Discoveries

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 

I just returned from a trip to Weyburn Field in Saskatchewan, Canada. Weyburn, operated by EnCana Corp., is the site of the largest full-scale, in-the-field study of CO2 storage in a commercial EOR operation.

Weyburn is a huge, 50-year-old field that produces from Mississippian Midale. Original oil in place was 1.4 billion barrels; 370 million will be recovered via primary and secondary methods. The CO2 flood is estimated to add 155 million barrels of incremental oil.

In addition to the well-accepted use of CO2 to aid oil recoveries, Weyburn also demonstrates the ability of old oilfields to store CO2. At the end of the commercial oil-recovery phase, some 33 million tons of industrially generated CO2 will be permanently sequestered in the Midale formation.

As a yardstick, the average car emits about six tons of carbon dioxide every year. So Weyburn will eventually hold the volume of CO2 that would be saved by taking 5.5 million cars off the roads for a one-year period.

This sequestration is one of the truly exciting trends in the oil industry. EOR processes can usefully employ the waste gases thrown off by industrial processes, and afterward the target oilfields can serve as secure storage containers for that gas.

Many thanks to the province of Saskatchewan and the people of EnCana for their warm hospitality and enlightening visit.

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

pwilliams@hartenergy.com 

At the annual EnerCom Inc. conference in Denver, Calgary-based operator Canadian Superior Energy Inc. announced its Bounty wildcat, drilled in Block 5(c) offshore Trinidad, tested at a stablized rate of 60 million cubic feet of gas per day, restricted by equipment. The resource potential of the tested structure is up to 2.6 Tcf.

“Today’s a very important day for Canadian Superior,” said Craig McKenzie, chief executive officer, speaking to an attentive crowd at the first session after lunch on August 13. “This is the second discovery we’ve made this year in Trinidad and Tobago, so we’re on a roll.”

When the Bounty well is hooked up and developed, the company expects it to produce at rates approaching 200 million cubic feet a day. “I don’t know how many shale-gas wells that is, probably about 500,” said McKenzie.

Next, the Kan Tan IV semi-submersible will move to another wildcat prospect, Endeavour, on the same block.

Congratulations to CanSup!

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

pwilliams@hartenergy.com

Perhaps the last great frontier of the North American continent is Greenland, the world’s largest island. The self-governing Danish province has leased concessions off its west coast, which is ice-free for about five months a year. Operators with acreage in western Greenland include ExxonMobil, Chevron, EnCana, Husky and Cairn Energy. At present, Cairn plans to begin acquiring 2-D seismic over its block. In the West Greenland and Eastern Canada petroleum province, the U.S. Geological Survey has placed undiscovered resource figures of 7.2 billion barrels of oil, 1.1 billion barrels of NGL and 51 Tcf of gas.

But bigger prizes likely lie offshore Greenland’s east coast, which some liken to western Norway’s prolific offshore. The U.S.G.S. assessed the potential of Eastern Greenland’s rift basins at 8.9 billion barrels of oil, 8.1 billion barrels of NGL and 86 Tcf of gas, and ranked it has the fourth most prospective region in all of the circum-Arctic.

Eastern Greenland’s offshore has an active hydrocarbon system, and geological characteristics are favorable. Workers believe its shelf could be home to the same Upper Jurassic source rocks that delivered oil to most of the North Atlantic’s considerable oilfields. Studies indicate that thermal maturity is in the correct range for oil generation;  Jurassic and Devonian reservoirs are extrapolated into the area; and mudstone seals appear to be present.

Additionally seismic data support the idea that North Sea-style tilted structures that occur onshore Greenland continue into its offshore. Explorers are intrigued by possible traps in large, rotated fault blocks and anticlines that have good timing for migration and accumulation.

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

pwilliams@hartenergy.com

North America’s northern reaches are receiving new attention, particularly Alaska. Earlier this year, operators wagered huge sums at a lease sale in the Chukchi Sea, between Alaska and Russia. Seven companies offered bids totaling nearly $3.4 billion, and high bids added up to nearly $2.7 billion on 2.76 million acres. Shell submitted a total of 275 high bids, including $105 million for one tract. Its total commitment was $2.1 billion. ConocoPhillips submitted 98 high bids that summed to $506 million.

The reason for the interest was made clear when the U.S. Geological Survey released its assessment of undiscovered resources above the Arctic Circle. The Survey determined that Arctic Alaska alone holds potential for 30 billion barrels of oil, 6 billion barrels of natural-gas liquids and 221 trillion cubic feet of gas.

Arctic Alaska, especially the Arctic platform, holds outstanding oil potential, fully 30% of all the undiscovered oil in the entire globe above the Arctic Circle. The Chukchi Sea falls within this highly prospective area, as does Canada’s Mackenzie Delta.

The U.S.G.S. has set up a website at http://energy.usgs.gov/arctic/. If you are interested in undiscovered oil and gas resources above the Arctic Circle, it offers a fact sheet, slide show and podcast.

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

pwilliams@hartenergy.com

Since 1998, natural gas production has surged from northeast Texas and the Rocky Mountain regions. According to the Energy Information Administration, between 1998 and 2006, production grew 114% from northeast Texas and 86% from three Rocky Mountain states.

Texas Railroad Commission districts 5, 6 and 9 grew production by 1 Tcf during the period, thanks to sterling results in the Barnett shale, Cotton Valley and Bossier plays. Rocky Mountain states Wyoming, Colorado and Utah grew their natural-gas production by nearly 1.5 Tcf, mainly from massive tight-sand field developments. Wyoming led the group with addition of 857 Bcf.

To take a look at EIA’s 2006 Annual Report, its most recent, click here.

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

pwilliams@hartenergy.com

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