Horizontal Displacement (HD)
The horizontal displacement is the distance between any two points along a wellbore projected onto a horizontal plane or plan view.
Vertical Section (VS)
The vertical section is the distance between any two points along a wellbore projection onto a vertical section plane.
Azimuth
The azimuth is the angle in the horizontal plane measured from a fixed reference direction (such as True North), usually measured clockwise.
Quadrant
The quadrant bearing of a well is the angle in the horizontal plane measured from either a North or South reference direction towards the East or West, defining the direction of the wellbore.
Types of Profile
The well path may follow a number of different routes. The main types are
Summarized in the following paragraphs.
Type 1 (Build and Hold)
This is the most common and the simplest profile for a directional well. The hole is drilled vertically down to the KOP, where the well is deviated to the required inclination. This inclination is maintained over the tangential section to intersect the target. Generally, a shallow KOP is selected since this reduces the size of the inclination angle necessary to hit the target. This type of profile is often applied when a large horizontal displacement is required at relatively shallow target depths. Since there are no major changes in inclination or azimuth after the build-up section is complete, there are fewer directional problems with this profile. Under normal conditions the inclination should be 15-55°, although greater inclinations have been drilled.
Type II (Build, Hold and Drop)
This profile is similar to the Type I down to the lower part of the tangential section. Here the profile enters a drop-off section where the inclination is reduced, and in some cases becomes vertical as it reaches the target . This is a more difficult profile to drill than the Type I, owing to the problems of controlling the drop-off section just above the target. Extra torque and drag can also be expected owing to the additional bend. This type of profile is used when the target is deep but the horizontal displacement is relatively small. (Under such conditions a Type I profile may produce a small inclination angle which would be difficult to control.) It also has applications when completing a well that intersects multiple producing zones, or in relief well drilling if it is necessary to run parallel with the wild well.
Type III (Deep Kick-off and Build)
This profile is only used in particular situations such as salt dome drilling or sidetracking. A deep KOP has certain disadvantages.
(a) Formations will probably be harder and less responsive to deflection.
(b) More tripping time is to change out BHAs while deflecting.
(c) Build up rate is more difficult to control.
Horizontal Wells
A horizontal well is one in which the inclination reaches 90° through the reservoir section. Horizontal wells have important applications in improving production from certain reservoirs that would otherwise be uneconomic (e.g. fractured limestone, low-permeability zones, etc.) The profile of the horizontal well is shown in Fig.Notice that there is more than one build-up section used to achieve the inclination of 90°. Conventional techniques are employed to drill this type of horizontal well, but there are many drilling problems to be overcome and so drilling costs are higher.
Horizontal Drain holes
In this type of profile the well is drilled vertically to the KOP using conventional techniques. A special BHA is then run which is used to build up angle rapidly along a circular arc of about 30 ft radius. This corresponds to build-up rate of 2° per foot. This rapid build-up of angle is only possible using special components in the drill string, such as articulated collars and knuckle joints. This type of profile can be used for producing from tight formations and reducing gas or water coning problems.
Directional Well Planning
The careful planning of a directional project prior to the commencement of actual operations is probably the single most important factor of a project. Each directional well is unique in the sense that it has specific objectives. Care has to be exercised at the planning stage to ensure that all aspects of the well are tailored to meet those objectives. Drilling a directional well basically involves drilling a hole from one point in space (the surface location) to another point in space (the target) in such a way that the hole can
then be used for its intended purpose. To be able to do this we must first define the surface and target locations.
Location
The first thing to do is to define a local coordinate system originating at the structure reference point. In many land wells, this will be the surface location. The target location is then converted to this local coordinate system, if necessary.
Target Size
During the drilling phase of a directional well, the trajectory of the wellbore in relation to the target is constantly monitored. Often, costly decisions have to be made in order to ensure that the objectives of the well are met. A well defined target is essential in making these decisions. The technology available today allows us to drill extremely accurate wells. The cost of drilling the well is largely dependent on the accuracy required so the acceptable limits of the target must be well defined before the well is commenced.
