ENI - Casing Design Manual

ARPO

ENI S.p.A. Agip Division

ORGANISING DEPARTMENT

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REFER TO SECTION N.

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STAP

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134

6110

TITLE CASING DESIGN MANUAL

DISTRIBUTION LIST Eni - Agip Division Italian Districts Eni - Agip Division Affiliated Companies Eni - Agip Division Headquarter Drilling & Completion Units STAP Archive Eni - Agip Division Headquarter Subsurface Geology Units Eni - Agip Division Headquarter Reservoir Units Eni - Agip Division Headquarter Coordination Units for Italian Activities Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CDRom version can also be distributed (requests will be addressed to STAP Dept. in Eni Agip Division Headquarter)

Date of issue:

28/06/99

„ ƒ ‚ • € Issued by

REVISIONS

P. Magarini E. Monaci 28/06/99

C. Lanzetta

A. Galletta

28/06/99

28/06/99

PREP'D

CHK'D

APPR'D

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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INDEX 1.

2.

3.

4.

5.

6.

INTRODUCTION

5

1.1.

6

PURPOSE OF CASING

CASING PROFILES AND DRILLING SCENARIOS

7

2.1.

Casing 2.1.1. 2.1.2. 2.1.3. 2.1.4.

7 7 7 7 7

2.2.

Drive, Structural & Conductor Casing 2.2.1. Surface Casing 2.2.2. Intermediate Casing 2.2.3. Production Casing 2.2.4. Liner

Profiles Onshore Wells Offshore Wells - Surface Wellhead Offshore Wells - Surface Wellhead & Mudline Suspension Offshore Wells - Subsea Wellhead

SELECTION OF CASING SEATS

8 8 9 10 11

12

3.1.

Conductor Casi ng

15

3.2.

Surface Casing

15

3.3.

Intermediate Casing

15

3.4.

Drilling Liner

16

3.5.

Production Casing

17

3.6.

CASING AND relative HOLE SIZES 3.6.1. Standard Casing and Hole Sizes

17 21

CASING SPECIFICATION AND CLASSIFICATION

22

4.1.

CASING SPECIFICATION

22

4.2.

API CASING CLASSIFICATION

23

4.3.

NON-API CASING

25

MECHANICAL PROPERTIES OF STEEL

28

5.1.

General

28

5.2.

Stress-Strain Diagram

28

5.3.

Heat Treatment Of Alloy Steels

30

TUBULAR RANGE LENGTHS & COLOUR CODING

36

6.1.

Range lengths

36

6.2.

api tubular marking and colour coding 6.2.1. Markings 6.2.2. Colour Coding

38 38 39

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APPROACH TO CASING DESIGN

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41

7.1.

WELLBORE FORCES

42

7.2.

DESIGN FACTOR (DF) 7.2.1. Company Design Factors 7.2.2. Application of Design Factors

42 44 45

DESIGN CRITERIA

46

8.1.

BURST 8.1.1. Design Methods 8.1.2. Company Design Procedure

46 46 47

8.2.

COLLAPSE 8.2.1. Company Design Procedure

50 50

8.3.

TENSION 8.3.1. General 8.3.2. Buoyancy Force 8.3.3. Company Design Procedure 8.3.4. Example Hook Load During Cementing

54 54 54 59 59

8.4.

BIAXIAL 8.4.1. 8.4.2. 8.4.3. 8.4.4.

STRESS General Effects On Collapse Resistance Company Design Procedure Example Collapse Caclulation

62 62 62 64 65

8.5.

BENDING 8.5.1. General 8.5.2. Determination Of Bending Effect 8.5.3. Company Design Procedure 8.5.4. Example Bending Calculation

67 67 68 70 70

8.6.

CASING WEAR 8.6.1. General 8.6.2. Volumetric Wear Rate 8.6.3. Factors Affecting Casing Wear (Example) 8.6.4. Wear Factors 8.6.5. Detection Of Casing Wear 8.6.6. Casing Wear Reduction 8.6.7. Wear Allowance In Casing Design 8.6.8. Company Design Procedure

72 72 73 76 80 86 86 87 88

8.7.

SALT SECTIONS 8.7.1. General 8.7.2. External Loading Due To Salt Flow 8.7.3. Company Design Procedure

89 89 89 94

CORROSION

96

9.1.

General 9.1.1. Exploration and Appraisal Wells 9.1.2. Development Wells 9.1.3. Contributing Factors to Corrosion

96 96 96 97

9.2.

Forms Of Corrosion 9.2.1. Sulphide Stress Cracking (SSC) 9.2.2. Corrosion Caused By CO2 And Cl-

98 98 105

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Corrosion Caused By H2S, CO2 And Cl-

0 107

9.3.

Corrosion Control Measures

108

9.4.

Corrosion Inhibitors

109

9.5.

Corrosion Resistance of Stainless Steels 9.5.1. Martensitic Stainless Steels 9.5.2. Ferritic Stainless Steels 9.5.3. Austenitic Stainless Steels 9.5.4. Precipitation Hardening Stainless Steels 9.5.5. Duplex Stainless Steel

109 109 110 110 110 111

9.6.

Casing For Sour Service

113

9.7.

Ordering Specifications

114

9.8.

Company Design Procedure 9.8.1. CO2 Corrosion 9.8.2. H2S Corrosion

114 114 115

10. TEMPERATURE EFFECTS

118

10.1. High Temperature Service

118

10.2. Low Temperature Service

119

11. LOAD CONDITIONS

120

11.1. SAFE ALLOWABLE TENSILE LOAD

120

11.2. CEMENTING CONSIDERATIONS 11.2.1. Casing Support 11.2.2. Cementing Loads

120 120 121

11.3. PRESSURE TESTING

122

11.4. BUCKLING AND COMPRESSIve loading 11.4.1. Buckling 11.4.2. Compressive Loads

122 122 123

12. PRESSURE RATING OF BOP EQUIPMENT

126

12.1. BOP selection criteria

126

12.2. Kick tolerance

129

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INTRODUCTION The selection of casing grades and weights is an engineering task affected by many factors, including local geology, formation pressures, hole depth, formation temperature, logistics and various mechanical factors. The engineer must keep in mind during the design process the major logistics problems in controlling the handling of the various mixtures of grades and weights by rig personnel without risk of installing the wrong grade and weight of casing in a particular hole section. World-wide, experience has shown that the use of two/three different grades or two/three different weights is the maximum that can be handled by most rigs and rig crews. After selecting a casing for a particular hole section, the designer should consider upgrading the casing in cases where: • •

Extreme wear is expected from drilling equipment used to drill the next hole section or from wear caused by wireline equipment. Buckling in deep and hot wells.

Once the factors are considered, casing cost should be considered. If the number of different grades and weights are necessary, it follows that cost is not always a major criterion. Most major operating companies have differing policies for the design of casing for exploration and development wells, e.g: • • •

For exploration, the current practice is to upgrade the selected casing, irrespective of any cost factor. For development wells, the practice is also to upgrade the selected casing, irrespective of any cost factor. For development wells, the practice is to use the highest measured bottomhole flowing pressures and well head shut-in pressures as the limiting factors for internal pressures expected in the wellbore. These pressures will obviously place controls only on the design of production casing or the production liner, and intermediate casing.

