East Texas Cotton Valley pinnacle reef E&D emerging as hot gas play

Richard Wheatley
Associate Managing
Editor-News

• In this colorized 3D seismic cross-section, amplitude dimming can be seen over the top of the reefal anomaly in the 2 Riley Trust. Image provided courtesy of SK Resources Inc. [181493 bytes]
• Cotton Valley Pinnacle Reef Trend Action [98701 bytes]

An "impact play," a "3D seismic play," "an expensive play," and "a dangerous play" are all terms that accurately assess exploration and drilling under way to tap carbonate platform objectives, most notably pinnacle reefs.

Cotton Valley pinnacle reef wells-overpressured and sour-are expensive to drill and complete, an undertaking not for the unprepared. But with risked finding costs of 20¢/Mcf equivalent or better, economic rewards offset the operational risks and costs of drilling. Successful wells can yield significant reserves for a company, hence the use of the term "impact" by some operators when characterizing the play.

Cotton Valley reefs grew not only as 400-500-ft spires, or pinnacles, but also in various shapes and sizes within and on the carbonate platform as part of tectonic and marine depositional activity.

"It's a test of modern geophysics," said Thomas D. Barrow, president and chief executive officer of T-Bar-X, a private Houston exploration company, and the former vice-chairman of Standard Oil Co. (Ohio).

Operators stress the current play, which evolved from early Cotton Valley lime exploration beginning late in the 1940s, reached the stage where it is today only because of 3D seismic technology. The technology enables geologists and geophysicists to spot pinnacles and other reef forms, which exist individually and in clusters along a narrow 10-15 mile shelf fairway atop the carbonate platform that encircles the East Texas basin in the general shape of a twisted and crushed horseshoe.

While economics have been attractive, the infrastructure to develop and produce these wells-which average 90 days to drill and complete-has been limited, principally because exploratory activity became so intense so fast that companies often had to play catch-up in laying new gathering systems, building treatment plants, and expanding trunk pipeline systems. But the infrastructure is growing.

Whether drilling a producer or dry hole, operators say they're learning more about the play with each well. Where the play will migrate is open to educated guess.

In the meantime, uncertainty is intensifying the action, driving up the cost of leasing ahead of and in proximity to the main play and forcing operators to hold their cards extremely close to their vests as they try to stay ahead of the competition.

Current play

USX Corp. unit Marathon Oil Co., which inherited a significant 2D seismic database when it acquired early player TXO Production Co., sparked the current play about 3 years ago with its 1 Poth Family Trust discovery in Leon County, which opened Pearwood field.

The 1 Poth flowed on test at more than 20 MMcfd. Since the 1993 discovery, Marathon has added a string of successful Cotton Valley pinnacle reef wells.

Marathon benefited from being able to rework TXO's existing 2D and 3D data and leverage its position after gaining a better understanding of what TXO found-and didn't find.

Marathon reprocessed existing seismic data and was successful in imaging the reefs, which are referred to by various descriptive terms other than pinnacle, including "patch," "barrier," "atoll," and "fringe" reefs, to name a few, because of their varied shapes and dimensions.

But targets of choice are the pinnacles, resembling spires with wide bases, or "footprints," as small as 10-20 acres or as large as 60-80 acres, possibly more, operators conjecture.

The majority of pinnacle reef drilling activity has been focused on Robertson, Leon, and Freestone counties, which are essentially leased up. But with each successful well, the play advances farther north, and heavy 3D seismic survey action can be found on trend ahead of the drilling in Anderson, Henderson, Van Zandt, Smith, and Wood counties.

According to available maps, the trend appears to extend north from the central portion of Robertson County, into Leon, Freestone, Anderson, and Henderson counties (see map, p. 25). From there, it clips southeastern Van Zandt County and crosses northwestern Smith County, before curving back south through Smith again and passing through western Cherokee County.

It then cuts a swath through eastern Anderson County, touches northeastern Houston County, and reenters Cherokee County before heading east on the south side of the Sabine uplift.

Heavy drilling activity focuses on the Donie and Beargrass areas in the main play area, while 3D survey work tracks the reef fairway north into the so-called Cayuga, Tri Cities, Opelika areas and east into the Neches area along the eastern side of the basin's embayment.

