Petroleum engineering (drilling) project 2

Drilling Engineering

Class 4

1

Directional Drilling • Surface Location

• Wellhead coordinates at the surface elevation

• Measured Depth (MD) • Total footage drilled according to pipe tally

• True Vertical Depth (TVD) • Vertical depth from surface location

• Inclination (INC): Build/Drop inclination • Angle from vertical • 0 degrees is straight downward/ 90 deg is horizontal

• Azimuth (AZ): Turn in azimuth • Angle from True or Grid North • 0 degrees is North/ 90 degrees is East, etc.

• Kick off Point (KOP) • Depth where wellbore begins to build or drop inclination (start of the curve)

• Tangent • Section of the curve where the inclination & azimuth is held constant

• Landing Point (LP) • Depth at MD & TVD where the curve lands in the target formation at the start of the lateral

• Target formation/zone • Desired formation/zone with a set thickness to place the lateral

• Lateral • Horizontal part of the wellbore. Follows the target formation from LP to TD

• Vertical Section (VS) • A horizontal measurement from the surface location to any given point in the well. VS is defined with AZ

direction. Usually has same AZ direction as the lateral

2

Directional Drilling

• Why drill directionally?

• Horizontal Drilling

• Maximize wellbore exposure to producing formation

• Multiple producing zones

• Target multiple zones with one surface wellbore

• Relief Well

• Drill into adjacent well to relieve a blown out rig or wellhead

• Side Track

• Kick off and side track around a fish (object stuck downhole)

• Inaccessible locations

• Large cities, protected land, noise, etc.

• Shoreline Drilling

• Much cheaper day rate for land rig than offshore rig 3

Downhole Tools • Conventional Bent Motors

• Cheaper to drill

• Used on shorter lateral wells to drill curve & lateral in one run

• Rotate and Slide Drilling

• Motor is set to a desired bend before TIH

• Distance from the bit to the bend can vary and greatly affects build rates

• The achievable dogleg from a set motor is called the “motor yield”

4

Downhole Tools • Rotary Steerable Systems (RSS)

• Latest technology

• Expensive

• Designed for long wellpaths

• Constantly Rotates

• Push to Bit Type Steering

• Point to Bit Type Steering

• https://youtu.be/nIAsf1g6wQE

• https://youtu.be/uVrw3InxPyc

5

Downhole Tools

• Rotary Steerable Motors (RSS)

6

Positive Displacement Motors

7

Positive Displacement Motors

8

• Rotor & Stator configuration is selected based on desired torque & rotary speed. • Motors come with a specified rev/gal (revolutions per gallon)

• As fluid is pumped through the motor, additional rotary is gained at the bit

𝑟𝑝𝑚𝑏𝑖𝑡 = 𝑄 ∗ 𝑟𝑝𝑔 + 𝑟𝑝𝑚𝑡𝑜𝑝 𝑑𝑟𝑖𝑣𝑒,

𝑤ℎ𝑒𝑟𝑒 𝑟𝑝𝑚𝑏𝑖𝑡 𝑖𝑠 𝑡ℎ𝑒 𝑟𝑜𝑡𝑎𝑟𝑦 𝑠𝑝𝑒𝑒𝑑 𝑎𝑡 𝑡ℎ𝑒 𝑏𝑖𝑡 𝑖𝑛 𝑟𝑒𝑣

𝑚𝑖𝑛 ,

𝑄 𝑖𝑠 𝑡ℎ𝑒 𝑚𝑢𝑑 𝑓𝑙𝑜𝑤 𝑟𝑎𝑡𝑒 𝑖𝑛 𝑔𝑎𝑙

𝑚𝑖𝑛 , 𝑟𝑝𝑔 𝑖𝑠 𝑡ℎ𝑒 𝑚𝑜𝑡𝑜𝑟 𝑟𝑎𝑡𝑖𝑛𝑔 𝑖𝑛

𝑟𝑒𝑣

𝑔𝑎𝑙 ,

𝑎𝑛𝑑 𝑟𝑝𝑚𝑡𝑜𝑝 𝑑𝑟𝑖𝑣𝑒 𝑖𝑠 𝑡ℎ𝑒 𝑟𝑖𝑔 𝑟𝑜𝑡𝑎𝑟𝑦 𝑠𝑝𝑒𝑒𝑑 𝑖𝑛 𝑟𝑒𝑣/𝑚𝑖𝑛

Directional Plans

• Type I: “L” Profile

• Build and Hold Trajectory

• Drilled vertical from surface

• Relatively shallow KOP

• Casing ran to the End of Build-Up

• Hold INC & AZ in tangent

• Drill tangent to TD

• Typically shallow wells

• Single producing zone

9

Directional Plans

• Type II: “S” Profile

• Build, Hold, Drop Trajectory

• Drilled vertical from surface

• Relatively shallow KOP

• Hold INC & AZ to end of tangent

• Drop INC to near vertical

• Drill vertical to TD

10

Directional Plans

• Type III: “J” Profile

• Drilled vertical to deep KOP

• Quickly build to high INC with low VS

• Reach TD at end of the curve

• Not a common well path

• EX: multiple sand producing zones

11

Directional Plans

• Type IV

• These can combine any of the previous profiles with the addition of a lateral section

• Lateral is near 90 degrees INC or following producing formation

• Increases wellbore exposure to the producing formation

• Thin oil zones

• Low permeability reservoirs

12

Directional Plans • Typical Horizontal Well Components

13

1

2 3

4

5

6

7

1

2

3

4

5 6 7

1. Vertical 2. KOP #1 3. Tangent

4. KOP #2 5. LP 6. Lateral 7. TD

Well Planning

• Need land/lease permits and coordinates

• Wellhead surface coordinates (Surface Hole Location SHL)