Cost versus Accuracy
Cost versus accuracy is the key consideration here. In many cases, operator companies adopt an arbitrary in-house target size (or radius of tolerance), particularly in multi-well projects. The size of the target radius often reflects the convention rather than the actual geological requirements of the well. It is common for specific restrictions or hard lines to be specified only when they depict critical features such as fault lines, pinch outs or legal restrictions such as lease line boundaries. Many directional wells have been unnecessarily
Corrected or sidetracked in order to hit a target radius which in fact did not represent the actual objective of the well.
Good communication
With the relevant department (Geology or Exploration) before beginning the well can help to avert this kind of error. This is particularly true when a correction run is being contemplated. The first step of any plan to correct the azimuth of a well should always be consultation with the Geology Department.
Formation Characteristics
The type of formations to be drilled can affect the planning of the profile in several ways.
(a) In selecting the kick-off point (KOP) the hardness of the formation is important. Hard formations may give a poor response to the deflecting tool, so that the kick-off may take a long time and require several bits. Kicking-off in very soft formations may result in large washouts. A soft-medium formation provides a better opportunity for a successful kick-off.
(b) Certain formations exhibit a tendency to deflect the bit either to the left or to the right. The directional driller can compensate for this effect by allowing some "lead angle" when orienting the deflecting tool. If the bit is expected to walk to the right by a certain number of degrees, the lead angle will point the bit an equal number of degrees to the left. As the bit begins to drill, the formation effect will bring the well back on to its intended course.
Deflecting Tools Available
The capabilities of the deflecting tools available and the techniques that are applicable in a particular situation will influence the shape of the well path. If jet deflection is to be used, the KOP must be at a relatively shallow depth in a fairly soft formation. The availability of different bent subs will dictate the rate of build up. If a turbo drill is to be used over the long tangential section, it will tend to make the bit walk to the left. The directional behaviour of the various tools and bottom hole assemblies to be used must be considered when planning the well.
Location of Adjacent
Wellbores On offshore platforms there is only a small distance (7-12 ft) between adjacent conductors. Under these conditions precise control is required and great care must be taken to avoid collisions directly beneath the platform. For this reason the KOPs for adjacent wells are chosen at varying depths to give some separation. When choosing slots it is better to allocate an outer slot to a target which requires large horizontal displacement. This will result in a shallower KOP to allow a smaller inclination. Slots closer to the centre of the platform should be allocated to targets requiring smaller inclinations and deeper KOPs. This will help to avoid the problem of wells running across each other. As each well is being drilled, the proximity of all the adjacent wells should be checked by calculating inter-well distances from survey results. Anti-collision plots generated by computer are now widely available for doing this. It may be necessary to nudge a new well away from the existing wells, even though this means going away from the target direction. Once the well is a safe distance away, the well path can be corrected to bring it back onto the planned course.
Choice of Build-up Rate
If the change of angle occurs too quickly, severe dog-legs can occur in the trajectory. These sharp bends make it difficult for drilling assemblies and tubular to pass through. Severe dog-legs also cause more wear on the drill string. If the angle is built up very slowly then it will take a longer interval of hole to reach the required inclination. To obtain a gradual build-up of angle at a reasonable curvature, a build-up rate of 1.5-2.50 per 100 ft is commonly used, but higher build-up rates may be necessary in some cases.
TYPES OF DIRECTIONAL WELLS
There are four basic types of directional wells. Most wells can be categorized by one of the four basic types or there combination.
Type I Well
A type I well is often called a build and hold. The Type 1 well is drilled vertically from the surface to kickoff point at a relatively shallow depth. At that point, the well is steadily and smoothly deflected until a maximum angle and the desired direction are achieved. Then, casing is run and cemented if desired. The established angle and direction are maintained while drilling to the target depth. One or more strings of casing can be run if necessary. Usually this method is employed when drilling shallow wells with single producing zones.
Type II Well
The type II well is often called an “S” curve. It is similar to the Type I because the well is deflected at a relatively shallow depth, and surface casing is frequently (but not always) run through the build curve. The angle and direction are maintained until a specified depth and horizontal departure has been reached. Then, the angle is steadily and smoothly dropped until the well is near vertical. Intermediate casing is usually run through the section of the hole where the angle was dropped. Drilling continues in the vertical hole below the intermediate casing to the target. Type II wells are generally used where multiple pay zones are encountered. Also, after the well has been returned to vertical, directional drilling services are no longer required. Since most of the directional drilling is done in the more shallow portions of the hole where trips are shorter and penetration rates are higher, the overall cost of the well is reduced. A disadvantage of the Type II is that it will generate more torque and drag for the same horizontal departure.