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PURPOSE OF CASING Casing tubulars are placed in a wellbore for the following reasons: a) b) c) d) e) f)

Supporting the weight of the wellhead and BOP stack. Providing a return path for mud to surface when drilling. Controlling well pressure by containing downhole pressure. Isolating high pressure zones from the wellbore. Isolating permeable zones from the wellbore which are likely to cause differential sticking. Isolating special trouble zones which may cause hole problems e.g.: • • • • • •

g) h) i) j) k)

Swelling clay, shales. Sloughing shales. Plastic formations (evaporites). Formations causing mud contamination e.g. gypsum, anhydrite, salt. Frozen unconsolidated layers in permafrost areas. Lost circulation zones.

Separating different pressure or fluid regimes. Providing a stable environment for packers, liner hangers, etc. Isolating weak zones from the wellbore during fracturing. Isolating permeable productive formations, reducing the risk of underground blowouts. Confining produced fluid to the wellbore and providing a flow path to surface.

Production casing must perform a number of critical functions as follows: a) b) c) d) e)

Providing internal pressure containment when the tubing system leaks or fails. Preventing wellbore fluids from contaminating production. Providing protection for completion equipment. Providing access to producing formations for remedial operations. Providing cement integrity across producing formations.

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2.

CASING PROFILES AND DRILLING SCENARIOS

2.1.

CASING PROFILES The following are the various casing configurations which can be used for onshore and offshore wells.

2.1.1.

Onshore Wells • • • • • • •

2.1.2.

Drive/structural/conductor casing Surface casing Intermediate casings Production casing Intermediate casing and drilling liners Intermediate casing and production liner Drilling liner and tie-back string.

Offshore Wells - Surface Wellhead As in onshore above.

2.1.3.

Offshore Wells - Surface Wellhead & Mudline Suspension • • • • • •

2.1.4.

Drive/structural/conductor casing Surface casing and landing string Intermediate casings and landing strings Production casing Intermediate casings and drilling liners Drilling liner and tie-back string.

Offshore Wells - Subsea Wellhead • • • • • • •

Drive/structural/conductor casing Surface casing Intermediate casings Production casing Intermediate casing and drilling liners Intermediate casing and production liner Drilling liner and tie-back string.

Refer to the following sections for descriptions of the casings listed above.

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DRIVE, STRUCTURAL & CONDUCTOR CASING The purpose of this first string of pipe is primarily to protect incompetent surface soils from erosion by drilling fluids. Where formations are sufficiently stable, this string may be used to install the full mud circulation system. It also serves the following purposes: • • • • •

Guide the drilling string and subsequent casing into the hole. The conductor in offshore drilling may form a part of the piling system for a wellhead jacket or piled platform. Provide centralisation for the inner casing strings which limits column buckling. They do not carry direct axial loads except during initial installation of the surface casing. Reduce wave and current loadings imposed on the inner strings. Provide sacrificial protection against oxygen corrosion in the splash zone. Minimise the transfer of stresses to the inner casings resulting from the settlement and rotational movement of gravity platforms.

The conductor casings are usually driven completely to depth or, alternatively, run into a predrilled or jetted hole and cemented. If they are driven, they must be designed to withstand hammering loads. Conductor casings, in offshore drilling with subsea BOP's, are usually either jetted into place or cemented in a predrilled hole. They support a Temporary Guide Base which accommodates and aligns all future wellhead installations for both the drilling and production phases. They directly carry both the axial and bending loads imposed by the wellhead, but are rigidly connected to the next casing with centralisers and cement in order to dissipate loading and minimise resulting stresses. 2.2.1.

Surface Casing The surface casing is installed to: • • • •

Prevent poorly consolidated shallow formations from sloughing into the hole. Enable full mud circulation. Protect fresh water sands from contamination from the drilling mud. Provide protection against hydrocarbons found at shallow depths.

The surface casing string is cemented to surface or seabed and is the first casing on which BOPs can be mounted. It is important to appreciate that the amount of protection provided against internal pressure will only be as strong as the formation strength at the casing shoe, hence it may be necessary to vent any influx taken through the surface string, rather than attempt containment. The surface string usually supports the wellhead and subsequent casing strings. In offshore wells, above the top of the cement, the surface casing must be centralised to limit column buckling. The annulus between the conductor and surface string is usually left uncemented above the mudline to minimise load transfer and bending stresses in the surface string.

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Intermediate Casing These are used to ensure there is adequate blow-out protection for deeper drilling and to isolate formations or hole profile changes, that can cause drilling problems. The first intermediate string is the first casing providing full blow-out protection. Its setting depth is often chosen so that it also isolates troublesome formations, loss zones, shallow hydrocarbons, water sands, or the build-up section of deviated wells. It is usually cemented up into the shoe of the conductor string and in some cases all the way to surface. It is essential to install an intermediate casing string whenever there is a risk of experiencing a kick which could cause breakdown at the previous casing shoe, and/or severe losses in the open hole section. An intermediate casing string is, therefore, nearly always set in the transition zone above or below significant overpressures, and in any cap rock below a potential severe loss zone. Similarly, it is good practice when appraising untested or deeper horizons, to case off the known hydrocarbon bearing intervals as a contingency against the possibility of encountering a loss circulation zone. Obviously the latter is intended primarily for massive reservoir sections rather than sand-shale sequences with numerous small reservoirs and subreservoirs. An intermediate string may also be set simply to reduce the overall cost of drilling and completing the well by isolating intervals which have been found to cause mechanical problems in the past. For example it may be desirable to isolate: • • • • • • •

Swelling gumbo shale. Brittle caving shale. Creeping salt. Over-pressured permeable stringer. Build-up or drop-off section. High permeability sand. Partly depleted reservoir that causes differential sticking.

The designer should plan to combine many of these objectives when selecting a single casing point. A liner may be used instead of a full intermediate casing and difficult wells may actually contain several intermediate casings and/or liners. Caution should be taken when using liners as it is necessary to ensure the higher casing is designed for the pressures at lower depths. The cement should cover all hydrocarbon zones and any salt or other creeping evaporites. Zones containing highly corrosive formation waters are also often cemented off, especially where there may be aquifer movement which replenishes the corrosive elements around the wellbore. Longer cement columns are sometimes required to prevent buckling of the casing during deeper drilling. Many operating companies cement up inside the previous casing shoe for this reason and is legislated on by some regulatory authorities.

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Production Casing This is the string through which the well will be completed, produced and controlled throughout its life. On exploration wells this life may amount to only a very short testing period, but on most development wells it will span a significant number of years during which many repairs and recompletions may be performed. It is essential therefore that production casing retains its integrity throughout its life. In most cases, the production casing will serve to isolate the productive intervals, to facilitate proper reservoir maintenance and/or prevent the influx of undesired fluids. In other cases, accumulation conditions are such that the well can be cased with an open hole section below the casing for an open hole completion (Refer to the completion design manual). The size of the production casing should be selected to meet with the desired method of completion and production. On production wells the drilling engineer must design the casing in conjunction with the completion engineer to ensure the optimum completion design is obtained. This usually impacts on the production casing design with regard to: • • • • • •

Well flow potential, i.e. tubing size. The possibility of a multiple tubing string completion. The space required for downhole equipment e.g. safety valves, artificial lift equipment etc. The geometry required for efficient through-tubing well intervention operations. Potential well servicing and recompletion requirements. Adequate annular clearances to permit circulation at reasonable rate and pressures.

