Directional Ddrilling Operations Manual

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Table of ContentsOverview of Computalog 1 CHAPTER 1 Directional Drilling Introduction Directional Drilling Terminology Applications of Directional Drilling Directional Drilling Limits CHAPTER 2 Methods of Deflecting a Wellbore Bottomhole Assemblies Building Assemblies Dropping Assemblies Holding Assemblies Jetting Special BHA’s Stabilization Rotating Blade Type Continue…. Integral Blade Stabilizer Welded Blade Stabilizers Shrunk on Sleeve Stabilizers Replaceable Sleeve-Type Stabilizer Common BHA Problems Whipstock Downhole Motors w/ Bent Sub Steerable Assembly CHAPTER 3 Downhole Mud Motors Motor Selection Components Dump Sub Assembly Power Section Drive Assembly Adjustable Assembly Sealed or Mud Lubricated Bearing Section

Gear Reducer Assembly Kick Pads Stabilization Drilling Motor Operation Assembly Procedure & Surface Check Prior to Running in Hole Tripping in Hole Drilling Reactive Torque Drilling Motor Stall Bit Conditions Rotating the Drilling Motor Tripping Out Surface Checks After Running in Hole Drilling Fluids Temperature Limits Hydraulics CHAPTER 4 Survey Calculations Tangential Balanced Tangential Average Angle Radius of Curvature Minimum Curvature CHAPTER 5 Planning a Directional Well Profiles of Directional Wells Information Required Planning Torque and Drag CHAPTER 6 Planning a Horizontal Well Data Collection Casing Design Selection of Build Rates

Planning Team Planning Geosteering CHAPTER 7 Magnetics Magnetic Fields Magnetic Interference Drill String Magnetic Interference Minimizing Errors External Magnetic Interference Directional Sensor Package Spacing The Earth’s Gravitational Field Applications of Magnetics & Gravity CHAPTER 8 Survey Equipment, Selection & Accuracy Magnetic Single Shot & Multishots Magnetic Multishot Survey Instrument Gyroscopes Evolution of Gyroscopes Used in Surveying Oil Wells Survey Accuracy & Quality Control Gyro Errors Measurements While Drilling (MWD) Directional Sensor Package CHAPTER 9 Operational Considerations CHAPTER 10 The Problem of Deviation & Doglegging Rotary Boreholes Table 1: Survey Results from Seminole Theories of Causes of Deviated Field Holes Categorizing Crooked Holes CHAPTER 11 Planning an Underbalanced Hz Well Introduction Why Drill Underbalanced Limitations Directional Planning Issues Operational Issues Equipment & Drilling Problems

Downhole Motor Tests Under Two Phase Flow What this Means to a Directional Driller Conclusions & Recommendations CHAPTER 12 Underbalanced Drilling To Be Developed Formation Damage UBD or CPD Modeling UBD Equipment Gas Supply Alternatives Corrosion Issues

A L G E R I A C O U R S E

OVERVIEW OF COMPUTALOG DRILLING SERVICES

Computalog is a Canadian company wholly owned by Precision Drilling. Computalog was started in 1972 as a small perforating company under the name Perfco. Perfco grew into a small wireline company and with Gearhart Industries in 1974 formed Computalog Services. They continued to grow providing cased and open logging services through a newly developed direct digital logging system. In 1979 Gearhart Industries was developing measurement while drilling (MWD) systems in the United States. In 1980 the name was changed to Computalog Gearhart Ltd. and became a publicly traded company with stations in the US and Canada. In 1983 United Directional Drilling and Trigon Oilwell Surveys were purchased to provide a direct supplier to the oilfield of the latest MWD technology to the Canadian oil industry. Computalog introduced the first MWD gamma ray tool into Canada in 1984. In 1987 Computalog acquired several more companies including Maxi-Torque, a manufacturer of downhole positive displacement motors used primarily for directional drilling operations. Also Computalog continued to expand its presence in many international areas including China, Africa, Costa Rica and the Middle East. In 1989 the name was changed to Computalog Ltd. and developed its own MWD system. The wireline group was also expanding and developing new technology rapidly. In 1997, Computalog entered into a joint venture with Geoservices S.A. of France, the worlds largest supplier of electromagnetic MWD technology. The partnership was called United GeoCom Drilling Services. United GeoCom Drilling Services became the third largest directional drilling company in Canada. UGC has continued to grow and is now one of the largest directional companies in Canada with the most experience at providing underbalanced drilling services to the oil industry. In 1999, Precision Drilling purchased Computalog and joined it with several other service supply companies to become a very unified and growth oriented company. We have a significantly improved research and development budget and are now poised to develop new and improved technology: 1) new generation MWD with a full suite logging while drilling tools, 2) rotary steerable directional system and 3) improved multilateral window and tie-back systems for horizontal wells to name a few. We are also making improvements in the wireline division as well.

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Chapter

1 DIRECTIONAL DRILLING Introduction In the early days of drilling, no one worried about hole deviation. The whole objective was to get the well drilled down, completed and producing as quickly as possible. Many drilling personnel assumed the wells were straight - others simply did not care. Subsequently, wells were deliberately drilled in some unknown direction. This began as a remedial operation to solve a drilling problem - usually a fish or junk left in the hole. Today, with the advent of tighter legal spacing requirements, better reservoir engineering modelling and drilling of multiple wells from a single surface location, it has become very important to both control the wellbore position during drilling and to relate the position of existing wellbores to lease boundaries, other wells, etc. The development of the skills and equipment necessary to direct these wellbores is the science of directional drilling. Directional Drilling is the science of directing a wellbore along a predetermined path called a trajectory to intersect a previously designated sub-surface target. Implicit in this definition is the fact that both the direction and the deviation from vertical are controlled by the directional driller from the surface.

Directional Drilling Terminology A short glossary of the more frequently used terms for Directional Drilling is included here and is intended only as an aid in understanding directional drilling terminology and is neither a definitive work in the field nor by any means complete. Some of the more important and commonly used terms are: Target The target, or objective, is the theoretical, subsurface point or points at which the wellbore is aimed. In the majority of cases it will be defined by someone other than the directional driller. Usually this will be a geologist, a reservoir engineer or a production engineer. They will often define the target in terms of a physical limitation - i.e. a circle with a specified radius centred about a specified subsurface point. If multiple zones are to be penetrated, the multiple targets should be selected so that the planned pattern is reasonable and can be achieved without excessive drilling problems.

Some care should be taken with target definition. Any target can be reached - given enough time, money and effort but the economics of drilling dictate the use of as large a target as possible. Each of the various targets is discussed below: 1. Circular

A horizontal circle of given radius about a fixed subsurface point. 2. Bounded

A circular, square or rectangular shape with at least one side fixed by a physical constraint e.g. a fault, a formation change (salt dome), legal boundary etc.

3. Angle at Depth

Targets may be defined as an angle limitation at depth - e. g. 2o or 5o from projected trajectory.

When targets are defined the directional driller must also know the true vertical depth at which the target applies. In some cases this depth may not be available within several hundred meters and could be specified as the wellbore intercept of a given formation top. This top of target would almost certainly preclude the use of Build and Hold wells and require use of "S" shaped wellbores. Target Displacement Target displacement is defined as the horizontal distance from the surface location to centre of the target in a straight line. This is also the directional summation of the departure (the due East or West displacement) and the latitude (the due North or South displacement). The target bearings are a measure of the direction in degrees, minutes and seconds (or decimals) and typically expressed with reference to well centre. True Vertical Depth True Vertical Depth (TVD) is the depth of the wellbore at any point measured in a vertical plane and normally referenced from the horizontal plane of the kelly bushing of the drilling rig. Kick Off Point This is the point at which the first deflection tool is utilized and the increase in angle starts. The selection of both the kick off point and build up rate depend on many factors including the formation(s), wellbore trajectory, the casing program, the mud program, the required horizontal displacement, maximum allowable dogleg and inclination. This Kick Off Point (KOP) is carefully selected so the

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maximum angle is within economical limits. Fewer problems are faced when the angle of the hole is between 30o and 55o. The deeper the KOP is, the more angle it will be necessary to build, possibly at a more aggressive rate of build. The KOP should be at such a depth where the maximum angle to build up would be around 40o; the preferred minimum is 15o. In practice the well trajectory may be calculated for several choices of KOP and build up rates and the results compared. The optimum choice is that which gives a safe clearance from all existing wells, keeps the maximum inclination within the desired limits, avoids unnecessarily high dogleg severity’s and is the best design from a cost point of view. Build Rate The change in inclination per measured length drilled (typically o/100’ or o/30 m). The build rate is achieved through the use of a deflection tool (positive displacement motor with a built in adjustable housing or purposefully designed stabilized bottomhole assembly). Build Up Section This is the part of the hole where the vertical angle is increased at a certain rate, depending on the formations and drilling assembly used. During the Build Up the drift angle and direction are constantly checked in order to see whether a course correction or change in build rate is required. This part of the hole is the most critical to assure the desired wellpath is maintained and the final target is reached. Tangent This section, also called the Hold Section, is a straight portion of the hole drilled with the maximum angle required to reach the target. Subtle course changes may be made in this section. Many extended reach drilling projects have been successfully completed at inclinations up to 80o, exposing much more reservoir surface area and reaching multiple targets. However, inclination angles over 65o may result in excessive torque and drag on the drill string and present hole cleaning, logging, casing, cementing and production problems. These problems can all be overcome with today's technology, but should be avoided whenever there is an economic alternative. Experience over the years has been that directional control problems are aggravated when the tangent inclination is less than 15o. This is because there is more of a tendency for bit walk to occur, i.e., change in azimuth, so more time is spent keeping the well on course. To summarise, most run-of-the-mill directional wells are still planned with inclinations in the range 15o - 60o whenever possible.

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Drop Section In S-type holes, the drop section is where the drift angle is dropped down to a lower inclination or in some cases vertical at a defined rate. Once this is accomplished the well is rotary drilled to TD with surveys taken every 50m (150’). The optimum drop rate is between 1o- 2 ½ degree per 30m and is selected mainly with regard to the ease of running casing and the avoidance of completion and production problems. Course Length This course length is the actual distance drilled by the well bore from one point to the next as measured. The summation of all the course lengths is Measured Depth of the well. The term is usually used as a distance reference between survey points. The Horizontal Projection (Plan View) On many well plans, the horizontal projection is just a straight line drawn from the well centre or slot to the target. On multi-well platforms it is sometimes necessary to start the well off in a different direction to avoid other wells. Once clear of these, the well is turned to aim at the target. The path of the drilled well is plotted on the horizontal projection by plotting total North/South co-ordinates (Northings) versus total East/West co-ordinates (Eastings). These co-ordinates are calculated from surveys. Vertical Section The Vertical Section of a well is dependent upon the bearing or azimuth of interest. It is the horizontal displacement of the well path projected at 90o to the desired bearing. Lead Angle Since roller cone bits used with rotary assemblies tend to "walk to the right", the wells were generally kicked off in a direction several degrees to the left of the target direction. In extreme cases the lead angles could be as large as 40o. The greatly increased use of steerable motors, changes in conventional rock bit design and the widespread use of PDC bits for rotary drilling have drastically reduced the need for wells to be given a "lead angle". Most wells today are deliberately kicked off with no lead angle, i.e., in the target direction.

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Applications of Directional Drilling Multiple Wells From Offshore Structure One of today's more common applications of directional drilling techniques is in offshore drilling. Many oil and gas deposits are situated beyond the reach of land based rigs. To drill a large number of vertical wells from individual platforms is impractical and would be uneconomical. The conventional approach for a large oilfield has been to install a fixed platform on the seabed, from which as many as sixty directional wells may be drilled. The bottomhole locations of these wells can be carefully spaced for optimum recovery. This type of development greatly improves the economic feasibility of the expensive offshore industry by reducing the number of platforms required and simplifying the gathering system. In a conventional development, the wells cannot be drilled until the platform has been constructed and installed in position. This may mean a delay of 2-5 years before production can begin. This delay can be considerably reduced by pre-drilling some of the wells through a subsea template while the platform is being constructed. These wells are directionally drilled from an offshore rig, usually a semi-submersible, and tied back to the platform once it has been installed. Relief Wells Directional techniques are used to drill relief wells in order to "kill" blowout wells. The relief well is deviated to pass as close as possible in the reservoir to the uncontrolled well: it is not generally targeted to hit the out of control well as costs to do this would be prohibitive. Heavy mud is pumped into the reservoir to overcome the pressure and bring the wild well under control. Controlling Vertical Wells Directional techniques are used to "straighten crooked holes". In other words, when deviation occurs in a well which is supposed to be vertical, various techniques are used to bring the well back to vertical. This was one of the earliest applications of directional drilling. Sidetracking Sidetracking out of an existing wellbore is another application of directional drilling. This sidetracking may be done to bypass an obstruction (a "fish") in the original wellbore or to explore the extent of the producing zone in a certain sector of a field.

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Inaccessible Locations Directional wells are often drilled because the surface location directly above the reservoir is inaccessible, either because of natural or man-made obstacles. Examples include reservoirs under cities, mountains, lakes, etc. Other Applications Directional wells are also drilled to avoid drilling a vertical well through a steeply inclined fault plane, which could slip and shear the casing. Directional Wells may also be used to overcome the problems of salt dome drilling. Instead of drilling through the salt, the well is drilled at one side of the dome and is then deviated around and underneath the overhanging cap. Directional wells may also be used where a reservoir lies offshore but quite close to land, the most economical way to exploit the reservoir may be to drill directional wells from a land rig on the coast. Reservoir Optimization Horizontal drilling is the fastest growing branch of directional drilling. Horizontal wells allow increased reservoir penetration, especially in thinner reservoirs, allow increased exposure of the pay zone and allow higher production rates at equivalent drawdowns. Numerous specific applications for horizontal drilling are being developed with major advances occurring in the tools and techniques used. Multilateral Wells Within the science of horizontal drilling, multilateral hole drilling is rapidly becoming a common occurrence. Wells are drilled horizontally to total depth and laterals drilled from them in various directions. These laterals remain essentially horizontal and are directionally controlled to ensure maximum pay zone exposure.

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Sidetracking Salt dome drilling

Inaccessible locations Fault controlling

Multiple wells from a single well Offshore multi-well drilling

Under lakes Multiple sands from a single wellbore

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Drilling relief wells Horizontal wells

Speciality Applications In addition to exploration for oil and gas, controlled directional drilling practices are used in other industries such as construction and mining. The following examples are applications in common use: • Conduit holes - Holes drilled to accommodate pipelines, cables or other

transmission mediums. These holes are generally drilled to traverse obstacles in a proposed right of way which present problems to conventional trenching methods such as:

- River crossings - Steep or unstable terrain presenting backfill and future erosion problems - Shore approaches - Environmentally sensitive areas.

• Storage Caverns • Solution Mining - Extraction of water-soluble minerals (e.g. salt, potash) can be

attained through solution mining technologies. In this practice, "paired" wells are drilled to predetermined targets and water is circulated through the holes until communication is established. Water is then forced down one hole and allowed to exit through the other carrying with it the mineral in solution. At surface the minerals are removed through various methods and the water re-circulated in a continuous procedure.

• Grout Holes - Proper placement and control of grout holes (to stabilize

unconsolidated formations or isolate water-bearing formations) will result in reduced overall costs and greater technical efficiencies for the procedure.

• Evacuation Holes - Methane and water drainage holes have been common in

the mining industry for years. Similar technologies are now being employed in the environmental area for in-site evacuation of toxic contaminants left in

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industrial and waste disposal sites. Directional Drilling Limits Any drilling limit described in a textbook written today would be simply broken tomorrow by some operator. We have drilled horizontal wells with laterals over 6,100m long; extended reach wells with over 10,000m of horizontal reach (horizontal to vertical ratio of 6 or 7 to 1); multi-lateral horizontal wells with 10 legs; purposefully turned horizontal wells 180o in bearing; drilled 27 wells off a single land based pad location; re-entered just about every wellbore configuration to drill to a new target and are now drilling stacked well pairs within 3m (10’) of each other. Coiled tubing drilled wells are also setting new records with lateral sections in excess of 1,200m. Just about anything can be drilled provided you have the financial support. It is better to know the potential equipment or wellbore limitations. The following is a list of some of the factors considered when planning a directional well that will be further discussed in a later section: 1.) Through experience many operators have established their own maximum

inclination and/or dogleg severity limits to minimize rod and casing wear. 2.) Open-hole and cased hole logging equipment have limits on dogleg

severity the tools can safely pass through that depends upon the tool OD, hole OD and tool length.

3.) It may be impossible to get sufficient weight on bit (WOB) to drill the well

depending upon factors such as drag, drill string assembly design, mud type and hole geometry to name a few.

4.) Key seat and differential sticking potentials. 5.) Maximum dogleg directional equipment can be rotated or slid through

(bending stresses). 6.) Wellbore stability (tectonic conditions, sloughing, boulders) 7.) The ability to steer the BHA along the required course (reactive torque). 8.) Ability for equipment to build inclination at the required rates As directional drilling technologies continue to develop, new applications will emerge. Although oil and gas drilling applications will continue to dominate the future of the directional industry, environmental and economic considerations will force other industries to consider directional drilling alternatives to conventional technologies.

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Chapter

2 METHODS OF DEFLECTING A WELLBORE There are several methods of deflecting a wellbore. By deflecting we mean changing the inclination and/or direction of a wellbore. The most common methods used today are: 1. Bottomhole Assemblies 2. Jetting 3. Whipstocks 4. Downhole Motors – most common Bottomhole assemblies are the least expensive method of deflecting a well and should be used whenever possible. Unfortunately, the exact response of a bottomhole assembly is very difficult to predict and, left or right hand walk is almost impossible to control. When refinements of the wellbore course are necessary usually the latter method is used. Bottomhole Assemblies Before the invention of measurement while drilling (MWD) tools and steerable motors, rotary bottomhole assemblies (BHA) were used to deflect wellbore. A bottomhole assembly is the arrangement of the bit, stabilizer, reamers, drill collars, subs and special tools used at the bottom of the drill string. Anything that is run in the hole to drill, ream or circulate is a bottomhole assembly. The simplest assembly is a bit, collars and drill pipe and is often termed a slick assembly. The use of this assembly in directional drilling is very limited and usually confined to the vertical section of the hole where deviation is not a problem. In order to understand why an assembly will deviate a hole, let’s consider the slick assembly which is the simplest and easiest to understand. The deviation tendency in this assembly is a result of the flexibility of the drill collars and the forces acting on the assembly causing the collars to bend. Even though drill collars seem to be very rigid, they will bend enough to cause deviation. The point at which the collars contact the low side of the hole is called the tangency point. The distance L from the bit to the tangency point is dependent upon collar size, hole size, applied bit weight, hole inclination, and hole curvature. Generally, the distance L is less than 50m (150 feet).

Above the tangency point of the slick assembly, the remainder of the drill string generally has no effect on deviation. As weight is applied to the bit, the tangency point will move closer to the bit (Figure 4-1). Because of the bending of the drill collars, the resultant force applied to the formation is not in the direction of the hole axis but is in the direction of the drill collar axis. As bit weight is applied, the tangency point moves toward the bit increasing the angle. It can readily be seen that an increase in bit weight leads to an increase in deviation tendency.

Figure 4-1 Effect of increased bit weight Unfortunately, the direction of the resultant force is not the only force involved. The resultant force can be broken up into its components. The primary force would be the drilling force in line with the axis of the borehole. The bit side force is caused by the bending of the collars and is perpendicular to the axis of the borehole. The force due to gravity (acting on the unsupported section of drill collars) is in the opposite direction and counteracts the side force. The net deviation force is then equal to the summation of the bit side force and the force due to gravity. If the force due to gravity is greater than the bit side force the angle will drop. The deviation tendency can be controlled by changing the bit weight. Increasing the bit weight will lower the tangency point increasing the angle. Since resultant force is proportional to the sine of angle, an increase in bit weight increases the bit side force and ultimately the deviation tendency. Of course, a decrease in bit weight will decrease the deviation tendency. Another factor affecting deviation tendency is the stiffness of the drill collars. Stiffer collars will bend less, which increases the height to the tangency point. If

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the tangency point moves up the hole, then the deviation tendency will be reduced. The relative stiffness of a drill collar is proportional to the collar radius to the fourth power.

Relative Stiffness Coefficient = E X I E = Young’s Modulus I = Moment of Inertia I = π x (OD4 – ID4) / 64

As an example, assume the relative stiffness of a 6” drill collar is one and the ID of all drill collars is 2 inches. An 9” and 11” collar would be five and eleven times stiffer respectively (Table 4-1).

Table 4-1 Relative Stiffness of Drill Collars

Drill Collar Diameter Inches (mm)

Relative Stiffness

11 (279) 11.4 9 (229) 5.1 7 (178) 1.9 6 (152) 1.0

4 ¾ (121) 0.4 Therefore, small diameter drill collars will enhance the deviation tendency. Table 4-1 shows the relative stiffness of various drill collars when the stiffness of a 6” by 2” ID drill collar is assumed to be one. The addition of a stabilizer above the bit significantly affects the deviation tendency of a bottomhole assembly. The stabilizer acts as a fulcrum around which the unsupported section of the bottomhole assembly reacts. The addition of the moment arm between the bit and stabilizer increases the bit side force. In fact, the single stabilizer assembly is a very strong building assembly. The addition of multiple stabilizers to an assembly makes the determination of side forces at the bit much more complicated. The analysis of these types of bottomhole assemblies is best suited for a computer and is beyond the scope of this manual. Assuming the formation is uniform and the bit can drill in any direction, the bottomhole assembly would drill in the direction of the vector sum of the forces at the bit. Unfortunately, the bit side-cutting and forward-cutting ability are not

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equal. Also, the anisotropic failure of the rock can cause a deviation in a direction other than the vector sum of the forces at the bit. The side cutting ability of a bit is proportional to the side force exerted at the bit. Under static conditions, the side force on the bit can be calculated using a computer program. When the entire bottomhole assembly is considered, it can also be shown the stabilizers in the assembly exert a side force. The stabilizers have a side-cutting ability too. One would think the deviation tendency could then be calculated. Unfortunately, the side forces will change under dynamic conditions. Both the bit and the stabilizers cut sideways reducing the side force on each until an equilibrium is reached. Under dynamic conditions, the relative side-cutting of the bit and stabilizers becomes complicated which, in turn, makes the deviation tendency very difficult to calculate. The relationship between the bit and stabilizer side-cutting is dependent upon the type of bit, type of stabilizer, penetration rate, rotary speed, lithology, hole size, and bottomhole assembly type.

Figure 4-2 Stabilizer Forces The side-cutting ability of soft formation bits is generally considered better than for hard formation bits. Diamond bits have a greater side-cutting ability because they are designed with more of a cutting structure along the lateral face of the bit.

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The second factor affecting the deviation tendency is the anisotropic failure characteristics of the formation. In isotropic formations, equal chip volumes are formed on each side of the bit tooth and the bit will drill straight ahead (Figure 4 -3).

Figure 4-3 Illustration of Isotropic and Anisotropic Formations But formations are not isotropic because the rock contains bedding planes. Also, the relative hardness of the formation changes with vertical depth. In an anisotropic formation, relatively large chip volumes are formed on one side of the bit tooth causing the bit to deviate (Figure 4-3). The magnitude and direction of the formation deviation tendency will depend upon bed dip. Generally, the bit will walk up dip when beds are dipping 0o to 45o and down dip when beds are dipping 65o to 90o. Bed dips between 45o and 65o can cause either an up dip or down dip walk. Bed strike can cause the bit to walk left or right. There are three basic types of assemblies used in directional drilling, they are: 1.) Building Assemblies, 2.) Dropping Assemblies 3.) Holding Assemblies

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A building assembly is intended to increase hole inclination; a dropping assembly is intended to decrease hole inclination; and a holding assembly is intended to maintain hole inclination. It should be noted that a building assembly might not always build angle. Formation tendencies may cause the assembly to drop or hold angle. The building assembly is intended to build angle. The same is true for the dropping and holding assemblies. Building Assemblies As previously stated, the building assembly uses a stabilizer acting as a fulcrum to apply side forces to the bit. The magnitude of that force is a function of the distance from the bit to the tangency point. An increase in bit weight and/or decrease in drill collar stiffness will increase the side force at the bit increasing the rate of build. The strongest building assembly consists of one stabilizer placed 3 to 6 feet above the bit face with drill collars and drill pipe above the stabilizer. This assembly will build under the majority of conditions. Of course, the rate of build will be controlled by formation tendencies, bit and stabilizer types, lithology, bit weights, drill collar stiffness, drill string rpm’s, penetration rate, and hole geometry.

Figure 4-4 Building Assemblies

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Another strong to moderate building assembly consists of a bottomhole stabilizer placed 3 to 6 feet from the bit face, 60 feet of drill collars, stabilizer, collars, and drill pipe. This is the most common assembly used to build angle. The second stabilizer tends to dampen the building tendency. This assembly can be used when the previous assembly builds at an excessive rate. Other building assemblies can be seen in Figure 4-4. Dropping Assemblies A dropping assembly is sometimes referred to as a pendulum assembly. In this assembly, a stabilizer is placed at 30, 45, or 60 feet from the bit. The stabilizer produces a plumb bob or pendulum effect; hence the name pendulum assembly. The purpose of the stabilizer is to prevent the collar from touching the wall of the hole causing a tangency point the bit and stabilizer. An increase in the length of the bottomhole assembly (the length below the tangency point) results in an increase in the weight. Since the force is determined by that weight, the force is also increased exceeding the force due to bending. The net result is a side force on the bit causing the hole to drop angle. Additions of bit weight will decrease the dropping tendency of this assembly because it increases the force due to bending. Should enough bit weight be applied to the assembly to cause the collars to contact the borehole wall (between the stabilizer and the bit), the assembly will act as a slick assembly. Only the section of the assembly below the tangency point affects the bit side force. If an increase in dropping tendency is required, larger diameter or denser collars should be used below the stabilizer. This increases the weight of the assembly, which results in an increase in dropping tendency. As an example, suppose a dropping assembly with 7” (178mm) drill collars was being used in a 12 ¼” (311mm) hole. By substituting 9” (229mm) collars for the 7” collars, an increase in dropping tendency can be achieved. Dropping assemblies will have a higher rate of drop as hole inclination increases. The force which causes the dropping tendency is calculated using the following formula: F = 0.5 X W X Sin (I) Where: F = Side force at the bit caused by the weight of the unsupported section of the bottomhole assembly, lbs (daN).

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W = Buoyant weight of the unsupported section of the bottomhole assembly, lbs (daN). I = Hole inclination, degrees. An increase in hole angle will result in an increase in F, resulting in an increase in dropping tendency.

Figure 4-6 Drop Assemblies HOLDING ASSEMBLIES Holding the inclination in a hole is much more difficult than building or dropping angle. Under ideal conditions, most assemblies either have a building or dropping tendency. Most straight hole sections of a directional well will have alternating build and drop tendencies. When holding inclination, these build and drop sections should be minimized and spread out over a large interval. The most common assemblies are indicated in Figure 4-6 indicating their strength at holding inclination.

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Figure 4-6 Hold Assemblies When selecting a hold assembly, research the well records in the area to find out which assembly works best for the types of formations being drilled. If no formation is available, use a medium strength assembly and adjust it as necessary. These build and drop assemblies are still used on directional wells but generally limited to slant hole drilling. The hold assemblies are very commonly used on deep vertical wells to minimize the amount of directional drilling required.

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EXAMPLE ROTARY ASSEMBLIES Although their use is being minimized the rotary assembly still sees common use in certain fields. The following assemblies were successfully used in an area of shallow well drilling (500m) in Alberta. Note the subtle changes in BHA and their effect on build/drop rates. Their use has been severely curtailed due to the inevitable trip to change the BHA and loss time incurred. 3 degree/30m Build Assembly Tool Description OD (mm) Length (m) Bit 222 0.25 Near Bit Stabilizer 222 1.50 3 – NMDC’s 171 27.00 2 degree/30m Build Assembly Tool Description OD (mm) Length (m) Bit 222 0.25 Near Bit Stabilizer 222 1.50 2 – NMDC’s 171 18.00 NM Stabilizer 222 1.50 1 – NMDC 171 9.00 1 degree/30m Build Assembly Tool Description OD (mm) Length (m) Bit 222 0.25 Near Bit Stabilizer 222 1.50 Short NMDC 171 3.50 NM Stabilizer 216 1.50 1 – NMDC 171 9.00 NM Stabilizer 222 1.50 1 – NMDC 171 9 Hold Assembly Tool Description OD (mm) Length (m) Bit 222 0.25 Near Bit Stabilizer 222 1.50 Short NMDC* 171 3.50 NM Stabilizer 222 1.50 1 – NMDC 171 9.00 NM Stabilizer 222 1.50 1 – NMDC 171 9 * change to full length NMDC and had less turn

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3 degree/30m Drop Assembly Tool Description OD (mm) Length (m) Bit 222 0.25 Bit Sub 1.50 NMDC 171 9.00 NM Stabilizer 222 1.50 1 – NMDC 171 9.00 NM Stabilizer 222 1.50 1 – NMDC 171 9.00 2 degree/30m Drop Assembly Tool Description OD (mm) Length (m) Bit 222 0.25 Bit Sub 1.50 Short NMDC 171 3.50 NM Stabilizer 222 1.50 1 – NMDC 171 9.00 NM Stabilizer 222 1.50 1 – NMDC 171 9.00 1 degree/30m Drop Assembly Tool Description OD (mm) Length (m) Bit 222 0.25 Near Bit Stabilizer 216 1.50 Short NMDC 171 3.50 NM Stabilizer 222 1.50 1 – NMDC 171 9.00 NM Stabilizer 222 1.50 1 – NMDC 171 9.00 JETTING The jet bit method of deflecting a well at one time was the most common method used in soft formations. Jetting has been successfully used to depths of 8,000 feet (2,400m); however the economics of this method and the availability of other directional drilling tools limit its use. A formation suitable for jetting must be selected. There must be sufficient hydraulic horsepower available and the formation must be soft enough to be eroded by a mud stream through a jet nozzle.

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There are special bits made for jetting including those with two cones and an elongated jet nozzle replacing the third cone. The elongated nozzle provides the means to jet the formation while the two cones provide the mechanism for drilling. Other tri-cone deflection bits are available with an enlarged fluid entrance to one of the jets. This allows a greater amount of fluid to be pumped through one of the jets during jetting operations. To deflect a well using the jet method, the assembly is run to the bottom of the hole, and the large jet is oriented in the desired direction. The kelly should be high to allow rotary drilling after the deflection is started. 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 150 m/sec (500’/sec). The drill string is set on bottom and if the formation is sufficiently soft, the WOB drills off. A pocket is washed into 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 1.5m (5’) off bottom and then let it fail, 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 that may help is to ‘rock’ the rotary table a little (15o) right and left of the orientation mark while jetting. After a few feet have been jetted, the pumps are cut back to about 50% of that used for jetting and 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 length 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 and an appropriate angle build assemble.

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Figure 4-7 Jetting Assembly SPECIAL BHA’s Tandem Stabilizers It’s fairly common to run a string stabilizer directly above the near-bit stabilizer. This is normally for directional control purposes. An alternative is to run a near-bit with a longer gauge area for greater wall contact. High rotary torque may result in either case. It is dangerous to run tandem stabilizers directly after a more limber BHA due to the reaming required and potential sticking. Roller Reamers In medium/hard formations where rotary torque is excessive, it may be necessary to dispense with some to all of the stabilization. Roller reamers are a good alternative however they behave different then stabilizers. As a rule they tend to drop angle.

