The 350 Bcf reduction in Sable Offshore Energy Project (SOEP) gas reserves estimates taken by Shell Canada and Pengrowth Energy Trust is a big disappointment for the companies, the gas industry and the province of Nova Scotia, but analysts now believe Sable producers could team up with EnCana and possibly other exploration companies — Canadian Superior and El Paso, for example — to maintain production and improve long-term development economics.
Shell Canada announced last Thursday that it would cut its SOEP reserves estimates by another 300 Bcf on its 31.3% share of the project, which currently is the only source of natural gas from offshore Atlantic Canada. This cut compares to the 90 Bcf (11%) and 300 Bcf (27%) negative revisions taken in 2002 and 2001, respectively. Shell Canada’s SOEP reserves now stand at only 430 Bcf compared to the 1.1 Tcf it originally estimated.
Additionally, Pengrowth announced Monday that it would take a 28% negative revision (50 Bcf) on its 8.4% share of proved sales gas reserves for the same project, leaving its reserves at 126 Bcf.
“The adjustments are primarily due to the removal of the Glenelg Field from current development plans, the exclusion of an undrilled fault block at North Triumph [field] and poorer than anticipated performance for the Venture field,” Pengrowth said Monday.
SOEP started production on Dec. 31, 1999 and reached a peak of roughly 550 MMcf/d of dry gas in December 2001. However, primarily because of water encroachment, dry gas production dropped significantly, falling roughly 30% to 390 MMcf/d last September. Start-up of the Alma Field in early December 2003 increased dry gas production back up to 450-500 MMcf/d.
The project has been a “bit of a disappointment, as water encroachment accelerated production declines last year and drilling results deemed development of a satellite field (Glenelg) uneconomic,” said Lehman Brothers analyst Phillip R. Skolnick. Partners in SOEP are ExxonMobil (50.8%, operator), Shell Canada (31.3%), Imperial Oil (9%), Pengrowth (8.4%) and Mosbacher Operating (0.5%).
SOEP currently is producing gas from four fields: Alma, Venture, North Triumph and Thebaud. The project has consisted of two development tiers. Tier I was completed in December 1999 with the Venture, North Triumph and Thebaud fields. Tier II plans originally consisted of the Alma, South Venture and Glenelg fields. However, a technical review of Glenelg, which included disappointing results from a 2003 development well, concluded that development of the field is not economically viable at this time. Tier II began in 2002 and is expected to continue through 2007.
Nova Scotia Energy Minister Cecil Clarke told the Halifax Herald last week that based on Shell’s revision, the province has reduced its estimates of how much money it will collect in royalties over the life of the project to between C$600 million and C$1.1 billion, from estimates of C$1.2 billion to C$2.3 billion. “It certainly is a reality check and indicates the risks involved with the industry,” he told the Herald. But Clarke added that it also is a “rallying call” for industry to start drilling more wells off Nova Scotia.
“The SOEP partners are taking several steps to maintain production level,” said Skolnick. “This includes development of the South Venture field, which is expected to start production late this year, and field compression, which is scheduled for start-up in 2006.
“The SOEP partners also are evaluating potential development synergies with EnCana’s Deep Panuke natural gas project, which has been put on hold due to poor economics,” he added.
Maritimes & Northeast Pipeline, which transports SOEP’s gas production to markets in Canada and the Northeast United States, notified the Federal Energy Regulatory Commission in December that it was withdrawing its application to add 385 MDth/d of firm transportation capacity to its system in New England because EnCana halted the Canadian regulatory review of its Deep Panuke project.
EnCana pulled its applications for Deep Panuke in December, telling regulators from Canada’s National Energy Board and the Canada-Nova Scotia Offshore Petroleum Board that it was working to resolve technical and commercial issues. Deep Panuke was determined to be uneconomic because the expected commercial production of the field wouldn’t be sufficient to support a 20-year firm transportation agreement with Maritimes. The field has about 1 Tcf in estimated gas reserves, with daily production projected to be 400 MMcf.
EnCana COO Randy Eresman also said in December that the company was assessing “the most appropriate way to develop the field, including the potential of a smaller production facility that produces at lower plateau volumes for a longer period of time, thereby reducing the project’s capital cost. We’ve also held preliminary discussions with the SOEP group about the possibility of using existing infrastructure.”
In an attempt to improve the economics of Deep Panuke, EnCana recently drilled two wells, one of which (MarCoh) was with ExxonMobil (51%) and Shell Canada (24.5%). The first well, Margaree (EnCana, 100%) tested at 53 MMcf/d during a nine-day test. The MarCoh well was not production-tested.
“ExxonMobil and Shell Canada’s dominant ownership interest in both SOEP and the MarCoh well could facilitate an arrangement with the SOEP group,” noted Skolnick. “This would be a positive for EnCana.
“Offshore East Coast Canada continues to be a challenging environment,” he added. “A number of exploration wells have resulted in dry holes. However, Canadian Superior recently announced that its Mariner I-85 exploration well, which offsets SOEP, has encountered significant gas shows.”
The Mariner well, in which El Paso has a 50% stake, is targeting an estimated 1.2 Tcf of reserves and is still being drilled. Results are expected in eight to 10 weeks.
“If successful, this could possibly provide support for a ‘spoke and hub’ type development scenario with SOEP and Deep Panuke or other potential discoveries in the area, if reserves are not large enough for stand-alone development,” said Skolnick.
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