The Haynesville Shale and Hydraulic Fracturing

Drilling a horizontal well is just half the story. The next vital step is completing the well. In the case of a shale gas play like the Haynesville, this means successful, multi-stage hydraulic fracturing of the formation. There are many variables to consider. Here is an example:
Peter

HAYNESVILLE SHALE - HYDRAULIC FRACTURE STIMULATION APPROACH

Mark Parker, Halliburton

Abstract (source)

The Haynesville Shale is an ultra low permeability unconventional gas reservoir located in East Texas and Northwest Louisiana. High gas prices and the success of other shale gas plays have led operators to invest highly in this resource play. It has great potential for development by applying all the new technology that is available in the Oil and Gas Industry today. Hydraulic fracturing is required to realize the potential of this reservoir. The nature of the formation requires that it be addressed on its own merits and not be considered an analog to other shale reservoirs. Therefore, cookbook recipes for fracture stimulation treatments will not lead to the optimum production results.

A critical evaluation of the target zones and the boundary layers is necessary for an accurate treatment design using available fracture simulators. An understanding of the formation characteristics and how they impact the development of fracture geometry and proppant placement can lead to improved success.

This paper will review the design process and the technologies that are required to achieve the best production results. Examples of pumping schedules and fracture design output are presented to illustrate the following: * Design approach * Isolation mechanism (pump down technology, CT technology, e-coil) for horizontal completions * Fracture design tools (process logs to identify correct fracture initiation points, fracture design programs, DFIT, Microseismic fracture mapping) * Fluid systems and additives * Proppant recommendations

US and Canadian Shale Gas Plays Examined

Study analyzes nine US, Canada shale gas plays

A recent study has estimated that nine US and Canada shale-gas plays may produce as much as 24 bcfd by 2018. (source)

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The Oct. 6, 2008, Tristone Capital Inc. study evaluated the gas resources in the Bamett (Fort Worth basin), Deep Bossier, Haynesville, Fayetteville, Woodford, and Marcellus shales in the US and the Montney, Hom River (Muskwa), and Utica shales in Canada (Fig. 1).

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The study expects companies ultimately to recover from these resources 261 tcf of gas, based on various risk factors applied and a long-term average gas price of $8.50/MMbtu. Without the risk factors, Tristone Capital says these shales have a 743-tcf recovery potential (Fig. 2).

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Fig. 3 shows the study’s estimated production from these plays, and Fig. 4 shows its US well completion forecast.

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Several emerging shale plays with limited well control also may contribute additional gas to future production, according to the study. These include the Pearsall shales in the Maverick basin of South Texas, the Niobrara shales of Western Colorado, and the Barnett shale in the Delaware basin of West Texas.

Shale play comparison

The study says that shale-gas plays owe their success to a balance of various parameters along with constantly evolving drilling and completion techniques and infrastructure. “It is commonly said that no two shale gas plays are exactly alike,” the study says.

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Table 1 summarizes shale-gas play attributes, and Fig. 5 compares the arithmetic average of the attributes. The study notes that the most productive core portions of plays may deviate from the averages.

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Multistage hydraulic fracturing along a horizontal lateral and improvements in stimulation are main factors influencing shale-gas development economics. The study says these factors have improved economics by more than three times from that of vertical well developments by improving both ultimate recovery and initial production rates.

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Table 2 compares typical lateral lengths and frac treatments for the nine plays.

The three types of frac fluid noted are slick water, CO₂-polymer, and gelled cross-linked oil-based fluid.

Slick-water fracs use a nongelled fracturing fluid with low proppant concentrations and a friction-reducing chemical additive that allows pumping the water into the reservoir faster. The fluid often is a brine or potassium chloride (KCl) water to inhibit swelling of clays. The study notes that this fluid is less expensive than hydrocarbon-based fluid and works best in low-permeability reservoirs

Companies pioneered slick-water fracs first in the Fort Worth basin’s Barnett shale.

The CO₂-polymer frac fluid contains emulsified CO₂ in a methanol-water mixture of 5% water and 20% methanol. The study says the mixture appears to minimize reservoir damage and maximize fluid recovery from multiple diversions in the well. Including CO₂ also reduces by 25% the fluid required and provides extra energy, as the gas expands, during frac fluid flow-back greatly to shorten cleanup time, the study says.

The Montney formation in British Columbia is where companies use this fluid. The study notes that stimulating a horizontal well in the Montney typically involves perforating, isolating, and fracturing 6-11 zones at a cost of about $100,000- 120,000/frac interval. It is common to spend more than $1 million for fracturing these wells, the study says. The study describes these jobs as needing 8-10 pump trucks or about 18,000-22,500 hp and taking more than 1 week to complete.

