Calculate casing string weight in air
6. PRESSURE TESTS Reference
6.1. Hydraulic oil must be used. P-1-M-6140 15.2.3
6.2. Pressure test value doesn’t exceed 70% casing collapse resistance. P-1-M-6140 15.2.3 6.3. During primary & secondary packing group’s test, previous casing
spool valve must be kept open.
P-1-M-6140 15.2.5-4
6.4. All pressure tests should be kept for at least 15 minutes. P-1-M-6140 15.2.5-4
7. DRILLING PROGRAMME CONTENTS Reference
Includes the following, minimum information:
• Manufacturer
• Base flange: size, working pressure
• Casing spool: size, working pressure
• Tubing spool: size, working pressure
• Well head components
• Height of individual components and total height of well head
• Part number of all components
• Amounts
• The well head diagram will also be included
• Remarks
In the case of cluster wells, a sketch showing the orientation of the various well heads with respect to true North will be included
P-1-N-6001E 6.3.8
8. UNCONVENTIONAL WELLHEAD SYSTEM Reference
8.1.1. Mudline casing suspension system: The system makes possible the temporary abandonment of the well in a short time and without casing cutting.
P-1-M-6100 8.5
9. SUBSEA WELLHEAD SYSTEM Reference
9.1. Functional requirements M-1-SS-5708 4
9.2. Engineering requirements M-1-SS-5708 5
Reference List:
‘Drilling Design Manual’ STAP-P-1-M-6100
‘Drilling Procedures Manual’ STAP-P-1-M-6140
‘Operating Procedures for Drawing the ’Well Drilling Programme”’ STAP-P-1-M-6001E ‘Specification for Surface Wellhead and Christmas Tree Standard
Equipment’ STAP-M-1-SS-5701E
‘Specification for 10,000 and 15,000 WP Subsea Wellhead System’ STAP-M-1-SS-5708
‘Standardisation of Surface Wellhead and Christmas Tree Equipment’ STAP-M-1-M-5020
AGIP CODE Ref.nrTop flange (in) Max. W.P. (psi) Btm (CSG) (in)Ref. nrBtm Flange (in) Max. W.P. (psi) Top flange (in) Max. W.P. (psi) Ref. nr Btm flange (in) Max. W.P. (psi) Top flange (in) Max. W.P. (psi) Ref. nrBtm Flange (in) Max. W.P. (psi) Top flange (in) Max. W.P. (psi) Ref. nrDiam (in)Max. W.P. (psi)
Diam tbg (in) MSCL 11.313 5/8500013 3/8 & 9 5/82.113 5/8500013 5/850005.113 5/85000950006.1950002 7/8 MSCL 21.313 5/8500013 3/8 & 9 5/82.113 5/8500013 5/850005.113 5/85000950006.2950003 1/2 MSCL 31.313 5/8500013 3/8 & 9 5/82.113 5/8500013 5/850005.113 5/85000950006.3950005 DCSFSL 11.221 1/4500020 & 18 5/82.421 1/4500013 5/850002.113 5/8500013 5/850005.113 5/85000950006.6950002 x 2 3/8 DCSFSL 21.221 1/4500020 & 18 5/82.421 1/4500013 5/850002.213 5/8500013 5/8100005.213 5/8100009100006.89100002 x 2 3/8 DCSFSL 31.221 1/4500020 & 18 5/82.421 1/4500013 5/850002.113 5/8500013 5/850005.313 5/850001150006.51150002 x 3 1/2 SCSO 11.221 1/4500020 & 18 5/82.421 1/4500013 5/850002.113 5/8500013 5/850005.413 5/850007 1/1650006.47 1/1650003 1/2 DCSO 11.221 1/4500020 & 18 5/82.421 1/4500013 5/850002.113 5/8500013 5/850005.413 5/850007 1/1650006.97 1/1650002 x 2 3/8 DCSO 21.221 1/4500020 & 18 5/82.421 1/4500013 5/850002.213 5/8500013 5/8100005.513 5/8100007 1/16100006.77 1/16100002 x 2 3/8 DCSO31.221 1/4500020 & 18 5/82.421 1/4500013 5/850002.213 5/8500013 5/8100005.213 5/8100009100006.89100002 x 2 3/8 (*)1.221 1/4500020 & 18 5/82.521 1/4500013 5/8100002.313 5/81000013 5/810000 1.126 3/4300024 1/22.626 3/4300021 1/450002.521 1/4500013 5/8100002.313 5/81000013 5/810000
3° CASING HEAD SPOOL (*) Typical wellhead configuration for deep wells (po Valley)
Typical outlines for on-shore, off-shore single and dual completion class -A and class -B (STAP -M-1-SS-5701E) CASING HEADCASING HEAD SPOOLCASING HEAD SPOOLTUBING SPOOLTUBING HANGER
Table PL 2.8 - Typical Outlines for single and duel completions class A and B
PL. 2.14. WELL CONTROL
1. BOP SELECTION CRITERIA Reference
1.1. Pressure rating
1.1.1. The working pressure of any blow-out preventer shall exceed the maximum anticipated surface pressure to which it may be subjected
P-1-M-6110 12.1
1.2. Eni-Agip BOP-selection criteria
1.2.1. The maximum theoretical pressure at the casing head occurs when the well is full of gas and the fracture pressure has been reached at the weakest point (generally the last casing shoe).
