A strong U.S. gas market signals sustained drilling for gas through first quarter 1994, laying the groundwork for continued growth in the gas industry.
Seven solid years of growing gas consumption, coupled with dwindling U.S. deliverability, have brought U.S. gas supply and demand into a precarious balance.
At a time when low oil prices are prompting many producers to trim oil directed capital and exploration spending, almost 4 years of consistently higher U.S. gas prices except for first quarter 1992 spot prices are sparking a modest gas industry recovery.
Most noticeable has been the drilling response.
Baker Hughes Inc., Houston, reports the count of rigs in the drilling U.S. gas wells at mid March was more than 130 units higher than the count 1 year earlier. By contrast and despite low oil prices, oil drilling activity has been holding at or slightly above the year ago count.
Higher gas drilling activity is welcome in an era when overall drilling in the U.S. is at its lowest point in more than 50 years. But with demand for gas expected to continue growing in all markets, serious questions remain about whether producers are drilling enough of the right kinds of gas wells.
Figures show U.S. operators during the past decade, counting additions from all sources, have roughly maintained gas reserve volumes. When only reserves added by exploratory whiffle discoveries are counted, however, additions fall far short of replacing yearly production.
As a result, doubt persists among producers and consumers about how effectively the mix and locations of new gas supplies will be able to serve future U.S. markets.
U.S. GAS DEMAND
After dropping in 1986 to a low of 16.2 tcf, U.S. gas consumption in 1993 by most estimates topped 20 tcf. That includes about 2.215 tcf of Canadian imports.
Oil & Gas Journal expects U.S. gas consumption to reach 20.35 tcf this year (OGJ, Jan. 31, p. 53). Consumption is to increase in all major market sectors except electric utilities.
Last year's 2.2% demand increase was concentrated among residential and commercial customers, which grew 5.4% and 4.7%, respectively. U.S. gas demand is to continue growing through the rest of the 20th century and beyond.
The American Gas Association earlier this year predicted gas consumption in the U.S. through 2010 will increase by about 5 tcf. AGA estimates 1994 U.S. gas demand at 21.3 tcf, up from 20.8 tcf last year.
U.S. gas consumption through 2010 will expand in all major market sectors. AGA estimates demand will increase by 1.5 tcf among U.S. industrial customers, 1.3 tcf among electric utilities, 1.2 tcf in residential and commercial markets, and 1 tcf in transportation markets.
If gas use increases as AGA expects, by 2010 that fuel will provide about 27% of primary energy in the U.S., up from 25% at present.
DRILLING FOR GAS
William A. Gilbert, manager of research and consulting for Dwights Energy, Research (DER), Denver, an affiliate of Dwights Energydata Inc., says even if gas is extremely successful in capturing shares of growing power generation and transportation markets, gas demand still will grow at a slow, steady pace.
However, Gilbert disputes the role that demand projections play when most U.S. gas producers are deciding which wells to drill. While wellhead prices and market demand are linked, operators know it's dangerous to assume prices will increase just because demand is increasing. Rather, gas prices depend as much or more on factors such as supply of competing fuels.
Similarly, profits of a specific well depend more on where it is located, whether the producer has a gathering line in place or must install one, how pipeline deregulation has affected his transportation options, or whether he has a buyer for the gas. In addition, because of proration rules in many states, a producer might not be allowed to sell as much gas as he could.
"That happens more than people think," Gilbert said.
So instead of overall demand, operators are more interested in the outlook for gas prices and whether gas prospects in their portfolios can yield adequate profits under price expectations.
"They think more in terms of that 2-3 year wellhead price than the 2 3 year demand outlook," Gilbert said. "Obviously, demand affects wellhead prices, but the people drilling wells in the U.S. think in practical terms.
"If an operator perceives gas prices are to be going up and look strong if the 2 3 year price horizon looks good we'll see more drilling. Most drilling decisions are based on whether the price outlook justifies the economics of wells being drilled today."
PROFITS UNDERSCORED
Homer Hershey, senior vice president of production for Mitchell Energy & Development Corp., The Woodlands, Tex., says each gas prospect has to meet certain profitability criteria to warrant development.
While general industry trends and outlooks often are effective warning signals about what type of activity to avoid, profitability of specific gas developments doesn't necessarily reflect industry trends.
Mitchell makes its drilling decisions on revenue estimates and profitability analyses based on actual costs and wellhead prices rather than projections. While the company generates such standard industry wide measurements as company wide finding and development costs, Hershey says, "We keep all those numbers because that's what's used in the outside world."
Because Mitchell sells much of its gas under two long term contracts with relatively high wellhead prices, the company maintains profits by concentrating on replacing reserves in fields serving those contracts.
