Petroleum engineering (drilling) project 2

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PNGE 310

Class 2

Overbalanced Drilling

• Most common type of Oil & Gas drilling

• Drilling with Fluid filled hole

• Hydrostatic pressure > formation pressure

• 𝑃ℎ = 0.052 ∗ 𝑀𝑊 ∗ 𝑇𝑉𝐷 ,

• 𝑤ℎ𝑒𝑟𝑒 𝑃ℎ 𝑖𝑠 𝑡ℎ𝑒 ℎ𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑖𝑛 𝑝𝑠𝑖,

• 𝑀𝑊 𝑖𝑠 𝑡ℎ𝑒 𝑓𝑙𝑢𝑖𝑑 𝑑𝑒𝑛𝑠𝑖𝑡𝑦 𝑖𝑛 𝑝𝑝𝑔 ( 𝑙𝑏

𝑔𝑎𝑙 ),𝑎𝑛𝑑

• 𝑇𝑉𝐷 𝑖𝑠 𝑡ℎ𝑒 𝑡𝑟𝑢𝑒 𝑣𝑒𝑟𝑡𝑖𝑐𝑎𝑙 𝑑𝑒𝑝𝑡ℎ 𝑖𝑛 𝑓𝑡

• Freshwater: 8.33 ppg

• Brine: ~8.5- 9.0 ppg

• Muds: ~8.5- 20 ppg • Water Based Mud

• Diesel Based Mud

• Synthetic Oil Based Mud

Overbalanced Drilling: Rig Components

1. Crown Block 2. Cat Line (Hoist) 3. Drill Line 4. Monkey Board 5. Traveling Block (Hook) 6. Top Drive 7. Derrick (Mast) 8. Drill Pipe, Elevators, Bails 9. Doghouse, Drillers Cabin (DS, ODS) 10. BOP (Stack) 11. Rig Water 12. Cable Tray (Festoon) 13. Generators (Gens) 14. Rig Fuel 15. Electric House (VFD) 16. Mud Pumps 17. Bulk Mud Storage 18. Mud Pits 19. Earth Pit (Solids Control) 20. Separator (Gas Buster) 21. Shakers 22. Choke Manifold 23. V-Door 24. Pipe Racks 25. Accumulator

Crown Block

• An assembly of sheaves or pulleys mounted on beams at the top of the derrick. The drilling line is run over the sheaves down to the hoisting drum.

Traveling Block

• An arrangement of pulleys or sheaves through which drilling cable is reeved, which moves up or down in the derrick or mast.

Top Drive

• The top drive rotates the drill string without the use of a kelly and rotary table. The top drive is operated from a control console on the rig floor or from joysticks in the drillers house.

Bails

• Large steel tubular used to connect the elevators to the top drive. Used when picking up pipe, tripping drill pipe, or running casing.

Elevators

• A set of clamps that grips a stand, or column, of casing, tubing, drill pipe, or sucker rods, so the stand can be raised or lowered into the hole.

Drawworks

• The hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line which raises or lowers the traveling blocks

Catwalk

• Equipment where pipe is laid to be lifted to the rig floor by the catline or by an air hoist. Can be automated by hydraulics.

• https://www.youtube.com/watch?v=Nzn2m_wqzlM

https://www.youtube.com/watch?v=Nzn2m_wqzlM

Drill String Design

• Drill String Components:

• Bit

• Drill Collars

• Tapered/ Non-Tapered

• Drill Pipe

• Tapered/ Non-Tapered

Buoyancy

• Buoyancy Factor is the factor that is used to compensate loss of weight due to immersion in drilling fluid, 0-1.0

• 65.44ppg is the weight of steel

𝐵𝐹 = 1 − 𝜌𝑓𝑙𝑢𝑖𝑑

𝜌𝑝𝑖𝑝𝑒 𝑜𝑟

65.44 − 𝑀𝑊[𝑝𝑝𝑔]

65.44

Drill String Design Checklist

1. Air Weight Calculations

2. Tapered/Non-Tapered DC Calculations

3. Stiffness Ratio

4. Bending Strength Ratio

5. DC Make-Up Torque

6. Drill Pipe Information & Design

7. Margin of Pull (MOP) also called Overpull

Drill String Design

Drill String Component Quantity Connections

Section 1: 9" x 3“ 192 #/ft 6 7-5/8" Reg

Section 2: 7-3/4" x 2-13/16“ 139 #/ft 6 5-1/2" FH

Section 3: 6" x 2-1/2“ 79 #/ft ? 4-1/2" FH

HWDP

5" x 3” 49.3 #/ft 6 NC 50

5", 19.5, Grade E-75, Premium ? NC 50 (XH)

5", 19.5, Grade S-135, Premium ? NC 50 (XH) 14

Example:

Desired Parameters

TD 12,000 ft

MW 11 ppg

Bit 12-1/4"

WOB 50,000 lbs

SF 15%

MOP 120,000 lbs 15

Design a tapered drill string utilizing the inventory listed in the previous slide. Plan to use all 6 DCs in section 1 and all 6 DCs in section 2. How many DCs are needed in section 3? Note: all the WOB should be utilized from the DCs. Plan on using all the HWDP for BHA stiffness.

