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Kambi Mwd Manual

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    MWD Operational Manual

    KAMBI ENTERPRISES Inc.11981 44 St SE.Calgary AB T2Z 4G9Ph: +1(403) 243-4438Fax: +1(403) 243-8958www.kambi.ca


    Prepared by: Ewert Muoz

    December 01, 2006Revision: 2

    This manual is primarily intended to provide Kambi Enterprises Inc. or associates Operators with guidance of the bestpractice in the operation of MWD systems in a variety of downhole conditions.

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    Theory of Operation

    MWD System

    Modular Design Retrievable and Reinsertable Operating Specifications

    Flow RangesPressure DropData TransmissionElectrical Power/ Operating TimeBattery Duration Table

    Operational ModesMaximum Lateral Displacement ErrorInclination AccuracyTool face AccuracyDip Angle AccuracySensor PerformanceSensor ToleranceMaximum Lost-circulation MaterialEnvironmentalShockVibrationOperating temperaturesTable Orifice / PoppetFlow Chart

    Pulse Shape.ResolutionData word transmission times

    Down Link Communications Detection Coding, Detection and Decoding Processes. Directional Computations Summary

    Surface Equipment Considerations

    Rig ConsiderationsRig Type & Equipment

    Make-up and Break-out of MWD UBHORetrievable / Replaceable MWD ToolsFishing Equipment

    MWD HardwarePressure Transducer (Sensor)Revolutions Per Minute (RPM)Rig Data Acquisition System

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    Mud PumpsPump TypeDuplex PumpsPulsation Dampeners

    Liner Condition / Efficiency.

    MWD and BHA Configuration

    Sensor Placement and Orientation (Directional Module)

    Drillstring Magnetic Interference External Magnetic Interference Shock & Vibration

    Drill Pipe Screens

    Downhole Considerations

    Signal StrengthFlow RatePressure DropSignal AttenuationPulse Width (Transmission Frequency)Positive Displacement Motors

    Drilling FluidsCompressible Drilling Fluids

    Planned Mud Additives ( Add LCM)Lost Circulation Material (LCM)Lubricating BeadsBariteHematite

    Mud Mixing Mud Contaminants

    Pipe Scale / Plastic / CementGloves, Wrenches and Other JunkCuttings and Mud SolidsHeavy Cuttings in High Angle Holes

    Drilling ConditionsDeep DrillingHole Size RestrictionsTemperature

    PressureStuck Pipe / Borehole Stability

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    Trajectory / Geological Considerations

    Wellbore ProfileMWD Surveying Procedures

    Dogleg SeveritySurvey Accuracy / Uncertainty

    Sag CorrectionsDepth ErrorGyro LimitationsCollision AvoidanceTarget Shrinking

    Physical Formation ParametersFormation MeasurementsHard or Cemented FormationsRugosity and Washouts

    Appl ications / Techniques

    Invasion / Time-Lapse LoggingReal-Time / Recorded Data Densities Economic and Regulatory Considerations

    Critical MWD InformationEconomically Beneficial MWDLogistics and Geographics

    Reliabil ity and Statist ics

    Failure AnalysisFailure Type

    EnvironmentAdditional Questions

    MWD Operational Guidelines Check List


    Conversion table

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    This manual is primarily intended to provide operators of Measurement-While-Drilling (MWD) Tools with guidance onthe best practice in the operation of the GE systemunder a variety of downhole conditions. It contains advice on howto set up the operational environment most conducive to successful operations. Due to the variety of MWD operations,this manual covers most of the operations of the company in Canada.


    Downhole Sensor.

    The main sensor is a GE magnetometer. It is a standard electronic instrument proven by many years of usein downhole survey systems ranging from utility boring devices to MWD systems and Steering tools.The GE electronics package contains Temperature Sensors. Three-Axis Magnetic Sensors and Three-Axis

    Accelerometers that are capable of detecting the Borehole Temperature, The Earth's Magnetic Field andthe Gravitational Field with High resolution and precision. The output from these sensors can be digitizedand processed to find the vector to the earth's magnetic north pole and the vector for "down" center of theearth, with temperature compensation. This information, along with other parameters, produces data suchas Inclination, Azimuth and Magnetic and Gravity Toolfaces. Data such as Battery Voltage, Dip Angle, total

    Gravity field, and Total Magnetic Field, may also be transmitted to the surface to assist in the quantifying ofthe survey data.


    The GE-MWD Downhole Processor is the controller of the system and commands all functions of thesystem and performs all downhole calculations. Contained inside the assembly are: a Single Port MPU, aTriple Power Supply and a Digital Orientation Module. The Single Port MPU is a modular micro-controllerassembly based on the Motorola MC68HC11 microprocessor that implements qMIX communicationsprotocol (qMIX/11). The Triple Power Supply provides regulated power for the complete assembly.The processor monitors the state of the flow sense to determine when mud flow has starred or stopped.When it senses No Flow after a Flow On position the processor initiates the program to activate the sensorsfor measuring the parameters required to complete a survey. Upon completion of the survey acquisition

    procedure by the sensors, the processor digitizes, formats, and stores the data for transmission uphole.After the processor senses that flow has resumed, the pulser is activated and begins the pulsing sequencestransmitting the coded signals to the surface via the mud column in the bore of the drill string.

    Battery Pack.

    Energy is supplied to the downhole probe via the battery pack(s). A "Long Duration" probeincorporates two single battery packs housed in their individual battery barrels. If the operator is planning touse the directional package and requires extended battery life, then the system can be stacked in thestandard arrangement, with the second battery barrel placed above the Survey Electronics module. Shouldthe operator require the use of the Gamma Ray detection module, then the batteries can be stacked intandem above the Survey Electronics module, while the Gamma Ray detection module will be placeddirectly above the Pulser Module. The arrangement of the modules in the tool design is limited only to thededicated collar design. The battery modules and the gamma module are identical in length and aretherefore interchangeable, The design of the dedicated collar places the Survey Electronics module abovethe battery(or gamma) module.

    NOTE: The Pulser in the QDT MWD is always on the lower end of the tool.

    The batteries are lithium. Lithium packs go to 150 degrees C., eight cells are used in the lithium packs. It isestimated that a single lithium battery pack will last over 160 hours. The battery pack life depends on thepulse length, the tool configuration and operational modes used.

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    The pulser consists of an oil filled pulser section and an electronic Pulser Driver. The Driver contains acapacitor bank that derives its energy from the batteries and is controlled by the timing / switching circuitry.The oil filled pulser section contains two solenoids or coils with the first solenoid designated the "pull-back"solenoid. When energized, the pull-back solenoid retracts a plunger that is connected to a series of rodsand shafts to the servo-poppet. The second solenoid designated the "Holding Coil" solenoid, energizes afterthe first solenoid pulls the assembly back. The retraction of the servo-poppet initiates mud flow through theservo-orifice and into the pulser plenum below. This maneuver and resulting mud flow redirection initiatesthe propagation the mud pulse.The pull-back solenoid requires a large energizing charge, supplied by the capacitors in the driver. Thecapacitors then discharge to the "Holding Coil", just below the Pull-Back solenoid. The Pull-Back solenoidonly operates for about 80 milliseconds before it is de-energized. For the remainder of the pulse length theservo-poppet and shafts are held in the "up", or open position by the force applied to the Holding Coil. Whileenergized a clapper maintains contact to the front face of the Holding Coil completing a magnetic circuit.To sustain this position the Holding Coil requires very little current. When the Holding Coil is de-eneigized,the return springs drive the shafts and servo-poppet back to the "down", or closed, position. This reversemaneuver and the resulting mud flow redirection initiates a return of the signal poppet to the open positionand completes the pulse generation procedure.To summarize, the processor sends a signal to the pulser driver. The Driver Circuit controls and energizes

    the two solenoids, one to pull-back and one to hold, and moves the shafts up in the pulser, thus controllingthe servo-poppet movement. The servo-poppet, by opening and closing, regulates the fluid movement intothe plenum. The resulting mud flow through the plenum pushes against the main signal piston inassociation with the force from the main spring, and overcomes the opposing forces which hold the signalpoppet up or in the open position. The main signal poppet is forced down, partially obstructing mud flowthrough the restrictor orifice creating a higher back pressure in the annulus. When the servo-poppet movesdown and seats, flow through the plenum is shut off. Though holes in the probe fluid enters and pushes onthe opposite side of the main signal piston and pushes it up, due to the lower differential pressure in theplenum, and overcomes the main piston spring force.This pulls the main signal poppet up and out of the main orifice allowing full fluid flow and a resultingreduction in the annular pressure. The differences in annular pressure created by the main signal poppet isperceived as a pulse.Thus, the servo-poppet is electro-mechanically controlled, and drives the action of the main signal poppet

    which is powered by regulated fluid pressure. This makes the probe very energy efficient and because onlytwo parts must move [ the servo-poppet and main signal poppet]. It is also very reliable. This design hasallowed GEto develop a small O.D. MWD that is capable of producing a very large (high pressure) positiveand clean pulse with very low energy consumption. This results in more reliable signals and longer batterylife. The capability to use two battery packs independently of each other allows the operator to utilize onebattery pack at a time gaining the maximum battery life from each pack before switching to the fresh packthus insuring that the investment in batteries is fully realized.

