Directional Drilling: The Driving Force in Geosteering

(adsbygoogle = window.adsbygoogle || []).push({}); Geosteering Overview Over the years, oil companies have had to take up the challenge of developing difficult, sometimes marginal prospects. As "easy" reservoirs become depleted, the challenge is to produce oil that was left behind, or to develop smaller, thinner, fractured, or low-quality reservoirs that had previously been passed over as poor prospects. Extended reach, horizontal, directional drilling, and multilateral wellbores have helped oil companies to book more reserves, and optimize production of these "poor" prospects. To develop bypassed reserves or hard-to-reach reservoirs requires precise targeting of the wellbore through a process known as GeoSteering. This approach to drilling advances the integration of Geology, Geophysics, and Petroleum Engineering toward a common goal of improving production. This module reviews valuable insights into the GeoSteering process, provided by Kenneth Bowdon, President of Horizontal Solutions, International, a company with experience gained over the course of steering nearly 2000 horizontal wells. GeoSteering Defined GeoSteering is the application of geologic and engineering skill to direct a horizontal or extended-reach wellbore path, based upon knowledge of the enclosing stratigraphy, with the expressed aim of maximizing wellbore exposure to the target reservoir. (Figure 1: Maximizing wellbore exposure). FIGURE 1 Maximizing wellbore exposure (adsbygoogle = window.adsbygoogle || []).push({}); GeoSteering is not the same as directional drilling, and it is not simply a directional tool, or a gamma ray or a resistivity device mounted above the bit. GeoSteering is not a service offered by a consulting company or a service company. GeoSteering is not the wellbore plan. All of these components are important parts of the GeoSteering toolbox. Directional Drilling Briefly stated, directional drilling is the process of manipulating specialized downhole tools to mechanically guide a deviated, high-angle or extended-reach wellbore. GeoNavigation GeoNavigation involves the analysis of critical pieces of information needed to make a steering decision. The GeoSteering Team uses the geonavigation services of consultants and service companies who either provide hardware, software, or interpretations of the well data obtained as it is being drilled. This data ranges from drilling performance data to directional surveys, MWD/LWD data and geophysical data. The service companies and consultants may play a major role in successfully steering a horizontal well under the direction of the GeoSteering Team. They can, however, also produce disastrous results if they are allowed to actually make steering decisions based only upon their specific area of expertise. Having the right geonavigation hardware and software is critical to the success of the well. But the methods used to interpret the data, as well as the individuals who make the interpretation will play an even greater role in the success of the geosteering project. The Geosteering Team A GeoSteering Team is often called upon to prioritize and evaluate a wide range of geonavigation data, and then communicate steering instructions to the Directional Driller. The GeoSteering Team may grow or shrink on the basis of project complexity, but typically consists of a Team Leader and Directional Driller (at a minimum). In some cases, the team will include a Wellsite Geologist, Drilling Engineer or Company Drilling Representative, and may sometimes include a Geophysicist or Petrophysicist. The Team’s composition should be based upon the minimum number of people needed to interpret the range of geonavigation data generated as the well is drilled. The Team evaluates only information that is essential to the steering decision. (Petrophysical information is typically evaluated only after steering decisions are made, except in cases where water saturation is used to indicate proximity to the water leg of a reservoir.) Companies utilize a variety of methods to arrive at key geosteering decisions. Some companies prefer to have an engineer and a geologist who is a geosteering specialist on location, to make "instant decisions." Other companies have an elaborate system to transfer data real-time to the office, for a team of geologists, geophysicists, and engineers to pore over. Some companies use consultants to evaluate data from a horizontal well, and then assign a single individual or team to coordinate, compare and act upon these interpretations. The structure of any geosteering team will depend upon the corporate culture, the level of horizontal well expertise possessed by the geoscience team, and the company’s commitment to keep its well in zone. Regardless of the team’s composition, the members all need to adapt an interdisciplinary mindset, as they will need to make sense of a wide range of data -some of which will invariably come from outside of their field of expertise. (Figure 2: The role of the Geologist) FIGURE 2 The role of the Geologist in Directional Drilling Characteristics of a Successful Geosteering Team (adsbygoogle = window.adsbygoogle || []).push({}); The composition of the geosteering team will vary, depending upon the expertise of available personnel. Regardless of the makeup of the Geosteering Team, there are certain characteristics common to most successful teams. The Geosteering Team should be comprised of geoscientists that have the authority to make steering decisions. Once the Team is formed, Management should stay out of the steering decision process. Steering decisions may be required at any time, and are always time-sensitive. If a decision must wait for approval up the chain of command, then the recommendation might quickly become obsolete as the well continues to drill, thus requiring a more radical correction that could even jeopardize the hole. The Geosteering Team should be as small as possible while still covering the skill sets required by the geosteering project. When too many people are involved in a decision and no one in particular is in charge, then only mis-direction will occur. A compromise steering decision is not a decision -it is a mistake. At the very minimum, a team should include at least one cross-trained geoscientist and the Directional Driller. Additions to the Team should consist only of those individuals needed to determine the geometric, stratigraphic, and structural position of the bit. The focus must always remain upon targeting the reservoir, not evaluating the reservoir. Individuals on the Team must be trained in complimentary disciplines so that each understands the input from others on the team, and each understands what it is possible for the Directional Driller to do. Each Team member should have a defined role and be fully informed about the objectives of the well. The frustration of not "being in the loop" may cause friction and confusion, which may in turn cause errors in judgment and uncooperative team members. There must be a Team Leader. An integral part of the Team concept is the identification of a Team Leader, who has final authority to "pull the trigger." The Team Leader should have experience and should be cross-trained to understand horizontal drilling from a Geologic, Drilling, Completion, and Reservoir perspective, and must be able to collate information from diverse sources to derive the whole picture of what is happening down the wellbore. Geosteering is an art that is practiced through acquired skill. As in all such endeavors, there will be some people who just have a natural ability for steering a well because they can visualize in three dimensions, and can work on the basis of incomplete data from multiple sources. Others may have a harder time grasping the concepts, but all can improve their skills through cross-disciplinary training combined with experience. To steer an actively drilling well, it is important to determine what kind of information the geosteering team needs to make good steering decisions. Then the team should determine how the data will be interpreted, and how the interpretation will be used to communicate steering decisions to the Directional Driller. In the following sections, we will provide an overview of the reasons for drilling directional wells, and then discuss tools, methods, and terminology used in drilling deviated wells. (adsbygoogle = window.adsbygoogle || []).push({}); Directional Drilling Candidates (adsbygoogle = window.adsbygoogle || []).push({}); The GeoSteering process begins long before the well starts drilling. Each reservoir is unique, so obtaining a comprehensive understanding of the reservoir is the first step in planning a GeoSteering project. Optimization of reservoir performance is the primary reason that a horizontal well is