It is also possible that the casing itself could be used as a conduit for maximising well deliverability (casing flow), for minimising the pressure losses during frac jobs, for chemical injection or for lift gas. Consideration must be given to production operations which will affect the temperature of the production casing and impose additional thermal stresses. Annulus thermal expansion can cause production casing collapse when it is cemented up into the intermediate casing. The loads to which a production casing is subjected are, therefore, quite different from those imposed during drilling. It is very important that the selection of the steel grade and connections for the production string are made correctly. Special considerations are required where the production casing will be drilled through and may therefore suffer some damage e.g.: open hole (barefoot) completions, open hole gravel packs, liner completions, deep zone appraisal. In a liner completion, both the liner and casing form the production string and must be designed accordingly.

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Liner A liner is a string of pipe which is installed but does not extend all the way to surface. It is hung a short distance above the previous casing shoe and is usually cemented over its entire length to ensure it seals within the previous casing string. Drilling liners may be installed to: • • •

Increase shoe strength. Meet with rig tensional load limitations. Minimise the length of reduced diameter and the possible adverse effects on drilling hydraulics.

Production liners may be installed to: • • •

Reduce costs. Minimise the length of reduced diameter production tubing and the consequent adverse effect upon well flow potential. Meet with rig tensional load limitations on occasions on deep wells.

Either type of liner may subsequently be tied-back to surface with a string of pipe stabbed into a liner hanger Polished Bore Receptacle (PBR). There are a number of disadvantages to installing liners, including: • • • •

The risk of poor pressure integrity, either across the liner lap due to poor cementation or as a result of wear to the casing from which the liner is hung off. The risk of the liner running equipment being cemented in the hole. The difficulty of obtaining a good cementation due to smaller liner to hole and liner to production casing clearances. The need to set a retrievable bridge plug above the liner lap if the BOP stack needs to be removed. (This does not apply to completion operations when a tubing string has been run and landed.)

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SELECTION OF CASING SEATS The selection of casing setting depths is one of the most critical in the well design process and is based on: • • • • • • • • • • •

Total depth of well. Pore pressures. Fracture gradients. The probability of shallow gas pockets. Problem zones. Depth of potential prospects. Time limits on open hole drilling. Casing programme compatibility with existing wellhead systems. Casing programme compatibility with planned completion programme (production well). Casing availability (grade and dimensions). Economy, i.e. time consumption to drill the hole, run casing and cost of equipment.

When planning, all available information should be carefully documented and considered to obtain knowledge of the various uncertainties. Information is sourced from: • •

Evaluation of the seismic and geological background documentation used as the decision for drilling the well. Drilling data from offset wells in the area. (Company wells or scouting information).

The key factor to satisfactory picking of casing seats is the assessment of pore pressure and fracture pressures throughout the well. As the pore pressures in a formation being drilled approach the fracture pressure at the last casing seat then installation of a further string of casing is necessary. figure 3.a and figure 3.b show typical examples of casing seat selections.

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Figure 3.A - Example of Idealised Casing Seat Selection Notes to figure 3.a above: a)

Casing is set at depth 1, where pore pressure is P1 and the fracture pressure is F1. b) Drilling continues to depth 2, where the pore pressure P2 has risen to almost equal the fracture pressure (F1) at the first casing seat. c) Another casing string is therefore set at this depth, with fracture pressure (F2). d) Drilling can thus continue to depth 3, where pore pressure P3 is almost equal to the fracture pressure F2 at the previous casing seat. This example does not include any safety or trip margins, which would, in practice, be taken into account.

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Figure 3.B - Example Casing Seat Selection (for a typical geopressurised well using a pressure profile).

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CONDUCTOR CASING Setting depth is usually shallow and selected so that drilling fluid may be circulated to the mud pits while drilling the surface hole. The casing seat must be in an impermeable formation with sufficient fracturing resistance to allow fluid circulation to the surface. Where working with subsea wellheads, no there is no circulation through the conductor string to the surface. It is set deep enough to assist in stabilising the guide base to which guide lines are attached. Large sizes are required (usually 16ins to 30ins diameter) as necessary to accommodate the size of all subsequently required strings.

3.2.

SURFACE CASING Setting depths should be in an impermeable section below any fresh water formations. In some instances, near-surface gravel or shallow gas may need to be cased off shallower. The depth should be great enough to provide a fracture gradient sufficient enough to allow drilling to the next casing setting point and to provide reasonable assurance that broaching to the surface will not occur in the event of BOP closure to contain a kick. In hard rock areas the string may be relatively shallow, but in soft rock areas deeper strings are necessary.

3.3.

INTERMEDIATE CASING The most predominant use of intermediate casing is to protect normally pressured formations from the effects of increased mud weight needed in deeper drilling. An intermediate string may be necessary to case off lost circulation zones, salt beds, or sloughing shales. In cases of pressure reversals against depth, intermediate casing may be set to allow reduction of mud weight. When a transition zone is penetrated and mud weight increased, the normal pressure interval below surface pipe is subjected to two detrimental effects: • •

The fracture gradient may be exceeded by the mud gradient, particularly if it becomes necessary to close-in on a kick The result is loss of circulation and the possibility of an underground blow-out occurring. The differential between the mud column pressure and formation pressure is increased, increasing the risk of stuck pipe.

To ensure the integrity of the surface casing seat, leak-off tests are necessary and must be specified in the Drilling Programme.

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Sometimes it is necessary to alter the setting depth of the intermediate casing during drilling under certain circumstances such as when: • •

3.4.

Hole problems prohibit further drilling. Pore pressure changes occur substantially shallower or deeper than originally calculated or estimated. For this reason the Geological Drilling Programme should state the pore pressure requirement at which casing should be set when setting casing into a transition zone.

DRILLING LINER The setting of a drilling liner is often an economically attractive decision in deep wells as opposed to setting a full string. Such a decision must be carefully considered as the intermediate string must be designed for burst as if it were set to the depth of the liner. If drilling is to be continued below the drilling liner then burst requirements for the intermediate string are further increased which increases the cost of the intermediate string. Also, there is the possibility of continuing wear of the intermediate string that must also be evaluated. If a production liner is planned, then either the production liner or the drilling liner should be tied back to the surface as a production casing. If the drilling liner is to be tied-back, it is usually better to do so before drilling the hole for the production liner. By doing this, the intermediate casing can be designed for a lower burst requirement, resulting in considerable cost savings. Also, any wear to the intermediate string is spanned prior to drilling the producing interval. If increasing mud weight will be required, while drilling hole for the drilling liner, then leak-off tests must be conducted and specified in the casing programme for the intermediate casing shoe within the Geological Drilling Programme (Refer to the Drilling Procedures Manual). Insufficient fracture gradient at the shoe may limit the depth of the drilling liner.

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PRODUCTION CASING Whether production casing or a liner is installed, the depth is determined from the geological objective. Depths, hence the casing programme, may have to be altered accordingly if depths come in too high or too low. The objective and the method of identifying the correct production casing depth should also be stated in the programme. To cater for some completion operations, a sufficient amount of sump is required for fill during production or well intervention operations, run out for logging tools and to accommodate lost tools or dropped TCP guns, etc. Drilling extra hole, for dropping TCP guns or similar reasons, may be costly and the effectiveness of such considerations should be seriously evaluated before commitment.

3.6.

CASING AND RELATIVE HOLE SIZES In general, it is good practice to run standard bit sizes but in deep wells, thick walled casing may be necessary to provide sufficient strength. The designer can sometimes solve this problem by specifying ‘special’ drift casing which will allow running of bits with diameters approaching the casing inside diameter rather than being limited to drift diameter. Manufacturers produce oversize casing in several sizes providing strength comparable to API sizes, but with clearances to suit standard bit sizes. A typical well may have 30ins drive/ structural/conductor casing, 20ins surface casing, 133/8ins and 95/8ins intermediate casing and 7ins production casing/liner. Although the above is one of the most common arrangements, there is a multitude of different combinations of casing sizes which the operator may choose to use if he desires, and if the casing design allows. For a normal exploration well, it is recommended that an 81/2ins hole be the smallest diameter planned because of drilling and evaluation difficulties encountered with 6ins. A 6ins hole size should only be planned as a contingency. figure 3.c shows the choice of casing and bit sizes available to engineers.

