E&P magazine hosted its BOMA (Brownfields: Optimizing Mature Assets) conference again in Denver, Colo., in another effort to bring state-of-the art techniques in front of the people who can use them. The least impressive thing about the conference was the name, brownfields. No one seems to like it, so we probably will beat a hasty retreat and rename it next year. Recommendations gratefully encouraged.

The conference was good enough this year that we’re going to publish snapshot views of the presentations in the January issue of the magazine. We think you’ll like what you see.
In the spirit of scooping the competition — even if the competition is our own January issue — let’s take a snapshot look at some of the snapshots of the presentations.

How much can you improve existing assets? Dr. Don Wolcott, president of E&P Aurora Oil & Gas Co., has a pinch of experience. He handled three mature fields at Yukos, fields in which production had plunged from 2 million b/d to 800,000 b/d from 1986 to 1999. When oil prices fell, investment stopped. When he came in, 14,000 wells averaged 65 b/d of oil. By the time he finished, Yukos produced four times as much oil from half as many wells through a system of workovers and tuning waterfloods. Reserves climbed to 16.9 billion bbl from 11.4
billion bbl with a finding and development cost of US $1.07/bbl.

The secret? Find out what you’ve got, calculate the potential and fill in the gap.
Brian Hageman, chief executive office of Deluge E&P Corp., described his natural energy engine for oilfield pumps. It uses warm and cool water to expand and contract liquid CO2 in a chamber with a piston to lower pumping costs, a major oilpatch expense.

Jim Lea of PLTech LLC said some 830,000 wells in the United States depend on artificial lift, and operators spend a little less than $4 billion a year on artificial lift.

The industry is on a quest for more production, fewer failures and greater efficiency, and that involves more reliable equipment and matching equipment to specific tasks.

Jim Mack, president of TIORCO Inc., has treated more than 500 producing wells for the oilfield’s number one expense, dealing with produced water. Water isn’t bad. A waterflood can raise production from a field from 10% to as much as 40% of the oil in place, but at some point the expense grows too great. Per-barrel expenses for water include 12 cents for de-oiling, 10 cents for lifting, 16 cents for pumping, 8 cents for filtering and 3 cents for injecting. Designer wells can mitigate water incursion, but at some point it gets to be too great a problem and requires control, often in the shape of polymers to help the sweep and gels to shut down fingering to the well bore.

He’s seen treatments cut water production by 75 to 90% with a 50 to 100% oil production increase. He’s seen payout in 30 to 180 days, and success rates range from 60 to 90%.
Bryan Dotson, deliquification project leader for BP, came to the conference with a challenge, not a solution.

BP’s gas wells, like everyone else’s, load up with water or condensate in the well bore, restricting gas flow. He wants a little solution. He wants a pump that will draw 10 b/d of liquids from the bottom of a 10,000-ft (3,048-m) well in high-permeability reservoirs. That should require only 3¼4 of a horsepower, but most existing solutions work off higher-horsepower motors with higher operating costs.

A $150,000 net present value cost to get 200 Mcf/d with a 1-year payout on $4 gas won’t do the job. But if the industry can draw the cost down to $120,000 on 4,000 wells, it could add 300 MMcf/d of production and create a $500 million market. He thinks industry can lower that lifting cost to $60,000.

Roy Long, technology manager at the National Energy Technology Laboratory, listed some cures for the high cost of keeping existing reservoirs producing at maximum levels, including coiled tubing (CT) and microhole drilling for lower cost and less rig time.

Steve Melzer, owner of Melzer Consulting and an expert in CO2 flooding, described designs and techniques that work, particularly with an average CO2 cost of $19/bbl and oil prices around the $60/bbl mark. Shell even has a spreadsheet program that will calculate the
net present value of a CO2 flood.

Probably the most enthusiastic speaker at the conference was Tom Wood, chairman of Xtreme Coil Drilling Corp., who makes hybrid CT and top drive drilling rigs. Shallow wells in Canada that cost $65,000 with a conventional rig could be drilled for $29,000 with a CT rig. In one area, a CT rig drilled three wells a day while a conventional rig managed one a day.
In 2006, he estimated, CT will drill between 7,500 and 9,000 wells.
Oldsters advise youngsters about to go off on a risky venture, “Don’t give up your day job.” Makes sense.

That’s solid income with chances for improvement. It’s the same way in the oilpatch. Don’t give up your mature asset. Techniques and technology are on the way to improve field lives and production.