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Measurement While Drilling MWD

MWD
MWD

The use of measurement and logging while drilling has matured a great deal in the last 10 years.  The use of these tools that have been developed for the oil and gas industry for use in primarily sedimentary depositional environments must be investigated in light of the goals set for EGS systems.  Let us first define what is meant in this section by the terms, realizing that the line between these two areas continue to blur.

1)      Measurement While Drilling (MWD): Tools that measure downhole parameters of the bit interaction with the rock are MWD tool.  These measurements typically include vibration and shock, mudflow rate, direction and angle of the bit, weight on bit, torque on bit, and downhole pressure.

2)      Logging While Drilling (LWD): Tools that measure downhole formation parameters are LWD tools.  These include gamma ray, porosity, resistivity and many other formation properties.  The measurements fall into several categories that are discussed below.  The oldest and perhaps most fundamental formation measurements are spontaneous potential (SP) and gamma ray (GR).  Today one or both of these traces are used mostly for correlation between logs.  Electric or formation resistivity logs are another class of logs used in oil and gas logging.  Because of the long history of these logs, several varieties have evolved.  The electrical basis of this class of logs is to measure the conductivity or resistivity of the various geologic materials and fluids in them.  The resistivity of shales vs that of a clean sand set the limits for an ideal electric log.  The fluids in the formation also are reflected in this measurement as water is conductive when found in boreholes and oil is not.  The basic use of electric logs is to delineate bed boundaries and in combination with other logs to determine gas/oil/water contacts.  Yet another class of logs is density logs.  These logs are indicative of the formation density of the material in the well bore.  These logs require either a neutron or a gamma source, and actually measure gamma ray flux differences.  Porosity tools are another class of common logging tools.  These tools normally use chemically or now more common electrically generated neutron to estimate formation porosity.  Since these logs are normally calibrated in sandstone, limestone or dolomite care has to be taken when measurements are made in different rock types.  Finally in the last few years a number of specialty tools have evolved, these include specialized formation pressure testing tools which can be run while drilling, nuclear magnetic resonance tools, and pulsed neutron spectroscopy tools to list only the most popular.

Rationale for use

In recent years the cost of an average oil and gas hole has increased dramatically, part of this cost increase has been driven by the need to go after much deeper and more complicated reserves.  This increases the risk of failure of holes drilled into these reserves.  As a reaction to increased risk, the use of LWD and MWD technology and techniques has increased.  In the final analysis, the decision to use of LWD and MWD tools depends on managing risk.  The EGS program moves the art of geothermal drilling into a new region of risk, the evaluation of the LWD and MDW technologies must be undertaken to determine the applicability of these technologies to the particular risks faced in this new effort.  It is important to realize in the EGS model, in many cases we are not going to be setting our surface casing into igneous or metamorphic rock as we have in the past.  These deeper holes may look more like the classic oil and gas hole at the shallower depths, with this in mind we begin to examine the possible uses of the LWD and MWD technologies.  We begin by listing what is commonly available.

Measurements available from current LWD/MWD oil field tools.

Mention of companies and tool or service names does not imply endorsement by Sandia National Laboratories; it appears that most companies involved in MWD and LWD have a version of these tools.  Searching the internet is a reasonable way to get most of this information.

