MWD and Basic Directional Drilling

COMPUTALOG DRILLING SERVICES

MWD I Essentials Training Curriculum

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Computalog Drilling Services Technology Services Group 16178 West Hardy Road, Houston, Texas 77060 Telephone: 281.260.5700 Facsimile: 281.260.5780

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MWD I Essentials (Bombay, India) Course #110 Course Outline: Monday, June 2 through Saturday, June 7, 2003 Day One (Monday) Introduction Registration, Introductions, and Course Description

1 hour

Directional Drilling Basics Directional Drilling Applications Conventional Rotary BHA Configurations Positive Displacement Motors

2 hours

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

3 hours

Data Acquisition Methods 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

1 hour

1

CROL_110_revA_0306 (Bombay)

The Borehole Environment 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

1 hour

Day Two (Tuesday) Surveying Essentials and Quality Control 8 hours Importance of Directional Surveying Directional Surveying Terminology Directional Sensor Hardware Sensor Axes and Orientation Sensor Calibration Directional Sensor Response versus Orientation Magnetic Field Strength, Dip Angle, Horizontal and Vertical Components Calculations of Toolface, Inclination, Hole Direction Survey Quality Parameters - Gtotal, Btotal, Goxy, Boxy, Mag Dip Azimuth to Quadrant Conversions Magnetic Declination

Day Three (Wednesday) Surveying Essentials and Quality Control (continued) 3 hours Grid Convergence GEODEC Examples Factors Affecting Inclination and Hole Direction NMDC Spacing Calculations Survey Quality Control techniques Well Plan Parameters (Horizontal & Vertical Projections) and Calculation Methods

2


Sensor Theory, Application, and Interpretation Gamma Ray Logging o Applications Overview o Gamma Ray Theory o Sensor Hardware Functions o Environmental Effects on the Gamma Ray Measurement o Sensor Response versus Lithology & Fluid Type o Data Interpretation o Factors Affecting Gamma Log Quality o Applications Details

5 hours

Resistivity Logging o Applications Overview o Resistivity Theory o Sensor Hardware Functions o Environmental Effects on the Resistivity Measurement o Sensor Response versus Lithology & Fluid Type o Data Interpretation o Factors Affecting Resistivity Log Quality o Applications Details

Day Four (Thursday) Log Presentations and Formats Log Heading Bit Run Summary o Run Specific Data o Mud Data o Environmental Data o Sensor Specific Data Disclaimer and Remarks Bottomhole Assembly Diagrams Main Log o Vertical Scale Time Based Depth Based • Measured Depth • True Vertical Depth Correlation Log Detail Log o Log Tracks Linear and Logarithmic Curve Scaling and Units Track 1 – Lithology

3


2 hours

Track 2 – Resistivity Track 3 – Porosity Track 4 – Resistivity or Porosity Track 5 - Depth o Annotations o Typical Presentations Standard Triple Combo Repeat Sections Calibration Data Survey Report and Plots (TVD log)

Circulation System Hydraulics Function of Borehole Fluids Pressure Balance Equation Using the Hydraulic Slide Ruler to Calculate Bit Pressure Loss

3 hours

Mud Pulse Detection & Troubleshooting

2 hour

Day Five (Friday) Operational Issues Toolface Offset Measurement Procedures Introduction to MWD Field Operations Manual Open Discussion

3 hours

Review for Exam

1 hour

Lithium Battery Safety (Course #080)

4 hours

Day Six (Saturday) Written Exam

4

4 hours




SERVICES GROUP TECHNOLOGY

Directional Drilling Basics


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

TECHNOLOGY

SERVICES GROUP

Introduction to Directional Drilling


1

SERVICES GROUP

Types of Directional Wells

TECHNOLOGY

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


TECHNOLOGY

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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


2

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

TECHNOLOGY

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Applications of Directional Drilling


TECHNOLOGY

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• Sidetracking

• Inaccessible locations


3

TECHNOLOGY

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TECHNOLOGY

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Applications of Directional Drilling • 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


4

• Drilling underbalanced

• • • •

TECHNOLOGY

SERVICES GROUP


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.


TECHNOLOGY

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Directional Drilling Limitations • • • • • • •

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


5

TECHNOLOGY

SERVICES GROUP

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


TECHNOLOGY

SERVICES GROUP

Whipstock Operations


6

TECHNOLOGY

SERVICES GROUP

Jetting


TECHNOLOGY

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Directional Control with Rotary Assemblies • BHA types

• Design principles

• Building assembly • Dropping assembly • Holding assembly

• • • •

Side force Bit tilt Hydraulics Combination


7

• Increasing Weight on Bit, increases Deviation Tendency …. and vice-versa

TECHNOLOGY

SERVICES GROUP

Weight On Bit


TECHNOLOGY

SERVICES GROUP

Stabilization Principle • Stabilizers are placed at specified points to control the drill string and to minimize downhole deviation • The increased stiffness on the BHA from the added stabilizers keep the drill string from bending or bowing and force the bit to drill straight ahead • The packed hole assembly is used to maintain angle


8

TECHNOLOGY

SERVICES GROUP

Reasons for Using Stabilizers • • • • •

Placement / Gauge of stabilizers control directional 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


TECHNOLOGY

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Stabilizer Forces


9

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

TECHNOLOGY

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Building Assemblies (Fulcrum)


TECHNOLOGY

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Building Assemblies (Fulcrum)


10

TECHNOLOGY

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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


TECHNOLOGY

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Dropping Assemblies (Pendulum)


11

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

TECHNOLOGY

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Holding Assemblies (Packed)


TECHNOLOGY

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Application of Steerable Assemblies • • • • • •

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


12

SERVICES GROUP

Steerable Assemblies

• Build

TECHNOLOGY

• Drop • Hold


Turbine Motor

Positive Displacement Motor

TECHNOLOGY

SERVICES GROUP

Mud Motors


13

TM

PDM Motors

TECHNOLOGY

SERVICES GROUP

Commander


TECHNOLOGY

SERVICES GROUP

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


14

TECHNOLOGY

SERVICES GROUP

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


TECHNOLOGY

SERVICES GROUP

Motor Selection • Medium Speed / Medium Torque (4:5) motor typically used for: • Conventional and directional drilling • Diamond bit and coring applications • Sidetracking wells


15

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

TECHNOLOGY

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Motor Selection

TECHNOLOGY

SERVICES GROUP


Components of PDM Motors • • • • •

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


16

TECHNOLOGY

SERVICES GROUP

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


TECHNOLOGY

SERVICES GROUP

Dump Sub • Allows Drill String Filling and Draining • Operation

- Pump Off - Open - Pump On - Closed

• Discharge Plugs • Connections


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SERVICES GROUP

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

TECHNOLOGY

• 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


TECHNOLOGY

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Power Section • • • •

Pattern of the lobes and the length of the helix dictate the output characteristics Stator always has one more lobe than the rotor Stage – one full helical rotation of the lobed stator With more stages, the power section is capable of greater differential pressure, which in turn provides more torque to the rotor

Performance Characteristics COMPUTALOG DRILLING SERVICES

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TECHNOLOGY

SERVICES GROUP

Drive Assembly • Converts Eccentric Rotor Rotation into Concentric Rotation – Universal Joint » Flex Rod

Constant Velocity Joint -COMPUTALOG DRILLING SERVICES

TECHNOLOGY

SERVICES GROUP

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

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TECHNOLOGY

SERVICES GROUP

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


TECHNOLOGY

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Motor Handbook • Every possible motor configuration is represented in the Motor Handbook • • • •

Dimensional Data Specifications Adjustable Housing Settings Performance Charts


20

TECHNOLOGY

SERVICES GROUP

Motor Dimensional Data


TECHNOLOGY

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Motor Specifications


21

TECHNOLOGY

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Estimated Build Rates


TECHNOLOGY

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Performance Charts


22

TECHNOLOGY

SERVICES GROUP

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 pressure and 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


TECHNOLOGY

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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


23

TECHNOLOGY

SERVICES GROUP

Operational Constraints • 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%


TECHNOLOGY

SERVICES GROUP

Operational Constraints • 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


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

TECHNOLOGY

SERVICES GROUP

Directional Drilling Problems


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

TECHNOLOGY

SERVICES GROUP

Pressure Increases


25

TECHNOLOGY

SERVICES GROUP

Pressure Decreases • • • • •

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


TECHNOLOGY

SERVICES GROUP

Loss of Rate of Penetration • • • • •

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


26

• Revolution RST – Smart Stabilizer

TECHNOLOGY

SERVICES GROUP

Rotary Steerable


TECHNOLOGY

SERVICES GROUP

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


27

TECHNOLOGY

SERVICES GROUP

“Push the Bit” versus “Point the Bit”


• Geology • Completion and Production • Drilling Constraints

TECHNOLOGY

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Planning a Directional Well


28

• • • • •

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

TECHNOLOGY

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Geology


TECHNOLOGY

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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


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

TECHNOLOGY

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Drilling Constraints


TECHNOLOGY

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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 COMPUTALOG DRILLING SERVICES

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TECHNOLOGY

SERVICES GROUP

Planning • Build rates • Build and hold profiles should be at least 50m • Drop rate for S-curve wells is preferably planned at 1.5 o/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


TECHNOLOGY

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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


31

TECHNOLOGY

SERVICES GROUP

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 anticollision check


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PETROLEUM GEOLOGY PRIMER

Rocks and Minerals

1

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

2

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 surface Granite

• 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 Æ • Shale Æ

Marble Slate

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

3

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

4

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

5

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

6

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 bedrock may separate along deep fractures or bedding planes • Rockslide or avalanche

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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

8

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 bouldersized 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

9

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

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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

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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

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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

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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’s petroleum • 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

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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

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Origin of Hydrocarbons

u ta lo g

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”

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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 1215%

Chemical Composition of Average Crude 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%

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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

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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

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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

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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

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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

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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

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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 Anticline Structure

• 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 Impermeable Bed Sealing Fault

• 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

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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

Stream Channel

• 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

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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 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

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Combination Traps • Many petroleum traps have both structural and stratigraphic features • Typically found near salt domes

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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

1

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

2

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

3

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

4

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 • Computalog’s initial LWD telemetry method will be 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

5

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

6

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

TransmitterReceiver

Earth Antenna

Bi-directional Transmission

Emitting Antenna

Drill Bit

Injected Current

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) • Computalog’s LWD system will be able to utilize EM telemetry in the future

7

Electromagnetic Telemetry Advantages • No restriction on drilling fluid characteristics; drilling fluid can 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 between the emitting antenna and surface receiver • “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

8

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

1

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

2

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

3

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

4

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

Formation Permeability

<1 md

Poor

1-10 md

Fair

10-100 md

Good

100-1000 md

Very Good

• 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

5

Formation Permeability • 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

6

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%) • The saturations of each fluid throughout the formation will affect LWD sensor response in very distinct ways

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

7

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”

8

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

9

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

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

10



LWD SENSOR THEORY, APPLICATION, & INTERPRETATION Directional

1

Importance of Directional Data

“Delivery of high quality,

accurate directional data is your highest priority on my wellsite” - the customer

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

3

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

4

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

5

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.

6

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)

7

Measured Depth • Measured depth refers

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

8

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)

9

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

10

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

11

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.

12

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

13

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

14

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.

15

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

16

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

17

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

18

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)

19

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

20

Magnetic Pole Movement (1945 – 2000) North Pole

South Pole

21

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.

22

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

23

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 + Declination 80° = 75° + (+5°)

24

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 + Declination 115° = 120° + (-5°)

25

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

26

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

27

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

28

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

Convergence is zero here

29

Grid Zones • Convergence correction increases as location moves away from the equator and central meridian • Convergence should not be more than +/-3°, otherwise the incorrect central meridian has been chosen

Maximum Grid Correction

30

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

31

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

32

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

33

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°)

34

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°)

35

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°)

36

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)

37

Sources of Real-time Inclination Errors • These factors can introduce error into the inclination value presented to the directional driller: – – – – –

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

38

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? 2

2

2

Gtotal = (Gx + Gy +Gz )

1/2

39

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

40

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? 2

2

2

Btotal = (Bx + By +Bz )

½

• Is Gtotal within +/- 0.003 g of the Local Gravitational Field Strength?

41

Additional Survey Quality Checks (Bx * Gx) + (By * Gy) + (Bz * Gz) • MDIP = ASIN {----------------------------------------------} Gtotal * Btotal • • • •

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

42

Survey Quality Checks 2

2

2

2

2

• Gtotal = (Gx + Gy +Gz ) 2

• Btotal = (Bx + By +Bz )

1/2

1/2

(Bx * Gx) + (By * Gy) + (Bz * Gz) • MDIP = ASIN {----------------------------------------------} Gtotal * Btotal

43

Survey Quality Check Limits • Gtotal = Local Gravity +/- 0.003 g • Btotal = Local Field +/- 350 nT • MDIP = Local Dip +/- 0.3°

44

Survey Quality Example #1 Given the following survey data, decide whether each quality check is within limits Local References:

INC 3.72

Gtotal = 1.000 g

AZ 125.01

Btotal = 58355 nT

Gtotal 1.0012

Mdip = 75.20°

Btotal MDip 58236 75.25

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

45


INC 3.72

Gtotal = 1.000 g

AZ 125.01

Btotal = 58355 nT

Gtotal 1.0012 +0.0012

Mdip = 75.20°

Btotal MDip 58236 75.25 -119 -0.05

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

46


INC 5.01

Gtotal = 1.000 g

AZ 127.33

Btotal = 58355 nT

Gtotal 1.0009

Mdip = 75.20°



47


INC 5.01

Gtotal = 1.000 g

AZ 127.33

Btotal = 58355 nT

Gtotal 1.0009 +0.0009

Mdip = 75.20°

Btotal MDip 58001 74.84 -354 -0.36

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

48


INC 8.52

Gtotal = 1.000 g

AZ 125.34

Btotal = 58355 nT

Gtotal 0.9953

Mdip = 75.20°



49


INC 8.52

Gtotal = 1.000 g

AZ 125.34

Btotal = 58355 nT

Gtotal 0.9953 -0.0047

Mdip = 75.20°

Btotal MDip 58150 74.28 -205 -0.92

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

50


INC 17.13

Gtotal = 1.000 g

AZ 129.88

Btotal = 58355 nT

Gtotal 1.0120

Mdip = 75.20°



51


INC 17.13

Gtotal = 1.000 g

AZ 129.88

Btotal = 58355 nT

Gtotal 1.0120 +0.0120

Mdip = 75.20°

Btotal MDip 57623 73.44 -732 -1.76

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

52

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’

53

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

54

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

55

Average Angle Calculation Method • Assumes distances from survey to survey are straight lines • Fairly accurate and conducive to hand calculations

56

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

57

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

58

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

59

Survey Terminology

60

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

61

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 northsouth direction in the horizontal plane – North is positive, South is negative

•

Departure (Easting) – The distance traveled in the eastwest direction in the horizontal plane – East is positive, West is negative

62

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

63

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 * (Target Direction – Closure Direction)

64

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 Vertical Depth

Build Section Locked in Section

Tangent Vertical Section

65

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

Closure Proposal Direction

Latitude

E Departure Vertical Section

66

Directional Sensors

1

MWD Survey Measurements

Introduction

The Directional Sensor is made up of electronic printed circuit boards, a Tensor Tri-Axial Magnetometer and a Tensor Tri-Axial Accelerometers, and Temperature sensor. These modules are configured into a directional probe and are run in the field mounted in a nonmagnetic drill collar. The Directional Sensor provides measurements, which are used to determine the orientation of the drill string at the location of the sensor assembly. The Directional Sensor measures three orthogonal axis of magnetic bearing, three orthogonal axes of inclination and instrument temperature. These measurements are processed and transmitted by the pulser to the surface. The surface computer then uses this data to calculate parameters such as inclination, azimuth, high-side toolface, and magnetic toolface. The sensor axes are not perfectly orthogonal and are not perfectly aligned, therefore, compensation of the measured values for known misalignments are required in order to provide perfectly orthogonal values. The exact electronic sensitivity, scale factor and bias, for each sensor axis is uniquely a function of the local sensor temperature. Therefore, the raw sensor outputs must be adjusted for thermal effects on bias and scale factor. Orthogonal misalignment angles are used with the thermally compensated bias and scale factors to determine the compensated sensor values required for computation of precise directional parameters.

2

4/24/2002


Directional Sensor Hardware The figure above shows the basic configuration of the Directional Sensor probe. The directional probe is mounted to the MWD assembly and keyed into a Non-Magnetic Drill Collar. The nominal length of the sub is 30 feet. The nonmagnetic collar is usually referred to as Monel.

Directional Sensor Components Contained inside the assembly is a Single Port MPU, Triple Power Supply and a Digital Orientation Module. The Single Port MPU is a modular micro-controller assembly based on the Motorola MC68HCll microprocessor implementing Honeywell's qMIXTM communications protocol (qMIX/ll TM). The Triple Power Supply provides regulated power for the complete assembly. The microprocessor provides the control and timing to interface the logic circuit controls the analog power switch. With the analog power switch off only the 5 volt circuits are active and the current drain from the sub bus is approximately 8 milliamps. When the logic board switches on the analog power switch, battery power is directed to the 12 volt regulator on the analog circuit. The current drain with the analog power switch on and the sensors off is approximately 80 milliamps. With the accelerometers powered up the current drain is approximately 120 milliamps. With the magnetometer powered up the current drain is approximately 140 milliamps.

Analog Circuit The Analog Circuit provides an interface with the inclinometer, magnetometer, and pressure transducer sensors. The 16 channel multiplexer on the analog circuit takes input from various sensor outputs and sends the data to the logic circuit for transmission. A sensor power switch takes power from the 12 volt regulator and selectively powers up the accelerometers and magnetometers. A 5 volt excitation supply from the 12 volt regulator is used to power the pressure transducer. The status voltages appear on the surface probe test and are defined as follows: 1. Sub Bus Voltage - battery voltage on the sub bus. 2. 5 Volt Supply - the 5 volt excitation supply from the 12 volt regulator that powers the pressure transducer. 3. Accelerometer Power Status - voltage that is currently being supplied to the inclinometer (0 or 12.5v).

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4. Magnetometer power Status - voltage that is currently being supplied to the magnetometer (0 or 12.5v). 5. Steering Mode Status - 4.5 volts when steering mode is set.

Tensor Inclinometer The TENSOR Tri-axial Accelerometer measures three orthogonal axes of inclination (Gx, Gy, and Gz) and also includes a temperature sensor. The inclinometer has a 1g full scale output in survey mode and a 7 g full scale output in steering mode. The sensor operates within the following parameters: 1. Input Voltage +/- 12.5 to 15.5 volts 2. Input Current < 80 ma/g 3. Accelerometer Output 3.0 ma/g

The inclinometer is made up of three accelerometers. The operation of the accelerometer is based on the movement of a quartz proof mass during acceleration. The figure above is a diagram of a accelerometer. The accelerometer consists of two magnets and a quartz disc with a coil attached to it. The quartz disc is a proof mass with a hinge that has been chemically etched to allow movement in one direction. A torquer coil is attached to the proof mass, which is suspended between the two permanent magnets. The proof mass position is maintained by applying current to the torquer coil. The magnets have reference plates, which measure the capacitance between the two magnets. When a force is applied to the accelerometer, movement of the proof mass changes the capacitance. A circuit detects the 4

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change in capacitance and applies current to the torquer coil to restore the proof mass to its original position. The amount of current required to restore the proof mass to its original position is a function of the amount of force applied to the accelerometer. Force is related to acceleration by F = ma. We measure the acceleration of gravity in g's (gravity units) in three orthogonal directions relative to the Directional Sensor probe. This allows us to calculate the inclination of the tool relative to vertical.

