3. Wellheads and Casing

TAMU - Pemex Offshore Drilling Lesson 3 Wellheads and Casing

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Wellheads and Casing  Drilling with a Riser  Temporary and Permanent Guide Bases  Fracture Gradients  Subsea Cementing  Casing Seals  Drilling Procedures - An Example 2

Conventional Riser Drilling FLOATER

DRILLING RISER CHOKE LINE

SEA WATER HYDROSTATIC MUD HYDROSTATIC

DEPTH

BOP

SEAFLOOR

PRESSURE

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Conventional Riser Drilling - Install 30-in Conductor FLOATER

DRILLPIPE

~200

30”

Jet 30-in Conductor to ~ 200 ft below mudline No riser - “Mud” returns to seafloor No annulus - no cementing (in GOM) 4

Conventional Riser Drilling - Install 20-in Conductor FLOATER

DRILLING RISER CHOKE LINE

D

30”

~1,050 20” Drill 26-in hole to 1,050 ft below mudline Riser optional - Mud returns to surface or seafloor Run 20-in Conductor to ~ 1,000 ft below mudline Cement to mudline

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Conventional Riser Drilling - Install 13 3/8-in Surface Csg. FLOATER

DRILLING RISER CHOKE LINE

BOP Run Riser and BOP Stack Drill 17 1/2-in hole to 4,050 ft BML Drill with Mud returns to surface Run 13 3/8-in Surface Casing to ~ 4,000 ft below mudline Cement to mudline

D

13 3/8”

Now, finally, we can close the BOP if necessary

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Wellheads and Casing A subsea wellhead, like a land wellhead:  Must support the BOP’s while drilling  Must support the suspended casing while cementing, and  Must seal off between casing strings during drilling and production operations. 7

Wellheads and Casing, cont. In floating drilling, the casing hangers, casing seals and cementing heads differ from land and platform operations in the following manner: 8

Wellheads and Casing 1. The first and second casing strings are cemented with returns to the seabed. 2. Casing is run with the last joint madeup on a casing hanger and permanently suspended prior to cementing. Mud returns flow through fluting in the hanger. 9

Wellheads and Casing 3. Usually, cementing plugs are located at the wellhead and released remotely. The cementing string from the vessel to the wellhead is drill pipe. 4. Casing seals are run and set remotely. 10

Wellheads and Casing 5. Special test tools are required for remotely testing the casing seals. 6. Wear bushings are essential for protecting the wellhead.

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Fig.4-10. Typical sealing arrangement for subsea wells.

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13

Depth BML 240 ft 1,100 ft 4,100 ft

8,600 ft 10,100 ft

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Permanent Guide Structure.

Temporary Guide Base

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Utility Guide Frame

Hole Opener Temporary Guide Base

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Procedure for Starting a Well 1. To get the well started, place a heavy steel template on the seafloor. Run on drillpipe. 2. Four guidelines guide bit, casing, etc to the right location on the seafloor. 3. Run 36” hole opener (with guide frame) and drill 36” hole to ~240 ft BML with returns to the seafloor. 19

Procedure for Starting a Well 4. Run 30” casing and cement with returns to the seafloor. With the 30” casing also run the permanent guide structure and the wellhead housing. (3 & 4 alt. Sometimes the 30” casing is jetted or driven in. - instead of drilling). 5. Drill 26” hole to 1,050 ft below mudline. 20

Procedure for Starting a Well 6. Run 20” conductor casing. With the 20” casing, run the high pressure wellhead. Cement the casing. NOTE: The 26” hole may be drilled with returns to the seafloor, or with returns to the surface using the marine riser. Note the guide posts on the permanent guide structure. These are for the BOP stack21

Fig. 4-5. Estimated Fracture gradients at 100 ft below seabed (Santa Barbara Channel). 22

Fracture gradient at 100 ft. below seabed (Santa Barbara Channel).

Why drill with returns to the seafloor? With this low fracture gradient it is difficult to drill with returns to the surface. No shallow gas would be expected at this depth below the mudline. 23

Drill with Diverter to the Surface Casing Point

Fig. 4-5. Estimated Fracture gradients at 1000 ft below seabed (Santa Barbara Channel). 24

Shallow Gas Blowout

Gas reduces buoyancy!

