Emerging Oil

At press time, Crosby 12H-1 was under way in Wilkinson County in the southwestern corner of Mississippi, among rolling hills just east of the ancient river and its legendary delta. Goodrich Petroleum Corp., operator with 50% working interest, was just about to finish a targeted 7,300-foot lateral, and the post-completion flow results were highly anticipated.

Yet, frankly, news from every one of these new Tuscaloosa Marine shale wells is anxiously awaited.

Within a year, the area that hadn’t had a new horizontal Tuscaloosa attempt since 2009 now hosts more than a dozen completed wells and another dozen are in permitting, drilling or completion. Rob Turnham, Goodrich president and chief operating officer, estimates 20 or 25 completed wells by the end of this quarter. With this, Goodrich and other operators may be able to develop decline-curve and estimated-ultimate-recovery (EUR) statistics for the play, forming the basis for determining whether it has an economic future.

Results that have been announced to date have been very encouraging. Encana Corp.’s Anderson 17H, in which Goodrich has a 7% interest, in Amite County averaged a whopping 933 barrels of oil equivalent (BOE) per day, almost all oil, in its first 30 days on a 15/64 choke from a roughly 7,300-foot lateral and 30 frac stages. It posted 1,172 a day in a 72-hour rate and was making 300 a day six months later.

"We feel we have a real shot at proving this play. the resource is there," Rob Turnham, President and COO, Goodrich Petroleum Corp., says of Tuscaloosa Marine shale.

“It’s on artificial lift now,” Turnham says. “Production has flattened, so we’re seeing the hyperbolic curve, indicative of long-life, matrix flow versus an exponential decline which would lead you to believe we were only draining fractures.”

All of the modern TMS wells are making oil. Devon Energy Corp.’s nearby Richland Farms 74H-1 came in at 284 BOE a day on a 9/64 choke from a roughly 5,000-foot lateral with 20 frac stages in Wilkinson County. And, Encana Corp.’s Horseshoe Hill 10H-1 made 656 BOE a day in a 30-day average from a roughly 5,300-foot lateral and 18 frac stages.

South, in Louisiana, Devon made Murphy 63H-1 for 408 barrels a day on an 11/64 choke from some 5,300 feet of lateral in West Feliciana Parish.

Moving east, Devon’s Beech Grove Land Co. 68H-1 made an average of 101 a day over 30 days from a 3,400-foot lateral and 12 frac stages.

Turnham notes that another well, Encana’s Weyerhaeuser 73H-1, has been online for nearly a year now; it came in at an average of 740 BOE a day from a 5,000-foot lateral and 15 frac stages. Its decline curve is promising.

“Just like the Anderson 17H, we see a hyperbolic curve which has us comfortable with the resource potential. Now, our primary focus is getting the well costs down and putting the economics out there, so investors can make their decisions.”

In a year of work, wells are now estimated to cost $12- to $13 million each, with a 7,500-foot lateral and 25 frac stages, down from early estimates of as much as $19 million. Further cost reduction is possible once the play is proved and more oilfield equipment, crews and infrastructure enter the area. “In fact, EOG (Resources Inc.) reached total depth on a well in 28 days which, by our estimates, would be in the $10-million-completed-well-cost range. This, in our opinion, would generate very high rates of return, and be competitive with other oil plays,” Turnham says.

It appears that the longer lateral—that is, a two-section lateral, which is permitted in Mississippi but not yet in Louisiana—is better. The most impressive wells revealed to date are in Amite County, just east of Wilkinson. After the whopping Anderson 17H-1, Encana’s Anderson 18H-1 averaged 1,072 BOE a day over 30 days from a roughly 8,800-foot lateral and 29 frac stages.

This Mississippi side of the play is where Goodrich is focusing now—about 55% of its 134,000 net, 156,000 gross, acres are there; the balance, in Louisiana. Amongst all its acreage, some 95% of it is where TMS oil pay is at a shallower depth—10,500 to 13,500 feet—than at the 16,000 feet the TMS can reach in some areas.

Ensign Energy Services Inc.'s Rig 753 works on lateral for Goodrich's Crosby 12H-1.

