well placement final

survey tools

• pipe tally: measures MD for TVD

• accelerometer: measures inclination for northing

• magnetometer: measures azimuth for easting, vertical section & DLS

surveying

defining a point in space or along the path of the wellbore

purpose of survey

• drilling

  • ensure a safe well path to the target

  • ensure the target is hit

  • prepare for relief well

  • locate DL & allow DLS calculation

  • avoid collision

  • locate the TF orientation of deflection tool/ steerable system

• reservoir/ production

  • provide a good log position/ reserves estimation

• report data to regulators

• conduct forensics investigation

survey tool classification

• magnetic → use earths magnetic field to determine the direction of the wellbore. used in drilled open-hole sections & placed in NMDC

• gyroscopic → use gyro to determine hole direction for where M-interference prevents the use of magnetic tools, in DP or casing strings

Survey Tools Data Gathering Techniques

• photographic film

• memory modules

• wireline

• mud pules telemetry

• electromagnetic telemetry

• wired drill pipe

magnetic survey tools

• compass-based tools

  • magnetic single shot

  • magnetic multishot

• electronic tools

  • electronic magnetic multishot

  • steering tool

  • measurement while drilling (MWD)

gyroscopic survey tools

• single/ multi shot

• rate/north seeking gyro

• ring laser gyro

• inertial grade gyro

inclinometer/ drift indicator

Inclination only tools measure only the hole inclination and give no indication of hole azimuth

• MD Totco deviation (Single)

• Teledrift (Multi)

magnetic single shot

Records simultaneously the magnetic direction and inclination of an uncased well bore on a single film disc. Used as:

• check shot at section TD

• bit trip

• WD has failure

magnetic multishot

Records simultaneously the magnetic direction and inclination of an uncased hole on a film strip at multiple stations.

• when BHA is being tripped out of the hole

Solid State Magnetic Survey Tools (Electronic)

Measure Earth's gravity and magnetic field by using sets of three orthogonal (i.e. mutually perpendicular) solid state accelerometers and magnetometers, respectively. Used as:

• single-shot tools (ESS)

• multi-shot tools (EMS)

• wireline steering tools

• MWD tools

electronic survey tool process

1. can record survey data downhole on a computer chip or transmit the data to the surface by a wireline or mud pulse telemetry.

2. A surface computer initially set up and configure the tool prior to the survey and also to recover and process the data after the survey.

Electronic Magnetic Multishot (EMS)

Uses a sensor array of accelerometers and magnetometers housed in a rugged electronics probe. The data is recorded downhole on a memory chip and then transferred to computer disc for processing when the tool is retrieved at surface or data sent via wireline to surface.

→ confirms MWD surveys

steering tool

Give continuous surface readout of survey data while drilling with a downhole motor and bent sub assembly.

• A solid state electronics probe plus spacer bars + a mule-shoe

steering tool process

1. The raw data from the probe is transmitted to surface via the conducting wireline.

2. A surface computer decodes the signals and calculates the survey data.

steering tool limitations

• Pulling and running the steering tool for each connection takes a long time.

• With side entry sub, time could be saved however the wireline cable might be damaged while making connection.

• The drill string cannot be rotated while the steering tool is in the hole (CT?).

MWD tools

Incorporated as part of the downhole drilling assembly, use magnetometer and accelerometer sensors and transmit the recorded sensor data to surface via a series of pulses sent through the column of drilling mud. The pulses are detected as pressure differentials by surface interface panels and thereafter derived into the required directional information. Measures:

• directional survey

• drilling mechanics data

MWD components

• Downhole sensor package (Microelectromechanical systems (MEMS)).

• Downhole power source.

• Downhole computer (microprocessor and electronics for controlling and monitoring the downhole system).

• Method to transmit data from downhole to surface.

• Surface sensors (for reception of data signals from downhole).

• Surface computer to receive data and convert it to a usable format.

MWD systems

• collar based: All the sensors and electronics are built directly into the body of NMDC. → Allows full wellbore of the NMDC to be used, specially when LCM are expected to be pumped

• probe based: In this system , the tools are built in separate barrel. This barrel then sits inside the ID of the NMDC

MWD downhole assembly

• power supply

• sensors

• directional sensors: triaxial accelerometer → all 3 reads some value of the vector G (orthogonal set) determines inclination and tool face

• orientational sensor: triaxial magnetometer → all 3 read some value of the vector H (orthogonal set) determines the azimuth

• mud pulse telemetry

• electromagnetic telemetry

• wireline telemetry

power supply

Batteries, or downhole turbine, supply power to the tools → allow the tools to operate without the flow of mud, but the operating time and sensor power output is limited.

sensors

• There are two types of directional sensors:

