Directional Drilling

Directional drilling is defined as the practice of controlling the direction and deviation of a well bore to a predetermined underground target or location

1.Applications

• Multiple wells from a single location. Field developments, particularly offshore and in the Arctic, involve drilling an optimum number of wells from a single platform or artificial island. Directional drilling has helped by greatly reducing the costs and environmental impact of this application.

• A well is directionally drilled to reach a producing zone that is otherwise inaccessible with normal vertical-drilling practices. The location of a producing formation dictates the remote rig location and directional-well profile.

• A very cost-effective way of delivering high production rates involves intersecting multiple targets with a single well bore. This is also applicable to multiple production zones adjacent to a fault plane or beneath a salt dome.

• This technique may be employed either to drill around obstructions or to reposition the bottom of the well bore for geological reasons.

• It is often difficult to drill a vertical well through a steeply inclined fault plane to reach an underlying hydrocarbon-bearing formation. Instead, the wellbore may be deflected perpendicular or parallel to the fault for better production. In unstable areas, a well bore drilled through a fault zone could be at risk because of the possibility of slippage or movement along the fault. Formation pressures along fault planes may also affect hole conditions.

• Salt-dome exploration. Producing formations can be found under the hard, overhanging cap of salt domes. Drilling a vertical well through a salt dome increases the possibility of drilling problems, such as washouts, lost circulation, and corrosion.

• Relief-well drilling. An uncontrolled (wild) well is intersected near its source. Mud and water are then pumped into the relief well to kill the wild one.Directional control is extremely exacting for this type of application.

• River-crossing applications. Directional drilling is employed extensively for placing pipelines that cross beneath rivers, and has even been used by telecommunication companies to install fiberoptic cables.

2.Directional-Well Profiles

2.1.Surface-Hole Section

Most directional wells are drilled from multiwell installations, platforms, or drill sites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved. At the start of the well, the overriding constraint on the well path is the presence of other wells. At its worst, the opportunity to reach certain targets from the installation can be lost if not carefully planned from the outset. Visualizing the relative positions of adjacent wells is important for correct decisions to be made about placing the well path to minimize the number of adjacent wells that must be shut in as a safety precaution against collisions. The steel in nearby wells requires that special down hole survey techniques be used to ensure accurate positioning. This section is generally planned with very low curvatures to minimize problems in excessive torque and casing wear resulting from high contact forces between drill strings and the hole wall. Many directional wells are drilled from surface pads and offshore locations. the traveling-cylinder diagram (TCD). The TCD provides an effective means of portraying the actual position of the well being drilled relative to its planned course and to adjacent wells. The normal-plane projection displays the intersection of wells with a plane constructed in space to be normal to the direction of the planned well at the point of interest. Because of its clear and simple presentation of a complex situation, the normal-plane TCD has recently been used at the well site to assist the simple go/no-go decision and the visualization of collision potential without making any interpretive judgments on well convergence or survey error values.

2.2.Overburden Section

the main part of the well path through the overburden is specifically designed to put the well in the best possible position for penetrating the reservoir. There are three different overall shapes of the well, depending on the penetration requirements. These are build-andhold, S shaped, and continuous build. Getting the right well path through the overburden is a multidisciplinary task in which geologists advise the designer about the presence of faults, the precise shape of salt formations, mud diapers, and other subsurface hazards. Understanding the interaction between the 3D well trajectory and the formation stresses. The main reasons for drilling an S-shaped well are completion requirements for the reservoir. The S-shaped well is often employed with deep wells in areas where gas troubles, saltwater flows, etc. A continuous-build well starts its deviation well below the surface. The angle is usually achieved with a constant build to the target point. The deflection angles may be relatively high, and the lateral distances from vertical to the desired penetration point are relatively shorter than other well types. Because deflection operations take place deep in the hole, trip time for such operations is high, and the deflected part of the hole is not normally protected by casing.

