The application of horizontal drilling technology to the discovery and productive development of oil reserves has become a frequent event over the past 5 years. A recently published Energy Information Administration Technical Report, DRILLING SIDEWAYS -- A REVIEW OF HORIZONTAL WELL TECHNOLOGY AND ITS DOMESTIC APPLICATION (DOE/EIA-TR-0565, April 1993) addressed this subject, focusing primarily on domestic horizontal drilling applications and on salient aspects of current and near-future horizontal drilling and completion technology. This feature article is based upon key portions of that report.
The areas of most oil and gas reservoirs are much more extensive than are their thicknesses. By drilling that portion of a well which intersects such a reservoir along its more extensive dimension, rather than vertically through its thickness as has conventionally been done, horizontal drilling exposes significantly more reservoir rock to the wellbore surface (Figure 1). The choice of horizontal drilling is frequently motivated by other objectives (such as avoidance of water production) related to specific physical characteristics of the target reservoir. Several examples of these are given later on.
The initial (usually vertical) portion of a horizontal well, unless very short, is typically drilled using the same rotary drilling technique that is used to drill most vertical wells. Depending on the intended radius of curvature and the hole diameter, the arc section of a horizontal well may be drilled either conventionally or by use of a drilling fludriven motor mounted downhole directly above the bit. The near-horizontal portions of a well are almost always drilled using a downhole motor. It is possible to drill the arc section of the well bore because the drill pipe sections are sufficiently flexible that each can be bent a distance off the initial axis without significant risk of structural failure. The smaller the pipe diameter and the more ductile the steel alloy, the greater the deviation that can be achieved within a given drilled distance, i.e., the smaller the arc's radius can be made. Downhole instrument packages that telemeter sensor readings to operators at the surface are included in the drill string near the bit, at least while drilling the arc and near-horizontal portions of the hole. Minimally, a sensor provides the subsurface location of the drill bit so that the hole's direction can be tightly controlled. Control of hole direction (steering) is accomplished through the employment of at least one of: a steerable downhole motor, downhole subassemblies that introduce small angular deviations into the drill string, and eccentric pipe stabilizers, all of which come in manually and remotely adjustable versions. The additional cost of remote control capability may, in many instances, be outweighed by time-related savings, due to a substantial reduction of the number of trips(1) needed, many of which would be made for the sole purpose of direction adjustment. Additional downhole sensors can be, and often are, included in the drill string. They may provide such information on the downhole environment as bottom hole temperature and pressure, weight on the bit, bit rotation speed, and rotational torque. They may also provide any of several measures of the physical characteristics of the surrounding rock and its fluid content, similar to those obtained via conventional wireline well logging methods, but in this case obtained in real time while drilling ahead. The downhole instrument package, whatever its composition, is referred to as a measurement-while-drilling (MWD) package.
The advantages of horizontal drilling come at a price: a horizontal well can be anywhere from 25 percent to 300 percent more costly to drill and complete for production than would be a vertical well directed to the same target horizon. PETROLEUM ENGINEER INTERNATIONAL (PEI) reported that horizontal wells drilled in the U.S. during 1989 had averaged slightly over $1 million per well to drill, plus an additional $140,000 per well to complete for production. The average cost per foot of horizontal displacement was $475 nationally, and $360 for horizontal wells drilled into the Upper Cretaceous Austin Chalk Formation of Texas(2), while some experienced companies got close to $300/foot in 1990.(3) The cost difference reflects a combination of sometimes radically different drilling conditions. Also, at this early stage of technology application, each new type of target has a "learning curve" for developing optimal drilling and completion techniques for that target. Costs of successive wells tend to fall as more is learned and technique is improved. Additionally reflecting the cost premium, the industry's JOINT ASSOCIATION SURVEY ON 1990 DRILLING COSTS(4) reported that average horizontal drilling cost per foot of wellbore was $88.16 as compared to $75.40 for wells not drilled horizontally, a 17-percent difference. Total expenditures on horizontal drilling reached $662 million in 1990, representing 6 percent of the total drilling expenditure of $10.937 billion.
