Granite Wash, an old-school tight gas play in the Atoka Formation, which extends from the Texas Panhandle into western Oklahoma, has more than a few new shale believers taking a second look -- and grabbing acreage where they can.
In 2003 operators were drilling wells in the tight-sand gas reservoir with estimated ultimate recoveries (EUR) of around 1 Bcf/well, according to the Oklahoma Geological Survey. But that was oh-so-long ago -- light years past in drilling technology. Fast forward to 2009. Forest Oil Corp., one of the largest operators in the trend with a 91,000-net acre leasehold, drilled its first horizontal well in April. The well came online at an initial production (IP) rate of 17 MMcfe/d; over four months the IP rate has averaged 7.8 MMcfe/d.
"Even though we've talked about plays like the Granite Wash for several years, we're seeing our ideas validated by us and others," said Forest CEO Craig Clark.
"If we only had two places in which to build the company, the Texas Panhandle and East Texas north of Louisiana would be as good as any," said Forest COO J.C. Ridens. He recently explained what makes the play so special.
"The overall Granite Wash producing trend was set up by a mountain front originated from northwest to southeast," Ridens said. "The Wichita mountain front became the source of deposition as the erosion of the mountains occurred, and these granitic sediments were deposited in a direction primarily southwest to northeast, and lobes coming off the mountains, thus the term 'Granite Wash.'
"A very basic way to view to this depositional environment is to lay your hand on the table, viewing your knuckles as the mountain front and your fingers as the lobes that were subsequently deposited. Much like your fingers, the lobes of the Granite Wash are fairly straight [and] do not exhibit the serpentine nature of mature stream channels, thus making the geology fairly predictable..."
The Bureau of Economic Geology at the University of Texas at Austin does not consider the Granite Wash a "separate hydrologic unit," and some producers refer to results from the Texas Permian Basin, or the Atoka Formation. Basically, the Granite Wash in Texas is in the Palo Duro Basin of the Panhandle, where it's considered a northern extension of the Permian Basin.
"The naming convention varies amongst operators, as what we call Camp South and Pyre Ranch has been called Stiles Ranch by others," said Ridens. "Ignore these three field names; it's all the same area."
Tight sands plays have traditionally been vertically drilled, but "horizontal development works in this play because it's an effective tool to allow for more volume of reservoir rock to be contacted with the single well bore," Ridens explained. "Drilling a 3,600- to 4,000-foot lateral into only one member of the reservoir and then performing eight to 10 frac [hydraulic fracturing] stages provides much more rock volume to be contacted than when you drill a vertical well and perform multiple-stage fracs on several intervals. It basically allows us to concentrate the fracs into the best portion of the lateral, which has shown a significant increase in IPs and projected EURs."
The lower costs to drill in the Granite Wash are a selling point for producers, said Ridens.
Forest's estimated horizontal well costs through completion are around $5.5 million, said Ridens. Forest is using a 6.5 Bcfe EUR for its horizontal wells in play, which is about the same EUR that Chesapeake Energy Corp. uses for its Haynesville Shale wells. Chesapeake recently has gotten the cost of its Haynesville wells to around $7.5 million to complete.
Another player, Newfield Exploration, acquired its initial interest in the Stiles Ranch Field in 2002. At the time the field was producing less than 3 MMcfe/d using vertical drilling techniques. However, the operator took its successful horizontal drilling experience from the nearby Woodford Shale and put it to work in the Granite Wash. The results: Newfield in July reported that of the seven horizontal wells it has drilled since 2008, IP rates have averaged 22 MMcfe/d for all seven wells.
Newfield, with a 20,000-net acre leasehold in the Stiles Ranch Field and an additional 15,000 net acres in western Oklahoma, expects to drill 14 wells in the play this year. Drilling and completion costs are averaging $10 million/well gross; the most recent well was completed for $7.4 million. Longer lateral completions, lower rig rates and ongoing efficiency gains are expected to further improve returns until the end of the year, Newfield said.
Some of the biggest gas producers are taking notice. Devon Energy Corp. has grabbed more than 46,000 net acres in the Granite Wash, said COO Dave Hager.