2.3.Reservoir-Penetration Section

the main part of the well path through the overburden is specifically designed to put the well in the best possible position for penetrating the reservoir. There are three different overall shapes of the well, depending on the penetration requirements. These are build-andhold, S shaped, and continuous build. Getting the right well path through the overburden is a multidisciplinary task in which geologists advise the designer about the presence of faults, the precise shape of salt formations, mud diapers, and other subsurface hazards. Understanding the interaction between the 3D well trajectory and the formation stresses. The main reasons for drilling an S-shaped well are completion requirements for the reservoir. The S-shaped well is often employed with deep wells in areas where gas troubles, saltwater flows, etc. A continuous-build well starts its deviation well below the surface. The angle is usually achieved with a constant build to the target point. The deflection angles may be relatively high, and the lateral distances from vertical to the desired penetration point are relatively shorter than other well types. Because deflection operations take place deep in the hole, trip time for such operations is high, and the deflected part of the hole is not normally protected by casing.

3.Horizontal Wells
Horizontal wells are high-angle wells (with an inclination of generally greater than 85°) drilled to enhance reservoir performance by placing a long well bore section within the reservoir.
3.1.The advantages of horizontal wells include
• Reduced water and gas coning because of reduced drawdown in the reservoir for a given production rate, there by reducing the remedial work required in the future.
• Increased production rate because of the greater well bore length exposed to the pay zone.
• Reduced pressure drop around the well bore.
• Lower fluid velocities around the well bore.
• A general reduction in sand production.
• Larger and more efficient drainage pattern leading to increased
overall reserves recovery. Horizontal wells are normally characterized by their buildup rates and are broadly classified into three groups that dictate the drilling and completion practices required.
The “build rate” is the positive change in inclination over a normalized length. A negative change in inclination would be the “drop rate.”
4.Multilateral Wells
Multilateral wells are new evolution of horizontal wells in which several well bore branches radiate from the main borehole. Multilateral technology has advanced dramatically in recent years to assist in recovering hydrocarbons, particularly in heavy-oil applications.
5.Extended-Reach Wells
An extended-reach well is one in which the ratio of the measured depth (MD) vs. the true vertical depth (TVD) is at least 2:0.
6.Design Wells
Today, most directional-well planning is done on the computer. Modern computer technologies, such as 3D visualization and 3D earth models, have provided geoscientists and engineers with integrated and interactive tools to create, visualize, and optimize well paths through reservoir targets.
7.Directional Survey
The method used to obtain the measurements needed to calculate and plot the 3D well path is called directional survey. Three parameters are measured at multiple locations along the well path (MD, inclination and hole direction). MD is the actual depth of the hole drilled to any point along the wellbore or to total depth, as measured from the surface location. Inclination is the angle, measured in degrees, by which the wellbore or survey-instrument axis varies from a true vertical line. For example an inclination of 0° would be true vertical, and an inclination of 90° would be horizontal. Hole direction is the angle, measured in degrees, of the horizontal component of the borehole or survey-instrument axis from a known north reference. This reference is true north, magnetic north, or grid north, and is measured clockwise by convention. Hole direction is measured in degrees and is expressed in either azimuth (0 to 360°) or quadrant (NE, SE, SW, NW) form. Each recording of MD, inclination, and hole direction is taken at a survey station, and many survey stations are obtained along the well path. The measurements are used together to calculate the 3D coordinates, which can then be presented as a table of numbers called a survey report. Surveying can be performed while drilling occurs or after it has been completed.
7.1.The purposes of directional survey
•Determine the exact bottom hole location to monitor reservoir performance.
•Monitor the actual well path to ensure the target will be reached. •Orient deflection tools for navigating well paths.
•Ensure that the well does not intersect nearby wells.
•Calculate the TVD of the various formations to allow geological mapping.
7.2.Survey Instruments
Survey instruments can be set up in several different variations, depending on the intended use of the instrument and the methods used to store or transmit survey information. Basically, there are two types of survey instruments: magnetic and gyroscopic. Depending on the method used to store the data, there are film and electronic systems.
7.2.1.Magnetic Sensors
Magnetic sensors must be run within a nonmagnetic environment [i.e., in uncased hole either in a nonmagnetic drill collar(s) or on a wireline]. In any case, there must not be any magnetic interference from adjacent wells. Magnetic sensors can be classified into two categories mechanical and electronic compasses

Mechanical compass uses a compass card that orients itself to magnetic north. Inclination is measured by means of a pendulum or a float device. In the pendulum device, the pendulum is either suspended over a fixed grid or along a vernier scale and is allowed to move as the inclination changes. The only advantage of mechanical compasses is the low cost, while the drawbacks are high maintenance costs, a need to choose inclination range, limited temperature capability, the possibility of human error in reading film, and the inability to use them in MWD tools.