drilled, however, each well may also have critical secondary objectives. There is no standardized wellbore plan that will work in all reservoirs. A development plan should exploit the reservoir morphology, matrix and fracture porosity, permeability and porosity distribution, the type of reservoir drive, and the fluid content. The wellbore plan is based on the reservoir development plan, and the geosteering strategy is based on the wellbore plan. Each of the situations listed below can be addressed through horizontal drilling, and will require the Geosteering Team to develop a different strategy for each. Reduced Surface Footprint Horizontal wells can make economic sense, even in conventional reservoirs, when hostile environments (such as deep water), or environmental concerns (as on Alaska's north slope) would otherwise prohibit economic development. Horizontal drilling is now part of the continued development plan for Prudhoe Bay Alaska and surrounding fields. This development is being conducted at a lower cost, and with less environmental impact, than would occur through vertical development. Horizontal drilling is also being utilized in the deep-water Gulf of Mexico, offshore Brazil, Africa, the North Sea and many other areas where costs associated with building a platform would make economic development with vertical wells prohibitive. In this instance, where several wells will be drilled from a template, the Geosteering Team will be particularly concerned with collision avoidance. Planning should include detailed maps of pre-existing wellbores. Laterally Heterogeneous Reservoirs Reservoirs that are characterized by lateral heterogeneity often provide some of the best targets for horizontal drilling. Such targets are found in: Channel sandstones within a specific stratigraphic interval (Figure 1a and Figure 1b: Map and side views of channel sands). FIGURE 1 a,b Channel sandstones within a specific stratigraphic interval Karsted reservoirs (Figure 2a and Figure 2b: Map and side views of karsted reservoirs). FIGURE 2 Map and side views of karsted reservoirs [A,B] (adsbygoogle = window.adsbygoogle || []).push({}); Reservoirs with discontinuous porosity development and stratigraphic pinch out (Figure 3a and Figure 3b: Map and side views of discontinuous or pinched-out zones). FIGURE 3 Map and side views of discontinuous or pinched-out zones Fractured reservoirs (Figure 4a and Figure 4b: Map and side views of fractured and faulted reservoirs). FIGURE 4 Map and side views of fractured and faulted reservoirs These reservoirs are especially challenging for the Geosteering Team, and require detailed stratigraphic maps in order to chart the best geosteering strategy and contingency plans. Reduced Water Coning When a horizontal wellbore is drilled at a proper distance above an oil / water contact, it will create reduced pressure draw-down along the path of the wellbore as compared to a vertical wellbore, thereby reducing the incidence of water coning. When planning to drill near a water contact, the Geosteering plan should include an LWD package that can detect the proximity of a water zone before the wellbore actually penetrates the contact. Heavy Oil Reservoirs (adsbygoogle = window.adsbygoogle || []).push({}); Heavy Oil production has reached record levels in Canada, largely because of the successful fulfillment of a development plan that relies extensively on horizontal drilling. Horizontal wells have been drilled on very close spacing ( + 100 m) to efficiently tap huge reserves of heavy crude. One successful horizontal technology being used is Steam Assisted Gravity Drainage (SAGD). This technique is implemented by drilling two horizontal wellbores, one above the other (Figure 5: Oil mobilized and produced through SAGD). FIGURE 5 Oil mobilized and produced through SAGD Steam is injected in the upper lateral. The steam heats the oil, thus reducing its viscosity, and allowing it to be produced from the lower lateral. Another such example of this technique is Conoco's Petrozuata development in the Orinoco Basin of Venezuela, which is currently producing more than 120,000 BOPD from horizontal wellbores. In these cases, the Geosteering plan will require special attention to maintaining a close spacing between the two wellbores while avoiding collision. Waterflood Injection / Production A number of companies, including Shell, EnCana, and Talisman Energy have used horizontal wellbores successfully to water-flood their fields, reviving fields that were already considered very mature. (In some cases, a few fields had already been waterflooded using vertical wells.) Horizontal wellbores used as injector wells will take fluid at higher volumes with less pressure required to inject the fluid. This increases efficiency while reducing the overall cost of injection when compared to a conventional vertical water flood. In this case, the Geosteering Plan will call for maintaining position below the contact, and should include an LWD tool that can indicate proximity to the pay zone. Infill drilling Increasingly, when a company is faced with drilling infill wells to increase drainage density, a horizontal well is considered. Using this option, the operator can replace two to four vertical wells with a single horizontal well, thereby increasing wellbore exposure to the pay zone while reducing drilling and operating costs (Figure 6: Replacing multiple vertical wells with a single horizontal wellbore). FIGURE 6 Replacing multiple vertical wells with a single horizontal wellbore For infill wells, the Geosteering Team must locate all pre-existing wells that could potentially interfere with the trajectory of the proposed well, and plan to closely follow structure and stratigraphy of the pay zone. Gas Storage Fields Gas storage wells often include multilateral horizontal wellbores to significantly enhance the annual injection and withdrawal rates. Evaluating Economic Viability of producing horizontal wells Though a reservoir might possess the right morphology, drive and permeability to support a horizontal well, no drilling will commence until the costs are determined. The prime concern is whether the development costs associated with a horizontal well are lower than the development cost of the vertical wells it is intended to replace. If the cost of drilling a horizontal well is NOT lower than that of a specified number of vertical wells, then the project should not be drilled - despite otherwise favorable geologic conditions. The following check list can be used to determine the viability of a project. 1. Determine the projected cost of the well through completion and stimulation.This requirement means that you must not assume that STIMULATION WILL NOT BE REQUIRED in a horizontal wellbore. The general rule of thumb is that if a reservoir needs stimulation in a vertical hole, then that same reservoir is very likely to require stimulation in a horizontal wellbore.It is important to begin by determining whether stimulation will be required, because the type of stimulation will dictate the type of completion needed to effectively produce the well, and also may determine the optimum length of the lateral section. There is no reason to drill more hole than it is possible to complete.The completion type will dictate the hole size, which will affect casing sizes and ultimately impact the entire well plan. It is therefore necessary to break down the to cost per lateral foot through the build section, then determine the estimated cost per foot in the lateral section. Remember, the cost per foot in the lateral section will generally increase as the length of the lateral section increases, due to the increased time required to make a trip, as well as any complications of increased torque and drag, etc. Generally, the formation itself may ultimately determine the length of the lateral. 2. Determine the drilling and completion cost of a vertical well in the same reservoir. 3. Determine the spacing that a vertical well will require, and more importantly, the actual drainage area within those spacing requirements. 