LWD I Essentials

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1 CROL_170_revE_0605

LWD I Essentials Course #170

Course Description: This 4-day introductory level course concentrates on the essential background knowledge and theory that the field engineer must possess in order to effectively analyze, interpret, and troubleshoot LWD data. The course provides classroom instruction in petroleum geology, directional drilling basics, data acquisition methods, basic LWD sensor theory, application, and interpretation, LWD system specifics, and surveying theory and quality control. The Lithium Battery Safety course (#080) is also included within the structure of this training. A written assessment designed to measure the student’s understanding of the subject matter will be administered upon completion of the course material. Course Outline: Day One Introduction 0.5 hour

Registration and Introductions Petroleum Geology Primer 2 hours

Rocks and Minerals Transport and Deposition Sedimentary Rock Classifications Origin of Hydrocarbons Hydrocarbon Migration Hydrocarbon Accumulation

Directional Drilling Basics 1.5 hours

Introduction to Directional Drilling Applications of Directional Drilling Directional Drilling Limitations


Methods of Deflecting a Wellbore o Whipstock o Jetting Assemblies o Rotary Bottomhole Assemblies

Building Assemblies Dropping Assemblies Holding Assemblies

Mud Motors o Motor Selection o Components o Operational Limitations & Constraints

Rotary Steerable Assemblies Data Acquisition Methods 1 hour

Recorded Data Measurement Process o Recorded Data Advantages / Disadvantages

Real-time Data Measurement Process Real-time Telemetry Methods

o Mud Pulse Telemetry Theory of Operations Positive Pulse Telemetry Negative Pulse Telemetry Mud Pulse Telemetry Advantages / Disadvantages

o Electromagnetic Telemetry Theory of Operations Electromagnetic Telemetry Advantages / Disadvantages

The Borehole Environment 1 hour

Drilling Fluid Properties o Drilling Fluid Advantages o Drilling Fluid Disadvantages

Formation Properties o Formation Porosity o Formation Permeability o Pore Fluid Saturation and Density o Lithology o Formation Thickness o Shale Content

Pressure Differential o Overbalanced o Underbalanced


Day Two LWD Sensor Theory, Application, and Interpretation 4 hours

Directional Data o Importance of Directional Surveying o Directional Surveying Measurements o Directional Sensor Hardware o Sensor Axes and Orientation o Magnetic Field Strength, Dip Angle, Horizontal and Vertical Components o Magnetic Declination o Grid Convergence o Factors Affecting Inclination and Hole Direction o Survey Quality Control - Gtotal, Btotal, Magnetic Dip Angle o Well Plan Parameters (Horizontal & Vertical Projections)

Formation Evaluation Data

o Gamma Ray 1 hour Theory Applications Interpretation

o Resistivity 2 hours

Theory Applications Interpretation

Drilling Mechanics Data 1 hour

o Pressure While Drilling Theory Applications Interpretation

Day Three LWD Sensor Theory, Application, and Interpretation (continued)

Formation Evaluation Data o Neutron 1.5 hours


o Density 1.5 hours



Drilling Mechanics Data o Vibration 1.5 hours


LWD System and Sensor Specifics 2 hours

LWD System Specifications o HEL (Hostile Environment Logging) o PrecisionLWD

LWD Sensor Specifications o BAP o HAGR o IDS o ESM o MFR o TNP o AZD

LWD Sensor Measure Points LWD Tool Configurations

Review for Written Exam 1 hour

Day Four Written Exam 4 hours Lithium Battery Safety (Course #080) 4 hours

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1© 2005 Weatherford. All rights reserved.

CRCM_170_revE_0605

LWD I EssentialsCourse 170

Shale

GasOil

Salt Water

Salt

Shale

© 2005 Weatherford. All rights reserved.

Registration

• Legibly complete the information requested on Course Enrollment Sheet (see below)

• Print your name exactly as you wish it to appear on your course certificate

• Obtain a copy of the course curriculum from the front of the room• Obtain a pad of paper and writing materials if needed

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Course Outline

• Days 1 - 3– Introduction– Petroleum Geology Primer– Directional Drilling Basics– Data Acquisition Methods– The Borehole Environment– Basic LWD Sensor Theory,

Application, and Interpretation– LWD System and Sensor Specifics

• Day 4– Comprehensive Written

Assessment– Lithium Battery Safety Course


Daily Activities

• Class starts at 8:00 AM daily

• Class ends approximately 5:00 PM daily

• Breaks – one in morning, one in afternoon

• Quizzes possible at any time

• Written Assessment on final day of course

Petroleum Geology Primer 1©2006 Weatherford International Ltd. Confidential – Not To Be Distributed Or Copied. All Rights Reserved.


CRCM_170_revE_0605

Petroleum Geology PrimerRocks & Minerals


Minerals

• A mineral is a naturally occurring inorganic crystalline element or compound

• Minerals have definite chemical composition and characteristic physical properties such as crystal shape, melting point, color, and hardness

• Most minerals found in rocks are not pure• Examples are quartz and feldspar



Rock Classifications

• A rock is a hardened aggregate composed of different minerals

• Rocks are divided into three classifications on the basis of their mode of origin

– Igneous– Metamorphic – Sedimentary


Igneous Rock

• Rock mass formed by the solidification of magma within the earth’s crust or on its surface

• Two principal types of igneous rock– Intrusive (plutonic), those that have solidified

below the surfaceGranite

– Extrusive (volcanic), those that have formed on the surface

Lava (Basalt)



Metamorphic Rock

• Rock derived from preexisting rocks by mineralogical, chemical, and structural alterations caused by heat and pressure within the earth’s crust

– Limestone Marble– Shale Slate

• Metamorphism results in a crystalline texture which has little or no porosity


Sedimentary Rock

• Rock composed of materials that were transported to their present position by wind or water

• Sandstone, limestone, shale sometimes referred to as clastic rocks, which are distinguished primarily by grain size

– Weathering breaks down the structure– Erosion is the removal of weathered rock– Transportation mechanisms move the eroded sediments to a

basin where deposition occurs– Compaction forces from the weight of overburden sediments

and cementation hardens the sediments into sedimentary rock



Sedimentary Rock

• Sedimentary rocks cover 75% of the land surface of the earth’s crust

• Because most sedimentary rocks are capable of containing fluids (reservoir rock) they are of prime interest to the petroleum geologists

• Shale is a sedimentary rock that is not typically a reservoir rock, but it is a “source rock” for the production of hydrocarbons

Sandstone


The Rock Cycle

• The possible sequence of events, all interrelated, by which rocks may be formed, changed, destroyed, or transformed into other types of rock



Rock Texture

• Clastic Texture (Sedimentary)– Rock texture in which individual

rock, mineral, or organic fragments are cemented together by a crystalline mineral such as calcite

• Crystalline Texture (Metamorphic & Igneous)

– Rock texture that is the result of progressive and simultaneous interlocking growth of mineral crystals


Sedimentary Transport & Depositional Environments



Sedimentary Transport

• Tectonic forces raise lowlands above sea level, ensuring a continuing supply of exposed rock for producing sediments

• Gravity causes sediments to move from high places to low

• Gravity also works through water, wind, or ice to transport particles from one location to another

• Gravity ultimately pulls sediments to sea level


Sedimentary Transport Mechanisms

• Mass Movement• Water Transport• Wind Transport• Glacial Transport



Mass Movement

• In high elevations – Severe weathering – Instability of steep slopes

• A large block of bedrockmay separate along deepfractures or bedding planes

– Rockslide or avalanche


Water Transport

• Primary means of sediment transport

• The distance a sedimentary particle can be carried by water depends on:

– Available water energy

– Size

– Shape

– Density

• The higher the water energy the larger the volume and size of sediments carried

• Lighter particles become part of the suspended load, whereas heavier ones settle into the bed load

• Spherical particles are more difficult to carry than randomly shaped ones

• The more dense a particle is, the faster it will settle out



Wind Transport

• Wind moves only minor amounts of sediment compared to water transport

• High winds carry clay, silt, and sand much as a river does

• In arid (desert) climates wind may act as the primary weathering and transport agent

• Wind-driven sediments are often reworked and redeposited by flowing water


Glacial Transport

• Glaciers move slowly but with great weight, grinding rocks into various sized particles

• Glacial sediments are often reworked and redeposited by flowing water

• Can move boulder-sized sediments that water and wind cannot



Depositional Environments

• A place where sedimentary particles arriving at a location outnumber those being carried away

• Common depositional environments:– Fluvial– Lacustrine– Glacial– Aeolian– Marine


Fluvial Deposits

• Sediments deposited by flowing water• Sediments accumulate where the energy

is reduced (inside of bend)– Sandbars– Floods– Deltas



Lacustrine Deposits

• A collection of sediment in a lake at the point at which a river or stream enters

• When flowing water enters the lake, the encounter with still water absorbs most or all of the stream’s energy, causing its sediment load to be deposited

• Eventually the lake will fill with sediments and ceases to exist, leaving behind a deposit from which hydrocarbons may be born


Glacial Deposits

• Sediments deposited by moving ice sheets are rare because they are subject to erosion and rework by other agents

• Retreating glaciers leave behind accumulations of unsorted sediments called till, which is a chaotic jumble of mud, gravel, and large rocks



Aeolian Deposits

• Sediments deposited by wind, typically in arid climates• Sand dunes• Loess (thick beds of silt carried by winds from the

outwash plains of glaciers


Marine Deposits

• Marine deposits are far enough seaward not to be affected by wave action or fluvial deposition

• Generally associated with finer grained sediments

– Reef

– Turbidites



Sedimentary Rock Classifications


Clastics

• Rocks composed mostly of fragments of other rocks which are distinguished by grain size



Conglomerates

• A sedimentary rock composed of pebbles of various size held together by a cementing material such as clay

• Similar to sandstone but are composed mostly of grains more than 2 mm in diameter

• Usually found in isolated layers; not very abundant


Sandstones

• A sedimentary rock with more than half of its grains between 1/16 mm and 2 mm

• Generally composed of quartz and feldspar

• Commonly porous and permeable making it a likely type of rock to find a petroleum reservoir

• One fourth of all sedimentary rocks are sandstones



Shales

• Distinctive, fine-grained, evenly bedded sedimentary rock composed mostly of consolidated silt or clay

• Formed from fine sediments that settled out of suspension in still waters, shale occurs in thick deposits over broad areas, interbedded with sandstone or limestone

• Silt grains – 1/256 mm to 1/16 mm

• Clay grains – flat, plate-like crystals less than 1/256 mm across

• Organic shale is thought to be the source of most of the world’spetroleum

• Shales also make excellent barriers to the migration of fluid and tend to trap petroleum in adjacent porous rock

• One-half to three-fourths of the world’s sedimentary rock is shale


Evaporites

• A sedimentary rock formed by precipitation of dissolved solids from water evaporating in a closed basin

• Indicators of former dry climates or enclosed drainage basins

• Only a small fraction of all sedimentary rocks but play a significant part in the formation of petroleum reservoirs associated with salt domes

Anhydrite

Halite



Carbonates

• A sedimentary rock composed primarily of calcium carbonate (limestone) or calcium magnesium carbonate (dolomite)

• Make up about one-fourth of all sedimentary rocks

• Most carbonates are formed as a direct result of biological activity

• Limestone forms in warm, shallow water

Limestone


Origin of Hydrocarbons

putalog



Hydrocarbons

• Originally oil seemed to come from solid rock deep beneath the surface (“inorganic theory”)

• Scientists showed oil-rocks were once loose sediment piling up in shallow coastal waters

• Advances in microscopy revealed fossilized creatures• Chemists discovered certain complex molecules in

petroleum known to occur only in living cells• That source rocks were shown to originate in an

environment rich with life clinched the “organic theory”


Chemical Factors

• A hydrocarbon molecule is a chain of one or more carbon atoms with hydrogen atoms chemically bound to them

• Variations are due to differences in molecular weight• Despite those differences the proportions of carbon and

hydrogen do not vary appreciably • Carbon comprises 82-87% and hydrogen 12-15%



Chemical Composition of AverageCrude Oil & Natural Gas

Element Crude Oil Natural Gas

Carbon 82 – 87% 65 – 80%

Hydrogen 12 – 15% 1 – 25%

Sulphur 0.1 – 5.5% 0 – 0.2%

Nitrogen 0.1 – 1.5% 1 – 15%

Oxygen 0.1 – 4.5% 0%


Chemical Factors

• Methane, the simplest hydrocarbon, has the chemical formula CH4

– Four is the maximum number of hydrogen atoms that can attach to a single carbon atom

• Petroleum is only slightly soluble in salt water

– Molecules with up to four carbon atoms occur as gases

– Molecules having five to fifteen carbon atoms are liquids

– Heavier molecules occur as solids

• Petroleum occurs in such diverse forms as

– Thick black asphalt or pitch,

– Oily black heavy crude,

– Clear yellow light crude,

– And petroleum gas



Biological Factors

• Each level of the food chain contributes to the accumulation of organic material, particularly at the microscopic level (protozoa and algae)

• Bacteria plays an important role in recycling this decaying organic material

– Aerobic (oxygenated) - requires free oxygen for their life processes (i.e., forms slime or scum)

– Anaerobic (reducing) - do not require free oxygen to live and are not destroyed by its absence; takes oxygen from dissolved sulfates and organic fatty acids producing sulfides and hydrocarbons

• Although aerobic decay liberates certain hydrocarbons that some small organisms accumulate within their bodies, the anaerobics are more important in oil formation


Petroleum Formation

• For an accumulation of petroleum to form, the supply of oxygen must be cut off

• Examples of where anaerobic environments exist:– Deep offshore– Salt marshes– River deltas– Tidal lagoons

• In this environment organic waste materials and dead organisms sink to the bottom and are preserved in an anaerobic environment instead of being decomposed by oxidizing bacteria

• Accumulation and compaction of impermeable clay along with the organic material help seal it off from dissolved oxygen

• Transformation into petroleum is accomplished by the heat and pressure of deeper burial



Physical Factors

• Certain chemical reactions occur quickly at 120°-150°F, changing the organic material trapped within the rock

– Long-chain molecules are broken into shorter chains– Other molecules are reformed, gaining or losing

hydrogen– Some short-chain hydrocarbons are combined into

longer chains and rings • The net result is that solid hydrocarbons are converted

into liquid and gas hydrocarbons• Thus the energy of the sun, converted to chemical energy

by plants, redistributed among all the creatures of the food chain, and preserved by burial, is transformed into petroleum


The Petroleum Window

• The set of conditions under which petroleum will form

• Temperatures between 100°F-350°F

• The higher the temperature, the greater the gas proportion

• Above 350°F almost all of the hydrocarbon is changed into methane and graphite (pure carbon)

• Source beds (or reservoirs) deeper than about 20,000 feet usually produce only gas



Source Rocks

• Source Rock

– Rock in which organic material that has been converted into petroleum

• Reservoir Rock

– Rock in which petroleum accumulates

• Generally, the best source rocks are shales rich in organic matter deposited in an anaerobic marine environment

• Limestone, evaporites, and rocks formed from freshwater sedimentary deposition also become source beds

• Time is the final ingredient in the formation and accumulation of petroleum

• Little petroleum has been found in reservoir rocks with source beds less than one million years old


Hydrocarbon Migration



Migration

• The movement of hydrocarbons from the area in which it was formed to a reservoir rock where it can accumulate

• Primary migration– Movement of hydrocarbons out of the source rock

• Secondary migration– Subsequent movement through porous, permeable

reservoir rock by which oil and gas become concentrated in one locality


Primary Migration

• Petroleum leaves its source rock by forces of compaction and water flow

• As shale gets compressed into less space, it is not the solid mineral grains that are compressed but the pore spaces

• Interstitial water is squeezed out, carrying droplets of oil in suspension and other hydrocarbons in solution

• Fluids squeezed out of the more readily compressible shale source rocks will collect in the adjacent sandstone, which retains more of its original porosity



Secondary Migration

• Hydrocarbons are moved through permeable rock by gravity

– Compressing pore spaces containing fluid – Causing water containing hydrocarbons to flow – Causing water to push less dense petroleum fluids

upward• Effective porosity and permeability of the reservoir rocks

are more important than total porosity• These factors control how easily the reservoir can

accumulate fluids as well as how much it can hold


Hydrocarbon Accumulation



Traps

• Like water in a puddle, hydrocarbons collect in places it cannot readily flow out of such as:

– structural high points – zones of reduced permeability

• Traps are a geologic combination of impermeability and structure that stops any further migration


Traps

• The basic requirements for a petroleum reservoir are

– A source of hydrocarbons– Porous and permeable rock enabling migration– Something to arrest the migration and cause

accumulation• Two major groups of hydrocarbon traps

– structural, the result of deformation of the rock strata

– stratigraphic, a direct consequence of depositional variations

• Most reservoirs have characteristics of multiple types

• Timing is critical; the formation of the trap must occur before the arrival of the petroleum



Structural Traps

• Anticlines

– Created by tectonic deformation of flat and parallel rock strata

– A short anticline plunging in both directions along its strike is classified as a dome

• Faults

– Occur when deformational forces exceed the breaking strength of rock

– Most faults trap oil and gas by interrupting the lateral continuity of a permeable formation

Anticline Structure

Impermeable Bed

Sealing Fault


Stratigraphic Traps

• Result of lateral discontinuity or changes in permeability and are difficult to detect

– Stratigraphic traps were not studied until after most of the world's structural oil fields were discovered

– They still account for only a minor part of the world's known petroleum reserves

• Stratigraphic traps are usually unrelated to surface features

• Many stratigraphic traps have been discovered accidentally while drilling structural traps



Stratigraphic Traps

Shoestring Sands• A sinuous string of

sandstone winding through impermeable shales

• Form complex branching networks

• Create isolated “compartments”

• Clues such as direction of greatest permeability and general slope of the buried land surface help find the next productive location


Stratigraphic Traps

• Lens– Isolated body of permeable rock enclosed within less permeable

rock – Edges taper out in all directions

• Formed by turbidity currents and underwater slides • Isolated beach or stream sand deposits • Alluvial fans

– Not extended in length

Lens TrapsLens Traps



Stratigraphic Traps

• Pinchout– Occurs where a porous and permeable sand body is

isolated above, below, and at its updip edge– Oil or gas migrates updip to the low-permeability zone

where the reservoir "pinches out"

Pinchout Traps


Combination Traps

• Many petroleum traps have both structural and stratigraphic features

• Typically found near salt domes

Directional Drilling Basics 1


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Directional Drilling Basics


Introduction to Directional Drilling

• Directional drilling is defined as the practice of controlling the direction and deviation of a well bore to a predetermined underground target or location.



Types of Directional Wells

• Slant• Build and Hold • S-Curve• Extended Reach• Horizontal


Directional Drilling Tools

• Drilling Tools• Surveying/Orientation Services• Steering Tools• Conventional Rotary Drilling Assemblies• Steerable Motors• Instrumented Motors for geosteering applications• Rotary Steerable Systems• At-Bit Inclination Sensor



Applications of Directional Drilling

• Multiple wells from offshore structure• Relief wells• Controlling vertical wells



• Sidetracking• Inaccessible locations






• Extended-Reach Drilling

– Replace subsea wells and tap offshore reservoirs from fewer platforms

– Develop near shore fields from onshore, and– Reduce environmental impact by developing fields

from pads




• Drilling underbalanced

– Minimizes skin damage,– Reduces lost circulation and stuck pipe incidents,– Increases ROP while extending bit life, and– Reduces or eliminates the need for costly stimulation

programs.


