• By Megan Morgan - Oklahoma Magazine | link to article

    The energy sector helps power the Oklahoma economy.

    Few would argue that the energy industry quite literally powers our lives, but Oklahomans especially owe a lot to our local energy companies. These companies help power more than cars and homes; they power the economy.

    SandRidge Energy
    Employ: 1,004

    SandRidge Energy, now headquartered in Oklahoma City, began in Amarillo, Texas, five years ago. Greg Dewey, vice president of communications and community relations at SandRidge Energy, says that the move into Oklahoma City has definitely had an impact on the state.

    “Oklahoma City is one of the most recession-proof cities in the U.S., and one reason for this is energy companies, SandRidge included,” Dewey says.

    Being a new company and a very active driller, Dewey says that Sand Ridge is growing, and that “opportunity” is the key word.

    “It’s a collaborative environment and employees have the unique opportunity to share ideas and innovate here,” he says. “We have a family atmosphere that is special for our growth.”

    Sand Ridge is looking to hire hard workers with a high level of character.

    New Dominion, LLC
    Employ: 100

    Another benefit of the energy industry is the decrease of foreign oil dependence, says chief operating and financial officer of New Dominion, LLC Tim Cargile. And this only begins the impact of energy companies.

    “We as Oklahomans can produce hydrocarbons from our land that create wealth for our citizens and generate tax dollars to fund our state budgets and rebuild our infrastructure,” Cargile says.

    New Dominion digs into Oklahoma’s economy with several hundred wells and is budgeting for 60 more next year.

    “We operate over 300 wells in Oklahoma that will generate over $250 million in gross revenues,” Cargile says.

    New Dominion focuses on the highly technical process of dewatering, made possible by the company’s strong management and field teams, Cargile adds.

    New Dominion’s advanced technology and opportunities for internal promotions also make the company a great one to work for, and the company is hiring in its Land Department and hopes to add 20 new positions in 2012.

    Chaparral Energy
    Employ: 650

    Chaparral Energy might seem small compared to some of the larger energy companies in Oklahoma, but employee relations manager Kyle Essmiller says that their size is actually beneficial.

    “Chaparral is small enough that employees get broad exposure and a wide breadth of opportunity,” Essmiller says. “And we’re also big enough to offer perks.”

    Chaparral is in a position to grow, Essmiller says, and plans to hire for more than 60 new positions, ranging from engineers to accountants.

    In addition to job creation, Chaparral’s field work in rural areas positively impacts the state.

    “Our annual Oklahoma payroll is approximately $50 million, and our annual tax payments are approximately $40 million,”

    Essmiller says.

    Yet, Oklahomans should realize that the energy industry, while growing like never before, is not a new phenomenon.

    “The energy business has been a part of Oklahoma history since the beginning, and it will continue to be so,” Essmiller says. “Oklahoma is very rich in the ground still, and the role and impact of energy going forward can be huge… even national.”

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    By Peggy Williams - Oil and Gas Investor

    Oil is the ticket these days, and an unconventional oil play that's attracting revived interest is the socalled Hunton dewatering play. The concept has been around for years-the Oklahoma Geological Survey reports that some 1,000 wells have been drilled in the Sooner State in Hunton/Misener reservoirs since 2000.

    Oklahoma operators have been pafticularly active in dewatering ventures, led by Tulsa-based New Dominion LLC. "If you think conventionally, water is your enemy. If you think unconventionally, water is your friend," says David Chemicky, president and chief executive. The company targets Hunton, Arbuckle and Cleveland reservoirs, mainly in central Oklahoma.

    Chernicky has been working in dewatering for 26 years. "Dewatering is more like mining than traditional oil production. Dewatering is all about infrastructure and economies of scale," he says.

    The theory of dewatering is simple. Highquality reservoirs exhibit classic three-phase gravity separation, with gas, oil and water stacked one on another. Recovery factors are robust and traditional production methods work beautifully.

    Low-quality reservoirs, however, are often a mishmash of facies, and their oil, gas and saltwater are distributed in various concentrations throughout. It's these heterogeneous, difficult reservoi¡s that are preferred targets of dewatering ventures.

    As it happens, horizontal wells are pafücularly good at dewatering dual-porosity oil reserwoirs, because of their ability to contact so much rock. In dual-porosity reservoirs, water preferentially flows through highporosity pathways, while less mobile oil gets stuck in small and isolated pores. When high-capacity pumps are installed, resewoir pressures drop over time and the associated gas can expand and push trapped oil toward the wellbore.

    Naturally, actual operations are considerably more complicated.

    "You need scale-abundant power, substantial gas gathering and processing facilities and high-volume water disposal infrastructure," says Chernicky. "And you need to drill enough wells. It's a very largescale endeavor."

    And, unlike traditional oil operations, flush production will be mostly water. These wells have present-value challenges, so investors have to be patient and savvy and wait out initial dewatering periods.

    An individual well may make 4,500 barrels of water per day when it's placed on pump; daily oil volume might be 50 barrels along with 200,000 cubic feet of gas. A year later, the same well might make 1,500 barrels of water, 40 barrels of oil and 1 million cubic feet of gas a day. The product mix skews toward liquids, as gas produced during dewatering tends to be extremely rich.

    Additionally, lots of wells are needed because dewatering is not a one-off venture. Banks of wells pumping together work best to create the pressure drop essential to economic production. Typically, wells are drilled on one-section spacing and feature one to five laterals that are completed open hole with no stimulation. Submersible pumps are used until water rates drop below 400 barrels a day, and then wells are shifted to beam pumps.

    It's a margin business, and New Dominion works diligently to reduce costs and increase efficiencies. Last year, it slashed completed well costs by 2O% and overall cosÍsby 25%

    At present, New Dominion is running two rigs in Oklahoma. It plans to spend $130 million this year on its projects.

    Since 2002, when New Dominion adopted its existing structure, the company has grown annual net production 24% per year, from some 2.5 billion cubic feet equivalent (Bcfe) to nearly 9 Bcfe. It operates more than 250 wells and mans field offices in Oklahoma City and Prague, Oklahoma.

    "Instead of looking for individual fields, I invest in infrastructure," says Chernicky. "The only variables in dewatering are the cost of services and the price of the product. The geologic risk is less than 10%, because we are working in areas with long drilling histories and lots of data."

    Without doubt, Chernicky believes that lots of reservoirs across the Patch could respond to dewatering. "'We know that dewatering techniques work in Oklahoma, and we think that they will work in many additional areas."

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    By Rod Walton - Tulsa World | link to article

    PRAGUE — Tulsa-based New Dominion LCC will hold its New Dominion Dayz celebration Friday on the Prague Middle School grounds, marking the company's decade-plus involvement in reopening abandoned oil fields to new production.

    "New Dominion Dayz is a way we've found to give something back to show our appreciation," New Dominion Chairman David Chernicky said.

    Prague, a central Oklahoma community best known for its Kolache Festival also running this weekend, was the site of historic oil development in Oklahoma dating back to the early 20th century.

    The fields, however, were forgotten for decades — deemed as empty or too difficult to tap further because of salt water issues.

    Then Chernicky arrived in the late 1990s seeking a testing ground for his "dewatering" technique. Under the method, directional lines are drilled and vast mixtures of oil, gas and water are pumped out and separated above ground.

    The technique, risky for both New Dominion and local residents at the start, worked better than many expected. New Dominion has spent $475 million for project development in Prague, Seminole and the Oklahoma City in the last four years, said Tim Cargile, chief operating and financial officer of the company.

    Production from the three areas has topped 107 billion cubic feet of natural gas and 2 million barrels of oil, Cargile estimated.

    New Dominion has paid out $61 million in royalties in the last two years, most coming from the Prague fields, Cargile said. The company plans to drill another 30 wells in the area in 2010.

    "There was no activity there at all" before the company's arrival in Prague, he said.

    Prague School Superintendent Rick Martin said New Dominion has donated up to $20,000 annually for scholarships to help 10 to 20 students.

    "That's a pretty significant number," he said, noting that the district has about 75 students in its average graduating class.

    Chernicky and New Dominion also have donated more than $3 million in scholarships, grants and other donations statewide. For Prague, those efforts also include new water wells.

    New Dominion Dayz runs from 11 a.m. to 2 p.m. Friday. It includes Safari Joe's exotic animals, entertainment and a raffle to generate matching scholarship funds.

    The event is back after a one-year absence because of tough economic times for other local sponsors. Canadian Valley Electric Cooperative is a corporate sponsor for this year's event.

    "I couldn't be happier that we're able to bring about its return this year," Chernicky said.

    Read more from this Tulsa World article at

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    By Rod Walton - Tulsa World

    Somebody else might pick up an aged copy of " The Greatest Gamblers " and feel like they were reading of a bygone era, a boom that never will be again. Gone.

    Not Me. Earlier this month, I finally cracked open Ruth Sheldon Knowles' classic exploration of American oil's founding, rise, fall and rise again. Her son Tony Knowles, the former Alaska governor and head of the Tulsa-based National Energy Policy Institute, first told me about the book and his pride in his monther's achievement.

    I can see why. Originally published in 1959 for the centennial celebration of the U.S. oil inudstry, " Greatest Gamblers" lays out tale after tale of risks taken and hopes floated, sometimes rewarded, somtimes dashed.

    Characters with depth

    Mostly it's the story of men whose faith proved them right if not always rich. Edwin Drake, on his last few dollars and wisps of good will, finally struck oil around the creeks of Titusville, Pa., and set off this mania that hasn't subsided 151 years later. Drake gained little from his find except the historical staisfaction of being the man who started it all.

    And then there's my new hero, Mike Benedum. Somehow this historical figure escaped my consciousness until now. He and partner Joe Trees played hunches gave some of the first strong credence to the new science of geology and drilled dry holes and gushers almost in equal measure. Yet Benedum never gave up and, while maintaining the independence of the earliest wildcatters, struck enough fields to make himself into a near billionaire.

    Old made new

    "Great Gamblers" also shows that what goes around comes around.How so? Well, I was forunate enough to join New Dominion LLC Chairman David Chernicky, some of his company's best hands and investors on a field trip several weeks ago to oil and gas operations in Prague, Centerview and Oklahoma City. I saw the old made new again.

    Ten years ago, these were abandoned fields and Chernicky, showing the same verve and diehard resolve as the classic wildcatter, convinced locals, investors and infrastructure builders to belive in his own gamble that plenty of production remaind well below the surface.

    Those fields are now yielding oil and gas from scores of wells. In face, many of historic American oil fields that Knowles touted in her book are sunddenly all rage again, due to better drilling technologies. The biggest percentage growth in new rigs is in oil exploration's original home, Pennsylvania, where the massive Marcellus Shale draws billions' worth of investments.

    Same battles, different age

    Ruth Sheldon Knowles worried about the domestic oil industry giving up too much to the foreign fields. She also quoted grizzled wildcatters who fretted about too much government intervention and the financial pressures of exploreers forced to use the latest gusher's profits to pay for the last dry hole's expneses.

    Some things never change, not 51 years ago, not ever. Read "The Greatest Gamblers" again and be impressed.

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    By Rod Walton - Tulsa World | link to article

    David Chernicky is chairman of New Dominion LLC, a Tulsabased producer known for recovering untapped oil and gas from existing fields. A native Oklahoman and longtime geologist, Chernicky formed New Dominion in 1998 with two other partners. He took full ownership of the company four years later.

    1 New Dominion is known for its specific "de-watering" technique in recovering oil. Can you tell us how it works?

    De-watering is a process that produces all the in-place saltwater and the liquid and gaseous hydrocarbons within a targeted production zone. It's also one that requires a lot of infrastructure before you produce any oil and gas.

    Our process represents a paradigm shift in thinking in oil and gas production because it recovers vast amounts of hydrocarbons left behind by earlier conventional producers due to the amount of saltwater present.

    Economies of scale matter. I remember the first wedding I attended as a young teenager. No one would pour me a fresh glass of champagne, given my age. But I had a great time drinking all of the leftover, half-empty glasses even though the champagne was a bit warm and flat. Eureka! One person's trash is another's treasure.