    Flow Sensor.

    Interconnect Modules.

    The intermodules serve four purposes.

    1. They provide the wire ways between modules.2. They act as flex points in the probe allowing it to bend to a very tight radius downhole.3. The intermodules act as part of the centralizer system, that holds the probe centered in the drill

    collar.4. The elastomeric cushioning around the intermodule acts as a shock and vibration absorption

    system that filters out much of the low frequency vibration energy transmitted through the BHA fromthe action of the bit and rotation.

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    The intermodules were designed to be the points at which the components of the downhole probe aremade-up and broken down, i.e., the field connections.


    The muleshoe works like all other orienting devices by having a key which catches the helical edge on theprobe end, and orients the probe to a fixed location as it seats. The key is in line with an orientation bolt thatgoes through the wall of the drill collar and to orient and lock the muleshoe in the collar. This allows theMWD operator to easily measure the offset angle between the orientation bolt/muleshoe key and the bentsub/mud motor scribe line. This angle is entered as the Driller's Assembly Offset (DAO) in the qMWDCnfgprogram into the DRT through the Toolface Offset Procedure.Note: the operator must also be aware of the Internal Mounting Offset (IMO) of MWD probe and go throughthe procedure to measure this angle and insure that the total offset is correct and that both corrections areregistered into the propel systems.The muleshoe also contains the main orifice into which the pulser main signal poppet projects into to createthe pressure pulse. There are 9 different sizes of orifices. 1.20 1.23 1.25 1.28" 1.30" 1.35" 1.40" 1.50"1.60 I.D. They may be changed out by removing the muleshoe from the drill collar and removing the snap-ring and sliding the orifice out of lower end of the muleshoe.The amount of the flow will dictate the size of the main orifice. A new snap ring should be used wheneverthe orifice is reseated. The muleshoe is held in place in the lower end of the drill collar by 2 screws.

    Surface Equipment.

    The GE-MWD system is designed to operate with PC, a Surface Receiver, a Safe-Area Power Supply, anda Pressure Transducer. The qMWD software to communicate with the receiver and downhole probe,provided by GE, is loaded onto the hard disk of the PC. The qMWD software allows the operator toconfigure the Tool and the DRT using the PC the Instruction Manuals supplied by GE.

    Connecting the PC and the cabling as diagrammed in drawings, will allow the selection of the parametersdesired; such as Pulse Length, Delay Times and Local Magnetic Dip Angle, etc. Then the MWD Operator,can select the various parameters and options necessary to configure the downhole probe and the DrillersRemote Terminal display with the proper operating parameters.

    After the desired parameters and format are selected, they are loaded into the MWD Transmitter and theDRT. The PC should then be loaded with the qMWD/PC program to monitor field operations from a Safe

    Area.Note: the PC does not actively function in the decoding operations, but can act as the permanent filingsource for all data transmitted by the MWD probe. The Programming Cable to the probe should then bedisconnected and the spear point re-attached to the probe, and torqued to the proper 58 ft/lbs. Then it canbe loaded into the drill collar, ready for downhole operations. Power draw from a completely made-up tool isminimal. With no flow to the tool, depending on the program installed, the probe will initiate a survey and

    just monitor the circuits until flow is recognized. Only when flow is sensed by the flow switch will the toolcommence the pulsing process and go into the Survey and Toolface Sequencing Modes.The surface receiver is powered by the Safe-Area Power Supply. which must be located in a Safe Area.(i.e. an area where flammable vapors do not exist). The surface receiver is the only unit that is qualified forHazardous Area operation. It may be set up on the rig floor to supply MWD data to the driller. The Power

    Supply Cables should be neatly run from the Driller's Console to the Safe Area Power Supply. TheTransducer Cable should be nearly run also from the Transducer to the DRT. The PC is then connected tothe Safe Area Power Supply via the qBUS connection on the power supply to the EOM port on the PC.

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    MWD System

    An MWD system is a valuable downhole tool, with surface sensors and a surface computer. The surface sensorsinclude a signal receiver (Transducer) and drilling monitors (Rig Display). The surface computer may need to belocated in a safe area away from the rig floor normally inside the doghouse. The downhole tool is made up of multiplecomponents - a pulser section (Pulser), a power section (Battery Barrel), a main brain or computer processor which

    interprets the readings from the sensors that measure borehole direction, formation properties and drilling performance(Directional Module), and normally a second power section for long runs or back up power.Our MWD designs are modular and the different sections can be configured or interchanged relatively easily on the Rigsite. Sensors that are available today measure borehole direction, (inclination, azimuth, and tool face orientation)natural formation gamma-rays, resistivity, downhole vibration, temperature and pressureOur System is a Positive Pulse, through positive pulses, downhole life and servicing is simplified through the productionof and minimal moving parts. Maintenance in the field can be achieved with minimum tools and time.

    Modular Design

    The GEs modular MWD System is easily assembled in the field, enabling easy addition of formation evaluationsystems such as gamma ray modules and centerfire resistivity solutions. The component structure of the systemenables a flexible sensor position and placement close to the drill head, optimizing sensor performance. Replacementof individual sensors in the field is another added benefit, eliminating the need to replace the entire MWD system.

    Retrievable and Reinsertable

    The GE MWD probe can be retrieved and reinserted, maximizing downhole time effectiveness and enabling efficientprobe upgrades and replacements. In the event that the pipe gets stuck in the hole, this feature minimizes the rig timelost for probe retrieval. Two people can transport the probe to the rig floor, eliminating the need for overhead cranes.

    Operating Specifications

    Flow Ranges

    75-165 gpm, 3.5 in. O.D. collar100-300 gpm, 4.75 in. O.D. collar150-600 gpm, 6.5 in. O.D. collar400-1200 gpm, 8.25 in. O.D. collar

    Pressure Drop

    100 psi @ 400 gpm

    Data Transmission


    Electrical Power/Operating Time

    Lithium battery operates to +150C or +175C. Will operate for 175 to 200 hours per battery pack under normal used, incold weather like Canada, batteries perform poorly and in temperatures around -15 to -20 the voltage reading decreasedramatically, it is recommend that under -5.0 C, uses battery blanket over Batt1.

    The pulse width used in the configuration will also affect battery life. The faster the pulse width, the more battery lifethat is used.

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    Battery Duration Table

    Standard Tool

    Pulse Width Duration in Hs.

    3.00 210

    2.00 190

    1.50 160

    1.20 135

    1.00 120

    0.80 100

    Standard Tool + Gamma

    3.00 190

    2.00 150

    1.50 120

    1.20 100

    1.00 900.80 75

    Notes : Standard Tool is Pulser + Battery Section + Directional Module.

    Operational Modes

    Operator-selectable sequences and downlinking options. Highly flexible operating software. Selectable resolution allparameters

    Maximum Lateral Displacement Error

    2.6 ft. /1000 ft. or a conical uncertainty of 0.15 maximum

    Inclination Accuracy


    Toolface Accuracy


    Dip Angle Accuracy


    Sensor Performance

    Azimuth 0 to 360 +/- 0.15 conical uncertainty

    Inclination 0 to 180 +/- 0.1

    Gravity Toolface 0 to 360 +/- 0.1, Inclination = 90

    Magnetic Toolface 0 to 360 +/- 0.1, Inclination = 0, 0 Lat.

    Gravity Intensity 0 to +/- 1000 mg +/- 1.0 mg

    Magnetic Intensity 0 to +/- 700 mGauss +/- 0.10 mGauss

    Dip Angle -90.0 to 90.0 +/- 0.15

    Temperature 0 to +150C +/- 2C

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    Sensor Tolerance

    Magnetic Field Strength :Accepted tolerance is 0.020 Gauss. Total Gravity Field : Accepted tolerance is 0.005 g. ( For Canada average reading is 1.003/1.005) Dip Angle :Accepted tolerance is 0.65 Degrees .

    Maximum Lost-circulation Material

    40-50 ppb concentration, any size, pre-mixed


    1000g, 0.5 msec, 1/2 sine all axes


    5-30 Hz, 1 in. (double amplitude)30-500 Hz, 20 g, all axes

    Operating temperatures

    Models available for -20C to +150Cor -20C to +175C

    Table Orifi ce / Poppet





    1.28 1.125 0.297 Under 250

    1.28 1.086 0.360 200-3751.28 1.044 0.437 300-500

    1.35 1.125 0.443 225-475

    1.35 1.086 0.505 350-5501.35 1.044 0.582 475-600

    1.40 1.125 0.550 350-575

    1.40 1.086 0.612 450-650

    1.40 1.044 0.690 475-700

    1.50 1.125 0.778 475-750

    1.50 1.086 0.840 500-800

    1.50 1.044 0.918 Over 700

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    Pulse Shape

    Flow Chart

    1.28 1.122 1.28 1.086

    1.35 1.122

    1.35 1.0861.28 1.040

    1.40 1.122

    1.40 1.086

    1.35 1.040

    1.50 1.122

    1.50 1.086

    1.40 1.040

    1.50 1.040

    1.20 1.125

    1.20 1.167







    0.3785 0.757 1.135 1.514 1.892 2.271 2.649 3.028 3.406

    Flow (M)



    1.28 1.122 1.28 1.086 1.35 1.122 1.35 1.086 1.28 1.040 1.40 1.122 1.40 1.086

    1.35 1.040 1.50 1.122 1.50 1.086 1.40 1.040 1.50 1.040 1.20 1.125 1.20 1.167





    0.5 1.0 1.5 2.0 3.0

    Pulse Duration (sec)



    Max average Amplitude reached

    for pulse duration 1.0 & 1.2 Sec.

