Horizontal Drilling | What is a horizontal drilling?

(adsbygoogle = window.adsbygoogle || []).push({}); Learning Objectives After completing this topic “Horizontal Drilling”, you will be able to: What is horizontal drilling used for? Why is horizontal drilling better? What is vertical and horizontal drilling? Introduction Horizontal drilling is the process of directing part of a well course through a reservoir such that its inclination angle is approximately 90° from vertical. This horizontal section may be anywhere from a few feet to thousands of feet in length. Horizontal wells can trace their roots back to at least the 1930s (Ranney, 1939). But it was not until the 1980s that advances in directional drilling and formation evaluation brought them into the mainstream of oil and gas operations. Since then, in a number of fields, they have significantly outperformed conventional wells in terms of increased productivity, improved ultimate recovery and lower overall development costs. There have also been disappointments along the way, which have shown that the benefits of horizontal drilling are not all-encompassing, but are contingent on reservoir characteristics. Horizontal Drilling Applications (adsbygoogle = window.adsbygoogle || []).push({}); Horizontal wells work to best advantage in thin reservoirs having a relatively high ratio of vertical to horizontal permeability (vertically fractured formations are prime candidates) and a potential for drawdown-sensitive production problems like sand production water and gas coning. Other common candidates for horizontal drilling are: Reservoirs that would otherwise be economically inaccessible. Heavy oil reservoirs. Channel deltaic sand and reef core reservoirs. Coal bed methane reservoirs. Increasing reservoir contact within the reservoirs. Unconventional shale, tight oil & gas reservoirs. Figure 1 illustrates some typical applications of horizontal well technology. FIGURE 1 The remainder of this section focuses on drilling methods and considerations for horizontal wells. For a detailed discussion of horizontal well applications that addresses the reservoir management, formation evaluation, completion and stimulation aspects of this technology, the reader may refer to Economides (1993), or to the subject titled " Horizontal Wells: Completion and Evaluation," under the topic heading "Well Completion and Stimulation." (adsbygoogle = window.adsbygoogle || []).push({}); Well Configurations https://youtu.be/R794OnxvBwg (adsbygoogle = window.adsbygoogle || []).push({}); Horizontal drilling begins with a more-or-less vertical surface section (the one exception being slant drilling rigs, where this section is pre-inclined), followed by a bend section, which progresses from approximately 0° to 90° inclination with depth, and finally by a horizontal or lateral section. The transfer of weight to the drill bit during the horizontal drilling phase involves different concepts, which translate into different well configurations. We may generally distinguish these configurations, based on radius of curvature, as long turn radius, medium turn radius, short turn radius and ultra-short turn radius (Figure 1, Horizontal drilling methods): FIGURE 1 The considerations that enter into selecting one of these well configurations include cost well spacing and lease restrictions conditions of re-entry wells reservoir rock characteristics production methods well objectives problem-causing lithologies above the pay zone amount of total horizontal departure completion methods availability of specialized downhole tools kick-off depth constraints horizontal displacement constraints Table 1 and Table 2, below, compare the basic characteristics of long, medium and short radius wells. Table 1: Comparative Characteristics of Horizontal Drilling Methods (Mitchell, 2006) Long Radius Medium Radius Short Radius Build rate 2∘ 2^{\circ} to 6∘ 6^{\circ} per 100 ft 100\ ft 6∘−35∘ 6^{\circ} - 35^{\circ} per 100 ft 100\ ft 5∘−10∘ 5^{\circ} - 10^{\circ} per three feet Build radius (ft) 1000 - 3000 160 - 1000 20 - 40 Hole size (in) No limits 434, 618, 612, 812, 978 4\tfrac{3}{4},\ 6\tfrac{1}{8},\ 6\tfrac{1}{2},\ 8\tfrac{1}{2},\ 9\tfrac{7}{8} 434, 612 4\tfrac{3}{4},\ 6\tfrac{1}{2} Drilling Method Rotary or steerable motor systems for curve and horizontal sections Specially designed motors for angle build section; rotary or steerable motor systems for horizontal sections. Specially designed deflection tools or articulated motors for angle build section; rotary tools and special drill pipe for horizontal