Flexibility is key to surviving and prospering in the oil and gas industry. It used to be about supply and demand. Today, speculators and geopolitical events add a new layer of uncertainty. For anyone playing in this high-stakes business, staying on top of the game is essential.

Ironically, operators' success in drilling and producing shale gas is a major culprit in the current oversupply of natural gas, which has tamped down prices to a paltry $3 to $4-plus per thousand cubic feet, while crude oil prices keep rising. And as commodity prices diverged, operators began scrambling to stake claims in oil-rich deposits, either forsaking gas entirely or assembling a buffer for their gas programs.

In large part, shale remains uppermost in the minds of these operators—oil shale, that is, in plays like the Eagle Ford, Bakken and Niobrara, which apparently hold a treasure trove of oil. But operators are just as focused on opportunities elsewhere: California, the Permian Basin, enhanced oil recovery in older fields, and North Louisiana and Mississippi, to name just a few.

Monterey revisited

Environmentally correct California is rich in oil, with a long history of exploration and production that began in Los Angeles, of all places. According to Stephen Testa, executive officer of the State Mining and Geology Board of California, "Los Angeles was built on oil."

Venoco Inc. is focused on California's Monterey shale. Mike Wracher, vice president, Sacramento Basin & Exploration, says, "There's a lot of oil still trapped in that shale, and that's what we're going after."

Surface oil seeps, such as the famous La Brea tar pit, are not unusual in this region. The Los Angeles City oilfield was discovered in 1892 by two prospectors visiting downtown Los Angeles who noticed a tar coating on the wheels of a cart. Upon being told where the tar originated, they rushed to evaluate the nearby area, ultimately drilling a 450-foot well using the sharpened end of a eucalyptus tree. Today, with crude prices soaring, excitement is swirling around the state's oil potential.

Almost all of the oil in California has been sourced by the Miocene-age Monterey shale, according to Mike Wracher, vice president of the Sacramento Basin & Exploration, with Denver-based Venoco Inc. To put this in perspective, the Monterey has sourced producing giants Kern River, Elk Hills, and Midway-Sunset fields, to name a few.

"About 38 billion barrels have been sourced to conventional fields, and the source rock itself can probably source 10 times that amount," Wracher says. "More than 17,000 wells have penetrated the Monterey, which is thought to contain as much as 300 billion barrels of oil in place."

The Monterey formation is a complex lithology—it's a shale, but not a shale, in the minds of some industry folks. It's a mix of rock types and is basically a large deposit of diatomaceous material. At one stage it's low-permeability, unaltered diatomite—the Opal A phase—and must be stimulated to recover oil.

As pressure and temperature increase with depth, the Monterey becomes more brittle and fractured as it alters into cristobalite tridymite, known as the Opal CT phase. It evolves into a quartz phase as lithification progresses. The formation produces from all three phases, and results can vary significantly among wells. The Monterey may contain sandstones, depending on the locale.

In a striking difference compared with other shale plays under way that are typically associated with structures about 300 million years old, the Monterey is 5- to 17 million years old. There are large areas in the peak oil-generation window, so it's generating oil now. Some of the larger Monterey fields have been in geological existence for less than a million years. The region's subsurface has been highly twisted and broken from the huge amount of physically disturbing activity in this tectonically active part of the world. The good news: this tends to create a variety of hydrocarbon traps.

Surface casing awaits use as Black Creek Drilling Rig #1 drills an injector well for Denbury Resources Inc. at its enhanced oil recovery operations in the West Hastings Unit, Texas.

No matter the differing views regarding whether the Monterey is a shale or not, conventional or not, Venoco has sufficient experience to support its opinion. In addition to its onshore California Monterey shale activity, which kicked off in 2006 focusing on the Salinas Valley, San Joaquin and Santa Maria basins, the company has amassed considerable successes in this shale offshore.

"This is not a conventional play by any stretch of the imagination," Wracher emphasizes. "There's a lot of oil still trapped in that shale, and that's what we're going after.