Measurement Name: Downhole Weight On Bit Abbreviation:  DWOB
Class: MWD Measurement Function:
Max Temp: 175ºC Length: 25’
Current Oil Field Use :
This trace allows the determination of the actual weight on bit at the bit.
Potential Geothermal  Use:
The DWD program has shown that this measurement can be used to detect bit-damaging events and prolong bit life
Special Conditions : None Example Tool: Schlumberger TeleScope
Baker Hughes Inteq CoPilot (service)
Measurement Name: Downhole Torque On Bit Abbreviation: DTOB
Class: MWD Measurement Function:
Max Temp: 175ºC Length: 25’
Current Oil Field Use :
This trace allows the determination of the actual torque on bit.
Potential Geothermal  Use:
The DWD program has shown the use of this measurement in prolonging bit life and providing an effective drilling program.
Special Conditions : None Example Tool: Schlumberger TeleScope
Baker Hughes Inteq CoPilot (service)
Measurement Name:  Downhole flow rate Abbreviation:
Class: MWD Measurement Function:
Max Temp: 175ºC Length: 25’
Current Oil Field Use :
This measurement allows the determination of the mudflow rate at or near the bit.
Potential Geothermal  Use:
The rolling float meter program has shown that this measurement in combination with a good measurement of return flow is critical in detecting lost circulation events.  The DWD program has shown the use of this measurement in detecting pipe washout and bit plugging conditions.
Special Conditions : None Example Tool: Schlumberger TeleScope
Measurement Name:  3-D Shock Abbreviation:
Class: MWD Measurement Function:
Max Temp: 175ºC Length: 25’
Current Oil Field Use :
This trace used in combination with 3-D vibration is used to monitor bit conditions.  Avoiding shock loads has been shown to increase bit life
Potential Geothermal  Use:
Same as oil field  but more critical in harder formations.
Special Conditions : None Example Tool: Schlumberger TeleScope
Baker Hughes Inteq VSS (service)
Measurement Name: 3-D Vibration Abbreviation:
Class: MWD Measurement Function:
Max Temp: 175ºC Length: 25’
Current Oil Field Use :
This trace used in combination with 3-D shhock is used to monitor bit conditions.  Avoiding damaging vibrations  has been shown to increase bit life, and increase ROP. Also used to determine RPM at bit
Potential Geothermal  Use:
Same as oil field  but more critical in harder formations.  RPM determination critical to avoiding several bit damaging situations.
Special Conditions : None Example Tool: Schlumberger TeleScope
Baker Hughes Inteq CoPilot (service)
Measurement Name: Direction and Inclination Abbreviation:  D&I
Class: MWD Measurement Function:
Max Temp: 175ºC Length: 25’
Current Oil Field Use :
These traces are used in directional drilling.  Both are required to control bit position
Potential Geothermal  Use:
Would be used in directional drilling applications.
Special Conditions : None Example Tool: Schlumberger TeleScope
Measurement Name: Azimuthal Natural Gamma Ray Abbreviation: GR
Class: LWD Measurement Function: Gamma Ray
Max Temp: 150ºC Length: 26’
Current Oil Field Use :
This trace measures the naturally occurring gamma radiation in several directions from the borehole. The trace is used to identify shales and clays as opposed to sands in lithologic sequences.  Processed trace is a primary correlation  trace between logs run at differing times.
Potential Geothermal  Use:
Gamma ray is primary correlation trace particularly in cased hole.
Special Conditions : None Example Tool: Schlumberger EcoScope
Measurement Name: Multi-frequency resistivity Abbreviation:
Class: LWD Measurement Function: Electric
Max Temp: 150ºC Length: 26’
Current Oil Field Use :
This measurement in oil and gas logging provide bed boundary and gas/oil/water contact information.
Potential Geothermal  Use:
Could be used in sedimentary sequence for bed boundary identification.  Usefulness in metamorphic and igneous formation is undocumented.
Special Conditions : None Example Tool: Schlumberger EcoScope
Measurement Name: Sonic Abbreviation:
Class: LWD Measurement Function: Sonic
Max Temp: 150ºC Length: 23’
Current Oil Field Use :
This measurement set provides information on porosity, mechanical rock properties and borehole stability.
Potential Geothermal  Use:
The borehole stability information would be a greatest value
Special Conditions : None Example Tool: Schlumberger sonicVision
Baker Hughes Inteq SoundTrak
Measurement Name: Multi-frequency, multi-depth resistivity Abbreviation:
Class: LWD Measurement Function:  Special/Electrical
Max Temp: 150ºC Length: 11’
Current Oil Field Use :
This tool is intended formation imaging.  Used for fracture identification and finding stress orientation.  Use in non-sedimentary formation is undocumented.  Also provides temperature data.
Potential Geothermal Use:
This tool may find use in advanced directional drilling applications.  If fracture imaging can be done in non-sedimentary geologies may be useful for fracture mapping and stress orientation
Special Conditions: Requires use of conductive mud system. Example Tool: Schlumberger GeoVision