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Gas in the Water Column

Typical specific gravity variations in a blowout boil have increasing effect nearer the water’s surface. Fortunately for a semi-submersible, the rig’s primary flotation members are situated below the zones where specific gravity has been reduced the most. 26

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Gas in the Water Column

If there is sufficient length to the mooring system cables/ chains, the rig will be pushed off location and out of harm’s way. However, the plume can also cause the rig to list, which reduces its freeboard and makes it more susceptible to capsizing. 28

Fracture Gradients in Deep Water Increasing the water depth reduces the total overburden gradient and consequently the formation fracture gradient. This can be expressed as:

g f = (g ob − g p )Fσ + g p 29

g f = (g ob − g p )Fσ + g p Where:

g f = fracture gradient, psi/ft g p = formation pressure gradient, psi/ft g ob = overburden pressure gradient, psi/ft Fσ = horizontal / vertical stress ratio 30

For offshore drilling: g ob =

1 d KB

[ 0.44 d + 0.4335 ρp f f(d KB − d − d F )]

Where: d KB = depth measured from the kelly bushing, ft d

= water depth, ft

d F = height of flowline above the water, ft ρ f = formation bulk density, g/cm

3

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g ob =

1 d KB

[ 0.44 d + 0.4335 ρp f f(d KB − d − d F )]

0.44 d is the overburden due to water, or simply the hydrostatic pressure at the seafloor. (dKB - d - dF) is merely the penetration into the seafloor. 32

Get ρ f from density log. Get Fσ from this plot. Get gp Calculate gf Formation bulk density vs. horizontal to vertical stress ratios for the Santa Barbara Channel. 33

Fig. 4-7. An example of onshore and offshore fracture gradients. 34

J. W. Barker and T. D. Woods “Estimating Shallow Below Mudline Deepwater Gulf of Mexico Fracture Gradients” Presented at the 1997 Houston AADE Chapter Annual Technical Forum, April 2-3, 1997.

Cumulative average (BML) formation bulk density

ρ = 5.3 * (TVDBML )0.1356 e.g. ρ = 5.3 * (3,000)0.1356

= 15.70 lb/gal 35

J. W. Barker and T. D. Woods cont’d At 1,000 ft below mudline, avg. OB. Density,

ρ = 5.3 * (TVDBML )0.1356 gob = 5.3 * (1,000)0.1356 = 13.52 lb/gal gf = 0.9 * ρ

ob

gp = 0.8 * ρ

ob

= 12.17 lb/gal = 0.663 psi/ft = 10.82 lb/gal = 0.563 psi/ft

NOTE: These are gradients relative to 36

J. W. Barker and T. D. Woods cont’d At 1,000 ft below mudline, in 1,500 ft water: Total overburden = 0.44 * 1,500 + 0.052 * 13.52 * 1,000 psi gob = 1,363/2,500 psi/ft = 10.48 lb/gal !! pf = 0.44 *1,500 + 0.052 * 12.17 * 1,000 psi gf = 1,293/2,500 psi/ft = 9.94 lb/gal gp = 0.44 * 1,500 +0.052 * 10.82 * 1,000 psi = 1,223/2,500 psi/ft = 9.40 lb/gal NOTE: These are gradients relative to SURFACE!

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Ben A. Eaton and Travis L. Eaton “Fracture Gradient Prediction for the new generation” World Oil, October 1997, pp. 93-100. Fracture gradient equation: F S p  γ  p  + =  −   D  D D   1− γ  D

γ = Poisson’s Ratio

g f = (g ob − g p )Fσ + g p

from Text 38

Fig. 4-8. Plot of a leak-off test. 39

Fracture Gradient Calculation Mud Weight 9.5 PPG Casing 13 inches Set to 3,340 ft-KB Frac. Grad. = ? Fracture Pressure = 0.052 * 9.5 * 3,340 + 650 = 2,300 psig Frac. Grad. = 2,300/3,340 = 0.6886 psi/ft = 0.6886/0.052 = 13.24 ppg 40

Leak-Off Test

BOPs Casing Drillpipe

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Fig. 4-9. Sub-sea cementing system.

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Fig.4-10. Typical sealing arrangement for subsea wells.