The scaling of the X and Y accelerometer channels depends on the operational mode (survey or steering), while the Z channel and the temperature sensor have the same scaling for both modes. The full scale output voltage sensitivity for each mode is as follows: CHANNEL

SURVEY

STEERING

1. X Accelerometer

4.5 v/g

642 mv/g

2. Y Accelerometer

4.5 v/g

642 mv/g

3. Z Accelerometer

4.5 v/g

4.5 v/g

4. Temperature

10 mv/deg K

10 mv/deg K

Tensor Magnetometer The Tensor Tri-axial Magnetometer measures three orthogonal axes of magnetic bearing (Bx, By, and Bz) as well as temperature. The Tensor Model 7002MK Magnetometer has an output operating range of plus and minus 100,000 Nanotesla (the earth's field is about 50,000 Nanotesla) and operates within these parameters:

1. Input voltage +/- 12 - 18 vdc 2. Input current 25 milliamps 3. Flux Gate Output 1 mv / 20 Nanotesla 4. Temperature Output Voltage 10 mv / oK

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The Tensor magnetometer is a saturable core device. It consists of two coils with a core between them, which has a certain magnetic permeability. A magnetic field produced by one coil travels through the core and induces a current in the other coil. The core will only transmit a certain amount of magnetic field, that is , when the level of magnetic flux gets to a certain point the core will become saturated and greater amounts of flux will not pass through the core. The point at which a substance becomes saturated is a property of that substance, i.e. certain metals will saturate sooner than others. The magnetometer continually drives the core to saturation. In the presence of an external magnetic field the point that the core saturates is shifted. The signal shift is detected, amplified, and fed back as a bucking magnetic field to maintain the core at a balanced around zero magnetizing force. The servo amplifier offset caused by the signal shift is further amplified and presented as the output of the magnetometer. In the tri-axial set of magnetometers, the three flux gate channels and temperature channel are supplied power conditioned by a common pair of internal regulators. The individual magnetometer transducers come in biaxial sets. The magnetometer package contains two biaxial magnetometers, of which only three axes are used. The sub bus around the magnetometer requires particular attention because the current through the sub bus is alternating current, any change in that current will produce a magnetic field that can affect the magnetometer.

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Directional Sensor Measurements and Calculations

The measurements that we make with the DIRECTIONAL SENSOR are made relative to these axes. The X-axis is perpendicular to the tools long axis and is in the direction of the scribe line etched on the DIRECTIONAL SENSOR nonmag sub. The Y-axis is also perpendicular to the long axis. The Z-axis is along the long axis of the DIRECTIONAL SENSOR; in the direction the hole is being drilled. The scribe line on the DIRECTIONAL SENSOR sub allows measurement of the relationship TOOL PHYSICAL AXIS between the tools axis and the bent sub or mud motor scribe line. This measurement is called the toolface offset. The toolface offset is measured by extending the bent sub scribe line to the DIRECTIONAL SENSOR X scribe line and measuring the degrees offset with a compass. The measurement is made from _________ scribe line scribe line to _____________ scribe line using the right hand rule, thumb pointing in the direction of the hole, measure in the direction the fingers of your right hand are pointing. Running a highside orientation program in the MWD software can also make the measurement. Y

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Z

The main parameters that we calculate with the raw data from the DIRECTIONAL SENSOR are as follows:

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Highside Toolface is the angle between the deflection tool scribe line and the top or highside of the hole. This is calculated using the X-axis and Y-axis inclinometer measurements. Magnetic Toolface is the direction that the deflection tool scribe line is pointing relative to true or grid north. This is calculated using the X-axis and Y-axis magnetometer measurements. Inclination is the angle between vertical and the wellbore in the vertical plane. We measure this angle by measuring the direction that gravity acts relative to the tool. Gravity acts in a vertical direction and has a magnitude of 1 g at sea level at the equator.

Azimuth is the direction of the wellbore relative to true or grid north in the horizontal plane. We measure this angle by measuring the direction of the earth's magnetic field relative to the tool. Magnetic Declination is the difference in degrees between magnetic north and true north or grid north for a particular location on the earth. This value changes with time and location and must be determined using the software program. On a directional well it is important that the value for magnetic declination that we use is the same one that the directional driller is using. Usually there will be a difference between the value that the software calculates and the one that the directional driller provides, however, always use the value provided by the directional driller.

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Magnetic Field Strength is the total magnitude of the earth's magnetic field in Nanotesla for a particular location on the earth. This value also changes with time and location and can be determined using the software program. Magnetic Dip Angle is the angle between horizontal and the earth's magnetic field force lines. This angle increases as you go north toward the magnetic north pole. If you were exactly on top of the magnetic north pole the angle would be 90 degrees.

Highside Toolface The X-axis and Y-axis inclinometer measurements are required to calculate highside toolface. The figure below is a vector diagram showing the highside toolface measurement. On the left is a diagram of the tool and

its relationship to the X - Y plane and the gravity vector, along with the components of gravity in the X - Y plane and on the Z-axis. Gxy is the vector sum of the X and Y components of the gravity vector measured by the tool. On the right is a diagram of the X - Y plane showing the X and Y components of the gravity vector and the sum Gxy. Highside toolface is the angle between the X axis and the highside of the hole and is calculated as follows:

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Gxy = ( Gx2 + Gy2)1/2 COS ( HSTF) = -Gx / Gxy SIN (HSTF) = Gy / Gxy HSTF = ATAN ( Gy / -Gx ) or HSTF = ATAN2 ( Gy, -Gx) Where:

Gx = Gravity vector in the X direction Gy = Gravity vector in the Y direction Gxy = Sum of the X and Y vectors HSTF = Highside toolface and all vectors are in gravity units.

Magnetic Toolface The X-axis and Y-axis magnetometer measurements are required to calculate magnetic toolface. Bxy is the vector sum of the X and Y components of the magnetic vector measured by the tool. Magnetic toolface is the direction the scribeline is pointing and is calculated as follows: Bxy = ( Bx2 + By2)1/2 MTF = ATAN ( By / -Bx ) Where:

or

MTF = ATAN2 ( By, -Bx)

Bx = Magnetic vector in the X direction By = Magnetic vector in the Y direction Bxy = Sum of the X and Y vectors MTF = Magnetic toolface and all vectors are in gravity units.

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Inclination

To calculate inclination we use the X, Y, and Z inclinometer measurements. The figure shows a diagram of the tool and the relevant axes. Again, Gxy is the sum of the X and Y components of the gravity vector as calculated above. Gz is the Z component of the gravity vector as measured by the tool. Gtotal is the total gravity vector and is the sum of the X, Y, and Z components. This sum should be equal to 1 g, as long as your elevation is relatively close to sea level. Inclination is the angle between the Z axis and vertical and is calculated as follows: Gtotal = ( Gxy2 + Gz2 )1/2 Sin ( INC ) = Gxy / Gtotal

or

INC = ASin Gxy

Cos ( INC) = Gz / Gtotal

or

INC = ACos Gz

INC = ATAN ( Gxy / Gz ) INC = ATAN2 (Sin (HSTF) Gy – Cos (HSTF) Gx, Gz)

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Where: Gxy = the sum of X and Y gravity components Gz = the Z axis gravity component Gtotal = the sum of the X, Y, and Z gravity components INC = inclination units are in g's. Note that since we know that Gtotal is 1 g, we can calculate inclination from only the X and Y measurements, or only the Z measurement if one of the accelerometers fail, however, if only Gz is known the accuracy at low angles is less because the Z accelerometer is near full scale.

For Gz only: Not accurate for inclination less than 15o +/- 1/2o accuracy for inclination greater than 15o and less than 30o +/- 1/4o accuracy for inclination greater than 30o and less than 45o +/- 1/8o accuracy for inclination greater than 45o

Long Collar Azimuth To calculate azimuth using the conventional method the following data is required: 1. Bx = magnetic field vector in the X direction 2. By = magnetic vector in the Y direction 3. Bz = magnetic vector in the Z direction 4. HSTF = highside toolface 5. INC = inclination Azimuth is referenced in the horizontal plane to true or grid north. The magnetic field that we measure, however, is at some angle from the horizontal, that is the magnetic dip angle. Therefore to reference our measurement to true north in the horizontal plane we must project the magnetic vector to the horizontal. This is why you need HSTF and inclination to calculate azimuth.

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Where: Bn = horizontal component of the magnetic vector Btotal = total magnetic field strength DIP = magnetic dip angle

Combining the above equations for raw azimuth yields the following:

Bx Sin (HSTF) + By Cos (HSTF) AZ = ATAN {--------------------------------------------------------------------------} (Bx Cos (HSTF) - By Sin (HSTF)) Cos (Inc) + Bz Sin (Inc)

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Short Collar Azimuth Traditional compass type surveying instruments with their ability to sense only the direction of the local magnetic field vector must be used in conjunction with enough nonmagnetic drill collars so that the local magnetic field vector is uncorrupted by drill string magnetization. With solid state magnetometers and their ability to measure 3 orthogonal axes of the local magnetic vector it is possible to compensate for axial magnetization and use much shorter lengths of nonmagnetic material. Azimuth is defined as any azimuth measurement made with respect to the local magnetic field without correction, ie. the long collar azimuth. When there is no magnetic interference the azimuth is the true azimuth, otherwise an extraneous magnetic field produces a systematic error in the azimuth measurement and the long collar azimuth differs from the true azimuth. The short collar azimuth is based upon a patented technique that uses the magnitudes of the magnetic field components Bx and By in conjunction with the known values of the earth's magnetic field strength and dip angle to compensate for the corrupted Bz measurement. An instrument used with the corrected azimuth technique requires highly accurate calibration, because the absolute magnitudes of the field vector components are required. The long collar azimuth, however, requires only ratios of the magnitudes of these components, thus reducing the calibration complexity and scale factor errors for this measurement.

Survey Quality The following items will be used to validate a MWD survey:

Gtotal = (Gx2 + Gy2 +Gz2 ) ½ G total - this value is equal to (Gx2 + Gy2 + Gz2)1/2, and should be within +0.003 g of the local gravity, which is 1.000 g in most locations. A Gtotal value outside of these limits may indicate that the Directional Sensor did not achieve stability during accelerometer polling, there was a hardware failure, BHA movement or improper misalignment and/or scale/bias values were used.

Btotal = (Bx2 + By2 +Bz2 ) ½ B total is equal to (Bx2 + By2 + Bz2)1/2, and should trend consistently over the interval of a bit run. Under ideal conditions, i.e., no cross-axial or axial magnetic interference, Btotal should read the earth's local magnetic field strength. Abrupt variations in Btotal during a bit run will be caused by a "fish", a nearby cased well bore, certain mineral deposits, solar events, localized magnetic anomalies, or a hardware failure. Since all of the above will typically affect all three magnetometer responses, magnetic interference will be detectable by tracking the Btotal value.

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As a general guideline, Btotal should not vary by more than +- 350 Nanotesla from the local magnetic field strength or from survey to survey during a bit run. The local magnetic field strength is determined by using magnetic modeling software or directly measuring it through infield referencing. Surveys which do not conform to this guideline should alert the field engineer that some magnetic interference is probable or that there was a hardware failure. Btotal may also change abruptly from bit run to bit run due to a change in BHA configuration, which does not have the correct Monel spacing. Magnetic Dip Angle should trend consistently over the interval of a bit run. Under ideal conditions, (i.e., no cross-axial or axial magnetic interference or pipe movement), MDIP should read the earth's local magnetic dip angle. Abrupt variations in MDIP during a bit run will be caused by a "fish", a nearby cased well bore, certain mineral deposits, solar events, localized magnetic anomalies, pipe movement or a hardware failure.

(Bx * Gx) + (By * Gy) + (Bz * Gz) MDIP = ASIN {-------------------------------------------------------} Gtotal * Btotal As a general guideline, MDIP should not vary by more than +- 0.3 degrees from the local magnetic dip angle or from survey to survey during a bit run. The local magnetic dip angle is determined by using magnetic modeling software or directly measuring it through infield referencing. Surveys which do not conform to this guideline should alert the field engineer that some magnetic interference or pipe movement is probable, or that there was a hardware failure. MDIP may also change abruptly from bit run to bit run due to a change in BHA configuration, which does not have the correct Monel spacing.

Magnetic Interference Magnetic interference problems when surveying a well are usually due to casing or a fish that has been left in the hole. Unfortunately, the majority of the magnetic interference problems occur when the accuracy of our azimuth is very critical. A well is usually kicked off just below a casing shoe or through a window in the casing. The casing is a large concentration of magnetic material, the ends of which act like magnetic poles from which the curving flux lines cause magnetic interference. On production platforms or pads nearby wells can cause interference as well. The magnetic interference that we are primarily concerned with is in the X and Y direction. This is due to the fact that magnetic toolface uses the X and Y magnetometers to calculate toolface. Also with the Short collar method of surveying, only the X and Y magnetometers are used. A good way of determining how much magnetic interference we are getting on the Zaxis with the Short collar method is to compare Btotal measured with Btotal calculated.

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The X and Y magnetometers will react to magnetic interference in the same manner as the Z magnetometer. This would mean that a perpendicular distance of about 30' would be required when kicking off near casing. The orientation of the casing with respect to the magnetometers may have some effect on how much azimuth is affected. As the tool is rotated, X and Y interference changes, but Btotal should stay the same.

Non-Mag Spacing When kicking off a well below casing, it is necessary to have at least 10 diameters of clearance between the shoe and the DIRECTIONAL SENSOR. When kicking off next to another well or a fish, where the magnetic interference is perpendicular to the tool, up to 30' clearance may be required to obtain good magnetic toolface or surveys. Take special care when running a magnetic survey to prevent the effects of magnetic interference. Such interference can be caused by proximity to steel collars and by adjacent casing, hot spots in nonmagnetic collars, magnetic storms, and formation with diagenetic minerals.

Nonmagnetic drill collars are used to separate the electronic survey instrumentation from the magnetic fields of Drill string both above and below and prevent the distortion of the earth's magnetic field at the sensor. The collars are of four basic compositions: (I) K Monel 500, an alloy containing 30% copper and 65% nickel, (2) chrome/nickel steels (approximately 18% chrome, 13% nickel), (3) austenitic steels based on chromium and manganese (over 18% manganese) and (4) copper beryllium bronzes. Currently, austenitic steels are used to make most nonmagnetic drill collars. The disadvantage of the austenitic steel is its susceptibility to stress corrosion in a salt mud environment. The K Monel and copper beryllium steels are to expensive for most drilling operations; both however are considerably more resistant to mud correction than austenitic steels. The chrome/nickel steel tends to gall, causing premature damage to the threads.

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When the electronic survey instrumentation is located in a nonmagnetic collar between the bit and steel collars the distortion of the earths magnetic field is minimized and it is isolated from drill string interference generate both above and below the electronic survey instrumentation unit. The number of required nonmagnetic collars depends on the location of the well bore on the earth and inclination and direction of the well bore. The figure above is a compilation of empirical data that are fairly reliable in selecting the number of nonmagnetic drill collars. First, a zone is picked where the well bore is located either zone 1, 2 or 3. Then the expected inclination and direction are used locate the curve, either A, B or C. Example, on the north slope of Alaska a well plan calls for an inclination of 60 degrees and a magnetic north azimuth of 50 degrees. Solution, The north slope of Alaska is in zone 3. From the chart for zone 3 at 60 degrees inclination and 50 degrees magnetic north azimuth, the point falls in Area B, indicating the need for two 30’ magnetic collars with the electronic survey instrumentation unit 8 -10 feet below the center. This is just a recommendation and the survey should always be checked to make sure it is with in acceptable tolerances of the (non-corrupted) earth's magnetic field.

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Empirical Data Charts for Nonmagnetic Drill Collar Spacing ZONE 1

18

ZONE 2

ZONE 3

90

90

90

80

80

80

70

70

70

60

60

60

50

50

50

40

40

40

30

30

30

20

20

20

10

10

10

10 20 30 40 50 60 70 80 90

10 20 30 40 50 60 70 80 90

10 20 30 40 50 60 70 80 90

Direction Angle from Magnetic N or S



Compass Spacing

Compass Spacing

Compass Spacing

Area A 18’ collar: 1’ to 2’ below center Area B 30’ collar: 3’ to 4’ below center Area C tandem 18’+25’: center of bottom collar

Area A 30’ collar: 3’ to 4’ below center Area B 60’ collar: at center Area C 90’ collar: at center

Area A 60’ collar: at center Area B 60’ collar: 8’ to 10’ below center Area C 90’ collar: at center

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Survey Accuracy Survey accuracy is a function of both instrument related uncertainties and systematic uncertainties. Instrument related uncertainties include such things as sensor performance, calibration tolerances, digitizer accuracy, and resolution. This is defined as the baseline uncertainty and it is present in all survey sensors. Systematic uncertainties are a function of magnetic interference from the drill string and can be reduced by housing the instrument in a longer nonmagnetic drill collar. The total uncertainty is equal to the baseline uncertainty plus the systematic uncertainty. The long collar azimuth, when measured in an environment free from magnetic interference, will always provide the most accurate azimuth, the only uncertainty being the baseline uncertainty. The Short collar algorithm corrects for systematic uncertainties due to the presence of magnetic interference along the Z axis of the magnetometer. For the Short collar method, the systematic uncertainty is in the values that we obtain for the magnetic field strength and dip angle. Due to the fact that this uncertainty is along the Z axis, survey accuracy will be a function of inclination and azimuth, as well as dip angle and magnetic field strength. If we consider only the baseline uncertainty, in the absence of magnetic interference, survey accuracy will be a function of inclination and magnetic dip angle. This relationship is shown in figures below, where Bn (Bnorth) is defined as the projection of the magnetic field vector in the horizontal plane, Berror is defined as the baseline uncertainty and has a constant value, and Bref is defined as the measured magnetic field vector (Bref = Bn + Berror). As shown in the figure below, as the inclination increases, the horizontal projection of Berror is a larger percentage of Bref resulting in a decrease in survey accuracy. In the figure below, the effect of magnetic dip angle on survey accuracy is shown. As the magnetic dip angle increases, the size of the horizontal projection of Bn decreases, resulting in a larger percentage of Berror in Bref. Thus anything that causes the horizontal projection of Berror to increase or Bn to decrease results in decreased survey accuracy.

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For systematic uncertainty, the uncertainty is along the Z-axis. This will result in decreased survey accuracy when drilling east or west as opposed to drilling north or south. This is due to the fact that Berror will tend to pull Bref in the direction of the Z-axis, away from Bn. This relationship is shown in the figure below.

Directional Sensor Calibration The accuracy of borehole azimuth and inclination measurements are largely dependent on our ability to identify and correct constituent errors in the individual sensors that are used to calculate the directional parameters of the well bore. These sensors include the three orthogonal accelerometers and three orthogonal magnetometers. The calibration process is based upon the known value of the total field intensity of both the gravity and magnetic fields at the location of the calibration. Each sensor is rotated through the known field and its output is compared with known values. This process yields a set of values for bias, scale factor, and

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alignment corrections over a range of temperatures from room temperature to the upper operating limit. The data is fit to a third order polynomial so that the correction factors can be applied at any given temperature within the operating range of the tool. To be certain that the a calibration technique will meet the performance as well as maintenance objectives it must meet the following objectives: 1. Total package evaluation 2. Repeatability 3. Tolerant of positioning errors during calibration 4. Reliability under down hole conditions The calibration is performed at the highest level of assembly through the instruments data acquisition system and final housing. This allows a total package model to be built so that errors do not accumulate as separate modules are incorporated into each other. Repeatability and tolerance to positioning errors during calibration is achieved by establishing specific performance standards for each sensor and through the methodology of the calibration itself. Reliability under down hole conditions is addressed at the Materials Testing Laboratory by exposing each sensor to vibration and thermal cycling while monitoring their output. Reliability is also achieved through failure analysis and design and modification of the sensor package.

Calibration Methodology The calibration procedure consists of rotating the sensor through the field of investigation for each axis and comparing the output with known values. Examine the ideal response of a single axis rotation, at 0 degrees the sensor axis is aligned with the field and the output voltage is at a maximum. As you rotate the sensor counter clockwise the voltage decreases until at 90 degrees the output goes to 0 volts. As you continue to rotate the sensor counter clockwise the output voltage goes negative above 90 degrees and reaches a maximum negative value at 180 degrees. The response as you go from 180 to 360 degrees is similar. Note that this response applies to both accelerometers and magnetometers when rotated through the gravity or magnetic field. Scale factor corrections scale the output of the sensor to a given standard so that all sensors will have the same voltage response to a given field. Alignment errors are positioning errors between the individual transducers and the DIRECTIONAL SENSOR probe true physical axis. The computation of bias, scale factor, and alignment corrections based on the examination of a single axis would put considerable accuracy requirements upon both the calibration fixtures and the personnel that operate them. By performing an analysis using data simultaneously obtained from multiple axes greatly reduces sensitivity to positioning errors and improves repeatability.

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References

22

1.

Estes, R. A., and Walters, P. A., "Improvement of MWD Azimuth Accuracy by use of Iterative Total Field Calibration Technique and Compensation for System Environmental Effects", SPE paper presented at the 1986 MWD Seminar, May 16.

2.

Russell, A. W., and Roesler, R. F., "Reduction of Nonmagnetic Drill Collar Length Through Magnetic Azimuth Correction Technique", paper SPE / IADC 13476 presented at the 1985 Drilling Conference, New Orleans

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Validating Sensor Response This document describes how to use the excel spreadsheet “INC MAG QC Plots” to validate the sensor response of the OM (Orientation Module) and IDS (Inclination and Direction Sensor) from a field operations prospective.