"Typical drill[ing] and completed costs for these horizontal wells are between $5 million and $11 million, with recoveries up to 7 Bcf per well," said Hager. To date, the company has drilled 10 "successful horizontal wells," focusing on sands at depths of 11,000-16,500 feet. "Initial production rates can range from 3 MMcf to 15 MMcf per day.:"
The drilling results in the Granite Wash "can be attractive under normalized conditions," but because Devon's acreage is held by existing output, "we have the luxury to defer drilling," Hager said.
Another player that is taking its time in the play is Chesapeake Energy Corp., which has been "quietly" drilling wells in two trends, the Granite Wash and the nearby Colony Granite Wash, CEO Aubrey McClendon said recently.
"We could be at 10 to 15 rigs pretty easily," McClendon said of the two areas' results. In the Texas Panhandle, Chesapeake's leasehold is held by production (HBP) "and so really it's just completely selective drilling. and you want to pick and choose your time...
"If we didn't have any carries, those two Granite Wash plays would be the best in the company. Now we are favoring our plays with carries because you can't beat finding costs of less than 50 cents that we're generating in the Haynesville and Marcellus right now."
Apache Corp. also has acreage that it's testing, said COO John Crum. The region, he said, has been a core focus "for decades." The Houston producer to date has drilled more than 100 successful vertical wells there over the past five years, and "we know these rocks well. Dozens of horizontal wells have now been drilled with initial rates above 10 MMcf/d, significantly reducing our risk as we begin rigorous evaluation of the horizontal potential on our acreage."
Apache now is drilling its first operated horizontal well in Granite Wash, and it has identified other areas it plans to test through the rest of this year, said Crum.
"The central region is really starting to see the cost reductions we were looking for to improve the economics of our drilling programs," Crum said. Like Devon, he said Apache's "huge HBP acreage position has allowed us to defer activity until costs reflect the level of product prices we are experiencing..."
With around 23,000 net acres, Questar Corp. doesn't plan to miss the dance, said COO Chuck Stanley. Questar E&P is "encouraged by the prospectivity" in Granite Wash and "will likely commence a horizontal drilling program to evaluate some of our acreage later this year. We are in the process of choosing optimum locations and getting permits on those locations, doing the title work before we go out and commence testing our play. But it's in the right ZIP code."
Granite Wash holds a lot of promise for midstream operators too: there's an estimated 30% liquids component from production.
"This significantly increases the value of this production strength," Forest's Ridens said of the liquids output. The results give "us further confidence in the huge potential that this play has to offer. We estimate that a horizontal well here will recover about 6.5 Bcfe, compared to about 1.5 Bcfe for a vertical well. This means we are getting about four times the reserves for a little over twice the cost comparing a horizontal to a vertical well."
Frank Semple, the CEO of midstream operator MarkWest Energy Partners LP, said his company's gas volumes in the western Oklahoma system "have nearly doubled" at the Stiles Ranch project, which was expanded in 2008. Referring to Newfield's results alone, Semple said, "it's clear that this could grow to be a very significant field.
"The driver for the increased processing in Oklahoma has come from the Granite Wash development. We do certainly expect the success of Newfield out in the Granite Wash to continue..."
Other midstream operators also see some prospects for the region. Just days ago Tenaska Capital Management LLC (TCM) and Energy Spectrum Partners V LP said they plan to jointly operate Frontier Gas Services LLC to acquire, develop, own and operate natural gas infrastructure across the United States (see Daily GPI, Aug. 18). To initially capitalize Frontier Gas, Energy Spectrum and Frontier would contribute from their existing midstream partnership the 36 MMcf/d Indian Creek natural gas processing facility in Roberts County, TX, with production from the Granite Wash formation.
"The Granite Wash holds a particular interest for us," said TCM Senior Managing Director Daniel E. Lonergan. "You read about a lot of rig laydowns, and it makes economic sense in higher finding cost areas on the margin to be the first to see lower activities. But in lower-cost areas like Granite Wash, there's a reduced rate of laydown, and there's continuing drilling in Granite Wash because of those characteristics. More wells are coming on line, and that will take an investment in gathering and processing."
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