The study notes that companies initially used gelled cross-linked oil-based fluids as the “fluid of choice” for hydraulic fracturing because of its compatibility with most formations and its cold weather attributes. In several basins, slickwater fracs have replaced oil-based fracs because the slick water uses less water and costs less, the study says.

To prevent swelling and permeability loss in the shales, companies typically continue to use oil-based frac fluids in formations that contain extensive water-sensitive clays. The study notes that these fluids are used in the Fayetteville, Haynesville, and Woodford shales.

Fort Worth basin Barnett

Development activity continues to evolve with part of the current activity in urban sites such as Fort Worth and the Dallas-Fort Worth airports.

The study notes that as of Aug. 18, 2008, the Barnett had 8,416 gas wells drilled in 19 counties. Production had increased to 3.8 bcfd in first-quarter 2008 from 219 MMcfd in 2000. The study expects the shale to produce 6-7 bcfd in the next 5 years.

Some of the newer techniques in the play noted in the study are:

• Longer horizontal laterals, up to 3,500 ft, often drilled from pads with multiple wells, especially in the urban areas.
• Testing of tighter well density with laterals, spaced 250-ft apart (25-30) compared with 500 ft between laterals (50-acre spacing).
• Simultaneous fracing of wells to increase recovery.

Deep Bossier

Wells in Deep Bossier of East Texas reach a 15,000-20,000 ft depth, have pressures of about 15,000 psi, and have tested at 65 MMcfd. The study notes that these wells are expensive, costing $10-20/million for a vertical well.

Currently the play has six main fields in four counties: Robertson, Leon, Freestone, and Limestone.

Fayetteville

The Fayetteville shale in Arkansas is the shallower and thinner equivalent of the Barnett shale. The core of the play is in five counties in central Arkansas: Cleburne, Van Buren, Conway, Faulkner, and White.

The study says as of May 31, 2008, the play had 877 producing wells, with production in July of 740 MMcfd compared to only 90 MMcfd in December 2006. The study expects the play to produce 3.15 bcfd by 2018.

Haynesville

The Haynesville shale is in northwestern Louisiana and East Texas. Wells in the play initially have produced 5-20 MMcfd, the study said. The study expects wells to have ultimate gas recovers of 4-8 bcf.

Currently, companies have drilled about 20-25 horizontal wells in the play, and the study expects about 60-80 rigs could be active in the play by yearend 2008, with most of the drilling in Caddo and DeSoto Parishes in Louisiana.

Woodford

The Devonian-aged Woodford shale lies at 6,000-14,000 ft depths in the Arkoma basin of southeast Oklahoma. The study notes that the $6 million well cost in the Woodford is more than the $2-3/million/well cost in the Fayetteville and Barnett shales.

The study estimates that an 80-acre well in the Woodford will recover about 4 bcf of gas.

Marcellus

The Marcellus shale in the Appalachia basin extends over several states, although most wells drilled to date have been in Pennsylvania, the study notes.

It says Marcellus production has been minimal to date because of the need to expand the existing infrastructure to accommodate the high-pressure gas that the gas transportation system in Appalachia cannot at this time handle.

Most companies have so far drilled mostly vertical wells to delineate the play, but the study expects horizontal wells to be the primary means for developing the formation.

Montney

The Montney shale lies in the east-central part of British Columbia. The study notes that continued drilling should increase production to 1 bcfd by yearend 2009 from the current 600 MMscfd in early 2008.

Operators typical include five to eight fracs/well, and the study expects estimated ultimate gas recovery to increase to 7 bcf/well from the current 5 bcf/well as technology innovation continues.

Horn River basin

The Horn River basin in Northeastern British Columbia extends into the Northwest Territories. The Devonian Muskwa shale is the main play although the basin also has other shales with large original gas in place such as the Fort Simpson, the study says.

Initial well production rates have ranged from 2 to 8.8 MMcfd with wells with more fracs stages producing better, the study notes. The study says estimated ultimate gas recovery ranges from 4 to 6 bcf/section.

Utica

The Utica and the overlying Lorraine shales are relatively new plays in Quebec with only a few wells testing the formations to date. The study estimates that recoverable gas could be as much as 40 tcf (150 bcf/section).

An initial vertical well tested at 1 MMcfd; rates should be higher for horizontal wells with multiple fracs, according to the study.

Emerging plays

Three emerging shale plays listed by the study are Pearsall shales in the Maverick basin of South Texas, the Niobrara shales of Western Colorado, and the Barnett shale in the Delaware basin of West Texas.