Directional Drilling Limitations

• Doglegs• Reactive Torque• Drag• Hydraulics• Hole Cleaning• Weight on Bit• Wellbore Stability



Methods of Deflecting a Wellbore

• Whipstock operations– Still used

• Jetting– Rarely used today, still valid and inexpensive

• Downhole motors– Most commonly used, fast and accurate


Whipstock Operations



Jetting


Directional Control with Rotary Assemblies

• Design principles• Side force• Bit tilt• Hydraulics• Combination

• BHA types• Building assembly • Dropping assembly• Holding assembly



Weight On Bit

• Increasing Weight on Bit,increases Deviation Tendency

…. and vice-versa


Stabilization Principle

• Stabilizers are placed at specified points to control the drillstring and to minimize downhole deviation

• The increased stiffness on the BHA from the added stabilizers keep the drillstring from bending or bowing and force the bit to drill straight ahead

• The packed hole assembly is used to maintain angle



Reasons for Using Stabilizers

• Placement / Gauge of stabilizers control direction• Stabilizers help concentrate weight on bit• Stabilizers minimize bending and vibrations• Stabilizers reduce drilling torque less collar contact• Stabilizers help prevent differential sticking and key

seating


Stabilizer Forces



Building Assemblies (Fulcrum)

• Two stabilizer assemblies increase control of side force and alleviate other problems


Building Assemblies (Fulcrum)



Dropping Assemblies (Pendulum)

• To increase drop rate:

– increase tangency length

– increase stiffness

– increase drill collar weight

– decrease weight on bit

– increase rotary speed

– Common TL:

• 30 ft

• 45 ft

• 60 ft

• 90 ft


Dropping Assemblies (Pendulum)



Holding Assemblies (Packed)

• Designed to minimize side force and decrease sensitivity to axial load


Application of Steerable Assemblies

• Straight-Hole• Directional Drilling / Sidetracking• Horizontal Drilling• Re-entry Wells• Underbalanced Wells / Air Drilling• River Crossings



Steerable Assemblies

• Build

• Drop

• Hold


Mud Motors

Positive Displacement MotorTurbine Motor



Commander TM PDM Motors


Motor Selection

• These are the three common motor configurations which provide a broad range of bit speeds and torque outputs required satisfying a multitude of drilling applications

– High Speed / Low Torque - 1:2 Lobe– Medium Speed / Medium Torque – 4:5 Lobe– Low Speed / High Torque – 7:8 Lobe



Motor Selection

• High Speed / Low Torque (1:2) motor typically used when:

– Drilling with diamond bits– Drilling with tri-cone bits in soft formations– Directional drilling using single shot orientations


Motor Selection

• Medium Speed/Medium Torque (4:5) motor typically used for:

– Conventional and directional drilling– Diamond bit and coring applications– Sidetracking wells



Motor Selection

• Low Speed / High Torque (7:8) motor typically used for:– Most directional and horizontal wells– Medium to hard formation drilling– PDC bit drilling applications


Components of PDM Motors

• Dump Sub Assembly• Power Section• Drive Assembly• Adjustable Assembly• Sealed Bearing Section



Dump Sub Assembly

• Hydraulically actuated valve located at the top of the drilling motor

• Allows the drill string to fill when running in hole• Drain when tripping out of hole• When the pumps are engaged, the valve

automatically closes and directs all drilling fluid flow through the motor


Dump Sub

• Allows Drill String Filling and Draining• Operation

- Pump Off - Open- Pump On - Closed

• Discharge Plugs• Connections



Power Section

• Converts hydraulic power from the drilling fluid into mechanical power to drive the bit

– Stator – steel tube containing a bonded elastomer insert with a lobed, helical pattern bore through the center

– Rotor – lobed, helical steel rod• When drilling fluid is forced through the

power section, the pressure drop across the cavities will cause the rotor to turn inside the stator


Power Section

• Pattern of the lobes and the lengthof the helix dictate the output characteristics

• Stator always has one more lobe than the rotor

• Stage – one full helical rotation ofthe lobed stator

• With more stages, the powersection is capable of greater differential pressure, whichin turn provides more torqueto the rotor Performance

Characteristics



Drive Assembly

• Converts Eccentric Rotor Rotationinto Concentric Rotation

Constant Velocity Joint --

Flex Rod

Universal Joint


Adjustable Assembly

• Can be set from zero to three degrees

• Field adjustable in varying increments to the maximum bend angle

• Provides a wide range of potential build rates in directional and horizontal wells

H = 1.962 o



Sealed Bearing Section

• Transmits axial and radial loads from the bit to the drillstring

• Thrust Bearing• Radial Bearing• Oil Reservoir• Balanced Piston• High Pressure Seal• Bit Box Connection


Motor Handbook

• Every possible motor configuration is represented in the Motor Handbook

– Dimensional Data– Specifications– Adjustable Housing Settings– Performance Charts



Motor Dimensional Data


Motor Specifications



Estimated Build Rates


Performance Charts



Using the Performance Charts

• Differential Pressure

–Difference between the system pressure when the drilling motor is on-bottom (loaded) and off-bottom (not loaded)

• Full Load

–Indicates the maximum recommended operating differential pressures of the drilling motor

• RPM

–Motor RPM is determined by entering at the differential pressureand projecting vertically to intersect the appropriate flow rate line

• Torque

–Motor torque is determined by entering at the differential pressure and projecting vertically to intersect the torque line


Operational Constraints

• Temperature – 219 °F / 105 °C –Stator can be customized for temperatures up to 300 °F / 150 °C

–Special materials and sizes of components used• Excessive Weight on Bit

–Excessive weight on bit stops the bit from rotating, and the power section of the motor is not capable of providing enough torque to power through (Motor Stalling)

–Rotor cannot rotate inside of the stator, forming a seal–Continued circulation will erode and “chunk” the stator




• Motor Rotation – Rotating at bend angle greater than 1.83 degrees is not

recommended (housing damage and fatigue)– Speed of rotation should not exceed 60 RPM (excessive

cyclic load on housing)• Drilling Fluids

– Designed to operate with practically all types of drilling fluids such as fresh and salt water, oil based fluids, mud with additives for viscosity control or lost circulation, and with nitrogen gas

– Hydrogen based fluids can be harmful to elastomers– High chlorine content can cause damage to internal

components– Keep solids content below 5%– Keep sand content below 0.5%



• Differential Pressure– Difference between the system pressure when the drilling

motor is on-bottom (loaded) and off-bottom (not loaded)– Excessive pressure drop across the rotor and stator will

cause premature pressure wash (chunking), and impair performance

– Maximum differential is flow rate dependent; higher the flow rate the lower the allowable differential pressure

• Underbalanced Drilling– Proper gas/liquid ratio must be used to avoid motor damage– Under high pressure operation conditions, nitrogen gas may

permeate into the stator and expand when tripping out of the hole causing blistering or chunking of the stator



Directional Drilling Problems

• Pressure increases• Pressure decreases• Loss of rate of penetration


Pressure Increases

• Motor Stalled or stalling• Motor or Bit Plugged• Undergauge (tight) Hole



Pressure Decreases

• Dump Sub valve stuck open• Worn or damaged stator• String Washout / Twist-off• Lost Circulation• Gas Kick


Loss of Rate of Penetration

• Bit Worn or balling• Worn Stator (Weak Motor)• Motor Stalled• Change of Formation• Drill String / Stabilizer Hang Up



Rotary Steerable

• Revolution RSS – Smart Stabilizer


Benefits of Rotary Steerable

• No Sliding reduces risk of buckling pipe• Continuous rotation of drillstring reduces chance of

differential sticking• Reduces torque & drag due to smoother well bore

curvature• Longer reach wells• Longer horizontal / lateral sections• Improved formation evaluation due to pad contact of

wireline tools• Improved formation evaluation with LWD tools• Deviation control in Vertical Wells



“Push the Bit” versus “Point the Bit”


Planning a Directional Well

• Geology• Completion and Production• Drilling Constraints



Geology

• Lithology being drilled through • Geological structures that will be drilled • Type of target the geologist is expecting • Location of water or gas top• Type of Well


Completion and Production

• Type of completion required (“frac job”, pumps and rods, etc.)

• Enhanced recovery completion requirements• Wellbore positioning requirements for future

drainage/production plans• Downhole temperature and pressure



Drilling Constraints

• Selection of surface location and well layout• Previous area drilling knowledge and identifies particular

problematic areas


Drilling Constraints

• Casing size and depths• Hole size• Required drilling fluid• Drilling rig equipment and capability• Length of time directional services are

utilized• Influences the type of survey

equipment and well path



Planning

• Build rates• Build and hold profiles

should be at least 50m• Drop rate for S-curve wells

is preferably planned at 1.5o/30m

• Kickoff Point as deep as possible to reduce costs and rod/casing wear

• In build sections of horizontal wells, plan a soft landing section


Planning

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

• On horizontal wells clearly identify gas / water contact points

• Turn rates in lateral sections of horizontal • Verify motor build rates



Planning

• Where possible start a sidetrack at least 20m out of casing

• Dogleg severity could approach 14o/30m coming off a whipstock

• Identify all wells within 30m of proposed well path and conduct anti-collision check

Data Acquisition Methods 1


CRCM_170_revE_0605

Data Acquisition Methods


Data Acquisition Methods

• There are two methods in which LWD data can be acquired:

– Recorded– Real-time

• We will discuss the following about each:– Measurement Process– Advantages and Disadvantages



Recorded Data Measurement Process

• LWD recorded data is obtained by sampling the downhole sensors, storing each data point in downhole memory, and retrieving the data when the toolstring is tripped out of the hole

• Each data point is associated with a time from the master (or sensor) downhole clock

• Depth monitoring versus time is performed on the surface during drilling

• Synchronization of the surface and downhole clocks at the start of the bit run is critical

• During post-run processing, the time component from the depth and data files are matched to create sensor data versus depth information that is used to create logs


Recorded Data Advantages

• High data resolution

– data resolution is at least as good and usually much better than real-time

– real-time resolution is generally no better than 8-bit (except for survey data)

– recorded resolution at least 8-bit, does go up to 16-bit

– Typically replaced real-time data once it is extracted from tool memory

• Independent of Transmission Problems

– no missed data due to poor detection or surface sensor problems

• Fast Sample Rates

– more data points per depth interval

– can store data at a much faster rate than transmission

– can log the hole faster than real-time and achieve the same data quality



Recorded Data Disadvantages

• No real-time feedback– recorded data is not as useful for drilling mechanics

data such as pressure and vibration (historical only)– difficult to use for pore pressure prediction and casing

and coring point selection– impractical and very expensive to use recorded data

for directional drilling and geosteering applications


Real-time Data Measurement Process

• LWD real-time data is obtained by sampling the downhole sensors, encoding the data into a binary format, and transmitting the data through some medium to the surface

• The transmission is decoded at the surface, processed into a sensor data value and associated with depth to create real-time logs

• The process sounds simple, but it is extremely complex and requires a combination of events to happen perfectly for a data point to be processed



Real-time Telemetry Methods

• In LWD real-time applications there are 3 types of telemetry methods:

– Positive Mud Pulse– Negative Mud Pulse– Electromagnetic

• “Telemetry” basically amounts to accessing and transmitting data to and from remote locations

• The LWD industry did not create telemetry, but adapted it from other disciplines


Mud Pulse Telemetry

• Mud pulse telemetry utilizes an incompressible transmission path (mud column in drillpipe) to carry pressure waves created by a downhole pulser

• Sensor data can be encoded in many different ways (manchester, pulse position modulation, etc.), but all of these methods require the pressure pulses to be detected at the surface in order for the data to be decoded



Positive Mud Pulse Telemetry

• Positive mud pulse telemetry uses a hydraulic poppet valve to momentarily restrict the flow of mud through an orifice in the pulser

• This generates an increase in pressure in the form of a positive pulse or pressure wave which travels back to the surface and is detected by a transducer on the standpipe and/or pumps

• Precision’s main LWD telemetry method is Positive Pulse


Negative Mud Pulse Telemetry

• Negative mud pulse telemetry uses a controlled valve to vent mud momentarily from the interior of the tool into the borehole annulus

• This generates a decrease in pressure in the form of a negative pulse or pressure wave which travels back to the surface and is detected at the standpipe and/or pumps



Mud Pulse Telemetry Advantages

• Simple mechanical operation• Reliable if maintained properly• Original telemetry method; 20+ years of development and

improvement history


Mud Pulse Telemetry Disadvantages

• Transmission medium must be incompressible (no air in mud column)

• Slow data transmission rates (1 to 3 bits/sec)• Advanced signal processing techniques are required

to reduce the effects of distortion and noise within the telemetry band

• Limited two-way downlink capability (series of pump cycles to switch between 2 fixed modes)

• Negative pulse systems require ample pressure drop below the valve to generate sufficient pulse amplitude

• Positive pulse systems require the use of drillpipe screens



Electromagnetic Telemetry

• EM emitting antenna injects an electric current into the formation around the hole

• An electromagnetic wave is created, which propagates in the formation while being “channeled” along the drillstring

• Data is transmitted by current modulation and decoded at the surface

• Propagation of EM waves along the drillstring is strongly enhanced by the guiding effect of the electrically conductive drillstring

Transmitter-Receiver

EarthAntenna

Bi-directionalTransmission

EmittingAntenna

Drill BitInjectedCurrent


Electromagnetic Telemetry

• Signal attenuation is affected by the frequency of transmission, strength of signal received, and the level of parasitic electrical interference upon the carrier signal

• Works on Ohm’s Law principle (V = IR)

• Precision’s LWD system is able to utilize EM telemetry



Electromagnetic Telemetry Advantages

• No restriction on drilling fluid characteristics; drilling fluidcan be incompressible or compressible (allows for use in Underbalanced Drilling applications)

• Reduced survey/connection time (tool is always on; no need to cycle pumps to turn tool on and off)

• Unlimited two-way communication with the downhole tool• No moving parts


Electromagnetic Telemetry Disadvantages

• Slow data transmission rate (1-3 bits/sec)

• Suffers higher vibration in underbalanced applications

• Standard EM setup suffers extreme signal attenuation at excessive depths or if high resistivity “barrier” formations are present at the emitting antenna

• “Extended Range” EM setup can be used to relocate the point of telemetry nearer to the surface receiver; this requires hanging off a wireline in the hole

The Borehole Environment 1


CRCM_revE_0605

The Borehole Environment


The Borehole Environment

• We will consider the borehole environment to be the borehole annulus and the formation affected by invasion of the drilling fluid

• Any physical barrier between the sensor detector and the uninvaded formation rock must be accounted for prior to log interpretation

• Key aspects to discuss:– Drilling Fluid Properties– Formation Properties– Formation/Borehole Pressure Differential



Radial Borehole Profile

• KEY POINT:–LWD sensors do not

preferentially measure the virgin formation alone; their response is affected by whatever is between the sensor and the uninvaded formation


Drilling Fluid Properties

• Drilling Fluid provides many critical functions during the drilling of a well:

• Hole cleaning (transport of cuttings)• Solids suspension (gel strength, PV/YP)• Bit hydraulics (aid the bit in rock failure and chip removal)• Lubricity (reduce torque and drag)• Control formation damage (oil-based mud, fluid loss)• Hole stability (control formation pressure, prevent hole

collapse, inhibit shale swelling)• Cooling the BHA



Drilling Fluid Properties

Drilling fluid can also create some unfortunate “side effects”:

• Decreases drilling rate as mud density increases• Causes real-time data detection problems if mud

viscosity is too high• Can cause irreversible formation damage• Expensive – oil-based mud requires careful containment

and cutting recycling processes• Percolates into permeable formation pore spaces (in

overbalanced situations) making log interpretation more difficult and complex

• Renders some logging tools unusable or ineffective (oil-based mud, salt saturated mud) and can severely alter sensor response (mud additives)


Formation Properties

• The physical makeup of the formation will affect sensor response. Some of the properties that we must consider are:

• Formation Porosity• Formation Permeability• Pore Fluid Saturation and Density• Lithology• Formation Thickness• Shale Content



Formation Porosity

• Total porosity is the ratio of the total pore space volume to the bulk formation volume

• For example, a total porosity of 25% means that per cubic foot of formation, there is ¼ cubic foot of void space dispersed throughout (a sponge is a good analogy)

• Maximum theoretical porosity is 48% if the grains are same size perfect spheres stacked on end (perfect sorting, cubic packing)

• Porosity is the ultimate storage space for formation fluids (gas/oil/water)


Formation Porosity

• Effective porosity is the ratio of the volume of all the interconnected pores to the total volume of a rock unit

• Only the pores that are connected with other pores are capable of accumulating petroleum

• Effective porosity depends upon how the rock particles were deposited and cemented as well as upon later diagenetic changes



Formation Permeability

• Formation Permeability is a measure of how easily fluid flows through interconnected formation pore spaces

• Permeability is a function of the size of the pore openings, the viscosity of the fluid, and the pressure acting on the fluid

• By definition, one darcy of permeability is equal to 1 cc/sec of flow of 1 cp viscosity fluid from a core sample with an area of 1 cm2 at a differential pressure of 1 atm

• Permeability indicates the potential mobility of the fluids from the formation during production



• The basic unit is the Darcy; 1/1000 of a Darcy is a millidarcy (md)

• The permeability of sandstones commonly ranges between 0.01 and 10,000 md

• For comparison a piece of writing chalk has a permeability of about 1 md

100-1000 md10-100 md1-10 md<1 md

Very GoodGoodFairPoor




• Although closely related, permeability and effective porosity are not the same

• Differences in capillarity, the ability of a fluid to cling to the rock grains, may make the permeability of a given rock relatively high for gas, lower for water, and near zero for viscous oils

• Permeability can vary with direction of flow• Pore connections may be less numerous, narrower, or

less well aligned in one direction than another


Fluid Accumulation

• Most petroleum reservoirs are “water-wet”, meaning that the rock grains were originally filled with water (deposited in marine environments)

• All reservoirs will contain some irreducible water component due to the strong attractive forces between the connate, or original water and the rock grain surfaces (bound water)

• Any hydrocarbons present are a result of displacement of any movable water

• Most oil fields have 50-80% maximum oil saturation• Above 80%, the oil can be produced with very little water

mixed in• Below 10%, the oil is not recoverable



Pore Fluid Saturation and Density

• All available pore space will be filled with fluid• There will always be water present within the pore space• The sum of the fluid saturations of gas, oil, and water is

100% (Sg + So + Sw = 100%)


Pore Fluid Saturation and Density

• If gas, oil, and water are present in a formation they will be distributed by density

• Gas will be on top, followed by oil, then water• The type of fluid filling the formation pore space will

affect LWD sensor response in very distinct ways



Lithology

• Lithology corrections are required for some sensor data when logging formations different from the calibration standard which is typically limestone


Formation Thickness

• When formations beds are thinner than the vertical resolution of the sensor, the response of that sensor will not be able to yield a “true” formation value due to the effect of the surrounding “shoulder beds”



Shale Content

• Clays can be distributed in sand formations in three different ways: dispersed, laminated, and structural

• Regardless of the distribution, different clay types have properties that affect all LWD sensor responses

• Shale content calculations are key to correcting LWD data


Pressure Differential

• The pressure differential between the borehole and the formation can have a large effect on LWD sensor response

• There are 2 scenarios to consider:– Overbalanced– Underbalanced



Overbalanced Condition

• An overbalanced condition exists when the bottomhole circulating pressure is greater than the formation pressure

• Although this condition is considered the safest method to drill under it can cause the following undesirable effects:

– Drilling Fluid Invasion

– Terminal fluid loss

– Differential sticking of drillpipe

– Low drilling penetration rates

– Expensive drilling fluid systems

– Expensive and ineffective stimulations


Conventional Overbalanced Drilling

• Overbalance for well control• Filtercake for fluid loss• Fluid designed for rock compatibility• Post drilling treatment• Casing and cement• Perforation and stimulation



FLUIDFLUID

INVASIOINVASIONN

FLUIDFLUID

INVASIOINVASIONN

Filter CakeFilter Cake

ShallowShallowMatrixMatrixDamageDamage

WellboreWellbore

Wellbore Wellbore CrossectionCrossection

RESERVOIRRESERVOIR

Conventional OBD Wellbore


OBD In Horizontal Wells

• Extended wellbore exposure• Mechanical filtercake erosion• Significant fluid loss• Poor post drilling cleanup• Ineffective completion stimulation• Permanent permeability impairment• Limited reservoir deliverability



INVASIONINVASION

INVASIONINVASION

RESERVOIRRESERVOIR

OBD Horizontal Wellbore


Drilling DamageDrilling Damage

Fracture Fracture PluggingPlugging Pore PluggingPore Plugging

Filter CakeFilter CakeWellbore CrushingWellbore Crushing

ShallowShallowMatrixMatrixDamageDamage

OBD Damage



Underbalanced Condition

• Underbalanced drilling can reduce or eliminate some of the problems associated with overbalanced drilling by reducing the bottomhole circulating pressure to pressures below or equivalent to the formation pressure

• Underbalanced drilling has the following benefits:

– Controlled inflow of reservoir fluid or gases during drilling operations

– Controlled drilling condition while accurately separating and measuring recovered drilling fluids as well as produced liquids and gases

– Higher rates of penetration

– Eliminates differential sticking

– Uses simplified drilling fluid systems

– Allows formation evaluation to be conducted during drilling*

• *A major disadvantage is that conventional LWD mud pulse telemetry systems cannot be used in compressible drilling fluids; only electromagnetic telemetry can be used

Directional 1


CRCM_170_revE_0605

LWD Sensor TheoryApplication & Interpretation

Directional


Importance of Directional Data

“Delivery of high quality, accurate directional data is your highest priority

on my wellsite”

- the customer

Directional 2


Importance of Directional Data

• Things to remember:– You only have one chance to put the hole in the

right spot– You can’t assume that because the computer

comes up with an answer that it’s always correct (GIGO)

– It costs the company lots of money (profit) to correct a directional data screw up


Implications of Bad Directional Data

• Well is drilled at wrong inclination or in wrong direction• Well collides with another well• Well crosses a lease line• We lose credibility with the customer• You potentially lose your job

Directional 3


What is Survey Data?

• A survey, or more appropriately a survey station, consists of the following components:

– Inclination– Hole Direction (Azimuth)– Measured Depth

• The highest quality survey data is best achieved as a static measurement

• Survey data tells the directional driller where the hole has been

• Inclination and hole direction are downhole directional sensor measurements

• Measured depth is a surface derived depth monitoring system measurement


Inclination

• Inclination is the angle, measured in degrees, by which the wellbore or survey instrument axis varies from a true vertical line

• An inclination of 0° would be true vertical• An inclination of 90° would be horizontal.

Directional 4


Hole Direction

• Hole direction is the angle, measured in degrees, of the horizontal component of the borehole or survey instrument axis from a known north reference

• This reference is true north or grid north, and is measured clockwise by convention

• Hole direction is measured in degrees and expressed in either azimuth form (0° to 360°) or quadrant form (NE, SE, NW, SW)


Measured Depth

• Measured depth refers to the actual length of hole drilled from the surface location (drill floor) to any point along the wellbore

Directional 5


What is Steering Data?

