Sam Fletcher
OGJ Online
HOUSTON, Aug. 21 -- Some 100-200 rigs now drilling for natural gas in North America will be idled within the next 6-9 months because of lower commodity prices and increased costs for drilling and completions, said officials at Simmons & Co. International, Houston, in a recent report.
Low commodity prices are most likely to affect natural gas drilling in East Texas, West Texas, South Texas, and the Gulf of Mexico, said company officials. But operations in the US Midcontinent, North Texas, and especially the coalbed methane play in Wyoming's Powder River Basin remain viable at lower price levels, they reported.
The predicted drop off in drilling is based on "the current $3.37/Mcf 12-month strip and feedback we have received from our survey of industry participants," said Simmons officials in an August report on drilling economics. Baker Hughes Inc. last week reported 1,024 rotary rigs were drilling for natural gas in the US alone, one fewer than the previous week (OGJ Online, Aug. 17, 2001). A total of 1,590 rigs were working last week in the US and Canada, drilling for either oil or gas.
Upfront drilling and completion costs, along with initial production levels, have the biggest influence on the economics of otherwise marginal wells that many producers have been drilling in the last 18 months, said W. Mark Meyer, vice-president of E&P research at Simmons & Co.
Drilling activity in East Texas, West Texas, South Texas, and the Gulf of Mexico is especially sensitive to those economic influences, said Meyer. The jump in the number of stacked-ready mobile offshore rigs in the gulf this summer -- from a single unit in mid-May to 18 by early August -- is a clear indicator of that fall off in gas drilling, he said.
The number of mobile offshore rigs under contract in the US sector of the Gulf of Mexico has declined for 8 of the last 9 weeks, dropping through a 13-month low in late July. Utilization fell to 77.8% last week, with 165 mobile rigs under contract in the gulf out of the 212 available for work, said officials at ODS-Petrodata Group, Houston.
Up to 80% of the independent operators in the gulf have already spent their offshore budgets for 2001, said industry sources.
Lack of "meaningful growth" in gas production "despite 18 months of record gas-directed drilling" is evidence that marginal wells "were and are being drilled," Simmons Co. officials reported.
The 21 producers surveyed by Simmons managed year-to-year production increases of only 0.4% in the first quarter and 0.6% in the second quarter of this year. Recent information reported by the Texas Railroad Commission indicates that gas production has been flat or maybe even down this year in Texas, which accounts for about 30% of all US gas deliverability.
The rapid run-up of natural gas commodity prices to $4-$5/Mcf over the last 18 months triggered a rush among producers to capture "unprecedented returns from the drillbit," said Meyer. But many of those producers drilled small and otherwise marginal prospects in developed areas where the pipeline infrastructure was already in place to rush the new reserves to market. Higher risk exploration projects in frontier areas without such infrastructure often were ignored, even though they offered potential long-term production and reserve growth benefits, said Simmons officials.
"Producers had a window of opportunity, created by a much higher commodity price and an available infrastructure that gets gas to market within 60 days from start of drilling," Meyer said. "Operators with marginal properties figured they might as well get those projects done."
Gas commodity prices in excess of $4/Mcf generated robust well economics, said Simmons officials. But increased demand has since triggered a sharp rise in service industry prices. In some areas, rig day rates more than doubled from first quarter 2000 levels, the report said.
Meanwhile, natural gas lost some of its market as oil became more competitive during the peak winter season. It has not yet regained a large chunk of that lost market despite a significant drop in gas commodity prices this year.
Analysts expect natural gas commodity prices to fall below $2.50/Mcf this year, maybe as low as $2/Mcf. The type of gas projects drilled in the last 18 months would no longer be economic to drill at those low commodity prices.
In their study, Simmons officials looked at nine kinds of gas wells in seven areas to calculate the economic viability of drilling an average well in each of those representative categories. They acknowledged that some operators have special skills, knowledge, and other advantages in some of those areas that would enable them to exceed Simmons' calculations for a typical well. "Well quality is a huge issue," said Meyer.
