Company OverviewPathFinders core business lies in Logging-While-Drilling (LWD) and Measurement-While-Drilling Services (MWD), Directional Drilling Services and Downhole Drilling Motors.

We are one of a few companies worldwide that currently has the technological capability to offer a full comple-ment of LWD products and services. LWD tools provide real-time data about the physical properties of downhole formations. In addition to indicating the possible presence of hydrocarbons, this data also assists in improving drilling performance.

Before the introduction of LWD technology, well formation data were typically obtained using open hole wireline tools where in-formation can only be obtained after the well has been drilled or during the drilling process if drilling is halted and the drill string is removed from the well. An advantage that LWD has over tra-ditional open hole wireline logging is that costs are reduced be-cause the LWD tools accompany the drill string and downhole data is provided during drilling operations in real-time. LWD technology uses real-time formation information to assist in im-mediate decision making to either alter the path of the wellbore to a point in the formation which, when compared with previ-ously obtained wireline data, provides for enhanced recovery of oil and natural gas.

We also offer measurement-while-drilling (MWD) products and services, which use downhole tools to help locate and direct the toolstring to the intended target. This capability is particu-larly advantageous when drilling directional (non-vertical) wells, which represent an increasing percentage of overall drilling ac-tivity. In order to drill a directional well, the driller must be able to determine the precise direction the drill bit is moving during the drilling operation. MWD tools assist the driller in making this determination by transmitting data to the surface enabling the driller to adjust the drilling path as necessary during the drilling process.

Our directional drilling services have grown from select areas internationally to include all of North America. Direc-tional drilling involves skilled personnel directing the wellbore along a pre-determined path to optimally recover oil and natural gas from a reservoir. These services are used to more accurately drill vertical wells and to drill deviat-ed or directional wells (which deviate from vertical by a planned angle and direction), horizontal wells (sections of wells drilled perpendicular or nearly perpendicular to vertical) and extended reach wells (deviated over extended distances).

We are a supplier of downhole drilling motors and a manufacturer of their components and replacement parts. PathFinder Drilling Motors product line consists of a wide range of sizes of downhole drilling motors ranging from 3 inch to 11 inches in outside diameter for use at various drilling depths and downhole environments. The components of the drill motor are designed to operate at various speeds and torque levels and to withstand severe environmental conditions such as high temperatures, hard rock and abrasive drilling fl uids.

Please visit PathFinders website www.PathFinderLWD.com for latest information about our products and services.

Figure 1: PathFinder PathMaker rotary steerable tools .

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Tools, Processing & ServicesWe have created a full range of state-of-the-art Directional Drilling and M/LWD technology and services to sup-port any drilling project - off shore, onshore and in all hole sizes. From motors, rotary steerables, and a whole family of LWD tools featuring a modular design allowing BHA fl exibility such as our Quad Combo, to our state-of-the-art LWD surface computer and software packages and Formation Analysis Services, PathFinders tools off er a unique downhole reprogramming protocol providing a drilling package that can be changed to meet the dynamic needs of todays drilling environments.

Please refer to tool spec sheet and PathFinder website for more details. http://www.PathFinderlwd.com/services/

2.1. Directional Drilling2.1.1. PathFinder Drilling Motors (PDM)

PathFinder Drilling Motors, Inc., which includes Dyna-Drill Motors, was established in April of 1991 with the pur-pose of supplying the oil and gas industry with a series of high quality and dependable downhole drilling motors on a sales, lease, or rental basis. PDM motors have been a major player in all areas of the world.

Although diff erent sized motors have diff erent performance characteristics, they share the same basic components:

- Top Sub - Catch Mandrel - Power Section - Power Transmission Coupling - Fixed or Adjustable Bent Housing - Bearing Pack Assembly - Bit Box - Near-Bit Stabilizers

Figure 2 illustrates the major components of our drilling motors.

The TOP SUB has a dual function. It is used as a cross over between the motor assembly and the drill string. It also functions as part of the catch system by providing the seat for the catch mandrel.

The Rotor Catch Mandrel is incorporated in the design of PDM mo-tors as a retaining device. Its function is to minimize the possibility of losing motor components in the hole in the unlikely event that an external connection breaks or backs-off . It is also designed to communicate a possible connection failure to the surface via a se-ries of pressure signals. To recognize these signals, it is important to understand how the Rotor Catch Mandrel behaves under normal and distressed conditions.

Figure 2: Major Components ofPathFinders Drilling Motors.

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The Catch Mandrel is attached to the top of the rotor by a threaded connection. The fl ow channels around the mandrel are sized to minimize the pressure losses across the catch mechanism. The upset section of the catch is positioned inside a cavity within the Top Sub. This cavity provides the seat for the catch if or when an external motor connection fails. Under normal operating conditions, the catch simply rotates with the rotor without any substantial load being applied to it. Figure 3-left illustrates the catch under normal operating conditions.

Figure 3 shows the catch position after a connection failure. There are two basic modes of connection failure: connection breakage and connection back-off . The catch behaves diff erently under each condition. If an external motor connection is severed, with motor on-bottom, a sudden loss of pressure occurs. Picking the motor off -bot-tom will seat the catch resulting in off -bottom pressure increase. The increase in pressure can range from a few hundred psi to several hundred psi, depending on the fl ow rate and mud properties. As soon as the motor is set on bottom, the catch will unseat itself and relieve the pressure. This pressure fl uctuation is indicative of a possible connection failure.

If the mode of failure is connection back-off , two scenarios are possible. If the connection separates completely, the pressure signal will be as previously described. If the catch seats itself before the joint is totally separated, then setting the motor on-bottom will not unseat the catch. The rotation of the drill string might screw the connection back together and relieve the ex-cessive pressure.

The POWER SECTION uses what is known in the industry as Positive Displacement power section. Its function is to convert a portion of the hydraulic energy of the drilling fl uid into me-chanical horsepower. The components comprising the power section are the rotor and the stator. The rotor is a long and spiral shaft, designed to fi t inside a corresponding stator. It is manu-factured from a solid bar of stainless steel and plated with hard industrial chrome or tungsten carbide. The chrome or tungsten carbide is intended to protect the parent metal against corro-sion and wear while reducing the friction between the rotor and the stator. In high-fl ow applications, PDM rotors can be jetted to divert the additional fl ow to the bit.

The stator is the non-rotating member of the power section. It is made out of a seamless, heat-treated tube, lined with an elastomer (rubber) lining. The internal cavity of the liner has a spiral geometry designed to accept a rotor of compatible geometry and size. In a Positive Displacement power section, the rotor always has one less lobe than the stator. When the rotor is inserted inside the stator, a certain number of cavities are formed along the length of the power section. The interference between the rotor and the stator lining seals these cavities from each other. During the drilling operation, high pressure drilling fl uid is forced into the cavities, causing the rotor to turn inside the stator.

Figure 3: The cross-sectional view of the rotor and the stator profi le with diff erent lobe ratios.

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Power sections are categorized by their size, rotor/stator lobe ratios, and the number of stages (stage in a power section is defi ned as the distance, measured parallel to the rotor axis, between two corresponding points of the same spiral lobe, i.e. lead length of the spiral). Figure 4 shows the cross-sectional view of the rotor and the stator profi le with diff erent lobe ratios.

There are a few rules of thumb, which might be benefi cial in the selection and operation of any PDM motor:

Optimum completion of a drilling project relies heavily on the proper selection of the stator elastomer compound. The main factors to consider are the maximum downhole temperature, mud type, mud additives, and any harm-ful chemicals which might be encountered during drilling. Given enough forewarning, testing of the drilling fl uid under simulated downhole conditions can be conducted before the drilling tools are assembled. Test results are helpful to determine the optimum elastomer for the application.

As mentioned in earlier sections, PDM off ers several diff erent stator elastomer compounds. These diff erent com-pounds react diff erently when exposed to elevated temperatures and the various chemicals present in drilling fl uids. The standard elastomer is a nitrile based rubber NBR suitable for use with water-based and low temperature oil-based drilling fl uids. This rubber is suitable for use in wells with temperatures in excess of 270 F with the proper sizing and fl uid compatibility. The standard nitrile stators are the most common and cost eff ective option for most drilling conditions. An additional nitrile elastomer is available in certain models which is more rigid and resilient. This NBR-HR elastomer can deliver a minimum of 50% more power than the standard NBR with the proper drill-ing parameters.

In drilling applications where the drilling fl uid is less typical and the tem-perature is elevated, the highly saturated nitrile elastomer HSN may be the optimum choice. The highly saturated type elastomer is formulated for greater chemical resistance, especially at higher temperature. HSN elastomer is the best suited elastomer for oil-based and most synthetic based drilling fl uids.

Some motor sizes have the option of a metal reinforced or uniform elasto-mer thickness stator equipped power section. The uniform or even elas-tomer stator compared to a conventional stator can be seen at Figure 5.

Figure 4: The corss-sectional view of the rotor and the stator profi le with diff erent lobe ratios.

Figure 5: The uniform or even elastomer stator compared to a conventional stator.

The rotational speed of the rotor is proportional to the rate of fl uid fl ow through the power section. The generated torque is proportional to the differential pressure across the power section. The torque gener ated is independent of the fl uid fl ow through the power section. Power sections with a higher lobe ratio typically generate more torque and have slower rotary speed than the ones with a lower lobe ratio. For example, a 9 5/8 motor with 3:4 lobe ratio will rotate the drill bit at a higher RPM and will have less output torque per stage than a 9 5/8 motor with 4:5 lobe ratio. An increase in the number of stages will proportionally increase the

output power and torque at the same fl ow rate.