• Steering, or toolface data, is dynamic data and tells the directional driller the position of the bend of the mud motor

• Orienting the bend to the desired position allows him to control where the hole will be going

• There are two types of toolface data– Magnetic– Highside (Gravity)


Magnetic Toolface

• Magnetic toolface is the direction, in the horizontal plane, that the mud motor bend is pointing relative to the north reference

• Magnetic Toolface = Dir Probe Mag Toolface + Total Correction + Toolface Offset

• Magnetic toolface is typically used when the inclination of the wellbore is less than 5°

• The magnetic toolface reading is whatever magnetic direction the toolface is pointed to

Directional 6


Gravity Toolface

• Gravity toolface is the angular distance the mud motor scribeline is turned, about the tool axis, relative to the high side of the hole

• Gravity toolface = Dir Probe Gravity Toolface + Toolface Offset

• If the inclination of the wellbore is above 5°, then gravity toolface can be used

• The toolface will be referenced to the highside of the survey instrument, no matter what the hole direction of the survey instrument is at the time

• The toolface will be presented in a number of degrees either right or left of the highside


Gravity Toolface

• For example, a toolface pointed to the highside of the survey instrument would have a gravity toolface of 0°

• A toolface pointed to the low side of the survey instrument would have a gravity toolface of 180°

• If the probe highside point was rotated to the right of highside, the gravity toolface would be 70° to the right.

Directional 7


Electronic Accelerometer & Magnetometer Axes

• “Z” axis is along the length of the probe (axial plane)

• “X” and “Y” are in the cross-axial plane and are perpendicular to each other and to the “Z” axis

• “Highside” is aligned with the “X” axis• All three axes are “orthogonal” to each

other


Quartz-Hinge Accelerometers

• Respond to the effect of the earth’s gravitational field in each plane

• An alternating current (AC) is used to keep the quartz proof mass in the reference position as the accelerometer is moved relative to gravity

• The intensity of the “bucking” current is related to the gravitational force felt by the accelerometer

Directional 8


Fluxgate Magnetometers

• Respond to the effect of the earth’s magnetic field in each plane

• The magnetometer contains two oppositely wound coils around two highly magnetically permeable rods

• As AC current is applied to the coils, an alternating magnetic field is created, which magnetizes the rods

• Any external magnetic field parallel with the coil will cause one of the coils to become saturated quicker than the other

• The difference in saturation time represents the external field strength.


Earth’s Magnetic Field

• The outer core of the earth contains iron, nickel and cobalt and is ferromagnetic

• The Earth can be imagined as having a large bar magnet at its center, lying (almost) along the north-south spin axis

• Although the direction of the field is magnetic north, the magnitude will be parallel to the surface of the Earth at the equator and point steeply into the Earth closer to the north pole

Directional 9


Earth’s Magnetic Components

• M = Magnetic North direction• N = True North direction• Btotal = Total field strength of the

local magnetic field• Bv = Vertical component of the local

magnetic field• Bh = Horizontal component of the

local magnetic field• Dip = Dip angle of the local

magnetic field in relationship to horizontal

• Dec = Variation between the local magnetic field’s horizontal component and true north

• Gtotal = Total field strength of the Earth’s gravitational field


Dip Angle vs. Latitude

• Lines of magnetic flux lie perpendicular (90°) to the earth’s surface at the magnetic poles

• Lines of magnetic flux lie parallel (0°) to the earth’s surface at the magnetic equator

• Dip Angle increases as Latitude increases

• As dip angle increases the intensity of the horizontal component of the earth’s magnetic field decreases

Directional 10


Dip Angle vs. Latitude

• At the magnetic equator, Bh = Btotal, Bv = 0

• At the magnetic poles, Bh = 0, Bv = Btotal

• Bh is the projection (using the dip angle) of Btotal into the horizontal plane

Bh = Btotal

Bv = Btotal Bh = 0

Bh = Btotal(cos Dip)

Btotal

Bv = Btotal(sin Dip)


Magnetic Declination

• Complex fluid motion in the outer core causes the earth’s magnetic field to change slowly and unpredictably with time (secular variation)

• The position of the magnetic poles also change with time• However, we are able to compensate for this variability by

applying a correction (declination) to a magnetic survey which references it to true north

Directional 11


Magnetic Pole Movement (1945 – 2000)

North Pole

South Pole


True North

• True north, or geographic north, is aligned with the spin axis of the Earth

• True north does not move making it a perfect reference

• A survey referenced to true north will be valid today and at any time in the future

• The correction we apply to change a magnetic north direction to a true north direction is called declination.

Directional 12


Applying Declination

• To convert from Magnetic North to True North, Declination must be added:

• True Direction = Magnetic Direction + Declination• Important Note:

–East Declination is Positive & West Declination is Negative in both the northern and southern hemispheres


Applying an East Declination

• An east declination means that magnetic north is east of true north

• For example, if magnetic north hole direction is 75° and the declination is 5° east, the true north direction would be calculated as follows:True Direction = Magnetic Direction + Declination80° = 75° + (+5°)

Directional 13


Applying a West Declination

• A west declination means that magnetic north is west of true north

• For example, if magnetic north hole direction is 120° and the declination is 5° west, the true north direction would be calculated as follows:True Direction = Magnetic Direction + Declination115° = 120° + (-5°)


Implications of an Incorrect Declination

• Since declination is a addition of degrees of correction to the magnetic hole direction, any mistakes made to the declination have serious consequences.

• For example, if you intend to apply a +18° declination but instead input a -18 ° declination, your reported hole direction will be wrong by 36°!

• This mistake may not be detected until the data is compared against independent survey data

Directional 14


Grid Convergence

• Corrects for the distortion caused by projecting the curved surface of the earth onto a flat plane

• Correction becomes more severe moving from the equator towards the poles

• Two common projection methods are Transverse Mercator and Lambert


UTM Grid Projection

• In the Universal Transverse Mercator Grid, the earth is divided into sixty, 6° grid zones

Directional 15


Convergence is zero here

Grid Zones

• A central meridian bisects each 6° grid zone

• Each central meridian is along true north

• If directly on the central meridian or on the equator, the grid correction is ZERO


Grid Zones

• Convergence correction increases as location moves away from the equator and central meridian

• Convergence should not be more than ±3º, otherwise the incorrect central meridian has been chosen

Maximum Grid Correction

Directional 16


Grid Zones

• For rectangular coordinates, arbitrary values have been established within each grid


Comparing Grid Projections

• Different projections yield varying views in terms of distance, shape, scale, and area

Directional 17


Applying Convergence

• To convert from Grid North to True North, Convergence must be subtracted:

• Grid Direction = True Direction – Convergence

• Important Note:–East Convergence is Positive & West Convergence is Negative in the Northern Hemisphere

–East Convergence is Negative & West Convergence is Positive in the Southern Hemisphere


Applying an East Convergence

• An east convergence means that grid north is east of true north

• For example, if true north hole direction is 70° and the convergence is 3° east, the grid north direction would be calculated as follows:Grid Direction = True Direction -Convergence 67° = 70° - (+3°)

Directional 18


Applying a West Convergence

• A west convergence means that grid north is west of true north

• For example, if true north hole direction is 120° and the convergence is 3° west, the grid north direction would be calculated as follows:Grid Direction = True Direction -Convergence 123° = 120° - (-3°)


Applying Declination and Convergence Simultaneously

• Replacing the formula for a true north direction in the grid north direction equation gives us the following formula:

Grid Direction = Magnetic Direction + Declination – Convergence

(Declination – Convergence) is called the Total Correction

• If magnetic declination is 5° east and the grid convergence is 3° west, and the magnetic direction is 130°, the grid direction is calculated as:138° = 130° + (+5°) - (-3°)

Directional 19


Static Survey Procedure

• Drill down to the end of the joint or stand and stop rotating

• Work the pipe up and down to release any built up torque in the drillstring

• Lower the bit to the survey point and shut down the pumps

• Wait 30 – 40 seconds• Turn on the pumps and transmit the survey to the

surface (pipe may be moved slowly while sending up the survey)


Sources of Real-time Inclination Errors

These factors can introduce error into the inclination value presented to thedirectional driller:

• Movement during a survey (axial or rotational) • Accelerometer or associated electronics failure• Calibration out of specifications• Sensor measurement accuracy• Real-time Data resolution

Directional 20


Inclination Quality Checks

• Does the inclination value match the actions of the directional driller?

• Is Gtotal within ± 0.003 g of the Local Gravitational Field Strength?

222 GzGyGxGtotal ++=


Sources of Real-time Azimuth Errors

These factors can introduce error into the hole direction value presented to the directional driller:

• Magnetic Interference (axial or cross-axial)

• Magnetometer or associated hardware failure

• Calibration out of specification

• “Bad” accelerometer input (inclination and highside toolface are part of the calculation!)

• Mathematical Error (at 0° and 90° inclination)

• Sensor measurement accuracy

• Real-time Data resolution

• Latitude, Inclination, Hole direction

• Wrong Declination and/or Convergence

Directional 21


Azimuth Quality Checks

• Does the azimuth value match the actions of the directional driller?

• Is Btotal within ± 350 nT of the Local Magnetic Field Strength?

• Is Gtotal within ± 0.003 g of the Local Gravitational Field Strength?

222 BzByBxBtotal ++=


Additional Survey Quality Checks

• Is the calculated Magnetic Dip value within ± 0.3º of the Local Magnetic Dip value?

• MDIP utilizes inputs from the accelerometers and magnetometers but is not as sensitive of a quality check as Gtotal and Btotal

• It is possible for the MDIP to be out of specification even if the Gtotal and Btotal are not

• NOTE: MDIP should not be used as sole criteria to disqualify a survey if Gtotal and Btotal are within specification

( )BtotalGtotalGzBzGyByGxBxASINMdip ∗∗+∗+∗= )()()(

Directional 22


Survey Quality Checks

222 GzGyGxGtotal ++=

222 BzByBxBtotal ++=

( )BtotalGtotalGzBzGyByGxBxASINMdip ∗∗+∗+∗= )()()(


Survey Quality Check Limits

• Gtotal = Local Gravity ± 0.003 g

• Btotal = Local Field ± 350 nT

• MDIP = Local Dip ± 0.3°

Directional 23


Survey Quality Example #1

• Given the following survey data, decide if each quality check is within limits

• Local References: Gtotal = 1.000 g Btotal = 58355 nT Mdip = 75.20°

INC AZ Gtotal Btotal MDip3.72 125.01 1.0012 58236 75.25

• Based on your observations, are the inclination and azimuth values acceptable?



• Given the following survey data, decide whether each quality check is within limits



+0.0012 -119 -0.05

• Based on your observations, are the inclination and azimuth values acceptable? YES / YES

Directional 24












+0.0009 -354 -0.36

• Based on your observations, are the inclination and azimuth values acceptable?YES / NO

Directional 25












-0.0047 -205 -0.92

• Based on your observations, are the inclination and azimuth values acceptable?NO / NO

Directional 26












+0.0120 -732 -1.76

• Based on your observations, are the inclination and azimuth values acceptable?NO / NO

Directional 27


Survey Calculation Methods

• Once we have verified the quality of the inclination, hole direction, and measured depth values at the survey station the data is then passed to the directional driller

• Survey calculations are performed between survey stations to provide the directional driller with a picture of the wellbore in both the vertical and horizontal planes

• If the input parameters are identical the calculated survey values on your survey report should match the directional drillers’


Survey Calculation Methods

• Survey calculations are more easily understood by applying basic trigonometric principles

Directional 28


Tangential Calculation Method

• Assumes that the borehole is a straight line from the first survey to the last


Average Angle Calculation Method

• Assumes distances from survey to survey are straight lines

• Fairly accurate and conducive to hand calculations

Directional 29


Radius of Curvature Calculation Method

• Applies a “best fit” curve (fixed radius) between survey stations

• More accurately reflects the shape of the borehole than Average Angle


Minimum Curvature Calculations

• Uses multiple points between survey stations to better reflect the shape of the borehole

• Slightly more accurate than the Radius of Curvature method

Directional 30


Comparison of Calculation Methods

• Total Survey Depth @ 5,985 feet• Maximum Angle @ 26°• Vertical hole to 4,064 feet, then build to 26° at 5,985 feet• Survey Intervals approximately 62 feet


Survey Terminology

Directional 31


Survey Terminology

• Survey Station

– Position along the borehole where directional measurements are taken

• True Vertical Depth (TVD)

– The projection of the borehole into the vertical plane

• Measured Depth (MD)

– The actual distance traveled along the borehole

• Course Length (CL)

– The measured distance traveled between survey stations


Survey Terminology

• Horizontal Displacement (HD)– Projection of the wellbore into the

horizontal plane– Horizontal distance from the

wellhead to the last survey station– Also called Closure

• Latitude (Northing)– The distance traveled in the north-

south direction in the horizontal plane

– North is positive, South is negative• Departure (Easting)

– The distance traveled in the east-west direction in the horizontal plane

– East is positive, West is negative

Directional 32


Survey Terminology

• Target Direction– The proposed direction of

wellbore • Vertical Section (VS)

– The projection of the horizontal displacement along the target direction

– The horizontal distance traveled from the wellhead to the target along the target direction

• Dogleg Severity (DLS)– A normalized estimate (e.g.,

degrees/ 100 feet) of the overall curvature of an actual well path between two consecutive survey stations


Vertical Section Calculation

• To calculate vertical section the closure (horizontal displacement), closure direction, and target direction must be known

• The vertical section is the product of the horizontal displacement and the difference between the closure direction and target direction

VS = HD *cos (Target Direction –Closure Direction)

Directional 33


Vertical Projection

• In the vertical projection the directional driller plots True Vertical Depth versus Vertical Section

• The wellbore must pass through the vertical target thickness along the vertical section direction in order to hit the target in this plane

Kickoff Point

True

Ver

tical

Dept

h

Vertical Section

Tangent

Build Section

Locked in Section


Horizontal Projection

• In the horizontal projection the directional driller plots Latitude versus Departure

• The wellbore must pass through the horizontal target radius along the proposed target direction in order to hit the target in this plane

N

E

Latitude

Departure

ProposalDirection

Closure

Vertical Section

Gamma Ray 1


Gamma Ray

CRCM_170_revE_0605


Gamma Ray

Shale

GasOil

Salt Water

Salt

Shale


Gamma Ray

Gamma Ray Sensor Theory

• Natural Gamma Ray devices are “passive” detectors of radioactive gamma ray decay occurring within formations

• The three most common gamma emitting isotopes found in the earth’s crust are Potassium-40, Thorium-232, and Uranium-238

• High gamma counts measured by the sensor indicate a high concentration of radioactive material

• Natural gamma devices cannot distinguish the origin of the gamma radiation because of the type of detector they employ (Geiger-Mueller tubes)

Gamma Ray 2


Gamma Ray


• Potassium and Thorium are typically associated with clay minerals which are a large component in SHALE

• Log analysts generally infer that high gamma count formations are shale and low gamma count formations are “non-shales” (sandstone, limestone, halite, gypsum, coal, etc.)

• Gamma count values higher than the shale baseline are uncommon and are typically seen in rock of volcanic origin or inpermeable reservoir rock where uranium has precipitated out in the pore space

• Gamma Ray sensors indicate matrix clay content, but DO NOT directly reveal fluid contents (i.e., gas, oil, water)

• Can be run in any environment – air, any salinity fluid, oil-based fluids, open hole or cased hole wells


Gamma Ray


• Spectral Gamma Ray devices are also “passive” detectors of radioactive gamma ray decay occurring within formations

• Unlike natural gamma devices, however, the spectral device uses a detector which can distinguish the origin of each gamma ray it detects

• This can be done because potassium, thorium, and uranium each have unique decay spectrums

Decay Spectrums of Potassium, Thorium, & Uranium

1.46

0.23

0.61

Gamma Ray 3


Gamma Ray


• Azimuthal Gamma Ray devices are also “passive” detectors of radioactive gamma ray decay occurring within formations

• The azimuthal gamma detector is partially shielded to attenuate gamma radiation on one side of the tool and uses an accelerometer to give information about the up or down position of the unshielded “window” during the measurement

• Used in “geosteering” applications


Gamma Ray

Gamma Ray Sensor Applications

• Lithology Identification • Formation Thickness• Stratigraphic Correlation• Geosteering• Shale Volume Estimation

Gamma Ray 4


Gamma Ray


Lithology Identification• Shale versus “non-shale”

indicator• Low gamma response can

indicate potential reservoir rockFormation Thickness• Differences in the radioactivity

level between formations allows log analysts to use gamma data to determine formation thickness

• The thick sandstone interval in the example is well defined on the gamma curve


Gamma Ray


Stratigraphic Correlation• Gamma data can be used to

correlate formation tops and “marker beds” between nearby wells to help determine geologic structure and the areal extent of the reservoir

• Marker beds generally show responses that are very different from the surrounding beds

Gamma Ray 5


Gamma Ray


Geosteering

• The intentional directional control of a well based on the results of downhole geological logging measurements rather than three-dimensional targets in space, usually to keep a directional wellbore within a pay zone

• In mature areas, geosteering may be used to keep a near horizontal wellbore in a particular section of a reservoir

• Azimuthal Gamma Ray sensors were designed specifically for geosteering applications


Gamma Ray


• Shale Volume Estimation– Shale Volume is the ratio between

the zone value and the spread between the clean and shale lines

– Used to correct other formation evaluation sensor data for the effect the shale has on the data

– Example calculation:VSH (%) = GRlog – GRclean X 100

GRSH – GRclean

VSH (%) = 50 – 25 X 100

75 – 25

VSH (%) = 50%

Shale Baseline (75 api)

Clean Line (25 api)

Zone of Interest (50 api)

Gamma Ray 6


Gamma Ray

Gamma Ray Data Interpretation

• Lithology response is different between shale and sandstone due to the varying amounts of radioactivity within the matrix of each

• No change in gamma response in the sandstone despite the change in fluid type through the formation

• Gamma data can NOT be used to identify the presence or type of hydrocarbon in the formation

Shale

Shale

Sandstone

Gas

Oil

Salt H2O


Gamma Ray


• Shale is fairly consistent over short intervals allowing the analyst to determine the “shale baseline”

• Halite (NaCl), which is not a reservoir rock, has an extremely low gamma response because it is pure and has no radioactive components

• Gypsum, anhydrite, coal are other formation types that will generate very low gamma counts

Shale

GasOil

Salt Water

Halite

Shale

Gamma Ray 7


Gamma Ray


• Log analysts can make qualitative inferences based on the shape and trend of the gamma curve

• This is an example of a sandstone “cleaning up” (decreasing in shale content) from top to bottom


Gamma Ray


• The Spectral Gamma Ray’s ability to determine the potassium, thorium, and uranium components of a formation may allow the log analyst to identify specific clay mineralogy

• Spectral analysis can also be used to reveal situations that could cause the analyst to misinterpret some log responses

• In the isolated zone in the example, the natural gamma curve shows higher radiation than the zones above and below it, indicating shale; the zone is actually a sandstone with a high concentration of uranium

Natural GR Spectral GR

Pressure 1


PressureCRCM_170_revE_0605


Pressure


Pressure

Pressure Sensor Theory

• Downhole pressure sensors are drilling performance tools that provide continuous and direct downhole measurement of absolute bore and annular pressure

Pressure 2


Pressure


• Bore pressure communicates with the transducer through a hole on the inside of the insert

Annulus Pressure PortAnnulus Pressure Port

Bore Pressure PortBore Pressure Port


Pressure


• Annulus pressure communicates with the transducer through a hole on the outside of the collar

Annulus Port

Pressure 3


Pressure


• Real-time LWD pressure measurements provide information on downhole hydraulics and fluid performance that help the driller avoid drilling problems and optimize the drilling process

• Safe Operating Envelope– For safe drilling the equivalent mud density must

remain between• Minimum Fracture Pressure• Maximum Pore Pressure


Pressure


• Annulus Pressure– Hydrostatic density of the mud column plus frictional losses in the

annulus from the pressure sensor to surface• Bore Pressure

– Hydrostatic density of the mud column plus frictional losses through the BHA below the pressure sensor, pressure drop through the bit and frictional pressure losses in the annulus from the bit to the surface

• Differential Pressure– Difference in pressure between the bore and annulus pressure

gauges– Provides the pressure across the BHA and through the bit– Used to monitor motor performance, blockage at the bit, washout

in the lower BHA, and evaluating where packoff is occurring

Pressure 4


Pressure


• Equivalent Mud Weight (EMW)

– Static (pumps off) EMW is equal to the average density of the static mud column

– Dynamic (pumps on) EMW is equal to the average density of the static mud column plus annular frictional pressure losses; commonly called Equivalent Circulating Density (ECD)

K=.052 (Pressure in psi, TVD in feet, EMW in lb/gal)

K=.00981 (Pressure in Pa, TVD in meters, EMW in g/cc)

KTVDpressureEMW ∗=


Pressure


• Factors Affecting EMW– Mud Weight– Breaking a Gel– Cuttings Load– Flow Rate– Formation Fluid Influx– Restrictions in the Annulus– Swab and Surge Pressures– Sliding versus Rotary Drilling

Pressure 5


Pressure


• Mud Weight– The measured surface mud weight is the primary

factor controlling downhole pressure– The mud weight sets the baseline around which all

other factors vary


Pressure


• Breaking a Gel– The gel strength of a drilling mud determines its

ability to hold solids in suspension during non-flowing conditions

– The force needed to break the gel and return the mud to a fluid state adds to the annulus pressure losses until the mud is fluid again