Baker Hughes Inteq StarTrak; AziTrak
Measurement Name: Annular pressure Abbreviation: APWD
Class: LWD Measurement Function: Pressure
Max Temp: 150ºC Length: 26’
Current Oil Field Use :
This trace measures the pressure near the BHA-open hole interface.
Potential Geothermal  Use:This trace would be used to determine areas where lost circulation may be occurring.
Special Conditions : None Example Tool: Schlumberger EcoScope
Baker Hughes Inteq PressTEQ (service)
Measurement Name: Azimuthal Density Abbreviation:
Class: LWD Measurement Function: Density
Max Temp: 150ºC Length: 26’
Current Oil Field Use :
This trace measures the formation density in multiple  directions out from the bore hole.  Used in combination with other measurements for formation lithology identification
Potential Geothermal  Use:
This trace could be used in directional holes to drill along a bed boundary
Special Conditions : None Example Tool: Schlumberger EcoScope
Baker Hughes Inteq LithoTrak
Measurement Name: Compensated Neutron Abbreviation: CN
Class: LWD Measurement Function: Porosity
Max Temp: 150ºC Length: 26’
Current Oil Field Use :
This measurement is used to estimate porosity.  This trace is integrated in most logging tools as a part of a triple combo.
Potential Geothermal  Use:
Same as oil field use
Special Conditions : None Example Tool: Schlumberger EcoScope
Baker Hughes Inteq APLS
Measurement Name: Photoelectric Factor Abbreviation:
Class: LWD Measurement Function:  Special
Max Temp: 150ºC Length: 26’
Current Oil Field Use :
This trace measures the average atomic number of the formation constituents, used with density to determine mineralogy.
Potential Geothermal  Use:
Same as oil field use
Special Conditions : None Example Tool: Schlumberger EcoScope
Measurement Name: Ultrasonic Caliper Abbreviation:
Class: LWD Measurement Function: Borehole
Max Temp: 150ºC Length: 26’
Current Oil Field Use :
Measures the hole size directly behind the bit.  Used to determine size of hole and rugosity
Potential Geothermal  Use:
Same as oil field use.
Special Conditions : None Example Tool: Schlumberger EcoScope
Baker Hughes Inteq LithoTrak
Measurement Name: Porosity Abbreviation:
Class: LWD Measurement Function: Porosity
Max Temp: 150ºC Length: 26’
Current Oil Field Use :
This trace measures the apparent porosity of the formation based on fast neutrons emitted by a neutron source.  Neutron source may be chemical or electrical in nature.
Potential Geothermal  Use:
This trace could be used to in the estimation of formation porosity
Special Conditions : None Example Tool: Schlumberger EcoScope
Baker Hughes Inteq LithoTrak
Measurement Name: Sigma Abbreviation: Ѕ
Class: LWD Measurement Function: Special
Max Temp: 150ºC Length: 26’
Current Oil Field Use : This trace is a measure of the macroscopic absorption cross section for thermal neutrons, used to determine formation water saturation. Potential Geothermal  Use:
Special Conditions : None Example Tool: Schlumberger EcoScope
Measurement Name: Pulsed neutron spectroscopy Abbreviation:
Class: LWD Measurement Function: Special
Max Temp: 150ºC Length: 26’
Current Oil Field Use : This measurement utilizes a pulsed neutron source, and gamma ray detectors to estimate formation oil content, salinity, lithology, porosity and clay content.   Potential Geothermal  Use:This trace could be used to in the estimation of porosity and the determination of lithology
Special Conditions : None Example Tool: Schlumberger EcoScope
Measurement Name: Nuclear magnetic resonance Abbreviation:
Class: LWD Measurement Function: Special
Max Temp: 150ºC Length: 39’
Current Oil Field Use : This measurement is used to determine free and bound fluid volumes, fluid type, porosity and permeability estimation. Potential Geothermal  Use:This trace could be used to in the estimation formation porosity and permeability.
Special Conditions :
Informal conversations with persons who have used this tool indicate that its use is best understood in sandstone.
Example Tool:
Sperry MRIL-WD
Baker Hughes Inteq MagTrak
Measurement Name: Seismic Abbreviation:
Class: LWD Measurement Function: Special
Max Temp: 150 ºC Length: 14’
Current Oil Field Use : Data derived from this tool is used to look-ahead for formation changes, pore pressure changes and faults. Potential Geothermal  Use:
Same as oilfield uses
Special Conditions : Requires active seismic source on surface Example Tool:Schlumberger  seismic Vision
Measurement Name: Formation Pressure Abbreviation:
Class: LWD Measurement Function: Pressure
Max Temp: 150ºC Length: 31.5’
Current Oil Field Use : This tool measures the formation pressure and fluid mobility while drilling.  This measurement can replace some drill-stem (DST) formation test measurements.  Device seals against borehole wall and isolated formation from drilling fluids for testing.  This measurement is also used to drilling optimization. Potential Geothermal  Use:Sam
e as oil field use
Special Conditions : None Example Tool: Schlumberger Stethoscope
Baker Hughes Inteq TesTrak