Evolution

TXO Production Co. is credited with the early Cotton Valley pinnacle reef discoveries.

In 1980, TXO drilled the 1 McSwane field discovery in Freestone County, which tested about 1.5 MMcfd. At the time, however, the company likely didn't know that it had hit the top of a Cotton Valley reef.

Then, in 1982, TXO drilled the 14,830-ft 1 Marshall A in Leon County, which tested almost 10 MMcfd. The well, which was difficult to control, had bottomhole pressures of more than 13,000 psi.

TXO allowed it to produce at natural flow rates of as much as 45 MMcfd, filling up area pipeline systems. Subsequent production curtailments from other nearby wells were blamed on the Marshall A, prompting lawsuits. In 1984, the Marshall well was reported producing an average 25.5 MMcfd.

Subsequently, the well blew out at estimated rates of 30-40 MMcfd after production tubing was apparently forced upward and tore a hole in the casing. The well was eventually killed, plugged back, and redrilled.

The 1-X Marshall A relief well was drilled using the same well bore. Completed in 1986, it continues to produce.

Additional exploration by TXO-including using 3D seismic-proved unsuccessful and the play languished for the rest of the 1980s.

Both Marshall wells have cumulative production of about 60 bcf of gas to date, and cumulative production from the McSwane totals more than 13 bcf.

Players

The pinnacle reef action in East Texas is attracting an aggressive crowd, mainly large and small independents.

In addition to Marathon, players include operators Amoco Corp.; American Cometra Inc., Fort Worth; Union Pacific Resources Group Inc. (UPR), Houston; and non-operating Houston firms T-Bar-X; American Exploration Co. (Amex); Mcnic Oil & Gas Co., a unit of MCN Energy Group Inc., Detroit; and Vastar Resources Inc., participating as an equity owner with Marathon.

Other participating Houston area companies include the Broughton Associates joint venture, including general partner SK Resources Inc. and operating company Zackson Resources; United Meridian Corp. (UMC); Seagull Energy Corp.; Mitchell Energy & Development Corp., The Woodlands, Tex.; Sonat Exploration Co., a unit of Sonat Inc., Birmingham, Ala.; and Apache Corp.

Shell Oil Co. unit Shell Western E&P reportedly holds a 30,000-acre position in the trend.

Operator Tom Brown Inc., Midland, Tex., has an exploration joint venture with Amex covering 55,000 gross acres under lease or in options in Anderson, Cherokee, and Smith counties. Alone, Tom Brown has rights to 75,000 gross acres.

Another player that has been actively exploring is Energy Arrow Exploration LLC, Dallas, a venture of UMC, Denver's Aspect Resources LLC, and M.B. Exploration LLC.

Companies from outside the region with current or past involvement include Tamarack Petroleum Co. Inc., Milwaukee; Belco Oil & Gas Corp., New York; and St. Mary Land & Exploration Co., Denver.

Delhi Gas Pipeline Corp., Dallas, which has gathered and processed all of the reef production so far, continues to expand its 2,100-mile East Texas pipeline system and treatment plant infrastructure. It's nearing completion of a second-phase system expansion to accommodate pinnacle reef and other production. The expansion project will boost Delhi's total pinnacle reef gathering/treating capacity to about 300 MMcfd, leaving Delhi with about 100 MMcfd of excess capacity to handle future production.

Benefits of seismic

Interpreted 3D data allow operators to pinpoint reefal anomalies in the trend, make adjustments based on well histories, and select optimum drilling locations.

Pinnacle reefs are found above the Haynesville formation, encased by the shallower Bossier shale. On 2D seismic, they're subtle and hard to see.

"It is entirely dependent upon 3D seismic to define the pinnacle reefs precisely enough to be able to hit them with the drill bit," said Tom H. Neel, Mcnic's Mid-Continent/Gulf Coast Region vice-president.

"Seismically, we only see the very tip-top of the reef," said Neel. "We're fairly certain that we are not delineating the entire outer boundary of the reef-kind of like looking at the top of a pyramid."

