The Denver-Julesburg Basin Delights
By Clouser, Gary
Producers enjoy gas-manufacturing traits in the D-J Basin’s Wattenberg Field, a jewel in the crown for many companies. The venerable Denver-Julesberg Basin in Colorado and parts of western Nebraska is one of the key gas plays in the Rocky Mountain region, and it is important to a number of significant independents. Anadarko Petroleum Corp.’s production from its Wattenberg Field asset in the D-J of north-eastern Colorado ranks among the company’s top-producing assets. Noble Energy Co.’s Wattenberg assets are its largest in North America.
Wattenberg, says David Howell, general manager of Anadarko’s Wattenberg operations, is the “jewel” within the D-J.
David Howell
Anadarko Petroleum
“It is like a manufacturing plant operation, with predictable, repeatable, low-risk” drilling advantages, and its production has good margins, he says.
The entire D-J Basin has produced about 12.5 trillion cubic feet of gas equivalent (Tcfe) since its discovery in the early 1900s. Of that amount, the Wattenberg Field has produced about 3.5 Tcfe. Howell says recent downspacing provisions and advancements in fracturing technology will extend the life of the field for many more years. The D-J boasts about 20,000 active wells with about 11,000 of those in Wattenberg alone.
The top-five D-J producing companies for 2006, according to IHS Inc., a Houston-based data and services company, were all out of state: Houston’s Noble Energy and the old Kerr-McGee assets (now part of Anadarko); Petroleum Development Corp. of Bridgeport, West Virginia; Calgary’s EnCana oil & Gas; and Berry Petroleum Co. of Bakersfield, California. U.S. Exploration, which ranked 10th, has since been acquired by Noble Energy. Each company has a large Denver office.
Since December 2006, Petroleum Development Corp. has spent $170 million on acquisitions in the Wattenberg Field.
The largest producing county in the D-J Basin by far is Weld County northeast of Denver, says Brian Macke, director, Colorado Oil & Gas Conservation Commission. The number of approved applications for permits to drill in Weld County has been increasing during the past few years, spurred by higher gas prices and better frac techniques: in 2004, some 796 permits were issued; in 2005, there were 901; and in 2006, there were 1,418.
“The estimated number for 2007 is 1,550,” says Macke. “Given that, it should be reasonable to assume that oil and gas production from the D-J Basin should remain at or above its current levels for the foreseeable future, if there is no change in the current strong oil and natural gas price environment.”
Gas production in 2006 in Weld County alone was 180 billion cubic feet (Bcf).
Research and consulting firm Wood Mackenzie with its U.S. operations headquartered in Houston, projects gas production from the D-J for 2007 will be about 678 million cubic feet (MMcf) a day and top 705 million daily by 2011, compared with the 2006 volume of 654 million a day. Liquids production is a relatively flat 6,000 barrels a day.
While the volume of conventional gas from the D-J has declined sharply since 2000, the increase in production from tight gas has more than exceeded that decline, says David Haas, Wood Mackenzie analyst. Conventional gas volume from the D-J has decreased from 129 MMcf a day in 2000 to its current rate of about 30 million a day. But, tight-gas production has soared from 397 million a day in 2000 to current levels of more than 640 million a day, says Haas.
ANADARKO’S STORY
“The D-J is definitely an important part of our overall portfolio,” Howell says. “It’s one of the assets that we refer to as consistent and predictable. It is among other onshore properties that provide the balance for our higher-impact opportunities internationally and in the deepwater Gulf of Mexico.
“As far as production, the Wattenberg Field accounts for about a quarter of our overall production from the Rocky Mountain region.”
The field has been producing for more than three decades and has a ready supply of complementary field services and midstream assets, adding to its desirability.
Anadarko’s current daily production from its Wattenberg assets is about 255 MMcf equivalent. At year-end 2006, Anadarko’s Wattenberg assets contained about 1.5 Tcfe of reserves and had an unbooked net resource potential of an additional 1.9 Tcfe, Howell says. For second-quarter 2007, the D-J was second only to Algeria, among Anadarko’s main producing regions.
“Back in 2005, we were producing about 230 million cubic feet a day net,” Howell says. “So, you can see this is a fairly stable production base, and we expect to continue into the years ahead. We have a sizable inventory of economic projects-about 9,300 of them- including development activities, fracs and re-fracs.”
Top D-J Producers
Advancements in technology also continue to support the productivity of the field, operators say.
“It’s tight gas that we have extensive experience working with,” Howell says. “This is a play type we understand very well, which is part of the reason we consider this field to be predictable, consistent and repeatable. These are also relatively inexpensive wells to drill, and they respond very well to tracing and re- fracing.”
In second-quarter 2007, Anadarko spent about $60 million on its Wattenberg assets, up about 15% from the previous year.