Electronic compass system is a solid-state, self-contained, directional-surveying instrument that measures the Earth’s magnetic and gravitational forces. Inclination is measured by gravity accelerometers, which measure the Earth’s gravitational field in the x, y, and z planes. Depending on the packaging of the electronic sensors, the electronic-compass system can be employed in different modes, such as single-shot, multi-shots, and MWD, in which data are sent to surface in real time through the mud-pulse telemetry system
7.2.2.Gyroscopic Sensors
Gyroscopic surveying instruments are used when the accuracy of a magnetic survey system may be corrupted by extraneous influences, such as cased holes, production tubing, geographic location, or nearby existing wells.Gyroscopic systems (gyros) can be classified into three categories free gyros, rate gyros, and inertial navigation systems
7.3.Calculation Methods
There are several known methods of computing directional survey. The five most commonly used are:

• Tangential: This method uses the inclination and hole direction at the lower end of the course length to calculate a straight line representing the wellbore that passes through the lower end of the course length. Because the wellbore is assumed to be a straight line throughout the course length, it is the most inaccurate of the methods discussed and should be abandoned completely.
• Balanced Tangential: Modifying the tangential method by taking the direction of the top station for the first half of the course length, then that of the lower station for the second half can substantially reduce the errors in that method.
• Average Angle: The method uses the average of the inclination and hole-direction angles measured at the upper and lower ends of the course length. The average of the two sets of angles is assumed to be the inclination and the direction for the courseAAPG Academy Team length. The well path is then calculated with simple trigonometric functions.
• Curvature Radius: With the inclination and hole direction measured at the upper and lower ends of the course length, this method generates a circular arc when viewed in both the vertical and horizontal planes. Curvature radius is one of the most accurate methods available.
• Minimum Curvature: The difference between the curvature-radius and minimum-curvature methods is that curvature radius uses the inclination change for the course length to calculate displacement in the horizontal plane (the TVD is unaffected), whereas the minimumcurvature method uses the DLS to calculate displacements in both planes. Minimum curvature is considered to be the most accurate method.
7.4.Sources of Errors in Directional Survey
Survey Instruments: The survey instrument’s performance depends on the package design elements, calibration performance, and quality control during operation. System performance will functionally depend on the borehole inclination, azimuth, geomagnetic-field vector, and geographical position.

Tool Misalignment: The misalignment of the survey instrument with the wellbore results in errors in measuring wellbore-axis direction and inclination.

MD Error: Sources of depth error depend on the type of survey system used. Drillpipe-conveyed tools (MWD, multi-shots, and single-shot) suffer from errors in the physical measurement of drill pipes and the differential effects of drill string compression and stretch. Because of wellbore friction, drill string compression and stretch are not easily calculated, particularly in inclined wells. Depth errors can account for the relatively large angular errors frequently observed when comparing overlapping, high-accuracy surveys in deviated wells, wireline survey tools generally have smaller depth errors than drillpipe-conveyed tools.

Magnetic Interference: Magnetic interference may be defined as corruption of the geomagnetic field by a field from an external source. Potential sources of magnetic interference are:(Drillstrings, Adjacent wells, Casing shoes, Magnetic formations, “Hot spots” in nonmagnetic drill collars)

Cross-Axial Interference: This can arise from hot spots or from close proximity to magnetic elements in the drillstring

Well bore position Error

The survey errors described previously must be translated into position error. So the geoscientist can asses the impact of the errors. In extreme case of these errors ,if not recognized can result in a well missing. To quantify the effects of the instrument errors on bottom hole location; WALSTROM generate 2D ellipses. An ellipse is used because the greatest survey errors are usually azimuth error rather than inclination error. the ellipse is expressed as an ellipsoid with the long axis at right angle to the well bore direction. The most accepted method of computing error source is introduced by WOLFF AND WARDT. It’s an alternative method of determining wellbore uncertainty by suggesting the survey errors were systematic rather than random.