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STABILIZATION Consider the performance of two slick BHAs: 1) 200.0 mm Bit 2) 222.3 mm Bit

158.8 mm (6.25 inch) DC 158.8 mm (6.25 inch) DC Which of the two assemblies have shown better performance? #1 had better performance because of better stabilization within the borehole during drilling. Comparatively, the service life of bit #2 is shortened because of a misaligned axis of rotation. This misalignment may be of a parallel or angular basis. Parallel misalignment is caused by the use of a small drill collar in relation to the hole size and no stabilization. The bit can move off centre until the drill collar OD contacts the wall of the hole. This results in an offset due to drilling off centre (bottom of the hole shifts in a parallel manner and is called parallel misalignment). Angular misalignment is caused by the use of small drill collars in relation to the hole size and no stabilization. Most or all of the bit load is applied to one cone at a time, causing rapid breakdown and failure of both the cutting structure and bearing structure of the bit. Arthur Lubinski and Henry Woods (research engineers for Hughes Tool Co.) were among the first to apply mathematics to drilling. They stated in the early 50s that the size of the bottom drill collars would be the limiting factor for lateral movement of the bit, and the Minimum Effective Hole Diameter (MEHD) could be calculated by the following equation: MEHD = Bit Size + Drill Collar OD 2 Robert S. Hoch (engineer for Phillips Petroleum Comp.) theorized that, while drilling with an unstable bit, an abrupt change can occur if hard ledges are encountered. He pointed out that a dogleg of this nature would cause an undersized hole, making it difficult or maybe impossible to run casing. Hoch rewrote Lubinski’s equation to solve for the Minimum Permissible Bottom-Hole Drill Collar Outside Diameter (MPBHDCOD), as follows: MPBHDCOD = 2 x (casing coupling OD) - Bit OD

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Example: 311.2 mm bit 244.5 mm casing (coupling OD = 269.9 mm)

Minimum Drill Collar Size = 2 x (269.9 mm) - 311.2 mm = 228.6 mm OD Bit misalignment can be controlled through use of appropriate size drill collars. An alternate method of control is through the use of stabilized bottom hole assemblies, particularly when drilling with diamond bits, journal bearing or sealed bearing bits. Reasons for Using Stabilizers

1. The placement and gauge of stabilizers are used as the fundamental method of controlling the directional behavior of most bottom hole assemblies.

2. Stabilizers help concentrate the weight of the BHA on the drill bit.

3. Stabilizers resist loading the bit in any direction other than the hole axis.

4. Stabilizers minimize bending and vibrations, which cause tool joint wear and damage to BHA components such as, MWD tools.

5. Stabilizers reduce drilling torque by preventing collar contact with the side of the hole and by keeping the collars concentric in the hole but also add torque due to their side-loading.

6. Stabilizers help prevent differential sticking and key seating.

Available Types of Stabilizers

1. Integral blade stabilizers

2. Welded blade stabilizers

3. Replaceable sleeve stabilizers

4. Non-rotating rubber sleeve stabilizers

5. Replaceable wear pad stabilizers

6. Roller reamers

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7. Combination reamers/stabilizers

Types of Stabilizers

There are three basic types of stabilizing tools with some variations of each available:

a) Rotating Blade Type b) Non-Rotating Sleeve Type c) Roller Reamer Type

Rotating Blade Type

• Can be a straight blade or a spiral blade (short or long blade) configuration.

• Rotating blade stabilizers are available in two types - shop repairable - rig repairable.

• Are Integral Blade, Welded Blade or Shrunk on sleeve construction.

Integral Blade Stabilizer They are made from one piece of material rolled and machined to provide the blades and are more expensive then 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.

They normally have tungsten carbide inserts (TCI). Pressed in TCI are recommended in abrasive formations i.e. hard limestone, dolomites, sandy shales, chert, quartzite, and quartzitic sands since they tend to stay in gauge longer than welded blade stabilizers.

Two main designs are available - spiral blade configuration for maximum wall contact and cloverleaf (straight blades) for less drag when not rotating.

Integral blade stabilizers have longer blades and larger wall contact surface areas and are therefore good for maintaining angle and direction. They can be used as a near-bit stabilizer when angle build is required and a good rate of build will be obtained.

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Welded Blade Stabilizers The blades are welded onto 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.

They aren’t recommended in hard formations because of the danger of blade failure. They are best suited to large hole sizes where the formation is softer because they allow maximum flow rates to be used. They are less expensive to build than integral blade stabilizers and the blades can be built up when they are worn.

They aren’t recommended for use as the near-bit stabilizer in formations where bit walk is a problem because of the smaller area of blade/wall contact. They aren’t as good as other stabilizer types for locking up an assembly so more walk (azimuth change) tends to occur. Shrunk On Sleeve Stabilizers A sleeve type integral blade stabilizer is constructed with the ribs integral with a sleeve. The sleeve is attached to the body with a shrink fit. When ribs wear out, the old sleeve is removed with a cutting torch and a new sleeve shrunk on with proper heating equipment. Spiral or Straight Blade type

Either have a replaceable metal sleeve (i.e. Eze Change Stabilizer) or replaceable metal wear pads. They were originally developed for remote location use.

Non-Rotating Rubber Sleeve Stabilizers also fall into this area.

Non-Rotating Rubber Sleeve Stabilizers

Used somewhere above the top conventional stabilizer in the BHA, especially in abrasive formations. The rubber sleeve doesn’t rotate while drilling and since the sleeve is stationary, it acts like a drill bushing and therefore will not dig into and damage the wall of the hole. The sleeve life may be shortened in holes with rough walls. Special elastomer sleeves may be used for high temperature wells. Newer polymer design sleeves have been developed that may extend their use.

Replaceable Wear Pad Stabilizer

Has four long blades 90o apart composed of replaceable pads containing pressed-in tungsten carbide insert compacts. They are good for directional control and/or in abrasive formations but may provide excessive torque.

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Replaceable Sleeve-Type Stabilizer Two main designs of sleeve-type stabilizer:

1. Two-Piece Stabilizer (mandrel and sleeve).

• Sleeve is screwed onto the coarse threads on the outside of the mandrel and torqued to recommended value. Sleeve makeup torque is low and there is no pressure seal at the sleeve.

• Convenient to change sleeves on the rig floor.

• Hard-facing or tungsten carbide inserts protect the blade surfaces from wear.

• One body can accommodate several sleeve sizes. Therefore are more economical than Integral Blade Stabilizers (easier to transport also).

2. Three-Piece Stabilizer (mandrel, sleeve and saver sub).

• The sleeve is screwed onto the mandrel by hand initially. The saver sub is then screwed into the mandrel and this connection is torqued up to the required value. A mud pressure seal is situated at the mandrel/saver sub connection.

• Proper makeup torque is required to minimize downhole washing.

• Since it can be time-consuming to change/service the sleeve, this type of stabilizer is not as widely used today.

Clamp-On Stabilizer

Several designs are available and allow more flexibility in BHA designs. They can be positioned on NMDCs, MWD tools, and PDM at required spacing for directional control. Nonmagnetic clamp-on stabilizers are also available. Risk exists of clamp-on moving position downhole during drilling.

For any of the sleeve stabilizers one of the major disadvantages with there use is the restrictions in circulation rates in smaller hole diameters - 8.5” (216 mm) or less because of the reduced clearance between the stabilizer body and the wall of the hole.

Roller Reamers

They are designed to maintain hole gauge, reduce torque and stabilize the drill string. They can be 3-point or 6-point design and both near-bit and string roller reamers are available. They are particularly useful in abrasive formations.

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Near-bit roller reamers help prolong bit life and 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. The disadvantage to this is that more bit walk is experienced since a smaller area of wall contact exists compared to other types of stabilizers. Also, lower build rates are obtainable with roller reamers used as near bit stabilizers with building assemblies.

Selection of Stabilizer

Geology is an important consideration when choosing appropriate stabilizer for the well i.e. how hard is the formation? Cost and convenience also influence the selection of one stabilizer type over another. Stabilizer gauge influences the performance of the BHA, i.e. will it build or drop angle as predicted? Or will the stabilizer wear prematurely in the formation being drilled?

Type of Stabilizer Applications

Integral Blade Maximum durability for toughest applications

Welded Blade Large hole size in soft formation. Top hole section of directional well (above KOP)

Replaceable Sleeve Valuable where logistics are a problem. Economic

considerations.

Non-Rotating Rubber Very hard and/or abrasive formations.

Sleeve Straight holes.

Roller Reamers Hard formations.

Common BHA Problems Formation Effects It often happens that when a certain TVD is reached, BHA behavior changes significantly. A BHA, which held inclination down is now starting to drop angle. Why? Assuming that the near-bit has not gone under-gauge, it’s probably due to formation effects (change in formation, change in dip or strike of the formation etc). It’s vital to keep a good database and try to anticipate the problem for the following well. Abrasive formations pose problems for the directional driller. Ensure the bit has good gauge protection and use stabilizers with good abrasion resistance. Check the gauge of the stabilizers when out of the hole and watch out for a groove cut on the leading edge of stabilizers (indication of need to change out the stabilizer).

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When it’s difficult to drop inclination, sometimes a larger O.D. drill collar is used as the lower part of the pendulum. Another possibility is the use of a tungsten short collar; higher concentration of the same into a much shorter element should provide a more effective pendulum force. Worn Bits In a long hole section in soft formation inter-bedded with hard stringers, the long-toothed bit may get worn. ROP will fall sharply and net side force will decrease due to stabilizers undercutting the hole. Thus, a BHA which had been holding inclination up to that point will start to drop angle. However, if the survey point is significantly behind the bit, this decrease in angle will not be seen in time. If the worn teeth are misinterpreted as a balled-up bit and continued lengthy efforts made to drill further, serious damage may be done to the hole. It has happened that a drop in inclination of 6o (with a severe dogleg severity) has happened in this situation. In addition, a bit having worn teeth has a tendency to lose direction. Thus, it is important to pull out of the hole when a worn bit situation develops. Accidental Sidetrack In soft formation, where a multi-stabilizer BHA (either Buildup or Lockup) is run immediately after a mud motor/bent sub kickoff run, great care must he taken. Circulation should be broken just before the kickoff point. The BHA should be washed/worked down, using full flow rate. The directional driller must be on the drill floor while this is happening. Try to work through tight spots. If string rotation is absolutely necessary, keep the RPM low and cut rotating time to the absolute minimum. The risk of sidetracking the well (with subsequent expensive plug-back and re-drill) is high. Several kickoffs have been lost in various parts of the world by carelessness. Where the kickoff is done in a pilot hole in soft formation, an under-reamer or hole opener is used to open the hole prior to running casing. Again, to avoid an unwanted sidetrack, a bull-nose (not a bit) and possibly an extension sub/short collar should be run below the under-reamer/hole opener. Pinched Bit In hard formations, it is especially important to check each bit for gauge wear etc. when it’s pulled out of the hole. When running in the hole with a new bit and/or BHA, it’s imperative that the driller starts reaming at the first sign of under-gauge hole (string taking weight). If he tries to “cram” the bit to bottom, it will become “pinched”. Bit life will be very short.

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Differential Sticking Where differential sticking is a problem, more than three stabilizers may be run in an effort to minimize wall contact with the drill collars. However, the distance between these “extra” stabilizers normally has to be such that they have little effect. They only lead to increased rotary torque. It is vital to minimize time taken for surveys (even with MWD) in a potential differential sticking area. Drilling Parameters High rotary/top drive RPM acts to stiffen the string. Thus for directional control, if possible, high RPM should be used during the rotary buildup phase, when the BHA is most limber. However, it’s vital to check with the MWD engineer for an acceptable range of RPM (to avoid resonance). On a new job, the rig specifications (particularly mud pumps and drawworks) should be checked with the toolpusher. Typical values in 17-1/2” (444mm) hole during rotary build/lockup phases with a milled-tooth bit would be 160-170 RPM. The rotary transmission would normally have to be put into high gear. In 12-1/4” (311mm) hole, RPM is normally less (e.g. 100-140), due to bit life and other factors. Conversely, to induce right-hand walk, it’s recommended to slow the RPM (if the hole direction allows). Weight on bit may be simultaneously increased, if the hole inclination allows. PDC bits normally have a tendency to walk left. This should be allowed for when planning the lead angle at the pre-kickoff stage. Again, experience in the area and with the bit has to be used in making this decision. To increase rate of buildup, increase the weight on bit. This is normally the case. However, when the WOB reaches a certain value, reverse bending may occur when using a flexible buildup BHA (e.g. 90’ between near-bit and bottom string stabilizers). Suggested maximum value of WOB for 17 1/2” hole is 55,000 lbs. If inclination is not building enough at this WOB, it’s very unlikely that increasing the WOB will improve the situation. Look to hydraulics or possibly pull out of the hole for a more limber hook-up. It’s vital that the directional driller observes the buildup rate carefully. Drilling parameters normally have to be changed very often (typically after every survey). With MWD, there’s no excuse for not keeping close control of buildup rate. Most operators will not complain about taking too many surveys if they know the risk but get rather upset if the well goes off course due to insufficient control.

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BHA Equipment and Tools It’s the joint responsibility of the directional driller and operator to ensure that everything needed (within reason) for future BHA’s is available on the rig. All the directional equipment must be checked thoroughly on arrival at the rig-site. For rotary BHA’s, following are some suggestions: • A selection of stabilizers (normally a combination of sleeve- type and integral

blade design for 17-1/2” and smaller hole sizes) with 360o wall coverage should be available.

• Short drill collars are a vital component of a lockup BHA. If possible, a

selection of short collars (e.g. 5’, 10, and 15) should be available. In addition, in a well where magnetic interference from the drill string (mud motor) is expected to be a problem during the buildup phase, non-magnetic (rather than steel) short collars should be provided.

• Check that the rig has sufficient drill collars and HWDP available. • Check that sufficient bit nozzles of each size (including what’s needed when

running a mud motor) are available. • Have at least one spare non-magnetic drill collar of each size. As NMDC’s are

more prone to galling, damaged collars should be returned to the shop for re-cutting/re-facing when replacements arrive.

• Any crossover subs, float subs, bit subs etc. required later must be on the rig. It’s a good idea to be thinking at least one BHA ahead! Recap • To build inclination, always use a full-gauge near-bit stabilizer. • The more limber the bottom collar, the greater the buildup rate achievable. • Take frequent surveys (e.g. every single with MWD) during the buildup phase

(all wells) and the drop-off phase (‘S”-type wells) in order to react quickly to unexpected trends.

• A jetting BHA is a modified buildup BHA. Don’t jet too far! Watch the

WOB available for jetting/spudding.

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• To drop inclination, either use an under-gauge near-bit (semi-drop BHA, for low drop-off rate) or no near-bit (pendulum BHA, for sharp drop-off rate).

• A locked BHA, which is holding inclination with an under-gauge stabilizer

above the short collar, will start to drop inclination if this stabilizer is made full-gauge.

• In an “S”-type well, try to start the drop-off early using a semi-drop BHA.

Change to a pendulum BHA at around an inclination of 15o. • Try not to have to build inclination into the target; it is better to drop slowly

into the target. • Three stabilizers are normally sufficient in a BHA. In pendulum BHA’s, two

stabilizers should suffice. • Use as few drill collars as possible. Use heavyweight drill pipe as remaining

available weight on bit. • Try to use a fairly standard (reasonably predictable) BHA. Do not try any

“fancy” BHA’s in a new area. Get some experience in the field first! • Directional driller should be on the drill floor when washing/working rotary

BHA through kickoff section in soft formation. Avoid sidetracking the well! • After a kickoff or correction run in medium and hard formations, ream

carefully through the motor run with the following rotary BHA until hole drag is normal.

• In hard and/or abrasive formations, gauge stabilizers carefully when POOH.

Replace stabilizers as required. Check the bit and if it is under-gauge, reaming will be required! Do not let the driller “pinch” the bit in hard formation.

• Check all directional equipment before and after the job. It’s good practice to

caliper all the tools and leave list on drill floor for drillers. Watch out for galled shoulders!

• In potential differential sticking areas, minimize survey time. If using single-

shot surveys, reciprocate pipe. Leave pipe still only for minimum time required.

• A BHA that behaves perfectly in one area, may act very differently in another

area. Local experience is essential in ‘fine-tuning” the BHA’s.

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• In the tangent section of a well, a BHA change may simply entail changing the

sleeve on the stabilizer directly above the short collar. The trick is by how much should you change the gauge? Sometimes a change in gauge of 1/16” may lead to a significant change in BHA behavior!

• High RPM ‘stiffens” the BHA and helps to stop walk due to formation

tendencies. • It’s usually easier to build inclination with lower RPM. However, high RPM

during the buildup phase may be required for directional control. WOB is the major drilling parameter influencing buildup rate.

• To help initiate right-hand walk, it’s advisable to use higher WOB and lower

RPM.

• In soft formation, it may be necessary to reduce mud flow rate to get sufficient WOB and reduce hole washout. Be careful! Wash each joint/stand at normal flow rate before making the connection.

• Reaming is effective in controlling buildup rate in soft formation. It becomes less effective as formation gets harder. However, even in hard formation, reaming before each connection helps keep hole drag low.

• Lower dogleg severity = smoother wellbore = lower friction = lower rotary torque = less keyseat problems = less wear on tubulars = less problems on trips.

WHIPSTOCK The retrievable open-hole whipstock is an old directional drilling tool, which is seldom used in open-hole deflections today. The whipstock is pinned to a limber BHA which includes a small bit. A typical BHA would be as follows: Whipstock – pilot bit – stabilizer – shearpin sub – 1 joint of drill pipe – UBHO (to single shot survey) – non-magnetic drill collar The hole must be clean before running the whipstock. Upon reaching bottom the tool is pulled up slightly off-bottom and the concave face of the whipstock is oriented in the desired direction. The tool is then oriented in the desired direction and 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 whipstock face and rotation is started. About 15 to 20 feet (4.5 to 6m) of rathole is drilled at a controlled rate. The whipstock is then retrieved and the rathole is opened with a pilot bit and hole-opener. Another trip with a full-gauge bit, near-bit stabilizer and

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limber BHA is made to drill another 30’ (9m). A full gauge directional BHA is then run and standard drilling is resumed. This is a very time consuming method of open-hole deflection and creates an abrupt change in inclination or dogleg (typically 14o to 20o per 100 feet or 30 meters) . A permanent whipstock could also be run but the risks of the whipstock falling over or shifting after time is generally thought to be too large. DOWNHOLE MOTORS WITH BENT SUB The use of downhole bent subs has been severely reduced with the invention of steerable motors but is still used in some areas with turbodrill and positive displacement motors, in conjunction to achieve higher build rates and when other choices are not available. Turbodrills were first used in the 1800’s with limited success due to their high RPM (500 to 1200). The use of turbodrills were limited as a deflection tool as well due to their low torque output. The rotation of a turbodrill is derived from the interaction of the drilling fluid and the multiple stages of turbine blades. The rpm’s are directly related to the fluid velocity and torque. One disadvantage of the turbodrill is that the efficiency is lower than the positive displacement motor. Therefore, it requires more horsepower at the surface. Many rigs do not have enough hydraulic horsepower to run a turbodrill. The hydraulics should always be checked prior to running a turbodrill. The positive displacement motor uses the Moyno principle. This tool has found wide application in directional drilling and even straight hole performance drilling. The basic design and components of a positive displacement motor will be discussed in a later section. The best application of the positive displacement motor is in moderately soft formations. When the formation is too soft, the motor is not as effective as jetting. In hard formations, the motor is slow and expensive to use. Both the positive displacement motor and the turbodrill exhibit reverse torque (reactive torque) when placed on the bottom of the hole. This must be taken into account when orienting the motor. Experience in the area is the best method of predicting the reverse torque. If no other information is available, a rule of thumb can be used. That is allow 10o of left torque per 1,000 feet (3o per 100m) of depth in soft formations and 5o/1,000 feet (1.5o per 100m) of depth in hard formations. If the change in well course is critical, steerable motors with MWD equipment should be used. The downhole motor has a distinct advantage over jetting and whipstocks. Doglegs created by jetting and whipstocks are more severe than those created by a

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downhole motor. Jetting and whipstocks create abrupt changes in angle and direction. On the other hand, downhole motors produce a smooth arc over an extended length of the wellbore, and the dogleg severity can be controlled by the angle of the bent sub used. The basic drilling assembly for using a downhole motor consists of a full gauge bit, motor, bent sub, mule shoe sub (some bent subs incorporate a mule shoe sleeve), and non-magnetic drill collars. The bent sub has one of the connecting threads machined at an angle to the axis of the body of the sub. It imparts the bending force in the assembly as drilling progresses, thus producing a change in hole direction. Under dynamic conditions, the side force at the bit is relatively constant. This is the reason the downhole motor produces a continuous change in the wellbore course along a smooth arc of a circle. Because of the high bit offset with this assemble it is advisable to not rotate this type of BHA. Using downhole motors to deflect deep wells can minimize some of the problems associated with shallow, severe doglegs. These problems are drill pipe fatigue, drill string wear, casing wear, keyseats, torque, drag, and production problems. When drilling directional wells, changes in the dogleg severity should be minimized to prevent problems but it depends on the depth of the dogleg. All changes should be as gradual as possible and still accomplish the objectives. STEERABLE ASSEMBLY A steerable assembly is defined as a bottomhole assembly whose directional behavior can be modified by adjustment of surface controllable drilling parameters including rotary speed and weight on bit. The ability to modify behavior in this way enables the assembly to be steered toward a desired objective without its removal from the wellbore. To some extent, rotary assemblies are steerable if the build or drop tendency is weight sensitive. However, the ability to control a rotary assembly is limited especially controlling walk. The most common steerable assembly consists of a PDM that incorporates a fixed or adjustable bent housing on top of the bearing housing below the stator. With the smaller displacement of the bit as compared to using a bent sub, the motor can be safely rotated at RPM’s up to 50 depending upon the bend setting and formation. The motor housing may also incorporate an 3mm (1/8”) undergauge stabilizer. With the bent housing, the stabilizer is not required but the hold tendency of the assembly in the rotary mode is improved. The steerable system operates in two modes; sliding and rotary drilling. In the slide mode, the motor acts like a typical motor run. The motor is oriented in the desired direction (tool face), and drilling progresses without drill pipe rotation. The change in inclination and or direction is derived from the bit tilt from the

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bent housing and the side force created from the stabilizer or the wall contact with the motor. In the rotary drilling mode, the assembly is rotated per normal but at lower values (30 to 50 RPM) and the side force is cancelled by this rotary action. In some formations the assembly will change inclination/direction even in the rotary mode. Because of the bit offset or the side force associated with a steerable system, the assembly will drill an overgauge hole in the rotary mode. Advances in downhole motor reliability have made the steerable system economical in many applications. Typically, the mean time between failure is in excess of 2000 hours for the motor and excess of 800 hours for the measurement while drilling equipment thereby exceeding the life of a tri-cone bit. Where feasible, the tri-cone bit has been replaced with a PDC or diamond bit. When properly matched to the formation and motor torque output, a PDC bit can last much longer than a tri-cone bit; however, a PDC bit can not always be used. They are applicable to soft and medium hardness formations with consistent lithology. In areas where formation hardness changes a lot, PDC bits do not perform as well as tri-cone bits. Also the ability or ease of controlling build and turn rates of a PDC vary considerably. In some cases, the penetration rate of a steerable system will out perform that of a rotary assembly. The majority of the time, it is used in soft formations. As formation hardness increases, rotary assemblies will drill faster than a steerable system unless special high torque performance motors are used. Harder formations are less sensitive to rotary speed, and bit weight is the predominant drilling parameter. In hard formations, the penetration rate for a motor can be half that of a rotary assembly. In soft to medium hard formations, the penetration rate for a downhole motor has been twice that of a rotary assembly. As the torque and drag in a directional well increases, the rate of penetration for a steerable system while sliding can be considerably less than while rotating. In some cases it will be half the rate seen while rotating. Therefore, it is advantageous to rotate a steerable system as much as possible especially when approaching TD. The directional plan can be followed much more closely with a steerable system. Since trips are not required, corrections in the slide mode are made much more frequently. The frequent corrections will keep the wellbore closer to the planned path. In the hold section, the directional driller will often rotate for a portion of a connection and slide for the remainder of the connection. He must first get a feel for how much the assembly is walking and building or dropping while in the rotary mode. Once he gets a feel for that then he can determine how much he needs to slide per connection and what the tool face orientation must be.

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This does not mean that the dogleg severity is very low. It only means that the changes are small and frequent. Surveys at 20m to 30m intervals will not pick up the actual dogleg severity in the well. Whereas with rotary assemblies and motor corrections, the dogleg severity is picked up by the surveys. Frequent motor corrections (short dogleg intervals) will minimize problems associated with keyseats. The doglegs are not long enough for keyseats to form easily. The steerable system should be designed to generate a dogleg severity 25 percent greater than that required to accomplish the objectives of the directional plan (a more aggressive bent housing setting). Formation tendencies can cause the dogleg severity of a steerable system to change. If it decreases the dogleg severity generated by the system, then a trip may be require to pick up a more aggressive assembly. However if the assembly is designed to be more aggressive, then the assembly will still be able to produce a dogleg severity sufficient to keep the wellbore on course and less slide drilling is required resulting in a higher average ROP. Reducing the dogleg severity of a steerable system is not a problem. Alternately sliding and rotating the assembly will reduce the overall dogleg severity. The most significant advantage of the steerable system is that a trip does not have to be made in order to make a course correction. When a correction is required, the motor is oriented and drilling continues in the slide mode until the correction is complete. Then drilling in the rotary mode continues until the next correction is required. If a steerable system is not used, a trip would be required to pick up a motor assembly before making the correction. After the correction is made, another trip would be required to pick up the rotary assembly. Another advantage of the steerable system is that it provides the ability to hit smaller targets at a reasonable cost. Because a trip is not required to make a course correction, the steerable system can hit a smaller target with less cost. It’s not that a small target can not be hit using rotary assemblies and motor corrections; its that the costs increase significantly as the target gets smaller. Steerable systems are typically used in drilling multi-target directional and horizontal wells. Drilling through a cluster of wells is another good application for a steerable system. Drilling out from under a crowded platform may require building, dropping and turning at various rates over a relatively short distance in order to avoid other wellbores. A steerable system is capable of making all the corrections without tripping. In an environment where the daily operating costs are high, the steerable system can result in significant savings. Just because the industry has the capabil i ty to hit smaller targets does not mean that the targets should be unduly restr icted. The smaller the target, the more expensive it can be to hit . With a

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steerable system, the cost differential isn’t as high as i t would be using rotary assemblies and making motor corrections.

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Chapter

3 DOWNHOLE MUD MOTORS There are two major types of downhole motors powered by mud flow; 1) the turbine, which is basically a centrifugal or axial pump and 2) the positive displacement mud motor (PDM). The principles of operation are shown in Figure 7.1 and the design of the tool are totally different. Turbines were in wide use a number of years ago and are seeing some increased use lately but the PDM is the main workhorse for directional drilling.

Turbine Motor Positive Displacement Motor

Figure 7-1 Motor Types Motor Selection Four configurations of drilling motors provide the broad range of bit speeds and torque outputs required satisfying a multitude of drilling applications. These configurations include: High Speed / Low Torque Medium Speed / Medium Torque Low Speed / High Torque Low Speed / High Torque -Gear Reduced

The high speed drilling motor utilizes a 1:2 lobe power section to produce high speeds and low torque outputs. They are popular choices when drilling with a diamond bit, tri-cone bit drilling in soft formations and directional applications where single shot orientations are being used. The medium speed drilling motor typically utilizes a 4:5 lobe power section to produce medium speeds and medium torque outputs. They are commonly used in most conventional directional and horizontal wells, in diamond bit and coring applications, as well as sidetracking. The low speed drilling motor typically utilizes a 7:8 lobe power section to produce low speeds and high torque outputs. They are used in directional and horizontal wells, medium to hard formation drilling, and PDC bit drilling applications. The gear reduced drilling motor combines a patented gear reduction system with a 1:2 lobe high speed power section. This system reduces the output speed of the 1:2 lobe power section by a factor of three, and increases the output torque by a factor of three. The result is a drilling motor with similar performance outputs as a low speed drilling motor, but with some significant benefits. The 1:2 lobe power section is more efficient at converting hydraulic power to mechanical power than a multi-lobe power section and also maintains more consistent bit speed as weight on bit is applied. This motor can be used in directional and horizontal wells, hard formation drilling, and PDC bit drilling applications. Some other motor selections are also available including a tandem and modified motor. These variations are described below. Tandem Drilling Motor - The drilling motor utilizes two linked power sections for increased torque capacity. Modified Drilling Motor - The bearing section of the drilling motor has been modified to provide different drilling characteristics (ie. change bit to bend distance, etc.). Components All drilling motors consist of five major assemblies: 1. Dump Sub Assembly 2. Power Section 3. Drive Assembly 4. Adjustable Assembly

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5. Sealed or Mud Lubricated Bearing Section. The gear reduced drilling motor contains an additional section, the gear reducer assembly located within the sealed bearing section. Some other motor manufacturers have bearing sections that are lubricated by the drilling fluid. Dump Sub Assembly As a result of the power section (described below), the drilling motor will seal off the drill string ID from the annulus. In order to prevent wet trips and pressure problems, a dump sub assembly is utilized. The dump sub assembly is a hydraulically actuated valve located at the top of the drilling motor that allows the drill string to fill when running in hole, and drain when tripping out of hole. When the pumps are engaged, the valve automatically closes and directs all drilling fluid flow through the motor. In the event that the dump sub assembly is not required, such as in underbalanced drilling using nitrogen gas or air, it’s effect can be negated by simply replacing the discharge plugs with blank plugs. This allows the motor to be adjusted as necessary, even in the field. Drilling motors 95 mm (3 3/4”) and smaller require the dump sub assembly to be replaced with a special blank sub. Power Section The drilling motor power section is an adaptation of the Moineau type positive displacement hydraulic pump in a reversed application. It essentially converts hydraulic power from the drilling fluid into mechanical power to drive the bit. The power section is comprised of two components; the stator and the rotor. The stator consists of a steel tube that contains a bonded elastomer insert with a lobed, helical pattern bore through the centre. The rotor is a lobed, helical steel rod. When the rotor is installed into the stator, the combination of the helical shapes and lobes form sealed cavities between the two components. When drilling fluid is forced through the power section, the pressure drop across the cavities will cause the rotor to turn inside the stator. This is how the drilling motor is powered. It is the pattern of the lobes and the length of the helix that dictate what output characteristics will be developed by the power section. By the nature of the design, the stator always has one more lobe than the rotor. The illustrations in Figure 7-2 show a 1:2 lobe cross-section, a 4:5 lobe cross-section and a 7:8 lobe cross-section. Generally, as the lobe ratio is increased, the speed of rotation is decreased.

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Figure 7-2: Cross-sections of the most common power section lobe configurations The second control on power section output characteristics is length. A stage is defined as a full helical rotation of the lobed stator. Therefore, power sections may be classified in stages. A four stage power section contains one more full rotation to the stator elastomer, when compared to a three stage. With more stages, the power section is capable of greater overall pressure differential, which in turn provides more torque to the rotor. As mentioned above, these two design characteristics can be used to control the output characteristics of any size power section. This allows for the modular design of drilling motors making it possible to simply replace power sections when different output characteristics are required. In addition, the variation of dimensions and materials will allow for specialized drilling conditions. With increased temperatures, or certain drilling fluids, the stator elastomer will expand and form a tighter seal onto the rotor and create more of an interference fit, which may result in stator elastomer damage. Special stator materials or interference fit can be requested for these conditions. Drive Assembly Due to the design nature of the power section, there is an eccentric rotation of the rotor inside of the stator. To compensate for this eccentric motion and convert it to a purely concentric rotation drilling motors utilize a high strength jointed drive assembly. The drive assembly consists of a drive shaft with a sealed and lubricated drive joint located at each end. The drive joints are designed to withstand the high torque values delivered by the power section while creating minimal stress through the drive assembly components for extended life and increased reliability. The drive assembly also provides a point in the drive line that will compensate for the bend in the drilling motor required for directional control.

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Adjustable Assembly Most drilling motors today are supplied with a surface adjustable assembly. The adjustable assembly can be set from zero to three degrees in varying increments in the field. This durable design results in wide range of potential build rates used in directional, horizontal and re-entry wells. Also, to minimize the wear to the adjustable components, wear pads are normally located directly above and below the adjustable bend. Sealed or Mud Lubricated Bearing Section The bearing section contains the radial and thrust bearings and bushings. They transmit the axial and radial loads from the bit to the drill string while providing a drive line that allows the power section to rotate the bit. The bearing section may utilize sealed, oil filled, and pressure compensated or mud lubricated assemblies. With a sealed assembly the bearings are not subjected to drilling fluid and should provide extended, reliable operation with minimal wear. As no drilling fluid is used to lubricate the drilling motor bearings, all fluid can be directed to the bit for maximized hydraulic efficiency. This provides for improved bottom-hole cleaning, resulting in increased penetration rates and longer bit life. The mud lubricated designs typically use tungsten carbide-coated sleeves to provide the radial support. Usually 4% to 10% of the drilling fluid is diverted pass this assembly to cool and lubricate the shaft, radial and thrust bearings. The fluid then exits to the annulus directly above the bit/drive sub. Gear Reducer Assembly An alternative to the type low speed drilling motor is the gear reduced design. It utilizes a gear reduction assembly within the sealed bearing section in combination with a 1:2 lobe power section. This patented design reduces the speed of rotation by a factor of three while increasing the torque by the same multiple. The benefit with this design is increased stability in the bit speed for different differential pressures, and improved hydraulic efficiency out of the power section. Kick Pads Most drilling motors can incorporate wear pads directly above and below the adjustable bend for improved wear resistance. Eccentric kick pads can also be used on most motors ranging from 121 mm (4 3/4’) to 245 mm (9 5/8”) in size. This kick pad is adjustable to match the low side of the motor to increase build rate capabilities. It will also allow lower adjustable settings for similar build rates, thereby reducing radial stresses applied to the bearing assembly, and permit safer rotation of the motor. They can be installed in the field by screwing them onto specially adapted bearing housings.