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Figure 3.C - Casing and Bit Selection Chart

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The chart in figure 3.c can be used to select the casing bit sizes required to fulfil many drilling programme options. To use the chart: 1) 2) 3)

Determine the casing or liner size for the last size pipe to be installed. Enter the chart at that point. The flow of the chart then indicates hole sizes that may be required to set that size pipe (i.e., 5” Liner inside 6” or 61/2” hole). Solid lines indicate commonly used bits for that size pipe and can be considered to have adequate clearance to run and cement the casing or liner (i.e., 51/2” Casing inside 77/8” hole). The broken lines indicate less common optional hole sizes used (i.e., 5” inside 61/8” hole, etc.). The selection of one of these broken paths requires special attention be given to the connection, mud weight, cementing and doglegs. Large connection ODs, thick mud cake build-up, problem cementing areas (high water loss, lost returns, etc.) and doglegs all aggravate the attempt to run casing and liners in low clearance situations. Once the hole size has been selected. a casing large enough to allow passage of a bit to make that hole can be selected. The solid lines are commonly required casing sizes. encompassing most weights (i.e., 61/2” bit inside 75/8” casing). The broken lines indicate casing sizes where only the lighter weights can be used (i.e. 61/8” inside 7” casing). This selection process is repeated until the anticipated number of casing sizes has been reached.

Note:

Some drilling programmes can require special tools and operations to obtain the wellbore size for the casing to be installed. An underreamer is a drilling tool, used to enlarge section of hole below a restriction (situations where equipment, such as BOP or wellhead size restrictions, limit the tool entry size).

figure 3.d shows the standard casing programme and figure 3.e the possible alternative. further standard casing and hole sizes information is shown in table 3.a.

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Figure 3.D - Standard Casing Programme

Figure 3.E - Alternative Casing Programme

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3.6.1.

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Standard Casing and Hole Sizes Largest Inner Casing Size

Outer Casing Size

Under-Reaming Minimum Pilot Hole Size

Under-reamed Diameter

Maximum Tool OD

20

181/2

26

18

20

16

1

17 /2

22

17

16

3

13 /8

3

14 /4

1

17 /2

14

13 /8 (48-68#)

3

10 /4

1

12 /4

15

113/4

113/4

85/8

105/8

121/4

10

9 /8 (29.3#)

5

7 /8

3

8 /4

1

11 /2

81/4

85/8 (24-32#)

65/8

75/8

91/2

71/4

85/8 (36-49#)

6

73/8

9

7

5

7 /8

1

5 /2

1

6 /4

1

8 /2

6

7 (17-32#)

5

6

8

53/4

24

3

5

Table 3.A - Recommended Casing Size Versus Hole Size Note:

Recommendations above are based on: • •

The minimum clearance of 0.400” on diameter between the outer string drift diameter and inner coupling diameter. The clearance between the hole wall and the coupling OD is at least 2” on diameter. Less clearance than this may create a back pressure which will dehydrate the cement to a point where it cannot be pumped.

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CASING SPECIFICATION AND CLASSIFICATION There is a great range of casings available from suppliers from plain carbon steel for everyday mild service through exotic duplex steels for extremely sour service conditions. The casings available can be classified under two specifications, API and non-API. Casing specifications, including API and its history, are described and discussed in sections 4.1 and 4.2. Non-API casing manufacturers have produced products to satisfy a demand in the industry for casing to meet with extreme conditions which the API specifications do not meet. The area of use for this casing are also discussed in section 4.1 below. The properties of steel used in the manufacture of casing is fundamentally important and should be fully understood by design engineers, and to this end these properties are described in section 4.2.

4.1.

CASING SPECIFICATION The American Petroleum Institute (API) has an appointed Committee on Standardisation of tubular goods which publishes, and continually updates, a series of Specifications, Bulletins and Recommended Practices covering the manufacture, performance and handling of oilfield tubular goods. They also license manufacturers to use the API Monogram on products which meet with their published specifications therefore can be identified as complying with the standards. The API Forum has been in existence since 1924, and their standardisation of oilfield equipment and practices are almost universally accepted as the world standard on tubulars. This does not mean that the published performance data is accepted as the best theoretical representation of the parameters of tubulars. It is essential that design engineers are aware of any changes made to the API specifications. All involved with casing design must have immediate access to the latest copy of API Bulletin 5C2 which lists the performance properties of casing, tubing and drillpipe. Although these are also published in many contractors' handbooks and tables, which are convenient for field use, care must be taken to ensure that they are current. Also a library of the other relevant API publications shall be available and design engineers should make themselves familiar with these documents and their contents. It should not be interpreted from the above that only API tubulars and connections may be used in the field as some particular engineering problems are overcome by specialist solutions which are not yet addressed by API specifications. In fact, it would be impossible to drill many extremely deep wells without recourse to the use of pipe manufactured outwith API specifications (non-API). Similarly, many of the ‘Premium’ connections that are used in high pressure high GOR conditions are also non-API.

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When using non-API pipe, the designer must check the methods by which the strengths have been calculated. Usually it will be found that the manufacturer will have used the published API formulae (Bulletin 5C3), backed up by tests to prove the performance of his product conforms to, or exceeds, these specifications. However, in some cases, the manufacturers have claimed their performance is considerably better than that calculated by the using API formulae. When this occurs the manufacturers claims must be critically examined by the designer or his technical advisors, and the performance corrected if necessary. It is also important to understand, that to increase competition, the API tolerances have been set fairly wide. However, the API does provide for the purchaser to specify more rigorous chemical, physical and testing requirements on orders, and may also request place independent inspectors to quality control the product in the plant. 4.2.

API CASING CLASSIFICATION Casing is classified by: • • • • • •

Outside diameter. Nominal unit weight. Grade of the steel. Type of connection. Length by range. Manufacturing process

An example of an API table showing the parameters listed above in given in table 4.a. Reference should always be made to current API specification 5C2 for casing lists and performances.

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Col 1

Col 2

Size: OD

Col 3

Col 4 Wall Thickness

0

Col 5

Nominal Wt

Grade

ins

mm

lbs per ft

Grades Inc

ins

mm

Short

5

219.1 219.1 219.1 219.1 219.1 219.1 219.1 219.1 219.1 244.5 244.5 244.5 244.5 244.5 244.5 244.5 244.5 244.5 244.5 244.5 244.5 273.1 273.1 273.1 273.1 273.1 273.1 273.1 273.1 273.1 273.1 273.1 273.1 273.1 298.5 298.5 298.5 298.5 339.7 339.7 339.7 339.7 339.7 406.4 406.4 406.4 473.0 473.0 508.0 508.0 508.0 508.0

24.00 28.00 32.00 32.00 36.00 36.00 40.00 44.00 49.00 32.30 36.00 36.00 40.00 40.00 43.50 47.00 53.50 59.40 64.90 70.30 75.60 32.75 40.50 40.50 45.50 51.00 55.50 60.70 65.70 59.40 65.70 73.20 79.20 85.30 42.00 47.00 54.00 60.00 48.00 54.50 61.00 68.00 72.00 65.00 75.00 84.00 87.50 87.50 94.00 94.00 106.50 133.00

