Kambi Mwd Manual

MWD Operational Manual

KAMBI ENTERPRISES Inc. 11981 – 44 St SE. Calgary – AB – T2Z 4G9 Ph: +1(403) 243-4438 Fax: +1(403) 243-8958 www.kambi.ca

MWD OPERATIONS MANUAL

Prepared by: Ewert Muñoz December 01, 2006 Revision: 2

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

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TABLE OF CONTENTS Overview •

Theory of Operation

MWD System • • •

• • •

Modular Design Retrievable and Reinsertable Operating Specifications Flow Ranges Pressure Drop Data Transmission Electrical Power/ Operating Time Battery Duration Table Operational Modes Maximum Lateral Displacement Error Inclination Accuracy Tool face Accuracy Dip Angle Accuracy Sensor Performance Sensor Tolerance Maximum Lost-circulation Material Environmental Shock Vibration Operating temperatures Table Orifice / Poppet Flow Chart Pulse Shape. Resolution Data word transmission times Down Link Communications Detection Coding, Detection and Decoding Processes. Directional Computations Summary

Surface Equipment Considerations •

Rig Considerations Rig Type & Equipment Make-up and Break-out of MWD UBHO Retrievable / Replaceable MWD Tools Fishing Equipment

•

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

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•

Mud Pumps Pump Type Duplex Pumps Pulsation 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 •

• •

•

•

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Signal Strength Flow Rate Pressure Drop Signal Attenuation Pulse Width (Transmission Frequency) Positive Displacement Motors Drilling Fluids Compressible Drilling Fluids Planned Mud Additives ( Add LCM) Lost Circulation Material (LCM) Lubricating Beads Barite Hematite Mud Mixing Mud Contaminants Pipe Scale / Plastic / Cement Gloves, Wrenches and Other Junk Cuttings and Mud Solids Heavy Cuttings in High Angle Holes Drilling Conditions Deep Drilling Hole Size Restrictions Temperature Pressure Stuck Pipe / Borehole Stability

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Trajectory / Geological Considerations •

•

• •

Wellbore Profile MWD Surveying Procedures Dogleg Severity Survey Accuracy / Uncertainty Sag Corrections Depth Error Gyro Limitations Collision Avoidance Target Shrinking Physical Formation Parameters Formation Measurements Hard or Cemented Formations Rugosity and Washouts Applications / Techniques Invasion / Time-Lapse Logging Real-Time / Recorded Data Densities Economic and Regulatory Considerations Critical MWD Information Economically Beneficial MWD Logistics and Geographics

Reliability and Statistics •

Failure Analysis Failure Type Environment Additional Questions

MWD Operational Guidelines Check List

Glossary

Conversion table

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Overview This manual is primarily intended to provide operators of Measurement-While-Drilling (MWD) Tools with guidance on the best practice in the operation of the GE system under a variety of downhole conditions. It contains advice on how to 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.

THEORY OF OPERATION GE-MWD Downhole Sensor. The main sensor is a GE magnetometer. It is a standard electronic instrument proven by many years of use in 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 and the Gravitational Field with High resolution and precision. The output from these sensors can be digitized and processed to find the vector to the earth's magnetic north pole and the vector for "down" center of the earth, with temperature compensation. This information, along with other parameters, produces data such as 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 of the survey data. Proccesor. The GE-MWD Downhole Processor is the controller of the system and commands all functions of the system and performs all downhole calculations. Contained inside the assembly are: a Single Port MPU, a Triple Power Supply and a Digital Orientation Module. The Single Port MPU is a modular micro-controller assembly based on the Motorola® MC68HC11 microprocessor that implements qMIX™ communications protocol (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 sensors for 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 sequences transmitting 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" probe incorporates two single battery packs housed in their individual battery barrels. If the operator is planning to use the directional package and requires extended battery life, then the system can be stacked in the standard arrangement, with the second battery barrel placed above the Survey Electronics module. Should the operator require the use of the Gamma Ray detection module, then the batteries can be stacked in tandem above the Survey Electronics module, while the Gamma Ray detection module will be placed directly above the Pulser Module. The arrangement of the modules in the tool design is limited only to the dedicated collar design. The battery modules and the gamma module are identical in length and are therefore interchangeable, The design of the dedicated collar places the Survey Electronics module above the 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 ºC., eight cells are used in the lithium packs. It is estimated that a single lithium battery pack will last over 160 hours. The battery pack life depends on the pulse length, the tool configuration and operational modes used.

