Efficiency Gains Keep Oil & Gas Production Rising in the Face of Lower Prices

Written by John Egan for Industrial Info Resources (Sugar Land, Texas)--Over the past year, U.S. Oil & Gas Producers have used a variety of techniques--both at headquarters and in the field--to slash costs and increase production in the face of a 40% decline in oil prices. Last summer, about 1,545 rigs were drilling for oil in the U.S. and production was about 8.63 million barrels of oil per day (BBL/d). Now, the oil rig count has fallen roughly 59% to about 634, according to Baker Hughes Incorporated (NYSE:BHI) (Houston, Texas). But over the past year, oil production has increased about 11%, or 1 million BBL/d, to about 9.6 million BBL/d, according to the U.S. Energy Information Administration (EIA) (Washington, D.C).

One response to falling oil prices is for producers to drill only their most promising onshore properties, called "high grading." This is a short-term way to cope with falling oil prices: drill and complete only those wells that are economic at current prices. Production from shale formations can increase rapidly if prices warrant it. There are between 2,500 and 3,000 drilled but uncompleted unconventional wells in the U.S. today, according to Stephen Trammel, director of unconventionals research at IHS Energy, a unit of IHS Incorporated (NYSE:IHS) (Englewood, Colorado).

High-grading of properties has helped the industry more effectively deploy its capital, which in turn lowers breakeven points, IHS noted in a recent study. Higher-cost plays with higher break-even prices have been put on the shelf. Companies are focusing their drilling in larger, better-established shale plays like the Permian Basin, Eagle Ford Shale and Bakken Shale. More speculative plays, like the Mississippian Lime, are being put on the back burner.

In its recent study, "Strong Capital Efficiency Gains Mitigating Damage to E&P Companies," IHS said it expects U.S. exploration and production (E&P) companies to post a 25% to 30% gain in the average efficiency of onshore upstream capital investment in 2015, when compared with 2014.

Another response to low oil prices is harder negotiations between oil producers and oilfield-service companies. Drilling and completion costs have fallen as operators pay less for rig rates and frac sand, among other things. Depending on the well and the formation, well-drilling and completion costs have fallen by 15% to 40% since mid-2014, and by yearend 2015 those costs are projected to fall another 15%, IHS estimated in its recent study.

Another consulting firm, Wood Mackenzie (Edinburgh, Scotland), recently estimated these efficiency gains could shave $10 to $15 off the cost to produce a barrel of oil by mid-2016. Analysts at Wood Mackenzie credit greater experience with the reservoir dynamics there; more efficient drilling of horizontal wells; faster pressure-pumping systems; and better technology. As operators experiment with different mixtures of hydraulic fracturing fluids, they are getting a better understanding of what works in different formations, thus increasing production, and shortening drilling and completion times. They also are drilling longer laterals, making better use of information technology, and using different drill bits.

The monthly Drilling Productivity Reports from the U.S. Energy Information Administration (EIA) (Washington, D.C.) show oil and gas produced from new wells is growing rapidly. The newer wells feature multi-well pads, improved fracking techniques and better fracking technologies, all of which shave days off a well-completion time.

For example, new gas wells drilled in the Niobrara Shale are producing about 38 thousand cubic feet per day (Mcf/d) more than legacy wells. New Eagle Ford Shale gas wells should average 43 Mcf/d more to wells drilled a few years back. In the Haynesville Shale, new gas wells are producing about 34 Mcf/d more than earlier generation wells. And gas production from new wells drilled in the Marcellus Shale yield an average of 46 Mcf/d more than before.

On the oil side, the results are similar. In the Bakken, new wells produce an average of 23 more barrels per day than legacy wells. In the Eagle Ford, production from new wells is up about 22 BBL/d. Wells drilled in the Niobrara Shale produce 13 BBL/d more than their predecessors there.

For more on companies that are using efficiency gains to produce more oil and gas with less capital outlays, and thus compete in the current price environment, see May 21, 2015, article - Chesapeake Energy Spends Less to Produce More Oil & Gas; March 9, 2015, article - Gulfport Energy: Production in Utica to Continue Increasing, Despite Sharply Lower Capital Spending for 2015; and March 6, 2015, article - PDC Energy's 2015 Outlook: Spend Less, Produce More.

Anadarko Petroleum Corporation (NYSE:APC) (The Woodlands, Texas) is one of several oil producers that reported strong production gains in recent quarters, driven by lower costs and improved efficiencies. Between fourth-quarter 2014 and first-quarter 2015, the company cut by 15% its cost to drill a well in the Denver-Julesburg Basin, from $4 million to $3.4 million. It also shaved several days off its drilling-to-spud time in the Eagle Ford Shale.

Improved drilling and operating economics pushed Anadarko's production to a record of 65 million barrels of oil equivalent (boe) in the first quarter, an increase of 59,000 boe per day over fourth-quarter 2014 results. Most of those gains were from liquids produced in the D-J Basin and Eagle Ford Shale. Buoyed by higher well performance, the company recently raised its full-year production guideline by 5 million boe--to a range of 300 million to 306 million boe, up from a range of 295 million to 301 million boe made earlier this year.

In the Eagle Ford, Statoil ASA (Stavanger, Norway) has reduced the number of rigs by 33%, yet its production there has grown 33%, according to The New York Times, which credited different grades of sand, varying well depths and new well chokes that technicians can operate remotely from a computer--or even a smartphone--to quickly adjust flows to maximize production without overtaxing pipelines.

The Times reported Statoil has cut the average cost of drilling a well from $4.5 million to $3.5 million, in part by reducing the time it takes to drill from an average of 21 days to 17 days. Better planning and reduced use of less-efficient crews helped the company reduce drilling time 19% in the Eagle Ford.

"There's a proverb in Norway that says necessity teaches the naked woman how to knit," Bjorn Otto Sverdrup, a Statoil vice president, told the Times.

Whiting Petroleum Corporation (NYSE:WLL) (Denver, Colorado) has increased well productivity in the Bakken Shale by 28% in recent months by, among other things, installing new speed controls on its well pumps, which lowered equipment repair down time by 48%, the Times added.

Earlier this year, Hans-Christian Freitag, vice president of technology for Baker Hughes, told the Associated Press, "Everybody has gotten a little more imaginative, because they need to."

"Mark Twain once said, 'the reports of my death have been greatly exaggerated,'" said Jesus Davis, Industrial Info's vice president of research for Oil & Gas Production, Pipelines and Terminals. "I think that applies to U.S. companies operating in shale formations. Advances in technology and techniques, coupled with declining input costs, are allowing the nimblest to increase production with less capital spending. Lower prices have taken their toll on the earnings of these producers, but not their production."

Industrial Info Resources (IIR), with global headquarters in Sugar Land, Texas, five offices in North America and 10 international offices, is the leading provider of global market intelligence specializing in the industrial process, heavy manufacturing and energy markets. Industrial Info's quality-assurance philosophy, the Living Forward Reporting Principle™, provides up-to-the-minute intelligence on what's happening now, while constantly keeping track of future opportunities.