The study says the Pearsall is as deep as 3,500 m in places, has a 200-300 m thickness, and contains about 30-175 bcf/section of original gas in place. It notes reports that say initial horizontal wells flowed at 0.8-3.8 MMcfd.

The Niobrara shales outcrop in Kansas and Nebraska, but are at more than 2,500 m depths in western Colorado. The study notes that in the eastern shallower portion of the play, the shales are underpressured and wells have low initial rates, while in the deeper overpressure portion, wells may produced at 1 MMcfd and recover 100-150 bcf of gas/section.

The Barnett in the Delaware basin is twice a deep as the Barnett in the Fort Worth basin and therefore holds much more gas per section. One estimate is that the Delaware Barnett has 500 bcf/section compared with 150 bcf/section in the Fort Worth basin. The study notes that developing Delaware Barnett gas will be more complicated and costly.

Great Economic News From Shreveport, Louisiana (Courtesy of the Haynesville Shale Gas Play)

More good news is the Haynesville Shale Gas Play is having very strong positive economic effects in the Shreveport area of northwestern Louisiana. This is not pie-in-the-sky, wishful thinking for creating jobs and energy supplies, such as windmills and solar farms. This activity is not a government "make-work" project. This is the real deal.

Shale gas is an available resource being exploited using existing technology. We need this kind of good economic good news in America, badly. Someone should invite President Obama down to Shreveport and give him a tour.
Peter

July 1, 2009 Shreveport-Bossier among best for a fresh start, Web site says By Curtis Heyen cheyen@gannett.com (source) Shreveport-Bossier City has been ranked 15th among the top 20 places in the U.S. to begin a new career or a new life, according to the Web site BusinessWeek.com. The Web site cites Shreveport-Bossier City for having a low cost of living and seeing new jobs coming from the natural gas industry and the movie business. The listing reinforces what local leaders have believed for a long time, said Kurt Foreman, president of the Northwest Louisiana Economic Development Foundation. "We certainly feel like this is a great place to start over, build a business or grow a career. "I'm pleased that these national magazines are seeing what we have seen for a long time." The recession has not negatively impacted Shreveport-Bossier City as much as other parts of the nation, Bossier City Mayor Lo Walker said. "We do have job opportunities. ... We've had a net increase in population and jobs. "This news can only encourage people to be more receptive to coming to this region." The BusinessWeek.com article notes that a number of movies, among them "W.", include scenes filmed in Shreveport and the surrounding area. In fact, Oliver Stone shot most of his movie in Shreveport. Another example not noted by the Web site is "Year One," which was filmed near Sibley and on a Shreveport soundstage. That moving, starring Jack Black, opens in theaters today. But the local film industry has slowed significantly this year. The next major project is "Straw Dogs," a Sony Screen Gems picture slated to begin filming here this summer. On the other hand, interest in the Haynesville Shale in northwest Louisiana continues to fuel employment in the region. The natural gas formation, trumpeted as perhaps the largest in the nation, has pumped millions of dollars into some property owners' pockets -- including local governments -- since the discovery was announced in April 2008. A recently completed economic impact study estimates Haynesville Shale activity created about 32,742 jobs, about $2.4 billion in business sales statewide and nearly $3.9 billion in household earnings, including almost $3.2 billion in lease and royalty payments to private landowners, in 2008. Topping BusinessWeek.com's list is the Anchorage, Alaska, metropolitan area. Also among its top five are Provo-Orem, Utah; Kennewick-Richland-Pasco and Yakima, both in Washington; and Omaha, Neb.-Council Bluffs, Iowa. The Web site ranked metropolitan areas based on the percentage of companies planning to hire in the third quarter, according to a survey by Milwaukee staffing firm Manpower of 28,348 U.S. employers that was conducted April 6-29. Businessweek.com says it eliminated Barnstable, Mass. (Cape Cod), which would have topped the list, because the surge in expected hiring in the next quarter is likely due to seasonal hires. In cases where areas have equal percentages of companies planning to hire, the Web site says, the unemployment rate was used to break the tie. The best job prospects for each area also were pulled from the same survey. Home prices used for the BusinessWeek.com's list were provided by Zillow.com, 2008 population is based on U.S. Census Bureau data, and the March unemployment rate comes from the U.S. Bureau of Labor Statistics.

Canadian Companies Prefer Drilling In U.S.

Here is another oddity. The Canadian Government is in effect subsidizing companies to produce gas in Canada, while one Canadian comany, EnCana, plans to spend $290 million in the Haynesville Shale Gas Play in northwestern Louisiana while cutting its drilling activity elsewhere.

