Horizontal and Multilateral Wells

Increasing Production and Reducing Overall Drilling and Completion Costs

Cost experts agree that horizontal wells have become a preferred method of recovering oil and gas from reservoirs in which these fluids occupy strata that are horizontal, or nearly so, because they offer greater contact area with the productive layer than vertical wells.¹ While the cost factor for a horizontal well may be as much as two or three times that of a vertical well, the production factor can be enhanced as much as 15 or 20 times, making it very attractive to producers. Despite these facts, it took several decades for the industry to embrace the technique.

“Some of the earliest development toward horizontal drilling took place during the early 1940s when John Eastman and John Zublin developed short-radius drilling tools designed to increase the productivity of oil wells in California,” explains Frank Schuh, a horizontal-drilling consultant.

“The tools were designed to drill 20- to 30-ft (6.096 to 9.144 m) radii and horizontal distances of 100 to 500 ft (30.48 to 152.4 m), and they permitted the drilling of numerous laterals in the same formation in various directions around the wellbore. Typical designs used between four and eight laterals.”

The equipment preceded downhole survey tools and included extraordinary knuckle-jointed flexible drill collars that could be rotated around the extremely high curvatures. Also, it allowed for the employment of a drilling technique that was the perfect completion companion to standard, vertical open-hole completions being used at the time. “Basically, Eastman and Zublin were instrumental in drilling the first multilaterals,” Schuh states. “Today’s multilateral wells are simply modern versions of these earlier efforts.”

Unlike a directional well that is drilled to position a reservoir entry point, a horizontal well is commonly defined as any well in which the lower part of the wellbore parallels the pay zone. And the angle of inclination used to drill the well does not have to reach 90° for the well to be considered a horizontal well. Applications for horizontal wells include the exploitation of thin oil-rim reservoirs, avoidance of drawdown-related problems such as water/gas coning, and extension of wells by means of multiple drainholes.²

Early Experimentation

True development and employment of horizontal-well techniques began in the U.S. during the mid-1970s. However, horizontal-drilling experimentation began much earlier.

The U.S. Dept. of Energy (DOE) marks the starting date as 1929 in Texon, Texas. Here, says the DOE, the first “true horizontal well” was drilled. Additionally, the DOE cites a well drilled in Yarega, U.S.S.R., in 1937 and a 500-ft (152.4 m) well drilled in 1944 in the Franklin Heavy Oil field in Venango City, Pennsylvania, as being some of the first wells to be drilled horizontally.

During the 1950s, the Soviet Union drilled 43 horizontal wells, a considerable effort with respect to the equipment available then. Following their foray into horizontal drilling, the Soviets concluded that while horizontal wells were technically feasible, they were economically disappointing or, in other words, not profitable. As a result, they abandoned the method.

In the mid-1960s—10 years after the Soviet experience—the Chinese drilled two horizontal wells. The first, 500 m (1,640.4 ft) in length and not cased, collapsed after a week of production. The second was interrupted by the “Cultural Revolution.” Like the Russians, the Chinese concluded that horizontal drilling was uneconomical and abandoned the method for more than 20 years.³

True Development Begins

North American Horizontal Wells

From 1979 to 1982, a renaissance of true horizontal-well development work occurred in North America. It was during this period that Alan Barnes, an engineer for a major oil company, used a complex reservoir-simulation model to promote the benefits of the Eastman/Zublin short-radius technique to his superiors.

Following his modeling studies, the company drilled approximately 12 horizontal wells in the Empire Abo reef in New Mexico. They targeted a thinning oil column in a massive limestone reservoir with a significant gas cap and active water drive. Oil recovery of the first hole exceeded the production of a comparable vertical well by more than 20 times before breakthrough of the gas cap. The success of the Empire Abo project led the company to look for means of a broader application. The company appointed Schuh to lead the search.