Survey quality control

It's very difficult to go down the well to check if the bottom is located where the calculation claim, the best way of verifying survey results is to have survey obtained from two different source, two different sensor types are preferably such as MWD survey checked by a rate gyro or inertial navigation system.

8.BHA Design for Directional Control

8.1.Design Principles

In general, the factors that determine the drilling tendency of a BHA are bit side force, bit tilt, hydraulics, and formation dip. The direction and magnitude of the bit side force determine the build, drop, and turn tendencies. A drop assembly is defined as when the bit side force acts toward the low side, whereas a build assembly is when the bit side force acts toward the high side of the hole. A hold assembly is when the inclination side force at the bit is zero. The bit tilt angle is the angle between the bit axis and the hole axis and affects the drilling direction because a drill bit is designed to drill parallel to its axis.

8.2.Rotary Assemblies

Rotary assemblies are designed to build, drop, or hold angle. The behavior of any rotary assembly is governed by the size and placement of stabilizers within the first 120 ft from the bit. Additional stabilizers run higher on the drillstring will have limited effect on the assembly’s performance. Commonly used stabilizer types are sleeve, welded blade, and integral blade. Sleeve stabilizers are most economical, but ruggedness often is an issue. Welded-blade stabilizers are best suited to large holes in soft formations. Integral-blade stabilizers are the most expensive but very rugged, making them the ideal choice in hard and abrasive formations.

8.2.1.Building Assemblies: Fulcrum Principle

A typical build assembly uses two to three stabilizers. Building assemblies use the fulcrum principle─a near-bit stabilizer, The first stabilizer usually connects directly to the bit, creates a pivot point wherein the bending drill collars force the near-bit stabilizer to the low side of the hole and create a lateral force at the bit to the high side of the hole. The second stabilizer is added to increase the control of side force. Build rates can be increased by increasing the distance between the first and second stabilizers. The build rate of a fulcrum assembly increases as inclination increases because the larger component of the collar’s own weight causes them the bend. Increasing the WOB will bend the drill collars behind the near-bit stabilizer even more, increasing the build rate. A higher rotary speed tends to straighten out the drill collars, thus reducing the build rate. Sometimes, in soft formations, a high flow rate can lead to formation washout, resulting in decreased stabilizer contacts and, thus, a reduced build tendency.

8.2.2.Holding Assemblies: Packed Hole

The packed-hole assemblies contain three to five stabilizers properly spaced to maintain the angle. The increased stiffness on the BHA from the added stabilizers keeps the drillstring from bending or Sleeve stabilizer Integral blade stabilizer Welded blade stabilizerAAPG Academy Team bowing and forces the bit to drill straight ahead. The assembly may be designed for slight build or drop tendency to counteract formation tendencies.
8.2.3.Dropping Assemblies: Pendulum Principle

A dropping assembly usually contains two stabilizers. The pendulum effect is produced by removing the stabilizer just above the bit while retaining the upper ones. While the remaining stabilizers hold the bottom drill collar away from the low side of the wall, gravity acts on the bit and the bottom drill collar and tends to pull them to the low side of the hole, thus decreasing the hole angle. Pendulum assemblies sometimes can be run slick (without stabilizers). Although a slick assembly is simple and economical, it is difficult to control and maintain the drop tendency. Initially, low WOB should be used to avoid bending the pendulum toward the low side of the hole. Once a dropping trend has been established, moderate WOB can be used to achieve a higher penetration rate.