J, K H H J, K J, K C, L, N C, L, N, P C, L, N, P C, L, N, P, Q H H J, K J, K C, L, N C, L, N, P C, L, N, P C, L, N, P, Q C 90 only C 90 only C 90 only C 90 only H H J, K J, K C, K, K, N, P C, L, N, P P, Q P, Q C 90 only C 90 only C 90 only C 90 only C 90 only H J, K J, K J,K,N,C,L,P,Q H J, K J, K C,L,J,K,N,P,Q C, L, N, P, Q H J, K J, K H, J, K J, K H, J, K J, K J, K J, K

0.264 0.304 0.352 0.352 0.400 0.400 0.450 0.500 0.557 0.312 0.352 0.352 0.395 0.395 0.435 0.472 0.545 0.609 0.672 0.734 0.797 0.297 0.350 0.350 0.400 0.450 0.495 0.545 0.595 0.545 0.595 0.672 0.734 0.797 0.333 0.375 0.435 0.489 0.330 0.380 0.430 0.480 0.514 0.375 0.438 0.495 0.435 0.435 0.438 0.438 0.500 0.635

6.71 7.72 8.94 8.94 10.16 10.16 11.43 12.70 14.15 7.92 8.94 8.94 10.03 10.03 11.05 11.99 13.84 15.47 17.07 18.64 20.24 7.09 8.89 8.89 10.16 11.43 12.57 13.84 15.11 13.84 15.11 17.07 18.64 20.24 8.46 9.52 11.05 12.42 8.38 9.65 10.92 12.19 13.06 9.52 11.13 12.57 11.05 11.05 11.13 11.13 12.70 16.13

X X X X X

8 /8 85/8 85/8 85/8 85/8 85/8 85/8 85/8 85/8 95/8 95/8 95/8 95/8 95/8 95/8 95/8 95/8 95/8 95/8 95/8 95/8 103/4 103/4 103/4 103/4 103/4 103/4 103/4 103/4 103/4 103/4 103/4 103/4 103/4 113/4 113/4 113/4 113/4 133/8 133/8 133/8 133/8 133/8 16 16 16 185/8 185/8 20 20 20 20

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Type of Thread

X X X X

Long

Buttress

Extreme Line

X X X X X X

X X X X X X

X X X X X X

X X X X X X

X X X X X X

X X X X X

X X X X X X X X

X X X X X X

X X X X X X X X X X X X X

X X X X X X X X X X

X

X

X X

X X

Table 4.A - Example API Casing List

X X X

X X X X

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4.3.

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NON-API CASING Eni-Agip Division and Affiliates policy is to use API casings whenever feasible. Some manufacturers produce non-API casings for H2S and deep well service where API casings do not meet requirements. The most common non-API grades are shown in the attached table figure 4.a shows the API and non-API materials available and the environment in which they are recommended to be used.

Figure 4.A- Casing Materials Selection

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Domain

Mild Environment

Domain “A”

Sulphide Stress Corrosion Cracking (medium pressure and temperature)

Domain “B”

Sulphide Stress Corrosion Cracking (high pressure and temperature)

Domain “C”

Wet CO2 Corrosion

Domain “D”

Material

Domain “E”

Domain “F”

SM 95G SM 125G

API

SM 80S SM 90S SM 95S SM 85SS SM 90SS SM C100 SM C110 SM 9CR 75 SM 9CR 80 SM 9CR 95 SM 13CR 75 SM 13CR 80 SM 13CR 95 SM 22CR 65* SM 22CR 110** SM 22CR 125** SM 25CR 75* SM 25CR 110** SM 25CR 125** SM 25CR 140** SM 2535 110 SM 2535 125 SM 2242 110 SM 2242 125 SM 2035 110 SM 2035 125 SM 2550 110 SM 2550 125 SM 2550 140 SM 2060 110*** SM 2060 125*** SM 2060 140*** SM 2060 155*** SM C276 110*** SM C276 125*** SM C276 140***

L 80 C 90 T 95 1Cr 0.5Mo Steel Modified AISI 4130

9Cr 1Mo Steel

22Cr 5Ni 3Mo Steel

25Cr 35Ni 3Mo Steel 22Cr 42Ni 3Mo Steel 20Cr 35Ni 5Mo Steel

Most Corrosive Environment

Domain “G”

SM’ Designation

J 55 N 80 P 110 (Q 125) Cr or Cr-Mo Steel

25Cr 6Ni 3Mo Steel

Wet CO2 with H 2S Corrosion

0

API

13Cr Steel Modified AISI 420 Wet CO2 with a little H 2S Corrosion

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Application (Refer to figure 4.a)

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IDENTIFICATION CODE

25Cr 50Ni 6Mo Steel

20Cr 58Ni 13Mo Steel


Notes

Higher yield strength for sour service Quenched and tempered Quenched and tempered Duplex phase Stainless steels *

Solution Treated

** Cold drawn As cold drawn

As cold drawn

*** Environment with free Sulphur

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Table 4.B - Example Non-API Steel Grades

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5.

MECHANICAL PROPERTIES OF STEEL

5.1.

GENERAL

0

Failure of a material or of a structural part may occur by fracture (e.g. the shattering of glass), Yield, wear, corrosion, and other causes. These failures are failures of the material. Buckling may cause failure of the part without any failure of the material. As load is applied, deformation takes place before any final fracture occurs. With all solid materials, some deformation may be sustained without permanent deformation, i.e. the material behaves elastically. Beyond the elastic limit, the elastic deformation is accompanied by varying amounts of plastic, or permanent, deformation, If a material sustains large amounts of plastic deformation before final fracture. It is classed as ductile material, and if fracture occurs with little or no plastic deformation. The material is classed as brittle. 5.2.

STRESS-STRAIN DIAGRAM Tests of material performance may be conducted in many different ways, such as by torsion, compression and shear, but the tension test is the most common and is qualitatively characteristics of all the other types of tests. The action of a material under the gradually increasing extension of the tension test is usually represented by plotting apparent stress (the total load divided by the original cross-sectional area of the test piece) as ordinates against the apparent strain (elongation between two gauge points marked on the test piece divided by the original gauge length) as abscissae. A typical plot for a carbon steel is shown in figure 5.a. From this, it is seen that the elastic deformation is approximately a straight line defined by Hooke's law, and the slope of this line, or the ratio of stress to strain within the elastic range, is the modulus of elasticity E, sometimes called Young's modulus. Beyond the elastic limit, permanent, or plastic strain occurs. If the stress is released in the region between the elastic limit and the yield strength (see above) the material will contract along a line generally nearly straight and parallel to the original elastic line, leaving a permanent set. In steels, a curious phenomenon occurs after the elastic limit, known as yielding. This gives rise to a dip in the general curve followed by a period of deformation at approximately constant load. The maximum stress reached in this region is called the upper yield point and the lower part of the yielding region the lower yield point. In the harder and stronger steels, and under certain conditions of temperature, the yielding phenomenon is less prominent and is correspondingly harder to measure. In materials that do not exhibit a marked yield point, it is customary to define a yield strength. This is arbitrarily defined as the stress at which the material has a specified permanent set (the value of 0.2 percent is widely accepted in the industry). For steels used in the manufacturing of tubular goods the API specifies the yield strength as the tensile strength required to produce a total elongation of 0.5 and 0.6 percent of the gauge length.

