IPM-ST-WCI-025 Casing and Tubing Design_270905

Prepared by: IPM Stds Ctte

IPM

Ref. IPM-ST-WCI-025 IPM-ST-WCI-0 25

Verified by: G. Cuvillier

Casing and Tubing Design

Approved by: G. Ritchie Ritchie

Standard

Page Page 1 of 10 10

Ver. 1.1.1

Issued: 27 Sept 2005

IPM CASING AND TUBING DESIGN STANDARD

Rev

Issue

Revisio Revision n Descript Description ion

Prepared Prepared by Verified Verified by

Date 1.1.1

27 Sept 2005

Approve Approved d by

Statement of Standard, Implementation and monitoring – Change of wording

IPM WCI

G. Cuvillier

G.Ritchie

Standards

IPM Well

Committee

Eng & Ops Manager

1.1.0

16-04-03

Change liner and tieback external pressure profiles

G.Lindsay

G.Ritchie IPM WCI Well Engineering Manager

L.Hibbard IPM WCI VP

1.0.0

31-01-02

Supersedes IPM-WELL-S029 IPM-WELL-S029

G.Lindsay

G.Ritchie

L.Hibbard

Rev

Issue Date

Revisio Revision n Descript Description ion

Prepared Prepared by Verified Verified by

This revision approved by ;

Approve Approved d by

Signed

G.Ritchie IPM Well Eng & Ops Manager

Warning: Paper copies of this document document are UNCONTROLLED. This copy valid only only at the time of printing. The controlled version of this document is stored on the Schlumberger IPM Intouch Web Site http://www.intouchsupport.com/ Please check the Revision History on the first page of the document at that site for any revisions.

The CUSTODIAN of this document is the VERIFYING ENTITY. The document control requirements are outlined in the IPM-PR-QAS-001 Document Control & Numbering Procedure.

Copyright, Schlumberger, Unpublished Work, All Rights Reserved.


IPM



Approved by: G. Ritchie

Standard

Ref. IPM-ST-WCI-025 Ver. 1.1.1

Page 2 of 10


TABLE OF CONTENTS

1.

STATEMENT OF STANDARD...............................................................................................................3

2.

OBJECTIVE............................................................................................................................................3

3.

SCOPE....................................................................................................................................................3

4.

IMPLEMENTATION AND MONITORING ........................................... .............................................. ..... 3 4.1 Definitions..............................................................................................................................................3 4.2 Information to be gathered prior to casing and tubing design ........................................................4 4.3 Considerations when defining the anticipated load cases ..............................................................4 4.4 Minimum Design Factors .................................... .................................... ............................................. 5 4.5 Minimum Considerations for Burst and Collapse Load Cases........................................................6 4.6 Considerations for Other Loads..........................................................................................................7 4.7 Effect of temperature............................................................................................................................8 4.8 Effect of inner casings/liners on outer casings.................................................................................8 4.9 Compression Effects ........................................ .................................... ................................................ 8 4.10 Material Selection in Sour Environments .................................. .................................. ....................... 8 4.11 CO2 Corrosion-Resistant Material ................................. .................................... .................................. 8 4.12 Casing and Tubing Design Software ........................................ ............................................ .............. 9 4.13 Connection Ratings ...................................... .............................................. .......................................... 9 4.14 Connection Type .................................. .............................................. .............................................. ..... 9 4.15 Responsibilities...................................................................................................................................10

5.

DOCUMENTS AND REFERENCES ..................................... .......................................... ..................... 10



IPM




Standard


Page 3 of 10


1. STATEMENT OF STANDARD All casings and tubings shall be designed to withstand all loads that can be imposed on them during installation and throughout the lifetime of the well. The current version of TDAS will be used to simulate all load cases as described in this standard. No well construction program shall be commenced without an approved casing and tubing design. If a series of similar wells are to be constructed, a detailed generic design shall be done at the inception of the project. Subsequently, individual wells shall be compared with the generic design and a document certifying that the specific well conditions were found to be within the generic design envelope shall be prepared and kept in the well file.

2. OBJECTIVE To ensure that t he well will be drilled and operated safely throughout its lifetime. To ensure that consistent minimum design criteria and factors are used for all IPM casing and tubing design activities.

3. SCOPE The standard applies to all casing and tubing design work on IPM projects where IPM is responsible for well design and/or mechanical integrity of the well. It shall also serve as a basis for checking the integrity of client and/or third party designs.