“We developed what is generally referred to now as ‘medium radius’ (20°/100 ft) horizontal drilling,” Schuh says as he recalls the project. “The development determined the maximum hole curvatures possible in drilling horizontal wells without damaging conventional drillstring and drilling tools. We found that the unique application of horizontal drilling allows hole curvatures that are five to 10 times greater than can be used in conventional directional drilling. We utilized the latest advancements in downhole motors and measurement-while-drilling (MWD) equipment to develop methods for establishing long, low-cost horizontal boreholes.” Using their technique, Schuh and his colleagues drilled their first medium-radius well in January 1985. During the 1980s, more than 300 horizontal wells were drilled in North America including the first one in Prudhoe Bay, Alaska, in 1985. During this period, Texas’ Austin Chalk trend also received a great deal of attention from horizontal-well operators who, at the time, drilled some of the highest-producing-rate wells in the U.S.

But the decade of the 1990s most certainly will become known as “the decade of the horizontal well.” Through 1998, the number of horizontal wells drilled in the U.S. has totaled more than 3,000, an increase of 1,000% over the previous 10-year period. By the late 1990s, a dramatic shift in corporate philosophy regarding horizontal drilling occurred when one major operator set a requirement that prior management approval was necessary for all vertical wells.⁴

European Horizontal Wells

The renaissance of horizontal-well drilling techniques in Europe began about the same time as in North America. In 1977, Elf Aquitaine and L’Institut Française du Pétrole (IFP) began work on the FORHOR project, which eventually led to the success of the Rospo Mare field, the only oil field in the world at that time that produced systematically through horizontal wells. Drilled in the Adriatic Sea in water depths ranging from 200 to 300 ft (60.96 to 91.44 m), the technical and economic success of this field is credited with triggering the world’s interest in horizontal drilling.

Jacques Bosio, a former R&D deputy director and Vice President of Elf Aquitaine, was one of the pioneers in the field of horizontal drilling as a project manager of the Elf/IFP FORHOR horizontal-drilling research study.

“What I remember about that period, when nobody in the world would believe that horizontal wells could become a new tool for the industry, is that it was more difficult to change, by 90°, the way people were thinking than it was to do it with the wells,” says Bosio, recalling those early days in Italy. “We had been raised with the idea that the maximum possible inclination for a well could not exceed 70°. I don’t know why, that’s just the way we were taught. But, one of the main reasons the FORHOR project succeeded was because we had the perseverance to go one step further with a rotary drilling rig. Remember, we didn’t have downhole motors then.

“When we talked to our drillers [about going beyond 70° inclination] . . . they first laughed and then turned real mad at ‘those crazy R&D people,’” Bosio muses. “Even supposing that you could drill it, a horizontal well made ‘no economic sense,’ they said. ‘It will cost at least 10 times as much as a nearby vertical well but will never produce 10 times more. Besides, no coring, logging or testing will be possible, and it will collapse on you before a liner can be run.’ ”

In spite of the ridicule and disbelief of others, Bosio and his colleagues pressed on in May 1980 to drill the Lacq 90 (a total coincidence that this was the name of the well) in southern France, the first well drilled at 90° inclination.

“We had to swear that we would plug the well if it happened to disturb the drainage of the reservoir so production could go back to normal,” Bosio says as he stifles a laugh. “Lacq 90 went 275 m (902.2 ft) within the reservoir with 100 m (328 ft) purely horizontal at a cost of 3.2 times that of a vertical well,” he continues. “It did produce . . . much more water than its neighbors since the reservoir was 90% watered out.” This led to claims that horizontal wells were only good for producing water, an unfair statement that did nothing to advance the technology. Shrugging off such comments, Bosio had much better luck later on with the well’s successor, the Lacq 91.

With their data in hand, Bosio’s group set out to apply it in the Rospo Mare field, a perfect laboratory for the development of horizontal-drilling techniques. The field is unique because the nature of its reservoir and the characteristics of its oil prevent it from being produced through conventional vertical wells. By early 1981, five wells, all vertical, had been drilled from a platform at the center of the field to appraise, set the field’s limits, and begin exploitation.⁵

“Our attention now turned to the Rospo Mare field,” states Bosio enthusiastically. “We drilled the Rospo Mare 6 in January 1982, 370 m (1,213.9 ft) of which was horizontal at a cost factor of 2.1 times more than a vertical well. More importantly, it was an immediate success, producing 20 times more oil than a neighboring vertical well and boosting the field’s recoverable reserves from near zero to 70 million barrels,” says Bosio proudly.

Bosio believed the Rospo Mare 6 well’s success would jolt the industry into jumping aboard the horizontal-well bandwagon. Unfortunately, the success was greeted with a big industry yawn.