In most cases, 3D seismic depicts the location of pinnacle reefs as dim spots instead of bright spots, which are typically seen when interpreting Gulf Coast/Gulf of Mexico strata using 3D data. This dimming of amplitude can be spotted above reefal anomalies.

Elliott Pew, Amex's vice-president of exploration, said, "What you typically see is a dim spot where the Haynesville reflector will break up or disappear. Accompanied with that, you pick up a reflector up above the Haynesville that's typically the top of a reef."

Amex says it has found existing 2D data of 1960-80 vintage to be a good quality starting point in assessing prospective acreage.

Said Pew, "This tends to be older data, though, relatively short offset-type data. Sometimes you can see what's going on; sometimes you can't.

"For a long, long time, nobody knew how to replicate the Marshall (well, on seismic); they really weren't certain what it looked like. The 3D is what gave the clue on the signature; now that you know what that looks like, you can back into what that looks like on 2D."

The learning curve

UPR was a player in the mid-1980s, had minimal success, and left-only to come back again in May 1996. The lure: 3D drilling successes.

UPR's reef leasehold is part of an overall 300,000-net acre leasehold in East Texas, covering 15 counties from Milam in the south to Wood and Upshur in the north.

It's drilling the 1 UPR/T-Bar-X Lightning Unit on a farmout from T-Bar-X. The well is a 16,500-ft test on a 213-acre lease, at Ridge, Tex., in northeastern Robertson County. The well spots about 2 miles southeast of Marathon's Bohlwhite field.

Nearby, UPR recently spudded 1 Bearcat Unit, an Amoco farmout, projected to 16,400 ft.

John Applegath, UPR's East/South Texas Business Unit general manager, said, "We were very heavily in this play in the mid-1980s. We had leased up quite a bit of land. We saw some funny-looking things on seismic that seemed to match very good wells.

"We didn't realize, and I don't think the rest of the industry did at that time, that those funny looking things were reefs. But we now know that the Marshall and McSwane (wells) were reefs."

UPR drilled two wells, including an offset dry hole, "and decided that while we believed that great production was tied to these anomalies, which we now call 'reef indicators,' we didn't have the technology at that time to make the play-gas prices were low, high drilling costs-(so) it had to wait on 3D," Applegath said.

UPR has been focusing elsewhere since leaving the play but decided to take another look because of the results of successful wells, such as Sonat's 1 Fountain, a 30 MMcfd well in Leon County, and the high reserves per well being found with 3D.

Applegath said, "So now there's a reason to say, 'Yes, we were in there before. Technology has changed the equation; we ought to get back in.'"

UPR, which is planning several more wells shortly, is gearing up to operate or take part in as many as nine 3D shoots, some as small as 40 sq miles and others as large as 110-150 sq miles.

"The wonderful thing about this play is the chance for serendipity," said UPR's Applegath. "There are productive zones from the Cotton Valley lime all the way up to almost near surface. Some of these areas have not been drilled, some have been drilled but only shallow. Almost none of these areas have had 3D shot on them.

"There's no telling what we're going to find. Even if we don't find a reef, we'll find something else."

Cautious ways to play

Houston's T-Bar-X prefers to farm out acreage for others to drill in a calculated strategy to avoid operating risk, while Mcnic Oil & Gas, a non-operator, is a participant through the Broughton Associates JV.

T-Bar-X believes the best way to approach Cotton Valley pinnacle reef wells is from a distance: "They're expensive, and they're dangerous," said T-Bar-X's Barrow.

"Three things can happen, and two are bad."

Besides farming-out to UPR, T-Bar-X farmed out the 2 Roach in the Burleson Hill area of Freestone County to Seagull and Mitchell Energy. In mid-February, the well was drilling below 12,000 ft toward a projected 15,000-ft TD.

Mcnic Oil & Gas has a 41% interest in the Broughton Associates JV, which holds 300,000 gross acres (155,000 net) acres in Robertson, Leon, and Freestone counties. Drilling by the JV so far has been only in Robertson County.

The Broughton Associates JV carries out the leasing and seismic, while Zackson Resources is the JV's operating company.