    2 Your company is a supporter of Energy Libraries Online, an effort to digitalize old well logs and other early industry production data previously found only on paper. How is the process going?

    Unfortunately, the effort has been hampered by a lack of funding because of depressed economic times and perhaps some short-sightedness within our industry. But this data must be saved now, or it will be lost forever. The consolidation and conversion to a more permanent medium of these vast amounts of historic scientific data is of paramount importance for future generations of petroleum producers.

    3 Horizontal drilling has opened up vast new fields for natural gas producers. Can you elaborate on this technique?

    Without a doubt, horizontal drilling is the most important innovation in oil and gas exploration during the past 50 years because it effectively represents the evolution of man-made technology to emulate nature.

    Visualize an oil and gas reserve underground. It isn't packaged in a barrel-like basin. Instead, it typically is a heterogeneous reservoir of hydrocarbon-producing rock that covers a large area and, conceptually speaking, could be considered as the single leaf of a tree.

    A conventionally drilled vertical well just punches a hole in that reservoir, only recovering a small percentage of its resources. On the other hand, an accurately drilled horizontal well functions like a leaf's vascular system for that reserve, because it runs longitudinally across and through it, providing a maximum bidirectional flow.

    4 New Dominion had some exposure to SemGroup prior to that company's bankruptcy. How has the experience changed the way companies handle their risk management issues?

    The collapses of SemGroup, AIG, Lehman Brothers and the entire world economy were the results of a larger endeavor. I'd suggest that your readers closely watch the congressional hearings investigating this matter.

    With respects to risk management, it has forced the entire industry to reduce its exploration expenditures because of a lack of market capital. This brings to the forefront the importance of our counterparties on all transactions — not just hedging — and of understanding the financial strengths and commitments of our bank groups, financial investors and purchasers.

    5 Exxon Mobil recently made a big move into natural gas with its $31 billion buy of XTO Energy Inc. Do you see other majors pushing their way into unconventional drilling, and what impact will that have?

    I don't foresee other majors making such a large entrance, but I do see and predict more investment by foreign and state-owned companies, similar to the strategic alliance announced in November between Norway's StatoilHydro and Chesapeake Energy to produce natural gas from the Marcellus Shale. They're taking a long-term view here.

    But the major impact of these investments by mega-companies will, I fear, have a negative impact on other independents, smaller companies and consumers because it will drive the already-inflated cost of services through the roof, decreasing profitability for all producers without a significant increase in total production.

    Read more from this Tulsa World article at

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    By Tom Lindley - The Journal Record

    OKLAHOMA CITY – Southeast Oklahoma City’s long-gone oil patch has become a twice-dreamed field of dreams.

    And, if it can happen here, said David Chernicky, an oil and gas man with a healthy unconventional streak in him, it can happen in a lot of places.

    "You can’t fathom the amount of oil and gas left to be recovered in Oklahoma alone," said Chernicky, chairman of New Dominion LLC of Tulsa.

    There is a catch.

    Chernicky’s strategy of targeting previously produced reserves and restoring them to life with his perfected saltwater extraction method involves substantial infrastructure costs that won’t be recouped overnight, which has made him stand out in an industry of mavericks.

    "If you graded me as a textbook geologist, I am a complete and utter failure," Chernicky said. "That’s because the only appreciable amount of oil and gas I’ve found the way the textbooks say to find it is by an accidental blowout."

    Yet, if he is measured by the 100 million barrels of oil and 2 trillion cubic feet of natural gas his dewatering process has produced, well, textbook authors might revise their thinking.

    When Chernicky started New Dominion in 2002, it had 16 employees and operated fewer than 20 wells. Today, his company has eight officers, 75 employees and operates about 300 wells. In 2009, the company drilled a total of 437,277 feet or about 83 miles, and completed 27 wells.

    While its Prague/Seminole field is its largest project, New Dominion’s foray into the all but abandoned legendary Oklahoma City field has set conventional wisdom on its ear.

    A neighborhood, a whole city even, had grown up around the spot where the Oklahoma City No. 1 original discovery well struck oil on Dec. 4, 1928. Hundreds of wells dotted the landscape in the early days. In all, the field produced more than 735 million barrels of oil and more than 2 trillion cubic feet of natural gas until 1969, when most were of the wells were plugged.

    As a student of history, Chernicky knew the field wasn’t dried up. It simply fell victim to the times and extraction methods of the day. "The original discovery zone was in the Arbuckle formation in 1928," Chernicky said. "What happened not long after that? Well, the stock market collapsed, everybody ran out of money and oil went from $1.50 to 15 cents a barrel," Chernicky said.

    To stifle the flow in hopes of stabilizing price, the state shut down the field.

    "When they closed the valves, the water in the reservoir filled the pore spaces and killed the well," he said. "Instead of having a case pipe full of oil and gas, it was full of saltwater, and it didn’t make economic sense to pump oil and water out of those zones when other zones produced better flows."

    Seventy-five years later, Chernicky is dreaming the dream in the same old field, only he’s got the technology and the conviction of his beliefs to put everything on the line.

    Typically, Chernicky looks for areas in and around conventional reservoirs, but he was attracted to the Oklahoma City field because the Arbuckle reservoir had produced only a fraction of its reserves.

    Chernicky has spent most of his career perfecting a nonconventional approach that he first saw put into practice in a field in Pawnee in 1982 by someone who didn’t "revere the textbooks."

    "I said, wait, this is counter to everything I’ve learned, but I also thought it was so intuitively simple," he said. "I’ve spent 28 years trying to figure how it works, why it works, whether it’s a singular application or can be turned into a niche. It’s not like I invented it, but I think by intuition was correct."

    New Dominion’s process uses high-volume, electric submersible pumps in its wells to pull water, gas and oil from rock formations in a way that enables them to being producing high-quality oil and natural gas once again. And, unlike conventional reservoirs, the production in New Dominion’s wells tends to improve over time as more water is extracted.

    The projects also require specially designed separators installed on production pad sites to separate out water, natural gas and oil. From there, the water is sent to disposal wells through an elaborate underground pipe system the company installed in the middle of an urban area. The oil is stored in tanks for pickup by trucks and natural gas flows into a gathering system and then to a processing plant constructed at the site. Because the upfront costs are daunting, Chernicky compares dewatering to offshore drilling and the high costs of putting up platforms and pipelines.

    With 20 wells now operating in his Southern Dome Field in southeast Oklahoma City, his investment is only now beginning to come to fruition as average daily production has hit about 1,000 barrels of oil and about 12 million cubic feet of gas.

    "Hey, it’s like going to the moon," he said. "You do the best you can, but sometimes you have a hiccup."

    However, he has no doubts about the big picture.

    "What we are seeing in southeast Oklahoma City is applicable in many reservoirs around the world as the global need for oil continues to grow and conventional methods get tougher," he said.

    He also said success is more about empirical evidence and understanding the nature of the investment than it is luck.

    "I don’t rely on luck. I rely on science because I’ve never been lucky in my life," he said.

    "I never won a raffle. The only thing I got was out of a Cracker Jack box but then everybody gets something out of that box."

    He does think it would be a lucky day for consumers if geology students have an opportunity to get something out of a college textbook about nonconventional production techniques.

    "Basically, we are redefining the levels of economic productivity that have been set forth in textbooks that were written when there were so many conventional reserves that people didn’t have to think a little bit outside the box," Chernicky said.

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    Dan T. Boyd, Oklahoma Geological Survey

    This article is a summary of 2009 Oklahoma drilling activity and highlights results that became public by January 1, 2010. Significant wells registered after this date will appear in next year’s summary. Except where noted, all data were supplied online by Petroleum information/Dwights LLC dba IHS Energy Group, all rights reserved. Without this excellent database this report could not have been completed. Editing was performed by Neil Suneson and cartography by Russell Standridge, both from the Oklahoma Geological Survey.

    General Activity

    The number of working drilling rigs is a fundamental barometer of oil and gas activity in any area. The Baker Hughes Company has tracked monthly rotary drilling rig counts for many years for regions all over the world. According to Baker Hughes (2010), the number of active drilling rigs in Oklahoma went from a high of 219 during the week of September 5, 2008 to a low of 69 working rigs about one year later (Figure 1). This loss of 2/3rds of the active rigs in the space of one year is the central theme of this review. The good news is that since reaching its low in September, the trend has been modestly but steadily upward, reaching a year-end level of 95 active rigs. The 2008 to 2009 decline ended a mostly continuous rise in Oklahoma’s working rig numbers that began in 2003. This drop in the State’s average annual rig count puts us on a par with the level seen in 2002 (Figure 2).

    In a State in which gas drilling usually represents 2/3rds to 3/4s of all wells completed, the price of natural gas is by far the most important factor controlling drilling activity in Oklahoma. The close correlation between natural gas prices and drilling activity can be seen by comparing Figure 2 with Figure 3. Sharp drops in price in 2002 and 2009 reduced the number of working rigs below 100 in both of those years. The rise in prices in the intervening years saw Oklahoma drilling activity rise to levels not seen since the drilling boom of the early 1980s.

    The average 2009 wellhead natural gas price in Oklahoma is projected to be approximately $3.27 per thousand cubic feet (MCFG) (Soltani, 2009). This is less than half last year’s average price, which, at $7.32 per MCFG, was an alltime record (Figure 3). Although at this writing, prices have increased modestly due to unusually cold winter weather; the long-term course of natural gas prices and future drilling activity is as impossible to predict as winter weather and the speed at which the U.S. economy will recover. Of greater concern than the number of active rigs at any given moment is the fact that more than one quarter of the State’s gas production comes from wells that are less than a year old (Boyd, 2005). Reporting lags make it difficult to determine precisely, but the sharp fall in drilling activity in 2009 looks like it will precipitate a reduction in State gas production of between five and ten percent. Thus, as well as making each cubic foot less valuable, low natural gas prices also rapidly reduce the volume that can be delivered. This reduces not only operator income, but because gas represents 82% of BOE (barrel of oil equivalent) production, it is the key factor in lower gross production tax revenue and State budget shortfalls.

    Total completions in 2009 were 53% gas and 35% oil (Figure 4). The larger proportion of oil completions over previous years is due to the fact that in the 2009 oil drilling declined about a third while gas dropped by over half. Water-injection and disposal wells represent about 5% of 2009 drilling with dry holes accounting for only 7% of the total. This overall 93% success rate is comparable to previous years and shows that drilling for both oil and gas in Oklahoma continues to be overwhelmingly developmental. Reporting delays increased the number of 2008 registered completions from last year’s report by 33%. If this delay remains constant through the coming year, it is estimated that the total number of 2009 completions will be roughly 2,800, reflecting a 40% decrease over 2008’s total of about 4,800 completions.

    Hundreds of companies drilled wells in 2009, but Chesapeake Operating continues to be by far the most active operator (Figure 5). The 272 completions registered through January 1st are half the 545 completions that were assigned to them in last year’s report. However, these still represent more than one in eight of all wells drilled in Oklahoma in 2009. Chesapeake drilled wells in almost every area of the State, but favorite targets were the Chester and Mississippian on the Anadarko Shelf and the Des Moines Granite Wash in the deep Anadarko Basin.

    In order of number of wells completed, other major operators in 2009 include New Dominion, whose activity rose substantially from 2008. Their drilling is associated almost exclusively with dewatering projects, and these are concentrated in the Misener-Hunton in the central part of the State and the Arbuckle in the Oklahoma City Field. Newfield Exploration’s activity was restricted to horizontal Woodford development in the main Woodford fairway located the western Arkoma Basin. XTO Energy’s activity was divided mostly between horizontal Woodford development wells in the same area and gas development in a variety of reservoirs on the Anadarko Shelf. Citation Oil and Gas concentrated their activity in oil development in southern Oklahoma, mostly in the Healdton, Fitts, and Sho-Vel-Tum Fields (Figure 5).