"There are some conventional aspects like structural components, and that helps because those areas are more heavily fractured; but a lot of shale plays have structure," he says. "We're going after the deeper, more brittle, naturally fractured Opal CT and quartz phases, and most of our acreage is in the quartz phase, which is the most brittle and most naturally fractured.

"We picked our acreage in all the basins we're working based on our understanding of the natural fractures, and we're definitely focused on structural trends where the rock is more broken up."

Venoco has latched onto a lot of land in the process: more than 200,000 net acres total in the play and 46,000 acres held by production, with more leasing under way.

Wracher does note that there is production from sands within the Monterey, with distinct channel sands bounded by the shale. "In the old days, companies wouldn't venture outside the channels, but now they realize they can produce right out of the shale. These sands likely will provide conventional opportunities, adding to the upside for the play." Venoco expects to have additional geologic control to better place wells as a result of its ongoing 500-square-mile joint 3-D seismic shoot with Occidental Petroleum Corp., covering 320,000 acres in the San Joaquin Basin.

Venoco has drilled a number of vertical wells in the Monterey shale, but they are mainly "science" wells to cut cores for evaluation of rock properties of differing zones. Very little core has been cut through the formation away from the older established fields.

Horizontals are the order of the day for drilling the expected producers. The initial horizontal well in the San Joaquin Basin was a duster, but the company thinks there may be potential in the target zone in a different direction from the lateral leg, along with deeper potential on the acreage. In the Santa Maria Basin, the second horizontal well apparently drilled into a gas cap. Venoco plans to redrill the well, only deeper. The vertical section of the third well, in the same basin, reached total depth at 8,000 feet, and the 4,000-foot lateral was to be multifraced.

In the Salinas Valley, Venoco's fourth horizontal with a 2,100-foot lateral was "looking good" at total depth; management's longer-term expectation for an unstimulated lateral of this length, in this area, is for an initial potential of 154 barrels of oil equivalent per day. The company had spudded its fifth and sixth horizontals as of mid-March and had three rigs running in the play, with a fourth to be added.

Initially, Venoco anticipated large acid jobs would be the completion MO, but now plans to implement frac jobs in a number of wells, with the specific mix yet to be nailed down.

There's plenty of oil awaiting the drillbit, but getting there can be pricey.

"We estimate the average estimated ultimate recovery (EUR) for a Monterey shale well to be 400,000 barrels of oil equivalent, and we anticipate the average cost for a horizontal going forward could increase to the $6-million-plus range," says Tim Ficker, chief financial officer

The company plans to drill 30 gross wells in the Monterey shale in 2011, including 22 horizontals. The capital budget dedicated to the play for 2011 currently stands at $100 million, but that could increase to cover higher drilling and completion costs, according to Mike Edwards, vice president of corporate and investor relations.

Oxy often remains mum on its activities, but the company can't avoid a high-profile status in the California oil patch, where it's an industry leader with impressive fields to its credit. One of the best known is Elk Hills Field, where it's thought that the Monterey producing gross column is hundreds of feet thick. The company reportedly will drill 107 shale wells outside of Elk Hills Field during 2011. Other companies reported to have Monterey-prospective acreage include Zodiac Exploration, Gasco Energy, Plains Exploration & Production, Berry Petroleum and National Fuel Gas.

Dave Slater, executive vice president and chief operating officer of Signal Hill Petroleum Inc., notes that Long Beach Field is highly complex, "and in that complexity we know there's a lot of opportunity."

Long Beach

There's a whole other kind of oily play taking place in California's urban Long Beach area, where residents generally coexist peacefully with oil production. It's the old Long Beach Oilfield, dubbed Long Beach/Signal Hill Field by some of the locals. It qualifies as one of the giant fields in the U.S., having produced more than 1 billion barrels of oil to date from Pliocene and Miocene-age sandstones.