Air Weight Calculations: Tapered DC • Section 1 DC

𝑊𝑎𝑖𝑟 = 6 ∗ 30ft ∗ 192 ൗ lbs

ft = 34,560 lbs

• Section 2 DC 𝑊𝑎𝑖𝑟 = 6 ∗ 30𝑓𝑡 ∗ 139 ൗ

𝑙𝑏𝑠 𝑓𝑡

= 25,020 𝑙𝑏𝑠

• Section 3 DC → need to calculate length for tapered string

Tapered DC Calculations:

• Buoyancy Factor

𝐵𝐹 = 65.44 − 𝑀𝑊[𝑝𝑝𝑔]

65.44

𝐵𝐹 = 65.44 − 11

65.44 = 0.8319

• Equivalent WOB in Air 𝑊𝑂𝐵𝑎𝑖𝑟 =

𝑊𝑂𝐵∗𝑆𝐹 𝐵𝐹

= 50,000 𝑙𝑏𝑠∗1.15

0.8319 = 69,118 𝑙𝑏𝑠

Length of Section 3 DC

𝐿𝐷𝐶(𝑆3) = 𝑊𝑂𝐵𝑎𝑖𝑟 − 𝑊𝑎𝑖𝑟𝐷𝐶(𝑆1) + 𝑊𝑎𝑖𝑟𝐷𝐶(𝑆2)

𝐷𝐶𝑤𝑡(𝑆3)

𝐿𝐷𝐶(𝑆3) = 69,118 𝑙𝑏𝑠 − [34,560 𝑙𝑏𝑠 + 25,020 𝑙𝑏𝑠]

79 #/𝑓𝑡

𝐿𝐷𝐶(𝑆3) = 121 𝑓𝑡

• Round DC(S3) up to even length of 30’ joints → 150 ft (5 DC)

Tapered DC Design

• Recalculate the safety factor with designed BHA and check with original SF. Checks ok

𝑊𝑂𝐵′𝑎𝑖𝑟 = 34,560 + 25,020 + 150𝑓𝑡 ∗ 79#/𝑓𝑡 = 71,430 𝑙𝑏𝑠

𝑆𝐹𝑐 = 𝑊𝑂𝐵′𝑎𝑖𝑟 ∗ 𝐵𝐹

𝑊𝑂𝐵 − 1 ∗ 100%

𝑆𝐹𝑐 = 71,430 ∗ 0.8319

50,000 − 1 ∗ 100% = 18.75%

DC Summary

• Section 1 DC 𝑊𝑎𝑖𝑟 = 6 ∗ 30ft ∗ 192 ൗ

lbs ft = 34,560 lbs

• Section 2 DC 𝑊𝑎𝑖𝑟 = 6 ∗ 30𝑓𝑡 ∗ 139 ൗ

𝑙𝑏𝑠 𝑓𝑡

= 25,020 𝑙𝑏𝑠

• Section 3 DC 𝑊𝑎𝑖𝑟=5 ∗ 30𝑓𝑡 ∗ 79 ൗ

𝑙𝑏𝑠 𝑓𝑡

= 11,850 𝑙𝑏𝑠

BHA Summary

Summary

Length [ft] Total

Length [ft] Wair [lb] Wboy [lb] Wtotal [lb]

Total

Grade S-135 DP

Grade E-75 DP

HWDP 180 690 8,874 7,382 66,805

Section 3 DC 150 510 11,850 9,858 59,423

Section 2 DC 180 360 25,020 20,814 49,565

Section 1 DC 180 180 34,560 28,751 28,751

Non-Tapered BHA

• To find the length of non-tapered Drill Collars:

𝐿𝐷𝐶 = 𝑊𝑂𝐵 ∗ 𝑆𝐹

𝐵𝐹 ∗ 𝐷𝐶𝑤𝑡 𝑜𝑟

𝑊𝑂𝐵𝑎𝑖𝑟 𝐷𝐶𝑤𝑡

Stiffness Ratio

• If I/C Ratio is less than 3.5, the stiffness change between two different components is considered “OK”

