June 1998 Vol. 219 No. 6  Production

Robert E. Snyder,  Editor

1998's not bad, 1997 was just too good

One reason that oil industry spending can slow some this year is that 1997 was such a good year that a momentum was built up that is carrying over into 1998, despite a few budget cuts. Of course, the extra cash flow from $20 – $25 oil through most of 1996 was certainly a big factor in boosting last year's spending.

In one supreme rationalization heard from a panel member at OTC, the slowdown at this time is probably a "good thing," because it is preventing the industry from overheating. Tell that to an independent operator in Wichita Falls, Texas!

Tangible information on this subject was reported by Arthur Andersen and John S. Herold, Inc., in their U.S. Upstream Performance Trends report, released April 15. In presenting the study — a review and analysis of 1997 revenues, capital spending, performance and reserve levels for 49 companies with U.S. oil / gas reserves exceeding 100 MM boe and 1997 expenditures exceeding $100 million — the two firms highlighted several key facts, some of which are noted here.

The largest oil / gas companies spent $30.4 billion in the U.S. upstream during 1997 — 43% more than in 1996, and a record for the 1990s. U.S. exploration spending increased 24% to $5.7 billion, and development expenditures rose 32% to $15.1 billion in 1997. Shell led both categories with $638 million in exploration, and $1.4 billion in development spending, primarily related to its Gulf of Mexico projects.

Property acquisitions registered the largest year-to-year increases. Purchases of unproved properties, primarily undeveloped leases, more than doubled to $3.5 billion, led by Texaco, Conoco, Union Pacific Resources and Shell. Acquisitions of proved reserves jumped 70% to $6.1 billion, approaching the mid-1980s activity level. The implied average price paid for proved reserves rose 21% to $4.23 per boe, from the 1996 low of $3.50.

Domestic proved oil reserves of the companies increased almost 5% to 19.1 billion barrels, the highest level since 1992. And new discoveries and extensions of existing reservoirs rose 49% to 1.4 billion barrels in 1997, while drillbit reserve additions replaced 83% of the companies' 1.7 billion barrels of domestic oil production. IOR added 430 million barrels.

Conversely, proved U.S. natural gas reserves were essentially unchanged, despite a 24% increase in extensions and discoveries, to 10.1 Tcf, the highest level of drillbit natural gas reserve additions in the five-year study period. Negative reserve revisions totaled 1 Tcf. This result prompted Andersen and Herold to express concern that domestic additions may not be adequate for the industry to meet U.S. demand increases.

As an important performance measure, U.S. reserve replacement costs — to add reserves through drilling, improved recovery, revisions and acquisitions — rose more than 8% to $5.50 per boe in 1997, 41% higher than the $3.91 level in 1995. This reflects increased domestic capital investment and rising oil field service and equipment costs.

Almost 70%, or 34 of the companies, experienced increased reserve replacement costs in 1997 over 1996. But as a measure of operating efficiency, production costs remained under tight control, improving to $4.01 per boe from $4.04 in 1996.

OTC vs. West Texas. Literally bumping elbows with many of the 49,000 attendees at the 1998 Offshore Technology Conference was certainly a contrast to the atmosphere at Texas Tech University's annual Southwest Petroleum Short course, held in Lubbock, April 7 – 9.

OTC has always been a "magic" show, in which concepts and models of up to $200-million vessels are displayed, and operators review deepwater projects with 20,000-bopd oil wells. It wasn't like that in Lubbock's Holiday Inn, where 38 presentations by inventors and users of practical tools and techniques talked about how to eke out an additional 10 – 100 bopd from wells in fields that were probably drilled before all of that offshore magic was even seriously considered.

The Short Course itself was initiated 45 years ago. Its attendees are the people that do the work in the field and are there to learn new techniques. The 38 presentations this year were oriented heavily toward artificial lift, with about half directly discussing sucker rod, plunger and gas lift, and electric submersible pump techniques. CO₂ injection and well completions / stimulation were also covered. And several methods for analyzing and controlling field production / well systems were presented.

A couple of observations from the Short Course are noteworthy. One presenter noted that control of gas in oil well pumping is a problem that is returning to West Texas. They started out with gassy wells when they first brought on the fields and before the operators "blew down" the inherent gas energy to get that flush production. Pumping "deader" oil was then a lesser problem for many years, until CO₂ injection caught on— now GORs are on the rise again as in-field injection resaturates the oil in place.

A downhole video presentation by Halliburton was revealing. It showed that a wellbore is frequently full of water, and oil flows from the formation into that water in globs that float to the liquid's surface — not the exact concept you might envision in your mind, if one thinks about such things in great detail. And that's probably not the way oil flows into those 20,000 bopd deepwater wells, at least not until those gas caps have also been blown down.

And while it may not cause Texaco's stock to surge, the operator has been awarded the Midland Reporter Telegram-Hearst Newspapers Energy Award for Technology for its successful initiation and development of the Dual Action Pumping System (DAPS). This dual-plunger device pumps oil that separates in the borehole up, and excess water down, below a packer to an injection zone. DAPS was discussed at the Short Course, and it is featured in World Oil, March 1998, page 69.

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