The following items (Gx, Gy, Gz, Bx, By, Bz, Temperature) calculated from the OM and IDS (with scale, bias and misalignment applied) must be scrutinized to assess the validity of the calibration and software interaction.

Enter the calculated and measured data from a 24 or 72 point roll test into the “INC MAG QC Plot” spreadsheet under the appropriate columns shown below.

Time

Gx

Gy

Gz

Bx

By

Bz

TMF - proton mag

This will generate the following information used to validate the sensor response. Gtotal

Inc xyz

Btotal

GTF

Goxy

LCAZ

Boxy

SCAZ

Inc z

Delta Az

Inc xy

Bz Calc

Gtotal – Local Gravity - is equal to (Gx2 + Gy2 + Gz2)1/2, and should be within +0.003 g of the local gravity, which is 1.000 g in most locations. A Gtotal value outside of these limits may indicate that the OM or IDS was moving during accelerometer polling, there is a hardware failure, the improper misalignment and/or scale/bias values were used or some other problem exist. Btotal – Local Magnetic Field Strength - is equal to (Bx2 + By2 + Bz2)1/2, and should be within + 350nTesla of the local magnetic field strength measured by the proton magnetometer. A Btotal value outside of these limits may indicate that the OM or IDS did not have a stable magnetic field to measure during magnetometer polling, there is magnetic interference, there is a hardware failure, the improper misalignment and/or scale/bias values were used or some other problem exist.

1

Validating Sensor Response

Goxy - is equal to (Gx2 + Gy2)1/2, which represents the cross-axial gravity value of the accelerometers and should mirror the Gz value measured by the sensor. Look for Goxy to respond appropriately with sensor position (i.e. 0.00g’s when vertical, 0.707g’s at 45 degrees inclination, 1.000g’s when horizontal and consistent during a toolface roll). A Goxy value that is inconsistent with it’s position may indicate that the OM or IDS was moving during accelerometer polling, there is a hardware failure, the improper misalignment and/or scale/bias values were used or some other problem exist.

Boxy - is equal to (Bx2 + By2)1/2, which represents the cross-axial magnetic field value of the magnetometers and should mirror the Bz value measured by the sensor. Look for Boxy to respond appropriately with sensor position versus local magnetic field position (i.e. match the proton magnetometer when perpendicular to the magnetic field, 0.0 nTesla’s when parallel to the magnetic field and consistent during a toolface roll). A Boxy value that is inconsistent with it’s position may indicate that the OM or IDS did not have a stable magnetic field to measure during magnetometer polling, there is magnetic interference, there is a hardware failure, the improper misalignment and/or scale/bias values were used or some other problem exist.

Inc z – Inclination calculated from Gz - is equal to ACOS(Gz), assuming the total gravity field is 1.000. This value should match the actual position in the stand within +- 0.1 degrees between 5 – 90 degrees. This value is compared to the Inc xy and Inc xyz. Between 5 –85 degrees Inclination all three of these values should overlay each other within +- 0.1 degrees inclination as specified on the product data sheet. An Inclination value that does not overlay and is outside of these limits may indicate that the OM or IDS was moving during accelerometer polling, there is a hardware failure, the improper misalignment and/or scale/bias values were used or some other problem exist.

Inc xy – Inclination calculated from Gx, Gy - is equal to ASIN(Goxy), assuming the total gravity field is 1.000. This value should match the actual position in the stand within +- 0.1 degrees between 0 – 85 degrees. This value is compared to the Inc z and Inc xyz. Between 5 –85 degrees Inclination all three of these values should overlay each other within +- 0.1 degrees inclination as specified on the product data sheet. An Inclination value that does not overlay and is outside of these limits may indicate that the OM or IDS was moving during accelerometer polling, there is a hardware failure, the improper misalignment and/or scale/bias values were used or some other problem exist.

Inc xyz – Inclination calculated from Gx, Gy, Gz - is equal to ATAN (Goxy / Gz). This value should match the actual position in the stand within +- 0.1 degrees. This value is compared to the Inc z and Inc xy. Between 5 –85 degrees Inclination all three of these values should overlay each other within +- 0.1 degrees inclination as specified on the product data sheet. This value is used to calculate Azimuth. An Inclination value that does not overlay and is outside of these limits may indicate that the OM or IDS was moving during accelerometer polling, there is a hardware failure, the improper misalignment and/or scale/bias values were used or some other problem exist.

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GTF – Highside or Gravity toolface -is equal to ATAN (Gy / -Gx). Above 5 degrees Inclination this values should match the actual position in the stand within +- 0.5 degrees. This value is used to calculate Azimuth.

LCAZ – Long Collar Azimuth - is equal to ATAN{ (Bx Sin (HSTF) + By Cos (HSTF))/( (Bx Cos (HSTF) - By Sin (HSTF)) Cos (Inc) + Bz Sin (Inc)). This value should match the actual position in the stand within +- 0.25 degrees. This value is compared to the SCAZ. The difference between LCAZ and SCAZ should be within +- 0.1 degrees. An Azimuth that does not match the stand position or the SCAZ calculation indicates an unstable magnetic field measure during magnetometer polling, there is magnetic interference, there is a hardware failure, movement during polling, the improper misalignment and/or scale/bias values were used or some other problem exist.

SCAZ – Short Collar Azimuth - is equal to ATAN{ (Bx Sin (HSTF) + By Cos (HSTF))/( (Bx Cos (HSTF) - By Sin (HSTF)) Cos (Inc) + BzCalc Sin (Inc)). This value should match the actual position in the stand within +- 0.25 degrees. This value is compared to the LCAZ. The difference between LCAZ and SCAZ should be within +- 0.1 degrees. An Azimuth that does not match the stand position or the LCAZ calculation indicates an unstable magnetic field measure during magnetometer polling, there is magnetic interference, there is a hardware failure, movement during polling, the improper misalignment and/or scale/bias values were used or some other problem exist.

Delta Az – is equal to LCAZ - SCAZ. The difference between LCAZ and SCAZ should be within +- 0.1 degrees. A value out of limits indicates an unstable magnetic field measure during magnetometer polling, there is magnetic interference, there is a hardware failure, the improper misalignment and/or scale/bias values were used for Bz or some other problem exist.

Bz Calc – Bz calculated from the Total Magnetic Field measured by a proton magnetometer, Bx, By - is equal to (TMF2 - Bx2 - By2 )1/2. This value is used to calculate SCAZ. Bz Calc replaces Bz measured by the sensor in the Azimuth calculation.

Gt Plot - It is useful to plot Goxy, Gz and Gtotal for each survey station to confirm the sensor is operating properly and is applying the correct scale/bias and misalignment. This plot also identifies cross-axial (rotational) and axial tool motion during a survey. The plots of Goxy and Gz should trend inversely, relative to each other and touch at 45 degrees inclination, unless a sensor operating error or motion occurs in one or both of the reference planes. For instance, if the IDS is rotated during a survey attempt, then Goxy and Gtotal will be affected and Gz will not. If the IDS is moved up and down during a survey attempt, then Gz and Gtotal will be affected and Goxy will not. A true change in inclination will be indicated by consistent changes in both Goxy and Gz, while maintaining a constant Gtotal.

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Gx, Gy, Gz - these values should be consistent with the orientation of the sensor. For example, when the sensor is in the vertical position most of the gravity vector will be acting on the Gz accelerometer, and little on the Gx and Gy accelerometers. If an accelerometer experiences a hard failure, an erroneous gravity value will be calculated by the software, resulting in a Gtotal value that is out of limits. One accelerometer failure that has been identified is "sticking", which will be evidenced by a non-changing gravity value from the suspect accelerometer as its orientation changes. A more subtle, and possibly unrecognizable failure, can occur if a sensors' calibration drifts downhole. It is possible that slight variations in calibration can occur without causing radical changes in gravity values or Gtotal.

Bt Plot - It is useful to plot Boxy, Bz and Btotal for each survey station to confirm the sensor is operating properly and is applying the correct scale/bias and misalignment. This plot also identifies cross-axial and axial magnetic interference during a survey. The plots of Boxy and Bz should trend inversely, relative to each other and touch when in the same plane as the local magnetic field and at 45 degrees relative to the magnetic dip angle, unless a sensor operating error or magnetic interference occurs in one or both of the reference planes. For instance, if the IDS measures cross-axial magnetic interference during a survey attempt, then Boxy and Btotal will be affected and Bz will not. If the IDS measures axial magnetic interference during a survey attempt, then Bz and Btotal will be affected and Boxy. A true change in azimuth will be indicated by consistent changes in both Boxy and Bz, while maintaining a constant Btotal.

Bx, By, Bz – these values should be consistent with the orientation of the sensor versus the local magnetic field. For example, when the sensor is in the parallel position with the local magnetic field will be acting on the Bz magnetometer, and little on the Bx and By magnetometers. When the sensor is in the perpendicular position to the local magnetic field will be acting on the Bx and By magnetometer, and little on the Bz magnetometers. If a magnetometer experiences a hard failure, an erroneous magnetic value will be calculated by the software, resulting in a Btotal value that is out of limits.

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Gt Plot: example of bad data Gz, Goxy gravity

Inc QC Plot

Gz Goxy Gtotal

Gtotal gravity

1.1

1.006

1

1.005

0.9

1.004

0.8

1.003

0.7

1.002

0.6

1.001

0.5

1.000

0.4

0.999

0.3

0.998

0.2

0.997

0.1

0.996

0

0.995

-0.1

0.994

Bt Plot: example of bad data Bz, Boxy nTesla

50000 45000 40000 35000 30000 25000 20000 15000 10000 5000 0 -5000 -10000 -15000 -20000

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Mag QC Plot

Bz msrd Boxy Btotal msrd TMF

Btotal nTesla

51000 50000 49000 48000 47000 46000 45000 44000

5


Inc Plot: example of bad data Inclination degrees

inc xyz

Inclination

inc xy inc z

180.00 160.00 140.00 120.00 100.00 80.00 60.00 40.00 20.00 0.00

Az Plot: example of bad data degrees

Delta Az Delta Az

3.00 2.00 1.00 0.00 -1.00 -2.00 -3.00 -4.00 -5.00

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Gt Plot: example of acceptable data Gz, Goxy gravity

Inc QC Plot

Gz Goxy Gtotal

1.10000

Gtotal gravity 1.006

1.00000

1.005

0.90000

1.004

0.80000

1.003

0.70000

1.002

0.60000

1.001

0.50000

1.000

0.40000

0.999

0.30000

0.998

0.20000

0.997

0.10000

0.996

0.00000

0.995

-0.10000

0.994

Bt Plot: example of acceptable data Bz, Boxy nTesla

70000 65000 60000 55000 50000 45000 40000 35000 30000 25000 20000 15000 10000 5000 0

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Mag QC Plot

Bz msrd Boxy Btotal msrd TMF

Btotal nTesla

60000 59000 58000 57000 56000 55000 54000 53000

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Inc Plot: example of acceptable data Inclination degrees

inc xyz

Inclination

inc xy inc z

60.00 55.00 50.00 45.00 40.00 35.00 30.00 25.00 20.00 15.00 10.00 5.00 0.00

Az Plot: example of acceptable data degrees

Delta Az Delta Az

1.00 0.00 -1.00 -2.00 -3.00 -4.00 -5.00

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GAMMA RAY SENSOR THEORY, APPLICATION, & INTERPRETATION

Shale Gas Oil Salt Water Shale

Salt

1

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, Thorium232, 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 (GeigerMueller tubes)

2

Isotopes •

•

•

Atoms with the same number of protons but different numbers of neutrons are called isotopes of the same element The number beside each isotope is the sum of the protons and neutrons in its’ nucleus and is called the atomic weight The three most common gamma emitting isotopes found in the earth’s crust are Potassium-40, Thorium-232, & Uranium-238

3

Thorium-232 Decay Sequence

4

Gamma Ray Interactions •

Photoelectric Effect: In this interaction the energy of the x-ray or gamma-ray is completely transferred to an atomic electron which is ejected from its atom. The x-ray or gamma-ray no longer exists after the collision.

•

Compton Effect: The x-ray or gamma-ray loses only part of its energy in its interaction with an atomic electron. The electron is ejected from its atom. The x-ray or gamma-ray of reduced energy and the electron fly off in different directions

•

Pair Production: Gamma-rays with an energy greater than about 1.2 MeV may interact with an atomic nucleus to form an electron positron pair. The gamma-ray energy is completely converted into the mass and kinetic energy of the electron and positron with only a very small amount going to the nucleus in order to conserve momentum.

5

Gamma Ray Shielding • Gamma ray energy is attenuated (reduced) most effectively by collisions with dense materials • For example, lead is a more effective gamma shield than the human body

6

Gamma Ray Sensor Theory • •

•

• •

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 in permeable 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

7

Geiger-Mueller Tube •

•

• •

Consists of a gas-filled (99% Neon, 1% Bromine) tube containing electrodes, between which there is a 1000 volt potential When gamma radiation passes through the tube electrons are knocked from the tube inner lining. They collide with the Neon atoms creating an electron “avalanche” which causes a drop in voltage on the inner electrode Bromine is used as a “quenching gas” to stop the reaction Each voltage cycle is registered as a count

+1000 v

+1000 v

1 count

8

Advantages of GM Tubes • • • •

Sturdy construction (no glass or flimsy components) Low current consumption (less than 1 mA) Can withstand high shock and vibration Temperature rated up to 200 °C (must be used in high temperature tool design)

9

Disadvantages of GM Tubes • Very inefficient counter (less than 5% of all gamma rays are counted by the tube) • Low efficiency means multiple tubes must be utilized to yield accurate data • Using multiple tubes increases the length of the sensor, decreases its vertical resolution, and increases costs • Cannot be used to perform “spectral analysis”

10

Gamma Ray Sensor Theory • 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

11

Scintillation Detectors •

•

• •

Consists of a Sodium Iodide (NaI) crystal, photomultiplier, and amplification circuitry When gamma radiation passes through the crystal structure it deposits energy within the crystal This energy is released in the form of “visible” light The intensity of the light flash is directly proportional to the energy deposited in the crystal

12

Gamma Module Measurement Circuit

• • • •

Scintillator crystal captures energy and produces a light flash PMT collects light and converts it into an electrical signal High Voltage provides power to circuit Pre-Amplifier and Amplifier boost electrical signal and provide A/D conversion

13

Advantages of Scintillation Detectors • Very efficient counter (greater than 50%) • High efficiency means a single detector can be used, reducing module length and cost • Smaller detector length improves vertical resolution • Can be used to perform “spectral analysis”. (Unfortunately the Gamma module’s downhole software does not support this function; LWD spectral gamma in development)

14

Disadvantages of Scintillators • Not as shock and vibration resistant as GM tubes • Cannot withstand temperatures greater than 165 °C • Require considerably more power than GM tubes

15

Gamma Ray Sensor Theory •

•

•

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

16

Gamma Ray Sensor Applications • • • • •

Lithology Identification Formation Thickness Stratigraphic Correlation Geosteering Shale Volume Estimation

17

Gamma Ray Sensor Applications • Lithology Identification • Shale versus “non-shale” indicator • Low gamma response can indicate potential reservoir rock

• Formation 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

18

Gamma Ray Sensor Applications • 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

19

Gamma Ray Sensor Applications • Geosteering • The intentional directional control of a well based on the results of downhole geological logging measurements rather than threedimensional 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

20

Gamma Ray Sensor Applications

Clean Line (25 api)

Shale Baseline (75 api)

• 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 GRsh – GRclean VSH (%) = 50 – 25 75 – 25

Zone of Interest (50 api)

X 100

X 100

VSH (%) = 50%

21

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 Gas Sandstone

Oil Salt H2O

Shale

22

Gamma Ray Data Interpretation


• 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

Halite

23

Gamma Ray Data Interpretation • 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

24

Gamma Ray Data Interpretation •

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

25

Factors Affecting Gamma Log Quality • • • • • •

Calibration Depth of Investigation Vertical Resolution Sample Period vs. Logging Speed Collar Attenuation Borehole Conditions

26

Calibration • Removes “bias” from the detector response • Compensates for collar attenuation • All gamma sensors should read the same API (or AAPI) value under the same conditions

27

What is an “API”? •

The standard unit for gamma ray measurement is the “API” and is defined as 1/200 of the log deflection when the tool is between the two lower concrete zones of low and high radiation in the pit

•

The radioactive concrete (center section) is composed of 12 ppm uranium, 24 ppm thorium, and 4% potassium and has approximately twice the radioactivity of an average shale

•

“Apparent” API units must be used if the module cannot be run in the API test pit

28

Depth of Investigation • • • •

The maximum radial distance from which the detectors can measure gamma counts Dependent upon the travel distance of a gamma ray Typically, 50% of the measured gamma rays come from a radius of 4” (10 cm) The stated depth of investigation of the gamma module is 9 - 12” (23 - 30 cm)

29

Vertical Resolution • •

•

Shale

detector

•

The thinnest vertical bed that the sensor can fully resolve “Resolve” is defined as being able to determine the actual value of the formation Typically based upon 3 times the length of the detector Gamma module vertical resolution is stated to be 12” (31 cm)

4”

Shale

30

Effect of Detector Length on Gamma Response

• The smaller the detector length the thinner the bed that can be “resolved” • As the logging speed increases, the actual gamma value provided by the sensor becomes much less accurate

31

Sample Period vs. Logging Speed •

•

•

If logging speed is too fast for the sample period (time constant), the depth correlation of the data will be incorrect If drilling rate is too slow for the sample rate, the data will be statistically “noisy” “Noisy” data can be smoothed, whereas low accuracy data cannot be improved

32

Sample Period vs. Logging Speed • Notice how much better the bed definition and depth correlation is for the curve on the left (720 ft/hr) versus the curve on the right (2700 ft/hr)

33

Collar Attenuation • Drill collar reduces the gamma ray intensity by a factor of 5 to 10 depending on the collar thickness • This loss of count rate can directly affect gamma ray accuracy and indirectly affect bed resolution • Gamma factors compensate for collar attenuation and detector bias

34

Borehole & Formation Effects • The environment between the formation and the detector will have a major effect on the count rates seen by the module • • • •

Formation Density Mud Weight (barite, cuttings load) Mud Additives (KCl) Hole Size (washout, collar-to-bit ratio)

35

Formation Density • The higher the formation density, the higher the attenuation of the gamma rays will be as they travel through the matrix • Matrix Densities: • • • •

Sandstone = 2.65 g/cc Limestone = 2.71 g/cc Dolomite = 2.87 g/cc Average Shale = 2.5 g/cc

36

Mud Weight • • • •

Barite is used to increase mud weight Barite density is 5.5 g/cc Barite acts as a “shield” The higher the mud weight (i.e., the thicker the shield) the higher the attenuation of formation gamma rays

37

Mud Additives • The addition of certain salts and chemicals to the mud system will affect the gamma ray sensor response • For example, adding Potassium Chloride (KCl) salt to the mud will cause an increase in gamma counts

38

Hole Size Changes (Washout) • If the annular flow rate exceeds critical velocity the washout effect greatly increases due to the turbulent nature of the fluid • Washout effectively moves the formation further away from the detectors, reducing the overall count rate relative to a gauge hole

39

Hole Size Changes (Shale Hydration)

• Swelling of shales high in montmorillonite clay moves the formation closer to the detectors, increasing the overall count rate relative to a gauge hole • Oil-based mud and certain chemicals added to the mud can inhibit shale hydration

40

Gamma Ray Accuracy • One-foot bed resolution is the minimal acceptable criteria • Sample Period & Drilling Rate are the key factors controlling accuracy

41


Gamma Ray Sensor Theory What Are Gamma Rays? Gamma rays are a form of high energy electromagnetic (EM) radiation. Other examples of EM radiation are visible light, radio and microwaves, infrared and ultraviolet light, and x-rays. Each of these forms is distinguished in the EM spectrum by their frequency (f) and wavelength (λ). In free space (that is, a vacuum) all EM waves travel at the speed of light, c, which is 3 × 108 meters/second, or 186,000 miles/second 1. The frequency and wavelength are related to the speed by the equation

c =λf While the characterization of EM energy by frequency and wavelength implies wavelike behavior, it is a reality of the microscopic (i.e., quantum mechanical) world that waves of short enough wavelength exhibit particle-like behavior. Such “particles” of light are designated “photons”. This particle-like behavior is important in the physics of gammagamma logging devices. Whether or not it is appropriate to treat EM radiation of a particular frequency as a particle is a function of the wavelength of the radiation and how it compares with atomic dimensions. Visible light, which has wavelengths that are a factor of about 107 greater than atomic dimensions, and the even longer wavelength radio waves, are almost always analyzed as waves. But x-rays and gamma rays, which are at the short end of the spectrum of wavelengths, are most often thought of as particles rather than waves. Photons have no mass as do the electron and proton, but they do have energy and momentum. These are dependent on their frequency (or wavelength, since given a knowledge of the speed of light, one can be computed from the other) 2. It is important to realize that a gamma ray’s energy is proportional to its frequency. Thus, as its energy decreases, its speed, c, remains the same (it does not “slow down”); rather, its frequency decreases. Although we speak of gamma rays as particles, they have no mass (in contrast to electrons, protons, and neutrons, which each have their own characteristic mass). However, a fundamental interaction of electrons with gamma rays, that of Compton scattering, is adequately understood by analyzing the interaction as one would a billiard ball type collision between two particles. Finally, we note that the electron volt (eV) is the unit used to characterize the energy of gamma rays and most other entities in the atomic and nuclear world. The electron volt is the amount of energy gained by an electron when it is accelerated through an electrical potential difference of one volt. It is equal to 1.6 × 10-19 joules of energy (or 4.4 × 10-26 Kilowatt-hours). For comparison, the energy required to ionize a hydrogen atom (separate it into a free proton and electron) is 13.6 eV, and the energy of the gamma rays emitted by the Cs137 logging source is 662 KeV (that is, 662 × 103 eV). 1. The letter “c”, which often designates the speed of light mathematically, is chosen thanks to the word “celerity”, which denotes rapidity of motion or action. 2. The kinetic energy, or energy associated with the motion of a particle, is given by the formula (1/2)mv2, where m and v are mass and velocity respectively. Likewise, the momentum of a particle is the product of its mass and velocity. However, this only applies to particles which have mass. Photons have no mass. The energy of a photon is given by the equation E=hf, where f is the frequency in Hertz, or cycles per second, h is Planck’s constant, which is 4.14 × 10-15 eV-s, and E is energy in electron volts (eV). The momentum of a photon is p=h/λ=hf/c.