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The metal reinforcement of the elastomer profi le provides a structural reinforcement of the elastomer profi le al-lowing its seal against the rotor to operate at signifi cantly higher pressure diff erential than conventional stators. This higher pressure diff erential produces a higher operating and stall torque. The higher pressure seal between the rotor and the stator assures a more steady speed of operation than a conventional power section.

The metal reinforcement also provides a superior path for heat dissipation from the rotor and stator interface. This superior heat dissipation allows the metal reinforced stator to operate more reliably at elevated temperatures than a conventional power section. The smaller elastomer content of the metal reinforced stator also provides for a stator more resistant to aggressive oil and synthetic based drilling fl uids.

The POWER TRANSMISSION COUPLING is the link between the rotor and the bearing mandrel. It converts the eccentric motion of the rotor into the concentric rotary motion of the bearing mandrel or driveshaft. It also trans-mits the torque and the rotary motion of the rotor, generated by the power section, to the bearing assembly. The hydraulic down thrust of the rotor is also transferred to the bearing section through this member.

All PDM power transmission couplings are manufactured from a high grade of heat treated alloy steel. The working surfaces of the power transmission are sealed with a high temperature and pressure lubricant to assure optimum operation and reliability.

The FIXED or ADJUSTABLE BENT HOUSINGS contain the power transmission coupling and connects the stator housing to the bearing housing. Bent housings are available with fi xed and adjustable bends. Fixed bent housings can only be confi gured at PDM facilities in angles ranging from 0 to 5.0 degrees depending on the motor model. The adjustable housings can be set to various bend angles at the rig site (see the appendix section of this hand-book for adjustment procedure). The magnitude of the adjustable bent housing bend angle ranges from 0 to 3.0 degrees. This bend of the fi xed or adjustable bent housing gives the motor its steering capability. The fi xed and adjustable bent housings are manufactured out of premium grade high strength alloy steel. Their contact surfaces with the formation are hard-faced to minimize wear while drilling.

The BEARING PACK ASSEMBLY contains the necessary components to transmit the rotary drilling motion to the drill bit and transmit the drilling forces from the Bottom Hole Assembly (BHA) to the drill bit. The main compo-nents of the bearing pack assembly are the bearing mandrel or driveshaft, thrust and radial bearings. The bearing mandrel or driveshaft is a bored, long shaft designed to transmit the power (torque and rpm) to the drill bit. It also channels the drilling fl uid to the bit. It is manufactured out of a high grade of alloy steel that is forged and heat-treated for strength and toughness.

The thrust bearings are designed to sustain the applied weight to the drill bit while on-bottom. They are also capable of bearing the downward hydraulic thrust load of the rotor while circulating off -bottom or drilling with underbalanced bit weight. Depending on the motor model, the thrust bearings may consist of a unique tool steel ball bearing design that is precision made and enables the same set of bearings to carry the on-bottom as well as the off -bottom load. This important feature increases the number of bearing races within the limited available space and increases the thrust load capacity and the life of the bearing pack. An alternative thrust bearing design utilized in some models consists of high grade Polycrystalline Diamond Compact (PDC) inserts similar to those used on PDC drill bits. These PDC inserts provide a high capacity and extremely wear-resistant thrust bearing for applications where shorter tool length or extra longevity is required.

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The radial bearings rigidly support the bearing mandrel inside the bearing housing and transfer the radial forces

generated during drilling to the housings and the rest of the BHA, while assuring that the driveshaft is aligned and

concentric with the axis of the bearing housing. The radial bearings are constructed from specialized tungsten

carbide components to provide optimum life and reliability. The design of the tungsten carbide radial bearings

also precisely meter the amount of drilling fl uid that fl ows through the radial and thrust bearings for cooling of the

bearings. This assures the optimum drilling fl uid fl ow through the driveshaft and out to the drill bit.

The bearing pack assembly of the PathFinder motor is one of the few designs that also incorporates a driveshaft safetycatch feature to minimize the possibility of leaving the drill bit in the hole in the unlikely event the driveshaft breaks or backs-off . Figure 6 illustrates the normal running position of the driveshaft and the driveshaft catch on the left and the engaged position of the catch on the right. If the driveshaft breaks or backs-off , a precision low stress upset or ridge on the lower portion of the driveshaft engages a split ring contained within the lower portion of the bearing housing preventing the driveshaft from exiting the bearing pack. A substantial decrease in the off -bottom pressure drop on the surface will signal an incident has occurred so that appropriate action can be taken.

The BIT BOX is an integral part of the bearing mandrel. Its out-side diameter is sized to accept a specifi ed box connection. While all the external components of the motor are station-ary relative to the drill string, the bit box is the only external component which has a rotary motion independent of the ro-tational speed of the drill string. The drill bit is screwed directly into the bit box.

NEAR-BIT STABILIZERS are available with removable or integral stabilizers. The removable stabilizers are screwed on the bearing housing. Occasionally, certain clients wish to have the option of installing diff erent stabilizers on the motor at the rig site to alter the directional performance of the motor. In that case, the motor and the stabilizer(s) can be shipped separately and a protective sleeve protects the external threads of the bearing housing.

In todays cost-conscious oil and gas environment, companies and operators recognize the positive contributions downhole drilling motors can make to their bottom-line. The application of downhole drilling motors are no lon-ger limited to conventional drilling, but has expanded to other areas such as:

PathFinder Drilling Motors off ers a wide variety of motor confi gurations, bit speeds, fl ow ranges, and power out-puts to suit your particular need. Our state-of-the-art drill motor is designed to exceed the load capacity of any available drill bit in the industry today.

Normal OperatingPosition

ActivatedPosition

Bit Box

Figure 6: The normal running position of the drive-shaft and the driveshaft catch (left) and the engaged position of the catch (right).

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2.1.2. PathMaker Rotary Steerable ServicePathFinder Energy Services PathMaker Rotary Steerable System is designed for accuracy, reliability and versatil-ity and has set new standards for rotary steerable in the global marketplace. The specifi c design of our PathMaker System enables successful performance in all environments, from extremely soft to very hard rock, from water-based to oil-based muds, and from in-gauge to over-gauge holes.

Tool DesignThe PathMaker Rotary Steerable System (available for 8 16 hole-sizes) is designed with three hydraulically actuated pads housed in a steering unit. While drilling, the pads provide a constant contact force with the wellbore to maintain the steering unit stationary. The toolface and dogleg severity (DLS) are controlled by proportionally offset-ting the steering unit from the centerline of the hole. This proportional control enables the tool to drill a constant curve resulting in superior borehole quality and reduced torque and drag.

The PathMaker System is the only Rotary Steerable System (RSS) currently available on the market that provides a Real-time Pad-Contact Caliper (RPCCTM) measurement while drilling. The caliper measurement, taken from the physi-cal pad positions, gives the directional driller real-time caliper information within fi ve feet of the bit. This information gives real-time feedback on the borehole condition and allows surface parameters to be optimized so as to ensure consistent and accurate directional response.

To date, the PathMaker System has been deployed worldwide ranging from vertical to horizontal wells in a vari-ety of drilling environments. With the 8 tool capable of 6 DLS and the 6 tool capable of producing 10 DLS, the PathMaker System is suitable for all conventional wells being drilled today. The use of underreamers or fi xed cutter reamers allows a variety of hole sizes to be drilled up to 17 .

Tool Confi gurationsDepending on the drilling application, the PathMaker System can be confi gured as either Point-the-Bit or Push-the-Bit. The point system uses a near-bit stabilizer to provide a fulcrum point to tilt the bit in the desired direction. The push system uses the steering unit to push the bit directly sideways resulting in higher DLS making it more suitable for shallow washed-out applications and open hole sidetracking.

In push-the-bit mode (Figure 7 a), the steering unit is used to push-the-bit sideways in the desired steering direction. In point-the-bit mode (Figure 7 b), a near-bit stabilizer is used to act as a fulcrum point and tilts the bit in the desired direction. There are advantages to both systems depending upon the application. Typically, the system runs in push-the-bit mode if hole washout is expected, or if higher doglegs are required.

In situations where higher RPM is required at the bit, or where casing wear is a concern, the PathMaker System can be powered with a PathFinder mud-motor. The motor-assist option is ideal for performance drilling where maximum ROP is required.

Figure 7a: Push-the-bit Confi guration Figure 7b: Point-the-bit Confi guration

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The PathMaker System can be integrated with any of PathFinders MWD/LWD suite of tools. For lower-cost vertical applications, the PathMaker V System can be run stand-alone in Automated Vertical Control Mode.

Additional FeaturesDownlink of steering commands to the PathMaker System is achieved using a non-intrusive patented RPM pro-gramming method. No special surface equipment or rig-up is required. The system relies solely on RPM and fl ow commands from surface. The downlink sequence has been designed to allow commands to be sent while on-bot-tom drilling ahead.

Automated closed-loop control for maintaining inclination and azimuth is another feature available on the Path-Maker System to optimize drilling effi ciency. This mode allows the tool to lock onto the current inclination and/or azimuth, providing automated control without the need for human interaction. The Target Inclination and Target Azimuth values can be changed using a downlink if the well path or drilling target positions are moved for any rea-son. This automated feature is typically used for long tangent sections or laterals to reduce downlink commands.Lateral and axial vibration severity, and stick-slip severity are monitored using the onboard Real-Time Stick-Slip and Vibration Detection (RSVDTM) system. Severity levels are transmitted in real-time to surface allowing the di-rectional driller to change drilling parameters if necessary to reduce downhole vibration and stick-slip.