  • PM (Position Monitor): sensor used in conjunction with the negative pulse telemetry system

  • PCD (Pressure Case Directional): sensor used with the positive pulse and EMT (electromagnetic telemetry)

field acceptance criteria

• B-total: total field strength of the local M-field

• G-total: total field strength of the earth’s G-field

• G = Reference +/- 2.5 milli g

• H = Reference +/- 6 counts (300nT)

mud pulse telemetry

1. Information is transmitted to the surface through the mud by way of a data signal created downhole.

2. The surface equipment decodes the data signals of the measurements so that the driller can make adjustments.

The three common types of signals generated are:

• Positive pressure pulses

• Negative pressure pulses

• Continuous pressure waves

mud pulse telemetry Shortcomings

1. Transmission medium must be incompressible

2. Slow data transmission rates (1 to 3 bits/sec)

3. Advanced signal processing techniques are required to reduce the effects of distortion and noise within the telemetry band

Electromagnetic Telemetry

An electromagnetic wave is created, and it is transferred through the formation used when compressible drilling fluids are used & fore onshore mainly

Electromagnetic Telemetry characteristics

• No continuous fluid column requirements

• No LCM restrictions

• Real-time use can be influenced by the vibration

• Data transmission rate is slow, but possible while making a connection (save time)

• Only batteries are the source of power (Usage life).

• Two-way communication

Electromagnetic Telemetry advantages

• No restriction on drilling fluid characteristics

• Reduced survey/connection time

• No moving parts

Factors effecting the signal of electromagnetic telemetry

• Formation impedance (Higher than 500 ohms , or less than 10 ohms, not possible)

• TVD (Signal loss due to pipe, solution Repeater)

• MD (Signal loss due to pipe, solution Repeater)

• Drilling fluid (OBM)

• Casing effect (75 ft below casing shoe)

• Batteries life time

wireline telemetry

Data can also be sent to the surface through a wire attached to the MWD tool (steering tools). With an attached wire, the drill-string cannot be rotated.

Today, wireline is used in conjunction with coiled tubing, where the drill string is a continuous length of metal pipe fed into the wellbore from a drum and cannot be rotated.

MWD tool operation

1. Surveys are taken when the tool is in stationary mode

2. Pump must be stopped for 30 to 60 second

3. Turn the pump back

4. Flow begins

5. Tool powered up

6. 30 second warm up period

7. Running pulses start

8. Pulses are measured by the transducer and encoded by the surface computer

MWD surface processing

1. A transducer (or sensor) at the surface receives the pressure pulses and converts them to electrical signals.

2. Surface computers decode the electrical signals from the transducer and turn the digital information into engineering values and survey computations.

3. The data produced by the MWD tool is processed and used to provide information about the well. This information is used to make critical decisions about the drilling process, such as the well direction.

4. Monitors display data in real time on the drilling floor so that the driller can make well steering decisions

Gyroscopic Survey Tools

Provide an accurate means of surveying a borehole free from drill string and/or casing steel interference. Run (on wireline ) after a casing has been cemented as a verification survey to measure AHD.

→ must be centralised

Categories of Gyroscopic Survey Tools

1. Conventional Gyroscopic Survey Tools

2. North seeking Gyroscopic Tools

3. Inertial Grade Gyro (Inertial Navigation System)

4. Gyro while drilling (coming soon)

conventional gyroscopic tool

Spinning gyro determines azimuth using the difference between the orientation of the gyro (of known direction aka foresight) and the orientation of the case containing the gyro. Does not measure inclination independently.

conventional gyroscopic tool disadvantages

• Drift: It is the rotation of outer gimbal due to earth rotation (time dependence)

• Reference misalignment

• Centralization

North seeking Gyroscopic Tools (Rate Gyro)

Based on the measurement of the horizontal component of the Earth rotation vector, which becomes smaller for increasing latitudes. It orients itself to true north, which eliminating the human error associated with Foresight and reduce the error due to drifting.

North seeking Gyroscopic Tools operation modes

• Gyro-compassing Mode: the tool is held stationary, and the azimuth is calculated independently at each survey station by measuring the component of the Earth's rate of rotation vector in the horizontal plane.

• Continuous Mode: At the start of the survey interval, the tool is referenced to True North by gyro-compassing. Following this, the tool is run continuously, with the tool's azimuthal change determined and its integration resulting in the actual azimuth.

North seeking Gyroscopic Tools limitations

• Sensitive to motion

• The maximum latitude of operation is approximately 80° N/S due to the reduction of the horizontal component of the Earth rotational vector, reducing the ability of tools to North seek.

• For gyro compassing, the survey time might be longer, depends on survey interval.