    Horizontal Drilling

    Oklahoma has abundant conventional and unconventional low-permeability reservoirs. This has helped make horizontal drilling by far the most important drilling/completion technique to be recently applied in the State. Horizontal-drilling technology has made formerly unproductive areas and reservoirs profitable and revitalized reservoirs that have been producing for decades. Its share of drilling continues to grow with horizontal wells now representing 27% of all State drilling.

    In addition to increased wellbore exposure to low-permeability reservoirs, horizontal drilling is useful in dewatering dual-porosity oil reservoirs. Dewatering is the process by which reservoir pressure is reduced in fields with natural water support through aggressive water production. This production triggers associated gas expansion in poorer (unswept) parts of the reservoir, forcing oil into the naturaland/or induced-fracture system and ultimately into the wellbore. Most of the notable wells listed in this report are horizontal completions.

    Almost every significant productive reservoir in the State has been drilled horizontally somewhere, but some have been systematically exploited in well-defined area(s) which can be thought of as geologic plays. Using an arbitrary 50-well cutoff, there are three horizontal plays that, while still producing, are largely inactive in terms of drilling. Chesapeake utilized horizontal-drilling technology in the mid- to late-1990’s to pursue mostly oil in the Sycamore carbonate in southern Oklahoma. Most of these wells are located in Sho-Vel-Tum Field and the Golden Trend. EOG Resources in western Texas County made another largely inactive horizontal play. Here they drilled about 70 horizontal gas wells between 2000 and 2003 in the Council Grove, mostly in Unity SW and Guymon-Hugoton Fields (Figure 6).

    A much more scattered and diverse horizontal play is targeting the Mississippi Lime and Chat. The Mississippi Lime is a regional carbonate that is found across most of the State. Reservoir quality tends to be poor, but it is often fractured, and horizontal drilling affords the opportunity to encounter more of these fractures. This strategy seems to be behind gas drilling in McIntosh County in the northern Arkoma Basin as well as oil-targeted drilling along the northern shelf of the Anadarko Basin. Of particular interest in horizontal Mississippi Lime development is Chesapeake’s drilling in northeastern Woods County. Here they have had some success (see Well #4) with multi-stage fracture stimulations on horizontal Mississippi Lime wells, 11 of which were completed in 2009 (Figures 6 and 7).

    A related horizontal play, which because of inconsistent reservoir naming is here combined with the Mississippi Lime, is the Mississippi Chat. The Chat, a thin, siliceous zone of variable reservoir quality that intermittently develops on top of the Mississippi Lime, can be identified seismically. Horizontal wells located and oriented based on seismic anomalies have allowed operators to maximize reservoir exposure to the Chat. This play has been largely restricted to western Osage and Kay Counties on the Cherokee Platform (Figure 7).

    In an aggressive dewatering project that utilizes horizontal drilling, New Dominion has targeted the Arbuckle in the Oklahoma City Field (Figure 6). Here they have drilled 51 horizontal laterals from 17 surface locations since 2004, with seven registered thus far as 2009 completions. Cumulative production stands at about 1.4 MMBO and 10.0 BCFG, with latest daily rates of about 1,000 BO and 13 MMCFG. New Dominion is now disposing over 145,000 BWPD, which is going back into the Arbuckle via horizontal wells drilled on the downthrown side of the field’s trapping fault.

    The most active horizontal plays and their drilling activity over the last five years are shown in Figure 8. The 2009 totals for each of the six categories listed have been increased by 33% in an attempt to account for the reporting delays described previously. This gives a more accurate year-to-year comparison and hopefully shows the direction that activity in these plays is taking.

    The Woodford horizontal play appeared to remain nearly as active as it was in 2008. That this could happen in a year in which natural gas prices fell by over half (Figure 3) is probably due to the fact that a large number of expensive leases are nearing expiration. Most of the horizontal Woodford drilling in 2009 was concentrated within or close to established fairways. The largest of these lies in the western Arkoma Basin in a broad trend extending from north-central Pittsburg and Hughes through Coal and western Atoka Counties. In 2009 this fairway expanded eastward, becoming more contiguous with satellite areas located in Pittsburg County. Many operators were active in this area, but Newfield Exploration continues to be the dominant player (see Well #11).

    The smaller fairway located in the Anadarko Basin in western Canadian County saw 46 horizontal Woodford wells completed in the last 12 months. Most were located within the established productive area, but others will enlarge the play west and south into Blaine and Caddo Counties (Figure 6). Overall, Devon Energy and Cimarex Energy were the most active operators in 2009 in this area (see Well #8).

    The last area of major horizontal Woodford drilling is located on the northern flank of the Ardmore Basin. After more than two-dozen completions in 2009, disconnected groups of wells will merge into a more contiguous trend extending from northeastern Marshall into north-central Carter County (Figure 7). This area tends to produce more liquids than the western Arkoma or Anadarko Basin parts of the play (see Well #9).

    Since 2005, about 1,100 horizontal Woodford wells have been drilled, about a third (363) of which will be completed in 2009. There are now 919 horizontal producing wells and these have brought production in four years to over 880 MMCFGPD. Cumulative horizontal Woodford production now stands at about 493 BCFG. This yields an average perwell cumulative volume of just over one half BCFG and an average rate of about 960 MCFGPD (IHS Energy, 2010). Although true of all plays, but especially so because of its high initial declines, the direction that Woodford production takes from here will be entirely dependent on drilling activity, which in turn is dependent on the price of natural gas.

    Hartshorne coalbed methane has been exploited in the Arkoma Basin with horizontal wells for more than a decade. During this time over 1,550 wells have been drilled. However, the fall in natural gas prices has reduced horizontal Hartshorne drilling activity by about 85%, giving it the largest decline in activity for any major horizontal play in 2009 (Figure 7). Before being eclipsed by the Woodford in 2007, the Hartshorne coalbed play was by far the most active horizontal play in the State. Cumulative horizontal Hartshorne coalbed methane production now stands at 336 BCFG with a current daily rate of 142 MMCFGPD. Cumulative production for the average well now stands at 214 MMCFG at a current rate of about 150 MCFGPD.

    Dewatering has found its greatest application in the Hunton (Misener/Hunton) reservoir where nearly 1,000 wells have been drilled in the last seven years. This method of production has been pursued in a number of areas but is mostly concentrated in central Oklahoma in and around Lincoln and Seminole Counties. Like the Woodford, this play remained strong in 2009, largely due to the efforts of New Dominion, who accounted for over half of the 2009 Misener/Hunton horizontal drilling in Oklahoma. Most of this drilling has stayed within previously established fairways (Figure 7).

    Horizontal drilling activity targeting the Cleveland sandstone fell by about a third in 2009, presumably because the most prospective acreage in the established trend has been drilled. Horizontal Cleveland activity had been restricted to central Ellis County (and the Texas Panhandle), but in the past year a number of outliers have been drilled, the most notable being six new wells mostly in southwestern Dewey County (see Well # 2). This new area is 30 miles from the main fairway and is characterized by high initial gas rates with varying volumes of condensate with gravities up to 48º API. Similar production characteristics are seen in the main fairway in Ellis County, but it is not yet known if horizontal Cleveland production in these two areas will eventually be linked into a single large trend (Figure 6).

    The Des Moines Granite Wash horizontal play (see Well #5) is located in the deep Anadarko Basin in Washita County (Figure 6). Vertical wells have produced from this formation since the mid-1980s, but horizontal production only began in April 2007. In slightly more than two and a half years this play has produced about 50 BCFG and 2.8 MMBC at a rate of 120 MMCFG and 11 MBC per day (IHS, 2010). Despite the fact that most of the 72 producing wells have been on line for under a year, this yields an average per well recovery thus far of about 700 MMCFG + 40 MBC. In the Des Moines Granite Wash play Chesapeake operates 66 of the 76 horizontal wells, which they call their Colony Wash Play. The play has increased in activity every year and this is expected to continue as Chesapeake indicates that it will drill 40 net wells in 2010 using the seven rigs that it has now dedicated to this play (Chesapeake Energy, 2009). Numerous staked locations and uncompleted wells suggest that this play will expand both east and west from its current ‘sweet spot’ in north-central Washita County.

    The Oklahoma oil and gas industry is applying horizontal-drilling technology to a variety of other reservoirs across the State. Many wells are clearly sub-economic, but others are showing promise. These wells are classified as ‘Other’ in Figure 8. Reservoirs that are being more actively pursued include the Tonkawa, Sylvan, and Viola, each of which has 15 to 20 completions registered for 2009. These or others may eventually develop into larger horizontal-drilling plays. With Oklahoma’s myriad reservoirs exhibiting low-permeability, dual-porosity systems, thick transition zones, or compartmentalization, it is virtually certain that other plays will emerge in the future.

    Significant Wells in 2009

    The following is a list of what are, or may become, significant wells for 2009 in Oklahoma. It is based on a weekly review of wells described in the IHS Energy EnergyNews on Demand Mid-Continent activity reports that were released online throughout the year. An initial list of 138 possibilities compiled from this publication was distilled to a total of 13. Such a list is necessarily subjective and may miss wells that could eventually become noteworthy. Due to confidentiality issues, wells that may be notable for technical reasons will probably be missed. For instance, those that confirm some new type of trapping style or proved the benefit of a new completion technique will be difficult to identify until information is disseminated years later.

    The wells shown here are of two general classes – those that establish significant production more than one mile from existing production in the same reservoir, which is the standard to be considered a discovery, and those that are notable for other reasons. The latter include rank wildcats, major play expansions, or wells that prove the benefit of new production and/or completion techniques. The following are wells reported as completed in 2009 that are considered significant (Figure 9).

    1) Sec. 29-1S-23W (Jackson County): GLB Exploration is in the process of testing the State’s first horizontal Barnett Shale well – the 1-29 Hatch. Located in far southwestern Oklahoma in the Hollis Basin, the well is three miles from the Texas border. At last report the well had reached its pre-drill projected depths: measured depth (MD) of 12,481’ and a true vertical depth (TVD) of 8,400’. The Barnett Shale in the Fort Worth Basin was the first major shale gas reservoir to be exploited in the world. The horizontal drilling and completion techniques that were pioneered there laid the groundwork for all future shale gas plays. Success or encouragement with the Hatch well will likely set off additional drilling and potentially initiate a new play for the State.

    2) Sec. 28-16N-19W (Dewey County): An area with two isolated horizontal Cleveland wells in western Dewey and Custer Counties received a boost in 2009 with the drilling of five additional wells. The best of these was the JMA Energy Chester Owens #1-28H. This well had an initial potential of 6.9 MMCFGPD + 379 BCPD (45º API) from an open-hole completion in the last 400’ of a 4,300’ lateral. This interval (TVD 9,768’) was fracture stimulated in a single stage with about 850,000 pounds of sand. In four months of production the Owens made 681 MMCFG + 18 MBC with a rate in its last month of 5.8 MMCFGPD. This area is about 30 miles southeast of the main Cleveland horizontal fairway located in Ellis County and indicates that the productive limits of this reservoir are far from defined (Figure 6).

    3) Sec. 35-20N-4W (Garfield County): Underscoring this statement, Kirkpatrick Oil drilled a horizontal Cleveland well over 100 miles northeast of the JMA Energy well (Figure 6). Completed in a 2,500’ lateral (TVD 5,180’) that was fracture stimulated in a single stage with 400,000 pounds of sand, the LaDonna #1-35H had an initial flowing potential of 103 BO + 485 MCFG + 445 BWPD. In its first six months online the well produced a relatively modest 10 MBO with a rate in its last month of 60 BOPD. History shows that horizontal recoveries can improve dramatically as drilling/completion practices are refined and integrated with geology. Time will tell if this area will become a focus of horizontal Cleveland Sandstone production.