Even when drilling technique has been optimized for a target, the expected financial benefits of horizontal drilling must at least offset the increased well costs before such a project will be undertaken. In successful horizontal drilling applications, the "offset or better" happens due to the occurrence of one or more of a number of factors. First, operators often are able to develop a reservoir with a sufficiently smaller number of horizontal wells, since each well can drain a larger rock volume than a vertical well could. Second, a horizontal well may produce at rates several times greater than a vertical well, due to the increased wellbore surface area within the producing interval. For example, in the Austin Chalk reservoir of Texas' Giddings Field, under equal pressure conditions, horizontal completions of 500 to 2,200 foot horizontal displacement produce at initial rates 2 to 7 times higher than vertical completions.(5) Chairman Robert Hauptfuhrer of Oryx Energy Co. noted that "Our costs in the [Austin] chalk now are 50 percent more than a vertical well, but we have three to five or more times the daily production and reserves than a vertical well."(6) A faster producing rate translates financially to a higher rate of return on the horizontal project. Third, use of a horizontal well may preclude or significantly delay the onset of production problems that engender low production rates, low recovery efficiencies, and/or premature well abandonment.
Little horizontal drilling occurred until the early 1980's, by which time improved downhole drilling motors and the invention of other necessary supporting equipment, materials, and technologies, particularly downhole telemetry equipment, had brought some kinds of applications within the imaginable realm of commercial viability. Tests indicating that commercial horizontal drilling success could be achieved in more than isolated instances were carried out between 1980 and 1983 by the French firm Elf Aquitaine in four horizontal wells drilled in three European fields. These included the Rospo Mare Oil Field, located offshore Italy in the Mediterranean Sea, where output was very considerably enhanced.(7) Early horizontal production well drilling was subsequently undertaken by British Petroleum in Alaska's Prudhoe Bay Field, in a successful attempt to minimize unwanted water and gas intrusions. Horizontal drilling has since been undertaken with increasing frequency by many more operators. Domestic horizontal wells have now been planned and completed in at least 57 counties or offshore areas located in or off 20 States. They have been almost entirely focused on crude oil applications. In 1990, worldwide, more than 1,000 horizontal wells were drilled. Some 850 of them were targeted at Texas' Upper Cretaceous Austin Chalk Formation alone.(8) Less than 1 percent of the domestic horizontal wells drilled were completed for gas, as compared to 45.3 percent of all successful wells (oil plus gas) drilled.(9) Of the 54.7 percent of all successful wells that were completed for oil, 6.2 percent were horizontal wells. Market penetration of the new technology has had a noticeable impact on the drilling market and on the production of crude oil in certain regions. For example, in mAugust of 1990, crude oil production from horizontal wells in Texas had reached a rate of over 70,000 barrels per day.(10)
Petroleum engineers categorize horizontal wells according to the radius of the arc described by the wellbore as it passes from the vertical to the horizontal. Wells with arcs of 3 to 40 foot radius are defined as short-radius horizontal wells. Medium-radius wells have arcs of 200 to 1,000 foot radius, while long-radius wells have arcs of 1,000 to 2,500 feet.(11) The required horizontal displacement, the required length of the horizontal section, the position of the kickoff point (from the vertical), and completion constraints are generally considered when selecting a radius of curvature.
Short-radius horizontal wells are commonly used when re-entering existing vertical wells in order to use them as the physical base for the drilling of add-on arc and horizontal hole sections. The steel casing (lining) of an old vertical well facilitates attainment of a higher departure (or "kick off") angle than can be had in an uncased hole, so that a short-radius profile can more quickly attain horizontality, and thereby rapidly reach or remain within a pay zone. The small displacement required to reach a near-horizontal attitude favors the use of short-radius drilling in small lease blocks, while a need to avoid extended drilling in a difficult overlying formation may call for use of a short-radius well that kicks off near the bottom of, or below, the difficult formation. Short-radius horizontal drilling also has certain economic advantages over longer radius drilling. These include a lower capital cost,(12) the fact that the suction head for downhole production pumps is smaller, and that use of an MWD system is frequently not required if long horizontal sections are not to be drilled. A current drawback to use of a short-radius horizontal well is that adequate tools do not yet exist to reliably do producing zone isolation, logging, remedial, or stimulation work in short-radius holes. Most therefore have to be completed open hole (no casing), and to allow this the reservoir rock must be physically competent, or serious production problems will result.
Medium-radius horizontal wells allow the use of larger hole diameters, near-conventional bottom hole (production) assemblies, and more sophisticated and complex completion methods. It is also possible to log the hole. Although the drilling of medium-radius horizontal wells does require the use of an MWD system, which increases drilling cost,(13) medium-radius holes are perhaps the most popular current option. They can be drilled on leases as small as 20 acres.(14) Long-radius holes can be drilled using either conventional drilling tools and methods, or the newer steerable systems. Long-radius wells, in the form of deviated wells (not, however, deviated to the horizontal), have existed for many years. They are not suited to leases of less than 160 acres due to their long lateral displacements before reaching the horizontal.