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Figure 5.A - Stress - Strain Diagram Similar arbitrary rules are followed with regard to the elastic limit in commercial practice. Instead of determining the stress up to which there is no permanent set, as required by definition, it is customary to designate the end of the straight portion of the curve (by definition the proportional limit) as the elastic limit. Careful practice qualifies this by designating it the ‘proportional elastic limit’. As extension continues beyond yielding, the material becomes stronger causing a rise of the curve, but at the same time the cross-sectional area of the specimen becomes less as it is drawn out. This loss of area weakens the specimen so that the curve reaches a maximum and then falls off until final fracture occurs. The stress at the maximum point is called the tensile strength (TS) or the ultimate strength of the material and is its most often quoted property. The mechanical and chemical properties of casing, tubing and drill pipe are laid down in API specifications 5CT and 5C2. Depending on the type or grade, minimum requirements are laid down for the mechanical properties, and in the case of the yield point even maximum requirements (except for H 40).

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The denominations of the different grades are based on the minimum yield strength, e.g.: Grade

Min. Yield Strength

H 40

40,000psi

J 55

55,000psi

C 75

75,000psi

N 80

80,000psi

etc. In the design of casing and tubing strings the minimum yield strength of the steel is taken as the basis of all strength calculations As far as chemical properties are concerned, in API 5CT only the maximum phosphorus and sulphur contents are specified, the quality and the quantities of other alloying elements are left to the manufacturer. API specification 5CT ‘Restricted yield strength casing and tubing’ however, specifies the complete chemical requirements for grades C 75, C 95 and L 80. 5.3.

HEAT TREATMENT OF ALLOY STEELS The structure of a metal or alloy and its mechanical and corresponding physical properties are strongly dependent on the chemical composition of the material and heat treatment applied. In the heat treatment process, the temperature reached and the rate of cooling are the essentials of obtaining the physical properties. Comparison of the chemical composition shows that in general there is little difference between the various grades of steel and the difference in mechanical properties is achieved mainly through the variation heat treatment process. Rapid cooling of the steel from above the crystallisation temperature by quenching provides a hard, brittle type steel. Slow cooling provides a soft low-strength steel. The hardness of a specific alloy steel is directly proportional to the strength of that steel. The various methods of heat treatment are as follows: Annealing

Normalising

In this process the steel is heated above a critical temperature and cooled very slowly, usually in the furnace. Annealing accomplishes the following: • Refines grain structure. • Makes structure more uniform. • Improves machinability. This is an identical process to annealing except that the steel is air cooled. As an example API grades J and K55 are heated to about 860°C (1,580°F) before cooling.

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Tempering

Consists of re-heating a quenched or normalised steel to a specified temperature below the critical temperature, between 600°C and 680°C (1,110°F and 1,260°F) depending on the grade for a specific time and cooling back to room temperature. This process makes the steel tougher with only small loss in strength.

Stress relieving

Is similar to the tempering process but is done to relieve internal stresses set up during the manufacturing process (such as in upsetting).

Quenching

Is the same procedure as normalising but has rapid cooling, usually done in water, salt water or oil. un-tempered quenched steels are very hard and brittle.

See the following tables for process of manufacturing, heat treatments, chemical composition and mechanical properties of API tubulars.

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Tempering Temperature Min. Group

1

2

3

4

Grade

Type

Process of Manufacture

H 40 J 55

-

S or EW S or EW

K 55

-

S or EW

N 80 (Casing)

-

S or EW

N 80 (Tubing) C 75 C 75 C 75 C 75 C 75 C 90 C 90 C 95 L 80 L 80 L 80 P 105 P 110 Q 125 Q 125 Q 125 Q 125

1 2 3 9 Cr 18 Cr 1 2 1 9 Cr 13 Cr 1 2 3 4

S or EW S or EW S or EW S or EW S S S S S or EW S or EW S S S S S or EW*** S or EW*** S or EW*** S or EW***

Heat Treatment None None Note 1 None Note 1 None Note 1 Note 1 N&T Q&T N&T Q&T* Q&T* Q&T Q&T Q&T Q&T Q&T* Q&T* Q&T or N&T** Q&T or N&T** Q&T Q&T Q&T Q&T

o

F

o

C

-

-

-

-

-

-

1,150 1,150 1,150 1,100 1,100 1,150 1,150 1,000 1,050 1,100 1,100 -

621 621 621 593 593 621 621 538 566 593 593 -

Note: Full length normalised, normalised and tempered (N&T) or quenched and tempered (Q&T) at the manufacture’s option or if so specified on the order. Type 9 Cr and 13Cr grades may be air quenched ** Unless otherwise agreed between purchaser and manufacturer/processor *** Special requirements unique to electric welded Q 125 casing are specified in SR11. When welded Q 125 casing is furnished, the provisions of SR11 automatically in effect. S

=

Seamless pipe

EW

=

Electric welded Pipe Table 5.A - API Process of Manufacture and Heat Treatment

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Group

Grade

Type

33 OF 134

Carbon

0

Nickel

Copper

Phosphorous

Sulphur

Silicon

max.

max.

max.

max.

max.

max.

Maganese

Molybdenum

Chromium min

min

max.

min

max.

min

max.

1

H - 40 J - 55 K - 55 N - 80

... ... ... ...

... ... ... ...

... ... ... ...

... ... ... ...

... ... ... ...

... ... ... ...

... ... ... ...

... ... ... ...

... ... ... ...

... ... ... ...

... ... ... ...

0.040 0.040 0.040 0.040

0.060 0.060 0.060 0.060

... ... ... ...

2

C - 75 C - 75 C - 75 C - 75 C - 75 L - 80 L - 80 L - 80 C90 C90 C95

1 2 3 9Cr 13Cr 1 9Cr 13Cr 1 2 ...

... ... 0.38 ... 0.15 ... ... 0.15 ... ... ...

0.50 0.43 0.48 0.15 0.22 0.43* 0.15 0.22 0.35 0.50 0.45*

... ... 0.75 0.30 0.25 ... 0.30 0.25 ... ... ...

1.90 1.50 1.00 0.60 1.00 1.90 0.60 1.00 1.00 1.90 1.90

0.15 ... 0.15 0.90 ... ... 0.90 ... ... ... ...

0.40 ... 0.25 1.10 ... ... 1.10 ... 0.75 NL ...

*** ... 0.80 8.0 12.0 ... 8.0 12.0 ... ... ...

*** ... 1.10 10.0 14.0 ... 10.0 14.0 1.20 NL ...

*** ... ... ... 0.5 0.25 0.5 0.5 0.99 0.99 ...

*** ... ... ... 0.25 0.35 0.25 0.25 ... ... ...

0.040 0.040 0.040 0.020 0.020 0.040 0.020 0.020 0.030 0.030 0.040

0.060 0.060 0.040 0.010 0.010 0.060 0.010 0.010 0.010 0.010 0.060

0.45 0.45 ... 1.0 1.0 0.45 1.0 1.0 ... ... 0.45

3

P -105 P110

... ...

... ...

... ...

... ...

... ...

... ...

... ...

... ...

... ...

... ...

... ...

0.040 0.040

0.060 0.060

... ...

4

Q -125 Q -125 Q -125 Q -125

1 2 3 4

... ... ... ...

0.35 0.35 0.50 0.50

... ... ... ...

1.00 1.00 1.90 1.90

... ... ... ...

.75 NL NL NL

... ... ... ...

1.20 NL NL NL

0.99 0.99 0.99 0.99

... ... ... ...

0.020 0.020 0.030 0.030

0.010 0.020 0.010 0.020

... ... ... ...

