04 directional
TRANSCRIPT
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Trajectory Designand
Directional Drilling
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Directional Drilling
• What is Directional Drilling?
“Intentional, controlled deflection of a wellbore to intersect pre-determined targets.”
• Topics:– Terminology– Drivers for directional drilling– Directional tools and techniques– Measuring trajectories – Calculations– Potential problems
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Trajectory Components
True
Ver
tical
Dep
th
Horizontal Departure
Kickoff Point (KOP)
Tangent
Lateral
2nd Kick
off Point
Build Section
2nd Build Section
Measured Depth
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Trajectory Measurements
Inclination: the measure in degrees of the angle of the wellbore from vertical
Azimuth: the measure of the direction of the wellbore in:
45°
0° / 360°
90°
180°
270°
45° = N 45°E
200° = S20°W155° = S25°E
295° = N65°W
(1) degrees from North between 0° and 360°, or
(2) degrees from North or South to the East or West
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Drivers for Directional Drilling• Access to remote reservoirs from a central
platform, template, or pad.– Avoid or defer capital expenditures – fewer
platforms, fewer subsea installations– Monetize otherwise uneconomic reserves –
offshore reserves from onshore facilities• Access to otherwise inaccessible reserves.
– Environmental restrictions– Other exclusions, e.g. lakes, cities, shipping lanes
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Directional Drilling Applications
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Industry Directional Capabilities
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Potentially high contact force in build (torque, casing wear)
Simple; Long reaches achievable Low tangent angle
Build and hold: Constant BR to tangent angle, hold constant tangent angle
Limited intervention and stimulation scenarios
Increased exposure to reservoir, reduced drawdown, fewer surface facilities
Multi-Lateral: branched well bores from mother bore through various junction styles
More curvature means more torque and drag, limited reach
Flexibility to handle anti-collision and multiple target requirements
3-D: Any of the above with significant azimuth changes
Theoretical benefits not cost-effective in implementation; Limited reach
Lowest contact force (torque, casing wear) of any trajectory
Catenary: Continuously increasing build rate (BR) with depth, no tangent
High tangent angleMuch longer reach than catenary; Lower torque/drag
Multiple build: BR increases with depth in several discrete steps to tangent angle, hold constant tangent angle
Higher tangent angle for given reach; Potentially high contact force in build (torque, casing wear)
Allows lower angle reservoir entry, possibly easier intervention
S-shaped: Includes angle drop section
Requires deep steering; High angle in second tangent
Very long reaches possible with lower contact forces in upper build
Double build: Build-hold-build-hold trajectory, can use two different BRs in curves.
High tangent angle; Reduced reach
Lower contact force in build sectionUndersection: Build and hold with deep KOP
DisadvantagesAdvantagesOption
Trajectory Options
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Trajectory Options
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Trajectory Design Criteria
• Targets
• Drillability
• Cost
• Intervention
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Trajectory Design Criteria• Targets
– Specifications• Horizontal departure• Size• Shape• Orientation
– Stacked targets– Natural Drift Predictability
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Horizontal Departure
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Stacked Targets
Final tangent angle may vary widely depending upon Horizontal Departure required to reach targets.
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Walk Tendencies
Angle Building• Normal Force into the high
side of the hole = ↑ Inclination• With RH rotation of bit, walk
tendency is to the left.
Angle Dropping• Normal Force into the low
side of the hole = ↓ Inclination• With RH rotation of bit, walk
tendency is to the right.
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Natural Drift
• As directional tendencies become known for local combinations of:
FormationsBitsBHAs
• Rig locations can be optimized to minimize expensive directional control techniques in favor of natural drift.