P-1-M-6110 12.1
1.2.2. Production test operations: see point 1.2.1
1.2.3. Drilling operations: 60% of maximum theoretical head pressure has been chosen as limit value.
P-1-M-6110 12.1
1.2.4. A first approximate determination of BOP size for a wildcat well is given in the graph reported on the Casing design manual, both for drilling operations and production tests. The anticipated casing setting depths and pore pressure values are the required information.
P-1-M-6110 12.1 P-1-M-6100 9.1
2. EQUIPMENT REQUIREMENTS Reference
2.1. Minimum BOP stack requirements 2.1.1. Land rigs, Jack-up / Fixed platforms:
• 5,000psi WP stack should have at least 2 ram type preventer (1 blind or shear ram type and 1 pipe ram type) and 1 bag preventer
• 10,000psi WP stack should have at least 3 ram type preventers (1 blind or shear ram type and 2 pipe ram type) and 1 bag preventer
• 15,000psi WP stack should have at least 4 ram type preventers (1 blind or shear ram type and 3 pipe ram type) and 1 bag preventer
P-1-M-6150 6.1.1
2.1.2. Land rigs: the shear rams installation will be evaluate with reference to local law or deduced by ‘risk analysis’ computations.
M-1-M-5005 1.1
2.1.3. The pipe rams preventers shall be equipped, at all times, with the correct sized rams to match string in use.
P-1-M-6150 6.1.1-b
2.1.4. Floating drilling rigs:
A 10,000psi working pressure stack should have at least:
• 4 ram-type preventers (1 shear ram and 3 pipe rams,)
• 1 or preferably 2 x 5,000psi annular-type preventers (one annular retrievable on Lower Marine Riser Package.)
A 15,000psi working pressure stack should have at least:
• 4 ram-type preventers (1 shear ram and 3 pipe rams).
• 2 x 10,000psi annular type preventers (one annular retrievable on Lower Marine Riser Package.)
P-1-M-6150 6.1.2
2.2. Diverter general requirements
2.2.1. • The diverter must be equipped with two lines facing opposite directions (offshore applications).
• Minimum diverter outlets 12” ID
• Diverter valves shall be full opening valves, preferably ball valves, and pneumatically or hydraulically actuated. The use of butterfly valves is forbidden.
P-1-M-6150 6.6-b-e-g
2.3. Choke / kill lines & manifold
2.3.1. Choke / kill lines, choke manifold shall have a working pressure rating equal or greater than preventers in use.
P-1-M-6150 6.3-a
2.3.2. Minimum diameter:
• Choke line diameter 3” ID
• Kill line diameter 2” ID
P-1-M-6150 6.1.1-g
2.4. Inside pipe shut-off devices
2.4.1. While drilling shallow holes a float valve is used. P-1-M-6150 9.3.1-e
P-1-M-6140 4.1.5-1 M-1-M-5012 2.5
2.4.2. Blowout equipment available on drill floor:
• Additional lower kelly cock, kept in open position at all time.
• Gray type inside BOP, with appropriate connection for pipe in use.
• Drop-in type back pressure valve.