Note: *** For Grade C - 75, Type 1, Chromium, Nickel and Copper combined shall not exceed 0.50%. * The Carbon contents for L - 80 may be increased to 0.50% max. if the product is oil quenched. * The Carbon contents for C - 95 may be increased to 0.55% max. if the product is oil quenched. NL No Limit. Elements shown must be reported in product analysis. Table 5.B - Chemical Composition of API Tubulars

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Yield Strength

Group

*

Grade

34 OF 134

min.

0

Tensile Strength max.

Hardness

min.

psi

MPa

psi

MPa

psi

MPa

max.* HRC BHN

1

H -40 J - 55 K - 55 N - 80

40,000 55,000 55,000 80,000

276 379 379 552

80,000 80,000 80,000 110,000

552 552 552 758

60,000 75,000 95,000 100,000

414 517 655 689

... ... ... ...

... ... ... ...

2

C - 75 1,2,3 C - 75 9Cr C - 75 13Cr L - 80 1 L - 80 9 Cr L - 80 13 Cr C - 90 C - 90 C - 90 C - 90

75,000 75,000 75,000 80,000 80,000 80,000 90,000 90,000 90,000 90,000

517 517 517 552 552 552 620 620 620 620

90,000 90,000 90,000 95,000 95,000 95,000 105,000 105,000 105,000 105,000

620 620 620 655 655 655 724 724 724 724

95,000 95,000 95,000 95,000 95,000 95,000 100,000 100,000 100,000 100,000

655 655 655 655 655 655 690 690 690 690

... 22 22 23 23 23 25.4 25.4 25.4 25.4

... 237 237 241 241 241 255 255 255 255

C - 95

95,000

655

110,000

758

105,000

724

...

...

3

P - 105 P - 110

105,000 110,000

724 758

135,000 140,000

931 965

120,000 125,000

827 862

... ...

... ...

4

Q -125 Q -125 Q -125

125,000 125,000 125,000

860 860 860

150,000 150,000 150,000

1035 1035 1035

135,000 135,000 135,000

930 930 930

... ... ...

... ... ...

Specified Wall Thickness

Allowable Hardness Variation

Inches

HRC

0.500 or less 0.501 to 0.749 0.750 to 0.999 1.000 and above

3.0 4.0 5.0 6.0

0.500 or less 0.501 to 0.749 0.750 and above

3.0 4.0 5.0

In case of dispute, laboratory Rockwell C hardness tests shall be used as the referee method. Table 5.C - API Tensile and Hardness Requirements

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STAP-P-1-M-6110

0

Figure 5.B - Yield Strength/Tensile Strength Ratios

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REVISION

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6.

TUBULAR RANGE LENGTHS & COLOUR CODING

6.1.

RANGE LENGTHS The following tables provide the API tubular length ranges available. Range

1

2

3

16-25

25-24

24-48

Permissible Variation, max.

6

5

6

Permissible length, min

18

28

36

20-24

28-32

-


2

2

-


20

28

-

Casing And Liners ** Total range length include * Range Length for 95% or more of carload

Tubing ** Total range length include * Range Length for 100% or more of carload

Pup Joint *** Lengths 2,3,4,6,8,10 and 12ft Tolerance ±3ins * Carload tolerance shall not apply to orders of less than a carload. For any carload of pipe, shipped to the final destination without transfer or removal from the car, the tolerance shall apply to each car. For any order consisting of more than a carload and shipped from the manufacturer’s facility by rail. but not to the final destination, the carload tolerance shall apply to the total order, but not to the individual carloads. ** By agreement between purchaser and manufacturer or processor the total range length for range 1 tubing may be 20-28ft *** 2ft pup joints may be furnished up to 3ft long by agreement between purchaser and manufacturer, and lengths other than those listed may be furnished by agreement between purchaser and manufacturer. Table 6.A - API Range Length In Feet

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Range

0

1

2

3

4.88-7.62

7.62-10.36

10.36-14.63


1.83

1.52

1.83


5.49

8.53

10.97

6.10-7.32

8.53-9.75

-


0.61

0.61

-


6.10

8.53

-

Casing And Liners Total range length include * Range Length for 95% or more of carload

Tubing ** Total range length include * Range Length for 100% or more of carload

Pup Joint *** Lengths 0.61, 0.19, 1.22, 1.83, 2.44, 3.05 and 3.66m Tolerance ±76.2mm * Carload tolerance shall not apply to orders of less than a carload shipped from the manufacturer’s or processor’s facility. For any carload of pipe shipped from the manufacturer’s or processor’s facility to the final destination without transfers or removal from the car, the tolerance shall apply to each car. For any order consisting of more than a carload and shipped by rail, but not to the final destination in the rail cars loaded, the carload tolerance shall apply to the total order, but not to the individual carloads. ** By agreement between the purchaser and manufacturer or processor the total range length for range 1 tubing may be 6.10-8.53m *** 0.61m pup joints may be furnished up to 0.91m long by agreement between purchaser and manufacturer, and lengths other than those may be furnished be agreement between purchaser and manufacturer. Table 6.B - API Range Length in Metres

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6.2.

API TUBULAR MARKING AND COLOUR CODING

6.2.1.

Markings

0

All API tubulars are marked as per API specification 5CT. The following example shows the marking code.

Table 6.C - Example Marking Code (Dalmine)

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6.2.2.

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Colour Coding Group 1, Group 3, Group 4 In addition to the required identification markings as specified in 6.2.1 above, each length of casing and tubing shall be colour coded by one or more of the following methods. •

A paint band encircling the pipe at a distance not greater than 2ft (0.61m) from the coupling or box. A paint band encircling the centre of the coupling. Paint entire outside surface of coupling.

• •

For pup joints shorter than 6ft (1.83m) in length, the entire surface except the threads shall be painted. The colour and number of bands shall be as follows: Grade H 40

No colour marking, or black at the manufacturer’s option

Grade J 55

One bright green band

Grade K 55

Two bright green bands

Grade N 80

One red band

Grade P 105

White

Grade P 110

White

Grade Q 125

Orange

Group 2 1)

A paint band or bands encircling the pipe at a distance not greater than 2ft (0,61m) from the coupling or box. Grade C75 One blue band Grace C75, 9Cr

One blue band and two yellow bands

Grade C75, 13Cr

One blue and one yellow band

Grade L80

One red band and one brown band

Grade L80, 9Cr

One red and one brown and two yellow bands

Grade L80, 13Cr.

One red and one brown and one yellow band

Grade C90

One purple band

Grade C95

One brown band

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3)

4)

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2)

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0

A paint band or bands encircling the centre of the coupling. Grade C75 One blue band Grade C90

One purple band

Grade C95

One brown band

Paint entire outside surface of coupling. The colour shall be as follows: Grade C75 Blue Grade C75, 9Cr

Blue with two yellow bands

Grade C75, 13Cr.

Blue with one yellow band

Grace L80

Red with brown band or longitudinal stripe

Grade L80, 9Cr

Red with two yellow bands

Grade L80, 13Cr.

Red with one yellow band

Grade C90

Purple

Grade C95

Brown

For pup joints shorter than 6ft (1.83m) in length, the entire surface except the threads shall be painted.

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7.