sections. Tubulars used Conventional tubulars. Heavy wall drill pipe for build rates of up to 15° per 100 ft; special service drill pipe for higher build rates. Special articulated tubulars; special drill pipe with short articulated motors. Drill bit No limits No limits Rotary: No limits Motor: Diamond or PDC Drilling fluids No limits >No limits No limits Surveying No limits MWD capabilities limited for hole sizes smaller than 618 6\tfrac{1}{8} - inches Special Coring Conventional coring, no limits Conventional coring, no limits 3-foot core barrel, 1-inch diameter core Table 2: Comparative Characteristics of Horizontal Wells (IADC/SPE) Long Radius Medium Radius Short Radius Selective completion capabilities Yes Yes No Multiple pay zones No Yes Yes Artificial lift capabilities All types All types Rod pumps in vertical portion Workover capabilities Yes Yes Yes Typical productivity index increases in non-fractured zones 3.5 2.5 2.5 Typical productivity index increases in fractured zones >10 > 10 >10 > 10 Depends on fracture distribution Production enhancement ratio (horizontal/vertical well) 6 7 Varies widely; can be from 1 to 100 Cost ratio (horizontal/vertical well) >2 > 2 >2 > 2 1.5 (adsbygoogle = window.adsbygoogle || []).push({}); Long Turn Radius Drilling (adsbygoogle = window.adsbygoogle || []).push({}); https://youtu.be/xws2dEEhAd0 A long turn radius well is a well having at least one section with a build rate of between 2 ° and 6° per 100 ft, and a build radius of 1000 ft or more. Long radius applications include: Drilling multiple, extended-reach wells from offshore platforms or other single surface locations. Reaching otherwise inaccessible locations. Drilling exploratory wells over long intervals. Drilling wells that require zone isolation and selective completion/stimulation. The advantages of long radius drilling over other horizontal drilling methods include minimal dog-leg severity, attainment of horizontal departure while drilling the build section, and the ability to employ either conventional rotary bottomhole assemblies or steerable drilling systems. In addition, long radius methods impose no restrictions on hole diameter, bit type, coring LWD MWD capabilities, and they permit various options with respect to completion, stimulation and artificial lift. Long-radius drilling also has some limitations, including high torque-and-drag tendencies, and greater difficulty in hole cleaning. A limiting factor in designing a long radius well is the ability to rotate the pipe at the surface as the bit approaches total depth. There may also be constraints imposed by shallow pay zones, lease boundaries or other restrictions. (adsbygoogle = window.adsbygoogle || []).push({}); The use of conventional rotary assemblies to drill long radius wells is quite common. There are a number of software packages available for optimizing and predicting BHA operating parameters. The BHA designs that are generated can prove very successful, assuming that accurate information on formation anomalies is available. If this information is not available, then frequent trips may be required to correct the well course, resulting in high drilling costs. In such cases, it may be more economical to use a steerable drilling system. A steerable, or navigation drilling system, is a bottomhole assembly that can be controlled from the surface while it is in the hole. Thus, it is possible to direct such a system along a pre-selected well trajectory without having to trip it out of the well. Drilling cost saving, along with reduced dog-leg severity problems, result from the steerable system's ability to build, drop, turn or hold angle, continually monitor well trajectory and control drilling parameters from the surface. The cost effectiveness of a steerable system depends, of course, on effective well planning and on the system's proper design and operation. The tools that make up a steerable system generally consist of a bit, a bent housing positive displacement motor (PDM), bent subs, measurement-while-drilling tools, drill collars and stabilizers. The system can operate in an oriented mode, where drill bit rotation is induced only by the PDM, or a rotary mode, where the main source of bit rotation is still the PDM, but the drill string is rotated as well to negate deviation tendencies. (adsbygoogle = window.adsbygoogle || []).push({}); Medium Turn Radius Drilling https://youtu.be/JzC4N6iDc9c (adsbygoogle = window.adsbygoogle || []).push({}); A medium turn radius well has at least one section with a build rate angle of between 6° and 20° per 