A gamma-at-bit feature is available for the 6 tool size. PathFinders PZIG (PayZone Inclination Gamma) technol-ogy can be integrated into the near-bit stabilizer.

The PathMaker Rotary Steerable System has proven successful on a steady string of wells from North America land, Gulf of Mexico, North Sea, and Mediterranean Sea. It is the practical choice for your next directional well.

2.2. MWD2.2.1. Directional Sensors2.2.1.1. Measurement Principle

The PathFinder directional sensor is an integral part of the directional tools (HDS), the PayZone Inclination Gamma tool (PZIG) and the Array Wave Resistivity tool (AWR). Our tools use proven triaxial directional sensors and store raw data for all surveys in downhole memory. Computed surveys or raw data can be transmitted to the surface in real-time. Battery power allows survey acquisition with or without mudfl ow. Triaxial magnetic azimuth correction (MAC3D) is available. Where magnetic interference prevents the use of conventional magnetic directional sen-sors, PathFinder is able to provide the gravity MWD.

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2.2.1.2 Tools2.2.1.2.1 HDS ToolsHigh-speed Directional Survey (HDS) is the primary modular component for the PathFinder MWD services. Figure 8 shows the HDS-1L tool which has a proven triaxial directional sensor. The raw data for all surveys are stored in downhole memory. Computed surveys or raw data can be transmitted to the surface. Battery power allows survey acquisition with or without mudfl ow. Triaxial magnetic azimuth correction is available.

The Gravity MWD system is used where magnetic interference prevents the use of conventional MWD tools. Figure 9 shows the PathFinder Gravity MWD system HDS-1G, which employs dual accelerometers to compute azimuth and inclination.

2.2.1.2.2. PZIG ToolPathFinders PayZone Inclination Gamma (PZIG) tool provides near-bit inclination and gamma measurements. Please refer to section 2.2.1.2.2 for more information.

Figure 8: HDS-1L Tool. Note the mud pulser at the top of the tool, vibration sensor, directional sensor and gamma sensor at the middle of the tool.

Figure 10: Gyro HDS-1 Tool.

Figure 9: HDS-1G Tool. Note the dual directional sensors

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The Gyro HDS-1 system off ers considerable time savings over conventional wireline gyros. After drilling beyond magnetic interference, the Gyro module can be deactivated and drilling continued with the HDS-1 MWD system. Figure 10 shows a picture of Gyro HDS-1 tool.

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2.2.1.3. Advanced Processing2.2.1.3.1. Tri-Axial MWD Survey Correction (MAC3D)Inaccuracies in MWD survey data produce uncertainties in the position and TVD of ev-ery point in the wellbore. Magnetic azimuths from MWD sensors are aff ected by magnetic fi eld distortion from many sources, such as the drillstring even when non-magnetic col-lars are used. These induced errors accumu-late over the length of the well and may aff ect bottom hole location calculations. MAC3D is a Measurement-While-Drilling (MWD) survey error reduction technique. An advanced tri-axial magnetic correction routine is used to reduce MWD survey ellipse of uncertainties. MAC3D identifi es and corrects for the eff ects of axial and cross-axial, permanent and in-duced magnetic infl uences. When used in conjunction with PathFinders sag correc-tion routine, Gravity MWD, Well Interference Navigation and Ranging (WINNER) tech-nique, gyro becomes redundant, Figure 11.

2.2.1.4. ApplicationsDirectional measurement is the funda-mental measurements used in well drill-ing. It is widely applied in directional drilling, kick-off /drill without a gyro to reduce costs and save rig time. It is also used in casing exits, and collision avoid-ance.

Passive Ranging is a technique used to detect nearby and adjacent wells using conventional MWD tools transmitting raw magnetic data. Applications where Passive Ranging is typically used in-clude:

Well Avoidance. Relief Well Drilling. Well Twinning (Figure 12).

Figure 11: Graph from a recent well showing MAC3D azimuths directly compared to two diff erent types of gyro tool.

Figure 12: PathFinders passive ranging technique helps EnCana to drill SAGD twin wells in heavy oil reserves.

Please refer to Figure 28 and Figure 29 for log examples showing good agreement between dynamic inclinations and MWD survey inclinations.

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2.2.2. BHA Vibration 2.2.2.1. Measurement PrincipleThe BHA vibration monitor is integrated in PathFinder HDS-1 MWD platform (Figure 8). The vibration sensor contains a single-axis accelerometer mounted in the lateral plane, along with various fi ltering circuitry. Output data from the accelerometer is sampled digitally and processed by a microprocessor unit. The output is in counts of shock above 5G per second. Once sustained BHA vibration is detected, the relevant personnel off shore must be informed without delay.

2.2.2.2. ToolsThe vibration monitor is integrated in PathFinder HDS-1 MWD platform (Figure 9).

2.2.2.3. ApplicationsBHA vibrations can aff ect the drilling performance and break the downhole equipment. LWD log quality can also be aff ected by the vibration. Driller can use BHA vibration monitoring measurement to adjust drilling parameters to optimize drilling performance and protecting equipments and ensure LWD log quality.

2.2.3. Borehole and Annular Pressure2.2.3.1. Measurement PrincipleIt is critical to measure annual pressure and drillpipe pressure during the drilling process. The tool measures the drillpipe mud pressure and annual mud pressure and temperature. The measurements are transmitted to the surface real-time and the Equivalent Circulating Density Measured (ECDM) is calculated using the following equation.

ECD = APd / (.0519*TVD)where:ECD: Equivalent Circulating Density (lbs./gal)APd: Dynamic Annular Pressure (PSI)TVD: Pressure sensor depth in true vertical depth (ft) 0.0519: Conversion factor (gal/lbs./ft.)

2.2.3.2. Tools 2.2.3.2.1. Dynamic Pressure Module (DPM) Tool

Figure 13: Schematic of Dynamic Pressure Module (DPM) Tool

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The DPM tool (Figure 13) uses two independent pressure transducers to continuously measure annulus pressure and temperature and internal pipe pressure and temperature. The Equivalent Circulating Density Measured (ECDM) is the most accurate measure of the pressures exerted on the formation and comes from a direct downhole annular pressure measurement. The drill string pressure (DPPR), annular pressure (ANPR) and annular temperature (TDMP) are measured downhole and transmitted in real-time.

2.2.3.3. Applications The Applications of Dynamic Pressure Module Tool include: Real-time ECD monitoring. Minimize Reservoir & Borehole Damage. Detects overloading of cuttings in annulus. Detect well kicks. Aides in well kick control. Optimizes drilling & mud motor performance. Determines problem areas within the borehole. Provides ability to monitor and adjust mud properties. Poor hole Stability and cleaning. Lost circulation. The leak-off test. Fracture initiation and propagation. Causes of lost circulation. Hole collapse. Hole cleaning. Kick detection. Motor / sliding performance.

2.2.3.3.1. Borehole pack off detectionPoor hole stability and cleaning is the greatest cause of drilling downtime. It can potentially be more expensive than normal drilling operations due to losing bottom hole assemblies and M/LWD tools, losing mud and ex-pensive additional additives, unscheduled personnel and equipment movements, formation damage, and stress on equipment and people. Figure 14 shows an example DPM log of packing off . The log annotations provide the answers to interpreting this DPM log. An elevated ECDM was seen on the DPM log. Average size of 2 pressured shale was coming over the shale shakers. The well is fl ow-ing at a lower rate. The driller pulled three stands of pipes out of bottom and reamed back to bottom, the ECDM dropped to normal value. This pack-off is due to shale sloughing.

Figure 14: Example of packing off .

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2.2.3.3.2. Well Kick Detection/Control

DPM log can aid in well kick detection/control. When there is an infl ux of gas, there is actually little eff ect on the DPM log since eff ects of gas cut on mud is greater on surface than downhole because gas is compressible and expands as it rises. If a kick is detected on the DPM log, it is usually a very serious problem and requires well control. Figure 15 shows that while circulatingat the casing shoe, ECD began to decrease due to an infl ux of gas. The driller tripped back to bottom (9 stands) to circulate and monitor the well. In this scenario, the monitoring of ECD at the casing shoe prevented a well control situation and saved rig time.

2.2.3.3.3. Lost Circulation DetectionLost circulation is a common problem in naturally ex-isting high permeability or fractured formations. Un-consolidated formations, fi ssures / fractures, unsealed fault boundary, vuggy / cavernous formations can cause lost circulation. Poor hole cleaning may also be the reason for lost circulation. Increase cuttings vol-ume weighting up the mud, pack-off and increased viscosity are all possible reasons for lost circulation. Figure 16 shows an example of lost circulation due to poorly conditioned mud. The highlighted annota-tions shows the well started losing synthetic oil based mud due to high ECDM. The driller had to pull out of the hole to change the BHA (lay out DNSC and CLSS due to mud problems and fear of getting stuck/los-ing tools downhole) and condition mud. On this well, the viscosity exceeded 100 sec/qt and the high ECD caused by the high viscosity mud exceeded the Leak-off Test (LOT) pressure. An increase in ECDM is also due to rotational eff ects. Very soon after rotation started, the formation started taking fl uid (50 bbl loss). The company who drilled this well lost four days of drill-ing time to control the mud viscosity. The DPM logs were used by the customer to negotiate a $0.5 million discount off the mud bill. Once the viscosity was un-der control, the ECD dropped 0.5 PPG (from Run 4 to Run 5).

