U.S. Lower 48 and Non-Arctic Canadian Gas Production by Type

Barnett Shale Ignites Imagination

Woodford Shale: Decades of Potential

Oklahoma CBM Annual Production

Midcontinent Coalbed Methane

CBM Data Sources Sidebar

Arkoma CBM Development: Horizontal or Vertical?

Great Things to be Achieved Unconventionally

Unconventional Energy in the Southern Midcontinent
by Dylan Powell, hostonwriter.com on PTTC's behalf
Excerpts in PTTC Network News, 1st Quarter 2004

"Nothing great was ever achieved without enthusiasm," noted Ralph Waldo Emerson. With enthusiasm as the measure, numerous speakers involved in unconventional energy and 345 energetic participants at the recent Unconventional Energy Resources in the Southern Midcontinent conference portend further significant growth for unconventional energy from shale, coalbed methane and tight gas sands. Insights from hundreds of millions of dollars of project experience were revealed, which accelerated progress in the remaining learning curve. The event was organized by the Oklahoma Geological Survey, with special compliments to Brian Cardott, and co-sponsored by the U.S. Department of Energy's National Energy Technology Laboratory and PTTC's South Midcontinent Region.

Unconventional  Energy for an Unconventional Future

A recent National Petroleum Council study points out that increasing natural-gas-supply diversity is a serious national issue. Our current energy landscape forewarns a strong dependence on increasing unconventional gas production in the lower 48 and Canada. As David Fleischaker, Oklahoma Secretary of Energy and the conference's lunch speaker, points out, "Non-conventional fuels will play an important role in the short- to mid-term—serving as an essential bridge until the time that we increase imports by building a pipeline to the North Slope and increasing our Liquified Natural Gas imports."

The Newark East Barnett Shale field, the largest active gas field in Texas, now produces more than 220 Bcf of natural gas per year. Unconventional energy resources in Oklahoma include Hunton de-watering and coalbed methane (CBM) activity in the Arkoma and Cherokee basins. According to Cardott, CBM activity in Oklahoma's Arkoma Basin produced about 70 Bcf of gas cumulatively through mid-2003. About two-thirds of this production is from vertical wells, but horizontal production  is rapidly overtaking that from vertical. Cherokee Basin CBM cumulative production is about 45 Bcf, all from vertical wells. CBM wells in southeast Kansas are now producing about 10 Bcf per year, and activity is strong. Arkansas CBM production is just now taking off.

U.S. Lower 48 and Non-Arctic Canadian Gas Production by Type

Barnett Shale Ignites Imagination

As Jeff Hall, Manager of Exploration and Exploitation with Devon Energy, pointed out during his presentation, the Barnett Shale is still one of the most exciting discoveries around. With its first completion in 1981, the Barnett isn't a secret. Estimated resources are as high as 140 Bcf per square mile across its 54,000 square miles. Though about 2,500 wells have been drilled in this field, there is a lot of action forthcoming. Devon, who operates about 60 percent of the wells in the field, estimates that recovery from conventional vertical wells will be 10 to 12 percent, with an additional 5 to 10 percent from re-fracs and additional production enhancements. That leaves 80 percent of gas-in-place for innovative thinkers who can successfully leverage new technology!

About 60 companies currently work the play. Its strong activity stems from evolving Barnett stimulation knowledge, including re-fracing and horizontal drilling. Progressive Barnett Shale developers, armed with frac mapping and tiltmeter technology, noticed that as their wells produced for a few years, the rock stress environment changed. When it was re-fractured, orientation of the new fractures was different from the original fractures.

Because the Mississippian-age Barnett is so tight, and its drainage area so limited, even a minor re-orientation of fracs essentially opened up a new reservoir to production. It is similar to getting a whole new well at times. Currently, most well workovers involve re-fracing the Lower Barnett with better frac technology and adding Upper Barnett perforations. About two-thirds of the production increase and reserves observed in re-frac treatment completions come from the Lower Barnett. Although the first series of re-fracs have proven profitable, none of the wells are mature enough to test the potential of additional rounds of re-fracing.