"Companies producing gas to sell through contracts with higher than market prices drill wells that are profitable under the precise scenarios in which they're operating," Hershey said. "So Mitchell and other production companies in similar situations might drill gas wells in some areas that on an industry wide basis don't look too good but on a profitability basis are very good."
When oil prices began sliding in fourth quarter 1993, Mitchell began curtailing its oil well drilling activity. By yearend, the company had virtualIy halted oil directed drilling. Today, the company has no rigs drilling for oil and doesn't intend to drill an oil well unless forced to for strategic purposes.
"We've put essentially all of our drilling into gas," Hershey said, "and I don't see that changing until we see the oil price change. Many companies right now unless they have oil prospects that have to be drilled won't be drilling oil wells."
Mitchell plans to drill 102 net wells during its fiscal 1994 ending Jan. 31, 1995, including only seven oil wells. In 1993, the company drilled 121 net wells, 22 of which were oil wells.
GAS DRILLING
Gary R. Flaharty, manager of market research for Baker Hughes Inc., Houston, says recent counts of active drilling rigs in the U.S. show that the correlation between wellhead gas price and rig count holds up better for gas than for oil if effects on drilling activity of the federal Section 29 incentive for gas produced from nonconventional reservoirs are excluded prior to yearend 1992.
Flaharty said, "From 1989 through the winter of 1992, gas rig activity was on a downward trend. From early 1992 through early 1993 there was an upward trend. After that the upward trend flattened, reflecting oil prices and fuel switching.
"In 1991, producers were starting to loose patience with gas because it looked as if the gas bubble was going to last forever. Then, just as supplies were tightening, wellhead prices hit that all time low."
Baker Hughes' count of active rigs throughout 1993 averaged 373 drilling for gas. In first quarter 1994, the count averaged 403 gas rigs. The count of gas directed rigs in mid March dropped to less than 400 units for the first time since August 1993. Meantime, the U.S. oil rig count registered a seasonal decline.
EFFECT OF SECTION 29
Data compiled by, Smith International Inc. (SII), Houston, show that the effect of Section 29 on U.S. gas drilling was substantial. According to SII's estimates, at yearend 1992, rigs drilling gas wells in qualified Section 29 reservoirs accounted for nearly 60% of the 679 gas directed rigs drilling in the U.S.
After the deadline passed for spudding Section 29 gas wells, U.S. gas drilling slumped. SII's mid March 1993 count of all rigs drilling gas wells in the U.S. slipped to 332 units after starting the year at 671. During the same time, Section 29 rig activity plunged to four units from 392.
While SII's data show the number of rigs drilling Section 29 gas wells decreased by 388 units in less than 3 months, overall gas drilling activity declined by only 339. So market factors by mid March 1993 had begun boosting U.S. gas directed drilling.
Because drilling in the Gulf of Mexico has not been distorted by artificial incentives, Baker Hughes' Flaharty says Gulf of Mexico drilling more accurately reflects U.S. gas market conditions than any other domestic gas province.
If so, gas drilling activity in the gulf bottomed out in second quarter 1992, when fewer than 15 rigs were drilling gas wells, then began climbing to more than 30 gas rigs by yearend 1992. The number of rigs drilling gas wells in the gulf climbed throughout 1993 to nearly 60 units during third quarter. After briefly backtracking in third quarter to about 55 units, Baker Hughes' gas rig count climbed to nearly 70 units in fourth quarter, then fell to between 60 65 at yearend.
Flaharty, said, "After gas prices bottomed out and began turning around in first quarter 1992, you definitely can see the point about 3 months later when gas drilling activity in the gulf turned around and began to head back up. The psychology took some time to readjust, but you can see gas rig activity turn around from that point."
Organizing regional gas drilling activity, into three groups of U.S. gas provinces shows the Gulf of Mexico's rapid drilling activity increase since mid 1992, steady growth since late 1991 on the U.S. Gulf Coast and Denver and Arkla basins, and the drilling spike in all other U.S. gas prone areas caused by, Section 29.
"Since May June 1992, we've seen the greatest increase of rigs drilling gas wells in the gulf," Flaharty said.
GAS WELL COMPLETIONS
Spurred by increasing gas drilling, U.S. well completions by many estimates increased in 1993.
The American Petroleum Institute reckons total well completions last year registered a 4.2% increase over 1992, led by a 16% increase in gas wells. Oil well completions declined 7.5%.
Although API says exploratory gas well completions increased in 1993, fewer wildcat oil wells were completed, decreasing overall exploratory completions by 1.8%.
By comparison, Petroleum Information Corp. in January reported 17,096 oil and gas wells completed in 1993--according to PI's yearend count also a 16% increase from 1992. PI said total well completions could reach 25,500 when all reports are in, yielding a 6% increase over 1992.