Someone should tell the Obama Administration there is a shale gas "boom" going on in the U.S. Developing this resource can create jobs, increase revenue to State, Local, and the Federal Governments. The pipelines are there, the drilling rigs are there, the technology exists, the trained workers are there, ready to go. Mr. Obama, what are you waiting for?

This natural gas can be used to power buses, trucks and cars. It will reduce America's dependence on foreign oil, and last but not least, it will pacify some environmentalists because it is a "clean" source of energy.
Peter

Alberta Extends Natural-Gas Incentives to Compete With Shale

By Gene Laverty (source)

June 25 (Bloomberg) -- The province of Alberta, the biggest foreign supplier of natural gas to the U.S., said it will extend by one year incentives to boost drilling for the fuel to make it more competitive with U.S. shale gas deposits.

The province will charge producers a flat rate of 5 percent during the first year of output from new wells, a government statement said. Drillers will also receive a royalty credit of C$200 ($172.64) for each meter (3.28 feet) of new well depth drilled.

The programs had been set to expire in March 2010, Energy Minister Mel Knight said in the statement. They will be extended to March 2011.

Companies including EnCana Corp., the nation’s biggest gas producer, are shutting wells amid a 70 percent decline in New York gas futures in the last year. Companies are using new methods to tap gas large gas deposits trapped in shale in Texas and Louisiana that are closer to U.S. consuming regions. Calgary-based EnCana plans spend $290 million on its Haynesville Shale properties this year while slashing drilling in other regions.

To contact the reporter on this story: Gene Laverty in Calgary at glaverty@bloomberg.net.

The U.K's BG Buys A Stake (From EXCO) In The Haynesville Shale Gas Play

This is good news for those of us in the service sector who depend on drilling activity. It is also good to have foriegn money coming into the U.S and creating jobs. The price this U.K. natural gas company is paying to enter the Haynesville Shale Gas Play may seem steep, but they are surely counting on the price of gas and leases to increase.

Also, and not insignificantly, they're paying for the science and technology that has been developed to extract this "unconventional" source of gas. By this I mean primarilly horizontal drilling and hydraulic fraturing. This would also, I hope, include the "steering" of these horizontal wells into the optimum stratigraphic layers of rock.
Peter


BG Buys Exco Stake for $1.06 Billion to Tap Shale Gas (Update3)

By Eduard Gismatullin

June 30 (Bloomberg) -- BG Group Plc, the U.K.’s third- largest natural-gas company, bought assets from Exco Resources Inc. for $1.06 billion to develop its first U.S. shale gas project. Exco shares rose 16 percent.

BG Group acquired a 50 percent stake in 120,000 net acres in East Texas and northern Louisiana, the company said today in a statement. The purchase includes part of the Haynesville Shale gas formation and adds 2.6 trillion standard cubic feet to BG’s resources, with current net output of 78 million standard cubic feet a day.

“We expect BG will use this shale gas to meet U.S. contract commitments, thereby releasing Atlantic basin LNG cargoes for higher-priced global” markets, said Oswald Clint, a London-based analyst at Sanford C. Bernstein & Co.

BG will compete with larger rivals including Royal Dutch Shell Plc, BP Plc and StatoilHydro ASA in the development of U.S. shale deposits. It has also expanded oil and gas resources in Australia and Brazil and forecasts production will rise between 6 percent and 8 percent a year and reach 1.6 million barrels of oil equivalent a day in 2020.

“This alliance brings material new resources and supply to our existing U.S. business at a competitive price and in a prime location at the heart of the world’s largest gas market,” Chief Executive Officer Frank Chapman said in the statement. “The transaction increases BG Group’s exposure to long-term unconventional gas resources and skills.”

Marketing LNG

Dallas-based Exco rose $1.80 to $12.92 in New York Stock Exchange composite trading. BG Group fell 19 pence, or 1.8 percent, to 1,018 pence in London.

Shale gas is natural gas stored in organic rich rocks such as dark-colored shale, interbedded with layers of shaley siltstone and sandstone, according to BG.

BG has been marketing liquefied natural gas in the U.S. and supplied 55 percent of all LNG cargos imported into the country in 2007, according to its Web site. The company also generates power in the U.S. to customers in New England.

A total of $655 million will be paid on completion, plus $400 million as a carry of 75 percent of Exco’s future costs to develop the Haynesville Shale gas, the Reading, U.K.-based company said. The partners agreed to co-operate on further development and BG expects its production in the area will rise to 250 million cubic feet a day in 2012.

‘Expensive’ Deal?

