Discoveries

A production bubble will expand worldwide LNG supplies in 2009. That’s according to Waterborne Energy, a Houston-based consulting group that specializes in LNG markets.

Waterborne’s president Steve Johnson says he expects that between November 2008 and December 2009, about 2.8 Tcf of new LNG production will be introduced into the market. 

Projects in Qatar, Russia, Nigeria, Indonesia, Yemen and Australia will come online during the period. Several are behind schedule already and are under tremendous pressures to begin production.

By the end of March 2009, new supplies of 117 Bcf per month will be available. This means abundant LNG will begin to significantly impact U.S. markets by next summer. Given the growth in domestic supplies from swelling unconventional natural-gas plays, we could see some gas-on-gas competition.

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

pwilliams@hartenergy.com

Essentially, half of the natural gas produced in the U.S. flows from wells drilled and completed during the past 40 months, said Dr. Phillip Stark, vice president of IHS Inc. That’s eight months shorter than the figures of just two years ago. I attended Stark’s presentation at the 20th Annual Rocky Mountain Natural Gas Strategy conference, a joint effort by the Colorado Oil & Gas Association and Rocky Mountain Section of AAPG. More than 3,000 people thronged the Denver event, a lively and bustling affair.

Stark pointed out that high prices have stimulated a great deal of drilling activity, but the shift to lower-volume unconventional sources means that the U.S. must have increased and robust drilling to continue to grow gas production. Increasingly, the U.S. relies on gas production from new and current drilling: in 1996, less than 9,000 gas wells were drilled in America, and in 2006 more than 30,000 were drilled!

Stark presented an intriguing analysis of gas-play economics. Based on capex, operating costs, royalties and clearing prices, IHS has quantified returns by play.  In 2005, when it started this effort, about 85% of U.S. gas plays generated at least a 10% return on investment on average. By 2007, less than 40% of plays scored in the desirable range. Today’s gas prices are quite strong and most every play makes economic sense, but the IHS analysis highlights the vulnerability of gas profitability to costs, price volatility and basis differentials.

So, while national gas production and reserves are growing, this growth depends on strong prices and very active drilling campaigns.

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

pwilliams@hartenergy.com

The Arkoma Basin Woodford Shale is an incredible play– it covers 1,500 square miles and has more than 40 rigs at work. Active operators include Newfield Exploration, Antero Resources, Continental Resources, Devon Energy, St. Mary Land & Exploration, PetroQuest Energy and XTO Energy.

Simultaneous fracs are being tried in this play. Not only are wells fractured at the same time,  the same segment of each lateral is fractured at the same time. That would be something to see! The volumes of water, sand and people are sensational. The technique appears to make a material difference in production volumes, and well results are strongly improved over conventional fracs.

Average per-well costs in the play have been $5 million and recoverable reserves 3 Bcf, but operators appear to be successfully pushing well costs downward and ultimate recoveries upward.

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

pwilliams@hartenergy.com

Yesterday I attended a Bakken core workshop, held at the U.S. Geological Survey Core Facility in Denver. It was sponsored by the Petroleum Technology Transfer Council, Rocky Mountain Region.

The short course was illuminating. Julie LeFever and Stephen Nordeng, of the North Dakota Geological Survey, shipped core to the U.S.G.S. facility from 14 wells scattered across the Bakken play. What impressed me was the micro-scale of the porosities within the very fine-grained clastics and carbonates of the Middle Bakken. This is some tight rock, and it’s a testament to petroleum engineers that they can design fracture stimulations that achieve the striking flow rates enjoyed from Bakken wells.

A take-away point was the tremendous upside potential of the Three Forks and Sanish intervals, which occur below the Bakken. The Bakken petroleum source system actually extends 150 feet into the Three Forks, through the Bakken and into the base of the Lodgepole formation. Any reservoir rock within this interval will be charged with oil and associated gas, it seems.

Kudos to Julie and Steve for a fascinating day!

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

pwilliams@hartenergy.com

The American Association of Petroleum Geologists president Will Green recently drafted a letter to House Speaker Nancy Pelosi, Majority Leader Steny Hoyer and Minority Leader John Boehner. It was a response to the recent debate about access and leasing activities on federal lands.

The geologists’ organization strove to make several key points. It marked the long lengths of time often required to find oil and gas deposits and bring them to market, as well as the risks of exploration. AAPG pointed out the variability of the distribution of oil and natural gas deposits in the subsurface.

One of the common misunderstandings the industry faces is the perception that it sits upon vast tracts of federal acreage that it does not develop. The professional organization noted that some acreage available for leasing is never leased, because there is no compelling idea of why oil or natural gas should occur there. Other acreage is leased and repeatedly drilled with no success.

Initiatives to increase exploration costs, decrease the available time to properly evaluate leases, and restrict access to federal lands both onshore and offshore “do not provide the American people with short-term relief from high prices and undermine the goal of increasing stable, long-term supplies,” wrote Green.

True indeed.

To read the entire letter, click here

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

pwilliams@hartenergy.com

I just returned from a field trip to the Williston Basin to visit the Bakken play. This is a major resource play in a complex shale reservoir that contains interbedded sands, dolomites and limstones. Operators are using horizontal drilling and multi-stage fracture stimulations to make some exceptional oil wells.

The extent of the Bakken play is phenomenal– we drove many miles across North Dakota’s rolling prairie, from Williston to Watford City down to Killdeer, and then from Williston out to Stanley and down toward New Town. And that was just a slice. 

