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New life from old oil wells.

The Persian Gulf crisis has drawn new attention to the U.S. oil business, as petroleum companies seek domestic sources to offset possible shortfalls of imported crude. Since this latest oil boom occurs against an environmental backdrop that limits the freewheeling exploration of decades past, the industry's success in meeting demand in the 1990s may hinge on enhanced oil recovery methods from existing fields.

According to estimates, there are approximately 650,000 oil wells in the United States. But production at 450,000 of those wells is less than 3 barrels of oil per day (bopd). To tap oil resources beneath low-producing wells, one of the technologies receiving a great deal of attention is horizontal drilling. Oil reservoirs are often partitioned by vertical rock fractures. Sinking vertical wells means drillers may completely miss an oil-bearing fracture, or at most, tap a single fracture at a time. But by drilling a hole that curves in a horizontal direction from a vertical well-bore, it is possible to intersect and drain multiple fractures. Indeed, in cases where multiple fractures are successfully tapped, drillers report that oil production from horizontal wells is up to five times higher than that from vertical wells, at a cost that rises only 1.5 to 3 times over the expense of drilling a vertical well.

Horizontal drilling is not new, but recent innovations have widened its applications and made it more profitable. These include steering devices and computer models to improve drilling accuracy or drilling in multiple directions at multiple depths to increase the chance of striking oil; new synthetic diamonds and high-pressure water jets that can outperform metal drill bits; and adjustable motors that can cut both the curved and lateral sections of the underground wells.

One advantage of horizontal drilling is reduced pressure inside the well-bore, as compared to vertical wells. Higher pressure forces more water and gas into the well-bore, contaminating the oil. By adjusting the flow rates on a horizontal well, drillers can reduce water and gas contamination. Another advantage is that the use of adjustable motors reduces the number of tools needed at the oil field site and eliminates the expense of repeatedly removing a drill, adjusting it on the surface, and reinserting it into the well-bore.

Horizontal drilling even has an indirect environmental benefit; it holds down the number of vertical wells that must be drilled to expose oil fractures. It can also reduce the number of offshore oil platforms required, because it allows drilling from platforms constructed on the beach. Often, a single offshore drilling platform can be used to drill multiple horizontal wells.

Early Successes

Tapping offshore oil from lateral wells drilled from land-based platforms has been an established practice in places like Long Beach, Calif., since the 1920s, when drillers tilted bits to reach offshore oil deposits from shore-based platforms. However, this practice is properly termed directional drilling, since the lateral wells are drilled at a maximum of 45 degrees from the vertical well-bore, rather than the 90-degree angles of true horizontal drilling. Directional wells were drilled to get around watery barriers such as rivers or coastal shorelines. Much of the equipment used in horizontal drilling is the same as that used in directional drilling.

Horizontal drilling dates back to water wells in the early 1900s. Robert E. Lee of Coleman, Tex., built several horizontal drilling tools for oil exploration in the 1920s and successfully drilled the first horizontal well from a vertical well-bore in 1929 for Big Lake Oil Co. at a site near Texon, Tex. Modern-day horizontal drilling for oil dates from 1978, when French petroleum giant Elf Aquitaine (Paris) initiated a study on the subject. "The problem was less technological than psychological," said Jacques Bosio, deputy for research and development at Elf. "The industry said it couldn't be done, that gravity would pull the drill bit downwards, that horizontal drilling would cost 10 times as much as a vertical well. We found it was easier to turn a well 90 degrees than to turn the way people think."

Common oil field wisdom held that drillers could never get the standard steel equipment used in directional drilling to bend and stay flexible at a 90-degree angle. However, this turned out to be false. In 1980, Elf engineers employed the standard steel directional-well drilling equipment to drill a 220-meter-long 90-degree lateral well in Lacq, located in southern France. It cost three times as much as nearby vertical wells. A second horizontal well in Lacq, which was 370 meters long, cost 2.7 times as much as a vertical counterpart.

On the basis of the Lacq demonstration wells, Elf decided to drill its first commercial horizontal well in its offshore field in Rospo Mare, Italy, on the Adriatic coast. Rospo Mare's oil reservoir was broken by many vertical fractures, and the wells did not produce sufficient quantities of oil to be economical. But when Rospo Mare 6 was drilled 606 meters horizontally in 1982, production rose immediately. Since 1986, the Rospo Mare field has produced a profitable 25 million barrels of oil.

The variety of innovations in horizontal drilling and the international interest these improvements have piqued may be gauged by a study conducted by the U.S.-based Drilling Engineering Association (DEA), along with Phillips Petroleum Co. (Bartlesville, Okla.) and Maurer Engineering inc. (Houston). The DEA project on horizontal well technology gathered the accumulated experience of oil and service companies from 20 countries.