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Metal-to-Metal Casing Annulus Seal  Assures maximum seal over extended periods, even in highpressure holes  Eliminates dependence on seal materials that deteriorate or “cold flow”.  Available on systems up to 15,000 psi pressure integrity. 44

1. Actuating force is transferred to the 2. Resilient compression element which expands, forcing the 3. Metal seal lips into contact with the surface of the 4. Wellhead housing and the 5. Casing hanger Upper Metal Seal Lips Resilient Compression Element Lower Metal Seal Lips 45

Casing Hanger and Pack-off Assembly Single trip installation The pack-off seal assembly is run simultaneously with the casing hanger body. All operations - installing the casing hanger, cementing the casing string and actuating and testing the pack-off seal are performed in a single trip of the running string. 46

Large Flow-By Areas Large flow-by areas can handle most drilling fluid applications with a minimal drop in pressure. Deep 2" wide flow-by slots in the casing hanger body, and ample porting through the pack-off nut assembly, provide clear passage for cuttings and mudcake without plugging. 47

Liquid Compressibility The volume required to compress a liquid is defined by the equation: ∆ V = Vi * Cp * ∆ P

Where: Vi = volume of system, bbl Cp = compressibility = 3 * 10-6 per psi for water = 6 * 10-6 per psi for mud ∆ P = test pressure, psi 48

Seal Test - Example Water depth = 500 ft (all depths are KB) Casing string = 13 3/8” OD Volume of system above the seal = 11 bbl Test pressure = 3,000 psi Test fluid = water Previous casing string = 20”, J-55, 94.0 lb/ft Previous casing seat = 1,500 ft KB Cement top = 996 ft 49

Seal Test - Example V = 11 bbl 500 ‘ KB 996’ 1,500’

Mud Line 20” 13 3/8” 4,000 ft 50

With no leak, the system will require ∆ V = 3 * 10-6 * 11 * 3,000 = 0.1 bbl water to reach test pressure.

If the seal leaks, the volume will be more, but how much more? 51

Obviously, 0.1 bbl would be difficult to measure. The annular volume between the seal and the cement is (996 - 500) ft * 0.1815 bbl/ft = 90 bbl of mud Now,

? ∆ V = 6*10 * 90 ∆ P + 3*10 * 11 ∆ P bbl = ( 5.4 * 10-4 + 3.3*10-5 ) ∆ P bbl = ( 5.73 * 10-4 ) ∆ P bbl What should the maximum pressure be? -6

-6

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Pressure in the annulus must always be less than the collapse pressure of the inner casing, and less than the internal yield of the outer casing. This will depend on both volume and pressure. Table 4-2 shows the relationship for four grades of casing. Also, the internal yield of the 20-inch casing is reached at 2,110 psi when V = 1.24 bbl. 53

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Plug for testing casing seal to full working pressure.

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Test Procedure 1. Set seal 2. Land test plug in wellhead, sealing off below the seal 3. Displace mud with water for test 4. Close pipe rams 5. Pump slowly down the choke line, preferably in stages, to protect the casing in case of leaks 56

Test Evaluation During the test, if the wellhead system being tested will not sustain test pressure, several possible causes should be considered: 1. Leak in the surface manifold 2. Leak in the test plug (detected by returns through the drillpipe) 57

Test Evaluation, cont. 3. Leak in the casing seal 4. Leak in the BOPs 5. Leak in the hydraulic wellhead connector

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Test Evaluation, cont. When the well does not sustain pressure, it is obvious that there is a problem. There is also a problem if the well takes too much fluid to reach test pressure, just as we have discussed. 59

Drilling Procedures from a floater  Install 30” Structural Csg.  Install 20” Conductor  Install 13 3/8” Surface Casing  etc. 60

Drilling Procedures Tentative Hole and Casing Sizes  8 1/2” Pilot Hole to 180’ BML  26”x36” Hole Opener to 180’ BML Install 30” Structural Csg.  8 1/2” Pilot Hole to 1040’ BML  17 1/2” Pilot Hole to 1040’ BML  17 1/2”x26” Under reamer to 1040’ Install 20” Conductor 61

Drilling Procedures Tentative Hole and Casing Sizes  12 1/4” Pilot Hole to 3,830’ BML  12 1/4”x17 1/2” Hole Opener to 3,830’ BML Install 13 3/8” Surface Csg.  12 1/4” Hole to TD (8,530’ BML) Install 9 5/8” Production Csg.  8 1/2” Hole if Required7” Contingency Liner 62

General Rules 1. Do not change the tension on the anchor lines until the 30” casing has been run and cemented. 2. Have all the 30” casing and all of the wellhead equipment on board prior to spudding. 3. There will be an SLM prior to any logging or coring run. 63