The British company will pay $19,000 per acre for the Haynesville Shale gas assets. It may also buy a 50 percent interest in gas-gathering and transportation assets from Exco for $249 million to supply the fuel to U.S.’s Midwest and Eastern regions.

“Recent deals in the shale gas play have been around $15,000 per acre,” said Bernstein’s Clint. “Hence this deal at $19,000 per acre could be viewed as expensive on that basis.”

The acquisition of the gas assets is conditional on the purchase of the transport infrastructure, BG said.

To contact the reporter responsible for this story: Eduard Gismatullin in London at egismatullin@bloomberg.net

EXCO To Open Haynesville Shale Field Office

Tuesday, June 23, 2009, 1:01pm CDT

Exco to open Haynesville Shale office

Dallas Business Journal (source)

Dallas-based oil and natural gas company Exco Resources Inc. (NYSE: XCO) will officially open a new field office in the Haynesville Shale on Friday and will break ground on a new Haynesville Shale gas gathering and treating facility in Louisiana to accommodate all of the work the company is doing in the gas-rich shale.

The new field office is in Grand Cane, La., about 30 miles south of Shreveport.

Exco Resources has nine horizontal wells and eight vertical wells drilled and completed in the Haynesville shale play, the company said Tuesday. Exco intends to complete 21 more horizontal wells by the end of this year.

“We are very excited about the success we have achieved in the Haynesville Shale and have committed over two-thirds of our 2009 drilling and completion budget to continue developing the 85,000 net acres we have in the play,” said Doug Miller, chairman and CEO of EXCO Resources. “In addition to our production and development plans, we are committed to spend over $100 million in 2009 on our midstream business to add treating capability and throughput capacity in excess of 500 million cubic feet of natural gas per day by early 2010 in our Haynesville shale area.”

The Woodford Shale, A Major New Play

The Woodford Shale, A Major New Unconventional Oil And Gas Play

With the advent of new horizontal drilling and frac techniques, the Woodford Shale exhibits the potential to become a major new oil and gas play in the Midcontinent and West Texas areas of the Unitied States. Look at the numbers given for the potentially recoverable volumes of oil and gas. Can we "drill our way" out of America's dependence on foreign oil? GP

Special Focus: NORTH AMERICAN OUTLOOK-UNCONVENTIONAL RESOURCES

(source)

Reservoir characteristics and production potential of the Woodford Shale
With enough oil and gas to potentially become a major unconventional hydrocarbon reservoir, the Woodford is a viable play.
John B. Comer , Indiana Geological Survey, Bloomington, Indiana

The Woodford Shale is an attractive target for unconventional oil and gas development because it is a mature source rock that is widely distributed throughout the southern midcontinent, and because it locally produces oil and gas from naturally fractured intervals in conventionally completed wells. 1 In addition, drilled intervals yield oil shows from cuttings and cores, and produce a gas response on mudlogs, confirming that the Woodford Shale contains anomalously high oil and gas. Finally, the Woodford play that has developed in Oklahoma (279 wells drilled from 2004 to 2007 with cumulative production of nearly 64 Bcf gas and 66,538 bbl oil/condensate)2 confirms the commercial viability of the Woodford and provides incentive for additional exploration and development.

The following provides a regional overview of the oil and gas producing potential of the Woodford Shale in the US southern midcontinent. The article focuses on the Anadarko and Permian Basin depocenters and adjacent provinces, where organic-rich Woodford facies are thickest, and where conventional oil and gas production and infrastructure are extensive, Fig. 1. Of particular importance are source rock properties, especially Total Organic Carbon (TOC) and thermal maturity, and lithologic properties, especially silica content and type. Also, the geographic distribution of lithofacies, organic hydrogen content and thickness are important in deciding where to drill, and they allow volumes of oil-in-place and gas-in-place to be estimated. 3

Fig. 1 . Map showing geologic provinces with Woodford Shale in the (A) Anadarko Basin and (B) Permian Basin. 3

SOURCE ROCK PROPERTIES
Hydrocarbon source rocks (> 0.5 weight percent TOC) are attractive targets for unconventional drilling because their hydrocarbons are indigenous and their hydrocarbon charge does not depend on the fortuitous and inefficient processes of expulsion from a fine-grained source bed, secondary migration through porous and permeable carrier beds, and accumulation in an adequately sealed reservoir.