According to John Vozniak, Maurer's assistant project manager for DEA-44, data received from the forum's international participants point to a vast worldwide market for horizontal drilling, requiring as many as 10,000 wells per year by the year 2000. Much of this optimism is predicated on the continuing refinement of horizontal drilling technologies described by DEA-44, and their success in producing oil. (Vozniak was the chair of the session on horizontal drilling technology at ASME's 19th annual Energy Sources Technology Conference and Exhibition, which was held January 20-24 in Houston.)

Unpredictable Sites

One of the first U.S. locations for horizontal oil wells was the Austin Chalk formation of south Texas. The dense, cretaceous limestome of this area is noted for its vertical fractures and unpredictability. Vertical drilling in the Austin Chalk had peaked by 1977, with wells in the Chalk's Pearsall field such as Baggett No. 7 producing a meager average of 5 bopd.

Oryx Energy Co. (Dallas) reentered the Baggett No. 7 well and drilled out a horizontal extension 240 feet long. The well then produced 107 bopd. In 1986, Oryx extended the Baggett No. I I well 140 feet horizontally, increasing its production to 80 bopd from 7 bopd. Although the Baggett wells were not economical, Oryx management was convinced that new drilling techniques would make horizontal drilling in the Austin Chalk and elsewhere a competitive technology.

An early challenge for Oryx drilling engineers was finding drilling fluids that would not plug the fractures the company hoped to tap. In typical vertical oil well drilling, a drilling mud is used to circulate the rock cuttings upward and to balance the hydrostatic pressure so the oil will flow. Drilling mud is a fluid that can contain components such as clay, brine, polymers, or oil itself, depending on the characteristics of the formation being drilled. According to Ralph Maness, Oryx's Gulf Coast region drilling manager, clear water proved useful with the Baggett wells.

By April 1988, the company drilled Baggett No. 13, its first profitable horizontal well. This 2250-foot extension tested at 1607 bopd. Since then, Oryx has drilled longer lateral wells, some beyond 4000 feet, tapping a greater number of fractures from a single well-bore.

When combined with geoscientific methods of locating oil, Oryx believes horizontal drilling can prove itself as an exploratory tool. To test this thesis, Oryx chose the uneconomical E.B. Jones "B" No. 3 well in Zavala County, Tex., for their first exploratory horizontal well. "We believed that our subsurface mapping and seismic work declined a target that the previous well didn't properly test," recalled Bill Kaufman, who led the Oryx Advanced Exploration effort. This proved prescient, with the 8789-foot well testing at 2000 bopd and nearly 1.3 million cubic feet of natural gas.

Kaufman suggests that horizontal drilling may become a key element in reducing exploration, development, and production costs by increasing the chances of encountering oil reservoirs. This was the case in the Oryx development of Pearsall Field in the Austin Chalk. Oryx had completed 18 horizontal wells, three of them exploratory, in Pearsall Field by September 30, 1990. The company boosted its average gross dally production in the field from 6600 bopd in the previous January to 22,000 by the end of September, a 230 percent increase.

Sizing Curves

There are four commercially available types of horizontal drilling: ultrashort radius (1-15 feet), short radius (15-200 feet), medium radius (200- 1 000 feet), and long radius over 1000 feet). These refer to the length within which the well curves from a vertical to a horizontal position. Among the lessons Oryx learned in its groundbreaking exploration at Austin Chalk was that short-radius drilling causes excessive friction and does not permit sufficient extension into fractures. Controlling the curve on long-radius wells was costly, pointing to medium-range wells as the best solution in the Chalk.

Most commercially available horizontal drilling systems are medium range. Drillers using equipment manufactured by Drillers Systems Inc. (Houston) begin the curved, or build, section of horizontal medium-range wells by inserting a whipstock into an old vertical well-bore. This whipstock is an assembly of steel rollers and slides possessing a 2-degree curve that pushes the drill bit off to the side. The whipstock is hydraulically set to the proper depth and oriented by a gyroscope. A window is cut into the side of the drill casing by a 2-foot-long starter mill and expanded if necessary by a sidetracking mill and watermelon-shaped mill.

A double-bend downhole motor cuts the curved passage. It consists of a rotor and stator and a universal joint. Pumping drill mud through the stator rotates the stator and the drill. The 2-degree bend between the bearings on the universal joint and the I degree bend on the top of the motor cause the drill to follow a curved course. Fin-like stabilizers keep the motor steady. To change direction, drill rotation is stopped and the motor is realigned.