And it boasts the highest recovery per surface square foot of productive area of any field in the world, according to Dave Slater, executive vice president and chief operating officer of Signal Hill, California-based Signal Hill Petroleum Inc. (SHPI). The company operates the majority of the field, where it currently produces 2,800 barrels of oil per day from 200 producing wells. There have been 2,800 wells drilled in the field, most of them abandoned. But Signal Hill is at work rejuvenating this field. The company has allocated $25 million for the field for 2011, including a current 3-D program.

Twenty percent of the field occurs in Long Beach, and 80% in Signal Hill, which is a two-square-mile community of 10,000 residents, surrounded by the 50-square-mile city of Long Beach and its half-million residents.

"In the 1920s, after the discovery of oil in Long Beach Field, the city proposed an onerous oil tax," explains Slater. "The oil men got together and basically created their own city of Signal Hill and voted not to have an oil tax on themselves. Today, both cities have an oil tax."

The company estimates there are up to 3 billion barrels of original oil in place in the field, which bull's-eyes on Signal Hill, but modern seismic technology hasn't been applied there or to the Los Angeles Basin overall. Dense urban environments are not conducive to seismic surveys with their array of crew members, sprawling cables, noise and myriad other issues.

ecognizing both the need for seismic data and the challenges to its acquisition, SHPI did some serious homework on seismic equipment and zeroed in on a completely cable-free land nodal seismic-data-acquisition system developed by FairfieldNodal, of Sugar Land, Texas. Each of the small, lightweight nodes was buried in an eight-inch hole drilled into the ground, where they remained until time to be moved to a different survey area. Nodes were buried along the Long Beach Airport's taxiways and runways. In accord with California's often unique approach to challenges, a special-events permit was required and issued for the vibrator source trucks to move along the streets, like a slow parade.

The team tested an array of acquisition parameters while acquiring the 2-D seismic data. Today, they are acquiring data on a 22-mile 3-D node survey, which overlays about three-quarters of the city of Long Beach; it's scheduled for a June 2011 completion. SHPI has an economically successful well based on the 2-D data that was a re-drill to a step-out location. Since it began drilling in the field a couple of years ago, most of the wells have been re-drills at varying costs.

Long Beach Field has long been a candidate for modern 3-D interpretation. "The field sits along the Newport-Inglewood fault zone, which is one of the major fault systems cutting through the Los Angeles Basin," Slater says. "All of the folding, thrusting and faulting has created a highly complex field, and in that complexity we know there's a lot of opportunity.

"Two years ago, we started a drilling program and drilled the first new well in the field in 25 years. We've been successful in finding great oil saturations, but often in previously unmapped fault blocks. Long Beach Field is a massive reservoir with more than 10,000 vertical feet of productive section that's all chopped up. It's our conclusion there's been a tremendous amount of sourcing of the reservoirs vertically up the faults that filled everything up, and has resulted in such a high recovery per producing acre. We have wells and productive zones from 1,500 feet to 11,500 feet."

Signal Hill Petroleum is widely recognized for its neighbor-friendly approach, which has enabled it to forge ahead in this environmentally sensitive locale. The company owns and operates one drilling rig and four workover rigs as well as most of the other equipment needed to drill and maintain its wells.

"All of the drilling we're doing is with our own rig, which runs only 12 hours a day and is shut down on Saturdays and Sundays," Slater says. "We have very compact and flexible rig-up options because we work on very tight locations, and we need to be extremely quiet and odor-free. Because of the proximity to the public, the nighttime shutdown is absolutely essential. One sure way to control noise is to turn everything off. Our unique drilling schedule is not very calendar efficient, but it's cost effective in drilling wells."

When queried about 2011 action, Devon Shay, manager of the reservoir management team at SHPI, says the company plans to re-drill 14 wells at varying depths and to bring six wells on that were previously idled. "The first part of this year, we are targeting underdeveloped and bypassed zones identified from conventional subsurface mapping," she says. "The second half of the year we plan to use 3-D data to develop drilling targets."

