Oil and gas industry consolidation in North America and emerging seismic capabilities have triggered a burst of onshore three dimensional surveys by independent operators.
Major integrated companies have helped set the stage for all the activity by divesting onshore oil and gas leases across the U.S. and Canada in favor of bigger, possibly more profitable prospects overseas.
Independents, meantime, have been acquiring castoffs, mostly in mature hydrocarbon provinces, and combing through them in search of economic oil and gas accumulations. More and more, 3D seismic data are the favored tools for sifting through subsurface geological indicators.
Much of the rise of 3D onshore seismic surveys among independent producers stems from steady efforts to improve operating results and manage costs because of low oil and gas prices. Positive publicity by major companies, seismic contractors, and petroleum industry trade groups has prompted many independents to determine whether 3D seismic would work for them.
As often occurs when new technology is widely applied, changes follow in the meaning of traditional measures of seismic activity. Crew counts, for example, no longer pinpoint the level of activity because a land 3D crew can collect many times the volume of data possible by a 2D counterpart. Similarly, because many 3D crews are collecting data to be used for development, so seismic activity is no longer an indicator of exploration.
CHEAPER, FASTER, BETTER
With more applications for the technology, independents are collecting more 3D data onshore because geophysical computer software has become cheaper and more capable, the hardware more efficient and more powerful.
High channel 3D seismic acquisition systems have proliferated, cutting acquisition costs. The portability of onshore 3D acquisition systems has improved while systems' footprints have diminished, speeding field work and mitigating environmental effects.
Independents are learning that, as with 2D data acquisition, the cost of acquiring 3D seismic data onshore is influenced mostly by topography over the survey site. Field data for a 3D survey over flat terrain - in West Texas, for example - can be obtained for as little as $12,000-15,000/sq mile plus permitting costs. In wetland areas like most of South Louisiana, 3D field data are more likely to cost $50,000100,000/sq mile.
As equipment has improved, the time needed to process 3D seismic data is being compressed and interpretive strategies are improving accuracy.
The cost of processing 3D data in the past 3 years on average has fallen 20-25% but still varies widely. Recent bids by contractors to process a set of 3D data from West Texas ranged from $1,200 to $2,900/sq mile. A cost of minor importance on a large 3D survey, the cost of processing 3D data is a more significant expense on the relatively smaller shoots typical of independents.
More capable interpretation work-stations have begun flooding North American markets. An independent can acquire high end hardware and software he needs to interpret 3D seismic data for $75,000-150,000. A less capable, usually personal computer based system can be purchased for as little as $20,000-25,000, including $4,000-5,000 for hardware and $10,000-15,000 for software.
SMALLER, DEEPER, FASTER
Many scientists and engineers with 3D seismic experience have left major companies in the past 6 years-either voluntarily or because of layoffs-creating a pool of 3D consultants for independents to tap.
Sometimes through trial and error, the growing use of onshore 3D has led to better understanding of 3D survey design. Independents are more aware of the importance of a well designed 3D survey, and consultants are more proficient at designing them. Operating on the mistaken belief that any 3D data were good data, in part because of their experiences with less complicated 2D surveys, independents in the past often chose the least costly design among competing 3D survey plans.
Now, more experienced independents are more likely to weigh competing 3D plans on a range of merits rather than price alone.
The combination of better equipment, better technicians, and more knowledgeable customers means more independents are able to use 3D seismic data to delineate smaller, deeper geological features faster and more accurately.
Even many high end 3D capabilities are relative bargains because they must be priced to compete with better known 3D technologies that cost less. With the cost of an onshore dry hole consistently more than $250,000, 3D seismic quickly becomes affordable if an operator can avoid even one dry hole.
RANGE OF NEEDS
Independents of different sizes and capabilities use different mixes of seismic services to acquire good 3D data.
Generally, the smaller the company the more outside services or products it must acquire. Because such companies likely have no geophysicists on staff, they must hire consultants or contractors to handle each phase of survey design, data acquisition, processing, and interpretation. For a small operator, just a few good wells can radically affect performance and activity.
