Production optimization at the well level and at the field level helped Joe Bridges and Michael Geffert reap an enviable profit for themselves and their investors in an existing Louisiana field.

“We paid handsomely for this field, but we got a handsome return in the end. You had to do a lot of work to make sure you were right,” said Bridges, co-managing partner with Geffert at Greystone Oil & Gas LLP.

Production optimization takes many forms since circumstances vary among fields, but solid

A field production graph shows Sligo’s normal decline, increases from artificial lift in blue, increases from workovers in green and increases from new wells in red. (Graph courtesy of Greystone Oil & Gas LLP)
techniques and the right timing offer any operator opportunities in the oil and gas business, if that operator is willing to do the work.

The two men started their alliance at Kelley Oil, Bridges as president and Geffert as senior vice president of exploration and production. Some of that company’s prime properties were in Webster and Bienville parishes in northern Louisiana, located immediately east of and adjacent to Sligo field in Bossier Parish. Most of Kelley Oil’s north Louisiana production came from the Hosston and Cotton Valley formations. Sligo field also produces from the Hosston and Cotton Valley formations.

Sligo field
When they formed Greystone, they took a close look at the areas where they had experience, and they liked what they saw at Sligo field, which was operated by several producers at the time, but the main operator was Pennzoil.

When they examined the decline curve for the field over 10 years, Bridges said, it looked like a normal decline curve for a field with a steady rate of decline. The presence of gas behind pipe wasn’t obvious. They had a feeling that the field could produce more than it was producing, and in 1995 they started a year-long evaluation of the field. They mapped every horizon and calculated natural gas volumes using publicly available state data on some 200 wells.

“The key to any success story is doing your homework. We had time to correlate logs and reservoirs. We pulled monthly cards for every well. We also pulled the old perforation records, (also on cards) from the Shreveport, La., district office of the Louisiana Oil & Gas Conservation Commission) Geffert said.

It’s a formula that has worked well for ages. They found out what the wells were producing. They calculated how much they could produce, and they figured out how to fill in the gap.
They calculated the original gas in place and detailed how much gas had been produced from each of 65 to 70 horizons in the field.

By the end of the exercise, they determined a lot of gas remained behind pipe. Bridges and Geffert proposed a purchase to Pennzoil in 1996 and got no response, but they persisted with repeated offers as it looked like Union Pacific Resources might buy the company, through Pennzoil’s spinoff of PennzEnergy and finally when the field ended up in the hands of Devon Energy. Devon turned down their first offer.

The partners had done the hard homework; they had the experience to recognize opportunity and develop their plans. All they needed was the right timing.

Two events provided that timing. The World Trade Center disaster on Sept. 11, 2001, created a lot of uncertainty in the markets and sent gas prices as low as US $2.04/MMBtu as the February 2002 futures contract closed, Bridges said.

At the same time, Devon’s stock was suffering as the company had purchased a large number of high-potential assets that weren’t yet producing. Wall Street analysts urged the company to sell some properties.

It sold its Sligo field holdings to Greystone for $131 million. The deal came together in a hurry, but the partners were able to connect with First Reserve and Shell Capital for help with the financing.

At the time, Greystone’s section of the field was producing about 9.5 MMcf/d of gas. “We paid a record price in dollars per Mcf of daily production. That record held until just lately. But we had put in a lot of work to make sure we were right, and that work gave us the confidence to make the acquisition,” Bridges said.

Everything didn’t work that smoothly. “We felt that Pennzoil had left so many gas/condensate-bearing reservoirs behind pipe, we could simply recomplete the wells,” Geffert said. Instead, they found many wells with no, or little, cement behind pipe, or too many packers to drill through and poor pipe integrity. In short, they found conditions that made recompletions and aggressive fracturing impossible in many of those older wells.

Even with work, those wells were producing at only a third of their projected production rates. That led to a lot of soul searching. The partners recalculated their volumetrics. “We redid everything,” Bridges said. They went back and collected all of the logs on the deep wells in the field and ran a NuTech evaluation on each of the wells. NuTech evaluations gave them porosity and permeability values for every sand in every well. They used these foot-by-foot porosity and permeability values in their isopachs to recalculate the volumetrics of each reservoir across the entire Sligo structure.