Big triple rigs punctuate the broad blue-white skies. The play is booming: wells are being drilled and fractured, tanks are being set, gas plants are under construction and pipelines are being laid. Yet, the wide spacing of the big horizontal wells–they stretch up to 9,000 feet laterally at vertical depths of some 10,000 feet–means that the activity is in the background. 

North Dakota remains serene. I’m happy to report that sunrise this morning was truly stunning.

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

pwilliams@hartenergy.com

Brazil is rapidly becoming one of the world’s top petroleum producers. In December 2007, state company Petrobras produced a record of 2.2 million barrels of oil equivalent per day, an outstanding jump from 1 million barrels a day produced less than two years ago. Last year, the company added six platforms capable of making 590,000 barrels a day to its productive capacity.

Brazil proudly points out that it has achieved its record outflow of oil by following a path unlike that taken by other major producing countries. Most nations in the 2-million-barrel-plus range make their oil from massive onshore deposits.

Petrobras has instead explored offshore in deep and ultradeep waters. Indeed, an astonishing 1.75 million barrels of Petrobras’ production came from offshore fields, mainly in the Campos and Espirito Santo basins.

And, its future appears very promising: this year, Petrobras will begin flowing oil and gas from another four projects. Platforms P-51 and P-53 in the Campos Basin will each have production capacities of 180,000 barrels a day, and two FPSOs, in the Campos and Espirito Santo basins, will add 100,000 barrels of oil and 350 million cubic feet of gas per day, respectively.

Farther ahead, Petrobras has already set in motion a program to bring its outstanding Tupi subsalt discovery to market. The company plans a long-duration test by the end of this year that will produce 30,000 to 40,000 barrels of oil per day for a period of six months. It’s the first step in commercializing the multi-billion-barrel deepwater find.

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

pwilliams@hartenergy.com
 

Shale-gas production in the U.S. is ballooning. I was recently doing a back-of-the-envelope calculation, and I think gas production from shales could easily be north of 5 Bcf per day at present.

Here’s my thinking: the Barnett shale currently produces 3.5 Bcf a day, according to the Powell Barnett Shale Newsletter. The Antrim made 136.1 Bcf in 2007, according to the state of Michigan. That comes to 370 million a day. The Fayetteville in the Arkoma Basin made 47 Bcf in the first three months of this year, according to the state of Arkansas. That’s 530 million a day.

I’m less certain about volumes for the Woodford in Oklahoma, but Newfield says it has nearly 200 million per day net, and it’s running 12 of the 46 rigs active in the play. So it’s probably safe to double its number to get current play-wide rates.

When you add in production from Big Sandy in Appalachia, Lewis in the San Juan and New Albany in Indiana and Kentucky, it’s easy to get past 5 Bcf a day. That’s truly amazing, as IHS Inc. reports that U.S. shale-gas production was 2 Bcf a day in 2005.

Now burgeoning plays in Appalachia’s Marcellus and Ark-La-Tex’s Haynesville shales are on the horizon, and development of shales from the Pierre in the Raton Basin, Baxter in the Greater Green River, and Mancos in the Piceance/Uinta are under way. So shale-gas production is only going to rise.

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

Contact me at pwilliams@hartenergy.com 

This year, LNG import levels in the U.S. are plummeting to levels not seen since 2003. It’s a sea change from 2007, when imports of liquefied gas reached record levels. The drop hammers home the U.S. market’s role as the port of last resort for worldwide LNG, according to Steve Johnson, president of Waterborne Energy Inc., a Houston-based consulting firm that specializes in LNG matters.

A large bump in worldwide supply was supposed to hit the market in 2008, but supply projects throughout the world experienced delays. At the same time, worldwide demand has soared from a variety of factors, including a drought in Spain and a huge nuclear-plant outage in Japan. “A lot of factors combined to line up to create these record shortages in the U.S.,” he says. 

This situation is likely to be short-term, however. “I’m a believer that the market could drastically swing, and this time next year we could have a record import year,” he says. On the horizon, megatrains and projects in Qatar, Nigeria, Indonesia and Australia are scheduled to add a whopping 35- to 38 Bcf per month to the world market by first quarter 2009.

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

Contact me at pwilliams@hartenergy.com

Calgary-based explorer Talisman Energy Inc. is embarking on a major shift in strategy. At a recent investor day, the company said that it planned to spend up to C$420 million on pilots in five unconventional plays, four in Canada and one in the U.S.

It is focused on multi-zone Outer Foothills reservoirs in Alberta and British Columbia, Montney gas in B.C., Bakken light oil in southern Saskatchewan, Utica/Lorraince shales in Quebec and Marcellus shale in New York.

The latter play was of particular interest to me. Talisman is the #1 producer of gas in New York State, and has been successful in the Trenton-Black River hydrothermal dolomite play around the Finger Lakes region. Now much of that same acreage is prospective for Marcellus. The company has 800,000 gross (640,000 net) acres of lands in New York and northern Pennsylvania.

Since 2006, the company has drilled 13 vertical Marcellus wells. Results have been encouraging: its most recent vertical well tested at an average rate of 800,000 cubic feet per day. Talisman thinks that it will likely develop the Marcellus with horizontal wells, however. 

A significant horizontal Marcellus test will be completed in the second quarter, and Talisman’s first operated horizontal well will be completed in the third quarter. It expects to have drilled four vertical and 20 horizontal wells in five pilot areas in New York by year-end 2009. 

The company reported original gas in place values of 20 to 100 billion cubic feet per section. It is assuming well costs of $4.3 million and estimated ultimate recoveries of 2 to 3 Bcfe per well.

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

Contact me at pwilliams@hartenergy.com