    Amplitude Decreases rapidly

    for Pulse Lenghts < 1.5 Sec.

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    Here are the values to program the tool for accurate information. Listed below are the ranges for each of the variables.

    Variable Range 6 Bit 7 Bit 8 Bit 9 Bit 10 Bit 11 Bit 12 Bit

    Azim 360 5.714 2.835 1.406 0.705 0.352 0.176 [0.088]

    Inc 180 2.857 1.417 0.703 0.352 0.176 0.088 [0.044]Temp 255 4.048 2.008 [1] 0.499 0.249 0.125 0.062MagF 1 0.016 0.008 0.004 0.002 [0.001] 0 0DipA 90 1.429 0.709 0.353 0.176 0.088 [0.044] 0.022Grav 2 0.032 0.016 0.008 0.004 0.002 [0.001] 0TFA 360 5.714 2.835 [1.412] 0.705 0.352 0.176 0.088

    Gama 255 4.048 2.008 [1] 0.499 0.249 0.125 0.062BatV 51.1 0.811 0.402 [0.2] 0.1 0.05 0.025 0.012

    Notes:1) The red values are recommended for most operations to the best configuration to program the tool.

    To estimate the figures shown in the above chart it is only necessary to take 2 times itself to the number ofbits and divide this into the span of the variable. Azimuth would be:

    2 x 2 x 2 x 2 x 2 x 2 x 2 x 2 x 2 x 2 x 2 x 2 = 4096

    360 (span) divided by above (4096) = Resolution

    Data Word Transmission Times


    0.8 6 11 Sec.0.8 8 14 Sec.0.8 12 21 Sec.1.0 6 14 Sec.1.0 8 18 Sec.1.0 12 26 Sec.1.2 6 17 Sec.1.2 8 22 Sec.1.2 12 31Sec.1.5 6 21 Sec.1.5 8 27 Sec.1.5 12 39 Sec.2.0 6 28 Sec.

    2.0 8 36 Sec.2.0 12 52 Sec.3.0 6 42 Sec.3.0 8 54 Sec.3.0 12 78 Sec.

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    Downlink Communications Detection

    There are two different modes for Down-linking Mode number and Rate Sequence. Rate Sequence allowsthe operator to change much more of the configurations of the downhole tool. Mode Number allows the operator todownlink into 1 of 4 different mode numbers. While rate sequence allows you more versatility, Mode Number take lesstime to configure the tool and is more effective configuration. The downlink communications detection process receives

    and processes commands sent to the telemetry process through a series of timed flow on and off sequences. Thesecommands are generally used to control the telemetry data rate and data content. Down-linking is done by bringing thepumps on and off in a predefined sequence of Down-linking pulses. These pulse time lengths are set by the Down LinkTime Period (DLTP), which is normally set at 60 seconds. The pulse time lengths is of DLPT with +/- 10 Sec.Tolerance.

    The downlink command protocol consists of a series of short flow on periods, referred to as command pulses,and a specific flow off time between the last command pulse and a flow on condition which exceeds the command pulseperiod.

    Mode Number

    Mode Number allows the operator to downlink into 1 to 4 modes that are configured on surface. Each of these modeswill include one of the four mode numbers that you configure in MWDConfig with pulse width / survey sequences andtoolface sequences. Next example show standard case in the field.


    To downlink into Mode 2 using a DLTP = 60 seconds (Step1)Pumps will be shut off for 60 seconds (Step2)Turn pumps on for 35 seconds (downlink pulse #1) (Step3)Turn pumps off for 35 seconds. (Step4)Turn pumps on for 35 seconds (downlink pulse #2) (Step5)Turn pumps off for 120 seconds (DLTP (60 sec) x 2 (mode 2) tolerance of +/-10 Sec. to recognize flow. (Step6)Turn pumps on at least 60 Sec. to finish the sequence.

    Coding, Detection and Decoding Processes.


    A large number of different coding schemes have been used for encoding MWD mud pulses signal.A paper bu Steve Monroe ( SPE 20326, 1990) discusses the relative advantages and disadvantage ofmany of these methods, especially with regards to their Data Rate ( data bits per second), Pulse Rate(pulses per data byte), and Signal Efficiency (data bits per pulse). The method that GE uses is notdiscussed by Steve Monroes paper but has a name similar to one described in the paper. We call ourcoding method the M-ary coding. We have chosen this method for its reasonable combination of gooddata rate, and good signal efficiency, as well as some desirable characteristics related to having to detectonly a single pulse in the present of noise.







    CommandPulse #1

    CommandPulse #2

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    M-ary Coding

    GE coding method involves breaking up any data word into a combinations of 2 and 3 symbols,each encoded by locating a single pulse in one-of-four or one-of-eight possible time slots. An example forthese case of 8 bit data word encoding a value of 221 is shown below:

    Word value: 221 Maximum Value: 255; Digital value: 128 64 32 16 8 4 2 11 1 0 1 1 1 0 1

    This encodes in M-ary as 3,3,5 where the first 3 comes form the symbol containing 11, the two mostsignificant bits of the digital word, then 3 from the next symbol, 011, and the final 5 from the 3 bits symbol,101. Visually this can be shown as:


    Where the pulses are transmitted most significant first.

    In the above example we have chosen to use time slots (time resolution-intervals) equal to one halfthe pulse width, and have allowed for a full pulse width (two slots) pulse-interference-gap (PIG) or recoverytime after each pulse. These choices were mainly based on earlier modeling and experimental work(Marshal, Fraser and Holt: SPE 17787, 1988). One important feature of this method is that we have to findonly the best single pulse in a window containing four or eight possible locations for the pulse. This featureincreases the robustness of the detection process at the expense of data rate and signal efficiency.

    Synchronization of the Detection and Decoding Processes with the Transmitted Signals.

    GE uses a triple wide pulse followed by three to eight single wide pulses to provide a method of synchronizingthe surface equipment to the transmitted data sequences. The surface receiver equipment functions by looking first forone received pulse matched to the shape of the triple wide pulse, followed by establishing a time base derived from the

    received positions in time of the three or more single wide pulses. The receiver also utilizes a tracking loop thatremoves clock drift by slowly adjusting the surface timing based on the average location in time of the received pulses.Pulse Detection

    GE receiver uses the cascade of a simple front end analog roofing filter, followed by a steep cut off tunable lowpass filter, followed by matched filter executed in software. This methodology is discussed in the paper by Marshal, et.Al., mentioned above. The matched filter has been shown to be optimum filter for detecting signals corrupted byadditive while Gaussian noise under a wide variety of criteria. Use of the matched filter has proven effective in manydifferent MWD systems over the years. GE has the ability to shift the tunable filter edge during operation to help reducethe effect of inband interference. For those cases where the noise/interference is concentrated in the upper portion ofthe passband, manually lowering the low pass cutoff frequency will reduce the noise/interference faster than it reducethe signal resulting in enhanced signal detection quality. The results of the pulse detection process are the location intime of the centroid of the best pulse located in the allowed time window, its amplitude and other characteristics. Incase multiple pulses are detected in the allowed symbol window, an evaluation in contained in the qMWD EngineersReference MANUAL, SECTION

    Decoding Process

    After each pulse is detected, the value of the symbol corresponding to its location is determined, and when theexpected pulses making up a data word have been received, the decode value is reported to the receiver display andlogging function, The receiver display maintains files containing all decoded data words, pulses data buffers (containsthe characteristic of all detected and suspect detected pulses), and pulse waveform records (contains a stripchart vstime of the output of the matched filter process).

    3 P P 2 1 0 7 6 5 4 3 P P 2 1 0 7 6 5 P P 4 3 2 1 0

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    Parity Check and Error Correction Code

    Each data word and header (if used) can be encoded with parity or ECC symbols added to the data. The paritycheck will detect a single one-slot position error contained in the detected data word. The error correction code willdetect a single two-slot pulse position error, and correct a single one-slot pulse position error. The single slot error inpulse location is the most likely form of error sources to be expected in the received signal.