After reallocated production, they obtained the material balances of each reservoir. The new calculations verified that they still had 500 Bcf of gas in the Hosston, so they decided their initial calculations were correct.

Those poor results that they obtained from the initial seven wells that they recompleted, however, suggested the partners needed to change their approach to production.
They had increased production with the recompletions, but results convinced them they needed to drill new wells. “When we started drilling, [production] really shot up,” Bridges said. Those weren’t just random holes.

At the north end of the field approximately 50% of the reservoirs tested came in at virgin pressure. At the south end approximately 65% of the reservoirs tested came in at virgin pressure. The balance of the reservoirs at both ends of the field tested at at least 50% of original pressure.

The partners were certainly pleased, but they weren’t surprised. That was the kind of production potential the volumetric studies told them they should expect.
They then put their work program in place on existing wells that weren’t scheduled for recompletions by installing artificial lift equipment on existing wells with high potential.

They put Pacemaker plunger lifts on some wells to get rid of load water, and they put beam pumps on wells with bigger loading problems.

The USA 1 well represented the best of what they expected. Ten years before the acquisition, the well had been producing 1.3 MMcf/d of gas, but production had steadily dropped to 300 Mcf/d after producing 38 Bcf from five Hosston intervals. An analysis showed the well was loading up with water. The more it loaded up, the more production it smothered. They spent $50,000 on a pumpjack, installed the unit with the sucker-rod pump below the production perforations and pumped the water off the well. It took seven weeks to dewater the reservoir near the wellbore, at which time the well returned to the producing rate of 1.3 MMcf/d, a level it hadn’t recorded for a decade.

“This well had the best post-workover results of all of the wells that we worked over, though we did the same thing on quite a few other wells which also had great production increases,” Geffert said. Pumping off water to cure loading problems halted the field decline and added 10 to 12% to production.

By the time they finished with the workovers and modifications to existing wells, the modified wells alone produced 40% more than the total production from Greystone’s segment of the field when they bought it.

Most of the field’s production had come from the Hosston, but as the project progressed, they turned their attention to the Cotton Valley zones in Sligo field. The partners found the Bodcaw, Davis and Taylor zones in the Cotton Valley in the north end of the field still held virgin pressure, and these reservoirs, along with the Cotton Valley “D” in the south, maintained virgin pressure.

As they drilled new wells, they took cores to verify the producibility of the reservoirs. In the Bodcaw, they saw high resistivity on top of low resistivity on logs. In most cases that would indicate gas above the water. The cores helped prove that, in this case, the low-resistivity lower portion of the formation contained thin bedded sands between thin bedded shales. The result was that they were able to prove that the entire Bodcaw reservoir was gas-productive.

They were able to test 1 MMcf/d to 2 MMcf/d from each of the Bodcaw, Davis and Taylor formations, though when commingled, the formations flowed for 2 MMcf/d. But production would last longer.

The best new well tested at 6 MMcf/d of gas from the Hosston. It was dualed with a 2 MMcf/d Cotton Valley completion.

In both the north and south ends of the field, they tapped the virgin pressure in the Cotton Valley. “That was probably 100 Bcf of gas we added to our reserve base from the Cotton Valley,” Bridges said.

As they expanded operations, they bought Murphy Oil Corp.’s stake in another part of Sligo field. That was Murphy’s last onshore US property.

They invested $55 million in the property. That included a 40 MMcf/d propane refrigeration unit at the north end of the field, a pipeline joining the two ends of the field and more compression. It also included a new high-pressure gathering system for the new wells to work with the existing low-pressure system for existing wells.

The partners bought the field with 9.5 MMcf/d of production for $131 million in March 2002. They sold it in May 2004 to Chesapeake with 61 MMcf/d of production while also completing recently drilled wells and drilling additional wells with three rigs running.

“We thought there was potential for 130 MMcf/d,” Bridges said.

Chesapeake said it bought the field for $425 million, and that company continues to develop the potential of Sligo.