“If you look at the hundreds of wells drilled through the TMS in the 1970s and early ’80s for gas, a number of them produced or showed oil in the shallower portion, so our block is where the TMS is shallow.”

Findings to date include that the TMS appears there to be 100 to 160 feet thick with a little higher clay component in the upper portion. The amount is slightly more clay than in the Eagle Ford, but less than in the Utica. “We’re not concerned we have too much clay here,” Turnham says.

Of course, Goodrich and Encana, which have adjacent acreage in Mississippi, aren’t focusing on the upper part of the TMS anyway. Instead, they’re targeting the bottom half or third of the rock, which is also where they’re finding it to be brittle, having natural fracturing.

“Clearly, that is how you’re getting these 1,000-BOE-a-day wells. You’re seeing very good fracturing and pressures providing high initial rates and matrix production from the shale itself, which is giving you the hyperbolic-shaped curve and the long-life resource.”

Rubble trouble

Meanwhile, the pair is also working to solve for the rubble zone. In a joint well, Encana’s Ash 31 H-1, the 6,500-foot lateral was landed above this roughly 10-foot trouble zone that sits some 35 feet above the bottom of the TMS in Amite County. The zone is composed of poker-

“We feel we have a real shot at proving this play. The resource is there,” Rob Turnham, president and COO, Goodrich Petroleum Corp., says of the Tuscaloosa Marine shale. Overleaf, a pumpjack in southeastern Mississippi as the sun works to clear a morning fog in late November. Facing page, Ensign Energy Services Inc.’s Rig 753 works on the lateral for Goodrich’s Crosby 12H-1.

chip-size pieces of shale that crumble easily.

“It’s fine when you’re drilling through it,” Turnham says. But the key appears to be to enter this zone at a steeper angle because, at 80 or 90 degrees, the wellbore wants to cave in or slough, causing increased rig days while the wellbore is washed and cleaned out.

Rubble rubble, toil and trouble. This happened to Goodrich’s first TMS operated well, Denkmann 33 H-1, adding several rig days. Upon successful repair of a popped casing connection, Denkmann is to flow this year from a 4,000-foot lateral—abridged from a 7,000-foot plan.

Nearby, the famous Anderson 17H-1 entered at a roughly 70-degree angle and had no trouble in the rubble. “The big question for us is if this is unique to this area. What we have seen is, if you take a bit of a steeper angle through the rubble zone, you do seem to stay in it less time and have less of a problem.”

Roughnecks on Ensign Rig 753 work on the Crosby 21H-1 in Wilkinson County, Mississippi. The crew moved to the Crosby after drilling Goodrich’s first operated TMS horizontal, Denkmann 33H-1, just east, in Amite County.

Another option is to land laterals above the rubble zone. Encana’s second Ash well, Ash 31H-2, was being drilled at press time off the same pad as the first; each is expected to be fraced this month. “The question here is if you will stimulate the entire interval if you land above the rubble zone. It shouldn’t be a problem, but it is a question right now.”

Goodrich is testing another option with its Crosby 12H-1 by getting the rubble zone behind about 200 feet of additional well casing. “So, when we come out to replace bits or bottomhole assembly, we just don’t have to deal with the sloughing issue; it’s behind the liner.”

None of this rubble trouble will ruin a well, though. “If you drill the hole with a big enough diameter, you can come up and get it behind your liner. That is a contingency. We just have to make sure we build a big enough hole, so we will have that contingency.”

A decision will ultimately be based on if landing above or below the rubble zone will

make a better well. “We think you could stimulate the entire zone. And there has been some microseismic run that suggests you could get 200 or 300 vertical feet of growth when you frac the interval, with stimulation up and down regardless of where you land.

“It could be that you don’t need to land below. But we want to make sure and have a comparison because the two best wells drilled in the TMS to date are the two Anderson wells and each of these landed below the rubble zone. They didn’t have the sloughing issue because they came in at a very high pitch; they didn’t stay in that zone for long because they were in at less than 75 degrees.”

The cheaper approach is sans the additional casing, although it isn’t very expensive, he says. “We need an answer. Once we figure out we’re stimulating the same shale and getting the same results, we would go with the cheaper approach.”

