A horizontal tsunami is surging across the industry. Mature areas are awash in horizontal-drilling programs, and gas is pouring from rapidly developing resource plays.
A stream of change has churned into a torrent. Shales, led by the now-legendary Barnett in the Fort Worth Basin, are targets across the country.
And another class of reservoirs is sailing into view. Limestones, dolomites and chalks were some of the earliest targets of horizontal drilling, as lateral wellbores worked nicely in carbonates that were pervasively fractured. But, after initial waves of success in such reservoirs as the Austin Chalk, operators had to come up for air. Fractures that held gas depleted quickly, and ones that weren’t full of gas were often swamped with water.
Horizontal drilling in carbonates simmered for a while, limited to localized plays that lent themselves to simple horizontal holes.
That’s all changed. Carbonates, from Selma Chalk in the Mississippi Salt Dome Basin, James Lime in the East Texas Basin and Basal Abo/Wolfcamp in the Delaware Basin are flowing their treasures to companies armed with the latest drilling and completion technologies.
Interesting results are being reported in a number of tight-sand reservoirs. Tight sandstones can offer lucrative horizontal targets, but selecting reservoirs most amenable to horizontal work can be challenging. Several North Louisiana and East Texas operators are investigating the technology closely, notably in the Cotton Valley sand.
Hundreds of billions—even trillions—of cubic feet of gas are being added to the country’s domestic sources, both from reservoirs that cannot be produced by conventional means, and from reservoirs that deliver superior results with horizontal approaches.
“We’ve seen a big jump in horizontal drilling in the Selma Chalk, James Lime and Wolfcamp horizontal plays,” says Robert Clarke, Houston-based analyst, Gulf Coast upstream, for U.K.-based research firm Wood Mackenzie. “Total horizontal rig counts have risen sharply in these areas.”
In the Mississippi Salt Dome Basin, no horizontal rigs were at work in first-quarter 2007, but since May 2007, two to three rigs have been steadily drilling. “Mississippi has been quiet for several years, but now we have a rapid rig build,” says Clarke. “That’s a definite standout from the past five or six years of activity.”
Penn Virginia Oil & Gas Corp., EOG Resources Inc. and Denbury Resources Inc. operate horizontal rigs in the growing Selma Chalk horizontal play.
The James Lime in the East Texas Basin is another red-hot horizontal target. Active participants include Cabot Oil & Gas Corp., St. Mary Land & Exploration Co., Goodrich Petroleum Corp. and Southwestern Energy Co.
“In East Texas in the Cotton Valley sands, we saw horizontal wells being drilled out of necessity. Margins were getting squeezed, and horizontal drilling was an innovative way to improve margins,” says Clarke. “In contrast, vertical wells don’t work economically in the James Lime, and the only way to recover the gas is through horizontal wells.”
The shift to horizontals in the Ark-La-Tex region has been dramatic: At the beginning of 2007, a dozen rigs were drilling horizontal wells. At year-end, there were 33 rigs running horizontally. James Lime and Cotton Valley sands are main objectives.
In the Delaware Basin, Wolfcamp horizontal activity has been strong for the past two years. In early 2006, just a lone horizontal rig was running in the basin; in early 2008, 10 were at work, and the total reached 16 in October 2007.
“These horizontal plays are not yet in the mainstream, but when we look at the trend for the companies that do have acreage, and the number of rigs drilling horizontally in each of these basins, it sends a signal for what could be on the horizon.”
Selma Chalk
Penn Virginia Oil & Gas, based in Radnor, Pennsylvania, has been working the Selma Chalk in Mississippi for nine years. In 1999, the company purchased Gwinville, a salt-dome field that had been making oil and gas from Eutaw and Tuscaloosa reservoirs since its discovery in 1944.
Penn Virginia kicked off a vertical drilling program in the Selma, an Upper Cretaceous reservoir that’s a massive, shallow-water chalk. Early results were promising, and the company looked for other salt-dome fields with chalk potential. In 2001 and 2002, it added interests in Maxie Field in Forrest County and Baxterville Field in Lamar and Marion counties. Today, it holds 26,069 net acres: 15,489 at Baxterville, 8,000 at Gwinville and 2,580 at Maxie.
