1 Casing / Conductor Design, BOP & Wellhead

1 Casing / Conductor Design, BOP & Wellhead ................................................... 1 1.1 Casing setting depths and justification...........................................................................................2 1.1.1 Introduction.........................................................................................................................................2 1.1.2 30” Foundation Pile...........................................................................................................................2 1.1.3 20” Conductor Casing.......................................................................................................................2 1.1.4 16” Drilling Liner (contingency)........................................................................................................2 1.1.5 133/8” Surface Casing........................................................................................................................3 1.1.6 95/8” Production casing.....................................................................................................................3 1.1.7 7” Production liner (contingency) ....................................................................................................3 1.2 Casing Design Criteria......................................................................................................................5 1.3 Minimum EMG and Kick Tolerance................................................................................................5 1.3.1 Kick Detection....................................................................................................................................7 1.4 Casing Test Pressure........................................................................................................................8 1.5 Casing Specification..........................................................................................................................9 1.6 Wellhead.......................................................................................................................................... 10 1.6.1 Wellhead Running Procedures..................................................................................................... 10 1.7 Casing Centralisers........................................................................................................................ 10

1.1 Casing setting depths and justification. 1.1.1 Introduction

The Example deepwater exploration well can be classified as a wildcat well. The nearest offset well, was 16 km away and was drilled in only 450 ft of water. Therefore a large uncertainty in the pore-pressure and formation strength is predicted. In that, and based on a more conservative design, deepwater wells require usually more casing strings than similar wells in shallower water. The Example well design is therefore rather flexible and comprehensive (maximum of 6 casing strings in just 5900 ft below seabed). Casing setting depths are flexible and should be selected during the drilling process. Close monitoring of drilling parameters and other available information from MWD/LWD and PWD should be used to select the optimum casing point before drilling further. Casing points should be selected in close consultation between on and offshore staff. Note Casing setting depths have been selected based on the expected pore pressures. It is possible that

a casing string has to be set shallower (or deeper) if pore pressures require a higher (or lower) mud weight than planned.

1.1.2 30” Foundation Pile

The setting depth of the 30” conductor is dependent on the 8½” soil investigation hole. Based on the experience it will be decided to either jet the 30” foundation pile or drill a 36” hole and to run either 4, 5 or 6 joints. A main criteria is to have sufficient support for the 30” foundation pile and the 20” Conductor in the soft and unconsolidated seabed.

1.1.3 20” Conductor Casing

The objective is to set the 20” casing as deep as possible, to ensure sufficient formation strength and to minimize the need for the 16” drilling liner. However, it should be realized that many wells have been lost in deepwater due to pushing the 20” casing too deep. Drilling parameters and MWD/LWD and PWD data should be monitored closely to decide if hole conditions require a higher mud weight than seawater.

1.1.4 16” Drilling Liner (contingency)

Will only be run if the 20” conductor has to be set early, resulting in a insufficient leak-off. The same criteria apply as for the 20” conductor. If the 16” is required it might be decided to set it somewhat deeper than the original planned 20” conductor setting depth, this to be better prepared for a pressure increase in the trust wedge.

1.1.5 133/8” Surface Casing

The 133/8” casing will be set just above the Yellow horizon. It is expected that formation pressures will be hydrostatic until this formation. Although it is possible that the pore pressure could be inflated if the trust wedge is penetrated. Setting the 133/8” as close as possible above the Yellow horizon will be optimum if there is a pore pressure increase in the Yellow horizon.

1.1.6 95/8” Production casing

The 95/8” casing will be set as close as possible above the Example objective. Setting the 95/8” casing as close as possible above the Example objective will be optimum for penetrating the main reservoir(s) and minimizes the open hole length before coring. 1.1.7 7” Production liner (contingency)

There are no plans to run a 7” Liner but a liner will be available as a contingency.

0 ft

2484 ft bdf (2411 ft ss )

2843 ft bdf (2660 ft ss )

3873 ft bdf (3800 ft ss )

4073 ft bdf (4000 ft ss )

4373 ft bdf (4300 ft ss )

4873 ft bdf (4800 ft ss )

7573 ft bdf (7500 ft ss )

8391 ft bdf (8318 ft ss )

30” x 310# X-52 Quik -Stab Structural pipe

TOL 20” 133# X-56 RL-4S Conductor Casing

TOC

16” 84.0# K55 BTC Liner (Contingency)

13 3/8” 54.5# K55 BTC Surface Casing TOC

9 5/8” 43.5# N80 BTC Production Casing

7” 26# L80 NSCC Production Liner

Mud Line

RKB

Mean Sea Level

WELL SCHEMATIC

Sea water

0.46 psi/ft

PHPA 20% NaCl 3% Glycol

0.6 - 0.65psi/ft

0.6 - 0.70 psi/ft

Drilling Fluid

26” Hole

17 1/2” Hole or 22” underream

17 1/2” Hole or 14 3/4” hole & 171/2” underream

12 1/4” Hole

8 1/2”Hole

Lithology

Predominantly soft clay / shale /

silt

Gumbo ??