• Well lateral TD coordinates (Bottom Hole Location BHL)

• Need lease line boundaries

• Desired lateral spacing

• Desired Doglegs

• Surrounding wells to avoid (Offset Wells)

• Need to know a landing point (LP)

• LP at desired TVD

• Land at what inclination

• Land at what vertical section (VS)

• Torque/Drag models are run to optimize well plans 14

15

Certified Plat

Well Planning-Torque/Drag Models

16

Well Planning-Torque/Drag Models

17

MWD Surveys

• Typical MWD email survey

“MD: 6295 SD: 6208 Inc: 39.6 Azm: 219.9 TVD: 6074.80 VS: 181.06 DLS: 1.72

Currently we are: 7.6' Low and 7.8 Left of the line, seeing 17' of Slide.

Please find attached survey data”

• Typically 45ft between surveys in the curve

• 90ft or shorter between surveys in the lateral

• Accelerometers measure INC & AZ

• All MWD surveying tools provide a relative position.

• Surveys do not provide a location in space

• Each survey would build upon the previous to map the wellbore 18

EM MWD Surveys

19

• Modern EM (Electromagnetic telemetry) tools are designed to take a survey and send the data to surface through formation when the flow of drilling fluid is stopped.

• The tool sends either a magnetic pulse or electrical current through the ground to the receiver at surface.

• On the surface the data is received through ground antennas and the data is processed

• Sometimes an antennae can be placed midway in the drill string to help clarify the signal.

• Different areas have different formation Resistivity so Amperage and effectiveness of the EM signal will vary.

Mud Pulse MWD Surveys

• Positive mud pulse telemetry (MPT) uses hydraulic poppet valve to momentarily restrict mud flow through an orifice to generate increase in the pressure in form of positive pulse which travel back to the surface through the drill string to be detected .

• MPT tools take longer to receive data compared to EM. MPT is more reliable in harsh conditions, and the formation type has no effect on mud pulse signal.

• Like EM, MPT tools sends survey data back to the surface as soon as the flow of fluid is stopped.

20

Postive Negative Continuous

Dogleg Severity

• Numerically describes the severity of a bend, by combining both inclination and azimuth changes in 3-dimensions

• Measures in degrees per 100 feet

• Several formulas to calculate dogleg severity

• Only accurate with small changes in angles

• Small doglegs decrease Torque and Drag (T&D)

• Increases curve length and decreases lateral footage

• Large doglegs increase T&D

• Provide shorter curves to lateral section

21

Dogleg Severity

• Radius of curvature method

• Calculate Dogleg Angle β

• Calculate DLS by taking Dogleg Angle and normalizing to 100 feet

22

• Dogleg Angle β

• The angle of change between surveys

𝑤ℎ𝑒𝑟𝑒, 𝜖 𝑖𝑠 𝐴𝑧𝑖𝑚𝑢𝑡ℎ, 𝜖𝑁 𝑖𝑠 𝑛𝑒𝑤 𝐴𝑧𝑖𝑚𝑢𝑡ℎ, 𝛼 𝑖𝑠 𝐼𝑛𝑐𝑙𝑖𝑛𝑎𝑡𝑖𝑜𝑛, & 𝛼𝑁 𝑖𝑠 𝑛𝑒𝑤 𝐼𝑛𝑐𝑙𝑖𝑛𝑎𝑡𝑖𝑜𝑛

Dogleg Severity

23

𝛽 = cos−1 cos ∆𝜖 ∗ sin 𝛼𝑁 sin 𝛼 + cos 𝛼𝑁 cos 𝛼

Dogleg Severity

• Dogleg Severity δ

• Describes how ‘severe’ the angle of change is between surveys.

• Normalized to 100ft in order to compare and communicate with ease

• Units of degrees per 100ft

• Abbreviated as DLS

𝛿 = ൗ 𝛽 ∆𝐿 ∗ 100

𝑤ℎ𝑒𝑟𝑒, 𝛽 𝑖𝑠 𝑡ℎ𝑒 𝑑𝑜𝑔𝑙𝑒𝑔 𝑎𝑛𝑔𝑙𝑒 & ∆𝐿 𝑖𝑠 𝑡ℎ𝑒 𝑑𝑖𝑠𝑡𝑎𝑛𝑐𝑒 𝑏𝑒𝑡𝑤𝑒𝑒𝑛 𝑠𝑢𝑟𝑣𝑒𝑦𝑠 𝑖𝑛 𝑓𝑒𝑒𝑡

24

Dogleg Severity

• Example:

• Calculate the dogleg severity DLS based on the following two MWD survey reports in the lateral

25

Survey A Survey B

MD (ft) 11,436 11,531

INC (α) 89.00 90.34

AZM (ε) 320.11 323.94

TVD (ft) 6,349.85 6,350.39

VS (ft) 5,133.05 5,227.50

Geosteering

26

• A pilot well is drilled on a multi well pad to obtain gamma logs of the desired target and formations around it.

• Geosteering uses the pilot log as a reference and relies on the gamma data to interpret the bit’s location while drilling laterals

Geosteering • Typical Geosteering email

“As of the last survey at 17304’MD (7317.98’ TVD), based on the GR Image and current correlation it appears that we are:

Gamma Ray Sensor Position: ON TARGET, ~2.5’ BELOW TARGET TOP

Relative Formation Bed Dips: ~91.25deg relative dip (133 deg AZI)

As of right now, continue with TI of 90.5deg.”

27

Project 1

• https://www.youtube.com/watch?v=XntxeRG3ifQ

28