ൗ𝐼 𝐶 𝑅𝑎𝑡𝑖𝑜 = ൗ𝐼 𝐶 𝐿𝑎𝑟𝑔𝑒𝑟 𝑃𝑖𝑝𝑒

ൗ𝐼 𝐶 𝑆𝑚𝑎𝑙𝑙𝑒𝑟 𝑃𝑖𝑝𝑒

ൗ𝐼 𝐶 = 0.0982 ∗ 𝑂𝐷4 − 𝐼𝐷4

𝑂𝐷

Stiffness Ratio

Tapered BHA I/C Ratio

9" x 3" 70.70

7-3/4" x 2-13/16" 44.92 1.57

6" x 2-1/2" 20.57 2.18

Drill Pipe Information

• Ex: 5”, 19.5ppf, Grade E, XH, NC50, Premium • 5” Tube OD

• 19.5 nominal weight • Not the actual weight/foot!

• Grade E determines minimum Yield value • Grades E-75, X-95, G-105, S-135, V-150

• XH is the tool joint description • XH (extra hole) aka IEU (Internally & Externally Upset)

• IF (internally flush) aka EU (Externally Upset)

• NC50 is the connection threads (Numbered Connection) • Diameter on pin end, 5/8” from shoulder

• Ex: NC50 = 5.0417”; NC46 = 4.628”

• Premium is the wear classification based on inspections • New, Premium, and Class 2

• Each classification affects the yield values

Minimum Yield

• As DP is used, the material becomes worn. Pipe inspection companies will inspect the pipe and classify it as Premium or Class 2. DP is only classified as New one time. After one time use, the rating falls to Premium.

• Grade E-75 means minimum yield is 75,000psi

• To find the max load (or pull) allowed on the DP:

𝐹𝑌𝑚 = 𝑌𝑚 ∗ 𝐴 ∗ %𝐴𝑟𝑒𝑎 𝑅𝑒𝑑𝑢𝑐𝑡𝑖𝑜𝑛 → 𝑢𝑠𝑒 𝑐ℎ𝑎𝑟𝑡𝑠 𝐹𝑌𝑚 = 75,000 ∗ 5.2746 = 395,595 𝑙𝑏𝑠 𝑁𝑒𝑤 𝐹𝑌𝑚 = 75,000 ∗ 5.2746 ∗ 0.7875 = 311,535 𝑙𝑏𝑠 𝑃𝑟𝑒𝑚𝑖𝑢𝑚 𝐹𝑌𝑚 = 75,000 ∗ 5.2746 ∗ 0.6836 = 270,432 𝑙𝑏𝑠 (𝐶𝑙𝑎𝑠𝑠 2)

