The best laid schemes of Mice and Men oft go awry,
And leave us nothing but grief and pain, for promised joy!
— Robert Burns, To a Mouse (Poem, November, 1785)
Little fanfare accompanied the Mineral Management Service’s (MMS) report1 Gulf of Mexico Oil and Gas Production Forecast: 2007 — 2016, published in May, 2007. This lack of attention was in sharp contrast with Chevron’s successful Jack #2 test well result announced in September, 2006. Business Week reassured an anxious world that there was Plenty of Oil — Just Dig Deeper.
You can tune out all the scare talk about Peak Oil for a while—probably a long while… a successful test in a mammoth field deep beneath the Gulf of Mexico, announced on Sept. 5 by Chevron, Devon Energy, and Norway’s Statoil, should help put that scary scenario on hold for decades.
It’s time to revisit the Gulf of Mexico (GOM) with a focus on reality, not hyperbole.
The graphic (left) shows both historical GOM oil production and the MMS projections out to 2016. There are two estimates, the Committed Scenario and the “more speculative” Full Potential Scenario, where “projects in less than 1,000 ft (305 m) water depths are considered to be shallow-water projects and those in greater than 1,000 ft (305 m) are considered to be deepwater projects.” In the Committed Scenario, future shallow water production is modeled by fitting an exponential decline curve to the sustained decline period 1997 — 2004 and then “assuming that future shallow-water production will decline at half this rate.” (2005 is considered anamolous because of Katrina and Rita.) Deepwater estimates are based on an operator survey for projects in production or those under development. The Committed Scenario shows GOM oil production growing from about 1.25 million b/d in 2006 to a peak of about 1.75 million b/d in 2010.
Evaluating the MMS’s more conservative scenario requires a look at what’s going on with producing and scheduled oil projects in the Gulf now, especially the coming bigger developments like Thunder Horse, Atlantis and Tahiti. (See the MMS report for a complete list of GOM projects from 1979 to 2010.) It is important to note that only about 0.5 million b/d will be added to the U.S. supply in the most realistic case, even granting the MMS’s assumption of a slower decline rate in the shallow water.
Chevron’s Tahiti Offers Clues to Stamina of Gulf Oil Boom (Rigzone, June 20, 2007) provides a good vantage point from which to appraise how things are going in the Gulf. Chevron faces uncertainty about how Tahiti, with a capacity of 125 thousand b/d, will perform when the first commercial oil comes on-stream in mid-2008.
On an oil platform, machinery is typically crammed into every inch of deck space, to the point where crews live two to a closet-sized room.
But Chevron Corp. has left precious deck space clear as it puts the finishing touches on Tahiti, a skyscraper-sized offshore production facility, illustrating the uncertainty about what will follow the current production boom in the U.S. Gulf of Mexico.
Tahiti, which is scheduled to produce first commercial oil in mid-2008, is one of several new, multibillion-dollar energy projects in the deepwater Gulf. Taken together, they are expected to temporarily halt a 20-year decline in U.S. oil production by the end of the decade….
Chevron expects output from the $3.5-billion Tahiti platform to increase to 125,000 barrels a day of high-quality oil within seven months of the start of production. Other companies will be scrutinizing how Chevron, the second-largest U.S. oil company by market capitalization, uses the empty patch on Tahiti’s top production deck as much as the initial production figures.
The space is marked off for whatever equipment will be needed to slow the decline that will come a few years, or perhaps even months, after Tahiti hits its peak. All fields decline at some point, but other projects in the deepwater Gulf have seen unexpectedly rapid drop-offs in production.
Why might Chevron be leery about Tahiti’s future production profile? The reason is that other comparable fields in the deepwater GOM have not met expectations. The fear is that the oil will be in a number of small, discrete traps, and the uncertainty exists because the oil lies beneath a salt canopy which makes 3-D seismic surveys difficult.
The salt hides crucial details about oil reservoirs from even the most advanced imaging techniques, meaning Chevron won’t know how difficult it will be to maintain the flow of oil once production begins next year…
Murphy Oil Corp. built a 60,000-barrel-a-day platform over its Front Runner field, about 40 miles northeast of Tahiti, in 2005. Production peaked at 20,000 barrels a day; Murphy now says Front Runner will average no more than 9,500 barrels a day this year.
BP-operated Mad Dog, drilled into a similar rock formation same geological age of Tahiti’s reserves, is built to handle 12 wells producing 100,000 barrels a day, but currently operates at half its capacity [50 thousand b/d]. Drilling the 12 wells has proven slower and more expensive than expected.
The least-desired path would involve extracting oil tucked away in many small reservoirs, known as compartments.
