Discoveries

Five main challenges stand in the way of shale-gas development in Europe, said Alastair Nichol, executive advisor, Encana Corp., speaking to a crowd of 150 attendees at the Global Unconventional Gas 2010 conference in Amsterdam, organized by the Gas Technology Institute.

These challenges are surmountable, he noted:

1.  A lack of drilling rigs necessary for horizontal wells, and limited service company infrastructure. Although these factors are seen by many as constraints on European shale development, they can be addressed through alliances with U.S. service companies and E&P firms.
2. Restricted surface access. Europe’s population density is much higher than North America’s, but techniques such as pad drilling can help minimize footprints.
3. High water usage of shale completions. The development of nonpotable water supplies will be a strategy to overcome this objection to shale drilling, said Nichol. He pointed to Encana’s efforts to find a nonpotable water supply in the Debolt formation in Canada’s remote and fragile Horn River Basin as an example that could be applied to European developments.
4. Lack of pipeline capacity. In Europe, the bundling of transmission and utility functions has removed some competitiveness from the midstream sector. However, pipelines can be built if needed.
5. Finally, the regulatory environment in Europe is considered more stringent than in North America. This will be addressed if Europe’s citizens decide that they need and want shale-gas development within their borders, he noted.

“I believe all the challenges are solvable,” said Nichol.

 by Peggy Williams, Director, Unconventional Resources

 Contact me at pwilliams@hartenergy.com

A new shale play is delighting Michigan explorers, and it’s being developed by a Canadian firm. Encana Corp., based in Calgary, recently unveiled a Collingwood and Utica shale play in the heart of the venerable Michigan Basin. 

The company revealed that it had accumulated 250,000 net acres of leases. Its first well, drilled by subsidiary Petoskey Exploration LLC, in Missaukee County, produced at an average rate of 2.5 million cubic feet equivalent per day during its first 30 days on production. The well, drilled close to the depocenter of the basin, produced primarily from the Collingwood and had some contribution from the Utica. 

A report by Ross Smith Energy Group notes the Middle Ordovician Collingwood is sandwiched between the Trenton Black River limestone (below) and the Utica shale (above) in the northern third of Michigan. Potentially, the play could stretch across an attractive swath of Michigan’s Lower Peninsula; Encana’s leasehold spans seven counties.

In southern Ontario the Collingwood has been recognized as an oil shale reservoir since Colonel Drake drilled his Titusville well. According to a 1983 paper by J.F. Barker et al, shale oil was produced in Ontario from a plant near Collingwood on Lake Huron, where the shale outcrops. From 1859 to 1863, oil was retorted from the shale to produce fuel and lubricants. Ironically, it was the discovery of conventional oil in Ontario that rendered the retorting business uneconomic.

Barker and his colleagues reported that the Collingwood often included intervals of two to five meters with more than 3% TOC, and posited it had major economic potential for oil shale. Now it appears that Encana holds that same opinion of the shale, at least where it is gas- and condensate-prone in the depths of the Michigan Basin.  

by Peggy Williams, Senior Exploration Editor

Contact me at pwilliams@hartenergy.com

The Barnett Combo play in Montague and Cooke counties, Texas, is firmly economic. That was the takeaway from EOG Resources’ recent analyst day presentation. The Houston-based independent revealed telling details about the play, in which it is by far the largest operator and driving force.

According to EOG, the Barnett Combo play works for several reasons. First, the resource base is enormous–in fact, it ranks as one of the largest in the world. Oil in place ranges from 40- to 200 million barrels equivalent per square mile. Many old vertical wells, with long production histories, were drilled in the area, and these gave solid indications of the potential of the play. Rock work–cores and logs–showed that pore throats are large enough to produce oil.

At present, EOG is running nine rigs in the play, and it plans to grow that  to 14 rigs by year-end. It has scheduled 234 net wells in the Combo area in 2010, split almost equally between verticals and horizontals. That will rise to 300 wells in 2011 and 2012.

EOG’s average costs are $2 million for a vertical well and $3.4 million for a horizontal well. Verticals are employed in Cooke County, in a narrow area rife with thrust faults and fractures.  EOG’s recoveries are currently 167,000 Boe gross in reserves for a vertical completion. Horizontal wells in the Montague County core area are expected to recover 337,000 Boe gross.

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

pwilliams@hartenergy.com

Shale plays are reshaping the nation’s gas supply, and their influence is extending to all aspects of the industry. The transaction market has also been profoundly influenced by the shale plays, said Ward Polzin, managing director, Tudor, Pickering, Holt & Co., at DUG 2010.

In 2007, shale deals began to impact the market, and by 2009 shale deals accounted for more volume than non-shale deals.  “We now have a shale market that is equal to or greater than the rest of the market,” Polzin said.