4. The vertical replacement index (the number of vertical wells that one horizontal well of a given length will replace) is then determined by the following equation. [latex]VRI=\dfrac{\dfrac{L\cdot S_v}{DR_v\cdot 2} + DA_v }{DA_v}[/latex] Where: VRI= Vertical replacement index L= lateral length DRv= Drainage Radius of vertical well DAv= Drainage Area of vertical well [latex]= \dfrac{DR_{v}^2\cdot \pi }{43,560}[/latex] Sv= Spacing of vertical well in acres Example: For a forty acre vertical spacing and a 3960-foot lateral (See Figure 7) (adsbygoogle = window.adsbygoogle || []).push({}); FIGURE 7 For a forty acre vertical spacing and a 3960-foot lateral L = 3960 feet DRv = 660 [latex]DA_{v} = \dfrac{660^{2}\cdot \pi}{43,560} = \dfrac{1,368,481}{43,560 }= 31.416\, acres[/latex] Sv=40 acres [latex]VRI=\dfrac{\dfrac{3960\cdot 40}{660\cdot 2} + 31.416 }{31.416} = 4.82[/latex] 5. Compare the VRI against the Cost Ratio (CR) between the Horizontal well and the vertical well.In order to justify the cost of drilling a horizontal well, a typical oil company will require the VRI to be at least 1.5 times the cost ratio.For instance, in an area where a vertical well costs $450,000 with a forty acre spacing and a 3960-foot horizontal well costs $970,000, then the [latex]\dfrac{VCI}{CR}[/latex]=2.23, which indicates favorable economics for drilling a horizontal well in this case.Conversely, if a typical vertical well in this area was drilled on 320 acre spacing, then the VRI=2.35 and the CR=2.15 Thus the well would probably not be economic to drill. 6. The next step is to empirically determine the productivity multiplier (PM) for the planned horizontal well. The PM is a ratio of the 1st three months of production from the average horizontal well, divided by the first three months production of the average vertical well (Figure 8: Comparing production from horizontal and vertical wells). FIGURE 8 Comparing production from horizontal and vertical wells This number can be determined easily if horizontal wells have already been drilled in an area. Simply divide the ultimate cumulative production of an average horizontal well by the ultimate cumulative production of the average nearby vertical wells. Perform this for several wells to get a good average PM. When few horizontals have been drilled in an area, or the proposed horizontal wellbore is not near any vertical wells, then one must estimate the productivity index using volumetrics. The PI should be equal to or greater than the CR. (adsbygoogle = window.adsbygoogle || []).push({}); Directional Drilling Hardware: The Bottom Hole Assembly (adsbygoogle = window.adsbygoogle || []).push({}); The Bottom Hole Assembly (BHA) used in directional drilling consists of four special components that work together, making it possible to accurately steer a directional wellbore: Bit Bent sub Mud motor MWD tool Each of these components is described below. (Note that the mechanical aspects of directional drilling are described in much more detail in the IPIMS module on Directional and Horizontal Drilling, found in the Drilling Engineering Series, under the Petroleum Engineering Discipline.) The Bit Bit selection is key to the effective drilling of a horizontal wellbore. A balance must often be struck between the durability, rate of penetration (ROP), and steering stability of the bit. Bit trips in horizontal wellbores can be very expensive, so bit durability is a key factor in the overall cost of drilling. Ultimately, the ROP should be maximized to make as much hole in as little time as possible (including trips for bit changes). However, if ROP is maximized at the expense of reducing the capability to maintain the intended course, then any cost savings realized by fast ROP is negated because the well will not stay on target. Each formation reacts differently to specific bit designs (Figure 1: Diamond, Roller Cone and PDC bits). Bit selection of cone bits, PDC bits or impregnated bits will depend on the section that must be drilled. Most bit manufacturers have a variety of bits in each class to suit the application. It is often best to defer to local experience in guiding the bit selection process. FIGURE 1 Diamond, Roller Cone and PDC bits The Bent Sub The bent sub is located above the bit and beneath the hydraulic turbine. This sub is bent at just a small angle (typically ranging from 0.2 degrees to a just couple of degrees), as shown in the following Figure 2. A number of subs have been designed so that the angle can be adjusted to meet different applications (Figure 3: Changing the angle of the). The bent sub plays an important role in providing the fulcrum necessary to change the direction of the wellbore. FIGURE 2 The bent sub FIGURE 3 Changing the angle of the bent sub The toolface of this sub is defined as the direction, relative to the high side of the hole, in which the convex face of the bend is oriented. Toolface orientation is specified as X-degrees left or right, with 0 degrees pointing the toolface straight up (Figure 4: Toolface set at 130° left). FIGURE 4 Toolface set at 130° left (adsbygoogle = window.adsbygoogle || []).push({}); To orient the toolface, the Directional Driller slowly rotates the drillpipe at the surface, pointing the toolface toward the direction where angle will be built. Once the toolface is set, the mud motor is engaged while keeping the drillpipe stationary at the surface. The bend points the bit in a direction that differs from the axis of the wellbore. The hole then cuts differentially in the direction of the toolface, causing the wellbore to deviate in that direction and to continue building angle. Once the desired wellbore azimuth is attained, that azimuth may be maintained by rotating the entire drillstring (including the bent section). Now, instead of the bit drilling in a single direction off the wellbore axis, it will sweep around, with the result that its net direction will coincides with the existing wellbore. Some tools allow steering while rotating, thus achieving higher rates of penetration. The Mud Motor The mud motor consists of a hydraulic turbine, which is driven by the force of the drilling fluid that is pumped down through the drillpipe (Figure 5: Mud motor). The mud motor turns the bit without the usual necessity of rotating the entire drill string. FIGURE 5 Mud motor The MWD / LWD Tool The next component in the BHA is the Measurement While Drilling (MWD) tool. The MWD contains instruments to measure toolface orientation, along with borehole azimuth and inclination or other measurements. Often, a suite of Logging While Drilling (LWD) tools are included as part of the downhole measurement package. A typical LWD tool string might include such devices as the Gamma Ray, Resistivity, Density, Neutron, and Sonic logging tools (Figure 6: Typical MWD/LWD tool string). FIGURE 6 Typical MWD/LWD tool string (adsbygoogle = window.adsbygoogle || []).push({}); MWD/LWD tools transmit their measurement data to the surface by way of mud pulse telemetry. A pulser or transmission module sits atop the tool string to transmit data uphole (Figure 7: Telemetry/Pulser module). FIGURE 7 Telemetry/Pulser module The data obtained by MWD/LWD tools can be stored downhole in the tool’s memory modules should the mud pulse unit fail. Many aspects of MWD/LWD operation are similar, however, MWD usually refers to directional and pressure sensors. LWD usually refers to the formation evaluation sensors. Downhole Data Transmission The drilling or petrophysical parameters measured below the mud motor or at the bit can be digitally encoded and transmitted to the surface on a real-time basis. For instance, toolface direction can be measured and sent to the surface for real-time control of the bit orientation. A telemetry system is used to relay data from sensors located near the bit to the MWD tool, positioned further up the hole (it can range up to 200 feet behind the bit). This telemetry path actually bypasses the intervening drilling tools (such as the mud motor) between the bit and the MWD tool. Typically, an MWD pulse system receives the signal from the near-bit telemetry link, then recodes it and sends the data to the surface in real time, using mud-pulse telemetry (other telemetry methods can also be used, as described below). Data recording, interpretation and tool control are monitored by the system computer at the surface. From the surface, control instructions can be sent back downhole by varying mud pump flow. Data can be transmitted to the surface by a number of methods: Mud-Pressure Telemetry positive pressure pulse, negative pressure pulse, and continuous wave Electromagnetic Wave Telemetry Drill Pipe Telemetry Each of these methods will be described below. Positive Pressure Pulse The most common method uses a positive pressure pulse system. With this type of system, a hydraulic poppet valve momentarily restricts the flow of the mud through the drillpipe, creating a positive standpipe pressure pulse. Data is transmitted to the surface as a series of pressure pulses. A transducer at the surface detects the pressure changes and a computer decodes the signal. Negative Pressure Pulse A negative mud pulse system uses a control valve in the sub to vent mud from the interior of the tool to the annulus, thus creating a drop in pressure at the standpipe. Data is recorded at the surface in a manner similar to that described above. Continuous Wave Continuous wave telemetry uses a downhole rotary valve with a slotted rotor and stator to restrict the mud flow through the MWD tool, thus generating a modulating positive pressure wave which travels