Type III Well
The type III Well is a continues build to target. It is similar to the Type I well except the kickoff point is at a deeper depth, and surface casing is set prior to deflecting the well. The well is deflected at the kickoff point, and inclination is continually built through the target interval. The inclinations are usually high and the horizontal departure low. This type of well is generally used for multiple sand zones, fault drilling, salt dome drilling, and stratigraphic tests. It is not used very often.
Type IV Wells
The type IV well can be categorized as horizontal or extended reach wells. Design of these wells can vary significantly, but they will have high inclinations and large horizontal departures. Horizontal wells will have an inclination greater than 80°.
Drilling Tools & Deflection Methods
Before the arrival of the positive-displacement mud motor (PDM), whip-stocks, knuckle joints and jetting (in soft formations) were used as deflection methods. DD tools and technology have evolved tremendously in the past 20 years. Today, there is a broad range of PDMs for different applications. The various methods used to deflect a wellbore are described in this chapter. The directional driller must be familiar with all the directional drilling tools at the rig-site and in the workshop. Most of the DD tools are straightforward to operate.
While a directional drilling simulator is a useful aid in the teaching of DD concepts, the only way to fully understand how a wellbore is deflected and how the various DD tools are used is to get some on-the-job training. This chapter should provide a lot of the background knowledge required.
Drilling Tools
The major drilling tools likely to be used by the DD are discussed briefly here.
Drill Collar (DC)
Drill collars are heavy, stiff steel tubular. They are used at the bottom of a BHA to provide weight on bit and rigidity. Flush or spiral drill collars are available. In directional drilling, spiral drill collars are preferable. The spiral grooves machined in the collar reduce the wall contact area by 40% for a reduction in weight of only 4%. The chances of differential sticking are greatly reduced. Spiral drill collars usually have slip and elevator recesses. Stress-relief groove pins and bore back boxes are optional.
Short Drill Collar (SDC)
Often called a pony collar, this is simply a shortened version of a steel drill collar. Short drill collars may be manufactured or a steel drill collar may be cut to make two or more short collars. For the DD, the SDC and the short non-magnetic drill collar (SNMDC) have their widest application in the make-up of locked BHAs. SDCs of various lengths
(E.g. 5’, 10’, 15’).
Non-Magnetic Drill Collar (NMDC)
Non-magnetic drill collars are usually flush (non-spiral). They are manufactured from high-quality, corrosion-resistant, austenitic stainless steel. Magnetic survey instruments run in the hole need to be located in a non-magnetic drill collar of sufficient length to allow the measurement of the earth’s magnetic field without magnetic interference.
Survey instruments are isolated from magnetic disturbance caused by steel components in the BHA and drill pipe. MWD tool and its successors are fixed inside their own special MWD non-magnetic drill collars. SLIM-1, however, is run inside a standard NMDC. Stress-relief groove pins and bore back boxes are optional.
Short Non-Magnetic Drill Collar (SNMDC)
A short version of the NMDC, SNMDCs are often made by cutting a full-length NMDC. The SNMDC may be used between a mud motor and an MWD collar to counteract magnetic interference from below. It is also used in locked BHAs, particularly where the borehole's inclination and direction give rise to high magnetic interference. Finally, BHAs for horizontal wells often use a SNMDC.
Float Sub
This is a PIN x BOX sub which is bored out to take a float valve. It is often run above a mud motor. In conventional rotary BHAs, a float valve is inserted either in the bit sub (in the case of a pendulum BHA) or in the bored-out near-bit stabilizer. Poppet and flapper designs of float valve are available. Note that some clients may not allow the use of a float valve (because of kick-control problems).
Bit Sub
This is a BOX x BOX sub which is run directly above the bit (hence its name) when no near-bit stabilizer is used. It is bored out to take a float valve.
Junk Sub
A junk sub is fabricated from a solid steel body with a necked-down mid-portion. A” skirt" is fitted to the lower part of the body, around the necked-down portion, forming a basket for junk to settle in. The junk sub is run directly above the bit. It catches pieces of junk which are too heavy to circulate out. Bleed holes in the skirt allow the mud to return to the system.