Horizontal drilling equipment is also made by Eastman Christensen, a division of Baker Hughes Inc. (Houston). John Eastman, founder of Eastman Directional Drilling and Oil Well Surveys, as the company was then known, purchased Robert Lee's patents when Lee joined the military prior to World War 11. Eastman Christensen introduced its medium-radius horizontal drilling system in 1985. The system is driven by the company's high-speed low-torque Navi-Drill Mach 1 positive-displacement motor.

Eastman Christensen's system uses either nonrotating or steerable motors. Nonrotating motors drill a true arc at a consistent build rate and are replaced by another motor to drill the straight lateral well section. Steerable motors can drill both straight and curved sections. Most medium wells drilled with Eastman Christensen equipment use a Mach 1 steerable motor with a double tilted U-joint housing. The double joint is bent in opposite directions, permitting the motor to drill a curve of 2 to 5 degrees per 100 feet. The angle drilled per 100 feet is referred to as the build rate.

In order to create higher build rates, Eastman Christensen's Drilling Research Center in Celle, F.R.G., developed the double kick-off submotor assembly. The two bends on the motor make possible build rates of up to 10 degrees. These assemblies have successfully drilled horizontal wells in Venezuela and Malaysia. To support the operation of the steerable motor, researchers at Eastman Christensen's Salt Lake City facility developed a fully retrievable 2-inch directional measurement-while-drilling (DMWD) tool. The DMWD contains sensors to chart the direction and angle of the drill. A computer decodes the sensor data to provide a real-time picture of the drill's trajectory that helps operators steer the drill as it proceeds down the hole. The system speeds operations because engineers and technicians don't have to repeatedly stop and manually reorient the drilling equipment.

Another Eastman Christensen innovation is an adjustable kick-off (AKO) subsection on the drill-motor housing that places the bend close to the drill bit. The AKO design can be adjusted to the motor housing tilt angle at settings ranging from 0 to 2 degrees and can drill curves up to 12.5 degrees per 100 feet. Because the AKO can achieve a variety of build rates with a single motor, it reduces the number of drilling tools needed in the field. Economically successful medium-range horizontal wells have been drilled with the AKO motor in the United States, France, Gabon, Holland, and Norway.

Aggressive Angles

Guided Horizontal Drilling Inc. (Houston) developed a medium-range horizontal drilling system using downhole high-speed motors capable of 600 to 800 rpm. The motors range in size from a 2 7/8-inch model that is used to drill 3 1/2- to 4 1/2-inch holes, to a 9-inch motor that drills holes 17 1/2 inches in diameter.

Bent housings on the motors also vary, from 0.5 to 2.5 degrees depending on how sharp an angle the driller needs to build the curve; this can be anywhere from 12.5 to 19 degrees per 100 feet according to Vlado Katic, president of Guided Horizontal Drilling.

When this system is steered in the curved section of a well, the rotating motor is stabilized by spiral fins placed opposite the bend in the motor. As the assembly slides forward to drill the lateral well, deflection pads are used opposite the motor bend.

The Guided Horizontal Drilling system has been used to drill over 100 medium-radius horizontal wells in the Austin Chalk oil field. Sixty percent of these were from depleted vertical wells drilled in the early 1980s; the remainder were from new wells. Hole diameters drilled horizontally from existing wells averaged about 4 1/2 inches, while lateral drilling from new vertical wells averaged 8 1/2 inches. "By drilling as much as 2000 feet laterally, reentry and new wells initially produced from 300 to 3000 barrels of oil per day, with a few exceptional ones yielding over 5000," Katic said.

Durable bits have been a key factor in the success of the Guided Horizontal Drilling system. When the system was being developed in 1985, conventional diamond bits were used, which lasted 200 feet and drilled 4 to 6 feet per hour in Austin Chalk. Research conducted by PDC Bits Inc. (Houston) and Maurer Engineering led to the use of thermally stable bits made of synthetic polycrystalline diamond. These bits drill up to 30 feet per hour and can last for the entire 2000 feet of the well.

Although most horizontal wells are of medium radius, there are situations where drillers turn to the extended reach of long-radius wells. These include research wells to determine the extent of a reservoir, off-shore platform drilling, remote surface locations, or drilling in areas where there are no lease-size limitations on a well's profile. Eastman Christensen uses its low-speed high-torque double tilted U-joint NorTrak motors to permit the build rates of 2 to 5 degrees that long-radius wells require. These motors employ larger drilling tools than their medium-range counterparts to make longer holes. For example, the NorTrak Mach 1 motor used in long-radius drilling can use 11 1/4-inch drilling tools to drill holes up to 26 inches in diameter.