The attainable horizontal displacement, particularly for medium- and long-radius wells, has grown significantly, as operators and the drilling and service contractors have devised, tested, and refined their procedures, and as improved equipment has been designed and used. Routinely achievable horizontal displacements have rapidly climbed from 400 to over 8,000 feet.(15)
As noted previously, horizontal drilling is usually undertaken to achieve important technical objectives related to specific characteristics of a target reservoir. These characteristics typically involve the reservoir rock's permeability, which is its capacity to conduct fluid flow through the interconnections of its pore spaces (matrix permeability), or through fractures (fracture permeability), and/or the expected propensity of the reservoir to develop water or gas influxes deleterious to production. Due to its higher cost, horizontal drilling is restricted to situations where vertical wells would not be as financially successful. In an oil reservoir which has good matrix permeability in all directions, no gas cap, and no water drive, drilling of horizontal wells would likely be financial folly, since a vertical well program could achieve a similar recovery of oil at lower cost. But when low matrix permeability exists in the reservoir rock (especially in the horizontal plane), or when intrusion of gas or water can be expected to interfere with recovery, horizontal drilling becomes a financially viable or even preferred current option.
By far the most intense domestic application of horizontal drilling has been in a few Texas oil fields in which the Upper Cretaceous Austin Chalk Formation is the reservoir rock. At year-end 1990, some 85 percent of all domestic horizontal wells had been drilled to the Austin. Most of the productive permeability in the formation is fracture permeability, rather than matrix permeability. As a consequence, horizontal wells drilled to intersect several vertical fractures at an approximate right angle have typically demonstrated much larger initial production rates than were provided by previously drilled vertical wells which, at best, intersected only one vertical fracture. Production from Austin Chalk horizontal wells in the Pearsall Field has been responsible for the recent increase of oil production experienced in Texas Railroad Commission District 1. A number of these wells tested at flows of over 1,000 barrels per day, a relatively unusual event in the modern day lower 48 States onshore. For example, the Winn Exploration Co. 10 Leta Glasscock tested at 5,472 barrels of oil per day accompanied by 2,368,000 cubic feet per day of gas.(16) Another Austin Chalk field, the Giddings Field, has also served as a commercial testing arena for horizontal drilling. An eight-well Amoco Production Company program showed an increase of productivity with increased length of horizontal displacement, relative to offsetting vertical wells. The productivity ratio (quantity obtained from the horizontal hole relative to quantity obtained from the offset vertical hole) measured at 500 feet of horizontal displacement was 2, whereas at 2,200 feet of horizontal displacement it was 7.(17) Horizontal drilling in the Giddings Field not only significantly improved average well recovery, it more than offset the increased drilling costs. A study of 91 horizontal wells, all drilled after August 1989, and all with at least 6 months of production history, showed an average 195,000 barrels of oil equivalent recovery over the economic well life. Three-fourths of this amount is obtained in the first 3 years. The study indicated that an average Giddings Field Austin Chalk horizontal well would return an after-tax investment (discounted at 10 percent) of 1.6:1, would have a net present value of $650,923, and would pay out its cost in 1.1 years.(18)
Beyond the fractured, low matrix permeability class of reservoirs exemplified by the various chalk formations, there are numerous other geologic situations in which horizontal drilling is being applied with less frequency. Early applications at Prudhoe Bay Field to avoid or minimize either water or gas intrusion have already been mentioned; many similar applications have since been executed there and elsewhere for the same purpose. An important type of application attempts to produce oil that has not yet migrated to a conventional trap, but instead remains in the porosity of the source rock unit in which it was generated. A prime example is the Mississippian Bakken Formation of North Dakota and Montana, which is an oil-wet shale believed to contain several billion barrels of oil-in-place. Meridian Oil, Inc., indicated that its Bakken horizontal drilling program had added net reserves of more than 16.6 million barrels of oil equivalent by March 1992.(19) Meridian's program followed a very clear learning curve. The first 10 wells had an after-tax rate of return of 30.6 percent, which climbed to 44.2 percent for the second 10 wells, and again to 66.6 percent for the third 10 wells. Pacific Enterprises Oil Co. indicated that, compared to vertical wells on 160 acre spacings, its Bakken horizontal wells, spaced at 320 acres, provided a 40-percent greater return on investment.(20) In North Dakota, oil production from horizontal completions rose steadily from nothing in 1986 to 3.7 million barrels in 1991, although it dropped off to 3.0 million barrels in 1992.(21)
Some effort to develop Silurian Niagaran reef structures (stratigraphic type traps) in the Michigan Basin has been undertaken.(22) Short and medium radius horizontal drilling techniques for coalbed methane recovery have been successfully demonstrated in several Western basins.(23) Meridian Oil, Inc., brought in one such San Juan Basin well that produced at a rate of 7 million cubic feet per day, as opposed to the average conventional well rate of 1.05 million cubic feet per day.(24) Yet another type of horizontal drilling application attempts to increase the recovery factor (the produced fraction of oil-in-place) experienced in already mature reservoirs that have high heterogeneity or overall low permeabilities.