At year-end 2007, it produced 19.9 million cubic feet equivalent per day from the formation. The Selma chalk’s 139 billion cubic feet equivalent (Bcfe) are 22% of Penn Virginia’s total proved reserves.
For the past seven years, Penn Virginia has run a brisk two- to three-rig vertical program in the Selma. The formation, found at depths between 6,500 to 7,500 feet, exhibits two different productive intervals at Gwinville and one at Baxterville.
Last year, the company launched a program to downspace its 20-acre wells to 10 acres, and it set out to compare that effort with the performance of horizontal wells. “We had success in other areas drilling horizontal wells in shales and coals, and that led us to attempt two horizontal wells in the chalk,” says Baird Whitehead, president.
The attempts worked, and Penn Virginia ramped up its horizontal efforts. “We were so pleased with results on the horizontal wells that we’re rethinking the downspacing program. To drain a comparable reservoir area, the horizontal well costs less money, and disturbs much less surface area than the vertical infills.”
Significantly, the horizontals also deliver superior results: each replaces four or more vertical wells in initial potentials, production rates and reserves. For a typical vertical well that recovers 300- to 400 million cubic feet of reserves, a horizontal can deliver 1.8 Bcfe. At the same time, a horizontal well costs 3.0 to 3.5 times that of a vertical. Essentially, a $2-million horizontal completion can replace $2.5 million worth of vertical holes.
This year, Penn Virginia has one rig drilling horizontal wells, and one vertical rig testing and drilling out in front of the horizontals. Its 2008 program calls for 18 horizontal and 14 vertical Selma wells.
It permits 4,000-foot laterals, but most of its wells are in the 3,000-foot range at total depth. The Selma Chalk at Gwinville and Baxterville is akin to shattered glass, with myriad small faults. Those are in turn bounded by primary faults. The company strives to keep its laterals within a 20- to 40-foot high-porosity window, and steers its wells to the northeast-southwest, parallel to the larger faults. Adjustments are continually made to keep the laterals within the target zone, as the borehole crosses small up- and down-thrown fault blocks.
To date, the company has not employed 3-D seismic in its chalk development. It enjoys abundant well control, as it has drilled some 250 vertical wells each in Gwinville and Baxterville fields.
The key to achieving economic rates in the horizontal wells is the ability to induce fractures at frequent intervals along the lateral. “Multi-stage fracs in long laterals are what make this play work,” says Jim McKinney, Kingsport, Tennessee-based vice president and eastern region manager.
Each well is fraced with three to eight stages, using the “Packers Plus” technology, an openhole system of multiple external packers run on a production liner. Fracture ports allow one interval at a time to be stimulated at high pressures, beginning at the toe and working toward the heel of a lateral. The method was developed by Canadian firm Packers Plus Energy Services Inc. a few years ago and since has been widely adopted by horizontal operators.
Penn Virginia’s drilling program includes areas both within and along the limits of its fields. “We’re stepping out from the known area with our horizontals,” says McKinney. To date, it has drilled four successful horizontal chalk wells; cumulative production from the first two is four times or more that of their vertical counterparts.
Penn Virginia figures it has some 500 vertical locations left to drill on its chalk acreage. That roughly translates to about 80 horizontal wells, which means the company can keep its horizontal rig busy for years.
“Based on our early wells, and the promise those wells have demonstrated, we’re excited about the application of horizontal drilling in the exploitation of the chalk.”
The upshot? “Horizontal wells can accomplish the same thing as 10-acre or less downspacing, and the horizontals ultimately cost less and are more effective and more efficient,” says Whitehead.
James Lime
Another horizontal carbonate play that is enjoying a rising tide of interest is the Lower Cretaceous James Lime in the East Texas Basin. This 250-foot-thick, high-porosity limestone has intrigued horizontal drillers since the technology’s first bloom in the late 1980s.
Past attempts to make commercial wells in the James Lime didn’t work well. Results were spotty, and water production was frequently an issue. The game has changed as drilling and completion technologies have improved.
A standout project that has caused many to rethink their opinions of the James is Houston independent Cabot Oil & Gas Corp.’s County Line project, astride the Shelby/San Augustine county line.