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Pulser. The pulser consists of an oil filled pulser section and an electronic Pulser Driver. The Driver contains a capacitor 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 rods and shafts to the servo-poppet. The second solenoid designated the "Holding Coil" solenoid, energizes after the first solenoid pulls the assembly back. The retraction of the servo-poppet initiates mud flow through the servo-orifice and into the pulser plenum below. This maneuver and resulting mud flow redirection initiates the propagation the mud pulse. The pull-back solenoid requires a large energizing charge, supplied by the capacitors in the driver. The capacitors then discharge to the "Holding Coil", just below the Pull-Back solenoid. The Pull-Back solenoid only operates for about 80 milliseconds before it is de-energized. For the remainder of the pulse length the servo-poppet and shafts are held in the "up", or open position by the force applied to the Holding Coil. While energized 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 reverse maneuver and the resulting mud flow redirection initiates a return of the signal poppet to the open position and 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 controlling the servo-poppet movement. The servo-poppet, by opening and closing, regulates the fluid movement into the plenum. The resulting mud flow through the plenum pushes against the main signal piston in association with the force from the main spring, and overcomes the opposing forces which hold the signal poppet up or in the open position. The main signal poppet is forced down, partially obstructing mud flow through the restrictor orifice creating a higher back pressure in the annulus. When the servo-poppet moves down and seats, flow through the plenum is shut off. Though holes in the probe fluid enters and pushes on the opposite side of the main signal piston and pushes it up, due to the lower differential pressure in the plenum, 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 resulting reduction in the annular pressure. The differences in annular pressure created by the main signal poppet is perceived 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 only two parts must move [ the servo-poppet and main signal poppet]. It is also very reliable. This design has allowed GE to develop a small O.D. MWD that is capable of producing a very large (high pressure) positive and clean pulse with very low energy consumption. This results in more reliable signals and longer battery life. The capability to use two battery packs independently of each other allows the operator to utilize one battery pack at a time gaining the maximum battery life from each pack before switching to the fresh pack thus 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 from the 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 are made-up and broken down, i.e., the field connections. Subs. The muleshoe works like all other orienting devices by having a key which catches the helical edge on the probe end, and orients the probe to a fixed location as it seats. The key is in line with an orientation bolt that goes through the wall of the drill collar and to orient and lock the muleshoe in the collar. This allows the MWD operator to easily measure the offset angle between the orientation bolt/muleshoe key and the bent sub/mud motor scribe line. This angle is entered as the Driller's Assembly Offset (DAO) in the qMWDCnfg program 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 through the procedure to measure this angle and insure that the total offset is correct and that both corrections are registered into the propel systems. The muleshoe also contains the main orifice into which the pulser main signal poppet projects into to create the 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 snapring 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 whenever the 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, and a 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 to configure 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 parameters desired; 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 Drillers Remote Terminal display with the proper operating parameters. After the desired parameters and format are selected, they are loaded into the MWD Transmitter and the DRT. 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 filing source for all data transmitted by the MWD probe. The Programming Cable to the probe should then be disconnected and the spear point re-attached to the probe, and torqued to the proper 58 ft/lbs. Then it can be loaded into the drill collar, ready for downhole operations. Power draw from a completely made-up tool is minimal. 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 tool commence 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 for Hazardous 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. The Transducer Cable should be nearly run also from the Transducer to the DRT. The PC is then connected to the 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 sensors include a signal receiver (Transducer) and drilling monitors (Rig Display). The surface computer may need to be located in a safe area away from the rig floor normally inside the doghouse. The downhole tool is made up of multiple components - 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 Rig site. Sensors that are available today measure borehole direction, (inclination, azimuth, and tool face orientation) natural formation gamma-rays, resistivity, downhole vibration, temperature and pressure Our System is a Positive Pulse, through positive pulses, downhole life and servicing is simplified through the production of and minimal moving parts. Maintenance in the field can be achieved with minimum tools and time.

Modular Design The GE’s modular MWD System is easily assembled in the field, enabling easy addition of formation evaluation systems such as gamma ray modules and centerfire resistivity solutions. The component structure of the system enables a flexible sensor position and placement close to the drill head, optimizing sensor performance. Replacement of 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 efficient probe upgrades and replacements. In the event that the pipe gets stuck in the hole, this feature minimizes the rig time lost 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. collar 100-300 gpm, 4.75 in. O.D. collar 150-600 gpm, 6.5 in. O.D. collar 400-1200 gpm, 8.25 in. O.D. collar

Pressure Drop 100 psi @ 400 gpm

Data Transmission Positive-pulse

Electrical Power/Operating Time Lithium battery operates to +150˚C or +175˚C. Will operate for 175 to 200 hours per battery pack under normal used, in cold weather like Canada, batteries perform poorly and in temperatures around -15 to -20 the voltage reading decrease dramatically, it is recommend that under -5.0 ºC, 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 life that is used.

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Battery Duration Table Standard Tool Pulse Width 3.00 2.00 1.50 1.20 1.00 0.80

Duration in Hs. 210 190 160 135 120 100

Standard Tool + Gamma 3.00 2.00 1.50 1.20 1.00 0.80

190 150 120 100 90 75

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

Operational Modes Operator-selectable sequences and downlinking options. Highly flexible operating software. Selectable resolution – all parameters

Maximum Lateral Displacement Error 2.6 ft. /1000 ft. or a conical uncertainty of ±0.15˚ maximum

Inclination Accuracy ±0.1˚

Toolface Accuracy ±0.5˚

Dip Angle Accuracy ±0.1˚

Sensor Performance Azimuth Inclination Gravity Toolface Magnetic Toolface Gravity Intensity Magnetic Intensity Dip Angle Temperature°

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0° to 360° 0° to 180° 0° to 360° 0° to 360° 0 to +/- 1000 mg 0 to +/- 700 mGauss -90.0° to 90.0° 0° to +150°C

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+/- 0.15° conical uncertainty +/- 0.1° +/- 0.1°, Inclination = 90° +/- 0.1°, Inclination = 0°, 0° Lat. +/- 1.0 mg +/- 0.10 mGauss +/- 0.15° +/- 2°C

MWD Operational Manual

MWD Operational Manual

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 ºDegrees.