Figure 15: Example-DPM log helped detect a kick and prevented a well control situation

Figure 16: DPM log example of lost mud circulation due to poorly conditioned mud.

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2.2.3.3.4. Surge/Swab Pressure Control

Surge / swab can cause downhole pressure changes due

to high pressure transients. High swab pressures can lead

to mechanical collapse. High surge pressure can fracture

formation and loosen blocks. Figure 17 shows the eff ect

of pipe speed on ECDM. On Run #3, the pressure surges

from tripping to bottom too fast caused mud losses when

on bottom. Run #4 after the company representative saw

the DPM log, showing pipe speed and ECDM surge, the

trip speed was slowed down.

2.2.3.3.5. ECDM Monitoring During Sliding and Rotation

When the drill pipe rotates, the mud carrying capacity is

increased. Cuttings tend to be thrown into a higher ve-

locity region of the annulus by centrifugal forces. Pipe

eccentricity is reduced. Figure 18 shows a DPM log ex-

ample with a sharp increase in ECDM when the pipe be-

gins rotating after a long slide interval. The cuttings are

re-suspended causing an increase in ECDM (also note the

increase in ROP while rotating; this will add cuttings to

the annulus at a higher rate). During sliding, the fl ow is

laminar. The fl ow regime changes to turbulent with the

rotation of the pipe. Turbulent fl ow also increases the

amount of cuttings in suspension. The ECDM increases

as a result.

Figure 17: DPM log example showing surge and swab pressure on ECDM at diff erent pipe speeds.

Figure 18: DPM log example showing increased ECDM when increased cutting suspension with drill pipe rotation.

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2.2.3.3.5.1. Riserless Drilling

In a deepwater riserless drilling setup, Mud Weight-iIn

(MWI) does not represent the Equivalent Mud Weight

(EMW) in the hole. Mud Weight Calculated (MWC) is

used as a comparison to ECD to assist in the interpreta-

tion. Figure 19 shows a DPM log display in a riserless

drilling setup. Note the large diff erence between MWI

and MWC. This example is tripping out of the hole. No-

tice the eff ect depth has on MWC and ECDM.

2.2.3.3.6. Safe Operating Window

To design and drill the optimal well we need to know : What are the formation pore pressures? What are fracture and collapse pressures? What are the stresses imposed on the formation? Are we adequately cleaning the hole?

The DPM service can be used to signifi cantly reduce these un-certainties. Figure 20 shows a typical example of mud weight window for a stable wellbore with diff erent borehole deviations. With in the information provided by DPM log, the mud program can be optimized to achieve the optimum drilling performance and maintaining a stable wellbore. Figure 21 shows a typical rock mechanical analysis plot. Track 1 shows the gamma ray and caliper curves. Track 2 shows a crude caliper image using two identical but opposed caliper curves. Track 3 shows the minimum and maximum borehole pressure curves delineating a green area of stable wellbore conditions, together with pore-, mud-, and overburden pressures. Track 5 shows lithology computed using a standard deterministic (or any other) volumetrics program.

The critical minimum pressure is the pressure at which the formation fails due to shear failure, in other words it indicates the sanding potential of the formation. When the pressure in the wellbore drops below this critical mini-mum pressure, the formation will have a sanding problem, during drilling, swabbing or production. The fracture closure pressure indicates the borehole pressure at which, existing but closed, natural fractures will be re-opened, resulting in mud loss, and at which the hydraulic fracturing process may begin. The shaded area between these two curves defi nes the mechanically stable wellbore pressure conditions.

Figure 19:Example DPM log in a riserless drilling setup.

Figure 20: Wellbore Failure and Borehole Deviation.

15

This type of log analysis can be used to design hydraulic fracturing jobs; it provides the stress profi le information for 3-D fracture design programs. The data can be used in completion decisions such as frac and pack or gravel pack completions. They can be used in well planning to design deviated or extended reach and horizontal wells. Finally, LWD rock mechanical analysis can be done in real-time at the wellsite to help assist with decisions re-garding mud weights and casing points.

Figure 21: Wellbore stability analysis plot.

2.2.4. Joint End Locator (JEL)2.2.4.1. BackgroundThe objective of the MWD Joint End Locator (JEL) is to mill win-dow avoiding casing joint ends. We can use the MWD JEL to de-tect the joint ends and set the whipstock, the advantages being that no wireline casing collar locator (CCL) tool is required, no bridge plug is required and no additional downhole equipment is required. It uses a standard MWD Directional tool.

Using current techniques, the CCL tool detects the casing collars, a bridge plug is set, the MWD tool orients the whipstock, and the window is milled. This requires two trips. By using MWD JEL, the JEL detects joint ends, orients and sets the pack-stock, and then the window is milled. This requires only one trip. No CCL wireline run is required; hence, saves time and thus saves money.2.2.4.2. Basic TheoryCasing collars and casing joint ends are found from magnetism forced into the casing during MPI. The MWD JEL tool detects the magnetic fl uctuations and can hence detect the joint ends. The surface system does this by calculating the Dynamic Total Magnetic Field from EX and EY (and EZ if transmitted). By then plotting TMF against depth on a log, the casing end joints can be clearly seen (Figure 22). A whipstock symbol has also been added so that the user can clearly see the current estimated whipstock location in relation to the casing joints.

Figure 22: JEL locates casing joint and replaces whipstockat its optimum location.

16

2.3. LWD2.3.1. Gamma Ray (GR)

2.3.1.1. Measurement Principle

Figure 23: Gamma ray scintillation detector.

2.3.1.2. Tools

2.3.1.2.1. Universal Gamma Sensor (UGS)The PathFinder gamma ray tool is an integral part of the directional tools (Figure 8, Figure 9 ) and the CWR and AWR resistivity tools (Figure 43, Figure 44, Figure 45). It is available with the retrievable directional tools. The sen-sor is a sodium iodide (NaI) crystal used to detect naturally occurring gamma rays. The GR tools measure the GR detection rate in counts per second, which is converted to API units by the calibration gain factor.

2.3.1.2.2. PayZone Inclination Gamma (PZIG)

PayZone Inclination Gamma (PZIG) is PathFinders near-bit gamma and inclination tool. It is designed to operate as two separate subs (Figure 24). Lower sub (LXM) acquires data and transmits data to upper sub via EM frequency and upper stub (UXM) provides communication to MWD/LWD telemetry (Figure 26). The PZIG can accomodate fl exible BHA design and is compatible with any motor. Since it is not integrated into the motor, the cost is re-duced. PZIG provides the closest to the bit sensor off sets available in the industry and is the only tool to provide both gamma and inclination at-bit. Table 1 shows the gamma and inclination sensors distance-to-bit.

The Gamma ray (GR) log is a measurement of the formations natural radioactivity. Gamma ray emission is produced by three radioactive series found in the earths crust: Potassium (K40), Uranium series and Tho-rium series. GR is probably the most wide-ly used measurements for lithology iden-tifi cation, shale volume calculation and correlation. PathFinders LWD gamma ray measurement using scintillation detectors to achieve improved effi ciency, resolution and repeatability compared with old Gei-ger Muller detectors. Figure 23 shows the scintillation gamma ray detectors.

10

0110100

0100010010011000100100010001100101001001001000

Figure 24: PayZone Inclination Gamma (PZIG) Tool

17

PZIG Advantages compared with Standard MWD GammaWhen a standard MWD GR tool recognizes a formation change, the bit is already about 35 feet or more out of the target zone (Figure 25). PZIG can recognize a formation change much quicker when the bit is nearing a bed boundary (Figure 26).

2.3.1.3. Advanced Processing

2.3.1.3.1. Gamma Ray Enhanced CalculationGamma ray measurement is aff ected by environment eff ect such as borehole and mud. The Gamma Ray Enhance-ment Calculations program is primarily intended to enhance the interpretability of gamma ray measurements in potassium-rich muds by removing the eff ect of the potassium. Standard environmental corrections are also performed. This program can also be used solely to make environmental corrections by setting the potassium content of the mud to zero. GR corrections depend on the tool type and size. Corrections for the GR measurement incorporated in the following tools are available:

HDS 4.75, 6.75, 8 and 9.5AWR 6.75, 8 and 9.5SAWR 4.75CWR 6.75, 8 and 9.5

In Figure 27, potassium chloride mud system was used in run 2, but not in run 1. The black curve represents the uncorrected GR for both runs. The shift in the GR curve to high values is obvious in the run 2 data. The red curve is the corrected gamma ray and we observe a smooth transition from run one to run two.

Tool size 4 6 11 20

Inclination distance - to-bit 22 31

Gamma Ray distance - to-bit

Table 1: PZIGTM gamma and inclination sensor distance-to-bit.

Figure 25: Standard MWD gamma ray is + 35 ft. from bit. When gamma recognizes formation change, the bit is already + 35 ft. out of zone.

Figure 26: PZIG gamma ray is 11 from the bit. When PZIG recog-nizes a formation change; the bit is nearing the bed boundary.

Figure 27: Gamma Ray KCL Correction.

18

2.3.1.4. ApplicationsGamma ray measurement is the most widely used log. It was widely used in lithology identifi cation, shale volume calculation and correlations.