Commentary

As one can see from the list, most tools are rated to 150ºC.  Some measurements can be made up to 175ºC.  These tools provide limited bandwidth data to the surface via mud pulse telemetry and higher bandwidth data via large onboard memories, which can be unloaded as a part of a bit trip.

The Sandia DWD program provided a limited MWD tool for testing.  While this tool was much more difficult to operate than the mud pulse telemetry tools listed above it did provide a great deal of data and demonstrated the usefulness of a MWD tool in optimizing drilling parameters with respect to drilling performance and extending bit life.  Extensive reviews of this work have been published and presented by others, and may be of interest to some readers.  One class of measurement that was not present in the DWD tool that is present in most current MWD tool is direction and inclination, which are critical in directional drilling.  The case for MWD tools in EGS is relatively clear.  The costs associated with damaged bits and BHA components clearly indicate the need for MWD.  In the longer term, if the use of directional drilling is contemplated MWD is a requirement.

The case for most LWD tools or traces will have to be made on a well-by-well basis.  As a minimum, one must comply with the individual states requirements for logging and MWD may be a viable option to meet these requirements for deeper holes.  MWD may not be required for the full duration of the drilling effort but certainly may be a requirement in deeper directionally drilled holes to assure that the hole is completed in the target area.   As has been noted most LWD traces and tools are optimized for drilling sedimentary formations; some experience will be required to determine the optimal MWD suite for EGS drilling programs.  With this in mind, the first few EGS programs should be funded and scheduled to provide for the evaluation of a wide variety of available MWD tool.  The basic limitation on the available tools is temperature, and accommodations will need to be made in the mud system and operational procedures to maintain the tools within their operational temperature ranges long enough to allow a reasonable evaluation.  After some experience is gained with the available tools efforts to construct tools suitable for higher temperatures could begin.

While the least complex of these measurements can be telemetered to the surface via mud pulse technology, the more complex, data dense applications will require a higher speed telemetry systems and indeed may require two way communication.  Here the use of a wired pipe system such as the intelliserv system will be required.  Looking back on the previous drilling efforts such as the Long Valley drilling project, there has always been a desire by the scientific community to use these precious drilling opportunities to test new and different ideas and tools.  The adoption of a standard telemetry system such as the intelliserv network early in the life of the drilling program would encourage a well disciplined scientific program and provide a framework on which the scientific community could plan their programs in a way that would minimally interfere with the drilling program.

Summary

Just as it would not be reasonable to try to up the efficiency of the countries truck fleet  by looking solely at replacing all tires in use today with tires that lower rolling friction; rather one needs to step back and look at the entire system including routing and deadheading for a quick example;  the selection of MWD and LWD tools must be driven by the entire EGS system. The selection of tools that is currently available at lower temperatures is more that sufficient.  One needs to look at the needs as generated from a broad system outlook and then upgrade the temperature capabilities of the necessary MWD and LWD tools.  A far more challenging task is to evaluate how these tools mostly designed and used in sedimentary environments will react in the EGS environment.  This project should be undertaken early in the development of EGS wells and will require a theoretical as well as a practical side.  If as is expected that directional drilling is an important part of the overall EGS effort, understanding how to control and direct these drilling tools with the available MWD  and LWD modules will be a major effort.

Directional Drilling Glossary

directional drilling
directional drilling

The glossary of terms used in directional drilling has been developed by the API Subcommittee on Controlled Deviation Drilling under the jurisdiction of the American Petroleum Institute Production Department’s Executive Committee on Drilling and Production Practice. The most frequently used terms listed below.

Angle of inclination (angle of drift). The angle, in degrees, taken at one at several points of variation from the vertical as revealed by a deviation survey, sometimes called the inclination or angle of deviation.

Angle of twist. The azimuth change through which the drillstring must be turned to offset the twist caused by the reactive torque of the downhole motor.

Anisotrospic formation theory. Stratifiedor antisotropic formations are assumed to posses different drill abilities parallel and normal to the bedding planes with the result that the bit does not drill in the direction of the resultant force.

zimuth. Direction of a course measured in a clockwise direction from 0◦ to 360◦; also called bearing.

Back-torque. Torque on a drill string causing a twisting of the string.

Bent sub. Sub used on top of a downhole motor to give a non straight bottom assembly. One of the connecting threads in machined at an angle to the axis of the body of the sub.

Big-eyed bit. Drill bit with one large-sized jet nozzle, used for jet deflection.

Bit stabilization. Refers to stabilization of the downhole assembly near the bit; a stabilized bit is forced to rotate around its own axis.

Borehole direction. Refers to the azimuth in which the borehole is heading.

Borehole directional survey. Refers to the measurements of the inclinations, azimuths and specified depths of the stations through a section of borehole.

Bottom-hole assembly (BHA). Assembly composed of the drill bit, stabilizers, reamers, drill collars, subs, etc., used at the bottom of the drillstring.

Bottomhole location. Position of the bottom of the hole with respect to some known surface location.

Bottomhole orientation sub (BHO). A sub in which a free-floating ball rolls to the low side and opens a port indicating an orientation position.

Build-and-hold wellbore. A wellbore configuration where the inclination is increased to some terminal angle of inclination and maintained at that angle to the specified target.

Buildup. That portion of the hole in which the angle of inclination is increased.

Buildup rate. Rate of change (◦/100 ft) of the inclination angle in the section of the hole where the inclination from the vertical is increasing.

Clearance. Space between the outer diameter of the tool in question and the side of the drilled hole; the difference in the diameter of the hole and the tool.

Clinograph. An instrument to measure and record inclination.

Closed traverse. Term used to indicate the closeness of two surveys; one survey going in the hole and the second survey coming out of the hole.

Corrective jetting runs. Action taken with a directional jet bit to change the direction or inclination of the borehole.

Course. The axis of the borehole over an interval length.

Course bearing. The azimuth of the course.

Crooked-hole. Wellbore that has been inadvertently deviated from a straight hole.

