Independent operators report strong US exploration and production efforts despite increased drilling costs and other service costs. Companies strive to mitigate higher expenses through operating efficiencies, noting that the 2008 field cost outlook is uncertain.
Partially because of rising field costs, Apache Corp. reduced its 2007 US exploration and development budget from its 2006 budget. Yet, the company continues to increase production and add reserves.
This story reviews the methods Apache uses to manage its costs in the Anadarko basin, Permian basin, and East Texas. Devon Energy Corp. provided information about its operations in the Barnett shale and the Rocky Mountains.
Several independents declined to discuss company-specific field costs with OGJ, and some said the information is proprietary.
High service costs can contribute to higher commodity prices. Adam Sieminski, Deutsche Bank chief energy economist, recently revised his 2008 average price forecast for West Texas Intermediate crude on the New York Mercantile Exchange to $85/bbl, up $5/bbl.
“One key factor that offers compelling new evidence that our longer-term energy price forecasts need to be revised higher is rapidly increasing finding and development costs,” Sieminski said.
Oil price declines historically follow lower demand for refined products, improvements in seismic and drilling technology, and better access to petroleum reserves, said.
“A repeat of this confluence of events is certainly possible, but seems improbable over the course of the next few years,” Sieminski said, citing flourishing oil demand growth in Asia and the Middle East.
JAS shows rising costs
The Joint Association Survey on Drilling Costs (JAS) estimates industry spent $76.2 billion in 2005 to drill and equip wells in the US, up 18% from the estimate for 2004.
Increases in the number of wells and footage drilled pushed the average cost per well and cost per foot to higher levels (see table). The JAS survey relies upon actual well costs provided by hundreds of operators.
The American Petroleum Institute, Independent Petroleum Association of America, and Mid-Continental Oil and Gas Association sponsor the survey. API analysts have compiled the yearly survey report since 1954.
The survey of 2005 costs was released in April 2007, said Hazem Arafa, API statistics department director.
Survey compilers have about 70% of the data when they begin a report, and they use those field cost reports to estimate the costs for every well in the database, Arafa said. It takes 3 years for 99.7% of the wells drilled to be reported.
“Once we develop the model, we estimate costs,” Arafa said. “As wells come in later on, we always can attach a cost to it using the model. We don’t resurvey the companies.”
Ron Planting, API’s manager of statistical information, said API prepares drilling cost indexes that separate out the effects of shifts in drilling depths and regional patterns, as well the effects of general inflation.
“Without adjusting for these factors, the survey shows that average cost per well more than doubled between 2001 and 2005.” Planting said. “Part of that cost increase, however, was due to shifts to deeper drilling and other changes in drilling patterns.”
After removing the effects of changes in depth and regional drilling patterns, the API index shows that costs rose 78%. If that is further adjusted for inflation, the JAS indexes show that inflation-adjusted costs rose 68%, Planting said.
API Chief Economist John Felmy noted that companies are continually experiencing higher drilling success rates. He said field costs for 2005 are much different than the costs reported decades ago, in part because the success rate has gone up dramatically.
“Here in Washington, people like to point out you’ve got $100/bbl oil. But at the same time, you’ve also got to realize that costs have increased,” Felmy said. “It’s a challenge for oil companies because you’ve got costs that are changing dramatically.
Oil companies are looking to go forward and develop resources, but they’ve got to be sure that they can do it,” Felmy said. “Companies are putting projects in place that are going to last 30-40 years, and that just makes it much, much more challenging.”
CERA: Costs moderating
Cambridge Energy Research Associates (CERA) said upstream capital costs moderated slightly during the first half of 2007 compare with the rate of cost increases during 2006.
Pritesh Patel, lead researcher on upstream capital costs for CERA, said, “This raised an expectation in the industry that cost increases may be coming to an end.” However, he said, “The latest data indicate this not to be the case.”
Although rigs are being built and equipment manufacturing capacity is increasing, much of that expansion will not come on line until the second half of 2008 or later.
In November 2007, CERA and its parent IHS Inc. said costs of constructing new oil and gas facilities had surged to a record high, up 11% in 6 months to 198 points on CERA’s upstream capital costs index.
“This is nearly double the costs observed as recently as 2005 when the index measured 106 points,” CERA said. Analysts did note a slight decline in day rates for offshore drilling rigs.
A sustained increase in the price of steel in 2003 followed by rising oil prices triggered a dramatic increase in oil field equipment and facilities in 2005.
“As industry activity levels increased in 2005-06, manufacturers and suppliers of oil and gas equipment and services reached maximum capacity and began to increase their prices,” CERA said. The cumulative effect of tight capacity due to high activity levels and high raw-material costs nearly doubled the capital required for the same set of facilities.
Apache lowering costs
Apache combines improved equipment and drilling technology with finely tuned exploration strategies
Tom Voytovich, vice-president of Apache’s Central Region, said land rig rates are down 5-10% from their levels a year ago. Rig availability also has improved somewhat from the same time last year, especially for intermediate-sized rigs. New rigs and those with more powerful pumps remain in short supply.
Apache’s Central Region waited 3 months to get rigs in early 2007, but the Houston independent’s rig wait was only few weeks as of early 2008. Voytovich credits drilling contractors for building rigs so that supply climbed to meet increasing demand.
“Our drilling performance continues to improve, so we are realizing a savings over a year ago across the Midcontinent and Texas,” Voytovich said. “We continue to climb the learning curve on technologies and build on our area expertise.”
