonetheless achieved an EUR of 71 bbl/ft.
Fisher said, “We think the conclusion is that economic wells are possible in this area with the proper completion technique and the proper drilling of your well.”