COSTS OF ADDING RESERVES SLIDING IN THE U.S.

Bob Tippee
Managing Editor-Economics and Exploration

Bob Beck
Economics Editor

Exploration and development in the U.S. aren't what they used to be.

They're cheaper.

U.S. operators are using a broadening range of technologies and strategies to make their operations ever more efficient and, in relation to volumes of oil and gas added to reserves, less costly.

To be sure, it costs more in absolute terms to drill and complete an average U.S. well now than it did two decades ago. It costs more to drill a foot of hole.

In inflation-adjusted terms, however, the cost of finding and developing a barrel of oil or a million cubic feet of gas through drilling was nearly as low in 1989 as it had been in the mid-1970s. And the trend is down.

Real costs per unit of reserves added peaked in 1982, end of the most recent drilling boom (see Table 1). By 1989, latest year for which the full range of data is available, they had fallen to levels comparable with those of 1975.

Part of the explanation comes from well cost declines since the boom ended.

Unadjusted for inflation, drilling and completion costs averaged $514,378/well in peak year 1982. The average in 1989: $362,243/well. in 1970, the cost averaged about $95,000/well.

Average cost per foot drilled last year was $73.59, compared with $108.73 in 1982 and $18.84 in 1970.

To a large degree, the cost declines since 1982 reflect price reductions for oil field services, supplies, and equipment during the drilling slump of the mid and late-1980s.

But something else is happening. Operators in the U.S. are finding more oil and gas for each well and each foot of hole that they drill than they have at any time since the early 1970s.

In 1989, operators added reserves at the rate of 90,954 bbl of oil equivalent per well completed. That's the highest rate since 1973.

In relation to the amount of hole drilled, oil equivalent reserves additions-excluding revisions and extensions-occurred at a rate slightly exceeding 20 bbl/ft in 1989, highest since 1971.

The improvements come despite maturation of the U.S. as an exploration province. Accessible prospects on average are shrinking or becoming more difficult and expensive to find and develop. Operators are bucking the trend by steadily improving the efficiency of their work.

MANY FORMS

Efficiencies take many forms-from risk management to organization to technology.

It's clear from drilling statistics that U.S. operators have tried to pare their risks in recent years.

As a group, they've shifted their emphasis to development and infill wells from wildcats.

In the 1970s, 24% of the 370,734 wells completed in the U.S. were exploratory wells. Of the 595,267 wells drilled last decade, less than 19% were exploratory.

"We're concentrating on things that are a little less risky," says J. C. Burton, until recently senior vice-president, production, of Amoco Production Co.

A traditional leader in U.S. exploration and development but with a growing international emphasis the last 5 years, Amoco domestically is "drilling more of the sure thing," says Burton, now group vice-president, international.

Many companies are confining activity to areas with which they're familiar.

Louisiana Land & Exploration Co., for example, has become "extremely focused in plays and trends where we've had some success," says John F. Greene, executive vice-president, exploration and production. In the U.S., those areas are the Gulf of Mexico, South Louisiana, and parts of Oklahoma and the Rocky Mountains.

Like most operators, LL&E makes reserves replacement and cost targets a matter of strategy. Three years ago, the company set goals of 110%/year for reserves replacement and $5/bbl of oil equivalent for finding and development costs.

Since then it has replaced 140% of its reserves at $4/bbl of oil equivalent. Of that, 80% is "off the bit," Greene says. Last year, LL&E added reserves equivalent to 204% of its production at a finding and development cost of $3.23/bbl of oil equivalent.

In addition to focusing on familiar areas, LL&E has created what Greene calls a "team environment" that uses computers to help meld the efforts exploration and production professionals who formerly tended to work in isolation. Now, says Greene, geophysicists, geologists, petroleum engineers, landmen, and other professionals "are working out of a common database."

Phillips Petroleum Co. has been using a similar concept for several years, functioning through what it calls interdisciplinary work teams to coordinate technical skills of its personnel.

It also has a program called "operation clean sheet" that reduces paperwork requirements to "let our engineers do more engineering and our geologists do more geology," says Rick Mott, manager of planning for exploration and production.

In one of its first applications of the integrated work team approach, the company analyzed field data and identified new drilling targets to help reverse a gas production decline on Gulf of Mexico High Island Block 160, which it holds in a 50-50 partnership with Shell Oil Co., the operator. Consequent drilling tripled the field's reserves and raised production net to Phillips from less than 5 MMcfd in 1984-85 to about 35 MMcfd in 1989.

In another project, a Phillips integrated work team analyzed field data from Ada gas field in Bienville and Webster parishes, La., to identify development opportunities. Development work under the program pushed production to more than 80 MMcfd last year from less than 10 MMcfd in 1986.

Mott estimates Phillips' finding and development costs in the U.S. at less than $3/bbl of oil equivalent.

FINDING A NICHE

Like many other operators, Maxus Energy Corp. tries to "find our niche out there in the business," says Butch Bagley, vice-president of North American operations. In addition, Maxus in 1989 reorganized to improve efficiency, consolidating decision-making functions in its Dallas headquarters. One aim is to facilitate communications between Dallas and the field.

"A field guy can call in and talk to Butch if he wants to," testifies Kent Rogers, Maxus division operations engineer for offshore operations.

Maxus focuses on Gulf of Mexico prospects it can operate in water no deeper than 200 ft. It also works in the Texas Panhandle and parts of the Midcontinent.

A key element of its offshore strategy is holding to a minimum the turnaround time between drilling of a discovery and first production.

In a discovery at the high end of its water depth range Maxus typically moves a platform jacket onto location within 6 months, drills development wells through the jacket with a jack-up, and is ready to begin production soon after the deck and facilities are installed.