2.3.1.4.1. PZIG Log ExamplesPZIG has been widely used in Coal Bed Methane (CBM), tight gas, shale gas plays.

The Benefi ts of PZIG include: Optimize wellbore positioning for accelerated production. Make better real-time decisions. Early bed boundary detection. Reduce uncertainty. Reduce well tortuosity and dogleg severity. Reduce cost.

Figure 28 shows an improved casing point selection using PZIG tool. Figure 29 shows PZIG tool helping to iden-tify drilling across a fault quickly to minimize the out-of-zone section. Please also note that the PZIG dynamic in-clination measurement while drilling has a very good agreement with the static survey inclination measurement.

Figure 28: PZIG Example 1. PZIG GR (NBGR) detects at-bit formation changes while the standard GR is still in shale. Casing point was selected with PZIG Gamma with-out concerns of sensor off set. While rotating at HZ, PZIG INC shows good agreement with the MWD survey inclina-tion.

Figure 29: PZIG Example 2. The driller drilled 4 ft through fault before recognizing the fault with PZIG GR while drill-ing at 175ft/hr. PZIG GR showed faulted above reservoir, slide down re-enter reservoir using both PZIG GR and INC. two more slides to prevent BHA from exiting bottom of zone. 3ft TVD zone of interest. While rotating at HZ, PZIG INC shows good agreement with the MWD survey inclination.

19

PZIG Application in Coal Bed Methane Horizontal Geosteering

Figure 30 is an example of a horizontal CBM well drilled with at-bit measurements WLD resistivity real-rime geo-steering. Detailed pre-well modeling was prepared in addition to real-time modeling while drilling. The model was constructed while drilling. The coal seam was encountered deeper than expected. However this was predicted by the onsite geosteering specialist utilizing the forward-modeling software, and the landing point of the planned horizontal well was adjusted to enter the coal seam at a measured depth of X475. The LWD resistivity measure-ments and the forward-modeling software were critical for making the decision to adjust the landing point while drilling. Deep-reading resistivity gave advanced warning that the coal seam would be encountered deeper than expected.

By using the combined at-bit gamma and PathFinders geosteering services, the customer was able to improve the in-zone section from 30% in previous wells, which was drilled with regular GR, to almost 100% in this well.

2.3.2. Resistivity 2.3.2.1. Measurement PrincipleThe basic operating principle of electromagnetic wave resistivity measurement was discovered and documented in the early 1970s [Gouillod and Levy, 1970], and fi rst applied to MWD in the early 1980s [Coope, Shen et al, 1984]. The techniques can be summarized as follows: A radio frequency (400kHz, 500 kHz or 1MHz, 2 MHz) electromag-netic wave is launched from a transmitter coil wound over the drill collar (Figure 31). The wave travels in the bore-hole and in the formation before being sensed by two receiver coils mounted on the same mandrel. The phase diff erence (degrees) and attenuation (decibels) observed between the two receivers is primarily related to the resistivity of the formation in the vicinity of the borehole (Figure 32). The measure point is the midpoint between the two receivers.

Figure 30: Real-time model of CMB horizontal well drilled with at-bit measurements, LWD resistivity and forward-modeling software.

20

Figure 31: Cartoon of electromagnetic wave propagation resistivity measurement operating principle.

Figure 32: Cartoon of amplitude and phase shifting measurement of electromagnetic wave propa-gation resistivity tool.

21

2.3.2.1.1. Phase and Attenuation Resistivity

Figure 33: Data fl ow of AWR apparent attenuation resistivity.

Figure 34: Data fl ow of AWR apparent phase resistivity.

The CWR and AWR tool feature a borehole compensation scheme similar to those implemented earlier in wireline acoustic and electromagnetic devices [Wharton et al, 1980]. The main advantages of this system are in the mitigation of borehole rugosity and tool tilt eff ects. It also compensates for any temperature related electronics drift. A further advantage of a borehole compensated design is the symmetrical response of the array, whereby a symmetrical bed with similar shoulders yields a symmetrical log response. The data fl ow of attenuation and phase resistivity are shown in Figure 33 and Figure 34 . The phase and attenuation measurement are converted to apparent resistivity value with dielectric assumptions. Figure 35 and Figure 36 shows the phase and attenuation resistivity conversion for CWR and AWR tools.

AMPLITUDE MEASUREMENTS

APPARENT ATTENUATIONRESISTIVITY

ATTENUATION = Amp near/Amp far

BOREHOLE COMPENSATIONATTENUATION = (Attenuation T1 * Attenuation T2) 1/2

PHASE MEASUREMENTS

APPARENT PHASERESISTIVITY

PHASE SHIFT = Ph near - Ph far

BOREHOLE COMPENSATIONPHASE SHIFT = (Phase Shift T1 +Phase Shift T1)/2

T1near, T1far, Tnear, T1farT2near, T2far, T2near, T2farT3near, t3far, T3near, T3far

T1, T1T2, T2T3, T3

T1T2T3

RDAHRMAHRSAH

T1near, T1far, Tnear, T1farT2near, T2far, T2near, T2farT3near, t3far, T3near, T3far

T1, T1T2, T2T3, T3

T1T2T3

RDPHRMPHRSPH

22

Figure 35: CWR response curves for interpreting phase and attenuation with dielectric assumption of =10

Figure 36: AWR response curves for interpreting phase and attenuation with dielectric assumption =5.0+108.5*Rt-0.35

2.3.2.1.2.Depth of Investigation and Vertical Sharpness

Diameter of Investigation (D.O.I.) is the diameter of the cylinder from which half of the measured signal emanates computed from the pseudo-geometric factors of the measurements. Figure 37 shows the defi nition used to derive the D.O.I of our tools as shown in Figure 38. Figure 38 and Figure 39 shows the diameter of investigation of AWR and CWR phase and attenuation resistivity measurements of diff erent spacings, respectively. The D.O.I depends on sensor spacing, frequency, attenuation/phase and most importantly on the resistivity of the formation.

Figure 37: Depth of Investigation.

23

Figure 38: Depth of investigation of (S)AWR attenuation and phase resistivities of diff erent spacing.

Figure 39: Depth of investigation of CWR attenuation and phase resistivities of diff erent spacing

Figure 40: Vertical sharpness.

24

Figure 41 shows the vertical sharpness of the AWR phase and attenuation resistivity measurements.

Figure 41: Vertical sharpness of AWR attenuation and phase resistivities for diff erent spacing.

Figure 42: Vertical sharpness of CWR attenuation and phase resistivities for diff erent spacing.

2.3.2.2. Tools2.3.2.2.1. Compensated Wave Resistivity (CWR) Tool The CWR tool is a dual spaced, symmetrically matched array, 2 MHz resistivity tool. The tool itself is approximately 27 ft long and comprises a dedicated power supply (battery), tool memory, processing electronics, and gamma ray sensor with associated electronics along with the resistivity measurements section. The CWR measurement has two spacings of 25 and 55 (Figure 43).

Figure 43: Compensated Wave Resistivity (CWR), available in 6.75-in, 8-in and 9.5-in. Two transmitter spacings of 25 and 55. Borehole compensation. Frequency: 2 MHz. 300 F, 20,000 psi.

25

The Slim Compensated Wave Resistivity (SCWR) is the 4 version of CWR and has two spacings of 15 and 35 (Figure 44).

Figure 44: Slim Compensated Wave Resistivity (SCWR). 4.75-in OD. 15 and 35 transmitter spacings. Borehole compensation. Frequency: 2 MHz. 300 F. 20,000 psi.The design objective of the CWR was to make a compensated measurement of deep and shallow resistivity. Trans-mitter to measure point spacings of 55 inches and 25 inches were determined to be the optimum spacings to quantify uninvaded zone and invaded zone resistivity, respectively. For the slim hole tools (4 ), these spacings have been shortened to 35 inches and 15 inches, respectively.

During a fi ring sequence, the four transmitter coils are activated sequentially with a 2MHz signal. For each activa-tion, signals are induced in the two receiver coils. Amplitudes of the signals and the phase diff erence between the two receiver signals are measured for each transmitter. The amplitude from the receiver closest to the transmitter is divided by the amplitude furthest from the transmitter to obtain a ratio indicative of attenuation.

The results for each pair of transmitters are averaged to produce borehole compensated attenuation and phase values. Finally, the two phases and two attenuation ratios are each converted to resistivity values. The conversion curves are shown in Figure 35.

For 9 , 8 and 6 tools the four resistivity measurements produced are R55A (55 Attenuation Resistivity); R55P (55 Phase Shift Resistivity); R25A (25 Attenuation Resistivity) and R25P (25 Phase Shift Resistivity). For the 4 tools, these measurements are, respectively R35A, R35P, R15A and R15P.

The AWR tool is PathFinders latest generation of LWD resistivity tool. It features dual frequency measurements of 2 MHz and 500 kHz. The transmitter receiver spacings are 15, 25 and 45. It has a simplifi ed robust design and new patented electronics packaging to provide more reliability. The HP/HT version is rated 350 F, 25,000 psi (please refer to section 2.4). The large memory storage capability (700 hours at 2 points per ft drilling 200 ft per hour), and separate battery collar which is replaceable at the rig site, together with high speed memory dump provide more operational fl exibility. AWR tool also contains a gamma sensor and an inclination sensor.

Figure 44: Slim Compensated Wave Resistivity (SCWR). 4.75-in OD. 15 and 35 transmitter spacings. Borehole compensation. Frequency: 2 MHz. 300 F. 20,000 psi.