Horizontal drilling technology has also inspired new approaches to the injection of fluids or heat into oil or tar sand reservoirs to enable or improve recovery. Dramatic oil production gains have been reported in the New Hope Field, Franklin County, Texas, by Texaco Exploration & Production Inc., utilizing two horizontal injection wells drilled into the Lower Cretaceous Pittsburg reservoir. The Pittsburg is a relatively thin, low permeability sandstone. Since introduction of the horizontal injection wells, production per producing well has increased from about 100 to about 400 barrels of oil per day, the highest production rates in the history of the field.(25) Costs of the development are estimated at $2 to $3 per barrel of incremental reserves added. Company officials estimate that the productive life of the New Hope shallow unit has been extended by 10 to 15 years.(26) Cyclic steam injection through multiple ultrashort radius horizontal radials has been tested in a Department of Energy-sponsored project at the Midway-Sunset Field, California. The field has a history of successful thermal operations and is California's second largest current producer. A set of eight radials was drilled into a cold zone within the 400-foot thick Upper Miocene Potter C reservoir interval, located at a depth of 884 feet. Temperature logging in an observation well located 50 feet from the end of one of the radials showed a substantial temperature increase in the 800- to 875-foot interval, demonstrating effective containment of steam in the target interval. Production from the well started out very low in the first week and then increased over the next 3 weeks to a peak of 60 barrels of oil per day with a 30 percent water cut. Production stayed strong from mJuly 1990, through the first week of October.(27)
Virtually all relevant trade journals have carried articles over the past 5 years expressing considerable optimism as to the business growth prospects of horizontal drilling. So far, these predictions appear to be valid. A close student of the subject, David Yard, estimated in January 1990 that horizontal completions would escalate by 230 percent annually, and that more than 2,000 successful completions could be expected in 1992. He also expected lifting costs to fall into the $4- to $6-per-barrel range.(28)
New developments which will affect horizontal drilling include increased use of coiled tubing in lieu of standard drill pipe and the use of smaller hole diameters, so-called slim hole drilling. Coiled tubing is a continuous (jointless) length of pipe that is stored wrapped around a large reel. In operation, the tubing is straightened off the storage reel and led over a curved guide to and through a motorized injector head mounted atop the well control equipment stack, and thence through the control stack into the well. Tools are attached to the downhole end; wire cables can also be passed, and fluids circulated, through the tubing. The tubing's wall thickness is considerably less than that of conventional jointed drill pipe and its diameter is also less. The smaller dimensionality, as well as the use of different alloys, renders the tubing much more flexible than standard drill pipe, at the expense of increased fragility and decreased load handling capabilities in both compression and tension. Thus, tighter controls on operating conditions and handling methods are required in coiled tubing applications than are normally applied when using conventional drill strings. Offsetting that drawback is the fact that a coiled tubing unit is often less expensive to operate than a conventional drilling rig, for a number of reasons. A coiled tubing unit is quicker to rig up on-site. "Run in" and "pull out" rates can exceed 170 feet per minute, so when numerous trips are required, use of a coiled tubing unit significantly reduces total on-site time and, therefore, cost. Another favorable factor is that fluid circulation can be maintained at all times since there is no need to break apart joints of pipe when tripping. A bonus, from both cost and environmental viewpoints, is that a coiled tubing unit typically has a smaller footprint and is less noisy relative to a conventional drilling rig. Finally, operations performed by the use of coiled tubing technology are often less damaging to the potential producing formation than if performed using conventional drilling and completion methods.(29)
Application of coiled tubing technology in the drilling, completion, and servicing of horizontal wells has been growing both absolutely and with respect to the range of jobs performed. Wells with horizontal displacements of over 1,500 feet have been drilled using coiled tubing. Drill-out of blockages in existing wells using positive displacement mud motors mounted to coiled tubing have also worked, with the advantage that horizontal wells can be entered via coiled tubing without the prior removal of production tubing or liners.(30) Coiled tubing is also used in horizontal wells to insert and manipulate flow control equipment that regulates reservoir drainage, as well as in the traditional well workover application, the precision placement downhole of various fluid treatments such as cement slurries and acid gels. Over time, it is to be expected that lighter but nevertheless robust tools will be developed, extending the capabilities of the technology. Its use is expected to continue to grow rapidly in both horizontal and conventional applications.