Today, 55% to 60% of the deal volumes have a shale orientation, and half the number of deals done are shale.  The discrepancy between volume and numbers comes because shale deals are generally larger, he noted. Furthermore, the new tranche of shale deals are coming from every shale basin. “There’s not one shale dominating the volume: there’s a buyer in every one of those positions.”  

The rise of the shale joint venture is another notable development. Some $15 billion worth of shale joint ventures have been consummated during the past few years, and this trend is increasing. “We are seeing two to three significant-sized JVs being announced every quarter,” said Polzin. The JVs fit well in today’s market: buyers like the repeatability and scale of the shale JVs, and sellers like the ability JVs give to hold on to large land positions and accelerate value.

Even in a tough environment, the shale plays stand out. Private equity, foreign buyers and public companies are all quite active in shales—today, shales are the place to be.

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

pwilliams@hartenergy.com

Thanks largely to the use of 3-D seismic in prospecting for small structural closures, oil production has been rising in Kansas. In 2007, the state produced 36.59 million barrels of crude and in 2008 it made 39.58 million barrels. From January through October 2009, 32.76 million barrels had already been produced.

The new flows of crude are coming mainly from counties in western Kansas and on the Central Kansas Uplift. In these regions of the Sunflower State, prospectors can image closures as subtle as 10 to 15 feet on 3-D, and that’s enough to make an oil well. Economics are strong, as the wells are shallow and inexpensive to drill and complete.

For more on Kansas, look for the article “Little Kansas Bumps” in the upcoming April 2010 issue of Oil and Gas Investor.

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

pwilliams@hartenergy.com

2010 is the year of the unconventional play, at least that’s the impression I took away from NAPE. Eagle Ford gas/condensate plays in South Texas were top attractions, as were a wealth of new Niobrara opportunities across the Rockies, at the winter NAPE Expo 2010 in Houston last week. 

Marcellus deals in the Appalachian Basin were also abundant. One exhibitor told me that last year his Marcellus-focused booth was standing room only, but this year’s traffic was slower yet steady and viewers were more serious about buying.

Many firms had expiring acreage, acquired not so long ago in the heady days of high commodity prices. Pitches to shoppers to take a quarter or a third of a deal were common, with a number of prospects partially placed but still needing one last partner to step up.

Overall, the mood was positive. Prospect generators have responded to the current disparity in value between oil and natural gas by focusing heavily on oil ideas and gas prospects with high condensate yields.  Potential buyers seemed pleased with the quality of deals, and while booths were not festooned with as many ‘SOLD’ signs as in past NAPEs, most exhibitors I spoke to said they were seeing good interest and booking more detailed showings in the weeks to come.

And, of course, NAPE is always a great time to network and say hi to old friends.  

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

pwilliams@hartenergy.com

A new assessment by the U.S. Geological Survey says that Venezuela’s Orinoco Belt holds more than a trillion barrels of heavy oil in place, and more than half of that is likely recoverable with present-day technology.

Specifically, the U.S.G.S. found that between 380 billion and 652 billion barrels of heavy Orinoco oil can be recovered, and the mean volume is 513 billion barrels. It’s important to note that technically recoverable is not the same as economically recoverable; the assessment does not factor in costs of recovery, rates of heavy oil production or a time frame for recovery.

Nonetheless, the new mean value is nearly double what the industry has long accepted. Since the mid-1980s, in-place resources were estimated at 1.2 trillion barrels, and the Orinoco’s recoverable crude was set at around 270 billion barrels, based on a recovery factor of 22%.  

Now, assuming the use of widespread horizontal drilling and thermal recovery methods such as steam-assisted gravity drainage, the U.S.G.S. thinks the median recovery factor for the Orinoco resources is 45%.  Additionally, the overall in-place volume has been tweaked upward to 1.3 trillion barrels.

The Orinoco Belt stretches across 19,000 square miles of the East Venezuela Basin. The heavy, 4- to 16-degrees API oil is trapped in sandstone reservoirs at depths from 500 to 4,600 feet. Unlike the bitumen in Canada’s oil sands, Orinoco oil is movable at reservoir conditions because subsurface temperatures are high. It appears that the application of SAG-D and other recovery processes can increase that mobility substantially.

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

pwilliams@hartenergy.com

North American unconventional-oil plays have gained increased attention as results improve. One of the plays explorers are closely monitoring is the Cretaceous Niobrara shale in the Rocky Mountain region.

People have long known that the Niobrara is thick, rich in organics and thermally mature. Oil has flowed from the Niobrara since the dawn of the industry: Florence Field, near Canon City, Colorado, was discovered in 1876 near an oil seep. Florence produces from fractured Pierre shale, part of the Niobrara formation. Oil pioneers also found the Niobrara productive at Salt Creek, Teapot Dome, Tow Creek and Rangely fields.