Extension Sub
This is a short sub which can be used to fine-tune a BHA. It is normally PIN x BOX. A float sub can be used as an extension sub.
Heavyweight Drill Pipe (HWDP)
This is an intermediate-weight drill string member with drill pipe dimensions for easier handling. Its heavy wall tube is attached to special extra-length tool joints. These provide sample space for recutting the connections and reduce the rate of wear on the OD. The OD of the tube is also protected from abrasive wear by a centre wear pad. Tool joints and wear pad are hard-banded. Some HWDP have two wear pads.
HWDP is less rigid than DCs and has much less wall contact. Chances of differential sticking are reduced. Its three-point wall contact feature solves two serious problems in directional drilling. It permits high-RPM drilling with reduced torque. HWDP can be run through hole angle and direction changes with less connection and fatigue problems. Today, the trend in BHA design is to minimize the number of DCs in the BHA and use HWDP to comprise a major portion of available weight on bit However; it is the DD’s responsibility to ensure there are sufficient joints of HWDP on the rig. For normal directional jobs, 30 joints of HWDP should be sufficient.
Stabilizer
Stabilizers are an indispensable part of almost all rotary directional BHAs. Near-bit stabilizers have BOX x BOX connections. They are usually bored out to accept a float valve. String stabilizers have PIN x BOX connections. Most stabilizers have a right-hand spiral. For directional control, 360 wall coverage (in plan view) is recommended. Stabilizer blades are "dressed" with various possible types of hard-facing (Figure 5-4). The leading edge of most stabilizer designs also has hard-facing applied. It is possible to order variations of stabilizer design. Stabilizers are used to:
Control hole deviation.
Reduce the risk of differential sticking.
Ream out doglegs and keysets.
There are many designs of stabilizer. The most common types are:
Welded-blade Stabilizer
The blades are welded on to the body in a high-quality process that involves pre-heating and post-heating all components and the assembled unit to ensure stabilizer integrity and minimize the possibility of blade failure. Blades can be straight, straight-offset or spiral design. Welded-blade stabilizers are not recommended in hard formations Because of the danger of blade fatigue. They are best suited to large hole sizes where the formation is
softer because they allow maximum flow rates to be used. They are relatively cheap. The blades can be built up when worn.
Integral blade Stabilizer (I.B.)
I.B. stabilizers are made from one piece of material rolled and machined to provide the blades. They are more expensive than welded-blade stabilizers. The leading edge may be rounded off to reduce wall damage and provide a greater wall contact area in soft formations. They can have either three or four blades. I.B. stabilizers normally have tungsten carbide inserts (TCIs). Pressed-in TCIs are recommended in abrasive formations.
Non-rotating Rubber Sleeve stabilizer
This type of stabilizer is used somewhere above the top conventional stabilizer in the BHA, especially in abrasive formations. The rubber sleeve does not rotate while drilling. Blade wear and wall damage are thus minimized. A special elastomeric sleeve may be used in temperatures up to 350 °F.
Replaceable Wear Pad stabilizer (RWP)
Has four long blades 90° apart composed of replaceable pads containing pressed-in TCI compacts. RWP stabilizers are good for directional control and/or in abrasive formations but may give excessive torque.
Under gauge Stabilizer
The Under gauge stabilizer is a down hole-adjustable stabilizer. It has two positions - open (full gauge) or closed (under gauge). It is expanded to full gauge down holes by slacking off a small amount of weight-on-bit and is then locked in place by a hydraulic latch. To deactivate, the pumps are cut back before pulling off bottom. In this case, the hydraulic latch locks the stabilizer in the closed position when normal pump rate is resumed.
Roller Reamer
Roller reamers are designed to maintain hole gauge, reduce torque and stabilize the drill string. They can be 3-point or 6-point design. Both near bit and string roller reamers are available. They are particularly useful in abrasive formations. Near-bit roller reamers help prolong bit life. They are normally bored out to accept a float valve. A near-bit roller reamer is sometimes used in place of a near-bit stabilizer where rotary torque is excessive. Sometimes one or more string roller reamers are also used in a BHA. Roller reamers help to ream key seats, dog legs and ledges. Cutters are available for soft, medium and hard formations. Cutters, blocks and pins can be changed at the rig-site
Under Reamer
Common applications for the under reamer are wiping out bridges and key-seats, opening directional pilot holes, opening hole for a casing string below a BOP restriction. The tool is opened hydraulically. It is held in the open position while hydraulic pressure is maintained. When the pumps are shut off, the arms collapse back into the body of the under reamer.