    4) Sec. 3-28N-15W (Woods County): Widely scattered horizontal Mississippi Lime production (Figure 6) found at least a temporary focal point with the drilling of the Chesapeake Serenity 1-3H. Completed in January 2009, this well had an initial flowing potential of 1,250 BO + 1,064 MCFG + 1,392 BW per day with a MD of 9,212’ and a TVD of 5,071’. The well was perforated from 5,480’ to 9,156’ and acid-fracture stimulated in seven stages with about 125,000 pounds of sand per stage. Several follow-up wells have been drilled around the Serenity, each fracture stimulated in a single large (800,000-900,000 pound) stage. In its first ten months online the Serenity has produced about 61 MBO and 82 MMCFG. Chesapeake’s four follow-up wells had initial potentials between 48 and 271 BOPD, but none in three to five months has produced more than 2 MBO and 8 MMCFG. Time will tell if elaborate acid-fracture stimulations are economically justified in the Mississippi Lime.

    5) Sec. 13-11N-19W (Washita County): A well for which economics are not in question is the Chesapeake Huls USA #1-13H. Completed in February, this well was drilled in the Des Moines Granite Wash with a MD of 16,851’ and TVD of 12,527’. Its initial potential was, for this play, a modest 5.734 MMCFGPD. However, in its first eight months of production it has made 1.994 BCFG and 32 MB of 55º API condensate. Even more impressive than cumulative production is the fact that in its last month of production the Huls USA was making 15 MMCFGPD. This well produces from a 4,156’ lateral that was fracture stimulated in a single stage with about 2.1 million pounds of sand. Located on the western edge of the current play fairway (Figure 6), future drilling will certainly expand this play in the coming year.

    6) Sec. 16-9N-16W (Washita County): Chesapeake has established excellent production in an almost unproductive township in the deep Anadarko Basin. Their South Fork #1-16 was completed in late 2008, but did not register until this year. It was drilled southwest of the only productive well in the township (10-9N-16W), which is the GHK Garst #1-10. A 22,850’ well drilled in 1981; it produced 1.1 BCFG from the Morrow. Chesapeake perforated the Springer in their new well from 21,536-544’ and fracture stimulated it in two stages with about 200,000 pounds of sand. Although the South Fork’s initial potential was 6.6 MMCFGPD, in its last month online it was producing 8.2 MMCFGPD, and has cumulative production in 12 months of 3.1 BCFG. Chesapeake has offset the South Fork with a well (Merkey #1-15) in Section 15. This well has no listed initial potential, but produced an average of 5.2 MMCFGPD in its first month. Chesapeake has permitted two additional wells in Sections 10 and 20 of the same township.

    7) Sec. 10-6N-11W (Caddo County): Continuing on the success of their Norma Jo well (Sec. 6-6N-11W) that appeared in the 2007 drilling highlights report (Boyd, 2008), St. Mary Land & Exploration drilled two excellent development wells and a 2.5-mile step-out to their production in Broxton North Field. This step-out, the #1-10 Wilt, had an initial potential of 6.2 MMCFGPD in the Springer from perforations from 19,982-20,002’. In its first 11 months online this well has produced about 1.8 BCFG and continues to produce at an average rate of 4.1 MMCFGPD. This is the 6th deep Springer well to be drilled by St. Mary in this area in the last two years. In the last reported month these wells were producing a combined 50 MMCFGPD and had a cumulative production of about 23.5 BCFG.

    8) Sec. 21-13N-11W (Blaine County): Although not the best horizontal Woodford well drilled in the Anadarko Basin in 2009, the Marathon Hicks BIA #1-21H was the best step-out from the established producing trend. Highlighting the pitfalls in judging wells based only on their initial potentials, this well initially tested at only 1.3 MMCFG + 1200 BWPD. However, in its first seven months of production it has made 706 MMCFG with a rate in the last month of about 3.0 MMCFGPD. The well produces from a 3,800’ lateral (TVD 14,170’) that was fracture stimulated with a total of about 1.3 million pounds of sand introduced over an 8-stage treatment.

    9) Sec. 15-4S-1W (Carter County): In a major step-out, XTO Energy completed a horizontal Woodford oil well 7.5 miles southwest of the nearest Woodford production in the established producing trend in the Ardmore Basin. The Prairie Valley #1-15H had an initial potential of 310 BO + 2,154 MCFG + 1,946 BWPD from a 3,780’ lateral with a TVD of 10,834’. The well was fracture stimulated in a single stage with 100,000 pounds of sand, which is very modest by Woodford standards. The well has not yet been put on production, but any encouragement has the potential to dramatically increase the prospective area for horizontal Woodford in the southern Oklahoma.

    10) Sec. 29-4N-12E (Pittsburg County): Based on cumulative production, the best horizontal Woodford well drilled in 2009 in the main area in the western Arkoma Basin was BP America’s IGOU #1-29H. Cumulative production for this well is 1,309 MMCFG in nine months on line. Of note is the fact that in its last month it was still producing at a rate of about 3.5 MMCFGPD, which is just below its initial potential of 3.65 MMCFGPD. This well produces from a 3,500’ lateral (TVD 8,583’) that was fracture stimulated with 1.5 million pounds of sand in a one-stage treatment.

    11) Sec. 22-2N-10E (Coal County): In a demonstration that there is more to drill horizontally in the western Arkoma Basin than just the Woodford, Newfield Exploration has five laterals planned from a single surface location. Their Cunningham well has three Viola laterals planned (3H, 4H, and 5H), one Woodford lateral that is already producing (1H), and a Cromwell lateral (2H) that was recently completed. The Cromwell completion was made in a 4,900’ lateral at a TVD of about 7,600’. This well underwent a 10-stage fracture stimulation with about 300,000 pounds of sand per stage. The initial potential was 6.5 MMCFG + 1,010 BWPD. Two Woodford laterals from another surface location are already producing in this section, each with a cumulative production of about 900 MMCFG and a current rate of about 1.3 MMCFGPD.

    12) Sec. 34-3N-20E (Latimer County): Although it was completed as a dry hole, GHK set a benchmark in 2009 by drilling the deepest well in the Arkoma Basin. Drilled to 26,100’, the #2-34RE Mary well was the reentry of a deep (20,628’) Jackfork producer in the Potato Hills Field. This well produced about 475 MMCFG through perforations from 18,235-18,347’. The reentry tested subthrusted Oil Creek and Arbuckle from 25,170-25,422’. This interval was treated with about 300,000 pounds of bauxite, but tested gas a rate that was too small to measure.

    13) Sec. 20-6N-22E (Latimer County): The Atokan Red Oak sandstone has produced gas for decades across a broad swath of the Arkoma Basin through Pittsburg, Latimer and Le Flore Counties. Since 2007 BP America has drilled and completed 15 horizontal Red Oak producers in part of this trend within the Red Oak Field. In an average producing life of about one year these wells have produced a combined 12.5 BCFG and continue at a rate of about 28 MMCFGPD; this despite the fact that they lie in a sea (~ 40-acre spaced) of vertical Red Oak producers. The BP Martin Unit #C-12 was completed in June and in its first month made 227 MMCFG. This average rate of 7.5 MMCFGPD was 3 times its initial potential of 2,579 MCFGPD. The C-12 well was completed in a 3,600’ lateral (TVD 8,024’) and fracture stimulated in one stage with about four million pounds of sand. Time will tell how much gas can be recovered from the less permeable parts of the Red Oak reservoir that the vertical wells have been unable to access, but if this technique can be applied throughout the play, the potential is enormous.


    Dan Boyd is a petroleum geologist with the Oklahoma Geological Survey, where he has been employed since 2001. Dan received his Master of Science degree in geology from the University of Arizona in 1978. He spent the first 22 years of his career as an exploration and development geologist in the petroleum industry. From 1978 through 1991 he worked on a variety of areas in the United States from Houston, Dallas, and Oklahoma City for Mobil Oil and Union Texas Petroleum. In 1991 he moved overseas, working in Karachi Pakistan for four years and Jakarta Indonesia for the following four. He returned with his family to the U.S. in 1999 with Arco (the successor to Union Texas) where, until Arco's sale to BP, he worked the offshore Philippines from Plano, Texas.

    Since joining the OGS staff Dan has presented and published several reports on the history, status, and future outlook of the oil and gas industry in Oklahoma. He chaired the 2002 Symposium on Cherokee Reservoirs in the Southern Midcontinent (OGS Circular 108), and prepared and presented a workshop on the Booch gas play in southeastern Oklahoma (Special Publication 2005-1). His most recent study of oil reservoirs and recovery efficiencies (Shale Shaker May/June, 2008) demonstrates that large volumes of producible oil remain in the ground and that a major barrier to finding and producing this oil is shortcomings in State oil and gas data. Dan serves on the board of Energy Libraries Online (ELO) from a conviction that the long term success of the Oklahoma industry depends on improving both the completeness and accessibility of State oil and gas data.


    • Baker Hughes, 2010, 2009 Average Rotary Drilling Rig Count, Accessed at:
    • Boyd, D.T., 2002, Map of Oklahoma oil and gas fields (distinguished by GOR and conventional gas vs. coalbed methane: Oklahoma Geological Survey Map GM-36.
    • Boyd, D. T., 2005, Oklahoma oil and gas production: Its components and long-term outlook: Oklahoma Geology Notes, v. 65, no. 1, p. 4-23.
    • Boyd, D. T., 2008, Oklahoma 2007 Drilling Highlights, Shale Shaker (Journal of the Oklahoma City Geological Society, Vol. 58, No. 5 pp. 173-181.)
    • Chesapeake Energy, October 29, 2009, Chesapeake Energy Corporation Provides Operational Update, accessed on Internet at:
    • IHS Energy, 2010, Well Data supplied online by Petroleum Information/Dwights LLC dba IHS Energy Group, January 1, 2010, all rights reserved.
    • Northcutt, R. A.; and Campbell, J. A., 1995, Geologic provinces of Oklahoma: Oklahoma Geological Survey Open-File Report 5-95.
    • Soltani, Cameron, 2009Oklahoma Corporation Commission, Oil and gas information: Oklahoma Corporation Commission: 2008 Report on Crude Oil and Natural Gas Activity within the State of Oklahoma; accessed at: REPORT.pdf, partial 2009 data from personal communication, December 22, 2009.
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    By Jack Money

    The Oklahoma City Oil Field isn't done yet.

    A local company and its partners have put $250 million and eight years of hard work into the Oklahoma City field, and expect to begin seeing positive cash flow from its 20 producing wells by the end of this year.

    New Dominion entered the area in southeast Oklahoma City — all but abandoned as an oil and natural gas reservoir decades ago — with a unique, but well-tested theory that more oil and gas could be recovered from the field.

    The company is dewatering the field, capturing oil and gas brought up with saltwater and sending the water back into the ground using disposal wells that are on the field's far side — actually on the opposite side of a fault line that divides the area.

    How the wells are being used

    Producing wells' pumps are submerged within the wells and powered by electricity, pushing fluid to a three-phase separator on pad sites, where it separates and measures the oil, natural gas and water. The oil flows to a central storage area of two, 10,000 barrel tanks via pipeline. The gas goes straight into lines that lead to a natural gas processing plant built by Scissor Tail Energy capable of treating 15 million cubic feet a day (and expandable up to 80 million cubic feet a day) for the project, while the water is piped back to the disposal wells.

    "I am using natural hydrology" to recover the oil and natural gas, said David Chernicky, New Dominion's president and chief executive, who estimates the field still contains at least 50 million barrels of recoverable oil and more than a half-trillion cubic feet of gas.

    Chernicky said he first saw the technology he is using today in 1982, was intrigued by it, and has been working ever since to perfect its application to old fields like the one in Oklahoma City.

    "I basically have been rewriting the geology and engineering books when it pertains to dewatering," Chernicky said.

    Bob Griffith, a field inspector with the Oil & Gas Conservation Division of the Corporation Commission, said New Dominion has developed its dewatering technology into a science. During the recent Mid-America Regulatory Conference in Oklahoma City, he provided an overview of New Dominion's field operations and took a tour group to some of its locations.

    "One well, for instance, makes 3,500 barrels of water a day — now that's an oilfield barrel, which holds 42 gallons, so you begin to see the enormous amount of water" a well produces, he said. "But from that well, they are making massive amounts of oil and natural gas.