100 ft in the rotary mode, and as much as 35° per 100 ft in an oriented mode, in reaching horizontal. The radius of curvature ranges from about 160 up to 1000 feet. Medium-radius wells are appropriate for areas that could benefit from horizontal drilling, but where long-radius methods are either unnecessary or impractical, as would be the case when lease boundary restrictions limit the well course. They are particularly applicable for re-entry wells sandstone reservoirs, reef reservoirs, fractured reservoirs and reservoirs with potential for gas or water coning. The primary advantage of medium radius over long radius drilling is that the well profile is shorter. A medium-radius well can reach the lateral section with greater precision at a shallower depth, with less departure from vertical, and in less time than it takes to drill the curved section of a long radius well. Torque and drag tendencies are also less than in long-radius wells. The vertical portion of the well can be drilled deeper and casing set deeper before beginning the directional drilling phase, and upon completion, production equipment can be set in the vertical section, closer to the pay interval. Relative disadvantages of medium radius drilling are an inability to build angle using rotary methods (however, steerable systems are commercially available that allow an operator to switch from a rotary to an oriented mode without having to trip the drilling assembly), and that fact that the tighter radius places more stress on the drill string. There are no restrictions on bit type or coring capabilities, although MWD applications are limited for hole diameters smaller than about six-and-one eighth inches. (adsbygoogle = window.adsbygoogle || []).push({}); Heavy-wall drill pipe can be used for build rates of up to 15 degrees per 100 feet. Higher build rates require compressive service drill pipe. Figure 1 (Medium radius fixed-angle and steerable angle-build motors) illustrates typical fixed-angle build and steerable angle build assemblies, which allow for continuous, smooth curvature build-up. FIGURE 1 The angle hold assembly may be of the conventional rotary type, or it may contain a downhole motor. In some cases, an operator may drill a vertical or inclined rat hole for locating, logging and testing the pay zone before drilling the curved portion of the horizontal well. This works to good advantage in identifying the target horizon, especially if the structure is not thoroughly understood or the target zone is very narrow. Where coning is a problem, or in interbedded sands, this is a good way to identify the various gas, water and formation interfaces. Once the target has been defined in this manner, the usual procedure is to plug back the rat hole with a good quality cement plug and prepare to drill the angle build portion of the well. (adsbygoogle = window.adsbygoogle || []).push({}); Short Turn Radius Drilling https://youtu.be/U3017Syp1Sk (adsbygoogle = window.adsbygoogle || []).push({}); The build rate angle on a short radius well may range from 5 to 10 degrees per three feet (roughly one meter). The radius of curvature may be as small as 20 ft, with a hole size of between 4 3/4 inches and 6 1/2 inches. Figure 1 (Short radius angle-building assembly) illustrates a short radius angle-build assembly that employs curved, articulated tubulars. FIGURE 1 Short-radius applications include infill drilling in depleted reservoirs draining the very top of undrained reservoirs (attic oil), drilling shaly intervals or other trouble-prone formations and drilling multiple drainholes from one vertical wellbore. They are also proving useful for enhanced oil recovery, particularly steam flooding. Short-radius wells are relatively inexpensive. They provide easy, precise entries to the horizontal sections, and can reach lateral displacement at a minimum measured depth. This makes them particularly appropriate, and sometimes necessary, for shallow reservoirs. Disadvantages of short radius wells include special drilling equipment requirements such as articulated tubulars, limits on hole size and reach, limited azimuth control, and a limited ability to run logging tools or casing. Coring abilities are limited to 3-foot sections of 1-inch diameter core, and diamond or PDC bits must be used when drilling with a short, articulated motor. (adsbygoogle = window.adsbygoogle || []).push({}); Ultra-Short Turn Radius Drilling https://youtu.be/caX5Mwg7YZU (adsbygoogle = window.adsbygoogle || []).push({}); A special class of short-radius wells is the ultra-short radius