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Trajectory Design Criteria• Drillability
– Normal force • Curvature + Tension = Normal Force• Torque / drag: ↑ normal force = ↑ torque / drag• Casing / drill string wear: ↑ normal force = ↑ wear rates
– Wellbore stability• Orientation of wellbore in the in-situ tectonic stress field will
effect stresses, and therefore, stability of wellbore wall.– Hole Cleaning
• Cuttings transport efficiency affected by hole inclination– Anti-collision
• Constraints imposed by nearby wellbores
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Trajectory Design Criteria• Cost
– Tool selection• Availability• Familiarity / Support• Track record• Logistics
– Cost-effectiveness• Cost (including Lost in Hole charges)• Time• Efficiency• Impact on other drilling systems
– Failure likelihood• Failure modes – trip or fish• Recovery plans – back up plan
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Trajectory Design Criteria• Intervention
– Wireline– Coiled Tubing
• Critical Angle (α)– Ability of tools to slide under their own
weight without being pushed from above– α = Tan-1(1/µ)– Function of Coefficient of Friction (µ)– Ex. Where µ=0.2, α= 78.7°
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Achieving Directional Control• Two Primary Approaches:
– Push the bit: side force > side cutting– Point the bit: bit tilt
• Push the bit– Traditional rotary BHAs– Bent sub motor assemblies– Rotary steerable – BHI Autotrak /
Schlumberger Powerdrive• Point the Bit
– Bent housing motor BHAs– Rotary steerable – Halliburton GeoPilot
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Bit Side Force• All BHAs cause a side force at the bit • This side force may make the bit
– build angle– hold angle– drop angle– turn right– turn left
• The key is to control the direction and magnitude of the force.
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Rotary BHA Configurations90 ft 30 ft
60 ft 30 ft
45 ft 30 ft
10-20 ft30 ft 30 ft
30 ft 30 ft
UG
10-20 ft
30 ft 30 ft30 ft
45 ft 30 ft
90 ft 30 ft
60 ft 30 ft
60-90 ft 30 ft
UG
UG - UndergaugeStabilizer Optional Stabilizer
Strong angle building tendency
Moderate angle building tendency
Slight angle building tendency
Strong holding tendency (little incl. and azim. change)shorter stab. spacing gives better holding capability
Moderate holding tendency - highly UG 2nd stab. may provide some building tendency
Slight holding tendency - formation tendencies to build or drop angle often overpower this assembly
Strongest angle dropping tendency
Weakest angle dropping tendency
(Optional stabs. make behavior more predictableand increase dropping tendencies)
UG near-bit stab. may moderate dropping tendency
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Directional Motor BHA Configurations
ADJ - AdjustableStabilizer Optional Stabilizer
Simple motor with bent sub - prior to 1980higher side load and less bit tilt - sliding mode only
Bent housing motor - early ‘80’s higher bit tilt and less side load - sliding mode only
Bent housing motor with bent sub above - lower deflections allowed string rotation and “steerability”
Adjustable bent housing deflection angle (some downhole adjustable)
Downhole adjustable stabilizer allows 2-D steerability (inclination only) in rotary mode (e.g. TRACS)
Rotary steerable tools allow downhole 3-D (inclination and azimuth) steerability in rotary mode (e.g. Autotrack)
BSmotor
DTU motor
BH motor
AKO motor
BH motorBS
RST
Double tilted u-joint motor - mid ‘80’s very high bit tilt - limited string rotation
ADJ
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Rotary Steerable Systems
• Push-the-bit– BakerHughes INTEQ Autotrak– Schlumberger Powerdrive
• Oversize hole can reduce build rate
High Side
Orientation
MagnitudeBit Side Force
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Rotary Steerable Systems
• Point-the-bit– Halliburton SperrySun Geopilot
• Pair of eccentric rings • Controls orientation and magnitude of deflection
Zero deflection
Maximum deflection
Intermediatedeflection
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• Measurement Types:• Inclination Only• Inclination and Azimuth• Single Shot• Multi-Shot
• Tool Types:• Gravity• Magnetic• Gyroscopic
• Deployment Mechanisms:• Wireline• MWD – telemetry or memory• Pipe - conveyed• Dropped
• Measurement Errors• Position Uncertainty
• Collision Avoidance
Trajectory Measurement - Surveying
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Magnetic Instrument
1. Pendulum2. Circular Glass3. Compass4. Pressure equalization5. Cover glass
Inclination = 5°Direction = N 45°E or Azimuth = 45°
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Raw Reading:Inclin. = 5.5°
Dir. = N35°W
Must be corrected for Declination
Magnetic Instrument Film
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• Inertial effects keep it pointing in the same direction.• Not affected by the earth’s magnetic field, or by steel in the wellbore• Single shot or multi-shot tools available
Typical Gyroscope
Outer Gimbal
Inner Gimbal(Spin Motor)
Spin Axis
Inner Gimbal Axis
Outer Gimbal Axis
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Sources of Survey Errors
• Instrument measurement limitations• Depth Error• North Reference Error • Magnetic Interference • Gyro Drift Errors• Instrument Alignment Errors
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Magnetic Declination• Declination is the angle a freely turning magnetic
needle makes with the imaginary line pointing to True North.