4. IMPLEMENTATION AND MONITORING 4.1 Definitions Oil Well An oil well is defined as a well with a Gas Oil ratio (GOR) less than 3000 SCFT/Bbl of liquid. Conductor The conductor is used to prevent washout of shallow formations and to enable diverters to be installed. Surface Casing The surface casing is used to isolate shallow hydrocarbon/water zones and loss zones prior to penetrating deeper, potentially hydrocarbon-bearing, zones. Surface casings shall be set within competent formations thereby allowing the installation of blowout preventers prior to drilling into potentially hydrocarbon-bearing and pressured formations. Intermediate Casing The intermediate casing is used to isolate hydrocarbon-bearing, abnormal pressure zones, fractured and loss zones, problem shales, and similar geological horizons. Intermediate casings are set within more competent formations than the surface casing thereby allowing higher blowout protection for drilling deeper (than the previous casing will allow). Drilling Liner The drilling liner is used in the following situations:



IPM




Standard

•

•


Page 4 of 10


In cases where it is not feasible (economically or technically) to run a casing string to surface In order to isolate deeper hydrocarbon-bearing zones, abnormally pressured zones, fractured or loss zones, unstable shales, or similar problematic geological horizons.

It shall be set within a more competent formation than the previous casing (for higher shoe strength) thus allowing a subsequent casing string to be set deeper. Production Casing / Liner The production casing/liner is the last casing/liner in the well. It isolates the different zones above and/or within the production zone and withstands all the anticipated loads during production and/or testing operations for the well’s lifetime. Any casing/liner that creates an annular space with the production tubing shall be treated as a production casing/liner. Drilling Tieback Drilling tieback is the casing string connecting wellhead to drilling liner top with specially designed connector. Use of liners with tie-back casing strings also results in lower hanging weights in the upper part of the well and thus often permits more economical design. Production Tieback Production tieback is the casing string connecting wellhead to production liner top with specially designed connector. Production liners with tieback casing strings are most advantageous when exploratory drilling below the productive interval is planned. Sour Environment An environment is considered sour if the total pressure is at least 65 psia and the partial pressure of H2S in a wet (water as liquid phase) gas phase of a gas, gas condensate, or crude oil system is equal to or exceeds 0.05 psia (NACE MR0175-95 definition).

H2S Partial Pressure (psia) Total pressure in psia x H2S concentration in ppm x 1/1,000,000. Example: If the H2S concentration is 20 ppm, and the expected absolute pressure is 4000 psia, the partial pressure of H2S is 0.08 psia and H2S service equipment must be used.

4.2 Information to be gathered prior to casing and tubing design •

•

•

4.3

Estimated pore pressure and rock mechanical strength using offset borehole strength versus depth relationship, offset static and flowing temperature gradients. The minimum and maximum casing sizes at TD that will allow the anticipated logging, testing, and/or completion program. The effects of geological uncertainties on casing setting depths and the ability to safely circulate out the maximum anticipated kick volume.

Considerations when defining the anticipated load cases •

Well type (exploration, appraisal, or development well).

•

Function of the well (oil/gas producer, gas/water injector).

•

•

Well geometry (effect on predicted values of torque and drag, especially for horizontal and extended reach wells). Pore pressures, fracture pressures, and temperatures.



IPM

Ref. IPM-ST-WCI-025




Standard

•

•


Drilling fluid used (e.g. for air, foam or aerated mud, the casing shall normally be designed for full internal evacuation which caters for fluid supply system failure with the resulting exposure of the wellbore to atmospheric pressure.) Cementing and fracture program.

•

Pressure testing.

•

Page 5 of 10

Lithology (e.g. point loading due to mobile salt formations)

•

•

Ver. 1.1.1

The effects of anticipated pipe deterioration due to corrosion, wear, thermal effects, fatigue, or other causes. Choke manifold backpressure during well control procedures.

4.4 Minimum Design Factors Table 1. Minimum Design Factors DESIGN LOADS

Collapse

Surface & intermediate casings, drilling liners, drilling tiebacks

Production casings/ liners, production tiebacks

Tubing

1.0

1.1

1.1

1.1

1.1

1.1

- critical service

1.25

1.25

1.25

Tension

1.6

1.6

1.6

Compression

1.2

1.2

1.2

1.25

1.25

1.25

Burst - normal service

1

2

3

Triaxial

1.

All casings, liners, and tubings are considered “NORMAL service” if the internal SURFACE pressure is LESS THAN 5000 psi and the string IS NOT expected to suffer deterioration due to H2S, CO2, thermal effects, stress-corrosion cracking, etc.

2.

All casings, liners, and tubings are considered “CRITICAL service” if the internal SURFACE pressure is GREATER THAN OR EQUAL TO 5000psi and/or the string may suffer deterioration due to H2S, CO2, thermal effects, stress-corrosion cracking, etc. Triaxial analysis shall be done for critical service casings.

3.

OD and wall tolerances shall be considered when calculating the VME design factor.