Crooked-hole area. An area where subsurface formations are so composed or arranged that it is difficult to drill a straight hole.

Cumulative fatigue damage. The total fatigue damage caused by repeated cyclic stresses.

Deflection tools. Drilling tools and equipment used to change the inclination and direction of the drilled wellbore.

Departure. Horizontal displacement of one station from another.

Fulcrum technique. Utilizes a bending moment principle to create a force on that the bit to counteract reaction forces that are tending to push the bit in a given direction.

Mechanical technique. Utilizes bottomhole equipment which is not normally a part of the conventional drillstring to aid deviation control. This equipment acts to force the bit to turn the hole in direction and inclination.

Packed-hole technique. Utilizes the hole wall to minimize bending of the bottomhole assembly.

Pendulum techniques. The basic principle involved is gravity or the “plumb-bob effect.”

Directional drilling contractor. A service company that supplies the special deflecting tools, BHA, survey instruments and a technical representative to perform the directional drilling aspects of the operation.

Direction of inclination. Direction of the course.

Dogleg. Total curvature in the wellbore consisting of a change of inclination and/or direction between two points.

Dogleg severity. A measure of the amount of change in the inclination and/or direction of a borehole; usually expressed in degrees per 100 ft of course length.

Drag. The extra force needed to move the drill string resulting from the drill string being in contact with the wall of the hole.

Drainholes. Several high-angle holes drilled laterally form a single wellbore into the producing zone.

Drift angle. The angle between the axis of the wellbore and the vertical.

Drop off. The portion of the hole in which the inclination is reduced.

Drop-off rate. Rate of change (◦/100 ft) of the inclination angle in the section of the wellbore that is decreasing toward vertical.

Goniometer. An instrument for measuring angles, as in surveying.

Gyroscopic survey. A directional survey conducted using a gyroscope for directional control, usually used where magnetic directional control cannot be obtained.

Hole curvature. Refers to changes in inclination and direction of the borehole.

Hydraulic orienting sub. Used in directional holes with inclination greater than 6◦ to find the low side of the hole. A ball falls to the low side of the sub and restrict an orifice, causing an increase in the circulating pressure. The position of the tool is know with relation to the low side of the hole.

Hydraulically operated bent sub. A deflection sub that is activated by hydraulic pressure of the drilling fluid.

Inclination angle. The angle of the wellbore from the vertical.

Inclinometer. An instrument that measures an angle of deviation from the vertical.

Jet bit deflection. A method of changing the inclination angle and direction of the wellbore by using the washing action of a jet nozzle at one side of the bit.

Keyseat. A condition wherein the borehole is abraded and extended sideways, and with a diameter smaller than the drill collars and bit; usually caused by the tool joints on the drill pipe.

Kickoff point (kickoff depth). The position in the well bore where the inclination of the hole is first purposely increased (KOP).

Lead angle. A method of setting the direction of the wellbore in anticipation of the bit walking.

Magnetic declination. Angular difference, east or west, at any geographical location, between true north or grid north and magnetic north.

Magnetic survey. A directional survey in which the direction is determined by a magnetic compass aligning with the earth’s magnetic field.

Measured depth. Actual length of the wellbore from its surface location to any specified station.

Mechanical orienting tool. A device to orient deflecting tools without the use of subsurface surveying instruments.

Methods of orientation

Direct method. Magnets embedded in the nonmagnetic drill collar are used to indicate the position of the tool facewith respect to magnetic north. A picture of a needle compass pointing to the magnets is superimposed on the picture of a compass pointing to magnetic north. By knowing the position of the magnets in the tool, the tool can be positioned with respect to north.

Indirect method. A method of orienting deflecting tools in which two survey runs are needed, one showing the direction of the hole and the other showing the position of the tool.

Surface readout. A device on the rig floor to indicate the subsurface position of the tool

Stoking. Method of orienting a tool using two pipe clamps, a telescope with a hair line, and an aligning bar to determine the orientation at each section of pipe run in the hole.

Monel (K monel). A nonmagnetic alloy used in making portions of downhole tools in the bottomhole assembly (BHA), where the magnetic survey tools are placed for obtaining magnetic direction information. Monel refers to a family of nickel-copper alloys.

Mud motor. Usually a positive displacement or turbine-type motor, positioned above the bit to provide (power) torque and rotation to the bit without rotating the drillstirng.

Mule shoe. A shaped form used on the bottom of orienting tools to position the tool. The shape resembles a mule shoe or the end of a pipe that has been cut both diagonally and concave. The shaped end forms a wedge to rotate the tool when lowered into a mating seat for the mule shoe.

Multishot survey. A directional survey in which multiple data points are recorded with one trip into the wellbore. Data are usually recorded on rolls of film.

Near-bit stabilizer. A stabilizer placed in the bottomhole assembly just above the bit.