1

Gamma Ray Sensor Theory

The Gamma Sensor Measurement Gamma sensors measure naturally occurring radiation rather than induced gamma rays from a source. These natural gamma rays emanate from radioactive elements contained in sedimentary formations, mainly potassium (K), thorium (Th), and uranium (U). Potassium and thorium are closely associated with the presence of clay minerals in shale (illite, kaolinite, and montmorillonite), while uranium may be found in sands, shale, and certain carbonates. The gamma sensors provide an excellent indicator of the presence of shale.

Gamma Ray Emission Spectra of Potassium, Thorium & Uranium The radiation from potassium is distinct, with a single energy value of 1.46 MeV. Both thorium and uranium emit radiation with a range of energies, but with certain peak frequencies. These peaks are especially distinct at energy levels of 2.62 MeV for thorium and 1.7 MeV for uranium. Emission spectra for potassium, thorium, and uranium are shown in the figure below.

Figure 1 - Gamma Ray Emission Spectra

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Gamma Ray Sensor Theory A gamma sensor counts the gamma rays emitted by the formation. The relationship between counts and gamma ray energy from potassium, thorium, and uranium is shown in the figure below.

Figure 2 - Complex Spectrum Observed from a Radioactive Source Containing K, Th, and U

Gamma Scattering and Interactions with Matter There are three mechanisms by which gamma rays may interact with matter: Pair Production, Compton Scattering, and the Photoelectric Effect. Which of these effects occur, and their relative probability of occurrence, is governed by the energy available in the photon and by the physics involved in the interaction of the photon and its environment.

Pair Production In the case of pair production, the gamma ray is converted into an electron/positron pair. In order for this to occur, the photon must have an energy above threshold of 1.02 MeV, which is simply the sum of the rest mass energies of the electron/positron pair, as determined by Einstein’s formula, E=mc2. If the photon energy is less than 1.02 MeV, pair production is prohibited since the energy required to produce the two particles is unavailable. The most common source of gamma rays used in well logging is radioactive cesium, which emits gamma rays with energies of 662 KeV. Since this energy is less than 1.02 MeV, pair production is excluded as a possibility and will be considered no further here.

Compton Scattering Compton scattering refers to the particle-like interaction between a gamma ray and a free electron. The outcome of scattering between a gamma ray and an electron is governed by the laws of conservation of energy and momentum. Basically, these laws establish limits on the possible outcomes of the interaction. The best analogy to Compton scattering is that of a collision between two billiard balls. In such a collision, a ball moving at some velocity collides with a second ball that can be considered without loss of generality to be initially at rest. In the collision, the first ball transfers some of its energy and momentum to the second ball. After the collision, the balls leave the collision site with values of momentum and energy that are constrained by the physical laws – those of conservation of energy and conservation of momentum.

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Gamma Ray Sensor Theory For energy to be conserved, the total kinetic energy of the two balls after the collision cannot be greater than the total kinetic energy of the balls before the collision. If the second ball is at rest before the collision, as we have said, then the total kinetic energy before the collision is simply that which the first ball had before the collision. To conserve momentum, the vector sum of the momentum of the balls following the collision must be the same as the vector sum of the momentum of the balls preceding the collision.

Figure 3 - Representation of a Scattering Event by Billiard Balls

In the interaction between a gamma ray and an electron, the gamma ray is the incoming particle with both energy and momentum. In the collision, some energy and momentum are transferred to the electron from the gamma ray. The Compton interaction is perfectly “elastic”, in that all of the energy lost by the gamma ray appears as kinetic energy gained by the electron. This is different from the billiard ball case in that the sum of the kinetic energies of the balls after the collision is always slightly less than the kinetic energy of the cue ball before the collision because some energy is transformed into heat and sound during the collision. The billiard ball collision is always an “inelastic” collision. The directions of travel of the electron and gamma ray after the collision are such that their combined momentum after the collision is the same as before the collision. The specific case of head-on collisions is of particular interest in both billiards and Compton scattering. For such a collision the maximum amount of energy is transferred when two billiard balls collide head-on, the energy and momentum of the first ball is completely transferred to the second, with the result that the first stops completely at the interaction site and the second continues on with the velocity and energy that the first ball had before the collision. The laws of physics allow this complete transfer of energy and momentum to occur only in head-on collisions between balls -- or particles -- of equal mass. For Compton scattering, however, the gamma ray has no mass; as a consequence, it is impossible for it to completely transfer its energy to the electron. So a head-on collision

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Gamma Ray Sensor Theory between a gamma ray and electron may occur, but the maximum amount of energy that can be transferred from the gamma ray to the electron in the Compton interaction will always be less than the total energy of the gamma ray, and the gamma ray will always still exist after a Compton scattering event.

Photoelectric Effect While gamma rays always emerge from the Compton interaction, albeit with a reduced energy, they do completely disappear as a result of the third form of gamma ray interaction with matter, the photoelectric interaction, or photoelectric effect. In this case, a gamma ray encounters an electron bound in an atom and the energy of the gamma ray is completely absorbed by the electron - atom system. The energy of the gamma ray is distributed between the electron, which is completely ejected from the atom as a result of the interaction, and the remainder of the atom (now a positive ion after the ejection of the electron). The reason the gamma ray can completely disappear in this case, and not in the case of the Compton interaction, is the fact that after the interaction there are two particles -- the electron and the positive ion -- which in combination can always allow momentum to be conserved in the interaction.

The Life History of a Gamma Ray It is now useful to discuss the “life history” of a gamma ray in matter. We imagine the simple situation of a source of gamma rays imbedded in a homogenous formation. When a gamma ray is emitted from an atom, it travels in a straight line until it interacts with an electron. Since the speed of all gamma rays is the same (3.0 × 108 meters/second), the distance the gamma ray travels before its collision will depend just on the density of electrons. As indicated above, for the chemicals in that part of the earth typically measured by logging tools, the first interaction will most likely be Compton scattering. This is represented by point A, where such an event is schematically depicted. At point A, an electron acquires some of the energy of the gamma ray, and the gamma ray itself recoils in another direction with its energy reduced by the amount given to the electron. Eventually the gamma ray encounters another electron (point B) and a second interaction occurs, with the result that yet more energy is lost by the gamma ray, which undergoes another change in its direction of travel. This may occur several times in succession, with the energy decreasing further with each interaction. The amount of energy lost at each interaction point (A, B, C, and D) and the deviation in the direction of travel of the gamma ray is random with each occurrence. With each interaction and associated reduction of gamma ray energy, the probability of a photoelectric event in the next interaction increases. When the photoelectric event finally occurs (point E), all of the remaining energy of the gamma ray is transferred to the electron and its associated atom, and the gamma ray ceases to exist. For each successive gamma ray, the distances between interactions and the outcome of each are random. On the average however, the distance between interactions decreases for each successive interaction and this average will be a function of the electron density of the material

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Figure 4 - Life History of a Gamma Ray

It may be useful at this point to imagine a cloud of gamma rays in the vicinity of the source. Near the source, the cloud has its highest density. The gamma rays have their highest energies near the source and are moving primarily in a direction radially away from it in this region. As the distance from the source increases, gamma rays are likely to have scattered at least once, with the result that the average energy of the gamma rays in the cloud is decreased. With greater distances from the source, the probability of additional scatterings is larger and the average energy of the gamma rays in the cloud is even lower. The density of gamma rays in the cloud decreases with increasing distance from the source. This is true for two reasons: first, simple geometrical spreading occurs; second, the decreased energy of the gamma rays with increasing distance renders their disappearance due to the photoelectric effect progressively more likely. At sufficiently great distances from the source, the gamma rays will all have been reduced in energy through multiple scatterings to be removed altogether through the photoelectric interaction.

Figure 5 - Gamma Ray Density as a Function of Distance from Source

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Gamma Ray Spectral Analysis The gamma ray spectrum, otherwise known as a pulse height spectrum or pulse height distribution, is a method to analyze the energy information obtained from a scintillation detector. It consists of obtaining the distribution of gamma rays detected according to pulse height or energy. There are several steps in the process of producing such a spectrum. First, the electronic pulses from the PMT are digitized according to pulse amplitude. That is each pulse is assigned a number, the magnitude of which is proportional to the pulse height (in volts) of the gamma ray. Since the pulse height is proportional to the energy that the gamma ray deposited in the scintillator, it follows that this number is then proportional to that energy as well. In the production of a spectrum the energy range of the gamma rays is divided into discrete intervals, or channels. Each of these channels is assigned a memory location in the computer, which serves as a scalar, or counter, of detected gamma rays whose energies fall in its range. The pulse height spectrum is a display of the number of counts per channel versus the channel number, or versus the energy corresponding to each channel.

Figure 6 - Illustration of Voltage Pulse Conversion into a Pulse Height Distribution

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Gamma Ray Sensor Hardware Gamma Ray Detection with GMT’s and Scintillators In order to count gamma rays, one must detect them. Detection is universally accomplished through exploiting the fact that the interaction of the gamma rays with matter produces electron-ion pairs. Two types of gamma ray detectors are commonly used in MWD/LWD sensors: Geiger-Mueller (G-M) tubes and NaI Scintillators (a scintillator is a material that converts energy into light).

Geiger-Mueller Tubes The G-M tube has a crude detection capability. The tube consists of a metal cylinder, which functions electrically as a cathode and a single anode wire down its center. The tube contains inert gases (e.g., bromine, neon) in which ionization takes place. A high voltage (usually >1000 volts) is placed between the wire and the cylinder, with the wire functioning as the (positive) anode. Operationally, a gamma ray is detected when it interacts with an electron in the wall of the tube (either through Compton scattering or the photoelectric effect) causing the electron to be ejected into the gas of the tube. Interactions in the gas are much less likely than in the wall because of the much lower density of the gas. Once the negatively charged electron is in the gas it is attracted to the positive anode wire. As it approaches the wire, it gains energy from the electric field, and collides with atoms of gas in the tube causing further ionization in the tube gas. The free electrons created in these collisions are also attracted to the anode, and as they gain energy, they ionize more atoms themselves. A multiplicative effect ensues, which eventually results in a momentary electrical breakdown of the tube. This is observed as a voltage pulse across the cathode and anode of the tube, and may be counted electronically. The G-M tube is a simple, rugged device. However, one of its disadvantages is its low counting efficiency. The most likely place for an interaction causing a breakdown is in the small volume constituting the inner surface of the tube. The gas itself is of low enough density that ionizing events are seldom initiated in it. Another disadvantage is the fact that the G-M tube gives no information about the energy of the gamma ray it detected. Low and high energy gamma rays will produce pulses that are, for all practical purposes, indistinguishable.

Scintillation Detectors Detection of gamma rays using Scintillators represents a significant improvement over both the efficiency and spectral deficiencies of G-M tubes. The most common scintillation detector, and the one used in MLW/LWD sensors, is the sodium iodide (NaI) crystal. Again, the detection occurs as the gamma ray interacts with the electrons in the NaI crystal, either through Compton scattering or the photoelectric event. However, the effective volume of the detector is that of the crystal (to be compared with the small volume defined by the inner surface of the G-M tube). That is, an interaction occurring anywhere in the crystal will be detected. This means that an NaI crystal will be as effective at detecting gamma rays as a G-M tube(s) occupying many times the NaI volume.

8

Gamma Ray Sensor Theory A second desirable feature of the NaI detector is its energy, or spectral, sensitivity. Spectral sensitivity follows from the way detection is actually accomplished. When a gamma ray interacts with an electron in the NaI crystal through Compton or photoelectric mechanisms, all (photoelectric interaction) or part (Compton) of the gamma energy will be imparted to the electron. In its turn the electron interacts with atoms in the NaI crystal, and it is a property of the crystal that a repeatable fraction of the energy of the electron is converted to light within the crystal. Hence the term “scintillation detection”. The amount, or intensity, or brightness of the light pulse is proportional to the energy of the electron. The light that is produced by even the highest energy gamma ray is still much too dim to be seen with the unaided eye; however, it may be detected by converting it to an electronic signal and amplifying that signal using a photomultiplier tube (PMT). Such a tube is connected optically to the crystal, and light entering the tube from the crystal is converted to an electrical pulse. The electrical pulse amplitude is proportional to the brightness of the light pulse and, therefore, proportional to the energy of the electron in turn. Thus, the NaI crystal/PMT combination constitutes a detector capable of measuring the energy given to the electron by the gamma ray. Note again that the energy obtained by the electron as a result of Compton scattering is not that of the gamma ray but some lesser amount. However, if the scintillation crystal is large enough, it is possible that successive multiple scatterings of an individual gamma ray can occur within the crystal until all of the gamma energy is converted to light. Since the gamma ray travels with the speed of light, such multiple events are all simultaneous within the resolution of the electronics. Thus, the energies of the electrons created by all the interactions all add together to produce an optical pulse, and in its turn an electronic pulse that is proportional to the energy of the fully absorbed gamma ray. In this case then, a relationship may be drawn between electronic pulse amplitude and gamma ray energy.

Environmental Effects on the Gamma Ray Measurement Washout The Gamma Ray log is relatively unaffected by small borehole irregularities, but is greatly affected by large washouts. This is due to the increase in drilling fluid between the formation and the detector which causes increased Compton scattering and a decrease in the gamma ray log value. As the hole gets larger relative to the tool size, fewer gamma counts are detected. Turbulent flow of mud occurs when annular velocity exceeds critical velocity. Turbulent mud flow causes a washout to occur more quickly than under laminar flow conditions.

Mud Weight Gamma ray energy is attenuated by dense material. Barite is a highly efficient absorber of gamma ray energy (about 5.5 g/cc). Since barite is a weighting material, gamma ray response decreases as mud weight increases.

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Gamma Ray Sensor Theory Borehole Effects On the other hand, the opposite effect is caused by the use of radioactive drilling fluid additives, such as KCl. The Gamma Ray sensor detects radioactivity in the potassium and results in an increase in absolute values, particularly in the area of a washout. Introduction of KCl into the mud system causes a positive baseline shift, as shown in the figure below.

Figure 7 - Effects of KCl drilling fluid on log

Gamma Ray Sensor Response Shale (Clays) Shale is a mixture of clay minerals and silt laid down in a very low energy depositional environment. Solids in typical shale may consist of about 50% clay (mostly potassium and thorium), 25% silica, 10% feldspar, 10% carbonate, and 2% organic matter. Organic matter gives shale its’ dark color and is the main ingredient that allows shale to be a hydrocarbon source rock. Since the depositional environment for shale is fairly consistent, the response from the sensor should be fairly uniform through short intervals, revealing a shale baseline which can be used to distinguish them from reservoir zones.

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Reservoir Rocks Reservoir rocks are generally sandstone (SiO2), limestone (CaO3), or dolomite (CaMgCO2). In “clean”, clay-free reservoirs the gamma ray response will be fairly low, but not zero, due to the presence of some radioactive impurities. However, if clay is present in a reservoir rock, the gamma ray response will be somewhere between the clean zone and a shale response.

Salt Halite is crystalline NaCl, with no radioactive impurities. The gamma response will be very close to zero. Note: Coal, anhydrite, and gypsum appear similar to salt on a log.

Hot Streaks High radiation zones, or hot streaks, are usually thin layers due to depositional conditions of the time period associated with volcanic activity. These streaks typically have a much higher gamma response than the shale baseline

Uranium Uranium is soluble in water and can migrate into permeable beds. This can mask the response of a reservoir rock if uranium is present

Overpressured Zones In an overpressured zone, excess bound water replaces matrix thereby reducing the overall gamma response. This trend is very slight and not very noticeable over a short interval on the Gamma curve.

Analysis & Interpretation of Gamma Ray Logs Add in examples as they are obtained

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Factors Affecting Gamma Log Quality Depth of Investigation Generally speaking, the gamma ray sensor measures naturally occurring radiation from within 30 cm (both horizontally and vertically) of the sensor detector. The relationship between the percent of contribution to the radiation signal measured by the detector and the distance from the borehole wall is shown in the figure below.

Figure 8 – Gamma Ray sensor depth of investigation

Hole Size vs. Tool Size As the distance between the sensor and the hole decreases, gamma counts increase, and vice versa. This can occur as a result of a change in tool size during a BHA change with the same hole size.

Rotation vs. Sliding During a slide in a directional hole, the detector bank may coincidentally be closer to the formation. The phenomenon may reverse or be eliminated during the next slide depending upon the position of the sensor.

Calibration Factors Inaccurate correction factors used for processing data can appear on as log as a shift in the gamma ray curve.

Logging Speed and Sampling Interval There are restrictions on logging speeds when using the Gamma Ray sensor because gamma rays are counted over a fixed time period, called the sampling interval. Practically speaking, the gamma ray sensor should not travel more than 30 cm during the sampling interval. The goals in any type of nuclear logging are mutually exclusive. That is, we know that the longest sampling interval possible is best for precise statistics, but that the shortest sampling interval provides for the maximum log data density.

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Gamma Ray Sensor Theory Important: Data density and vertical resolution are frequently confused. Vertical resolution is defined by the sensor design, not be data rate. Effective resolution can be decreased, however, for any sensor if the sample rate is insufficient. In order to resolve these two requirements, we must develop guidelines based on minimum acceptable precision and minimum acceptable data density, and then choose the appropriate sampling intervals and data densities to meet these minimum requirements. Gamma sensors count gamma rays during the entire sampling period. This means that the distance the drill pipe moves during the sampling interval is significant. Although we plot only one point at the end of the sampling interval, this value represents an average of the formation encountered during the entire sampling interval. Nuclear sensors will provide a legitimate average of the formations traversed, and will merely tend to smear the beds rather than miss them entirely. However, as we increase the sampling interval in an attempt to increase data density, we know that the precision of the measurement decreases. The statistical error in a 16 second measurement will be exactly twice the error at 64 seconds. At 4 seconds, the error will be double the 16 second error, and so on. There is a point (different for each sensor) where the error (noise) becomes very large compared with the measurement itself, and it at this point that the data becomes essentially meaningless. Important: Any time there is a question about sample rates, it is better to be in error on the side of choosing a faster sampling rate. In the event the statistics are poor, we can always average multiple measurements and achieve the same statistical precision as would have been achieved with the longer sampling interval. Going in the reverse direction is impossible. There is no way to improve the effective resolution of a log made with long sampling intervals.