When one considers shale, one typically thinks of natural fracturing delivering increased recovery. Not in the Barnett, where fractures are not as important as thermal maturity. Given the optimum thermal maturity, the Barnett Shale becomes a stimulation technology play. "Technology is going to extend the play beyond its core area," noted Devon's Hall. The play also has surface access challenges, with the subdivision and strip-mall laden Dallas-Fort Worth suburbs sprawling just above the action.

Stimulation considerations led to the current trend of horizontal wells. In the heart of the play, Ordovician tight limestone provides barriers to keep the large frac treatments in the Barnett. Moving westward, this lower frac barrier disappears. Moving southward, both its upper and lower frac barriers disappear. Horizontal wells where frac barriers are absent are said to stand the best chance of staying in zone. And they are being oriented according to prevailing stress orientations that run southwest to northeast.

Over time, will re-fracing the Upper Barnett create similar reorientations as experienced in the Lower Barnett? For either, would a second re-frac after an extended production period create yet another frac orientation that would give production an economic boost? Stay tuned. "When I went to school at Oklahoma State University and took geology," noted conference presenter Kent Bowker with Star of Texas Energy Services, "we did not discuss this rock as a reservoir rock. We have to re-educate ourselves and try to understand how we can take what we learn from the Barnett and apply it to other basins."

Woodford Shale: Decades of Potential

If it took 15 to 20 years to realize significant value from the Barnett Shale, our goal with the Woodford Shale is to half the Barnett's learning curve—even if the Woodford doesn't become as significant a resource as the Barnett has. The prime area for this Upper Devonian/Lower Mississippian shale's gas potential lies just a couple hundred miles north of the Barnett Shale, but it is considered to be where the Barnett Shale was 15 to 20 years ago and gas wells have not yet proliferated. Current Woodford Shale production stands at 24 Woodford-only gas leases and 48 Woodford-only oil leases (oil and associated gas). Cumulative production may be minimal, but the resource potential is large.

Many questions remain about how to turn Woodford Shale gas-resource potential into production. As in the Barnett, will thermal maturity combined with stimulation technology be the keys to economic production? Or will it be natural fracturing? Or will it be something else entirely? Coalbed-methane researchers have developed a six-element producibility model. Will that model or a modification thereof help operators unlock the secret to shale gas reservoirs such as the Woodford?

Midcontinent Coalbed Methane

CBM activity is robust in the Cherokee Basin in southeast Kansas and northeast Oklahoma, as well as in the Arkoma Basin in Oklahoma and Arkansas. In the Arkoma Basin, the Oklahoma Geological Survey reports that 605 vertical CBM wells produced 44 Bcf of gas from 1989 to mid-2003 and 182 horizontal CBM wells in the Arkoma produced over 27 Bcf of gas from 1998 to mid-2003. Eight hundred and forty-four CBM wells in the northeast Oklahoma shelf produced over 45 Bcf of gas between 1994 and 2003.

Oklahoma CBM Annual Production

Cherokee Basin production, which with a few exceptions comes from vertical wells, is now about 11 Bcf per year in northeast Oklahoma and 10 Bcf per year in southeast Kansas. In the Oklahoma side of the Arkoma Basin, production from horizontal-well completions has now exceeded that from vertical wells-around 12 Bcf per year versus 8 Bcf per year from vertical wells. CBM activity in Arkansas is embryonic, limited almost exclusively to horizontal wells in the Lower Hartshorne coal.

When it comes to Midcontinent CBM, what we know depends on where we are. In Kansas, there is a strong focus on CBM resource definition, including looking further north into the Forest City Basin. The Kansas Geological Survey has developed isopach maps for different coals and is developing depositional interpretations that will turn them into treasure maps. Understanding gas content is still critical in Kansas. Limited sampling indicates that it can be quite variable. Contrary to logic, some of the shallower coals can have higher gas content!

"The Western Interior Coal Region is vast, located in six states and 87,000 square miles," commented Simon Testa, who summarized some of his results gathered by TICORA Geosciences, Inc. (www.ticora.com) for a three-year study on frontier basin resource and production potential sponsored by the Gas Technology Institute. "Our sample density was low. But you'll be amazed at some of the regression that we've found across the general region." An interpretative framework is developing to explain observed gas content trends for the study, which is schedule to be completed in August.