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Figure 7-3 General motor component layout

Stabilization Bearing housings are also available with two stabilization styles, integral blade and screw-on. The integral blade style is built directly onto the bearing housing and thus cannot be removed in the field. The screw-on style provides the option of installing a threaded stabilizer sleeve onto the drilling motor on the rig floor in a

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matter of minutes. The drilling motor has a thread on the bottom end that is covered with a thread protector sleeve when not required. Both of these styles are optional to a standard bladed bearing housing. Drilling Motor Operation In order to get the best performance and optimum life of drilling motors, the following standard procedures should be followed during operation. Slight variations may be required with changes in drilling conditions and drilling equipment, but attempts should be made to follow these procedures as closely as possible. Assembly Procedure & Surface Check Prior to Running in Hole Most motors are shipped from the shop thoroughly inspected and tested, but some initial checks should be completed prior to running in hole. These surface check procedures should only be used with mud drilling systems. To avoid potential bit, motor, and BOP damage, these preliminary checks should be completed without a bit attached. A thread protector should be installed in the bit box whenever moving the motor, but must be removed before flow testing. 1. The correct lift sub must always be installed and used for moving the tool

on or off the rig floor, and for lifting the tool into position for make-up. Also be sure the connection between the lift sub and the drilling motor is tight. To lift the drilling motor to the rig floor, use a tugger line secured around the lift sub. Pick up the drilling motor with the elevators and set it into the slips of the rotary table. Install the dog collar/safety clamps. The lift sub supplied with the drilling motor should only be used for lifting the drilling motor. The capacity of the lift sub is restricted to the weight of the drilling motor and should not be used for any other purpose. Only apply rig tongs on the identified areas of the drilling motor. All connections marked “NO TONGS” of the drilling motor are torqued in the service shop. Further make-up on the rig floor is not necessary, and if attempted may cause damage.

2. Remove the lift sub and connect the kelly to the drilling motor, remove

the safety clamp, and lift the drilling motor out of the slips. Remove the thread protector from the bit box and inspect the threads for damage.

3. Lower the drilling motor until the dump sub ports are below the rotary

table, yet still visible. CAUTION: The dump sub valve will remain open until there is enough fluid pressure to close it. Therefore, the drilling

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motor should be lowered until the ports are below the rotary table. This will prevent the initial flow of drilling fluid from spraying on the rig floor.

4. Slowly start the pumps and ensure drilling fluid is flowing out of the dump

sub ports. Increase the flow rate until the dump sub ports close, and drilling fluid stops flowing out. Make note of the circulation rate and standpipe pressure. CAUTION: Do not exceed the maximum recommended flow rate for this test.

5. Lift the drilling motor until the bit box becomes visible. It should be

rotating at a slow, constant speed. Listen to the bearing section of the drilling motor for excessive bearing noise, especially if the tool has been used previously without being serviced.

6. Before stopping the pumps, the drilling motor should be lowered below

the rotary table. Ensure that drilling fluid flows out of the dump sub ports after shutting down the pumps. It is possible that the dump sub valve remains closed after this test due to a pressure lock. If this occurs, no drilling fluid will flow out of the ports. To remove the pressure lock, bleed off some stand pipe pressure and the valve will open. The surface check should be as short as possible; since it is merely to ensure that the drilling motor is rotating.

7. After this surface check, the bit should be attached to the motor using a

bit-breaker, while holding the bit box stationary with a rotary tong. Be sure to avoid contacting the end cap directly above the bit box with the tong dies. It is recommended that you never hold the bit box stationary and rotate the drilling motor counter-clockwise, or hold the drilling motor stationary and rotate the bit box clockwise. This could possibly cause the internal drilling motor connections to back off and damage it. Although rotating in the opposite direction will result in drilling fluid to be pushed out the top end, the internal connections will not be at risk of disconnecting. Get wet or damage motor.

8. If the drilling motor has been used previously, an overall inspection should

be completed. Inspect for seal integrity by cleaning the area above the bit box and visually checking for lubricating oil leakage or seal extrusion. General visual inspection of the entire drilling motor should be carried out to check for missing oil plugs, housing damage, or loose connections.

9. Set the adjustable assembly to the desired bend. The instructions for this

procedure depend upon the motor manufacturer and should be adhered to. Ensure the rig tongs can generate the required make-up torque the motor.

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10. If a float sub is used, it should be placed immediately above the drilling motor.

Tripping In Hole Generally, a drill string with a drilling motor can be run into the hole like a standard bottom hole assembly. The drilling motor is rugged, but care should be taken to control travel speed while tripping into the hole. The drill string should be tripped with the blocks unlocked and special care must be taken when passing the B.O.P., casing shoe, liner hanger, bridges and nearing bottom. Tight spots should be traversed by starting the pumps and slowly reaming the drilling motor through. When reaming, the drill string should be periodically rotated to prevent sidetracking. Great care should be taken during these operations. When tripping to extreme depths, or when hole temperatures are high, periodic stops are recommended to break circulation. This prevents bit plugging and aids in cooling the drilling motor, preventing high temperature damage. Fluid should not be circulated through a drilling motor inside casing if a PDC or diamond bit is being used, as this may damage the bit cutters. If a dump sub assembly is not used and the pipe is not being filled while tripping in, the back pressure on the power section will cause the rotor to turn in reverse. This could cause internal connections of the drilling motor to unscrew. Stop and break circulation before putting drilling motor on-bottom. Failure to do so could plug jets and/or damage the drilling motor. Drilling After the assembly has been tripped to the bottom of the hole, drilling motors should be operated in the following manner: 1. With the bit 1-2 meters (3-6 feet) off bottom, start the pumps and slowly

increase the flow rate to that desired for drilling. Do not exceed the maximum rated flow rate for the drilling motor.

2. Make a note of the flow rate and the total pump pressure. Note that the

pressure may exceed the calculated off bottom pressure due to some side load effects between the bit and the hole diameter.

3. After a short cleaning interval, lower the bit carefully to bottom and slowly

increase the weight. Torque can be affected by a dirty, uncirculated hole and the hole should be adequately cleaned prior to orienting the tool. Fill maybe cleaned out of the wellbore by slowly rotating the drilling motor or

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by staging the drilling motor full circle 30o to 45o at a time. This prevents ledge buildup and side tracking.

4. Orient the drill string as desired and slowly apply further weight onto the

bit. Pump pressure will rise as the weight on bit is increased. Record the change in system pressure between the off bottom and on bottom values. This will be the differential pressure. Try to drill with steady pump pressure by keeping a steady flow rate and constant weight on bit.

Adding weight on bit will cause both the differential pressure and torque to increase. Similarly, reducing weight on bit will reduce both the differential pressure and the torque. Therefore, the rig pressure gauge enables the operator to monitor how the drilling motor is performing, as well as a weight on bit indicator. Applying excessive weight on bit may cause damage to the on-bottom thrust bearings. Similarly, applying excessive tension while stuck may cause damage to the off-bottom thrust bearings. Refer to the manufacturer specifications for the recommended maximum loads for these conditions. Optimum differential pressure can be determined by monitoring motor performance, penetration rate, and drilling requirements. Also, maintaining a constant weight on bit and differential pressure assists in controlling orientation of the drill string.

Reactive Torque Drilling motors drive the bit with a right-hand (clockwise) rotation. As weight is added to the bit, reactive torque acting on the drilling motor housing is developed. This left-hand (counter-clockwise) torque is transferred to the drill string and may cause the joints above the motor to tighten. Reactions of this type increase with larger weight on bit values and reach a maximum when the motor stalls. This reactive torque also affects the orientation of the motor when it is used in directional drilling applications. Therefore, this reactive torque must be taken into account when orienting the drilling motor from the surface in the desired direction. As a rule-of-thumb 4 ½” drill pipe will turn 10o for every 300m (1,000’). Determining the amount of torque generated by the motor and using drill pipe twist tables can also produce a rough determination of the torsional angle of the drill string. By measuring the on-bottom and off-bottom pressure, the differential pressure can be determined. With this value use the torque performance charts for the motor to determine the approximate downhole torque generated. Utilizing the following drill string twist table will estimate the amount of reactive torque.

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3 ½” – 13.30 lb/ft drill pipe 19 degrees per 100 N.m torque per 1000m of hole 8 ½ degrees per 100 ft-lb torque per 1000 ft of hole 3 ½” – 15.50 lb/ft drill pipe 17 degrees per 100 N.m torque per 1000m of hole 7 ½ degrees per 100 ft-lb torque per 1000 ft of hole 4 ½” – 16.60 lb/ft drill pipe 7 ½ degrees per 100 N.m torque per 1000m of hole 3 1/3 degrees per 100 ft-lb torque per 1000 ft of hole 5” – 19.50 lb/ft drill pipe 6 degrees per 100 N.m torque per 1000m of hole 2 5/8 degrees per 100 ft-lb torque per 1000 ft of hole Example: 159mm high speed motor with an applied differential pressure of 2000 KPa produces a torque of 720 N-m. We are drilling at a depth of 800m with 4 ½” drill pipe. Potential reactive torque is 800/1000 x 720/100 x 7 = 40 degrees Critical Rotary Speed Motor sections are available in a number of configurations. These different designs are identified by the number of lobes on the rotor and cavities in the stator. For example a 4/5 power section has 4 lobes and 5 cavities. With every rotation made by the rotor, there are eccentric motions about the radius of the rotor equal to the number of lobes. So a 4/5 power section would go through 4 eccentric movements for every rotation. In all multi-lobed tools, regardless of size or configuration, the critical tolerance for this eccentric movement is 1000 cycles per minute. Exceeding this critical tolerance sets up three degenerative cycles in the tool: • The high oscillation factor combined with the inherent friction of the rotor

contacting the stator results in excessive heat generation in the stator molding. Oscillations above 1000 cycles per minute may result in temperatures sufficient to cause hysteretic failure of the stator molding (elastomer doesn’t return to original shape).

• Vibration frequencies are introduced by the high oscillation rates that can

contribute to mechanical failures in motor components other than the rotor and stator. It is not known if these vibrations are harmonic or random however, it is logical to assume that some degree of resonance would be present in the frequency.

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• The centrifugal force of the rotor in an “over-speed” condition combined with the diminished compressive strength of a stator in hysteretic failure, accentuate the eccentric motion (run out) of the rotor. The result is an expontenial increase in the degenerative effects of the condition.

Drilling Motor Stall Stalling usually occurs when the application of excessive weight on bit or hole sloughing stops the bit from rotating and the power section of the drilling motor is not capable of providing enough torque to power through. This is indicated by a sudden sharp increase in pump pressure. This pressure increase is developed because the rotor is no longer able to rotate inside the stator, forming a long seal between the two. If circulation is continued, the drilling fluid forces it’s way through the power section by deflecting the stator rubber. Drilling fluid will still circulate through the motor, but the bit will not turn. Operating in this state will erode and possibly chunk the stator in a very short period of time, resulting in extensive damage. It is very important to avoid this operating condition. When stalling occurs, corrective action must be taken immediately. Any rotary application should be stopped and built up drill string torque released. Then the weight on bit can be reduced allowing the drill bit to come loose and the drilling motor to turn freely. If the pump pressure is still high, the pumps should then be turned off. Once again, failure to do this will result in the stator eroding until the drilling motor is inoperable. Other conditions can be occurring downhole that indicate the motor is stalling. On underbalanced wells when the motor is being supplied with too low a combined equivalent flow rate will not drill (see later discussion on two-phase flow tests). Under gauge bits or a badly worn heel row of cutters on the bit can also make the motor stall. Bit Conditions The bit speeds developed when drilling with a drilling motor are normally higher than in conventional rotary drilling. This application tends to accelerate bit wear. When drilling with a drilling motor and simultaneously rotating the drill string, it is important to avoid locking up the bit and over running the drilling motor with the rotary table. A locked bit will impart a sudden torque increase in the drilling motor which can be detected by a sudden, sharp increase in standpipe pressure. Small pressure fluctuations can also indicate the onset of bit failure.

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Rotating the Drilling Motor For directional control, we often rotate a drilling motor which has the adjustable assembly set for a deviation angle. It has been found that rotating the drilling motor set at bends greater than 1.8 degrees may fatigue the housings of the drilling motor to a point where a fatigue crack is initiated, and fracture occurs. Additionally, rotation of motors with settings greater than 1.83 degrees place high radial stresses on the bearing section which may initiate premature failure. Most motor manufacturers have a policy that drilling motors set at greater than 1.83 degrees not be rotated. The extent of the damage is very dependent upon the drilling conditions and formations being drilled. Although fractures from fatigue due to rotating over 1.83 degrees are a relatively rare occurrence, a risk is still being taken when it is done. The operator of the drilling motor must be aware of this risk. It is also recommended that the speed of rotation not exceed 50 RPM. If this value is exceeded, excessive cyclic loads would occur to the drilling motor housings and possibly causing pre-mature fatigue problems. Tripping Out Prior to tripping out when drilling with conventional mud, it is recommended that the fluid be circulated for at least one “bottoms-up’ time to ensure that the wellbore has been cleaned thoroughly. The tripping out procedures for a drilling motor is basically the same as those for tripping in. Taking care when pulling the drilling motor through tight spots, liner hangers, casing, casing shoes, and the B.O.P. is necessary to minimize possible damage to both the drilling motor and the wellhead components. Rotating may also be done to assist with the removal of the drill string. The dump sub valve will allow the drill string to be emptied automatically when tripping. Although the drill string will drain when tripping out, the drilling motor itself may not. Once the drilling motor is at surface, rotating the bit box in a counter-clockwise direction will naturally drain the drilling motor through the top. This is recommended before laying down the motor since aggressive drilling fluids can deteriorate the elastomer stator and seals. When possibly, fresh water should also be flushed through to ensure thorough cleaning of the drilling motor. Also, clean the bit box area with clean water and install a thread protector into the box connection. Rotating the bit box in a clockwise direction will naturally drain the drilling motor through the bottom, but one of the internal connections could break and unscrew. For this reason, it is not recommended to rotate it in this manner.

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Surface Checks After Running in Hole Before laying down a drilling motor, it should be inspected in the event that it is required again before servicing. Listen for indications of internal damage when draining the drilling motor. Inspect the seal area between the bit box and the bearing section for lubricating oil leakage, and check the entire drilling motor for loose or missing pressure plugs. If there are any concerns with the drilling motor, it should be laid down for servicing. Drilling Fluids Most drilling motors are designed to operate effectively with practically all types of drilling fluids. In fact, the stator or power-section of most PDM’s are supplied by the same one or two manufacturers with the same general elastomer type. Successful runs have been achieved with fresh or salt water, oil based fluids, fluids with additives for viscosity control or lost circulation, and with nitrogen gas. However, some consideration should be taken when selecting a drilling fluid, as elastomer components of the drilling motor are susceptible to pre-mature wear when exposed to certain fluids especially under higher temperatures. Hydrocarbon based drilling fluids can be very harmful to elastomers. A measure of this aggressiveness is called the Aniline Point. The Aniline Point is the temperature at which equal amounts of the hydrocarbon and aniline become miscible. This temperature is an indication of the percent of light ends (aromatics) present in the hydrocarbon. It is recommended that the aniline point of any drilling fluid not be lower than 70 to 94.5o C (158 to 200o F), depending upon stator manufacturer. The lower the aniline point the higher the percentage of elastomer damaging “high-ends” in the hydrocarbon fluid. Also, the operating temperature of the drilling fluid should be lower than the aniline point. Operating outside these parameters tends to excessively swell elastomers and cause premature wear, thus reducing the performance of the motor. In cases where hydrocarbon based fluids are used it is recommended that stators material or designs that account for the elastomer swelling be used (HSN or changed interference of stator/rotor. Drilling fluids with high chloride content can cause significant damage to internal components (chrome plated rotors). When these components become damaged, the drilling motor’s performance is dramatically reduced. Lost circulation materials can be used safely with drilling motors but care must be taken to add the material slowly to avoid plugging the system. (Good rule of thumb is no more than 2.5 lbs/barrel). If coarse lost circulation material is required a circulating sub should be installed above the motor assembly to by-pass the motor.

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The percentage of solids should be kept to a minimum. Large amounts of abrasive solids in the drilling fluid will dramatically increase the wear on a stator. It is recommended that the sand content be kept below 2% for an acceptable operational life. A solids content greater than 5% will shorten rotor and stator life considerably. For the above reasons, it is extremely important to flush the drilling motor with fresh water before laying it down, especially when working with the types of drilling fluids described above. Failure to do so will allow the drilling fluid to further seriously deteriorate components to the drilling motor long after it has been operated. The solids can also settle out in the motor and in the worse case lock the motor up. Temperature Limits The temperature limits of drilling motors again depend on the effect of different fluids and temperatures on the components made of elastomers. Generally, standard drilling motors are rated for temperatures up to 105o C (219o F). At temperatures above this, the performance characteristics of elastomers are changed, resulting in reduced life expectancy. When exposed to higher temperatures, the elastomers swell, creating more interference than desired, wearing the parts out prematurely. The strength of the elastomers is also affected. When drilling in wells with temperatures greater than 121o C (250o F) it is important to maintain circulation to minimize the temperature the stator liner is subjected to. To compensate for these elastomer changes, special materials and special sizes of components are used. This results in drilling motors that are specifically assembled for high temperatures. These special order drilling motors may be operated in temperatures up to 150o C (300o F) and higher. The rubber in the stator is specially selected for more clearance at higher temperatures to minimize interference. Therefore, at lower temperatures, the stator elastomer will not seal adequately on the rotor and fluid bypass will occur. Therefore, it is important that the drilling motor be used in the conditions it is designed for in order to operate as required. Hydraulics The use of a PDM in the drill string changes the hydraulic calculations and should be considered. Various factors have to be taken into account. These are: 1. Range of flow rates allowable: Each size and type of PDM is designed to take a certain range of volumes of fluid.

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2. No-load Pressure Loss: When mud is pumped through a mud motor which is turning freely off-bottom (i.e. doing no work) a certain pressure loss is needed to overcome the rotor/stator friction forces and cause the motor to turn. This pressure loss and motor RPM are proportional to flow rate. Their values are known for each size and type of PDM. The no-load pressure loss is usually no greater than 100 psi. 3. Pressure Drop across the Motor: As the bit touches bottom and effective WOB is applied, pump pressure increases. This increase in pressure is normally called the motor differential pressure. Motor torque increases in direct proportion to the increase in differential pressure. This differential pressure is required to pump a given volume of mud through the motor to perform useful work. For a multi-lobe motor, it can be 500 psi or even more. 4. Stall-out Pressure: There is a maximum recommended value of motor differential pressure. At this point, the optimum torque is produced by the motor. If the effective WOB is increased beyond this point, pump pressure increases further. The pressure across the motor increases to a point where the lining of the stator is deformed. The rotor/stator seal is broken and the mud flows straight through without turning the bit (blow-by or slippage). The pump pressure reading jumps sharply and does not vary as additional WOB is applied. This is known as stall-out condition. Studies have shown that the power output curve is a parabola and not a smooth upward curve, as originally thought. If the PDM is operated at 50%-60% of the maximum allowable motor differential pressure, the same performance should be achieved as when operating at 90% of differential. The former situation is much better however, there is a much larger ‘cushion’ available before stall-out. This should result in significantly longer motor life. The greater the wear on the motor bearings, the easier it is to stall-out the motor. It is useful to deliberately stall out the PDM briefly on reaching bottom. It tells the directional driller what the stall-out pressure is. He may want to operate the motor at about 50% of stall-out differential pressure. In any case, he must stay within the PDM design specifications. It is obvious that, if the pump pressure while drilling normally with a mud motor is close to the rig’s maximum, stalling of the PDM may lead to tripping of the ‘pop-off valve’. This should be taken into account in designing the hydraulics program. Rotor Nozzle: Most multi-lobe motors have a hollow rotor. This can be blanked off or jetted with a jet nozzle. When the standard performance range for the motor matches the drilling requirements, a blanking plug is normally fitted.

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The selection of the rotor nozzle is critical. Excessive bypass will lead to a substantial drop in motor performance and, consequently, drilling efficiency. If a rotor nozzle is used at lower flow rates, the power of the motor will be greatly reduced. From the above, it is clear that careful planning of the PDM hydraulics program is required.

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Figure 7-3 Example of a typical motor performance chart for a 1:2 lobe motor.

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Figure 7-4 Example of a typical motor performance chart for a 4:5 lobe motor.

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Chapter

4

SURVEY CALCULATIONS Directional surveys are taken at specific intervals to determine the position of the wellbore relative to its surface location. The surveys are converted into a North-South, East-West and true vertical depth using one of several calculation methods. The co-ordinates are then plotted in both a vertical and horizontal plane. By plotting the survey data, the directional personnel can then compare the progress of the well to the planned wellpath and make changes as required to reach the desired target. There are several methods that can be used to calculate the survey data, however, some are more accurate than others. Some of the most common methods are:

• Tangential

• Balanced Tangential

• Average Angle

• Radius of Curvature and

• Minimum Curvature The tangential method is the least accurate with the radius of curvature and minimum curvature methods being the most accurate. The industry typically uses minimum curvature for these calculations but may use radius of curvature for planning.

Tangential At one time the tangential method was the most widely used because it was the easiest. The equations are relatively simple, and the calculations can be performed easily in the field. Unfortunately, the tangential method is the least accurate method and results in errors greater than all the other methods. The tangential method should not be used to calculate directional surveys. It is only presented here to prove a point. The tangential method assumes the wellbore course is tangential to the lower survey station, and the wellbore course is a straight line. Because of the straight-line assumption, the tangential method yields a larger value of horizontal departure and a smaller value of vertical displacement when the inclination is increasing. This is graphically represented in Figure 3-1. Line AI2 is the assumed wellbore course. The dashed line AB is the change in true vertical depth and the dashed line BI2 is the departure in the horizontal direction. The opposite is true when the

inclination is decreasing. With the tangential method, the greater the build or drop rate, the greater the error. Also, the distance between surveys has an effect on the quantity of the error. If survey intervals were 10 feet or less, the error would be acceptable. The added expense of surveying every 10 feet prohibits using the tangential method for calculating the wellbore course especially when more accurate methods are available. Tangential Equations ∆TVD = ∆MD X CosI2 ∆North = ∆MD X SinI2 X CosA2 ∆East = ∆MD X SinI2 X SinA2

Figure 3-1: Illustration of Tangential Calculation Method

Balanced Tangential The balanced tangential method is similar to the tangential method in that the tangent to the angle determines the wellbore course. The difference between the two methods is the balanced tangential uses both the upper and lower surveys stations. The top half of the wellbore course is approximated by the upper inclination line I1A in Figure 3-2 and the lower half of the wellbore course is approximated by the lower inclination line AI2. The azimuth is approximated in the same manner. Both the upper and lower portions of the assumed wellbore course are in error, but the errors are opposite and will nearly cancel each other. Therefore, the balanced tangential method is accurate enough for field applications. The balanced tangential equations are more difficult to perform and are more likely to result in an error because of mechanical mistakes while making the calculations.

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The North-South, East-West coordinates are determined by assuming the horizontal departure of the course length is in the same direction as the azimuth recorded at the lower survey station, but this assumption is wrong. The actual wellbore course will be a function of the upper and lower survey stations. Therefore, the tangential method results in an additional error because an error already exists due to the method used to calculate the horizontal departure. The error is compounded when the North-South, East-West coordinates are calculated.

Figure 3-2: Illustration of Balanced Tangential Calculation Method Balanced Tangential Equations

∆TVD = ∆MD X (CosI1 +CosI2) 2

∆North = ∆MD X [(SinI1 X CosA1) + (SinI2 X CosA2)] 2

∆East = ∆MD X [(SinI1 X SinA1) + (SinI2 X SinA2)] 2 Average Angle When using the average angle method, the inclination and azimuth at the lower and upper survey stations are mathematically averaged, and then the wellbore course is assumed to be tangential to the average inclination and azimuth. The calculations are very similar to the tangential method and the results are as

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accurate as the balanced tangential method. Since the average angle method is both fairly accurate and easy to calculate, it is the method that can be used in the field if a programmable calculator or computer is not available. The error will be small and well within the accuracy needed in the field provided the distance between surveys is not too great. The average angle method is graphically illustrated in Figure 3-3.

Figure 3-3: Illustration of the Average Angle Calculation Method Average Angle Equations ∆TVD = ∆MD X Cos[(I1 + I2)/2] ∆North = ∆MD X Sin[(I1 + I2)/2] X Cos[(A1 + A2)/2] ∆East = ∆MD X Sin[(I1 + I2)/2] X Sin[(A1 + A2)/2] Radius of Curvature The radius of curvature method is currently considered to be one of the most accurate methods available. The method assumes the wellbore course is a smooth curve between the upper and lower survey stations. The curvature of the arc is determined by the survey inclinations and azimuths at the upper and lower survey stations as shown in Figure 3-4. The length of the arc between I1 and I2 is the measured depth between surveys. In the previous methods, the wellbore course was assumed to be one or two straight lines between the upper and lower survey points. The curvature of the wellbore course assumed by the radius of curvature method will more closely approximate the actual well; therefore, it is more accurate. Unfortunately, the equations are complicated and are not easily calculated in the field without a programmable calculator or computer.

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Figure 3-4: Illustration of Radius of Curvature Calculation Method. A closer inspection of the radius of curvature equations show that if the inclination or azimuth are equal for both survey points, a division by zero will result in an error. In this case, the minimum curvature or average angle methods can be used to make the calculations. It is also possible to add a small number (such as 1 x 10-4) to either survey point. The resulting error will be insignificant. Generally, the radius of curvature calculations is used when planning a well. Using one of the three previous methods to plan a well will result in substantial errors when calculating over long intervals Radius of Curvature Equations ∆TVD = (180) X (∆MD) X (SinI2 +SinI1) π X (I2 – I1) ∆North = (180)2 X (∆MD) X (CosI1 – CosI2) X (SinA2 – SinA1)] π2 X (I2 – I1) X (A2 – A1) ∆East = (180)2 X (∆MD) X (CosI1 – CosI2) X (CosA1 – CosA2)] π2 X (I2 – I1) X (A2 – A1) Minimum Curvature The minimum curvature method is similar to the radius of curvature method in that it assumes that the wellbore is a curved path between the two survey points. The minimum curvature method uses the same equations as the balanced tangential multiplied by a ratio factor, which is defined by the curvature of the wellbore. Therefore, the minimum curvature provides a more accurate method of determining the position of the wellbore. Like the radius of curvature, the equations are more complicated and not easily calculated in the field without the aid of a programmable calculator or computer.

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Figure 3-5: Illustration of the Minimum Curvature Calculations. The balanced tangential calculations assume the wellbore course is along the line 11A + AI2, see Figure 3-5. The calculation of the ratio factor changes the wellbore course to I1B + BI2 which is the arc of the angle B. This is mathematically equivalent to the radius of curvature for a change in inclination only. So long as there are no changes in the wellbore azimuth, the radius of curvature and minimum curvature equations will yield the same results. If there is a change in the azimuth, there can be a difference in the calculations. The minimum curvature calculations assume a curvature that is the shortest path for the wellbore to incorporate both surveys. At low inclinations with large changes in azimuth, the shortest path may also involve dropping inclination as well as turning. The minimum curvature equations do not treat the change in inclination and azimuth separately. The tangential and average angle methods treat the inclination and azimuth separately. Therefore, larger horizontal displacements will be calculated. The radius of curvature method assumes the well must stay within the survey inclinations and will also yield a larger horizontal displacement though not as large as the tangential and average angle. The minimum curvature equations are more complex than the radius of curvature equations but are more tolerant. Minimum curvature has no problem with the change in azimuth or inclination being equal to zero. When the wellbore changes from the northeast quadrant to the northwest quadrant, no adjustments have to be made. The radius of curvature method requires adjustments. If the previous survey azimuth is 10o and the next survey is 355o, the well walked left 15o. The radius of curvature equations assume the well walked right 345o which is not true. One of the two survey azimuths must be changed. The lower survey can be

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changed from 355o to –5o, then the radius of curvature will calculate the correct coordinates. Minimum Curvature Equations ∆TVD = ∆MD X [(CosI1 +CosI2) X FC] 2 ∆North = ∆MD X [(SinI2 X CosA2) + (SinI1 X CosA1)] X FC 2 ∆East = ∆MD X [(SinI2 X SinA2) + (SinI1 X SinA1)] X FC 2 D1 = Cos(I2 – I1) – {SinI2 X SinI1 X [1-Cos(A2 – A1)]} D2 = Tan-1 X SQRT [(1/D12) – 1] FC = 2/D2 X Tan (D2/2) Note: Inclination and azimuth values must be in radians only. Table 3-1 shows survey data used to illustrate the difference in the calculation methods. Table 3-2 and 3-3 is a summary of the results. Table 3-1 Surveys for Comparison Calculations

MD (ft) Inclination (degrees)

Azimuth (degrees)

MD (ft) Inclination (degrees)

Azimuth (degrees)

0 0 0 2900 30.60 22.00 1000 0 0 3000 30.50 22.50 1100 3.00 21.70 3100 30.40 23.90 1200 6.00 26.50 3200 30.00 24.50 1300 9.00 23.30 3300 30.20 24.90 1400 12.00 20.30 3400 31.00 25.70 1500 15.00 23.30 3500 31.10 25.50 1600 18.00 23.90 3600 32.00 24.40 1700 21.00 24.40 3700 30.80 24.00 1800 24.00 23.40 3800 30.60 22.30 1900 27.00 23.70 3900 31.20 21.70 2000 30.00 23.30 4000 30.80 20.80 2100 30.20 22.80 4100 30.00 20.80 2200 30.40 22.50 4200 29.70 19.80 2300 30.30 22.10 4300 29.80 20.80 2400 30.60 22.40 4400 29.50 21.10 2500 31.00 22.50 4500 29.20 20.80 2600 31.20 21.60 4600 29.00 20.60 2700 30.70 20.80 4700 28.70 21.40 2800 31.40 20.90 4800 28.50 21.20

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Table 3-2 Comparison of Survey Calculation Methods At Total Depth

Method TVD (ft) North (ft) East (ft)

Tangential 4364.40 1565.23 648.40 Balanced Tangential 4370.46 1542.98 639.77 Average Angle 4370.80 1543.28 639.32 Radius of Curvature 4370.69 1543.22 639.30 Minimum Curvature 4370.70 1543.05 639.80 Table 3-3 Relative Difference in Survey Calculation Methods at Total Depth

Method ∆ TVD ∆ North ∆ East

Tangential -6.30 +22.18 +8.60 Balanced Tangential -0.24 -0.07 -0.03 Average Angle +0.10 +0.23 -0.48 Radius of Curvature -0.01 +0.17 -0.50 Minimum Curvature +0.00 +0.00 +0.00 Closure And Direction The line of closure is defined as a straight line, in a horizontal plane containing the last station of the survey, drawn from the projected location to the last survey station of the survey. Simply stated, the closure is the shortest distance between the surface location and the horizontal projection of the last survey point. The closure is always a straight line since that represents the shortest distance between two points. When defining closure, the direction or azimuth must also be given. Without indicating direction, the bottom hole location projected in a horizontal plane could be anywhere along the circumference of a circle defined by a radius equal to the closure distance. The azimuth and closure distance accurately specifies the bottom hole location relation to the surface location. Closure Direction = Tan–1 (East/North) Closure Distance = SQRT [(North)2 + (East)2] Vertical Section The vertical section is the horizontal length of a projection of the borehole onto a specific vertical plane (Azvs) and scaled with vertical depth. When the path of a

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wellbore is plotted, the vertical section is plotted versus TVD. The closure distance cannot be plotted accurately because the plane of closure (closure direction - Azcl) can change between surveys. The vertical plot of a wellbore is in one specific plane. The closure distance and vertical section are only equal when the closure direction is the same as the plane of the vertical section. Vertical Section = Cos(Azvs – Azcl) X (Closure Distance)

Figure 3-6 Graphical representation of Closure and Vertical Section

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Chapter

5 PLANNING A DIRECTIONAL WELL When preparing to drill a vertical or directional well, all operational components of the process are reviewed, optimized and included into a drilling program. The surface location is scouted to determine the best site that will allow for any natural drift, provide suitable access for drilling rig, service rig, production facilities and can be constructed for a reasonable cost. A casing program is prepared to provide 1) adequate well control, 2) prevent water table contamination, 3) maintain wellbore integrity, 4) plan for varying formation fracture gradients, and 5) provide hydraulic isolation of various producing zones. Mud programs are developed to provide good wellbore cleaning, reasonable filter cake development and minimal formation damage. Cement programs are required to provide good hydraulic isolation and casing support given the bottom hole temperature and pressure. Since the highest possible rate of penetration possible is desired, considerable time is spent preparing an effective bit program to optimally drill the well. Previous wells drilled in the area are reviewed, to determine any potential drilling problems. Finally a proper BHA and drill string design is prepared to provide sufficient design safety parameters. A directional drilling company will review most of these same components or ask the operator what he is selecting and apply it to the well profile and equipment limitations. For example the drilling fluid needs to be compatible with the Measurement While Drilling (MWD) equipment and motors. With their area knowledge it will also be reviewed for hole cleaning capability for high inclination wells. A drilling motor is selected that will provide optimum performance for the planned hydraulics or modifications are recommended. A bottom hole assembly (BHA) and drill string design is suggested that will allow the best ROP for the different drilling conditions (rotating versus orient or slide drilling). In some cases the desired well path cannot be optimally drilled with the drill string currently available on the rig and changes are recommended. Bit selection for a standard vertical well may not be suitable for the planned directional well path. Although a particular PDC bit provides the best ROP for the area, it may not provide the directional control needed. Also special drilling motors may be required to provide sufficient horsepower. If the project involves sidetracking of the horizontal legs special diamond sidetrack bits may be required.