Effects of Statistics on Log Quality A full understanding of the effects of nuclear statistics on log quality is imperative for individuals working with such logs. Accuracy and precision are not interchangeable terms. Accuracy is the extent to which a measuring device is capable of determining the true value of the parameter being measured. Precision is the extent to which a single measurement of the device may differ from the true value of the parameter. This is significant because a very precise measurement will have very little variation from one measurement to the next, but may or may not be accurate. An accurate device may yield individual measurements that differ greatly from the true value, but the average of multiple measurements will be equal to the true value. Since gamma sensors rely on measurements of the rate at which nuclear particles enter a detector, they are, by definition, statistical in nature. All purely statistical measurements can be assessed for accuracy only through probability theory. This means that unless there is some non-statistical method for measuring the parameter of interest, one can never measure the absolute accuracy of the parameter. The only way to measure gamma values in any zone is to make repeat measurements with a sensor of known precision, and average them to determine the true value.

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Gamma Ray Sensor Theory When designing a gamma ray sensor, trade-offs between precision, accuracy, and sampling interval must be considered. Accuracy of gamma ray sensors is adjusted through appropriate calibration procedures. Precision, however, is a function of the detector efficiency. In nuclear statistics, the number of counts per second detected is generally directly related to the measurement precision. Thus, a sensor with 90 percent efficiency is likely to have better precision than a sensor with 10 percent efficiency, since an error of 10 counts in 100 is much greater than an error of 10 counts in 1000.

Gamma Ray Applications Gamma ray applications include: • Determining shale volume - By using the relative response of the gamma curve compared with a 100% shale reading, the shale volume (Vsh) in the formation can be estimated from the following equation:

To calculate the shale volume (Vsh) of any zone, determine the denominator of the equation by subtracting the clean sand reading (GRclean) from the shale baseline reading (GRsh). Then, determine the numerator of the equation by subtracting the reading in the zone of interest (GRzone) from the shale baseline (GRsh). Calculate the shale volume (Vsh) by dividing the numerator by the denominator. • Well offset correlation - The gamma ray sensor provides excellent correlation in field appraisal and development drilling, particularly if initially used on exploratory and delineation wells for development well correlation. In many fields, the gamma ray sensor alone is suitable for real-time casing and core point selection. • Safety - The gamma ray sensor will accurately chart bed stratification. In combination with the resistivity sensor, the gamma ray sensor enables pore pressure prediction, leading to faster, safer exploratory drilling and operations in difficult fields. • Log of record – In combination with the resistivity sensor, the gamma ray sensor will provide intermediate logs of definitive quality for archive uses while providing information to improve drilling operational efficiency. • Enhanced interpretation of wireline logs - Higher data sampling rates (recorded logs) give greater definition and more exact bed delineation, which aids in identifying the smoothing/averaging effects of high wireline traverse speeds. Because at typical drilling rates the gamma ray sensor passes formations slower than typical wireline gamma ray sensors, the resulting logs have higher definition and less statistical uncertainty. • Directional control - The gamma ray sensor allows for improved trajectory monitoring. By removing one bank of detectors and replaying them with shielding, azimuthal readings may be taken. In its azimuthal configuration, the gamma ray may be used not only to differentiate between shale and reservoir rock, but to also determine whether the wellbore has exited out of the top or bottom of the reservoir.

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LWD SENSOR THEORY, APPLICATION, & INTERPRETATION Resistivity


Salt

1

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

2

Resistivity Sensor Theory • 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

3

Resistivity Sensor Theory

•

• •

Resistivity

Conductivity

Phase Shift

Attenuation

High

Low

Small

Low

Low

High

Large

High

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 resistivity mud) 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

4

Resistivity Sensor Theory • 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 DOI

5


Phase Shift (°)

100

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

10 1 0.1 0.01 0.1

1

10

100

1000

Resistivity (ohm-m)

6


Attenuation (-dB)

10

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

1 0.1 0.01 0.001 0.1

1

10

100

1000

Resistivity (ohm-m)

7

Resistivity Sensor Theory • 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

8

Resistivity Sensor Theory • 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

9

Resistivity Sensor Theory • 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

10

Resistivity Sensor Theory •

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

11

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

12

Resistivity Sensor Applications • 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

Increasing Resistivity

Shale Baseline

13

Resistivity Sensor Applications • 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

14

Resistivity Sensor Applications • 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

15

Resistivity Sensor Applications • 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

16

Resistivity Sensor Applications • Casing Point Selection

Set casing here…

• Resistivity data can be used to determine acceptable casing points • Casing is set in nonpermeable formations like shale • Trying to set casing in a permeable sandstone may cause the formation to fracture or even collapse the casing … or here

17

Resistivity Sensor Applications • 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

18

Resistivity Sensor Applications • 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”

19

Resistivity Sensor Applications •Geosteering •Objective: Keep wellbore in oil zone (avoid shale, gas, and water)

SHALE

•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

GAS SAND

OIL SAND

WATER SAND

20

Resistivity Sensor Applications The deeper the depth of investigation of the resistivity sensor allows ample anticipation time to prevent drilling into the water leg Water Oil Water Saturation

Neutron Porosity

EWR® Resistivity (Ohm-m) 200

Water Saturation CNφ® SW Neutron Porosity 42 (LS pu) -18 1 % 0

•

DGR™ Gamma Ray (AAPI) 100 ROP 500 (ft/hr) 0 2

Resistivity

Rate of Penetration

Well Path

0

Gamma Ray

X00 TVD (FT)

Zone A

X50

Zone B

X000

Measured Depth (Ft)

Well Path

X500

21

Resistivity Sensor Data Interpretation • General Resistivity Response Shale Gas Oil Salt Water Shale

• 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)

Salt

22

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

23

Resistivity Sensor Data Interpretation • Zone #1 Evidence • Resistivity decreases, indicating either a decrease in the resistivity of the pore fluids or an increase in porosity • Bulk density decreases and the neutron porosity increases, both indicating an increase in porosity • Gamma ray moves from the shale baseline towards a less shaley formation • Qualitative interpretation of this zone based on these curves is a porous, wet zone

Gamma

Resistivity

Neu / Den

Zone #1

24

Resistivity Sensor Data Interpretation • Zone #2 Evidence • Resistivity increases, indicating either an increase in the resistivity of the pore fluids or a decrease in porosity • Bulk density increases and the neutron porosity decreases, both indicating a decrease in porosity • Gamma ray moves from the shale baseline towards a less shaley formation • Qualitative interpretation of this zone based on these curves is a low porosity (tight) zone

Gamma

Resistivity

Neu / Den

Zone #2

25

Resistivity Sensor Data Interpretation • Zone #3 Evidence •

•

• •

Resistivity increases, indicating either an increase in the resistivity of the pore fluids or a decrease in porosity Bulk density decreases indicating an increase in porosity; however, the neutron porosity is showing a decrease in porosity (the two curves crossover each other) Gamma ray moves from the shale baseline towards a less shaley formation Qualitative interpretation of this zone based on these curves is a porous, gas zone

Gamma

Resistivity

Neu / Den

Zone #3

26

Resistivity Theory and Application Physical Principles The Resistivity sensor responds to the way in which RF electromagnetic waves propagate through the formation. The propagation of an RF wave is controlled by the following physical properties of the material through which the wave is propagating: • Electrical conductivity (σ), which is the ability of a material to conduct an electrical current. • Dielectric permittivity (ε), which is the ability of a material to store an electrical charge. • Magnetic permeability (µ), which is the ability of a material to become magnetized. At frequencies below about 10 MHz, the formation conductivity is the dominant factor affecting RF wave propagation. Thus, by making reasonable assumptions for the dielectric permittivity and magnetic permeability values, measured wave propagation parameters (phase shift and attenuation) can be related to the formation conductivity or Resistivity.

Resistivity Frequencies 4KHz and 2 MHz The Resistivity tool operates at frequencies of 2 MHz (shallow, and medium spacing measurements) and 400 KHz (deep spacing measurement). 400 KHz is in the medium wave or AM radio band, and 2 MHz lies between the AM and FM radio wave frequency bands. The choice of this frequency range is dictated by two physical phenomena. First, at frequencies above about 10 MHz, the dielectric permittivity dominates the wave propagation, and the measured phase shift and attenuation values are more dependent on the formation’s dielectric permittivity than on its conductivity or Resistivity. Secondly, at frequencies below about 0.1 MHz, electrical eddy currents are induced in the steel drill collar. These eddy currents would flow between the transmitter and receivers and “short circuit” the measurement. Thus, the Resistivity tool must operate within a fairly narrow frequency window to allow us to measure formation Resistivity while using an electrically conductive drill collar. The shallow, and medium transmitters operate at a frequency of 2 MHz, while the deepspacing transmitter operates at 400 KHz. During the development of the Resistivity tool, it was realized that we needed to reduce the deep transmitter’s frequency in order to receive signals of sufficient amplitudes at the longer spaced receivers in all formation Resistivity. For the same conditions, the amplitude of a propagating 400-kHz wave is √2 times greater than that of a 2-MHz wave.

Phase Shift Measurement Although the propagation velocity for electromagnetic waves is normally thought of as a constant (300,000 km/second, commonly referred to as the “speed of light”), this is actually the case only for an electromagnetic (EM) wave traveling through a vacuum or free space. In an electrically conductive material, the velocity of a propagating EM wave slows in proportion to the conductivity of the material.

1

Resistivity Sensor Theory and Application

The wavelength, frequency, and velocity of a propagating wave are related by the following equations: V= ω∗λ

or

V = 2πf * λ

where λ is the wavelength, V is the velocity of the propagating wave, f is the frequency, and ω is the angular frequency. The wave travels at higher speeds in resistive formations than it does in conductive formations. Thus, the transmitted Resistivity signal will have a longer wavelength in higher-Resistivity formations and a shorter wavelength in more conductive, lower-Resistivity formations. The velocities of propagating electromagnetic waves can be expressed in the traditional units of velocity (length/time), or alternatively, in what electrical engineers called phase shift, which has units of degrees. Historically, people have preferred to use the concept of phase shift when describing the velocity measurement made by an MWD propagation Resistivity tool. The shift in phase that occurs between two receivers is basically a measurement of the fraction of one wavelength that occurs between the 8 – inch spacing that separates the two receivers (see Figure 1). For example, if the wavelength (one complete 360-degree cycle) were 12 inches, then we would expect to measure a phase shift of 180 degrees, or one-half of a complete cycle, between two receivers spaced 8 inches apart. In a more resistive formation, in which the wavelength was 80 inches, we would expect to measure a phase shift of (8/80) × 360, or 36, degrees between the two receivers. Finally, as the conductivity approaches zero (Resistivity approaches infinity), the wavelength becomes many meters in length and the measured phase shift that occurs over the Resistivity tool’s 8 - inch spacing becomes very small. Table 1 summarizes the interrelationships among these parameters.

Figure 1 Phase Resistivity Measurement Principle

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Resistivity Sensor Theory and Application Table 1 Velocity, Phase Shift, and Wavelength, as a Function of Resistivity and Conductivity

The three phase shift-to-Resistivity transforms that we use are graphically depicted in Figure 2 below. These transforms are based on well established theoretical models that have been bench-marked with laboratory data. The lab data were acquired in very large fiberglass tanks filled with salt water of known Resistivity.

Figure 2 Phase Shift-to-Resistivity Conversions

Attenuation Measurement An EM wave will decay exponentially as it propagates through a conductive formation. The rate of decay, or attenuation, is directly proportional to the formation conductivity. Attenuation (sometimes referred to as amplitude ratio) is calculated from the “ratio” of the amplitudes of the signals detected at the two receivers, which are at different distances from the transmitter. A root-mean-squared (RMS) circuit in the receiver electronics is used to measure these signal amplitudes. This circuit outputs an RMS DC voltage, which is proportional to the amplitude of the detected AC signal.

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The most common unit for quantifying the level of attenuation is the decibel (dB). This “amplitude ratio” unit is defined as: Amplitude Ratio (dB) = 20 x log (Afar/Anear) where the Amplitude, A, is in units of volts. Since the signal amplitude at the near receiver is typically greater than that at the far receiver, the amplitude ratio, as defined by the above equation, is usually a negative number. The greater the attenuation, the larger, in terms of absolute value, this negative number becomes. In a high-conductivity formation, the high degree of attenuation will result in a significant signal decay between the near and far receivers, with the far receiver signal amplitude being significantly weaker than the near receiver signal. At high Resistivity, the transmitted signal suffers less attenuation, and the far receiver amplitude will be only slightly less than the near receiver amplitude. Table 2 summarizes the interrelationships among these parameters. Table 2. Attenuation as a Function of Resistivity and Conductivity

The three attenuation-to-Resistivity transforms are graphically depicted in Figure 3. These transforms are based on well-established theoretical models that have been bench-marked with laboratory data. The lab data were acquired in very large fiberglass tanks filled with salt water of known Resistivity.

Figure 3 Attenuation to Resistivity

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CPA Resistivity Because the measured values of both phase shift and attenuation are inversely proportional to Resistivity, a formation Resistivity measurement can be computed from any one of the following: 1.

phase shift measurement

2.

attenuation measurement

3.

a combination of the phase shift and attenuation measurements

The Resistivity service provides Resistivity values computed from the phase shift measurement, and from a mathematical combination of phase shift and attenuation measurements; the latter is known as the combined phase and attenuation (CPA) Resistivity. To produce the CPA Resistivity value, the measured phase shift and attenuation values are mathematically combined to produce a new computed parameter, known as the CPA value. A transform is then used to compute the CPA Resistivity from the computed CPA value for each of the three transmitter-receiver spacings. These transforms are depicted in Figure 4 below.

Figure 4 CPA to Resistivity Conversion

Calibration Theory The Resistivity tool measures basic physical parameters (phase shift and attenuation) of electromagnetic waves. Thus, it is not necessary to calibrate each tool in a simulated formation or “calibration pit”. The fundamental mathematical transforms between Resistivity and the measured values of phase shift and attenuation are based on well-established electromagnetic principles that are described by Maxwell’s equations, and have been experimentally verified by logging large bodies of water of known Resistivity with the tool.

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For the phase shift measurement, we assume that the velocity of the EM wave in air is the speed of light, and consequently, the observed phase shift in air or a vacuum should be a very small constant value. When we “air hang” a tool and observe its reading in air, we assume that ALL of the observed offset from zero degrees of phase shift is due to tool “imperfection.” This airhang value, in degrees of phase shift, is subsequently used to calibrate the raw measurements made by the tool. In the Resistivity tool software this value is subtracted from each raw phase shift measurement made, before it is pulsed to the surface and/or recorded in memory. Of course, for the Resistivity tool, we have a unique airhang calibration factor for each of the four spacings. Furthermore, since these hardware dependent “imperfections” can be temperature sensitive, we characterize them as a function of temperature from 20oC to 150oC. A propagating EM wave is attenuated by the conductivity of the medium through which it passes, and when its amplitude is measured at two different distances from a transmitter, additional attenuation, due to what is commonly referred to as geometrical spreading, is also observed. This geometrical spreading loss term is significant and must be accounted for; however, it is not Resistivity dependent. Consequently, we determine its magnitude in air, and similar to the phase shift data downhole processing, it is subtracted from each raw measurement of attenuation that is made. Other hardware-induced “measurement imperfections” are implicitly included in these airhang attenuation values. These “imperfections” can also be temperature dependent; therefore, we characterize them as a function of temperature from 20oC to 150oC. NOTE: The output of each receiver insert’s RMS circuit is also extensively calibrated against precision lab equipment to ensure that the amplitude measured by any insert will be the same for a particular received signal. These calibration data are used by the tool’s software to compute calibrated amplitudes for both the near and far receiver signals, before the attenuation is calculated and the airhang correction is applied. The raw amplitude of the signal detected at each receiver, V (in volts), is converted into a calibrated value of amplitude in the receiver insert. During the calibration step, the unit used to quantify the amplitude of the signal is also changed from the volt to the decibel-milliwatt, or dBm. The equation defining this unit of relative (to 1 milliwatt) power is: Amplitude (dBm) = 10 x log [(V2/R)/.001] The reference power for the dBm unit is one milliwatt, or 0.001 watt. The impedance, R, of the receiver circuit is nominally 50 ohms, and the receiver insert amplitude calibration performed in the lab uses a 50-ohm load. Substituting 50 for R in the above equation yields: Amplitude (dBm) = 10 x log [(V2/50)/.001] The above equation is used in the Resistivity 4 tool’s software and the surface software to convert the raw, uncalibrated receiver voltages into calibrated values of relative power. Using the units of dBm for the two signal amplitudes (relative powers) in the amplitude ratio, or attenuation, equation results in the following simple relationship: Amplitude Ratio (dB) = Afar (dBm) - Anear (dBm) Therefore, the amplitude of the FAR receiver’s signal, in dBm, can be easily calculated, since we record the near receiver signal’s amplitude (in dBm) and the downhole calculated value of the amplitude ratio (in dB). Since the far receiver’s signal amplitude is typically lower than the near receiver’s, the amplitude ratio (in dB) is typically a negative quantity. 6

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Accuracy The accuracy of the Resistivity measurements varies with the formation Resistivity. Like wireline induction tools, propagation Resistivity sensors are most accurate at low Resistivity, where small changes in Resistivity correspond to large, easily-measured changes in phase shift and/or attenuation. The measurements become less accurate at higher Resistivity where small changes in phase shift and/or attenuation correspond to large changes in Resistivity. Since phase shift-derived Resistivity measurements are useful over a wider range of Resistivity than either attenuation-derived or CPA-derived Resistivity measurements, their accuracies will be discussed in more detail. Table 3 illustrates the relationships between measured phase shifts and derived Resistivity. Table 3 Resistivity vs. Phase Shift

The accuracy of the Resistivity raw measurements should be constant in terms of degrees of phase shift and decibels of attenuation. However, the non-linear relationship between Resistivity and these measured parameters results in an accuracy, expressed in ohm-m, which varies with formation Resistivity. As the Resistivity increases, a given error in the phase shift and attenuation measurements translates into a larger error in the derived phase shift Resistivity and CPA Resistivity values. Table 4 illustrates the effect of a constant error of +0.1 degree in phase shift on the percentage error in the medium phase shift-based Resistivity value in ohm-meters. In terms of ohmmeters, the percentage error increases dramatically as the Resistivity increases from 0.1 to 1000 ohm-m. Table 4 Resistivity Error Resulting from a +0.10 Degree Medium Phase Shift Error

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Based on reviewing many sets of Resistivity tool airhang data, a reasonable measurement uncertainty to assume for a stable, well-calibrated tool is ±0.05 degrees of phase shift. This amount of uncertainty should be considered “best case” for this tool design. Figure 5 through Figure 8 illustrate the effect this small constant error in phase shift has on the inferred Resistivity. In Figure 5, an example depicts the situation in which the X-shallow phase shiftbased Resistivity log reading (R a) is 300 ohm-m. For this assumed uncertainty, the true Resistivity (Rt) could be as low as 210 ohm-m or as high as 520 ohm-m, depending on the sign of the error. NOTE: how the effect of this constant error in phase shift varies dramatically with Resistivity. Also, note how the effect varies with transmitter-receiver spacing and frequency, remembering that the deep transmitter operates at 400 KHz.

Figure 5 Shallow Phase Shift Uncertainty = ± 0.05 degrees

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Figure 6 Shallow Phase Shift Uncertainty = ± 0.05 degrees

Figure 7 Medium Phase Shift Uncertainty = ± 0.05 degrees

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Figure 8 Deep Phase Shift Uncertainty = ± 0.05 degrees

Phase Shift vs. CPA Resistivity Accuracy At higher formation Resistivity, the phase shift Resistivity is more accurate than the CPA Resistivity. There are two reasons for this. First, as the formation Resistivity increases, the change in attenuation with a further increase in Resistivity becomes very small and difficult to accurately resolve. In other words, a cross-plot of attenuation vs. Resistivity (see Figure 3) would show the relationship to “flatten-out” above about 20-50 ohm-m, whereas there remains a small but measurable change in phase shift with changing Resistivity for Resistivity values up to approximately 1000 ohm-m (see Figure 2) . Because the attenuation measurement is a component of the CPA Resistivity, this loss of sensitivity of the attenuation measurement is also reflected in a decrease in the accuracy of the CPA Resistivity values at higher Resistivity (see Figure 4). The second factor contributing to the poorer high-Resistivity accuracy of the CPA Resistivity logs results from the greater dielectric sensitivity of the attenuation measurement, as compared with the phase shift measurement. This results in the CPA Resistivity being more sensitive to dielectric constant-related errors than the phase shift Resistivity. Thus, because dielectric errors become more significant as the Resistivity increases, and because the CPA Resistivity is more sensitive to dielectric effects than is the phase shift measurement, the CPA Resistivity is more likely to suffer from significant dielectric effects at higher Resistivity than is the phase shift Resistivity. As a rule of thumb, the Resistivity phase shift Resistivity measurements can be considered quantitatively accurate up to about 200 to 500 ohm-m, and qualitatively useful up to about 1000 ohm-m. The CPA Resistivity values should only be used quantitatively at Resistivity below about 30 ohm-m.