well, which effectively has no bend section. Ultra-short drilling methods employ jetting techniques and coiled tubing to eliminate angle build sections, and are used in soft, unconsolidated formations to drill multiple drainholes from existing vertical wells. Dickinson et al (1989) describe a system developed by Bechtel Investments, which uses high-pressure water jets (10,000 psi) and high-pressure coiled tubing to drill 2-inch diameter holes around a 1-ft radius turn (Figure 1, Ultra-short turn radius drilling system). FIGURE 1 This system is capable of drilling 100 to 200 ft horizontally in unconsolidated or weak rock. It includes a specially designed, flexible surveying tool and a special electrochemical perforator. Once the lateral sections are drilled, the flexible pipe can be cut off at the wellbore, perforated and gravel-packed. (adsbygoogle = window.adsbygoogle || []).push({}); Trajectory Planning https://youtu.be/VQjm2sliT4E The starting point in planning a horizontal well trajectory is to specify the entry depth into the reservoir and the minimum drainhole length or total depth inside the reservoir. Reaching the target involves three phases: (adsbygoogle = window.adsbygoogle || []).push({}); Vertically drilling to the kick-off point. Directionally drilling to the objective zone. Laterally drilling within the objective zone. By the time a well reaches kick-off depth, plans have already been made to either continuously build angle until reaching the entry depth, and then hold angle through the target zone (Figure 1, Continuous build tangent section), or build-and-hold in two phases until the lateral section reaches the minimum drainhole length or total depth (Figure 2, Two-build tangent section). FIGURE 1 FIGURE 2 In other words, the directional portion of the well may contain either one or two build sections. The trajectory we choose for a given well is based on minimizing problems related to hole cleaning, torque and drag, and wellbore instability. We also have to look to the future with respect to the expense involved in well completion and intervention. The two most common problems that occur while drilling build sections are inability to build hole angle and inability to correct azimuth. These problems typically result from troublesome formations and improper bottomhole assembly design. (adsbygoogle = window.adsbygoogle || []).push({}); Build Curve Design (adsbygoogle = window.adsbygoogle || []).push({}); There are four basic build curve designs used in bringing a well from vertical to horizontal: single build (Figure 1) FIGURE 1 simple tangent (Figure 2) FIGURE 2 Complex tangent (Figure 3) FIGURE 3 (adsbygoogle = window.adsbygoogle || []).push({}); Ideal (Figure 4) FIGURE 4 The equations for designing these curve types are easy to derive, and are summarized below (Schuh, 1989). From Figure 5 (Circular arc), FIGURE 5 [latex]L_{c}= \dfrac{\theta _{i}-\theta _{i-1}}{BR}[/latex] (1) [latex]\Delta H_{b}= R_{b}\cdot \left ( \cos\theta_{i-1}-\cos \theta_{i} \right )[/latex] (2) [latex]\Delta V_{b}= R_{b}\cdot \left ( \sin \theta_{i-1}-\sin \theta_{i} \right )[/latex] (3) where Lc = length of curved section Rb = build curve radius BR = build rate angle ΔHb = horizontal displacement of build curve section ΔVb = vertical displacement of build curve section θi, θi−1 = inclination angles at stations i and i−1, respectively, on build curve The straight section required to hit a sloping target (Figure 6) is FIGURE 6 [latex]L_{s} = \dfrac{\Delta H_{s}}{\sin \theta_{s}}[/latex] (4) [latex]\Delta H_{s}= \dfrac{\Delta V_{s}}{\cos \theta _{s}-\cos \theta _{tr}}[/latex] (5) where (adsbygoogle = window.adsbygoogle || []).push({}); Ls = length of straight section ΔHs = horizontal displacement of straight section. ΔVs= height to target slope. θs, θtr = straight section and target angles, respectively. s = straight tr = target The build rate angle required to hit a sloping target (Figure 7) is [latex]BR = \dfrac{57.3}{V_{tr}}\cdot \left ( \sin \theta _{i} - \sin \theta _{i -1} +\dfrac{\cos \theta _{i}\cdot \cos \theta _{i-1}}{\tan \theta _{tr}}\right )[/latex] (6) where BR = build rate Vtr = vertical height from target FIGURE 7 [latex]\Delta H = \dfrac{57.3}{BR}\cdot \left ( \cos \theta _{i-1}-\cos \theta _{i} \right )[/latex] (7) [latex]\Delta V_{tr} = \dfrac{57.3}{BR}\cdot \left ( \sin \theta _{i}-\sin \theta _{i-1}+\dfrac{\cos \theta _{i}\cdot \cos \theta_{i-1} }{\tan \theta_{tr}} \right )[/latex] (8) [latex]\Delta V = \dfrac{57.3}{BR}\cdot \left ( \sin \theta _{i}-\sin \theta _{i-1} \right )[/latex] (9) The tool