Discoveries

This morning’s Denver Post carried an article about drilling slow-downs in western Colorado. The Centennial State had been enjoying record levels of drilling, thanks mainly to massive programs in tight-gas sands in the Piceance Basin.

The paper reported that Chevron Corp. has decided not to increase investment in the basin. Previously, it had planned to double its drilling program; now it will stay at two rigs, and forego the ramp-up to six rigs it had scheduled for 2009.  Williams Production, another active Piceance player, will drop six rigs from its fleet in 2009, moving down to 20 from 26 rigs. Likewise, Berry Petroleum will lay down three rigs, and keep one active in the area in 2009.

Drilling could be off 35% to 40% in western Colorado over the next few months. Naturally, low commodity prices are the primary reason for the dampened forecast. Nymex prices are low, and the basis differential has ballooned again for Rockies producers. The credit crunch and new, more restrictive regulations expected to be imposed on drilling operations by the state government are contributing factors.

The rigs are already disappearing. In September, 93 rigs were turning to the right in the Piceance; in early November that count had declined by 10.

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

Contact me at pwilliams@hartenergy.com

In an area along the Saskatchewan-Manitoba border, Maple Leaf operators are busily developing the Upper Devonian Torquay, a formation that underlies the Bakken. The Torquay is composed of dolomitic mudstones and siltstones. It’s a weathered, brecciated formation with good reservoir characteristics. In places where the Lower Bakken shale is absent and the Torquay onlaps the Middle Bakken, the Torquay has been charged with Bakken oil.

Initially, operators drilled vertical wells into the formation. The focus has recently shifted to horizontal drilling.

Fairborne Energy Ltd., an active participant, reported that it is currently interpreting data from a 42-square-mile 3-D survey that it shot in the Sinclair area.  It recently drilled 10  horizontal wells that have average per-well production of approximately 65 barrels of oil equivalent per day.

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

pwilliams@hartenergy.com           

According to a talk given by John Harper, chief, oil, gas and subsurface services at the Pennsylvania Geological Survey, some 792 wells suspected to target Marcellus shale have been permitted in the Keystone state. Of those, 571 were vertical and 221 were horizontal locations.

Prior to 2003, only a handful of wells produced from the formation outside of Erie County, along the shores of Lake Erie in far northwestern Pennsylvania. The current flurry of Marcellus-directed drilling surged in 2007, when 307 such wells were permitted, versus 54 in 2006. As of Fall 2008, 402 permits were issued by the state for wells believed to target Marcellus.

Many operators are active in the Marcellus play across Pennsylvania: EOG Resources has locations in Bradford and Elk counties; Rex Energy in Butler County; Atlas Resources in Fayette, Greene, Washington and Westmoreland counties; CNX Gas Co. in Greene County; Turm Oil in Susquehanna County and Range Resources in Washington County, among others, reports IHS Inc.

Harper gave his talk at the AAPG-SPE Eastern Meeting, held in Pittsburgh in mid-October.  

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

pwilliams@hartenergy.com           

Some 1,300 people attended a fabulous meeting in Pittsburgh last week. The AAPG-SPE Eastern Meeting, held October 11-15, focused on shales, CO2 sequestration, tight sands and hydrothermal dolomites.

I spent my time in the shale sessions. On Monday, such sessions were so popular that people lined the walls and sat in the aisles, and some couldn’t even get into the room (which had capacity of around 400) at all. Tuesday’s shale talks were moved to a room twice the size, and were nearly full. 

Here’s my Top 5 list of things I learned about the Marcellus, in no particular order:

1.      The Marcellus is an extremely high-quality source rock. Two areas that have generated great volumes of hydrocarbons are southwestern Pennsylvania and southern New York/eastern Pennsylvania.

2.      The organic-rich facies achieves thickness of 250 feet in southern New York/eastern Pennsylvania.

3.      Three units make up the Marcellus: Oatka Creek Shale, Cherry Valley Limestone (which has different names in various areas), and Union Springs Shale. These have different organic contents, and thicken and thin independently due to non-deposition or erosion.

4.      Typical Marcellus fracs employ 300,000 to 500,000 pounds of proppant and 750,000 gallons of water.  In horizontal wells, guar and cross-linked gels are added on a limited basis.

5.      Marcellus pressure gradients vary from .40 to .58 psi. The core area of the play sprawls across some 18 million acres.

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

pwilliams@hartenergy.com           

The news is bad, and then it gets worse. Oil and natural gas commodity prices are in freefall. Energy stocks have given back all their tremendous gains of the past year and more.

Companies with loans due are scrambling to refinance or extend deadlines. Operators are choking back capital expenditures to preserve liquidity.  Deals are being cancelled. Credit lines are being tapped while they are still available, and the cash held tightly.  

Defense is the game.  The industry is digging trenches and laying in rations. We’ve been through this before, but the speed and severity of this crash is stunning. And this time,  it’s not just the oil and gas industry that’s affected. The collapse is broad and deep.

We’re bracing for more shocks. Keep your head down and your helmet on.

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

pwilliams@hartenergy.com

The New Albany shale in the Illinois Basin just gained a new producing field. NGAS Resources announced that it is producing gas from its Haley’s Mills Field in Christian County, Kentucky. The company has completed 10 miles of field gathering, pipeline and gas-processing facilities and now is flowing gas into the Texas Gas interstate pipeline.

NGAS has drilled 37 wells in the field to date, and 26 are producing. It has been developing the project with vertical wells, but recently drilled its first horizontal in the field. That well is completed and will be hooked up to sales within a month.