Permian power

When it comes to the potential to wrest more oil from older fields, no region holds quite the allure—or the mystique—of the giant Permian Basin in West Texas and southeastern New Mexico. Ninety years after the first commercial well was completed there in 1921, it is still known as the Big Daddy of crude oil reserves.

"One of the exciting things about the Spraberry is that people have been drilling deeper and deeper over the past two to five years," says Scott Sheffield, Pioneer Natural Resources chairman and CEO.

The basin encompasses a surface area that exceeds 86,000 square miles. It had produced a total of 30.4 billion barrels of oil through 2000, and it accounted for 17%, or 327 million barrels, of U.S. oil production as recently as 2002, primarily from geologic formations ranging in age from the Ordovician through Permian.

Waterfloods and CO2 injection programs to improve recovery from the region's subsurface reservoirs have been commonplace for many years. As times change and technology advances, so does the potential recovery in most old fields. Today, the hot new targets in this gem of a basin are unconventional plays like the Bone Spring and Wolfberry—and even the Strawberry.

The Wolfberry gets its moniker from the commingling of oil from the long-producing Spraberry sandstone and the deeper packed-limestone Wolfcamp formation.

The newer, so-called Strawberry is a combo of the Spraberry and Strawn, which occurs directly above yet another deeper drilling target, the lowermost Pennsylvanian Atoka formation.

The long-productive Spraberry, often called Spraberry-Dean to include the underlying Dean sandstone, is a tight sand overall with isolated sandstone lenses that are conventional pay zones. Spraberry Trend Field was discovered in 1949, and Pioneer Natural Resources Co., Concho Resources Inc. and SM Energy Co., among others, currently have a high profile in the field.

Over the years, the Spraberry acquired a reputation as a formation where an operator can punch a well in any location and be darn-near guaranteed to tap into production that is at least so-so, with the potential to keep going for many years.

"One of the exciting things about the Spraberry is that people have been drilling deeper and deeper over the last two to five years," says Scott Sheffield, chairman and chief executive officer at Irving, Texas-based Pioneer Natural Resources. It is the largest acreage holder (approximately 900,000 acres), driller and producer in Spraberry Trend Field, where its net production is anticipated to average as much as 46,000 barrels of oil equivalent per day in 2011.

"Operators coined the name Wolfberry because it sounds more exciting, but it's just a made-up name, and all these wells are legally in this same field. They've even taken it a step further and have the Strawberry now," Sheffield notes. "We're probably one of the few companies that talk about Spraberry.

"We cored the entire Spraberry and found out there are shale zones with hydrocarbons in them, so we started opening those zones up in addition to the traditional silty sandstones," Sheffield says. "As a result, we increased the number of frac stages, so we're getting more oil out of the Spraberry and Dean than before.

"Then we started going deeper and picking up Wolfcamp and Strawn, so a combination of opening up non-traditional pay and also new-pay zones deeper, and increasing fracture stimulation, has allowed us to get much better economics.

"Over the next couple of years, companies will be looking at both conventional and unconventional zones in the Spraberry and Wolfcamp and drilling a series of horizontal wells to see if they can continue to improve on economics," Sheffield predicts. "We've drilled two wells into the Wolfcamp, which is very thick and has three or four organic-rich shales, and we're waiting on results."

As if this were not a full plate, Pioneer also is in the midst of a 7,000-acre waterflood project in the Upper Spraberry interval. "We've been injecting water since last August and are starting to see a response," says Frank Hopkins, vice president of investor relations at Pioneer. "Instead of the wells on decline, they're flattening out, and we're starting to see a couple of wells with a little increase.

"We expect over the next couple of quarters to see more response as we inject more water, and we've drilled a series of new wells so there's not as much void to fill with water. The program has 12 injectors and 110 producers with a combination of old and new wells."