Bosio recalls his experience in giving a paper on the well at the 1983 World Petroleum Congress (WPC) meeting in London. “When I went to the chair to present the first paper ever presented on horizontal wells, more than half the room, which was full from the preceding paper, got up and left! They simply weren’t interested,” Bosio explains. “At the next WPC in 1987 in Houston, the paper I presented attracted a small crowd. Then, at the 1991 WPC in Buenos Aires, we had a full session on horizontal wells.”

Finally, producers had begun to realize that horizontal wells can increase production rates and ultimate recovery, reduce the number of platforms or wells required to develop the reservoir, reduce stimulation costs, and bypass environmentally sensitive areas.⁶

Multilateral Wells

The acknowledged father of multilateral technology is Alexander Grigoryan. In 1949, Grigoryan became involved in the theoretical work of American scientist L. Yuren, who maintained that increased production could be achieved by increasing borehole diameter in the productive zone. Grigoryan took the theory a step further and proposed branching the borehole in the productive zone to increase surface exposure.

Grigoryan put his theory into practice in the former U.S.S.R.’s Bashkiria field (today’s Bashkortostan). There, in 1953, he used downhole turbodrills without rotating drillstrings to drill Well 66/45 in the Bashkiria Ishimabainefti field. His target was the Akavassky horizon, an interval that ranged from 10 to 60 m (32.8 to 196.8 ft) in thickness. He drilled the main bore to a total depth of 575 m (1,886.4 ft), just above the pay zone, and then drilled nine branches from the open borehole without cement bridges or whipstocks. When completed, the well had nine producing laterals with a maximum horizontal reach from kickoff point of 136 m (446.1 ft). It was the world’s first truly multilateral well, although rudimentary attempts at multilaterals had been made since the 1930s.

Compared to other wells in the same field, 66/45 was 1.5 times more expensive, but it penetrated 5.5 times the pay thickness and produced 17 times more oil each day. Grigoryan’s success with the 66/45 well inspired the Soviets to drill an additional 110 multilateral wells in their oil fields during the next 27 years, with Grigoryan drilling 30 of them himself.

Like horizontal wells, multilateral wells justify their existence through their economics. Defined as a single well with one or more wellbore branches radiating from the main borehole, they can be an exploration well, an infill development well or a re-entry into an existing well. But they all have a common goal of improving production while saving time and money.

Multilateral-well technology has not yet evolved to the point of horizontal-well technology. The complexity of multilateral wells ranges from simple to extremely complex. They may be as simple as a vertical wellbore with one sidetrack or as complex as a horizontal extended-reach well with multiple lateral and sublateral branches.⁷ While existing techniques are being applied and fresh approaches are being developed, complications remain, and the risks and chances of failure are still high.

The Future

As indicated earlier, it took several decades for the industry to endorse the concept of drilling horizontal and high-angle wells. Producers had to be convinced that the two- or three-fold cost increase of horizontally drilled wells would be justified. Once producers got a taste of the 15- to 20-fold production increases, they wholeheartedly jumped on the bandwagon.

“This initial growth of horizontal drilling has been quite rapid and now represents about 10 to 15% of all drilling activity. The future growth of horizontal wells depends on how the industry handles the next rounds of technological advancement,” Schuh says.

“The present state-of-the-art is economically attractive in easily drilled formations where the reservoir can be efficiently produced without the need of mechanical intervention. The greatest growth potential is in harder-to-drill formations and reservoirs that require selective completions, selective isolations, and stimulation operations. “Success in these areas will require new drilling equipment, a great expansion of completion options and development of new completion equipment and well-repair techniques,” Schuh concludes.

It seems that the future of multilateral technology will follow that same course. According to Jim Longbottom,⁸ a service/supply company engineer in multilateral technology and a highly published author, multilateral completions have a bright future, but it will be some time before that future is realized. “Drilling and completion of multilateral wells is at the same development state as horizontal drilling and completion was 10 years ago,” he says. “Acceptance and expansion of multilateral drilling indicate that within a decade, multilaterally completed wells will be as commonplace throughout the industry as horizontal wells are now.