Area formation integrity knowledge while it is being directional drilled through (sloughing, loss of inclination, inability to control direction, potential for differential sticking to name a few ) is extremely important to minimize drilling time or potential problems. Let’s assume a directional plan with a very tight target size is prepared that kicks off very low in a formation that has a history of erratic build rates. Several things could happen in this scenario:

• Planned build rates are attained and target reached

• Very aggressive oriented drilling operations are required (full single slides) and the ROP is half of normal

• Trips are required to change the motor setting (increase or decrease the adjustable housing setting)

• Erratic doglegs are created that may cause problems later when running casing

• Target is missed and well must be plugged back and sidetracked When permitted, a directional company also reviews the well pad layout and provides their recommendations to reduce directional costs for multiple well pads. When they are involved with a project from the start and are aware of future re-entries, multi-laterals, sidetracks and production requirements a more optimally tuned well path can be designed. Profiles of Directional Wells In order to reach the required downhole target co-ordinates there are several main profiles used; 1) slant, 2) build and hold, 3) s-curve, 4) extended reach and 5) horizontal. These profiles may also combined as required to reach the target or targets. Slant Specialized drilling and completion rigs are used on these profiles. The well is spudded at an angle greater than 0o and less than or equal to 45o. This profile is typically used on shallow wells when trying to reach a target with a horizontal displacement that is 50% or more of the TVD. It is also used on multiple well pad sites to drain a large area with several wells radiating out from a central site. The most common pattern is the Star shaped layout that has let as many as 27 wells be drilled from one site. The savings on reduced lease requirements and production facilities can be quite substantial.

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Build and hold This is the main profile for most directional wells. It includes a build section to a predetermined terminal angle that is then held through the target and in some cases to total depth. In most cases once the target has been reached or there is no risk of missing the target the directional tools are released and the remainder of the hole is rotary drilled allowing the well path to follow a natural direction. The inclination is usually 15o or better S-Curve The S-curve has a build, hold and drop section that may or may not drop the inclination down to 0 degrees. This shape is for the following reasons:

• Hit multiple targets at the same horizontal displacement

• Reach a desired horizontal displacement but allow drilling through severely faulted or troublesome formations in a near vertical mode

• Avoid local faulted regions

• Minimize the inclination through a zone that will be frac’d during the

completion phase. Extended Reach A modified or complex build and hold that typically has an inclination between 60 and 80 degrees with a reach that is magnitudes of the TVD (between 4 and 7 times the vertical depth). Most common location for these wells is off-shore from a central drilling platform. Horizontal with Single or Multiple Legs A profile that consists of a build section to 90o +/- with a horizontal section through the same reservoir. Additional laterals can be drilled from the first lateral into different regions or into different zones. Information Required In order to plan a directional well that can be drilled safely and be cost effective, a great deal of information is needed by the directional company. By reviewing the information and requirements the best plan can be selected that will meet everyone’s needs and produce a usable wellbore. The planning of a directional well can involve multiple disciplines and their needs must be successfully

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combined into the wellpath proposal. Obviously not all wells require input from each division but the more complex the well is the more important a synergy is developed within the departments and with the directional drilling company. Geology Interaction with the geologists is of prime importance to understand any limitations in the particular zone of interest. Although all information collected is important to the drilling operation communication at this stage can be the make or break point of the well.

• Lithology being drilled through (sand, shales, sloughing tendencies, coals, salt, medium hard formations with hard or soft stringers, marker zones)

• Location of water or gas top

• Level of geological control

• Type of target the geologist is expecting (channel sand, pinnacle reef, a

seismic irregularity, exploration or infill drill)

• Geological structures that will be drilled through or into (dip, faults, unconsolidated shales)

• Regulatory issues (oil or gas target boundaries, wellbore clearance from

existing wells, location of final total depth)

• Type of Well (Oil or Gas)

• Future sidetrack or re-entry potentials Completion and Production

This group is often missed and may result in a costly error if their needs are not considered in the planning phase. They usually share some of the planning responsibility with the geology department.

• Location of surface facilities or ability to move existing when infill

drilling on an existing pad

• Type of completion required (frac, pump rods)

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• May specify maximum inclination and dogleg limits based upon log and production requirements

• Enhanced recovery completion requirements

• Wellbore positioning requirements for future drainage/production

plans

• Downhole temperature and pressure Drilling This group usually has control over the main operation and tries to pull all parties together. The overall cost estimation and economic feasibility may also rest in their hands. Consequently, the directional representative usually spends most of their time consulting with the members in this group. Even though the other groups have just as important information, the drilling group typically controls how the well is drilled and will make the final decision on any operational issues that occur.

• Selection of surface location and well centre(s) layout

• Casing size and depths

• Hole size

• Required drilling fluid

• Drilling rig equipment and capability

• Length of time directional services are utilized

• Influences the type of survey equipment and wellpath

• Previous area drilling knowledge and identifies particular problematic areas

Planning Once the information has been collected from the various departments, a directional plan is prepared that meets all the requirements (if possible). A good well planner also tries to incorporate operational issues that contribute to the success of the well and can have a dramatic impact on the length of time required

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for directional equipment. This can be very important on pad layouts for multiple directional wells and can save the operator considerable expenses if properly utilized. Anyone can plan a well to be drilled from point ‘A’ to ‘B’ but it requires operational knowledge to plan a profile that can physically be drilled without unnecessary trips to change assemblies given the hole size and area. The following are few of the general rules-of-thumb when well paths are being prepared:

• Build rates kept at 2 to 3 o/30m for pumping oil wells. In fact most oil wells are planned at this rate unless the horizontal displacement requires higher build rates to reach the target. Typically most operators prefer to keep the actual doglegs less than 8 or 9 o/30m, therefore the plan should be less than 7 o/30m to allow for operational variances.

• The hold portion for build and hold profiles should be at least 50m (150’) to allow for operational adjustments should they have trouble achieving build rates.

• The drop rate for S-curve wells is preferably planned at 1.5 o/30m but

can go as high as 2.5. A key-seat or differential sticking risk could occur with aggressive drop rates in softer formations. Also a minimum 30m (100’) tangent section should be planned in the middle of an S-curve profile to allow for drilling problems or changes in target depths.

• Keep the KOP as low as possible to reduce directional costs and on

pumping oil wells to reduce potential rod/casing wear. KOP must be selected in a competent formation.

• Pick a KOP that has a competent enough formation that will allow the

planned build rate to be achieved.

• On long or extended reach well profiles keep the KOP low to provide a larger vertical portion for applying weight on bit but also keep the build rate low (less than 4 o/30m).

• When planning a well that will use single shot survey equipment make

sure at least two thirds of the build section is completed before drilling into any problem zone. If it cannot be accomplished use higher build rates or place KOP as low as possible in the problem zone an insure a sufficient hold section after terminal angle is reached (100m).

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• In build sections of horizontal wells, plan a soft landing section (lower build rate) for casing point if the required motor setting is greater than 1.8o or severe geological uncertainty exists (target TVD changes greater than 2m).

• Plan for a terminal angle of a minimum 15o since it is easier to hold

inclination and direction.

• Avoid high inclinations through severely faulted, dipping or sloughing formations.

• On horizontal wells be sure to clearly identify any gas or water contact

points and keep sufficient clearance below or above to prevent breakthrough.

• Turn rates in the lateral sections of horizontal wells should be kept at

less than 8 o/30m, especially if the proposed lateral length is long.

• Know what build rates are achievable for the motors being used in a specific hole size. The following rates are for most standard motors.

311mm hole - up to 10+ o/30m (motor with kick pad) 222mm hole – up to 14 o/30m 159mm hole – up to 25 o/30m 121mm hole – up to 35 o/30m

• Keep subsequent sidetracks on horizontal legs at least 20m (60’) apart.

• Where possible don’t start a sidetrack until at least 20m out from

casing point.

• Be sure to identify what profiles will require trips to set motor down before any rotation should occur.

• Assume a dogleg of approximately 14 o/30m will occur coming off a

whipstock.

• Identify all wells within 30m of proposed well path and conduct anti-collision check. On long horizontal sections this should be extended to 100m away.

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• Where possible design a wellpath that will minimize the percentage of hole drilled in the oriented mode. Typically the ROP of these sections are one half or less of the rotary ROP.

Torque And Drag One of the most significant problems associated with extended reach or horizontal drilling is torque and drag which is caused by the friction between the drill string and the hole. The magnitude of the torque and drag is determined by the magnitude with which the pipe contacts the hole wall and the friction coefficient between the wall and pipe. Figure 8-1 shows the forces associated with an object on an incline. The weight component along the axis of the incline (w SinΦ) would be the force required to move the object in a frictionless environment.

Figure 8-1 Forces on an inclined plane Unfortunately, friction is always present and will contribute to the force required to move the object. The friction force is equal to the normal force times the friction coefficient. Therefore, the force required to pull the pipe from the hole is: T= -W SinΦ + µ WCosΦ

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Where: T = Axial Tension W = Buoyed Weight of Pipe

µ = Friction coefficient Φ = Angle of incline

The force required to push the pipe from the hole is: T= -W SinΦ - µ WCosΦ The friction coefficient depends upon the type of drilling fluid in the wellbore and the roughness of the wellbore walls. Cased hole should have a lower friction coefficient than open hole. Untreated water based muds will have a higher friction coefficient than oil based muds. Friction coefficients have been reported to range from 0.1 to 0.3 for oil based muds and 0.2 to 0.4 for water based muds. When hole curvature is considered, an additional force is added to the normal force. Pipe placed in a curved wellbore under tension will exert a force proportional to the tension and rate of curvature change. Buckling of the drill string while tripping into the wellbore causes an additional drag force. The critical buckling load is a function of the inclination, pipe size and radial clearance. Once the compressive forces in the drill string exceed the critical buckling load, an additional normal force is imposed on the drill string increasing the drag force in sections of the wellbore. The torque in the drill string is determined by the normal force times the friction coefficient and is the force resisting rotation of the drill string. The torque and drag will increase as the tension and dogleg severity increases. In normal directional wells, the drag is the main concern but as depth, inclination, build rate and length of hold section increase the torque can become a major concern. Torque will also limit the tension capability of drill pipe when combined with tensile loads. There are three main ways to reduce the drag in the well; 1) change friction coefficient by changing mud system, 2) change the directional profile or 3) change the string weight or tension. Since the drag is proportional to the coefficient of friction, finding a way to reduce this value by half will halve the drag. Changing the directional profile can have significant benefits but if you’ve already drilled a good portion of the profile wiper/reamer trips to smooth out any ledges or doglegs in the build section can have significant benefit. Replacing drill collars with hevi-weight or regular drill pipe can have a significant effect on reducing the tension and normal forces thus drag.

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There are excellent torque and drag models in the market that very accurately predict values for a chosen wellpath. It must be remembered this is just a model and one of its better design uses is for comparison of different profiles with all other factors the same. Another very helpful place to utilize this tool, is while drilling horizontal wells. Large changes between predicted and actual drag values can indicate the hole is not cleaning. These models are also used to effectively design the drill string from the bottom of the well to surface.

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Chapter

6 PLANNING A HORIZONTAL WELL Planning a horizontal wellbore is different from planning a normal directional well. In a normal directional wellbore, the target is usually described in terms of a departure at a certain TVD. The target has tolerances in the horizontal plane (North and East). Unless drilled from a platform or pad, a horizontal wellbore seldom has a target described by the departure. The target is most commonly described by the TVD plus or minus a tolerance. For example, a formation top may be at a true vertical depth of 1200m (3936 feet) and the formation is 6m (19.7’) thick. The placement of a horizontal well in this formation will require the wellbore to be horizontal at a TVD of 1203m (3946 feet), plus or minus 3m. There have been some horizontal wells drilled with a TVD target tolerance of plus or minus 0.5m (1.6 feet) requiring the wellbore to stay within a 1m vertical zone. These tight tolerances can be very expensive to maintain since the ROP will likely have to be controlled and more survey stations will be required to meet these objectives. As you can see, target tolerances for horizontal wellbores are much smaller than typical directional wells. Consequently, they are a little harder to hit and greater care must be exercised in drilling a horizontal wellbore. Data Collection The first step in planning a horizontal wellbore is to gather all the information possible about the well and the formation to be drilled. Available data from offset wells, even vertical wells should be collected. Items of interest are well logs, bit records, mud logs, directional data, daily reports and any other data that might be helpful. Even vertical offset wells can provide valuable information for drilling a horizontal well including target depths. There are few if any horizontal exploratory wells therefore, offset well information is always available. The reason for drilling the horizontal wellbore must be defined. Is the horizontal well being drilled to prevent water or gas coning or to intersect vertical fractures. Many times the reason for drilling the horizontal well drives the completion which in turn, drives the drilling program. The type of completion must always be considered in horizontal well planning. The geology of the target is very important. Remember, TVD targets can be very small and bed dip is a major consideration. A bed dip of only two or three degrees can cause the horizontal wellbore to fall outside the target interval in only a short distance. Also, the geology of a formation can be slightly more complicated than originally expected. Figure 9-1 is an example of what can

happen in a horizontal well. The left side of the figure was the planned wellbore path and geology but the right side is the actual wellbore path and geology. The actual conditions in the formation did not match the predicted conditions. As a result, the operator ended up with a poor horizontal well. Knowing the exact geology of the formation is extremely important.

Figure 9-1 Geological uncertainty Planning a horizontal wellbore’s path must take into consideration all the geologic constraints. It must also take into consideration the reason for drilling the horizontal well. If the well is being drilled to prevent water coning, then the wellbore will be placed near the top of the producing interval away from the water. Gas coning would require that the well be placed near the bottom of the producing interval. If the well is being drilled to intersect natural fractures, the wellbore may be drilled from the top of the reservoir at the end of the build curve to the bottom of the formation at the end of the horizontal section as shown in Figure 9-2.

Figure 9-2 Horizontal wellpath through a fractured formation It may also be that the geology of the formations is not precisely known. The planning may require that the formation be drilled vertically and logged and/or cored before drilling horizontally. The vertical well defines the target TVD and

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also provides information about the lithology changes within the formation. Then, the wellbore is plugged back, sidetracked and drilled horizontally in a favourable position. Remember, a lot of money is being spent to drill the well horizontally and if the geologic data is inadequate, the chances of a commercially viable horizontal wellbore decrease significantly. Casing Design Once the target constraints have been defined, the wellbore must be planned. Review the offset data to determine where casing must be set. Decide what bit size will be required to drill the horizontal section. In many horizontal wells, casing is set through the build curve to eliminate any potential problems with formations above the pay zone. However, casing set through the build curve is not a requirement. It depends upon the stability of the formations above the pay zone and the completion method. The horizontal well takes longer to drill than a vertical well and formations above the pay zone may deteriorate with time. Even though these formations may not be a problem in a vertical well, they may start to be a problem due to the longer drilling time in a horizontal well. Each well must be considered individually. If the horizontal well is to be completed open hole or with a slotted liner, water producing formations above the pay zone may have to be cased. They can be cased before drilling the horizontal or after the horizontal section is drilled. Casing the build section after the horizontal portion has been drilled will require running an external casing packer for isolation and cementing above the packer. In open hole completions, the formation above the pay zone may not be stable over a long period of time. For example, a horizontal well is to be drilled in a limestone formation. The limestone is sufficiently stable to allow an open hole completion but the shale section immediately above the limestone may not be stable and will have to be cased. The type of casing connection used in the build section should be checked to confirm it can handle the bending stresses it will be subjected to both during running and its producing life. An ST & C connection is not recommended for any casing in the build section. It may be able to handle the bending stresses but its lower tensile capability makes it a poor choice of connection for an expensive horizontal well. The operator must consider if the casing will be also rotated during the cementing operation and special connections should be investigated for these jobs. Selection of Build Rate Planning the build rate has to take a number of considerations into account. First the preferred build rate (long, medium or short radius) must be decided. Long radius builds are time consuming and more expensive to drill. Medium radius build rates are more common but require higher build rates resulting in a smaller

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TVD tolerance if the formation tops come in at different depths than planned. Short radius build rates definitely require the most accurate geological information and because of their specialization and special equipment needs the directional costs are higher. Also the bending stresses produced by these build rates require different tubulars (2 7/8” high strength tubing). Typically a short radius build rate is used on re-entry wells and where the geology changes rapidly as the distance from the surface location increases. When determining the build rate the result of an error in achieved build rate should be considered. Figure 9-3 shows how the TVD of the wellbore will change when the build rate is ±10%. Long Radius = less than 6 o/30m Medium Radius = less than 40 o/30m but greater than 6 o/30m Short Radius = greater than 40 o/30m, quite often build rates of 100 o/30m The above classifications should be applied to hole size versus a generic build value but are suitable for purposes of this manual.

Figure 9-3 TVD variance with an error in achieved build rate The actual build rate is usually based on preference or available kick off points. Typically, higher build rates are used in smaller diameter holes and lower build rates are used in larger diameter holes. The dogleg severity limit for 4 ½” drill pipe is about 18o/30m whereas, the limit for 3 ½” drill pipe is 24o/30m. Above these limits, fatigue can be a problem. Also, the tools used to build inclination cannot build as fast in a large diameter hole as a small diameter hole. An 8 ½” hole is limited to about 15 to 18 o/30m build rates depending upon who’s motor configuration is being used. A 6 inch hole is limited to about a 25 o/30m build rate though some short radius tools are now available for higher build rates.

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The operator must decide upon what build rate to use. Generally, the higher build rates will yield less time drilling and, therefore, less cost. The build rate may also be determined by hole problems or casing setting depths. If the kick off point is selected, the build rate is calculated and vise versa. When the target requirements are small, it may be necessary to make some adjustments to the build curve to hit the intended target. The build rate of most motor assemblies is somewhat predictable to within ten to fifteen percent. With previous experience in a specific area, the build rates are even more predictable. In areas with little experience drilling horizontal wells, it is not uncommon to plan the well with either a tangent section or a soft landing. A tangent section is a short portion of the build curve drilled at a relatively constant inclination. For example, the wellbore may build inclination at 12 o/30m to 45o, then a 30m section is drilled at 45o before continuing to build inclination at 12 o/30m. The tangent section allows for differences between planned and actual build rates. If the actual build rate is less than the planned build rate, the well reaches 90o too deep. If it is greater than the planned rate, the wellbore will reach 90o too shallow. The tangent section can be used to compensate for the differences. If the build rate is greater than anticipated, the tangent section can be lengthened to consume more TVD. Conversely, if the build rate is less than anticipated, the tangent section is shortened providing more TVD to work with. At one time, it was very common to plan a tangent section for a horizontal well, but they are not as common as they use to be. Tangent sections are not needed for wells with large TVD targets. Tangent sections cost money, and should be avoided if possible. The other option is to plan the build section with a “soft land”. This refers to a reduced build rate for the last 3 to 10m of TVD. This section again will allow for slight changes in casing landing depth to be made. Typically the difference between the first and second build rate is 2 or 3 o/30m. It is important to be aware of the motor setting required for these different build rates. The operator would rather not make a special trip to change the motor setting. In both cases it is important to know if the motor can be safely rotated or if a trip is required to reduce the setting. This can be very costly and should be avoided where possible or timed with a bit trip. Planning Team As should be evident by now, horizontal well planning is a multi-disciplined project. Horizontal planning must include personnel from

• Geology • Drilling • Reservoir • Production and • Service Companies

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The effect of geology on the horizontal well has already been discussed. The reservoir and production personnel should be involved in the planning. There may be certain portions of the reservoir where the horizontal wellbore will be more effective. What are the pressures within the section that will be penetrated by the horizontal well? What kind of formation damage can be expected from the drilling fluid? Will the horizontal wellbore require stimulation to produce effectively? Will the well have to be produced using artificial lift and what volumes can be expected? There are many questions to be answered before the drilling plan can be finalized and the reservoir and production groups will have to help answer these questions. Service company personnel must be involved in the planning phase. They have more experience with their equipment than anyone and can help the operator during the planning phase. It is best to know the limits of the equipment before the drilling operations begin. This includes the equipment used to drill the well and the equipment used in the completion of the horizontal well. It has been said many times that “failing to plan is the same as planning to fail”. In horizontal drilling, this is certainly true. Planning is one of the most important steps in drilling a horizontal well. In planning any directional well profile, certain information is required. Horizontal drilling is no different. As stated earlier, the target for a horizontal well is usually a TVD target and the departure is seldom a consideration unless drilled from a platform or pad. With a platform or pad, the wellbore must first reach the portion of the reservoir where the horizontal well is to be placed. In that case, the upper portion of the well is drilled like a normal directional well and the lower portion is drilled like a normal horizontal well. Generally, planning the directional drilling profile is a trial and error process. Planning Once you have selected either the build rate or horizontal displacement to casing point, quick estimates can be made to determine the KOP. Assuming no tangent and a constant build rate to casing point set at 90 degrees is used the following equation will determine either build rate or horizontal displacement and thereby the KOP. Build Rate = 5729.578/Horizontal Displacement (degrees per 100 feet) Build Rate = 1718.8734/Horizontal Displacement (degrees per 30 meters) Example: Horizontal Displacement to casing point is 500 feet Build Rate = 5729.578/500 = 11.46 o/100’ but Desired Build Rate = 9 0/100’ Horizontal Displacement = 5729.578/9 = 636.62’ KOP = TVD – Horizontal Displacement (casing at 90 degrees) TVD = 12000’ KOP = 12000 – 636.62 = 11363.38’

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Although this is a very simplified approach it immediately establishes a potential kick off point which can then be checked against the expected formations to determine the suitability of this depth. All directional companies have computer programs to aid in planning the best trajectory for your well path and can adjust for many requirements as dictated by the “planning team”. When bed dips are taken into consideration, planning the horizontal well can be more complicated. The inclination of the horizontal section will be a function of the apparent bed dip in the plane the well is being drilled not the bed dip perpendicular to the bed strike. Generally the apparent dip can be obtained from the geology department. The inclination of the horizontal section also depends upon the position of the horizontal section within the producing formation. Obviously this is starting to get complicated and as it is important with all horizontal wells a diagram is very important.

Figure 9-4 Illustration of dipping beds for a horizontal well

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The following formula can be used to determine the inclination of the angle of the horizontal section (IH) of the well in the target plane: IH = 90 – arcTan[ Tan(Idip) x Cos(AZdip – AZWELL)] - degrees Idip = dip of the target plane - degrees AZdip = target plane dip azimuth - degrees AZWELL = planned azimuth of the horizontal well - degrees The following equation is used to determine the TVD at the end of the build section in the target plane:

TVDEOC = TVDTP + DISPL[Tan(Idip) x Cos(AZdip – AZWELL)]

TVDEOC = TVD at end of curve in the target plane – ft or m TVDTP = TVD of target plane under the surface location – ft or m DISPL = horizontal displacement length from surface to EOC – ft or m IDIP = dip of target plane - degrees AZdip = target plane dip azimuth - degrees AZWELL = azimuth of horizontal well - degrees = arcTan (East/North) Example:

Dip angle equals 5o, Idip Dip azimuth = 135o, AZdip TVD of target under surface is 9000’, TVDTP a) well direction is due East = 90o AZWELL b) well direction is due West = 270o AZWELL If well direction is due East IH = 90 – arcTan[Tan5 x Cos(135 – 90)] = 90 – (3.54) = 86.46o If well direction is due West IH = 90 – arcTan[Tan5 x Cos(135 – 270)] = 90 – (-3.54) = 93.54o If the EOC is 800’ due East of surface location the target TVD is TVDEOC = TVDTP + DISPL[Tan(Idip) x Cos(AZdip – AZWELL)] = 9000 + 800[Tan(5) x Cos(135-90)] = 9000 + 49.41 = 9049.41 feet Summary – land curve at 9049.41 feet TVD, at an inclination of 86.46o.

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The radius of curvature equations can also be used to provide quick estimates of KOP and build rates provided you know at least two of the unknowns. ∆TVD = 180 x [(I2 – I1)/(BR/100)] x (SinI2 – SinI1) π x (I2 – I1) Example 1: What is the KOP for well using a 14 o/100’ build rate with a target TVD of 5000’ and an inclination of 85o? ∆TVD = 180 x [(85-0)/(14/100)] x (Sin85 – Sin0) / (π x (85 – 0)) = 180 x 607.14 x 0.9962 / (267.035) = 407.70 feet, therefore KOP = 5000 – 407.7 = 4592.3 feet Example 2: What is the required build rate for the same well if the expected target TVD suddenly came up to 4990’ and you are already at 50 degrees and a TVD of 4905.8 feet and still want to land at 85o? Rearrange the formula to: BR = 180 x [(I2 – I1) x (SinI2 – SinI1) x 100 ∆TVD x (π x (I2 – I1)) BR = [180 x (85-50) x (Sin85 – Sin50) x 100] / [(4990 – 4905.8) x (π x (85-50))] = 144,994.66 / 9258.27 = 15.7 o/100’ As the parameters change while drilling a horizontal well having the use of a computer program to re-plan the well becomes of utmost importance. Mistakes in hand calculations can be very expensive. Geosteering Geosteering is defined as “the drilling of a horizontal, or other deviated well, where decisions on well path adjustment are made based on real time geologic and reservoir data”. In conventional deviated drilling, the well path is steered according to a predetermined geometric plan. The objective is to follow the line as closely as possible. Geosteering is a departure from this convention. It is required when the geological marker is ill defined, target tolerances tight, or the geology so complicated as to make conventional deviated drilling impractical. Logging while drilling (LWD) data can be used to help place the horizontal wellbore in the proper position. The most common LWD data is gamma ray and therefore, the directional path of the wellbore can be adjusted based on real time logging data. One of the major problems when drilling horizontal wells in thin formations is to establish the well as horizontal in the objective formation. It is often the case that despite the best efforts of the wellsite personnel, the well becomes horizontal immediately above or below the target in the reservoir. Productive hole can be

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lost in establishing the well in the reservoir. As illustrated in Figure 9-5a, geosteering enables the geological marker above the reservoir to be recognized and the final build to horizontal to be adjusted accordingly. Typically, gamma ray and resistivity tools are used to identify marker formations above the producing formation. As illustrated in Figure 9-5b, when the reservoir thickness is very small, drilling horizontally within such tight tolerances and approaching geological boundaries must be recognized early and appropriate directional drilling corrections taken. Resistivity and gamma ray logs are frequently affected by formations over and underlying the reservoir, thereby allowing the position of a boundary to be determined without exiting the reservoir. Varying formation dip angle, varying thickness of the reservoir and the presence of small faults invariably complicates drilling of the formations. Although the reservoir may be thick, it may be desirable to remain a fixed distance above and oil water contact or below a gas oil contact within the reservoir to maximize production as illustrated in Figure 9-5c. In the case of an oil water contact the resistivity log would be the most useful. In the case of a gas oil contact the density reading would provide the key.

Figure 9-5 Reasons for geosteering horizontal wells In highly faulted reservoirs such as Figure 9-5d, several hydrocarbon blocks may be connected in one wellbore. The success of this operation depends on recognizing the departure from one block and taking appropriate steering action to enter the next block. Geosteering is fundamental to this and to maximizing productivity. Of course, you must know whether to drill up or down.

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A significant disadvantage that has arisen when steering within tight tolerances is the distance of the various data sensors behind the bit. This distance varies from 10 to 15m (30 to 50 feet) in a conventional LWD geosteering assembly. The data lag means that changes in formation are established after significant further hole has been drilled. Also, the directional results of the steered section are seen late. In critical applications these disadvantages can mean the difference between maintaining the well within the objective and losing valuable productive hole. Fortunately, there are some tools now available that places the data sensors at the bit. Not all horizontal wells have to use LWD to be placed in the proper position. If the depth of the formation is well known and the target interval is large enough, geosteering is not required. Sometimes there is no distinct gamma signature of marker formations close to the reservoir. Other forms of geosteering are available for considerably less expense. They are drilling parameters and mud logging. The combination can be used to determine the depth of the target zone. To determine the entry point, geologic makers can sometimes be found due to penetration rate changes and formation identification. The mud logger can be looking for a change in penetration rate and then look at samples to determine if the geologic marker has been penetrated which is the same as using a gamma ray or resistivity tool. Penetration rate along with sample identification is commonly used to keep the wellbore within the producing zone. Many times the porosity of the producing zone allows the well to be drilled with higher penetration rates than the formations above and below the zone. If the penetration rate starts to slow down and samples indicate the wellbore is exiting the zone, the TVD can be adjusted to keep it in the zone. It is difficult to stay above an oil water contact or below a gas oil contact when using drilling and mud logging data. The only way to tell if the wellbore has exited the oil section is to look at the samples. Penetration rates should remain fairly constant and does not help. Unfortunately, the wellbore must already be out of zone before samples can be used to determine the position of the wellbore. The intent of the horizontal well is to stay well away from the water and gas. If the wellbore is already out of the oil, then the purpose of drilling the wellbore horizontally has been defeated. LWD data is not necessary where drilling data and mud logging data can be used to effectively find and keep the wellbore in the zone of interest. Larger targets are easier to hit and stay in. As the target size decreases, LWD data can be used more effectively especially where the geology is not fully understood.

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Chapter

7 MAGNETICS While measurement while drilling (MWD) tools are in wide use today many other types of surveying equipment is still in use on various directional projects. Before describing the different types of surveying equipment it is important to have a basic understanding of magnetics. Magnetic Fields Our understanding of earth magnetism is based on ideas about how magnets interact with one another and about how magnetism is produced. The eighteenth century French physicist Charles Coulomb described the interaction of magnets in terms of forces acting at points called magnetic poles. Every magnet possesses a positive pole and a negative pole, so named because of their opposite effects on the poles of another magnet i.e. like poles of two magnets exert a repelling force on one another, whereas unlike poles exert a force of attraction. Coulomb’s law expresses the force, F, acting on two poles having values of pole strength P1 and P2 and separated by a distance r: F = (1/u) x (P1 xP2)/r2

Where u = magnetic permeability, property of the medium where the magnets are located. In a vacuum, u = 1.0, which is very close to its value in the earth’s atmosphere.

The two poles of a magnet act oppositely but with equal pole strength. It is not possible to separate or extract either of these poles. To break a magnet is to immediately create two new magnets, each with a positive pole and a negative pole. For this reason, we commonly use the word dipole to describe a magnet. Metals that are strongly attracted by magnets are said to be ferromagnetic. Such materials have magnetism induced in them when they are near a magnet. If a piece of iron is brought near the south pole of a magnet, the part of the iron nearest the magnet has a north pole induced in it, and the part farthest away has a south pole induced in it. Once the iron is removed from the vicinity of the magnet, it loses most of the induced magnetism. Some ferromagnetic metals actually retain the magnetism induce in them, that is they become permanent magnets. Regular magnets and compass needles are made of such metals. Ferromagnetism is also the basis of magnetic tape recording.