In 2007, the company plans to drill about 250 wells in the Wattenberg area and operate five drilling rigs, two of which are coiled tubing rigs. At any given time, the company has about 50 drilling permit applications in the Wattenberg pending before the Colorado Oil & Gas Conservation Commission.
About 90% of Anadarko’s current Wattenberg production is coming from its Kerr-McGee acquisition, which was completed in August 2006. Anadarko already owned substantial mineral rights throughout the Wattenberg area, but gained the producing assets and complementary midstream position through the acquisition. That improved the operational margins of the play. Kerr-McGee was itself a top-three producer in the D-J Basin.
NEW FIELD RULES
Also making the play more attractive to Anadarko was the revision to Rule 318A of the Colorado Oil & Gas Conservation Commission. That rule increases the number of wells in each quarter section from five to eight per formation. The added down-hole density is credited with allowing for additional gas recovery.
Denver-Julesburg Gas Production
Kerr-McGee, Noble Energy and EnCana, as well as the Colorado Oil and Gas Association, a trade group, aggressively sought the rule, which went into effect in December 2005. At the time, the three companies boasted that they accounted for about 75% of the natural gas produced in the Wattenberg Field.
Directional drilling is frequently used in the Wattenberg as a result of the new rule. It reduces the environmental footprint by enabling companies to drill multiple wells from a single pad, minimizing the need for new roads and pipelines, Howell says.
He says Anadarko expects coiled tubing drilling to further improve its margins. The company started using coiled tubing drilling in the field in November 2006.
“The technique is quieter, more efficient and cost-effective than traditional drilling methods. As a result, there’s less impact to nearby surface owners because the rigs are on location for a shorter amount of time and they make less noise,” Howell says.
Completion operations using advanced fracturing techniques have enabled the company to greatly reduce its total water consumption. The low permeability of the Wattenberg tight gas lends itself well to re-fracing, Howell says.
Ted Brown, Noble Energy
NOBLE’S NEW MUSCLE
Noble Energy says greater reliance on D-J Basin assets fits in well with its strategy announced in 2003 to acquire a larger inventory of high return/low-risk projects for near-term growth. That strategy included selling its Gulf of Mexico shelf assets and acquiring Patina Oil & Gas (completed in 2005), U.S. Exploration Inc. (completed in 2006) and entering into a joint-venture drilling program with Teton Energy.
Noble acquired Patina for $3.4 billion and U.S. Exploration for $411 million. Production from its Wattenberg assets has thus grown 20% from 2005, and Noble Energy projects additional annual production growth of more than 5% in the next five years.
“We’re a different company,” Chuck Davidson, chairman and CEO, said at the company’s senior management meeting May 17, 2007.
“There’s no doubt in my mind. If you would have told me back in 2000 that we could wipe out 70% of the core production base and grow this company at 12% per year over the succeeding years, I would have just said you were nuts.”
“We’re currently producing about 250 million cubic feet equivalent in the Wattenberg Field, and we’ve had a pretty steady growth rate since 2005,” says Ted Brown, vice president, northern region for Noble Energy.
The annual growth rate has been about 10%, despite a short-lived dip early in 2007 because of weather-related delays. Noble Energy is operating eight drilling rigs in the Wattenberg. It plans to conduct more than 1,200 projects in 2007, on which it will spend about $430 million, Brown says.
“Resources continue to grow. We’ve almost doubled our proved and potential reserves since 2003,” he says.
Brown also speaks optimistically about coiled-tubing drilling.
“Basically, our expectation is to reduce drilling time in half. The potential to drill a 7,000-foot well in about three days is tremendous,” he says. The joint venture with Teton Energy, a Denver- based E&P company, also confirms the potential of the Niobrara formation found in the basin. That 20-well drilling project, intended to develop Teton’s assets in the eastern D-J Basin, has a success rate of about 88%, he says.
In all, Noble Energy’s gross production for the Teton project is about 1 MMcf per day with additional wells to be delivered to sales throughout the remaining portion of 2007. Currently in the Niobrara, Noble Energy has increased its acreage position to more than 380,000 net acres and is producing 23 MMcf per day, net to Noble. Overall, it expects to drill more than 150 Niobrara wells in the tri-state area of Colorado, Kansas and Nebraska in 2007.
Teton Energy has participated in the drilling of 42 wells on its 266,000 gross acre block, with a 25% working interest, the company said in a news release in August providing an operational update. Twenty of those wells are part of the initial pilot program, with Noble Energy as the operator. Plans for 2007 include the drilling of 90 gross wells, of which 22 have been drilled to date, and acquiring 50 square miles of 3-D seismic of which 12 square miles are in progress, says Dominic Bazile, chief operating officer and executive vice president of Teton.
In second-quarter 2007, the D-J contributed 6.4 MMcf, or 2.4%, of the total company net production. The company plans to spend $8.1 million in the D-J in 2007.
PDC’S GROWTH
Petroleum Development Corp.’s president, Thomas Riley, credits the company’s Wattenberg operations as being the “cornerstone” of the company’s dramatic growth during the past five years.