Apache significantly lowered its field costs at Stiles Ranch, primarily through what Voytovich calls “aggressive use” of polycrystalline diamond compact (PDC) bits and through using rigs with top drives.
PDC bits allow Apache to get much faster penetration rates and also much longer bit runs, which saves time because it requires fewer trips.
“What that accomplished is that we now drill wells in significantly less time,” Voytovich said. Apache took 50 days to drill 16,000-ft vertical wells in Stiles Ranch in mid-2006, but now it drills a well in 40 days. In January, Voytovich expected Apache would reduce its drilling time there to 37-38 days within a couple of months.
The use of top drives eliminates some steps in pipe handling, reduces nonproductive time, and enables a rig to multitask by being able to rotate and circulate while tripping and running casing.
“This is beneficial when drilling directional wells, and it provides better well control on trips,” Voytovich said. “Operational efficiencies achieved through the use of top drives translate directly into cost savings.”
Apache lowered drilling costs $200,000/well for Stiles Ranch, which straddles the Oklahoma-Texas border just north of US Interstate 40 and is one of the most active areas for Apache’s Central Region. Apache drilled 21 wells in Stiles Ranch during 2007 and expects to drill 25 or more wells there this year.
In East Texas, Voytovich sees rig availability “loosening up a little.” He expects Apache will drill about 25 wells there this year. He sees strong demand for drilling rigs capable of drilling horizontal wells in East Texas, which is something that Apache does.
Regarding Midcontinent field costs, Voytovich expects day rates will fluctuate with natural gas prices.
“It has to do with the redistribution of rigs as well,” he said. “We lost rigs from Oklahoma and the Texas Panhandle up to the Rockies in the last couple of years. We are starting to see some of those rigs come back. If that continues, we should see prices go down.”
Strong rig demand in Permian
Apache plans to drill more than 200 wells this year in the Permian basin, a moderate increase over what it drilled there last year.
“This is really driven by rig availability,” Voytovich said. “Permian is an area that is receiving a lot of heat and light right now because of [high] oil prices, so rig availability is a little tighter there.”
He noted that smaller rigs in the Permian handle singles only while most rigs hired by Apache use triples. Apache’s current contract land fleet includes rigs ranging from 500 hp to 2,000 hp. The fleet involves newbuild rigs having the latest technology and decades-old rigs having had various upgrades and modernization.
Ziff Energy Group reports overall Permian basin operating costs increased 35% since 2004. A recent benchmarking study, “Improving Field Performance,” was Ziff’s sixth Permian study since 1996. Five of the six participating operators were independents.
The study examines operating cost data for a 12-month period from mid 2006 to mid 2007. The study assessed 134 fields (including 26 carbon dioxide tertiary enhanced oil recovery fields) that collectively produce nearly half the basin’s oil and a third of its natural gas.
Part of the increased average operating costs since 2004 was associated with higher oil and gas prices.
The average operating cost for Permian oil fields increased 34% to $10.42/bbl since last analyzed. Saying that increase was in line with increased oil prices, Ziff also noted that leading operators achieved average oil field operating costs below $6.50/bbl.
The average operating cost for gas fields increased 45% to nearly $1.35/Mcf. By contrast, leading operators of gas fields achieved average operating costs of less than 80¢/Mcf.
“Unlike the oil price, however, the gas price has hardly increased, so gas margins are squeezed,” Ziff said.
Ziff analysts concluded that electricity costs increased 40% and that taxes constituted the largest single cost component for both oil and gas fields (40% for gas fields, and almost a third of total operating expenses for oil fields).
“Cost pressures and reduction potential are heavily concentrated in four specific cost categories: well servicing, taxes, labor and field supervision, and electricity,” Ziff said.
Rocky Mountain costs
Operating costs in the Rocky Mountains vary dramatically because of weather, remote locations, and water production from coalbed gas wells, Devon said. Labor, transportation, and compression costs also are higher in the Rockies.
Devon’s Rocky Mountain operations involve various types of wells drilled. Some wells are shallow, conventional wells while others are deeper or coalbed gas wells. The company’s Rocky Mountain operations stretch from northern New Mexico up through parts of Colorado, Utah, Wyoming, and Montana.
In the Washakie basin in Sweetwater County, Wyo., Devon said wells averaged $2.5 million compared with $2.2-2.3 million about 18 months ago.
In 2007, Devon drilled about 130 conventional wells and 200 coalbed gas wells in the Rockies.
“This year, we expect to drill 100-150 conventional wells and about 100 coalbed natural gas wells in the area,” the company told OGJ. “Devon’s capital budget in the Rockies is about $300 million for 2008.”
Devon is very active in the Barnett shale near Fort Worth, Tex. In 2007, Devon drilled 524 wells there, and it anticipates drilling about the same number this year. The 2008 capital budget for the Barnett shale is $1.4 billion.
“The average cost to drill a horizontal well in the Barnett shale is about $2.5-3.5 million,” Devon said. “However, we continue to improve our efficiency and keep our costs in the play relatively flat. For example in 2004, the average Barnett horizontal well took 33.4 days from spud to rig release. In 2007, we averaged 16.7 days/well.”
In very general terms, Devon listed the following costs in descending order for an average Barnett shale horizontal well’s cost: stimulation, rig time, directional services, casing and tubulars, logging services, and drillbits.