Midsize independents still aren't likely to have much 3D survey design expertise but might be able to oversee collection of field data and rudimentary interpretations. Many still need help with processing and some interpretative functions.
Large independents generally need the least amount of outside help. This type of company usually has geophysicists on staff and often maintains a technology group. Generally, the largest independents are the most capable when it comes to 3D, many times working hand in hand with their contractors and consultants.
Observers estimate that 3D surveys have been run over less than 10% of U.S. onshore oil and gas provinces, much of them by major companies. But geophysical consultant Tim S. Brown, owner-operator of CAEX Services, Houston, says independents are stampeding to conduct 3D surveys.
"It's a very discernable, major movement," he said.
3D ACTIVITY INDICATORS
Debate continues about the meanings of specific activity indicators, but there is little doubt about the spread of 3D work onshore.
The number of land seismic crews collecting 3D data in North America by many estimates in 1994 averaged about 48, up from only five as recently as 1992. In November 1994, 94 of 117 crews active in North America were collecting 3D seismic data, including 64 of 80 land crews and 34 of 37 crews offshore.
Opinions vary, but onshore 3D seismic surveys by independent producers reportedly have been especially heavy in South Louisiana, Canada, and West and South Texas.
Bill Matthews, Landmark Graphics Corp., Houston, said independents in West Texas can acquire low cost 3D seismic data in areas between fields surveyed by large speculative shoots.
"Over half of West Texas already has been shot by 3D surveys," Matthews said.
Other reports of onshore 3D seismic shoots by independents include surveys in Ohio, Indiana, Kentucky, New York, Nevada, and the Williston basin of Montana. A 3D survey in Mississippi reportedly is being shot over a salt dome with a grid of 2,600 live channels.
The Geco-Prakla unit of Schlumberger said the pace at which 3D seismic use onshore has been accelerating is evident in yearly totals of areas over which Geco-Prakla has collected 3D data for customers.
Jack Caldwell, Geco-Prakla manager of market development in North and South America, said the unit in 1990 collected only 6 sq mile of 3D data. The company surveyed 35 sq miles with 3D data in 1991, 252 sq miles in 1992, and 643 sq miles in 1993. The 1994 total is expected to be about 1,115 sq miles.
Caldwell said 20-25% of the area surveyed with 3D seismic by Geco-Prakla was for small and midsize independents, with large independents and major company surveys accounting for the rest of the area.
3D SURVEY COUNT
While areas surveyed with 3D data in 1994 appear certain to increase, a trend toward larger surveys has split opinions about how the count of 3D surveys could change.
After almost doubling in 1993 to a count of 550, Matthews said, the number of 3D surveys in 1994 could decrease slightly.
"I think we'll be lucky to break 425 because companies are spending more time shooting bigger or denser 3D surveys," Matthews said. "The more 3D data they shoot, the more drillable prospects they have in inventory."
Despite effects in 1994 of larger shoots on the survey count, Jay M. Green, vice-president and investor relations director of geophysical data and services provider Seitel Inc., Houston, said it is likely the number of onshore 3D seismic surveys by independents will increase in 1995 because many independents' budgets this year include increased spending for 3D seismic services and data.
In the past, most spending by independent companies for 3D seismic data was budgeted for offshore prospects.
"But in the 1995 budgets, they have earmarked an increasing amount of money for land 3D surveys," Green said.
ESTIMATING FUTURE ACTIVITY
How Onshore 3D Seismic Surveys Are Increasing (13189 bytes)
Based on his knowledge of geology in major oil and gas provinces, Alex Cranberg, Aspect Management Corp., Denver, for the past 1 1/2 years has been trying to scope future onshore 3D activity.
Cranberg said the number of locations identified by companies that have been most successful using 3D technology is "staggering." After collecting and compiling information about 3D programs covering thousands of square miles in 20 oil and gas provinces across the U.S., Cranberg believes he has developed a sense of where 3D seismic surveys are likely to be shot.
Last year, Cranberg estimated that by yearend 1994 about 5% of the total 3D suitable area onshore in the U.S. would be shot with 3D seismic. But as 1994 passed, Cranberg found U.S. operators "adopting 3D seismic data a lot faster than even our aggressive forecast had shown."