To date, the company has completed 17 successful wells and no dry holes in the project. From zero two years ago, Cabot has grown production to nearly 40 million cubic feet per day. “Our horizontal James Lime wells come onstream at rates of up to 15 million cubic feet per day, and average 30-day production rates are 5- to 6 million a day,” says Mike Walen, senior vice president and chief operating officer.
Cabot entered the James Lime just two years ago. It put the acreage together from scratch, on an in-house prospect idea. The company had not previously worked the James, but it was enjoying good results at its Minden Field development to the north in Rusk County.
The Cabot team keyed off existing vertical wells that had shows in the Pettit and James. It offset one such test and made a good Pettit completion, and also recorded a great show in the James. A subsequent completion pleased the company with its stout performance.
Cabot’s first horizontal James well was drilled on the south end of its acreage with another operator. That well worked, and Cabot, utilizing what it learned from that operation, moved up to the central portion of its acreage where it had existing infrastructure. It kicked off a drilling campaign.
This year, the company is ramping up substantially. “We just added a third rig, and expect to drill between 30 and 40 wells in 2008,” says Walen. Each well takes 26 to 30 days to drill and set casing.
Reserves are between 2 and 5 Bcfe and costs are $3 million per well; about $800,000 of that is for completion.
Cabot drills laterals in its James wells underbalanced, and aims for lengths from 4,000 to 6,000 feet. There are two to three little porosity stringers that it tries to stay within, and it directs most of its laterals northeast. It ends the holes in toe-up positions.
Fracturing is the key to a fine well, however. Cabot stimulates up to eight stages in each well with slick-water treatments via the Packers Plus method. “That method has revolutionized completions,” says Walen. “We use a simple slick-water frac, pump at high rates and turn it around quickly. It makes enough of a difference to make the James work.”
Cabot doesn’t cement casing, and it doesn’t shut its wells in with fluid on the formation. Clean-up is through a test separator, and gas flows directly to sales. “We try to protect the fractured rocks from any damage or loss of permeability.” The approach yields excellent results: Cabot’s #2 Timberstar Perry was recently completed at 15.4 million a day.
Indeed, its drilling has been so successful that it badly needed infrastructure. In February, Cabot completed a major upgrade of six-inch and 12-inch gathering lines, along with a 20-inch transmission line. Now, it can flow up to 100 million per day.
The extent of the play is impressive. Cabot has proved up an area that spans 12 miles, and has 100 to 110 proved locations at spacing between 1,000 and 1,200 feet apart. North of its current drilling, it holds acreage to support another 70 to 100 unproved locations. Beyond its 26,000-acre County Line project, Cabot has initiated two new James Lime areas in East Texas.
Again, the James is not a seismic play. Cabot has not used 3-D, and has employed just a bit of 2-D data to date. Nonetheless, it is planning a 3-D survey over part of County Line. “We’re going to see what it shows, such as small faults that might change well spacings and patterns.”
Not surprisingly, Cabot is very pleased with its James Lime wells. “These are great wells. Our average IP (initial production) is 10 million a day, and they hold up better than the typical horizontal well,” says Walen.
Broad extent
Another operator that has been a pioneer in this successful round of James Lime activity is Denver-based St. Mary Land & Exploration. It entered the play in 2003 through the acquisition of a lone producing well in Huxley Field in Shelby County.
“At that time, most companies used open-hole, unstimulated completions in the James Lime,” says Jay Ottoson, executive vice president and chief operating officer.
St. Mary started to experiment with the formation. After Huxley, it moved to its Spider Field in DeSoto Parish, Louisiana. There, it acidized and fraced some zones with the Packers Plus system. “We made much better wells with the stimulated completions, and that’s what opened up the play for us.”
Historically, the risk in the James Lime has been water production, from cutting wet faults. “We look for quiet areas, although we do believe there is some structural component to the production,” he says. To stay away from wet faults, St. Mary employs 2-D seismic data.
It generally drills a single lateral to lengths between 4,000 and 7,000 feet, and runs between five and seven frac stages per well. Completed well costs range between $3- and $3.5 million and recoveries are expected to range between 2- and 2.5 Bcfe each. “These wells come on at good rates, and flush production drives the economics.”
From its first efforts in Huxley and Spider, St. Mary has pushed the play across a broad area. “Now we are drilling all through the trend, and we’ve extended the play from its historical development area,” says Ottoson. “The James Lime appears to be a fairly ubiquitous opportunity, but we are still working on what makes one prospect better than another.”