Maximum Lost-circulation Material 40-50 ppb concentration, any size, pre-mixed

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

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

Operating temperatures Models available for -20°C to +150°C or -20°C to +175°C

Table Orifice / Poppet

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ORIFICE

POPPET TIP

FLOW AREA

(ID)

(OD)

(SQ/IN2)

(GPM)

1.28 1.28 1.28 1.35 1.35 1.35 1.40 1.40 1.40 1.50 1.50 1.50

1.125 1.086 1.044 1.125 1.086 1.044 1.125 1.086 1.044 1.125 1.086 1.044

0.297 0.360 0.437 0.443 0.505 0.582 0.550 0.612 0.690 0.778 0.840 0.918

Under 250 200-375 300-500 225-475 350-550 475-600 350-575 450-650 475-700 475-750 500-800 Over 700

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FLOW RANGES

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MWD Operational Manual

Flow Chart

1.20 1.167

1.20 1.125

1.28 1.122

1.28 1.086

1.35 1.086

1.28 1.040

1.35 1.122 1.40 1.122

1.40 1.086 1.35 1.040

300

1.50 1.122

1.50 1.086

200 Max Flow 6-3/4" Collar

Pulse Amplitud (PSI)

400

Max Flow 4-3/4" Collar

Min Flow 4-3/4" Collar

500

100

1.40 1.040

1.50 1.040

0 0.3785

0.757

1.135

1.514

1.892

2.271

2.649

3.028

3.406

Flow (M³) 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

Pulse Shape

Amplitude Decreases rapidly for Pulse Lenghts < 1.5 Sec. Max average Amplitude reached for pulse duration 1.0 & 1.2 Sec.

Pulse Amplitude

0.5

1.0

1.5

2.0

2.5

3.0

Pulse Duration (sec)

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

Variable Azim Inc Temp MagF DipA Grav TFA Gama BatV

Range 360 180 255 1 90 2 360 255 51.1

6 Bit 5.714 2.857 4.048 0.016 1.429 0.032 5.714 4.048 0.811

7 Bit 2.835 1.417 2.008 0.008 0.709 0.016 2.835 2.008 0.402

8 Bit 1.406 0.703 [1] 0.004 0.353 0.008 [1.412] [1] [0.2]

9 Bit 0.705 0.352 0.499 0.002 0.176 0.004 0.705 0.499 0.1

10 Bit 0.352 0.176 0.249 [0.001] 0.088 0.002 0.352 0.249 0.05

11 Bit 0.176 0.088 0.125 0 [0.044] [0.001] 0.176 0.125 0.025

12 Bit [0.088] [0.044] 0.062 0 0.022 0 0.088 0.062 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 of bits 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

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PULSE WIDTH

RESOLUTION

UPDATE TIME

0.8 0.8 0.8 1.0 1.0 1.0 1.2 1.2 1.2 1.5 1.5 1.5 2.0 2.0 2.0 3.0 3.0 3.0

6 8 12 6 8 12 6 8 12 6 8 12 6 8 12 6 8 12

11 Sec. 14 Sec. 21 Sec. 14 Sec. 18 Sec. 26 Sec. 17 Sec. 22 Sec. 31Sec. 21 Sec. 27 Sec. 39 Sec. 28 Sec. 36 Sec. 52 Sec. 42 Sec. 54 Sec. 78 Sec.

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Downlink Communications Detection There are two different modes for Down-linking “Mode number and Rate Sequence”. Rate Sequence allows the operator to change much more of the configurations of the downhole tool. Mode Number allows the operator to downlink into 1 of 4 different mode numbers. While rate sequence allows you more versatility, Mode Number take less time 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. These commands are generally used to control the telemetry data rate and data content. Down-linking is done by bringing the pumps on and off in a predefined sequence of Down-linking pulses. These pulse time lengths are set by the Down Link Time Period (DLTP), which is normally set at 60 seconds. The pulse time lengths is ½ 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 pulse period.

Mode Number Mode Number allows the operator to downlink into 1 to 4 modes that are configured on surface. Each of these modes will include one of the four mode numbers that you configure in “MWDConfig” with pulse width / survey sequences and toolface sequences. Next example show standard case in the field. Example: To downlink into Mode 2 using a DLTP = 60 seconds ƒ (Step1)Pumps will be shut off for 60 seconds ƒ (Step2)Turn pumps on for 35 seconds (downlink pulse #1) ƒ (Step3)Turn pumps off for 35 seconds. ƒ (Step4)Turn pumps on for 35 seconds (downlink pulse #2) ƒ (Step5)Turn pumps off for 120 seconds (DLTP (60 sec) x 2 (mode 2) tolerance of +/-10 Sec. to recognize flow. ƒ (Step6)Turn pumps on at least 60 Sec. to finish the sequence.

Step1

Step2

Step4

Command Pulse #1

Command Pulse #2

Step6 Step5

Step3

Coding, Detection and Decoding Processes.

Background 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 of many 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 not discussed by Steve Monroe’s paper but has a name similar to one described in the paper. We call our coding method the “M-ary coding”. We have chosen this method for its reasonable combination of good data rate, and good signal efficiency, as well as some desirable characteristics related to having to detect only a single pulse in the present of noise.