It is useful to employ the concept of a field to represent the effect of a magnet on the space around it. A magnetic field is produced by a magnet and acts as the agent of the magnetic force. The poles of a second magnet experience forces when in the magnetic field: its north pole has a force in the same direction as the magnetic field, while its south pole has a force in the opposite direction. A compass can be though of as a magnetic field detector because its needle will align itself with a magnetic field. The shape of the magnetic field produced by a magnet can be mapped by noting the orientation of a compass at various places nearby. Magnetic field lines can be drawn to show the shape of the field. The direction of a field line at a particular place is the direction that the North Pole of a compass needle will point. There are several theories to explain the Earth’s magnetic field: Theory #1: Rotation of the Earth’s solid exterior relative to its liquid iron core is believed to induce a slow rotation of the core. A magnetic field results from the electrical currents generated by the relative motion between the liquid core and the mantle.

Figure 5-1 Illustration of Theory #1

Theory #2: Similar to theory #1. The centre portion of the Earth is largely composed of iron and has the mechanical properties of a fluid. These fluids are subjected to internal circulation currents similar to phenomena observed at the periphery of the sun. The internal circulation of these fluids acts as the source of the Earth’s magnetic. In any event it appears that some mechanism is stirring up the core and causing fluid motion. These motions combine in a particular pattern to give rise to the dipole field, which is observed at the earth’s surface.

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The total magnetic field is the sum of two fields of different origins: • The principal field which originates within the fluid nucleus of the Earth and • The transitory field which is generated outside the Earth. This field is caused

by the rotation of the Earth relative to the Sun and by the cycles of the Sun’s activity.

Aspects Of The Transitory Field The transitory field is responsible for the following variations of the magnetic field. • Secular variations of approximately 15 gammas per year - a minor effect. • Diurnal solar variation on the order of 30 to 40 gammas per day — a minor

effect. • The cyclical “Eleven Years” variation – a minor effect. • Magnetic storms which may reach several hundreds of gammas - a major

effect. The Earth’s own magnetic field extends out to approximately 8 times the radius of the planet. Beyond this prevails the Magneto Pause, a region in space where the Earth’s magnetic field contacts the solar wind. On its sunward side, the Earth’s magnetosphere is compressed by high energy particles from the solar wind (figure 5-2). These particles collide with the Earth’s magnetic field at a speed of 640 miles per second and are slowed down at the shock front to 400 miles per second. Variations in the solar wind produce changes in the Earth’s magnetic field. Solar flare particles reach the Earth in approximately two days. The shock wave preceding the cloud of plasma from the solar flare compresses the magnetosphere and rapidly intensifies the geomagnetic field at ground level.

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Figure 5-2 Fluctuations in the Earth’s magnetic field This compression takes place over a few minutes and is called the Sudden Storm Commencement. It is followed by the Initial Phase which lasts from 30 minutes to a few hours. The Main Phase produces a drop in the magnetic field strength due to an opposing field generated by the energized particles in the magnetosphere. This is normally not a problem for locations in the Gulf of Mexico and at lower latitudes. In Alaska and some parts of the North Sea, however, this has serious effects. Magnetic Field Strength The total magnetic field strength may be referred to as the H value, HFH, magnetic field strength or TTL field. The Geological Society Electromagnetic Units are used for measuring the strength of the Earth’s magnetic field and are called Gammas. Some useful conversions: 1 gamma = 1 Nanotesla = 1 x 10-9 Tesla 1 microtesla = 1 x 10-6 Tesla = 1000 gammas 1 tesla = 1 x 109 gammas 1 gauss = 1 x 105 gammas 1 gauss = 1 x 10-4 Tesla 1 gauss = 1 oersted 1 tesla = 1 newton / ampere * meter

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The magnetic field intensity recorded at ground level is of a much smaller magnitude than that prevailing around the Earth’s core. At the periphery of the core (approximately 3500 kilometers outward from the centre of the Earth), the field strength reaches 800,000 gammas. Extreme total field values at the surface which you are unlikely to see range from 63,000 gammas close to the North Pole to 27,000 gammas near the equator (magnetic field intensity is greater at the North Pole then the equator). The total magnetic field intensity is the vector sum of its horizontal component and its vertical component. The vertical component of the magnetic field points toward the ground and therefore contributes nothing to the determination of the direction of magnetic north. The horizontal component of the magnetic field strength can be calculated from the following equation: Horizontal Component = Magnetic Field Strength (HFH) x COS(Magnetic Dip Angle) Some common values of total magnetic field strength are: • Gulf of Mexico = 50,000 gammas • Eastern Canada = 54,000 gammas • Beaufort Sea = 58,500 gammas • North Sea = 50,000 gammas The Magnetic Dip Angle is equal to the angle between tangent to Earth’s surface and magnetic field vector (magnetic North). Extreme values which you are not likely to see for Dip Angle range from 90 degrees close to the North Pole to almost 0 degrees at the equator. There are also several other points on the Earth’s surface where the dip is equal to 90 degrees. These are due to local anomalies and are called dip holes. Some common relative values for dip angle: Gulf of Mexico = 59 degrees Eastern Canada = 70 degrees Beaufort sea = 84 degrees North Sea = 70 degrees Example horizontal component calculations: For Alaska: • 57,510 gammas x COS(80.6o) = 9392 gammas

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For Gulf of Mexico: • 50,450 gammas x COS(59.70o) = 25,250 gammas MWD instruments measure the three components of the magnetic field vector, H. The expected value can be obtained from a previous acceptable survey or from a Geomagnetic software program. Differences observed between the measured magnetic field strength value and the value from the Geomagnetic software program may be due to: • Uncertainties in drill string magnetism. • Uncertainties induced by temporal variations in the magnetic field. • Uncertainty in the measured value of the magnetic field. • Temperature sensitivity of the magnetometers. • Errors from the tool electronics. Magnetic Declination Angle The Earth can be thought of as having a magnetic dipole running through its centre with north and south poles at either end. This dipole does not correspond with the Earth’s rotational axis (tilted approximately 12o relative to earth’s axis of rotation). The angle between magnetic north and geographic north (True North) is defined as the magnetic declination or the angle of declination (refer to illustration). The magnetic declination is dependent upon the location (latitude and longitude) and may vary in areas of high magnetic activity (such as Alaska). All magnetic surveys require a conversion to geographic direction by adding or subtracting this angle. Knowing magnetic declination, the direction of the Earth’s magnetic field relative to True North can be calculated.

Figure 5-3 Magnetic declination angle

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Magnetic declination can vary and the total magnetic field strength may vary greatly during extreme sun spot activity. Also, the closer to the equator:

• the lower the total field strength • the higher the horizontal component • the less the dip angle

All survey systems/plots are measured relative to True North (geographic north). Survey tool measurements are made relative to Magnetic North (necessary to adjust for magnetic declination). Magnetic Declination Correction: EAST + Correction to Azimuth

WEST - Correction to Azimuth When dealing with magnetic survey bearing or azimuth values expressed between 0 and 360 degrees, the magnetic declination is always added since the East or West value for the declination will adjust itself. For example survey reads 120o and the magnetic declination is 20o West, corrected bearing is 120 + (-20) = 100o. Magnetic Interference There are two types of magnetic interference; drill string and external magnetic interference which can include; 1) interference from a fish left in the hole; 2) nearby casing; 3) a magnetic “hot spot” in the drill collar; 4) fluctuation in the Earth’s magnetic field; and 5) certain formations (iron pyrite, hematite and possibly hematite mud). Any deviation from the expected magnetic field value can indicate magnetic interference. External magnetic interference can occur as the drill string moves away from the casing shoe or from the casing window. It can also occur as another cased hole is approached. All surveying instruments using magnetometers will be affected in accuracy by any magnetic interference. In such a case, gyroscopic (gyro) measurements will have to be used. There are certain instances where a gyro survey may need to be used if the well requires steering out of casing or if a possible collision exists with another well. There are also cases where magnetic interference may be corrected or at least taken into account until a different BHA is used. Drill String Magnetic Interference The drill string can be compared to a long slender magnet with its lower end comprising one of the magnetic poles. Even if the components of a drilling

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assembly have been demagnetized after inspection, the steel section of the drill string will become magnetized by the presence of the Earth’s field. Drill string magnetism can be a source of error in calculations made from the supplied magnetometer data. This may happen as the angle builds from vertical (Figure 5-4) or as the azimuth moves away from a north/south axis. Also, changing the composition of the BHA between runs may change the effects of the drill string. Correction programs for magnetism of the drill string exist.

Figure 5-4 Changes in horizontal component of magnetic field with inclination It is because of drill string magnetism that non-magnetic drill collars are needed. Non-magnetic drill collars are used to position the compass or direction sensors out of the magnetic influence of the drill string. The magnetometers are measuring the resultant vector of the Earth’s magnetic field and the drill string. Since this is in effect one long dipole magnet with its flux lines parallel to the drill string, only the Z-axis of the magnetometer package (Z-axis is usually the axis of the surveying tool) is affected, normally creating a greater magnetic field effect along this axis. The magnitude of this error is dependant on the pole strength of the magnetized drill string components and their distance from the MWD tool. The error will normally appear in the calculated survey as an increased total HFH value (higher total field strength than the Earth alone). This increase is due to the larger value of the Z-axis magnetometer. The total H value should remain constant regardless of the tool face orientation or depth as long as the hole inclination, azimuth and BHA remain relatively constant. When drill string magnetism is causing an error on the Z-axis magnetometer, only the horizontal component of that error can interfere with the measurement of the Earth’s magnetic field (see Magnetic Field Strength section). The horizontal component of the Z-axis error is equal to the Z-axis error multiplied by the sine of the hole deviation. This is why experience has shown that the magnetic survey accuracy worsens as the hole angle increases (especially with drill string magnetic interference). Since the horizontal component of the Earth’s magnetic field is

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smaller on the Alaskan Slope, the error from a magnetized drill string is relatively greater than that experienced in lower latitudes. Thus, a 50 gammas error has a larger affect on a smaller horizontal component, 0.53% error in Alaska compared to only 0.20% in the Gulf of Mexico. The increased value of the Z-axis due to drill string magnetism will normally cause all calculated azimuths to lie closer to north. This error will show up when a gyro is run in the well. Usually all MWD surveys will be positioned (magnetically) north of the gyro survey stations. (Some gyros derive True North from the Earth’s rotation.) Minimizing Errors One way to minimize the error caused by the drill string is to eliminate as much of the magnetism as possible. This is done by isolating the magnetometer package with as many non-magnetic drill collars as possible. The length of the non-magnetic collars implies a uniform and non-interrupted non-magnetic environment. This, however, is not true in practice. Each connection in a drill string, whether magnetic or not, is magnetic due to the effects of the mechanical torque of the pin in the box. This mechanical stress causes the local metal around the connection to change its magnetic properties and can actually cause a survey azimuth reading error in the tens of degrees in some cases. Therefore, never space within 2 feet of a connection. Additionally, do not space exactly in the centre of a non- magnetic collar. When a collar has been bored from both ends, there is a very slight ridge at the point where the two bores come together. This becomes magnetically hot due to the cyclic rotation stresses to which the collar is subjected during rotary drilling. Usually, this effect can be removed by trepanning the collar bore. As much as 40o of azimuth error has been seen due to this effect. Obviously the presence of a steel stabilizer or steel component between two non-magnetic collars results on a pinching of the lines of force (Figure 5-5). This is detrimental to the accuracy of the survey. A steel stabilizer may be satisfactory on the Equator, but not as far north as Alaska. In Alaska all stabilizers used in the BHA are non-magnetic, since a conventional steel stabilizer located between two non-magnetic collars results in an interfering field which may reach 250 gammas. Even non-magnetic stabilizers are actually magnetic near the blades. At a minimum, hard metal facing and matrix used on stabilizers can be very magnetic. Never space inside a non-magnetic stabilizer. The following are circumstances where more non-magnetic drill collars are necessary to counter drill string magnetism effects. These are also examples in which the azimuth accuracy will likely decrease.

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• The further away from the Equator (in latitude). • The larger the hole inclination. • The further away from a north/south hole azimuth. Note that even with 40m (120 feet) of non-magnetic material above the magnetometer package the effects of drill string magnetism in places like Alaska may still be seen.

Figure 5-5 Effect of steel stabilizer

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Special Notes lf magnetic interference is encountered from the drill string, the total H value should remain constant regardless of tool face orientation or depth as long as the hole inclination, azimuth and BHA remain fairly constant. The horizontal component of the Z-axis error is equal to (Z-axis error) x Sin(I). This is why a magnetic survey declines as the hole angle increases (especially with drill string magnetic interference). Drill string interference is more pronounced in areas of high dip angle.

External Magnetic Interference When magnetic interference from external sources is encountered (such as from a fish in the hole or from nearby casing), all three axis of the directional sensor package will be affected. Therefore, the total magnetic field will vary. The total H value will also vary when the sensor package is close to casing joints. If a hot spot occurs on a non-magnetic collar, the total H value will change with varying tool face settings, but will be repeatable when the BHA is placed in the same orientation. In places such as Alaska, total field strength can routinely vary by 100 gammas.

Do not mistakenly interpret change in total H value as a failed magnetometer sensor. It may be caused by magnetic interference. Do not mistakenly interpret a change in a survey with a failed magnetometer or inclinometer; it may be due to a tool face dependency.

Directional Sensor Package Spacing In order to avoid magnetic interference, non-magnetic drill collars must be used and empirical charts are used to estimate the length of non-magnetic material needed. Experiments have shown that mud motors can produce a magnetic field from 3 to 10 times greater than components such as steel stabilizers and short drill collars. As a rule of thumb, anytime a mud motor is run, a non-magnetic short drill collar (of 3m to 5m) should be placed between the motor and sensor package. It may even be necessary to use a non-magnetic orienting sub in some areas of the world. The following formula can be used to accurately predict errors in azimuth due to magnetic interference from the drilling assembly.

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Non-magnetic directional DC

IF = 770 + LP - LP (14 + X)2 (y + b)2 (y + b + c)2 AE = 57,300 x IF x SinI x Sin(Az – MD) H x Cos(dip) IF = calculated interfering field AE = Azimuth Error X = Length of non-magnetic collar above MWD, note the dimension 14 feet is an assumed value for the distance from the sensor package to the bottom of the NMDC and the actual value should be used for the respective tool configuration. b = Length of non-magnetic collar below MWD c = Length of magnetic material below MWD H = Total magnetic field strength in gammas Az = Azimuth of the well I = Inclination of the well MD = Magnetic declination Dip = Dip angle This formula is relatively easy to use and interpret. The absolute value of the predicted azimuth error (AE) should be less than 0.5 degrees. If it is not, continue adding lengths of non-magnetic drill collars both above and below the MWD collar until the AE value is below 0.5 degrees. Other equations have been prepared by other directional companies. For horizontal drilling, and especially for well paths with a medium radius of curvature, it may be impractical to achieve a predicted azimuth error of less than 0.5 degree. Some operators may prefer to drill with a predicted error of one degree during the build up phase of the well and then correct for it later. If a mud motor is used to correct the well azimuth (on a slant hole) and a change in the magnetic field is observed, due to magnetic interference from the motor, the change may not be problem as long as the operator and directional driller are aware of the change and take it into account. A simple way would be to re-survey the corrected path with a different spacing or a different BHA.

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The Earth’s Gravitational Field According to Newton’s Law of Gravitation; every particle of matter in the universe attracts every other particle with a force which is directly proportional to the product of the masses and inversely proportional to the square of the distance between them. Mathematically: g = G x m x Me / r2 g = attractive force G = Universal Gravitational Constant m = mass Me = mass of the Earth r = radius between centres The gravitational field (G) is primarily a function of:

Latitude (main factor). Depth/Altitude: referenced to mean sea level (MSL) Regional fluctuations in the density of the Earth’s crust.

Some of the changes in the measured value of G over the Earth are attributed to the Earth’s rotation. The rotation has given the Earth a slightly flattened shape. Therefore, the equatorial radius is larger than the polar radius. The G value changes from 0.997 at 0 degree latitude (Equator) to approximately 1.003 at 90 degree latitude (a 0.006 change). A decrease in G can also be seen with increasing hole depth. The rate of change is approximately 0.0005 per 10,000 feet. You would have to be at 20,000 feet to see 0.001. Regional fluctuations in the density of the Earth’s crust are practically negligible. Other reasons for discrepancies in the measured G value are due to instrumentation errors in the inclinometer. These can be attributed to:

• Temperature sensitivity.

• Errors due to bad axis alignment.

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• Errors due to electronic circuitry.

• Shifts in the sensor operating parameters, which occur when the inclinometer is exposed to the shocks and vibrations of the drilling environment.

Applications of Magnetics and Gravity In the MWD sensor package, two sets of sensors are used. One set (magnetometers) uses an XYZ system to measure orientation with respect to the earth’s magnetic field (Hx, Hy, Hz). The other set (accelerometers) uses an XY or XYZ system to measure orientation with respect to the earth’s gravitational field (Gx, Gy, Gz). From the magnetic sensors we can learn inclination, azimuth, and tool face angles. From the gravity sensors we can learn inclination and tool face angle. Magnetic Toolface, MTF For hole inclinations of 0 to 5 degrees use magnetics to determine hole direction. i.e. N 65oE i.e. MTF = Magnetic Azimuth +/- Declination + Toolface Offset (N) (0) (W) (270) + (90) (E) (180) (S)

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Gravity Toolface, GTF For hole inclinations of 5+ degrees use gravity to determine the hole direction. i.e. 65o or 65 R i.e.GTF= Tool Highside Angle +/- Declination + Toolface Offset Highside (0) Left (90) + Right (90) (180) Down

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NEGATIVE PULSE OFFSET TOOL FACE OFFSET TOOL FACE (OTF) SHEET This sheet is possibly the most important form that must be f i l led out correctly. All other work and activity performed by the MWD Operator means naught if the well must be plugged back with cement because of an incorrect OTF calculat ion (or the correct OTF not being entered into the TLW 2.12 software). Ensure that the OTF calculation is correct, entered into TLW 2.12 correctly and verified by the Directional Driller.

The procedure for measuring the OTF is as fol lows: 1. Measure in a clockwise direction the distance from the MWD high side scribe to the motor high side scribe. Record this length into the OTF work sheet as the OTF distance. In the fol lowing example, this value is 351 mm. 2. Measure the circumference of the tubular at the same location where the OTF distance is being measured. Record this length into the OTF work sheet as the Circumference of Collar . 3. Calculate the OTF angle using the fol lowing formula:

OTF Angle= OTF Distance x 360 Collar Cirumference

From the above example, if the col lar circumference is 500 mm, OTF Angle= (351/500) x 360 = 0.702 x 360 = 252.72o

A sample form is as fol lows:

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NEGATIVE PULSE OFFSET TOOL FACE (O.T.F. MEASUREMENT)

Well Name: Enter in the Well Name here Date: Enter in date OTF taken

LSD: Enter in the LSD here Time: Enter in time OTF taken Job #: Enter in the MWD job number here Run #: Enter in the run number

TOP VIEW OF MWD

MWD SCRIBE

PROPER

DIRECTION

OF OTF

MEASUREMENT

MOTOR SCRIBE (HIGH SIDE)

O.T.F. Distance (Anchor Bolts to Collar Scribe): 351 mm Circumference of Collar: 500 mm O.T.F. Angle (Distance / Circumference) x 360: 252.72 degrees O.T.F Angle entered into Computer as: 252.72 degrees O.T.F. Distance measured by: Both MWD Operator Names O.T.F. Calculated by: Both MWD Operator Names O.T.F Entered into computer by: Both MWD Operator Names O.T.F. Measurement and calculation Witnessed by: Directional Driller(s) Name(s)

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NEGATIVE PULSE OFFSET TOOL FACE

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2 5 2 .

POSITIVE PULSE TOOLFACE OFFSET

INTERNAL TOOL FACE OFFSET (TFO) SHEET Note: For the positive pulse MWD, the OTF is zero. Ensure that a zero OTF has been entered into TLW 2.12. The positive Tool Face Offset (TFO) sheet entries are as follows: 1. Positive Pulse Pulser Set to High Side / Directional Driller: Enter the names of the MWD Operator and Directional Driller respectively. 2.Positive Pulse T.F.O. from PROGTM: Enter the T.F.O. value reported from the high side tool face calibration from TLW 2.12. TFO internal toolface offset

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POSITIVE PULSE T.F.O. MEASUREMENT

Well Name: Enter in the Well Name here Date: Enter in date OTF taken LSD: Enter in the LSD here Time: Enter in time OTF taken Job #: Enter in the MWD job number here Run #: Enter in the run number

ROTATE PULSER TO HIGH SIDE

PULSER KEY WAY

PROPER

DIRECTION

OF TFO

MEASUREMENT

DAS HIGH SIDE TAB

Positive Pulse Pulser Set to High Side: Name of MWD hand Witness Directional Driller: Name of Directional hand Witness Positive Pulse T.F.O. from PROGTM: 163.25 degrees Gravity Tool Face (gtface) Should Equal Zero: 0.00 degrees Motor Adjustment: 2.12 / G degrees/setting Alignment of Mule Shoe Sleeve Key to Motor Scribe: Name of 2nd MWD hand Witness O.T.F.=0, Entered into Computer by: Name of MWD hand All Calculations Witnessed by: Signature of Directional Driller

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MWD - Positive Pulse OTF – External Drill Collar Offset Magnetic Declination Toolface switch over

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EM MWD Toolface Offset Magnetic Declination

Toolface Offset

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Check TF offset indicates that nothing is entered for toolface offset.

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Precision LWDTM Tool Face Offset

The Tool Face Offset is an external (drill collar) offset and must be measured clockwise, looking downward toward the bit from the HEL tool scribeline to the mud motor scribeline. This is one of the most important measurements that the LWD Engineer makes and MUST be done correctly. All other work and activity performed by the LWD Engineer means naught if the well must be plugged back with cement because of an incorrect TFO calculation (or the correct TFO not being entered into the Spectrum software). Ensure that the TFO calculation is correct, entered into Spectrum correctly and verified by the Directional Driller.

The procedure for measuring the TFO is as follows: 1. Measure in a clockwise direction the distance from the HEL tool’s

high side scribe to the motor high side scribe. Record this length into the TFO work sheet as the TFO distance. In the following example, this value is 351 mm.

2. Measure the circumference of the tubular at the same location where the TFO distance is being measured. Record this length into the TFO work sheet as the Circumference of Collar.

3. Calculate the TFO angle using the following formula:

360tan∗=

nceCircumfereCollarceDisTFOAngleTFO

From the above example, if the collar circumference is 500 mm,

oAngleTFO 72.252360702.0360500351

=∗=∗=

A sample form is as follows:

Computalog USA, Inc. This document contains Company proprietary information which is the confidential property of Computalog Drilling Services and shall not be copied, reproduced, disclosed to others, or used in whole or in part for any other purpose or reason except for the one it was issued without written permission.

Computalog USA, Inc. This document contains Company proprietary information which is the confidential property of Computalog Drilling Services and shall not be copied, reproduced, disclosed to others, or used in whole or in part for any other purpose or reason except for the one it was issued without written permission.

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Chapter

8 SURVEY EQUIPMENT, SELECTION & ACCURACY Magnetic Single Shots and Multishots Directional surveying permits 1) the determination of bottom hole location relative to the surface location or another reference system; 2) the location of possible dog legs or excessive hole curvatures; 3) monitoring of the azimuth and inclination during the drilling process; and 4) the orientation of deflection tools. The inclination and azimuth of the well bore at specific depths can be determined by one type of survey called the “single shot survey”, while “multiple shot” surveys are used to record several individual readings at required depth intervals. These magnetic survey instruments must be run inside non-magnetic drill collars or open hole. Magnetic Single Shot The magnetic single shot instrument is used to simultaneously record the magnetic direction of the course of an uncased well bore and its inclination from vertical. It is also used, in some cases, to determine the tool-face of a deflection device when deviating the well (usually a gyro is used). The instruments consist of four basic units; 1) a power pack or battery tube; 2) a timing device or sensor; 3) a camera unit and 4) a compass - inclinometer unit. These four elements are assembled together and usually inserted into a carefully spaced protective barrel (running gear) before being lowered or dropped, inside the drill pipe, to bottom. The protective casing can be thermally insulated for wells where the downhole temperature exceeds the tolerance of the photographic film used or battery. Power Pack The size and number of batteries required varies with the instrument, as does their polarity. Care should be taken to identify the correct polarity prior to loading batteries into the battery tube. Failure to do so can lead to a “mis-run” survey, causing lost time while the survey is re-run. The battery tube may have a snubber for use with top landing running gear.

Timer or Sensor The timing device is used to operate the camera at a predetermined time. The Surveyor must estimate the time it will take for the instrument to fall to bottom, whether lowered on wire line or dropped (go devilled). The timers available today are either mechanical, or electronic. In the past, mechanical timers have been considered more robust, although less accurate than the electronic timers. With modern solid state electronics this is no longer true and mechanical timers are now rarely used. Electronic timers allow the operator to preset the time delay on the instrument before loading it into the running gear. Problems arise when using either type of timer and are not necessarily due to instrument malfunction. The most common problem results from timer miscalculation. If the time delay expires before the instrument has seated inside the non-magnetic drill collar, the resulting survey will be invalid, affected by motion and magnetic interference from the drill string. Since it is quite difficult to accurately predict the time involved in lowering the instrument to bottom, and anticipate problems with wire-line units or other surface equipment, the usual solution to this problem is for the operator to overestimate the time required, “just to be safe”. This then results in time lost waiting for the timer to expire with the instrument in place, as well as unnecessary risk of stuck pipe resulting from not moving the drill string. The benefit of the timer is that it can be used when dropping or “go devilling” the survey; the operator knows exactly when the lights will come on and can minimize the length of time that the pipe is still. For Magnetic single shot surveys taken on wireline, timing devices are being replaced with electronic sensors which detect either the lack of movement as with a motion sensor or more commonly, the presence of non magnetic materials, as with a “monel” sensor. The motion sensor detects when all motion has stopped for a given time (usually about thirty seconds), before activating the camera unit. This system has several drawbacks; if the descent of the survey instrument is interrupted for any reason below surface, a wireline problem for example, the motion sensor will detect the loss of movement and fire the camera resulting in a mis-run. The motion sensor is to some extent mechanical: it employs a movable element to detect motion and this may stick or lose sensitivity again resulting in a mis-run. From a floating rig, the downhole movement of the drill pipe imparted by the heave of the ocean, may affect a motion sensor, particularly at shallow depths. A “monel”, or non-magnetic collar sensor, is not subject to these limitations. It senses the change in the surrounding magnetic field as it enters the non-magnetic drill collar. Most monel sensors must be in a non-magnetic environment for a set time, as a safety factor, usually from thirty seconds to one minute before firing the camera unit. This serves to ensure that the instrument is actually seated in the

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non-magnetic collar and allows the compass card and inclinometer in the angle unit to settle before the picture is taken. Timers and sensors should always be surface tested before use. Camera The magnetic single shot camera has three main components: the film disk seat, the lens assembly, and the lamp assembly. Unlike normal cameras, the single shot camera unit has no shutter mechanism, the exposure of the film is controlled instead by the timing of the light illumination. In most instruments, the lens assembly comes pre-focussed and no field adjustments are necessary. Angle Unit or Compass This is the measurement device. The inclinometer measures the inclination of the wellbore, and the compass measures the direction or azimuth of the well. These devices are normally designed for a specific application and vary in design and principle. They may measure inclination only, high side (for use with mud motors), a combination of inclination and direction, they may use pendulums, weighted floats or air bubbles. Perhaps the simplest inclinometer is one which that is used for measuring very low inclinations, the bubble inclinometer. Somewhat like a round carpenter’s level, it is very sensitive to low inclinations and is often used to survey vertical holes such as those drilled for conductor pipe where absolute verticality can be critical. Just as simple, and using the same principle, is the “low ball” type inclinometer, used not to measure inclination, but to identify the “low side” of the hole with a small metal ball enabling the gravity tool-face of a deflection tool, such as a mud motor, to be measured in an environment where magnetic interference precludes the use of conventional angle units. These are the simplest but least used inclinometers as they apply only to special cases. The more commonly used angle units fall into three basic categories: Cross-Hair Pendulum — Compass One of the most common types of angle units, for inclination and direction up to twenty degrees. The compass card is free to rotate inside the housing and maintain a reference to magnetic north. The inclinometer is an independent and free swinging pendulum cross-hair. The compass card is printed in reverse in order for the pendulum, which naturally falls to the low side, to depict the direction as it should be on the high side. The survey disk is read as correct. Care should be taken when interpreting gravity tool face using this type of angle unit.

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Scale Inclinometer — Compass Similar in principle to the pendulum cross-hair, this angle unit has an independent weighted inclinometer which appears as a scale superimposed onto the compass card on the survey photo disc. This type of angle unit is normally used for higher inclinations ( above twenty degrees). Depending on the manufacturer, gravity toolface is interpreted either “as read” or is reversed. Care should be taken to establish the correct method of determining gravity toolface, before using the single shot for downhole orientation. Floating Ball Inclinometer — Compass This type of angle unit utilizes a compass ball floating in fluid. The ball is inscribed with both azimuth and inclination. The cross hair sight is centered in the instrument and does not move, rather the compass ball tilts and rotates beneath it. Because the inclination and azimuth are not read independently, the angle units must be manufactured Geographically specific for the area or zone in which they will be used. This is normally identified by a stamp on the angle unit itself. Magnetic Multishot Survey Instrument The magnetic multishot survey tool differs from the single shot tool in that the timer is programmed to take a series of readings separated by a preset time interval, and the camera unit is designed to take a series of recordings instead of just one as in the single shot. The battery tube is often lengthened in order to accommodate a greater number of batteries. The running gear used is normally the same for both types of survey, and the compass units are usually interchangeable. The Multishot Timer Depending on the manufacturer, some tools allow the operator to specify the interval between shots, while others are fixed. This interval is commonly in the one to three shots per minute range, and in normal applications, is adequate. As the instrument is dropped or “go devilled” inside the drill pipe, and the surveys taken when the pipe is placed in the slips on tripping put of the hole, in most cases, one survey per minute would be acceptable. The capacity of the Multishot to store data depends upon the amount of photographic film that can be stored in the camera unit. In the case where the pipe is pulled extremely slowly, or reciprocated for long periods, and where the hole depth dictates a lengthy trip out of the hole, longer periods between shots can extend the running time of the instrument and allow a full survey in one run.

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The Multishot Camera These also vary with manufacturer, but do not differ much in principal. Basically the camera consists of a film magazine spool, which is loaded by the operator and installed in the tool, a guide spool which passes the film across the focus of the camera lens, and the take-up spool which stores the exposed film. The photographic film is, of course, light sensitive and must be handled either in a darkroom, or a portable developer bag (often supplied with the tool ) prior to development. In some types of tools, the film spools fit into separate cartridge-type magazines which can be preloaded and interchanged outside the darkroom without fear of exposure. The other feature of the multi-shot camera is the drive mechanism, which turns the film spools in synchronization with the exposure-timer. The drive mechanisms are usually simple worm-drive devices or solenoid plunger-ratchet type. The film, when developed, shows as a series of shots spaced along it. The operator, by carefully recording bit depth against time, can match individual shots with given depths, and calculate the survey using this data. Because the multi-shot takes continual surveys, some are unreadable due to pipe movement. The valid surveys are found at the points where the pipe was set in the slips for a connection and the compass was still. Because of this, the common interval between surveys is equivalent to the length of a stand of drill pipe. Possible Problems With Reading Single Shot Records

Problem Probable Cause Record is very light Disc was improperly exposed; check

battery An irregular shaped pink or black space on the record

An air bubble was trapped below the film. Shake the tank when developing.

The entire record is black Disc was exposed to light before loading, while loading or while unloading.

Crosshair is clear but background is dark or only faint images appear.

Instrument was moving while record was being taken.

Crosshairs are not on readable scale Drift angle is greater than maximum limit of the compass being used.

To protect the magnetic single shot instrument when lowered or dropped into the wellbore a protective casing is used. This protective casing protects the instrument while being retrieved or lowered and it also prevents drilling fluid from contaminating the tool.