Various formation-type cutters are available. Cutter arms and nozzles can be changed on the rig. A "full-coverage" configuration of cutter arms must be used. One size body accepts a range of sizes. It is recommended to run a bull-nose below the under reamer when opening a directional pilot hole in soft formation. This eliminates the possibility of an accidental sidetrack.
String Reamer
A string reamer is designed to increase the diameter of any key-seat through which it passes. The body of a string reamer is sometimes made from a short length of HWDP. The connections are usually the same as on the drill pipe. Blades are welded on the body. The blades are hard- faced. The blades may be either straight or tapered. The O.D. of the blades varies, but is never greater than the bit diameter. A more expensive design of string reamer is machined from one piece of steel and hard-facing then applied. A string reamer is normally run in the drill pipe. It is positioned in the drill string so that, on reaching bottom, it is close to the top of the key-seat area. As drilling progresses, the string reamer helps to ream out the key-seat. String reamers with larger-O.D. bodies are designed to be run in the drill collars. They have the same connections as the DCB.
Key-seat Wiper
In a well where key-seating is a problem, a key-seat wiper can be run between the top drill collar and the bottom joint of HWDP. When POOH,the hard-faced sleeve (which has an OD typically 1/4" greater than that of the DCs) tends to wedge in the keyset first. By releasing the drill string, the sleeve is jarred out of the key-seat. The clutch at the bottom of the sleeve is automatically disengaged. The string is then rotated and the hole back-reamed. The sleeve re-engages the tool body. It acts as a reamer to enlarge the key-seat and allow free passage of the drill collars. The tool can be either single-clutch or double clutch design. The sleeve has spiral blades with TCI hard-facing to provide fast cutting action and good resistance to wear.
Turbine
This tool uses centrifugal fluid mechanics. It is a totally different principle to the positive-displacement motor (PDM). Energy is diverted from the velocity or volume of mud flow directed onto a stationary angular stator, creating a rotating force on the opposed angular rotor. Each rotor/stator combination is called a stage. A turbine for DD work has many stages. Turbines (often called turbo drills) are not used much today. They are normally run by specialists.
Bent Sub
A bent sub normally is manufactured PIN x BOX. The pin connection of the bent sub must be compatible with the box of the PDM of the same O.D. The pin is machined at a certain offset angle to the axis of the body of the sub (high side). This angle usually from 1° to 3° in increments of 1/2°. A scribe-line on the body of the sub, directly in line with the centre
of the pin offset, is used as the master reference for tool-face position. A bent sub is used directly above a PDM or turbine. It forces the bit to follow a certain arc of curvature as it drills.
Orienting Sub
An orienting sub is commonly called a UBHO (Universal Bottom Hole Orientation) sub. It is a straight sub having PIN x BOX connections which are compatible with the bent sub and/or the NMDCs. It is bored out to accept a mule-shoe sleeve. After all intermediate connections have been torque up fully, the key of the mule-shoe sleeve is aligned directly above the scribe-line of the bent sub. This key is the landing-point for the mule-shoe survey running gear. It gives the DD the tool-face position on his survey disc. The sleeve is locked in place using two hexagonal screws (3/8" Allen key required) which are screwed in from the body of the sub shows the situation when the mule-shoe stinger is landed on the UBHO, with the mule-shoe slot sitting on the key of the UBHO sleeve. This is the situation when surveying during a single shot kickoff/correction run sidetrack.
Bent Orienting Sub (BOS)
A BOS is simply a sub which combines the features of a bent sub and a UBHO. The offset pin is compatible with the PDM; it is bored out to take a mule-shoe sleeve etc.
Hole Opener
A hole opener is usually designed as a fixed-diameter tool. Hole openers are used to open pilot holes. Various formation-type cutters are available. The cutters and nozzles can be changed on the rig-site. The use of a bull nose (rather than a bit) below the hole opener when opening directional pilot holes is strongly recommended
Bull nose
A bull nose is used to guide a hole opener or under reamer, particularly in deviated pilot holes. The bull nose can be either hollow or solid. Some under reamers have no nozzles. Thus, it is advisable to run a jet bull nose directly below the under reamer in such a situation. The fluid is directed upwards by the jets to clean the cutters and help the under reaming operation.