to the surface and is detected by the transducer at the standpipe. Electromagnetic Telemetry A different method has been devised for use in cases where a compressible drilling fluid is used (such as underbalanced drilling,) or in areas where severe lost circulation prevents transmission of a pressure pulse up the drillpipe. Developed as an alternative to mud-pulse telemetry, this system uses low-frequency electromagnetic waves to transmit data from the MWD tool to the surface. Instead of drilling fluid, the electromagnetic MWD tool (EM-MWD) relies on geological formations to conduct the data to a surface antenna, where it is relayed to an acquisition unit for decoding and processing. (Offshore, the antenna must be coupled to the sea-floor, as seen in Figure 8: Offshore installation, yellow waves show data transmitted from tool to surface, blue waves show instructions transmitted from surface to tool.) FIGURE 8 Offshore installation (adsbygoogle = window.adsbygoogle || []).push({}); The EM-MWD tool transmits toolface, inclination, and azimuth data for directional surveys. It is often fitted with a gamma ray tool to provide formation boundary definition for real-time correlation. An annulus pressure gauge can also be added to directly measure pressures during drilling and tripping operations. The EM-MWD requires no modification to the rig's drilling fluid circuit, and can operate continuously during all phases of drilling operations, including pipe connections and trips. Because EM-MWD systems do not depend on rig hydraulics to transmit their data, they are not plagued by problems common to mud telemetry systems such as bit-pressure drops, fluctuating flow rates, lost circulation materials, or mud losses to the formation. (However, the EM-MWD system has experienced difficulties in high resistivity formations, so to avoid problems with signal propagation and attenuation, it should be installed in high conductivity formations.) This system provides two-way communication between the surface unit and the downhole tool. Data is transmitted from the tool to the surface, and instructions can be sent from the surface to the tool. The EM-MWD system is able to collect and transmit survey data while the surface mud pumps are running or idle, as long as the drillstring does not move. Though used in conventional, horizontal, and directional drilling operations, this system is seeing increasing utilization in underbalanced drilling, as such wells become more popular in older, depleted fields. Because these wells frequently employ unconventional drilling fluids such as foam, mist, air, or aerated mud, the EM-MWD is often fitted with an annulus pressure gauge to monitor drilling operations. Drill Pipe Telemetry Drill pipe telemetry offers the capability of transmitting high-bandwidth data from any point along the drill string. This system requires specially manufactured drillpipe, incorporating a high-speed cable attached to the inner wall, and special couplers at the ends of each joint of pipe. (Figure 9: Cut-away view of IntelliPipe drill pipe telemetry system, developed by Grant Prideco and Novatek Engineering). FIGURE 9 Drill pipe telemetry system This special cable and coupler arrangement enables data to be transmitted up the hole at a rate of 1 million bits per second, which is several thousand times faster than mud-pulse telemetry systems. The drillpipe telemetry system is virtually transparent to standard rig operations, requires no special pipe-handling or make-up procedures, and works as long as there is pipe in the hole. This high-speed, bi-directional communications link can be integrated with downhole temperature and pressure sensors; steering systems; MWD or LWD systems; remote and Web-based monitors and analytical tools; and acoustic systems. This system allows the Geosteering Team to receive high-speed data for up-to-the-minute analysis. It also enables the Directional Driller to relay steering commands downhole more quickly in order to drill more precisely toward oil-and gas-bearing sweet spots and away from less productive areas. (adsbygoogle = window.adsbygoogle || []).push({}); Controlling Trajectory of Directional Wells (adsbygoogle = window.adsbygoogle || []).push({}); This section describes the tools and techniques used to control the path of a wellbore. Starting with the oldest method, we show how the process has evolved to provide better steering control and smoother wellbores. Rotary and Sliding Modes In nearly all cases (with the exception of wells drilled from slant-hole rigs), wells must first spud vertically before building wellbore angle. Controlled deviation from vertical begins at a pre-determined depth called the Kick-Off Point, or KOP (Figure 1: KOP -where the directional drilling starts). FIGURE 1 KOP -where the directional drilling starts The vertical segment of the well is drilled using conventional rotary methods, in which the drill string is rotated from the surface by a rotary table located beneath the derrick floor, or by a topdrive motor, suspended from the traveling block in the derrick. This type of drilling is called rotary drilling. With conventional rotary assemblies, it is possible to make small changes in direction or inclination by changing either the weight-on-bit (WOB) or the rotary speed. Sharper directional changes can be achieved by adding or changing stabilizers. This approach was pioneered in the early days of directional drilling as a way of building long-radius curves. For drilling short-to medium-radius curves, however, it is usually necessary to run a steerable mud motor. Upon reaching the KOP, therefore, the rotary BHA must be tripped out of the hole and replaced with a steerable mud motor. Basically, the steerable motor allows two modes of drilling: Sliding mode: where circulating drilling mud provides power to the mud motor, which causes the bit to rotate while the drillstring does not rotate. The bit drills in the direction of the oriented toolface; thus building a continuous angle from the vertical. Rotary mode: where the entire drill string is rotated from the surface, negating the effect of the toolface bend, and thus causing the bit to drill a straight course. In the overall directional drilling strategy, sliding is used for precision guidance of the assembly towards a prescribed target, whereas rotating involves no active guidance of the trajectory. Steerable motors drive the bit in the direction set by the bent sub; the larger the angle of the bend, the sharper the "build" in the curvature of the wellbore. As with the rotary BHA, minor changes in direction are achieved by adjusting the weight on bit. Large changes in direction are made by lifting off bottom and reorienting the bent sub by rotating its position from the surface. Once the proper trajectory is achieved, the lateral section of the wellbore is often drilled using a variation on the rotary mode. A conventional BHA may be used for straight, fast sections; or the steerable motor can be used like a conventional BHA, with the drill string rotated from the surface. The benefit of using a steerable motor in rotary mode is that any directional changes can be made without tripping for a new BHA. However, when a downhole motor is used to drill in rotating mode, the rate of penetration (ROP) is limited, to a degree, by how much weight on bit (WOB) the Directional Driller can safely apply. Though a certain amount of weight is needed, too much weight can stall or damage the motor, requiring an expensive trip for motor replacement. The Driller must balance the weight for increasing ROP against the operational limit of the motor. In lateral sections, gravity works at 90 degrees to the horizontal drillstring, thereby producing considerable torque and drag on the drillstring. When a horizontal well is drilled forward in rotating mode, the rotation of the drillstring and mud motor can reduce torque and drag somewhat. However, during sliding mode the drillstring does not rotate, and this generally results in increased torque and drag. Another hindrance is stacking of drillpipe. (Stacking occurs as pipe is deformed in the curve of the build section, when pipe rests and drags against the formation.) These problems are overcome by increasing the WOB. Though sliding mode provides greater control and flexibility over the directional aspects of drilling, it is gained at the expense of speed. Wells generally drill faster in rotary mode, and rotation of the drillstring has the added benefit of reducing the risk of getting stuck. Whenever possible, the Directional Driller will therefore opt to drill most sections of the hole in rotary mode, only using sliding mode for changing the hole angle. Alternatives to Sliding (adsbygoogle = window.adsbygoogle || []).push({}); The practice of rotating until a course correction is needed, and then