Discoveries

Shale-gas production now accounts for approximately 7% of annual domestic production, noted John Curtis, professor at Colorado School of Mines, in a presentation I attended at the recent AAPG Annual Convention in Denver.

The U.S. Energy Information Administration estimates that shale-gas production will overtake coalbed-methane production by 2025, and will grow from current volumes of more than 1 Tcf to 2.3 Tcf annually by 2030. A good part of today’s shale-gas production flows from the Barnett play in North Texas. Indeed, U.S. gas production as a whole grew by 9% from the first quarter of 2007 to the first quarter of 2008, in large part thanks to the Barnett.

Going forward, various forecasts call for shale-gas supply to grow to 10% or more of daily U.S. production. Some experts have even pegged eventual shale-gas contributions at levels as high as 50%. There are many constraints, naturally, including environmental and regulatory issues and pipeline capacities. But one area that does not appear to offer limits is the sheer size of the technically recoverable resource.

The industry’s understanding of the shale-gas resource base has grown tremendously in the past few years, noted Curtis. From older plays such as the Ohio shale in Appalachia to the Antrim in Michigan, the shale-gas universe has grown to encompass such powerhouses as the Barnett and Fayetteville and Woodford shales in the Midcontinent. Now, the Haynesville, in East Texas and North Louisiana, and the burgeoning Marcellus, in New York, Pennsylvania and West Virginia, are delivering on their great promise. And, plays like the Eagle Ford in South Texas continue to emerge.

“The good news is that the technically recoverable resource base is sufficient to support increases from the 10% level on up,” he said.  

Truly, that is good news! Curtis is Director of the Potential Gas Agency; the Potential Gas Committee’s 2009 report details the striking growth in U.S. gas potential.  To learn more, click here.

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

 pwilliams@hartenergy.com

In a conference call devoted to its activities in the Haynesville shale and Deep Bossier plays in Louisiana and East Texas, Calgary-based EnCana Corp. also dropped a few nuggets about its thoughts on the Middle Bossier shale.

The company noted that the Middle Bossier shale, which lies just above the Haynesville, achieves a thickness of about 180 feet across much of its Louisiana acreage position. Gas-in-place numbers are similar to the Haynesville.

EnCana said that production rates from vertical wells in the Middle Bossier shale are very good, and that it has a horizontal well that is producing 3- to 4 million cubic feet per day from a lateral stimulated with eight stages. It expects the well’s performance will compare favorably with its Haynesville completions.

This year, the company will drill a number of tests across its acreage position to probe the Middle Bossier shale. In EnCana’s view, this shale has the potential to parallel and be as significant as its Haynesville position.

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

Contact me at pwilliams@hartenergy.com

Hart recently held a Marcellus shale webinar, featuring three speakers. I thought the entire broadcast was intriguing, but I wanted to share one nugget in particular.

Randy Wright, president of Wright and Co., offered vertical and horizontal well models, with rates of return plotted against Nymex base prices.

Wright modeled a vertical Marcellus well using assumptions of 100% working interest and 85% net revenue interest; $1.5 million D&C costs; $1,250 per month LOE; and $7 a barrel for water hauling and disposal. No lease costs were added, and the prices were not adjusted upward for Btu or basis premiums. Additionally, a 5% severance tax that is being considered in Pennsylvania was not added. He ran four EUR dry-gas base cases: 300 million, 600 million, 900 million and 1.2 Bcf.

 The horizontal well model employed similar assumptions, but used $4 million D&C costs and $2,000 per month LOE. Its EUR base cases were 2 Bcf, 3 Bcf, 4 Bcf and 5 Bcf.

Results showed that at a Nymex base price of $5 per thousand, a vertical well needed to recover at least 900 million cubic feet of gas to hit a 10% ROR. That’s a pretty hefty vertical well. Horizontal wells, with their greater reservoir contact, fared much better. At $5 gas, a 2-Bcf Marcellus producer can deliver a ROR just below 10%, a 3-Bcf well hits a bit below 20%, a 4-Bcf well reaches 40%, and a 5-Bcf well, 60%.

Wright noted that these well models were not intended to represent typical Marcellus wells, or wells in any specific area. Rather, they illustrated sensitivities to EURs and base Nymex prices. To me, they showed why the horizontal Marcellus continues to attract investment even as other U.S. plays are withering.  

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

Contact me at pwilliams@hartenergy.com

Natural gas prices are terrible, due to waxing supply and waning demand. The U.S. Energy Information Administration just released its first energy consumption estimates from a 2006 survey of manufacturers, and since factories and electric power plants consume nearly 60% of the nation’s gas, I was curious to see which manufacturers relied most heavily on the vaporous fuel.