General Rules 4. All casing strings will be strapped and drifted prior to running. 5. Casing will not be run until the hole is in the best possible condition and a trouble free wiper trip can be made. 6. Cement densities will be monitored with a mud balance. 64

General Rules 7. The rig will be moved 50’ off location whenever the riser is being run or pulled. 8. No smoking or open flames are permitted on deck whenever the riser is connected to the well. 9. Welding permits (authorized by the drilling supervisor and tool pusher) will be required at all times. 65

General Rules 10. Coring will be at the the discretion of the well site geologist, but only after approval from the task force Manager and the Exploration Coordinator. 11. All information concerning the well will be kept strictly confidential. Any discussions will be held in a secure area in the quarters or on the rig. 66

General Rules 11. Confidentiality - cont’d. Only contractors with “a need to know” will be allowed access to well information. 12. All personnel on board and all visitors will be instructed with the necessary environmental and safety films and instructions. 67

General Rules 13. No one will be allowed on the helicopters, work boats, or drilling vessel without the proper authorization or identification. 14. The rotary table must be positioned within a 200 foot radius of the proposed location. 68

General Rules Anchoring

1. Place anchors on sea floor 5800’ from the desired final location. 2. Anchor lines should be equally deployed around the rig with an angular spacing of 45 degrees between adjacent lines. 69

General Rules Anchoring 3. Pull in opposing lines to set anchors. An indicated line tension of 125 kips is necessary for the anchor to receive any load. 4. A tension level of 440-460 kips should be reached before 600’ of line is taken in with the rig remaining stationary. 70

General Rules Anchoring 5. If a line tension of 440-460 kips has not been reached before 800’1000’ of line has been retrieved, then it may be necessary to use piggy-back anchors. 6. The following Western KDC plan outlines the mooring procedure. 71

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Shallow Gas Plan After the rig is properly anchored the following steps will be followed as there is a potential for shallow gas in this area:

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Shallow Gas Plan 1. Leave mooring line pawls or stoppels unset until the 20” casing has been set and cemented. 2. Mooring winches will be manned while the 8 1/2” pilot holes for the 30” and 20” casings are being drilled. 74

Shallow Gas Plan 3. Mooring winches will be manned while the 8 1/2” pilot holes for the 30” and 20” casings are being opened up or under-reamed. 4. The moonpool and seafloor will be observed for gas bubbles until the 20” casing is set and cemented. 75

36” Hole Plan 1. Premix 600 barrels of 11.5 ppg kill mud prior to spudding the well. 2. PU and TIH with an 8 1/2” bit, 6 - 6 1/2” drill collars, 6 jts of 5” Hevi-Wate drill pipe, and sufficient 5” drill pipe.

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36” Hole Plan 3. Tag bottom with the pilot bit, and note and report the following: a. RKB to water level b. RKB to mud line c. Water depth d. Time of day (tide allowance) 77

36” Hole Plan 4. Lower TV camera, and observe bit entering guide base. Retrieve universal guide frame back to surface. 5. Upon spudding, space out drill string with pup joints so that it will not be necessary to pull the bit above the guide base to make the first connection. 78

36” Hole Plan 6. Drill an 8 1/2” hole to +/- 30’ below the setting depth of the 30” casing (estimated at 180’ BML). Circulate returns to the sea floor, and monitor returns with the TV camera.

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36” Hole Plan 7. If there are no problems with shallow gas, pull out of hole, PU 26” bit and 36” hole opener, 6-9 1/2” DC’s, 6 jts 5” Hevi-Wate DP, and sufficient 5” DP. Drill 36” hole to set 150’ (4 joints) of 30” OD structural casing.

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36” Hole Plan Drill with sea water as follows: a. Circulate viscous sweeps as required to clean the hole. b. Survey hole at 30’, 60’, and 150’ BML. c. At TD of 36” hole, displace hole to the mud line with viscous mud. 81

36” Hole Plan Drill with sea water cont.: d. Make a wiper trip. e. Circulate the hole to the mud line with viscous mud. f. Penetration rate should not exceed 100 ft/hr overall. 82

36” Hole Plan 8. Run 30” structural casing per procedure. 9. If there are problems with shallow gas, displace the 8 1/2” hole with kill mud until the gas stops or the hole is full of kill mud. Monitor returns with the TV camera for evidence of gas or flow, and if after one hour the hole is stable, proceed as in steps 7 and 8. 83