Spraberry Trend Field has the highest rig count of any field in the U.S. today, according to Hopkins. "There are more than 200 rigs running today in the Spraberry Trend area, which accounts for about 60% of the total rigs in the Permian Basin; the rig count is at a 50-year high.

"Pioneer is in the process of going to 35 rigs by July 1 and will drill about 700 wells in 2011, and we plan to have 45 rigs to drill 1,000 wells in 2012."

The company has 20,000 drilling locations in the field and employs what it dubs a vertical integration approach to control drilling costs and ensure execution of its accelerated drilling program. It expanded into the service arena and now owns 12 of the rigs running in the field and three fracture-stimulation fleets, with two more on the way.

The company owns other field equipment as well as sand supply to cover forecasted requirements through 2015. Given the trend to drill deeper targets, the average well depth now is below 10,000 feet; the blended Pioneer and third-party average cost to drill and complete a well is $1.45 million. For 2011, Pioneer has budgeted more than $1 billion for the field, where its year-end 2010 proved reserves tallied 549 million barrels of oil equivalent.

Hastings Field CO2

Higher crude prices also have strengthened the economics for a long-planned enhanced-oil-recovery program. Plano, Texas-based Denbury Resources Inc. recently began its long-planned carbon dioxide (CO2) injection program at the old Hastings Field, 18 miles south of downtown Houston. It is using CO2 from its recently completed $884-million Green Pipeline, designed to transport up to 800 million cubic feet per day of man-made and naturally occurring CO2.

Phil Rykhoek, CEO of Denbury Resources, notes that over 90% of its current production is oil. He likes to kid his gas player friends that, "It's real crude, not liquids."

It's fortuitous that oil prices have soared since the program was in its infancy, considering that any enhanced-recovery application tends to be more costly than conventional production. The 325-mile-long Green Pipeline, which currently terminates at Hastings Field, connects in Donaldsonville, Louisiana, to the company's NEJD Pipeline, which originates at the large Jackson Dome geologic structure, about 16,000 feet deep, near Jackson, Mississippi. The feature is known for its copious reserves of naturally occurring carbon dioxide.

Denbury is in the catbird seat at Jackson Dome, where it owns all of the producing wells, presently turning out more than 1 billion cubic feet per day of CO2. Effective December 2010, the company had 7.1 trillion cubic feet of proved CO2 reserves at Jackson Dome and estimates it has an additional 2.8 trillion of probable and 2.9 trillion of possible reserves. The company currently injects approximately 900 million cubic feet per day into its fields suited for this EOR application and provides the remaining gas to industrial users.

"We're a CO2 EOR-focused company and have been doing this for about 12 years," says Phil Rykhoek, chief executive officer at Denbury. The independent public company is the largest oil and natural gas producer in both Mississippi and Montana.

"Some of our best rates of return have come from CO2 EOR, and over time we've sold off most of our other assets to concentrate on CO2 EOR operations. We do have a pretty large position in the Bakken shale play that came with our Encore Acquisition Co. purchase; the Encore purchase will significantly expand our CO2 EOR potential," he notes. "Over 90% of our current production is oil, and I kid my gas player friends in the industry, telling them, 'It's real crude, not liquids.'"

s Denbury latches onto even more candidate fields in the Gulf Coast region for this type of recovery, its need for CO2 will increase. "In the future, our goal is to use man-made, or anthropogenic, CO2 to supplement our natural source at Jackson Dome," Rykhoek says. "In March, we entered into a contract to purchase 70% of the CO2 captured from Mississippi Power Co.'s Kemper County Integrated Gasification Combined Cycle project in Mississippi, and other gasification plants have been proposed along the Gulf Coast."

Denbury's current production is in the range of 2,000 barrels of oil per day at Hastings Field, which was discovered in 1934 by Stanolind Oil & Gas. It has produced a cumulative 600 million barrels of oil from about 600 wells drilled into Miocene and Oligocene-age sandstones. It's estimated there may be 60- to 90 million barrels of oil recoverable via CO2 EOR.