“Asset managers have at their disposal the tools and technology to extract more value than ever before from their holdings,” he continues. “Horizontal and re-entry multilateral drilling has increased 50% during the past 5 years and will likely grow at more than 15% a year through 2000.”

However, if Longbottom’s predictions are to come true, multilateral technology will have to win over the Gulf of Mexico (GOM) operators, who seem to possess a mysterious lack of enthusiasm. Apparently these producers, who by nature are conservative, differ with their more risk-oriented counterparts operating in other parts of the world. GOM operators have a long tradition of resisting innovation, opting instead for systems that are dominated by near-term profit. They tend to shun new, exotic solutions to their daily problems.⁹

Some believe the future of multilateral-well development is tied to advances in the methods for drilling these wells—directional and horizontal drilling techniques, advanced drilling equipment, and coiled- tubing drilling. This may be true. However, it is also important to note that the industry’s ability to analyze the production and reservoir performance of multilaterals, particularly in a cost-effective manner, has fallen behind. Currently, drilling technology has temporarily outstripped the industry’s capabilities in production and reservoir-engineering analysis. It will catch up, but these factors are also a major impediment to more widespread application of multilaterals, particularly where improved-recovery methods are expected to be used.

Perhaps the biggest push on operators to install multilaterals in the future will come from the technology’s economics. Historically, when operators have found themselves in extended periods of depressed oil prices about which they could do nothing, they have reduced operating and capital expenditures to help the bottom line. Then, to help squeeze more oil from every drilling and completion dollar spent, they have turned to new technologies, even if they hadn’t endorsed them before. Most recently that technology has included geosteering, improved seismic data, and horizontal wells.

Also, multilateral technology offers an attractive package of economic incentives to producers looking for bottom-line help. Multilaterals allow multiple wells to be drilled from a single main wellbore, eliminating costly rig days for drilling an upper hole section for each well. And the ability to tap several zones from branches off a single wellbore, rather than a number of vertical ones drilled through the same section, holds the added attraction of risk reduction.

But the biggest economic driver will be deepwater offshore wells, where risks are high and the huge cost of deepwater installations can be reduced by multilaterals that shrink the number of wells and the amount of ancillary drilling and completion work needed to access high-production-rate fields.

As for horizontal wells, their future is assured. For multilateral wells, the pendulum is beginning to swing in their favor as operators steadily realize that the advantages of these systems are increasingly outweighing their risks. This is making their future look a lot more secure.

“When we talked to our drillers [about going beyond 70° inclination] . . . they first laughed and then turned real mad at ‘those crazy R&D people.’ ”

References

Novy, R.A.: “Pressure Drops in Horizontal Wells: When Can They Be Ignored?,” SPE Reprint Series No. 47, Horizontal Wells, SPE, Richardson, TX (1998) 109.
Jones, A.T. and Davies, D.R.: “Quantifying Acid Placement: The Key to Understanding Damage Removal in Horizontal Wells,” SPE Reprint Series No. 47, Horizontal Wells, SPE, Richardson, TX (1998) 127.
Bosio, J. and Reiss, L.H.: “Site Selection Remains Key to Success in Horizontal-Well Operations,” Oil & Gas J., Pennwell Publishing Co., Tulsa, OK (1988) No. 2 of a 7-part series, 9.
Briefing Paper, U.S. Dept. of Energy, Washington, DC (1999).
Dussert, P., Santoro, G., and Soudet, H.: “A Decade of Drilling Developments Pays Off in Offshore Italian Field,” Oil & Gas J., Pennwell Publishing Co., Tulsa, OK (1988) No. 1 of a 7-part series, 4.
Allen, D. et al.: “Modeling Logs for Horizontal Well Planning and Evaluation,” Oilfield Review, Schlumberger (Winter 1995) 47.
Bosworth, S. et al.: “Key Issues in Multilateral Technology,” Oilfield Review, Schlumberger (Winter 1998) 14–17.
Longbottom, J. and Herrera, I.: “Multilateral Wells Can Multiply Reserve Potential,” The American Oil & Gas Reporter, National Publishing Group Inc., Wichita, KS (September, 1997) 53.
von Flatern, Rick: “Multilaterals Remain a Gulf Mystery,” Offshore Engineer, Atlantic Communications/Emap Publishing Co., London, England (January, 1998) 50.