IPM




Standard


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4.5 Minimum Considerations for Burst and Collapse Load Cases Table 2. Minimum Internal (I) and External (E) Load Cases

Load Cases to Consider for Each String

Conducto r

Surface, /Interm., Drlg Liners, 6 Drlg Tieback

As Cemented 1 Mud (I), Cement Slurry + Mud (E) Green Cement Pressure Test Surface Pressure + Mud (I), Cement Slurry +Mud (E)

5

Full Evacuation 0 ppg (I), Mud or Packer Fluid (E) 2

Full Evacuation - Hot 0 ppg (I), Surface Pressure + Packer Fluid (E) 1/3 Evacuation 0 ppg + Mud (I), Mud (E) Full Gas Shut in – Static 3 Shut in WHP + Gas (I), Mud/Packer Fluid (E) 2

Full Gas Shut in - Hot Shut in WHP + Gas (I), Surface Pressure + Packer Fluid (E) Gas Kick BHP - Gas - Mud (I), Pore Pressure (E) 5

Pressure Test Surface Pressure + Mud (I), Pore Pressure (E) Pressure Test – Tubing Surface Pressure + Brine (I), Brine (E) Surface Tubing Leak – Static 3 Shut in WHP + Packer Fluid (I), See Note 7 Below (E) 2

Surface Tubing Leak - Hot 3 Shut in WHP + Packer Fluid (I), See Note 7 Below (E) 4

After Perforating BHP - Packer Fluid (I), Packer Fluid (E)


Production Csg, Liners. Production Tiebacks

Tubing


IPM

Ref. IPM-ST-WCI-025




Standard

Ver. 1.1.1

Page 7 of 10


1. Assume pore pressure for external profile if conductor is uncemented. 2. Assume flowing temperature profile. 3. TDAS Gas Prediction Model (GASP) calculates shut in WHP using the temperature profile (static or flowing), 100% methane and BHP equivalent to mud weight at TD minus 0.5ppg. 4. Only to be considered if the mud weight at TD - 0.5 ppg is greater than packer fluid density. It represents the burst load associated with under balanced through tubing perforation. 5. Pressure tests are an “as built” verification of the casing integrity. These load cases are a check to ensure that the casing is not overloaded during testing. The casing design should not be driven by the pressure test unless that pressure test simulates an actual well load case. 6. The Drilling Tieback is a special case and all load cases will use the drilling fluid gradient as the external pressure profile. 7. The Surface Tubing Leak (static and hot) load cases will use the following external pressure profiles: a) For production casing: assume a mud base fluid gradient above the TOC, and a cement mix water gradient below the TOC to previous shoe (if TOC is above the previous shoe), and pore pressure in open hole. b) For production liners: assume a pore pressure gradient below the TOC. c) For production tiebacks: assume a mud base fluid gradient above the TOC, and a cement mix water gradient below the TOC.

4.6 Other Design Considerations Table 3. Other Factors to Consider in Casing and Tubing Design Other Design Considerations

Conductor

Surface/ Interm., Drilling Liners

Dry or Buoyant Weight Wear Corrosion* Buckling Bending Overpull force if stuck Thermal Expansion Temperature Deration Ballooning Fatigue* Piston Effects* Shock Loads*


Production Casing & Liners

Production Tubing


IPM

Ref. IPM-ST-WCI-025




Standard

Ver. 1.1.1

Page 8 of 10


Reciprocation/Rotation* Triaxial Check * Considerations marked with * are not modeled in TDAS

4.7 Effect of temperature 4.7.1 Thermal Derating o

The minimum yield strength of all materials shall be derated when temperatures exceed 212 F. Low o alloy carbon steel casing and tubing shall be derated at 0.03% per F. Other materials shall be derated using available published data.

4.7.2 Annular Pressure Build Up in trapped Annulus Considerations should be given to annular pressure build up in trapped annulus due to temperature e.g. on a Subsea producing well with no access to the annulus.

4.8 Effect of inner casings/liners on outer casings The effect of each casing string during installation, pressure testing, and production on the outer casing strings shall be taken into account.

4.9 Compression Effects Compression effects shall be considered on certain casing strings as follows: •

•

•

Conductor casing: all uncemented portions of the conductor. Surface and intermediate strings: a consideration if the conductor has been cut off and the next string is not cemented to surface. HPHT wells.