sliding to get back on track, can lead to increased wellbore tortuosity, along with a host of unwanted problems. Tortuosity is caused by doglegs and spiraling of the wellbore, both of which stem from rapid changes in azimuth and/or inclination. Tortuosity can ultimately shorten the lateral length of a horizontal well as problems mount, due to: Increased hole cleaning difficulty and an increased risk for stuck pipe. Increased bit bounce, and whirl (a deviation of bit rotation from the bit’s geometric center). Increased torque and drag. Increased vibration resulting in increased wear and tear on MWD/LWD tools. Increased difficulty in running casing and wear on tubulars. After a well has been drilled, tortuosity can affect the completion program by restricting the ability to run completion tools, or increasing liquid holdup when the well is brought on-line. Ideally then, the well should be drilled to plan, with as little sliding as possible to attain a smooth wellbore and minimal tortuosity. Alternatives to the old rotate-and-slide method have been developed which provide greater steering precision, smoother wellbores, better hole cleaning, and faster ROP. Two basic options have been developed to greatly decrease the need for sliding, and allow the drill string to continue rotating while changing course. Adjustable Gauge Stabilizers Directional Drillers found they could obtain the benefits of rotary drilling by using an adjustable stabilizer. Sometimes called 2D rotary stabilizers, the adjustable gauge stabilizer is used to control wellbore inclination, but does not have the capability to control azimuth. These stabilizers use adjustable buttons or blades to change the diameter of the stabilizer (Figure 2: Buttons mounted on stabilizer blades in closed and extended positions). FIGURE 2 Buttons mounted on stabilizer blades in closed and extended positions The stabilizers are either mechanically activated by adjusting weight on bit, or they are activated hydraulically by reducing, and then increasing mud flow from the pumps. Adjustable stabilizers meet most horizontal drilling requirements to provide dependable, rapid, precise inclination control within tight target corridors. Because most trajectory corrections involve only inclination along a straight path (where azimuth is not a concern) these adjustable stabilizers can often be used to drill straight to TD. In wells that chase pay zones laterally from one target to another, the adjustable stabilizer is usually placed above a motor. This configuration eliminates sliding to correct for inclination, while allowing the motor to come into play when a change in azimuth is required. Rotary Steering Systems Rotary steering systems take directional control a step further, by controlling azimuth as well as inclination. These systems use a steering assembly mounted above the bit, and work by either applying a side force to the bit or by pointing the bit through a shaft or BHA deflection device. These systems are usually guided by directional sensors with feedback circuitry to orient the bit side force or maintain the prescribed trajectory (Figure 3: Rotary steering tool). FIGURE 3 Rotary steering system Early rotary steering models worked in much the same way as the adjustable stabilizer. These systems, sometimes classified as Push-the-Bit technology, steer the well by using adjustable pads or buttons that exert side forces on the wellbore to cause bit deflection. Second-generation systems are classified as Point-the-Bit technology. Instead of using external pads to push the bit sideways, these rotary steering systems steer the well by flexing a non-rotating drive shaft that is connected to the bit. This flexure changes the direction of the bit face. Most rotary steering systems can also provide automated steering capabilities by means of a pre-programmed trajectory, designed on the surface computer. Overall Benefits Though not always possible, rotary drilling has several advantages over sliding with a mud motor. Rotating allows more weight on bit and higher rates of penetration. Rotating generally does a better job of cleaning the hole of cuttings, thus reducing drag and the need for short trips to circulate up cuttings. The net result is an increase in footage drilled per day. A smoother wellbore ultimately influences every parameter of the drilling and production process. First, the tool string is subjected to less downhole vibration, torque and drag. With a reduction in bit bounce and whirl comes improved bit performance and increased reliability of downhole motors and LWD tools. Finally, it smoothes the process of running casing and decreases holdup of produced fluids. (adsbygoogle = window.adsbygoogle || []).push({}); Directional Drilling Sections (adsbygoogle = window.adsbygoogle || []).push({}); Now that we have reviewed the mechanical aspects of directional drilling, we can now describe the basic process of guiding the wellbore to the target. With the exception of the vertical portion of the well, there are three key segments of the wellbore that will most affect the geosteering project (Figure 1): FIGURE 1 Guiding the wellbore to the target The Build Section is that portion of the directional wellbore curve that generally extends from the Kick-Off Point (KOP) to the Last Chance Marker, where the majority of the angle is built. The Landing Section is that portion of the wellbore beyond the build section where the steering process is closely monitored and fine-tuned in order to hit the target. This section is further subdivided into two segments: The upper portion of the Landing Section is called the approach section, where major corrections to the trajectory can be made to setup the drill string to hit the target. The taper section forms a smooth transition at the end of the landing as the drillstring enters the target zone. The Lateral Section is the section of the wellbore that extends horizontally from the end of the landing taper, out to the end of the wellbore. The mechanics of geonavigation are basically the same for each section, but the Geosteering Team will find their priorities changing in from one section to the next. The Build Section The build section extends from the Kick Off Point (KOP) to the Last Chance Marker, or to a point where inclination reaches ±45 to 60 degrees (Figure 1). The KOP may be defined strictly by depth, but should ideally be tied to a stratigraphic marker that will be expected at a preplanned distance above the reservoir target. Once the stratigraphic marker for the KOP is cut, the Geosteering Team may need to adjust the entire wellbore plan up or down - depending on how high or how low the marker was intercepted by the wellbore. In cases where the target is below an unconformity, or in areas where there are no markers for correlation above the target, the well plan should place the KOP high enough in the section to provide sufficient room for building angle. It is better to place the KOP too high rather than too low. It will be stressed again and again that the target for landing the well should be a line, rather than a point in space. This will give the Directional Driller more flexibility than a point specified strictly at a certain distance, direction, and depth from the surface location. The target line through the build and landing sections may actually become a moving target to accommodate the unforeseen presence of small faults or changes in formation dip rates. This reinforces the assertion that, through the build section, it is important to know where the well lies with respect to the stratigraphic framework of the prospect. The formation dip between the surface location and the landing zone will exert a great influence as to where the target is actually intersected. It is important to keep track of the stratigraphic position of the wellbore throughout the build section by creating a True Vertical Depth (TVD) log or True Stratigraphic Position (TSP) log, and correlating it to the log from the pilot hole (if there is one) or to nearby offset wells. The Geosteering Team will use the TVD log to determine whether the well is drilling in an updip or downdip direction (Figure 2: Well log distortion with dip). FIGURE 2 Well log distortion with dip (adsbygoogle = window.adsbygoogle || []).push({}); If the TVD log from the horizontal LWD is thinner in the build section than the vertical offset, then the well is drilling updip. If the TVD log from the horizontal LWD is thicker, then the well is drilling downdip. If the TVD log is about the same thickness as the offset vertical log then the dip is relatively flat. This TVD effect is more noticeable with increasing inclination and higher formation dip rates, but can also be noticed with dips as low as 2 degrees. The Geosteering Team can then order minor adjustments to Build Up Rate (BUR), based