Pressure 6


Pressure


• Cuttings Load– Suspended solids in the mud increase the mud

weight, which increases the pressure of the mud column


Pressure


• Flow Rate– The pressure necessary at the bit to push the mud up

the annulus increases with increasing flow rate

Pressure 7


Pressure


• Formation Fluid Influx– When formation fluid flows into the annulus, it

changes the mud properties, which changes the hydrostatic pressure exerted by the mud

– During a gas kick, the gas bubble displaces mud and expands as it rises in the annulus, drastically reducing the annular pressure


Pressure


• Restrictions in the Annulus (Packoff)– Restrictions to circulation increase the pressure

necessary to move the fluid at a specific flow rate– Restrictions can be caused by swelling formations,

poor hole cleaning, hole collapse, fractured formations, or any other formation factor that causes the walls of the borehole to come loose and enter the annulus

Pressure 8


Pressure


• Swab and Surge Pressures– Moving the drillstring axially in the hole displaces the

drilling fluid like a piston in a cylinder– Swabbing the hole decreases the annulus pressure

and surging the hole increases the annulus pressure


Pressure


• Sliding versus Rotary Drilling– The annular fluid flow path when sliding is different

from the flow path when rotating the drillpipe– This changes the resistance to the flow, the type of

flow regime, and the path length of the flow

Pressure 9


Pressure

Pressure Sensor Data Interpretation

•Leak Off Test Data– Tests the integrity of the

casing shoe and formation– Gives an indication of

formation strength as an upper limit for the ECD to prevent lost circulation


Pressure


• Formation Integrity Test Data– A predetermined pressure (less than the LOT value)

is applied to the formation – Pressure is then observed for a period of time (10 -20

minutes) to see if the formation can hold that pressure

Pressure 10


Pressure


• Circulation & Rotation– During circulation (pumps

on) the EMW increases because cuttings are suspended; the EMW will drop as the cuttings are circulated out

– During pumps off, the EMW decreases to hydrostatic

– Rotation of the drillpipe increases the EMW (see next slide)


Pressure


• How Rotation increases EMW– Rotation changes the eccentricity of the drillpipe

which adds turbulence that requires more pressure to move the fluid; this effect is increased with increasing hole inclination and rotation speed

– Rotation keeps solids suspended which increases mud weight; how much of an increase is determined by the rate of rotation, mud properties, and the well geometry

Pressure 11


Pressure


• Surge and Swab– Surge pressures force

the fluid up the annulus with increased velocity, resulting in an increase in EMW

– Swab pressures force the fluid down the annulus; this subtracts from the pressures felt at the sensor and lowers the EMW

– Running speed and “tightness” of the hole will dictate the severity of the change in EMW


Pressure


• Rig Heave– When the bit is off bottom

and there is no active rig heave compensation, rig heave causes low frequency reciprocal surge-swab variations in the EMW

– In this North Sea example, rig heave during high seas in winter caused enough swab to collapse the hole and induce packoff, lost circulation, and hole fill

Pressure 12


Pressure


• Poor Hole Cleaning– Uneven EMW

during drilling is an indication of poor hole conditions and varying restrictions to circulation


Pressure


• Gas Influx– Gas influx into the annulus

appears as a rapid and sometimes dramatic decrease in the EMW

Pressure 13


Pressure


• Salt Water and Sand Influx during Riserless Drilling

– A salt water kick from an unconsolidated formation can carry sand into the annulus resulting in an increase in EMW


Pressure


• Gel Strength Pressure Spikes

– Gellation produces an initial resistance to circulation which may require significant pressure to overcome

– In this example, the gel pressure spikes initiated fractures in the formation which caused lost circulation

Fracture Pressure

Pressure 14


Pressure


• Packoff Pressure Spikes– Packoff occurs when enough settled cuttings are present to

create a restriction in the annulus which causes a sudden increase in EMW

– Packoff usually is a result of hole collapse or poor hole cleaning– Packoff spikes can be large enough to cause formation fracture


Pressure


• Lost Circulation– The pressure sensor does

not provide a direct indication of lost circulation unless the loss is severe enough to cause a loss of hydrostatic head

– Pressure data is often useful in determining how the lost circulation occurred and what the EMW was when it occurred

– In this instance a large reaming down surge immediately preceded a lost circulation incident

Pressure 15


Pressure

Pressure Sensor Applications

This results in a pressure spike only when the packoff is above the pressure sensor

The appearance of a series of positive spikes in the EMW indicates packoff

Detecting Packoff

The pumps-off minimum captures the lowest swab pressure

The pumps-off maximum pressure captures the largest surge or gel pressure experienced during the pumps off cycle

Measuring Pumps-Off Swab and Surge Pressures and Gel Strength of the mud

The data from the test is transmitted to the surface when the pumps come on

The pressure at which there is a break in the slope of the LOT pressure curve indicates the fracture pressure of the formation

Leak Off Test

The data from the test is transmitted to the surface when the pumps come on

Lack of pressure bleed off after shutting in the well indicates the formation will withstand the tested pressure

Formation Integrity Test

CommentsPressure ResponseApplications


Pressure


EMW is the same as the calculated ECD

A decrease of EMW to the input mud weight while circulating indicates the hole is clean

This results from restrictions in the wellbore while circulating

Short term variations in EMW can indicate poor hole cleaning

This results from settled cuttings being lifted back into suspension

A steady increase in EMW while rotating indicates poor hole cleaning

This results from cuttings settling out in high angle wellbores

A gradual decrease in EMW while steering indicates poor hole cleaning

Monitoring Hole Cleaning


Pressure 16


Pressure


A stable EMW between the fracture pressure and pore pressure

Mud Weight Optimization

Often correlates with high rotary torque

Hole collapse causes a sudden increase in EMW as solids load up in the annulus

Detecting Hole Instability

This is usually a dramatic change and not seen at the surface for several minutes

A sudden large decrease in EMW that does not correlate to rig operations

Detecting Gas Influx

The size of the decrease is relative to the mud densities and the volume of influx

A decrease in EMW that does not correlate to rig operations

Detecting Formation Fluid Influx when drilling with mud

EMW shifts with a change in rotary speed or flow

Measuring Pressures from Rotation or Flow


1


LWD Curriculum

LWD

Day 1 Day 2 Day 3

Geology

Directional Drilling

Data Acquisition

Bore Hole Environment

Directional

Gamma Ray

Pressure

Resistivity

Neutron Porosity

Density

Vibration

LWD Tool Specs


MWD Curriculum

MWD

Day 1 Day 2

Geology


Data Acquisition

Bore Hole Environment

Directional

Gamma Ray

Pressure

Resistivity

Neutron Porosity

Density

Vibration

MWD Tool Specs

Resistivity 1


Resistivity

CRCM_170_revE_0605


Resistivity


Resistivity

Resistivity Sensor Theory

• Physical Principles• Electromagnetic wave resistivity sensors respond to the way radio

frequency (RF) waves propagate (move) through the formation• The propagation of an RF wave is controlled by the following physical

properties of the material through which the wave is moving:– Electrical Conductivity, which is the ability of a material to conduct

an electrical current– Dielectric Permittivity, which is the ability of a material to store

electrical charge– Magnetic Permeability, which is the ability of a material to become

magnetized• At transmission frequencies below 10 MHz, the formation conductivity

is the dominant factor• If reasonable assumptions are made for the dielectric permittivity and

magnetic permeability, measured wave parameters can be related to the formation resistivity

Resistivity 2


Resistivity


What does the Electromagnetic Resistivity sensor measure?

• Phase Shift - the time difference of arrival of the RF wave between the two receivers

• Attenuation - the difference in intensity of the RF wave signal at each of the receivers

• Both the phase shift and attenuation data can be used to compute a formation resistivity value


Resistivity


• Electromagnetic waves can propagate through any medium, however, low resistivity (high conductivity) mediums cause the most signal reduction

• Electromagnetic sensors can be used in any type of drilling fluid (they actually perform better in high resistivitymud)

• Salinity of the drilling mud and the formation water, along with the formation temperature and porosity, have the greatest effect on the “apparent” measured resistivity

High

Low

Attenuation

Large

Small

Phase Shift

HighLow

LowHigh

ConductivityResistivity

Resistivity 3


Resistivity


Why two measurements?• The physics behind the

measurements dictate that the attenuation has a deeper depth of investigation than the phase

• However, the dynamic range of the phase is much better than the attenuation

• Typically the phase data is used quantitatively whereas the attenuation data is used qualitatively

Phase DOI Attenuation DOIPhase DOI


Resistivity


• The dynamic range of the phase measurement is between 0.1 and 1000 ohm-m

1000

Resistivity (ohm-m)

0.1 1 10 100

0.01

1

10

0.1

100

Phas

e Shi

ft (°)

Resistivity 4


Resistivity


• The dynamic range of the attenuation measurement is between 0.1 and 100 ohm-m

1000

Resistivity (ohm-m)

0.1 1 10 100

0.001

0.1

1

0.01

10At

tenu

atio

n (-d

B)


Resistivity


• Breaking down the formation components

• Hydrocarbons, rock matrix, and dry clay are infinitely resistive

• Since formation water is the only conductive component in the formation, the amount of water present in the formation volume, its salinity, and the formation temperature drives the resistivity response

Resistivity 5


Resistivity


• Why Multiple Transmission Frequencies?• The choice of transmission frequency is dictated by two

physical phenomena:• The measured phase shift and attenuation values are

more dependent on the formations dielectric permittivity than its resistivity at frequencies greater than 10 MHz

• At frequencies below 100 KHz electrical eddy currents are induced in the steel drill collar, essentially “short circuiting” the measurement between the transmitters and receivers

• Lower frequencies allow for creating higher amplitude signals, which allows for development of sensors with longer transmitter to receiver spacing, which provides deeper depths of investigation

• The more frequencies, the more measurements that can be made


Resistivity


• Why Longer and Multiple Transmitter to Receiver Spacings?

• The depth of investigation of the sensor increases with increasing transmitter to receiver spacing

• Having multiple spacings allows the sensor to “see” at different distances into the formation

• Typical sensor design allows for determination of the flushed zone, invaded zone, and virgin zone resistivities

• The virgin zone resistivity (true formation resistivity) is the most challenging to obtain because the measurement is affected by all the zones in between the sensor and the formation

Resistivity 6


Resistivity


• Shallow, Medium, and Deep spacings provide 2 MHz and 400 KHz transmission frequencies and yield phase and attenuation data (12 curves total)

– Shallow - 16”/ 24”– Medium – 26”/ 34”– Deep – 42”/ 50”

• Digital technology provides very accurate values, even at high resistivities

• Opposing transmitters compensate for thermal and borehole effects


Resistivity

Resistivity Sensor Applications

• Qualitative Hydrocarbon Zone Indentification• Determine Rt in Invaded Zones• Quantitative Petrophysical Evaluation (fluid saturations,

formation porosity)• Identify Movable Fluids (permeability indicator)• Determine Casing and Coring points• Predict Abnormal Formation Pore Pressure• Geosteering

Resistivity 7


Resistivity


Qualitative Hydrocarbon Zone Identification

• In general, when the resistivity response is higher than the shale baseline it is an indication of the presence of hydrocarbons

• In general, when the resistivity response is lower than the shale baseline it is an indication of the presence of salt water

Shale Baseline

Increasing Resistivity


Resistivity


Determine Rt in Invaded Zones

• MWD data is less affected by mud invasion than wireline data

• Typical MWD exposure time is less than one hour, whereas wireline exposure time is generally from one to seven days

Resistivity 8


Resistivity


• Quantitative Petrophysical Evaluation to calculate formation porosity, water saturation, and in-situ reserves

• Archie’s equations provide a quick-look estimation

• Other calculation methods are much more rigorous and take into account many more parameters


Resistivity


• Time-Lapse Logging aids in identifying movable fluids

• Re-logging a potential pay zone and comparing the resistivity values from each pass can qualitatively indicate formation permeability

• Multiple spacing resistivity sensors can provide similar information in a single pass

Resistivity 9


Resistivity


• Casing Point Selection• Resistivity data can be used to

determine acceptable casing points

• Casing is set in non-permeable formations like shale

• Trying to set casing in a permeable sandstone may cause the formation to fracture or even collapse the casing

Set casing here…

… or here


Resistivity


• Coring Point Selection• Resistivity data can be used to

determine coring intervals on subsequent wells drilled after the pilot hole

• Coring is very time consuming and expensive, therefore we would only want to core the hydrocarbon zone and not the salt water zone

Resistivity 10


Resistivity


• Predict Abnormal Formation Pore Pressure

• By monitoring shale resistivity values, the presence of an overpressure transition zone can be seen

• Drilling into formation pressure that is higher than borehole pressure can cause a “kick” and if uncontrolled can result in a “blowout”


Resistivity

OIL SAND

SHALE

GAS SAND

WATER SAND


Geosteering• Objective: Keep wellbore in

oil zone (avoid shale, gas, and water)

• Sensors Required for Geosteering:

• Gamma Ray - to differentiate between shale and sandstone

• Resistivity - to differentiate between oil and water zones

• Neutron porosity and Formation Density – to differentiate between oil and gas zones

Resistivity 11


Resistivity


• The deeper the depth of investigation of the resistivity sensor allows ample anticipation time to prevent drilling into the water leg

Water SaturationWaterOil

Neutron Porosity

Resistivity

Gamma Ray

Zone A Well Path

Rate of Penetration

Zone BWel

l Pat

hD

GR

™G

amm

a R

ay0

(A

API)

100

RO

P50

0

(f

t/hr)

0

EWR

®R

esis

tivity

2

(O

hm-m

)

200

CNφ®

Neu

tron

Por

osity

42

(L

S pu

)

-18

Wat

erSa

tura

tion

SW1

%

0

X000 Measured Depth (Ft) X500

TVD

X50

(ft) X

00


Resistivity

Resistivity Sensor Data Interpretation

General Resistivity Response• Shale response is typically low due

to the high amount of associated water with clays

• The hydrocarbon response (gas and oil) is generally high, and very different from the salt water zone (low)

• Salt has no fluid associated with it therefore its’ response is infinite (off scale high)

Shale

GasOil

Salt Water

Salt

Shale

Resistivity 12


Resistivity

Resistivity Sensor Data Interpretation

Invasion Profiles• Data logged in a high salinity water sand

with fresh mud

• No appreciable invasion seen on the MWD data (1 hour)

• Significant invasion seen on the MAD data (7.5 days, 23”)

• Wireline data shows even more invasion effect (12 days, 63”)

• Shallowest MWD spacing equivalent to wireline shallow guard measurement

• Notice the superior vertical resolution of the MWD data versus the wireline

Deep Shallow

Neutron 1


NeutronCRCM_170_revE_0605


Neutron

3.

4.

2.

1.

FARDETECTORCRYSTAL

NEARDETECTORCRYSTAL

NEUTRONSOURCE

H

H

H

Cl


Neutron

Neutron Porosity Sensor Theory

• The Life of a Neutron• A chemical source (Am241Be) generates neutrons which scatter

into the formation (free neutrons do not occur naturally) “1”• These epithermal, or “fast” neutrons are slowed by collisions

with nuclei in the formation• Hydrogen nuclei are the most efficient at slowing down neutrons

because their atomic masses are very similar (20 to 30 collisions) “2”

• When the neutron is slowed to the point where it is no longer moving and is at a very low energy state it is called a “thermal” neutron

• In this state thermal neutrons are susceptible to being absorbedor “captured” by other nuclei, particularly chlorine “3”

• As thermal neutrons are captured, gamma rays of capture are emitted “4”

• Neutron Porosity tools generally either detect thermal neutrons (3) or gamma rays of capture (4)

3.

4.

2.

1.

FARDETECTORCRYSTAL

NEARDETECTORCRYSTAL

NEUTRONSOURCE

H

H

H

Cl

Neutron 2


Neutron


• The objective of the neutron porosity measurement is to infer the total porosity of the formation by measuring the effect that the matrix and pore fluids have on emitted neutrons (hydrogen content indicator)

• Since neutrons and hydrogen have the same atomic mass (1), when they collide a large amount of energy is transferred from the neutron to the hydrogen atom (billiard balls)

• Typically the only hydrogen in the formation is in water and hydrocarbons

• When neutrons collide with high atomic mass atoms such as Barium(137), little energy is imparted and the neutron bounces off, retaining most of its energy (ping-pong ball and bowling ball)

• When a neutron loses energy, it slows down• This process is called “moderation”


Neutron


• If there is high hydrogen content in the formation in the vicinity of the source, the emitted neutrons will be slowed rapidly, resulting in a short travel distance from the source and low count rates at the detectors

• If there is low hydrogen content in the formation in the vicinity of the source, the emitted neutrons will be not be slowed rapidly, resulting in a long travel distance from the source and high count rates at the detectors

• The measurement relationship is as follows:– High Hydrogen Content = High Porosity = Low Counts– Low Hydrogen Content = Low Porosity = High Counts

1

10

100

1000

10000

0 10 20 30 40 50 60 70 80 90 100

Porosity (pu)

Ave

rage

Det

ecto

r Cou

nt R

ate

(c/s

) Near DetectorFar Detector

Neutron 3


Neutron


• Most LWD Neutron tools are thermal neutron devices• Thermal Neutron devices utilize He3 tubes as detectors• The He3 gas in the tube is very efficient in capturing

thermal neutrons• Despite the apparent simple nature of the measurement

and counts to porosity relationship, the initial derived porosity value is typically far from correct

• Neutron data requires significant environmental correction because of the limited depth of investigation of the sensor (9 – 14”)


Neutron

Neutron Porosity Data Interpretation

• The neutron porosity measurement is so sensitive to hydrogen content that there are some conditions where the sensor will give an erroneous porosity value

– “Bound” water in shales (clay)– Gaseous hydrocarbon zones– Environmental corrections not representative of the

environment during logging– “Off-matrix” lithology

Neutron 4


Neutron


“Bound” Water• The overall negative

charge of clays combined with their large surface area means that a relatively high volume of water can be associated with each clay grain

• This “bound water” is not free to move; it is tightly held to the grain by strong adsorption forces


Neutron


Why is bound water an issue?• For the neutron sensor, bound water (i.e.,

hydrogen) will artificially increase the calculated porosity

• In shale zones (which have very little actual porosity) the neutron sensor will be fooled by the bound water and typically generate porosities in excess of 40%

• If clays are present within a reservoir zone matrix, the bound water will affect the response of the sensor as mentioned above, indicating a higher than actual porosity

• How intense the effect will be depends on the amount and type of clay present

• This phenomenon is known as the “Shale Effect” and is much easier to recognize when analyzing neutron and density data together

Neutron 5


Neutron


Neutron “Gas Effect”

• Neutron collisions with nuclei in gaseous hydrocarbons occur much less frequently than collisions in liquid hydrocarbons because the molecules are spread out much farther

• This apparent lack of hydrogen causes the sensor to give an erroneously low value of porosity

• The sensor typically does not distinguish between oil and water since the hydrogen content of each is very similar

• This phenomenon is known as the “Gas Effect” and is much easier to recognize when analyzing neutron and density data together because the two curves display a distinctive “crossover” effect


Neutron


• Improper Environmental Corrections• Neutron sensor environmental corrections needed:

Hole DiameterMud DensityMud SalinityFormation SalinityTemperaturePressureLithology

• Most of the environmental corrections compensate for the change in hydrogen content seen by the sensor as it logs in conditions different than the calibration standard (Lithology is the exception)

• In other words, if the sensor is not logging in conditions identical to calibration, environmental correction of the data is required

Neutron 6


Neutron


• The corrections which can have the greatest effect on neutron porosity are the mud and formation water salinity values

• Salinity, a measure of the amount of free chlorine ions present in the mud and formation water, must be compensated for because chlorine is a very efficient absorber of thermal neutrons

• If there is high chlorine content, the overall count rates will be reduced, generating a porosity value which is erroneously high

• 150,000 ppm formation water in a 20 percent porosity formation will require a -3 p.u. correction

Formation Salinity @ 150 kppm

-6

-4

-2

0

2

4

6

0 5 10 15 20 25 30 35 40

Porosity (pu)

Cor

rect

ion

(pu)

6" Borehole - Centralized

7.25" Borehole - Centralized

8.5" Borehole - Centralized


Neutron


“Off-matrix” lithology• The lithology correction is typically applied after all other

environmental corrections have been applied• Limestone is the standard (zero correction)• It compensates for the different neutron thermalizing

properties of sandstone and dolomite• The correction is a direct addition or subtraction of

porosity units (PU)• Sandstone and dolomite corrections will be positive and

negative respectively and the amount of correction depends upon the formation porosity

• If the lithology correction is different from the lithology logged, the neutron porosity value will be incorrect

• Salt, which has zero porosity, reads approximately +4 PU in this example because the data has been processed assuming a sandstone matrix

Neutron 7


Neutron


• Obvious “Shale Effect” separation between the neutron and density curves

• Dramatic decrease in neutron porosity in gas zone (“Gas Effect”)

• “Crossover Effect” apparent in gas zones when analyzed with density curve

• Since oil and water have similar hydrogen content, it is difficult to see the oil/water contact (must use in combination with the resistivity curve)

• Since salt (not salt water) has no porosity, and thus no fluid, the neutron curve reads close to zero

Shale

GasOil

Salt Water

Salt

Shale


Neutron

Neutron Porosity Sensor Applications

• Indicates the presence of gaseous hydrocarbon alone, or in combination with the Formation Density sensor