4.10 Material Selection in Sour Environments All casings and tubings that can be exposed to sour environments shall be rated for sour service. The following table outlines the suitability of various common steel grades for H2S environments. The suitability of the casing material for specific applications shall be reconfirmed with the casing manufacturer and/or NACE. Table 4.Suitable Operating Temperatures for Casing Grades in H2S Environments (NACE MR0175-2000) Operating Temperature All Temperatures

>150 deg F

>175 deg F

>225 deg F

J55, K55, C75/90, L80, T95

N80 (Q&T), C95

H40, N80, P105/110

Q125* (Q&T)

Notes: Q&T Quenched and Tempered * Made of Chromium - Molybdenum alloy with maximum yield strength of 150,000 psi

4.11 CO2 Corrosion-Resistant Material Chromium-Molybdenum alloys (such as L80 13% Cr ) shall be selected.



IPM

Ref. IPM-ST-WCI-025




Standard

Ver. 1.1.1

Page 9 of 10


4.12 Casing and Tubing Design Software Schlumberger-approved TDAS (Tubular Design and Analysis System) and WEST (Wellbore Simulated Temperature) shall be used. TDAS enables the user to design and analyze tubulars by considering multiple load cases for any string based on an external pressure, an internal pressure, and a temperature profile for each load case. WEST shall be used where temperature is liable to be a critical design consideration (e.g. for production tubing) to provide a simulation of expected temperature profiles which can then be imported into TDAS.

4.13 Connection Ratings Connection ratings should meet or exceed the minimum design factors and considerations for the pipe body ratings. Where the connections are weaker than the pipe body, it should be clearly highlighted in the design. Combined loading (i.e. burst or collapse combined with axial loads and bending moments) shall be taken into account when selecting connections.

4.14 Connection Type Proprietary connections (for example, VAM or Hydril CS) shall be used in place of API connections (such as LTC, STC, EUE, BTC) whenever the operating conditions demand reliable pressure-tight sealing and/or for special clearance applications. Generally, proprietary connections shall be used in the following cases: •

If the casing material requires use of corrosion-resistant alloy material

•

If connection strength is required to be at least 100% of pipe body.

•

For special clearance applications

•

If production tubing temperature is greater than 212°F.

Other specific circumstances for selecting proprietary connections are shown in the following tables:

Table 5. Pressures in Liquid Producing Wells That Require Proprietary Connections Casing or tubing type

SHUT-IN SURFACE PRESSURE >3500 psi

>5000 psi

>7500 psi

Intermediate casings and drilling liners

a

Production casings/ liners

a

Production Tubing

a

a

Table 6. Pressures in Gas Producing Wells That Require Proprietary Connections Casing or tubing type

SHUT-IN SURFACE PRESSURE >3500 psi

>5000 psi

Intermediate casings and drilling liners

a

Production casings/ liners Production Tubing

>7500 psi

a

a

a

a

a



IPM




Standard

•

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•

•

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Proprietary connections with a smooth ID profile should be used for tubing strings in wells with high flow rates. Do not use API casing connections that are coupling weak for internal pressure or axial tension loads (i.e. 7 3/8 in BTC). Confine BTC to 13-3/8 in diameter pipe or less. Short strings of 16 to 20 BTC, with tension design factors greater than 6.0 can be used, but are not justifiable on rigs that have a high day rate. This is due to the difficulty in stabbing and verifying that a proper power tight makeup has been achieved. SR13 seal rings for other than 2-3/8 and 2-7/8 EUE 8R tubing are not recommended due to installation difficulties. A seal ring can easily become trapped in between the pin and box threads during makeup if incorrectly installed. "Oversized" pipe, such as 7-3/4, 9-7/8, 11-7/8, 13-5/8, etc., should never be manufactured with standard API connections. Standard API connections on oversized pipe do not utilize the full performance of the pipe body since the pipe body must be machined down to the D4 diameter of the standard size. Never use a tubing connection that is weaker than the pipe body. A significant fraction of the energy expended during the cyclical loading and unloading of the tubing will be absorbed by the weakest link. A connection that is weaker than the pipe body will become the load sink and will eventually part. If a gas tight connection is required, select a connection with one good seal (e.g. VAM). Multiple seals can interfere with one another and cause more harm then good.

4.15 Responsibilities The Project Manager shall ensure that the Well Engineer is competent in performing Casing and Tubing Design. The most Senior Well Engineer in a project shall have overall responsibility for all casing and tubing designs in that project. All casing and tubing designs should be independently verified and approved by a suitable person.. Additionally, the relevant Well Engineering Manager and/or designate shall approve all critical and special well casing and tubing designs.

5. DOCUMENTS AND REFERENCES IPM-ST-WCI-009 – Casing, liner and Tubing Pressure Testing Standard IPM-ST-WCI-011 – Kick Tolerance Standard IPM-ST-WCI-012 – Barriers Standard IPM-ST-WCI-022 – Well Control While Running Casing Standard IPM-PR-WCI-008 Technical and Operational Integrity Procedure NACE MR0175 - 2003


IPM-ST-WCI-025 Casing and Tubing Design_270905

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