TMS economics

As more wells come online, contributing to estimates of play economics, some surface characteristics will help as well. For example, oil from the area fetches the coastal Louisiana Light Sweet (LLS) price, which is roughly that of Brent, thus some $22 higher than WTI. Royalties average 20%; in South Texas’ Eagle

Ford, the average is about 25%. In Mississippi, the severance is roughly Louisiana, it is none at first, due to state incentives for horizontal drilling.

“And the play itself is 94% oil,” Turnham notes, and it is light and sweet with gravity between 38 and 44 degrees. “With the LLS price and low royalty and tax burden, you have the ability to spend a bit more money to generate rates of return similar to the Eagle Ford.”

Entering this year, Goodrich has participated in eight Tuscaloosa wells, 4.3 net, for a cost of some $40 million. Its leasehold, which it acquired for an average of $245 an acre, has terms ranging from a balance of one year to five years; some 50,000 net acres have “continuous drilling” permission that allows Goodrich to continue to hold it as long as one well is drilled per 180 days.

TMS results the farthest east to date are both from Devon in Tangipahoa Parish. Its Thomas 38H-1 had initial production of 402 BOE a day on a 9/64 choke; its Soterra 6H-1 averaged 176 BOE a day over 30 days from a 4,300-foot lateral with 13 frac stages.

Meanwhile, west of the Mississippi River, EOG’s Dupuy Land Co. 20H—the one that was drilled in just 28 days—was being completed at press time in Avoyelles Parish near Goodrich’s 40,000 net acres in Concordia Parish. Another EOG well, Gauthier 14H, was being drilled at press time, also in Avoyelles Parish.

Floyd Wilson’s new Halcon Resources Corp. has plans more west, in Rapides Parish, where Bill Pritchard’s Indigo Minerals LLC made an Eagle Ford well, Bentley 34-1H, in 2011.

Turnham expects industry to be able to make a ruling on the TMS’ economic future by the end of this quarter, deciding then if Goodrich will bring in a partner—that is, more money. “We feel we have a real shot at proving this play. The resource is there. But, in its early stages, you have to be very cautious with capital until you feel comfortable with the economics.”

Pearsall pay

In South Texas, pushing the new Pearsall play farther east is privately held start-up Momentum Oil & Gas LLC, with a $50-million equity commitment from Kayne Anderson Energy Funds and approval for up to $100 million of bank credit from Wells Fargo.

Rusty Shepherd, CEO (at top), and Loren Long, president, Momentum Oil & Gas LLC, are planning a first horizontal Pearsall well in their Fashing Field acreage this year. Shepherd says it is a myth that the Pearsall only makes dry gas: A USGS study only sampled in the dry-gas window in the Maverick Basin, “so you got what you would expect.”

Rusty Shepherd and Loren Long started the Houston-based company in 2011 with a traditional business model: for long-life producing assets in mature basins with new upside. That brought them to Fashing Field in eastern Atascosa County in South Texas via an acquisition from Newfield Exploration Co. of its long-life production from the Edwards formation and below, beginning at about 10,000 feet. Newfield kept rights above the Edwards, thus retaining its exposure to upside from the Olmos, Austin Chalk, Eagle Ford, Buda, Georgetown and other rocks.

The deal gave Momentum some 3,000 acres held by production (HBP) by Edwards with upside exposure to Glen Rose and Sligo as well as to Pearsall that is at about 12,000 feet in the area.

“Fashing Field is in the oil window of the Eagle Ford play,” says Shepherd, Momentum chief executive officer who was formerly with Crimson Exploration Inc. and The Houston Exploration Co. “We knew we were too late to the Eagle Ford to build a position there, but three events in 2011 accelerated our view of the Pearsall: the run-up in oil prices, drop in gas prices and the release of a high-rate, liquid-rich well test.”

In January 2012, the Momentum team began gathering deep rights from other mineral-rights owners, bringing the leasehold to some 24,000 gross and 21,000 net acres, including in eastern Atascosa County in the “Four Corners” area. Its first horizontal attempt in the rock is planned for this year with a one-section lateral and up to 22 frac stages.