True North
MagneticNorth
Declination Angle
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Magnetic Declination Correction
+
-+
-+
- +
-
West Declination(Subtract from Azimuth)
East Declination(Add to Azimuth)
BUT, when using oilfield direction nomenclature, declination must be added or subtracted from the magnetic compass reading, depending upon whether
it is East or West declination and in what quadrant the raw heading lies.
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Magnetic Declination Correction
ExampleDeclination = 5o WestMAGNETIC READING= S65oE = 115o Magnetic
Corrected Azimuth = 115o - 5o = 110o True
True North
MagneticNorth
115o
65o
110o
5o
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Magnetic Declination Correction
203°200°S23°WS20°W168°165°S12°ES15°E293°290°N67°WN70°W38°35°N 38°EN 35°E
CorrectedAzimuthCorrectedDirection
+
-+
-
West Declination(Subtract from Azimuth)
East Declination(Add to Azimuth)
35° = N 35°E
3° East Declination Corrects CW:
290° = N70°W
165° = S15°E200° = S20°W
+
- +
-35° = N 35°E
290° = N70°W
165° = S15°E200° = S20°W
3° West Declination Corrects CCW:
197°200°S17°WS20°W162°165°S18°ES15°E287°290°N73°WN70°W32°35°N 32°EN 35°E
CorrectedAzimuthCorrectedDirection
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Isogonic chart for the U.S.
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Isogonic: lines of equal magnetic declination
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Isogonic Chart for the World (2000)
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Measures may change a few minutes per year.
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Earth’s
Magneti
c
Field Lines
Steel Colla
r
Bit Sub
Compass Interference Field Lines
Magnetic Interference.
Non-magnetic Collar
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• Field intensity varies geographically. • Length of the nonmagnetic drill collars required in a BHA will vary
(1) from area to area and (2) as wellbore inclination & azimuth vary.
Earth’s Magnetic Field Intensity
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Direction Angle from magnetic N or S
Incl
inat
i on
Thailand is inZone I
Directional Plan:Azim: N40°WIncl: 55°
Required Length of Non-Mag DC:43 ft
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Direction Angle from magnetic N or S
Incl
inat
i on
UK is in Zone II
Directional Plan:Azim: N40°WIncl: 55°
Required Length of Non-Mag DC:60 ft
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Incl
inat
i on
Direction Angle from magnetic N or S
North Slope is inZone III
Directional Plan:Azim: N40°WIncl: 55°
Required Length of Non-Mag DC:60 ft
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Wellbore Position Uncertainty
• Uncertainty in surveys results in uncertainty in wellbore position.
• Common to have higher magnitude of uncertainty in azimuth orientation (L-R) than inclination orientation.
• Calculated uncertainty shows boundaries of EoUs.
• EoU Separation guidelines should be agreed beforehand
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Ellipse of Uncertainty Separation
• EoU’s should never overlap• EoU Separation guidelines
should be agreed beforehand
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“Christmas Tree”of Survey Errors
• Magnetic surveys like EMS and MWD typically have larger errors, and therefore larger EoUs.
• Gyro surveys at casing points reduce the errors and provide smaller EoUs.