Source rocks that contain the highest concentrations of organic hydrogen generate the most hydrocarbons. These are typically beds of lacustrine and marine origin that contain Type I and Type II kerogen and generate both oil and gas during thermal maturation.
Oil-to-rock correlation studies document that the Woodford Shale is a prolific oil source, 4-13 and estimates indicate that as much as 85% of the oil produced in central and southern Oklahoma originated in the Woodford. 13 The Woodford Shale contains high concentrations of marine organic matter, 14-19 with mean organic carbon concentrations of 4.9 percent weight for the Permian Basin (Texas and New Mexico), 5.7 percent weight for the Anadarko Basin (Oklahoma and Arkansas) and 5.2 percent weight for both regions combined, Fig. 2. Organic carbon concentrations range from less than 0.1 percent weight in some chert beds 15 to 35 percent weight in black shale, 18 and the organic matter is mostly oil-prone Type II kerogen. 1,14,15,18 Across the region, the Woodford Shale exhibits a wide range of thermal maturities from marginally immature to metamorphic (Ro = 0.37-4.89 %). 15,20

Fig. 2 . TOC concentrations (weight percent) and statistics for geologic provinces in the southern midcontinent. Mean organic carbon concentration exceeds 2.0 weight percent in each of the provinces listed.

STRATIGRAPHY
The Woodford Shale is mostly Late Devonian, but ranges in age from Middle Devonian to Early Mississippian. 21-24 Age-equivalent strata include the Chattanooga Shale, Misener Sandstone, Sylamore Sandstone, the middle division of the Arkansas Novaculite, upper part of the Caballos Novaculite, Houy Formation, Percha Shale and the Sly Gap Formation. 21,24-30 These units were deposited over a major regional unconformity and represent diachronous onlapping sediments. 21,31-35 In the southern midcontinent, these units are the stratigraphic record of worldwide Late Devonian marine transgression. The Woodford is stratigraphically equivalent to several North American Devonian black shales with active and potential unconventional oil and gas production, including the Antrim Shale (Michigan Basin), Ohio Shale (Appalachian Basin), New Albany Shale (Illinois Basin), Bakken Shale (Williston Basin) and Exshaw Formation (Western Canada Basin).

WELL LOG CHARACTERISTICS
The Woodford is identified primarily by high radioactivity on the gamma-ray log and by its stratigraphic position between carbonates, Fig. 3. The Woodford exhibits low sonic velocity, low resistivity and low neutron-induced radiation. Three subdivisions (the lower, middle and upper units) are commonly recognized in the Woodford, and can be correlated regionally based on well log signatures. 36 The lower unit immediately overlies the regional unconformity, has the lowest radioactivity, and contains more carbonate, silt and sand than the other two units. The middle unit has the highest radioactivity, is the most widespread lithofacies, and consists of black shale with high concentrations of organic carbon, abundant pyrite, resinous spores and parallel laminae. The upper unit has intermediate radioactivity and consists of black shale with few resinous spores and mostly parallel laminae.

Fig. 3 . Characteristic well logs for the Permian Basin and Anadarko Basin regions. (A) Permian Basin, Winkler County, Texas.36 (B) Anadarko Basin, Major County, Oklahoma. 37

LITHOLOGY AND FACIES DISTRIBUTION
The most widespread and characteristic Woodford Shale lithology is black shale. Other common lithologies include chert, siltstone, sandstone, dolostone and light-colored shale, with hybrid mixtures between them. 14,15,21-23,38 Optimum reservoir lithologies are siliceous and include the cherts, siltstones, cherty black shales and silty black shales that are dense and brittle and, when fractured, retain open fracture networks. Production potential is greatest where these lithologies are organic-rich, thermally mature and highly fractured. Naturally-fractured Woodford Shale reservoirs, which have produced hydrocarbons for many decades, are completed in organic-rich chert intervals. 1 Figure 4 displays photomicrographs of cherty black shale in a naturally-fractured Woodford reservoir with bitumen-filled fractures from an oil-producing zone. Figure 4A was taken at a depth of 3,056 ft and has 4.5% TOC, and Figure 4B was taken at 3,065 ft and has 7.8% TOC. The association of chert and fractures in producing reservoirs suggests that the best unconventional wells are likely to be completed in the cherty facies.

Fig. 4 . Photomicrographs of core from Texaco No. 1K Drummond, Marshall County, Oklahoma, 11-6S-6E, North Aylesworth field. 1 White elliptical bodies are recrystallized Radiolaria. Photographed in transmitted plane polarized light.

The Woodford facies distribution is the result of Late Devonian paleogeography and depositional processes. During the Late Devonian, the southern midcontinent lay along the western margin of North America in the warm dry tropics near 15° south latitude. 14,39 Woodford deposition began as sea level rose, drowning marine embayments in what are now the deepest parts of the Delaware, Val Verde, Anadarko and Arkoma Basins, and advancing over subaerially eroded, dissected terrane consisting of Ordovician to Middle Devonian carbonate rocks. The broad epeiric sea that formed had irregular bottom topography and scattered, low-relief land masses which supported little vegetation and few rivers.