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Gyroscopes The industry began developing what is now most commonly referred to as “rate-gyro surveying systems” in the late 1970’s. The goal of the overall development was to adapt modem aerospace guidance techniques for oil industry applications with the following objectives:

1. Provide a significant enhancement in survey accuracy. 2. Provide a means of quality assurance.

The existing surveying methods could not provide a reliable means of quality assurance for the level of accuracy wanted by the industry. Wellbore survey technology can be classified into four groups, as follows: 1. Inclination Only Device (Totco) 2. Magnetic-Based (film-based / electronic, single I multi-shot, MWD, steering tools, dip-meter) 3. Free-Gyro Systems (film-based/electronic) 4. Rate-Gyro Systems The Gyroscope A Gyroscope is basically a balanced, spinning mass, which is free to rotate on one or more axis. The basic operation of a gyroscope can be compared to a spinning top. As long as the top spins fast enough, it attempts to hold its vertical orientation. If the top were propelled by a spin motor at a particular speed designated by its mass, it would stay vertical for as long as the motor ran, that is, if no external forces acted on it. This is the simple basis of all gyroscopes used in navigation, a spinning mass that through its momentum becomes resistant to external forces and attempts to maintain an orientation like the top in space. The term “resistant to external forces” is important, for a perfect gyro cannot be built, that will not be upon by external force and react by movement. The classic example of a natural occurring gyroscope is the planet Earth - a spinning mass attempting to hold a particular orientation in space established long ago. Even the Earth is not a perfect gyro. It reacts to external forces with some movement, or drift, off its orientation. Fortunately, the drift is very small. The next step in basic gyro understanding is the two-degree-of-freedom gyroscope, the same kind used in the oil. Free-gyros have been used in wellbore surveying since the 1930’s.

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The frames supporting the gyroscope, and allowing this freedom of rotation are referred to as Gimbals. Because gyroscopes can be extremely complicated, we will look at simplified gyroscopes initially, in order to understand the forces working upon them. The gimbals isolate the gyro from the base so the spinning mass can attempt to maintain its original orientation no matter how the bass moves. As the probe moves downhole through different directions and inclinations, the gimballing allows the gyro to attempt to maintain a horizontal orientation in space. In performing a wellbore survey, the gyro is pointed in a known direction prior to running in the well, so throughout the survey the spin axis attempts to hold its surface orientation. Note that a compass card is aligned with the horizontal spin axis of the gyro. Survey data is collected downhole by affixing a plumb-bob assembly over the compass.

Figure 6-1 Simplified drawing of a gyro At each survey station a picture is taken of the plumb-bob direction with respect to the compass card, resulting in readings of wellbore azimuth and inclination. The plumb-bob always, as a pendulum, points down toward the Earth’s centre. When the tool is inclined off vertical, it points out the inclination of the well on the concentric rings and the azimuth by correlation with the known direction of

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the gyro spin axis established at surface. There are also electronic, surface read-out free-gyro systems which eliminate the plumb-bob. Components A gyroscope is a spinning wheel whose spin axis can move relative to some reference mount. For the sake of simplicity, the major components of the gyro are comprised of: The Spin Motor, the main characteristic of which is “angular momentum”. The Gyro Case which is the outer enclosure. The Gimballing System which is the structure carrying the spin motor. The gimballing system isolates the spinning rotor from the gyro-case if the gyro-case turns around the outer gimbal axis or if the gyro-case turns around the inner gimbal axis. The Gimbal suspension, which includes:

- the ball bearings (or gimbal bearings) between the gyro-case and the outer gimbal, and between the outer gimbal and the inner gimbal;

- the rotor bearings holding the spinning rotor in the inner gimbal.

- an Angular Pick-off which senses relative angular displacements

between the gyro gimbal and the case.

- a Torquer which enables compensation for certain types of errors and precessing the gyro at desired rates.

Evolution of Gyroscopes Used in Surveying Oil-Wells The First Generation of gyro survey instruments used a conventional two degree of freedom gyro to set a directional reference point. With this type of gyro the inclination is given by a plumb bob located inside an Angle-Unit and a camera records the survey data. Reliable directional data depends on two things:

• The gyro must be accurately aligned to some known direction before being run down hole.

• The gyro must maintain this heading throughout the survey.

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Downhole a small camera regulated by a timer and powered by a battery pack takes pictures of the plumb-bob superimposed on the gyro compass card. These surveys supply accurate readings when carefully operated by an experienced surveyor. The second generation “Surface Readout Gyro” provides progress in the recording of survey data. A down-hole electronics package replaces the camera angle-unit and timer. A wire line supplies power and connects the probe with a surface computer that monitors probe performance and prints survey data as it is gathered. Accelerometers instead of Angle-Units are used to measure hole inclination. However the system still relies on conventional two degrees of freedom gyros for directional data. Problems with battery powered mechanical cameras are eliminated and survey data is supplied in real time. The surface computer can monitor probe performance, therefore time wasted by mis-runs is reduced. North Seeking Gyroscopes are comprised of a rate integrating gyroscope and an accelerometer. Sensitive axes of the rate integrating gyro and the accelerometer scan components of the earth’s rotation and earth’s gravity. Survey data is read by a downhole electronics package and transmitted to the surface computer via a single conductor wireline. The computer calculates azimuth, inclination, tool-face and monitors probe temperature. The system requires no surface orientation and is not subject to such problems as gimbal lock and gyro tumbling sometimes encountered with conventional gyros. The rate-gyro, meanwhile, measures the Earth spin rate vector. When the tool is stopped at a survey station, one of the forces acting on it is the spinning Earth force. In the case of the free-gyro system, the spin force causes the gyro to move or drift (gyro precession) off the surface orientation. Since the rate-gyro instead measures the Earth-rate force, for a given latitude, the system can also calculate the true-north force component (TN) due the relationship of the vectors. The purpose of the rate-gyro is at each survey station to calculate the true north direction with respect to the wellbore azimuth, which is aligned with the tool axis. Once the gyro is set spinning and becomes free in space, pick-off and torque coils measure the forces acting on the gyro and keep it aligned with the case. Prior to a survey, the rate-gyro tool is calibrated in a highly precise test stand at the service company’s facility. Just as the force-components of gravity vary to resolve wellbore inclination, the values for the Earth rate and true north vectors vary with latitude, inclination and the direction of the tool. When the tool is placed in the test stand, it is turned in a range of directions while its measurements of Earth forces are modeled with respect to a known reference. When the rate-gyro is pointed in different directions in the stand it measures varying component values for earth spin-rate on its sensitive axes.

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When the tool is at a survey station in a wellbore, with latitude and inclination known, the rate-gyro reading of the component of earth spin-rate will correspond to a particular true north reference as modeled in the test stand. A survey point can be calculated utilizing the combined readings of the rate-gyro and accelerometer. Once the accelerometer measures gravity to calculate wellbore inclination, tool high-side is also known. Combining the true north reading from the gyro, provides wellbore azimuth as the angle between true north and high-side. Systems of the type described require an electric wireline and provide real-time data at surface. Depth is derived from wireline measurement and the system can perform single or multi-shot surveys. During a multi-shot run, the tool is stopped at periodic stations and a mathematical formula is applied for the overall survey calculation. Survey Accuracy and Quality Control To achieve a high range of accuracy and devise a means of assuring it, is a significant, difficult, and expensive task. For simplicity’s sake, let’s say the accuracy goal is one foot per 1,000 feet of hole. This means that in a 10,000 foot wellbore survey, the operator is to be assured of bottom-hole location by plus or minus 10 feet. Although other survey technologies (magnetic and free-gyro) may achieve this range of accuracy some percentage of the time, they have no available means of quality control to assure it. In the case of magnetics, although the technology has seen much improvement, error variables such as magnetic interference, declination corrections, northern latitudes, even sun spot activity pose difficult quality control problems. The free-gyro’s major error sources are surface orientation, gyro drift and tool misalignment. No film-based survey device has an opportunity to achieve this level of accuracy with assurance because the film cannot be read to the accuracy required. To get in the range of one foot per l,000 feet requires azimuth and inclination accuracy’s in the range of 0.1 and 0.05 degrees, respectively. Very often, the terms accuracy and resolution of readings are confused. A survey system may be able to read survey data to 0.1 degree - that’s resolution, but providing that level of precision is a completely different matter. Modern aerospace guidance techniques employing rate-gyros and accelerometers provide the only current means of both providing this range of survey accuracy and qualifying the information. These systems can accomplish this through extensive quality control procedures because rate-gyros and accelerometers can be calibrated for a level of performance and monitored and checked for data quality.

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However, the accuracy of available systems varies. Reviewing a service company’s procedures for quality control and data verification is important to assigning a specification to a particular system. Rate-gyro and accelerometer quality also varies in its ability to achieve accuracy, and running procedures can also degrade survey quality. For example, if a survey probe is misaligned in the well, accurate readings degrade in the overall survey calculation. Rate-gyro system accuracy’s can also vary according to inclination and latitude. Some systems degrade, for example, above 75 degrees of latitude because the Earth and gravity vectors become smaller and more difficult to resolve. Gyro Errors External Forces In the case of a free-gyro survey system, forces causing the gyro to drift off its surface orientation lead to azimuth error. Typical causes for drift include system shocks, bearing wear and the one inescapable force - Earth rotation. During a free-gyro survey, attempts are made to monitor drift and correct for it. Drift The apparent drift of a gyro is caused by the influence of the Earth’s rotation. If a perfectly balanced gyro were located at the North Pole in a horizontal position, so that its axis of rotation would be at right angles to the earth axis, the rotation of the earth would indicate an apparent 360o turn of the axis in 24 hours, or an apparent drift of 15o per hour. At the South Pole, the same would be observed but in reversed direction. At the Equator, the gyro axis would be parallel to the earth axis and the gyro would not show any apparent drift. The apparent drift caused by the rotation of the earth is corrected by applying a special force to the inner gimbal ring. An adjustable weight in the form of a screw is attached to the inner gimbal ring and has the effect of a vertical power on the gyro axis. Due to the phenomenon of precession, this force turns the outer gimbal ring. By adjustment of the screw, it can be set to offset the apparent drift at any geographic latitude by an identical counter acting force, to the effect that the gyro turns simultaneously with the rotation of the earth. The screw is set for the particular latitude where the gyro is used. Temperature Warming of the gyro can cause slight dislocations of the centre of gravity due to the varying expansion coefficients of the different materials, such as copper and steel. Possible errors caused by rising temperature are compensated by a piece of

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bimetal which is mounted on the inner gimbal frame and offsets sufficiently the unbalance caused by temperature through a bending effect. lntercardinal Tilt Error or Gimbal Error The gimballing error encountered in a directional gyro is also known as intercardinal tilt error. Gimbal errors occur when the angular motions of gimbals do not correspond to the actual motion occurring about their reference axes. When a gimbal axis transducer is used, its output measures relative motion between gimbals, which is not necessarily the actual angular motion of the base. The gimbal error depends upon borehole inclination and the hole direction related to the reference direction. In order to minimize such errors, when the surface orientation is carried out, the spin rotor axis should eventually be positioned in a plane parallel to the overall well direction anticipated, so as to result in a difference as little as possible. Measurements While Drilling (MWD) Most commercial MWD Systems use mud pulse or electromagnetic telemetry to transmit survey data during tool operation. In Mud Pulse the mud pressure in the drill string is modulated to carry information in digital form. Pressure pulses are converted to electric voltages by a transducer installed in the pump discharge circuit (standpipe). Then this information is decoded by the surface equipment. Tool measurements (toolface, inclination, azimuth etc.) are digitized downhole and then the measured values are transmitted to the surface as a series of zeroes and ones. The surface pulse decoders recognize these as representations of tool measurements. Many variations on the signal decoding exist and manufacturer should be contacted to determine their method, although this can be proprietary information. The electromagnetic system is more complicated and will be discussed later but it essentially it measures the voltage potential difference at surface, that is generated by the electromagnetic waves sent from the tool through the formation to surface, into zeros and ones as well. With mud pulse telemetry there are generally three main systems in common use today. The positive pulse telemetry uses a flow restrictor which when activated increases the stand pipe pressure. Negative pulse tools have a diverter valve that vents a small amount of mudflow to the annulus when energized. This decreases standpipe pressure momentarily. The third method is by standing (or continuous) wave pulsers that use baffled plates, which temporarily interrupt mud flow creating a pressure wave in the standpipe. Changes in relative rotation speed of the plates changes the wave phasing. These phase changes are identified aat surface and decoded.

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Positive pulse telemetry creates pressure pulses with a poppet type flow restrictor or a rotatlng valve. Unlike the negative system, flow is never interrupted. The system is much more tolerant of LCM and mud solids than either of the others, making its downhole reliability very good. It is also the least affected by pump and mud motor noise. The tool can have its valve gap modified if pulse heights are insufficient, or if too much pressure drop occurs in the tool during valve closure. Because of the large pulse amplitudes, positive pulse is generally thought to be the most reliable for decoding.

Figure 6-2 Schematic of positive and negative pulse valves When the negative pulse system is activated, a diverter valve channels mud flow to the annulus, decreasing standpipe pressure. The timing of these pulses is decoded into a series of l’s and 0’s, effectively transmitting tool data. Advantages of the system include low power consumption, and ease of decoding. The completeness of the valve opening/closing create very clean waveform - pulses downhole. This tends to reduce effects of pump noise by making the pulser signal easier to decipher. Negative pulse systems must maintain a pressure differential between the drill pipe and the annulus in order to create a pressure drop when the diverter valve is opened. This may limit allowable jet or nozzle selection at the bit. This is the main disadvantage of the negative pulse system. All of these systems use surface transducers to record standpipe pressure. It is recommended to provide a mounting device to allow the transducer to be vertically mounted above the mud flow (threads down) to avoid mud solids settling out on the transducer element. This condition would create decoding problems by reducing transducer efficiency.

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Hydraulic Considerations The drilling fluid system introduces noise during pump operation which can make MWD surface equipment struggle to decode the tool signal from down-hole. MWD performance can be improved by careful attention to the mud system. • Keep the pump rate as high as possible for the required flow rates. Mud

pump pressure pulses at increased pump frequency are filtered out by MWD surface gear. This reduces the effect of pump noise on the MWD signal.

• Make sure the pump liners are in good condition. Damaged liners cause so

much noise they may even have an identifiable signature on the surface pressure record. If the MWD engineer mentions a bad liner signature - at least check it out.

• Keep the pulsation dampeners fully charged. The ideal mud flow would be at

constant pressure, the only changes in system pressure being those of the MWD pulser. Properly charged dampeners go a long way towards this ideal condition.

• Maintain as constant weight on bit as possible, particularly when drilling with

mud motors. Changes in motor torque will themselves cause changes in standpipe pressure. By keeping these to a minimum, reliability of signal decoding will be improved.

• Mud additives should be mixed as uniformly as possible. Changes in viscosity

and suspended solids concentration can attenuate the MWD signal more than usual. Slugged additives can also clog the tools.

• Avoid duplex mud pumps if possible. Their noise is particularly difficult to

filter. The mud column is the mud pulse MWD tool communication line to the surface. Keeping this system clean, uniform and as free as possible of induced noise can materially improve the quality of the MWD job. Electromagnetic MWD Directional surveying with the EM MWD tool has become a reliable and cost effective means for surveying both directional and horizontal wells. Advances made over the past years have significantly improved tool reliability when drilling in harsh underbalanced air/mist environments, and have also overcome some of the earlier obstacles associated with operational depth. Additionally since the rig pumps do not have to be cycled to receive a survey, the overall survey cycle time can be

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reduced and can add up to a significant length of time on high ROP wells. The EM MWD is a viable and reliable method to survey underbalanced wells where conventional mud pulse survey tools cannot work.

Geoservices began research into electromagnetic type transmission in 1982 with the first successful field test achieved in 1983. Commercial operations commenced in 1984 when the technology was applied to a pressure and temperature gauge and this was followed in 1987 by an MWD tool. Electromagnetic telemetry consists of the injection and transmission of a low frequency electromagnetic carrier wave into the ground. The phase of this carrier wave is specially modulated to carry the raw directional and formation evaluation parameters. Electromagnetic transmission in an oil well can be approximated to the way ordinary coaxial cable can act as a wave guide for signal propagation. The casing string and drill string can be considered as the main coaxial cable conductor, while the formations situated at infinity can be considered the shielding or external conductor. Formations close to the wellbore, between the two conductors, can be considered as the insulation. The electromagnetic wave travels (radially) through the formation to surface, guided along the electrically conductive drill string. The electromagnetic low-voltage signal is then detected, amplified and decoded at surface. The low frequency of the electromagnetic wave is chosen to optimize the data transmission rate while minimizing signal attenuation and to give the longest possible transmission range. Dry air or gas drilling provides results that are similar to a non conductive mud. Nitrogen, air, or methane are excellent insulators therefore adding a mist or foam to these gases will improve transmission efficiency.

One important consideration, when using the EM MWD, is the operational depth. The average depth of operations today is 2315 m (7600 feet) TVD. The standard tool has been successfully run to 3750 m (12,300 feet) TVD, utilizing a single point of transmission. An extended cable and the latest extended range EM MWD tools have extended this operational depth limit. Since the dependence on drilling fluid properties is minimal all hydraulic concerns or pump issues can be ignored with EM systems. They also have no moving parts which increases their reliability over mud pulse systems. Directional Sensor Package The directional sensor package of any MWD tool consists of a set of triaxial inclinometers and triaxial magnetometers to measure respectively hole inclination (drift) and hole direction (azimuth). The triaxial inclinometer measures the 3 orthogonal axes components of the earth gravity vector ‘G’. The triaxial magnetometer measures the three orthogonal axes components of the earth

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magnetic field vector ‘H’. The reference axes for measurements are usually as follows but each vendor’s tools can have different reference convention. “Z axis’ along the tool axis and positive toward surface. “Y axis’ in a plane perpendicular to the tool axis and used as reference for angular tool face measurements. Usually passing through the scribe mark of the collar (reference for angular tool face). “X axis” orthogonal to both Y and X axis. Both set of orthogonal axes for inclinometers and magnetometers are aligned between each others at manufacturing and assembling. Nevertheless, these mechanical alignments are not 100% accurate and a calibration (in town) of the sensor package must be performed by the MWD vendor. All sensors are subject to drift, both in temperature and due to possible internal magnetic interference. All drill collar materials must be non-magnetic to avoid drill string magnetism interference with magnetometer measurements. The calibration process is best achieved in a controlled magnetic environment and using “roll test procedures” which output correction coefficients which are entered into the software for computation of inclination, azimuth and tool face. Incorrect entry of these coefficients have caused large errors in surveying and could have catastrophic consequences. The same applies for local magnetic declination entering to the surface system. Tool Face Tool face (TF) is an angular measurement of the orientation of the BHA versus the top of the hole (gravity tool face) or magnetic north (magnetic tool face). Reference for tool face is usually the “Scribe mark” on the non-magnetic drill collar. Computation for tool face angles are made from magnetometers. Accuracy requirement for tool face (typically +/- 1 to 2 degrees is not at all the same as the one for Azimuth (typically +1- 0.5 degrees). None of the directional sensors in common use have any moving parts other than the pulser system and they are all very reliable. Several vendors have retrievable systems which can be replaced without pulling the drill pipe by using slickline. All MWD sensors must be calibrated in special facilities free of magnetic interference. Correction coefficients are entered by software in surface processing.

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Compass & Grid Corrections Magnetic survey tools do not reference to geographic north but to the earth’s north magnetic pole. Since geographic and magnetic north differ an error is introduced in the survey called magnetic declination. However these values are well known at most places on earth and are easily added to survey calculations. The grid correction is a survey error caused by differences in map orientation. Most maps are drafted to have true north be vertical. Because the maps are on rectangular coordinates and the earth is spherical, errors occur at various surface locations. These errors are not added to the raw data display on MWD or any other type of survey, but are used in map plotting of the survey. Finally, MWD tools have an internal correction caused by misalignment of the sensor with the drill collar during assembly. It only affects toolface readings and is added in by the MWD engineer during display set up. While the correction does not affect the drillers operation, be aware that it exists and is a possible source of survey error if entered incorrectly. Power Supplies Tool power is supplied by battery, a downhole alternator or both. Batteries allow tool operation without mud flow. However their energy is limited. This means that the operating time is limited, and the sensor power output is limited. While not normally a problem on directional - only services, with the addition of formation evaluation sensors, the problem becomes more obvious. In addition, batteries have limitations in temperature. Alternators solve the energy limit problem but introduce some of their own. Mud pumps must be above a ‘drop-out” minimum rate for them to work, the turbines necessary to drive them can clog, and they limit the flow rate range in which an individual tool can operate. Alternator tools must be tailored for the pumping system in use on the rig. Turbine stages are configured for the expected mud flow rates. Expected flow rates are important information to set up the job with alternator tools. The drilling engineer should be sure the MWD vendor has this information well before the job is to begin. The alternator tools have an internal over-voltage protection device which stops the tools should the alternator output exceed its limit. Transmission Trigger All MWD tools have a signal mechanism to tell the tool to begin data transmission. In this way the surface equipment will be synchronized with the downhole tool’s data pulses allowing decoding.

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Surface Equipment The surface equipment performs the pressure pulse decoding and survey computations. All vendors use an operator console which is electrically connected to the transducer and rig power, and a remote driller’s or rig floor display. The operator’s console has digital readouts for azimuth, inclination and toolface. The driller’s dial, or rig floor display, has indicators for azimuth and inclination. They also have a display for toolface orientation. Data Transmission Formats MWD tool data are sent to the surface as a series of 0’s and 1’s. The pulse tools are programmed to begin a data sequence with a distinct marker recognizable by the surface decoder. EM MWD tools have a data on demand format. Data are then transmitted in order, with a certain number of 0’s and 1’s representing a ‘word” or frame of information. Transmission formats are programmable at the surface to send data in different styles. For example, toolface becomes very important while slide drilling with a mud motor. Since an entire sequence may take 3 to 5 minutes to transmit, it would be wise to use a format that sends several toolfaces per sequence, particularly during rapid drilling. Conversely, for pore pressure detection, high rates of gamma ray and resistivity are needed. The tool programming needs to be planned according to the objective of the bit run. Tools often detect rotation by measuring the x and y (normal to tool axis) magnetic fields. If change exceeds 240 degrees over a 10 second period, the tool switches to rotating mode. Rotating mode data will be sent uphole if the tool is programmed to do so. Synchronization of data bits is important! If the surface equipment loses communication with the downhole tool for even a short time, whole timing sequences of data will be lost, as the surface equipment cannot re-establish which bits represent which downhole data. A program has been written into the tool logic to recognize these events and produce warning error codes. Sometimes the existing rig hydraulics and necessary drilling program makes detection at higher data rates difficult. Several of the MWD tools can be reprogrammed to transmit at lower speeds. While this will increase the time between surface readings, it certainly is better than no surface readout at all! MWD Information In addition to the directional information today’s MWD equipment also provides other information depending upon the tool type and sophistication. New generation logging equipment is being developed as we speak to reduce or

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eliminate the need for open hole logging. Although the cost of this service can may be double the directional package the ability to get information quicker reducing the time the hole is unsupported with casing can be invaluable. Unfortunately with this extra cost also comes the increased “lost-in-hole” charges should the tools become stuck down hole. Gamma Ray All MWD tools are capable of providing this service and this tool is frequently used while drilling horizontal wells. The term commonly referred to is “geosteering”. The probe measures natural gamma radiation and has a depth of investigation between 8 to 15 inches depending upon your trust in the technology. Recently two variations in this tool have been made available to the industry. One type is called “focussed” gamma ray and the other is called “dynamic oriented” gamma ray and both are used to help reduce geological uncertainty. The focussed tool uses a shielded gamma probe with a known orientation to the high side of the motor. If the vendor is smart, the shield is oriented directly to high side of the motor. The data can only be interpreted into high side or low side readings if the tool is not rotating. By positioning the motor high side, a gamma reading of the high side of the hole can be obtained. The tool is generally oriented and then dragged backwards to provide a section view of the high side gamma readings. Unfortunately the drill string typically turns while being dragged backwards so true high side readings may not be obtained. Using this information the geologist can compare the gamma readings to other vertical logs and determine if he is still in the sand. The “dynamic oriented” gamma ray tool has an accelerometer tied into the shield orientation so every time a gamma count is taken the tool face is also recorded to determine what portion of the hole the reading came from. This data is then stored into separate banks of high side and low side data that is sent to surface so the changes in gamma counts on the high side and low side of the hole are known while rotating. Static checks can be made similar to the focussed gamma ray tool. It is important to remember that if you are slide drilling this data is only being collected from the high side of the motor and not necessarily from the high side of the wellbore. The oriented gamma ray tool had excellent success in horizontal wells and reduced the number of sidetracks required since they were able to stay in “the zone” better. One project recorded an average of 2 sidetracks per lateral without the tool and one sidetrack per 50 wells with the tool.

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Downhole Pressure Several companies have developed pressure gauges that read annular and drill pipe pressure. This is a very important tool for underbalanced drilling and enables appropriate decisions to made while drilling (see Planning and Underbalanced Horizontal Well). Temperature Surveys Temperature surveys are also taken from the inside of the drill string to monitor downhole circulating temperatures. This is important to protect the MWD tools that have lower temperature limitations. The main risk with high temperatures besides damaging the probes is a dangerous battery explosion potential when the tools are brought back to surface. Other Sensors Currently a limited number of logging while drilling tools (resistivity, density, neutron porosity and acoustic porosity) are readily available. Also vibration, bending moment, torque, bit RPM and weight on bit sensors are available on some products. Limited quantity and sizes are currently available for these sensors and many are sensitive to the dogleg severity they are either slide or rotated through. In this decade look for some remarkable changes in the available sensors of MWD and LWD equipment. Specfic Features of the Computalog MWD System The Computalog MWD system consists of s Secondary Acquisition Module (SAM) which controls downhole data transmission, a Computalog Interface Display (CID), a Rig Floor Display (RFD) for remote display of data, and a pulser which generates the signal. A personal computer is used by the operator for configuration, displaying and logging of data.

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The standard system provides drill string orientation and temperature information as measured downhole by the SAM. The SAM is initially programmed through the CID at surface to operate in a user specified mode downhole. This mode determines how and in what order the data will be acquired from its own sensors and from other sub-assemblies (gamma ray). The SAM is cued by a mud flow sensor to begin a transmission sequence; this consists of a synchronization pulse followed by frames of data. The typical frame pattern consists of a long frame containing survey data (typically 120 sec) followed by repeated short update frames (12 sec) of one or more critical data items. All data is transmitted using a patented encryption algorithm which ensures data integrity. The data transmission will shut down when the mud flow stops, or earlier, depending on the mode of operation. Typical modes include survey, steering, raw, calculated etc. On surface, pressure samples are digitally filtered and correlated to extract the average pressure, the position of the synchronizing pulses and the position of the data pulses. Using a combinatory algorithm, the pulse positions are decoded to yield the values in the exact format and resolution in which they were transmitted. MWD Surface System The MWD surface system consists of an interface display for data reception, a rig floor display for remote display of data, a PC which logs the data and a printer. The mud signal is digitally filtered within the interface display and five integrity checks are completed on all data. These checks enable the system to recognize pulses of 9 psi amplitude in a system operating at 4300 psi. these filters are programmable for various applications. The data can be plotted on screen or on the plotter on an ongoing basis during MWD transmission. The software also evaluates the data transmission to aid the operator for troubleshooting. Rig sensors are easily installed and connect to one cable on the rig floor. This cable transmits sensor information from the hazardous location to the interface display in the operations wellsite shack. Additional readouts can be connected to provide data to other locations around the rig. MWD Downhole Components The downhole components are housed in a non-magnetic drill collar. The MWD probe is bolted to the pulser sub (in the case of the negative pulse system) and screwed into the top of the MWD NMDC or bottom landed into a sleeve (positive pulse system). The gamma sensor for the positive pulse system is at the top of the MWD NMDC whereas the on the negative pulse it is at the bottom.

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Sensors The secondary acquisition module is a programmable microprocessor-based subsystem. It acts as a master module downhole, sampling seven sensors, collecting and transmitting data from other modules within the downhole assembly. Pulse format is generated and transmitted to the pulser for the data transfer to surface. Data is collected from: • Three axis magnetometers and accelerometers • Calibrated temperature correction for sensors • Mud flow determination by sensor or switch • Generation of error bits for high temperature, magnetic anomaly and

accelerometer failure. The gamma ray sensor is a digital acquisition system utilizing a scintillation detector. It is field programmable for sample time and rates (typically every 24 seconds) and stored in non-volatile memory. As previously discussed a focussed or dynamic oriented gamma ray options area available. Programmability The operator can program the tool (on surface) for the parameters needed for a specific well. Some programmable features include: 1. Data rate 2. Order in which data is sent to surface 3. Length of time in which sensors are sampled for acquiring data. 4. Angle at which tool changes from magnetic updates to gravitational updates

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5. Type of data sent to surface (raw or calculated) 6. Threshold at which the magnetic anomaly or vibration flag is set 7. Which integrity checks are sent to surface after transmission of data 8. Resolution of rapid tool-face updates (normally 2.0 degree every 12 seconds) 9. Threshold for rotary mode. Tool-faces are not sent during rotary mode to

conserve power consumption

Transmit Times for Various MWD Configurations Directional – raw data 232 sec

Pressure up delay 45 sec

Static survey Temp, angle, azimuth, TF 139 sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

Directional – calc data 153 sec

Pressure up delay 45 sec

Calculated survey Angle, azimuth 48 sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

TF u

pdat

e 12

sec

Directional and gamma – raw data 232 sec

Pressure up delay 45 sec

Static survey Temp, angle, azimuth, TF 139 sec

TF update gamma ray reading 24 sec

TF update gamma ray reading 24 sec

Directional and gamma – calc data 141 sec

Pressure up delay 45 sec

Calculated survey Angle, azimuth 48 sec

TF update gamma ray reading 24 sec

TF update gamma ray reading 24 sec

During the static survey continuous temperature, drift angle, azimuth and tool face updates are provided by the tool. Selection of Survey Equipment Now that we have discussed the different survey systems how does one select the correct system for the job? Many factors are included in this selection and the following are the most common: Target Size Small targets of 5m radius (15’) can be very difficult to reach with single shot (SS) equipment although many wells with targets of this size have been drilled with SS. The main concern lies within the estimation of the PDM’s reactive torque. An error made in this estimation can have a significant affect on the azimuth of the well and result in missing the target to the left or right. When slide drilling the

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tool face can change and unlike when drilling with MWD would not be known until the next survey. Well Depth This is very are dependent but typically in Canada once the depth exceeds 1,000m (3,000’) the ability to adjust for reactive torque is too difficult. Drilling Motor Type For single shot operations a high speed low torque motor is used. Drilling with medium or high torque motors and SS equipment is a crooked well path waiting to happen. Drilling Fluid With underbalanced drilling operations the mud pulse survey equipment can not be used since they depend upon accurate pressure pulses read at surface. The signal in two-phase fluids can not be read due to the fluid compression and noise. This can be the same problem in aerated or poorly maintained drilling fluids. Either the EM MWD or steering tools are used in these cases. Rig Equipment Sometimes the only rig available for the job has 3 ½” or smaller drill pipe (sometimes completion rigs are used). Although SS equipment has been used to drill directional wells with this limber of equipment, it is important to have a very experienced SS directional hand (few around anymore) who can accurately estimate the reactive torque. Duplex pumps can also create many signal detection problems with the mud pulse MWD equipment due to pump noise. Build Rate and Dogleg When build rates exceed 5 or 6 o/30m, achieving these build rates can be very critical to reaching the target. With MWD equipment a spot check in the middle of a single can quickly be made to verify the build rate and tool-face early and modify the percentage of single slid and adjust tool-face if required. Some of the MWD and specialty logging while drilling equipment have limits on the doglegs they can be rotated through due to bending stresses. Terminal Angle As the inclination increases the time it takes to drop a SS survey increases. Typically with inclinations greater than 40o it becomes more cost effective to look at MWD equipment. Typically for a well that is at 40o and 300m (1,000’) deep the

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survey time for SS is in excess of 30 to 45 minutes. This can have a significant impact on the average ROP for the day. Well Profile It is not recommended to use single shot equipment on the following well profiles:

• S-curve with very short tangent sections • Horizontal wells • Extended reach wells • Complex profiles with build and turn sections

Formations In every geographical area of the world, there are certain problem formations that either don’t build as expected or will collapse if left open too long. These are not good places to use single shot equipment due to higher potential for severe doglegs and the extra time taken for surveys with the drill string in a static mode. Required Survey Accuracy As the required survey accuracy increases (very tight TVD or azimuth control) the equipment selection shifts from SS to MWD to Gyro to Magnetic Ranging. Proximity of Existing Wells or Magnetic Interference When drilling re-entry wells out of casing or passing by existing cased wells, magnetic interference becomes an important factor in equipment selection. The azimuth accuracy becomes doubtful with all survey tools except gyros. Typically magnetic interference can occur within 15m (49’) of steel but both high and low variations have been witnessed. High Rate Drilling Horizontal Wells In Western Canada many horizontal projects in the oil sands can drill as fast as 100m/hr (300 ft/hr). At these rates using the EM MWD system can reduce the survey cycle time. One operator estimated he saved one day per well on his horizontal well project. The horizontal wells had a TVD of 500m (1,500’) and a total measured length of 2,500m (8,200’).