upon their stratigraphic correlation. One reason that it is better for a KOP to be too high rather than too low is because every BHA has a maximum BUR that it can attain. However, a lower BUR can be achieved either by wobbling the toolface, (turning the toolface a little left, then a little right) or by rotating the drillstring (most build assemblies cannot rotate, and extreme care should be taken with those that can). If the formation comes in higher than expected (usually due to an unexpected change in dip rate or a fault), then a trip may be required to adjust the BHA for a higher BUR before the build section is complete. Last Chance Marker The Last Chance marker is a stratigraphic marker that is used as the basis for making final adjustments prior to landing the well into the target zone (Figure 1: Last chance marker). This marker should be penetrated with a drillstring inclination of 45 -60 degrees. The Last Chance Marker is so named for a reason: when the Last Chance Marker is reached, it is the last opportunity for the Geosteering Team to decide whether to stay the course or to adjust the build rate. If the well is on target line and the BUR is within tolerance, then simply continue drilling with the same BHA. If the BUR is too high, and the well is above the projected line, then trip for a less aggressive BHA to land in target, or rotate the drill string if the BHA allows. If the BUR is too low and the well is below the projected line, then trip for a more aggressive BHA. Effects of Dip The last time it will be possible to make any major corrections to the BUR will be while the wellbore is at an angle of 45 to 60 degrees (depending on the formation dip and whether the well is drilled in an updip or downdip direction). There is less leeway on the target landing for an updip well than for a downdip well. When a well is drilled in an updip direction, not only is the well building angle, but the formation is coming up toward the well. This leaves less room between the KOP and the target at the end of the curve. If the well is drilled in a downdip direction, the formation falls away from the wellbore so that TVD distance increases between the KOP and the formation as the curve is built. It is nonetheless important to be positioned for the landing by the time that the wellbore inclination reaches 60 degrees. Once the Last Chance Marker is cut, or the wellbore reaches an inclination of 60 degrees (whichever comes first), the type of landing should be determined. The Landing Section The landing section is critical to the success of the horizontal well. The manner in which a well is landed depends on these important factors: the position of the bit at the end of the build, the BUR required to hit the target, and the presence (or lack of) good stratigraphic markers above the target Drilling the Landing Section The landing section is completed in at least two steps, as seen in Figure 1. The Approach Sectionis the portion of the Landing Section that extends from the Last Chance Marker to a point where inclination is within 5 -8 degrees of formation dip. For instance, if the formation dips at 5 degrees and the well is drilling in an up-dip direction, then the approach section should end at about 88 -90 degrees. (Conversely, if the well was drilling downdip in the same area, the approach section would end with an inclination of 77 - 80 degrees.) The Taper Section is the final stage of landing, and is generally performed with the maintenance assembly that will drill the Lateral Section. There are a number of ways to approach the target (Figure 3): (adsbygoogle = window.adsbygoogle || []).push({}); FIGURE 3 Drilling the Landing Section Option One -Ideal Case: In the ideal case, the target will come in with the expected dip rates and planned BUR, so the landing can be continued with the current BHA until the taper section is reached. In this case, the build section is continued to within 5 to 8 degrees of the apparent formation dip. Then the BHA must be tripped to change from a build to a maintenance assembly. The curve will then be tapered into the target, and the drilling transitions to the lateral section. Option Two -BUR Too High: If the BUR is too high at the Last Chance Marker, then there are two options. The first is to trip for a build BHA that will lower the BUR, then drill to the target, and trip again for the maintenance assembly. An alternate method is to continue with the current BHA until sufficient angle has been built to allow the maintenance assembly to complete the build, and then taper into the target. This will require only one trip versus two, but the GeoSteering Team must recognize that the landing will take place a little further out in the target zone. Ultimately, the GeoSteering Team must strike a balance between the cost of a trip and the loss of a little exposure to the reservoir. For short laterals, the first method may be more appropriate. For long lateral sections, however, a little lost exposure at the end of the curve can be regained in the lateral section. Option Three -BUR Too Low: When the build angle is too low for the current BHA to reach the target, then a trip will be required to pick up another BHA capable of attaining a higher BUR. This will require another trip for the taper and lateral sections, once the approach is completed. Option Four -Tangent Approach: In areas where the target depth is uncertain because of a dearth of stratigraphic markers above the target, then a tangent approach should be planned. With a tangent approach, it is best to build angle to a point where a rotatable BHA can be used to drill the tangent section, then taper the landing. The tangent section is often drilled at an angle of 75 -80 degrees. This angle will depend greatly upon the level of uncertainty with regard to: the intersection with the target reservoir, the thickness of the target, and the apparent formation dip of the target. Once the target formation is cut, the angle will be built to match apparent formation dip. Casing Points When setting casing at the top of the target, it is probably best to set casing before the taper is made, if the thickness of the target allows it. There have been a number of cases where angle was built to within one or two degrees of the predicted formation dip, only to have the bit unexpectedly penetrated the top of the zone upon drilling out of casing. This happens when the formation dip is steeper or flatter than the GeoSteering Team expected. The Lateral Section The Lateral Section is the most important segment of the horizontal well because it provides maximum exposure to the reservoir. (Again, seen in Figure 1.) Any course change within the Lateral Section will affect the reservoir for better or for worse. The Lateral Section is drilled using a maintenance BHA. The maintenance BHA will have a mud motor configuration that allows the drillstring to be rotated. The inclination and azimuth of the Lateral Section is maintained through a combination of sliding and rotating of the drillstring. The goal of many company Drilling Representatives or Wellsite Engineers is to slide as little as possible, because the bit cuts hole much slower in sliding mode. On the other hand, the Geosteering Team must ensure that the wellbore stays in the target zone. These two goals may often be at odds, so it is important that everyone be attuned to the goal of attaining maximum exposure to the reservoir. The method of geosteering in the Lateral Section and the selection of a target line depends upon: the style of wellbore planned the thickness of the target the complexity of the geology For instance, if a traverse or sinusoidal wellbore is supposed to be drilled through the target at a specified rate, then geosteering is used to ensure that the well does not pass through the section sooner (or later) than expected because of unanticipated changes in apparent formation dip rates. Small corrections should be made as the well is drilled to meet the reservoir penetration goals. For an in-zone well, the object is to stay as close to the apparent formation dip rate as possible. The closer that the drillstring is to dip, the longer it will stay in zone without correction. Thin targets will require more target changes and closer supervision, while thicker targets give the driller more leeway (which means fewer slides are needed). More steering decisions and closer supervision will be required in wells that are drilled in areas of complex geology. Specifying Geosteering Target Lines To get the most from the Directional Driller, the Geosteering Team should convey targets as lines, rather than points. Directional Drillers can often be grouped into two camps with respect to target lines. One camp prefers to slide only when the well is about to drill beyond the given target tolerances. At that point, they will