“PDC is extremely pleased with our production and reserve growth in the Wattenberg Field. Over 60% production growth is expected for this basin in 2007, and significant production and reserve growth is expected in 2008. This is a direct result of our ongoing drilling and re-frac programs, improved completion designs and our three acquisitions over the past 12 months,” says Bart Brookman, vice president of operations.
Most notable among those acquisitions was the $132.5-million purchase of Exco Resources’ Wattenberg assets.
PDC’s Wattenberg operations are its second largest, second only to the Piceance Basin in western Colorado. It has some 1,000 Wattenberg wells, 9,000 acres available for drilling and more than 450 undeveloped locations. The company has identified more than 1,200 projects for drilling, re-completions and re-fracs.
Its 2006 gross production rate was 40.6 MMcf a day. The company estimates its 2007 daily gross production rate will be 65 million.
Riley cites “predictable results” as a major benefit of its Wattenberg operations. PDC has a drilling success rate in the D-J Basin of 98%, and its average drilling time is five days per well.
PDC’s 2007 plan includes drilling 150 gross wells and 164 re- completions and re-fracs. Its Wattenberg capital expenditure of $100 million represents about 37% of the company’s total capital budget.
Denver-Julesburg Liquids Production
PDC also reports its eastern D-J Niobrara production in 2006 was 11 MMcf a day, and its estimated 2007 daily gross production will be 19 million. Its Niobrara capex for 2007 is $33 million. It expects to drill 140 wells and has 29,000 acres for drilling.
PRB’S FAST GROWTH
PRB Energy Inc., headquartered in Denver, is another producer reporting positive results from the Niobrara formation. It has drilled and cased 11 of the initial 12 wells drilled in the D-J Basin. Initial production rates per well will be about 200,000 cubic feet daily.
“The first two wells are on production, with the remaining nine wells expected to be on production by the end of the third quarter,” says Robert Wright, chairman and CEO.
“The Niobrara wells typically have a steep initial production decline and then will have stabilized production for a 20- to 30- year period. PRB is applying for 20 additional drilling permits.
“Plans calls for drilling approximately 50 to 60 shallow Niobrara wells in 2007 and approximately 140 wells in 2008. The total cost to drill and complete a well is in the range of $175,000 to $220,000, including the pumping units and flowlines,” he says.
PRB has increased its daily production in the D-J Basin from about 0.250 MMcf at the beginning of the year to about 1 million at press time as a result of the completion of the first two wells and installation of pumps on nine older wells. These are part of the 385,000 gross acres in the D-J that PRB purchased from Anadarko at the end of 2006.
“It is our plan to expand the gathering system in order to transport gas from our next round of drilled wells,” Wright says.
If future wells continue to show similar production rates to those already hooked up, and if PRB maintains its expected drilling schedule, the company believes its D-J production could be in excess of 6 million per day by early 2008, and more than 10 million by late 2008.
PRB expects to invest $10-to $12 million in capital drilling and completing wells in the D-J Basin in 2007 and $20- to $30 million in 2008.
“One of the benefits of the Niobrara play in the D-J is the ease and speed of drilling wells,” Wright says. “As a result, PRB currently is using only one rig in this area. That said, if we continue to experience the kind of success we’ve seen in the first several wells-and if the gas prices support ramping up production faster-we may add additional rigs.”
PRB is a different company than when it was formed in 2004 to capitalize on the need for midstream gathering to move the large amounts of coalbed methane (CBM) produced in the Powder River Basin. PRB has evolved into an exploitation and production company that also operates its own midstream gathering and processing.
“The conventional Niobrara play in the D-J provides immediate production and therefore provides diversification and an excellent strategic complement to our CBM wells,” Wright says.
Companies like PRB hope to benefit from better and less-volatile gas pricing in the future. Price improvement is critical if producers are to continue investing in the Rockies. The Rockies Express (Rex) pipeline is part of the solution for continued capital spending in the region. PRB, for example, is in the early stages of an aggressive drilling program in the D-J Basin in northeastern Colorado, the price risk of which should be reduced significantly as a result of the Rex line’s added capacity. The decision to pursue that opportunity and spend significant capital was influenced by the improvement in price and stability it expects of Rex.
“The completion of the Rockies Express pipeline will be a very positive development for natural gas producers in Colorado and the region,” Wright says. “As production has increased in the Rockies over the last couple years, lack of takeaway capacity has resulted in lower prices to producers in this region than those experienced elsewhere. The additional 1.8 billion cubic feet per day in takeaway capacity which Rex adds-a nearly 30% boost over current levelswill significantly increase access to nationwide demand for natural gas.”
BY GARY CLOUSER, CONTRIBUTING EDITOR
Copyright Hart Energy Publishing, LP Nov 2007
(c) 2007 Oil & Gas Investor. Provided by ProQuest Information and Learning. All rights Reserved.