Section Mill
This tool is used to mill a section of casing (usually prior to a cased-hole sidetrack. It operates on a similar principle to the under reamer. It includes six triangular cutters which
are dressed with tungsten carbide. On reaching the depth of the top of the section, pump pressure is applied. Three of the cutter arms expand and begin the cut-out. When the casing cut-out is complete, the second set of three arms expands into the milling position. The Flo-Tel feature gives a positive surface indication of casing cut-out. All six cutter arms are then seated squarely on top of the casing and milling of the section proceeds
Whip-stock
The fore-runner of the PDM as a deflection tool, whip-stock can be open-hole or cased hole. The open-hole whip-stock is retrievable. It is mainly used to do a deep sidetrack in hot holes or on small rigs. The cased-hole whip-stock is used to perform a sidetrack from inside casing. It is oriented, anchored inside the casing to allow deflection from the casing and is left in place. Several trips are necessary to complete the cased-hole sidetracking operation.
Drilling Jars
These are designed to deliver an impact either upwards or downwards. Jars are run in deviated wells so that the string can be jarred free in case of tight hole or stuck pipe. Jars can be mechanical, hydraulic or hydro-mechanical design.
Shock Absorber/Shock Sub
Drilling shock absorbers were designed to solve the problems of drill string vibration. The shock absorber absorbs or reduces the bit-induced vibration. It includes specially-designed springs having high end load capacity and low spring rate that dampen vibration in tension and compression.
Rebel Tool
The rebel tool corrects lateral drift by counteracting the bit walk. It can either slow down the bit walk or eliminate it completely. Left-hand or right-hand paddles are available. The paddles can be changed at the rig-site. It is most suitable in medium formations. The rebel tool can be used at inclinations above 12° in hole sizes from 8 1/2" to 12 1/4". A left-hand rebel tool (long paddle) is shown in. With the advent of steerable motors, the rebel tool is seldom used today
.
Deflection Methods
The main deflection tools used in directional drilling are:
Whip stocks
Jetting
Motors
Whip stock
The retrievable, open-hole whip-stock is only used in special applications e.g. rigs with small pumps, sidetrack in deep, very hot hole. The whip-stock is pinned to a limber BHA which includes a small bit. Atypical BHA is:
Whip-stock + Pilot Bit + Stabilizer + Shear pin sub +1 Joint of Drill Pipe +
UBHO + Non-magnetic DC.
The hole must be clean before running the whip-stock. On reaching bottom, circulation is started. The concave face of the whip-stock is oriented in the desired direction. The tool is set on bottom. The toe of the wedge is anchored firmly in place by applying sufficient weight to shear the pin. The bit is lowered down the whip-stock face. Rotation of the drill string is started about 15’ -20’ of rat hole are drilled at a controlled rate. The whip-stock is retrieved and the rat hole opened with a pilot bit and hole opener.
Another trip using a full-gauge bit, near-bit stabilizer and limber BHA is then made. About 30’ are drilled. More hole deflection is obtained. A full-gauge directional BHA is then run and standard drilling is resumed. It is obvious that the whip-stock deflection method of deflecting a wellbore is time-consuming and involves several runs.
Jetting
This technique is used to deviate the wellbore in soft and friable formations. The well can be kicked off and built up to maximum inclination using one BHA. Special jetting bits can be used or it’s possible to use a standard long-tooth bit, normally using one very large nozzle and two other blank (or very small) nozzles.
A typical jetting BHA is:
Bit + Near-bit Stab.+ UBHO + MWD + NMDC + Stab. + DC + Stab Etc. A formation suitable for jetting must be selected. There must be sufficient room left on the Kelly to allow for jetting and drilling the first few feet after the jetted interval. The centre of the large nozzle represents the tool face and is oriented in the desired direction. Maximum circulation rate is used while jetting. Jet velocity for jetting should be 500 ft/sec. The drill string is set on bottom. If the formation is sufficiently soft, the WOB "drills off”. A pocket is washed in the formation opposite the large nozzle.