PI's preliminary, estimates show operators in 1993 completed 7,173 U.S. gas wells, a more than 43% increase from the 1992 total. PI at yearend had counted about 145 new gas field discoveries by wildcat wells in 1993, more than 38% more than in 1992. By contrast, PI at yearend had counted 6,955 oil wells completed in 1993 and 148 new oil fields discovered, respectively 2% and 5.7% more than in 1992.
RESERVE ADDITIONS
Energy, Information Administration figures show about 1 bcfd of deliverability, is added in the U.S. for each 1,000 gas well completions. But reserves added/gas well and initial flows vary widely among different regions. So while gas well completions increase, the mix of wells going on line and their locations must temper results.
EIA data show an average new gas well in the Gulf of Mexico has an initial flow rate of 7.7 MMcfd and produces more than 150 MMcf of gas/1 bcf of reserves. Initial flow rates of gas wells in the Southeast U.S. and Rocky Mountains, by comparison, average 500 600 Mcfd with cumulative recoveries of less than 80 MMcf/bcf of reserves.
Baker Hughes' Flaharty says Gulf of Mexico gas reserves have declined about 20 tcf, while reserves in the Black Warrior and San Juan basins have shown combined growth of about 10 tcf because of recent drilling and completion trends.
"When you look at the reserve numbers, you find we've gone down about 10 tcf, and if you look purely at the ability to produce gas, it would appear that ability also has declined," Flaharty said.
So while it is an important part of the overall picture, maintaining a minimum number of gas well completions alone is not enough to assure retention of adequate reserves or deliverability. Among nonconventional gas reservoirs, for example, tight gas formations have very high early deliverability but steep production declines. By contrast, coalbed methane wells have lower front end deliverability but longer lives.
GAS WELL UTILIZATION
DER's Gilbert says low levels of gas reserve additions in the U.S. have forced utilization of available U.S. wellhead capacity so high that "we're walking a fine line."
In some areas the Gulf of Mexico, for example operators are producing all out, and production rates reportedly surpass 95% of deliverability. Meantime, many gas producers in the Rocky Mountains have gas wells shut in because of soft regional markets.
"It's just a logistical game," Gilbert said.
Flaharty says the rates at which U.S. operators have been replacing yearly production since 1980 have been adequate if reserve additions from all sources are included. However, if reserves added by revisions are excluded, reserve additions fall far short of production.
Of course, additions through revisions contribute to the collective reserve life of U.S. gas wells.
"But if you include revisions in reserve estimates, you have to question how those revisions affected deliverability," Flaharty said. "A key question becomes, 'How many gas well completions do we need in the U.S. to replace production so reserves remain relatively constant?' "
Much is said about how technological advances bolster upstream gas industry efficiency. But Flaharty says gas reserves added/well completion in the U.S. have increased only slightly since 1980 if revisions and other adjustments not related to drilling activity are excluded.
Similarly, success rates of neither development nor exploratory wells have improved significantly for the past 25 years. A case could be made, however, that technology has helped keep success rates and reserves added/completion from declining even more.
Clear evidence of more efficient upstream performance is found in completions/active rig, which show 24 25 oil and gas wells have been completed for each active drilling rig in the past 4 years, compared with about 15 completions/rig 15 years ago.
DWIGHTS' FORECAST
With oil and gas drilling activity in the U.S. at low levels, many in industry are concerned about whether enough gas drilling is adequate to maintain gas reserves and deliverability.
Despite continuing seasonal swings, DER has concluded gas drilling is likely to maintain steady growth through 1998 in 16 of the most productive U.S. gas basins. Gilbert says DER's data indicate U.S. gas demand will increase through 1998 at an average rate of 1.2%/year, while total U.S. energy demand increases by less than 1%/year.
Based on field by field projections of wells in the 16 most productive U.S. gas provinces, Dwights has this outlook for U.S. yearly gas well permitting:
- 1993 4,830 gas well permits, including 4,100 for development wells and 730 for exploration wells.
- 1994 5,622 permits, 4,678 development and 944 exploratory.
- 1995 5,643 permits, 4,695 development and 948 exploratory.
- 1996 5,838 permits, 4,857 development and 980 exploratory.
- 1997 6,153 permits, 5,119 development and 1,033 exploratory.
- 1998 6,494 permits, 5,403 development and 1,091 exploratory.
Here is Dwights outlook for U.S. gas well completions:
- 1993 6,248, including 5,706 development and 541 exploratory wells.
- 1994 6,303, 5,614 development and 690 exploratory
- 1995 6,263, 5,579 development and 685 exploratory.
- 1996 6,418, 5,714 development and 704 exploratory.
- 1997 6,711, 5,973 development and 739 exploratory.
- 1998 7,097, 6,317 development and 780 exploratory.
As drilling and completions build during DER's forecast period, the focus will shift gradually, along with gas reserves and deliverability.