Mad Dog was shutdown as of April 1, 2007, for reasons still under investigation. Mad Dog and Atlantis (capacity: 200 thousand b/d) lie close to each other in the Green Canyon area of the Mississippi fan fold belt (graphic left) beneath the salt canopy. It appears possible that Atlantis may experience reduced oil flows, but no one will know until the project, which has been delayed twice, comes on-stream in late 2007. On the other hand, Holstein, which is adjacent to both Mad Dog and Atlantis in the Green Canyon, has lived up to expectations (110 thousand b/d). Uncertainty rules the day.
The Thunder Horse project (Mississippi Canyon, 250 thousand b/d) has been delayed until the end of 2008. BP’s massive semi-submersible production platform was left listing in the Gulf waters after the 2005 hurricanes. Cracked manifolds created more woes, as BP attempts to produce commercial oil (Chicago Tribune) using the world’s deepest subsea collection of “pumps, wellheads, piping and gathering centers.”
Thunder Horse’s oil reservoir is nearly 5 miles below the water’s surface. At that depth, oil will gush from the drill pipes at a temperature of 275 degrees Fahrenheit, under a metal-crunching 17,400 pounds per square inch of pressure. Those conditions can stress even the mixture of high-strength steel and alloy that make up the half-inch welds on the manifolds and pipes of the Thunder Horse oil fields…
While the manifolds sat idle for a year after the platform tilted, the crushing pressure at the bottom of the sea forced hydrogen atoms into the mix of steel and high-strength alloy that made up the welds. The hydrogen caused the metal to become brittle, and when water was forced through the piping during the restart testing, the welds failed.
As BP diagnosed the problem, they notified Shell, who was also planning to “submerge manifolds at [similar] depths,” of the possible problems. Although Thunder Horse is a technological marvel, there are consequences when you are doing things for the first time. In every large field examined here, there are significant concerns affecting the MMS’s Committed Scenario.
What of the MMS’s Full Potential Scenario? This risky projection is based on operator discoveries and undiscovered resources (graphic top, left). The Committed Scenario already includes projects in various Lower Tertiary plays, including Cascade and Chinook at Walker Ridge, and Great White, Silvertip and Tobago in Alaminos Canyon. Presumably, undeveloped discoveries in the same areas — e.g. Jack, St. Malo and Das Bump at Walker Ridge — make up the bulk of the higher production levels in the Full Potential Scenario, which reaches 2 million b/d in 2011 and declines thereafter when undiscovered resources are excluded. The MMS makes a number of unwarranted assumptions — e.g. “Projects with discovered resource volumes over 200 MMBOE [million barrels of oil equivalent] are assumed to reach peak production in their second year, sustain that peak rate for a total of 4 years, then decline exponentially at 12 percent from that time forward” — in light of the fact that fields like Mad Dog have underperformed and there is no production history for Lower Tertiary fields to draw upon.
The MMS uses their Exploration, Development, and Production (EDP) model to project development of undiscovered resources, explaining that “in the EDP model, undiscovered fields are explored and discovered as a function of profitability and exploration drilling success rates.” Unfortunately, that’s not all there is to it. Near term projections (out to 2016) based on development of undiscovered resources are meaningless because the oil must first be discovered, there are long lead times from discovery to first oil accompanied by huge capital expenditures, and there are the many technical difficulties inherent in ultra-deepwater production. For both the discovered oil and assumed resources, logistical challenges in the oil industry make positive projections hard to swallow. Chevron Postpones $3 Billion Jack Prospect in Gulf (Bloomberg, June 13, 2007) reports that no additional appraisal wells will be drilled in the Jack Walker Ridge blocks until late this year or early 2008 because of the ongoing rig shortage.
Hurricanes are the final wildcard (graphic above, left). Historical GOM production has never matched its 2002 high water mark due to frequent storm disruptions. The MMS projections assume that the recent production trend will be reversed. The year 2005 may have been an anamoly — both Rita and Katrina caused extensive damage to oil & gas infrastructure. By the same token, however, so was the year 2006 — there were no hurricanes in the Gulf. The longer term hurricane activity trend since 1995 is not favorable, but the MMS ignores model forecasts showing that “higher than average activity rates are likely to persist for at least a decade.”
The Jack #2 test well result was used to lambaste analysts concerned about peak oil as prices fell in the fall of 2006. Those seriously studying the problem were portrayed as scaremongers, a characterization which still persists today. Yet, a sober look at future oil production in the Gulf of Mexico raises more doubts today than it might have when the Jack announcement was made. The Rigzone article quoted here and the Minerals Management Services report were barely noticed. It is hard to avoid the conclusion that public complacency may turn to panic soon enough as Gulf of Mexico oil production likely fails to meet the unrealistic expectations placed upon it.
1. This column analyzes the MMS projections for oil production in the Gulf of Mexico. However, their forecast for natural gas production in the Gulf is much worse (graphic, left). This disturbing trend will be the subject of a future article reporting on the North American natural gas supply situation.
Contact the author at [see original article at ASPO-USA]
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