Inertial Grade Gyro (Inertial Navigation System)

The system measures the change in direction of the platform and the distance it moves. It not only measures the inclination and direction of the well but it also determines the depth. Uses three rate gyros and three accelerometers mounted on a stabilized platform.

Inertial Grade Gyro (Inertial Navigation System) types

• FINDS (Ferranti) → stable gimballed platform; accumulated error 1 ft/1000 ft; requires ~40 min surface initialization; limited to 13⅜" casing or larger

• RIGS (Ring Laser) → strap-down system; usable in 7" casing/liners; accumulated error 2 ft/1000 ft; inclination limited to <45°; regular recalibration required

Gyroscopic Survey Advantage and Limitation

• advantages:

  • Increased Accuracy : Improves the ellipse of uncertainty

  • Not Affected By Magnetic Fields: interference, e.g. batch setting conductors, casing string, drill-string, fish, formations, magnetized mud/cuttings or magnetic variations (daily, storms)

  • Resurveys: old wells, re-entries.

  • Surveying: in cased hole/tubing/Pipe , where magnetic survey tools can not be used

• limitations:

  • very delicate and vulnerable in tough drilling environment

  • only run on wireline (or dropped) during drilling interruptions

Factors Influencing Survey Tool Selection

• Target Size

• Latitude of Well

• Target Direction

• Type of Drilling Installation

• Rig Costs

• Maximum Inclination Planned

• Formation and Hole Conditions

• Survey Depths

• Open or Cased Hole

Survey Tool Selection Criteria

• Application

• Accuracy

• Cost

• Physical Constraints

• Availability

• Reliability

causes of wellbore position uncertainty

• azimuth reading error

• depth error

• inclination error

helps constructing a cone of uncertainty around the actual

ellipsoid of uncertainty

• inclination error create the high side

• azimuth error creates the lateral side

• measured depth error creates a 3rd component along the axis of the wellbore

EOU plan view

EOU vertical section view

survey accuracy reasons

• geologic targets

• regulation/ property lines

• relief wells abandonment

• prevent collision

anti-collision methods

• Error System (Model): Wellbore position uncertainty (Error Method used)

• Error Surface: Calculating dimension of error surfaces between Well-paths (Method to Measure Distance)

• Warning Method: Criteria for reporting separation (Separation Factor)

• Scan Method: Distance between well-paths (Planning and Execution)

error origins

• Reference Error: Errors in altitude, coordinate system or the direction of Magnetic/True North

• Misalignment Error and SAG

• Relative Depth Error

• Drill String Magnetization: Magnetic Interference

  • Drilling Fluid

  • Formations

  • Eroded steel from casing or drill-string

• Inclination and Azimuth Errors – Tool sensor capability

  • Magnetic dip angle uncertainty

  • Magnetic field uncertainty

  • Accelerometer Bias error

  • Accelerometer Scale error

  • Magnetometer Bias error

  • Magnetometer Scale error

  • Cross-coupling/misalignment errors (Gyro tools)

in-field referencing

used to bypass the continuous change of magnetic storms via aeromagnetic & marine surveys to correct:

• dip angle

• magnetic field strength

• declination

depth error sources

• Pipe tally accuracy [+/- 2 to 3 ft]

• HKLD sensor [+/- 1 to 2 ft]

• Rig heave [+/- 1 to 2 ft]

• Stretch due to weight [+ 30 ft]

• Friction [+/- 5 ft]

• Weight-on-Bit [+/- 3 ft]

• Thermal expansion [+ 13 ft]

• Pressure [ < 1 ft]

• Buckling and Twisting [ < 1 ft]

sagging

Mechanical misalignment errors affecting directional survey measurements can be considered to be the difference between the orientation of the along-hole axis of the survey sensor and that of a line describing the geometric center of the well path.

factors effect SAG

• mud weight

• hole diameter

• BHA diameter

• stabiliser diameter & spacing

• collar stiffness

• formation stiffness

• hole curvature

SAG correction

• If it is less than 0.1° no correction applied

• If it is greater than 0.1° , correction must be applied to correct the survey

• If it is greater than 0.25⁰ , the BHA must be modified

error classification

• random

• systematic → generally expand to dominate the error envelope

• correlated → continue to be carried across multiple runs of different sensors of the same type

• uncorrelated → errors that don’t carry across different sensor runs or different tool runs

• gross → usually caused by human faults or failures of instruments in use

• global → affect every survey in every well in the same field

error models

• Cone of Uncertainty Model

• Walstrom Error Model

• Wolff and De Wardt Error Model

• Shell Extended Systematic Error Model [SESTEM]

• Industry Steering Committee for Wellbore Survey Accuracy Error Model [ISCWSA]

cone of uncertainty

It consisted of a simple ratio with measured depth that applied over a range of inclinations.

wolff & de wards error model

• considers relative depth, misalignment & inclination error, & compass reference & gyro compass

• A set of values (coefficients) were chosen for each tool and the mathematical model produced an EOU

ISCWSA error model

Rely on mathematical descriptions of all error sources which allows for both geographic location, tool performance and all well shapes.