• Hydrocarbon Typing - normalized count rates from the near and far detectors can be used to distinguish gas from oil

• Used with formation density data to determine rock type using crossplots

Neutron 8


Neutron


• The characteristic crossover of the neutron and density curves is an indication of the presence of gas

Gas Crossover

Bulk Density

Neutron Porosity


Neutron


• Near and Far count rates are forced to overlay by choosing appropriate plotting scales in a water (or oil) zone

• When gas is encountered, the deeper depth of investigation of the far detector makes it more sensitive to the gas, creating a separation between the two curves

• This method can be used to distinguishing gas from oil with only neutron sensor data

Near Counts (dash)

Far Counts (dot)

Hydrocarbon Typing

GAS

SS Porosity

Neutron 9


Neutron


• Crossplots allow for lithology and porosity determination from neutron and density data

Neutron-Density Crossplot


Neutron


• Crossplots allow for lithology and porosity determination from neutron and density data

Neutron-Density Crossplot

Density 1


DensityCRCM_170_revE_0605


Density


Density

Density Porosity Sensor Theory

The Life of a Gamma Ray• A Cs-137 source emits gamma radiation

that is focused into the formation at an energy of 0.662 MeV

• Gamma rays collide with electrons in the formation and are scattered, losing energy, not speed, in the process (Compton Scattering)

• Eventually, when the gamma ray is at very low energy (< 100 keV) it is absorbed by an electron-atom system (Photoelectric Effect) and completely disappears

• The sensor measures the number of gamma rays that are scattered back to the detectors

Density 2


Density


• The objective of the density porosity measurement is to infer the bulk density of the formation by measuring the attenuating effect that the matrix and pore fluids have on emitted gamma rays (function of bulk electron density)

• As gamma radiation interacts with materials of high electron density, it loses energy more rapidly

• For example, a 5-cm thick piece of lead would attenuate a gamma ray more efficiently than the human body

• Another by-product of the measurement is the Photoelectric Effect (Pe) which allows the log analyst to determine mineralogy


Density


• The matrix will attenuate gamma radiation more than the pore fluid since it is denser

• If the matrix is sandstone, a 10 p.u., water-filled zone will read higher density than a 30 p.u., water-filled zone

• The measurement relationship is as follows:

– High Bulk Density = Low Porosity = Low Counts

– Low Bulk Density = High Porosity = High Counts

0.20Gas0.80Oil1.00Pure Water

2.30 – 2.70Shale2.03Halite2.98Anhydrite2.87Dolomite2.71Limestone2.65Sandstone

Bulk Density (g/cc)

Matrix

Density 3


Density


• LWD density sensors are “contact” devices, meaning that the detector blade and source are in contact with the borehole wall

• Density data is considered more accurate than neutron and sonic data because the measurement is more direct

• Density sensor data requires some environmental correction because of the limited depth of investigation of the sensor


Density


• The LWD density sensor detectors measure gamma counts through low density windows in a blade on the drill collar

• The “detector blade” is forced against the borehole wall by the rotating action of the drillstring

• The blade will generally not remain in contact 100% of the time creating a condition called “standoff”

Density 4


Density


• In order to compensate for standoff, LWD density tools take many samples per revolution to insure that some samples are taken while in contact with the borehole wall

• These fast samples are then processed using special mathematical techniques and algorithms to calculate an apparent density value at each detector spacing


Density


• If the near and far density values fall on the “spine” (45° line) it indicates that there is no standoff correction needed

• Depending on which side of the spine the point falls will indicate a positive or negative correction

• How severe the correction will be depends on how far from the spine the point falls on a “rib”

“Spine & Ribs” Plot

Density 5


Density


• If standoff exists, the apparent density will typically be too low because of the ratio of the formation density and mud density

• The difference between the near and far density values is used to determine the appropriate standoff correction, which compensates for mud density and blade distance from the formation

0-0.5" Standoff, 1-2 gm/cc Mud

-0.05

0

0.05

0.1

0.15

0.2

0.25

-0.1 0 0.1 0.2 0.3 0.4 0.5

Correction Available (Far - Near Density)

Cor

rect

ion

Req

uire

d (T

rue

-Far

Den

sity

) Company A 6-3/4" ToolCompany B 6-3/4" ToolAES 4-3/4" Tool

Standoff Correction


Density

Density Porosity Data Interpretation

• The density porosity measurement is much less susceptible to environmental effects than the neutron sensor

• It is more or less a “what you see is what you get” type of measurement

• As discussed previously, the problem of standoff during rotation is compensated for with mathematics and the “spine and ribs” correction

• Bulk density data can be converted to density porosity data by making an assumption of matrix type and fluid type and applying the following formula:

φ = (ρma - ρb) / (ρma - ρfl)

Density 6


Density


• For example, if the assumed matrix is sandstone and the assumed fluid is water, a bulk density value of 2.25 g/cc will yield a porosity of:φ = (ρma - ρb) / (ρma - ρfl)φ = (2.65 – 2.25) / (2.65 – 1.00)φ = 24.2%

• Problems can arise if the density porosity value is calculated using the wrong matrix or fluid assumption

• For the example above let’s say we assumed the matrix was limestone when it really was sandstone

• The calculate density porosity would then become:φ = (2.71 – 2.25) / (2.71 – 1.00)φ = 26.9%, which is erroneously high

0.20Gas

0.80Oil

1.00Pure Water

2.30 – 2.70Shale

2.03Halite

2.98Anhydrite

2.87Dolomite

2.71Limestone

2.65Sandstone

Bulk Density (g/cc)

Matrix


Density


• Density (as well as neutron) sensor response is calibrated such that the “true” density (or porosity) value is computed in water-filled zones

• Therefore, the two curves should overlay, if all environmental corrections and assumptions have been properly applied

Density 7


Density


• The “Shale Effect” curve separation and “Gas Crossover” is easily recognized when analyzing the Density and Neutron curves together

• Since oil and water have similar densities, it is difficult to see the oil/water contact (must use in combination with the resistivity curve)

• Since salt (not salt water) has no porosity the density tool should read 2.03 g/cc, which is the density of salt

Shale

GasOil

Salt Water

Salt

Shale


Density

Density Porosity Sensor Applications

• Determine formation bulk density• Determine lithology and specific minerology

(Photoelectric Effect)• Indicates the presence of gaseous hydrocarbon in

combination with the Neutron Porosity sensor

Vibration 1


Vibration

CRCM_170_revE_0605


Vibration


Vibration

Vibration Sensor Theory

• Vibration sensors utilize three mutually orthogonal, DC-coupled accelerometers to measure changes in acceleration along three axes

• The X-axis measures lateral and radial acceleration of the drillstring

• The Y-axis measures lateral and tangential acceleration of the drillstring

• The Z-axis measures the longitudinal (axial) acceleration of the drillstring

Vibration 2


Vibration


• Vibration Mechanisms– Torsional– Axial– Lateral

Torsional Lateral

Axial


Vibration


• Sensor Measurements– Average

Represents the average acceleration over a specified time period

– PeakRepresents the highest acceleration which has occurred over a specified time period

– InstantaneousData sampled at very high rate (up to 2000 Hz) used mainly for frequency analysis

Vibration 3


Vibration

Vibration Sensor Applications

• Vertical or near-vertical wells• High-cost drilling environments where tripping

costs are prohibitive (deepwater drilling)• Harsh drilling environments• Intermediate sections of holes with large

diameters• Large formation washouts• Underbalanced drilling• Areas of hard drilling (low ROP)• Areas of drillstring damage or MWD failures


Vibration

Vibration Sensor Data Interpretation

• Factors Affecting Downhole Vibration– Rotary Speed– Weight on Bit– Hole Inclination– Bottomhole Assembly Configuration– PDC Bits– Lithology– Hole Size

Vibration 4


Vibration


• Rotary Speed

–Rotation of the drillstring is the main source of drillstring excitation

–High RPM creates high the imbalance force to the bit and drillstring, generating more energy to create lateral vibrations or BHA/bit whirl

–Low RPM is also undesirable because it creates higher frictional torque

–If rotary speed matches one of the natural frequencies of the drillstring, resonance can create large scale oscillations in the drillstring

–When a change of RPM is required, a 10 – 15% change in the RPM is usually recommended if it is within constraints of the operator


Vibration


• Weight on Bit– High WOB generally will increase the stability of a

PDC bit but aggravate the roller cone bit vibrations– High WOB can cause the BHA to buckle, resulting in

contact between the collars and borehole wall which can cause BHA whirl and lateral shocks

– When a change of WOB is required, a 10 – 15% change in the WOB is usually recommended if it is within constraints of the operator

Vibration 5


Vibration

0

5

10

15

20

25

30


• Vibration generally increases as WOB and RPM increase

g RMS

25

20

140

30

15130120 150

0

10

5

15

WOB

RPM


Vibration


• Hole Inclination– Severe drillstring lateral vibrations are more likely to

occur in vertical or near vertical wells rather than in highly deviated wells because gravity tends to reduce the amount of lateral displacement

– Torsional vibration (stick-slip) is more likely to occur in deviated holes due to the higher frictional torque involved

Vibration 6


Vibration


• Bottomhole Assembly Configuration– Drilling motors can reduce the energy of interactions between the

rotating BHA and the wellbore, eliminating the chance of BHA whirl and lateral shocks

– Packed hole conventional assemblies are subjected to less vibration than pendulum assemblies

– Long unstabilized spans, such as those found in pendulum assemblies used in vertical drilling, encourage bending and helpinduce collar and bit whirl

– Use full gauge stabilizers if possible – especially in vertical or near-vertical wells

– In extended reach and high angle wells, spiral stabilizers can be used to reduce drag

– Tool joints should be inspected at regular intervals if high levels of vibration have been seen.


Vibration


• PDC Bits– Anti-whirl PDC bits are

more stable than conventional PDC bits

– PDC bits tend to whirl at high RPM’s and in hard formations

– Dull or undergauge PDC bits can induce torsional vibration of the drillstring (stick-slip)

PDC Tri-Cone

Vibration 7


Vibration


• Lithology– Drillstring vibration will

always increase as the formation strength (hardness) increases

– Crossing a bed boundary at an angle can also intensify vibration


Vibration


• Hole Size– An oversized hole can increase the instability of the

drill bit and drillstring, increasing the likelihood of lateral shocks, BHA whirl, and bit whirl

Vibration 8


Vibration


• Torsional Vibration (Stick-slip)– Non-uniform bit rotation in which the bit stops rotating

momentarily at regular intervals causing the string to periodically torque up and then spin free

– Prevalent in high angle and deep (3000’ or more) wells or aggressive PDC bits with high WOB

– Surface torque fluctuation > 15%, PDC bit damage, lower ROP, connection over-torque, and drillstring twistoffs

– Average X – Average Y > 1g– Increase RPM and/or decrease WOB, use less

aggressive PDC bit, reduce stabilizer drag


Vibration


• Axial Vibration (Bit Bounce)– Large WOB fluctuations causing the bit to repeatedly

lift off and impact the formation– Prevalent in vertical wells, roller cone bits in hard rock– Impact loading can damage the bit, drillstring, or

hoisting equipment– High Peak Z acceleration– Decrease WOB and/or decrease RPM, use shock

sub, less aggressive roller cone bit

Vibration 9


Vibration


• Lateral Vibration (Backward Bit Whirl)– Eccentric rotation of the bit about a point other than

its geometric center caused by bit/wellbore gearing (analogous to a “Spirograph”)

– Extremely difficult to recognize on the surface– Prevalent with aggressive side-cutting PDC bits in

hard rock, vertical wells– Bit cutter impact damage, overgauge hole, BHA

connection failures, and MWD component failure– High Peak X and Y accelerations, medium to high

Average X and Y accelerations (equal to each other), frequency analysis shows a large magnitude primary whirl frequency

– Reduce RPM


Vibration


PDC Bit Whirl–Both backward and forward whirl take place with PDC bits

–Backward whirl is destructive for PDC bits

–Backward motion is responsible for the “looped” path of the intermediate cutter trace

–The innermost circle corresponds to the path of the center of the bit

Backward Whirl Pattern

Hole Gauge

Bit Gauge

Center of Hole

Path of the Bits center

Vibration 10


Vibration


• The mold of a cored bottom hole (right) shows a typical whirl pattern resulting from backward whirl.

• With bit whirl, the bit’s cutting pattern is larger, causing the bit to rotate over more surface area producing an irregular shaped and enlarged hole. This causes more bit wear and slows down the penetration rate.

Anti-Whirl Core BitBottom Hole Pattern

Conventional Core Bit with Typical Whirl Pattern


Vibration


• Lateral Vibration (Backward BHA Whirl)– Similar to bit whirl, the BHA gears around the

borehole and results in severe lateral shocks between the BHA and wellbore

– Extremely difficult to recognize on the surface– Prevalent in vertical or near vertical wells, pendulum

or unstabilized BHA’s– MWD component failure, localized tool joint and/or

stabilizer wear, washouts or twistoffs, increased average torque

– Same sensor response and recommended action as bit whirl

Vibration 11


Vibration


• Lateral Vibration (Side Shocks)– BHA moves sideways or sometimes whirls forward

and backwards randomly– Difficult to recognize at the surface– Prevalent in hard rock and unbalanced or long

unstabilized BHA’s– MWD component failure, localized tool joint and/or

stabilizer wear, washouts or twistoffs, increased average torque

– Medium to high Peak X and Y accelerations (equal), low Average X and Y, no dominant peaks in the frequency analysis

– Reduce RPM

Technical Specifications 1


Sensor SpecificationsCRCM_170_revE_0605

LWD System & Sensor Specifications


Sensor Specifications

MWD Versus LWD Systems

• Measurement-While-Drilling (MWD) systems generally include directional and gamma ray sensors, and may include downhole pressure, vibration/shock and temperature sensors

• The system becomes a Logging-While-Drilling (LWD) system when a resistivity, neutron, density or other logging sensor is added to the toolstring




PES LWD Systems (Advantage R&D)

• PrecisionLWD™ system– NOTE: there is no space between Precision and LWD

• Hostile Environment Logging (HEL™) MWD system



HEL™ System

• The HEL™ system is made up of these individual tools and sensors:

– IDS (Integrated Directional Sonde) sensor– ESM (Environmental Severity Measurement) sensor– BAP (Bore/Annular Pressure) sensor– RAT (Rapid Annulus Temperature) sensor *– HGAM (High Temperature Gamma Ray) sensor

or– HAGR (High Temperature Azimuthal Gamma Ray) sensor

or– SAGR (Spectral Azimuthal Gamma Ray) sensor– * RAT must be run in conjunction with BAP (for now)




PrecisionLWD™ System

• The PrecisionLWD system is made up of the components of the HEL™ system, but adds these tools:

– MFR (Multi-Frequency Resistivity) sensor

– TNP (Thermal Neutron Porosity) sensor

– AZD (Azimuthal Density) sensor



Common System Components

• Both systems employ:

– PMT (Pressure Modulated Telemetry) pulser assembly for data transmission

– DBM (Dual Battery Module) assembly for power

– Spectrum surface acquisition software for data acquisition and processing




EMpulse™ System

• The official name of the EM tool is the EMpulse™ electromagnetic MWD system.

• This system utilizes the same components as the HEL system except for the pulser



Revolution™ System

• Benefits over conventional and mud motor drilling– Rotation of drill pipe all the time– Smooth borehole (no corkscrewing)– Less time to complete well




HEL™ System Configuration

• PMT is on top of the toolstring because:

– It is not a sensor– It must be connected to the driver

controller insert (between PMT and DBM)

– Most likely component to be modified in the field (orifice)

• ESM is a component on the driver controller insert

• DBM is used to extend the power capacity of the toolstring

• IDS sensor is on bottom to allow for quicker decisions concerning the directional aspects of the hole



HEL™ System Highlights

• “Industry Best” Features and Benefits:– 30,000 psi pressure rating– Reliable operation at temperatures of up

to 356°F (180ºC), with survival to 392°F (200ºC)

– High flow rates for all size tools: • 4 3/4” up to 400 gpm• 6 3/4” and 8” up to 1000 gpm• 8 ¼” and 9 ½” up to 1800 gpm




HEL™ System Mechanical Specifications

Maximum Tension

Maximum Torque

Makeup Torque

Bottom Connection

Top Connection

Weight

Length HEL System

Maximum Tool O.D.

Nominal Tool O.D.

HEL Specification

528,000 lbs

16,700 ft-lb

9,900 - 10,900 ft-lb

3 1/2” IF pin

3 1/2” IF box

1400 lbs

25.2 ft

5 1/4”

4 3/4”

4 3/4” Tool

978,000 lbs

44,700 ft-lb

28,000 - 32,000 ft-lb

4 1/2” IF pin

4 1/2” IF box

2850 lbs

25.3 ft

7 3/8”

6 3/4”

6 3/4” Tool

1,480,000 lbs

77,300 ft-lb

52,000 - 56,000 ft-lb

6 5/8” Reg pin

6 5/8” Reg box

4100 lbs

25.2 ft

8 5/8”

8”

8” Tool

1,870,000 lbs1,450,000 lbs

112,000 ft-lb80,100 ft-lb

75,000-78,000 ft-lb

53,000-56,000 ft-lb

7 5/8” Reg Pin5 ½” IF pin

7 5/8” Reg box5 ½” IF box

5500 lbs4000 lbs

25.8 ft25.6 ft

10 1/8”8 7/8”

9 ½”8 ¼”

9 ½” Tool8 ¼” Tool



HEL™ System Mechanical Specifications

80 lb/bbl3%

1000 gpm

30,000 psi

392°F(200°C)

356°F(180°C)

8.0” x 4.18”16° / 100’

10° / 100’2:70

8” Tool

80 lb/bbl3%

1800 gpm

30,000 psi

392°F(200°C)

356°F(180°C)

8.25” x 5.17”15° / 100’

9° / 100’2:47

8 ¼” Tool

80 lb/bbl3%

1800 gpm

30,000 psi

392°F(200°C)

356°F(180°C)

9.5” x 5.16”14° / 100’

8° / 100’3:10

9 ½” Tool

3%3%Maximum Sand Content80 lb/bbl80 lb/bblLost Circulation Material

6 3/4” Tool4 3/4” ToolHEL Specification

392°F(200°C)

392°F(200°C)

Maximum Survival Temperature

30,000 psi30,000 psiMaximum Operating Pressure

1000 gpm400 gpmMaximum Flow Rate

356°F(180°C)

356°F(180°C)

Maximum Operating Temperature

6.75” x 4.20”4.75” x 3.22” Equivalent Bending Stiffness (O.D. x I.D.)

19° / 100’36° / 100’Dogleg Severity – Sliding

11° / 100’20° / 100’Dogleg Severity -Rotating

2:532:10Bending Strength Ratio




BAP Sensor Specifications

0 – 30,000 psi

± 3 psi

± 7.5 psi

1 psi

30,000 psi

Quartz Crystal

8” Tool

0 – 30,000 psi

± 3 psi

± 7.5 psi

1 psi

30,000 psi

Quartz Crystal

8 ¼” Tool

0 – 30,000 psi

± 3 psi

± 7.5 psi

1 psi

30,000 psi

Quartz Crystal

9 ½” Tool

0 – 30,000 psi0 – 30,000 psi

Measurement Range

30,000 psi30,000 psiMaximum Working Pressure

6 3/4” Tool4 3/4” ToolBAP Specifications

± 3 psi± 3 psiRepeatability

± 7.5 psi± 7.5 psiAccuracy

1 psi1 psiResolution

Quartz CrystalQuartz Crystal

Transducer Type



HGAM Sensor Specifications

± 5 AAPI @ 1000 ft/hr

18”

± 2 AAPI

0 – 250 AAPI

Geiger-Mueller

8 ” Tool

± 5 AAPI @ 1000 ft/hr

18”

± 2 AAPI

0 – 250 AAPI

Geiger-Mueller

8 1/4” Tool

Geiger-Mueller

Geiger-Mueller

Geiger-Mueller

Detector Type

9 1/2” Tool6 3/4” Tool4 3/4” ToolHGAM Specifications

± 5 AAPI @ 1000 ft/hr

± 5 AAPI @ 1000 ft/hr

± 5 AAPI @ 1000 ft/hr

Statistical Repeatability

18”18”18”Vertical Resolution

± 2 AAPI± 2 AAPI± 2 AAPIAccuracy

0 – 250 AAPI

0 – 250 AAPI

0 – 250 AAPI

Measurement Range




IDS Sensor Specifications

30 seconds

± 0.5°

± 0.1°

± 1.5°

3 seconds

8” Tool

30 seconds

± 0.5°

± 0.1°

± 1.5°

3 seconds

8 1/4” Tool 9 1/2” Tool6 3/4” Tool4 3/4” ToolIDS Specifications

30 seconds30 seconds30 secondsSurvey Update

± 0.5°± 0.5°± 0.5°Azimuth Accuracy

± 0.1°± 0.1°± 0.1°Inclination Accuracy

± 1.5°± 1.5°± 1.5°Toolface Accuracy

3 seconds3 seconds3 secondsToolface Update Period



ESM Sensor Specifications

Lateral Shock and Vibration

Single Axis Acceleromete

r

8” Tool



r

8 1/4” Tool 9 1/2” Tool6 3/4” Tool4 3/4” ToolESM Specifications



Lateral Shock and VibrationMeasurement


r


rSingle Axis

AccelerometerSensor Type




MFR Configuration

• Symmetrical antenna design minimizes borehole effects and cancels impedance changes in antennas caused by pressure and temperature variations while drilling

• Can be run in standalone configuration (powered by two battery inserts)

• Typical configuration also includes HGAM sensor



MFR Highlights

• Features and Benefits:– Fully compensated antenna

arrays integrated into the drill collar for increased reliability

– Fully digital electronics measure phase and attenuation at each transmitter-receiver pair, resulting in highly accurate measurements

– Three transmitter-receiver spacings measure 12 fully compensated phase and attenuation measurements at unique radial distances from the borehole

– Diameter of investigation of 197” at 20 ohm-m is the industry’s deepest reading LWD resistivity measurement




MFR Highlights

• Features and Benefits:– The MFR may be run in any mud system– Three independent transmitter-receiver antenna

spacings and two operating frequencies provide accurate measurements over a wide range of drilling conditions

– Deeper reading 400 kHz measurements are unaffected by eccentering and hole rugosity, providing stable measurements in highly conductive formations drilled with oil based mud (OBM)



MFR Highlights

• Features and Benefits:– Any three compensated measurements can be

combined to radially invert diameter of invasion (DOI), resistivity of the flushed zone (Rxo), and true resistivity (Rt) over a wide range of borehole conditions and resistivity contrasts

– Deep reading resistivity measurements and log inversion capabilities enhance geosteering applications and horizontal log interpretation




MFR™ System Mechanical Specifications

Maximum Tension

Maximum Torque

Makeup Torque

Bottom Connection

Top Connection

Weight

Length (HEL System)

Maximum Tool O.D.