Subsurface geologic forces created a major fault that breaks the field's overall subsurface domal structure into a western upthrown fault block known as the West Hastings Unit (WHU) and an eastern downthrown fault block (East Hastings Field), where the discovery well was drilled.

The predominantly natural gas Miocene reservoirs are in East Hastings, and the wells are currently shut in. The Oligocene Frio sands are mainly oil reservoirs and are productive throughout the field. In contrast to East Hastings, the WHU Frio sand has minimal associated gas caps atop the oil column.

74 years old and still producing, the Hastings Field #7704 was drilled in 1937.

Denbury owns the rights to the WHU, where it began CO2 injection in mid-December 2010, and currently is injecting approximately 90 million cubic feet of CO2 per day into six injection wells. First production from this effort is expected to occur late in 2011, at the earliest.

The Hastings project will require building some new infrastructure, including facilities to handle the oil and the CO2, cleaning out old wellbores and an array of housekeeping chores that come with rejuvenating an old field in this manner. The CO2 will be separated from the produced oil and reinjected, and Rykhoek notes that the company expects to recycle approximately 50% of the gas injected over the life of the field. The company also has begun CO2 injection at nearby Oyster Bayou Field east of Houston.

"For our programs over the entire Gulf Coast region, we estimate finding and development cost, including pipeline infrastructure, to be about $11.50 per barrel and cost to operate over the field life, about $21.50," Rykhoek says.

"Hastings Field might have slightly less F&D cost because the bigger the field, traditionally you get economies of scale. This is the largest field to date we've flooded, and the gross margins are very good. We're budgeted to spend in the range of $90 million at Hastings in 2011, mainly on facilities and not including CO2 and injection wells."

Denbury purchased Hastings Field in 2009 from Venoco Inc., which maintains a 22.3% reversionary interest. Venoco chief financial officer Tim Ficker notes it will consider marketing the interest once it has an idea of the CO2 response.

Steve Walkinshaw, president of Madison, Mississippi-based Vision Exploration LLC, says the company sees considerable potential in a new oil play in North Louisiana and Mississippi, the Brown Dense limestone.

Smackover action

Given the virtual time-out for dry-gas prospecting since prices landed in the dumpster, it's been a slow news day, so to speak, in north Louisiana, where the Haynesville shale-gas play has quieted following months of hype from the media and industry.

Not to worry. Today, there is a burgeoning new oil play in the region. It's the Brown Dense limestone, the lower section of the Upper Jurassic Smackover formation immediately underlying the Haynesville. The Smackover is a thick carbonate that occurs over a large part of the Gulf Coast region, where it has been drilled extensively since oil was first discovered in a test well drilled in the shallow Smackover Field in Union County, Arkansas, in 1937.

Over the years, numerous wells have been completed successfully in the higher sections of the Smackover in both carbonate and sandstone facies. The Upper and Middle Smackover grainstones and framestones represent the most prolific and widely distributed reservoirs within the Smackover, according to Steve Walkinshaw, president of Madison, Mississippi-based Vision Exploration LLC, an independent oil and gas exploration company that also consults.

In most areas, the Lower Smackover lacks the reservoir qualities to be produced in commercial quantity using conventional technologies. "The lower unit of the Smackover is aptly named the Brown Dense limestone, and it's the most prolific source rock in the Gulf Coast," Walkinshaw says.

"It's generally called a limestone, but in most areas, it's an organic-rich mudstone, a very muddy carbonate that's typically 200 to 300 feet thick. The brittle micritic limestone is remarkably uniform, with only rare developments of significant porosity; in many areas it's fractured, and wells drilled there typically encounter a lot of good oil and gas shows.

"Right now, any potential oil play out there is heavily scrutinized, and the Brown Dense is the flavor of the month, you might say, for southern Arkansas, parts of north Louisiana and the river counties in extreme west-central Mississippi and extreme eastern Louisiana.