Slim hole drilling is a trend that undoubtedly will be used more in both deviated and horizontal applications over the next few years. Most conventional oil and gas wells have been, and continue to be, drilled at a successively smaller series of diameters as depth increases, such that the bottom hole segment is on the order of 6 inches or larger, and the higher segments telescope upward in diameter between the bottom hole and final surface diameters. Slim hole drilling simply reduces the diameter of each segment substantially. The use of slim hole drilling in the oil and gas industry has been made possible by the development of materials and technologies that allow drilling, completion, and production operations within the bounds of the smaller involved diameters. As more instruments and tools are designed and built to accommodate the smaller diameters of slim holes, there will occur a perfectly natural extension of slim hole drilling to deviated and horizontal drilling operations, due to its principal advantage: reduced cost. For example, steel is priced by the ton and 1,000 feet of casing for 12 inch hole weighs 59 tons while the equivalent length of 8 inch hole casing weighs only 29 tons.(31) Lower costs similarly result for many other items such as drill pipe, drill bits, fuel costs, mud chemicals, cement, and cuttings cleaning and disposal. Beyond that, the overall size of the necessary drilling rig, its hook (lifting) capacity, and its footprint can all be lowered by scaling down the hole diameter. Finally, time to total depth is usually reduced, as a smaller diameter hole is usually much quicker to drill, all other factors being the same.
Yet another trend is the increased frequency of drilling multiple laterals from the initial vertical section of a hole. There are many instances in which two horizontal laterals have been successfully drilled and completed, running in opposite directions from the kickoff point. There are also instances in which several short and short-radius laterals have been drilled in a radial pattern from a single initial vertical hole section. Expansion to the drilling of multiple laterals with longer lengths and larger radii is not far off. Other technologies under development, such as creation of lower operating cost, computer managed "fire and forget" drilling systems, will also eventually affect horizontal well economics.
The technology of horizontal drilling has become an important tool of the oil industry over the past 10 to 12 years. A particular synergism of developments among equipment and techniques has aided its widespread testing and use. In many basins and reservoirs, properly applied horizontal drilling technology has demonstrated a distinct advantage over vertical wells.
A copy of the complete Technical Report from which this article was taken can be purchased from the Superintendent of Documents, U.S. Government Printing Office. Information regarding purchases is available from the National Energy Information Center, EI-231, Forrestal Building, Room 1F-048, Washington, DC 20585, (202) 586-8800.
(1) A "trip" encompasses removal of the entire drill string from the hole, usually for the purposes of adjustment or change of hardware, followed by reinsertion. A typical trip to a depth of several thousand feet can consume several hours, during which time no forward progress is made while the operating and rig rental costs continue unabated.
(2) Steven D. Moore, "Horizontal Drilling Activity Booms," PETROLEUM ENGINEER INTERNATIONAL, (November 1990), pp. 15-16.
(3) Steven D. Moore, "The Horizontal Approach," PETROLEUM ENGINEER INTERNATIONAL, (November 1990), p. 6.
(4) Finance, Accounting and Statistics Department, American Petroleum Institute, JOINT ASSOCIATION SURVEY ON 1990 DRILLING COSTS, (November 1991), pp. 4-5.
(5) B.A. Shelkholeslami and others, "Drilling and Production Aspects of Horizontal Wells in the Austin Chalk," JOURNAL OF PETROLEUM TECHNOLOGY, (July 1991), SPE Paper Number, p. 779.
(6) "Oryx's Hauptfuhrer: Big increase due in U.S. horizontal drilling," OIL & GAS JOURNAL, (January 15, 1990), p. 28.