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Survey Accuracy The first paper that successfully dealt with this subject was prepared by Wolf and de Wardt, “ Borehole Position Uncertainty – Analysis of Measuring Methods and Derivation of Systematic Error Model”. The latest paper released is a summary of work completed by a small joint-industry group and a steering committee on wellbore survey accuracy – “Accuracy Prediction for Directional MWD”, SPE #56702. This section summaries some of the main points from these papers on sources of error with examples. The photographic single shot instrument is the least accurate tool. The inclination error can be as great as 0.5 degrees and 2.0 degrees in azimuth and is very susceptible to human reading error. The electronic single shots have essentially the same accuracy as all other MWD equipment 0.2 degrees on inclination and 1.0 to 1.5 degrees in azimuth. The gyro tools have a significantly improved azimuth error of approximately 0.2 degrees but similar accuracy for inclination. When considering survey accuracy for MWD tools there are several sources of error. In general all directional sensor packages have the same resolution but their accuracy is dependent upon their calibration and shift between calibrations. We have already discussed magnetic interference from BHA components or local area interference. Tool misalignment is the error caused by the tool being out-of-parallel with the wellbore axis. The value assumed for magnetic declination affects the computed azimuth, which comes from estimates on the magnetic dip and field strength. The last main source of error is drill pipe depth measurements. Mathematical models have been generated to calculate the position uncertainty of wells based these sources of error and the type of survey tool. The numbers calculated generate an “ellipse of uncertainty” for a 2 standard deviation error. Essentially what it provides is a 3D volume that the wellbore could be within (a 95% confidence level that the actual wellbore path resides inside this ellipse). Typical errors seen when comparing MWD to rate gyro surveys. Case 1: Horizontal well TVD of 500m (1,600’) Measured Depth to Casing Point of 700m (2,300’) Case 2: Horizontal well TVD of 1,450m (4,750’) Measured depth to casing point of 1537m (5,000’)

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CASE CHANGE IN TVD LATERAL OFFSET

1 6.6’ (2m) 46’ (14m) 2 4.9’ (1.5m)

Obviously errors of this magnitude can have pronounced effects on wellbore positioning.

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9 OPERATIONAL CONSIDERATIONS There are many operational decisions made between the directional driller and the operator’s representative. To cover all aspects of these considerations would be a book in itself. As with any drilling operation, the most important item on a directional well is TEAM COOPERATION. The biggest hurtle to overcome in any multi-disciplined operation is the egos that come together on-site. It is this human characteristic that if not properly controlled or utilized in a positive manner can be the downfall on a directional project. Many oil field workers are very good working with equipment and getting the job down but have a difficult time dealing with the various personalities on-site. Sometimes the school of hard knocks becomes a tough learning environment known as “Employment Survival – 101”. A group of team players that share their knowledge, communicate well and mutually arrive at the best solution will always produce the record well. In order to address some of the operational considerations that directional company representatives must consider, the following sections are prepared to address what affects the equipment and performance of a directional operation or what could go wrong. These items may be discussed in the field with the operator’s representative and it is important to realize the impact. As technologies are developed so will the potential problem areas increase. Rig Mud Pumps Too small of a mud pump can restrict the performance of the PDM and drilling rate. The PDM has an optimum flow rate operating range. Insufficient available flow rate due to pressure restrictions and/or liner sizing can result in poor hole cleaning in high angle wells. The pressure restrictions can also affect the MWD system utilized. As discussed earlier the negative pulse system requires a pressure differential between the MWD and bit of 4000 KPa. If smaller nozzles are required in the bit but the pump cannot handle the pressure the MWD system may not work or you may have to cycle the pumps more often just to get a signal. This can lead to hole washes and lost time. Duplex pumps produce more noise than a triplex pump and it can be very difficult to filter these noise out with an MWD system to allow decoding of the pulses received on surface. A low pre-charge can also decrease the efficiency of decoding pulse signals.

Solids Control Equipment This is a key area that affects all equipment performance. Poor solids control can plug up MWD systems, create aggressive wear on all equipment, reduce penetration rates, create potential downhole sticking situations and increase formation damage. In many cases poor solids control affects the mud properties and limits its ability to suspend solids. We have witnessed cases where circulation of the drill string after running to bottom was impossible because the solids settled out in the motor causing it to pack off. On horizontal wells drill solids are pulverized into smaller particles due to a grinding action. If the best attempt to remove solids is not made on the first circulation, these fine solids are left in the system and tend to increase formation plugging. Rotary Equipment When directionally drilling, it is imperative that all rotary equipment is in good condition. When table locks do not work it is extremely difficult to control the tool-face when slide drilling. Wrapping tugger lines around the kelly bushing to control tool-face is a very dangerous situation. Tong lines that are out of calibration can result in incorrect torque applied to critical connections that may result in motors backing off downhole. Automatic diggers that do not allow subtle increases in WOB can result in motors frequently stalling when trying to initiate drilling after each connection. This affects the average ROP and time spent drilling. Smaller diameter drill pipe will twist more due to torque than larger diameter. Single shot operations with 3 ½” drill pipe can become very difficult if not impossible as the depth increase beyond 500m (1500 feet). Insufficient hevi-wate drill pipe will quickly limit the depth you can drill to and still make any slide corrections. Drilling vertical hole to KOP with too small of drill collars can result in having to pick-up directional tools earlier than planned due to deviation.

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Grounding Of Electrical Equipment All MWD systems use computers and special algorithms to decode pulse or electromagnetic signals. In some cases poorly grounded light plants and generators have created sufficient interference to prevent clear reception of these signals. In some cases the signal noise is too large to filter out. Communication and Data Collection Equipment Although an extra cost to the job, a phone system between the drill floor and the command center can save considerable time and relay drilling concerns much quicker. Remote recording instruments that provide all drilling data to the command center also allows a more educated decision when drilling problems arise. They also allow others to review the overall operation from a different point of view than the driller. In some cases small pressure fluctuations noted on the standpipe pressure graph was all that indicated a failing bit. The performance trends are much easier to detect when a graphical display is available. Bit Selection and Life Although PDC bits have come a long way in their development they still have some restrictions in their directional applications. A very careful review of the formations being drilled through, especially in the build section, must be made. Their use in horizontal sections has seen dramatic improvement over the years. It is very important the correct motor be selected for these runs otherwise their design cannot be fully utilized. When building inclination or trying to turn the wellbore, the outer row of teeth on the bit has the biggest influence. When erratic build or turn rates are noted, or you can’t build or drop inclination, it may be the teeth are worn down too far to “get a good bite” on the formation. The effective life of bits used on directional wells is usually lower than normal due to the different loading applied to the bit. Remember when rotary drilling with a motor to add the table RPM to the motor RPM and select the bit based upon this. Motor Problems High temperature holes (greater than 100o C) can severely limit the performance life of motors. The temperature tends to cause the elastomer in the stators to swell and cause premature stalling. Hydrocarbon based drilling fluids can cause the stator lining to swell, loose strength and chunk out.

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Abrasive fine solids left in the drilling fluid may cause aggressive wear of the stator that will result in loss of power and reduced ROP. Excessive back reaming can cause motor connections to back-off. Rotating motors at RPM’s greater than 50 is very hard on the bearing and drive sections. Also rotating motors with adjustable housing settings greater than 1.8o can cause premature bearing failures. When drilling underbalanced the motor is typically not lubricated to the same degree as overbalanced wells. Consequently, some very strange wear patterns have been seen on these motors and they may not last as long. Unique “pressuring up” situations have been noted on small hole size (121mm) underbalanced wells. Not fully understood at this time but appears to be pressure and temperature related. Motors have pressured up within 12 hours of drilling but show no problems on surface when disassembled. Stators are vary susceptible to aggressive wear on underbalanced wells with solids contents greater than 5%. Some motors only lasted 12 hours. MWD Systems Most are susceptible to solids plugging and have a flow rate limit through the MWD NMDC. Most have a percent solids limit that they can function in. Not all systems can handle lubra beads (or similar additives) before plugging. Each type of system has its own limit to the type and concentration of lost circulation material before plugging. It is always better to discuss with directional company the potential of lost circulation and possible mud additives that may be added. Jarring with MWD systems in the hole can result in damaging the electronic components. If hole problems are a significant problem in the area consider a retrievable system. The only problem here is most retrievable systems have a lower reliability value (mean time between failure). On whipstock operations never mill out casing with an MWD system in the drill string. Excessive damage occurs to the MWD system that the operator will be required to pay for.

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Pumping acid or bleach through MWD systems prior to tripping out at the end of a well can be very damaging to the equipment. In some cases operators have had to buy complete strings of tubulars due to internal cracking and probe damage just because they didn’t want to make another trip to flush the hole. A unique problem noted with electromagnetic systems is the interference between two rigs working close together. In one case the rigs were 50m apart and each rig could read the signal from the other. There are methods in place to avoid this occurrence. Most electromagnetic systems require some conductive fluid in the wellbore. In some cases the entire signal has been lost when drilling with diesel due to its poor conductivity. Most standard electromagnetic systems have a limit to the depth they can drill to due to the resistivity of the formations between the bit and surface. Resistivity logs must be carefully reviewed and modeled before selecting this tool for service. Failure of Z-axis accelerometer results in incorrect inclination measurements. The variation of these values is very subtle in a horizontal well and must be closely monitored at all times but especially when there are TVD concerns. Most times when the value remains the same for three surveys the tool should be pulled and checked. Build Sections Typically a directional driller will try to get kicked off slightly above the planned point. They should never get to far above the line unless there is a long tangent or hold section to the target. On build and turn profiles for a horizontal well, the driller should try to stay on the line as much as possible since getting behind or to far ahead can result in sharp doglegs later in the well path. If the current motor setting is not achieving the desired build rate do not wait too long before tripping to change the setting. Unless the area build performance is very well known waiting too long can result in missing the target or sharp doglegs. Large hole sizes (greater than 311mm) that require high build rates (greater than 3 o/30m in some cases) may be drilled faster with a smaller assembly and then opened up. This is especially true for deviated surface hole where the formations are too unconsolidated to achieve the build rates. On long reach wells with the build section left open, it is prudent to make a couple of wiper trips (maybe a reamer trip) through the build section to smooth out any ledges. This will reduce the hole torque and drag values as the hold section continues to be drilled.

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Never ream a build section without MWD equipment since this is when most new holes are started. Always orient through the build section with a reaming assembly, watching the tool-face behaviour. Hold Sections Depending upon the inclination this is when correction for azimuth is very important. The first 60m of hole drilled should be surveyed every 10m (single) to ensure the hole is maintaining the desired path. Some operators have released the directional company too early in these sections and when trying to makeup some time they apply too much WOB and push the wellpath off target. Stabilized bottomhole assemblies work well in this section but will require reaming all the way to bottom since the directional assembly typically drills a smaller average hole size. Frequent wiper trips or pumping viscous mud sweeps are highly recommended when the hold section inclination is greater than 60 degrees. Horizontal Sections Most common problem in the horizontal section is getting too aggressive in changing the TVD. Abrupt changes may get you back into the zone quicker but can limit the horizontal length. In some cases when requested to climb in TVD very quickly the directional driller was unable to come back down and level off in the zone. Know the hard boundaries in TVD before attempting any TVD changes. Determine what could happen to the well productivity if it suddenly climbs too high or drops too low. Beds of cuttings typically build up in the horizontal section like sand dunes. This can be noticed if the drag or torque begins to increase over what a torque/drag program predicts. Routine short wiper trips to stir up these beds helps clean the hole and prevent sticking. Never make quick changes in inclination or azimuth at the heel of a horizontal well, as this will quickly limit the maximum length you can drill.

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Open Hole Sidetracks Biggest mistake made in this operation is pushing too hard and fast. It is imperative a good ledge is built before increasing the differential pressure on the motor. Do not rush the directional driller and have him drill faster once a ledge is built. Never test the ledge by placing weight onto it. This is the quickest way to break off the ledge. Once a good ledge is established slowly increase weight on bit in stages and drill by differential pressure (control drill). Use densified cement plugs whenever possible when planning to sidetrack a well off of cement. Remember the bit will take the path of least resistance so if the cement is softer than the formation the bit will drill up the cement. Plan to have at least 75m of hard cement below sidetrack point. When entering a sidetracked leg always orient through to minimize the chance of breaking off ledges or starting a new hole. Have a sidetrack plan in place and stick to it. Allow the directional driller to show his experience at telling when a good sidetrack has been created. Whipstocks Biggest problem on these operations is getting the well started in the right direction. When there is angle in the well and it has an established direction you can not just point the whipstock where you want to go. All drilling must be down by tool-face. When high build rates are required (greater than 20 o/30m) it is very easy to get behind the curve. Due to magnetic interference and/or position of directional sensors you may have to drill 30 or 40m of hole before you know if you are achieving the required build rates. If you only needed a change of 30 degrees you may already be behind the curve. Always survey more often in the first 2 to 4 singles to check build rates (every meter in some cases) once the sensors are in new hole. Many times the whipstock is plus or minus 25 degrees from where you planned it to be. Some whipstocks can fall in on themselves when set at tool-faces greater than 90 degrees left or right when the inclination is greater than 45 degrees.

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Magnetic Interference Whether it is from hot tools, solar flare activity or proximity to steel this can be a very bothersome concern. It takes requires careful attention by both the directional driller and the MWD operator to find these problems. Solar activity has produced local magnetic declination errors of up to 7 degrees in the northern latitudes. Imagine what 7 degree shift in azimuth would do to a 1000m laterals planned end point (122m offset). NWDC’s and motors shipped with casing or drill pipe can in some cases develop magnetic hot spots. It is also easy to record false readings depending upon where the tools are checked (on racks surrounded by drill pipe versus on the catwalk). Magnetic checks should always be taken at multiple spots along the equipment and averaged out. The preceding sections have captured some of the problems that can occur in the field. It is through good team work and communication that their effects can be minimized.

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Chapter

10 PLANNING AN UNDERBALANCED HORIZONTAL WELL Since 1992 there has been a steady growth in the number of underbalanced drilled (UBD) horizontal wells in Western Canada and the world. The actual number is hard to determine since there seems to be no regulatory office that maintains a record of these wells and the definition of UBD wells varies with individuals. The US Department of Energy has predicted that by the year 2000, 25% of all wells drilled will use some form of UBD technology. The use of UBD techniques to drill deeper and more complex wells has also increased. Unfortunately our understanding of all the technical aspects of drilling underbalanced is not complete. In particular, the drilling fluid phase behavior and drilling motor performance requires additional work. This paper serves as a brief overview of some directional drilling planning basics that are required to drill an underbalanced horizontal well. Equipment and drilling problems are discussed and a procedure used to test positive displacement motors (PDM) under two phase flow conditions along with a summary of the practical knowledge gained has been included. Introduction For purposes of this paper, an UBD well is defined as a well drilled while maintaining an annular hydrostatic pressure less than the reservoir pressure, allowing the well to flow. This may involve the use of single or two phase flow. Most individuals assume an UBD well utilizes two phase flow however, at least an equal number of wells have been drilled with single phase fluids in a near balanced condition. The most common gas of choice in two phase flow is nitrogen from either bulk supplies or generating systems, although air, compressed exhaust gases and natural gas may also be utilized. This paper does not deal with coiled tubing drilling (CTD) but the author recognizes its use and the fact it is an excellent method to consistently maintain an underbalanced condition. Underbalanced drilling with CT units is increasing in frequency and equipment improvements have provided more opportunities. The use of conventional drilling equipment is still the most common with readily available equipment for these operations. The following sections review the purpose and limitations of drilling underbalanced, planning and operational issues, potential equipment and drilling problems and concludes with a discussion on two phase testing of PDM’s.

Why Drill Underbalanced There are several reasons why wells should be drilled underbalanced but the primary reason in most cases is to increase production rates through reduced formation damage. There are several forms of formation damage including fluid incompatibility and pore throat plugging with drilled solids. The degree of formation damage and its effect on potential production rate varies with the producing formation characteristics. In some regions wells may not be drilled economically unless UBD techniques are employed. Production rate increases of 3 to 10 times the regional average have been seen. Due to reservoir aging and depletion, many Western Canadian reservoirs have experienced significant pressure reduction. Lost circulation and fluid loss damage has become a primary concern while drilling. Also, the probability of becoming differentially stuck can be too high to risk drilling in an overbalanced or conventional condition. In an underbalanced drilling condition, these concerns can be minimized. When a well is drilled underbalanced, the formation can be easier to drill due to lower chip hold down force and significant improvements in rate of penetration (ROP) can be achieved. In some cases the improvement in ROP alone can justify the extra expense to drill underbalanced. Improvements in ROP of 3 to 5 times the regional average are common. In many cases operators have allowed the well to flow from different sections along the lateral to provide real time production test information. Although the daily drilling cost of these wells varies from $50,000 to $80,000 Cdn, the production test information has proven extremely useful for defining reservoir limitations. In some cases it could reduce the number of delineation wells required to define reservoir boundaries. Substantial savings in stimulation costs can also be realized by drilling underbalanced provided the subsequent completion activities do not damage the well. If none of the aforementioned reasons are applicable to your well, do not drill underbalanced. These are expensive wells to drill and significant gains in production or reduced drilling time must be realized to economically justify the additional costs. Limitations As with any specialized drilling operation, there are certain limitations related to the formation, equipment and personnel safety. Extremely under-pressured formations may not be good candidates for UBD unless you are willing to accept that certain sections of the wellbore may not be drilled underbalanced. The gas

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injection rates may be so high as too severely limit the directional equipment performance and friction losses may control the degree of underbalanced attainable. The use of concentric or parasite casing strings can provide a method to effectively remain underbalanced at all times while drilling but requires additional cost and can be operationally complex. Although borehole stability is not easy to predict, significant progress has been made in understanding its failure mechanisms. In some cases, portions of the build sections are left open as the lateral section is drilled underbalanced. In these cases, recommendations on a formation’s sensitivity to UBD operations and whether it would be suitable for drilling in this manner should be obtained. If this information is not available, it may be advisable to set casing in the target formation as insurance against potential future problems. If the well can be drilled underbalanced with single phase drilling fluids, standard mud pulse measurement while drilling (MWD) equipment can be utilized. When drilling with a two phase flow medium, the standard MWD equipment may not generate clear signals (pulses) on surface for transmitting directional or logging information. Some companies have reported adequate signals with up to 20% (by volume) of the two phase medium being gas. Generally, the wells drilled in Western Canada with two phase mediums utilize either electromagnetic (EM) MWD or a wireline steering tool to obtain the directional and logging information. The standard EM MWD tool has formation resistivity limitations and thus measured depth limitations that may require the use of a modified EM MWD tool. This modification has been successful on a number of wells, to true vertical depths of 3500m and measured depths of 4100m. The depth limitation for this new tool has yet to be determined. Steering tools are also used in UBD wells. The main concern with the use of steering tools is the increased potential of fluid slugging in the annulus due to the longer time taken on drill pipe connections. Fluid slugging is a result of the gas portion separating from the liquid portion of the two phase fluid. The liquid portion drops in the annulus while making a connection, resulting in an increase in the bottom hole pressure to circulate this additional liquid out when drilling commences. Although this also occurs while using the EM MWD, the effect is smaller due to shorter connection time. Circulating nitrogen before making a connection can reduce fluid slugging concerns.

In some cases, the required gas/liquid ratio to remain underbalanced is too high to enable drilling the well and still provide sufficient liquid cushion for the directional tools. This can result in systematic failure of the equipment due to vibration damage, leading to down time and/or costly repairs. The limit has not been clearly defined at this time but as more empirical data is collected the limits will become known. Additional probe centralization, improved circuit board

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mounting techniques and tougher components will improve the equipment’s performance. Hydrogen sulfide (H2S) and other corrosion concerns need to be considered from an equipment performance, damage and safety point of view when reviewing candidate wells for UBD. Several wells have been successfully drilled underbalanced with high H2S content (up to 15%) but the potential for failure is high, especially on gas wells with water production. At this time there is no guaranteed method of protecting the drill string from H2S. External pipe coatings would be removed with the rotating action of the string. In severe cases it may be necessary to budget for the purchase of a drill string damaged by H2S. Oxygen has been the other main corrosion catalyst and its presence with varying water makeup quality has caused considerable corrosion problems. However, the failure of downhole components can be considered minor if a portion of the surface blowout prevention control system fails. These concerns have resulted in an imposed moratorium against underbalanced drilling critical sour wells. The work conducted by the Drilling and Completions Committee (DACC) presents a number of equipment requirements and potential failure scenarios that must be reviewed prior to drilling these types of wells. Drilling a reservoir underbalanced that normally requires hydraulic fracturing to produce is generally not a good idea since UBD operations will not provide additional permeability. A poor well doesn’t necessarily become a great or even good well if drilled underbalanced. Directional Planning Issues Directional drilling contractors can be of significant help in the initial planning stages. It can be very beneficial to all parties if the directional contractor is involved in the early stages thus ensuring an optimum well path is planned. There are five main areas where they can provide significant input. Geological/Reservoir Factors Geological factors can have significant impact on the drilling and planning of underbalanced horizontal wells. Issues such as wellbore stability, confidence in the reservoirs’ trajectory and different pressures along the lateral length can affect the best way to plan and drill the well. Regulatory Issues Regulatory issues can also affect how the well path is planned. Drainage, boundaries and required setback distance issues must be considered to develop the best well path to minimize the time spent drilling in an oriented mode (sliding versus rotating the bottom hole assembly). The ROP while sliding is typically one

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half that of rotary drilling and on underbalanced wells it can sometimes be impossible to orient drill due to the increased friction when high gas/liquid ratios are required to maintain an underbalanced condition. In Western Canada, certain regions have a specified distance the mid-point of the lateral must be from unit or section boundaries. If worst case drilling is not considered (i.e. what will happen if you are unable to drill the lateral as far as planned), producing and or royalty issues and penalty fees can be significant. Data Requirements In addition to the standard directional information, real time or memory gamma and annular pressure data is available with most MWD systems. Additionally, the choice of standard, focussed or dynamic oriented gamma ray and resistivity has been made available. A focussed gamma reading provides a real time method of determining if the wellbore is closer to the roof or floor of the reservoir. Some gamma tools (focussed) record the high or low side values in a static mode while others (oriented) have a dynamic readout while rotating. Gamma and pressure readings can also be stored in memory for download and a secondary quality check on surface. The real time annular pressure gauge is almost indispensable to determine whether or not the wellbore is in an underbalanced condition and the amount of reservoir pressure draw down. Although not yet proven, the resistivity tool may become a valuable instrument to determine lithology changes in the lateral sections. Real time drill string pressure gauges near the motor, inclination and G-force values at the bit are additional tools available with some MWD systems. The usual surface pressure changes are masked in two phase flow, therefore motor stalling or bit problems can be difficult to detect and these additional features can be very beneficial. Hole Size Many laterals are being drilled underbalanced with 156mm or 159mm bits. This hole size has been more predominate for production and drill string design reasons. With the increase in re-entry horizontal wells, an increasing percentage of wells are being drilled with 121mm bits. The main drawbacks to this hole size are the requirements for smaller completion tools and the increased percentage of drill string buckling. Additionally, the smaller downhole motors provide lower throughput and less power. Some of these issues can be overcome through the use of PDC bits and 4:5 or 5:6 multi-lobe power sections, providing higher RPM and volume throughput. PDM’s with tandem or extended power sections can also help derive the best benefit from using PDC bits. Frictional losses in smaller hole sizes are also higher in underbalanced operations and need to be numerically modeled.

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Rig Equipment The most commonly used drill string is 101mm OD drill pipe with 60 to 80 joints of heavy weight drill pipe for wells with a 222/159mm build/lateral configuration. The stiffer and heavier 114mm OD drill pipe is preferred for the build section, especially for deeper wells and has shown an increase in ROP of 20% to 40%. Use of this larger drill pipe will require additional rig time to lay it down and pickup either a 101mm or 89mm drill string prior to drilling the lateral section. Drill collars have also been used in place of HWDP with good success in the build and lateral sections. One drawback to the use of drill collars is handling time when reconfiguring the drill string (shuffling) as the lateral distance increases. At this time the authors have not witnessed a major difference in ROP with the use of 89mm versus 101mm drill pipe in the laterals. Nine to 15 drill collars are also picked up for wells 2000m and deeper when needed to apply the required WOB. Another concern when using only drill collars is the potential buckling of the push pipe especially if 89mm drill pipe is used. This can mean frequent trips to shuffle the drill collars and in some cases the more flexible 89mm drill pipe buckles early in the lateral making drilling in the oriented mode difficult or impossible. Top drives have also been used on UBD horizontal wells to overcome some of the higher drag forces produced while drilling underbalanced. Drilling stands with top drives also reduces the amount of liquid slugging the wellbore is subjected to because of the reduced number of connections. Many operators have claimed the longer reach laterals could not have been drilled underbalanced without using a top drive. The importance of all drilling equipment operating efficiency is enhanced in underbalanced drilling operations. Operational Issues Prior to starting the job there are a number of operational issues that can affect the optimum well path. Information such as 1) the required lateral length; 2) the need for an underbalanced condition and 3) the consequences if the well goes overbalanced, help the directional contractor design an optimum well path. From a reservoir drainage and volume estimation point of view, a minimum lateral length may be required. If there are a number of planned depth or azimuth changes, the chances of obtaining the desired length can be reduced due to hole drag. Should drag become an issue, it will be necessary to minimize turns and depth changes to achieve the required length. Staying in the producing zone is crucial but if small local dips in the formation are occurring and the general trend is constant (allowing the zone to be penetrated 30 to 80 metres later), do you need to follow every formation dip change? The use of a focussed or dynamic oriented gamma ray probe can be very helpful. It is also beneficial to be aware of operational problems that may occur.

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When wells are drilled underbalanced to reduce formation damage, the need to maintain this condition is very important. Other wells are drilled underbalanced due to low reservoir pressures. Sometimes these wells can be drilled safely at or near a balanced condition with no detrimental consequences. It is important for the directional driller to understand these requirements should problems occur trying to maintain an underbalanced condition. Flow Tests The possibility of flow tests and their number should be discussed. Flow tests provide valuable production information but on gas wells, they can dry out the wellbore creating increased friction and drag. The requirement of multiple flow tests may affect the well path design or the ability to drill farther especially if conducted where a directional change is to occur. After a flow test, a short period of circulating may be required to lubricate the hole prior to attempting any directional changes by oriented drilling. Introducing a torque-reducing additive may be required to enable these directional changes. Any torque reducing agent’s compatibility with the formation, produced fluids and drilling fluids should be checked prior to implementation. Vibration Damage The dampening benefits of a single phase liquid is not available under two phase flow conditions and this can have detrimental effects on the directional equipment due to vibration damage. The drilling action of the bit and drilling motor creates the majority of drilling vibration specifically when drilling through transition zones. Additionally, the drill string and hole may be blown down utilizing straight gas injection, to start or continue underbalanced drilling after a trip. Drilling out the casing shoe in an underbalanced state can also shorten the life of the directional equipment and in particular the pressure gauge and gamma sensor. Centralizer design modifications and better quality control in the manufacture of electronic components has aided the integrity of this equipment. The gas rate used for blow down operations should not exceed the planned gas injection rate while drilling and the duration of this operation should be minimized. Also drilling out the casing shoe in an underbalanced condition is not recommended. As with any vibration-related failure, they are time and stress dependent and occur similar to fatigue cracks in drill pipe. Downhole Motor Damage Blowing down the drill string can also shorten the life of the PDM. Motor performance on UBD wells is reduced significantly in two phase flow and the change in lubrication may cause a motor to "burn out" prematurely after these operations. With no load (differential pressure) on the motor there is also the risk of over running the motor. As additional empirical knowledge is gained

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modifications in PDM design or operation will become available. Torque and Drag Theoretical sensitivity studies conducted utilizing torque and drag models, indicate a sudden transition from sinusoidal buckling to lock-up conditions can occur as the WOB is increased. The studies also revealed that it could require 60% to 80% more applied drill string weight (slack-off) to achieve the desired WOB. As expected, the drill string begins to buckle at or above the kick off point, if it is in compression but, drill pipe in the curve can also be in a buckled mode reducing the ability to apply weight on bit. A proper bottom hole assembly (BHA) design must take this into account and try to keep the HWDP through the vertical and into the build section. Drilling until the bottom of the HWDP reaches approximately 45o appears to be an optimum position before considering tripping and moving the HWDP further up in the drill string. As with any horizontal drilling operation, a sacrifice in ROP may be made to enable drilling farther before HWDP shuffling occurs. The importance of BHA design and correct HWDP positioning is magnified in UBD wells due to higher friction factors, especially at greater depths and when substantial oriented drilling is required. Modeling Finally, pre-job modeling provides information that is very important to the equipment selection and how to react as drilling progresses. Besides just equipment selection and sizing, the modeling provides valuable information with respect to gas/liquid injection parameter changes should wellbore cleaning or downhole annular pressures become problematic. This is a key component to enable the successful completion of an underbalanced drilled well.

Equipment and Drilling Problems In any drilling operation, equipment and drilling problems can and will occur. Wells drilled in an underbalanced condition are subjected to a higher probability of lost time incidents occurring due to the harsh drilling conditions and additional amount of equipment on site. Although no contractor wishes this to occur, it is advisable for the operator to ask or know what could happen before starting the project. Equipment Problems As with any drilling operation, there are potential equipment and drilling problems to be aware of before starting an underbalanced project. Inaccurate and varying flow rates, whether they are gas or liquid, have occurred in UBD operations. These changes can have dramatic effects on the underbalanced condition and the

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ability to clean the wellbore. There have been substantial improvements in the measuring equipment as well as the method of controlling injection quantities on various units. As stated earlier some EM MWD tools are sensitive to bulk formation resistivity changes. If the total resistivity becomes too high or too low the tool may have difficulty establishing a conductive loop and the signal is lost to the formation. This can happen if you drill into a salt or anhydrite stringer or in some cases develop a large cuttings bed preventing good contact with the surrounding formation. Once the EM MWD tool exits this section or the cuttings are cleaned out by a short wiper trip, the conductive loop can in most cases be reestablished and communication to surface is restored. The development of the extended range EM MWD has solved this problem and is currently used on underbalanced wells where the standard tool was unsuccessful. Steering tool electronics are also sensitive to vibration and introduce potential wireline problems. As with any wireline set or retrievable tool, the latching mechanism into the orienting sub can create potential problems. If the tool is not correctly latched into the orienting sub or it becomes unseated while drilling, false tool face readings can occur. If the anticipated tool face readings are not seen, the tool should be tripped to check the latch. This is not a common problem but mentioned since it has occurred in the past. The time taken for connections with a steering tool is also greater than an electromagnetic MWD tool and a well trained rig crew is essential. Additionally, when using a steering tool, drill string floats can not be strategically placed to minimize bleed off and pressure up time thereby increasing the fluid slugging problems on connections. Stator performance of positive displacement motors (PDM) used on UBD operations can also be variable depending upon the flow rate, fluid type and lubrication provided by the drilling fluid. Stator wear has been abnormal on some wells, changing the interference of the rotor/stator by up to 2.5mm in 25 hours or less of drilling. The wear has been indicative of an abrasive type with ribbing of the stator and more aggressive wear noted on the bottom. Motor performance on multiple runs with the same motor has also been inconsistent. Some motors have performed satisfactorily for up to three bit runs while others have only lasted one run. There may be a pressure/temperature/fluid condition that allows the motor to provide acceptable performance even with long term usage.