    Directional Computations Summary

    Grav = ( Ax + Ay + Az )

    MagF = ( Mx + My + Mz )

    Azm = ATAN2(( Mx*Ay My*Ax ) * Grav) /(Mx*Ax*Az+My*Ay*Az+Mz*(Ax+Ay))

    TAzm = Azm + MDec

    Inc = ATAN2 ( ( Ax + Ay ) / Az )

    mInc = ATAN2 ( ( Mx + My ) / Mz )

    UgTF = ATAN2 ( Ax / Ay)

    UmTF = ATAN2 ( Mx / My)

    UmT2 = ATAN2(( Grav*Mx + Ax *Mz ) /(Grav*My + Ay*Mz))

    dTFA = UgTF UmTF

    dMTF = 0 for magnetic toolface type 1ORdMTF = UmTF2-UmTF fpr magnetic toolface type 2

    gTFA = UgTF TFO


    mTFA = UmTF TFOMDec for magnetic toolface type1 (mTTy=1)ORmTFA = UmT2TFOMdec for magnetic toolface type2 (mTTy=2)

    mPTF = UmTFTFOMDec for magnetic toolface type1 (mTTy=1)ORmPTF = = dMTF+UmTFTFOMDec for magnetic toolface type2 (mTTy=2)

    aTFA = gTFA, if Inc >=IncTORaTFA = mTFA, if Inc

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    pTFA = gPTF, if Inc >=IncTORpTFA = mPTF, if Inc

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    MWD Hardware

    Pressure Transducer (Sensor)

    A key sensor in MWD mud-pulse telemetry operations is a pressure transducer installed between the mud pumps andthe kelly or top drive of the rig. The purpose of the transducer is to convert the pressure pulse sent by the MWD toolinto an electrical signal that is then sent to the surface data acquisition system via cable.Placement of the sensor is important to obtain the optimum signal. The transducer is normally mounted at a bull plugconnection close to the main part of the stand pipe, or on a T-piece inserted between the standpipe and the flexiblehose. Occasionally, we have to install the transducer below the rig floor, for last resources we can do it but always tryto be the closet to the standpipe.

    Note: Sensors thread is 2.0 NPT.

    Revolutions per Minute - (RPM)

    The recording of RPM is important to monitor rotary-drilling versus sliding and is an important parameter in controllingbit bounce, drillstring whirling, shock, and vibration. The RPM sensor is typically either an optical counter or a proximity/ magnetic switch sensor that detects rotation of the rotary or top drive system. Top drives often have their own internalRPM sensors and counters.

    Data Acquis ition System / Cabin

    The data acquisition system is the center of action for the MWD operation. It is used for the acquisition, storage, andmanagement of real time and downhole recorded data, and for preparation of equipment for future runs. Ideally, itshould be located near the rig floor and also close to an area where downhole tools can be checked out prior to the bitrun.

    The data acquisition system can either be located in an existing safe area on the rig, such as an office or living quartersor can be installed in a service company cabin. A cabin is typically 8-ft to 10-ft wide and 15 to 25 ft in length. Electricalcabling connects the unit with surface sensors mounted around the rig. A telephone link from the cabin to the rig floor isadvisable.

    Pertinent information acquired by the MWD system is often displayed on video terminals, usually on the rig floor and/orin the company representative's office.

    Mud Pumps

    Pump Type

    Triplex pumps typically have smoother pressure outputs and less interference with MWD mud pulses than duplex pumpsystems. Correct pump maintenance (see the discussion on dampeners and liners below) is most important.

    When Working with Duplex Mud Pumps

    Normally before leaving to a job, we will know which type of pump we will be working on. In order to be able to work inthe worst case scenario you will need to run 1.28 orifice and 1.125 Poppet for muleshoe configuration. Thisconfiguration will give you a good pulse size to eliminate the eventual pump noise.

    For Configuring the Pulse Widths is good practice to go to the Pump and see how long take one completestroke. That value will be the period of your noi se.Try to be out of that period, normally Duplex pumps take around1 Sec that stroke. It is recommend to be up of this time normally 1.2 or 1.5 Sec Pulse Width.Use Downlink controls to have more options. Give more time to the pump to stabilize the operation pressure normally40 to 50 Sec Receive delay time and around 60 Sec for Transmit Delay time. It is highly recommended to use theFILTER BANDWITH FACTOR CLOSE TO 1.

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    Pulsation Dampeners

    Mud pump discharge pulsations are responsible for mechanical vibrations and fatigue failures of pump componentssuch as valves, fluid cylinders, system instrumentation, pipes, and fittings. Pulsation dampeners mounted close to thedischarge side will significantly moderate these pulsations to acceptable levels and thus extend the life of the system.

    Pulsations may produce an interfering pump signal in the piping that compromises the detection of the real-time mud-

    pulse MWD signal as a function of several parameters: pump rate, standpipe pressure, mud type and pulsationdampener condition.

    Success of the pulsation dampener depends on the condition of the dampener itself in terms of the bladder andoperating pressure. If improperly maintained or at an incorrect pressure, the smoothing effect of the pulsationdampener is reduced.

    The ideal pre-charge pressure for MWD operations is 50% to 70% of the standpipe pressure, or slightly lower. Ingeneral, Hydril dampeners can be pre-charged to 2000 psi (maximum), and Continental Ensco dampeners to 1000 psi(maximum). If the standpipe pressure decreases, the pre-charge pressure must be reduced also.

    Dampener bladders need not fail to cause problems. Leaking bladders or those in poor condition will result in just asmuch MWD signal-noise interference as a broken bladder.

    Liner Condition

    Mud pump liner condition can also have a significant effect on the ability of MWD tools to decode pressure signals. Ifthe mud-pulse signal is too noisy, the mud pump liner condition should be checked as a possible source of the problem.

    MWD and BHA Configuration

    Sensor Placement and Orientation (Directional Module)

    Location of an MWD tool in the BHA is usually based upon attempting to get as many measurements as close to the bitas possible (in order to obtain the earliest possible wellbore directional data and geological information), while notinterfering with the directional steering characteristics of the BHA.

    When using a positive displacement motor, we use an orienting sub (UBHO) with the MWD tool to align the BentHousing with the Key from the Muleshoe. This allows the MWD Tool to be oriented to the High side of the hole when


    In standard configuration of BHA it placed two (2) Non Magentic Drill Collars (Monels), a good practice is locate theSensors (Directional Module - Probe) 1/3 of the total length of NMDCs available.

    Drillstring Magnetic Interference

    Drillstring magnetism can be a source of error in survey calculations made from magnetometer data. Non-magneticdrillcollars (NMDCs) are used, both above and below an MWD tool, in order to minimize the magnetic influence of thedrillstring on the compass or directional package.

    The effect of drillstring magnetism may increase as the hole angle builds from vertical or as the hole azimuth movesaway from a north/south axis. Changing BHA components between runs may alter the magnetic effect of the drillstring.

    Techniques are available to determine the number of NMDCs that are required (see SPE/IADC # 11382 as anexample).

    In some conditions, techniques are available that enable an operator to reduce, or even eliminate, the number ofNMDCs required above and below the magnetic directional sensor, as well as correct for drillstring magneticinterference. At least one NMDC is required to house the survey sensor (it must be protected from cross-axialinterference) if correction algorithms are used.

    In high angle wells, a trade-off between optimum BHA design and positional uncertainty may be required. This decisioncan only be taken if the positional uncertainties resulting from the various options are calculated.

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    External Magnetic Interference

    Sources of external interference include:

    Nearby casing;

    Fluctuations in the earth's magnetic field (e.g. diurnal fluctuations in high latitudes or magnetic storms);

    A fish left in a sidetrack hole or nearby well; and

    Certain minerals (pyrite, hematite and magnetite) in high concentrations close to the borehole can distort theearths magnetic field. 10 ppg hematite weighted drilling fluid has affected magnetic surveys by as much as twodegrees of azimuth.

    In-field monitors of the earths magnetism can be used to establish more precise values of the local field strength anddip, as well as identify fluctuations in the earths magnetic field. In this latter case it can be established that anomaloussurvey measurements may have not resulted from a malfunctioning downhole instrument. A wasted trip for a new toolmay be avoided, and a more appropriate surveying procedure devised.

    When magnetic interference from external sources is encountered, all three axes of the magnetic sensors areinfluenced. The total field measured by the directional package will remain constant as the toolface is rotated but willgenerally either change with depth as the sensors survey pass by the source of the interference or manifest itself as adivergence between the measured magnetic dip and the magnetic dip anticipated in that geographic region.

    Azimuthal corrections for external magnetic interference are not possible due to the difficulty in establishing themagnitude of the interference on each of the individual axes. In the event that external magnetic interference issuspected, gyro surveys should be considered.

    Shock & Vibration

    Good lateral vibrations do not exist! The energy expended into shock and vibration is often at the cost of reduced ROP,greater drill string fatigue, and possible MWD failure. Minimizing lateral shocks and vibration will improve ROP, reducebit and drill string failures, and help drill a more gauge borehole.

    Shocks are often worse in vertical wells because, in directional wells, high side-forces result in high axial drag whichdampens axial vibration. Also, gravitational forces make it difficult to lift collars in high-angle wells, reducing collarwhirling and thus dampening transverse impacts.

