Since acquiring the 8,100-acre North Westbrook Unit in 2005, Energen has grown production from 900 barrels of oil per day to some 4,900 barrels today. Here’s how it brought new life to the play.

It takes a special talent to bring back a decades-old oil field to production beyond its former glory. But Energen Resources Corp. accomplished just such a feat in the Permian Basin’s North Westbrook Unit, in Mitchell County, Texas. In recognition of its impressive waterflood work to enhance oil recovery in the play, the E&P subsidiary of Birmingham, Alabama-based Energen Corp. has earned Oil and Gas Investor’s Best Field Rejuvenation Award for 2009-2010.

In a historical note, the North Westbrook Unit, in 90-year-old Westbrook Field, includes #1 Abrams, the Permian Basin’s first commercial producer. Thanks to Energen’s operating acumen, the original 1920s-era wellbore continues to produce in ever-increasing quantities.

The bulk of the company’s 1.55 trillion cubic feet equivalent of natural gas, oil and liquids reserves are in the San Juan Basin in New Mexico and Colorado, the Permian Basin in West Texas, and Alabama’s Black Warrior Basin. Energen has built its subsidiary into a Top 25 independent (based on U.S. proved reserves) over the past 14 years, primarily through acquisition and exploitation of proved reserves with development potential.

Says James McManus, chairman and chief executive, “In rejuvenating a true Permian Basin legacy, our staff continues to demonstrate the technical expertise and ability that allow Energen to extract value following an acquisition.”

Westbrook Field was originally discovered in 1920. “Many people think the first well was the Santa Rita well, but it really was the #1 Abrams, which is actually in the Westbrook Southeast Unit,” says Joe Niederhofer, Midland, Texas-based general manager of the Permian operation. “It is still producing today. It’s kind of a monument out there, and we keep it painted and in good condition.”

North Westbrook was first developed by Standard Oil as a Middle Clear Fork formation play. In 1968, then-operator Chevron Corp. unitized the field, ramped up technical work and began secondary recovery with waterflooding. The field peaked in the mid-1970s at about 5,500 barrels of oil per day.

Chevron continued infield drilling from the late 1970s until 1985, adding more producers and injectors, and restoring production to 5,000 barrels daily. But development work fell off, and the field declined to some 600 barrels per day, until the fall of 2003.

That year, private-equity-backed Enervest Management Partners acquired Westbrook field. It drilled infield wells, completed others, and drilled the Upper Clear Fork formation to ramp up production to nearly 900 barrels per day by 2005, then production declined.

Joe Niederhofer

“Each year, with our successive drilling programs of both injections and producers, we’ve increased our oil production,” says Joe Niederhofer, Midland, Texas-based general manager of Energen’s Permian operation.

“We have several fields in this area, including the Westbrook Southeast Unit and the North Westbrook Unit, which are adjacent to each other,” says Niederhofer. Before purchasing North Westbrook, Energen reviewed its successes at the Westbrook Southeast Unit and determined it could translate that strategy and technology to the new asset.

The E&P purchased the Westbrook Southeast and North Westbrook units in late 2005 for $168 million and took over field operations in January 2006. Energen used available cash and existing lines of credit to pay for the acquisition, and repaid the associated short-term borrowings with internally generated cash flow by year-end 2006.

The bulk of the company’s 1.55 trillion cubic feet equivalent of natural gas, oil and liquids reserves are in the San Juan Basin in New Mexico and Colorado, the Permian Basin in West Texas, and Alabama’s Black Warrior Basin.

By that time, there were 158 Clear Fork and 31 Upper Clear Fork producing wells, with 56 injector wells. The upper formation was, and still is, on primary production.

The Middle Clear Fork is on waterflood-enhanced production.

In 2006, the company planned additional infield producing and injection locations and starting drilling the first new well in April. It drilled 32 producers and 30 injectors.

Says Niederhofer, “The wells are about 3,300 feet deep and all of our wells are fracture stimulated. Our engineering, geological and operations teams looked at how we could include the Upper Clear Fork into the units to combine the upper and middle formations. That would increase the economies of scale and access more pay zones.”

By the end of 2006, Energen was producing 1,550 barrels of oil daily from the field.

Yet, in 2007, it concluded the unit was still under-injected. It launched additional drilling, with three fresh-water supply wells, five disposal wells, 82 injectors and 37 producers.

New Approaches

“Through our technical work in the southeast and north units, we felt that formation damage could prevent the injectors from obtaining good sweep efficiencies, so we implemented an aggressive water-quality program,” he said.

“We installed a new fresh-water injection station with new pumps and filtration equipment, and made sure that the injected water was extremely clean. That maximized the sweep efficiency through the reservoir.”

In addition to the water system, Energen installed automation similar to that at its southeast unit. The new systems incorporated SCADA monitoring, pump-off control systems (Energen builds its own) and well-failure analyses programs to keep wells online longer, reduce lease-operating expense and increase production. By the end of 2007, Energen was producing slightly more than 1,920 barrels per day and had reduced its well failures by 50%.

Then it filed with the Texas Railroad Commission for unit expansions to include the Upper Clear Fork, gaining approval in 2008.

“We got busy drilling 44 injection wells and 48 Upper and Middle Clear Fork producing wells, using the same wellbore for each,” says Niederhofer. “We also started a pay-add program by adding Upper Clear Fork to some existing middle formation wells in what we identified as a core development area for this field. But we still needed to figure out how to expand that core area.”.

By year-end 2008, Energen had increased production to 3,350 barrels per day. It began expanding the boundaries of the field within the unit by identifying new pay zones using advanced log analysis. In 2009, it drilled 90 producers and 24 injectors, completed 45 Upper Clear Fork pay adds, and further expanded its waterflood. Energen’s year-end 2009 production reached 4,150 barrels of oil per day.

“Altogether, from the time we acquired the property until early 2010, we drilled 207 producers, 180 injectors, completed 90 Upper Clear Fork pay adds and had full field automation,” says Niederhofer. “For four years, we have been very busy with this project.”

At press time, Energen was producing 4,550 barrels per day. Although the associated gas is minimal in the field, the company is producing 350,000 cubic feet per day.

Today, its cost to complete Upper and Middle Clear Fork producing wells averages $543,000 each, with injection wells pegged at some $393,000.

What’s Next

“We’ve looked at doing some horizontal wells as part of the technical evaluation, but we have not drilled any yet,” Niederhofer says. “We will continue to keep that possibility on the drawing board in 2010.”

Meanwhile, Energen plans to drill another 70 producers and 30 injectors this year and is pilot-testing a waterflood in the Upper Clear Fork formation. It will continue to increase water injection and field automation, and plans to down space from 20-acre spacing to 10.

“Also, we aggressively run step-rate tests to determine the maximum injection pressure for the reservoir, to keep injection in the pay zone, and to improve efficiencies,” says Niederhofer.

“Each year, with our successive drilling programs of both injections and producers, we’ve increased our oil production,” he adds. “We continue to be very successful with our secondary-recovery techniques. I don’t think we’ve reached the maximum potential of the field yet.”

Including all assets, the company’s estimated 2010 production is 5.5 million barrels of oil, 74.8 million gallons of gas liquids and 70 billion cubic feet of gas. It has about 3.5 trillion cubic feet equivalent of proved, probable and possible reserves.