Sand / shale sequence

Mainly sand interbedded

w/ shales

20” 133# X-56 RL-4S Conductor Casing

5873 ft bdf (5800 ft ss )

0.50 psi/ft

73 ft

(Contingency)

5373 ft bdf (5300 ft ss )

Note : Casing setting depths will be adjusted based on actual formation pressures and hole conditions.

Figure 1 Well Schematic

1.2 Casing Design Criteria The casing design is performed using the design program STRESSCHECK. The casing design takes into consideration the collapse, burst, axial and tri-axial criteria as used by Stress check for the planned and maximum casing setting depth. Worst case scenario’s, using the highest expected pore pressures have been used for the design and the casing selection.

1.3 Minimum EMG and Kick Tolerance. The minimum EMG required at the casing shoe is calculated based on the following criteria: ♦ The minimum influx is set at 100 bbls for each hole. ♦ The Well Control Module of Well Plan for windows is used to calculate

maximum kick volumes. This module takes gas compressibility, temperature effects and well trajectory into consideration.

♦ The influx is either a swab kick or a drill kick, depending on the mud weight. ♦ Expected pore pressures are used. Refer to Table 1 Kick Tolerance as a function of formation strength and pore-pressure. 1) means top of influx already inside the shoe.

Casing

size Shoe depth (ft tvss)

Leak-off

(psi/ft)

Hole TD

(ft tvss)

Pore Pressure gradient

Mud-weight

(psi/ft)

Height of influx

(ft)

Volume (bbl)

Max Pore Pressure w/ gas to shoe

20" 4000 0.528 4800 0.435 0.450 800 1) 350 0.457 20" 4000 0.528 4800 0.435 0.435 800 1) 350 0.457 20" 4000 0.502 4800 0.435 0.450 795 348 0.435 20" 4000 0.477 4800 0.435 0.450 509 220 0.414 16" 4800 0.575 5800 0.435 0.500 1000 1) 267 0.493 16" 4800 0.575 5800 0.435 0.435 1000 1) 267 0.493 16" 4800 0.546 5800 0.435 0.500 1000 1) 267 0.469 16" 4800 0.519 5800 0.435 0.500 1000 1) 267 0.447 20" 4800 0.575 5800 0.435 0.500 1000 1) 267 0.493 20" 4800 0.546 5800 0.435 0.500 1000 1) 267 0.469 20" 4800 0.519 5800 0.435 0.500 1000 1) 267 0.447 20" 4800 0.575 5800 0.435 0.435 1000 1) 267 0.493

133/8" 5800 0.628 7500 0.555 0.600 1000 115 0.508 133/8" 5800 0.628 7500 0.555 0.555 931 106 0.508 133/8" 5800 0.628 7500 0.555 0.600 1000 115 0.508 133/8" 5800 0.597 7500 0.555 0.600 636 70 0.484 133/8" 5800 0.567 7500 0.555 0.600 290 28 0.461 95/8" 7500 0.709 8318 0.543 0.600 818 1) 36 0.649 95/8" 7500 0.709 8318 0.543 0.543 818 1) 36 0.649 95/8" 7500 0.674 8318 0.543 0.600 818 1) 36 0.617 95/8" 7500 0.640 8318 0.543 0.600 818 1) 36 0.587

Table 1 Kick Tolerance as a function of formation strength and pore-pressure.

1.3.1 Kick Detection

As mentioned earlier, pore pressures and formation strengths are difficult to predict for this wildcat well. This pore pressure uncertainty will pose higher responsibility upon drilling crews. To ensure timely detection for kicks, the following should be implemented/adhered to: ♦ Continuously monitor relevant drilling parameters, and gas shows with utmost

care. ♦ Carefully watch indications for pore pressure chances such as drill cutting

shape, hole fill, torque and drag, D-exponent, formation resistivity if available, etc.

♦ Mud logging unit required as an additional independent monitoring system. A comprehensive mud logging unit with experienced crew has been contracted for the job.

♦ Keep active system small to ensure sensitive pit level measurements. Monitor relevant pits as part of the active system during mud transfers. All pits should be equipped with sensors.