The antebellum Stanton Hall home, downtown Natchez, Mississippi, is just north of more than a dozen new TMS wells under way and a few blocks from Callon Petroleum Corp.’s historic headquarters. An adjacent restaurant serves fried catfish, crème brulee, mint juleps and, during Pilgrimage season, Southern musicals.

Old vertical and recent horizontal wells in Pearsall show it to range from 750 feet thick in eastern Dimmit County and roughly in excess of 300 feet across South Texas, Shepherd says.

Long, president and formerly with Bill Flores’ Phoenix Exploration Co. and Jeff Voncannon’s Redman Energy, says the oil, NGL and dry-gas windows of the Pearsall, based on log analysis, are similar to the gradation of the Eagle Ford, which is also Cretaceous in age, trending from oily in the north to gassy in the far south. One differentiation appears to be that each window sits slightly more north. “It’s just set farther back from the coast than the Eagle Ford because the Pearsall is older rock,” Shepherd says. Another difference is that the condensate window in the Pearsall may be larger than that in the Eagle Ford.

In Momentum’s target area, the Pearsall is at 12,500 feet, is 600 feet thick and has 4% to 10% porosity. “It is lower in porosity than the Eagle Ford, but it is thicker. It is more desirable than the Eagle Ford. As for permeability, we’re talking about nanodarcies, maybe microdarcies,” Shepherd says.

St. Catherine Creek National Wildlife Refuge along the Mississippi River, just south of Natchez.

Long says a log of Continental Oil Co.’s R.W. Carnes 1 vertical in Fashing Field in 1974 is one that most captured his and Shepherd’s attention, with its fire-red hydrocarbon shows in 559 feet of Pearsall. “That log really turned us onto that the Fashing Field could be pretty spectacular,” Long says.

A couple of other logs in the area had similar findings, such as EEX Operating’s Tom Unit 1-1 in Atascosa County in 1957 that found Pearsall to be 455 feet thick. Meanwhile, moving east into Karnes County, the Pearsall was less appealing: Shell Oil Co.’s BA Pawelek A1 in 1978 found it to be only 157 feet thick beginning at 12,740 feet.

Far west, in the Maverick Basin, the rock gives up gas, thus a U.S. Geological Survey study in the early 2000s suggested the Pearsall contains dry gas. “They only sampled in the dry-gas window,” Shepherd says, “so you got what you would expect. People got the idea from that, though, that it was a low-organic-content, dry-gas system.”

Since 2010, however, 17 wells have been landed in the Pearsall east of the Maverick Basin, showing liquids. Also, the rock appears to contain natural fractures that would enhance flow rates, but it isn’t faulted, which would make staying in zone difficult. Lithography is a hybrid of chalk and shale, like the Eagle Ford.

About 25% of Momentum’s acreage is HBP now; it has three to five years left on the balance. As it develops its Pearsall program, the Edwards can hold its acreage at Fashing Field, Long says, “so we have a lot of flexibility in developing the Pearsall.” He adds that exploring and exploiting Pearsall today for the budget of a start-up E&P is enabled because equipment and infrastructure have come into the area for the Eagle Ford.

The bustling Mississippi River bridge at Natchez, shown here at sunset, is the only bridge for a roughly 140-aerial-mile stretch of river. From the high bluff of downtown Natchez, the river’s legendary floodplain is visible on the Louisiana side.

The pay is promising. In Frio County, east of Momentum’s acreage, Blackbrush Oil & Gas LP’s Pals Ranch 11H made 1,837 BOE a day from Pearsall—706 oil and 700 gas liquids. A bit closer, Cabot Oil & Gas Corp. made Pickens 101H for 1,276 BOE a day with 976 of that being oil. A bit south, Oklahoma City-based Cheyenne Petroleum Co. made the ZCW 1H in

LaSalle County that came in at 1,789 a day, 742 oil.

Long says total organic content (TOC) hasn’t been published yet for Momentum’s part of the liquids-rich Pearsall trend. “Those numbers are just starting to come out. Rumors are they’re much higher than estimated before.”