It usually can bring discoveries in 200 ft of water on stream in 1-1 1/2 years. It expects turnaround time of a late 1990 discovery on Main Pass Block 181 in 136 ft of water to be about 1 year.

Maxus last year replaced 113% of its 1990 U.S. production at a finding a development cost of $5.55/bbl of oil equivalent.

Phillips, too, has tried to streamline exploration and development decisions in order to bring discoveries on stream faster, Mott says. In April it will start production from South Marsh Island Block 147 in the Gulf of Mexico. It acquired the lease just 2 1/2 years ago.

Flow from the field, in 180 ft of water, will peak at an estimated 96 MMcfd of gas and 5,500 b/d of oil and condensate.

BEYOND STRATEGY

The biggest improvements in U.S. exploration and development efficiency, however, come from technology.

Advances in completion technology, for example-along with a tax credit for unconventional fuels-have stimulated drilling for methane in coal seams, especially in the San Juan and Black Warrior basins.

But overall technological progress is most evident in horizontal drilling, which accounts for a growing share of U.S. rig counts and completion totals.

The advantages by now are well known: A successful horizontal hole develops and produces reserves that otherwise would require several vertical holes-if vertical holes could develop the reserves at all. The improved recovery rate more than offsets the higher costs of drilling horizontally.

Horizontal drilling doesn't work everywhere. But it has accelerated development of a host of individual exploration and drilling technologies that are improving efficiencies in other applications: improved seismic data acquisition and interpretation, computer integration of operations, measurement while drilling, and bit improvements, to name just a few.

Seismic technology is developing rapidly in conjunction with the growing power and sophistication of computers. Nontraditional acquisition geometry, such as vertical seismic profiling and cross-hole tomography, is becoming more common.

And three dimensional seismic techniques have become standard ways for operators to pinpoint drilling targets, even to spot targets they otherwise wouldn't have seen.

Amoco's Burton attributes his company's important Choctaw thrust gas play of Southeast Oklahoma to 3D data acquisition and interpretation.

Phillips, among others, is using 3D seismic and other technologies to take advantage of existing leases and infrastructure. In mature fields of the Permian basin, 3D surveys have highlighted compartmentalization and other reservoir characteristics to help the company plan waterfloods and other development work.

Exxon Co., U.S.A. credits improved seismic interpretation capabilities with its recent 300-500 bcf Chalkley Deep field deeper pool natural gas discovery in South Louisiana.

The company used reinterpretation of seismic data acquired in 1986 to identify an Oligocene Upper Frio Miogypsinoides structure below 14,000 ft in an area already producing from reservoirs shallower than 10,000 ft. Chalkley Deep can produce 120 MMcfd.

A TASK FORCE APPROACH

Blending the team approach and seismic technology, BHP Petroleum (Americas) Inc. recently formed a small group to, in the words of the group leader, "attack the key geophysical problems."

The group, explains Warren Franz, corporate manager of geophysical technology, "takes technology which is here but may be underutilized and then gets it into application within BHP as quickly as possible." Its scope is global.

Work so far has focused on applying computer modeling to improve offshore data acquisition, new multiple attenuation techniques, and prestack depth migration.

BHP uses computer models to "match the acquisition methods to the geological problem that we want to solve," Franz says.

BHP can run several simulations via computer models in the time it takes to conduct a single real shoot-and for much less cost. Results help the company determine how best to deploy air guns and receivers, saving time and money spent on operations at sea and ensuring that BHP acquires the cleanest data it can.

To improve multiple attenuation-suppression of a type of false reflection common in seismic data-the BHP group is experimenting with what Franz calls "full elastic wave modeling."

Computer models of the earth produce data including multiples that can be compared against actual seismic reflection data. "The comparison helps us design special algorithms to help improve signal to noise ratios," Franz says.

And the group has begun to use prestack depth migration where velocity anomalies so distort returning waves that normal common-depth-point stacks are misleading. The technique requires super computers to pull prestack data together in depth rather than time, using subsurface velocity information from well data or whatever sources are available.

Like many other companies, BHP relies increasingly on 3D techniques.

"We're just shooting gobs of 3D in the Gulf of Mexico and elsewhere," Franz says.

DRILLING TECHNOLOGY

Drilling technologies are developing on a variety of fronts, with much of the activity spurred by horizontal and directional applications.

Downhole motor durability is improving. Units now typically last 100-200 hr instead the 30-50 hr common just a few years ago.

Rig and offshore platform automation is advancing. And there have been experiments with reverse circulation drilling and air drilling for high-angle and directional holes.

A rapidly advancing technology scoring significant efficiency gains for operators is measurement while drilling (MWD).

The technique is now common for deviated wells offshore, although Amoco, for one, frequently employs it in straight holes onshore.

Offshore, says Rogers of Maxus, MWD can save 2-3 days in logging time alone, which, with day rates in the neighborhood of $36,000, means significantly reduced costs.

Another example of cost cutting potential is MWD's ability to conduct near real time directional surveys. During angle build on a Gulf of Mexico deviated hole, Rogers says, a survey must be conducted every 100 ft. With MWD the survey takes minutes; without MWD, it would require about 1 hr of shutdown time.

Operators say bit improvements also are helping them drill more efficiently. Most cite polycrystalline diamond compact (PDC) bits, which in many types of rock increase penetration rates and, because of their durability, boost bottom-hole times by reducing bit trips.

PDC bits have received widespread use offshore because pumps on offshore rigs already were large enough to handle the fluid volumes they require. But they're finding increasing application onshore.

Maxus, among others, is using PDC bits onshore, ordering rig pumps large enough to handle the fluid.

Rogers says Maxus used one 6 3/4 in. PDC bit to drill the bottom 2,700-3,000 ft of three 8,600 ft wells in South Texas. With conventional bits, the same drilling probably would have worn out two bits in each hole.