face angle required for the second build is [latex]\phi _{tf}= \cos^{-1} \dfrac{BR_{1}}{BR_{2}}[/latex] (10) The dog-leg severity is [latex]DL = \left ( \theta _{i} -\theta _{i-1}\right )\cdot \left ( \dfrac{BR_{1}}{BR_{2}} \right )[/latex] (11) The azimuth change is [latex]\alpha = \left ( 57.3\cdot \tan \phi _{tf} \right )\cdot \ln \left [ \dfrac{\tan\left ( \dfrac{\phi _{1}}{2} \right ) }{\tan \left ( \dfrac{\phi_{i-1}}{2}\right )} \right ][/latex] (12) where ϕtf = tool face angle, degrees DL = dog-leg severity, degrees BR1= first build rate angle BR2 = second build rate angle The required final curvature build rate, BRr, to hit a target is given by [latex]BR_{r} = \dfrac{57.3\cdot \left (\sin \theta_{tr} - \sin \theta _{i} \right )}{TVD_{tr}-TVD_{i}}[/latex] (13) where θtr = target inclination angle θi = present inclination angle TVDtr = target true vertical depth TVDi = target present true vertical depth (adsbygoogle = window.adsbygoogle || []).push({}); Horizontal Targeting (adsbygoogle = window.adsbygoogle || []).push({}); During drilling toward a horizontal target with a constant build rate, if the azimuth is found to be off the target, it is important to find an intermediate point at which the tool-face angle can be changed from right to left (or from left to right) to negate some of the change in azimuth while continuing the desired constant build rate (Schuh, 1989). The situation is shown in Figure 1. FIGURE 1 Guo et al. (1993) presented a method to accurately determine this intermediate point and other related parameter values. The relevant equations are illustrated in Figure 2 (Guo et. al's method for horizontal targeting). FIGURE 2 The inclination angle at the intermediate point is expressed as (adsbygoogle = window.adsbygoogle || []).push({}); [latex]I_{int} = 2 \cdot \tan^{-1}\sqrt{\tan \left ( \dfrac{I_{1}}{2}\right ) \cdot \tan \left ( \dfrac{I_{2}}{2}\right ) \cdot \exp \left ( \dfrac{A_{2}-A_{1}}{\tan \gamma } \right )}[/latex] (1) The change in azimuth from point 1 to the intermediate point is [latex]A_{1-int}= \tan \gamma \cdot \ln \left [ \dfrac{\tan \left (\dfrac{I_{int}}{2} \right )}{\tan \left ( \dfrac{I_{1}}{2} \right )} \right ][/latex] (2) The length to drill from point 1 to the intermediate point is [latex]\Delta L_{1-int}= \dfrac{\left ( I_{int} -I_{1}\right )}{B}[/latex] (3) The tool face angle to set is [latex]\gamma = \cos ^{-1}\left ( \dfrac{B}{D} \right )[/latex] (4) where B is the designed build rate and D is the deflection capacity of the tool. After the intermediate point is reached, the tool face should be re-oriented to the opposite direction in order to hit target at point 2. The tool face angle to set is [latex]\gamma = -\cos ^{-1}\left ( \dfrac{B}{D} \right )[/latex] (5) The change in azimuth from the intermediate point to point 2 is [latex]\Delta A_{int-2}= \tan \left ( -\gamma \right ) \cdot \ln \left [ \dfrac{\tan \left ( \dfrac{I_{2}}{2} \right )}{\tan \left ( \dfrac{I_{int}}{2} \right )} \right ][/latex] (6) The length to drill from the intermediate point to point 2 is [latex]\Delta L_{int-2} = \dfrac{\left ( I_{2}-I_{int} \right )}{B}[/latex] (7) (adsbygoogle = window.adsbygoogle || []).push({}); Formation Evaluation Aspects (adsbygoogle = window.adsbygoogle || []).push({}); The purpose of the formation evaluation program is to enhance drilling efficiency, and to provide data for reserves and production rate estimates. Formation evaluation methods used at the wellsite include coring, drill stem testing, mud logging and well logging. Well logging techniques may involve any of the following: logging using drill pipe logging using coiled tubing pump-down logging MWD and LWD tools formation pressures versus depth across the objective formation (MDT, etc.) formation fluid sampling (MDT, etc.) formation imaging (FMI, etc.) vertical seismic profile (VSP) With these techniques, it is feasible to log most horizontal wells, even where wireline methods are impractical. Coiled tubing logging systems and pump-down stinger systems offer a particular advantage, in that they can be operated under pressure. For more frequent use, MWD and LWD tools are recommended. The cost of obtaining a given set of logging measurements depends on the rig time required. In making cost comparisons, the engineer should note that in certain cases, pump-down stinger and coiled tubing systems can be used without a rig. (adsbygoogle = window.adsbygoogle || []).push({}); Completion and Stimulation Aspects (adsbygoogle = window.adsbygoogle || []).push({}); The most common types of horizontal well