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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 for these 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 1 1 0 11

421 101

This encodes in “M-ary” as 3,3,5 where the first 3 comes form the symbol containing 11, the two most significant 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:

3 P P 2 1 0 START OF DATA WORD

7 6

5 4

3

P

P 2

1

0

7

6

5

P P

4

3

2 1

0 END

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 half the pulse width, and have allowed for a full pulse width (two slots) pulse-interference-gap (PIG) or recovery time 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 find only the best single pulse in a window containing four or eight possible locations for the pulse. This feature increases 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 synchronizing the surface equipment to the transmitted data sequences. The surface receiver equipment functions by looking first for one 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 that removes 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 low pass 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 by additive while Gaussian noise under a wide variety of criteria. Use of the matched filter has proven effective in many different MWD systems over the years. GE has the ability to shift the tunable filter edge during operation to help reduce the effect of inband interference. For those cases where the noise/interference is concentrated in the upper portion of the passband, manually lowering the “ low pass” cutoff frequency will reduce the noise/interference faster than it reduce the signal… resulting in enhanced signal detection quality. The results of the pulse detection process are the location in time of the centroid of the “best” pulse located in the allowed time window, its amplitude and other characteristics. In case multiple pulses are detected in the allowed symbol window, an evaluation in contained in the qMWD Engineer’s Reference MANUAL, SECTION 2.4.5.2 Decoding Process After each pulse is detected, the value of the symbol corresponding to its location is determined, and when the expected pulses making up a data word have been received, the decode value is reported to the receiver display and logging function, The receiver display maintains files containing all decoded data words, pulses data buffers (contains the characteristic of all detected and suspect detected pulses), and pulse waveform records (contains a stripchart vs time of the output of the matched filter process).

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MWD Operational Manual 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 parity check will detect a single one-slot position error contained in the detected data word. The error correction code will detect a single two-slot pulse position error, and correct a single one-slot pulse position error. The single slot error in pulse location is the most likely form of error sources to be expected in the received signal.

Directional Computations Summary

Grav = √ ( Ax² + Ay² + Az² ) MagF = √ ( Mx² + My² + Mz² ) Azm = ATAN2(( Mx*Ay – My*Ax ) * Grav) / (Mx*Ax*Az+My*Ay*Az+Mz*(Ax²+Ay²)) TAzm = Azm + MDec Inc = ATAN2 ( √ ( Ax² + Ay² ) / Az ) mInc = ATAN2 ( √ ( Mx² + My² ) / 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 1 OR dMTF = UmTF2-UmTF fpr magnetic toolface type 2 gTFA = UgTF ± TFO gPTF = dTFA+UmTF ±TFO mTFA = UmTF ±TFO±MDec for magnetic toolface type1 (“mTTy”=1) OR mTFA = UmT2±TFO±Mdec for magnetic toolface type2 (“mTTy”=2) mPTF = UmTF±TFO±MDec for magnetic toolface type1 (“mTTy”=1) OR mPTF = = dMTF+UmTF±TFO±MDec for magnetic toolface type2 (“mTTy”=2) aTFA = gTFA, if Inc >=IncT OR aTFA = mTFA, if Inc =IncT OR pTFA = mPTF, if Inc 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 the established benchmark stations to ensure the MWD tool is recording well azimuth, inclination and tool face orientation data correctly. On bottom - Upon reaching bottom after every round trip a survey is recommended at the last MWD survey station of the previous run. The new survey data, including the depth measurement, should agree with the previous survey within the quality control criteria specified for that sensor. All benchmarks should be taken with the MWD sensors within ± 1 mts measured depth of the benchmark stations described above. Two or more successful benchmark surveys may be taken when necessary. The observed inclination and azimuth readings should agree with the benchmark values to within the MWD survey sensor specifications. It should be noted that changes in the BHA configuration may have an effect on uncorrected survey measurements. 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 of the borehole. It should be noted that the instantaneous dogleg severity calculation is dependent upon the interval

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MWD Operational Manual between surveying stations - typically 90 ft (28m). Dogleg severity calculations based upon shorter surveying intervals may 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 position uncertainty 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. A means 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 increases as measured depth increases). Azimuth errors tend to cause lateral uncertainty and have their biggest effect at high inclination (worst case being horizontal). Depth errors and inclination errors cause uncertainty in the plane of the well path. At very low inclination, depth errors cause TVD uncertainty, and inclination errors cause radial uncertainty. At horizontal, depth errors cause radial uncertainty and inclination errors cause TVD uncertainty. These basic characteristics mean that long, high angle sections can cause lateral and TVD uncertainty to increase dramatically relative 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, and the effect of drillstring interference on magnetic systems increases. The latter two effects are worse at higher latitudes and 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 be minimal. There may be little advantage in running an accurate system in the intermediate casing if the overall uncertainty 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 are random 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 random will tend to underestimate. MWD directional specifications tend to take the form of inclination and azimuth accuracies. If these specifications have a common basis, they are a useful means of comparing the accuracy of one tool to another. However, it is not always clear how accuracy specifications are derived. They will probably include sensor specifications, but may or may not include system level and environmental errors. In addition to sensor accuracy, there are other factors that affect the accuracy of an MWD directional survey. These include: depth error, magnetic dip and declination errors, magnetic field strength estimation error, washed-out borehole sections (and BHA stabilization), misalignment of the directional sensor in the drillstring, flexure of BHA between stabilizers (Sag) and magnetic interference. There are various methods which attempt to correct for the environmental errors, but none are wholly effective, and some have been known to increase rather than reduce errors. The following table lists the more important of these error sources and gives illustrative figures for the magnitude of the errors they are likely to generate in a typical directional well:

Error

Azimuth

Inclination

1°

0°

Depth Error

0.5°

0.5°

Magnetic Interference

0.75°

0°

Sensor Misalignment

0.1°

0.1°

Magnetic Field Error

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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 by deflection of the BHA due to gravity or weight-on-bit. Weight-on-bit deflection causes azimuth errors, but these are relatively small. In any case, most surveys are acquired with the bit off bottom. BHA sag due to gravity causes inclination errors. This error increases as inclination increases. Inclination errors at high inclination introduce TVD uncertainty 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 natural tendency 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 depth since it has accumulated over the whole length of the well. Absolute TVD uncertainty has its uses in defining the position of one well with relation to another, or in assessing the validity of prognosed horizons. However, in terms of optimizing recovery, all that matters is the position of a well relative to its true target, not the prognosed target and certainly not to the wellhead. If we can identify the point of entry into the producing zone, we can set relative TVD uncertainty 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. Well planning should always involve the use of valid error models that quantify the relative accuracy of the survey programs under consideration. The ability of rate gyro systems to define true north deteriorates as inclination, azimuth and latitude increase. At 70 degrees of latitude gyros are virtually unusable above 70 degrees of inclination. Attitude reference tools establish an accurate heading at the start of a survey and then carry it forward, making azimuth accuracy theoretically inclination independent.