DP Length Design by Overpull

𝐿𝐷𝑃 = 𝐹𝑌𝑚 ∗ 0.9 − 𝑀𝑂𝑃 − 𝑊𝑡

𝑊𝐷𝑃𝑎𝑐𝑡 ∗ 𝐵𝐹

𝑤ℎ𝑒𝑟𝑒: 𝐹𝑌𝑚 𝑖𝑠 𝑡ℎ𝑒 𝑓𝑜𝑟𝑐𝑒 𝑐𝑎𝑙𝑐𝑢𝑙𝑎𝑡𝑒𝑑 𝑓𝑟𝑜𝑚 𝑌𝑚, 𝑀𝑂𝑃 𝑖𝑠 𝑡ℎ𝑒 𝑚𝑎𝑟𝑖𝑔𝑖𝑛 𝑜𝑓 𝑝𝑢𝑙𝑙,

𝑊𝑡 𝑖𝑠 𝑡ℎ𝑒 𝑡𝑜𝑡𝑎𝑙 𝐵𝐻𝐴 𝑤𝑒𝑖𝑔ℎ𝑡 𝑖𝑛 𝑚𝑢𝑑 𝑏𝑒𝑙𝑜𝑤 𝐷𝑃,

𝑊𝐷𝑃𝑎𝑐𝑡 𝑖𝑠 𝑡ℎ𝑒 𝑎𝑐𝑡𝑢𝑎𝑙 𝑤𝑡

𝑓𝑡 𝑜𝑓 𝑡ℎ𝑒 𝐷𝑃,

𝐵𝐹 𝑖𝑠 𝑡ℎ𝑒 𝑏𝑜𝑦𝑎𝑛𝑐𝑦 𝑓𝑎𝑐𝑡𝑜𝑟

𝐿𝐷𝑃 = 311,535 ∗ 0.9 − 120,000 − 66,805

20.89 ∗ 0.832

= 5,383 𝑓𝑡 𝐺𝑟𝑎𝑑𝑒 𝐸 26

Drill Pipe Slips & Table Bushing

DP Length Design by Slip Crushing

𝐿𝐷𝑃 =

൘ [𝐹𝑌𝑚∗ 0.9

ൗ 𝑆ℎ

𝑆𝑇 ] − 𝑊𝑡

𝑊𝐷𝑃𝑎𝑐𝑡 ∗ 𝐵𝐹

𝑤ℎ𝑒𝑟𝑒, ൗ 𝑆ℎ

𝑆𝑇 𝑖𝑠 𝑎 𝑐𝑜𝑛𝑠𝑡𝑎𝑛𝑡 𝑓𝑜𝑢𝑛𝑑 𝑖𝑛 𝑡ℎ𝑒 𝑡𝑎𝑏𝑙𝑒𝑠,

𝑢𝑠𝑒 𝑐𝑜𝑒𝑓𝑓 𝑜𝑓 𝑓𝑟𝑖𝑐𝑡𝑖𝑜𝑛 = 0.08,𝑢𝑠𝑖𝑛𝑔 16" 𝑠𝑙𝑖𝑝𝑠

𝐿𝐷𝑃 = 311,535 ∗

0.9 1.42

− 66,805

20.89 ∗ 0.8319 = 7,519 𝑓𝑡 𝐺𝑟𝑎𝑑𝑒 𝐸

Drill String Design

• Use given value of DP Grade E Length

Summary

Length [ft] Total

Length [ft] Wair [lb] Wboy [lb] Wtotal [lb]

Total

Grade S-135 DP

Grade E-75 DP 5,383 6,073 112,451 93,548 160,364

HWDP 180 690 8,874 7,382 66,805

Section 3 DC 150 510 11,850 9,858 59,423

Section 2 DC 180 360 25,020 20,814 49,565

Section 1 DC 180 180 34,560 28,751 28,751

Drill String Design

• Calculate the remainder of Grade S Drill Pipe

𝐿𝐷𝑃 = 𝐹𝑌𝑚 ∗ 0.9 − 𝑀𝑂𝑃 − 𝑊𝑡

𝑊𝐷𝑃𝑎𝑐𝑡 ∗ 𝐵𝐹

𝐿𝐷𝑃 = 560,764 ∗ 0.9 − 120,000 − 160,364

22.60 ∗ 0.832

𝐿𝐷𝑃 = 11,930 𝑓𝑡 𝐺𝑟𝑎𝑑𝑒 𝑆135

Drill String Design

Summary

Length [ft] Total

Length [ft] Wair [lb] Wboy [lb] Wtotal [lb]

Total

Grade S-135 DP 5,927 12,000 133,950 111,434 271,788

Grade E-75 DP 5,383 6,073 112,451 93,548 160,354

HWDP 180 690 8,874 7,382 66,805

Section 3 DC 150 510 11,850 9,858 59,423

Section 2 DC 180 360 25,020 20,814 49,565

Section 1 DC 180 180 34,560 28,751 28,751

Check MOP

• Check MOP at weakest anticipated point in the Drill String

• How much over the string weight can the rig pull, before we should be concerned with failure in the pipe due to tension?

• Expect failure at the top of the Grade E Drill Pipe when pulling

𝑀𝑂𝑃 = 𝐹𝑌𝑚 ∗ 0.9 − 𝑊𝑡

𝑀𝑂𝑃 = 311,535 ∗ 0.9 − 160,364 = 120,018 𝑙𝑏𝑠 → 𝑜𝑘

• To illustrate, check MOP at Surface at Total Depth

𝑀𝑂𝑃𝑇𝐷 = 560,764 ∗ 0.9 − 271,788 = 232,900 𝑙𝑏𝑠 32

Drill Bit Selection

• Drill bit selection depends on

• Expected formations to drill

• Size of hole

• Length to drill

• Type of drilling fluid to be used

• Deviated wellbore or not

• Dogleg Severity needed (DLN)

• Cost

• Fixed Cutter Bit (Polycrystalline Diamond Compact PDC)