Nominal Tool O.D.

MFR Specification

528,000 lbs

16,700 ft-lb

9,900 - 10,900 ft-lb

3 1/2” IF box

3 1/2” IF box

1225 lbs

20.8 ft

5 1/4”

4 3/4”

4 3/4” Tool

978,000 lbs

44,700 ft-lb

28,000 - 32,000 ft-lb

4 1/2” IF box

4 1/2” IF box

2425 lbs

20.8 ft

7 3/8”

6 3/4”

6 3/4” Tool

1,480,000 lbs

77,300 ft-lb

52,000 - 56,000 ft-lb

6 5/8” Reg box

6 5/8” Reg box

3500 lbs

20.8 ft

8 5/8”

8”

8” Tool

1,870,000 lbs1,450,000 lbs

112,000 ft-lb80,100 ft-lb

75,000-78,000 ft-lb

53,000-56,000 ft-lb



6200 lbs4500 lbs

20.8 ft20.8 ft

10 1/8”8 7/8”

9 ½”8 ¼”

9 ½” Tool8 ¼” Tool



MFR™ System Mechanical Specifications

80 lb/bbl

3%

1000 gpm

30,000 psi

329°F(165°C)

302°F(150°C)

8.0” x 4.18”16° / 100’

10° / 100’

2:70

8” Tool

80 lb/bbl

3%

1800 gpm

30,000 psi

329°F(165°C)

302°F(150°C)

8.25” x 5.17”

15° / 100’

9° / 100’

2:47

8 ¼” Tool

80 lb/bbl

3%

1800 gpm

30,000 psi

329°F(165°C)

302°F(150°C)

9.5” x 5.16”14° / 100’

8° / 100’

3:10

9 ½” Tool

3%3%Maximum Sand Content

80 lb/bbl80 lb/bblLost Circulation Material

6 3/4” Tool4 3/4” ToolHEL Specification

329°F(165°C)

329°F(165°C)


30,000 psi30,000 psiMaximum Operating Pressure

1000 gpm400 gpmMaximum Flow Rate

302°F(150°C)

302°F(150°C)


6.75” x 4.20”

4.75” x 3.22”

Equivalent Bending Stiffness (O.D. x I.D.)

19° / 100’36° / 100’Dogleg Severity – Sliding

11° / 100’20° / 100’Dogleg Severity -Rotating

2:532:10Bending Strength Ratio




MFR Sensor Specifications

0.1 –200 Ω-mMeasurement Range (attenuation)

± 0.25 mmhosAccuracy (attenuation, all spacings)

Varies with type of measurement, frequency, spacing, and formation resistivityDepth of Investigation

± 0.25 mmhosAccuracy (phase, all spacings)

0.1 – 3000 Ω-mMeasurement Range (phase)

4 3/4”, 6 ¾”, 8”, 8 ¼”, 9 ½” ToolsMFR Specifications

Varies with type of measurement, frequency, spacing, and formation resistivityVertical Resolution



AZD / TNP Configuration

• AZD and TNP sensors offer density and neutron porosity LWD measurements at penetration rates of up to 400 ft/hr – with both the precision and accuracy of equivalent wireline tools

• AZD and TNP are run together in the same collar

• Can be run in standalone configuration (powered by two battery inserts)

• Combinable with the MFR tool and the HEL system




AZD Highlights

• Features and Benefits:– Optimized design results in

measurements less affected by standoff and improved spine and ribs correction

– Digital electronics allow 50 msec sampling for accurate standoff correction of both density and neutron measurements

– Patented self-binning technique accurately corrects measurement for tool standoff while rotating

– 2 curie, Cs-137 gamma emitting source



TNP Highlights

• Features and Benefits:– Multi-detector design

combined with stronger source provides exceptional statistical precision

– Optimized He3 detector spacings result in a high precision measurement with reduced environmental effects

– Multiple detectors at each spacing provide redundancy for increased log quality and deliverability

– 18 curie, Am241Be neutron emitting source




AZD™/ TNP™ System Mechanical Specifications

22.8 ft22.5 ft18.6 ftLength

Maximum Tension

Maximum Torque

Makeup Torque

Bottom Connection

Top Connection

Weight

Target Hole Size

Stabilizer Blade O.D.

Maximum Colar O.D.

AZD/TNP Specification

528,000 lbs

16,700 ft-lb

9,900 - 10,900 ft-lb

3 1/2” IF box

3 1/2” IF box

1225 lbs

6 1/8”

5 7/8”

5 1/4”

4 3/4” Tool

978,000 lbs

44,700 ft-lb

28,000 - 32,000 ft-lb

4 1/2” IF box

4 1/2” IF box

2425 lbs

8 ½”

8 1/4”

7 3/8”

6 3/4” Tool

1,450,000 lbs

80,100 ft-lb

53,000-56,000 ft-lb

5 ½” IF box

5 ½” IF box

5150 lbs

12 ¼”

12”

8 7/8”

8 ¼” Tool



AZD™/ TNP™ System Mechanical Specifications

3%3%3%Maximum Sand Content

80 lb/bbl80 lb/bbl80 lb/bblLost Circulation Material

8 1/4” Tool6 3/4” Tool4 3/4” ToolAZD / TNP Specification

329°F(165°C)

329°F(165°C)

329°F(165°C)


25,000 psi30,000 psi30,000 psiMaximum Operating Pressure

1800 gpm1000 gpm400 gpmMaximum Flow Rate

302°F(150°C)

302°F(150°C)

302°F(150°C)


8.25” x 4.39”6.75” x 4.29”4.75” x 3.22” Equivalent Bending Stiffness (O.D. x I.D.)

15° / 100’19° / 100’36° / 100’Dogleg Severity – Sliding

9° / 100’11° / 100’20° / 100’Dogleg Severity - Rotating

2.472.532.10Bending Strength Ratio




AZD / TNP Sensor Specifications

± 0.25 B/e-1 – 10 B/e- ± 5%Photoelectric Effect (Pe)

± 0.75 pu@ 20 pu

0 -10 pu ± 0.5 pu10 – 40 pu ± 5%

Neutron Porosity

± 0.0075 g/cc@ 2.4 g/cc

1.7 – 3.05 g/cc± 0.015 g/cc

Density

RepeatabilityAccuracyMeasurement



Revolution RSS Configuration

• The Revolution system’s point-the-bit technology uses a pivot stabilizer between the bit and the rotary steerable tool to orient the drill-bit axis with the axis of the hole

• Relative rotation between the center shaft, which carries torque to the bit, and the non-rotating housing drives a hydraulic pump

• The pump generates enough motive force to deflect the drill stem as programmed in the well’s steering plan




Revolution RSS Highlights

• Applications and Advantages:– “Point-the-bit” design for improved hole quality and bit

life relative to “push-the-bit” design– 4 3/4” system for extended reach, 6 1/8” wellbores– Simple functionality ensures high reliability– Deviation rates set from surface for improved

directional control– Build rates of up to 10°/100’ depending on formation

type– Short system length– Fully integrated with PrecisionLWD system– Measure point on inclination is 10’ from bit



Revolution™ System Mechanical Specifications

10,000 ft-lb

9,900 – 10,900 ft-lb

3 1/2” Reg pin

3 1/2” IF pin

200 lbs

2.8 ft

6 3/32”

4 3/4”

4 3/4” Tool

20,000 ft-lb

24,000 – 25,200 ft-lb

4 1/2” Reg pin

4 1/2” IF pin

790 lbs

3.6 ft

8 3/8”-9 7/8”

6 3/4”

6 3/4” Tool 8 1/4” ToolRevolution RSS Specification

5 1/2” Reg pinBottom Connection

53,000-56,000 ft-lbMake-up Torque

N/AMaximum Torque

5 1/2” IF pinTop Connection

N/AWeight (RSS mechanics)

N/ALength (RSS mechanics)

12 1/4”Maximum O.D.

8 1/4”Nominal Tool O.D.




Revolution™ System Mechanical Specifications

2%

350 gpm

25,000 psi

329°F (165°C)

302°F (150°C)

0°

10°/100 ft

250,000 lb (survival)

100,000 lb (reusable)

4 3/4” Tool

2%

1000 gpm

20,000 psi

329°F (165°C)

302°F (150°C)

0°

10°/100 ft

350,000 lb (survival)

130,000 lb (reusable)

6 3/4” Tool 8 1/4” ToolRevolution RSS Specification

N/AMaximum Operating Pressure

N/AMaximum Flow Rate

N/AMaximum Sand Content

329°F (165°C)Maximum Survival Temperature

302°F (150°C)Maximum Operating Temperature

0°Minimum Kick-off Angle

N/AMaximum Build Rate

N/AMaximum Tension



Toolstring Configuration Facts

• Sensor electronics are mounted on inserts (mud flows through insert), except for the IDS (mud flows around pressure case)

• Various length collars are used for different configurations

• Pulser must always be at top of toolstring• Driver is always directly below pulser• HEL tool typically run with two battery inserts, but can be

run with three for directional only configuration• IDS is always the bottom sensor in the HEL toolstring




Toolstring Configuration Facts

• HEL tool communicates with any sensors run below it via an adjustable male/female interconnect combination

• MFR can be run with or without an on-board HGAM sensor

• MFR can be run in stand-alone recorded only mode because of on-board batteries and memory

• AZD / TNP share a common collar• AZD / TNP can be run in stand-alone recorded only mode

because of on-board batteries and memory



Toolstring Configurations

• HEL – HGAM / BAP• Most common configuration





• Other configurations of the HEL string:

• HEL – DIRECTIONAL ONLY (2 BATTERIES)• HEL – DIRECTIONAL ONLY (3 BATTERIES)• HEL – HGAM• HEL – BAP (2 BATTERIES)




• HEL – MFR (with HGAM)

– Top end of HEL tool

• Pulser

• Driver

• Battery

• Battery

• BAP Insert

• IDS Flow Diverter

• IDS

• Male Interconnect

• Female Interconnect

• Battery

• Battery

• MFR

• HGAM





• TRIPLE COMBO

– This is the typical configuration although it is subject to some modification depending upon the customer’s requirements

– Top of toolstring:

• HEL – BAP

• TNP – AZD

• MFR – HGAM




• TRIPLE COMBO with RSS

– This is the typical configuration although it is subject to some modification depending upon the customer’s requirements

– Top of toolstring:

• HEL – BAP

• TNP – AZD

• MFR – HGAM

• IDS

• RSS




Sensor Measure Point and Sensor Distance

• Sensor Measure Point– Physical position on a sensor where the measurement is taken– Measure point does not change with configuration in toolstring or

BHA• Sensor Distance or Sensor Offset

– The distance from the sensor measure point to the bit– Will change with change of position within the toolstring or BHA

• Where a sensor appears in the toolstring may depend upon physical restrictions, customer request, and sensitivity to the borehole environment



Sensor Measure Points

• IDS– The midpoint between the center of the

accelerometer and magnetometer packages located 1.24’ (0.38 m) from the top of the jam nut

Top of jam nut





• HGAM– The center of the

Geiger-Mueller tube bank located 0.70’ (0.21 m) from the nose-end shoulder of the insert




• ESM– The center of the

single-axis accelerometer located 1.67’ (0.51 m) from the nose-end shoulder of the driver insert





• MFR– The midpoint

between the receivers




• BAP– The center of the

annulus pressure port on the collar





• TNP

–The midpoint between the near and far detectors




• AZD

–The center of the far detector window




4-3/4” AZD/TNP

Neutron Measurement Point

Density Measurement Point

13.6”

109.6”

NEUTRON

EDPSNF N FS

16”

24” 29.6”

89.6”

BOTTOMTOP

DENSITY

16”



6-3/4” AZD/TNP

Neutron Measurement Point

Density Measurement Point

14.5”

110.2”

NEUTRON

EDPSNF N FS

16”

24” 30.5”

90.2”

BOTTOMTOP

DENSITY

16”




Measure Points


Revolution® Rotary Steerable Service81/4-in. System

The Revolution service now offers a new 8 1/4-in.rotary steerable system (RSS) with point-the-bitdrilling technology for improved borehole qualityand bit life. The Revolution system’s short, compactdesign reduces the complexity of rotary steerabledrilling technology while placing critical LWDmeasurements close to the bit.

The Revolution system’s point-the-bit technologyuses a pivot stabilizer between the bit and therotary steerable tool to orient the drill-bit axis withthe of the hole. Relative rotation between thecenter shaft, which carries torque to the bit, anda non-rotating outer housing drives a hydraulicpump. This pump generates enough motive forceto deflect the drill stem as programmed in thewell’s steering plan.

© 2006 Weatherford. All rights reserved. 2957.00

Weatherford International Ltd.515 Post Oak Blvd., Suite 600Houston, Texas 77027 USATel: 713-693-4000www.weatherford.com

• Extended-reach 12 1/4-in. wellbores

Applications

• Point-the-bit design for improved hole qualityand bit life.

• Simple functionality ensures high reliability.

• Deviation rates set from surface for improveddirectional control.

• Build rates of up to 7.5°/100 ft depending onformation type.

• Compact system.

• Fully integrated with PrecisionLWD™ system.

• Measure point on inclination is 14 ft from bit.

Features, Advantages and Benefits

Near-bit gamma measure point

Near-bit inclination measure point

Non-rotatingRSS housing

Interface to MWDand electronics

RSS mechanics

Near-bit stabilizer

Bit



Weatherford products and services are subject to the Company’s standard terms and conditions, available on requestor at www.weatherford.com. For more information contact an authorized Weatherford representative. Unless noted otherwise, trademarks and service marks herein are the property of Weatherford. Specifications are subject to changewithout notice.


Specifications

Nominal tool OD . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8 1/4 in. (210 mm)Maximum OD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12 1/4 in. (311 mm)Top connection . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6 5/8 in. API IF (box)Bottom connection . . . . . . . . . . . . . . . . . . . . . . . . .6 5/8 in. API Reg (pin)Make-up torque . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .TBAMaximum torque . . . . . . . . . . . . . . . . . . . . . . . .50,000 ft-lb (67,790 N-m)Maximum tension . . . . . . . . . . . . . . . .1,000,000 lb (450,000 kg) survival

. . . . . . . . . . . . . . . . .250,000 lb (112,500 kg) reusableMaximum build rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.5°/100 ft.Minimum kickoff angle – vertical kickoff . . . . . . . . . . . . . . . . . . . . . . . . .0°Maximum operating temperature . . . . . . . . . . . . . . . . . . . 302°F (150°C)Maximum survival temperature . . . . . . . . . . . . . . . . . . . . .329°F (165°C)Maximum operating pressure . . . . . . . . . . . . . . . . .20,000 psi (138 MPa)Maximum flow rate . . . . . . . . . . . . . . . . . . . . .1500 gal/min (5,678 L/min)Maximum sand content . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2%




The Revolution service now includes a new 6 3/4-in. rotary steerable system (RSS) with point-the-bit drilling technology for improved borehole quality and bit life. The Revolutionsystem’s short, compact design reduces the complexity of rotary steerable drilling technology,while placing critical LWD measurements close to the bit.

The Revolution system’s point-the-bit technologyuses a pivot stabilizer between the bit and therotary steerable tool to orient the drillbit axis withthe of the hole. Relative rotation between the center shaft, which carries torque to the bit, anda non-rotating outer housing drives a hydraulicpump. This pump generates enough motive forceto deflect the drillstring as programmed in thewell’s steering plan.



• Extended-reach 8 3/8 to 9 7/8-in. wellbores

Applications




• Build rates up to 10°/100 ft depending onformation type.

• Compact design.


• Measure point on inclination is 11.2 ft from bit.






RSS mechanics

Near-bit stabilizer

Bit

13.0 ft (3.9 m)

11.2 ft (3.4 m)

8.1 ft (2.5 m)

1.0 ft (0.3 m)

4.5 ft (1.4 m)

3.2 ft (1.0 m)


Revolution® Rotary Steerable Service6 3/4-in. System




Specifications

Nominal tool OD . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6 3/4 in. (171 mm)Maximum OD . . . . . . . . . . . . . . . . . . . . . . .8 3/8–9 7/8 in. (213-251 mm)Length (RSS mechanics) . . . . . . . . . . . . . . . . . . . . . . . . . . .3.6 ft (1.1 m)Weight (RSS mechanics) . . . . . . . . . . . . . . . . . . . . . . . . .790 lb (359 kg)Top connection . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4 1/2 in. API IF (pin)Bottom connection . . . . . . . . . . . . . . . . . . . . . . . . .4 1/2 in. API Reg (pin)Make-up torque . . . . . . . . . . . .24,000–25,200 ft-lb (32,539-34,166 N-m)Maximum torque . . . . . . . . . . . . . . . . . . . . . . . .20,000 ft-lb (27,116 N-m)Maximum tension . . . . . . . . . . . . . . . . .350,000 lb (159,000 kg) survival

. . . . . . . . . . . . . . . . .130,000 lb (59,000 kg) reusableMaximum build rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10°/100 ft.Minimum kickoff angle – vertical kickoff . . . . . . . . . . . . . . . . . . . . . . . . .0°Maximum operating temperature . . . . . . . . . . . . . . . . . . . 302°F (150°C)Maximum survival temperature . . . . . . . . . . . . . . . . . . . . .329°F (165°C)Maximum operating pressure . . . . . . . . . . . . . . . . .20,000 psi (138 MPa)Maximum flow rate . . . . . . . . . . . . . . . . . . . . . .750 gal/min (2,839 L/min)Maximum sand content . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2%



The Revolution service was the first slimholerotary steerable system (RSS) to use point-the-bitdrilling technology for improved borehole qualityand bit life. The Revolution system’s short, compactdesign reduces the complexity of rotary steerabledrilling technology, while placing critical LWDmeasurements close to the bit.

The Revolution system’s point-the-bit technologyorients the drill bit axis with the axis of the desiredwell path, optimizing the directional drillingprocess and maximizing drilling efficiency. Relativerotation between the center shaft, which carriestorque to the bit, and a non-rotating outer housingdrives a hydraulic pump. This pump generatesenough motive force to deflect the drillstring asprogrammed in the well’s steering plan.



• Extended-reach 6 1/8-in. wellbores

Applications




• Build rates of up to 10°/100 ft depending onformation type.

• Compact design.







RSS mechanics

Near-bit stabilizer

Bit

11.0 ft (3.4 m)

9.0 ft (2.7 m)

6.1 ft (1.9 m)

0.8 ft (0.3 m)

3.3 ft (1.0 m)

2.5 ft (0.8 m)






Specifications

Nominal tool OD . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4 3/4 in. (121 mm)Maximum OD† . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6 3/32 in. (155 mm)Length (RSS mechanics) . . . . . . . . . . . . . . . . . . . . . . . . . . .2.8 ft (0.9 m)Weight (RSS mechanics) . . . . . . . . . . . . . . . . . . . . . . . . . .200 lb (91 kg)Top connection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 1/2 in. API IF pinBottom connection . . . . . . . . . . . . . . . . . . . . . . . . .3 1/2 in. API Reg boxMake-up torque . . . . . . . . . . . . .9900–10,900 ft-lb (13,423–14,778 N-m)Maximum torque . . . . . . . . . . . . . . . . . . . . . . . .10,000 ft-lb (13,558 N-m)Maximum tension . . . . . . . . . . . . . . . . . .250,000 lb survival (113,398 kg)

. . . . . . . . . . . . . . . . . .100,000 lb reusable (45,359 kg)Maximum build rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10°/100 ftMinimum kickoff angle – vertical kickoff . . . . . . . . . . . . . . . . . . . . . . . . .0°Maximum operating temperature . . . . . . . . . . . . . . . . . . . .302°F (150°C)Maximum survival temperature . . . . . . . . . . . . . . . . . . . . .329°F (165°C)Maximum operating pressure . . . . . . . . . . . . . . . . .20,000 psi (138 MPa)Maximum flow rate . . . . . . . . . . . . . . . . . . . . . .350 gal/min (1325 L/min)Maximum sand content . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2%Distance from bit, near-bit inclination . . . . . . . . . . . . . . . . . . .11 ft (3.4 m)Distance from bit, near-bit gam

†Dependent on bit size

MWD/LWD

HELTM MWD SystemThe hostile-environment logging (HEL) MWD system is specifically designedfor today’s high-pressure/high-temperature hostile drilling environments.Designed to operate at temperatures up to 356°F (180°C) and to withstanddownhole pressures of 30,000 psi (207 MPa), the HEL MWD systemmeets or exceeds all existing MWD system specifications.