Measurement-while-drilling technology combined with steerable motors, has cut costs for long-radius horizontal drillers using Eastman Christensen's system. One operator of a multiwell drilling program in the Java Sea spent $62 per foot using Eastman Christensen steerable motors. Had the driller used rotary techniques, the cost per foot would have been about $240.

Whether the well has a medium, long, or short radius, Eastman Christensen's horizontal drilling engineers benefit from an integrated drilling software package they developed called EC Trak. The package includes programs on well planning, hydraulics, and casing wear analysis. An added feature, the Drilling Database System, stores the drilling records, well name, location data, and borehole adjustment of each drilling job. This information has proven valuable in anticipating problems when planning new wells. Eastman Christensen engineers have access to EC Trak programs at the rig site as well as in corporate offices by means of portable or laptop computers.

Multiple Depths

In most formations that lend themselves to horizontal drilling, the longer a lateral well tunnels, the better the chance of striking oil-laden fractures in rock. In contrast, the ultra-short-radius horizontal wells drilled with Petrolphysics Inc. (San Francisco) technology have yielded untapped oil from lateral extensions measuring only 100 to 200 feet long. That is because Petrolphysics drills four wells at different depths and in different directions, increasing the chances of hitting oil separated by depth, rather than by vertical fractures, as is the case in some formations.

This method is not limited to quadruple drillings. "We drilled 205 horizontal wells in five levels in the Kern River Field, near Bakersfield Calif., just to demonstrate it could be done," said Wade Dickinson, the company's president. Petrolphysics' ultrashort horizontal drilling system is designed to work in unconsolidated rock, the sandy material typical of formations such as those found at Kern River. Hole diameters range from as little as 2 inches to as big as 18.

Instead of employing a metal or diamond bit, Petrolphysics uses water jets to drill its horizontal wells. Spraying these jets out of a nozzle at pressures ranging from 5000 to 10,000 psi creates a cone of water and rock particles that serve as abrasives to cut into the rock.

Petrolphysics controls its water drill by means of thruster jets of water positioned perpendicular to the nozzle. An electric valve on the nozzle is tied to a mercury bubble sensor similar to the bank-and-turn indicator used on an airliner. The valve adjusts the thrusters to keep the ultrashort drill on course.

One benefit of ultrashort drilling has been improved oil production. Normally, oil wells will produce heavily for a time but drop off precipitously--about 70 percent in a single year. It was found that horizontal wells drilled by Petrolphysics' ultrashort technique were producing at a consistently high level for over a year.

Petrolphysics engineers have suggested that the drilling mud used in vertical wells plugged the pores in rock where oil is found. By drilling with water and abrasives, Petrolphysics "unplugs" those pores and liberates untapped oil.

To date, Petrolphysics has drilled more than 1000 multidirection multilayer ultrashort wells in the United States and Canada. The company is preparing to bring its equipment to Venezuela sometime in 1991. The company is also researching the feasibility of longer-range multiple lateral wells in a project sponsored by the federal government.

Short wells

Short-radius drilling is useful in tapping small oil lease sites. It can also reach shallow oil reservoirs more easily, making pumping easier since it brings the vertical hole closer to the oil and requires the minimum measured depth to reach its horizontal angle. In order to drill a horizontal well within a 20- to 40-foot arc, Eastman Christensen designed a flexible positive-displacement motor, joining its sections with articulated couplings.

By making this system steerable, Eastman Christensen increased the length of its short-radius horizontal wells from the typical 400-foot length drilled by the preceding rotary system to 1500 feet. The precision drilling capability of the steerable downhole motor is useful in drilling within very narrow target boundaries where there is little margin for error.

The short-radius rotary system is still successfully used in formations including chalks, dolomites, and limestones. The system's nonrotating flexible shell is cut two-thirds around. This gives it sufficient flexibility to fit the arc profile by bending without stressing. When forced straight into the hole, the shell applies about 1000 pounds of side force on the drill bit, causing the drill to curve along the desired trajectory. Stabilizers on the backside of the shell control the build rate during this process. A flexible liner allows fluid to circulate.

Horizontal equipment manufacturers are optimistic about the future of lateral oil drilling. "This country has been pretty thoroughly explored there are likely no remaining undiscovered big fields," said of Petrolphysics. "However, it has been calculated that two-thirds of American oil reserves are still underground. Horizontal drilling methods permit drillers to access that oil."
COPYRIGHT 1991 American Society of Mechanical Engineers
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Title Annotation:horizontal drilling
Author:Valenti, Michael
Publication:Mechanical Engineering-CIME
Date:Feb 1, 1991
Words:3406
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