In 2007, St. Mary operated one rig focused on the horizontal James Lime. In 2008, it plans to operate two rigs throughout the year and drill 24 horizontal wells. “The Packers Plus completion method has made a big difference. It accelerates rate and adds reserves, which improves returns and lowers finding costs.”
Seasoned East Texas operator Goodrich Petroleum also works the play. It and St. Mary are partners in some areas and work independently in others.
“The James Lime appears prospective from Angelina and Nacogdoches counties eastward through East Texas to northwest Louisiana,” says Robert Turnham Jr., president and chief operating officer of the Houston-based firm. “It appears to us to be a broad trend that covers an area approximately 75 miles long.”
While it’s possible to drill vertical James wells and unstimulated horizontal wells in the trend, neither of those approaches has as attractive economics as stimulated horizontals. “This whole area had quite a bit of previous horizontal drilling in James Lime, but these are totally different wells. It’s all about the stimulations.”
The James has much to recommend it: drilling is straightforward, and rates of penetration in the soft formation are impressive. The multi-stage completions are reasonably priced, again because the rock is not difficult to fracture. Added to that, drilling and completion costs are flattening in the Ark-La-Tex region, and even dropping in some cases.
The company holds almost 70,000 gross acres in the Angelina Trend in Angelina and Nacogdoches counties, Texas. It currently has six wells in the James, and plans 20 wells this year, approximately half of which are anticipated to be drilled with St. Mary. Goodrich runs one horizontal rig and St. Mary has one.
Goodrich actually works two plays in its Angelina Trend, vertical Travis Peak and horizontal James. “We look for certain thickness of the limestone with gas shows to generate our James Lime prospects. We match gas shows to certain members in the formation, and that creates the prospects.”
Its approach is to drill and complete an 11,500- to 12,000-foot Travis Peak well. Then, it drills a horizontal James offset once it knows exactly where the target intervals will be.
“The play is very new, but our overall expectations are to spend $3.5- to $4 million to get 2- to 3 Bcfe.” Although Goodrich is still de-risking its acreage, it likes the repeatable nature of the James, which allows it to predict on a statistical basis what it should encounter. “That being said, the James Lime, like the Cotton Valley, has variability and with time and more wells drilled, predictability will only get better,” says Turnham.
Basal Abo/Wolfcamp
Across the wide state of Texas, over its western border with the Land of Enchantment, another carbonate reservoir is bristling with horizontal activity. The target is Lower Permian Basal Abo/Wolfcamp in northwestern Eddy and southern Chaves counties, New Mexico.
Like several other horizontal resource-extraction efforts, the play took off with the application of multi-stage horizontal stimulations.
The Wolfcamp play was generated by Capstone Oil & Gas Co., a small, private Midland-based company. Jim Geitgey, geologist, and Dale Douglas, landman, founded Capstone 10 years ago. The firm generates drilling projects, mainly in the Permian Basin and Oklahoma.
“Our strategy is to work with generating geologists who have a demonstrated track record of success in different basins and areas, and then work hard to put acreage together and promote the projects out to operators,” says Geitgey, Capstone vice president.
That’s the path they took in the Wolfcamp. The prospect was generated by Jerry Elger, a Permian Basin geologist with more than 30 years of experience. Elger saw some 20 marginal completions sprinkled along a 50-mile trend in southeast New Mexico. These one-well fields were usually deeper Morrow tests that had been plugged back and recompleted in zones identified as Abo or Wolfcamp. Recoveries were small—on the order of 250 million cubic feet per well. Elger recognized that the productive interval appeared to be one very large, continuous reservoir in the Basal Abo.
“Recoveries were so poor in existing wells that it was never targeted as a primary objective, just as a recompletion,” says Geitgey.
Capstone liked Elger’s idea. It was hunting for plays that might benefit from horizontal technology. Everywhere the Basal Abo had been tested, it had been productive of gas; Capstone figured it just needed a technology to boost rates.
The firm took the idea to Danny Campbell at CMS Oil & Gas Co., and buying began acreage. CMS accumulated a hefty position, but before it could test the idea, the company was sold. Perenco SA, a French firm, took over the prospect via their acquisition of CMS.