8.3.Deviation Tools

The most common deviation tools for directional drilling are the positive displacement motors (PDMs) and Rotary steerable systems (RSSs).
8.3.1.Steerable Motor Assemblies or PDMs

which contain PDMs with bent subs or bent housing. Steerable motor assemblies are versatile and are used in all sections of directional wells, from kicking off and building angle to drilling tangent sections and providing accurate trajectory control. Among the PDM assemblies, the most commonly used deviation tool today is the benthousing mud motor. Before the personal computer become widely available, the simple “three-point curvature” calculation was used to predict the build rates of the motor assemblies as:

in which rb = build rate in degrees/100 ft, θ = bend angle in degrees, L1 = distance from the first contact point (bit) to the second (bend) in ft, and L2 = distance from the second contact point to the third (motor top stabilizer) in ft.

A typical bent-housing motor contains the following four sections: dump sub, power unit, transmission/bent-housing unit, and bearing section.

Dump sub
It contains a Dump Valve Assembly. This allows the mud to fill or drain from the drill string while tripping.

Power unit
it converts hydraulic energy to mechanical energy: a rotor/stator pair converts the hydraulic energy of the pressurized circulating fluid to mechanical energy for a rotating shaft. The rotor and stator are of lobed design. Both rotor- and stator-lobe profiles are similar, with the steel rotor having one less lobe than the elastomeric stator. The speed and torque of a power section is linked directly to the number of lobes on the rotor and stator. The greater the number of lobes, the greater the torque and the lower the rotary speed.

Transmission bent-housing/unit
The universal couplings inside the transmission/bent-housing unit eliminate all eccentric rotor motion and accommodate the misalignment motion of the bent housing while transmitting torque and down thrust to the drive shaft, which is held concentrically by the bearing assembly.
Bearing section
Bearing assembly mostly consists of the thrust and radial (upper and lower) bearings, drive shaft, bearing housing and/or a flow restrictor thrust(off/on bottom load) and radial (side load) bearings transfer axial and radial load form the bit to the drill string while providing room for the bit to rotate. The flow restrictor allows approximately 5 to 8% of the circulating fluid to flow through the bearing section to cool and lubricate the bearing assembly.

8.3.2.Whipstocks

Openhole whipstocks are the first type of deflection tool used to change the wellbore trajectory but are seldom used today. Benthousing motors have replaced openhole whipstocks as the most commonly used deviation tool in openhole sidetracking. Casing whipstocks, on the other hand, are routinely used to sidetrack out of cased wellbores. Whipstocks can be either retrievable or nonretrievable.

8.3.3.Turbines

Turbines, commonly known as turbodrills, are powered by a turbine motor, which has a series of rotors/stators (stages) connected to a shaft. As the drilling fluid is pumped through the turbine, the stators deflect the fluid against the rotors, forcing the rotors to rotate the drive shaft to which they are connected. Turbines are designed to run on high speed and low torque; thus, they are suited for running with diamond or polycrystalline-diamond compact bit.
8.3.4.Jetting Bits

Jetting bits can be used to change the trajectory of a borehole, with the hydraulic energy of the drilling fluid used to erode a pocket out of the bottom of the borehole. The tricone bit with one large nozzle is oriented to the desired hole direction to create a pocket. The drilling assembly is forced into the jetted pocket for a short distance. This procedure continues until the desired trajectory change is achieved. Jetting is seldom used today because of its slow penetration rate and its limitations in soft formations.

8.3.5.RSSs

The RSS is an evolution in directional-drilling technology that overcomes the drawbacks in steerable motors and in conventional rotary assemblies. To initiate a change in the wellbore trajectory with steerable motors, the drilling rotation is halted in such a position that the bend in the motor points in the direction of the new trajectory. This mode, known as the sliding mode, typically creates higher frictional forces on the drillstring. In extreme ERD, the frictional force builds to the point at which no axial weight is available to overcome the drag of the drillstring against the wellbore, and, thus, further drilling is not possible. To overcome this limitation in steerable motor assemblies, the RSS was developed in the early 1990s to respond to this need from ERD. RSSs allow continuous rotation of the drillstring while steering the bit. Thus, they have better penetration rate, in general, than the conventional steerable motor assemblies. Other benefits include better hole cleaning, lower torque and drag, and better hole quality. Because they are expensive this tends to limit their use to highly demanding extended-reach wells or the very complex profiles associated with designer wells .

9.References and websites
PetroWiki
• Volume II DRILLING ENGINEERING Robert F. Mitchell,Editor