Discoveries

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

During the first quarter of 2008, a group of 32 global oil and gas companies covered by Evaluate Energy Ltd., a U.K. consulting firm, posted a 4% decrease in production of crude and natural gas liquids, and a 5% increase in natural gas production.

According to Eoin Coyne, senior analyst and author of the report, supermajors dragged down oil production totals during the first quarter due to their exposure to expropriations of Venezuelan assets and cuts in entitlements from production-sharing contracts.  Conversely, natural gas production was aided during the same period by several significant field start-ups, including Dolphin in Qatar (which benefited Total and Occidental Petroleum) and Ormen Lange in Norway (Shell, ExxonMobil and StatoilHydro). Additionally, acquisitions boosted gas production rates for XTO Energy, El Paso Corp. and ENI.

The net result was nearly flat production on an oil-equivalent basis. Rising oil and gas prices were directly responsible for a 57% surge in upstream earnings, rather than increases in production levels.

At the same time, capital expenditures by Evaluate Energy’s group shot sharply upward. From $40.4 billion spent on E&P activities in first quarter 2007, the group invested $54.5 billion in first quarter 2008. The jump was largely due to rising costs across the industry.

Evalute Energy’s Oil & Gas Review for Q1 2008 is available to the public. Click here to read a copy of the report.

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

Contact me at pwilliams@hartenergy.com

The Appalachian Basin’s Lower Huron shale has been delivering sturdy gas flows from horizontal wells. Pittsburgh, Pennsylvania-based Equitable Resources Inc. broke the play open when it figured out how to air-drill horizontal laterals in the shale, which is severely underpressured. Multiple frac stages goosed production rates further.

To date, Equitable has drilled more than 200 horizontal tests in Appalachia, mainly in Lower Huron. This year, it will drill 300 horizontal wells. It has a dozen rigs drilling sideways at present, and plans to add four more.

The type Lower Huron horizontal well costs $1.2 million for a 3,500-foot lateral with up to nine frac stages. Recovery is between 750 million and 1.5 billion cubic feet of gas. Flow rates during the first month of production range from 200,000 to 900,000 cubic feet equivalent per day. Horizontal wells in this shale deliver five times the reserves of traditional vertical ones.

What’s really astonishing about the Lower Huron play is that recovery efficiencies are 40% for a single-leg lateral, an exceptional jump from 8% recovery in a typical vertical shale producer. I’m amazed at what today’s horizontal drilling and completion technology can do, and it’s even more intriguing that plays such has the Lower Huron are flowering in such a well explored province.

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

Contact me at pwilliams@hartenergy.com 

Central Utah’s Hingeline is a buzz with activity. Grand Rapids, Michigan-based Wolverine Gas & Oil first stirred up the Beehive State with its discovery of Covenant Field in 2004. That find has already produced 4.5 million barrels of oil from 10 wells, according to IHS Inc.

Recently, Wolverine and its partner Occidental Petroleum are reputed to have made a discovery at their #24-1 Wolverine Federal Arapien Valley, in Section 24-20s-1e, Sanpete County. The partners haven’t issued any press releases about the new field, but word got out in February at the NAPE show in Houston. Now it’s widely discussed and generally acknowledged.

The discovery well for Providence Field is said to be productive from Jurassic Navajo. That’s the same reservoir found at Covenant, which lies nearly 20 miles to the southwest.  Size and shape of Providence are still unknown, but its significance is tremendous. The discovery means that oil was able to migrate from long distances into structures at more than one point along Utah’s Hingeline.  

Additional good news has come from Denver-based Delta Petroleum, which encountered oil in Jurassic Twin Creek at its #23- 44 Parowan Federal, in Section 23-33s-10w, Iron County. That test, which was wet in Navajo, lies some 84 miles southwest of Covenant Field. Delta has to wait until raptor stipulations are lifted in late summer to resume work on the wildcat, but the company thinks it could have something interesting in the Twin Creek interval. 

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

Contact me at pwilliams@hartenergy.com

I’ve been spending some time lately looking at the Horn River Basin, in far northeastern British Columbia. The Horn River lies between the Liard Basin and the Slave Point platform, in the Western Canada Sedimentary Basin.

Shales in the Horn River basin appear to be prime exploration targets. The Muskwa and Horn River formations form a 600-foot-thick package of organic rich, siliceous shales found at reasonable depths of some 6,500 feet. 

This wedge of sediment is thermally mature, loaded with total organic carbon, and contains high percentages of silica.

Additionally, areal extent of the play is vast: researchers have pinpointed an area of 2,404 square miles where all the elements needed for commercial shale-gas production appear to coincide. 

Total gas-in-place estimates in this piece of the Horn River Basin range to as high as 600 trillion cubic feet.

For more on this fast-developing play, check out British Columbia’s oil and gas division website by clicking here.

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

Contact me at pwilliams@hartenergy.com

Last week I attended the AAPG convention in San Antonio. I’ve been a member of the organization for more than 30 years, and this is the first time I’ve ever had to fight for a seat at a technical session. The talks on shales, subsalt provinces and tight sands were absolutely mobbed. Typically, I look over the schedule and hop between sessions to hear selected talks. This year, if I got up and left a session my seat was immediately taken, and then I couldn’t even get into the talk I wanted to hear.

The solution was to arrive early and commit to an entire session. I spent most of my time on shales, as I’m working on several shale articles at the moment. My background is in clastics, so the intricacies of shales are new to me.

Knowledge about shales has exploded during the past five years. Although shales have been long recognized as prolific reservoirs in Appalachia, operators in the Barnett play in North Texas have ushered in a host of fresh ideas and technologies that seem poised to break open a multitude of new shale plays.

In talk after talk, speakers presented papers that underlined the complex nature of shales. These are diverse and complicated rocks, and they hold many secrets. The term “shale:” is loosely applied to rocks that range from true shales, which by definition are fissile, through mudstones, claystones and siltstones. Indeed, it seems that the famous Barnett is not shale at all; rather, it’s siliceous mudstone.

The heterogeneity in shales is astounding. They can be high- or low-pressured, clay-rich or silica-rich, and if the latter, loaded with detrital or biogenic quartz. Shales can be soft and difficult to fracture, or shatter as easily as glass. Reservoir temperatures cross the spectrum from cold to hot; thermal maturities are all over the map. Almost anything goes, and geologists are trying to figure out just what combinations of which characteristics will make a particular shale a promising producer.

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

Contact me at pwilliams@hartenergy.com