(7) "Horizontal Drilling Contributes to North Sea Development Strategies," JOURNAL OF PETROLEUM TECHNOLOGY, (September, 1990), p. 1154.
(8) Steven D. Moore, "Technology for the Coming Decade," PETROLEUM ENGINEER INTERNATIONAL, (January 1991), p. 17.
(9) Finance, Accounting and Statistics Department, American Petroleum Institute, JOINT ASSOCIATION SURVEY ON 1990 DRILLING COSTS, (November 1991), p. 4-5.
(10) "The Austin Chalk & Horizontal Drilling," POPULAR HORIZONTAL, (January/March 1991), p. 30.
(11) For medium- and long-radius: B.A. Shelkholeslami, B.W. Schlottman, F.A. Seidel, and D.M. Button, "Drilling and Production Aspects of Horizontal Wells in the Austin Chalk," JOURNAL OF PETROLEUM TECHNOLOGY, (July 1991), SPE Paper Number 19825, p. 773.; other: S.D. Joshi, HORIZONTAL WELL TECHNOLOGY, Pennwell Publishing Company, (1991), Tulsa Oklahoma, pp. 13-18; for all: Lynn Watney, "Horizontal Drilling Is Feasible in Kansas," THE AMERICAN OIL & GAS REPORTER, (August 1992), pp. 84-86.
(12) "Horizontal Drilling and Completions: A Review of Available Technology," PETROLEUM ENGINEER INTERNATIONAL, (February 1991), pp. 14-15.
(13) Rainer Jurgens and others, "Horizontal Drilling and Completions: A Review of Available Technology," PETROLEUM ENGINEER INTERNATIONAL, (February 1991), p. 18.
(14) Lynn Watney, "Horizontal Drilling Is Feasible in Kansas," THE AMERICAN OIL & GAS REPORTER, (August 1992), p. 84.
(15) Rob Buitenkamp, Steve Fischer and Jim Reynolds, "Well claims world record for horizontal displacement," WORLD OIL, (October 1992), p. 41.
(16) "TEXAS," OIL & GAS JOURNAL, (January 1, 1990), p. 84.
(17) B.A. Shelkholeslami and others, OP. CIT., p. 779.
(18) William T. Maloy, "Horizontal wells up odds for profit in Giddings Austin Chalk," OIL & GAS JOURNAL, (February 17, 1992), pp. 67-70.
(19) M.G. Whitmire, "Fractured zones draw horizontal technology to Marietta basin," OIL & GAS JOURNAL, (March 30, 1992), p. 78.
(20) Sandra Johnson, "Bakken Shale," WESTERN OIL WORLD, (June 1990), pp. 31-45.
(21) Personal communication, North Dakota Industrial Commission, Oil and Gas Division.
(22) Scott Ballenger, MICHIGAN OIL AND GAS NEWS, Personal communication (June 24, 1992).
(23) Terry L. Logan, "Horizontal Drilling Techniques Used in Rocky Mountains Coal Seams," 1988-Coal-Bed Methane, San Juan Basin, Rocky Mountain Association of Geologists, pp. 133-141.
(24) "Meridian tests new technology," WESTERN OIL WORLD, (June 1990), p. 13.
(25) "Horizontal Wells Inject New Life Into Mature Field," PETROLEUM ENGINEER INTERNATIONAL, (April 1992), pp. 49-50.
(26) "Texaco completes horizontal injector in Southeast Texas oil field," OIL & GAS JOURNAL, (February 24, 1992), p. 44.
(27) Wade Dickinson, Eric Dickinson, Herman Dykstra, and John M. Nees, "Horizontal radials enhance oil production from a thermal project," OIL & GAS JOURNAL, (May 4, 1992), pp. 116-124.
(28) "Reservoir Engineering is Key to Horizontal Drilling," PETROLEUM ENGINEER INTERNATIONAL, (March 1990), p. 49.
(29) Vance Norton, Fred Edens, Glenn Coker, and George King, "Large diameter coiled tubing completions decrease risk of formation damage," OIL & GAS JOURNAL, (July 20, 1992), pp. 111-113.
(30) M. Wasson, F. Pittard, and L. Robb, "Horizontal Workover With Coiled Tubing and Motors," PETROLEUM ENGINEER INTERNATIONAL (June 1991), pp. 40, 42.
(31) "Smaller Top Hole Equates to Lower Drilling Costs," PETROLEUM
ENGINEER INTERNATIONAL, (September 1992), p. 17.
Source: -Petroleum Supply Monthly-, June 1993