Figure 45: Array Wave Resistivity (AWR). 4.75-in, 6.75-in, 8-in and 9.5-in OD. 15, 25, 45 Transmitter spacings. Borehole compensation. Dual frequency: 2 MHz & 500 kHz, 350 F (175 C) 25,000 psi.

26

2.3.2.3. Advanced Processing

Advanced Resistivity Analysis Processing (ARA) is a general purpose program designed to process PathFinder LWD resistivity data. The program is able to calculate borehole corrected resistivities, dielectric constraint inde-pendent (DCI) resistivities and dielectric constants, and anisotropic resistivities (Rh and Rv). The thin-bed analysis module is able to model Rv and Rh of thin-bed to fi t the measured data.

2.3.2.3.1. Borehole CorrectionThe measured resistivity logs can include signifi cant borehole ef-fects, especially when the mud resistivity, Rm, is low and the for-mation resistivity, Rt, is high. The eff ect tends to become larger as the hole size increases (Figure 46). While borehole corrections are usually minimal, it is a good practice to correct them since they typi-cally improve the data to some degree.

Borehole corrections remove the eff ect of a certain volume (defi ned by borehole diameter and tool diameter) of borehole fl uid of a certain resistivity. Correction algorithms and charts are available for conductive mud. Conductive mud can result in borehole eff ects with a centered tool even in typical borehole sizes. The borehole eff ects tend to be more severe when the mandrel is eccentered. In Figure 47, Figure 48, and Figure 49, the AWR borehole correction factors are plotted using a mud resistivity of .05 ohm.m. The borehole eff ects are slightly larger at 2 MHz than at 500 kHz. The data from the 25, 45 and 55 spacings see a lower borehole eff ect than the 15 spacing. The borehole eff ect may cause the apparent resistivity to be too high or too low depending on the situation (Haugland,

Figure 46: Resistivity measurement is subject to borehole eff ect.

Figure 47: SAWR correction chart, centered tool. Shallow, Medium and Deep 2MHz Phase Resistivity.

Rm = 0.05 ohm.mCentered

0.1 1 10 100 1000 1000RSPH

Rco

r/R

SP H

Rm = 0.05 ohm.m

RMPH

Rco

r/R

MP

H

Centered

0.50.60.70.80.911.11.21.31.41.5

0.1 1 10 100 1000 10000

Rm = 0.05 ohm.m

RDPH

Rco

r/R

DP

H

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Rm = 0.05 ohm.m

RSAH

Rco

r/R

SA

H

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Rm = 0.05 ohm.m

RMAH

Rco

r/R

MA

H

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Rm = 0.05 ohm.m

RDAH

Rco

r/R

DA

H

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Figure 48: SAWR correction chart, centered tool. Shallow, Medium and Deep 2MHz Attenuation Resistivity.

27

Figure 49: SAWR borehole correction chart, centered tool, Shallow, Medium and Deep 500 kHz Phase Resistivity.

Rm = 0.05 ohm.m

RSPL

Rco

r/R

SP

L

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Rm = 0.05 ohm.m

RDPL

Rco

r/R

DP

L

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Figure 50: SAWR borehole correction chart, centered tool, Shallow, Medium and Deep 500 kHz Attenuation Resistivity.

Rm = 0.05 ohm.m

RSAL

Rco

r/R

SA

L

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Rm = 0.05 ohm.m

RMAL

Rco

r/R

MA

L

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Rm = 0.05 ohm.m

RMPL

Rco

r/R

MP

L

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

Rm = 0.05 ohm.m

RDAL

Rco

r/R

DA

L

Centered

0.50.60.70.80.911.11.21.31.41.5

1 10 100 1000 10000

he borehole correction program makes the following assumptions:

The borehole is round and smooth. The mud resistivity and borehole diameter are both known. The tool is either centered or fully eccentric. If the tool is moving erratically in the hole and borehole eff ects are large, program results may be questionable. The mud is water-based with Rt>Rm. Oil-based muds are not addressed.

Data requirements: (S)CWR or (S)AWR resistivities in LAS format.Results: Borehole corrected attenuation and phase resistivities.

28

2.3.2.3.2. Anisotropy Analysis

A property of a medium is said to be anisotropic if its value depends on the direction of measure-ment. Resistivity and dielectric anisotropy is com-mon in earth formations because of depositional environments and compaction. Rh and Rv are respectively the resistivity of the formation mea-sured parallel and perpendicular to the axis of anisotropy, which is typically the normal to the bedding planes, as shown in Figure 50. The an-isotropy ratio is the ratio of vertical over horizon-tal resistivity (Rv/Rh).

The relative inclination is the angle between the normal to the bedding planes and the axis of the tool (or the wellbore). When the relative inclina-tion is small, the tool will only sense the hori-zontal resistivity because all the eddy currents induced by the transmitter are in the horizontal plane. These eddy currents have a component in the vertical direction when the relative inclina-tion is not zero. This results in sensitivity to the vertical resistivity and dielectric constant.

The typical response is that longer spacings are more aff ected than the shorter spacings. Phase resistivities are more aff ected than attenuation resistivities and high frequency measurements are more aff ected than low frequency measurements. All resistivities read higher than they would at zero relative inclination.

Figure 51 shows the response from the four resistivity measurements of the CWR tool in a formation with Rh = 1 and Rv/Rh = 3.

Figure 51: CWR tool anisotropy eff ect on apparent resistivities in a formation with Rh = 1 and Rv/Rh = 3.

Figure 51: CWR tool anisotropy eff ect on apparent resistivities in a formation with Rh = 1 and Rv/Rh = 3.

29

The anisotropy calculation is intended to operate reliably over the range of parameters covered in the chart book, and should be especially useful for shale analysis. The speed and ease of use are derived from the following sim-plifying assumptions:

Homogeneous medium is free of invasion and adjacent bed eff ects.Dielectric constant is isotropic and the same as the assumed value in apparent phase and attenuation resistivity processing. Accurate estimate for the relative inclination angle is needed for Rv estimation.

The homogenous medium assumption makes it easy to determine the outputs using data from a single depth. It also facilitates rapid calculation of the answer because a complicated model does not have to be evaluated. Adja-cent bed eff ects should not be a problem in most shales or when the vertical distance to another bed is fi ve feet or more. If adjacent beds need to be accounted for, use the Thin Bed Analysis program for detailed analysis. Invasion does not tend to happen in shales, so the assumption of no invasion is not a problem. This may cause inaccuracies in high permeability formations though invasion eff ects in LWD on-bottom measurements are usually small.

The isotropic dielectric constant assumption makes this calculation consistent with the chart book. Some dielec-tric assumption is necessary. For example, assume the dielectric constant has the same anisotropy ratio as the resistivity, and that it may depend on the horizontalrresistivity.

Data requirements: (S)CWR or (S)AWR resistivities in LAS format, relative inclination (well inclination and azimuth and formation dip) Please note that relative inclination is required for Rv. Rh is computed independent from the relative inclination.

Results: Horizontal and vertical resistivities (Rh, Rv)

Applications: Shaly Sand Analysis. In thin-bedded shaly sand formation the horizontal resistivity refl ects the low resistivity in the shale layers while the vertical resistivity is closer to the true resistivity in the hydrocarbon bearing sand layers.

Pore Pressure Estimation. Resistivity is often used to estimate abnormal pore pressure based on the deviation of the resistivity from an established natural compaction trend. The horizontal resistivity should be used in this analysis.

PayZone Steering. Rv (or equivalently Rv/Rh) is needed to allow for successful modeling of our tool response at high angles.

Wireline comparison. In many cases, wireline logs record a value close to Rh because of their low frequency, and because they are rarely run in very high angle wells. In high angle wells and anisotropic zones, the LWD horizontal resistivity will better match wireline resistivities from off set wells.

Example: Figure 52 shows an example of a CWR log where the four resistivity curves display an eff ect that resembles the anisotropy eff ect. The R25A reads the lowest, whereas the R25P and R55A read similar values. Compare to Figure 51. The only exception is that the R55A does not read the highest, as the theory predicts. The computed anisotropy ratio is plotted in track 1 and the horizontal and vertical resistivities in track 3. The gamma ray in track 1 does not in-dicate a change in lithology in the zone from X,X50 to X,X70 ft, where there is a strong anisotropy eff ect. The forma-tions above and below these depths display a 1.5 to 2 anisotropy ratio, typical for common shales. The anomalous zone appears to be a thin-bedded sequence of sand and shale beds with thicknesses below the vertical resolution of the gamma ray and resistivity measurements. A subsequent wireline imaging log confi rmed this hypothesis. The thin-bedded sequence as opposed to a uniform formation may possibly explain the R55P curve being lower than the predicted response in the anisotropic zone.

Figure 52: Log example of anisotropy analysis.

2.3.2.3.3.Dielectric Constraint Independent (DCI) Resistivity

Electrical PolarizationThe dielectric constant is a measure of the susceptibility of a medium to electrically polarize in the presence of an applied electric fi eld. Electrical polarization is distinguished from electrical conductivity because conductivity is a measure of how readily charge is transported from point-to-point within the material given an applied fi eld whereas polarization is a measure of how readily charges within a given material separate (are polarized) when an electric fi eld is applied. The higher the dielectric constant, the more readily the charges separate. A polar mol-ecule such as water has a relatively high dielectric constant because the charges are already separated due to the molecular structure. Such molecules tend to orient with an applied fi eld. When this happens, polarization can be observed.