completions are: Open hole, or open hole with slotted, perforated or pre-packed liner, and sand control screens with external open-hole packers Liner with external casing packer Cased, cemented and perforated Cased, cemented, perforated, multiple packers for multi-staged fracturing of unconventional shale, tight oil & gas. Multi-lateracompletions Figure 1 illustrates these completion types ((a) open hole, (b) open hole with slotted liner, (c) liner with external casing packer, (d) cemented and perforated ). FIGURE 1 Selection of a particular type depends on such reservoir conditions as: permeability and permeability anisotropy fractures section isolation along the horizontal well section hole stability sand problems coning problems production control Open hole completions, where only the vertical section of the well is cased, were the most common completion types in the early years of horizontal drilling, and they are still widely used. They are relatively inexpensive and easy to execute, and they work well in consolidated formations were sand production and hole collapse problems are not matters of concern. In homogeneous formations that are not well-consolidated, operators often run slotted or pre-perforated liners in open hole. Where sand production is a problem, they may substitute pre-packed liners. The main disadvantage of open hole and slotted liner completions is their inability to isolate zones. Considering that most formations are heterogeneous to at least some degree, this is a significant drawback, particularly if the completion interval is a long one. (adsbygoogle = window.adsbygoogle || []).push({}); In a number of instances, slotted liners equipped with external casing packers (ECPs) have proven successful at isolating formation intervals and providing for selective completion and stimulation. ECPs can be placed at strategic points in the liner string, and then inflated with mud or cement to seal off the liner/hole annulus. Their main drawbacks are that hole eccentricities can make it difficult to form an effective seal, and that they result in a relatively inflexible well design with respect to future workovers or recompletions. A cased, cemented and perforated completion is the most expensive horizontal well design, and the most difficult to properly execute. At the same time, it is the most effective configuration for attaining zone isolation, and the most flexible in terms of future workover, recompletion or stimulation jobs. Stimulation of Horizontal Wells In general, the fluids and additives used in matrix stimulations for horizontal wells are the same as those employed in vertical wells. The formation damage profiles for horizontal wells, however, differ significantly from those of vertical wells. This requires modifications in treatment volumes and placement techniques. With respect to hydraulic fracturing in horizontal wells, the materials used are likewise similar to those used for vertical wells. The orientation of well trajectories, and of the fractures themselves, represent the critical difference, and require careful planning of fracture stimulations even before drilling begins. Economides (1993) addresses in some detail the considerations involved in horizontal well stimulation. ICD Completion Well completion with inflow control devices (ICD) can delay encroachment from bottom water and/or gas production from gas caps in relatively homogeneous reservoirs. In heterogeneous reservoirs, ICD completions depress intrusions of water and gas from high-permeability reservoir channels or fractures. Different types of ICDs are used in the industry, including orifice types, nozzle types, and helical channel types. Figure 2 shows an orifice type ICD, while Figure 3 depicts an ICD completion. FIGURE 2 FIGURE 3 To delay water and/or gas coning in relatively homogeneous reservoirs, ICDs need to be sized and distributed to achieve a uniform pressure distribution along the sandface. (adsbygoogle = window.adsbygoogle || []).push({}); Figure 4 shows a comparison of annular pressures in a well with and without ICD installations. To postpone water and/or gas intrusion from high-permeability channels/fractures, ICDs need to be sized and distributed to achieve a uniform influx distribution along the sandface. FIGURE 4 Figure 5 presents a comparison of influx profiles in a well with and without ICD installations. The result of the ICD design should be checked with reservoir simulation for effectiveness. FIGURE 5 ICV/FCV Completion Well completion with inflow control valve (ICV) or flow control valve (FCV). An active component installed as part of a well completion (Intelligent, Smart) to partially or completely choke flow into a well. Inflow control valves can be installed along the reservoir section of the completion, with each device typically separated from the next via a packer. Each valve can be controlled from the surface to maintain flow conformance and, as the reservoir depletes, to stop unwanted fluids from entering the wellbore. A permanent downhole cable provides electric and hydraulic conduits to relay commands from the surface to each valve. These devices are generally installed in multi-lateral horizontal well completions. (adsbygoogle = window.adsbygoogle || []).push({}); Artificial Lift Considerations (adsbygoogle = window.adsbygoogle || []).push({}); Hole inclination is a limiting factor in applying artificial lift techniques, although most methods can be applied with some modifications. Specifically, we may note the following: Gas lift and hydraulic pumping by jetting, while they cannot be applied at very low bottomhole pressures, are relatively unaffected by high inclination angles. High inclination angles limit the use of wireline-installed equipment. In sucker rod pumping, protective devices are essential for preventing excessive rod and tubing wear. Electric submersible pumps, with slight modifications, can be used for high-angle wells. Hydraulic pumping by turbo-pump should be satisfactory in high-angle holes. Reciprocating hydraulic pumps are limited to cases where deviation angles are compatible with the operation of the pump check valves. Progressive cavity pumps (PCP)is a type of a sucker rod-pumping unit that uses a rotor and a stator. The rotation of the rods by means of an electric motor at surface causes the fluid contained in a cavity to flow upward. It is also called a rotary positive-displacement unit. A PCP is ideal for liquids with higher viscosities. (adsbygoogle = window.adsbygoogle || []).push({}); Exercises Horizontal drilling (adsbygoogle = window.adsbygoogle || []).push({}); 1. List five major considerations involved in selecting a particular horizontal well configuration. Solution The considerations that enter into selecting a horizontal well configuration include: cost well spacing and lease restrictions conditions of re-entry wells reservoir rock characteristics production methods well objectives problem-causing lithologies above the pay zone amount of total horizontal departure completion methods availability of specialized downhole tools kick-off depth constraints horizontal displacement constraints 2. Define the following horizontal well configurations and list their areas of application: (a) long radius (b) medium radius (c) short radius (d) ultra-short radius Solution (a) Long radius: Build rate between 2° and 6° per 100 ft; build radius ranges from approximately 1000 to 3000 ft Applications: Multiple, extended-reach wells from offshore platforms or other single surface locations. Otherwise inaccessible locations. Exploratory wells over long intervals. Wells that require zone isolation and selective completion/stimulation. (b) Medium radius Build rate between 6° and 35° per 100 ft; build radius ranges from approximately 160 to 1000 ft Applications: Lease boundary restrictions. Re-entry wells. Reef reservoirs. Fractured reservoirs. Reservoirs with potential for gas or water coning. (c) Short radius: Build rate between 5 ° and 10 ° per three ft; build radius 20-40 ft Applications: Infill drilling in depleted reservoirs Shaly intervals or other trouble-prone formations Multiple drainholes Enhanced oil recovery (d) Ultra-short radius: No bend section Applications: Soft, unconsolidated formations Multiple drainholes from existing vertical wells 3. The inclination angle at the current point is I1=50 deg. The azimuth angle at the current point is A1=30 deg. The required inclination angle at the target point is I2=90 deg. The required azimuth angle at the target point is A2=40 deg. The tool has a deflection capacity of D=33 deg/100 m. The required build rate is B=28 deg/100 m. Using Guo et. al's method, find the inclination angle and change in azimuth at the intermediate point, along with the length to drill from the current point to the intermediate point. Find also the tool face angle to set at the intermediate point, the change in azimuth from the intermediate point to point 2, and the total length to drill from the current point to the target point is 143.74 m. Solution Calculations are illustrated in Figure 1. FIGURE 1 Using Guo et al.’s method, the inclination