Ouija board (registered trademark of Eastern Whipstock). An instrument composed of two protractors and a straight scale that is used to determine the positioning for a deflecting tool in a inclined wellbore.

Permissible dogleg. A dogleg through which equipment and/or tubulars can be operated without failure.

Pendulum effect. Refers to the pull of gravity on a body; tendency of a pendulum to return to vertical position.

Pendulum hookup. A bit and drill collar with a stabilizer to attain the maximum effect of the pendulum.

Rat hole. A hole that is drilled ahead of the main wellbore and which is of a smaller diameter than the bit in the main borehole.

Reamer. A tool employed to smooth the wall of a wellbore, enlarge the hole, stabilize the bit and straighten the wellbore where kinks and abrupt doglegs are encountered.

Rebel tool (registered trademark of Eastman Whipstock). A tool designed to prevent and correct lateral drift (walk) of the bit tool. It consists of two paddles on a common shaft that are designed to push the bit in the desired direction.

Roll off. A correction in the facing of the deflection tool, usually determined by experience, and which must be taken into consideration to give the proper facing to the tool.

Setting off course. A method of setting the direction of the wellbore in anticipation of the bit walking.

Side track. An operation performed to redirect the wellbore by starting a new hole; at a position above the bottom of the original hole.

Slant hole. A non vertical hole; usually refers to a wellbore purposely inclined in a specific direction; also used to define a wellbore that is nonvertical at the surface.

Slant rig. Drilling rig specifically designed to drill a wellbore that is non vertical at the surface. The mast is slanted and special pipe-handling equipment is needed.

Spiraled wellbore. A wellbore that has attained a changing configuration such as a helical form.

Spud bit. In directional drilling, a special bit used to change the direction and inclination of the wellbore.

Stabilizer. A tool placed in the drilling assembly to Change or maintain the inclination angle in a wellbore by controlling the location of the contact point between the hole and drill collars. Center the drill collars near the bit to improve drilling performance. Prevent wear and differential sticking of the drill collars.

Surveying frequency. Refers to the number of feet between survey records.

Target area. A defined area, at a prescribed vertical depth, that is planned to be intersected by the wellbore.

Tool azimuth angle. The angle between north and the projection of the tool reference axis onto a horizontal plane.

Tool high-side angle. The angle between the tool reference axis and a line perpendicular to the hole axis and lying the vertical plane.

Total curvature. Implies three-dimensional curvature.

True north. The direction from any geographical location on the earth’s surface to the north geometric pole.

True vertical depth (TVD). The actual vertical depth of an inclined wellbore.

Turbodrill. A downhole motor that utilizes a turbine for power to rotate the bit.

Turn. A change in bearing of the hole; usually spoken of as the right or left turn with the orientation that of an observer who views the well course from the surface site.

Walk (of hole). The tendency of a wellbore to deviate in the horizontal plane.

Wellbore survey calculation method. Refers to the mathematical method and assumptions used in reconstructing the path of the wellbore and in generating the space curve path of the wellbore from inclination and direction angle measurements taken along the wellbore. These measurements are obtained from gyroscopic or magnetic instruments of either the single-shot or multishot type.

Whipstock. Along wedge and channel-shaped piece of steel with a collar at its top through which the subs and drillstring may pass. The face of the whipstock sets an angle to deflect the bit.

Woodpecker drill collar (indented drill collar). Round drill collarwith a series of indentations on one side to form an eccentrically weighted collar.

References:
1. Drilling Equipment and Operation.
2. drilling Operation

Drilling Bits

Drilling Bit
Drilling Bit

when talking about oil well drilling, it is important to know How well the drilling bit drills depends on several factors, such as the condition of the drilling bit, the weight applied to it, and the rate at which it is rotated. Also important for a drilling bit performance is the effectiveness of the drilling fluid in clearing cuttings, produced by the bit away from the bottom.

read more about Drilling Fluids

The aim of oil well drilling drilling is to:
i ) make hole as fast as possible by selecting drilling bits which produce good penetration rates.
ii ) run drilling bits with a long working life to reduce trip time.
iii ) use drilling bits which drill a full-size or full-gauge hole during the entire time they are on  bottom.

The choice of drilling bit depends on several factors. One is the type of oil formation to be drilled, whether it is it hard, soft, medium hard or medium soft. A second factor is the cost of the bit. Getting the highest possible footage from the bit cuts down bit costs and minimizes the number of trips needed for bit changes. It should be stated, however, that continuing to use a bit that is still drilling but slowly is false economy.

In the shallower part of the hole only one or two bits are needed before pipe is pulled for logging or running casing and often one drilling bit is sufficient to make the hole in which the conductor is to be set. As formations near the surface are usually very soft, one bit may prove sufficient for several wells. But in the deeper part or the hole, several bits often have to be drilled before casing depth is reached.