• The HEL MWD system is qualified using the most stringent testingregime in the industry. Tests include flow-loop erosion, lost circulation,high-pressure tests at elevated temperatures, and aggressive vibrationqualification including innovative random-on-random standards duringmultiple temperature cycles.



• 30,000-psi (207-MPa) pressure rating—the industry’s highest.

• Reliable operation at temperatures of up to 356°F (180°C), withsurvival to 392°F (200°C).

• High flow rates for all size tools: 4 3/4 in. (400 gal/min), 6 3/4 in., 8 in.(1000 gal/min), 8 1/4 in. and 9 1/2 in. (1800 gal/min).

• System handles lost circulation material (LCM) up to 80 lb/bbl.

• Pressure Modulated Telemetry (PMT™) system uses mudflow andbattery power to generate a positive mud pulse.

• Environmental Severity Measurement (ESM™) sensor monitors toolshock and drilling vibration.

• Dual Battery Module (DBM™) assembly provides long-duration,redundant power for extended downhole operation.

• High-Temperature Azimuthal Gamma Ray (HAGR™) tool for accurateAPI gamma ray measurements.

• Bore/Annular Pressure (BAP™) sensor uses quartz transducers toprovide highly accurate bore andannular pressure measurements.

• Integrated Directional Sonde (IDS™)provides directional and toolfacemeasurements.


Applications

IDS 5.7 ft

BAP 10.8 ft

HAGR 12.5 ft

DBM

ESM 19.2 ft

PMT

25.2 ft (7.7 m)

MWD/LWD

HELTM MWD System



Specifications

4 3⁄4 in. 6 3⁄4 in. 8 in. 8 1⁄4 in. 9 1⁄2 in.Nominal Sensor OD

Maximum OD 5 1⁄ 4 in. 7 3⁄ 8 in. 8 5⁄ 8 in. 8 7⁄8 in. 9 1⁄ 2 in.

Length (HEL system) 25.2 ft 25.3 ft 25.2 ft 25.6 ft 25.8 ft

Weight 1400 lb 2850 lb 4100 lb 4000 lb 5500 lb

Top connection 3 1⁄ 2 IF box 4 1⁄ 2 IF box 6 5⁄ 8 Reg box 5 1⁄ 2 IF box 7 5⁄ 8 Reg box

Bottom connection 3 1⁄ 2 IF pin 4 1⁄ 2 IF pin 6 5⁄ 8 Reg pin 5 1⁄ 2 IF pin 7 5⁄ 8 Reg pin

Make-up 9900– 28,000– 52,000– 53,000– 75,000–torque 10,900 ft-lb 32,000 ft-lb 56,000 ft-lb 56,000 ft-lb 78,000 ft-lb

Maximum torque 16,700 ft-lb 44,700 ft-lb 77,300 ft-lb 80,100 ft-lb 112,000 ft-lb

Maximum tension 528,000 lb 978,000 lb 1,480,000 lb 1,450,000 lb 1,870,000 lb

Bending strength ratio 2:10 2:53 2:70 2:47 3:10

Maximum dogleg severity, rotating 20°/100 ft 11°/100 ft 10°/100 ft 9°/100 ft 8°/100 ft

Maximum dogleg severity, sliding 36°/100 ft 19°/100 ft 16°/100 ft 15°/100 ft 14°/100 ft

Equivalent bending 4.75 in. 6.75 in. 8.0 in. 8.25 in. 9.5 in.stiffness (OD x ID) x 3.22 in. x 4.20 in. x 4.18 in. x 5.17 in. x 5.16 in.

Maximum operating temperature 356°F (180°C) 356°F (180°C) 356°F (180°C) 356°F (180°C) 356°F (180°C)

Maximum survival temperature 392°F (200°C) 392°F (200°C) 392°F (200°C) 392°F (200°C) 392°F (200°C)

Maximum operating 30,000 psi 30,000 psi 30,000 psi 30,000 psi 30,000 psipressure (207 MPa) (207 MPa) (207 MPa) (207 MPa) (207 MPa)

Maximum flow rate 400 gal/min 1000 gal/min 1000 gal/min 1800 gal/min 1800 gal/min

Maximum sand content 2% 2% 2% 2% 2%

Mechanical Specifications

MWD/LWD

HELTM MWD System




Specifications

4 3 ⁄4 in. 6 3 ⁄4 in. 8 in. 8 1⁄4 in. 9 1⁄2 in.Nominal Sensor OD

BAP™ Sensor

Transducer type Quartz crystal Quartz crystal Quartz crystal Quartz crystal Quartz crystal

Resolution 1 psi 1 psi 1 psi 1 psi 1 psi

Accuracy ± 7.5 psi ± 7.5 psi ± 7.5 psi ± 7.5 psi ± 7.5 psi

Repeatability ± 3 psi ± 3 psi ± 3 psi ± 3 psi ± 3 psi

Measurement range 0–30,000 psi 0–30,000 psi 0–30,000 psi 0–30,000 psi 0–30,000 psi

Measure point from 10.6 ft 10.6 ft 10.6 ft 10.6 ft 10.6 ftbottom of sensor

HAGR™ Sensor Specifications

Measurement range 0–250 API 0–250 API 0–250 API 0–250 API 0–250 API

Accuracy ± 2 API ± 2 API ± 2 API ± 2 API ± 2 API

Vertical resolution 18 in. 18 in. 18 in. 18 in. 18 in.

Statistical repeatability ± 5 API ± 5 API ± 5 API ± 5 API ± 5 API@ 100 ft/hr @ 100 ft/hr @ 100 ft/hr @ 100 ft/hr @ 100 ft/hr


IDS™ Sensor Specifications

Sensor face update period 3 sec 3 sec 3 sec 3 sec 3 sec

Sensor face accuracy ± 1.5° ± 1.5° ± 1.5° ± 1.5° ± 1.5°

Inclination accuracy ± 0.1° ± 0.1° ± 0.1° ± 0.1° ± 0.1°

Azimuth accuracy ± 0.5° ± 0.5° ± 0.5° ± 0.5° ± 0.5°

Survey update 30 sec 30 sec 30 sec 30 sec 30 sec


ESM™ Sensor Type - All Sizes

Sensor type Single-axis accelerometerMeasurement Lateral shock and vibration


MWD/LWD

Slimhole, Retrievable MWD System

The slimhole, retrievable MWD system is a positive-pulse, measurement-while-drilling system that provides unique cost-savingfeatures for operators. The system is 100% wireline-retrievableand features a rigid design, a high-speed pulser and mechanicalcharacteristics suggested by directional drillers.The slimhole, retrievable MWD system eliminates the need forroundtrips when drilling operations outlast the battery capacity ofthe slimhole MWD tool. The slimhole, retrievable MWD systemfeatures an OTIS 1 1/2-in. fishing neck so operators can fish thecomplete tool, as needed.The system’s rigid design reduces the impact of drilling operationson tool reliability. The system’s extended mean time between failures (MTBF) ensures reliable performance throughout drilling operations.The slimhole, retrievable MWD system’s high-speed, positivepulser creates high-speed data transfer rates. Tool-face data is transmitted every six seconds. Full surveys only require 45seconds of pump down time.Customer input dictated development of the system’s mechanicalcharacteristics. From bottom to top of housing, the downhole probeaccommodates a flow switch, optional gamma-ray sensor package, a directional sensor, telemetry electronics, a batterypack and a high-speed pulser.The system is packaged in rugged transport boxes and/or a specially designed MWD container that protects various componentsduring transportation. Both boxes and container are easy to han-dle. Boxes and container contain running gear, a special modularbox for downhole electronics, battery packs, surface unit and allother necessary accessories.The downhole tool is run in standard, non-negotiable drill collars.Collar sizes range from 9 1/2-in. O.D. to 3 3/4-in. O.D. The slimhole, retrievable MWD system also provides build rates of up to 30°/100 ft. For short-radius applications, an upgrade setis available that accommodates build rates of up to 100°/100 ft.The directional sensor package consists of field-proven, solid-state, three-axis accelerometers and magnetometers that areshock-resistant up to 1000 g.A temperature sensor monitors the downhole tool’s temperature.The gained value is used to correct other downhole measure-ments and provides an indication of local geothermal gradients.



Pulser

Battery pack

Middle centralizer

Directional unit

Directionalmeasure point

Gamma unit

Gammameasure point

Muleshoe adapterwith intergratedlocking device

Flow switch

Extension bar

Fishing neck

MWD/LWD

Slimhole, Retrievable MWD System




SpecificationsDownhole systemLength . . . . . . . . . . . . . . . . . . . . . . . . .23.86 ft (7.28 m) directional only

29.39 ft (8.96 m) directional plusoptional gamma unit

DiameterPulser . . . . . . . . . . . . . . . . . . . . . . . . .2.64 in. (67 mm)

Pressure housing . . . . . . . . . . . . . . . .2.24 in (57 mm)

Weight . . . . . . . . . . . . . . . . . . . . . . . . .180 lb (81.6 kg)

Tool configuration . . . . . . . . . . . . . . . .complete MWD tool fits in pulserSub/NMDC/orienting sub-combination

Adjustment to NMDC length . . . . . . . .by means of MWD extension bars

The slimhole, retrievable MWD system’s gamma ray sensor produces high-quality logs of natural gamma radiation, calibrated in AAPI units. Thisfacilitates geological interpretation during drilling. Gamma ray smoothingintervals can be user-selected to match the expected rate of penetration.

MWD/LWD

PrecisionPulseTMMWD SystemThe design of the PrecisionPulse MWD system is based on the proven reliability of theEMpulse™ electromagnetic MWD system butincludes modifications specifically for directionaldrilling with gamma ray services.



• Rated to 15,000 psi operating pressure.

• Rated to 300°F (150°C) operating temperature.

• Gamma ray probe with scintillation counter foraccurate AAPI measurements and recorded datain non-volatile memory.

• Pressure Modulated Telemetry (PMT™) systemuses mud flow and battery power to generate apositive mud pulse.

• A 1 3/4-in. sonde-based tool fits in collarsbetween 3 1/16 in. and 9 in.

• Retrievable in certain BHA configurations.

• Battery operated.


Orientation module

MWD electronics

Battery

Gamma ray

Control module

Pulser

Spear point

27.0 ft (8.23 m)

13.0 ft (3.9 m)

MWD/LWD

PresicionPulseTM MWD System




Specifications

External diameter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1 11/16 in. (43 mm)Length . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37.2 in. (945 mm)Standard operating temperature . . . . . . . . . . . . . . . . . . . . . .257°F (125°C)Optional (under development) temperature . . . . . . . . . . . . .302°F (150°C)Collapse pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15,000 psiMemory type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Non-volatileMemory capacity . . . . . . . . . . . . . . . . . . . . .200k (data sets) up to 47 daysSampling interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 secondsSensor position . . . . . . . . . . . . . . . . . . . . . . .700 mm from bottom of probe

Gamma Ray Probe

INC Inclination 0-128° 0.125° 0.2°

AZ Azimuth 0-360° 0.250° 1° for incl. >5°

MTF Magnetic Tool Face 0-360° 4° 2° for incl. <5°

GTF Gravity Tool Face 0-360° 4° 2° for incl. >5°

Tin CDS Internal Temperature 0-150°C 1°C 1°C

Collars and MuleshoeCollar OD 3 1/8 in. 3 1/2 in. 31/2 in. Flex 4 3/4 in. 43/4 in. Flex 6 1/4 in. 6 1/2 in. 6 3/4 in. 8.0 in. 9.0 in.

Collar ID 2 1/4 in. 2 1/4 in. 211/16 in. (68 mm)or 2 13/16 in. 3 1/4 in. (82 mm) 4.0 in. 4.0 in. (57.2 mm) (57.2 mm) 2 13/16 in. (71 mm) (102 mm) (102 mm)

Max flow w/2 in. pulser N/A N/A 350 to 400 gal/min 400 gal/min 700 gal/min 1200 gal/min 1200 gal/minMax flow w/1.75in.pulser 160 gal/min 160 gal/min 350 to 400 gal/min N/A N/A N/A

Collar length (new) 370 in. 370 in. 370 in. 370 in. 370 in. 370 in.(9.30 m) (9.30 m) (9.30 m) (9.30 m) (9.30 m) (9.30 m)

Collar connections2 11/16 in.–4 SA 2 7/8 in.–4 S 3 1/2 in. IF

4 1/2 in. XH (6.25 in., 6.50 in.)–6 5/8 in. REG 7H90

(Top box, bottom pin) 4 1/2 in. IF (6.75 in., 6.50 in.)

Muleshoe length 41 in. (1.0 m) 41 in. (1.0 m) 38.128 in. (0.97 m) 37.625 in. (0.96 m) 35.375 in. 41 in. (0.90 m) (1.0 m)

MS connections 2 11/16 in.–4 SA 2 7/8 in.–4 SA 3 1/2 in. IF 4 1/2 in. XH (6.25 in., 6.50 in.)–6 5/8 in. REG 7H90

(Top box, bottom pin) 4 1/2 in. IF (6.75 in., 6.50 in.)DLS—Rotating (°/100 ft) 38° 27° 38° 20° 27° 14° 13° 10° 9.5°DLS—Sliding (°/100 ft) 116° 66° 116° 36° 66° 20° 18° 15° 14°

EM Orientation ModuleName Description Range Resolution Accuracy

MWD/LWD

EMpulseTM MWD System

EMpulse electromagnetic measurement-while-drilling (EM MWD)system allows operators to drill and survey wells independentof rig hydraulics. Bit pressure drop, flow rates, and drilling fluidand formation loss are irrelevant to EM technology, creatingsubstantial savings in drilling time and project costs. EM MWDsaves an average of two to five days per well due to fastersurvey times and fewer limitations on hydraulics, compared to mud pulse MWD and steering tools.

The EMpulse system has no moving parts, deriving powerfrom long-life batteries instead of a mud-driven generator. The tool propagates an electromagnetic wave along the drillstring to surface, where data is detected and decoded by a surface transceiver. This method allows survey informationto be transmitted regardless of drilling fluid properties.

Electromagnetic surveys do not require extra rig time, unlikemud pulse surveys (which take an average of 3–5 min.) orsteering tools (which take an average of 25 min. to complete a transmission cycle). Once a connection is made, drillingresumes immediately.

EMpulse system is user friendly to drillers because of the system’sability to operate independent of the rig’s circulating system.

Current generation EM MWD transmits real-time data fromdownhole to surface:

• Directional surveys• Annulus pressure• Formation gamma ray• Oriented gamma ray (OGR)• Formation resistivity• Near-bit instrumentation (inclination, gamma ray)



• The tool is especially applicable for drilling permeableformations since it is unaffected by drilling fluid loss.

• EM telemetry also is well suited for underbalanced drillingsince it does not require a homogenous fluid column for data transmission.

Applications

Antenna

MWD

MWD

BatteryBattery

Gamma Ray

Gamma Ray

Antenna

• Simple, rapid installation at the wellsite.Surface equipment can be installed in lessthan one hour without any modifications to rig equipment.

• Reduced tool inventory/mobilization. EMpulsesystem is a sonde-based design configuredfor use in a full range of non-magneticdrillstring tubulars and hole sizes.

• Two-way communication with the MWD tool.The fundamental advantage of EMpulsesystem is the downlink ability that allowsoperators to communicate instructions to thedownhole instrumentation while drillingproceeds. Uplink and downlinkcommunications are completely independentof rig or drilling activity.

• Drillstring optimization. Survey data can berecorded in 15 sec while the drillstring isstationary, which is less than normalconnection time. This reduces the possibilityof differential sticking or hole sloughing thatcan result from extended periods withoutcirculation or pipe movement.

• Reduced survey/connection times. Due to thesystem’s independence from drillinghydraulics, there is no lag time or need tocycle the pumps for synchronization purposeswhen survey data is being transmitted or tore-sync after anomalous drilling hydraulicsincidents. This also reduces the risk of awashout when transmitting a survey.

• Reduced fishing/lost hole cost. The latestgeneration of EM-MWD allows, in certainbottomhole assembly (BHA) configurations,the ability to wireline-retrieve the EM MWDelectronics.

• Improved reliability. EMpulse system is builtentirely with solid-state electronics designedto operate in harsh drilling environments, suchas air/mist, foam and multiphase underbalancedhorizontal drilling applications.

• Gamma ray measurement. EMpulse systemcan be equipped with a real-time gamma rayprobe. Data is transmitted in real time andalso recorded in downhole memory.

• Annulus pressure. EMpulse system also can beequipped with a real-time annular pressuresensor to measure downhole pressure conditionson any rig while drilling, circulating, monitoringlost circulation or during shut-in conditions.

• GABIS. This short sub can be mounteddirectly above the bit to provide real-timeinclination and gamma ray near the bit.

• Oriented gamma ray. This sensor providesreal-time high-side and low-side gammameasurements while rotating, along with real-time total gamma ray.

MWD/LWD

EMpulseTM MWD System




The sonde- based EMpulseelectromagneticMWD system is easily tested at the rigsite. Simpleinstallation in theBHA minimizestime required on the rig floor.

In low-pressure formations and lost circulation zones, EM MWDsaves significant drilling time compared to steering tools andmud pulse MWD systems.

Average time savings per type of system usedSteering

toolMud pulse

MWD

EM MWD

Average connection time (min) Average survey time (min) Average drilling time (hr/d)

Features, Advantages and Benefits Options

MWD/LWD

PrecisionLWDTM System—Azimuthal Density (AZDTM) and Thermal Neutron Porosity (TNPTM) Sensors

The AZD and TNP sensors offer density and neutronporosity logging-while-drilling measurements at penetra-tion rates up to 400 ft/hr with the precision and accuracyof equivalent wireline tools.



System• Rated up to 30,000 psi (207 MPa) operating pressure.• Wireline accuracy at drilling rates up to 400 ft/hr.• Combinable with the Multi-Frequency Resistivity (MFR™)

sensor and the Hostile Environment Logging (HEL™)MWD system.

TNP Sensor• Multi-detector design combined with 18-Curie AmBe

radioactive source provides exceptional statisticalprecision equivalent to a wireline measurement atdrilling rates up to 400 ft/hr.

• Optimized He3 detector spacings result in a high-precision measurement with reducedenvironmental effects.

• Multiple detectors at each spacing provide redundancyfor increased log quality and deliverability.

AZD Sensor• Optimized design results in measurements less affected

by standoff and improved spine and rib corrections.• Digital electronics allow 50-ms sampling for accurate

standoff correction of both density and neutronmeasurements.

• Patented rotational correction technique providesaccurate measurement for tool standoff while rotating.

• Standoff and hole size are calculated while rotatingusing data acquired with fast sampling and may bedisplayed on both real-time and recorded logs.

Features, Advantages and BenefitsHe3 detectors

Source

Source

TNP 18.6 ft(5.7 m)

AZD 10.7 ft(3.3 m)

Near detector

Far detector

MWD/LWD

PrecisionLWDTM—Azimuthal Density (AZDTM) and Thermal Neutron Porosity (TNPTM) Sensors



Specifications

Nominal Tool OD 4 3/4 in. 6 3/4 in. 8 1/4 in.

Maximum collar OD 5 1/4 in. 7 3/8 in. 9 1/2 in.

Length 18.6 ft 22.5 ft 22.8 ft

Weight 1225 lb 2425 lb 5150 lb

Top connection 3 1/2 IF box 4 1/2 IF box 5 1/2 IF box

Bottom connection 3 1/2 IF Pin 4 1/2 IF Pin 5 1/2 IF Pin

Stabilizer blade diameter 5 7/8 in. 8 1/4 in. 12 in.

Target hole size 6 1/8 in. 8 1/2 in. 12 1/4 in.

Make-up 9900– 28,000– 53,000– torque 10,900 ft-lb 32,000 ft-lbf 56,000 ft-lb

Maximum torque 16,700 ft-lb 44,700 ft-lb 80,100 ft-lb

Maximum tension 528,000 lb 978,000 lb 1,450,000 lb

Bending strength ratio 2:10 2:53 2:47

Dogleg severity, rotating 20°/100 ft 11°/100 ft 9°/100 ft

Dogleg severity, sliding 36°/100 ft 19°/100 ft 15°/100 ft

Equivalent bending stiffness 4.75 in. 6.75 in. 8.25 in.(OD x ID) x 3.18 in. x 4.39 in. x 4.28 in.

Maximum operating 302°F 302°F 302°F temperature (150°C) (150°C) (150°C)

Maximum survival 329°F 329°F 329°F temperature (165°C) (165°C) (165°C)

Maximum operating 30,000 psi 30,000 psi 25,000 psipressure (207 MPa) (207 MPa) (172 MPa)

Maximum flow rate 400 gal/min 1000 gal/min 2000 gal/min

Maximum sand content 2% 2% 2%

Measurement Accuracy Repeatability

Density 1.7–3.05 g/cm3 ± .0075g/cm3

± .015 g/cm3 @ 2.4 g/cm3

Neutron Porosity 0–10 p.u. ± 0.5 p.u. ± 0.75 p.u.10–40 p.u. ± 5% @ 20 p.u.