U.S. manufacturing firms burned 14,428 trillion Btus of fuel in 2006, and natural gas was the largest single fuel source. It accounted for 32.8% of total energy consumed, followed distantly by electricity, at 19.6% of consumption.  Other sources of manufacturing fuel included residual fuel oil, distillate fuel oil, LPG and NGL, coal and coke.

So, as U.S. manufacturing goes, so goes natural gas demand. The sectors that used the most gas were chemicals and petroleum and coal products. Together, these sectors accounted for 43.8% of all gas used in U.S. manufacturing.  Food manufacturers consumed 13.2% of the sector’s gas.  The three categories of primary metals, fabricated metals and nonmetallic mineral products combined for 20.9% of gas use, and wood, paper and printing products took 10.1%.

This back-of-the-envelope calculation leads me to believe that we must await a broad-based recovery to restore natural-gas demand.  It is a fundamental fuel source for our factories, and these factories produce the basic building blocks of our modern lives.

Click on this link to review the EIA table!

EIA Manufacturing Energy Consumption Survey

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

Contact me at pwilliams@hartenergy.com

Some folks call British Columbia’s Triassic-age Montney a tight silt. Certainly, in look and appearance it’s a very fine-grained, shaley rock. Others call it a shale.

Like many circumstances in life, it’s relative. In the Montney’s case, rock type depends how close acreage might be to the clastic source. Most workers interpret the Montney as a turbidite reservoir, deposited far offshore. Its shaley layers are interlaminated with silts.

Generally, reservoir quality improves with silt content. Higher permeabilities and better production correlate with higher silt content.

The Montney has a number of positives: it’s found at moderate depths of around 8,000 feet; it’s very thick, with excellent gas-in-place values; and it occurs in an area with existing infrastructure and lots of prior drilling activity. And, the wells are remarkably consistent and the play covers a vast area.

According to the Canadian Society for Unconventional Gas, current production from the Montney is 200 million cu. ft. per day. Most new wells are horizontal with IP rates averaging 4- to 5 million a day. Due to the area’s established infrastructure and declining drilling costs, the play is economic at fairly low gas prices.

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

Contact me at pwilliams@hartenergy.com

Mike Walen, senior vice president and chief operating officer of Cabot Oil & Gas Corp., talked about the company’s Marcellus drilling program at Hart’s DUG conference in Fort Worth last week.

The conference was Cabot’s coming-out party in the Marcellus, the first time it has revealed details of its work in the Appalachian Devonian shale.  Cabot works in Susquehanna County, Pennsylvania. It picked that area because the Marcellus is tremendously thick, reaching more than 300 feet.  “We made a decision to concentrate our entire leasing program in just a few counties in northeast Pennsylvania,” said Walen.

The company leased its first 20,000 acres in the play in 2006; today it has more than 160,000 net acres. It figures 18 to 27 Tcf of in-place gas resides in the Marcellus beneath its leases, and between 4 and 6 Tcf are recoverable.

Cabot initially drilled vertical wells and took core.  “The rocks are exceptionally good source rocks,” he said.  Its vertical wells posted rates into the sales line ranging from 600,000 to 1.7 million cubic feet per day.

In 2008, Cabot drilled 15 vertical and five horizontal Marcellus wells. Its 30-day average for the verticals was more than 1 million cubic feet per day, and EURs were 1.4 Bcf per well.

“What got our attention were the IPs of the five horizontals that we drilled,” said Walen. Cabot’s horizontal tests flowed into sales at rates between 6.4- and 8.8 million cubic feet per day. “These wells are 4.5 Bcf or better,” said Walen. “And recent results have confirmed that these are repeatable.”

This year, Cabot plans to drill 30 horizontal and 30 vertical wells. Costs are $3.4- to $4 million completed for a horizontal well. It operates six rigs, split between horizontal and vertical drilling. The verticals are useful for land issues, and also as go-by wells for offset horizontals, but horizontals are the moneymakers.  

“This is probably the best play Cabot has in the States,” said Walen. “It’s truly world-class.”

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

Contact me at pwilliams@hartenergy.com

One bright spot in recent months has been Devon Energy Corp.’s discussion of the emerging Cana Woodford shale play in western Oklahoma. During a February conference call, the company reported that it had leased some 112,000 net acres in Canadian, Blaine and Caddo counties, and completed 10 operated wells, including seven long-lateral horizontals.

Devon calls its play Cana, after Oklahoma’s Canadian County. Here, the Woodford is considerably deeper than in Eastern Oklahoma’s Arkoma Basin play. The Anadarko’s variant of the Woodford occurs at depths from 11,500 to 14,500 feet, and is highly pressured. Initial gas-in-place estimates for the Cana shale are upward of 200 Bcf per square mile, and Devon said it expects recovery factors similar to those found in the best shale plays in the country.