    Torsional vibrations in deviated wells can be worse as higher frictional forces act like a slipping rotary clutch. Many of

    the MWD systems today measure shocks using downhole accelerometers mounted on one or more axes of the tool.

    There are some assemblies and BHA components that may cause excessive shock on not only the MWD tool but alsothe other elements of the drill string. Modeling will assist in optimizing MWD placement in the BHA. Especially in ShortRadius Wells. High DogLegs Wells.

    Generally, running MWD in a packed BHA or with a downhole motor results in very little vibration. However, rotationwith a bent sub or bent housing motor may cause excessive shocks, depending on the amount of bend.

    Some building or dropping assemblies where MWD systems are placed in the middle of a non-stabilized section ofthe BHA may cause excessive shock, if the unstabilized section is long and rotated at or close to a natural resonancefrequency.

    A key to reducing shock and v ibrat ion i s to ensure good stabi lization in our Interconnects against the NMDCsWall. Drilling operations such as underreaming and hole opening are particularly prone to high levels of shocks.

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    Drill Pipe Mud Screens

    Screens are designed to prevent damage and obstruction of MWD pulsers, but when screens trap junk from the mudsystem, circulation can be obstructed. Screens can be used in three possible places:

    1) Mud pump suction screen;2) Mud pump outlet screen;3) Surface screen located just below the kelly or top drive

    Care needs to be taken to ensure that the rig crew do not allow the surface screen to be sent downhole, although ourscreens are designed to be retrieved through the drill pipe.

    Downhole Considerations

    Signal Strength

    Flow Rate

    It is important to have the correct size tool for the flow rate application because hydraulic erosion can take place if mudvelocities are too high. This can have a compounding effect if the mud has high sand content or solids content asmentioned earlier. The 65 % to 75% of our Pulse Signal depend o f the Flow Rate.

    Pressure Drop

    The GEs MWD systems use the mud flow to generate pressure pulses to communicate to the surface. Depending onthe Bottom Hole Configuration (Poppet / Orifice) and flow rate, pressure drops between 250 psi and 600 psi can beexpected across an MWD tool. Mud pumping systems must be able to accommodate this additional pressurerestriction.

    Signal Attenuation

    The MWD signal generated downhole by the Pulser must propagate up the mud column inside the drillpipe. While

    traveling from downhole to the surface, the amplitude of a mud-pulse signal is reduced. It is normal that you lose ofSurface / Shallow Test Pulse Amplitude every 1000 m to 1200 m.

    Gas-cut mud can have a detrimental effect on the ability of a mud-pulse MWD tool to transmit to the surface. In a moregeneral case, the strength of a mud-pulse signal decreases (is attenuated) as the well depth increases, as the viscosityof the mud increases, and as the internal diameter of the drillpipe decreases. MWD signal attenuation is not as greatwith heavier drilling muds as it is with lighter mud weights.

    For example MWD mud-pulse signals are typically the poorest when drilling deep wells with a low density, oil base (highviscosity) mud, using small diameter pipes.

    Pulse Width (Transmission Frequency)

    As the signal strength decreases due to the environmental considerations listed above, depending on the type of well,we will discuss with the DD which PW we will select to be safe and according with the Directional requires. It may be

    possible to reduce the Pulse Width in areas where we work before or if we Run Downlink Options and still maintain datacommunication with the surface.

    Positive Displacement Motors

    When used in conjunction with MWD tools that use mud-pulse telemetry, positive displacement motors can generateinterference that, in some cases is greater than the MWD mud-pulse signal strength. In severe cases this interferencemay cause the MWD mud-pulse signal to be undetectable at the surface. Especially in Power Extended DHM.

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    Drilling Fluids

    Compressible Drilling Fluids

    Although most sensor measurements are unaffected by the drilling fluid, drilling with compressible fluids (air, gas, foam

    or mist) poses unique challenges for all MWD systems. These challenges relate mainly to tool reliability and datatransmission - specifically mud-pulse data transmission.

    MWD mud-pulse telemetry systems are designed to operate in water-based, oil-based and polymer-based drillingmuds. Compressible fluids have significantly different hydraulic characteristics compared to liquid muds, and MWDsignal generation, transmission and detection are all affected. Conventional MWD mud-pulsing systems are unlikely toprovide real-time data without significant modification.

    Planned Mud Additives

    Lost Circulation Material (LCM)

    Any use of lost circulation material (LCM) should be discussed with the MWD operator prior to implementation.Different MWD tool designs are tolerant of LCM to different degrees, and the various types of LCM affect MWD toolsdifferently.

    LCM additions should be limited to levels recommended by the MWD manufacturer and should be well dispersed.LCM additions through a hopper should be discouraged. Dumping LCM as a slug should be avoided for best resultswith MWD since jamming of the pulser may result.

    Granular LCMs tend to be better tolerated by MWD systems than the fibrous type. Mica can affect the Gamma Ray(GR) measurement.

    Lubricating Beads

    Lubricating beads are used as a friction reducing agent and come in a variety of sizes. They have similar effects onMWD as LCM. Any use of this additive should be discussed with the MWD Operator prior to implementation.


    Barite is also erosive - heavier mud is more erosive.


    Hematite is a weighting material that is also very erosive. Use of this material should be discussed with the MWDOperator in the planning stage. It is advisable to monitor the effect of hematite between MWD runs in order todetermine the optimum operating life and replacement interval for the MWD tool. The effect of hematite on MWD toolsis greatly affected by hematite concentration and flow rate.

    Due to the excessive wear of downhole metal parts in the hematite mud stream, it is not uncommon for the operator toasked the Oil company to have in mind a wireline unit to switch Tool after several hours.

    Mud Mixing

    When polymer muds are used, it is essential to ensure proper shearing of the polymers prior to pumping downhole;improperly sheared additives can cause blockage and MWD tool failures if flow rates are high. Barite drop-out can alsobe a problem if it is not well mixed. It is extremely recommended to Run without Sttoper in the Bottom End is we knowprior to the run.

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    Mud Contaminants

    Pipe Scale / Plastic / Cement

    Dried cement (following a cementing operation) or rust from the inside of pipe that has not been used for some time cancome loose. Another problem common with new drill pipe is that the internal plastic coating can come off. In order to

    reduce MWD pulser jamming problems, Rabbitting of the drill pipe is recommended after cementing operations andwith either rusty or new drill pipe. A good practice is Check after Kelly down what is coming in the Drill pipe Screen.

    Gloves, Wrenches and Other Junk

    Be aware that any junk in the mud system can not only jam or damage an MWD pulser, but can also interfere with thedrilling operation (e.g. preventing directional control or even mud circulation). Screens must be used to prevent, or atleast reduce, the possibility of allowing junk in the mud system:

    Screens are designed to prevent damage and obstruction in downhole devices, but when screens trap junk from themud system, circulation can be obstructed. Care needs to be taken to ensure that the rig crew do not allow the surfacescreen to be sent downhole, although some screens are designed to be retrieved through the drill pipe. The use ofsome or all of these screens should be discussed with the MWD Operator.

    Cuttings and Mud Solids

    The wear on MWD components exposed to the mud stream is dependent upon the both the flow rate and the solids andsand contents of the mud. Maximum cuttings-solids of 5% and a sand content of less than 1% by volume arerecommended in order to limit the erosion of metal components exposed to the mud stream. If solids and sandcontents exceed these concentrations, the driller should consider reducing the flow rate - in the context of cuttingstransport and hole cleaning.

    U-tubing can push cuttings back into the MWD tool when tripping into the hole, causing jamming problems. The use ofa float sub can help, but its installation should be coordinated with the operating company. Ported floats are preferredby some companies.

    Heavy Cuttings in High Angle Holes

    In highly deviated / horizontal wells heavy cuttings can build up on the low side of the hole affecting some


    In order to remove or try to realive the MWD Tool after this Contaminats, a sweep should be made with a high-viscos ity pil l and or Sweet Water. At least we need 5 to 10 min the Sweep crossing the Muleshoe.

    Drilling Conditions

    Deep Drilling

    Deeper wells have a number of factors that must be considered when using MWD tools: signal strength (as notedearlier), temperature, pressure, hole size, vibrations, shocks, other drilling phenomena and borehole instability / stuckpipe.

    Hole Size Restrictions

    The diameter of the borehole should be considered when selecting MWD configuration. At present, the sensors thatare readily available for most hole sizes are directional, resistivity and natural gamma ray.

    The main restriction is we will be retrievable. It is very important to discuss hole size with your MWD Manager and askin what size hole the tool is designed to operate.

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    In general, the Minimum size our MWD run is 3-1/2 OD, 4-3/4 holes. Any additional hole sizes may require specialtool modifications or borehole correction techniques.


    Due to the inability of electronic components to operate in extremely high temperatures, MWD equipment has maximumtemperature ratings ranging from 250 to 350 F (125 to 175 C). It should be noted that circulating temperatures can

    generally be maintained at about 10% less than the static temperatures.