Cranberg said in mid-December, "We have now reforecast activity. Our slow adoption curve now is above last year's rapid adoption curve. My feeling is that 80% of the U.S. 3D suitable oil and gas provinces that are at least moderately drilled eventually will be surveyed."
Included in Cranberg's definition of mature areas suitable for survey by 3D seismic crews are the most densely drilled regions in the U.S. with high quality reservoirs, structural complexity, or stratigraphic complexity that could be further imaged with improved seismic data. That meant including places like the Midcontinent, Rocky Mountain, and Gulf Coast regions, as well as the Permian, Arkoma, and Anadarko basins. Excluded were areas like the Appalachian and San Juan basins Cranberg considers non-seismic provinces.
Taking a conservative approach, Cranberg's rapid adoption curve found U.S. onshore 3D coverage approaching 100% of some areas as early as 2003-2005. But in some cases, 3D coverage could exceed 100% of an area.
"The industry is shooting a lot of areas twice for various reasons," Cranberg said.
Perhaps an early 3D survey wasn't shot correctly, or the operator is focusing on different targets or trying to achieve different goals. Whatever the motivation, Cranberg said, "I think we'll end up with cumulative square miles of 3D data shot representing about 150% of what I'm calling 3D suitable areas."
3D AND WELL CONTROL
With so many former major companies' leases now being redeveloped in the hands of independents, Cranberg's conclusion rings true.
Landmark said independents are using 3D seismic mainly for development because it not only is easier to justify spending on a productive lease but because risk is lessened further if 3D data can be calibrated with well control data.
"Companies that are making the best use of this technology are those that are integrating geology with geophysics," Matthews said. "Several independents drilling with 50% success based on 2D seismic are achieving 70%, 80%, and 90% success rates with 3D data. "
Some independents are using well control data with 3D seismic data to control risks on less than pure development plays.
One such operator, Bud Brigham, formed Brigham Oil & Gas LP, Dallas, in 1990 specifically to develop onshore prospects with 3D seismic. In the past 4 years, Brigham has collected more than 2,000 sq miles of 3D data onshore, mostly in West Texas, and has acquired interests in 19 3D seismic plays in six states.
So far, the company with partners has identified about 740 prospects and drilled 140 of them with a success rate of 70%. Well control data hold the key to the way Brigham works. Some of Brigham's prospects have been drilled in fairly remote areas, but "once we shoot the 3D and define a prospect, we feel we're doing development drilling," he said.
Brigham also said it is difficult to think of a 3D seismic prospect, whatever its location, as a wildcat because once a producer shoots the 3D, he has so much data he no longer has an exploratory drilling risk profile. Still, by concentrating in proven geological trends, the company is finding new fields with a 3D drilling program, not shooting over active fields and drilling infill wells. Brigham often calibrates 3D data with data from a control well as far away as 5, 10, or 20 miles.
"A lot of wells have been drilled in mature basins over the years, but a lot were dry holes," Brigham said. "It's nice to have an area targeted where there are a couple of analogous producing wells."
IMPROVED PRODUCTIVITY
As Robert H. Chaney, chairman and chief executive officer of R. Chaney & Co. Inc., Houston, sees it, the impetus for independents to use 3D seismic technology anywhere stems from the need to improve exploration and development drilling economics in an era of low prices.
With fewer wells being drilled, there also is a need to reduce risk, Chaney said.
"Overall, statistics show 3D seismic data definitely decrease risk."
In addition, there is ample evidence that 3D seismic data help find more reserves and drill more productive wells.
Landmark's Matthews said an independent that based drilling on 2D seismic data might have been drilling wells averaging 400,000-500,000 bbl of reserves each. Now with 3D, reserves have increased to 800,000-1 million bbl/well and production rates are higher.
"So on a project basis, operators not only are drilling fewer dry holes, they also are bringing in better wells,' Matthews said. "Many investors have realized this."
Susan Helgeson, Landmark's Americas marketing manager, said independents that have worked in limited areas for many years have unexpected advantages.