Devon figures its existing acreage holds net risk potential of 4 Tcfe. The gas is rich in liquids, and will require processing. This year, the company plans to run four rigs and drill 27 operated horizontal Cana wells. The wells are expected to cost around $9 million each, and yield estimated ultimate recoveries of up to 8 Bcfe.

Other operators active in the Cana play include Cimarex Energy, Questar and Marathon Oil.

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

Contact me at pwilliams@hartenergy.com

There’s a lot of talk within the natural-gas producing industry about stimulating demand for its product, and high-profile personalities such as T. Boone Pickens have been stumping the concept of 18-wheelers fueled with natural gas. 

The potential for the use of liquefied and compressed gas as transportation fuel is undeniably huge: the U.S. is home to some 251 million registered motor vehicles. Less than 120,000 of these are natural gas-powered vehicles (NGVs).

Interest is growing in NGVs, and one excellent use is in medium- and heavy-duty trucks that make multiple stops each day and return to the same location each night. For example, some 180,000 trash trucks presently comb U.S. streets to haul garbage, and about 1,500 factory-built  natural gas-powered trash trucks are being added to the nation’s fleet annually. Courier services, bread and snack food bakeries, laundry services and other “local route” businesses are placing orders for factory-built, CNG-powered step vans and, very soon, businesses will be able to factory order natural gas-powered conventional box-trucks.

“If we keep multiplying our market exposure, we could have a significant impact on oil and gas use,” says Stephe Yborra, director of marketing and communications for NGVAmerica, the Washington, D.C.-based natural-gas vehicle trade association.

“Right now, less than one-half of 1% of all U.S. natural gas used goes into vehicles. If we were just to ramp up to a total of 1 million vehicles, which we could easily do, we can hit the tipping point where manufacturers begin to invest in new production lines, and within five to 10 years we could be using 3% of U.S. annual gas supply.”

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

Contact me at pwilliams@hartenergy.com

Tom Petrie, vice chairman, Merrill Lynch & Co., spoke at the Oil & Services Conference VII last week. I just listened to the webcast of his talk, and Petrie made some of his usual shrewd observations about the state of oil and gas industry.

Today’s low commodity prices are a symptom of both self-reinforcing pessimism and the reality that long-term demand elasticity has been triggered, he said.

Specifically on natural gas markets, Petrie said that a perfect storm hit the business between mid-2005 and about a year ago. During that time, an earthquake in Japan disrupted two nuclear plants, new LNG capacity was seriously delayed, and the start-up of the Snovit project offshore Norway was troubled. All contributed to an extremely tight global gas market.

This year, world LNG supplies are projected to grow 30%, followed by another 18% in 2010. LNG will likely saturate Asian markets by this summer, then move into the U.S. Clearly, for the second and third quarters of 2010, a portion of that LNG will land in America.

At the same time, the U.S. domestic gas picture is changing. The construction of the Rockies Express pipeline is creating pressure in Midcontinent markets, and gas is pouring from such onshore shale plays as the Barnett, Fayetteville and Haynesville. Petrie expects the industry will see rotating basis blowouts in regions that have never experienced that particular twist before.

So, natural gas prices will be stressed for some time. “We’re now in a period of meaningful and potentially prolonged oil- and gas-price retrenchment,” said Petrie. A recovery is more likely in 2010 than this year, he concluded. 

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

Contact me at pwilliams@hartenergy.com

Today I listened to a teleconference on the National Clean Energy Project. On the call were T. Boone Pickens; Harry Reid, Senate majority leader; Ken Salazar, Secretary of the Interior; Steven Chu, Secretary of Energy; and John Podesta, president of Center for American Progress Action Funds.

 The dignitaries talked about several aspects of the Obama administration’s energy plan. I was most interested in the part that concerned natural gas, which is being cast as the bridge to the future.

By switching large trucks from diesel to natural gas, then moving to fleets, America’s oil imports could be cut 30% to 50% within 10 years, said Pickens.

The U.S. is absolutely overwhelmed with natural gas, thanks to the rapid development of shale-gas plays during the past decade. “We import 70% of the oil we use, but 98% of our natural gas comes from North America,” he said.  “We’re crazy if we don’t move in and take this wonderful opportunity for the country to use the natural gas for transportation fuel.” 

His plan calls for switching 380,000 of the 6.5 million 18-wheelers in the U.S. from diesel to natural gas. The cost of a natural-gas engine is $75,000 to $85,000 more than that of a diesel engine, so initially truckers will need incentives to make the change. The advantages are clear, however: the fuel is cheaper and cleaner than diesel, and it’s all domestic. Once the model is established, it can be scaled up and incentives won’t be needed, said Pickens.

“The only way that we can solve the problem of imported oil is that we have to use a resource in America.”

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

Contact me at pwilliams@hartenergy.com