Mcnic initially became involved in the JV in 1993 but increased its non-operated interests in 1996 because it liked how the play was progressing because of the success of 3D seismic application (OGJ, Aug. 5, 1996, p. 58).

Through the JV, Mcnic in 1996 participated in four wells, including Marathon's 1 Riley Trust and 2 Riley Trust. The 1 Riley Trust is producing at about 17.5 MMcfd, and 2 Riley Trust is producing at 28-30 MMcfd. The 3 Riley Trust was recently completed by Marathon, along with 2 Poth, a Pearwood field step-out (OGJ, Feb. 17, 1997, p. 66).

"Our partnership is currently operating three rigs, and it's our intent to continue throughout the course of the year drilling on our own behalf (through the JV) at three or four rigs continuously and then participating with others," said Mcnic's Neel.

Mcnic expects to participate in drilling about 15 wells this year through the JV, and participate in about 10 more.

Currently drilling are 2 Camp Cooley, Zackson 1 Verna Rachui-a follow-up on a new location to Marathon's 1995 drilled and abandoned 1 Rachui-and the Zackson 1 Pollard. Broughton Associates JV's working interest in the Pollard and Rachui wells totals 100%; 67% in the Camp Cooley.

Through the JV, Mcnic is also participating in the Marathon-operated 2 George-Savell in Robertson County. The JV has a 67% working interest in the well.

All wells are targeted below about 15,000-15,500 ft.

Drilling and completing

"These are tricky, tricky wells to drill and complete," said Amex's Pew.

Because of their size, most pinnacle reefs accommodate only a single well, and economics are based generally on average potential reserves of 20 bcf or more per reef, with 20 bcf conservative.

Generally, pinnacle reefs are encountered at 14,000-15,000 ft and deeper, and operators say permitting to 16,000 ft is usually sufficient.

Downhole conditions are severe-wells are overpressured, hot, and sour, with what has been termed "a meaningful content" of H2S, as well as CO2, requiring that gas be processed, extensively cleaned, and CO2 removed prior to sale.

Heavy mud weights-on the high side of 17-18 lb-are mandatory to maintain delicate hydrostatic pressure balance during drilling.

Jim Paquin, American Cometra's chief operating officer, said, "Often times, if you're just slightly overbalanced, you can lose circulation. If you lose circulation, and you're in the reef, you're going to take a kick."

Holes are drilled generally as straight bores, with some deviation, operators say, to attempt to keep the wells dead on target when penetrating the pinnacle columns. Sticking pipe is a common problem, and bores can be drilled into pinnacles only to come out on the side.

There has been use of directional controls downhole to fine-tune trajectories. Some operators are using VSP (vertical seismic profiling) technology to stay on target, as well as to look ahead downhole, especially if 3D seismic imaging has been less than satisfactory over some areas.

Porosities range from 15% to 20%, and permeabilities are on the order of 250-500 md. Significant wells probably result from as much as 50-80 ft of porosity, which exceeds 15%, operators say.

Pinnacles have vugular porosities. So-called "vugs" are not uniform throughout. Combined with the high permeabilities and vugular porosities, wells can easily flow gas into the wellbore, requiring them to be overbalanced with heavier mud weights to counteract vugular effects.

Gas is all sour. Concentrations are not terribly high, and they vary from well to well with lows of about 1,000 ppm to 5,000 ppm, or 0.5%. But when combined with the high bottomhole pressures, the sour gas produces a highly corrosive environment.

CO2 levels are generally constant at about 2.5%.

Bottomhole pressures are typically 11,000-13,000 psi, but American Cometra says it has averaged about 14,500 psi bottomhole pressures in the wells it has drilled so far, with 0.95 psi/ft pressure gradients. Bottomhole temperatures are on the order of 340-350° F.

In the shallower portion of the play, in Robertson, Leon, and Freestone counties, drilling and completing costs average about $4.5-5 million; "however, a number of operators, including ourselves, have experienced significant overruns over that," said Mcnic's Neel.

Average costs of drilling and completing are about $5-$5.5 million in the undrilled deeper part of the play, east of the western shelf edge toward the interior of the East Texas basin.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.