Capstone next brought Parallel Petroleum Corp. into the play, to the north and south of the Perenco position. Capstone also made a trade with EOG Resources on rights in some trend acreage.
Drilling kicked off in 2003. Perenco drilled five horizontals down to vertical depths of 5,000 feet and completed 4,000-foot laterals with uncemented slotted liners. It did acid jobs, but no additional stimulations. Results of this method were uneven.
EOG Resources also began to drill, and it had good outcomes. It ran and cemented casing in its laterals and performed four-stage, large Barnett shale-style fracs. It kicked off an aggressive drilling campaign.
Perenco subsequently sold its U.S. assets to Midland-based Endeavor Energy Resources LP, which operates in New Mexico as LCX Energy LLC. LCX soon moved rigs into the play, which was becoming more widely known as Wolfcamp.
Close to 180 horizontal wells have been completed in Basal Abo/Wolfcamp play, mainly on 320-acre spacing, and several hundred Bcfe of proved reserves have been established.
“It’s taken a while to figure things out,” says Geitgey. “There are sweet spots, and we are working through how to relate production back to geology and operations.”
At present, horizontal wells in the Cottonwood Creek core area average 1.6 to 2 Bcfe each, and per-well drilling costs range from $1.9- to $2.3 million. An average IP is 2 million a day, although an excellent well can make nearly 8 million.
Typically, Wolfcamp operators frac three to five stages per lateral. Some like to use CO2, and each has its own preferred size for stages. Large, multi-stage fracs through cemented casing appear to best unlock the resource.
The reservoir, which consists of shallow, intertidal platform sediments deposited in a back-reef environment, is sealed by an updip transition into tight evaporates. The huge stratigraphic trap spreads six to 10 miles wide, along a 50-mile fairway.
“Any well drilled within the fairway will encounter gas-charged dolomite,” he says. “The issues are production rates, estimated ultimate recoveries and how to recognize better areas.”
The reservoir is naturally fractured and contains matrix porosity, which complicates predictions of superior areas. In a helpful touch, fractures are oriented along strike, which is northeast-southwest. That means laterals drilled east-west or north-south intersect the fractures obliquely, and drilling units can be laid out in customary patterns.
Interestingly, the wells initially exhibit strong hyperbolic declines. But after about 18 months, they transition to exponential declines, evidence of a dual-porosity system.
The laterals target a gross porosity interval of some 50 feet. The dolomite reservoir consists of stringers of porosity laced throughout the section, with limited areal extent. Typically, operators drill vertical pilot holes through the Basal Abo to identify portions with good drilling breaks and gas shows, and laterals are kicked off in those sections. The goal is to stay within the interval, rather than follow any one localized stringer. Drilling is straightforward, with few mechanical or operational issues.
Development of the play has proceeded wholly through horizontal wells; other than the original recompletions that led to the prospect idea, no vertical attempt has been made.
Now that drilling is migrating to areas with fewer penetrations, companies are interested in what 3-D seismic might reveal. WesternGeco recently shot a 75-square-mile survey in the southern portion of the trend, and that is being processed.
Currently, the three main operators—Parallel, EOG and LCX—each run a rig continuously. Most of the acreage has been nailed down, and activity has moderated after an initial push to convert acreage to held-by-production status. The vast stratigraphic trap can easily support hundreds of additional wells at 320-acre spacing, and more than a thousand at 160s, a spacing that has been investigated with success in several tests.
“If drilling costs stay down and gas prices stay strong, this play has a lot of running room,” says Geitgey. “This is one of the bigger gas plays being pursued in the Permian.”
Cotton Valley sands
The Jurassic Cotton Valley sands in North Louisiana and East Texas have been targets of a number of horizontal operators for nearly two years. Although the tight-sand Cotton Valley play covers an immense swath, most of the lands in the prospective area are held by production. Unleased acreage is scarce and operators are not driven by expirations; the horizontal Cotton Valley play will likely unfold over a number of years, driven by deals.
Independent Petrohawk Energy Corp., based in Houston, holds interests in 125 sections in Elm Grove, a massive field that sits at the junction of DeSoto, Caddo, Bossier and Webster parishes, Louisiana.