"There's a challenge for those exploring this trend. Like other oily resource plays, 'storage' is key, and the microfracturing created in the source rock via in-situ hydrocarbon generation is insufficient for oil production in commercial volumes at current prices and technology; you need additional matrix porosity and permeability, e.g. interbedded sandstone facies, to provide ancillary storage," Walkinshaw says.

"Most of the source rock trends that don't contain this storage aren't currently commercial. This doesn't mean that people aren't willing to lease hundreds of thousands of acres in areas lacking ancillary storage, and it doesn't mean someone won't eventually figure out a way to produce it commercially—$100 a barrel makes a lot of things commercial."

nother significant challenge for the Brown Dense explorer is the risk that larger fractures extend vertically, either going high enough to reach and establish communication with the overlying Smackover porous facies, or traveling downward to communicate with the underlying Norphlet sandstone, where present.

The resulting pressure drawdown within the Brown Dense fracture system would introduce large volumes of extraneous brine, overwhelming oil production. In areas where such proximal brine-filled porosity occurs, the Brown Dense can't be fracture stimulated. In other words, to get the most bang for the buck, explorers had best seek areas where the Norphlet is absent and porosity development in the overlying Smackover is essentially nonexistent.

The 1937 Schlumberger well log for #7704 with hand-penned notations.

Vision opted to concentrate its efforts in the Brown Dense condensate window, which ranges in depth from 12,000 to 15,000 feet in Mississippi and is rich in Btu content. Commercial production of gas and condensate doesn't require the advanced levels of porosity and permeability that oil production does. Walkinshaw theorizes that the occurrence of hematite and other iron constituents within the sandstone lenses of the Brown Dense served to "scrub" a significant amount of hydrogen sulfide from those reservoirs soon after they were charged.

In areas that appeal to Vision, it's clear that certain clay constituents also preserved above-average porosity and permeability by preventing the subsequent formation of diagenetic quartz overgrowths. Such reservoirs can contain excessively rich gas and condensate at moderate depths with essentially no hydrogen sulfide and little carbon dioxide.

The modest lease bonus and royalty terms of the area, along with the potentially rich liquids yield, enable the play to make good economic sense, even at $4 per MMBtu gas, according to Walkinshaw.

Companies already are on record as drilling in the Brown Dense, with no fanfare. Shreveport, Louisiana-based Brammer Engineering and partner Anderson Energy Co. drilled a horizontal test in Columbia County, Arkansas, that reportedly was completed as an oil well. The partners also applied to the Arkansas Oil & Gas Commission for a horizontal Smackover test to a vertical depth of 9,900 feet and a 4,500-foot lateral if oil is confirmed by the vertical wellbore. Additionally, J.W. Operating Co., Dallas, has proposed a horizontal well.

There's little news being released, as zipped lips are the order of the day for most operators and others in the play. This may be a tip-off that things are looking hot and getting hotter. There are no placards touting "get your lease now," but Walkinshaw says there is plenty of leasing under way. Should this play take off, it could be meaningful to Haynesville players, provided their leases include the underlying Smackover. The vertical Pugh clause enforced in Louisiana limits the rights of the lessee to hold only particular depths of the leased property.

As for the Smackover in general, Walkinshaw predicts that considerable potential remains for discovery and development of conventional Smackover oil and gas fields across Mississippi, Alabama and Louisiana. Grayson Field, discovered in the early 1990s near Magnolia, Arkansas, is an example.

"It's a rather small Smackover structure that is projected to produce in excess of 16 million barrels of oil. But the structure, which is a simple anticlinal closure with a stratigraphic porosity pinchout on its west flank, escaped detection for decades after the surrounding area had been heavily explored, developed, and written off as having no future for any additional oil and gas discoveries of significance."

No doubt, soaring oil prices will continue to prompt second looks at a number of fields previously written off.

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