    In very hot holes, it is advisable to stop periodically while tripping into the hole in order to circulate and cool the mudsystem. Exceeding MWD temperature limits may result in tool failure or erroneous data. Mud cooling systems havebeen used with some limited success in high temperature wells in order to reduce mud temperature.

    Lithium batteries are used in many MWD tools and generally have an upper rating of 329 F (165 C). This limit shouldnot be exceeded. Lithium melts at 360 F (182 C) and cells can explode, giving off toxic gas, at this temperature.

    Reaming, in some cases, is done without circulating mud. This can potentially elevate the mud temperature well abovethe MWD tool specification and should be avoided.

    Minimum temperature ratings are also important in cold climates. Proper preparation may include facilities for warmingthe MWD tools prior to installation in the drill string and for check out.


    Maximum MWD working-pressure ratings range from 15,000 to 20,000 psi. These ratings should not be exceededunder any circumstances, in order to protect the internal components in the MWD collar.

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    Stuck Pipe / Borehole Stability

    To reduce the risk of losing an MWD tool string, an operator may wish to consider running all the question prior to RIHthe MWD Tool.

    There are a variety of services available from the MWD service companies which provide "stuck pipe avoidance"answers. Many of these programs are readily available, but they tend to be under-utilized by the industry. Review with

    the MWD service companies what can provide at the well site that will facilitate obtaining the highest quality MWD datawith a minimized risk of sticking pipe, and lost-in-hole charges.

    Trajectory and Geological Considerations

    Wellbore Profile

    Directional measurements are a critical part of most real-time MWD services. The objective of drilling a well is either toposition the borehole correctly in a producing reservoir or to drill through various geological objectives and evaluatetheir potential. A smoother well profile may enable further drilling objectives to be reached with less torque and

    wellbore friction.

    Surveys are used to determine the path of the well and the orientation of the BHA so that a wellbore can be steered inthe right direction. This is achieved measuring relative direction (and size) of the earths gravitational and magneticfields.

    MWD Surveying Procedures

    Several steps can be taken to ensure the integrity of the directional data as follows:

    1) It is recommended that a benchmark survey station be established in each hole section at a safe distance outside ofmagnetic interference (>30 mts from any magnetic string), where dogleg severity is less than 0.5.

    2) MWD benchmark surveys are recommended to check that the MWD survey sensors are reading correctly.

    Benchmarks are recommended in the following circumstances:

    Running into the well - A benchmark survey is recommended every time the assembly is run into the well at theestablished benchmark stations to ensure the MWD tool is recording well azimuth, inclination and tool face orientationdata correctly.

    On bottom- Upon reaching bottom after every round trip a survey is recommended at the last MWD survey station ofthe previous run. The new survey data, including the depth measurement, should agree with the previous survey withinthe quality control criteria specified for that sensor.

    All benchmarks should be taken with the MWD sensors within 1 mts measured depth of the benchmark stationsdescribed above. Two or more successful benchmark surveys may be taken when necessary. The observedinclination and azimuth readings should agree with the benchmark values to within the MWD survey sensorspecifications. It should be noted that changes in the BHA configuration may have an effect on uncorrected surveymeasurements.

    It is also recommended that at least the Follow Survey Sequence Definitions stay present in the Benchmark Survey:

    INC AZM DipA MagF Grav.

    Dogleg Severity

    If a well profile changes direction too abruptly, then it may not be advisable (or even possible) to drill around the dogleg.The bending limits (maximum permissible instantaneous dogleg severity) of MWD tools depend upon the diameter ofthe borehole. It should be noted that the instantaneous dogleg severity calculation is dependent upon the interval

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    between surveying stations - typically 90 ft (28m). Dogleg severity calculations based upon shorter surveying intervalsmay permit larger build-up-rates. Our Max DogLeg allowed is 26 / 10 Mts.

    Survey Accuracy / Uncertainty

    The present tendency to drill longer, higher angle wells to smaller targets has increased the need for valid positionuncertainty calculations. Sensor inclination and azimuth accuracy specifications do not give a direct indication of overall

    survey accuracy since position uncertainty is also heavily dependent on the location and profile of the wellbore. Ameans of modeling the combined effect of all these variables is therefore required.

    Uncertainty nearly always increases as distance from a known start point increases (i.e. typically, uncertainty increasesas measured depth increases). Azimuth errors tend to cause lateral uncertainty and have their biggest effect at highinclination (worst case being horizontal). Depth errors and inclination errors cause uncertainty in the plane of the wellpath. At very low inclination, depth errors cause TVD uncertainty, and inclination errors cause radial uncertainty. Athorizontal, depth errors cause radial uncertainty and inclination errors cause TVD uncertainty. These basiccharacteristics mean that long, high angle sections can cause lateral and TVD uncertainty to increase dramaticallyrelative to lower inclination sections. This increase in uncertainty at high inclinations is aggravated by other factors;gravity dependent inclination errors increase, the azimuth accuracy of many gyro systems degrades significantly, andthe effect of drillstring interference on magnetic systems increases. The latter two effects are worse at higher latitudesand as azimuths tend toward east or west.

    For well profiles that have long, high angle intervals the uncertainty at the target is highly influenced by the survey tools

    run over the high angle section, typically MWD. The impact of the survey tool run in the low inclination section can beminimal. There may be little advantage in running an accurate system in the intermediate casing if the overalluncertainty is governed by the tool run in the subsequent high angle section.

    Correct calculation of the uncertainty resulting from two or more surveys tied together is complex. Some errors arerandom from one survey to the other, while others are systematic. Most well planning software does not model this.Typically only one method of tie-in calculation is supported, or at best a choice of fully systematic or fully random.Generally, depending on the survey tools used, fully systematic will tend to overestimate uncertainty while fully randomwill tend to underestimate.

    MWD directional specifications tend to take the form of inclination and azimuth accuracies. If these specifications havea common basis, they are a useful means of comparing the accuracy of one tool to another. However, it is not alwaysclear how accuracy specifications are derived. They will probably include sensor specifications, but may or may notinclude system level and environmental errors.

    In addition to sensor accuracy, there are other factors that affect the accuracy of an MWD directional survey. Theseinclude: depth error, magnetic dip and declination errors, magnetic field strength estimation error, washed-out boreholesections (and BHA stabilization), misalignment of the directional sensor in the drillstring, flexure of BHA betweenstabilizers (Sag) and magnetic interference.

    There are various methods which attempt to correct for the environmental errors, but none are wholly effective, andsome have been known to increase rather than reduce errors. The following table lists the more important of theseerror sources and gives illustrative figures for the magnitude of the errors they are likely to generate in a typicaldirectional well:

    Error Azimuth Inclination

    Magnetic Field Error 1 0

    Depth Error 0.5 0.5

    Magnetic Interference 0.75 0

    Sensor Misalignment 0.1 0.1

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    Sag Corrections

    Another source of error is that caused by misalignment of the BHA in the wellbore. This misalignment is caused bydeflection of the BHA due to gravity or weight-on-bit. Weight-on-bit deflection causes azimuth errors, but these arerelatively small. In any case, most surveys are acquired with the bit off bottom. BHA sag due to gravity causesinclination errors. This error increases as inclination increases. Inclination errors at high inclination introduce TVDuncertainty which is often critical in horizontal wells. It is especially important to make BHA sag corrections in long

    horizontal well sections.

    Decisions made during the planning stage should be adhered to during the drilling phase of a well, and the naturaltendency avoided of selecting the most accurate options while planning but then altering the surveying program.

    Depth Error

    Typically TVD uncertainty is calculated relative to surface. The absolute uncertainty tends to be large at target depthsince it has accumulated over the whole length of the well. Absolute TVD uncertainty has its uses in defining theposition of one well with relation to another, or in assessing the validity of prognosed horizons. However, in terms ofoptimizing recovery, all that matters is the position of a well relative to its true target, not the prognosed target andcertainly not to the wellhead. If we can identify the point of entry into the producing zone, we can set relative TVDuncertainty to zero at that point.

    Gyro Limitations

    Gyro surveys are often considered to be inherently more accurate than magnetics. This is not always the case. Wellplanning should always involve the use of valid error models that quantify the relative accuracy of the survey programsunder consideration. The ability of rate gyro systems to define true north deteriorates as inclination, azimuth andlatitude increase. At 70 degrees of latitude gyros are virtually unusable above 70 degrees of inclination. Attitudereference tools establish an accurate heading at the start of a survey and then carry it forward, making azimuthaccuracy theoretically inclination independent.

    Collision Avoidance

    Existing nearby well locations and trajectories should be correctly specified prior to drilling a well. MWD servicecompanies offer Proximity Analyses to help plan and steer a new wellbore.

    Target Shrinking

    The location and boundaries of a geological target are subject to positional uncertainty in the same manner as the wellpath. This uncertainty should be defined by the reservoir or geology department, and the drilling target size reducedaccordingly. In a horizontal well, excessive uncertainty on the surveying sensors high side axis can result in a wellbeing landed much further into the target than planned - thus significantly reducing the wellbore interval actually drilledthrough the producing zone. If a target is deemed too small, the survey program must be revised, or the well re-planned.