"Independents started out thinking they would hire a consultant and let an expert interpret the 3D data," Helgeson said. "But if you can get them into a room with some people who have workstation experience, they suddenly get very interested because they know the geology and well data and they realize what enormous input they have to the interpretation."
In their limited areas of operations, "they might become better users of the technology than the majors," she said.
HIGH QUALITY PROJECTS
C. Eugene Ennis, president and CEO of 3DX Technologies Inc., Houston, said the Fausse Point 3D project in St. Martin and Iberia parishes of South Louisiana, about 20 miles south of Lafayette, is a good example of a quality prospect considered too small by most major companies to undertake.
Ennis said 3DX is an independent production company that takes interests in deals by providing all 3D seismic services. The company works only with other independents and does not take interests in wildcats. Since its formation, 3DX has been offered opportunities to take part in about 250 onshore 3D seismic surveys in the U.S.
"We have accepted fewer than 20, meaning we believe the projects are feasible from the perspective of 3D," Ennis said.
Fausse Point partners are shooting a 53 sq mile 3D survey over difficult terrain, including sugar cane fields, lakes, marshes, and swamps.
"The things we've had to face just to get the data positioned properly have been significant," Ennis said.
Estimated cost of the 3D survey is $7 million, including $5.5 million for data acquisition.
Half the Fausse Point survey area covers a field discovered by Texaco Inc. in 1937 where about 80 wells were drilled, including about 50 still producing oil from a Siphonina-Davisi interval at about 8,000 ft or gas from a series of Miocene sands at 10,00013,000 ft. Remaining reserves on the newly formed lease are estimated at 40-45 million bbl of oil and 150-200 bcf of gas, significant to many small companies.
Partners in the Fausse Point project include prospect generator Chanier Exploration Partners, Houston; Falcon Drilling Co., Abbeville, La., through Raptor Exploration Co. Inc.; operator Odyssey-Bellweather, a company formed about mid-1994 in a merger of Odyssey Petroleum Co. Ltd., Dallas, and Bellweather Exploration Co., Houston; and 3DX.
Fausse Point partners acquired a large leasehold over the area adjacent to Texaco's old lease, then took a farmout from Texaco to complete the acreage spread. 3DX created a 3D seismic data base and integrated all well data.
Amoco Production Co. joined the project in fall 1994 as a technical participant and equity partner.
"The fact that it was a high quality program caused Amoco's interest," Ennis said. "They saw the program and committed to it within 24 hr."
That a major company was impressed enough with a prospect generated by a group of independents to take an interest in the project indicates the high quality and capabilities of 3D seismic data in the hands of independents. Ennis said more 3D based redevelopment projects involving major and independent production companies likely will occur.
"A lot of independents think of small projects in West Texas as the 3D realm," Ennis said. "But the Fausse Point project is an entirely different class of program. I think it demonstrates the viability of the technology, the wave of the future, and opens ways that people can participate in larger programs without having to be a major oil company or a huge independent."
TYPICAL 3D SYSTEM
If independents are generating better 3D data-and thus better 3D prospects-much of the credit must go to improved seismic tools.
Many credit Input/Output Inc. (I/0), Stafford, Tex., with developing and introducing the most technically advanced 3D seismic data acquisition system, based on 24 bit analog to digital converter technology.
I/O has concentrated on developing acquisition systems based on smaller and lighter seismic equipment to record larger surveys and improve operating efficiencies over more varied terrain. With prices ranging from $104.5 million, an 1/0 data acquisition system is capable of collecting data from as many as 8,064 live channels across as many as 512 seismic lines.
I/O's onshore 3D seismic system consists of a central electronics unit and multiple remote ground equipment modules. A typical I/O acquisition system includes:
- Central electronics unit components that act as a control center.
- 12 line taps that manage the data collection process on each seismic line, further organize the data, and transmit the data and remote equipment operating status to the central electronic unit.
- 200 remote signal conditioners (MRXes), each of which handles the collection process for six channels of analog seismic data.
For independent producers, familiarity also plays a hand in the mix of new technologies employed.