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Antenna Configurations The First Resistivity tool had a single transmitter antenna and two receiver antennas. The receivers are 6 inches apart and the transmitter is 24 inches from the near receiver. The current Resistivity design begins with the a basic configuration and then adds additional transmitters: two shorter-spaced transmitters located 20 and 30 inches from the near receiver, and one longer-spaced transmitter located 48 inches from the near receiver. The purpose for employing multiple transmitter-receiver spacings is to provide multiple formation Resistivity measurements with different depths of investigation. Generally, Resistivity measurements acquired from longer transmitter-receiver spacings will “read deeper” into the formation than measurements from shorter transmitter-receiver spacings.

Figure 9 Comparisons Between Resistivity Tool Configurations

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Depth of Investigation The depth of investigation (DOI) of a particular Resistivity measurement is dependent on several parameters, including: the transmitter-to-receiver spacing, the transmitter frequency, and the measured parameter from which Resistivity is computed, i.e., phase shift, attenuation, or CPA. However, the parameter with the greatest effect on the DOI of the Resistivity measurement is the formation Resistivity itself.

Transmitter-to-Receiver Spacing The depth of investigation of Resistivity measurements increases with increasing transmitterto-receiver spacing. This principle is illustrated by the generalized diagrams below, which show the lines of constant phase of the shallow and medium-spaced transmitters in an isotropic medium. The shaded area indicates the region that will influence the phase shift measured between the near and far receivers. Note that for a longer transmitter-receiver spacing, this area of investigation extends farther laterally into the formation, providing a greater depth of investigation. Also note, however, that this increase in DOI is accompanied by a decrease in the vertical resolution for longer spacing measurements, as the area of investigation also extends farther “up and down” in the direction of the tool axis.

Shallow phase Shift Resistivity measurement.

Medium phase shift Resistivity measurement.

Figure 10 Area of Investigation of Shallow and Medium Phase Shift Resistivity Measurements

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Phase Shift vs. Attenuation The depth of investigation is also a function of which measured parameter (phase shift, attenuation, or CPA) is used to compute Resistivity. This difference in depth of investigation results from a difference in the spatial distribution of the phase and amplitude fields, as illustrated below.

Phase

Amplitude

Figure 11 Comparisons Between Phase and Amplitude Fields for Medium Spacing

For medium measurements, these are the lines of constant phase and amplitude. Note the different depths of investigation of phase shift and amplitude attenuation Resistivity measurements. In an isotropic medium, the electromagnetic field will radiate from the transmitter at the same velocity in all directions. Thus, lines of constant phase will form spheres around the transmitter (see the left side of Figure 11). However, the field is radiated perpendicular to the tool axis with greater intensity than in directions closer to the tool axis. Thus, the lines of constant amplitude are not spherical and are as shown on the right side of Figure 11. Therefore, the shaded area affecting the attenuation measurement is different (and deeper into the formation) than the area which affects the phase shift measurement.

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This difference in the spatial distribution of the phase and amplitude fields may seem difficult to understand, but consider the simple acoustic analogy of a trumpet. Sound waves emanate from the horn of the trumpet and travel at the speed of sound in all directions. Thus, a listener standing 10 meters to the side of the trumpet would hear notes at exactly the same time as a listener standing 10 meters in front of the trumpet. However, the person standing directly in front of the trumpet would hear a louder volume than the person standing off to the side. Both the Resistivity transmitters and the trumpet are directional transmitters, radiating a stronger signal in one direction, even though the signal will travel at the same velocity in all directions. Thus, lines of constant phase and amplitude of the acoustic energy around a trumpet would show a different spatial distribution, not unlike the phase and amplitude fields surrounding an Resistivity transmitter.

CPA A Resistivity measurement derived from a combination of the phase shift and attenuation measurements can have a depth of investigation which is either deeper than the attenuation Resistivity, shallower than the phase shift Resistivity, or intermediate between the phase shift and attenuation Resistivity values, depending on the way in which the phase shift and attenuation values are mathematically combined. Although the exact formula for combining the phase and attenuation values to produce the CPA value (from which the CPA Resistivity is computed) is rather complex, consider the simple case illustrated below.

Figure 12 Radial Response of Two Overlapping Measurements

This diagram depicts the radial response of two overlapping measurements. The vertical Yaxis represents the relative sensitivity, or the amount of signal, coming from various diameters. The shallower measurement is defined by areas A and B, whereas the deeper measurement is defined by areas B and C. These two raw measurements could be combined in several different ways to give a different effective depths of investigation. For example, if the shallower measurement were subtracted from the deeper measurement, we would be left with the response illustrated by area C. By subtracting the shallower component, B, of the deeper measurement, the resultant combined measurement (represented by area C) would have a deeper depth of investigation than either of the two basic measurements. In other words, by using the shallower phase shift measurement to cancel-out the shallower component of the deeper attenuation measurement, the resultant CPA value yields an effective depth of investigation that is deeper than either the phase shift or the attenuation measurements.

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Frequency Effects The depth of investigation of a propagation Resistivity measurement is also a function of the frequency of the transmitted signal. Generally speaking, lower frequency measurements will have a greater depth of investigation than otherwise-equivalent higher frequency measurements. Aside from depth of investigation issues, lower frequency measurements will also be less sensitive to dielectric effects, but will exhibit poorer precision at high Resistivity.

Formation Resistivity Effects The factor having the greatest effect on depth of investigation is the formation Resistivity itself. As previously mentioned under the discussion of the principles of the attenuation measurement, a radio-frequency electromagnetic wave suffers greater attenuation in a lowResistivity medium than in a high-Resistivity medium. This increased attenuation at low Resistivity means that the transmitted field will not extend as deep into the formation at low Resistivity as it will at higher Resistivity. This results in the phase shift and CPA Resistivity measurements, for a given transmitter-receiver spacing, having a much greater depth of investigation at high Resistivity than at low Resistivity. This variation in depth of investigation with Resistivity is illustrated in Figure 13 through Figure 20, which show the depth of investigation of the Resistivity phase shift and CPA Resistivity measurements for formation Resistivity values ranging from 0.2 ohm-m to 100 ohm-m. These figures show the fraction of the total measured conductivity signal (the integrated radial pseudo-geometric factor or IRPGF) vs. diameter of investigation. This diameter is measured from the center of the tool. This calculation of IRPGF is performed by assuming that:

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There is no borehole.

•

The formation is isotropic.

•

The formation is infinitely thick.

•

In the step invasion model, the difference between Rt and Rxo is infinitesimally small (uninvaded, for all practical purposes).

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Figure 13 Depth of Investigation: Deep CPA

Figure 14 Depth of Investigation: Deep Phase Shift

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Figure 15 Depth of Investigation: Medium CPA

Figure 16 Depth of Investigation: Medium Phase Shift

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Figure 17 Depth of Investigation: Shallow CPA

Figure 18 Depth of Investigation: Shallow Phase Shift

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The historical definition for depth of investigation for Resistivity tools is the 50% point on the IRPGF curve, meaning that half of the total signal sensed comes from within this diameter and half of the total signal comes from outside this diameter. In other words, when the diameter of invasion reaches the IRPGF 50% point, the tool reading will be mid-way between the conductivity of the flushed zone (CX0) and the conductivity of the uninvaded formation (Ct) in the step invasion model. A few very important insights into the nature of the response of a propagating wave Resistivity tool can be gleaned by close examination of these IRPGF curves: 1

For low values of Rt, all four phase shift-based Resistivity measurements (and, to a lesser degree also, the four CPA-derived resistivities) exhibit a diametrical area, between approximately 25 and 55 inches, in which the IRPGF significantly exceeds a value of 1.0.

Consequently, for the case of a low Resistivity zone that is invaded to this depth range with mud filtrate, the various Resistivity measurements provided by the Resistivity tool can overshoot (either higher or lower, depending on the values of Rt and Rxo) the theoretical limit (calculated assuming 100% flushing) of Rxo. 2

For low values of Rt, all four CPA-based Resistivity measurements exhibit a diametrical area, between approximately 10 and 45 inches, in which the IRGPF is significantly less than zero, or negative. This region of negative IRPGFs is not unusual for Resistivity tools, such as the Resistivity, that use the difference or the ratio of measurements made at two receivers to compute apparent Resistivity. This phenomenon provides inherent borehole compensation by rejecting (subtracting) the conductivity contributions from nearby regions, e.g., the borehole.

Therefore, for the case of a low Resistivity zone that is invaded to this depth range with mud filtrate, the CPA-based Resistivity measurements provided by the Resistivity service can overshoot (either higher or lower, depending on the values of Rt and Rxo) the true formation Resistivity in what may be considered the counterintuitive direction. Shallow resistive (Rxo > Rt) invasion will cause the apparent CPA Resistivity to be too low, while shallow conductive (Rxo < Rt) invasion will cause the apparent CPA Resistivity to be too high. This also applies to plain attenuation measurements. Alternatively, IRPGF data can be presented as a family of curves, one for each spacing, for a specific apparent Resistivity (Ra). Figure 21 through Figure 24 de scribe the depths of investigation of both the phase shift- and CPA-derived measurements for apparent resistivities of 0.5 and 50 ohm-m.

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Figure 21 Phase Shift Depths of Investigation: R a = 0.5 ohm-m

Figure 22 CPA Depths of Investigation: R a = 0.5 ohm-m

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Figure 23 Phase Shift Depths of Investigation: R a = 50 ohm-m

Figure 24 CPA Depths of Investigation: R a = 50 ohm-m

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The depths of investigation (using the IRPGF 50% point as the definition for DOI) for the Resistivity measurements at these two different resistivities (0.5 and 50 ohm-m) are listed in Table 5. Note the dramatic increase in depth of investigation as the formation resistivity changes, such that the phase shift-based resistivity measurements at 50 ohm-m “read deeper” than the CPA Resistivity measurements at 0.5 ohm-m. An interesting point to note is that at high resistivities the shallow, medium, and deep phase shift resistivity curves have DOI values which are very similar to wireline SFL, medium induction, and deep induction curves, respectively. Table 5 Depths of Investigation (IRPGF = 0.5) for Resistivity Measurements

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Dielectric Effects The dielectric permittivity of a material is quantified by what is called the dielectric constant. Typically, scientists ratio a material’s dielectric constant, ε, to the dielectric constant of free space (vacuum), εo, to simply change the range of typical values. This relative value is referred to as the relative dielectric constant, εr, and is defined as follows:

ε r = ε /ε o where,

εo = 8.8542 x 10-12 farads/m All the resistivity transforms we use assume a relative dielectric constant (εr) of 10. For a given formation resistivity, if the actual formation εr value is higher than this assumed value of 10, the measured phase shift will be slightly higher than expected and the measured attenuation will be significantly lower than expected. Consequently, the inferred resistivities will be in error (see Table 6). Thus, because the attenuation is more sensitive to changes in the relative dielectric constant than is the phase shift, the CPA-derived resistivity is more likely to suffer significant dielectric-related errors than is the phase shift-derived resistivity. Table 6 Effect of (εr) on Measured Phase Shift & Attenuation and Phase Shift & CPA Resistivities

The dielectric sensitivity of a particular measurement is also a function of the transmitter-toreceiver spacing as well as the measurement frequency. Longer-spaced measurements have a greater dielectric sensitivity than shorter-spaced measurements, and higher-frequency measurements are more sensitive to dielectric effects than lower-frequency measurements. Thus, in a shale with a very high εr value, we may see separation of the phase shift resistivity measurements with RMEDIUM < RSHALLOW < RDEEP. Note that, with respect to dielectric effects, the lower frequency of the deep-spacing measurement almost exactly offsets the effect of the longer transmitter-receiver spacing. Figure 25 through Figure 36 illustrate the sensitivities of the various types of derived resistivities to the difference between the actual relative dielectric constant, εr , of the formation and the assumed value of 10.

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Figure 3.26 Shallow Phase Shift

Figure 27 Medium Phase Shift

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Figure 28 Deep Phase Shift

Figure 30 Shallow Attenuation

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Figure 31 Medium Attenuation

Figure 32 Deep Attenuation

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Figure 34 Shallow CPA

Figure 35 Medium CPA

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Figure 36 Deep CPA

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Anisotropy Effects Because of their layered nature, many sedimentary formations are electrically anisotropic. This means that the electrical resistivity measured parallel to the bedding planes is different from the resistivity measured perpendicular to the bedding plane. This phenomenon can be caused by either of two distinctly different geologic situations. However, to the Resistivity tool, these two different geologic settings appear the same. One type of anisotropy is commonly called microscopic anisotropy. This refers to a single sedimentary rock that exhibits intrinsic anisotropy due to its structure. Shale, with its flat clay platelet structure, is a classic example of an electrically anisotropic rock. During deposition and subsequent overburden loading, these platelets tend to align themselves horizontally. Consequently, electricity flows easier parallel to these flat platelets than perpendicular to them (Figure 37). Another anisotropic phenomenon is caused by the layering of formations and is commonly referred to as macroscopic anisotropy. This can occur when the scale of the layering is much less that the resolution of the measuring device. A laminated sand-shale sequence is a classic example of this type of electrical anisotropy (Figure 38). Also, each layer (bed) can be isotropic and the unit can still be anisotropic.

Figure 37 Microscopic Anisotropy in Shale

Figure 38 Macroscopic Anisotropy in Laminated Formation

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If we think of the different rock layers as being electrical resistors in a circuit, they act as resistors wired in parallel to current flowing parallel to the bedding planes, and as resistors wired in series to current flowing perpendicular to the bedding planes. Like wireline induction tools, the Resistivity tool induces an eddy current which circles the tool in a plane perpendicular to the tool axis. Thus, the Resistivity tool measures the resistivity in a plane perpendicular to the borehole. Therefore, in a vertical well with horizontal beds, the Resistivity will read the horizontal resistivity of the formation. However, in a horizontal well, the induced eddy current will circle the borehole in a vertical plane, encountering both the horizontal and vertical components of the formation resistivity. In this latter situation, the Resistivity tool response will be a complex function of both the horizontal and vertical components of the formation resistivity, as well as the angle between the tool axis and the formation bedding planes. Because this function varies with transmitter-receiver spacing and frequency, the different Resistivity curves respond differently to anisotropic formations encountered at high angles.

Figure 39 Phase Shift Resistivity Responses where R h = 1 ohm-m and Rv = 4 ohm-m

Figure 39 illustrates the modeled responses of the phase shift-based Resistivity measurements in a formation having a horizontal resistivity, Rh, of 1 ohm-m and a vertical resistivity, Rv, of 4 ohm-m. The first letter, M, in each curve name means it is modeled or calculated (not measured) data.

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Figure 40 Relative Dip Angle Definition

For relative dip angles (see Figure 40 for definition) less than about 30 degrees, all four curves read close to the horizontal resistivity value of 1 ohm-m (this would be typical of a vertical well with horizontal or slightly dipping beds). However, as the relative dip angle increases above about 50 degrees (as would be the case in high-angle wells) the phase shift resistivity values depart from the Rh value and increase toward Rv. In fact, in some cases, the measured (apparent) resistivities will exceed the value of Rv. Also notice that the shallow, and medium curves are affected to differing degrees by the anisotropy, resulting in significant curve separation with RSP < RMP . The medium and deep Resistivity curves read almost the same value because the effect of the different transmitter spacing is almost exactly offset by the effect of different frequencies (1 MHz for the deep transmitter; 2 MHz for the medium and shallow transmitters). Thus, the characteristic log signature of formation anisotropy is RSHALLOW < RMEDIUM < RDEEP . A computer program has been developed which computes Rv, Rh, and the relative dip angle based on the shallow, and medium phase shift-based Resistivity log values. Note that this inversion calculation yields only the magnitude of the relative dip angle, not the azimuth direction. The computed Rh value can be compared with induction or 2MHz type logs recorded in vertical wells. Also, the Rh value can be used to compute water saturation in a “laminated sand” or parallel resistor interpretation model. The major limitation of this program is that it assumes that all of the separation between the three curves is due only to anisotropic effects. While this may be the case in impermeable shales or hydrocarbon-bearing reservoirs drilled with oil-based mud, a number of other effects such as invasion, dielectric constant differences, residual borehole effects, and/or shoulder bed effects may also contribute to the Resistivity curve separation. If present, these other effects will induce error in, or perhaps completely invalidate, the anisotropy inversion calculation. Thus, this model must be applied cautiously, with careful consideration given to these other potentially disturbing effects.

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Analysis and Interpretation of Logs Several case studies are presented here.1 Note: The data used in these examples pre-dated the introduction of the CPA-based resistivity computation. Consequently, plain attenuation-based resistivity curves are displayed. For the most part, comments relating to attenuation resistivity responses can also be applied to CPAbased resistivity responses.

Invasion Process - Verification of R t This S-shaped well, located in the Gulf of Mexico, was drilled with a 9.875-inch diameter drill bit using a bentonite-based fresh water drilling mud. Mud weight in these intervals was 9.7 pounds/gallon, API fluid loss was 4.8 cc/30 minutes, and mud resistivity was 0.26 ohm-m at reservoir temperature. Formation water resistivity was 0.025 ohm-m at reservoir temperature, and the mud filtrate resistivity was 0.17 ohm-m at reservoir temperature. Log ex. 1 displays a gas sand with a porosity of 31%, sidewall core empirical permeability of 900 md, and a relative dip angle, due to hole inclination and formation dip, of 30 degrees. Four MWD phase shift resistivity curves are plotted in Track II. Formation exposure time (i.e., the elapsed time between drilling and logging) for this interval was only one hour. The shallow phase resistivity values were reduced due to invasion of the fresh mud filtrate. Tracking of the medium and deep phase curves verified that they were indeed providing values of true formation resistivity. The diameter of invasion, calculated assuming a step-profile invasion model, was 20 inches at drilling time. Track III contains the MAD phase shift resistivity curves recorded eight days after drilling. The apparent diameter of invasion from the step-profile invasion model was 16 inches. Wireline resistivity data shown in Track IV were recorded 12 days after the well was drilled and show no apparent indication of invasion. Such reversals in apparent invasion depths have been discussed in prior literature. It has been proposed that this phenomenon can occur in gas zones logged in deviated wells and/or dipping beds, and is possibly due to gravity-induced fluid migration.2 It has also been suggested that the validity of these diameters of invasion, calculated by stepprofile invasion models, is suspect because the transition from the flushed zone’s water resistivity to the virgin zone’s water resistivity is not sharp, but gradational3.

Reference: 1. Ball, S., and Hendricks, W.E.: “Formation Evaluation Utilizing a New MWD Multiple Depth of Investigation Resistivity Sensor,” paper presented at the 15th European Formation Evaluation Symposium, May 5-7, 1993. 2. Woodhouse, R., Opstad, E. A., and Cunningham, A.B.: “Vertical Migration of Invaded Fluids in Horizontal Wells,” paper A presented at the SPWLA 32nd Annual Logging Symposium, Midland, Texas, U.S.A, June 16-19, 1991. 3. Beck, G. F., Oberkircher, J., and Mack, S.: “Measurement of Invasion Using an MWD Multiple Depth of Investigation Resistivity Tool,” paper SPE 24674 presented at the 67th Annual Technical Conference and Exhibition, Washington, DC, U.S.A, October 4-7, 1992.

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Log example 1 Gulf of Mexico Gas Sand MWD/MAD/Wireline – Phase Resistivities

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Invasion Process - Measurement of Rxo Log ex. 2 displays a water zone located deeper in the same well as above. The MWD curves in Track II had a formation exposure time of only one hour, and the agreement of all four phase shift resistivity curves signified that no appreciable invasion had occurred. Track III shows the same interval logged 71/2 days later, and significant invasion (Di = 23 inches) had occurred, as indicated by the interrelationship of the curves. This profile is commonly observed in Gulf Coast high salinity water sands invaded by a fresh mud filtrate. Wireline logs were run after 12 days of formation exposure time and indicated significant invasion, with a diameter of invasion computed to be 63 inches from the wireline service company’s tornado chart. The value of Rxo from the tornado chart was 0.96 ohm-m and the maximum (Sxo = 100%) theoretical value was 1.23 ohm-m. These are very close to the values of both the wireline shallow guard and MAD shallow phase resistivity measurements. Their agreement indicate that the shallow phase shift measurement can be used to estimate the flushed zone resistivity in this MAD environment.