    Physical Formation Parameters

    Formation Measurements

    Formation evaluation sensors that measure natural gamma-rays, resistivity (conductivity), neutron porosity, bulk

    density, photoelectric effect, acoustic travel time (velocity) and borehole imagery are available from various servicecompanies. Sensors and environmental correction methodologies are quite different for each service company. Designimplications on both the drilling process and the quality of measurements will depend on specific drilling and geologicalenvironments.

    Hard or Cemented Formations

    Vibration and shock to MWD tool electronics is a major cause of MWD failure. BHA modeling programs can be run tosimulate vibration harmonics with varying load conditions. However, modeling programs do not account for alldownhole variables and should not be used in isolation. In addition, in areas where shock is a concern, thrusters,flexible bit subs and shock subs might be utilized to help alleviate vibration problems.

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    Rugosity and Washouts

    Washing out of the borehole wall will affect the quality of the log response for gamma tools.

    MWD Applications / Techniques

    Invasion / Time-Lapse Logging

    The time difference between when a formation is penetrated by the bit and logged by a sensor can have a significanteffect on the response of MWD logging sensors. Because of the different distances between the bit and varioussensors, different formations have differing amounts of time that they are exposed to borehole fluids before they arelogged with an MWD tool. This is particularly significant when thin, hard formations that drill more slowly areencountered, or at the end of a bit run when the drillpipe is tripped and one sensor has logged a formation when thesection is first drilled, and another sensor does not log the same interval until after the pipe trip. Formation intervals thatare exposed to drilling fluids for longer periods of time are more susceptible to the influences of invasion and washoutson the logging measurements.

    It should be noted that Time-Lapse log responses are affected by borehole instability (changes in borehole size) andvariations in fluid properties.

    Real-Time / Recorded Data Densi ties

    Real-time MWD transmission rates are typically limited to only a few bits of data per second. It is, therefore, imperativethat drillers and geologists discuss with the service company, before the MWD tool is tripped into the hole, which typesof information, with what resolution (precision), and how frequently each different measurement should be transmittedto the surface in order to optimize real-time decision making. Some service companies have the ability to select fromdifferent pre-established transmission formats while the MWD tool is downhole. In this way the various types ofinformation (navigation, drilling performance, formation evaluation and quality control data) can be transmitted to thesurface with different priorities during the same bit run, depending on the decisions required at any particular time.

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    Economic and Regulatory Considerations

    Critical MWD Information

    In some wells, the MWD information is critical to either the drilling mechanics or the evaluation of the well.

    Examples of these wells are:

    - High-profile exploratory wells where MWD is used for correlation, to pick casing points, identify potential payintervals for early evaluation or for insurance logging in the event that a wellbore may be lost;

    - Highly deviated and horizontal wells where obtaining pipe-conveyed or conventional wireline logs is extremelydifficult or risky.

    - Production wellsrequiring a casing point above a severely drawn down reservoir with a high risk of lost circulation orsticking pipe.

    The ability to successfully drill and evaluate such wells virtually requires the use of MWD. In those situations wherealternatives to MWD are risky or do not exist, MWD costs should very easily be justified when weighed against thepotential risks of not using MWD.

    Economically Beneficial MWD

    Some wells fall into a category where obtaining MWD may be economically more attractive than other availablealternatives. In these wells, the MWD information is not critical to either the drilling or evaluation of the well.

    MWD is generally run for two broad reasons: real-time directional/correlation data for well placement, and formationevaluation data to replace wireline data. In either case, a number of diverse factors (cost, benefit, risk, etc.) must beconsidered in order to realize any real economic benefits. If these factors are not considered, not only is there thechance of not realizing any cost savings, but there is a very real possibility of incurring enormous costs. The lost-in-hole charge for a modern MWD string used for reservoir evaluation is approximately $800,000.

    Many factors must be considered when economically justifying the use of MWD. In general, the majority of cost savingsare due to reduction in rig time associated with wireline operations, conventional slick-line directional surveys and setup

    charges - particularly on offshore wells.

    Further cost saving can be derived from improved rates of penetration when by eliminating undesired drillingphenomena, better survey accuracy and real-time toolface data that result in smoother wellbores, faster / more accuratepenetration of the target, with less risk of losing a well (or BHA) because of borehole instability, fishing and sidetracks.

    If a single wireline logging service must be run, much of the potential cost savings may be lost. A well requiringauxiliary wireline information (i.e. dipmeter, sidewall core, or formation tester data), therefore, is less likely to be a goodcandidate for MWD wireline replacement based solely on economic reasons.

    The better wireline replacement candidates are usually limited to wells where time-consuming, pipe-conveyed logging isrequired or where good reservoir and geology databases exist. MWD may also be appropriate in areas of deepinvasion (e.g. depleted reservoir pressures) or when obtaining good quality wireline data is problematic due towashouts, ledges or doglegs.

    Logisti cs and Geographics

    There are a number of logistical issues pertaining to the running of MWD services in remote geographic locations,which, if not planned for, can have a significant impact on both the cost and success of the MWD operation. The more

    remote that a drilling operation is, so the more expensive it is to provide and maintain MWD service equipment.

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    Reliability and Statistics

    Failure Analysis

    The overall objectives of failure analysis are to improve the reliability of MWD tools by identifying systematic failures

    that are related to either tool design or operating practices. Failure analysis can also provide more useful operatingstatistics that can be used when planning wells and awarding contracts.

    Many MWD failures are the result of undesirable operating environments such as harsh geological settings, poor BHAdesigns or improper drilling parameters. Most MWD failures are due to:

    Exceeding operational design limits Mechanical wear Human error Inadequate tool design Random defects

    Except for random defects, causes of failures can be identified and processes improved through root-cause analysis,with the aid of proper tracking of MWD operations.

    The most common statistic used for tracking MWD tool performance is the mean time between failures (MTBF). MTBF

    is dependent upon the inherent tool design, operating conditions, as well as the wear on an MWD tool. Operators andservice companies should work together to inspect the MWD tools during normal drilling operations (e.g. internalerosion, and external abrasion) in order to assess the rate at which drilling fluids and rock formations are wear on theMWD systems. In this manner optimal drilling fluid properties and MWD preventative maintenance schedules forparticular geographic regions can be determined.

    Statistically, approximately 80% of the total MWD failures occur on 20% of the wells drilled using MWD tools. On somewells, one service company will experience a series of failures, be replaced, and a second service company willexperience another series of tool failures. Industry reliability statistics of MTBF do not apply to these situations.

    In order to obtain more appropriate reliability expectations for a driller planning a particular well, more detailed statisticsfor each particular well profile and BHA type are required. In addition, when the first MWD failure occurs, a more in-depth assessment should be made of whether the failure is due to random or systematic causes.

    Ultimately, a driller is concerned not only with the overall average number of hours that an MWD system can operate

    without failure, but also how MWD failures might impact the drilling operation for a specific well profile and a particularBHA.

    If the MWD tool is experiencing downhole problems, the first issue before tripping to change the tool may be for theoperator to evaluate the condition of the mud pumps and circulating system. The next question should then be to askwhether the MWD data at the time of failure are critical to current operations. If the decision is made to trip, or uponrecovery of any failed component, electronic diagnoses and physical inspections should be performed. Only afteranalysis of these statistics can improvements be made to operating procedures or tool designs and repeat failuresavoided.

    As a minimum operators should track the number of failure-free MWD bit runs, and circulating hours by service. TheIMS recommends that after each MWD failure operators should collect the following additional failure-related statisticsand parameters:

    Failure Type

    External physical or chemical wearInternal mechanical failure (erosion)Sensor typeMud solids or junk trapped by the MWD toolElectronics failurePoor data qualityData transmission failurePoor data rateFailure to record data

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    DepthTemperatureMode and level of downhole vibrationsWell inclination /dogleg severityFormation typeWeight on bit

    Surface RPMMud flow rateLCM type and concentrationMud characteristics: Type, weight, yield point, plastic viscosity, % solids, sand content, gas content, ppmchlorides, LCM type and LCM concentrationBHA configuration / stabilizationMud motor typeBit typeEffective real-time data transmission rate

    Addi tional Quest ions

    How might the cause of failure be eliminated?What is different when tripping back in the hole?Were the MWD data critical?

    Was the MWD tool operating outside its design specification (e.g. above its temperature limit)?Did other downhole components fail?Was the failure intermittent?What type of vibration monitoring was used?Did BHA design contribute to the failure?Does BHA modeling indicate a failure mode?Was the failure related to formation type?After the failure was data quality adequate?How many hours of lost time?Was an unplanned trip required for the MWD?Did the mud pumps contribute to data problems?How many hours was the MWD tool operating?How many bit trips did the MWD tool make?What charges were made for MWD repair?