"An operator in Abilene, Tex., isn't going to jump on the bandwagon of a brand new technology," Helgeson said. "He wants technology that someone else has used successfully. In that sense, the movement into 3D by independents indicates a maturing of technology in the market."
FAMILIARITY IMPROVES SKILLS
As independents have become more familiar with 3D seismic capabilities, their own 3D skills have improved. For example, the time needed to process 3D seismic data has decreased from typically 7-9 months to as little as a couple of months.
At Fausse Point, 3DX devised a preprocessing strategy that will allow it to start interpreting seismic data within 2 months after the last shot. In addition, the company improved communication between seismic data and well data by creating a digital ortho-map that combined both data sets, allowing group members to site new wells in the field within 1 m accuracy.
Peter M. Duncan, 3DX vice-president of technology, said it aims to eliminate a 5% error rate among survey data points by learning where the bad points are before the crew leaves the field. So after each swath is shot, 3DX sends the data to the processor, who has preprocessed model survey data to play out model runs. By processing field data immediately, the processor was able to identify which shot point data appeared to be mislocated in the record. That information was sent back while crews were still in the field.
"Even better, because we're doing all that preprocessing, we've already migrated half of the data and we're interpreting it right now," Duncan said. "We're going to finish processing this survey and start interpreting it 30-45 days after the last shot is taken."
To create the digital ortho-map that integrated well and seismic data, Fausse Point partners placed reflectors on the ground at surveyed locations over the field and took aerial photos in which the reflectors appeared. Next, the aerial photo was digitally processed to account for the curvature of the earth so it would conform with the seismic grid to within 1 m accuracy. Partners achieved that accuracy by using a scale in which each screen pixel equaled I m.
Next, Duncan said, partners entered the digitized aerial photo data into a seismic workstation and superimposed the surveyed seismic grid on top of it. Technicians can enlarge the unified map to a scale in which cars are easily visible on roads in the area.
"We have found existing wells that were mislocated by 300-500 ft because of the miscommunication between seismic and well data," Duncan said. "Later, when we locate new wells, we'll be able to go to the place with a photograph at a scale such that we'll be able to see exactly where it should be relative to houses and trees and roads or other landmarks."
3D LIMITATIONS
Despite the progress made by 3DX and other independents at mastering 3D seismic technology, many operators more familiar with 2D technology are surprised by the length of time needed to acquire, process, and interpret most 3D data.
Permitting time, especially identifying and obtaining approvals of all landowners over a survey site, is one of the biggest obstacles to collecting 3D data.
Fausse Point partners put the project's 3D survey out for bid in January 1994. Surveyors began working in June 1994, and crews began acquiring data the following August. Data acquisition is to end this month, processing is to be complete by Mar. 1, first phase interpretation by summer, and drilling is to begin by fall. By contrast, Duncan said, locating and negotiating with surface owners for access to their land took about 20 man-months.
Brown said there is so much activity that available 3D crews are hard to find in some regions. In other cases, 3D crews under contract have trouble finding enough shot hole drilling rigs.
"New instrumentation is being put out about as fast as it's being manufactured," Brown said.
Seitel's Green said the rapid pace of 3D seismic activity also is raising questions about availability of competent technicians.
"In terms of the worldwide populus of geologists and geophysicists, what percentage of them today really can use a 3D workstation efficiently?" he asked. "The estimates are only 10-15% of the 70,000 plus geologists-geophysicists around the world can use a workstation efficiently."
By some estimates, as long as 2 years is required for a geoscientist to become truly efficient with a 3D seismic interpretation workstation.
"So there is a tremendous learning curve or orientation curve," Green said. He views growing 3D seismic use by independents as part of general petroleum industry consolidation. While independents in North America appear sure to continue using more 3D seismic data to define prospects onshore, a role will remain for 2D data as well.
"Companies not only have to budget dollars but also time," Green said. "So because of the price and time discrepancies, we think for preliminary exploration and production there will continue to be a strong demand for 2D data.
"In fact, the best way to use 3D data is to first use 2D data to pinpoint where 3D will be most effective."
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