Today companies are chasing the Niobrara with new fervor. Lots of buzz is surrounding EOG Resources’ Jake well, a horizontal Niobrara discovery in Colorado’s Weld County, in the northern Denver-Julesburg Basin.  According to state records, the well, in Section 1-11n-63w, flowed an average 1,750 bbl. of oil and 360,000 cu. ft. of gas per day for its first eight days on production in October 2009. The next month, it made an average of 680 bbl. per day for 30 days.

In addition to the D-J Basin, active exploration is ongoing in the southern Powder River Basin in Wyoming, and in Colorado’s North Park, Sand Wash, Piceance and Raton basins.

There are plenty of places to prospect for Niobrara, as the shale occurs across a vast, tectonically active area. It can be anywhere from 150 to 1,500 feet thick, and its TOC ranges up to around 5%. It contains Type II kerogen. Additionally, the Niobrara contains a high proportion of carbonates, including brittle, calcareous chalk benches. These appear to enhance its porosity and its ability to be fractured, by both natural and mechanical processes. And the tremendous tectonic legacy of the central Rockies region means that natural fracturing can be extensive.

Finally, the thermal maturity of the Niobrara varies, so it can yield either oil or gas or both, depending on local conditions.  The shallow, biogenic Niobrara gas play in the eastern Colorado and western Kansas portion of the D-J illustrates how rapidly reservoir conditions can change within this enigmatic and fascinating formation.

We’re sure to hear much more about the Niobrara in months to come, as results are posted from a number of significant tests across several play types and basins.

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

pwilliams@hartenergy.com

McMoRan Exploration Co.’s ultra-deep Davy Jones prospect in the shallow waters of the Gulf of Mexico has hit Eocene Wilcox sands that appear productive on logs. In fact, they appear highly productive.

The test is a rank wildcat. It has already reached a depth of 28,263 feet, and McMoRan plans to take it down to 29,000 feet. Davy Jones is the first well to find productive Wilcox on the shelf—it’s 100-plus miles south of any control in the deep Wilcox, and 125 miles north of the deepwater Lower Tertiary play, which is also productive from Wilcox.

This discovery is momentous, and could be the first of a prolific new trend.  “The whole landscape of the subsurface geology of the shelf is being reshaped,” said Jim Bob Moffett, co-chairman of the board, in a conference call.

Davy Jones encountered 135 net feet of pay in four Wilcox zones. One zone is 50 feet thick, and another 40 feet, and they are full to base. The logs were dearly bought: it took McMoRan six tries to finally get the logs it needed.

The Davy Jones prospect covers 20,000 acres and four offshore blocks. The surface location is on South Marsh Island Block 230. Potentially, it could be one of the largest discoveries in decades on the Gulf of Mexico shelf.

Congratulations to McMoRan! This company has believed in the deep shelf and now has proof of concept. 

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

pwilliams@hartenergy.com

Flows of natural gas are increasing all around the world, from an amazing variety of sources. We’re seeing new gas supplies come onstream from Russian and Norwegian fields above the Arctic Circle, from tight sands in Europe, from shales in the U.S. and from CBM in Australia, Indonesia, Botswana and China. Additionally, new large deepwater, pre-salt discoveries such as Jupiter in Brazil and Tamar in Israel have been made in the last couple of years.

We are also seeing an explosion of new technology–especially in LNG technology–to bring gas to international markets. Developments range from a new gravity-based LNG regasification terminal off Italy to ExxonMobil’s Qatar project, which features the four largest LNG trains in the world and newly designed LNG ships that can handle significantly larger cargoes.

And, we are on the cusp of breakthroughs in sour-gas processing, such as ExxonMobil’s CFZ process. Controlled Freeze Zone is a single-step cryogenic separation process that freezes out and then melts carbon dioxide and removes H2S. Exxon is testing this process at its Shute Creek Treating Facility in LaBarge, Wyoming. The plant, which is expected to start up shortly, will process 14 million cubic feet a day over a two-year period. ExxonMobil says it intends to advance CFZ to the commercial-application stage.  According to the company:

CFZ lowers the cost of carbon capture and storage because the process separates CO2, and other contaminants, as a high-pressure liquid stream that can be reinjected underground. Conventional processes require expensive recompression of the CO2 for reinjection. The CFZ technology has additional benefits: there’s no need to use chemical agents in the process, and it also eliminates sulfur production from hydrogen sulfide often found in gas streams.

Potentially, this technology could unlock access to huge, previous noncommerical deposits of natural gas throughout the world, adding to the robust growth in conventional and unconventional supplies that is now occuring. 

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

pwilliams@hartenergy.com