    "This oil is so good, as far as its content," Griffith also said. "They've got the technology, the people, and they can do it safe."

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    By Peggy Williams, Senior Exploration Editor, Oil and Gas Investor

    When prospectors first started to drill for crude oil in Oklahoma, it was not yet a state and petroleum geology had not yet developed as a science.

    Random wildcatting (mixed with a fair amount of luck) yielded excellent discoveries in various parts of Oklahoma, and people began to untangle subsurface relationships.

    What soon became abundantly clear was the complexity of Oklahoma’s buried oil and gas reservoirs. Drillers were puzzled by great thicknesses of steeply dipping beds beneath the state’s diverse landscape. Prospectors were perplexed by the source of oil and its migration into disparate reservoirs. Multiple unconformities in the geologic section created unusual juxtapositions.

    Of course, Oklahoma’s complexity is one of its strengths. Straightforward areas yield all their prizes quickly; it’s the more difficult ones that continue to serve up discoveries for decades

    And that’s what has been happening in Oklahoma, which remains a production powerhouse.

    The state makes 1.6 trillion cubic feet of gas and 60 million barrels of oil a year. It ranks second in the country for natural gas production and fifth for crude oil.

    Hunt for Natural Gas

    Today’s explorers mainly look for natural gas in Oklahoma. The state’s oilfields are generally shallow, and drillers have already poked and probed the well-known productive section with some 450,000 wells. Most oil accumulations of size were discovered years ago.

    So, where’s an explorer with an eye on the big prize to look? Natural gas reservoirs that are extremely deep or hidden in structurally complicated areas are high on the list for elephant hunters. Current deep exploratory activity focuses along the southern flank of the storied Anadarko Basin, one of Mother Nature’s great repositories of hydrocarbons. Here, where the Wichita Mountain Front runs through portions of Comanche, Caddo, Washita, Kiowa and Beckham counties, companies drill 18,000-foot-plus tests for Pennsylvanian Atoka, Morrow and Springer sands. Modern wildcatters include Chesapeake Energy, Dominion E&P, St. Mary Land & Exploration and Marathon Oil.

    Infill drilling is also popular in the Anadarko’s deep reservoirs. In Beckham County’s Mayfield area,wells aimforMorrow and Springer reservoirs; in Caddo’sVerden Field, objectives are again Springer. Apache Corp. runs four rigs at Verden, which was discovered in 1976.The company says reservoir compartmentalization in the field has afforded it a wealth of drilling opportunities.

    Too, there’s a more bread-and-butter approach to natural gas drilling. Drilling for the commodity is concentrated in the Anadarko Basin and Shelf areas, in such reservoirs as the Chester, Morrow, Oswego, Atoka and Red Fork. Companies pick along the edges of existing accumulations and wedge additional wells into developed fields. Exploitation and development activity abounds in such areas as the Strong City District, Mocane-Laverne gas area and Watonga-Chickasha fields.

    A good chunk of natural gas activity also centers on coalbed-methane (CBM) plays.At the beginning of 2007,Oklahoma had 4,600 CBMwells. Statewide, such wells produce about 200 million cubic feet of gas per day, some 5%of total gas production. Since development started, Oklahoma’s CBM wells have produced a total of 360 billion cubic feet of gas.

    These days, drilling in Oklahoma’s two major CBM plays concentrates in areas of already established production. In 2006, the state estimated that some 475 CBM wells were completed in the Cherokee Basin in the Rowe, Mulky and Riverton coals, and in the Arkoma Basin in the Hartshorne coals.

    Technology and Innovation

    Oklahoma has a secure place as an innovator and early adopter of fresh technologies, and that’s demonstrated throughout its oil industry. Improvements in horizontal drilling have created many opportunities, and Oklahoma has been reaping its share of rewards from this technology.

    Horizontal drilling works well in Oklahoma because the state is stuffed with the types of rocks that offer prime targets. Reservoirs with low permeabilities and dual porosity systems can be economically produced with horizontal wells, and operators are applying the technology throughout the state’s petroliferous geologic section.

    Companies are able to tap bypassed or previously inaccessible reserves in old fields with the horizontals.Cleveland sandstones have proved to be amenable targets for horizontal drilling in the western Anadarko Basin, as have Cherokee reservoirs. In Grimes Field in RogerMills County, for instance, Chesapeake Energy has an on-going horizontal drilling program in the Cherokee.

    On the eastern side of the Anadarko, horizontal Hunton and Cottage Grove wells have made some excellent completions.

    Unconventional reservoirs such as shales and coals have also benefited greatly from horizontal drilling, particularly in the Arkoma Basin in eastern Oklahoma. The Woodford Shale play has lit up the industry with reports of solid wells in an area that trends from western McIntosh through central Coal counties. In Pittsburg, Haskell and LeFlore counties, horizontally drilled Hartshorne coal wells have been delivering excellent gas rates and reserves. Activity is high in such fields as Scipio Northwest, Canadian, Kinta, Poteau Southeast and Poteau-Gilmore.

    Oilfields Redux

    Finally, Oklahoma is home to an abundance of mature oilfields, and these are drawing fresh attention and technologies.

    New Dominion LLC of Tulsa is carrying out in Oklahoma one of the more interesting oilfield rejuvenation techniques in the U.S.

    The company produces high volumes of water from fields thought to be depleted. The water production reduces reservoir pressures, and the pressure drop causes natural gas associated with still-trapped oil to expand. The expansion drives the oil toward the producing wells, where it can be captured.

    New Dominion has projects in Hunton and Arbuckle reservoirs. In Oklahoma City Field, the company has been drilling multilateral horizontal wells in the Arbuckle.

    Other projects, such as enhanced oil recovery via carbon dioxide injection at Postle Field in Texas County, are also in progress. Whiting Petroleum is expanding the flood in that field.

    In southern Oklahoma’s Ardmore Basin, Citation Oil & Gas has massive ongoing operations. The company uses a variety of approaches, including 3-D seismic, detailed mapping and engineering studies to site wells in the mature waterfloods in the area, home to an amalgamation of fields discovered in the 1910s and ’20s. Active in Oklahoma since 1985, Citation today operates 4,300 wells in the state.

    And, notwithstanding the tilt toward natural gas, oil exploration retains a small but relevant place in Oklahoma activity. Chaparral Energy LLC is under way with an exploration program in Harmon County, in the northwestern Hardeman Basin. It is drilling several 8,500-footArbuckle tests in the lightly explored area.

    Range Resources is also at work on a field rejuvenation project at Tonkawa in Kay and Noble counties. Recently the company acquired 100% interest in the field and is in the midst of an active drilling program. It has reported that it has some 400 shallowwell locations in Tonkawa,which is one of Oklahoma’s original prolific fields and dates back to 1921.

    So, oil or gas, shallow or deep, straight or sideways, there’s a lot of drilling and producing going on in Oklahoma.Down the road, the industry looks to remain a cornerstone of the state’s identity and of its economy.

    Top 10 Operators 2005-2006

    Operator Wells Spud in 2005
    Chesapeake Operating Inc. 436
    Newfield Exploration Mid-continent Inc. 183
    EOG Resources Inc. 76
    Apache Corp. 66
    Dominion Oklahoma Texas Exploration & Production Inc. 60
    New Dominion LLC 59
    Questar Exploration & Production Co. 58
    PetroQuest Energy LLC 52
    Cimarex Energy Co. 48
    Vectra CBM LLC 46
    Operator Wells Spud in 2006
    Chesapeake Operating Inc. 508
    Newfield Exploration Mid-continent Inc. 226
    New Dominion LLC 95
    Apache Corp. 76
    Range Prodcution Co. 61
    Noble Energy Production Inc. 60
    Panther Energy Co. 60
    BP America Production Co. 56
    Dominion Oklahoma Texas Exploration & Production Inc. 54
    Special Energy Corp. 53
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    By Jami Mattox

    Innovative Oklahoma companies are developing new ways to tap old energy sources while still protecting the environment.

    Oklahoma has a rich history in the old and gas industry. And with energy prices soaring, several Oklahoma-based companies are coming up with new and innovative ways to tap into resources that, up until now, have been impossible to access.

    An Earth-Shattering Technique

    The Barnet Shale is not an area that most are familiar with. But to energy executives, this ancient deposit in north Texas spells gold for their industry.

    The Barnet Shale is a 6,000 square-mile area of bed rock that stretches over north Texas. The deposit is about 300 million years old and has been a source rock for oil and natural gas companies to produce from for decades.

    Exploration of the deposit began in 1981 by Mitchell Energy, headed by natural gas visionary George Mitchell. Prior to his innovations in extracting natural gas from the shale, energy companies had pulled oil and natural gas from the sandstone rock located above the shale deposit, depleting it.

    Mining into the shale had always proved impossible because the shale was dense and non-porous and didn’t allow for the passage of natural gas molecules for extraction. Mitchell developed a way to extract the natural gas by pumping water into the rock and essentially shattering it, creating millions of bore holes that would allow natural gas molecules to pass through.

    In 2002, Oklahoma-based Devon Energy acquired Mitchell Energy and its position in the Barnett Shale.

    "No one saw that (George Mitchell) was doing in the Barnett Shale as a viable means of extracting natural gas," says Chip Minty, supervisor of external communications for Devon.

    "Devon recognized that what he was doing was worthwhile and that we could advance the technology."

    After Devon announced the acquisition of Mitchell Energy, they also introduced a technique called horizontal drilling that would allow them to maximize their exploration efforts in the shale.

    An aquifer runs under the Barnett Shale, and any rupture of the shale that would allow water to seep in would kill the entire well. Devon was faced with the obstacle of boring into the shale without disturbing the water source beneath.

    Horizontal drilling allowed them to drill vertically down into the shale, then change course and drill horizontally for a few thousand fee.

    "Horizontal drilling gives us more contact with the shale itself, and allowed us to produce more gas," Minty says.

    "Devon has about a half-million acres of lease property to drill on, but before we could drill horizontally we only had access to about 180,000 of those. Just through this simple innovation we are able to reach so much more.

    "Devon found a good deal of success drilling horizontally, and that allowed us to expand drilling in the Barnet Shale. We showed the rest of the industry that Barnet was viable."

    Minty says the experience taken from the Barnet Shale is helping the Company explore similar areas across the country.

    "What we learned (in the Barnet Shale) is applicable to all other shale fields as well. We’ve opened up a brand new source of natural gas that the industry didn’t have a decade ago because of what we’ve learned," Minty says. "We’re now drilling into the Woodford Shale in southeast Oklahoma. We’re pulling natural gas out of it, producing an amount of economic benefit to an area of Oklahoma that could use it."

    Today, a huge number of companies hold positions in the Barnett Shale. It has become one the largest gas fields in the United States, producing over 2 billion gallons of natural gas a day.

    One company holding a large position in the Barnett Shale is Oklahoma City-based Chesapeake Energy Corporation. In October 2006, the energy giant signed a lease with DFW International Airport to begin drilling into the shale deposit located beneath the airport.

    On Sept. 28, 2007, Chesapeake’s first wells, drilled into and fractured under the airport, began producing natural gas. There are at least 30 wells now producing at DFW Airport. Chesapeake has give rigs working 24 hours a day to complete the 327-well drilling program over the next five to six years.

    One major challenge the Barnet Shale product presented Chesapeake officials was infrastructure.

    "Any time you try and dig under ground in an urban environment, it’s not the easiest thing to do," Chesapeake Chairman and CEO Aubrey McClendon said in a February earnings release conference call to analysts. "It’s not the easiest project in the world in an urban area of several million people to be laying pipelines underneath all the urban infrastructure that exists there."

    "Blending the cultures of Chesapeake, DFW Airport and the Federal Aviation Agency was really the key to making this project work," Dave Leopold, Chesapeake’s DFW Project Manager, recently told the company’s quarterly newsletter, The Play.

    "This project was the first of its kind to be attempted on such a large scale. Our partners had no experience to go by, and had to learn to overcome their preconceptions of oil and gas development. Basically, we came to understand each others’ businesses. Now, after building a relationship, we work together very well."