And then there's Arkansas. Because of its nascence, resource definition is paramount to its Arkoma Basin activity. According to Bill Prior with the Arkansas Geological Commission, about two-thirds of the Lower Hartshorne coal volume is at a depth of 500 to 1,000 feet. Faulting is extensive and a constant factor. For the explorationists out there, Prior noted that "Lower Hartshorne coal thickness is inversely related to thickness of the underlying Hartshorne sand." Research projects are underway defining CBM potential in the Desha Basin in southeastern Arkansas.

Arkoma CBM Development: Horizontal or Vertical?

The Hartshorne coal in Oklahoma's Arkoma Basin has been brought to profitable fruition both horizontally and vertically. And fans of both will find assurance. Horizontal completions will reach a higher peak rate sooner; but their initial decline is steeper. At the four-year point, horizontal wells will produce about two and a half times as much as a vertical well. Comparative ultimate recoveries are yet to be determined, but cost data shared by speakers indicated horizontal wells will cost from between two and a half to four times higher than their vertical counterparts. The perspective from which one approaches the problem influences the answer regarding which approach is best. As one speaker sagely advised, "Do what you know well."

El Paso Production Company is a powerhouse of horizontal-well development in Oklahoma's Arkoma Basin. Curtis Matthews, senior geologist, shared his horizontal-well success tips:

1. Exercise good well planning
2. Use an experienced directional driller
3. Employ a good wellsite geologist
4. Know the area geology (3-D visualization helps)
5. Have patience

And he should know. El Paso stays within a 4-ft-thick coal more than 90 percent of the time! This includes when laterals encounter small faults of a few feet displacement. Too small to be inferred from geological information, El Paso's experience is to expect them. When crossing a fault, one must get back in the coal quickly. But do you go up or down? Matthews advised that one should go up about 75 percent of the time. In addition, he notes that if sand is right on top of the coal, it may be time to turn in rather than endure the inevitable money pit that follows.

For vertical wells, minimalism has merit. John Wendell of Wendell Consulting shared his expertise developing Arkoma Basin vertical CBM wells. He stresses cost containment across the board. He gave one example regarding injection falloff testing to measure permeability. A vendor can do this, but the costs can add up. So Wendell built his own injection falloff-testing rig for roughly the cost of a single service job. It did not have leather seats and a sunroof, but it got him there; and it was a capital expenditure.

Artificial lift is generally required to keep water lifted off CBM wells. While conventional rod pumps are common, there are disadvantages: volume limitations; fines; maintenance costs, etc. Brian Weatherl of Source Rock Energy Partners discussed two increasingly popular alternatives. These include soap injection through capillary strings using gas-powered pumps and a simplified gas lift. Soap injection is cheaper than using rod pumps and lifts similar capacity. And it is maintenance-friendly. Using a simplified gas lift, setting a wellhead compressor and injecting gas back down the annulus, also has an economic advantage.

Great Things to be Achieved Unconventionally

The abundance of expertise in Oklahoma City created the kind of enthusiasm that multiplies. "I certainly enjoyed the presentations I saw that dealt with the Hartshorne coal and horizontal drilling. They were done well and I enjoyed being informed on horizontal drilling in the Arkoma Basin," notes conference attendee Ed Butler, who is in charge of engineering and planning for CDX Gas LLC. Butler agrees that this technology will be important over the long haul. John Dewey of Vintage Petroleum added: "I thought the conference was very good; it was informative, the papers were well done and the turn out was very good."

"I was very impressed with the technical presentations and the technical knowledge presented," noted Robert Gibson, one of three Questar Exploration and Production attendees at the conference. He continues: "Anybody that came could take something away-either an awestruck type of perspective of how much tight gas sands, coalbed methane and shale gas has contributed to increasing overall gas supply in the United States or, at a more microscopic level, a good understanding of the maturation process for these types of reserves. We've been producing these things since the turn of the last century. It's becoming more and more a part of our domestic overall U.S. gas supply and its projected to increase even more over time."

For further information, contact Lance Cole at lcole@pttc.org.