“We’ve been drilling vertical wells in Elm Grove for close to a dozen years,” says Dick Stoneburner, chief operating officer. Elm Grove produces from myriad reservoirs, but three zones in the Lower Cotton Valley stand out as horizontal candidates: the 100-foot-thick Davis and Turner members, and the 30-foot-thick Taylor.
Petrohawk has completed two operated horizontal wells in the Davis, and one in Taylor. Its completions are led by its #13-3H Killen, a Taylor completion that came onstream in late 2007 at 16.5 million per day. The two Davis wells initialed at 3.1- and 4.5 million daily.
Petrohawk has used openhole Packers Plus-type systems up to this point, but it plans to use cemented liners on some of its wells to evaluate their performance. “We’re going to compare those systems to cemented liners. We like the performance of the openhole system, but we have encountered some mechanical issues.”
The operator has two horizontal Lower Cotton Valley Taylor wells ready to complete, and it will stimulate one with each method. Both will feature multiple, 500-foot frac stages along 4,000-foot laterals. The cemented liner method is much more time- and labor-intensive, because the operator has to come in and out of the hole with coiled tubing for each stage. But costs are about the same, and it’s a tried-and-true method. The comparison will be telling.
Vertical wells are certainly economic at Elm Grove, so even the decision to go horizontal at all is under study. “The initial rates on the horizontal wells can really improve rates of return, even if the ultimate recovery ratio for dollar spent is somewhat less for horizontal wells,” says Stoneburner. “But it’s a win-win deal, because both vertical and horizontal wells are very economic. We see no downside in trying.”
This year, Petrohawk plans 20 horizontal wells at Elm Grove and 90 to 100 verticals. “By the end of the year, we’ll know if horizontals are really better in certain areas than drilling vertical wells. But the answer could well be a combination of the two.”
Lower Cotton Valley horizontals cost $4.5 million, and a typical commingled Hosston and Cotton Valley vertical well runs $1.8 million. Recoveries are 1 to 1.5 Bcfe on a vertical well. “If we can get recoveries north of 3 Bcfe, or even above 2.5 Bcfe in a horizontal, we’ll get better present values because of the higher production rates,” says Stoneburner.
Compare and contrast
Goodrich Petroleum also works Cotton Valley sands. “We have drilled four Cotton Valley horizontals so far,” says Turnham. “Horizontal drilling has not been utilized until recently in the Cotton Valley, and we’re trying to confirm that it’s a better route to take.”
At present, Goodrich is flowing a well back in Longwood Field in Caddo Parish, and is drilling its fifth horizontal test in Bethany Longstreet Field in DeSoto Parish.
The company targets both Taylor and Davis sands in the Cotton Valley interval, at vertical depths of some 10,000 feet. Laterals extend 3,000 feet, and are tricky to drill and keep in zone. A typical James Lime well might take 25 days to drill, but a Cotton Valley with half the lateral length requires upward of 45.
The Cotton Valley horizontals also need much larger fracs, with six to seven stages per lateral. “The cost per stage is approximately $100,000 and each stage covers about 400 feet,” he says.
Completed wells cost $5.5- to $6 million each, and expected ultimate reserves are 3 to 3.5 Bcfe. Of the 270 wells Goodrich owns, two-thirds are vertical Cotton Valley producers. Its typical vertical well currently costs $2- to $2.5 million and recovers 1 to 1.1 Bcfe.
In 2008, Goodrich plans four to five horizontal Cotton Valley tests. “But it depends on the success of our current two wells. We will switch back to verticals if we decide those are better,” he says.
Certainly, that’s the story throughout the industry. Where fresh applications of horizontal drilling and stimulation technologies work, entirely new plays will open and mature ones will be revitalized. Technology is never a one-size-fits-all situation, and there’s no substitute for trying something in the ground.
Since the mid-1990s, a handful of operators have applied high-volume pumps to improve recoveries from Hunton wells with very high water cuts. The Hunton behaved like a coalbed-methane reservoir: As massive volumes of water were pumped off, reservoir pressures lowered and relative permeabilities changed. Gas came out of solution, and oil trapped in tight portions of the reservoir was pushed free. Initially, operators used vertical wells, but by 2000 they began a shift to horizontal drilling.
The horizontal approach worked well, and today operators drill up to three horizontal laterals in a crow’s-foot configuration. At present, some 100 million cubic feet of gas equivalent per day is produced from the Hunton resource play.