Growth will occur first in the areas with the greatest potential: the Gulf of Mexico and Gulf Coast. Longer term, more gas supplies will be found and produced in other U.S. gas prone areas, including the Rocky Mountains, Midcontinent, and Southeast. Gas from nonconventional Section 29 reservoirs also will increase, now that operators have confirmed the reserves and developed the technical capability to recover them.
GAS DRILLING OUTLOOK
Whatever the precise gas drilling scenario, for the moment the gap between U.S. gas demand and producibility continues to decline.
"We have to drill some wells, find some reserves, and increase deliverability," Flaharty said.
Baker Hughes believes enough U.S. drilling capability remains to easily maintain yearly Lower 48 gas production of 18 18.5 tcf, as Flaharty demonstrates with a simple model. "In terms of the amount of gas you need to produce, the numbers don't change very much," he said. "The biggest variable is reserves added per gas well completion."
With constant gas imports from Canada of 2.1 tcf/year and 25 completions/year for each active rig, Flaharty calculates that U.S. producers could maintain gas production of 18 18.3 tcf/year with an average count of:
- 557 gas directed rigs and 13,900 gas well completions/year averaging about 1.3 bcf of reserves each.
- 505 gas directed rigs and 12,600 gas well completions/year with reserves of about 1.5 bcf each.
- 362 gas directed rigs and 9, 100 gas well completions/year with reserves of about 2.0 bcf each.
With the count of rigs drilling gas wells in the U.S. averaging about 400 units, he says, current rig activity is within the range needed to replace production. "My guess is we probably will need closer to 500 gas rigs to maintain supplies."
DRILLING RESPONSE UNDER WAY
If Flaharty, Gilbert, and others are right, gas directed drilling for about the past year has started showing signs that operators have begun stepping up activity in response to long term market signals.
Producers are responding on a regional basis, first drilling development wells in regions where gas prospects are deemed best: the Gulf of Mexico, U.S. Gulf Coast, and Canada.
As indicated by Dwights permitting and completion outlooks, the thrust of gas directed drilling will trend slightly toward more exploration, first testing relatively shallow prospects near production, followed by deeper, more remote tests.
Tom Wingerter, vice president of North American operations for Parker Drilling Co., Tulsa, says the deep drilling contractor is beginning to see renewed interest in testing deeper gas prospects in its two main U.S. operating areas, the Mid Continent and Rocky Mountains. Last year, Conoco Inc. hired Parker to drill a 17,000 ft gas wildcat in Terrell County, Tex.
"As U.S. producers become more confident of gas prices, they're beginning to talk again about drilling wildcats and some deeper gas wells," Wingerter said. "We're not hearing a lot of it, yet, but at least there's talk out there of some of the trends we typically saw in the early 1980s: good, deep, gas wells with tremendous reserve potential.
"When we start hearing that kind of talk among key customers, we know there is some confidence in the gas market."
While agreeing that U.S. producers in general can be expected to drill their least costly exploratory prospects first, Wingerter points out that specific drilling decisions in each company are based on its portfolio of prospects.
"Some companies have acreage positions only in areas that force them to look at deeper reservoirs," he said.
Flaharty says operators working along the Texas Louisiana Gulf Coast have registered big drilling gains in about the past year.
Also, he estimates about 70% of drilling activity in the Gulf of Mexico in the past 12 months has been gas directed, as opposed to a more equal oil gas split. Of the average 403 active gas directed rigs running in the U.S. during first quarter 1994, about 38% were in the Gulf of Mexico or Gulf Coast, up from about 21% in December 1992.
"U.S. gas rig activity, is moving toward offshore and Gulf Coast wells," he said. "Eventually, I think we'll see a move into deeper water, as well."
LIMITS TO ACTIVITY
Flaharty expects to see enough gas directed drilling in the U.S. to maintain gas reserves and wellhead deliverability. But gas drilling after 1994 likely won't maintain the same rate of growth achieved in the past couple of years. We've brought rigs back very quickly and I think we're starting to see a recline in the rate of increase," he said.
One thing that has changed possibly, forever is the relative emphasis on gas prospects. The U.S. likely won't need to average 1,100 1,200 total active rigs to maintain 500 plus active gas rigs. A total count of 800-900 rigs should allow adequate gas directed drilling, Flaharty says.
Recent counts of available rigs show that level of overall activity should be achievable. Yet Flaharty says trying to sustain 800 900 active rigs for a time could be difficult.
"When our weekly rig counts recently have risen to the 800 900 range, we've started running into a little bit of a pain threshold," he said.
If wellhead prices improved enough to sustain 800 900 active rigs, day rates would rise, too. In that event, contractors likely would be generating enough revenue to recondition rigs or order more drillpipe.
"My bet is, at that level of activity we're going to have problems finding enough experienced crews," Flaharty said. "In a tight market, the lead time needed to get drillpipe isn't too long. It takes a lot longer to train a crew."