Pe 1–10 B/e ± 5% ± 0.25 @ 3 B/e

STANDOFF EFFECTS ON LWD DENSITY:

• Patented rotational correctiontechnique developed to compensatefor both neutron and density standoff.

• Method accounts for simultaneouschanges in formation density andstandoff while tool is rotating.

• Data sampled every 50–250 ms.• Improved data quality by eliminating

samples with excessive standoff.• Segments with constant density and

constant standoff are determined.• Standoff correction is applied to

each data segment in real time.• Standoff corrected bulk density,

azimuthal bulk density and neutronporosity are stored in memory andtransmitted real time via positivemud pulse telemetry.

Tool rotationcauses standoff to vary during a single sample. The patentedrotationalcorrectioneliminates poorquality data withexcessive standoff.

AZD/TNP Tool Mechanical Specifications

AZD/TNP Sensor Specifications

MWD/LWD




LWD and Wireline Comparison—Eocene Shaly-Sands.This well was drilled using a 13.1 lb/gal oil-based mud and a 6 1/8-in. bit. The superior bed resolution of the 2-MHz, 46-in. phase resistivity (LWD_RPD2) compared to the wireline ILD in track two is highlighted by yellow shading. The LWD neutron porosity and bulk density closely correlate with wirelinelogs in the shale sections, but differ in hydrocarbon zones. LWD nuclear logs are less affected by invasion than wirelinelogs as shown in the highlighted Eocene shaly-sand gas zone at 6435 ft. The LWD logs were acquired one hour afterdrilling, and the wireline logs were acquired three days after drilling.

ROP

WL CALI

GR

Wireline LWD

fN fN

rb rb

PrecisionLWDTM—Azimuthal Density (AZDTM) and Thermal Neutron Porosity (TNPTM) Sensors

MWD/LWD

HELTM MWD System—High-Temperature Azimuthal Gamma Ray (HAGRTM) Sensor

The HAGR sensor is an integral part of the hostile environmentLogging (HEL) MWD system using Geiger Muller tubes to obtainreal-time azimuthal gamma ray measurements while drilling. Theazimuthal data can be transmitted in quadrant or octant format forgeosteering applications.

The HAGR sensor provides real-time azimuthal gamma ray measurements while rotating or sliding at temperatures up to 356°F(180°C) [392°F (200°C) survival] and pressures up to 30,000 psi(207 MPa). This extreme operating requirement requires the use ofGeiger Muller tubes rather than scintillation detectors. Five banks oftwo tubes each are implemented in the 4 3/4-in. sensor, while eightbanks are implemented in the 6 3/4- and 8-in. sensors. The number,size and symmetric distribution of tubes were chosen to provide thegreatest combination of statistical precision and azimuthal sensitivity.

All tools are calibrated to API standards using a combination ofmeasurements made at the University of Houston API gamma rayfacility, measurements made in secondary standards and computermodeling. Correction algorithms, developed for mud weight, bore-hole size and potassium concetration, are in agreement with labmeasurements. Field data obtained with the HAGR sensor showgood correlation with wireline data from the same well.



• Extreme operating specifications enable accurate, criticalformation evaluation data in deepwater drilling environments.

Applications

• Geiger Muller tubes measure real-time gamma ray to statisticallyprecise ±5 API at 100 API for 20-s unfiltered samples (±2.5 APIwith a five-point non-block filter).

• Rated to 356°F (180°C) operating and 392°F (200°C) survivaltemperatures.

• Rated to 30,000 psi (207 MPa) operating pressure.• Data transmitted to surface via the HEL MWD system using mud

pulse telemetry or EMpulse™ electromagnetic MWD system.


HEL MWD system

Geiger Mullertubes

25.2 ft (7.7 m)

HAGR 12.4 ft(3.8 m)

MWD/LWD




Specifications

4 3⁄4 in. 6 3⁄4 in. 8 in. 8 1⁄4 in. 9 1⁄2 in.Nominal Sensor OD

HEL MWD System Mechanical Specifications

Maximum OD 5 1⁄4 in. 7 3⁄ 8 in. 8 5⁄ 8 in. 8 7⁄ 8 in. 9 1⁄ 2 in.Length (HEL system) 25.2 ft 25.3 ft 25.2 ft 25.6 ft 25.8 ft

Weight 1400 lb 2850 lb 4100 lb 4000 lb 5500 lbTop connection 3 1⁄ 2 IF box 4 1⁄ 2 IF box 6 5⁄ 8 Reg box 5 1⁄ 2 IF box 7 5⁄ 8 Reg box

Bottom connection 3 1⁄ 2 IF pin 4 1⁄ 2 IF pin 6 5⁄ 8 Reg pin 5 1⁄ 2 IF pin 7 5⁄ 8 Reg pinMake-up 9900– 28,000– 52,000– 53,000– 75,000–torque 10,900 ft-lb 32,000 ft-lb 56,000 ft-lb 56,000 ft-lb 78,000 ft-lb

Maximum torque 16,700 ft-lb 44,700 ft-lb 77,300 ft-lb 80,100 ft-lb 112,000 ft-lbMaximum tension 528,000 lb 978,000 lb 1,480,000 lb 1,450,000 lb 1,870,000 lb

Bending strength ratio 2:10 2:53 2:70 2:47 3:10Maximum dogleg severity, rotating 20°/100 ft 11°/100 ft 10°/100 ft 9°/100 ft 8°/100 ftMaximum dogleg severity, sliding 36°/100 ft 19°/100 ft 16°/100 ft 15°/100 ft 14°/100 ft



Maximum survivaltemperature 392°F (200°C) 392°F (200°C) 392°F (200°C) 392°F (200°C) 392°F (200°C)




HAGR Sensor Specifications

Measurement range 0-250 API 0-250 API 0-250 API 0-250 API 0-250 APIAccuracy ± 2 API ± 2 API ± 2 API ± 2 API ± 2 API

Vertical resolution 18 in. 18 in. 18 in. 18 in. 18 in.

Statistical repeatability ± 5 API ± 5 API ± 5 API ± 5 API ± 5 API@ 100 ft/hr @ 100 ft/hr @ 100 ft/hr @ 100 ft/hr @ 100 ft/hr


MWD/LWD





Log Example

Log Example

MWD/LWD

HELTM MWD System—Bore/AnnularPressure (BAPTM) Sensor

The BAP sensor is an integral part of the hostile-environmentlogging (HEL) MWD system using highly accurate quartztransducers to monitor downhole well conditions for earlyindication of drilling problems.

The BAP sensor measures bore and annular pressure and downhole temperature while drilling, wiping or trippingout of hole.

BAP sensor information may be presented in pressure unitsor equivalent circulating density to optimize hole cleaning,control surge and swab, and minimize lost circulation. Thisinformation may be plotted vs. depth or time for flexibility inanalyzing drilling and non-drilling events. The BAP sensormay also be run in underbalanced applications or in holeswith no mud returns using the EMpulse™ electromagneticMWD system.



• Provides critical information in deepwater wells where a narrow window exists between pore pressure andformation fracture pressure.

Applications

• Accurate quartz gauges measure pressure ± 7.5 psi at1 psi resolution.

• Rated to 356°F (180°C) operating and 392°F (200°C)survival temperatures.

• Rated to 30,000 psi (207 MPa) operating pressure.• Data transmitted to surface with either the HEL MWD

system using mud pulse telemetry or the EMpulseelectromagnetic MWD system.

• Monitors hole cleaning and cuttings transport.• Can improve drilling efficiency by providing accurate

leak-off and formation integrity test information.


25.2 ft (7.7 m)

BAP 10.6 ft(3.2 m)

HEL MWD system

Quartztranducers

Annular pressureport

Borepressureport

MWD/LWD

HELTM MWD System—Bore/Annular Pressure (BAPTM) Sensor




Specifications



Maximum OD 5 1⁄4 in. 7 3⁄8 in. 8 5⁄8 in. 8 7⁄8 in. 9 1⁄2 in.



Top connection 3 1⁄ 2 IF box 4 1⁄ 2 IF box 6 5 ⁄ 8 Reg box 5 1⁄ 2 IF box 7 5 ⁄ 8 Reg box

Bottom connection 3 1⁄ 2 IF pin 4 1⁄ 2 IF pin 6 5 ⁄ 8 Reg pin 5 1⁄ 2 IF pin 7 5 ⁄ 8 Reg pinMake-up 9900– 28,000– 52,000– 53,000– 75,000–torque 10,900 ft-lb 32,000 ft-lb 56,000 ft-lb 56,000 ft-lb 78,000 ft-lb



Bending strength ratio 2:10 2:53 2:70 2:47 3:10Maximum dogleg severity, rotating 20°/100 ft 11°/100 ft 10°/100 ft 9°/100 ft 8°/100 ftMaximum dogleg severity, sliding 36°/100 ft 19°/100 ft 16°/100 ft 15°/100 ft 14°/100 ft


Maximum operatingtemperature 356°F (180°C) 356°F (180°C) 356°F (180°C) 356°F (180°C) 356°F (180°C)





BAP Sensor Specifications

Transducer type Quartz crystal Quartz crystal Quartz crystal Quartz crystal Quartz crystal

Resolution 1 psi 1 psi 1 psi 1 psi 1 psi

Accuracy ± 7.5 psi ± 7.5 psi ± 7.5 psi ± 7.5 psi ± 7.5 psi

Repeatability ± 3 psi ± 3 psi ± 3 psi ± 3 psi ± 3 psi

Measurement range 0–30,000 psi 0–30,000 psi 0–30,000 psi 0–30,000 psi 0–30,000 psi


MWD/LWD

HELTM MWD System—EnvironmentalSeverity Measurement (ESMTM) Sensor

The ESM sensor is an integral part of the hostile- environment logging (HEL) system using a single lateral accelerometer to monitor bottomhole assemblyshock and vibration while drilling.

An ESM sensor is installed in every HEL system to improve tool reliability. Real-time vibration data istriggered after exceeding pre-set thresholds.Information provided by the ESM sensor alerts thedriller that changes in drilling conditions are neededto reduce or eliminate harmful downhole vibration.Also vibration data from the sensor is used to adjustmaintenance schedules based on cumulative shockand vibration exposure.



• Provides real-time data that alerts drillers whenexcessive shock or vibration is occurring.

• ESM information allows rig personnel to vary weight-on-bit and/or rotary speed real time to reduceshock and vibration without sacrificing penetration rate.


HEL MWD system

25.2 ft (7.7 m)

ESM sensor19.2 ft (5.8 m)

MWD/LWD

HELTM MWD System—Environmental Severity Measurement (ESMTM) Sensor



Specifications



Maximum OD 5 1⁄4 in. 7 3⁄8 in. 8 5 ⁄8 in. 8 7⁄8 in. 9 1⁄ 2 in.



Top connection 3 1⁄ 2 IF box 4 1⁄ 2 IF box 6 5 ⁄8 Reg box 5 1⁄ 2 IF box 7 5 ⁄8 Reg box

Bottom connection 3 1⁄ 2 IF pin 4 1⁄ 2 IF pin 6 5 ⁄8 Reg pin 5 1⁄ 2 IF pin 7 5 ⁄8 Reg pin

Make-up 9900– 28,000– 52,000– 53,000– 75,000–torque 10,900 ft-lb 32,000 ft-lb 56,000 ft-lb 56,000 ft-lb 78,000 ft-lb




Maximum doglegseverity, rotating 20°/100 ft 11°/100 ft 10°/100 ft 9°/100 ft 8°/100 ft

Maximum doglegseverity, sliding 36°/100 ft 19°/100 ft 16°/100 ft 15°/100 ft 14°/100 ft


Maximum operatingtemperature 356°F (180°C) 356°F (180°C) 356°F (180°C) 356°F (180°C) 356°F (180°C)





ESM Sensor Type–All Sizes

Sensor type Single-axis accelerometer

Measurement Lateral shock and vibration

MWD/LWD




HELTM MWD System—Environmental Severity Measurement (ESMTM) Sensor

Log Example

MWD/LWD

PrecisionLWDTM System—Multi-Frequency Resistivity (MFRTM) Sensor

The MFR sensor is designed to operate at borehole pressures up to 30,000 psi (207 MPa) and flow rates from 400 to 1800gal/min, depending on tool size. The MFR sensoroperates in all mud types at 2 MHz and 400 kHz with transmitter-receiver spacings of 20, 30 and 46 in.



• May be run in any mud system.

• Deeper reading 400 kHz measurements are unaffected by eccentering and holerugosity, providing stable easurements inhighly conductive formations drilled with oil-based mud.

• Deep-reading resistivity measurements and log inversion capabilities enhancegeosteering applications and horizontal log interpretation.

Applications

Transmitters

Receivers

Transmitters

46 in.

30 in.

20 in.

4 in.

4 in.

20 in.

30 in.

46 in.

Measure point

A compensated antenna design minimizes borehole effects,increases accuracy and provides a symmetrical log response.

• Fully-compensated antenna arrays integrated into the drill collar for increased reliability.

• Rated to 30,000 psi (207 MPa) operating pressure.

• Designed for high flow—4 3/4 in. (400 gal/min), 6 3/4 in., and 8 in. (1000 gal/min), 8 1/4 in. and 91/2 in. (1800 gal/min).

• Fully-digital electronics measure phase and attenuation at each transmitter-receiver pair,resulting in highly accurate measurements.

• Three transmitter-receiver spacings measure 12 fully compensated phase and attenuationmeasurements at unique radial distances from the borehole.

• Diameter of investigation of 197 in. at 20 ohm-m is the industry’s deepest reading LWD resistivity measurement.

• Three independent transmitter-receiver antenna spacings and two operating frequencies provide accurate measurements over a wide range of drilling conditions.

• Each compensated measurement has a unique depth of investigation. Any three can be combined to radially invert invasion diameter, flushed resistivity zone (Rxo) and true resistivity (Rt) over a wide range of borehole conditions and resistivity contrasts.

• Symmetrical antenna design minimizes borehole effects and cancels impedance changes in antennas caused by pressure and temperature variations while drilling.

MWD/LWD





Maximum OD 5 1 ⁄4 in. 7 3 ⁄ 8 in. 8 5 ⁄ 8 in. 8 7⁄ 8 in. 10 1⁄ 8 in.



Top connection 3 1⁄2 IF box 4 1⁄2 IF box 6 5 ⁄8 Reg box 5 1⁄2 IF box 7 5 ⁄8 Reg box

Bottom connection 3 1⁄2 IF pin 4 1⁄2 IF pin 6 5 ⁄8 Reg pin 5 1⁄2 IF pin 7 5 ⁄8 Reg pin

Make-up 9,900– 28,000– 52,000– 53,000– 75,000–torque 10,900 ft-lb 32,000 ft-lb 56,000 ft-lb 56,000 ft-lb 78,000 ft-lb


Maximum tension 750,000 lb 1,800,000 lb 2,850,000 lb 1,450,000 lb 1,870,000 lb




Equivalent bending 4.75 in. 6.75 in. 8.0 in. 8.25 in.stiffness (OD x ID) x 2.29 in. x 3.06 in. x 4.20 in. x 5.28 in.






MWD/LWD




Specifications

4 3 ⁄4 in. 6 3⁄4 in. 8 in. 8 1⁄4 in. 9 1⁄2 in.Nominal Sensor OD


MWD/LWD




Phase MeasurementFrequency 2 MHz 2 MHz 2 MHz 400 kHz. 400 kHz 400 kHzSpacing 20 in. 30 in. 46 in. 20 in. 30 in. 46 in.

Resistivity, ohm-m0.2 19.1 in. 23.1 in. 28.2 in. 26.0 in. 31.7 in. 39.4 in.2 28.2 in. 36.0 in. 44.9 in. 39.4 in. 49.7 in. 62.9 in.20 43.1 in. 55.5 in. 71.3 in. 53.0 in. 71.4 in. 95.8 in.200 56.4 in. 77.5 in. 106.2 in. 61.8 in. 87.8 in. 126.1 in.2000 64.3 in. 91.3 in. 133.2 in. 65.1 in. 95.1 in. 141.9 in.

Attenuation Measurement

Frequency 2 MHz 2 MHz 2 MHz 400 kHz 400 kHz 400 kHzSpacing 20 in. 30 in. 46 in. 20 in. 30 in. 46 in.


100-ohm-m bed 20-in. spacing 30-in. spacing 46-in. spacing

2-MHz phase 22 in. 28 in. 36 in.

2-MHz attenuation 56 in. 66 in. 79 in.

400-kHz phase 25 in. 35 in. 48 in.

400-kHz attenuation 87 in. 96 in. 111 in.






Diameter of Investigation

Vertical Resolution—50% Response

NominalSensorOD(in.) 4 3/4 , 6 3/4 , 8 , 8 1/4 , 9 1/2

Phase Attenuation

Measure point from 10.4 ftbottom of sensor

Measurement range 0.1–3000 ohm-m 0.1–200 ohm-m

Accuracy (all spacings) ±.25 mmhos ±.5 mmhos

Performance Specifications

MWD/LWD





Limestone—horizontal well with salt-saturated mud


MWD/LWD

The MFR HT sensor is designed to operate atborehole pressures up to 30,000 psi (207 MPa)and flow rates from 400 to 2000 gal/min,depending on tool size. The MFR HT sensoroperates in all mud types at 2 MHz and 400kHz with transmitter-receiver spacings of 20, 30 and 46 in.


• May be run in any mud system.

• Deeper reading 400 kHz measurements areunaffected by eccentering and hole rugosity,providing stable measurements in highlyconductive formations drilled with oil-based mud.

• Deep-reading resistivity measurements andlog inversion capabilities enhance geosteeringapplications and horizontal log interpretation.

Applications

Transmitters

Receivers

Transmitters

46 in.

30 in.

20 in.

4 in.

4 in.

20 in.

30 in.

46 in.

Measure point

A compensated antenna design minimizes borehole effects,increases accuracy and provides a symmetrical log response.

PrecisionLWDTM System—Multi-Frequency Resistivity (MFRTM) High-Temperature Sensor

MWD/LWD



• Fully-compensated antenna arrays integrated into the drill collar for increased reliability.

• Rated to 30,000 psi (207 MPa) operating pressure.

• Designed for high flow—4 3/4 in. (400 gal/min) to 9 1/2 in. (2000 gal/min).

• Fully digital electronics measure phase and attenuation at each transmitter-receiver pair,resulting in highly accurate measurements.

• Three transmitter-receiver spacings measure 12 fully compensated phase and attenuationmeasurements at unique radial distances from the borehole.

• Diameter of investigation of 197 in. at 20 ohm-m is the industry’s deepest reading LWDresistivity measurement.

• Three independent transmitter-receiver antenna spacings and two operating frequenciesprovide accurate measurements over a wide range of drilling conditions.

• Each compensated measurement has a unique depth of investigation. Any three can becombined to radially invert invasion diameter, flushed resistivity zone (Rxo) and true resistivity(Rt) over a wide range of borehole conditions and resistivity contrasts.

• Symmetrical antenna design minimizes borehole effects and cancels impedance changes inantennas caused by pressure and temperature variations while drilling.



MWD/LWD




Maximum OD 5 1 ⁄4 in. 7 3 ⁄ 8 in. 8 5 ⁄ 8 in. 8 7⁄ 8 in. 10 1⁄ 8 in.



Top connection 3 1⁄2 IF box 4 1⁄2 IF box 6 5 ⁄8 Reg box 5 1⁄2 IF box 7 5 ⁄8 Reg box

Bottom connection 3 1⁄2 IF pin 4 1⁄2 IF pin 6 5 ⁄8 Reg pin 5 1⁄2 IF pin 7 5 ⁄8 Reg pin

Make-up 9,900– 28,000– 52,000– 53,000– 75,000–torque 10,900 ft-lb 32,000 ft-lb 56,000 ft-lb 56,000 ft-lb 78,000 ft-lb


Maximum tension 750,000 lb 1,800,000 lb 2,850,000 lb 1,450,000 lb 1,870,000 lb




Equivalent bending 4.75 in. 6.75 in. 8.0 in. 8.25 in.stiffness (OD x ID) x 2.29 in. x 3.06 in. x 4.20 in. x 5.28 in.






Specifications

4 3 ⁄4 in. 6 3⁄4 in. 8 in. 8 1⁄4 in. 9 1⁄2 in.Nominal Sensor OD


MWD/LWD




Phase MeasurementFrequency 2 MHz 2 MHz 2 MHz 400 kHz. 400 kHz 400 kHzSpacing 20 in. 30 in. 46 in. 20 in. 30 in. 46 in.


Attenuation Measurement

Frequency 2 MHz 2 MHz 2 MHz 400 kHz 400 kHz 400 kHzSpacing 20 in. 30 in. 46 in. 20 in. 30 in. 46 in.












Diameter of Investigation

Vertical Resolution—50% Response

NominalSensorOD(in.) 4 3/4 , 6 3/4 , 8 , 8 1/4 , 9 1/2

Phase Attenuation

Measure point from 10.4 ftbottom of sensor

Measurement range 0.1–3000 ohm-m 0.1–200 ohm-m

Accuracy (all spacings) ±.25 mmhos ±.5 mmhos

Performance Specifications

MWD/LWD





Limestone—horizontal well with salt-saturated mud

LWD I Essentials

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