Two Canadian firms are deeply involved. Petroflow Energy Ltd., a small, public company based in Calgary, runs its operations out of Denver through subsidiary North American Petroleum Corp. USA. Its partner is Enterra Energy Trust, a Canadian resource trust also based in Calgary.
Petroflow was a small, newly formed entity in 2006 when it identified an opportunity to purchase the assets of Altex Resources Inc., a pioneer in Hunton dewatering. Petroflow needed a well-capitalized partner, so it brought Enterra into the $250-million deal. The venture was structured as a purchase of Altex by Enterra and a subsequent farm-out of the development drilling to Petroflow.
The results: Petroflow manages drilling and completion operations and pays 100% of well costs; Enterra handles land acquisition and production and receives 30% interests.
“The arrangement works well for both sides,” says Kevin Davis, Petroflow senior vice president of corporate development. “We put all our money in the ground and get the development multiple, and Enterra maintains its cash flow.”
In 2006, Petroflow and Enterra drilled a dozen horizontal Hunton wells, mainly in Grant and Garfield counties. Last year, the partners added another 24, centered in Lincoln County. Between them, Petroflow and Enterra control 43,000 acres, spread across seven counties prospective for Hunton dewatering.
The multi-lateral horizontal wells target solution gas trapped in Hunton transition zones. “Gas is held in solution in residual oil, and we pump large volumes of water, up to 10,000 barrels per day per well. The rapid depressuring of the reservoir causes the gas to come out of solution and it becomes mobile in the reservoir,” says Davis. The technique also produces some oil, generally at fairly modest rates.
Petroflow uses a sump-type design on its Hunton wells. It drills a well angled at around 60 degrees through the Hunton and sets 7-inch casing. “Then we come up and set a whipstock and drill out into the Hunton openhole,” says Sandy Andrew, executive vice president and chief operating officer. The company targets lateral lengths between 1,500 and 3,000 feet, depending on drilling conditions. The sump design allows it to place pumps as low as possible in the wells to ensure maximum drawdown and hydrocarbon recovery.
Most of its drilling is focused on areas with no conventional production. “Our targets are areas without conventional traps,” says Davis. “We are in reservoirs with water saturations of 60% to 70%, and we’re really dealing with a fluid dynamics trap.”
Certainly, the area that falls within Petroflow’s parameters is impressive. The Hunton formation occurs across a wide swath of Oklahoma, and production from horizontal dewatering wells has been established in several counties. Petroflow targets dolomitic portions of the Hunton, which are generally more porous and permeable and carry higher residual oil saturations than the tighter fractured limestones.
“In any given area, what it comes down to is whether we can economically drill a long enough lateral to achieve the drawdown we need for economic gas and oil production,” says Andrew. “It’s a matter of whether we can get enough straws in the reservoir and move the water at a price that makes sense.”
Naturally, the biggest driver in the operating costs is water handling, and huge volumes mean costs are five to six times that of a conventional well. As water production drops, however, costs also trend sharply downward.
At present, Petroflow estimates a typical multi-lateral Hunton well costs $2.5 million to drill and complete, and will recover 2.3 billion cubic feet equivalent. One Arbuckle water-disposal well can typically handle eight to 12 production wells.
A typical well will start out producing up to 10,000 barrels of water a day. Within a few weeks, gas and oil will begin to appear. From an initial rate of a couple hundred thousand cubic feet per day, gas will peak at 900,000 per day or more. It can take about a year to reach peak production, and decline is hyperbolic from that point onward. Wells drilled in areas that are already dewatered often reach peak rates within six months.
“Gas rates are fairly consistent from area to area and well to well, but oil varies more widely,” says Andrew. On average, Hunton wells achieve peak oil rates between 20 and 40 barrels a day, then decline along with the gas. However, some wells have hit oil rates in excess of 200 barrels per day.
At year-end 2007, Petroflow was producing 2,100 barrels of oil equivalent per day. “We expect to exit 2008 at 4,400 per day,” says John Melton, president and chief executive. “We have three rigs running in the Hunton play, and we plan 30 wells this year and the same number in 2009.”
Beyond that, Petroflow has another 165 identified locations on its acreage. “The Hunton play in Oklahoma is the primary focus of our future growth.”