Collision Avoidance Existing nearby well locations and trajectories should be correctly specified prior to drilling a well. companies offer “Proximity Analyses” to help plan and steer a new wellbore.

MWD service

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

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 service companies. Sensors and environmental correction methodologies are quite different for each service company. Design implications on both the drilling process and the quality of measurements will depend on specific drilling and geological environments.

Hard or Cemented Formations Vibration and shock to MWD tool electronics is a major cause of MWD failure. BHA modeling programs can be run to simulate vibration harmonics with varying load conditions. However, modeling programs do not account for all downhole 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 significant effect on the response of MWD logging sensors. Because of the different distances between the bit and various sensors, different formations have differing amounts of time that they are exposed to borehole fluids before they are logged with an MWD tool. This is particularly significant when thin, hard formations that drill more slowly are encountered, or at the end of a bit run when the drillpipe is tripped and one sensor has logged a formation when the section is first drilled, and another sensor does not log the same interval until after the pipe trip. Formation intervals that are exposed to drilling fluids for longer periods of time are more susceptible to the influences of invasion and washouts on the logging measurements. It should be noted that Time-Lapse log responses are affected by borehole instability (changes in borehole size) and variations in fluid properties.

Real-Time / Recorded Data Densities Real-time MWD transmission rates are typically limited to only a few bits of data per second. It is, therefore, imperative that drillers and geologists discuss with the service company, before the MWD tool is tripped into the hole, which types of information, with what resolution (precision), and how frequently each different measurement should be transmitted to the surface in order to optimize real-time decision making. Some service companies have the ability to select from different pre-established transmission formats while the MWD tool is downhole. In this way the various types of information (navigation, drilling performance, formation evaluation and quality control data) can be transmitted to the surface 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 pay intervals 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 extremely difficult or risky. - Production wells requiring a casing point above a severely drawn down reservoir with a high risk of lost circulation or sticking pipe. The ability to successfully drill and evaluate such wells virtually requires the use of MWD. In those situations where alternatives to MWD are risky or do not exist, MWD costs should very easily be justified when weighed against the potential risks of not using MWD.

Economically Beneficial MWD Some wells fall into a category where obtaining MWD may be economically more attractive than other available alternatives. 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 formation evaluation data to replace wireline data. In either case, a number of diverse factors (cost, benefit, risk, etc.) must be considered in order to realize any real economic benefits. If these factors are not considered, not only is there the chance of not realizing any cost savings, but there is a very real possibility of incurring enormous costs. The lost-inhole 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 savings are 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 drilling phenomena, better survey accuracy and real-time toolface data that result in smoother wellbores, faster / more accurate penetration 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 requiring auxiliary wireline information (i.e. dipmeter, sidewall core, or formation tester data), therefore, is less likely to be a good candidate 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 is required or where good reservoir and geology databases exist. MWD may also be appropriate in areas of deep invasion (e.g. depleted reservoir pressures) or when obtaining good quality wireline data is problematic due to washouts, ledges or doglegs.

Logistics 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 operating statistics 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 BHA designs 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 and service companies should work together to inspect the MWD tools during “normal” drilling operations (e.g. internal erosion, and external abrasion) in order to assess the rate at which drilling fluids and rock formations are wear on the MWD systems. In this manner optimal drilling fluid properties and MWD preventative maintenance schedules for particular geographic regions can be determined. Statistically, approximately 80% of the total MWD failures occur on 20% of the wells drilled using MWD tools. On some wells, one service company will experience a series of failures, be replaced, and a second service company will experience 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 statistics for each particular well profile and BHA type are required. In addition, when the first MWD failure occurs, a more indepth 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 particular BHA. If the MWD tool is experiencing downhole problems, the first issue before tripping to change the tool may be for the operator to evaluate the condition of the mud pumps and circulating system. The next question should then be to ask whether the MWD data at the time of failure are critical to current operations. If the decision is made to trip, or upon recovery of any failed component, electronic diagnoses and physical inspections should be performed. Only after analysis of these statistics can improvements be made to operating procedures or tool designs and repeat failures avoided. As a minimum operators should track the number of failure-free MWD bit runs, and circulating hours by service. The IMS recommends that after each MWD failure operators should collect the following additional failure-related statistics and parameters:

Failure Type External physical or chemical wear Internal mechanical failure (erosion) Sensor type Mud solids or junk trapped by the MWD tool Electronics failure Poor data quality Data transmission failure Poor data rate Failure to record data

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Environment Depth Temperature Mode and level of downhole vibrations Well inclination /dogleg severity Formation type Weight on bit Surface RPM Mud flow rate LCM type and concentration Mud characteristics: Type, weight, yield point, chlorides, LCM type and LCM concentration BHA configuration / stabilization Mud motor type Bit type Effective real-time data transmission rate

plastic viscosity, % solids, sand content, gas content, ppm

Additional Questions 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 of these failures should still be reported back to the operator. Collecting the statistics like those shown above will help provide more reasonable performance expectations for the driller and thus reduce operating costs, as well as reduce the 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 is subjected to the same drilling environment. There are a number of real-time vibration and shock detection services that can help avoid undesirable drilling characteristics, and extend not only MWD performance, but also bit life and mud motor performance.