East Texas
In the last few years, East Texas has emerged as one of the most active areas to drill for natural gas in the Lower 48 States, with more than 50 operators in that area working some 140 rigs in the Bossier, Cotton Valley, and Travis Peak gas plays.
A typical well in the Cotton Valley play, drilled to a depth of 12,000 ft and completed a light sand fracture process, would cost about $2 million and tap a reserve potential of about 2 bcf of gas, according to the Simmons report.
Simmons officials figure initial production of 1.5 MMcfd and a 55% production decline rate within a year for such a well.
With gas market prices of $3.50/Mcf, that well would generate an 11% rate of return. But it would be potentially marginal at $3/Mcf and negative at $2.50/Mcf, the report concluded.
West Texas
The Sonora play in West Texas is another highly active gas drilling area, with wells drilled to an average 5,500-7,500 ft at a typical cost of $400,000 and an usual reserve potential of 540 MMcf. Initial production is some 400 Mcfd, with an annual decline rate of 30%.
Such a well enjoyed a 22% rate of return in a $3.50/Mcf gas market, but again is potentially marginal at $3/Mcf, officials said.
South Texas
Simmons officials also looked at land wells in the Wilcox formation along the Texas Gulf Coast. Although there are several variables in well performance in the Wilcox, they calculated the well at a depth of 12,000 ft, with $2.1 million capital costs and an average reserve potential of 2 bcfe. Initial production was surmised at 3 MMcfd, with a rapid 50% decline rate in the first year.
The Simmons report showed a 32% rate of return for such a well at $3.50/Mcf, dropping to 8% and "still viable" in a $3/Mcf market, "assuming no significant deterioration in initial production rate." At prices below that level, officials said, "Economics are challenged."
Gulf of Mexico
Simmons officials looked at three separate scenarios for gas operations on the Gulf of Mexico shelf, including 3D "bright spot" wells drilled by jack up rigs in water depths greater than 150 ft and less than 150 ft and drilled from an available slot on an existing platform.
In less than 150 ft of water, the well was figured to be drilled an average 6,000-8,000 ft deep at a cost of $5.5 million, tapping 5.5 bcfe of reserves in multiple formations. Initial production was calculated at 6 MMcfd, with a 42% decline rate in the first year. Simmons officials figured a 12% rate of return for such a well in a $3.50/Mcf market. But it would be "moderately sensitive to initial production rate assumptions" and potentially marginal at current costs and a market rate of $3/Mcf, the report concluded.
In water depths greater than 150 ft, the well was calculated at a total depth of 8,000 ft and a cost of $6.5 million, with a reserve potential of 5.4 bcfe. Initial production was figured at 7 MMcfd, with a 40% decline in the first year.
Even in a $3.50/Mcf gas market, such a well had the lowest return rate -- 9% -- of any calculated in the Simmons report. Its economics exhibit a high degree of sensitivity to initial production rate assumption at prices up to $4/Mcf, officials said. It, too, would be potentially marginal in a $3/Mcf market.
A well drilled from an existing platform was calculated at a total depth of 8,000 ft and a cost of $3.25 million, with an average reserve potential of 3.2 bcfe. Initial production was calculated at 6 MMcfd, with a 45% rate of decline.
At a market price of $3.50/Mcf, such a platform well could provide a return rate of 45% -- the best by far for an offshore well described in the report. But it, too, would be potentially marginal at current costs and with gas prices between $2.50-$3/Mcf, the report said.
The report was much more upbeat about the potential for gas wells in the Midcontinent US and North Texas regions and for coalbed methane, however.
Coalbed methane
The coalbed methane play dominated by Barrett Resources Corp. of Denver, Devon Energy Corp. of Oklahoma City, and other independents in Wyoming's Powder River Basin has been certainly the most active and probably the most lucrative onshore natural gas areas in the US. Low horsepower truck-mounted rigs are punching 600-800 ft wells into the Wyodak Coal formation on a daily basis at a negligible cost of $150,000/well. The average reserve potential per well is only 500 MMcfe. Initial production is 300 Mcfd, but the production decline also is a low 15%.