Oceanic water from an area of coastal upwelling flowed into the expanding epeiric sea and maintained a normal marine biota in the upper levels of the water column. Net evaporation locally produced hypersaline brine, and strong density stratification developed that restricted vertical circulation and resulted in bottom waters depleted in oxygen. Pelagic debris from the thriving biomass settled to the anoxic sea floor where organic- and sulfide-rich mud accumulated. The slow, continuous settling of pelagic debris was interrupted periodically by frequent storms and occasional earthquakes that triggered turbid bottom flows that supplied silt and mud to proximal shelves and basin depocenters, and caused resedimentation throughout the epeiric sea.

This depositional model explains why quartz grains and chert have very different distributions. Quartz grains represent terrigenous detritus transported from exposed older sources. Chert is biogenic and represents siliceous microorganisms (mostly Radiolaria) that bloomed in the nutrient-rich, upwelled water of the ocean and recrystallized after deposition on the sea floor. Detrital quartz is most abundant in areas near land, especially along the northwestern shelf and in the northwestern part of the Anadarko Basin, and in basin depocenters where turbid bottom flows finally converged. Chert beds increase in abundance and thickness toward the open ocean and are common along the continental margin and in distal parts of the major cratonic basins (Delaware, Anadarko, Marietta, Ardmore and Arkoma). The most distal allochthonous beds in the central area and core area of the Ouachita Tectonic Belt are almost pure radiolarian chert. High concentrations of radiolarian chert coincide with high concentrations of organic carbon along distal highs, such as the Central Basin Platform, Pecos Arch and Nemaha Uplift, and along the craton margin in the Arbuckle Mountain Uplift, Marietta and Ardmore Basins, western Arkoma Basin and frontal zone of the Ouachita Tectonic Belt. Where thermally mature, the organic-rich cherts and cherty black shales in these areas are optimum exploration targets.

THERMAL MATURITY
Thermal maturity follows Woodford structure, with the highest maturities in the deep basins and in orogenic belts, and the lowest maturities along structural highs, Fig. 5. 14,15,18,20,40-43 The Woodford Shale reaches its highest thermally maturity in the Anadarko, Delaware and Arkoma Basins where it is most deeply buried, and in the Ouachita Tectonic Belt where stratigraphically equivalent beds have been locally metamorphosed. Intermediate maturities occur in shelf settings, and the lowest maturities occur on structural highs such as the Central Basin Platform, Pecos Arch, Nemaha Uplift, Arbuckle Mountain Uplift and the frontal zone of the Ouachita Tectonic Belt. In deep basins, the Woodford Shale is in the gas generation window, whereas in the shelf and platform settings, the Woodford is in the oil generation window. 14,15

Fig. 5 . Map showing thermal maturity of Woodford Shale and age-equivalent units in (A) Anadarko and (B) Permian Basin regions. 3 Patterns are based on vitrinite reflectance (%Ro).

POTENTIAL PRODUCTION TRENDS
Potential production trends have been qualitatively ranked based on the probability that brittle or naturally fractured, thermally mature organic-rich beds of Woodford Shale are present in the subsurface, Fig. 6. The trends are designated as areas of probable, possible, local and poor success as follows. Probable success areas are those where organic-rich Woodford Shale is in the gas generation stage of thermally maturity and where large volumes of gas are likely to reside. Possible success areas are those where organic-rich Woodford beds are in the oil window and where the formation is shallow enough for economic drilling and for open fracture networks to persist. Local success areas are those in shelf settings where the Woodford Shale is relatively thin, but thermally mature and at a relatively shallow depth. Poor success areas are those where the formation is exposed at the surface or is shallow and unconfined, and where Woodford Shale or equivalent units have been metamorphosed or have very low organic carbon content.

Fig. 6 . Map showing hydrocarbon production potential and estimated volumes of oil-in-place and gas-in-place for Woodford Shale and age-equivalent units in the (A) Anadarko and (B) Permian Basin regions. 3

ESTIMATION OF RESOURCE POTENTIAL
The resource potential estimations assume that oil and gas in the Woodford Shale are indigenous, and were calculated based on organic carbon concentration, organic hydrogen concentration, organic matter type, thermal maturity and facies volumes (thickness times area), Fig. 6. 3 While this is not an assessment of recoverable oil and gas, it does estimate total gas-in-place and oil-in-place through mass balance calculations based on the concentration of organic hydrogen in the source beds. 3 The data suggest that total in-place gas in the Woodford Shale is on the order of 830 Tcf and total in-place oil is on the order of 250 Bbbl in the southern midcontinent. These volumes include 130 Bbbl of oil-in-place in the Anadarko Basin region, and 230 Tcf of gas-in-place and 120 Bbbl of oil-in-place in the Permian Basin region.