The bit and near-bit stabilizer work their way into the pocket (path of least resistance). Enough hole should be jetted to “bury" the near-bit stabilizer. If required, the bit can be pulled off bottom and the pocket "spudded". The technique is to lift the string about 5'off bottom and then let it fall, catching it with the brake so that the stretch of the string (rather than the full weight of the string) causes it to spud on bottom. Spudding can be severe on drill string, drilling line and derrick and should be kept to a minimum. Another technique which may help is to "rock" the rotary table a little (15) right and left of our orientation mark while jetting. After a few feet (typically 5’) have been jetted, the pumps are cut back to about 50% of that used for jetting. The drill string is rotated. It may be necessary to pull off bottom momentarily due to high torque (near bit stabilizer wedged in the pocket). High
WOB and low RPM are used to try to bend the collars above the near-bit stabilizer and force the BHA to follow through the trend established while jetting. The remaining footage on the Kelly is drilled down. Deflection is produced in the direction of the pocket i.e. the direction in which the large jet nozzle was originally oriented. To clean the hole prior to connection/survey, the jet should be oriented in the direction of deviation. After surveying, this orientation setting (tool face setting) is adjusted as required, depending on the results achieved with the previous setting. Dogleg severity has to be watched carefully and reaming performed as required. The operation is repeated as often as is necessary until sufficient inclination has been achieved and the well is heading in the desired direction. The hole inclination can then be built up to maximum angle using 100% rotary drilling. Small direction changes can be made if needed. The jetting method is compatible with the single-shot method or MWD. Illustrates the sequence Jetting BHAs .In very soft formation where hole erosion makes it impossible to keep enough WOB when drilling, a more limber ("Gilligan") jetting BHA may be required.
PDM (or Turbine) With Bent Sub
In this method, a bent sub is run directly above a PDM. A typical BHA is as follows:
Bit + PDM + Bent sub + Float sub + Orienting sub (UBHO) + Non-magnetic DCs + Steel DCs + HWDP + DP.
The pin of the bent sub is offset at an angle of 1°-3°. A scribe line is cut on the outside of the body of the bent sub, above the centre of the pin offset. The bent sub allows deflection
to occur by pushing the mud motor to one side of the hole. As drilling progresses with the drill string locked, the bit is forced to follow a curved path. The degree of curvature (dogleg severity) depends on the bent sub offset angle and the OD of motor, bent sub and drill collars in relation to the hole diameter. It also depends on the length of the motor and on the type of formation. The appropriate bit-bent sub/PDM combination is chosen to give the desired dog-leg severity. An orienting sub (UBHO) allows single- shot surveys to be taken as required. Because of the high bit offset caused by the bent sub, it is advisable not to rotate this type of BHA unless in special circumstances e.g. difficulty getting to bottom, re-establishing orientation.
Steerable Positive Displacement Motor
The most common type of steerable motor is the single bent-housing design the motor housing is not straight. One of the motor housing connections (usually the connecting rod housing) is machined at a certain precise offset angle. This is known as the bent housing angle. The bent housing angle is usually 1.5°. At offsets greater than this, it becomes difficult to rotate and motor life is shortened.
Because the bend in the housing is quite close to the bit, the nominal bit offset is much less than when using a straight PDM with bent sub as the deflection method. However, the rate of deflection (dog leg severity) achieved for a relatively small bent housing offset angle is high. A steerable motor can be used to perform kickoffs, correction runs and sidetracks. However, the usual application of a steerable motor is as the major component of a BHA which can be used in oriented ("sliding") or rotary mode. In sliding mode, the steerable motor changes the course of the well. The BHA is designed as a "locked" assembly in rotary mode. The ideal use of a steerable motor is to drill a complete hole section from casing point to casing point. In theory, provided the bit and BHA selection is good, a
steerable motor can stay in the hole until the next casing point. The extra cost to the client of running the motor must be compensated for by significant savings in rig time - due to less round trips and/or faster ROP. A surface-adjustable bent housing is now available.