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MWD Operational Guidelines Check List Economic Considerations

Y

N

Y

N

Y

N

Y

N

Y

N

Have lost-in-hole charges been discussed? Has the impact of wear – high solid content for MWD tool repairs been considered?

Surface Equipment Considerations Are 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 Have 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 formation evaluation? Are there sufficient non-magnetic collars in the BHA to minimize magnetic interference on directional measurements? 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 Extended Motor)? 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 reduce vibration? Has MWD battery life been discussed with the Directional Driller and CoMan? Are the downhole data recording set appropriately?

Downhole Considerations Has 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 size considered? 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 Is 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) been discussed? Is external magnetic interference (nearby wells, lost BHA’s, hematite mud and magnetic formations) insignificant? Have the appropriate ROP’s been determined for drilling through zones of interest? (For Logging matters)

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GLOSSARY ACCURACY (of a measurement) The closeness of the agreement between the result of the measurement and the (conventional) true value (of the measurand). API UNIT A unit of measurement in GR logs (previously neutron logs also). For GR tools, one API unit is equivalent to 1/200th of the total deflection observed between zones of high and low radiation in the test pit. MWD GR tools measure 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 compared to the same measurement by a wireline GR tool. GR measurements may vary from one service company to another AZIMUTH Direction, as in a compass direction. The clockwise angle of departure from a reference direction (typically geographic) north, measured in a horizontal plane. In dipmeter and directional surveys, it is the clockwise angle from magnetic north to the tool reference point or electrode. This measurement must be corrected for magnetic declination to compute true azimuth. The azimuth is generally expressed in degrees. AZIMUTHAL The characteristic of a logging tool to perform separate measurements in different directions (azimuths) around the axis of the tool. Currently, MWD sensors making azimuthal measurements are limited to density and tend to give measurements in quadrants around the borehole. Some MWD GR sensors are shielded on one side so that measurements are taken from only (primarily) the unshielded side. These are oriented measurements rather than true azimuthal measurements. BENDING STIFFNESS The resistance to axial bending of a drill collar (expressed in Nm/Rad or ft-lb/degree of deflection). It is equal to the bending moment required to produce a unit deflection of a collar when one end is fixed. This value is supplied to drilling engineers for the comparison of the angle building characteristic of an MWD drill collar to that of a standard API drill collar. BOTTOM HOLE ASSEMBLY (BHA) The portion of the drilling assembly below the drill pipe. The Bottom Hole Assembly (BHA) will typically consist of drill collars, stabilizers and drilling tools (e.g. motor and MWD) and the bit. BUILD ANGLE The rate of increase in inclination of a wellbore. This is sometimes expressed as Rate-of-Build (ROB) and expressed 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 to turn in a desired direction. CASING SHOE A short length of heavy steel pipe which has a tapered profile. The casing shoe is screwed onto the first joint of 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, the best cement job (integrity) is closest to the bottom of the well. DENSITY The mass of some material divided by its volume. In petrophysics, formations and drilling fluid densities are measured, primarily as input to equations to derive the porosity of the rock. Most logging tools actually measure bulk density (ρb), and express the density in g/cm3. The equation used for determining porosity (φ) from bulk density is: φ = (ρma - ρb)/(ρma - ρmf)

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where ρma is the assumed density of the matrix (formation) and ρmf is the assumed density of the fluid in the pore spaces. DEPTH ENCODER 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. DEPTH OF INVESTIGATION The radial distance from the measure point on a sensor to a circle, usually within the formation, where the predominant tool-measured response may be considered to be centered. It varies from one type of device to another because of different designs, and techniques of compensation and focusing. It also varies from formation to formation due to changes in formation properties. For a better understanding of the volume of investigation 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. DIP DIRECTION The direction of dip (maximum slope in a plane) perpendicular to the DIP STRIKE, expressed relative to compass directions. DIP STRIKE The direction or bearing of a horizontal line drawn on the plane of a structural surface. The strike is perpendicular to the DIP DIRECTION. DIRECTIONAL DRILLING Intentional drilling of an off-vertical well at a closely controlled, predetermined angle and direction through the use of special equipment. DIRECTIONAL SURVEY 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. DOGLEG SEVERITY The rate of change of hole angle and/or direction evaluated between the current survey point and the next shallowest survey point. It is expressed in degrees per course length, and is significantly influenced by the course length over which it is calculated. DOWNLINK The capability to retrieve data from, and send instructions to the tool when it is located downhole. Four principles are currently used for downlink communications: mechanical (wireline), electrical (inductive coupling), hydraulic (mud pulse) and electromagnetic propagation. DRIFT ANGLE The deviation of a section of the borehole from vertical. DRILL COLLAR 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. ELECTROMAGNETIC PROPAGATION The passing of electromagnetic energy through a medium. Most MWD resistivity logs are based on electromagnetic propagation and typically operate at high frequencies (typically between hundreds of kHz and a couple of Mhz). They are used for correlation and to determine formation electrical properties or invasion characteristics. MWD tools record the phase shift and attenuation of electromagnetic energy through the formation near the borehole, which are then converted into resistivities and dielectric properties.