The Scoop

In south-central Oklahoma, the founder of the giant horizontal Bakken play is making additional oil pay for itself, dubbed “Scoop” for the “South-Central Oklahoma Oil Province.” There, it is targeting the siliceous Woodford shale at as much as 15,000 feet deep that is up to 400 feet thick and is the source rock for as many as 60 different conventional reservoirs in the region.

“The Woodford shale is the source bed that generated most of the oil that has been produced from these conventional reservoirs for decades,” says Jack Stark, Continental Resources Inc. senior vice president, exploration. Continental estimates that up to 70 billion barrels of oil remain in the Woodford in the Scoop area.

Centered largely now in Grady, McClain, Garvin, Stephens and Carter counties, the area is an oil-field legend. “Scoop includes three of the top oil-producing counties in Oklahoma,” Stark notes. Among them, the area is home to the 1.4-billion-barrel producer Sho-Vel-Tum Field that was discovered in 1905. “More than 3.2 billion barrels of oil have been produced his area. And, the Woodford has been one of the primary sources of this oil.”

The play compares well to the Bakken, which is also Devonian in age, with TOC of 6% to 12%; porosity of between 5% and 8%; pressures up to 0.6 to 0.65 psi per foot; and original oil in place of 45- to 70 million barrels per section.

They only differ in terms of depth, thickness and fairway size. In the Scoop, the Woodford is at between 8,000 and 16,000 feet; in the Willis-ton Basin, the Bakken is at 8,000 to 11,500. Thickness of the former is 150 to 400 feet; the latter, 10 to 250. And, the footprint of Scoop is 3,300 square miles; the Bakken, some 15,000.

Putting together some 200,000 net acres over this portion of the Woodford, the play has quickly evolved from an idea to six Continental-operated rigs in 2012 to plans for 12 rigs by the end of this year.

Jack Stark, senior vice president, exploration, for the Bakken play’s founder, Continental Resources Inc., says Scoop oil-play economics in south-central Oklahoma are competing head to head with the Bakken.

To date, Continental has drilled 20 operated wells and participated in another 15 in Scoop. Multiple laterals are possible. “It is so thick in some areas we believe we may need to drill wells in both the upper and lower Woodford to effectively drain the reservoir,” Stark says. “We suspect one wellbore in a 400-foot-thick reservoir wouldn’t do a good job of draining all of that. It isn’t 400 feet thick everywhere but, where it is, we would test the productivity of laterals in both the upper and lower sections.”

Already, the company is netting 5,183 BOE a day from Scoop, such as from the oily Simms 1-32H that came in at 702 BOE a day, 80% liquids, and the NGL-rich Poteet 1-17H at 1,771, 55% liquids. Continental’s current reserve model estimates the EUR for wells in the condensate window is 1.2 million BOE, 61% liquids; the oil window, 626,000 BOE, 75% liquids. Rate of return is some 40% to 55% at $3.50 gas and $90 oil. Drill days have declined from 72 in 2011 to 45; well costs, from $10.7 million to $9 million; and frac stages from $428,000 to $296,000 each.

“The beauty is that these economics compete head to head with the Bakken. And, this play has upwards of 1.8 billion barrels of net unrisked resource potential to Continental from an estimated 2,200 net unrisked potential locations, assuming 80-acre spacing.”

Downspacing will come later, however. As some 75% of its leasehold isn’t HBP yet, it is dropping wells at the rate of 640-acre section by section, while also further defining the subtle transition of the NGL-rich to the oil-rich fairway across a 15- to 20-mile-wide swath of pay. “We have typically been fracing the wells with 12 stages, but recently have increased to 16 stages, and we will likely add more if results support it.”

Drillpipe is rolled for use in the Crosby 12H-1.

Meanwhile, Continental hasn’t found a challenge that is unique to the play, he adds. But it does have its faults—that is, that this area of the Woodford is faulted, which means there are desirable natural fractures in the rock but there are also some structural shifts. Staying in zone will be key.

“Because of the tectonic history of southern Oklahoma, the area is more highly fractured than in the northern (gassier) area of the Wood-ford.” Thus, the company acquired 600 square miles of proprietary 3-D seismic data as a “hazard survey.”