• Roller Cone Bit

• Milled tooth

• Tungsten Carbide Insert TCI 33

PDC Bits

PDC Features

PDC Anatomy

PDC Bits

PDC Cutters

PDC Mechanics

PDC Bits

• Mostly soft formations

• Size/Shape of cutters

• Profile shape/size

• Aggressiveness

• # of blades

• Single/Dual row cutters

• Back-up cutters

• # of nozzles

• Moderate WOB

• High RPM

• Expensive

• Used with fluid

• Drills by shearing rock

• https://www.youtube.com/watch?v=R8X6W0G7krg 40

Roller Cone Bits

•https://www.youtube.com/watch?v=WR8PTENpSAg

https://www.youtube.com/watch?v=WR8PTENpSAg

TCI Nomenclature

TCI Inserts

Milled Tooth Nomenclature

Roller Cone Anatomy

Roller Cone Bits

• Wide range of formations

• Various cutter shape/sizes

• Various # of cones

• Wide range of sizes

• Contains bearings

• Cheap

• Used with air or fluid

• High WOB capability

• Various RPM

• Any angle wellbore

• Drills by crushing 47

Roller Cone Bits

Milled Tooth Cutting Structure

TCI Cutting Structure

Bottom Hole Profiles

Percussion Bits/Hammers • https://www.youtube.com/watch?v=-78eb06Z9J8

• Used in hard formations

• Typically vertical holes

• Only used with air

• Wide range of sizes

• Various designs

• Button size/shape

• Breaks rock by tension

• Low WOB

• Slow RPM

https://www.youtube.com/watch?v=-78eb06Z9J8

Hydraulics

• Bit Hydraulics

• Cleans the bit and bottom hole

• Cools the bit

• Annular Hydraulics

• Carry cuttings to surface

• Limit annular pressure drop

• Limit hole erosion

• Downhole Tool Hydraulics

• Positive Displacement Motors (PDM)

• MWD Tools

Hydraulics

• Pump Pressure or Stand Pipe Pressure (SPP)

• What affects SPP?

• Flow Rate (# strokes per minute SPM)

• Flow Area

• Length of Circulating System

• Fluid Properties

𝑆𝑃𝑃2 = 𝑆𝑃𝑃1 𝑆𝑃𝑀2 𝑆𝑃𝑀1

Hydraulics-Bit Nozzles

• Nozzles are threaded into the bit prior to drilling

• Measured in 32nds of an inch

• Provides control of the following

• Flow area (TFA) as the fluid exits the bit (pressure loss)

• Fluid velocity as it exits the bit (cleans cutters)

• Provides a Horsepower cutting force as the fluid exits the bit to assist cutting rock

Hydraulics

• Pressure drop across the bit

• Nozzles are inserted to provide high hydraulic energy at the bit

• This cools the cutters, cleans the cutters (prevents bit balling), and acts as a pressure washer by carrying the rock cuttings away from the bit

𝑃𝑏𝑖𝑡 = 𝑀𝑊 ∗ 𝑄2

12,032 ∗ 𝐴2

Where MW is the fluid density in ppg, Q is the fluid flow rate in GPM, and A is the total nozzle flow area in square inches.

• Bit Hydraulic Horsepower

𝐻𝐻𝑃𝑏𝑖𝑡 = 𝑃𝑏𝑖𝑡 ∗ 𝑄

1714 56

Hydraulics

• Maximum Hydraulic Horsepower Theory

• 65% of available surface pump pressure is lost through the bit due to nozzle restriction

• Maximum Jet Impact Force Theory

• 48% of available surface pump pressure is lost through the bit nozzles

• Nozzle Velocity (Jet Velocity)

• This is the velocity of the fluid as it exits the bit through the nozzle

𝑉𝑛 = 0.321 ∗ 𝑄

𝐴𝑛 ,

𝑤ℎ𝑒𝑟𝑒 𝑉𝑛 𝑖𝑠 𝑡ℎ𝑒 𝑛𝑜𝑧𝑧𝑙𝑒 𝑣𝑒𝑙𝑜𝑐𝑖𝑡𝑦 𝑖𝑛 𝑓𝑡

𝑠𝑒𝑐 ,

𝑄 𝑖𝑠 𝑓𝑙𝑢𝑖𝑑 𝑓𝑙𝑜𝑤 𝑟𝑎𝑡𝑒 𝑖𝑛 𝑔𝑎𝑙

𝑚𝑖𝑛 ,

𝑎𝑛𝑑 𝐴𝑛 𝑖𝑠 𝑡ℎ𝑒 𝑡𝑜𝑡𝑎𝑙 𝑛𝑜𝑧𝑧𝑙𝑒 𝑎𝑟𝑒𝑎 𝑖𝑛 𝑡ℎ𝑒 𝑏𝑖𝑡 𝑖𝑛 𝑖𝑛 2 57