It is normal that the drilling bit used to drill the cement left in the casing is also used to drill the formation, although in some instances a separate bit is run to drill the cement and thereafter changed for a more suitable one for the formation expected deeper down.

Oil formations vary a lot in hardness and abrasiveness and have a considerable effect on drilling bit performance. If there were no difference in rock formations, one type of bit only would be needed which requires standard bit weight, rotary speed and pump pressure to drill at the maximum rate.

Unfortunately, such a situation does not exist and several drilling bits are required for the alternating layers of soft material, oil reservoir hard rocks and abrasive sections. Changing the bit every time as the formation changes is, however, impracticable. Therefore a compromise has to be made and a bit that performs reasonably well in all conditions is selected. The choice of drilling bit for a well in a field where the formations are familiar is obviously easier than for a wildcat.

Drilling Bits can generally be classified into two categories;

i ) roller bits.
ii ) drag bits.
The following is a description of both.

Roller Cone Bits

roller cone bit
roller cone bit

The cutting elements of roller cone bits are arranged on “conical” structures that are attached to a bit body. Typically three cones are used and the teeth (cutters) may be tungsten carbide that is inserted into pre-drilled holes into the steel cone shell or steel teeth that are formed by milling directly on the cone shell as it is manufactured. The length, spacing, shape, and tooth material are tailored for drilling a particular rock. Insert types used as teeth on roller-cone bits.

The IADC has developed a standard classification code that is used to classify drilling bits made by different manufactures according to the rock hardness that they are designed to drill including the particular design features of the bit. Each roller bit cone contains a bearing and lubrication system. In some cases the drilling mud is used as the lubricant (open bearing) and in other cases a special lubricant is confined inside the case (sealed bearing). The apes bearing system is used almost exclusively with roller bearings. The sealed bearing system may be used with either roller or journal bearings.

The rock cutting process of the roller cone bit is either by gauging (digging and shoveling) in soft formation or by chiseling in hard formation. A hydraulic cuttings removal system is incorporated in each bit to remove the cuttings from around the teeth. Typically, a nozzle is placed between each cone to direct mud at the bottom of the hole and cutters. These nozzles are usually located at a height approximately equal to the top of the cone, but in some cases are extended towards the arms where the cutters contact the rock.

The drilling fluid is pumped through the nozzles at relatively high velocity in order to remove the drilled cuttings. The three-cone rolling cutter bit is by far the most common bit type currently used in rotary drilling operations. This general drilling bit type is available with a large variety of tooth design and bearing types and, thus, is suited for a wide variety of formation characteristics. The three cones rotate about their axis as the bit is rotated on bottom. The shape of the bit teeth also has a large effect on the drilling action- of a rolling cutter bit. Long, widely spaced, steel teeth are used for drilling soft formations. As the rock type gets harder, the tooth length and cone offset must be reduced to prevent tooth breakage; the drilling action of a bit with zero cone offset is essentially a crushing action. The smaller teeth also allow more room for the construction of stronger bearings.

The metallurgy requirements of the drilling bit teeth also depend on the formation characteristics. The two primary types used are:
(1) milled tooth cutters.
(2) tungsten carbide insert cutters. The milled tooth cutters arc manufactured by.

milling the teeth out of a steel cone while the tungsten carbide insert bits arc manufactured by pressing a tungsten carbide cylinder into accurately machined holes in the cone. The milled tooth bits designed for soft formations usually are faced with a wear-resistant material, such as tungsten carbide, on one side of the tooth. The milled tooth bits designed to drill harder formations are usually case hardened by special processing and heat treating the cutter during manufacturing. The tungsten carbide teeth designed for drilling soft formations are long and have a chisel-shaped end. Rolling cutter bits with the most advanced bearing assembly are the journal bearing bits In this type bit, the roller bearings are eliminated and the cone rotates in contact with the journal bearing pin. This type bearing has the advantage of greatly increasing the contact area through which the weight on the bit is transmitted to the cone.

Drag Bits

There are two general types of drag bits that are in common usage. The oldest is the natural diamond matrix bit in which industrial grade diamonds are set into a bit head that is manufactured by a powdered metallurgy technique.

drag-bits
drag-bits

The size, shape, quantity, quality, and exposure of the diamonds are tailored to provide the best performance for a particular formation. Each drilling bit is designed and manufactured for a particular job rather than being mass produced as roller cone bits are. The cuttings are removed by mud that flows through a series of water courses. The design of these water courses is aimed at forcing fluid around each individual diamond. The matrix diamond bit cuts rock by grinding and thus a primary function of the fluid is to conduct heat away from the diamonds.
The other type of drag bit is the polycrystalline diamond compact (PDC) bit that is constructed with cutters comprised of a man made diamond material. The cutters are generally much larger than natural diamonds and are designed to cut the rock by shearing, similar to metal machining. PDC bits have proven very successful in homogeneous and, soft to moderate strength formations. In formations where they are successful, they can drill two to three times faster then a roller cone bit and may have an equally long life.