In the Anadarko Basin region, the estimated gas potential is 600 Tcf in the area of probable success, an area that includes the Anadarko and Arkoma Basins. The estimated gas potential is 0.24 Tcf and the estimated oil potential is 70 Bbbl in the area of possible success, encompassing the Nemaha Uplift, Marietta and Ardmore Basins, Arbuckle Mountain Uplift, southern flank of the Anadarko Basin, and frontal zone of the Ouachita Tectonic Belt in Oklahoma. About 4.4 Tcf of gas-in-place and 60 Bbbl of oil-in-place are estimated for the area of local success, which includes most of the northern and central Oklahoma Platforms.

In the Permian Basin region, the estimated gas potential is 220 Tcf in the area of probable success, which includes the Delaware and Val Verde Basins. The estimated gas potential is 0.11 Tcf and the estimated oil potential is 35 Bbbl in the area of possible success, encompassing the Central Basin Platform and northern flank of the Pecos Arch. About 9 Tcf of gas-in-place and 84 Bbbl of oil-in-place are estimated for the area of local success, which encompasses much of the shelf and platform provinces and most of the Midland Basin.

Although estimates of the volume of undiscovered hydrocarbons are inherently problematic because of the assumptions that must be made to complete the calculations, the mass balance approach yields orders-of-magnitude for in-place oil and gas, and provide a consistent means to compare and rank different areas of interest as to their hydrocarbon production potential.

CONCLUSIONS
The Woodford Shale is a major unconventional energy resource with the potential for producing significant volumes of both oil and gas. Intuitively, its status as a world-class oil source rock indicates that the formation should contain large residual concentrations of hydrocarbons, and analytical data from numerous studies confirm this inference. The inherent inefficiency of hydrocarbon expulsion is the primary reason why source rocks like the Woodford retain large volumes of oil and gas and are attractive targets for unconventional exploration. Given the ubiquity and magnitude of oil and gas shows, local production from naturally fractured reservoirs, recent unconventional production from the Woodford Shale in Oklahoma, successes in unconventional resource recovery from analogous formations, and current oil and gas prices, the Woodford Shale in the southern midcontinent is a compelling exploration target.

Optimum locations for exploration are where organic-rich beds are currently in the oil or gas generation window. Optimum reservoir facies are those comprising brittle lithologies capable of maintaining open fracture networks. The best reservoirs are likely to be completed in mature organic-rich cherts and cherty black shales but other lithologies, such as sandstone, organic-rich siltstone, and silty black shale, can also be expected to produce locally. Areas having the greatest production potential and most prospective lithologies are the Anadarko Basin in Oklahoma, Marietta and Ardmore Basins in Oklahoma, Arkoma Basin in Oklahoma and Arkansas, frontal zone of the Ouachita Tectonic Belt, Delaware Basin in Texas and New Mexico, Central Basin Platform in Texas and New Mexico and the Val Verde and Midland Basins in Texas.

ACKNOWLEDGEMENTS
The author is indebted to Indiana Geological Survey colleagues Kimberly H. Sowder, Barbara T. Hill and Renee D. Stubenrauch, who drafted the figures and formatted the photographs for this article. Also, IGS staff scientists Margaret V. Ennis, Nancy R. Hasenmueller, Maria D. Mastalerz, and Charles W. Zuppann reviewed the article and offered constructive criticisms. IGS editor Deborah A. DeChurch proofread the manuscript. Publication is authorized by John C. Steinmetz, State Geologist and Director of the Indiana Geological Survey.

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THE AUTHOR
John B. Comer is a Senior Scientist at the Indiana Geological Survey with an academic appointment at Indiana University. He earned a BA from Ohio Wesleyan University, an MS from The University of Wisconsin-Milwaukee and a PhD from The University of Texas at Austin, all in geology. During his 36-year career, he worked as a research scientist in the geochemistry group at the Amoco Production Company Research Center in Tulsa, an assistant and associate professor at Tulsa University and the Geochemistry Section Head at the Indiana Geological Survey. Dr. Comer has conducted research in organic, inorganic and environmental geochemistry, clastic sedimentation, sedimentary petrology and the deposition and diagenesis of organic-rich rocks. He is an active member of AAPG, SEPM and GSA and has authored more than 120 scholarly papers and technical reports in geology and geochemistry.