    Some failures cannot be diagnosed in the field, and tools will have to be sent back to a repair facility. The causes ofthese failures should still be reported back to the operator. Collecting the statistics like those shown above will helpprovide more reasonable performance expectations for the driller and thus reduce operating costs, as well as reducethe number of failures experienced by the service company.

    In summary, whenever an MWD tool fails, the cause of failure should be investigated, if possible, before another tool issubjected to the same drilling environment. There are a number of real-time vibration and shock detection services thatcan help avoid undesirable drilling characteristics, and extend not only MWD performance, but also bit life and mudmotor performance.

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    MWD Operational Guidelines Check List

    Economic Considerations Y NHave lost-in-hole charges been discussed?

    Has the impact of wear high solid content for MWD tool repairs been considered?

    Surface Equipment Considerations Y NAre the locations of MWD signal pressure sensors optimum?

    Is a backup MWD signal pressure sensor working?

    Has the type of depth recording equipment been discussed? (Chimo, Pason & Rigwatch)

    Is suitable fishing equipment available on-site for the MWD collars?

    Is a slickline or wireline unit available for retrievable MWD tools?

    Are pulsation dampeners maintained and at the correct operating pressure?

    MWD and BHA Configuration Y NHave thread and ID issues (gauge, crossovers) been reviewed?

    Are the MWD tool retrievable or replaceable from the surface?

    Is MWD sensor placement in the BHA prioritized with respect to distance from the bit and formationevaluation?Are there sufficient non-magnetic collars in the BHA to minimize magnetic interference on directionalmeasurements?Is the offset angle between Bent Housing line and the UBHO line measured correctly? If DAO applied.

    Is the pressure drop across the bit and through the MWD tool appropriate (especially in Power ExtendedMotor)?Has the MWD tool been configured for the appropriate flow rates?

    Are surface screens retrievable through the drillpipe?

    Has the BHA been modeled for critical resonance RPM and weight-on-bit combinations to reducevibration?Has MWD battery life been discussed with the Directional Driller and CoMan?

    Are the downhole data recording set appropriately?

    Downhole Considerations Y NHas the impact of the mud system (especially compressible fluids) on the MWD signal been considered?

    Are mud screens used to prevent junk from interfering with the MWD tool?

    Have the use of LCM, lubricating beads, hematite, barite and salt- or oil-based muds been discussed?

    Are the cuttings mud solids less than 5% and sand content less than 1%?

    Has a review of MWD tool selection been made with depth, temperature, pressure and hole sizeconsidered?

    Is mud periodically circulated when tripping into and out of high temperature wellbores?

    Are shallow hole tests performed when running in the hole to verify correct MWD operation?

    Geological / Trajectory Considerations Y NIs the planned wellbore curvature within the dogleg severity limits for both sliding and rotation of the MWD

    tool?Have the surveying accuracy and correction algorithms (magnetic interference, sag and depth errors) beendiscussed?Is external magnetic interference (nearby wells, lost BHAs, hematite mud and magnetic formations)insignificant?Have the appropriate ROPs been determined for drilling through zones of interest? (For Logging matters)

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    ACCURACY (of a measurement)

    The closeness of the agreement between the result of the measurement and the (conventional) true value (ofthe measurand).


    A unit of measurement in GR logs (previously neutron logs also). For GR tools, one API unit is equivalent to1/200th of the total deflection observed between zones of high and low radiation in the test pit. MWD GR toolsmeasure gamma radiation in API units, Counts Per Second (cps) and AAPI (see APPARENT API UNITS).Because MWD GR sensors are housed in thick steel drill collars, the measurements usually are reduced comparedto the same measurement by a wireline GR tool. GR measurements may vary from one service company toanother


    Direction, as in a compass direction. The clockwise angle of departure from a reference direction (typicallygeographic) north, measured in a horizontal plane. In dipmeter and directional surveys, it is the clockwiseangle from magnetic north to the tool reference point or electrode. This measurement must be corrected formagnetic declination to compute true azimuth. The azimuth is generally expressed in degrees.


    The characteristic of a logging tool to perform separate measurements in different directions (azimuths) aroundthe axis of the tool. Currently, MWD sensors making azimuthal measurements are limited to density and tendto give measurements in quadrants around the borehole. Some MWD GR sensors are shielded on one sideso that measurements are taken from only (primarily) the unshielded side. These are oriented measurementsrather than true azimuthal measurements.


    The resistance to axial bending of a drill collar (expressed in Nm/Rad or ft-lb/degree of deflection). It is equalto the bending moment required to produce a unit deflection of a collar when one end is fixed. This value issupplied to drilling engineers for the comparison of the angle building characteristic of an MWD drill collar tothat of a standard API drill collar.


    The portion of the drilling assembly below the drill pipe. The Bottom Hole Assembly (BHA) will typically consistof drill collars, stabilizers and drilling tools (e.g. motor and MWD) and the bit.


    The rate of increase in inclination of a wellbore. This is sometimes expressed as Rate-of-Build (ROB) andexpressed in degrees/unit length, often degree/100 ft or similar length. BHAs are designed to either build,hold, or drop angle as the well is drilled. Some BHAs, when combined with down-hole motors, are designed toturn in a desired direction.


    A short length of heavy steel pipe which has a tapered profile. The casing shoe is screwed onto the first jointof casing lowered into the hole. In many cases, sensor measurements made near the casing shoe are of

    doubtful accuracy due to poor hole conditions near the casing shoe. Conversely, in many wells, but not all, thebest cement job (integrity) is closest to the bottom of the well.


    The mass of some material divided by its volume. In petrophysics, formations and drilling fluid densities aremeasured, primarily as input to equations to derive the porosity of the rock. Most logging tools actuallymeasure bulk density (b), and express the density in g/cm

    3. The equation used for determining porosity ()from bulk density is:

    = (ma- b)/(ma- mf)

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    where mais the assumed density of the matrix (formation) and mf is the assumed density of the fluid in thepore spaces.


    A device that is generally affixed to the rig drawworks and that generates electric pulses as the drum rotates.After calibration the output of the encoder is converted to depth.


    The radial distance from the measure point on a sensor to a circle, usually within the formation, where thepredominant tool-measured response may be considered to be centered. It varies from one type of device toanother because of different designs, and techniques of compensation and focusing. It also varies fromformation to formation due to changes in formation properties. For a better understanding of the volume ofinvestigation of a logging tool, it is recommended to know the depths of investigation corresponding to 10%,50% and 90% of the cumulative GEOMETRIC FACTOR. See also RADIUS OF INVESTIGATION.


    The direction of dip (maximum slope in a plane) perpendicular to the DIP STRIKE, expressed relative tocompass directions.


    The direction or bearing of a horizontal line drawn on the plane of a structural surface. The strike isperpendicular to the DIP DIRECTION.


    Intentional drilling of an off-vertical well at a closely controlled, predetermined angle and direction through theuse of special equipment.


    A well survey that measures the degree of departure of a borehole from vertical and the direction of departure.Measurements are made of azimuth and inclination of the borehole.


    The rate of change of hole angle and/or direction evaluated between the current survey point and the nextshallowest survey point. It is expressed in degrees per course length, and is significantly influenced by thecourse length over which it is calculated.


    The capability to retrieve data from, and send instructions to the tool when it is located downhole. Fourprinciples are currently used for downlink communications: mechanical (wireline), electrical (inductivecoupling), hydraulic (mud pulse) and electromagnetic propagation.


    The deviation of a section of the borehole from vertical.


    Heavy, thick-walled tube, usually steel, employed between the drill pipe and the bit in the drill string to provide

    weight on the bit in order to improve its performance.


    The passing of electromagnetic energy through a medium. Most MWD resistivity logs are based onelectromagnetic propagation and typically operate at high frequencies (typically between hundreds of kHz anda couple of Mhz). They are used for correlation and to determine formation electrical properties or invasioncharacteristics. MWD tools record the phase shift and attenuation of electromagnetic energy through theformation near the borehole, which are then converted into resistivities and dielectric properties.

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    (1) Stratigraphic: A body of rock strata, of intermediate rank, in the hierarchy of lithostratigraphic units, whichis unified with respect to adjacent strata by consisting dominantly of a certain lithologic type or combination oftypes or by possessing other unifying lithologic features. The formation is the fundamental unit oflithostratigraphic classification.

    (2) Drilling: A general term applied by drillers without stratigraphic connotation to a sedimentary rock that can

    be described by certain drilling or reservoir characteristics.


    The mechanical strength of a formation that represents the maximum borehole fluid pressure that can besustained without fracturing the formation, and losing borehole fluid. This gradient is largely dependent uponlithology, the formation pore pressure, and the weight of overlaying sediments (see also LEAK-OFF TEST).


    Viscosity, equal to the time(in integer seconds) it takes one U.S. quart of mud to flow through a Marsh funnel.The measuring unit is seconds.


    A log of the formation natural radioactivity level. It is typically used as an indicator of formation shaliness. It is

    also used extensively for well-to-well correlation and to correlate cased-hole logs with open-hole logs.


    A brand name commonly used to refer to a drilling recorde