Classification of Drilling Bits

A large variety of bits designs are available from several manufacturers. The IADC (International Association of Drilling Contractors) approved a standard classification system for identifying similar bit types available from various manufacturers. The classification system adopted is the three digit code.

The first digit in the drilling bit classification scheme is called the bit series number. The letter “D” precedes the first digit if the bit is diamond or PDC drag bit. Series D1 through D2 are reserved for diamond bits and PDC bits in the soft, medium-soft, medium, medium-hard and hard formation categories, respectively. Series D7 through D9 are reserved for diamond core bits in the soft, medium and hard formation categories. Series 1,2 and 3 are reserved for milled tooth bits in the soft, medium and hard formation categories, respectively. Series 5, 6, 7 and 8 are for insert bits in the soft, medium, hard, and extremely hard formation categories, respectively. Series 4 is reserved for future use with special categories such as a “universal” bit.

The second digit is called the type number. Type 0 is reserved for PDC drag bits. Types 1 through 4 designate a formation hardness sub classification from the softest to the hardest formation within each category. The feature numbers are interpreted differently, depending on the general type of bit being described. Feature numbers are defined for diamond and PDC drag bits, diamond and PDC drag-type core-cutting bits, and rolling cutter bits.

Eight standard diamond and PDC drag bits features are “1”, step-type profile, “2”, long-taper profile, “3”, short-taper profile, “4”, nontaper profile, “5”, downhole-motor type, “6”, sidetrack type, “7”, oil-base type, and “8”, coreejector type. The remaining feature, 9, is reserved for special features selected by the bit manufacturer.

There are two standard feature numbers for diamond and PDC drag-type core-cutting bits. These bits are used to recover a length of formation sample cored from the central portion of the borehole. The two features are “1”, conventional core-barrel type, and “2”, face-discharge type. As in the previous case, feature “9” is reserved for special features selected by the bit.

manufacturer

There are eight standard feature numbers for rolling-cutter bits. The standard feature numbers are “1”, standard rolling cutter bit (jet bit or regular), “2”, T-shaped heel teeth for gauge protection, “3”, extra insert teeth for gauge protection, “4”, sealed roller bearings, “5”, combination of “3” and “4”, “6”, sealed friction bearing, “and “7”, combination of “3” and “6”. The remaining features, “8” and “9” were reserved for special features selected by the drilling bit manufacturer. Feature “8” is often used to designate bits designed for directional drilling. Some of the main design features of the various rolling cutter bit types include some of the tooth design features of the various bit types and classes. As the class number increases, the cone offset, tooth height, and amount of tooth hardfacing decreases while the number of teeth and amount of tooth case hardening increases. An increase in bearing capacity is possible for the bits with a higher class number. This is possible shorter length of bit teeth at higher bit class numbers.

Drilling Bit Evaluation

It is important to maintain careful written records of the performance of each bit for future references. Bits are worn by abrasion and shocks while drilling. The wear pattern is important, it should be inspected once the bit has been pulled and its grading should be recorded. Such records indicate the working life of the bit and aid the selection of the type of bit which may provide most efficient in a particular formation. The amount of wear on teeth, bearings andgauge is recorded according to a special coding system.

Wear on Teeth

Teeth wear is graded in eighths of the original tooth height. Using the letter T to denote teeth, T8 means that the teeth is completely worn out, and T3 means that 3/8 of the original height has been worn away. If the majority of the teeth in any row are broken, “BT” is added.

Bearing Wear

Grading a used bearing is the most difficult part of grading dull bits, because the condition of the bearings can be determined only by “touch”. Bearing wear is expressed in eighths of bearing life expended. Using the letter B to denote bearings, B8 means that the bearing is completely worn out, and B6 means that 6/8 of the estimated life has been used. For sealed bearing bits, the condition of the seal is a better means of grading the bearing life. For sealedbearings, only three codes are used; B3 means the seal is effective, B5 means the seal is questionable, and B8 means the seal failed.

Gauge Wear

This can be determined by using a ring gauge and ruler. There are two methods used to measure the wear. In the first and most popular, the ring gauge is pulled against the gauge points of two cones, and the space between the ring and third cone is measured. Usually, this measurement is used for the amount of wear. However, to be exact, the measurement should be multiplied by 2/3. In the second method, the drilling bit is centered in the gauge ring and the ruler is used to measure thedistance from the ring to the outermost cutting surface (gauge surface). This measurement must be multiplied by two to give the loss in diameter and, thus, the total amount of wear. Using the letter G for  gauge, G0 means in gauge, and G5 means bit diameter is 0.625 in. under gauge.

References:
1. Drilling Equipment and Operation.
2. drilling Operation

read also HSE in Drilling