Assumptions and Limitations of the ISCWSA Model

• Regular tool calibration

• A maximum of 100 ft survey intervals.

• Field QC checks, such as total magnetic field, gyro drifts, total gravity field and magnetic dip angle on each survey measurement.

• The use of non-magnetic spacing for MWD surveys according to industry standard

• For MWD, surveys taken in a magnetically clean environment away from casing and adjacent wells.

• It does not cover gross blunder errors (Human errors).

ISCWSA process

1. Find all error sources affecting Measured Depth, Inclination, and Azimuth

2. Designate an error code to each error source

3. Each error source has a set of weighting functions, which are the equations that describe how the error source affects the actual survey measurements of measured depth, inclination, and azimuth.

4. Each error source also has a propagation mode which defines how it is correlated from survey to survey; this is used in summing up the errors.

5. For a particular survey tool, each error source has an error magnitude.

anti-collision methods

• error system → wellbore position uncertainty

• error surface → calculating dimension of error surfaces between well paths

• Warning → criteria for reporting separation

• Scan method → distance between well paths

Anti-collision well classification

• single well → wellhead to wellhead distance > 12500m

• Nearby well → any well that‘s not a single well

Anti collision scanning

• global scan → the initial scan is made in the anti-collision planning process to scan through the entire database projector all nearby wells that fall within the user specified radius

• Proximity scan → on all the wells that have been identified as nearby-well using the subsurface survey data associated with/ each nearby to calculate the distance from each well to the subject well along its length

Center to center distance

The distance between the subject well & the offset well, using:

• horizontal plane

• Normal plane

• 3D least distance

Horizontal plane

Use by spider. Proximity scanning steps horizontally down the subject well at specific intervals

Normal plane

Used by traveling cylinder. Proximity calculation steps down each offset well at the specified intervals to ensure that the proximity of the entire offset well is analyzed, and to ensure the scanning of any potential perpendicularly approaching wellbore. At each step down the offset well this method scans the subject well to determine where a plane normal to the subject well intersects the offset well at the respective scanning point.

3D least distance

Proximity scanning calculates the nearest distance to each offset well by stepping down the subject well at specified intervals to determine a plane that is normal to the offset well survey and which intersects the subject well at the interval point.

=> shortest distance between the subject & offset well from each of the respective subject well scanning points

Separation factor

The ratio of the CtC distance between wells & the sum of the radii of the EOU, between the subject & offset wells being scanned

SF = CtC distance/ EOC(SW) + EOC(OW)

• SF>1 → completely separated ellipses = no overlap

• SF=! → touching ellipses

• SF<1 → overlapping ellispses

Oriented separation factor (pedal curve)

The ratio of the CtC separation between wells & the EOU separation, taking into account a fixed probability of collision as representing a SF of one

=> less conservative but more accurate

OSF = CtC distance/ OEOC(SW) + OEOC(OW)

• OSF =< 5 → alert

• OSF =< 1.5 → minor risk

• OSF =< 1 → major risk

Clearance factor

CF = CtC distance/ CtC - (OEOC(SW)-OEOC(OW))

• CF<1 → stop drilling, major risk

• 1<CF<1.25 → shut-in procedure

• CF>1.5 → safe

Allowable deviation from plan (ADP)

The radial distance from the plan at any point to which the directional driller may be allowed to depart from the plan during the drilling process for the purposes of drilling efficiency w/o causing anti-collision

Min. Allowable separation (MAS)

The min. CtC distance between the subject & offset wells that s allowable w/o any violation of the drill ahead anti-collision rule = defines a safety zone

MAS = CtC - ADP

anti-collision reporting & scanning tools

• spider plot

• travel cylinder

• ladder plot

• separation factor plots

spider plot

is a scaled horizontal plan view of all wells that reconsidered potential collision risk to the new planned well

+basic & easy to understand

-misleading & difficult to understand

travel cylinder

a measure of how close adjacent wells are to the planned wells & a visualisation tool that involves imaging several concentric circles concentric to & normal to the planned wellbore (form imaginary cylinders down the wellbore)

• center = subject well

• around = dots on the flat plane

ladder plot

a graph of the separation to target wells against the measured depth of the planned well → determine which well to watch for at which depth

anti-collision analysis

• performed during the planning phase

• in case of anti-collision analysis: SF<1 and adjust well trajectory

• risk assessment