make a large correction with a long slide to be certain the well stays in target. The other camp prefers to make a series of small corrections to ensure that the well stays on target. This group feels that 3 -5 foot corrective slides provide the best course of action. One point to remember is that the severity and position of doglegs are what cause torque and drag problems -not the number of slides. In a long Lateral Section, the second camp will more likely reach projected length. This is one of the reasons that target lines work when points do not. A Directional Driller is more likely to stay closer to a line. Long slides of 20 feet or more should be reserved for the build or landing sections, and should be used sparingly within the Lateral Section. The only time large corrections should be made are after a fault is cut or to counter strong dip changes. Occasionally, mechanical problems such as a formation change or torque and drag may prevent course corrections until a trip is made to clean the hole or change the BHA. After such a trip, a large correction may be needed to get back into target. Guidelines for the Lateral Section The Geosteering Team should develop contingency plans in advance of any major problems that may be encountered in the Lateral Section. The Lateral Section is more of a decision management exercise than either the Build or Landing Section, simply because it is more difficult to interpret the wellbore’s position within the targeted zone. GeoSteering Team guidelines for the Lateral Section include: Make decisions ahead of time: Contingency plans should be formulated before the well spuds in order to prescribe the general outline of response to a wide range of drilling scenarios. All that remains is to examine the data and act upon the decision. Often, in the excitement of the moment, there is a tendency to make decisions that do not adhere to the contingency plan, and hence fail to advance the objectives set forth in the plan. However, if a course of action can be planned under calmer conditions, before the event occurs, then adhering to the response plan will be easier. Make bailout or sidetrack contingencies, and then abide by them. When a fault is cut, or when a pinch-out is encountered, determine the throw and position of the well in-section after the fault, or confirm the pinch-out. If the throw is too great to recover, or if the formation has pinched-out, then follow the contingency plan. Make a target change ONLY WHEN THE GEOLOGY CHANGES. There simply is no other reason to make a target change. Target lines should only move when the wellbore begins to approach the target boundaries as a result of unforeseen changes in the formation. Make the least number of target changes possible to stay within the target. Every target change will affect the course of drilling in the remainder of the well. Doglegs increase torque and drag in the lateral section. Each dogleg adds to the problem, so the length of the lateral section is generally limited by the number of target changes. Thin targets with complex geology will require more target changes than thicker targets in simple geology. Thin targets, complex geology, and fast drilling can create nightmares for the Geosteering Team. These are the hardest type of targets to geosteer, and require constant supervision and intensive interpretation. Target changes for these types of reservoirs will be more frequent. Make steering decisions only when ALL of the critical data has been examined. Instant decisions that do not include all pertinent data are only guesses, and often cause more harm than good. The only mistake that the geosteering team should regret is the one made without first examining the data. A decision made through guessing or through panic can cause an unnecessary dogleg at minimum, or a sidetrack in the worst case. Mistakes in interpretation will invariably be made -so admit the mistake, recover, and continue. There are times when two perfectly reasonable interpretations fit the data. In these cases, it is best to look at more data to resolve the two interpretations (if possible). Many such cases actually resolve themselves in short order when more data is introduced. If the situation cannot be resolved with a reasonable amount of time and more data, then make the best choice and live with it. If it is discovered that the choice was not correct even after studying all of the data, then admit it and make plans to get back on target. (adsbygoogle = window.adsbygoogle || []).push({}); Directional Drilling Terminology (adsbygoogle = window.adsbygoogle || []).push({}); For a GeoSteering Team to work effectively with the Directional Driller and other geonavigation specialists, they must be able to communicate in the same language, using a precisely defined terminology that leaves little room for misinterpretation between specialists from different disciplines. The following terms will be useful in maintaining good communication between the GeoSteering Team and the Specialists at the wellsite. Accelerometer - A device mounted inside MWD, wireline, and survey tools to measure the acceleration of a tool in a particular direction, thus detecting changes in direction with respect to the Earth's gravity. Actuator - A hydraulic component in the MWD transmitter that creates a pressure pulse in the process of mud pulse telemetry. Azimuth - Direction of drilling expressed as a compass bearing ranging from 0 -360 degrees, without respect to Vertical Section Plane, Inclination, etc., as shown in Figure 1. Azimuth can be obtained as part of a directional survey. FIGURE 1 Azimuth Direction Azimuthal Deviation - The difference in azimuth between actual and planned well paths, typically expressed at a specific measured depth. Bit Whirl - A deviation in bit rotation around the bit’s geometric center. Build Up Rate (BUR) - The rate at which the well builds inclination, expressed as [latex]\tfrac{degrees}{30 meters}[/latex] of Measured Depth (or [latex]\tfrac{degrees}{100 feet}[/latex] ). [latex]BUR = \tfrac{\Delta_{Inc}}{30\textrm{ meters MD}}[/latex] (Figure 2). FIGURE 2 Build Up Rate (BUR) Closure Distance - The shortest lateral distance between the well’s surface location and a point in the wellbore, as shown by the blue line in Figure 3. (adsbygoogle = window.adsbygoogle || []).push({}); FIGURE 3 Closure Distance Closure Direction - The azimuthal direction from the surface location to a survey point in the wellpath, measured in a 360-degree (radial) coordinate system. Course Deviation - The vertical displacement between two survey points. Declination - The angular difference in azimuth between magnetic north and true north. The magnetic declination varies from one position on the earth to another, with changes in local magnetic fields. Declination also changes over time, usually at a regular pace of a fraction of a degree every year. This change occurs with the gradual drift of magnetic north. By convention, magnetic declination is denoted as positive when magnetic north lies east of true north, and negative when magnetic north lies west of true north. Departure - The coordinate measured in an east-west direction to describe the map view location of a target. Deviation - The inclination angle of the wellbore axis measured from a vertical axis. Dip - The inclination angle which a geologic layer, sedimentary bed, or seismic reflector makes with horizontal plane. Directional Drilling - The intentional deviation of a wellbore from the vertical, along a pre-planned course of trajectory. Directional Survey - A process of measuring depth, inclination and azimuth to determine the true vertical depth and position of the wellbore. Dogleg - An abrupt change in hole angle. Though doglegs are sometimes created intentionally by directional drillers, this term is most often used to describe a hole section where trajectory changes faster than anticipated or desired. The Directional Driller will strive to limit the severity of a dogleg, which can cause such problems as: Deviation of the wellbore from its planned course. Inability to run casing through the dogleg. Excessive wear between the casing and the drill string. Sticking problems arising from the development of keyseats in the crooked section of the hole. Dogleg Severity (DLS) - A normalized estimate of the overall curvature of the well path between two consecutive survey stations. Dogleg severity is expressed in degrees / 30 meters or degrees / 100 feet, and describes the three dimensional, cumulative change in wellbore inclination and azimuth. This information, obtained through regular wellbore directional surveys, can be considered a measure of wellbore tortuosity. Downhole Motor - A tool positioned above the drill bit that converts hydraulic energy from the circulating drilling fluid into mechanical energy, in order to