    Chesapeake announced in February another shale exploration project in the Appalachia area of the eastern United States.

    Scott Rotruck, vice president of corporate development for the eastern division of Chesapeake Energy, says the company has more than 1.6 million prospective acres for the Marcellus and Lower Huron shale located there. The area offers Chesapeake a tremendous advantage due to its proximity to some of the best natural gas markets on earth. The company will also see a great advantage at their early entry into the area through a $2.2 billion acquisition of Columbia Natural Resources in 2005.

    Chesapeake has now drilled 26 vertical and horizontal Marcellus and Lower Huron wells.

    "From what we can see today, the upside of this area will likely be worth more than 10 trillion cubic feet of natural gas net to Chesapeake," Rotruck says. "Since our leasing program is continuing, we will not release too many details about what we are seeing in these plays, but our success has led us to ramp up our drilling program to drill an estimated 165 Marcellus and Lower Huron Shale wells between now and the end of 2009."

    Chesapeake remains the most active driller and holder of more unconventional and shall acreage than any other company in the U.S.

    "When the full implications of the domestic clean-burning natural gas exploration industry’s ability to fully develop these resources becomes apparent, an increasing number of experts will include natural gas in the discussion of America’s premium electricity generating and transportation fuel for many more decades to come," Rotruck says.

    Outside the Box

    Tulsa-based energy company New Dominion, L.L.C., is also applying new advancements in the oil and gas industry for exploration.

    "We utilize a wide variety of special techniques and equipment, each of which is specially designed and manufactured to our specific requirements," says David Chernicky, president and CEO of New Dominion.

    The company considers it’s reverse engineering and utilization of the principles of dewatering high water saturation reservoirs the key to its success. "Horizontal drilling techniques are the major technological advancement that enables us to drill more efficiently. Virtually 100 percent of our producing and saltwater disposal wells are drilled and completed horizontally," Chernicky says.

    Having always encouraged its employees to "think outside the box," Chernicky says the company is constantly searching for a new and better way to operate. New Dominion is currently producing oil and gas from reservoirs that were previously bypassed by other operators because they were not considered economically viable to produce.

    New Dominion operates over 250 wells in Oklahoma, all of which are located at the company’s current two projects: one south of Prague, Okla. and one within the city limits of Oklahoma City.

    "The reservoirs from which we produce typically contain as much as 90 percent saltwater as compared to more conventional reservoirs containing less than 50 percent saltwater," Chernicky says.

    "This requires a large and time-consuming front-end capital investment to purchase right-of-way and construct high-current, dedicated three-phase electrical power, saltwater, oil and gas pipelines virtually every mile in all four directions. The last thing we do is drill saltwater disposal and producing wells.

    "This technique is literally 180 degrees backward from conventional oil and gas development."

    Chernicky says the three-phase mixture of oil, gas and water is produced at the wellhead, then separated into customized vessels. The gas and saltwater is transported by pipeline, and oil is trucked from central delivery points until volume reaches a level sufficient to justify a direct pipeline connection.

    Tulsa-based SemGroup, L.P. recently announced plans for a 550-mile pipeline that will mainstream their transport of crude oil from Colorado’s DJ Basin to the Cushing Interchange in Payne County, Okla. Construction began on the project in March. The project, called the White Cliffs Pipeline, was announced by SemCrude, L.P., SemGroup’s crude oil business segment.

    "The White Cliffs Pipeline is due to be operational by January 1, 2009. It will provide DJ Basin producers direct access into the Cushing market and to refiners in the Mid-Continent area. It will help producers to have uninterrupted flow capacities and receive maximum value for their crude oil." Says Kevin Foxx, executive vice president and COO of SemCrude, a division of SemGroup of which he is a co-founder.

    The White Cliffs Pipeline will transport 72,000 barrels of crude oil a day. The value of the project is estimated at approximately $8 million.

    Protecting Mother Earth

    With the new innovations and exploration in the oil and gas industry, energy companies are under increasing pressure to protect the environment in which they operate.

    According to a 2006 annual report, Chesapeake Energy is committed to protecting the safety of the world by meeting or exceeding environmental compliance regulations throughout the company’s areas of operations.

    The company’s goal is to minimize the environmental impact at the drilling site. The company prides itself on being a leading producer of natural gas, the cleanest-burning conventional energy source.

    Devon Energy has found an innovative way to recycle water at the Barnet Shale site.

    "In the Barnett Shale we use high volumes of water to pump down into well bores," Minty says. "A portion of that water comes to the surface once fracturing of the shale is complete, and we recycle that water rather than to draw more water than necessary from the fresh water supply."

    Water sent into the shale comes back full of impurities, rendering it unsuitable for relase on the earth’s surface.

    "We either have to inject it into a disposal well where it won’t pollute, or we can recycle it," Minty says. "We are the only company in the Barnett Shale recycling our water."

    Devon also utilizes horizontal drilling techniques to lessen their footprint at drilling sites by gaining access to energy resources without disturbing land above it. This also allows multiple wells to be drilled from a single pad.

    Horizontal drilling and centralized drilling and production facilities are also key to limiting the impact and utilization of surface for New Dominion.

    "We are now able to efficiently drill and produce four complete sections of land from one 10-acre location, whereas with conventional vertical technology, each section of land might have required between four to eight individual wells spread out over the surface," Chernicky says.

    "Now, one 10-acre site with four to eight horizontal wells can develop multiple formations and take the place of 16 to 32 wells. We now place all these wells below the surface in concrete cellars so only the separation, storage and electrical equipment are visible."

    New Dominion also buries all flow lines and pipelines. Surface electric lines are placed to minimize loss of pasture and other land for surface owners, and the company is burying most of its electric lines in urban areas to minimize the surface impact and to protect them from tornadoes and ice storms.

    "Our operations result in a new improvement to the area and community as a result of better roads, better electrical facilities for future use by the community, and an overall improvement in land utilization, drainage, fresh water systems and even neighborhood security," Chernicky says.

    ConocoPhillips, who has numerous operations in Oklahoma, is also committed to protecting the environment it occupies.

    "In all of the company’s operations, the highest environmental standards are implemented to ensure that the company’s actions today will not only provide energy, but will also secure a stable environment for tomorrow," says Nancy Turner, public affairs spokesperson for ConocoPhillips.

    "The company implements environmental policies and procedures to help create sustainable ecosystems, protect wildlife habitats, minimize the impact of our operations and improve the communities in which we operate to ensure a sustainable environment for the future.

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    New fracture-mapping technologies allow us to directly measure fracture parameters that were previously only modeled or assumed. Limitations exist, however, with every diagnostic technology and one of the greatest limitations has been the need for a nearby offset monitoring well… until now.

    New Dominion LLC is developing a Hunton play in the Little Field of Central Oklahoma. These wells are acid-fractured with no proppant and the geometry of the acid fracs is not well understood. Formation mechanical properties, acid reactivity, and other parameters have made it difficult to model created fracture geometry. Due to lack of nearby offset well locations, Halliburton and Pinnacle’s new Treatment Well Tiltmeters were employed to measure fracture geometry during a live acid fracture treatment.

    Although offset well tilt-mapping is well understood and has been utilized on more than 600 frac treatments in the past three years, tilt-mapping from the treatment well brings a new set of challenges. We are measuring minute wellbore movements in the midst of a high-velocity flowstream – fortunately the fracture induced tilt signals are much higher than the induced noise from fluid motion in the treatment well. Fracture height and width are measured in real-time during treatment well tilt-mapping procedures and those dimensions are then used in conjunction with FracproPT to estimate fracture length based on these measurements and matching modeled to actual net pressure data.


    A treatment well array was installed to map real-time fracture growth on the acid fracture treatment in the perforated interval from 4320' – 4400'. Eight tiltmeters spanned the interval from 25' below the bottom perforation to 115' above the top perforation.

    The pumping rate was held constant at 20 BPM during the first 10 minutes of the treatment, during which time the fracture height was measured to be contained largely within the perforated interval with at most 30' of height growth above the perforations. After the first ten minutes, pumping rate was increased to 50 BPM and held constant at that rate through the end of the 90,000 gallon treatment. After the rate increase, fracture height was seen to grow rapidly upwards, reaching more than 100' above the top of the perforated target zone within a few minutes. The rapid height growth after the rate increase can be seen on the raw tilt data versus time from the top tiltmeter (placed at 4205'). As is seen, the fracture-induced tilt is relatively unchanged until the rate increase and then is seen to rapidly increase as the fracture top approaches this tool. The reversal in tilt response seen at 13:44 is due to the fracture diverting elsewhere (decreasing tilt) and then approaching this depth again. More details are available in SPE 71648.


    From the treatment well tiltmeter data, it is clear that the treatment stayed reasonably centered on the target interval during the lower rate pumping stages, but later fracture growth is primarily out of zone during the higher rate pumping stages. Treatment well tiltmeters will be used for measuring rate-dependant fracture geometry and making changes to a treatment "on the fly" to help contain the treatment to the pay interval or to avoid undesirable fluid contacts (water zones, gas caps, etc.) In this case, a maximum critical pumping rate was identified and its impact upon fracture geometry can be seen for future design and optimization considerations.

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    A Hunton dewatering play in the heart of Oklahoma oil fields is proving that substantial reserves can yet be recovered from mature areas.

    By Peggy Williams

    An uncommon production technique is reawakening central Oklahoma’s slumbering oil patch. In 1995, geologist and Oklahoma native David Chernicky began working in Lincoln County’s Carney Field. The 4,800-acre accumulation has been sporadically drilled during the years, with 31 wells reaching the Silurian Hunton Lime at depths of about 4,900 feet. Production levels were lackluster, however, totaling just 37,000 barrels of oil and less than half a billion cubic feet (Bcf) of gas during a three-decade span. The problem, as in many of the Hunton fields on the Cherokee Platform, was very high water cut.

    Chernicky, president of Chernico Exploration, had an unconventional approach. He believed that high-volume submersible pumps could dramatically improve production from the Hunton reservoir. Sustained water production at very high rates would eventually dewater the reservoir, increasing oil and gas yields. "I saw the technique being used by Ames Oil & Gas in 1979 in northeast Oklahoma’s Pawnee Lake Red Fork Field. It really opened my eyes."

    Chernicky was intrigued enough to later try the dewatering technique in Lincoln County, in Mount Vernon Red Fork Field. He was responsible for an 80-well project that proved the concept was feasible. He then decided to test the method on the deeper Hunton interval in nearby Carney Field.

    "Early on, I saw evidence that the Hunton in the Carney area might be a candidate for dewatering. But, the main reason I started working there is that it was only four miles away from my existing Redfork project. It was essentially an experiment that just kept expanding."

    The results were so encouraging that Chernicky decided to embark on a full-scale development. At the time, he was working as director of exploration for Altex Resources, Inc. Then, in 1998, along with partners John F. Special and Chris McCutchen, he formed New Dominion LLC, which is headquartered in Stillwater. The companies remain alliance partners, essentially marching together in the Hunton play.

    In less than two years, New Dominion drilled or reentered 28 Hunton wells and developed recoverable reserves of 2.2 million barrels of oil and 16.2 Bcf of gas at Carney. By June 2000, daily production from its project area was more than 2,000 barrels of oil and 12 million cubic feet of gas.

    Today, New Dominion operates more than 140 Hunton wells and produces 4,000 to 5,000 barrels of oil and 35- to 40 million cubic feet per day. This year, the company has already drilled or recompleted 20 Hunton wells and plans another 20. Altex, working with Chernicky’s guidance, also has a commanding presence in the play. That firm produces about 3,000 barrels of oil and 20 million cubic feet of gas per day, and it expects to drill or recomplete as many as 70 wells in 2001.

    Presently, more than 250 wells are active in the Hunton dewatering play, producing an aggregate of about 11,000 barrels of oil and 70 million cubic feet of gas per day, estimates Chernicky. Recoverable reserves of more than 15 million barrels of oil have been established in the greater Carney area alone.