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Log Example 2 Gulf of Mexico Water Sand MWD/MAD/Wireline – Phase Resistivities

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Analysis in Oil-Based Mud Log ex. 3 and Log ex. 4 are examples taken from one of the first Resistivtiy logs run in the North Sea. It is also the first Resistivity log run in an oil-based drilling fluid. This well was drilled with an 8.5-inch diameter drill bit and a borehole inclination of 37 degrees. The intervals shown are a sandstone formation with 25% average porosity. Connate water resistivity is 0.021 ohm-m at formation temperature.

Log example 3 North Sea Oil Zone Logged After Coring Operation

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The phase shift resistivity curves displayed in Log ex. 3 (Track II) were run in a MAD mode due to a prior coring operation through this interval. Formation exposure time was 45 to 60 hours. With an oil-based mud and low formation water saturation (i.e., low relative permeability to water), significant differences among the various resistivity curves, due to filtrate invasion, would not be anticipated. Slight curve separations seen in the higher resistivity intervals are due to small differences in the vertical resolutions of the various spacings in this resistivity range. Track III is a conventional 2 MHz log presentation, containing the medium phase shift and medium attenuation resistivity curves only. An inexperienced user might wrongly interpret the separation of these two curves as an indication of mud filtrate invasion. However, the correct explanation for the observed differences is simply the different vertical resolutions of these two measurements. Attenuation resistivity curves are plotted in Track IV. Comparison of these curves with their phase shift counterparts in Track II highlights the much sharper vertical resolution of the phase shift-derived resistivity measurements. The magnitude of this difference in vertical resolution is a function of resistivity and it increases with increasing resistivity. In contrast, Zone A in Log ex. 4 exhibits the effects of invasion by the resistive oil-based mud filtrate within three hours after drilling. All four phase shift resistivity values plotted in Track II are affected to varying degrees in this permeable water-bearing sandstone. In comparison, the attenuation resistivity values shown in Track III exhibit invasion effects on the shallow curve only. The medium and deep attenuation resistivity curves overlay, confirming the measurement of Ro. Note that in this range of resistivities, the attenuation-based measurement has good vertical resolution. Zone B in Log ex. 4 is similar to Zone A, except that the formation exposure time in only 1.4 hours. Increases in the shallow phase shift resistivity values above the expected water zone resistivity values indicate invasion of the oil filtrate. The medium and deep phase resistivity curves provide a direct measurement of Ro. Note that the four attenuation resistivity curves are in good agreement with the medium and deep phase resistivity curves, thereby confirming measurement of Ro.

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Log example 4 North Sea Water Zone Logged While Drilling

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The sand shown in Log example 5 is usually deeply invaded at the time of wireline logging, thereby complicating accurate evaluation of its fluid saturations. It is also well known for producing commercial quantities of hydrocarbons when calculated values of water saturation are relatively high. The connate water resistivity, calculated in a nearby water sand, is 0.02 ohm-m at formation temperature. The mud filtrate resistivity is 0.11 ohm-m at formation temperature. After several unsuccessful attempts to record wireline logs through this sand, it was logged with the Resistivity tool approximately seven days after drilling. The separations of the phase resistivity curves (Track II) and the attenuation resistivity curves (Track III) are indicative of a deeply invaded formation. Utilizing a step-profile model of invasion and the phase shift resistivity data as inputs, Di-P (Track I), Rxo-P (Track IV), and RtP (Track IV) have been calculated continuously through this sand. The fact that the shallow phase curve overlay one another from ×400 to ×410 feet is a good indication that they are providing a measurement of Rxo. This supposition is confirmed by their very close agreement with the computed Rxo curve through this interval. The deep attenuation measurement is the only one of the eight measurements that is providing accurate values of Rt in this sand. It is consistent with, though slightly lower than, the value of Rt-P computed from the phase resistivity data. Using a step-profile invasion model and the attenuation resistivity data as inputs, an Rt curve (not shown) that is similar to the Rt-P curve, but with less character, was computed. Invasion of fresh mud filtrate has caused the other seven curves to read too high. Correct analysis of this sand’s water saturation requires a multiple depth of investigation resistivity tool that includes a relatively deep-reading measurement and modeling software to confirm that its readings have not been compromised by very deep invasion.

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39


Log example 5 Results from Step-Profile Invasion Model

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North Sea Horizontal Well Project: Oil-Based Mud vs. KCl Mud Log ex. 6 displays a section of the pilot hole drilled in conjunction with a horizontal well in the North Sea. The pilot well, drilled with an 8.5 inch diameter bit and at an inclination of 60 degrees through the target formation, utilized a KCL/polymer mud system. At the circulating temperature of 77o C, Rm was 0.05 ohm-m and Rmf was 0.036 ohm-m. Formation water resistivity was 0.075 ohm-m at 77o C. The phase shift-derived resistivity curves exhibit a slightly erratic character in the ××58 to ××61 meter interval, due to the combination of thin resistive coal streaks, irregular hole size, and the very conductive mud. The attenuation measurements are similarly affected, but to a lesser degree. A whole core was cut from ××77 to ×142 meters, which included an oil/water transition zone from ××96 to ×104 meters. The long formation exposure time, due to the two-day coring operation, created the potential for deep invasion in the hydrocarbon-bearing interval from ××61 to ×104 meters. The effect of the very conductive invading mud filtrate on the eight Resistivity curves is apparent in Log ex. 6. The attenuation-derived resistivity curves plotted in Track III exhibit much less separation than do the phase shift-derived resistivity curves plotted in Track II, because of the apparent deeper depths of investigation of the attenuation measurements in this environment. On the other hand, the vertical resolutions of the phase shift resistivity measurements are superior to their attenuation counterparts. Some values of Rxo, Di, and Rt, calculated using a step-profile model of invasion and the phase resistivity data as inputs, are annotated on Log ex. 6. From ××65 to ×125 meters, invasion diameters vary from 16 inches to 43 inches. The computed values of Rt are consistent with the medium and deep attenuation resistivity values in zones where these two measurements agree. When the computed value of Di is less than approximately 30 inches, the deep phase resistivity measurement agrees with the modeled value of Rt. When Di exceeds 30 inches, the computed Rt value is slightly greater than the deep phase resistivity value.

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41


Log example 6 Phase vs. Attenuation Resistivities in North Sea Pilot Hole

42

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Figure 7 illustrates a section of the horizontal well through the hydrocarbon zone shown in Figure 4. The attenuation resistivity data are not presented because they add minimal additional information in this particular environment. In contrast to the pilot hole, this horizontal borehole was drilled with an oil-based mud. The coal interval at ×221 to ×227 meters is more easily identified because borehole effects are much less pronounced in oilbased mud than in the very conductive mud used in the pilot hole. The resistivity peak at ×256.5 meters is a “polarization horn.” This phenomenon is caused by a discontinuity in the propagating electrical field as the tool crosses the boundary between beds having different resistivities. The size of the polarization horn depends on the contrast between the resistivities of the adjacent beds and the relative dip angle between the borehole and the formation. The higher the relative dip angle and greater the resistivity contrast, the larger the “horn.”4 Also, note how the magnitude of this horn diminishes with decreasing transmitter-receiver spacing for the four phase resistivity curves plotted. The different depths of investigation of the Resistivity tool are apparent in the varying degrees of anticipation of the formation top at ×256.5 meters. The deepest reading curve plotted in Figure 7, D-RES, “sees” the approaching bed first, followed by the M-RES, S-RES, and XRES curves respectively. Reference: 4. Anderson, B., Bonner, S., Luling, M.G., and Rosthal, R.: “Response of 2-MHz LWD Resistivity and Wireline Induction Tools in Dipping Beds and Laminated Formations,” paper A presented at the SPWLA 31st Annual Logging Symposium, Lafayette, Louisiana, U.S.A., June 24-27, 1990.

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43


Log example 7 North Sea Horizontal Well Phase Resistivities in Oil-Based Mud

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Triple Combo Log Example

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45


One of the customer log presentations is the triple-combo log. This log includes data from the gamma, resistivity, density, and neutron sensors on the same log. In Zone 1 of Figure 8, the bulk density decreases and the neutron porosity increases, both indicating an increase in porosity. The gamma ray moves from the shale baseline towards a less shaley formation. The resistivity decreases, indicating either a decrease in the resistivity of the pore fluids or an increase in porosity. A qualitative interpretation of this zone based on these curves is a porous wet zone. In Zone 2 the bulk density increases and the neutron porosity decreases, both indicating a decrease in porosity. The gamma ray moves from the shale baseline towards a less shaley formation. The resistivity increases, indicating either an increase in the resistivity of the pore fluids or a decrease in porosity. A qualitative interpretation of this zone based on these curves is a low porosity zone. In Zone 3 the bulk density decreases, indicating an increase in porosity, however, the neutron SS Porosity is showing a decrease in porosity. The gamma ray moves from the shale baseline towards a less shaley formation. The resistivity increases, indicating either an increase in the resistivity of the pore fluids or a decrease in porosity. The density-neutron cross-over is a typical response in a gas zone. It is caused by the differing effect of the gas’s decreased hydrogen content on the Neutron and Density sensors. The Neutron primarily measures the formation’s hydrogen content, whereas the Density measures the formation’s electron density. When a formation’s pore space fluid, such as water or oil, is replaced by gas there is a reduction in both the hydrogen content and the electron density. The Neutron responds to this reduction in hydrogen content by calculating a lower porosity, whereas the Density responds to the decreased electron density by calculating a higher porosity. This density-neutron crossover is a result of these responses. A qualitative interpretation of this zone based on these curves is a porous gas zone.

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LOG PRESENTATIONS & FORMATS

Log Heading • The log heading gives the log analyst a quick capsule of the well information • The heading is attached 90° to the rest of the log to give it a book appearance

#001

AES

1

Log Heading • The log heading contains the following data: • • • • • • • • •

Operator,Well, Field, Rig, State data Log Format and Vertical Scale Location and Depth Datum Well API # Latitude, Longitude, Magnetic Correction Data Borehole Record Casing Record Mud Record Service Company Equipment and Software Used

Bit Run Summary • • • •

Run Specific Data Mud Data Environmental Data Sensor Specific Data

2

Run Specific Data

Mud Data

3

Environmental Data

Sensor Specific Data

4

Disclaimer and Remarks • The disclaimer basically absolves the service company of any guilt for any losses the operator may incur in using the information contained in the log data

Disclaimer and Remarks • The remarks section contains a detailed description of specific log events • They are placed here because they would obscure the log traces if they are placed directly on the log

5

Bottomhole Assembly Diagrams • These diagrams show the configuration of the BHA from the bit through the logging sensors for each run • Useful for tracking the lengths and measure points for each of the logging sensors for each run

Main Log • The main log section contains the actual sensor data, commonly referred to as the “squiggly lines” • The data can be presented in many different formats depending on the customer’s requirements

6

Vertical Scale - Time Based

• The vertical scale divisions are in minutes per inch rather than feet per hour • Time scaling is usually reserved for drilling mechanics data (pressure, vibration)

Vertical Scale – Depth Based

• All formation evaluation sensor data is presented on a depth based vertical scale • Typical scaling is feet or meters per hour

7

Vertical Scaling – Measured Depth vs. True Vertical Depth Measured Depth

TVD

• Measured Depth is the actual length of hole drilled • True Vertical Depth is the projection of the Measured Depth into the Vertical plane • TVD is calculated using the measured depth and inclination data • Logs can be compared on a foot by foot basis when presented in TVD format (comparing “apples to apples”)

Vertical Scale Settings • The vertical scale is adjustable through software settings • In English depth units the scale is a ratio of inches of log paper to inches of log data • For example, a scale of “1:240” means that 240” (20’) of data will be compressed into 1” on the log plot • In Metric depth units the scale is a ratio of centimeters of log paper to centimeters of log data • For example, a scale of “1:1000” means that 1000 cm (10 m) of data will be compressed into 1 cm on the log plot

8

Vertical Scale – Correlation Log • A correlation log is used by the geologist to find particular formation events that can be used to compare to nearby well data • The most useful scaling for this type of log in English units is “1:1200” (1” per 100’) • The most useful scaling for this type of log in Metric units is “1:1000” (1 m per 100 m)

Vertical Scale – Detail Log • A detail log is used by the petrophysicist to find particular sensor data values that can be used to calculate formation parameters such as porosity, water saturation, etc. • The most useful scaling for this type of log in English units is “1:240” (5” per 100’) • The most useful scaling for this type of log in Metric units is “1:200” (5 m per 100 m)

9

Log Tracks • General log convention defines 6 tracks or areas that data will appear • Most log formats will only utilize tracks 1, 2, 3, and 5 (depth)

Track Formats – Horizontal Scaling • Tracks will be horizontally scaled in either LINEAR or LOGARITHMIC format • Linear format has 10 equal divisions across the track • For example, gamma ray data would be scaled from 10 to 110 units, left to right

LINEAR

10

Track Formats – Horizontal Scaling • Logarithmic format typically has 2-cycle logarithmic scaling across the track (track 4 is 4-cycle) • For example, resistivity data would be scaled from 0.2 to 20 units, left to right

LOGARITHMIC

Lithology Data – Track 1 • Track 1 contains sensor data that indicates lithology such as Gamma Ray, Rate of Penetration, Caliper, & Spontaneous Potential • Track 1 scaling is LINEAR in both correlation and detail formats

11

Resistivity Data – Track 2 Scales • Track 2 contains Resistivity data only • Track 2 scaling is LINEAR in correlation format and LOGARITHMIC in detail format

Porosity Data – Track 3 Scales • Track 3 contains sensor data that indicates porosity such as Neutron Porosity, Formation Density, and Acoustic • Track 3 scaling is LINEAR in both correlation and detail formats

12

Track 4 Scales • Track 4 is a combination of tracks 2 and 3 and is only used for special presentations • Generally will contain 4-cycle logarithmic scaling for resistivity data and linear scaling for porosity data • Track 4 is typically used for detail formats only

Track 5 • Track 5 contains depth labels at each of the major gridlines • Major gridline spacing is dictated by the vertical scaling

13

Linear-Linear-Linear Scaling

Linear – 2 cycle Logarithmic - Linear

14

Linear – 4 cycle Logarithmic

Log Annotations • Annotations provide critical information to the log analyst during evaluation • They help explain what was happening at the rigsite when the data was being obtained • Annotations should be used to refer the analyst to any remarks made on log header

15

Typical Presentations - Standard • Standard presentations typically include only basic sensor data such as gamma ray, resistivity, and rate of penetration data

Typical Presentations - Triple Combo • “Triple Combo” means that the log contains lithology, resistivity, and porosity data

16

Repeat Sections • Occasionally the geologist will request that a particular section of hole be relogged – a repeat section • All repeat sections should be well annotated and placed after the main log section • Some customers may want tie-in sections between bit runs to be provided as repeat sections

Calibration Data • Calibration/Verification data must accompany any log to validate the response of the sensors • Pre and Post run verifications are done to prove that the sensors were responding within tolerances during the bit run

17

Survey Reports and Plots • Survey Reports and Plots are typically provided on TVD plots only • The plots should include both Vertical and Horizontal views and should contain both planned and actual data

18

Downhole Hydraulics & System Pressure Loss

1

Role of Drilling Fluids

Hole cleaning – transport of cuttings Solids suspension Bit hydraulics – aid the bit in rock failure and chip removal. Lubricity – reduce torque and drag Control formation damage Hole stability Cooling the BHA 2

1

Hole Cleaning

More difficult to achieve as inclination increases <30° - rheology 30° - 60° - transition >60° - turbulent flow – high Q

3

Solids Suspension

Cuttings

High initial gels to keep cutting suspended when pumps are turned off

Weight material

Suspend barite – maintain uniform mud weight

4

2

Gel Strength

Is a function of a mud’s interparticle forces Gives an indication of the amount of gelation that will occur after circulation ceases and the fluid remains static for some time Should be adequate to suspend cuttings when drilling operations have been suspended for relatively long periods of time Optimum gel strength varies with the weight and viscosity of the mud and with the size of the cuttings in the drilling fluid 5

Plastic Viscosity

Is a function of the mechanical friction between the suspended particles and by the viscosity of the continuous liquid phase It is a function of the mud’s resistance to flow Determined with a rheometer by subtracting the 300 RPM reading from the 600 RPM reading 6

3

Yield Point

Measures the interparticle (attractive) forces within the mud It is also a function of the mud’s resistance to flow Determined with a rheometer by subtracting the Plastic Viscosity from the 300 RPM reading Yield Point is usually maintained equal to or greater than the Plastic Viscosity 7

Bit Hydraulics

Removal of cuttings from below bit Help to fail rock Traditional approach

Maximize Hydraulic Impact

Maximize Hydraulic Horsepower

• 48% of pressure available is at nozzles • 65% of pressure available is at nozzles

RARELY can we optimize bit hydraulics using traditional methods when using a motor! 8

4

Lubricity Reduce torque and drag Varies with fluid used OBM lowest Friction Factor WBM – some fluids are very slick

9

Formation Damage Use a drilling fluid that is compatible with Reservoir fluids Minimize fines

10

5

Hole Stability

Chemical inhibition

Shales can become unstable when exposed to water Solutions: • Use OBM • Potassium Sulphate mud

Tectonic Stresses – mountain building

Increase mud weight with increasing inclination

11

Cooling the BHA

Some wells can only be drilled by cooling the MWD & motor by circulating on trips

12

6

Optimum Hydraulics

Know equipment limitations Q – pumps / motor / MWD P – pumps / motor / MWD

Design to meet AV criteria Sacrifice Pbit to optimize Pmotor

The motor is doing the work. Ensure min Pbit is provided

13

Hydraulic Relationships Higher circulation pressure is required as: Flow Rate increases Flow Area decreases Flow Length increases Mud Density increases Mud Viscosity increases

14

7

Frictional Pressure Losses

Total pressure available is based on available standpipe pressure Pressure loss through all drillstring components and borehole annulus will equal the standpipe pressure Must have appropriate pressure loss below our tools to maximize pulse size (3500 kPa min (500 psi), 13,700 kPa max, (2000 psi)) 15

Pressure Balance Equation

PSP = ∆PDP + ∆PDC + ∆PMWD + ∆PCHOKE SUB + ∆PMOTOR + ∆PBIT + ∆PANNULUS + ∆PSURFACE EQUIPMENT

Surface equipment losses are typically 5 to 10% (we will assume 100% volumetric efficiency however) Annulus losses typically less than 700 kPa (100 psi) 16

8

“Commander” Motor Pressure Drops Motor Size ∆Pmotor 4 ¾” 2000 kPa 6 ¼” 1500 kPa 6 ½” 1200 kPa 6 ¾” & up 1000 kPa 1 psi = 6.895 kPa

(290 (215 (175 (145

psi) psi) psi) psi)

17

Slide Rule Example Drillpipe: Drill Collars: Hole Diameter: Mud Pumps : Mud Weight: Plastic Viscosity: ∆PMOTOR: ∆PMWD: ∆PANNULUS: ∆PSTANDPIPE MAX: Assume:

900 m of 88.9 mm O.D., 19.8 kg/m, I.F. connection drillpipe 300 m of 57 mm I.D. drill collars 152 mm Triplex, 230 mm stroke, 152 mm liner, pump speed = 60 spm 1300 kg/m3 20 cp 3000 kPa 700 kPa 500 kPa 15,000 kPa No choke sub, 100% volumetric efficiency in surface equipment

Question:

What 3-nozzle configuration will utilize the available pressure loss at the bit if the standpipe is run at maximum?

18

9

Slide Rule Example Drillpipe: Drill Collars: Hole Diameter: Mud Pumps : Mud Weight: Plastic Viscosity: ∆PMOTOR: ∆PMWD: ∆PANNULUS: ∆PSTANDPIPE MAX: Assume:

3000’ of 3.5” O.D., 13.3 #/ft, I.F. connection drillpipe 900’ of 2.25 “I.D. drill collars 6” Triplex, 9” stroke, 6” liner, pump speed = 60 spm 13 ppg 20 cp 435 psi 100 psi 75 psi 2200 psi No choke sub, 100% volumetric efficiency in surface equipment

Question:

What 3-nozzle configuration will utilize the available pressure loss at the bit if the standpipe is run at maximum?