Dielectric AssumptionsThe two most fundamental variables aff ecting the tool response are the conductivity and the dielectric constant. Both variables have to be accounted for. The approach currently used by most LWD companies is to assume a value for the dielectric constant and then compute resistivity estimates independently from the phase shift and attenuation measurements. This results in independent resistivity curves for phase and attenuation for each trans-mitter spacing and frequency.

31

The crossplot of resistivity and dielectric con-stant (Figure 53) shows phase shift (red) and attenuation (blue) factors for a 2 MHz measure-ment. The green line is the dielectric assumption of the AWR tool. A similar plot is also available for 500 kHz measurement. When the dielectric assumption is signifi cantly violated, the log will read an erroneous value. The most typical sce-nario is that the dielectric constant is actually higher than assumed. In this case, the attenua-tion resistivity reads too high, and the phase re-sistivity reads too low. If the dielectric constant is lower than assumed, the attenuation resistivity read below the phase resistivity.

Dielectric Constraint Independent Resistivity and Dielectric ConstantAn alternative to making dielectric assumptions is to simply fi t the attenuation and phase measurement to a model of the tool in a homogeneous, isotropic medium. When this is done, the result is a single resistivity estimate and a single dielectric constant estimate. PathFinder has shown that phase measurement senses the dielectric constant in essentially the same volume that the attenuation measurement senses the resistivity, and attenuation measurement senses the dielectric constant in essentially the same volume that the phase measurement senses the resistivity. The physical basis for these facts is that the transmitter induces two types of currents in the forma-tion: displacement currents, which are associated with the dielectric constant; and, conduction currents, which are associated with the resistivity. By defi nition, at any point in the formation, the displacement currents are 90 degrees out of phase with the conduction currents. The conclusion regarding the volume of investigation of each measurement with respect to each variable follows directly from the observation that the two types of current are 90 degrees out-of-phase everywhere.

2.3.2.3.4. Thin Bed ModelingFinite bed thickness is a common source of error on resistivity logs. Due to the limited vertical reso-lution of log measurement (please refer to section 2.3.2.1.2), thin-bed eff ects depend on many variables such as, bed resistivities, dielectric constants, relative inclination, bed thickness, the spacing and frequen-cy of the measurement, anisotropy, etc. Due to the complexity of the problem, inversion-based process-ing is the method of choice for thin-bed analysis. In this approach, model parameters that lead to calcu-lated results which agree with the actual log data are correlated with the formation parameters. In Figure 54, Rt (square log in tracks 2 and 3) was derived from the LWD resistivities (track 2). The estimates of the anisotropy ratio (square log, track 1) and dielectric constant (track 4) for each bed are also shown. The model was able to match the top and the bottom part of the logs perfectly. The middle part was not a good match due to borehole quality. The result shows a higher resistivity than the log shows and will improve the hydrocarbon estimation.

Figure 53: Phase shift and attenuation factor crossplot for 2 MHz measurement.

Figure 54: Example log of thin bed analysis.

32

2.3.2.4. Applications Resistivity measurement is one of the most useful logs. It is widely used in fl uid, and lithology identifi cation, quantitative analysis and geosteering (section 2.6).

2.3.3. Density Neutron The neutron and density measurements are important for porosity estimation and lithology identifi cation. PathFinders Density Neutron Standoff Caliper service provides the best available bulk density, neutron porosity and caliper measurements while drilling. PathFinder also provide density borehole image services.

2.3.3.1. Measurement Principle2.3.3.1.1. Density and Pe Measurements The density section of the DNSC is located underneath a sleeve to minimize standoff . The stabilizer is 8 O.D. for the 6 tool; 12 O.D. for the 8 tool. The measurement section consists of a 1.5 Curie (Ci) cesium-137 source and two sodium iodide scintillation detectors. The energy spectra of the detected gamma rays are partitioned into several energy regions, for which count rates are stored. As is common for wireline tools, a small cesium-137 source is used to stabilize the detectors against temperature drift (gain stabilization).

The detectors are placed inside a titanium pressure housing; required shielding and collimation are provided by tungsten. The use of titanium minimizes the number of (low energy) gamma rays that are absorbed by the hous-ing material and makes it possible to measure the formation Pe accurately.

The density response has been characterized at a test facility in Houston, Texas. This facility contains many stan-dards that were designed solely for density measurements. The primary standards used for this tool have a 9-inch borehole diameter; 12-inch and 13-inch diameters were also used to determine the diameter dependence and large standoff dependence.

Formation density and Pe are computed using the techniques described by Moake G.L. A New Approach to Deter-mining Density and Pe Values with a Spectral Density Tool Paper Z, SPWLA 1991 Annual Logging Symposium.

2.3.3.1.2. Neutron Measurements The neutron section is located in an enlarged portion of the collar (7 O.D. for the 6 tool; 11 for the 8 tool) to minimize standoff eff ects. It consists of an 8 Ci americium-beryllium (AmBe) source and two helium-3 counters. The detector spacings are similar to those used in wireline tools. The neutron response was characterized at test fa-cilities in Houston and Fort Worth, Texas. Monte Carlo calculations were also used to augment the empirical data.

The neutron porosity is based on the ratio of the near and far count rates. Next, this ratio is converted to porosity using a lithology dependent algorithm. The measurement is corrected for standoff and borehole size, with the former being the larger correction of the two as the ratio processing does not remove all sensitivity to standoff . This total correction is presented on the log as DNPH (representing ).

2.3.3.1.3. Ultrasonic Measurements Three ultrasonic transducers are used to make both a caliper measurement and a standoff measurement. These three transducers are spaced at 120-degree intervals around the tool. One of the ultrasonic transducers is aligned with the density and neutron detectors and measures standoff directly in front of the detector sections in order to improve the nuclear measurements.

1 2 inline ultrasonic transducers for SDNSC, iDNSC

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Measurements are made with each transducer every 10 milliseconds, providing 100 measurements in one rotation when the drill string is rotating at 60 RPM. Each measurement is converted to yield the distance from the transduc-er to the borehole wall. The borehole diameter is then computed using measurements from all three transducers. This provides an accurate caliper log, regardless of tool position and motion in the borehole. Apart from providing an accurate caliper log, these standoff and caliper measurements are used to apply a correc-tion to the neutron measurement and to improve the quality of all nuclear data by applying a technique named standoff weighting.

2.3.3.1.4.Stand-off Weighting, Data Processing and StorageMeasurements are made with the ultrasonic transducers every 10 milliseconds and nuclear detectors every 20 mil-liseconds. Measurements made over a 20-millisecond interval cover only a small angular fraction of the borehole (21.6 degrees when ro-tating at 180 RPM) and may span a wide range of standoff s in one rotation. Data corresponding to smaller standoff s will lead to more accurate measurements of formation properties than data obtained at larger standoff s. In order to take advantage of this, the 20-millisec-ond nuclear data is multiplied by a weighting factor that is computed from the ultrasonic standoff measurement. The weights are larger for smaller standoff s. Data is accumulated for a fi xed time interval (user selectable from 1-60 seconds, normally 10 seconds). At the end of this interval, the nuclear data is normalized and stored in tool mem-ory as weighted count rates along with the average values obtained from the ultrasonic sensors. This weighting greatly emphasizes small standoff data over large standoff data. The standoff weighting func-tion is represented in Figure 55.

Figure 56 is a schematic illustrating the weighting technique. Nuclear count rates (Ci) are accumulated in 0.02-sec-ond intervals. Standoff (Si) is also measured during that interval. A downhole processor calculates a weight (W(Si)) appropriate for the measured standoff (Figure 55) and multiplies each count rate by the weight. These weighted count rates are summed over a user selectable accumulation interval after which they are divided by the sum of the weights to obtain a weighted average ( ). On surface at the end of a run, the tool memory data are merged with depth and time information to yield data that are stored in even depth increments. The data are depth aligned and resolution matched before they are used in calculations.

Reference:Reduction of standoff eff ects on LWD density and neutron measurements, Moake et al, Paper V, SPWLA 37th Annual Logging Symposium, 1996.

Figure 55: Semi-log plot of the weighting applied to density and neutron measurements.

Figure 56: Standoff dynamic weighting of density and neutron measurements.

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2.3.3.2. Tools2.3.3.2.1. Density Neutron Standoff Caliper (DNSC) ToolThe DNSC tool density and neutron measurements are similar to wireline counterparts though the measurement sections are set out slightly diff erent. The tool sizes available are 6 and 8 (Figure 57 and Figure 58). The density section is at the bottom of the tool with the detectors placed above the source, the neutron section is above the density section with the detectors below the source. Three ultrasonic transducers are located near the neutron measurement section of the tool.

2.3.3.2.2.Slim Density Neutron Standoff Caliper (SDNSC) Tool

The Slim Density Neutron Standoff Caliper (SDNSC) tool combines density, neutron, standoff and caliper measure-ments in a 4 collar tool; see Figure 58 below. Similar to the DNSC, the density section is at the bottom of the tool and the neutron section is above the density section. Two ultrasonic transducers are located in between the neutron and density measurement sections of the tool. The transducers are in line with the neutron and density detectors and provide a redundant standoff measurement and a caliper measurement while rotating.