turn the bit without having to rotate the drill string. Drift - Deviation from the vertical. Extended Reach Well - Any well which deviates in excess of 65 degrees from the vertical, and which reaches out horizontally for a distance that is more than twice its vertical depth. Gyroscopic Survey Tool - A survey instrument which uses a gyroscope to measure the well’s azimuth angle at each survey point. Highly Deviated Well - A well drilled with an inclination of 30-80 degrees from vertical. Horizontal Drilling - A directional drilling technique which causes wellbore deviation to exceed 80 degrees from the vertical, with the intent of maximizing the length of wellbore exposed to the reservoir. Wells that undulate above and below 90 degrees deviation are also classed as horizontal wells. Inclination - The measure of a well’s deviation from vertical, in degrees, without respect to Azimuth, Vertical Section Plane, etc. Inclination can be measured by a pendulum-type mechanical drift indicator (only used in the vertical segment of a well), or by magnetic or gyroscopic survey tools, inertial navigation devices, wireline steering systems, or MWD tools. By convention, 0.0 degrees of inclination describes a vertical well path, while a horizontal path is expressed as 90 degrees. Hence, 10 degrees below horizontal is 80.0 degrees, and 10 degrees above horizontal is 100 degrees. (Figure 4) (adsbygoogle = window.adsbygoogle || []).push({}); FIGURE 4 Inclination measure of a well’s deviation from vertical Kick-Off Point (KOP) - The point at which a vertical well is intentionally deviated by increasing inclination to create a directional or horizontal well. This point marks the beginning of the build section in a directional well, captioned in yellow in the accompanying Figure 5. FIGURE 5 Kick-Off Point (KOP) Last Chance Marker - A recognizable stratigraphic marker, usually located near the base of the build section, which serves as the basis for making course adjustments before drilling into the landing section of a horizontal well, as shown in the accompanying Figure 6. Lateral Bore - The horizontal section of a horizontal or multilateral well. Long Radius Well - A horizontal well characterized by a maximum build rate of 6˚ per 100 feet, and a build radius of 1000 -3000 feet. Such wells can be drilled with rotary or steerable systems for the curve and horizontal sections. Measured Depth - The entire length of the well, as measured from the rotary table or kelly bushing. Medium Radius Well - A horizontal well characterized by a build rate of 6˚ -20˚ per 100 feet, with a corresponding build radius of 300 -700 feet. Such wells are drilled with specially designed motors in the angle-build section, and may use rotary or steerable systems for the horizontal sections. Minimum Curvature (Circular Arc) - A method used to derive horizontal and vertical coordinates from the values of along-hole-depth (ADH), inclination (I), and azimuth (A). Mud Motor - A downhole motor that is hydraulically driven by the circulation of drilling fluid, and designed to rotate the bit without rotating the drill string. Poppet Valve - A conical device on the MWD downhole assembly which extends and retracts to restrict the flow of mud, thus generating a pressure pulse. Pressure Pulse - A momentary variation in mud pressure used to transmit data from the downhole MWD tool up to the surface. Each pulse has a value of one or zero, depending on how long the poppet valve stays open. Proposed Direction - The azimuthal direction that a wellbore must follow to reach its target. Radius of Curvature (ROC) - The radius of curvature (Figure 2) refers to the length of the radius of the build section, and is related to the BUR with the following formula: Meters BUR=360⋅302πROC=5400πROC BUR = \tfrac{360\cdot 30}{2 \pi\, ROC} = \tfrac{5400}{\pi \, ROC} ROC=360⋅302πBUR=5400πBUR ROC = \tfrac{360\cdot 30}{2 \pi\, BUR} = \tfrac{5400}{\pi \, BUR} Feet BUR=360⋅1002πROC=18000πROC BUR = \tfrac{360\cdot 100}{2 \pi\, ROC} = \tfrac{18000}{\pi \, ROC} ROC=360⋅1002πBUR=18000πBUR ROC = \tfrac{360\cdot 100}{2 \pi\, BUR} = \tfrac{18000}{\pi \, BUR} Rate of penetration (ROP) - The speed at which the bit drills the formation. Rotor - A hub and vane assembly which transmits torque to the main drive shaft in an MWD turbine. Scribe Line - A reference line cut along the body of the sub or tool. Short Radius Well - A horizontal well characterized by a build rate of 1.5° -3° per foot, with a corresponding build radius of 20 -40 feet. Such wells are drilled with specially designed deflection tools or articulated motors in the angle-build section, and use rotary tools with special drill pipe for the horizontal. Stabilizer - A short sub equipped with blades which create an outside diameter that is equal to, or slightly smaller than the bit size. The blades are designed to support the drill string against the wall of the hole while providing a minimal restriction for the circulation of drilling fluids. In directional drilling, some stabilizers have adjustable blades which can be used to turn the direction of the wellbore. In other cases, fixed stabilizers are used to stiffen the drill string. (adsbygoogle = window.adsbygoogle || []).push({}); Stator - The stationary fluid guide of an MWD turbine, through which the rotor turns. Survey Tool - Electromechanical or mechanical device to measure either or both azimuth angle and inclination and to record these values photographically or mechanically. Tool Face - The relative direction of the bend in the directional assembly. Transducer - A component of the MWD system connected to the standpipe to detect mud pressure pulses generated by the downhole MWD tool. This sensor then converts the mud pressure pulses into electrical signals which can be processed by the surface MWD computer. Transmitter - A component of the downhole MWD tool, which converts the electrical data signal into a pressure pulse. True Vertical Depth (TVD) - The vertical depth of the wellbore measured from a datum (usually the kelly bushing or derrick floor). True Stratigraphic Position (TSP) - The position of the wellbore relative to a stratigraphic marker. The target horizon is designated as zero (0) TSP. If the well is above the marker it has a negative (-TSP); and if the wellbore is below the marker it has a positive TSP (+), as shown in Figure 6. FIGURE 6 True Stratigraphic Position (TSP) Vertical Section (Distance) - The horizontal distance of a well path projected on a vertical plane along a specific azimuth. The specific azimuth is usually equal to the final target azimuth. It is a one-dimensional number expressed in feet or meters. If the well path departs somewhere to either side of the vertical section plane (and it usually does), then the vertical section distance is projected back perpendicular to the vertical section plan (Figure 3). Vertical Section Azimuth - The proposed azimuth of the vertical section plane or proposed direction of the well. Vertical Section Plane - An imaginary 2-dimensional plane having vertical (Z) and horizontal (X) dimensions. It is more easily pictured as a cross-sectional plane that originates along a vertical line extending straight down from the well’s surface location, and which proceeds horizontally away from the location along the azimuth bearing that the well is supposed to follow. It is usually abbreviated VSP and defined as a direction 0 -360 degrees (azimuth) or "North xx.x degrees East", "South xx.x degrees West", etc. The vertical dimension is not specified (Figure 7). FIGURE 7 Vertical Section Plane (adsbygoogle = window.adsbygoogle || []).push({}); Assessment (adsbygoogle = window.adsbygoogle || []).push({}); 1. SP is the abbreviation of which of the following terms? A .Turning Slippery PipeB .True Stratigraphic Position ✔C .True Stationary PositionD .Tripping Safety Procedure 2. Horizontal wells are often a viable option with respect to: A .Reducing a well’s surface footprintB .Targeting laterally heterogeneous reservoirsC .Reducing water coningD .Producing from heavy oil reservoirsE .Replacing multiple vertical wells in infill drilling programsF .All of the above ✔ 3. When evaluating the potential for drilling a horizontal well one must consider A .The cost of the horizontal well relative to the cost of the number of vertical wells it will replace.B .The cost for completion of the horizontal wellboreC .The appropriate spacing for the horizontal wellboreD .All of the above ✔ 4. Geosteering is primarily ______. A .an engineering exerciseB .a stratigraphic exercise ✔C .a task assigned to the directional drillerD .a task that the Company Man should handle Recommended for You The Principles of Geosteering | Geosteering Best Practices Preparing the Geosteering Plan Geosteering Practices Case Study Geosteering (adsbygoogle = window.adsbygoogle || []).push({});