P-1-M-6150 6.4-b-d-e
3. BOP & CASING TESTS Reference
3.1. Land, Jack-Ups And Fixed Platforms BOP Pre-Deployment Tests 3.1.1. All BOP stacks will be pressure tested at their rated working pressure,
prior to use, on test stumps.
P-1-M-6150 7.2.1
3.2. Floating Rig BOP Surface Test
3.2.1. The complete BOP stack assembly shall be tested at the surface on test stumps:
• At low pressure of 300psi (21kg/cm2).
• At their rated working pressure
P-1-M-6150 7.3
3.3. Ram type preventer tests after installation on the wellhead
3.3.1. Pipe rams shall be tested with open-end cup testers to a low pressure of 300psi (21kg/cm2) and to a high pressure at least equal to the maximum anticipated wellhead pressure.
P-1-M-6150 7.2.2
3.3.2. In all cases, the maximum test pressure for each BOP test will not exceed 70% of the rated WP of the lowest rated item of equipment in the wellhead assembly, casing or preventer stack assembly, whichever is the lower.
P-1-M-6150 7.2.2
3.3.3. • An open-end cup tester is required or a blind test plug may be always used for BOP testing before or after the shoe is drilled out.
• Tests will be carried out with water.
P-1-M-6150 7.2.3
3.3.4. The accumulator system should be capable of closing each ram BOP within 30 sec
P-1-M-6150 6.2.1-a
3.4. Bag type annular preventer tests
3.4.1. The preventer will be tested to low pressure (300 psi), and to a high pressure at least equal to the maximum anticipated wellhead pressure.
P-1-M-6150 7.2.2
3.4.2. Closing time on 5” DP should not exceed 30secs for annular preventers smaller than 183/4” nominal bore and 45secs for annular preventers of 183/4” and larger
P-1-M-6150 6.2.1-a
3.5. Blind/Shear ram type preventer tests after installation on the wellhead
3.5.1. Blind/shear rams shall be tested using blind plug testers to the same pressure as stated above for pipe rams.
P-1-M-6150 7.2.2
3.5.2. Where a plug tester is not available, blind/shear rams will be tested against the casing each time a new casing string has been set prior to drilling out the cement. In this case the testing pressure will not be succeed 1,500psi (105kg/cm2).
P-1-M-6150 7.2.2
3.6. Floating BOP Test During and After Installation
3.6.1. While running BOP stacks on the riser joints, the choke/kill and buster lines from surface to the fail-safe shall be pressure tested to their rated working pressure.
P-1-M-6150 7.3.1-1
3.6.2. After the BOP stack is landed on the wellhead, a full function test on both pods shall be carried out.
P-1-M-6150 7.3.1-2
3.7. Floating BOP and Seal Assembly Test After Setting Casing.
3.7.1. The seal assembly shall be pressure tested to a maximum pressure, equal to the maximum anticipated wellhead pressure, or 70% of the internal yield pressure of the weakest item of equipment, whichever is the lower.
P-1-M-6150 7.3.2-1
3.7.2. All BOP components, shall be pressure tested to a low pressure of 300psi (21kg/cm2) and to a minimum pressure equal to the maximum anticipated wellhead pressure, or 70% of the internal yield pressure of the weakest item of equipment, whichever is the lower.
P-1-M-6150 7.3.2-3
3.8. Kill/choke lines & manifold tests
3.8.1. Every time tests are carried out on the BOP stack, the associated equipment shall also be tested, with water.
After the first BOP installation, the equipment shall be tested at their rated working pressure.
On routine tests, they will be tested at to least the same pressure applied for the BOP test.
P-1-M-6150 7.4.4-c P-1-M-6150 7.5
3.9. Casing tests
3.9.1. In all cases the test pressure will be no higher than 70% of API minimum internal yield pressure of the weakest casing in the string or to 70% of the BOP working pressure.
P-1-M-6150 7.5
3.10. BOP operating equipment
3.10.1. All BOP operating equipment hoses, control panels, regulator connections, shall be regularly checked and tested to the maximum manufacturers recommended values for closing and opening BOP.
P-1-M-6150 7.4.3
3.11. Diverter tests
3.11.1. They mainly consist on function test and closing time evaluation.
Closing time (on 5” DP):
• 30 seconds : diverter type • < 20”
• 45 seconds : diverter type • • 20”
P-1-M-6150 9.4.3
4. TESTS FREQUENCY Reference