36” Hole Plan 10. If the kill mud in step 9 does not stabilize the well and it appears that heavier mud will not stabilize the well or will break down the formation, then prepare to cement. Mix and pump, sufficient 15.8 ppg cement slurry to circulate cement to the mud line, and monitor returns for gas with the TV camera. 84

36” Hole Plan

10. Make sure that the hole is stable POH with BHA Retrieve TGB Move rig as required

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26” Hole Plan 1. Have 600 barrels of 11.5 ppg kill mud prior to drilling out below the 30” casing. 2. PU and TIH with an 8 1/2” bit, 9-6 1/2” DC’s, 9 jts of 5” Hevi-Wate DP, and sufficient 5” DP. 86

26” Hole Plan 3. Drill an 8 1/2” hole to +/- 40’ below the setting depth of the 20” casing (estimated at 1040’ BML). Circulate returns to the rig shakers, and monitor returns for indications of gas or flow. 87

26” Hole Plan

4. Displace the hole with viscous spud mud, make a wiper trip, displace the hole with viscous spud mud, POH, and log well as required.

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26” Hole Plan 5. If there are no problems with shallow gas, pull the riser, PU & TIH with a 17 1/2” bit, 26” hole opener, monel DC, 6-9 1/2” DC’s, 6-8” DC’s, 9 jts 5” Hevi-Wate DP, 26” stabilizer at 60’, qand sufficient 5” DP. Drill a 26” hole to set 1040’ of 20” OD conductor casing as follows: 89

26” Hole Plan a. Circulate viscous pills as required to clean the hole. b. Circulate returns to the sea floor with sea water. c. Maintain inclination at less than three degrees. d. Spot viscous mud at TD of 26” hole. 90

26” Hole Plan e. Make a wiper trip. f. Spot viscous mud as required. g. Drop multishot and POH. 6. Run 20” OD conductor casing and cement per procedure.

91

26” Hole Plan 7. If there are problems with shallow gas in Step 5, circulate the hole with viscous spud mud and slowly increase the weight until the flow has stopped or until the active system is depleted. If the flow continues, pump the kill mud at the maximum rate until the active system is depleted. 92

26” Hole Plan 7. (Cont.) Then pump sea water at the maximum rate until the hole bridges. 8. If the flow rate is significant, and the hole will not bridge, prepare to move the rig. Cement the hole to just below the sea floor with 15.8 ppg cement. POH with the BHA. Cut or shoot the 30” casing, and pull the TGB and PGB. Move rig as required. 93

26” Hole Plan 9. If the gas in step 7 depletes or the density is sufficient to control the well, then casing can be run or the well can be drilled ahead. 10. Drill 8 1/2” hole to +/- 40’ below the setting depth of the 20” casing (estimated at 1040’ BML). 94

26” Hole Plan 11. Circulate and condition for logs. Pull out of hole, and log well per procedure. 12. PU & TIH with 17 1/2” bit, Monel DC, 6-9 1/2” DC’s, stabilizers at 60’ amd 90’, 6-8” DC’s, jars, 9 jts 5” Hevi-Wate DP.

95

26” Hole Plan 13. Drill a 17 1/2” hole to sufficient depth to set 1040’ of 20” conductor casing. Drop multishot, and POH. 14. PU & TIH with 17 1/2” bit and 26” underreamer, 6-9 1/2” drill collars, 68” drill collars, 9 jts 5” Hevi-Wate DP, and 26” stabilizer at 60’. 96

26” Hole Plan 15. Underream to sufficient depth to set 1040’ of 20” conductor casing. 16. Circulate and condition the hole for casing. Care must be taken to have a balanced mud weight all the way around with no heavy slugs. 97

26” Hole Plan 17. Displace hole from TD to the sea floor with sufficient weight mud to balance the hydrostatic when the riser is removed. Again, care must be taken to have a balanced mud weight while displacing, and the riser may have to be voided with sea water as the heavier mud is circulated. 98

26” Hole Plan 18. POH, run the 20” casing and 18 3/4” 10,000 psi wellhead housing, and cement per procedure. 19. If there is evidence that the hole cannot be drilled deeper safely in step 9, the well will be underreamed at the depth reached in step 9 and 20” casing will be set. 99

26” Hole Plan 20. It will then be determined whether future casing settings need to be changed.

etc. etc. etc. 100

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