Figure 57: 6 -in, 8-in Density Neutron Standoff Caliper (DNSC) Tool

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Neutron -AmBe - 8 Ci Source -2 He3 Detectors

6 3/4-in, 8-in ODTemp: 300F/150CPress: 20,000 psi

Standoff & Caliper -3 Ultrasonic Transducers -120 Degrees

Density & Pe -Cs-137- 1.5 Ci Source -2 Nal Scintillation Detectors -Gain Stabilized

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Figure 58: 4 -in Slim Density Neutron Standoff Caliper (SDNSC) Tool.

2.3.3.3. Data Quality ControlVarious quality curves are available to use in examining the data, including: Standard deviation of all nuclear measurements. Weighted standoff for both neutron and density. Average standoff versus borehole size. DRHO (Density Correction). DNPH (Neutron Standoff + Caliper Cor). Formation exposure time. Detector health curves. Ultrasonic health curves, etc. An example diagnostic log is presented in Figure 59. Figure 60 shows a typical DNSC log in a triple combo job with DNSC QC curves.

Mnemonics listing for Log Examples:

NSAN Neutron Sandstone Porosity QN Near Detector StatusNLIM Neutron Limestone Porosity QF Far Detector StatusRHOB Bulk Density BS Bit Size DRHO Density Correction CALI CaliperDNPH Neutron Standoff + Caliper Cor DDDN Data DensitySOA Average Stand Off SDNP NLIM Std DevWSON Weighted Standoff Neutron SDRH RHOB Std DevWSOD Weighted Standoff Density

Neuston -Cf-252 -.011 Ci Source -3 He3 Detectors

4 3/4-in ODTemp: 350F/175CPress: 25,000 psi

Standoff & Caliper -2 Ultrasonic Transducers

Density & Pe -Cs-137- 1.5 Ci Source -2 Nal Scintillation Detectors -Gain Stabilized

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Figure 59: Example of a DNSC diagnostic log.

Figure 60: An example of a triple-combo log from a Gulf of Mexico well. The CWR was logged while drilling and the DNSC was logged while reaming at 200 ft/hr. Notice the good density and neutron resolution and cross-over indicating gas.

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2.3.3.4. Applications

Neutron density tools are the primary porosity estimation tools. Neutron density tools are also used in gas detec-tion, geosteering and lithology identifi cation.

2.3.3.4.1. D-N Crossplot Porosity The density-neutron crossplot is an invaluable formation evaluation tool (Figure 61). To compute porosity from the bulk density alone, one needs to know or assume a lithology, (sandstone, limestone, or dolomite). The combina-tion of bulk density and neutron porosity allows for the simultaneous evaluation of porosity and lithology. This porosity is referred to as D-N crossplot porosity (Figure 61).

2.3.4. Sonic 2.3.4.1. Measurement PrincipleCompressional SlownessThe formations compressional slowness (DTP) is computed in the tool in real-time using a 4-trace semblance al-gorithm. A fast shear can be computed downhole if the rock is hard enough to support a body shear wave. The downhole algorithm is described in Boonen et al., 1998. Whereas the downhole algorithm does a reasonable job in most cases,

Figure 61: PathFinder DNSC Neutron Density Crossplot.

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one can envision circumstances where the pre-set processing parameters do not cover the entire range in one log-ging trip. A common occurrence is borehole washout. Sonic energy is attenuated rapidly in fl uids and this eff ect gets worse with increasing borehole diameters. Another common problem is the slowness range of the formation. The tool is pre-set to compute slownesses spanning a range of 100 msec/ft. For instance, in a slow formation, the range is set from 70 to 170 msec/ft. If in this particular slow formation a hard streak is encountered, an anhydrite or a calcifi ed zone, the process will skip the fi rst arrival of these hard rocks if it is less than 70 msec/ft. Typically, the process will then pick on the hard shear which arrives in the 70 to 170 msec/ft range.

In PathFinders Computing Center, the log analysis can reproduce the downhole computed values using a similar semblance processing technique. A more advanced processing method is available based on the Phase Velocity Processing (PVP) algorithm presented by Kozak et al, 2001.

Figure 62 shows a comparison between the LWD compressional slowness and the wireline Dtc in a North Sea chalk formation. The LWD shear is also presented. Wireline shear was not available from the BHC type of tool. Velocity ratio and Poisons ratio are included to indicate the validity of the shear measurement.

Figure 63 shows a compressional log with comparison between upper and lower transmitter data and quality indicators (waveforms, semblance and waveform correlation coeffi cient).

Figure 62: A Comparison between the LWD compressional slowness and the wireline Dtc in a North Sea Chalk

Formation.

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Slow Shear ProcessingFor the purpose of this discussion, a formation will be called acoustically slow if the speed of sound in the borehole fl uid is greater than the velocity of shear waves in the surrounding formation. Shear wave logging under these cir-cumstances is an important and challenging application. In slow formations, a refracted shear wave does not propa-gate in the formation along the borehole wall. However, the slowness of guided modes such as Stoneley (mono-pole), fl exural (dipole), and screw (quadrupole) waves can be measured instead. These waves tend to have their energy concentrated in the borehole, and are thus referred to as borehole-guided waves. The guided wave slowness depends not only on the formation shear slowness but additionally on the mandrel properties and eccentricity, mud density and slowness, borehole diameter, frequency, and formation compressional slowness dispersion.

Figure 63: Good consistency of Dtc from top and bottom transmitter.

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The Figure 64 conveys a rule-of-thumb approach to the defi nition of slow shear as mentioned above. The curve in the graph represents the so called mud rock line pub-lished by Castagna et al. (1986). This line is an empirical relationship between compressional and shear for an off -shore Gulf of Mexico formation. Borehole fl uid slowness typically ranges from 189 msec/ft for a water-based mud to 240 msec/ft or more for a synthetic oil-based mud. When the formation compressional slowness exceeds between 90 msec/ft in WBM to ~110 msec/ft in OBM, the shear slowness will be greater than the borehole fl uid.

Figure 65 shows the eff ectiveness of the low frequency transmitter to enhance the fl exural arrival. These plots are semblance plots computed from 40 to 340 micro-seconds per foot for both low and high frequency wave-forms. The red colors represent the highest semblance, and the blue colors represent the low semblance values. It is obvious that the fl exural arrival is stronger in the low frequency waveforms whereas the compressional arrival is enhanced in the high frequency waveforms. Hence we are going to use the low frequency waveforms to com-pute the shear wave and the high frequency waveforms for the compressional slowness. Figure 66 shows an example about 300 ft of North Sea data. Although the semblance as shown in the preceding fi gure is not used directly to compute the fl exural slowness, it is used to generate a guide to aid the arrival picking routine of the phase velocity processing algorithm described later.

References: Kozak et al., 2001 (SPWLA 2001 PP)

Figure 64: Dts and Dts cross plot with mud rock line and bore-hole fl uid slowness.

Figure 65: Semblance plots of e-sonic data at low fre-quency (5 or 7kHz) and high frequency (15).

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Figure 66: Example of fl exural slowness and compressional slowness log in North Sea. Track 1: Gamma ray. Track 2: Low frequency waveform used to process the fl exural arrival (white curve). Track 3: Semblance of the fl exural arrival (white curve). Track 4: Compressional slowness (DTP) blue, fl exural slowness (DTS) red.

Dispersion Correction ProcessingSlow shear measurements depend on the processing of the fl exural mode. This guided wave slowness depends not only on the formation shear slowness but additionally on the mandrel properties and eccentricity, mud den-sity and slowness, borehole diameter, frequency, and formation compressional slowness. Processing, which relies upon values for these additional variables, is typically required to determine a shear slowness from measured guided wave arrivals. Such processing is often referred to as dispersion correction. This terminology implies that a guided mode in question propagates at the formation shear slowness in the zero frequency limit. Since this is not necessarily the case, it may be more appropriate to call the algorithm a shear slowness estimation algorithm.

Because of the relatively high frequency of the low frequency transmitter (5 or 7 kHz), the recorded fl exural arriv-als are still aff ected by dispersion, and we cannot directly use the fl exural arrival and call it slow shear. We have to apply a dispersion correction or more correctly apply a true shear estimation algorithm. Such an algorithm was developed at PathFinder. This algorithm is based on a closed form analytical solution of the wave equation. It is important to notice which input parameters are required to do this correction well. The interface slowness is the fl exural wave slowness that we record with the tool. The frequency is the center frequency of this arrival as shown earlier. It is advisable to include a bulk density measurment from a density tool. A great advantage of running a DNSC is that we then automatically have a caliper measurement which is another important input parameter in the algorithm. Other parameters are mud density (from log headers) and a mud velocity.

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An analytical solution to the 2.5-D isotropic medium problem is used to compute theoretical slowness val-ues for the guided waves. This theoretical slowness is then compared to the measured fl exural wave slowness using nonlinear optimization techniques. The solution to this equation is the correct formation shear slow-ness when the mode is correctly registered and the as-sumed parameter vector equals the actual parameter vector (frequency, eccentricity, borehole diameter, bulk density, borehole fl uid slowness and density). Figure 67 shows the dispersion correction for e-sonic .

Figure 68 is a fi nal log showing about 300 ft of data from a North Sea well. The gamma ray is in track 1, the low frequency waveform in track 2, the fl exural mode semblance in track 3, compressional,measured fl exural and dispersion corrected shear in track 4, compression-al semblance in track 5 and the high frequency wave- form in track 6. The slow shear has been dispersion corrected.

Based on our recent research on the unipole tool phys- ics, a new disper-sion correction method is being developed with an objective of ease of use. The ne