Assuming the well is dewatered within a few short months, Simmons officials calculated a whopping 242% rate of return with a market price of $3.50/Mcf. Even at $3/Mcf, the return rate is still a huge 173%. At $2.50/Mcf, the rate is an enviable 104%.
Although coalbed methane wells are highly sensitive to regional environmental restrictions and water disposal costs, they remain economically attractive "down to at least $2/Mcf, assuming current well costs and average well performance," the report concluded.
"We probably should have been a little more harsh on the differentials for the Rockies. But that area has relatively low finding and development costs, and they don't get all of the gas out real fast," Meyer told OGJ Online.
North Texas
Mitchell Energy & Development Corp. in The Woodlands, Tex., has long dominated the Barnett Shale tight gas play concentrated in Wise and Denton counties of north central Texas.
W.D. "Bill" Stevens, president of Mitchell Energy, said the company has drilled more than 400 wells in the Barnett Shale and encountered only two dry holes. Moreover, he said, the company has been primarily "a developer of natural gas, with a very small exploration program."
The prototype North Texas well calculated by Simmons officials is at the average permitted depth of 8,500 ft and drilled at a cost of $800,000 with an average reserve potential of 1.25 bcfe. The initial production rate is calculated at 1 MMcfd, with a decline rate of 55% in the first year.
In a $3.50/Mcf market, Simmons officials calculated the rate of return for such a well at 79%, the second highest rate for any of the seven locations. At current costs and average quality, they said, such a well would be "comfortably viable" at a gas commodity price around $2.50/Mcf.
Devon Energy's pending $3.1 billion cash and stock acquisition of Mitchell Energy (OGJ Online, Aug. 14, 2001) would give that company strong positions in two areas with the best potential returns even with low gas commodity prices. Devon officials said acquisition of Mitchell Energy also will give them "more than 3,000 possible and probable locations" to drill.
Midcontinent
The Midcontinent US contains a wide variety of geological plays and well types. Simmons officials focused on a typical 15,000 ft well drilled in the Red Fork formation, similar those Apache Corp., Houston, is drilling in Caddo County, Okla.
They figured such a well would cost about $900,000 to drill and would tap an average reserve potential of 1.3 bcfe. Initial production was calculated at 900 Mcfd with a 25% annual decline rate.
The economics of such a well would exhibit relatively low sensitivity to initial production rate assumptions, Simmons officials said. It would be "comfortably viable" in a $3/Mcf market, officials said.
Industry mindset
Because of the rapid depletion of new natural gas reserves, any major slowdown in current drilling activity will quickly affect US gas supplies. For that reason, Meyer said, it's unlikely that gas commodity prices can drop below $2.50/Mcf for an extended period.
He sees "no hard evidence that would support disagreement" with the conclusion that the industry could be subject to shorter and swifter drilling cycles and greater price volatility under those circumstances.
However, he said, the more successful producers have been careful to avoid the industry's usual "drill yourself into oblivion" scenario because they want to avoid even the perception among institutional investors that they might be reckless with capital.
"Most of the substantial producers do 'get it,'" Meyer said. "But it's a 'Catch-22:' They're damned if they don't make their production growth targets, and they're damned if drill only marginal projects where production will peak way early."
Moreover, he said, the recent rollback of some service sector costs could affect the economic viability of some gas prospects.
"Offshore rig rates are down $10,000-$15,000/day in some areas, and rig rates are a considerable component in your upfront drilling costs," said Meyer.
"A significant number of jack ups has come back to work after sitting idle for a week to more than a month this summer. You have to figure they're getting lower day rates under their new contracts," said Robert Moers, who tracks offshore drilling activity in the gulf for ODS-Petrodata Group, Houston.
Global Marine Inc., Houston, reported its worldwide Summary of Current Offshore Rig Economics (SCORE) for July fell by 0.3% from June (OGJ Online, Aug. 20, 2001).
Global Marine CEO Bob Rose said the slowdown in drilling activity in US waters forced contractors to reduce day rates. However, he said, oil companies are bidding up day rates to attract equipment to the tighter international markets.
Contact Sam Fletcher at [email protected]