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Position Errors by Survey Tool Type
After SPE 56702 / 67616 - 1999
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Calculate position of the wellbore based upon survey dataPosition: TVD
N-S / E-W departure (Rectangular Coordinates)Closure: Drift (HD) and Direction (Azimuth) (Polar Coordinates)
Survey Data at each survey station:Measured Depth (MD)InclinationAzimuth
Calculation Methods:Minimum Curvature Radius of CurvatureMany others…
Dogleg Severity (DLS) – Total rate of curvature (°/100 ft or °/30m)
Survey Calculations
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Arc Length to Angle Change Relationship
Length of arc of circle (S)Radius of Curvature (R)Angle Change (α)
∆S = R∆α
Smaller Radius
Larger Radius
r
r
R
R
α1
α2
S1
S2
NOTE: All angles in radians
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Survey Calculation Methods
• Minimum Curvature• Radius of Curvature• Tangential• Balanced Tangential (Acceleration Method)• Trapezoidal (Vector Averaging)• Average Angle• Mercury (Combined Method)• Simpson’s Rule Method
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Minimum Curvature Method
• This method assumes that the wellbore follows the smoothest possible circular arc from one survey station to the next.
• Knowns: Location of first survey point, ∆MD between surveys, and inclination and azimuth at both survey points.
Ref: API Bulletin D20 (1985)
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Minimum Curvature Method
P
r
O
r
RDL
Q
DL2
S
PQR ArcSRPSRF +
=
( )DLr2
DLtanr2
DLtanr
+
=
2DLtan
DL2RF =
))A-(Acos1(IsinIsin)I(Icos(DL) cos 122112 −−−=
NOTE: All angles in radians
RF = Ratio FactorDL = Dogleg Angle
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[ ]
[ ]
[ ] RF)cos(I)cos(I2
∆MD∆Vert
RF)sin(A)sin(I)sin(A)sin(I2
∆MD∆East
RF)cos(A)sin(I)cos(A)sin(I2
∆MD∆North
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2211
2211
•+=
••+•=
••+•=
Minimum Curvature Method - Equations
2DLtan
DL2RF =
))A-(Acos1(IsinIsin)I(Icos(DL) cos 122112 −−−=
Ref: API Bulletin D20 (1985)
Where:
NOTE: All angles in radians
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Radius of Curvature Method
• This method assumes the wellbore follows a smooth, spherical arc between survey points and passes through the measured angles at both ends. (tangent to inclination and azimuth at both survey points).
• Knowns: Location of first survey point, ∆MD between surveys, and inclination and azimuth at both survey points.
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Radius of Curvature Method - Equations
[ ] [ ]
[ ] [ ]
[ ])I(I
)sin(I)sin(I∆MD∆Vert
)A(A)I(I)cos(A)cos(A)cos(I)cos(I∆MD∆East
)A(A)I(I)sin(A)sin(A)cos(I)cos(I∆MD∆North
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12
1212
2121
1212
1221
−−•
=
−•−−•−•
=
−•−−•−•
=
Ref: API Bulletin D20 (1985) NOTE: All angles in radians
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• Poor response of directional tools• Industry going for more “science” and less “art”• Directional driller dependent on computer control
• Tool failure / system failure• MTBF of rotary steerables and other tools• Unable to steer in sliding mode
• Tortuosity• Unplanned curvature in wellbore• Increased torque, drag, casing wear
Directional Problems
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Sliding with Bent Housing PDMs
Drag force reduced once pipe moves
Dra
g Fo
rce
Time
Dynamic Friction
Static Friction
25%
Pipe movement
Dyn Drag = 50,000 lbs
Static = 67,000 lbs
WOB = 10,000 lbs
Total = 77,000 lbs
Pipe moves ===>WOB = 27,000 lbs,not…...10,000 lbs.
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Sliding with Bent Housing PDMs
0
1000
2000
3000
4000
5000
0 10 20 30 40 50
Weight-on-Bit, 1000 lb
Torq
ue, f
t-lb
Typical max torque for6-1/2” slow-speed motor
Series M121PDC bit
Series M332
Series 517Rollercone
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Tortuosity – Unsurveyed Curvature
Apparent Dogleg
Actual Dogleg
Survey Station (n)
Survey Station (n+1)
• Survey intervals may not allow correct representation of curvature.
• Calculation method assumes smoother curve than actually exists locally.
• Result is higher normal force, higher torque / drag, higher casing wear.
• Lower drillability, higher cost
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