    "The Hunton activity has been an unbelievable shot in the arm to central Oklahoma. Tax revenues are up, royalty checks are arriving in owners’ mailboxes, and trucks are moving up and down the highway."

    Retrograde oil cut

    What’s so intriguing about the Hunton play is that it is much more than simple high-watercut production. After the high-volume pumps have been placed on a group of wells, the overall fluid volume declines and the percentage of oil and gas to fluid produced actually begins to rise.

    The formation behaves somewhat like a coalbed methane reservoir. The dewatering process lowers reservoir pressure and allows the oil and gas stored in the tighter portion of the reservoir to bleed into the wellbore.

    Indeed, the mechanism for the dewatering technique appears to be relative permeability. In Carney and nearby fields, the Hunton exhibits two types of porosity—matrix porosity, with small pore throats and discontinuous compartments, and secondary porosity, characterized by large pore throats, vugs and fractures.

    Water is carried in the higher permeability and porosity streaks. Aggressive production of the reservoir, which easily flows thousands of barrels of water per day, eventually drops the reservoir pressure enough so that gas expansion can push the oil residing in the tighter matrix into the wellbore.

    "On a rod pump, it would take years to lower the pressure in the fractures and high perm streaks enough to allow the bulk of the oil in the matrix to flow into the wellbore," says Kurt Rottman, an Oklahoma City consulting geologist who has studied the play extensively. "The high-volume pumps allow a pressure differential to extend far enough into the reservoir so that the oil trapped in the lower porosity zones can be produced."

    The process was so successful that one well in Carney Field that was initially completed with an oil cut of less than 1% was producing at 25% oil cut after 18 months. Two wells on one lease, operated by Altex, produced 277,000 barrels of oil and 624 million cubic feet of gas during a 48-month period. From August 1997 through January 2000, Hunton wells in the Carney area produced 3.1 million barrels of oil and 9.2 Bcf of gas.

    An expanding play

    The successes at Carney have caused a great many companies to closely examine the peculiar play. Unquestionably, the Hunton could hold sizeable potential, as it covers more than 2.2 million acres in central and western Oklahoma.

    Further, the Hunton may be just the tip of the iceberg. The Technique could work in any reservoir that has similar characteristics to the Hunton, notes Rottman. "Dewatering has the potential to revitalize many older areas, and operators need to be aware of the technique."

    New activity is now focused in the Hunton trend in Seminole, Okfuskee, Okmulgee and Hughes counties. Operators have been testing the dewatering technique at various places, mainly in and around old Hunton producers. With their leaseholds largely in hand, players are highgrading these areas based on recent drilling efforts. More than fifteen operators, mainly from Texas and Oklahoma, are active in the play. New Dominion and Altex have been joined by companies including Marjo Operating, Buckeye Petroleum, Elder Operating, Ricks Exploration, Parsons Engineering, Montgomery Exploration, Belco Oil and Gas, Lance Ruffel Oil & Gas Corp., and Carmac Energy Corp.

    Some extensions of the Hunton have been more successful than others, notes Chernicky. "The Hunton production is probably about 90% stratigraphically controlled and 10% structurally controlled. There are many stratigraphic changes that affect the quality of production as you move from one area to the next."

    Sound geology is the premier requirement for operators looking at Hunton dewatering projects—the correct location is everything. "There are reservoir limits to the play, and those are still being determined," says Rottman. "You must demonstrate oil saturation in the reservoir that is sufficient to be economic."

    Dallas-based Western Petroleum Resources Inc. is one firm that seeks to expand the play. The private company is participating in the St. Annes Project in Seminole County, says president Keith Griffitts. Ricks Exploration and B&W Exploration, both of Oklahoma City, operate the venture.

    The companies assembled a 2,000-acre leasehold and started drilling in November 2000. Like others, they looked for an area with previous Hunton penetrations that could be deepened, recompleted or twinned. Records from old wells with high water production rates and oil and gas shows were analyzed to pinpoint the desirable prospects. Some were drilled as far back as the 1950s; many date from the ‘70s and ‘80s.

    To date, the partners have completed four new 4,500-foot wells, recompleted four existing wells, and built necessary infrastructure including disposal wells. New wells are completed with seven-inch casing, because of the large volumes of fluid that will be produced, and the 100-foot thick Hunton is perforated at one shot per foot. Costs per well run about $550,000 and they are drilled on 160-acre spacing.

    Dewatering is considered successful when fluid volumes have declined to the point that operators can switch from the submersible pumps, which consume $4,000 to $5,000 per month apiece in electricity costs, to the far more economical standard-beam pumps. The wells should then continue to make 100 to 350 barrels of fluid per day; in time, the water, oil and gas volumes will gradually decline.

    The water is disposed in the Wilcox or Arbuckle intervals beneath the Hunton. A 6,800-foot disposal well costs about $90,000 more than a producer, because it is deeper and requires larger tubing and casing strings.

    Griffitts is optimistic about the project. "In the past, operators either produced the Hunton briefly, or many times never produced it at all because of the water volumes. There is a large reservoir of oil and gas that lies untouched in this formation.

    The Nuts and Bolts

    A successful Hunton dewatering project requires several crucial elements, explains David Chernicky, co-founder and exploration director of New Dominion LLC, based in Stillwater, Oklahoma.

    First, picking the correct type of reservoir is essential. A high-water saturation, solution-gas reservoir with bimodal porosity is the ideal candidate. A detailed geologic assessment can identify the most promising areas.

    Given that, operators must have access to abundant and economic electrical power to run the submersible pumps; they must also have an extensive and economic water disposal system capable of handling many thousands of barrels of water per day. A high-volume gas gathering and processing system is also necessary, and often that piece of the infrastructure has to be added from scratch.

    Too, a number of wells are needed to effectively dewater an area. As in a traditional waterflood, the wells are drilled in a pattern of overlapping circles.

    Dewatering requires substantial infrastructure and heavy up-front investments, Chernicky notes. Although the projects are often set up in areas that previously produced from the Hunton, Chernicky usually drills new wells.

    "We use existing wells in less than 5% of the cases. Oftentimes, the old well was plugged and abandoned, or was used for disposal. About 10% of our production comes out of recompleted wells, but those wells account for probably 60% of our production problems."

    Indeed, operations have to be run by top field hands, as the production process continually presents complex challenges.

    Chernicky estimates a typical Hunton dewatering project will produce at economic levels for five to 10 years. These are shorter-lived than more conventional reservoirs because the fluids are being pulled at much higher rates, compressing the productive life.

    "It’s a niche play that requires considerable work."

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    By Dan Holder

    Energy prices cycle up and down with heartbreaking inconsistency, but the oil and natural gas industry can rely on one constant: technology and techniques devised to overcome one field’s challenge will quickly be adopted by others to satisfy totally different needs.

    Independents have a long history of moving into U.S. fields as majors leave, applying new techniques and economically exploiting the remaining reserves. Companies in the Mid-Continent region are adhering to that tradition and adapting existing practices to new situations.

    New Dominion LLC, based in Stillwater, OK, is applying refinements of technology developed for coalbed methane production to dewater saturated oil and gas fields, making new production of conventionally produced and depleted fields economical. Three Oklahoma partners, John F. Special, Chris McCutchen, both of Stillwater, and David J. Chernicky of Tulsa, founded New Dominion in July 1998. New Dominion is the state’s fastest-growing oil company ranked by daily oil production, the company reports. Together with its alliance partner, Altex Resources Inc., who also worked to develop this technology, they are collectively the state’s largest crude oil producers.

    Much of the attention among North Texas natural gas producers is on developing the Barnett Shale. Pitts Oil Company, based in Dallas, has been involved in the play directly and indirectly for a number of years, including participation with Mitchell Energy’s earliest wells. The company, started by Frank Pitts 60 years ago, is successfully going back into wells with new fracturing technology to access new reserves.

    Dewatering Success

    New Dominion is drilling in the Hunton Limestone Formation in central Oklahoma, an area that has had limited conventional production in the past because of high water saturation, observes John Special. When New Dominion took over the fields and began dewatering in July 1998, one well’s average daily production using a small submersible pump was 5-10 barrels of oil and 300 Mcf of gas, with 1,600 barrels of water. Over 16 months, after offset development wells were drilled to dewater the surrounding reservoir rock, Special says that well began producing less than 600 barrels of water a day, and was placed on a beam pump. Daily oil production increased to more than 80 barrels, and gas production jumped to 500 Mcf/d.

    "As far a dewatering this field, David (Chernicky) came up with that idea, but it has evolved from some Red Fork production in Northern Oklahoma that we all worked on, together and separately," Special, co-manager of New Dominion explains. "We had some Hunton production near Carney, OK, and we sold it to David and his partners through Altex Resources. They figured out the way to dewater it and (inject) the water into the Arbuckle. The disposal wells are the key to the project. New Dominion has spent a lot of time and money refining the disposal technology. If we didn’t have good disposal wells, the dewatering method would not be as successful."

    The Hunton Formation is widespread throughout most of Oklahoma. Special indicates, adding, "We and others are trying to generalize this dewatering concept to other areas of Oklahoma, and possibly even to other states. There has been limited but encouraging success. It doesn’t work everywhere. Just because you find the Hunton doesn’t mean that you have a dewatering project."

    New Dominion’s success in oil and gas production after dewatering depends on six components, the company explains:

    • Correct geological assessment of the reservoir;
    • Abundant and economic three-phase electric power;
    • A high-volume gas gathering and processing system, which is often nonexistent in the areas around these types of reservoirs;
    • A water disposal system capable of handling the high fluid volumes produced;
    • A large front-end capital investment to ensure that enough wells are drilled in the initial phase to create synergistic interaction between the wells and decrease the producing water/oil ration markedly as field development continues;
    • A well-trained field staff able to safely maintain a highly loaded and challenging mechanical system.

    "Production from the Greater Carney Field averages 7,000 to 8,000 barrels of oil, and more that 60 million cubic feet of gas a day. This is produced by four primary operators," Special adds. "Compared to last year, we are still on an incline, although since we had such tremendous early-on success it is hard to maintain that rate of growth. When we add wells, we are flattening our curve and not adding a lot of daily production. We have finally reached the size where it’s like a Wal-Mart: it’s hard for Wal-Mart to substantially increase its sales by adding a few new stores because it already has so many stores. When we discuss doubling production we are really talking about doubling the number of wells."

    Continued dewatering eventually changes the dynamics of the field, he reveals. "There is so much gas in solution in these reservoirs, that as you dewater them, you make large amounts of gas along with some oil. As the water diminishes, the oil decreases until the final stage is a gas well. New Dominion starts a new well on a large submersible pump. Once or twice during the well’s life the submersible pump may be down-sized, and in the final phase we install a beam pump."

    Electrical Demands

    In the Lincoln County project, which has 64 wells, New Dominion’s total infrastructure investment exceeds $28 million. This infrastructure includes water disposal facilities, electrical construction, tank complexes, leasehold/acquisition costs, drilling costs, and completion costs. Electricity accounts for approximately 60 percent of the $6,000 a month average operating cost a well.

    "You certainly need a good dependable and expandable supply of electricity, because if you do have some success, you will need more electrical power," Special relates. "The electric cooperatives here in Oklahoma require more than a year’s advance notice to order the various components. We are the largest customer for Central Rural Electric Co-op in Stillwater, Oklahoma and Canadian Valley Electric Co-op in Seminole, Oklahoma. Their engineering departments have been very accommodating, as far as helping us with our planning and giving us advance notice when there is going to be a shortfall in power, line construction, and other key components of the electrical infrastructure."

    For all of New Dominion’s field operations, the monthly electric bill exceeds half a million dollars, Special notes. "Any time you handle as much saltwater as we handle, over 100,000 barrels a day throughout our operations, it is a very costly aspect of our business," he details.

    New Dominion has considered adding cogeneration facilities in its fields, but so far Oklahoma’s power system has been able to provide the electricity it needs.