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FORMATION (1) Stratigraphic: A body of rock strata, of intermediate rank, in the hierarchy of lithostratigraphic units, which is unified with respect to adjacent strata by consisting dominantly of a certain lithologic type or combination of types or by possessing other unifying lithologic features. The formation is the fundamental unit of lithostratigraphic 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. FRACTURE GRADIENT The mechanical strength of a formation that represents the maximum borehole fluid pressure that can be sustained without fracturing the formation, and losing borehole fluid. This gradient is largely dependent upon lithology, the formation pore pressure, and the weight of overlaying sediments (see also LEAK-OFF TEST). FUNNEL VISCOSITY 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. GAMMA-RAY LOG 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. GEOLOGRAPH A brand name commonly used to refer to a drilling recorder that records particular drilling events as a function of time. Depth and rate of penetration are two drilling parameters derived from its recording. GEOSTEERING A technique in which one or more geologically sensitive parameters, measured downhole and transmitted to the surface, are used to guide the well path and keep it in the desired location. In GEOMETRICAL STEERING, the measurements are limited to azimuth and inclination, and the well is steered toward a predetermined geometrical target. In GEO (logical) STEERING, formation sensitive measurements are used to steer the wellbore in relation to adjacent geological features. GRAVITY TOOL FACE The angle between a tool reference axis and a line perpendicular to the hole axis and lying in the vertical plane. Also commonly referred to as HIGHSIDE TOOL FACE. KELLY The heavy square or hexagonal hollow steel member, which is suspended from the swivel, that connects to the drillpipe. It is engaged in the rotary table, via the kelly bushing, to rotate the drillstring. Drilling fluid is pumped through the kelly into the drillstring. KELLY BUSHING Device, through which the kelly slides, that fits into the rotary table. It transmits the torque of the rotary table to the kelly and consequently to the drillstring. It is sometimes also called the drive bushing or rotary kelly bushing (RKB). KICKOFF DEPTH The depth in the vertical part of a well at which the deviated (inclined) portion of the well is started. LEAK-OFF TEST A pressure test (usually performed after setting a casing string) that determines the maximum pressure (mud weight) that can be contained by the open hole formations without fracturing and losing circulation.

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LOG (1) A detailed record, usually correlated with depth, of certain parameters of the formations penetrated during drilling. Data recorded may include electrical and radioactive surveys, description of cuttings, core analyses, etc. (2) A history of operations where drilling time, intervals cored, drillstem test results, etc. are recorded. LOGGING SPEED The speed at which the measuring instrument is moving when the log is recorded. In wireline operations, the cable speed typically controls the speed of a particular logging tool. In MWD operations, the rate of bit penetration controls the speed of the logging operation. LOGGING TOOL A tool for performing downhole well log data gathering services for determining properties of the formation, or characteristics of the wellbore and its environment. LOGGING-WHILE-DRILLING (LWD) Sets of methods used to record formation characteristics while drilling - commonly called LWD. Also called FORMATION EVALUATION WHILE DRILLING. LOST CIRCULATION MATERIAL (LCM) Material added to the mud to aid in preventing the downhole loss of mud - also called LCM. Downhole mud pulse telemetry devices and turbine generators may be affected by the presence of this material in large quantities. MAGNETIC DECLINATION The angle between geographic north and magnetic north. It can be either a negative or positive number. It is used to transform data referenced to magnetic north to data referenced to geographic north. MAGNETIC INCLINATION Vertical angle between the direction of the magnetic field and the horizontal plane. Commonly called magnetic dip angle. MAGNETIC INTERFERENCE That condition which occurs when extraneous (not due to the earth) magnetic forces affect a magnetically sensitive instrument. Proximity to magnetized casing, magnetized drillstring components, and certain magnetic minerals are potential sources of interference. MAGNETIC PERMEABILITY The property of a substance that determines to what degree it modifies the magnetic flux in a magnetic field assumed to equal unity in most oilfield geological formations. Magnetic permeability is frequency dependent. See also DIELECTRIC PERMITTIVITY. MAGNETIC TOOLFACE The angle between magnetic north and the projection of the tools reference axis onto a horizontal plane. See RELATIVE BEARING. MAGNETOMETER A geophysical instrument used to measure the intensity, in both the horizontal and vertical directions, of the earth magnetic field. MEAN TIME BETWEEN FAILURE (MTBF) Average elapsed time between failures. It is calculated by dividing the number of MWD operating hours by the number of failures. Industry standard practice (see SPE paper #19862) has established two measures of MTBF, one for circulating hours (real-time transmission), and the second for total hours of operation below rotary (while the tool operating and recording data). MTBF statistics are recorded for individual components, for whole MWD systems, and by geographical area. Operators are also interested in the number of times