“We can identify where these faults are and not allow them to cause us problems while we’re drilling. Of course, when you’re dealing with a couple hundred to 400 feet of Woodford, you would have to have a pretty big fault to get completely out of zone.”

An MLP in the play

The team at Eagle Rock Energy Partners LP is grateful to Continental for giving the Scoop play a name this past October and highlighting it for the investment market. On the other hand, Eagle Rock was still accumulating acreage and the news swept quickly to mineral-rights owners and competitors—thus leading to higher lease costs—quips Joe Mills, Eagle Rock chairman and CEO. By this time, the company had picked up some 14,000 net acres.

It was drawn to the area in 2011 for its multi-stacked pay, such as from multiple, shallow Pennsylvanian-age sands like the Hart and Springer, and the deeper “Big Four” and bromide, through buying Maurice Storm’s Crow Creek Energy II LLC for $525 million. It went to work with two rigs targeting these zones, including the Woodford, vertically. As a master limited partnership (MLP), the company’s focus is on low-risk exploitation, rather than high-risk exploration. But, news of Continental’s early Woodford shale well in its operating area compelled the team to capture some of the potential upside for itself.

“We had not drilled horizontally in this area until Continental drilled their Lambakis 1-11H well,” Mills says. Eagle Rock followed with its first horizontal Woodford test, Beckham 1-27H, approximately six miles southeast of the Lambakis. “As an MLP, we are not incentivized to conduct high-risk exploration, but we knew enough about what Continental was doing and, given our vertical well control in the area, we could see the Woodford was highly prospective at 200 to 250 feet thick.”

That Beckham well—Eagle Rock’s one Scoop horizontal—has a 4,500-foot lateral completed with 13 frac stages. At press time, it was drilling a second horizontal Woodford test. Joe Schimelpfening, Eagle Rock’s senior vice president, upstream business, says, “At this time, we’re limiting our lateral length in these wells to a section, but other operators are beginning to push lateral lengths to 10,000 feet within our current development area. We believe two-section laterals will become increasingly more common in the development of the play.”

At top, a Goodrich field operations team leader samples TMS cuttings as rig equipment monitors drilling conditions.

Like Continental, Eagle Rock has seismic data to assist in drilling the horizontal section to avoid significant faults. “The Woodford accumulation is very large. In certain areas, it is heavily faulted, which can cause drilling problems for long-length laterals,” Schimelpfening says.

So how to fit an exploration play into an MLP? Mills says, “We are studying that.” He estimates Eagle Rock has approximately 200 gross well locations on 160-acre spacing and 300 on 80. “These are $10- to $12-million wells to drill and complete. Net to our working interest, we could easily spend $200- to $400 million of capital to develop our asset in this area, and that is a big bite for any MLP—certainly for one our size.”

On the other hand, the acreage offers Eagle Rock multi-stacked pay zones that are extremely productive from vertical wells as well,

and an MLP’s job is to consistently produce within cash flow so it can pay quarterly distributions. The team is evaluating bringing in a partner to pare its total capex exposure. “Another option is to outright monetize the Wood-ford portion. The shallow formations are more conducive to an MLP.”

Joe Mills, Eagle Rock Energy Partners LP chairman and CEO, says the company may have 300 net Scoop-play locations on 80-acre spacing.

For now, Eagle Rock intends to keep one rig running in the horizontal Woodford and one working on vertical-pay development. “Some time in this quarter, we’ll announce what our long-term intentions are,” Mills concludes. In terms of lease expiration, it has time, though; more than 80% of its acreage is HBP by other formations.

Name dropping

With prolific E&P assets worldwide, Houston-based Noble Energy Inc. is looking at a possible new tight-oil play not far from home—in Northeast Nevada, a region so lightly drilled that nomenclature for many of the rocks beneath the surface has not yet been assigned. “We’re just calling it the Tertiary Elko formation right now for our own purposes,” says Mike Putnam, Noble director of North American exploration and new ventures.

What is known is that the formations in Elko County may offer a menu of lithologies. “It could be a pretty mixed bag,” Putnam says of what data suggest a first vertical well will find later in this year. “There will be some thick shale sections. We know that. There will likely be some carbonates and, probably, some silty—maybe even sandy—sections. There is the potential for some volcanic deposits as well, based on the history of this area. The type and quality of the rock is what we need to determine through drilling.”