On some wells the drill string is recorded as "pressuring up" and the motor is the main suspect. Sometimes when the motor is later checked on a dynamometer and disassembled, nothing is found wrong except that the torque in a number of cases was slightly higher after use then before. In fact the stator on one 95mm motor was sectioned and inspected for any delaminating or blistering but no fault or explanation for the pressure increase could be found. Some individuals have conjectured nitrogen absorption into the elastomer thus swelling, is the cause of

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the increased circulating pressure. This theory assumes the nitrogen gas escapes once sufficient pressure is removed from the elastomer and also explains why it has not been duplicated on subsequent surface tests. Others suggest that it may be a rheological change occurring within the drill string as the foam quality changes. Another cause could be an insufficient or inconsistent liquid injection rate causing the motor to stall at lower weight on bit and differential pressures. If swelling of the elastomer is occurring how does that explain satisfactory operation once the string is bled off and drilling resumed? Is it possible for the elastomer to relax that quickly? It is likely a combination of all points discussed in the last two paragraphs and requires additional testing and empirical data. This “pressuring up” phenomenon has been more prevalent with smaller tools (89mm drill pipe or coiled tubing with 95mm or smaller PDM’s) but has also been recorded on the 121mm motors. Positive displacement drilling motors typically have a minimum lubrication requirement that is dependent upon the manufacturer and particular motor design. To try and extend its operational life, some manufacturers have modified the rotor/stator interference. Another topic for discussion is the potential swelling effect when hydrocarbon liquids are used for the liquid portion. Permanent swelling and chunking of the stator can occur and special elastomers have been developed to combat this problem. In some cases oversized stators (less interference between rotor and stator) are suggested. This does not solve the problem in all cases or prevent swelling or the pressuring up phenomenon. In some cases a standard hydrocarbon analysis has shown significant differences in the percentage of various aromatic components. Unfortunately additional data collection is required to address these problems. Drill string floats (as required by the Alberta Recommended Practices for UBD ID 94-3) have also been problematic on some wells. There are different types available for use including flapper, spring-loaded plungers and wireline set models. The use of spring-loaded plungers should provide better performance than a flapper style but they create a major restriction to free-point operations if required. The main problem with any float is the loss of sealing integrity during connections. Although the top drive can allow underbalanced wells to be drilled to depths not likely attainable otherwise, they have been sources of significant downtime. Properly maintained and designed equipment should reduce these problems but cold weather drilling is tough on these units.

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Drilling Problems The main drilling problems deal with torque and drag or wellbore cleaning. As discussed earlier, BHA design is very important, especially if formation depth or directional changes are contemplated. The drag issue becomes more enhanced at greater depths with the inability to provide sufficient WOB to drill or to move the drill string. Tapered drill strings, additional HWDP and drill collars, along with timely HWDP repositioning improves the ability to drill further. The use of a torque and drag model while drilling and the annular pressure gauge can be very helpful to determine the onset of wellbore cleaning problems. In some cases the ROP is limited due to hole cleaning issues and wiper trips after every 50m to 100m drilled are recommended. In some areas open hole sidetracking with tricone bits has been impossible or consumed a considerable amount of drilling time. The outer row of teeth on the bit could have been too dull hindering the process. Sidetracking in lateral sections that are relatively flat, through a dense cap rock at a high inclination or trying to sidetrack without increasing the true vertical depth can also be difficult. The use of a purposefully designed diamond sidetrack bit can be advantageous in these cases. In any sidetrack operation a good competent ledge must first be time-drilled. A PDM with a 4:5 or 1:2 lobe configured power section is recommended to build the ledge in harder formations. Be aware that sidetracking with a diamond bit can create a high dogleg at that point. Patience and a good understanding of what is causing the problem are a prerequisite to a successful sidetrack. The other phenomenon that becomes very evident on UBD wells is the “stick slip” condition. Although typically discussed as a rotating phenomenon, it can also be used to discuss erratic WOB when slide drilling. When weight is slacked-off on surface (WOB increased), an additional length of the drill string is placed into compression to pass the weight to the bit. The drill string can become stuck due to friction/buckling and not allow the additional weight to pass smoothly to the bit. As a slight amount of weight is drilled off, the drill string suddenly moves and/or slips and additional weight is quickly placed onto the bit. In some cases this weight transfer occurs too quickly and the motor stalls. As discussed in the following section, two phase flow can significantly alter the performance of PDM’s and they will stall at much lower differential pressures. In two phase flow, monitoring and controlling standpipe pressure and therefore differential pressure through the PDM is not practical and ROP is the only performance indicator. The use of an internal pressure gauge near the motor may allow the operator to adjust WOB as stall is occurring and minimize the damage done to the motor in a prolonged stalled condition.

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Downhole Motor Tests Under Two Phase Flow Several performance tests have been conducted on drilling motors under two phase flow conditions revealing some interesting behaviour1,2. Papers have been published presenting ideas on how to choose motors through performance indicators3 or bench testing. These tests and discussions are useful in understanding limitations with PDM’s in two phase flow conditions. However, relaying this information to a directional driller on what to expect and how to deal with the problem is more important. The explanation of why motors perform differently is somewhat understood but there are still certain problems that occur that can not be completely explained. The following sections outline test procedures, results and what this means to a directional driller. Test Procedure and Setup Prior to discussing the test results, the procedure used should be understood. Some tests have been conducted maintaining a constant back-pressure on the motor, similar to a constant bottom hole pressure, throughout the test. Other tests have been conducted by first establishing a maximum RPM of the motor under the desired two phase flow conditions through the use of a down stream choke. When the motor is being loaded (applied resistive torque) no changes are made to the choke setting in the latter test but continual changes are made in the former test procedure. Although the procedures sound different they both produced similar results and trends. The benefit of applying a constant back-pressure allows you to experiment with its effect on motor performance and simulate higher downhole pressure situations. Once you’ve established the procedure to follow, dependent upon your equipment pressure limitations, it is imperative to have accurate sensors installed in key positions as suggested below:

Temperature - at the inlet and outlet of f low loop (optional ly on motor power section) Pressure - at inlet of f low loop, before and after motor and after downstream choke

- consider pressure sensor after power section Flow monitor - on gas injection and l iquid injection l ines RPM counter - most important to confirm equivalent f low rates and amount of sl ippage

These sensors need to be connected to a data acquisition system that records and correlates data for later evaluation. The use of a real time display for RPM and torque versus differential pressure would better assist determining the onset of stall or slippage. The onset of motor stall is depicted by a sharp change in slope of

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the torque versus differential pressure curve. A drop in RPM indicates the onset of slippage as differential pressure increases. The motor should first be tested under straight liquid injection. Testing with a liquid only, at maximum and minimum flow rates, will establish base-line performance curves for later comparison. When starting the two phase portion of testing, the liquid injection rate should first be established followed by gas injection. Since the motor can be easily overrun at this stage, the choke should be adjusted to limit the maximum RPM of the motor that matches that witnessed on the base-line tests. To establish the effect of back-pressure, the torque loading should be removed and system allowed to stabilize back at the same RPM and injection rates. Then apply the desired additional back-pressure and repeat the test. Once the two phase flow testing is completed, the motor should be subjected to a straight liquid test to compare to previous base-line tests. Test Results Both 86mm and 121mm 7:8 configured motors were tested using the two previously discussed test procedures. Although the combined equivalent rate did vary during some of the tests, the trends were identical. Also air was used as the gas medium for the 121mm motor testing versus nitrogen on the 86mm motors. Figures 11-1 through 11-3 illustrate the results from these tests under different flow conditions but approximately equal combined equivalent flow rates. As has been discussed in a previous paper1, the performances of PDM’s are reduced considerably in two phase flow conditions. Figure 1 illustrates that as the liquid rate decreases but the combined equivalent flow remains the same, the torque output before stall can decrease substantially. It is interesting to note that all tests under different flow conditions provided the same torque output for a given differential pressure. This is valid since the torque is derived by vector addition of pressure forces along the rotor lobes and therefore not affected by different flow conditions (assuming no slippage and 100% motor efficiency). Of significance is the dramatic reduction in maximum torque output before the curve deviates from the base curve indicating the motor is approaching a stall condition. The graphs illustrated in Figures 11-2 and 11-3 are trend lines and indicate another performance change. These curves plot the RPM changes for different flow conditions while still maintaining the same combined equivalent flow rate. The curves were drawn based upon best-fit polynomial equations and the R-squared value was 0.95 or better (95% of data fits the equation). The initial values (at zero differential pressure) may start at unusual values but this is strictly due to curve fitting and should be ignored. After a differential pressure of 0.7 MPa the data

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generally matches extremely well to the data points. Sufficient back-pressure was applied at the start of testing to have a similar starting RPM thus combined flow rate. Note the dramatic drop in RPM for the same differential pressure as the liquid rate is decreased. When the RPM values under two phase flow conditions and similar differential pressures were compared to the base-line results, a drop of up to 50% was seen. A Torque versus RPM curve for the 86mm PDM testing is illustrated in Figure 11-4. Note the substantial drop in RPM for the same torque value at the different flow combinations. This performance change alone could have a significant affect on the rate of penetration. Upon conclusion of the two phase testing, the motors were tested with straight liquid. In every case, when these results were compared to the initial base-line results, the torque curves were slightly higher. This may imply that some swelling of the stator elastomer has occurred. In fact a number of post field use dynamometer results (witnessed by these authors) from this winters underbalanced drilling, has repeated this occurrence. Additionally some of the motors required a higher than normal load to remove the rotor. Calculated Combined Flow Rate Versus Actual There are a number of software programs available that calculate the combined equivalent flow rate for two phase flow conditions. Table 11-1 compares the results of two methods for a specific combined flow at various applied differential pressures on the motor. Note the difference in calculated results. Since the model calculations do not adjust for motor efficiency under load, a relationship between RPM and flow rate was established. By assuming 100% motor efficiency during the base-line test and RPM is directly proportional to flow rate the following relationship can be established:

Q[BASE] ÷ RPM[BASE] = Q[EQUIVALENT] ÷ RPM[ACT]

Base Case For 86mm Motor: 145 RPM at 404 lpm

Q[EQUIVALENT] = ( Q[BASE] ÷ RPM[BASE] ) X RPM[ACT] or

Q[EQUIVALENT] = 2.7862 X RPM[ACT]

Where; Q[EQUIVALENT] = combined equivalent flow rate (lpm) Q[BASE] = base case liquid flow rate (lpm) RPM[ACT] = recorded RPM under two phase flow RPM[BASE] = recorded RPM under base case liquid flow Using this equation and the recorded RPM values under various differential pressures, the actual combined equivalent flow rate has been calculated as shown

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in the last column in Table 11-1. As pressure is increased the equivalent liquid portion due to nitrogen is reduced. Although there is additional pressure applied to the nitrogen as the motor is loaded, the reduction in the theoretical combined equivalent flow rate, predicted by the two models, does not completely explain the RPM drop. The drop in flow rate must be a result of gas and possibly liquid slippage past the stator and this Table illustrates the degree of motor inefficiency under two phase flow conditions.

TABLE 11-1 – DATA TAKEN FROM TESTS ON 86mm MOTOR

Flow Rates Pressure RPM Combined Flow

Liquid Gas Inlet Outlet Delta Method A Method B Qeq* (lpm) (m3/min) (KPa) (KPa) (KPa) (lpm) (lpm) (lpm)

102 21.51 8300 7100 1200 122 390 367 340 100 21.02 8640 7450 1190 109 369 349 304 97.9 20.73 9040 7100 1940 87 363 332 242 94.9 20.86 9620 6970 2650 67 354 317 187 91.3 21.41 10260 7010 3250 55 347 305 153

• *Qeq is the combined equivalent flow rate calculated using ratio of base case

liquid RPM and flow rate to actual RPM. • This test data was selected since the initial combined equivalent flow was

very similar for all tests. What this Means to a Directional Driller A number of concerns and unique drilling or equipment problems in underbalanced drilling conditions have been identified in the previous sections. Most directional drillers are quite aware of these and the drag concerns created with erratic doglegs and poor positioning of HWDP. They are also aware of proper pre-planning for long lateral sections. Various conjectures and test results have also been described, but what does this mean to a directional driller? When you’re on site and drilling, you only have the equipment that was sent out and you’ve got to make it work. Besides the integrity of the directional and underbalanced equipment, the performance of positive displacement motors may at times be a frustrating component. It is important for a directional driller to understand how the performance of a

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PDM is affected by two phase flow and make small changes in operating parameters when trying to improve performance. The following is a list of points to consider when suspected drilling motor problems occur:

• The higher the gas/liquid ratio (lower liquid rates) the easier it is to stall the motor even though the combined equivalent flow rate is at maximum motor rating

• Lower liquid rates may cause poor lubrication resulting in faster wear rates • The motor is likely being over run while circulating the drill string off

bottom • Allow the weight on bit to “drill off” before pulling up off bottom • Slippage or blow-by (onset of stalling) occurs sooner and at lower

differential pressures in two phase flow than single phase flow. If an internal drill pipe pressure gauge is available, watch for an increasing pressure trend.

• Drill string pressure increases have occurred early in a motor’s life with no fault found so try varying the liquid portion slightly before tripping out to change the motor

• Work closely with the operator and underbalanced drilling engineer, to make small parameter changes as problems appear before laying the motor down

When describing a motor problem don’t fall back on “weak motor”. Too often this phrase is used to describe motor problems and it is insufficient detail for any motor manufacturer when trying to determine a cause for incident. Describe how it reacts under various conditions, what parameter changes were tried and note control or lack of, when applying bit weight. Not all UBD wells have these problems but be prepared with options should they occur. Conclusions and Recommendations 1. In all UBD operations there are a large number of multiple disciplined

individuals that have experience to lend and team work is a key component of a successful job.

2. Underbalanced dri l l ing operations are very dynamic, so effective

communication with al l service providers and the operator is a key issue.

3. Directional contractors can provide better well path designs and

operational suggestions if involved at the start of a UBD project .

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4. The performance of posit ive displacement motors under two phase f low condit ions is becoming better understood but st i l l requires more work and evaluation.

5. In addit ion to increasing the downhole vibration and poor motor

lubrication concerns, low fluid rates substantial ly reduce the performance potential of the posit ive displacement motor under two phase f low condit ions.

REFERENCES 1. Bennion, D.B., 1998. Using Underbalanced Drilling to Reduce Invasive Formation

Damage and Improve Well Productivity – An Update. 49th Annual Technical Meeting of The Petroleum Society in Calgary, #98-58

2. Bennion, D.B., 1993. Formation Damage Control and Research in Horizontal Wells.

5th International Conference on Horizontal Well Technology, Houston. 3. Li, J., Tudor, R.,Sonego, G., Varcoe, B., 1997. Performance of Positive Displacement

Motors Under Two-phase Flow. 48th Annual Technical Meeting of The Petroleum Society in Calgary, #97-73

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Chapter

11 THE PROBLEM OF DEVIATION & DOGLEGGING IN ROTARY BOREHOLES Deviation in drilling operations is not a new problem. The diamond core drill was invented in 1865 and widely used as a cable tool drill in mining operations. The first evidence of concern about hole deviation was the invention by Nolten in Germany in 1874 of the use of hydrofluoric acid to etch and predict hole deviation. Later a South African miner named MacGeorge invented the clinostat to predict both deviation and direction. The clinostat consisting of a magnetic needle and a plumb immersed in gelatin was lowered into the hole and the gelatin was allowed to set. The instrument was then brought to the surface and deviation and direction were read directly. At a meeting of mining engineers in London in 1885 MacGeorge presented data illustrating deviations of 75 feet in 100 foot mine shafts. The Petroleum Industry did not become aware of the problem until the Seminole, Oklahoma, boom of the middle 1920’s. Town lot spacing was the primary factor contributing to the experience of the industry. There are actual recorded incidents of offset wells drilling into each other, drilling into producing wells, two rigs drilling the same hole, and the wells in the geometric centre of the structure coming in low or missing the field completely. It was common drilling practice at that time to use only large drill pipe with no drill collars and all available weight since weight indicators were not available. Engineers and the industry in general made a concentrated effort to solve the crooked hole problem. As a result, most of the practices commonly used today in an effort to correct and control deviation were conceived, experimented with and adopted in the 1920’s, 50 years ago. The most effective practices adopted and still used today were the use of drill collars for weight and rigidity, the use of stabilizers at various points in the string to control deviation and provide rigidity, and the practice of fanning bottom to reduce angle. The first two have made the industry millions of dollars; the practice of fanning bottom has cost the industry millions of dollars. For whatever reason, early researchers were successful in their efforts. Wells surveyed in the greater Seminole, Oklahoma area with and without straight hole practices produced the results in Table 1.

Table 1: Survey Results from Seminole Field Without Straight-Hole Practices With Straight-Hole PracticesNumber of Wells 216 58 Total Feet Surveyed 910,232 233,341 Average Depth 4,214ft (1285m) 4,023ft (1227m) Average Angle 13o 5o Maximum Angle 46o 19o The data would indicate that the engineers of the 1920’s didn’t solve the problem of deviation, but the practices introduced are fundamental to the practices today. Very little research was performed in the area of deviation until Arthur Lubinski performed his work in the early 1950’s, and real interest resulted from the advent and popularity of directional drilling. In the last few years considerable field experience has been reported which has contributed significantly to the total knowledge of this particular aspect of oil well drilling technology. In many areas of the world, drilling contracts are written in the same manner, as they were 15 years or 50 years ago. That is, hole deviation is limited to 1o/1,000 feet. This is truly an area where most operators and drilling people merely do what has been done for the last 15 years thereby impeding progress by not doing anything. The potential for advanced thinking in this area is unlimited. This problem has cost the drilling industry too much money for too many years. With drilling costs what they are today, a lackadaisical attitude toward any phase of Drilling Technology, and particularly one so costly, should not be tolerated. Our industry can no longer afford to pay the prices that have been paid in the past for deviated holes. We can no longer afford to take twice as long to finish our work simply because we’re afraid the hole might get crooked.

Theories of Causes of Deviated Field Holes The anisotropic formation theory is widely accepted (Figure 2-1A). Past theoretical studies have assumed that the bit drills in the direction of the resultant force on the bit in uniform or isotropic formations. This implies that the bit does not display a preferential direction of drilling. Stratified or anisotropic formations are assumed to possess different drillability parallel and normal to the bedding plane with the result that the bit does not drill in the direction of resultant force. Each formation is characterized by its anisotropic index and dip angle. The anisotropic index does not depend upon specific rock properties but is an empirical constant determined from drilling measurements. This theory has been applied to the computation of the equilibrium hole inclination angle for straight inclined holes.

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Figure 2-1 Illustrations of various drillability theories The formation drillability theory seeks to explain hole angle change in terms of the difference in drilling rates in hard and soft dipping formations (Figure 2-1B). Presumably angle in the hole changes because the bit drills slower in that portion of the hole in the hard formation. Inherent in this theory is the underlying assumption that the bit weight is distributed uniformly over the bottom of the hole. It predicts up-dip deviation when drilling into softer rock and down-dip into harder rock. The miniature whipstock theory is based on drilling experiments made by Hughes Tool Company (Figure 2-1C) in which an artificial formation composed of glass plates has been drilled with the hole inclined to the laminations. In these tests the plates fractured perpendicular to the bedding plane, creating miniature whipstocks. If such whipstocks are created when laminated rock fractures perpendicular to bedding planes, this could cause updip drilling. This theory offers a possible

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qualitative explanation to hole deviation in slightly dipping formations; however, it does not explain the down-dip which occurs in steeply dipping formations. The drill collar moment theory suggests that (Figure 2-1D) when a bit drills from a soft to a hard formation, the weight on bit is not distributed evenly along the bottom of the hole. Since more of the weight on bit is taken by the hard formation, a moment is generated at the bit. Such a moment changes the pendulum length to the point of tangency as well as the side force at the bit. The variation of side force is not the same when drilling from soft to hard formations as when drilling from hard to soft and, therefore, can effect a change of hole inclination. Raymond Knapp suggests that deviation results in dipping formations which vary in hardness and is directly related to the inability of the bit to drill a full gauge hole (Figure 2-1E). All bits ream a small portion of the hole to gauge with the heel rows. Mr. Knapp contends that in going from a soft to a hard formation the bit would be unable to ream the hard formation to gauge as fast as it could drill the soft formation; therefore, the bit would be deflected toward the softer formation. Random deviation would result. Experience has shown that deviation occurs more often in laminated beds then thick, homogeneous deposits. Deviation is almost always associated with areas of steeply dipping formations. Faulting or perhaps the stresses associated with faulting influence deviation. In the final analysis there is no one satisfactory explanation for deviation. It appears to be related to geology. Deviation is never greater than bed dip. All theory and practice indicates that the maximum deviation is perpendicular to or parallel to the formation dip. In fact, Lubinski’s model, which is the most widely accepted, suggests that total deviation will always be less than formation dip. Categorizing Crooked Holes Deviation If we are to fight a problem, we must decide when the problem is a problem and when the problem is only a potential problem. When we talk of hole deviation, we cover a multitude of evils; therefore, it becomes necessary to dissect the agglomeration into its component parts and evaluate the problems associated with each and the techniques normally associated with coping with those problems. First then, let’s consider holes that deviate from vertical uniformly in one plane and the “doglegs” or changes in direction will be considered. A rotary borehole that is not vertical is deviated. A large percentage of the instruments commonly used in the industry today measure only deviation from vertical with no regard for

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direction or changes in direction. The assumption is made, then, that the borehole is anywhere within a calculated conical area. Figure 2-2A.

Figure 2-2 Target area for deviated wells With this type of deviation many reasons are given which brand this type hole as undesirable and necessitate the expenditure of multitudes of money to eliminate the problem. The more common anticipated problems are:

• Inadequate and misleading subsurface information.

• Insignificance of surface location with respect to well spacing (drilling into the same target with 2 wells).

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• Inadequate drainage of production zones.

• Crossing lease lines.

• Excessive production problems.

• Excessive drilling problems. Depending upon the area, these points may not be considered a problem thus controlling inclination is not a concern. Doglegs Doglegs or sudden changes in hole angle or hole direction were recognized as a major potential problem by the pioneers of the drilling business. When it was possible to determine that a rapid change in angle had occurred, their solution was automatic-plug back and start over. Perhaps it is well that detection procedures were not highly defined or else a hole may never have reached total depth. Modern surveying techniques indicate that no hole is perfectly vertical. Any hole has a tendency to spiral. In fact, some holes surveyed made three complete circles in 30m (100 feet). Spiraling is reduced as the deviation from vertical increases. The maximum spiraling occurs at angles less than 30o from vertical. At angles greater than 50o from vertical, the hole may move in a wide arc, but spiraling is almost non-existent. Doglegs are a major factor in many of our more severe drilling problems. Doglegging should be suspected when the following problems are encountered: (1) unable to log, (2) unable to run pipe, (3) key seating, (4) excessive casing wear, (5) excessive wear on drill pipe and collars, (6) excessive drag, (7) fatigue failures of drill pipe and collars, and or (8) excessive wear on production equipment. When drill pipe in a dogleg is in tension it is pulled to the inside of the bend with substantial force. The lateral force will increase the wear of the pipe and the tool joints. When abrasion is a problem it is desirable to limit the amount of lateral force to less than 2000 pounds on the tool joints by controlling the rate of change of hole angle. Figure 2-3 taken from API Spec RP 7G illustrates the effect of dogleg severity and tension on the tool joint and drill pipe. The broken lines indicate the combination of tension below the dogleg and the dogleg severity that will produce a constant lateral force on the tool joints. Likewise the solid lines indicate the combinations for lateral loads on the drill pipe. For example if we have 100,000 lbs below the dogleg and a 5 o/100’ dogleg the graph indicates a lateral force of less than 3,000 pounds on the tool joints and 0 on the drill pipe. If however the dogleg severity was 10 o/100’ the lateral tool joint force would be

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just less than 5,000 pounds and the drill pipe would also have a lateral force of just less than 500 pounds.

Figure 2-3 Lateral Forces on Tool Joints and Range 2 - 4 ½” Drill Pipe, 6 ¼” Tool Joints The major problem facing the industry was to define a severe dogleg within the industry’s ability to survey doglegs. Arthur Lubinski made the first efforts to define a severe dogleg in his paper entitled “Maximum Permissible Doglegs in Rotary Boreholes” published in 1961. Lubinski recognized that severe doglegs created major drilling problems and proposed that a dogleg was too severe if any one of the following conditions existed. 1. The stress reversals when rotating in the dogleg were sufficient to fatigue the drill pipe. 2. The thrust force on the drill pipe tool joint in the dogleg was sufficient to cause the tool joint to dig into the formation and cause a key seat or produce casing wear.

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3. The stress reversals when rotating in the dogleg were sufficient to fatigue the drill collars. Lubinski concluded that these conditions should be avoided and each section of the hole should be evaluated in view of the limiting conditions in order to determine the maximum permissible dogleg at any given depth. First, let’s consider drill pipe fatigue. Figure 2-4 illustrates the maximum permissible doglegs to avoid drill pipe fatigue as a function of tension on the drill pipe or depth for 4 1/2 inch Grade E drill pipe. From Figure 2-4, for example, with 300,000 pounds of tension on the drill string which is comparable to approximately 20,000 feet of pipe, a dogleg in excess of 1 ½ degree per 100 feet at/or near the surface would place the drill pipe into a region of fatique damage. At approximately 6,800 feet from the bottom of the 20,000 foot hole, the tension would be only 100,000 pounds, and a 5 o/100’ dogleg would be required to produce drill pipe fatigue. Thus potential drill pipe fatigue constitutes a limiting condition in determining a maximum permissible dogleg, and the tension or load on the drill pipe is the major factor affecting fatigue. Obviously, a much larger change in angle can be tolerated at total depth, whereas only very small changes can be tolerated at the surface in very deep holes. Another consideration is the force caused by the drill string at a dogleg in the hole or casing. In order to determine the maximum permissible thrust force, Lubinski assumed that a dogleg of 1 ½ o/100’ never caused any trouble. The deepest holes of that time were 16,000 to 18,000 feet in depth. At 17,000 feet, the drill pipe load in a 1 ½ o/100’ dogleg results in a 2000 pound thrust force on the formation or casing in the dogleg. Based on this experience then, it was assumed that a 2000 pound or less thrust force would never create a drilling problem. The dashed curve in Figure 2-3 labelled 2000 lbs, represents the maximum permissible dogleg to prevent excessive thrust forces as a function of tension on the drill string. Obviously, casing wear and key seats associated with excessive thrust forces are more critical near the surface in deep wells. Larger doglegs can be tolerated nearer total depth without danger to hole and casing. The final limiting condition, according to Lubinski, is drill collar fatigue. Lubinski studied various conditions for different collar sizes, and calculations were made of the abrupt dogleg angle for which the connections would be subjected to a bending moment sufficient to produce fatigue failure. It was concluded that the critical angle is a function of collar-to-hole clearance, the amount of tension or compression to which the collars are subjected in the dogleg, hole inclination, and whether the inclination is increasing or decreasing.

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Figure 2-4 Dogleg severity limits for fatigue of Grade E drill pipe The maximum permissible dogleg to be in a region of no fatigue damage, can be calculated from equations presented in API RP 7G as follows: C = 432,000 x BS x Tan-1(K x L) K = SQRT (T / (E x I))

π x E x D x K x L C = maximum permissible dogleg severity, degrees per 100 feet

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E = Young’s modulus, psi (30 x 106 for steel) D = dri l l pipe OD, inches L = one half the distance between tool joints, inches or 180” for range 2 T = buoyant weight ( including tool joints) suspended below the dogleg, pounds I = dri l l pipe Moment of Inert ia = π/64 x (OD4 – ID4) BS = permissible bending stress, psi σ t = buoyant tensi le stress, psi , in the dogleg = T/A A = cross-sectional area, square inches BS = 19500 – 0.1493 x σ t - 1.3366 x 10- 6 x (σ t – 33500)2 , for Grade E. Another equation is avai lable for Grade S dri l l pipe. The above equation is val id for values of σ t up to 67,000 psi Previous philosophies concluded the maximum permissible dogleg for the middle of the drill string to the top of the drill collars was determined by the potential drill pipe fatigue. Potential drill collar failure will dictate the maximum dogleg at both the bottom of the hole and from surface to total depth. Rotating off bottom through severe doglegs is not a good practice since additional tensile load results from the suspended drill collars. Horizontal wells use drill collars on top of drill pipe, have a reverse drill string cross-sectional transition design and have drill pipe in compression. The drill pipe is also being rotated through doglegs as high as 20 o/30m. Although failures do occur, their frequency has not detracted from successfully drilling very complex well paths that would have never been tried by maintaining conventional thought. Other practices designed to merely cope with severe doglegs are as follows:

1. Increase frequency of drill collar inspection.

2. Use non-hard-banded drill pipe through the dogleg to avoid excessive casing wear.

3. Reduce rotary speed while drilling through the dogleg to reduce the number of stress reversals.

4. Minimize off-bottom rotation to reduce unnecessary stress reversals with maximum tensile stress.

5. Use packed hole assemblies to reduce dogleg severity.

6. Keep the kick-off point in a directional well as deep as practical.

7. Use heavier casing through working doglegs.

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8. String reamers will often reduce dogleg severity and prevent key seats. In summary, dogleg severity is a serious drilling problem. Dogleg severity is a function of collar clearance. The best tool available to control dogleg severity is the square drill collar. In reports from around the globe covering over one million feet of hole, the square drill collar has been credited with improving hole conditions, reducing fishing jobs, improving penetration rates, improving bit runs, decreasing survey frequency, and decreasing dogleg severity. Fanning bottom is of no benefit in controlling dogleg severity and in fact, it is detrimental to the drill string. Dogleg Severity The previous sections have talked about some of the problems with doglegs but how do we define and calculate the value. Dogleg is a measure of the amount of change in inclination, and/or azimuth of a wellbore, usually expressed in degrees per 30m (or 100’) of course length. All directional wells have changes in the wellbore course and therefore have some doglegs. The dogleg severity is low if the changes in inclination and/or azimuth are small or occur over a long interval of course length. The severity is high when the inclination and/or azimuth changes quickly or occur over a short interval of course length. The effect on dogleg severity with a change in azimuth is not easy to understand or calculate. A 3o change in azimuth over 30 meters will not yield a 3 o/30m dogleg severity unless the inclination is at 90o. At low inclinations a change in azimuth will have a small dogleg severity. As the inclination increases, the dogleg severity for the small azimuth change will increase. The following equation is used to calculate dogleg severity using both inclination and azimuth: DLS = 30 X Cos–1{(SinI1 X SinI2) X [(SinA1 X SinA2) + (CosA1 X CosA2)] +(CosI1 X CosI2)} ∆MD ∆MD = course length between survey points I1 = inclination at previous survey station I2 = inclination at current survey station A1 = azimuth at previous survey station A2 = azimuth at current survey station For english calculations use 100 instead of 30

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The following table compares the dogleg severity at different inclinations for similar changes in azimuth:

Table 2-1: Comparison Of Dogleg Severity Survey Station

Measured Depth (m)

Inclination Azimuth Dogleg (deg/30m)

1 100 2 100 2 130 2 123 0.8 1 100 15 100 2 130 15 123 6.0 1 100 45 100 2 130 45 123 16.0

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178

86mm 7:8 - 3 STAGE POSITIVE DISPLACEMENT MOTORFigure 11-1

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 0.7 1.4 2.1 2.8 3.5 4.2 4.9 5.6 6.3 7DIFFERENTIAL PRESSURE (MPa)

TOR

QU

E ( N

-m)

'A', 400 lpm'B', 400 lpm @ 7 MPa BP'C', 250 lpm 17 m3 @ 7 MPa BP'D', 100 lpm 20 m3 @ 7 MPa BP

Motor Approaching Stall Condition

A

B

C

D

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86mm 7:8 - 3 STAGE POSITIVE DISPLACEMENT MOTORFigure 11-2

0

20

40

60

80

100

120

140

160

0 0.7 1.4 2.1 2.8 3.5 4.2 4.9 5.6 6.3 7

DIFFERENTIAL PRESSURE (MPa)

RPM

'A', 400 lpm'B', 400 lpm @ 7 MPa BP'C', 250 lpm 17 m3 @ 7 MPa BP'D', 100 lpm 20 m3 @ 7 MPa BP

310 LPM COMBINED FLOW RATE

420 LPM COMBINED FLOW RTE C B

A

D

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180

121mm 7:8 - 2.2 STAGE POSITIVE DISPLACEMENT MOTORFigure 11-3

0

20

40

60

80

100

120

140

160

0 0.35 0.7 1.05 1.4 1.75 2.1 2.45 2.8DIFFERENTIAL PRESSURE (MPa)

RPM

'A', 946 lpm

'B', 342 lpm 35 m3

'C', 342 lpm 20 m3

'D', 171 lpm 35 m3 @ 1.4 MPa BP

'E', 171 lpm 20 m3

BASE CURVE DATA WAS NOT FROM TEST MOTOR

A

B

C

D

E

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181

TORQUE VERSUS RPM FOR VARIOUS COMBINED FLOWS86mm 7:8 lobe PDM (BP = 7000 KPa )

FIGURE 11-4

0

500

1000

1500

2000

2500

0 20 40 60 80 100 120 140 160

RPM

TOR

QU

E (N

-m)

'A' Base Flow 400 lpm'B' Base Flow 400 lpm + BP'C' 250 lpm + 17 m3 + BP'D' 100 lpm + 20 m3 + BPA

B

C = 440 lpm

D = 370 lpm

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3

Chapter

12

UNDERBALANCED DRILLING To be Developed Formation Damage UBD or CPD Modeling UBD Equipment Gas Supply Alternatives Corrosion Issues