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MWD Operational Manual MWD failures interfere with drilling operations and require tripping for the MWD tool. MTBF is significantly affected by the drilling environment (e.g. SHOCK, VIBRATION, mud solids and flow rate) and by MWD maintenance schedules. MEASUREMENT WHILE DRILLING (MWD) A technique of making downhole measurements of azimuth, inclination, tool orientation, natural radioactivity, resistivity, porosity, temperature, vibration, weight, torque, etc. These measurements are made while drilling by sensors located in the bottomhole assembly close to the drill bit, and can be recorded downhole and/or telemetered to the surface. MUD A liquid circulated through the wellbore during drilling and workover operations. One purpose of the mud is to remove rock cuttings produced by drilling. The mud also helps cool the bit, it prevents the borehole walls from caving in, constrains high-pressure formation fluids, and provides a medium for MWD mud-pulse transmission signals. See DRILLING FLUID. MUD CAKE The sheath of mud solids which forms on the borehole wall opposite permeable formations when the mud filtrate seeps into the formation. MUD FILTRATE The liquid portion of the mud that is able to flow into permeable formations. PRECISION The closeness of agreement between the results obtained by applying a measurement procedure several times on identical materials and under prescribed measurement conditions. The smaller the random part of experimental error, the more precise the measurement procedure. PRESSURE Force per unit area applied to a body (e.g. hydrostatic, flow and pump pressures). It may be gauge or absolute. The kPa (kiloPascal) unit is used in physics. The more common related oilfield unit is the pound per square inch (psi). RESOLUTION (1) Intrinsic Sensor Resolution is the length associated with a sensor that relates to its ability to see thin detail (see also Impulse Response Function). It is quantitatively defined as the full width at half maximum of the response of a sensor to an infinitesimally short event of infinite magnitude, and is approximately equal to the minimum distance between two bed boundaries that the sensor can resolve. (2) Spatial Resolution is defined as the minimum formation thickness that can be resolved from a data set, and is a function of the intrinsic sensor resolution, data sampling interval and data filtering. (3) Digital Resolution is the precision with which data are digitized when either transmitted to the surface, or stored in memory. It is related to the number of digital bits used to represent a quantity. RETRIEVABILITY The ability to retrieve a portion of an MWD system from downhole while the MWD tool is in the bottom hole assembly. Retrievability is used on various MWD systems to recover electronics or radioactive sources from stuck bottom hole assemblies. See also REPLACEABILITY. SHOCKS Large and sudden, “instantaneous” forces applied to the BHA, and characterized by a relatively wide frequency band. Shocks are often associated with either resonant vibrations (accumulating large amounts of energy) or chaotic motion of the BHA. Accelerometer sensors are often used to monitor the severity and frequency of axial, lateral and tangential shock loading on an MWD tool in order to help the driller adjust surface drilling control parameters (e.g. rpm and hookload) to reduce the magnitude and frequency of destructive shocks. See also VIBRATION. SIDETRACK The drilling of a new and different hole from an existing wellbore.

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STABILIZER A bladed device that is used to eliminate vibration, centralize and prevent differential sticking of the bottom hole assembly, and to control the directional tendencies of the drilling process. The diameter of some stabilizers can be controlled by adjusting surface drilling parameters. STANDPIPE A pipe used for drilling fluid circulation that extends part the way up the derrick to a height suitable for attaching to the rotary hose. TALLY A record of the drillpipe, drillcollars, tubing or casing installed in a well containing the length of each joint, the number of joints, and the overall length of the string. TELEMETRY TYPE MWD signals are transmitted in real time either through the fluid in the borehole and casing (mud pulses), or through the earth formations (electromagnetically). MWD signals are either amplitude or frequency modulated. The type of drilling fluid (compressible or incompressible) and the conductivity of geological formations may dictate the appropriateness of one telemetry type or another. The type of telemetry affects data rate, the depth at which an MWD system can transmit in real time back to the surface, and various operational procedures. UTM COORDINATE SYSTEM The UTM (Universal Transverse Mercator) system is a convention for transforming a portion of the curved surface of the earth onto a flat plane surface of grid rectangular (x-y) coordinates. The grid system is designed for the identification of locations between the latitudes of 80 degrees south and 84 degrees north. VIBRATION Repeatable (quasi-harmonic) motion of the drillstring, MWD tool or other drillstring components, characterized by relatively narrow frequency bands. Vibration is often caused by resonant phenomena or driven energy sources (e.g. mud motors). See also SHOCKS. VISCOSITY The property of a substance offering internal resistance to flow; a measure of the degree of fluidity. Viscosity is defined as the ratio of the shear stress applied to a fluid divided by the shear rate resulting from the shear 2 stress application. If the shear stress is expressed in dynes/cm and the shear rate is expressed in reciprocal seconds, the viscosity would be calculated in poise. WHIRL An excentered rotation of the center axis of the drillstring in the borehole, induced most usually by either the compressive bending or the rotational mass imbalance of drill collars. Depending upon the frictional forces acting at the borehole wall, and upon the severity of the bending forces, whirl may manifest itself in the same direction as (forward whirl), or in the opposite direction as the rotation of the drillstring (backward whirl). Whirl can also be instable, transitioning between forward whirl and backward whirl states in a chaotic manner. YIELD POINT An additional thixotropic measurement of the mud, which is the resistance to internal fluid flow measured as stress.

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MWD Operational Manual

Conversion table

API unit

x Factor

ft

x 3.048

E-01

=m

ft/hr

x 3.048

E-01

= m/hr

psi

x 6.894757

E+00 = kPa

ppg

x 1.198264

E-01

°F

= Metric

= g/cm3

(°F-32) / 1.8 E+00 = °C

Ton

x 9.071847

E-01

= Mg

in.

x 2.54

E+00 = cm

cycles/sec

x 1.0

E+00 = Hz

lbs (force)

x 0.444822

E+00 = daN

lbs (mass)

x 0.453592

E+00 = kg

ftlbs

x 0.135582

E+00 = daNm

US gal

x 3.78533

E+00 = liters

US bbl

x 0.158984

E+00 = m3 or kL

psi/ft

x 22.62

E+00 = kPa/m

Table 1 - SI Metric Conversion Factors

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MWD Operational Manual

APPENDIX 1

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