The Lexington-based operator has interests in 26,000 gross acres at Haley’s Mill, where the New Albany is about 180 feet thick and occurs at depths of 2,500 feet. Vertical per-well costs are $150,000 to $175,000 and expected recoveries are 135- to 200 million cubic feet.

NGAS currently has two rigs working at Haley’s Mill.

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

Contact me at pwilliams@hartenergy.com

Oklahoma City-based Devon Energy Corp. has started clearing the site for its Jackfish 2 in-situ oilsands project in northern Alberta. The company’s original Jackfish project lies about 10 kilometers east of the new venture. The companion sites, owned 100% by Devon, are near Conklin, south of Fort McMurray.

Devon employs steam-assisted gravity drainage (SAGD) technology at Jackfish, and will use the same method at Jackfish 2. The projects will each be capable of producing at peak rates of 35,000 barrels of bitumen a day, and will each recover about 300 million barrels. The company is developing its site with seven well pairs on a pad; wells are drilled vertically to depths of around 450 meters, then horizontally 800 to 900 meters. Each well pair is expected to make 1,000 barrels of bitumen a day.

Jackfish has a couple of unique features. It is the first oilsands project to use saline water for its steam generation. The company processes some 100,000 barrels of water per day, and recycles 95% of that. Additionally, Devon designed the project with the capability to blend diluent or synthetic crude with its bitumen; at present it uses diluent. The mixture is sent to market via the Access pipeline, owned 50% by Devon.

Steam injection started at Jackfish in August 2007, and current production averages 14,000 barrels of bitumen a day. Construction cost was C$730 million. Costs for Jackfish 2 are estimated at C$1 billion, due to inflation in labor and materials.

Currently, Canadian oilsands projects make 1 million barrels of bitumen per day. There are 87 active projects; three are operating mines, two are proposed mines and the rest are in-situ. Total oilsands production is forecast to rise to 4 million a day by 2020.

I recently had the opportunity to visit Alberta’s oilsands region to tour Jackfish and see SAGD production first-hand. Certainly, SAGD and other in-situ methods are enormous technical breakthroughs that can allow the extraction of great quantities of bitumen with minimal surface disturbances. Well-based recovery schemes have much lighter environmental impacts than mining-based projects, for sure. 

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

pwilliams@hartenergy.com 

Calgary-based Petro-Canada has raised its cost estimates for its massive Fort Hills oilsands project in northern Alberta, Canada, by a stunning 50%. The company reports that preliminary results from its Front-End Engineering and Design (FEED) work have caused a drastic reworking of numbers announced in June 2007. At that time, costs were pegged at C$14 billion. Now, development could be in excess of C$21 billion.

Fort Hills is in integrated oilsands mine and bitumen extraction plant, located about 90 kilometers north of Fort McMurray. The project includes an upgrader in Sturgeon County, northeast of Edmonton. The Fort Hills block of oilsands leases contains more than 4 billion barrels of recoverable bitumen resource, according to the company. Ultimate peak production is forecast at some 280,000 barrels of synthetic crude a day.

Petro-Canada owns 60% of Fort Hills Energy LP. Other owners are UTS Energy Corp., with 20%, and Teck Cominco Ltd., with 20%. Rising costs have been a perennial concern in the oilsands projects, due to soaring expenses for labor and materials. Stocks of the partners fell after the revised figures were announced, but they confirmed they remain committed to the project.

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

pwilliams@hartenergy.com 

CO2 flooding is one of an arsenal of enhanced oil recovery (EOR) methods used to wring oil from older fields. Thermal strategies, such as steam injection, are popular in low-gravity oils. Injections of CO2 or nitrogen work with lighter gravities.

At present, some 643,000 barrels of oil a day are pumped from EOR projects in the U.S. That’s down from peak levels achieved in 1992, when 761,000 barrels were made each day. The drop comes from the decline in oil produced from thermal methods, which has fallen from 480,000 barrels a day in 1986 to around 273,000 a day in 2008.

The method on the rise is CO2 miscible flooding. Its production has been growing steadily, and volumes reached 240,000 barrels a day in 2008, a tenfold increase from 28,000 barrels a day in 1986.

In addition to its efficacy as an oil-recovery technology, CO2 flooding can deliver tremendous environmental benefits. That’s because CO2 can be sequestered in depleted oil reservoirs. Indeed, old oilfields could be used to permanently store considerable volumes of CO2 beyond those needed for oil recovery.

It’s an area where the expertise of the oil industry intersects with the world’s growing desire to reduce levels of CO2 emitted to the atmosphere.

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

pwilliams@hartenergy.com 

This year’s Summer NAPE, held at the George R. Brown conference center in Houston in late August, was bigger than ever. For those who haven’t had the opportunity to attend, this is the junior version of “Big NAPE,” a major prospect show held in the beginning of the year.

Summer NAPE featured an impressive variety of prospects, from gas shales (lots of Marcellus and Haynesville deals) to shallow oil ventures. I noticed a definite shift toward oil prospects, not a surprising trend given the continued strong prices of that commodity. Permian Basin oil plays were everywhere!

Natural gas futures have weakened considerably of late, thanks to strong storage injections and swelling supplies from unconventional plays. A wildcard is the impact of hurricanes, and talk on the floor centered on the possible path and strength of Gustav.  Still, most explorers consider the long-term outlook for natural gas prices to be high enough to continue aggressive development of a variety of shale and tight-gas plays.

There weren’t as many “Sold” signs posted during this NAPE meeting as I’ve seen in the past, but the mood was upbeat and exhibitors seemed happy with the booth traffic.

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

pwilliams@hartenergy.com