    Water Disposal

    New Dominion’s massive water disposal requirements present problems, but Special explains that the company’s solutions don’t rely on large amounts of high technology. "It’s just that everything is bigger, and of course more expensive, because we are handling saltwater, which is hostile to metals, so we have to coat almost everything," he says, adding: "To prove up one of these projects, you have to drill and complete a $500,000 disposal well before you test your idea. That was not very commonplace in central Oklahoma before this play kicked off, because you have a lot of independent operators who perhaps were not that well capitalized."

    The company designed the saltwater disposal wells anticipating high fluid volumes in the dewatering operation, Special details. New Dominion sets 9 5/8 inch casing through the Hunton to the top of the Arbuckle Limestone, with well depths as much as 2,500 feet below the base of the Hunton, in the 6,000--7,500 foot range. The company then runs 7-inch internally coated casing through the outer casing. Each disposal well can handle 15,000-20,000 barrels of water a day on vacuum and more than 25,000 bbl/d if equipped with a high-volume, low-pressure centrifugal pump to overcome friction in the tubing string.

    New Dominion perforates the entire zone, typically at one shot a foot, and uses an acid fracture with sand or rock salt as a diversion agent. To interpret reservoir quality, the company says it uses standard triple-combination open hole logging suites.

    Production Support

    To cope with the high volume of gas and liquids produced, New Dominion designed the gas-separation and water-separation facilities used on site, as well as refinements to the horizontal free-water knock-outs. "We typically have two or three separators at the wells to separate the large amounts of gas from the fluids, and then we use a free-water knock-out to separate the water from the oil," Special reveals. "Our company worked with the manufacturers to design these vessels with larger intakes to handle the large amounts of gas we are producing."

    New Dominion has also been extensively involved with the manufacturers of submersible pumps, helping redesign pump stages to deal with the large amounts of gas in solution.

    High production rates depend on fracturing the formation, Special indicates, adding that the high-water environment does not affect the frac.

    "Typically, we don’t selectively perforate our zones, since we know that there is oil, water and gas smeared throughout the entire interval. We perforate one shot a foot, and therefore we have gone to dual-stage fracs, where we may perforate in the bottom 60 feet of the zone, stimulate, and then set a plug. We then perforate the top 100 feet of the zone, just to ensure that the entire zone is broken down and treated. We frac at fairly high rates, between 30-70 barrels a minute," he says.

    Despite the enormous upfront costs of the saltwater disposal wells, Special indicates that the company has had little problem raising the needed capital. "We had a good base of production initially and very cooperative banking relations with the Bank of Oklahoma and Stillwater National Bank," he says. "They have been in on the play since the beginning, so establishing a comfort level was not that difficult. As we proceeded, they grew in their understanding of what we were doing."

    One factor in the bank’s decision to support New Dominion is the size of the reserves targeted by all the operators in the field. Special estimates them at more than 10 million barrels of oil in the Carney area, and between 60 billion and 80 billion cubic feet of natural gas. Although operating costs, especially electricity, are high, Special indicates that New Dominion’s operation can be profitable even at $12 a barrel oil and $1.75 a Mcf gas. "It takes a lot of hard work and long hours." A dedicated staff and knowledgeable field personnel are an absolute necessity. If you see soil and gas in the samples and the fluid flow conditions are favorable, we run the submersible pump, evaluate the results, drill a few offsets, and pretty soon an oil field develops if the other necessary criteria are present.

    "We are optimistic about the dewatering technique. I am not sure how optimistic I am regarding oil and gas prices," Special muses. "Once you become accustomed to $25-$30 a barrel oil and $4-$5 gas, the cyclical market can once again show us how quickly oil and gas prices can fluctuate."

    Fracing Barnett Shale

    The Pennsylvanian Conglomerate underlying much of North Texas has been the mainstay of the Boonsville Gas Field, which has been producing for more than 40 years. Interest in the underlying Barnett Shale took off in the early 1980s, and now Pitts Oil Company of Dallas is taking a second look at those early Barnett jobs, using improved fracturing technologies to improve, or even start, production from a number of wells.

    The companies working the Barnett Shale keep 25 rigs in the field, reports David Martineau, Pitts exploration manager, and there probably have been 800-900 wells drilled to date, a number that is continuing to increase.

    Mot of those operations focused on infill drilling and refracturing earlier wells, Martineau reports. Operators in the early ‘80s typically used 300,000 pounds of sand and 300,000 gallons of water in their frac jobs, later moving to increased us of sand, sometimes pumping 1.5 million pounds, and up to 1.5 million gallons of fluid downhole.

    "This gel-frac was the predominant fracing technique until three years ago, when water fracs, or as they are sometimes called, light sand fracs, were introduced," he notes. "You would still put a million gallons of water in there, but instead of a million pounds of sand, you would put 100,000 pounds of sand, virtually one-tenth the amount of sand you had before. You also then eliminated the gels, which carry the sand in formation.

    "Gels have to break at a certain time so the sand falls out. If the gel doesn’t break, you could end up with a mixture someone once referred to as ‘bubble gum,’ so the well maybe did not perform as well as they thought it should, based on comparable offset wells," Martineau reveals. "In most cases, the gel worked fine, and the wells have done very well for 15 years. But in a lot of cases, they didn’t. So operators have gone back in and are doing an extensive refract program on wells that were gel fraced the 1980s and early 1990s.

    Geological Factors

    Pitts Oil’s main production zone, concentrated in the eastern portion of the basin, is 7,000-8,700 feet deep, almost the deepest section of Barnett Shale, Martineau explains. Underneath Denton County, the formation gets deeper going to the east and north. Producers are looking to extend the play in all directions except east, where the Munster Arch Uplift limits production possibilities.

    Thinning of the formation to the west and underlying water tables hamper exploration and development efforts, Martineau says. The Barnett Shale, 300 feet thick in Wise County, thins to half that under Palo Pinto County, and continues shrinking as it continues west. However, the western edge of the formation is significantly shallower, he adds. In Palo Pinto County, it’s about 4,000 feet deep, while under Wise County it’s 7,000 feet down, and 8,500 feet in Denton County.

    Aside from varying in depth, the formation also has an upper and lower component for most of its length, explains Martineau. "The upper Barnett is about 100 feet thick, and the lower Barnett ranges from 300 feet to 600 feet. As you dip to the east-northeast, you get a thicker section moving to the northeast. They originally completed most of the wells only to the lower Barnett.

    "People who have a lower Barnett completion are coming back in and opening the upper Barnett. There is a different frac gradient between the upper and lower, which is why they couldn’t commingle them initially. The people who are drilling today, frac the lower Barnett with water, set a plug in the Forestberg Lime, and then frac the upper. They then drill out the plug and commingle the zones. That is the prevalent completion technique."

    Another complication facing those working the western portion of the Barnett Shale is that where the play is active, it is above the Viola Formation, Martineau continues. "As you move westward, the Barnett Shale sits on top of the Ellenberger Formation. The key question is, can you frac with these massive fracs and keep the frac from growing down into the Ellenberger, which traditionally in this area has primarily been water? Otherwise you end fracing into water."

    Operators are drilling wells in Parker, Hood, Palo Pinto, Johnson and Tarrant counties, attempting to come up with techniques to commercially produce from the Barnett without penetrating the Ellenberger, relates Martineau. The advantages out west, he notes, are that the Barnett is closer to the surface, so wells are cheaper, and because the Barnett has a single zone there, only one fracture job is needed.

    "So your well, rather than coming in at 1 million cubic feet a day, comes in at 200,000-300,000 cubic feet a day," he notes. "There are several wells that are stepping out and attempting to come up with a good technology for fracing where the Barnett sits on top of the Ellenberger and make a commercial well. It is going to happen, but if these gas prices continue to fall, you are not going to see quite as many experiments."

    New Fracture Lines

    An important component of reworking the old wells is getting the fracture job to open different parts of the reservoir, Martineau continues. "It’s amazing, but what happens is that when you drain a reservoir and release the pressure, it closes up. When you start refracing, if it can find a new fracture, you go into the new fracture area and not into the old one.

    Unlike most areas involved in exploration and production, three-dimensional seismic has a minimal role to play in North Texas, he reveals, principally because the fractures are typically undetectable hairline fractures. The only reason operators would run 3-D seismic, Martineau adds, is to avoid drilling next to a fault.

    "There are some faults that run through the area, and unfortunately when you happen to drill next to one—and most of these are vertical faults so they don’t really cut the well bores—you can have two wells side by side, and can have a complete section in both, but there will be a fault running between them. When you start doing a massive frac job, the frac gets into the fault, so that you have an ineffective frac job. You really don’t have your frac fluid in the zones you want. The only reason we would shoot 3-D seismic would be to determine where the faults are, to stay away from them."

    Economic Factors

    Using water fracs instead of gel fracs reduces the costs of fracturing wells approximately $150,000, Martineau indicates. Unfortunately, he remarks, a doubling of contract drilling day rates in the last couple years as the play has heated up, has consumed that savings.

    "The savings you had with the change from gel fracs to water fracs has been eaten up by increased drilling and completion costs," he confirms. "It is not just the frac companies. The cementing companies, the logging companies, and everybody went up. Drilling contractors doubled their rates; the other people went up anywhere from 10 to 30 percent. So we are right back to the same costs we had before."

    "The savings you had with the change from gel fracs to water fracs has been eaten up by increased drilling and completion costs," he confirms. "It is not just the frac companies. The cementing companies, the logging companies, and everybody went up. Drilling contractors doubled their rates; the other people went up anywhere from 10 to 30 percent. So we are right back to the same costs we had before."

    Another difficulty is the nationwide scarcity of rigs, Martineau points out. Oil and gas operators are trying to buy them or lure crews and equipment from West Texas and other states. Those with rigs under their control are "in the driver’s seat," he says, because they can negotiate for leases, although very few leases are available in the active portion of the play.

    North Texas Plans

    Pitts Oil doesn’t have a long production history reworking Barnett Shale wells, since it only began operations in the area in late 1999, Martineau relates. He adds that the history using in this play water fracturing technique is only three years old, further limiting estimates on future production. A 1998 Oil & Gas Journal reports estimates that the Barnett Shale has potential reserves of 10 trillion cubic feet, but he notes that the new fracing technology has boosted those reserve estimates, as well as the extent or future production.

    "I went to the Society of Petroleum Engineers annual meeting in Dallas this past year," he recalls. "They had a half-day seminar on refracturing. The Barnett Shale was one of the examples of what happens when you refract, and can bring the well back on production at three-fourths to almost 100 percent of what it was before. So you have obviously fraced into something new. This play has the potential, down the road, of going back in and refracing the zones you are currently in.

    "We don’t have any experience with water fracs over a 20-year life to say that after I have depleted this zone and produced a billion cubic feet of gas, that I can refract it and get another billion. Down the road, a lot of people may say, ‘Yes, it definitely can be refraced once, maybe even twice.’"

    Pitts Oil will continue to work its acreage in the Barnett Shale, and Martineau says the company expects to keep two-three rigs in continual operation for the foreseeable future. With two rigs running, he calculates Pitts Oil has at least a four-year drilling program for its 35,000 acres. The company is now drilling on 80-acre spacing. After analyzing drainage patterns, he says it may try experimental drilling on 40-acre spacing.

    "We are very excited about the play, obviously, and we are very fortunate to have a pretty good acreage position held by production," Martineau says. "As the play moves farther to the north into Montague County, though, because of the timing and depth of burial, it looks like it turns into oil.

    "Producing oil out of shales has always been a difficult thing to do, so it is in its embryo stage now. We completed a well last year in the Barnett for oil, and it looks like it is going to be a pretty good well. It has already produced around 10,000 barrels of oil, and it started a huge play."

    The Barnett Shale formation is drawing a lot of attention now, but Martineau calculates that future natural gas prices will determine how long that attention lasts. "Everybody hoped we would have a new baseline of $4.50-$5.50 to keep up with the increased costs. Nobody saw $9, but they sure didn’t see it dropping back to $3," he says.

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