19

Slide Rule Example Answer Index Number = 123 (117 I) Drillpipe Loss = 690 kPa/300 m 2070 kPa Drill Collar Loss = 1875 kPa/300 m 1875 kPa Available at Bit = 6855 kPa TFA = 127 mm (2 x 7.1 & 1 x 7.9) 20

10

Slide Rule Example Answer Index Number = 117 Drillpipe Loss = 116 psi/1000’ 348 psi Drill Collar Loss = 311 psi/1000’ 280 psi Available at Bit = 962 psi TFA = 0.22 in2 (3 x 10’s) 21

Slide Rule Example (con’t) What is the annular velocity around the drillpipe in the open-hole section? Open-hole diameter = 152 mm Drillpipe O.D. = 88.9 mm Flow Rate = 0.75 m3/min 22

11

Slide Rule Example Answer Hole I.D. plus Drillpipe O.D.= 241 mm Hole I.D. minus Drillpipe O.D.= 63 mm At 0.75 m3/m flow rate,

Annular Velocity = 62.5 m/min 23

12

Factors Affecting Mud Pulse Amplitude • Measured Depth • Pressure Loss • Mud Properties

1

Measured Depth • Every 1500 m of travel through the drillstring the pulse loses approximately HALF of its amplitude • Major cause of amplitude loss

2

1

Pressure Loss • Negative Pulse – maximize pressure loss below the valve to generate the largest amplitude pulse • Positive Pulse - maximize pressure loss above the valve to generate the largest amplitude pulse

3

Positive Pulse System • The positive pulse system uses a downhole device to restrict the flow of mud through the drillstring • This causes an increase in the standpipe pressure • To transmit data to the surface, this device creates a series of pulses that are detected by the surface transducer and decoded by the surface computer. 4

2

Negative Pulse System • The negative pulse system uses a downhole device to release a small volume of mud into the annulus • This causes a decrease in standpipe pressure • To transmit data to the surface, this device creates a series of pulses that are detected by the surface transducer and decoded by the surface computer. 5

Continuous Wave System • •

•

•

Unlike the two previous methods, no distinct pulses are generated in the continuous wave system The downhole system creates a regular and continuous variation in pressure that is essentially a standing wave To transmit data, the phase of the standing wave is altered. The surface equipment detects these phase shifts in the pressure signal This system offers a higher data rate than the two previous systems, but the complexity of both the downhole and surface components has limited its wider use. 6

3

Factors Affecting Pressure Loss • • • • • • •

Flow Rate Bit and Choke Sub nozzle flow area Available Standpipe Pressure Washout in BHA Plugged Drillpipe Screen Mud Motor Stalling Valve Oriented Lowside 7

Mud Properties • Mud Weight - as mud weight increases, pulse amplitude increases • Mud Viscosity – as mud viscosity increases, pulse amplitude decreases • Lost Circulation Material (LCM) – as LCM content increases, pulse amplitude decreases (same concept as viscosity increase) 8

4

Factors Affecting Mud Pulse Detection • Loss of pulse amplitude (as previously discussed) • Pressure Transducer – placement, failure, plugged • Poor Signal to Noise Ratio

9

Pressure Transducer Placement • Put transducer where it can detect the pulse as soon as possible (top of standpipe) • Make sure it is along the flow path of the pulse • Sometimes placing the transducer at the pumps produces better detection on some rigs 10

5

Failed Pressure Transducer • Check voltages at unit to verify transducer operating properly • Rig up back-up transducer in case of primary transducer failure • Symptom is “flatline” response from transducer output

11

Plugged Pressure Transducer • Decrease or loss of pulse amplitude • More possible after long periods of nonflow or extremely cold temperatures

12

6

Poor Signal to Noise Ratio • Surface Noise Events • Downhole Noise Events • Improper Detection Parameter Settings

13

Surface Noise Events • • • • • • •

Mud Pumps Insufficient Pulsation Dampener Pre-Charge Partially Open/Closed Valves Pipe I.D. Changes Flowline Material Changes (metal to rubber) Tees, Elbows, Dead-Ends Drillcrew noise (air hammers, sand blasters, etc.) 14

7

Downhole Noise Events • Drillstring Vibration – Bit Bounce, Stabilizer Rubbing, Stick-Slip • Formation Changes • Mud Motor Bearing Failure

15

Improper Detection Parameter Settings • Detection Threshold set too low (decreases signal to noise ratio) • Detection Threshold set too high (pulse never crosses threshold)

16

8

Signal to Noise Ratio (at surface) • Less than 1.0 • 1.0 to 2.0 • Greater than 2.0

0 – 10% detection 80 – 90% detection 90 – 100% detection

17

Detection Troubleshooting • The drilling fluid system introduces noise during pump operation which can make MWD surface equipment struggle to decode the tool signal from downhole • The mud column is the mud pulse MWD tool communication line to the surface. Keeping this system clean, uniform and as free as possible of induced noise can greatly improve the quality of the MWD job. 18

9

Detection Troubleshooting • Make sure the pump liners are in good condition • Damaged liners cause so much noise they may even have an identifiable signature on the surface pressure record

19

Detection Troubleshooting • Keep the pulsation dampeners charged to approximately 40% of standpipe pressure • The ideal mud flow would be at constant pressure, the only changes in system pressure being those of the MWD pulser. Properly charged dampeners go a long way towards this ideal condition. 20

10

Detection Troubleshooting • Maintain as constant weight on bit as possible, particularly when drilling with mud motors • Changes in motor torque will themselves cause changes in standpipe pressure. By keeping these to a minimum, reliability of signal decoding will be improved. 21

Detection Troubleshooting • Mud additives should be mixed as uniformly as possible • Changes in viscosity and suspended solids concentration can attenuate the MWD signal more than usual • Slugged additives can also clog the tools.

22

11

Detection Troubleshooting • Avoid duplex mud pumps if possible • Duplex pumps generate noise events at both even and odd harmonics of the primary frequency • For example, a 0.5 hertz primary pump frequency (30 spm) will generate noise events at 0.5 hz, 1.0 hz, 1.5 hz …..and so on • Fortunately, each successive harmonic is of lower amplitude than the previous • Triplex pumps generate noise events at odd harmonics only 23

12



HOW TO DETERMINE MUD PULSE & EM TOOLFACE OFFSETS

NEGATIVE PULSE OFFSET TOOL FACE OFFSET TOOL FACE (OTF) SHEET This sheet is possibly the most important form that must be filled out correctly. All other work and activity performed by the MWD Operator means naught if the well must be plugged back with cement because of an incorrect OTF calculation (or the correct OTF not being entered into the TLW 2.12 software). Ensure that the OTF calculation is correct, entered into TLW 2.12 correctly and verified by the Directional Driller. The procedure for measuring the OTF is as follows: 1. Measure in a clockwise direction the distance from the MWD high side scribe to the motor high side scribe. Record this length into the OTF work sheet as the OTF distance. In the following example, this value is 351 mm. 2. Measure the circumference of the tubular at the same location where the OTF distance is being measured. Record this length into the OTF work sheet as the Circumference of Collar. 3. Calculate the OTF angle using the following formula: OTF Angle=

x 360 OTF Distance Collar Cirumference

From the above example, if the collar circumference is 500 mm, OTF Angle= (351/500) x 360 = 0.702 x 360 = 252.72o A sample form is as follows:

NEGATIVE PULSE OFFSET TOOL FACE (O.T.F. MEASUREMENT) Well Name:

Enter in the Well Name here

Date: Enter in date OTF taken

LSD: Enter in the LSD here

Time: Enter in time OTF taken

Job #: Enter in the MWD job number here

Run #: Enter in the run number

TOP VIEW OF MWD

MWD SCRIBE PROPER DIRECTION OF OTF

MEASUREMENT

MOTOR SCRIBE (HIGH SIDE) O.T.F. Distance (Anchor Bolts to Collar Scribe):

351 mm

Circumference of Collar:

500 mm

O.T.F. Angle (Distance / Circumference) x 360:

252.72 degrees

O.T.F Angle entered into Computer as:

252.72 degrees

O.T.F. Distance measured by:

Both MWD Operator Names

O.T.F. Calculated by:


O.T.F Entered into computer by:


O.T.F. Measurement and calculation Witnessed by: Name(s)

Directional Driller(s)

NEGATIVE PULSE OFFSET TOOL FACE

252.72

POSITIVE PULSE Toolface Offset INTERNAL TOOL FACE OFFSET (TFO) SHEET Note: For the positive pulse MWD, the OTF is zero. Ensure that a zero OTF has been entered into TLW 2.12. The positive Tool Face Offset (TFO) sheet entries are as follows: 1. Positive Pulse Pulser Set to High Side / Directional Driller: Enter the names of the MWD Operator and Directional Driller respectively. 2.Positive Pulse T.F.O. from PROGTM: Enter the T.F.O. value reported from the high side tool face calibration from TLW 2.12. TFO internal toolface offset

POSITIVE PULSE T.F.O. MEASUREMENT Well Name:

Enter in the Well Name here

Date: Enter in date OTF taken

LSD: Enter in the LSD here taken

Time: Enter in time OTF

Job #: Enter in the MWD job number here number

Run #: Enter in the run

ROTATE PULSER TO HIGH SIDE PULSER KEY WAY

PROPER DIRECTION OF TFO

MEASUREMENT

DAS HIGH SIDE TAB Positive Pulse Pulser Set to High Side:

Name of MWD hand

Directional Driller:

Name of Directional hand

Witness Witness

Positive Pulse T.F.O. from PROGTM:

163.25 degrees

Gravity Tool Face (gtface) Should Equal Zero:

0.00

Motor Adjustment:

2.12 / G degrees/setting

degrees

Alignment of Mule Shoe Sleeve Key to Motor Scribe: Name of 2nd MWD hand Witness O.T.F.=0, Entered into Computer by: All Calculations Witnessed by: Driller

Name of MWD hand Signature of Directional

MWD - Positive Pulse OTF – External Drill Collar Offset Magnetic Declination Toolface switch over

EM MWD Toolface Offset Magnetic Declination

The “Bearing Display” GEOGRAPHIC radio button must be selected for the Declination value to be applied (by the surface software) to the transmitted magnetic hole direction.

Toolface Offset

Zero tool face offset G4 – this is the internal offset for the CDS probe; this value must always be entered as a NEGATIVE number from 0 to –360; this value is applied by the surface software. Tool face offset DC – this is the external (drill collar) offset; must be measured clockwise (looking toward bit) from the muleshoe boltholes to the mud motor scribeline (if using a stinger). For slimhole, measure from the CSGx locking bolts to the mud motor scribeline. When using a bipod measure from the tool carrier scribeline to the mud motor scribeline.

The main page software display can be checked to verify that the appropriate declination and toolface offset are being applied to the transmitted data.

Toolface Offset Summary

Mud Pulse System

Internal Offset

External Offset

Negative Pulse

Positive Pulse

None

Directional Probe (DAS)

DAS highside is mechanically oriented to align with pulser anchor bolts

Determine offset as per procedure and PROGTM into the DAS

Surface Software

Surface Software

Measure clockwise from anchor bolts to motor

Typical: Muleshoe sleeve is aligned with motor scribeline, therefore offset = 0°

0° to +360° values permitted Optional: If muleshoe sleeve is not aligned with motor scribeline, calculate offset as per procedure 0° to +360° values permitted

EM System

Electromagnetic Telemetry Surface Software

Internal Offset

Determine offset as per procedure and always enter value as a NEGATIVE number. (Zero toolface offset G4, “Job Data” screen) 0° to -360° values permitted

Surface Software Bipod: Measure clockwise from the tool carrier key to the mud motor scribeline. 0° to +360° values permitted. External Offset

Stinger: Measure clockwise from muleshoe boltholes to mud motor scibeline. 0° to +360° values permitted. Slimhole: With CSGx module, measure clockwise from the CSGx locking bolt to mud motor scribeline. 0° to +360° values permitted.

MWD OPERATIONS

Computalog

Computalog

Strip Chart Recorder (SCR) • The SCR is used to record incoming pulses on paper for troubleshooting purposes

1

Surface PC Backplane

• The surface PC provides the interface between the CID and the DAS

Computalog Interface Display (CID) •The CID receives pressure transducer inputs and decodes them before sending to the PC •Allows communication with the DAS on the surface •Sends messages to the RFD •Sends voltage output to the SCR •LED display showing surface sensor output

2

Systems Test Unit (STU) • The STU allows the operator to simulate real-time pulsing and to test the integrity of the the toolstring components

Setting the Compression Sleeve Gap •The compression sleeve gauge is used to set the proper compression between the connectors in the toolstring components •The compression should be set to 1/8”

3

Tandem Sub, O-rings, & Backups ÅPressure

• The tandem sub acts as an “electronic” crossover between the toolstring components • Backup rings should always be placed between the source of pressure and the o-ring • Backup rings keep the o-ring from extruding out of the o-ring groove under high pressure and temperature

Assembling the Components • Offset the HS “Fat” Tab and the HS Slot slightly when pushing the modules together • When they meet, rotate the modules until the tab slips into the slot • The “click” is the sound of the two, spring-loaded connectors inside the modules coming together

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Fastening Tandems • Once the modules have been connected, they should be secured with tool pins (nails)

Fastening Tandems • Once the nail has been countersunk with a punch, a rubber grommet and a tandem screw are inserted into the tandem sub hole

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Fuse Packs • The negative pulse fuse pack is single-sided; it has a 4-pin connector on ones side and is sealed with silicone on the other • The positive pulse fuse pack has a 6-pin connector on one side and a 2-pin connector on the other; the 6 –pin connector goes toward the tool

Fuse Pack Taping • The fuse pack should be secured to the module using high temperature Kapton tape

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TFO Procedure

• The pulser stinger keyway should be rotated to the highside position prior to determining the toolface offset

Installing the Poppet on the Positive Pulser • With a calibrated torque wrench and a crescent wrench (as backup), apply 40 ft-lb of torque to the poppet

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Pressure Transducer • Detects pulses at the standpipe that are generated by the downhole pulser • Works on a 4 – 20 mA current loop; 4 mA equals 0 psi, 20 mA equals 5000 psi

Muleshoe Sleeve Muleshoe Sleeve

• A muleshoe sleeve and muleshoe sub are used in the positive pulse configuration to align the highside of he DAS with the bend in the motor

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Anchoring the Muleshoe Sleeve • Once the sleeve and motor are aligned, the sleeve is fixed into place with muleshoe bolts • The bolts are torqued to 150 ft-lbs

Fractional Life Remaining (FLR) FLR = 1 - (PI – PU) + PU PF1 PF2 FLR = fractional life remaining PI = plugged in hours PU= pressured up hours PF1 = power factor 1 (for NP 400, for PP 350) PF2 = power factor 2 (for NP Dir 140, NP Gamma 125, PP 110)

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DOWNHOLE SOFTWARE OPERATIONS

Computalog

Computalog

SELFTEST (DAS & CID) • Command causes the following actions: – – – – – –

ROM checksum RAM pattern test EEPROM test Peripherals test Re-initialization of RAM from EEPROM or ROM Software re-initialization (resetting stack and queue pointers, etc.)

• The CID and DAS will perform a selftest on power up.

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USERID (DAS & CID) • Allows the user of the device to change his security level within that device by entering a password • Each security level one through five is associated with a unique password • Default is 1 • Level 3 password is “goatchow”; allows operator to change programming variables • Current user level can be interrogated with the USERLEV command

FLOWDET (DAS) • The pressure sensor output is sampled at 100 Hz • Two averages are updated in real-time from these samples, a long term average and a short term average • When mud flow goes from off to on, the output of the short term average will increase more rapidly than that of the long term average. As soon as the short term average exceeds the long term average by a threshold value, flow is set to on. It works in vice-versa also • Parameters are always “2, 10, 5000, 5000”

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INVSENS (DAS) • Informs the DAS if the sensor is mounted inverse to normal conventions in the drillstring • When set to “1” the DAS inverts the signs of the Y and Z axes • “0” for negative pulse, “1” for positive pulse

POWERCON (DAS) • DAS sensor power control switch, which is used to control the sensor power when not acquiring data • If set to “1”, the sensor is powered continuously • If set to “0”, the processor will turn sensor power off between acquire data commands in order to conserve power

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PSTRETCH (DAS) • DAS mud bus pulse stretch time in mud bus samples • Due to mechanical rise and decay times, the pressure pulse produced by the pulser valve may be of longer duration than the electrical pulse sent to open and close the valve • The electrical pulse sent to the pulser is therefore made to be Pwidth – Pstretch samples long in order to produce a pressure pulse approximately pwidth samples long • 12 for negative pulse, 18 for positive pulse

RSMASK (DAS) • DAS rotation sensing switch, which controls whether rotation sensing is performed • If RSMASK is enabled and the DAS senses rotation, it will disable transmission of toolface data • “0” for Gamma, “1” for Directional

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SERNUM (DAS) • Reads the 4-digit DAS serial number

SWTFLIM (DAS) • The values used in determining whether gravitational or magnetic toolface is transmitted over the mud bus • The first power on will default to magnetic toolface if the inclination is between the limits • Default limits are 28, 30 which are 2.8° and 3.0°

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NCCBS (DAS) • Control Blocks which dictate what data items will be transmitted by the DAS • “7” for Directional, “8” for Gamma

NFCBS (DAS) • Control Blocks which dictate the type of survey data that will be transmitted by the DAS • “3” for raw directional data • “4” for raw directional data and gamma • “7” for calculated survey data

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TFO (DAS) • Reports the internal toolface offset value in the DAS

RSTLOG (DAS) • Resets the logging memory pointer to the top so that all 8192 bytes are available for new log data • Once this command is issued, previous data stored in the logging memory is lost

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SETTIME (DAS) • • • •

Allows the operator to adjust the DAS time Current time format in the DAS YY:MM:DD:HH:MN:SS For example, SETTIME 02:03:06:13:13:13 for March 6, 2002 at 13:13:13

GETTIME (DAS) • Same format as SETTIME • Allow the operator to view the DAS time

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UNLOCKTM (CID) • Allows modification of the mud bus telemetry parameters after a PROGTM command has been sent to the CID • The user should be aware that unlocking and modifying the telemetry parameters during downhole operations will result in lost communications with the downhole DAS.

DATARATE (CID)

• An integer between 1 and 5 inclusive which selects the mud bus pulse width from the data rate versus pulse width table.

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MEASSYNC (CID) • The delay in seconds between the time that the CID detects flow on and the time that the CID detects sync • Mud parameters can affect how long it takes the pulse to travel from pulser to surface • This value affects how the parameters SYNCDEL and SYNCSIZE are set

SYNCDEL & SYNCSIZE (CID) • Tells the CID how long to delay from pumps on before it should look for the first sync pulse • The sync window (SYNCSIZE) is centered about the sync delay • During the sync window the CID looks for the sync signature sent from the DAS over the mud bus. • Both parameters are set based on the MEASSYNC value • SYNCDEL will typically need to be increased as the well gets deeper • SYNCSIZE will typically need to be decreased as the well gets deeper

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Relationship between Meassync, Syncdel, & Syncsize Syncdel

Voltage

Syncsize

Meassync Time

NUMCCBS (CID) • Control Block definitions which tell the CID what transmitted data items to expect from the DAS • “7” for Directional, “8” for Gamma • If the DAS and CID are not in sync with each other (NCCBS and NUMCCBS the same) then no data will be processed by the surface system

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NUMFCBS (CID) • Control Block definitions which tell the CID what type of survey data will be transmitted by the DAS • “3” for raw directional data • “4” for raw directional data and gamma • “7” for calculated survey data • If the DAS and CID are not in sync with each other (NFCBS and NUMFCBS the same) then no data will be processed by the surface system

PULSEPOL (CID) • Lets the surface system know how the raw directional data is being encoded by the DAS • When in a positive pulse configuration the DAS is run upside down; it inverts the signs of the Y and Z axes before transmission • “0” for positive pulse, “1” for negative pulse

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SIGTHR (CID) • “Signal Threshold” parameter tells the detection software what voltage level to start triggering pulse detection • The incoming signal (as a voltage) must cross above the threshold to be considered as a pulse • Set this value such that the mud pulse signal crosses the threshold but the background noise does not

AVNOISE (CID) • Displays the average strength of the noise component of the incoming transducer signal • Allows the operator to adjust the SIGTHR parameter to achieve better detection

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PROGTM (CID) • Sends the mud bus telemetry parameters from the CID to the DAS over the bus and prohibits further modification of those parameters until an UNLOCKTM command is given • If the user modifies any of these parameters while they are unlocked and then fails to send a PROGTM to the DAS, mud bus communication failure may occur as soon as an attempt is made to use the DAS downhole • Communication failure is indicated by a CSTAT1 message when flow is turned on. • Result of PROGTM is 0=successful, 1=unsuccessful

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MWD and Basic Directional Drilling

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