Noble announced this past fall that it had put together some 350,000 net acres in northeastern Nevada concentrated in Elko County with the intent of developing a new oil play. Putnam says, “We have a new-ventures team focused on finding new resource plays, particularly in North America, and they put together a pretty nice regional analysis of several areas in the western U.S. They identified this large, potentially overlooked, tertiary petroleum system in Northeast Nevada that got our attention.”

This was in late 2009. “As time went on, the data we looked at started to bear this out.” Data was from myriad sources, including the traditional geologic method of studying outcrops at the surface.

While the area in Elko County is very lightly drilled, some wells were attempted in the 1970s and early 1980s during the height of the oil-and gas-price boom of the era. Most exploration in Nevada had been focused on older rocks and more conventional traps, however. “We really haven’t seen much unconventional activity in Nevada, although there has been some drilling for the Paleozoic shales recently.”

One of those targets, known as the Chainman shale, is generally deeper than the Tertiary targets in which Noble is interested. Otherwise, most drilling in Nevada has been concentrated south, mostly in Nye County in the Railroad Valley area.

Data from that area may be analogous to what Noble will find in Elko County: source rocks in a lacustrine petroleum system. Lacustrine is a freshwater type of depositional system, which is also the hydrocarbon-producing setting of the Green River formation east of Elko in the Uinta Basin in Utah. The large, tertiary-age lakes in the Elko Basin created source rocks that old wells indicate contain oil pay; however, these wells were drilled prior to horizontal technology that today makes it possible to extract hydrocarbons that are trapped in low-permeability and low-porosity rocks.

Ensign Rig 753 crew members will move to Amite County to drill Goodrich’s third TMS-operated horizontal, Huff 10-7H-1, upon completing the Crosby.

From a 1,000-foot core retrieved near an outcrop outside the city of Elko and from studying old well logs, outcrops and other data, the Noble team has determined the Elko play may be between 1,500 and 2,000 feet thick at between 6,000 and 12,000 feet. Indications from that core analysis are of encouraging organic content, Putnam adds.

At press time, Noble had just wrapped the second of two 3-D surveys; a third is planned for the second half of this year.

Initial production may be possible by late 2013, and could reach 50,000 barrels a day by the end of the decade, the company estimates. The leasehold may contain 1.3 billion BOE of gross resource potential, almost entirely oil.

J eff Schwarz, Noble’s Rockies business-unit manager, says, “We’re not planning a horizontal attempt just yet. We’re thinking our pilot stage will be vertical and identify horizontal targets, if they’re there. This is going to be a relatively big interval, initially, to explore, but it could evolve into some horizontal targets in time.”

The company has time—at least in lease terms. One third of the acreage is federal land with 10-year initial terms; the balance, from private landowners, has terms that can be extended to between eight and 10 years. Schwarz says, “The 350,000 net acres we have currently will keep us busy in the foreseeable future.”

Coordination of equipment and crews in the Elko County wilderness will be a bit of a challenge, he adds. “There is nothing out there in terms of oilfield services. It’s a pretty remote area. We’re 250 miles from any active oil and gas province, so we need to make sure we have a long-term drilling plan ready to go when we hit the ground.”

The virginal play is surprisingly in the midst of oil and gas exploration across the Lower 48, where most new exploration is of long-bypassed shales and even of conventional rocks that have produced vertically.

“It is a rare opportunity,” Putnam says of going where no E&P company has gone before. “Others have been here, but they’ve been chasing other things, and that was a long time ago.”

Editor’s Note: Goodrich Petroleum Corp. reported on Feb. 6, 2013, that Crosby 12H-1, which is featured in this article, in Wilkinson County, Mississippi, had current production of 1,250 BOE/d and a 24-hour average rate of 1,130 BOE/d comprised of 1,050 bbl. of oil and 469 Mcf of gas on a 15/64-inch choke with 2,700 psi from some 6,700 feet of usable lateral and 25 frac stages. In the early stage of flowback, the results are impressive while only some 1% of the frac fluid had been recovered to date.