Specified Deflection Techniques
In the planning of directional wells it is usually intended to drill vertically until the kick-off point (KOP) at which the well is deflected towards the target. When the reservoir is relatively shallow and covers a wide area, this method requires a very high angle of inclination to reach the periphery of the field. The angle could be reduced by selecting a shallower KOP, but this is not always possible, because of softer formations nearer the surface. An alternative approach is to eliminate the vertical part of the trajectory completely by introducing deflection at the surface. By doing this, the problems of building and maintaining inclination are reduced, and a larger area of the field can be covered from one central platform. There are two techniques that have proved successful.
Curved Conductors
In offshore areas where the oil and gas reservoirs Situated at depths of 3000-6000 ft below the seabed. Large fixed platforms are required to develop these fields in water depths up to 450 ft. Conventional directional wells from these platforms cannot, however, cover the entire area and so several platforms are required, increasing the cost of the development by
a substantial amount. It has been possible since the 1970s to install curved conductors on these platforms. The curvature of the conductors is 3-6° per 100 ft and they are driven 150-200 ft into the seabed. The conductors can be oriented towards the target as they are being driven, so that horizontal corrections for azimuth are reduced. The initial deflection at the seabed is already 10-20° of inclination. Drilling problems with the curved conductors have proved to be no more serious than in previous directional wells. The typical profile of such a well is shown in fig.
Slant Hole Drilling
Another technique for drilling an inclined hole starting from the surface is to mount the rig at some angle to the vertical. The hole is spudded at this angle and drilling continues in the conventional manner. It is theoretically possible to orient the rig such that the hole is drilled directly to the target. For some land-based operations, the derrick has been tilted at 45° to the vertical. An example of a slant hole profile is given in Fig. To adapt a standard drilling rig for slant hole drilling, certain modifications must be made:
(a)The rotary table must be inclined so that it is perpendicular to the axis of the derrick. (A power swivel may be used as an alternative.)
(b) The travelling block and hook must be run on guide rails up inside the derrick.
(c) The BOP stack must be mounted on a frame that can be tilted to the required angle.
(d) A hydraulic pipe racking system makes the handling of drill pipe much easier.
Rotary Assembly
A rotary assembly is a BHA which is driven solely by the rotary table at surface. No down hole motors or turbines are included. By careful placement of stabilizers, rotary assemblies can be designed to build, hold or drop the angle of inclination.
Building Assembly
This type of assembly is usually run in a directional well after the initial kick-off has been achieved by using a deflection tool. A single stabilizer placed above the bit will cause building owing to the fulcrum effect. The addition of further stabilizers will modify the rate of build to match the required well trajectory. If the near-bit stabilizer becomes under gauge, the side force reduces. Typical building assemblies are shown in Fig. Assemblies A and B respond well in soft or medium formations. The inclusion of an under gauge stabilizer in assembly C will build slightly less angle. By bringing the second stabilizer closer to the near-bit stabilizer, the building tendency is increased. In hard abrasive rocks, the problems of bit wear are significant. To maintain gauge hole, the near-bit and second stabilizer should be replaced by roller reamers. The build rate should be
kept below 2° per 100 ft to reduce the risk of dog-legs. The amount of WOB applied to these assemblies will also affect their building characteristics. Too much WOB will cause rapid build-up of angle.
.
Holding Assemblies
Once the inclination has been built to the required angle, the tangential section of the well is drilled using a holding assembly. The object here is to reduce the tendency of the BHA to build or drop angle. In practice this is difficult to achieve, since formation effects and gravity may alter the hole angle. To eliminate building and dropping tendencies, stabilizers should be placed at close intervals, using pony collars if necessary. Assembly shown in Fig. has been used successfully in soft formations. The under gauge stabilizer in assembly E builds slightly to counter gravity. In harder formations the near-bit stabilizer is replaced by a reamer. Generally only three stabilizers should be used, unless differential sticking is expected. Changes in WOB will not affect the directional behavior of this type of assembly, and so optimum WOB can be applied to achieve maximum penetration rates. A
packed hole assembly with several stabilizers should not be run immediately after a down hole motor run.
Dropping Assemblies
In directional wells, only an S shape profile requires a planned drop in angle. The other application of a droppi'1g assembly is when the inclination has been increased beyond the intended trajectory and must be reduced to bring the well back on course. It is best to drop angle in a section of softer formation, since the response to a pendulum type assembly in hard rock is very slow. Figure gives some typical dropping assemblies (F and G).