angle at the intermediate point is calculated to be 76.32 degrees. The change in azimuth from the current point to the intermediate point is 18.5 degrees. The length to drill from the current point to the intermediate point is 94.78 m. The tool face angle to set at the current point is 31.8 degrees. After the intermediate point is reached, the tool face should be re-oriented to the opposite direction in order to hit target at point 2. The tool face angle to set at the intermediate point is -31.8 degrees. The change in azimuth from the intermediate point to point 2 is -8.54 degrees. The total length to drill from the current point to the target point is 143.74 m. Assessment Horizontal drilling (adsbygoogle = window.adsbygoogle || []).push({}); 1. The starting point in planning a horizontal well trajectory is to ____________________. A .establish the kick-off depthB .determine the configuration of the build section(s)C .specify entry depth into the reservoir and the minimum length of the drainhole section.D .specify the target radius 2. What is the primary reason for installing inflow control devices (ICDs) in horizontal well completions? A .Zonal isolationB .Balancing of influx profiles and delay of water or gas intrusion.C .Sand control 3. Ultra short turn radius drilling is used in __________. A .soft unconsolidated formationsB .steeply dipping formationsC .side tracking when having stuck pipe problemsD .deep wells 4. How can logging surveys be conducted in a horizontal hole section when wireline methods are impractical? A .Run logging tools on drill pipe.B .Use coiled tubing.C .Use tools with pump-down capability.D .Use MWD and LWD toolsE .A, B, C and DF .A, B and D only 5. What horizontal completion type would you choose if zonal isolation and the ability to conduct future workovers was a primary well objective? A .Open holeB .Liner with external casing packerC .Cased, cemented and perforatedD .B or C 6. Which of the following is NOT an advantage of medium radius drilling, when compared with long radius drilling? A .Torque and drag tendencies less than in long radius wellsB .Vertical portion of the well can be set deeperC .Attainment of a lateral section with less departure from the verticalD .Decreased dog-leg severity (adsbygoogle = window.adsbygoogle || []).push({}); 7. A medium turn radius well has one section with a build rate angle of: A .1 to 6° per footB .0 to 3 ° per 100 ftC .6 to 20° per 100 ftD .20 to 40°per 100 ft 8. The two most common problems that occur while drilling build sections are inability to build hole angle and inability to correct azimuth. These most often result from ________. A .troublesome formationsB .improper design of the bottomhole assemblyC .poor bit selectionD .A and BE .A, B and C 9. Which of the following is NOT an area of application for short turn radius drilling? A .Steam floodingB .Drilling multiple drainholes from a single wellboreC .Infill drilling in depleted reservoirsD .Wells requiring comprehensive formation evaluation programs. 10. Which of the following is NOT a curve design to bring a well from vertical to horizontal? A .Complex tangentB .Balanced tangentC .Simple buildD .Simple tangent 11. Which of these horizontal well configurations does not involve a limit on hole size? A .Long radiusB .Medium radiusC .Short radiusD .A and B 12. Which of these reservoirs would you be LEAST likely to consider as a candiate for horizontal drilling? A .Heavy oil reservoirB .Reservoir with high ratio of horizontal to vertical permeabilityC .Reservoir with high ratio of vertical to horizontal permeabilityD .Coal bed methane reservoir 13. A short turn radius well may have a radius of curvature as small as _______ feet. A .5 feetB .20 feetC .50 feetD .100 feet 14. Which of the following is NOT a typical application of long radius drilling? A .Drilling exploratory wellsB .Wells requiring selective completionC .Re-entry wellsD .Drilling multiple wells offshore 15. Advantages of long radius drilling include: A .Relative ease of hole cleaning and cuttings removalB .Low torque and drag tendenciesC .Ability to expose shallow pay zonesD .Minimal dog-leg severity 16. An artificial lift system that is relatively unaffected by inclination angles is: A .Sucker rod pumpingB .Electric submersible pumpsC .Reciprocating hydraulic pumpsD .Gas lift Recommended for You (adsbygoogle = window.adsbygoogle || []).push({}); Directional Drilling Overview Deviation in Vertical Wells Directional Drilling Tools and Techniques Case Study of Geosteering (adsbygoogle = window.adsbygoogle || []).push({});