♦ Perform a daily calibration check of a pit level and return flow rate measurement system.

♦ Implement a weekly maintenance check of the above equipment. ♦ Pump out of hole if any signs of swabbing. ♦ Avoid excessive ROP’s when drilling potential hydrocarbon bearing sections. ♦ Monitor PWD closely when available to detect changes in ECD’s ♦ Perform frequent kick drills to ensure fast reaction time.

1.4 Casing Test Pressure

Please find below the casing test pressure calculation and selection:

Casing Test Pressure Calculation Casing size 20" 16" 133/8" 95/8" 7" Inch Burst strength 3060 2978 2735 6327 7240 Psi

Deep Well Option Top of casing/Liner 2411 3800 2411 2411 7000 ft Casing shoe at 4800 4800 5800 7500 8300 ft Formation gradient at shoe 0.575 0.575 0.628 0.709 0.744 Psi Max TD next section 5800 5800 7500 8500 8500 ft Max Pore-pressure gradient at TD

0.583 0.583 0.667 0.744 0.744 Psi

Max pressure at shoe 2760 2760 3642 5317 6175 Psi Max burst at top joint 2521 2660 3304 4809 6045 Psi Min mud inside 0.46 0.5 0.5 0.5 0.55 psi/ft Test Pressure 1412 760 2098 3603 2195 Psi

Max Test Pressure 75 % of burst 2295 2234 2051 4745 5430 Psi

Selected Casing Test Pressure Selected Test Pressure 1300 1000 2000 3600 2500 Psi

Table 2 Casing Test Pressures

1.5 Casing Specification Table 3 presents the available data of each casing to be used for the example well.

Casing Technical Data Size Weight/Wall

Thickness (Lbs / in)

Grade Burst (psi)

Collapse (psi)

Yield (kips)

ID (inch)

Coupling OD

(inch)

Drift (inch)

Bending (kip-ft)

30" 457 / 1 ½” X-52 4550 3890 6984 27 - 3950 H-90/MT - 6700 - 4440 28 32.25 - 4380

30" 310 / 1” X-52 3030 1630 4738 28 - 2770 S-60/MT - 4200 - 2630 28 32 - 2600

20" 133 / 0.625

X-56 3060 1450 2130 18.73 - 18.543 834

RL-4S - 4100 - 1800 18.63 21.5 - 850 16" 84 K-55 2978 1407 1326 15.01 - 14.823

BTC - 3063 1410 1499 15 17 - 420 133/8" 54.5 K-55 2735 1131 853 12.615 - 12.459

BTC - 2730 1130 853 12.615 14.375 12.459 133/8" 48 NT-

55HE 2510 1030 744 - 12.599

BTC - 2510 904 14.375 12.599 95/8" 43.5 N-80 6327 3810 1006 8.755 - 8.625

BTC - 6330 3810 1074 8.755 10.625 8.599 7" 26 N-80 7240 5411 604 6.276 - 6.151 NSCC - 7240 5410 519 6.276 7.656 6.151

Table 3 Casing technical Data

1.6 Wellhead

A Dril-Quip SS-10C 18¾” wellhead system is selected for this well. The system is rated to 10,000 psi working pressure and is equipped with an ABB Vetco Gray H-4 wellhead connector profile. The high pressure housing has 3 casing ha nger positions, alternatively, the upper position can accommodate a tubing hanger in the event of a subsea completion. The 30” housing extension (full joint) is fitted with a Dril-Quip H-90D/MT box-down and the 18¾” housing has a 20 feet extension with an ABB Vetco Gray RL-4 pin connector. The wellhead system has been modified to suit the Example deepwater operations (see section xxxxx)The SS-10C wellhead package has the following equipment: ♦ Temporary guide base (200 ft2 mud-mat). ♦ Gymbal system to support and land on TGB. ♦ Permanent guide base complete with 4 of 10’ posts c/w Regan post top

profile and brackets for slope indicators. ♦ 30” wellhead housing and extension. ♦ 18¾” high pressure housing, left hand thread running profile, H-4 connector

profile up and RL-4 pin connector down on wellhead extension. ♦ 133/8” and 95/8 casing hangers. ♦ All necessary wear bushings (inclusive the extended type), running tools and

spare parts to support a 1 + 1 well program. ♦ 100 % back up for all equipment to be available on the rig.

1.6.1 Wellhead Running Procedures

- Refer to Manufacturers Manual.

1.7 Casing Centralisers. Refer to cementing section for the casing centralisers.