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APPROACH TO CASING DESIGN Casing design is actually a stress analysis procedure. The objective of the procedure is to produce a pressure vessel which can withstand a variety of external, internal, thermal, and self weight loading, while at the same time being subjected to wear and corrosion. During the drilling phase, this pressure vessel is a composite of steel and in conjunction with a variety of biaxially stressed rock materials. As there is little point in designing for loads that are not encountered in the field, or in having a casing that is disproportionally strong in relation to the underlying formations, there are four major elements to the casing design process: • • • •

Definition of the loading conditions likely to be encountered throughout the life of the well. Specification of the mechanical strength of the pipe. Estimation of the formation strength using rock and soil mechanics. Estimation of the extent to which the pipe will deteriorate through time and quantification of the impact that this will have on its strength.

Considering the axial stress (σa) in a string of casing, it is obvious that the stress due to the buoyant weight of the casing below any point of interest will be a major component of the total axial stress. Furthermore any changes in the internal and external pressures acting on casing will induce changes in the axial stress as well as the radial (σr) and tangential (σt) stresses. In addition, since the pipe is held or fixed at both ends, changes in all three stresses will occur due to temperature changes and from the occurrence, and degree, of any buckling effect. The inter-relationship between these loads can be analysed manually by applying a combination of Hooke's Law, ‘Lame's Equations’ and some form of yield criteria. This is referred to as ‘Triaxial Stress Analysis’. The forces affecting casing design are outlined in section 7.1.

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WELLBORE FORCES Various wellbore forces affect casing design. Besides the three basic conditions (burst, collapse and axial loads or tension), these include: • • • • • •

Buckling. Wellbore confining stress. Thermal and dynamic stress. Changing internal pressure caused by production or stimulation operations Changing external pressure caused by plastic formation creep. Subsidence effects and the effect of bending in crooked holes.

This list above is by no means comprehensive and research in progress may identify some other effects. The steps in the casing design process are: 1)

Consider the loading factors for burst first, since burst will dictate the design for the major part of the string. 2) Next, the collapse loading should be evaluated and the string sections upgraded if necessary. 3) Once the weights, grades and section lengths have been determined to satisfy the burst and collapse loading, the tensile load can then in turn be evaluated. 4) The pipe can be upgraded as necessary as the loading is determined. 5) From all of the above, the appropriate casing connection can be determined although, if the well is to be completed and the casing exposed to long term production, consideration may be given to using a premium connection. The final step is a check on biaxial reductions in burst strength and collapse resistance caused by compression and tension loads, respectively. If these reductions show the strength of any part of the section to be less than the potential load, the section should again be upgraded. 7.2.

DESIGN FACTOR (DF) The design process can only be completed if knowledge of all the anticipated forces is available. This however, is idealistic and never actually occurs, therefore some determinations are usually necessary and a degree of risk has to be present and accepted. The risk is usually associated with the assumed values and the level of the design factors applied.

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The design factors are necessary to cater for: • • • • • • •

Uncertainties in the determination of actual loads that the casing needs to withstand and the presence of any stress concentrations due to dynamic loads or specific well conditions. Reliability of listed properties of the various steels used in the industry and the uncertainty in the determination of the spread between ultimate strength and yield strength. Probability of the casing needing to bear the maximum load determined from the calculations. Uncertainties regarding the collapse pressure formulas. Possible damage to casing during transport and storage. Damage to the pipe body from slips, wrenches or inner defects due to cracks, pitting, etc. Rotational wear by the drill string while drilling.

The DF may vary with the capability of the steel to resist damage inflicted from handling and running equipment. The company values selected for DFs are a compromise between safety margin and economics. The use of excessively high DFs guarantees against failure but provides excessive strength and, therefore, increased cost. The use of low DFs requires accurate knowledge about the loads to be imposed on the casing as there is less margin available. Casing is generally designed to withstand stress which, in practice, it seldom encounters due to the assumptions used in calculations, whereas, production tubing has to bear pressures and tensions which are known or can be calculated with considerable accuracy. Furthermore, casing is cemented in place after installation whereas tubing is often recovered and used again. As a consequence of this, and due to the fact that tubing has to combat corrosion effects from formation fluid, a higher DF is used for tubing than casing.

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Company Design Factors The following table gives the DF’s are Eni-Agip’s specified design factors used in casing design calculations: Casing Grade

Burst

Collapse

Tension

H 40

1.05

1.10

1.7

J 55

1.05

1.10

1.7

K 55

1.05

1.10

1.7

C 75

1.10

1.10

1.7

L 80

1.10

1.10

1.7

N 80

1.10

1.10

1.7

C 90

1.10

1.10

1.7

C 95

1.10

1.10

1.7

P 110

1.10

1.10

1.8

Q 125

1.20

1.10

1.8

Table 7.A - Eni-Agip Design Factors Note:

The tensile DF on grade C 95 and below is 1.7, and higher than C 95 is 1.8.

Note:

The tensile DF must be considerably higher than the previous factors to avoid exceeding the elastic limit and, therefore invalidating the criteria on which burst and collapse resistances are calculated.

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Application of Design Factors The minimum performance properties of tubing and casing specified in the API bulletin are only used to determine if the chosen casing is within the DF. The design factors are applied as follows: Burst

For the chosen casing (diameter, grade, weight and thread) take the lowest value from API casing tables, columns 13 through 19. This value then divided by the applied DF gives the internal pressure resistance of casing to be used for design calculation.

Collapse

Use only column 11 of the API casing tables and divide the value by the DF to obtain the collapse resistance for design calculations.

Tension

Use the lowest value from columns 20 through 27 of the API casing tables and divide it by the DF to obtain the joint strength for design calculations.

Note:

It should be recognised that the Design Factor used in the context of casing string design is essentially different from the ‘Safety Factor’ used in many other engineering applications.

The term ‘Safety Factor’ as used in tubing design, implies that the actual physical properties and loading conditions are exactly known and that a specific margin is being allowed for safety. The loading conditions are not always precisely known in casing design, and therefore in the context of casing design the term ‘Safety Factor’ should be avoided at all times. Section 8 describes the exact design process in detail including the determination of all the loading applied.

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DESIGN CRITERIA

8.1.

BURST

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Burst loading on the casing is induced when internal pressure exceeds external pressure. 8.1.1.

Design Methods The most conservative design for burst assumes the gradient of dry gas inside the casing, the pressure of which equals the formation pressure of the lowest pressure zone from which the gas may have originated or, alternatively the fracture pressure of the open hole below the shoe. The basis for this design criteria is that a dry gas blow-out is assumed that, when shut-in at the surface, would either build to the blow-out zone's static shut-in pressure or cause an underground blow-out once the shut-in pressure reaches the fracture pressure of the weakest formation exposed in the open hole section. Most operating companies modify this basic ‘dry gas’ design concept according to a number of other influences including: • • • • •

Casing wear considerations Amount of open hole section Depth of the shoe DF applied Current BOP rating, etc.

Based on the vast amount of well data which is currently available, a set of key design considerations are made: a) b) c) d) e) f)

Blowouts, especially those which are capable of exerting ultra high surface pressure (i.e. dry gas blowouts), are very rare. Ultra high surface pressures can only be experienced if an actual dry gas blowout does occur. High strength casing, regardless of how overdesigned it may be, has no impact on the reduction of the blow-out risk. Once a blow-out has occurred, damage to the rig, environment, etc. will have already commenced, regardless of how strong the casing may be. If there is a blow-out, even a dry gas blow-out, it does not always concur that the casing will is exposed to high burst pressures. Surface wellheads have an advantage over subsea wellheads during drilling operations, as there is access to any of the previous casing annuli whereas this is not available with conventional subsea wellheads. Access to these annuli could in turn provide a means of applying back-up pressure to a casing string, thus reducing the net burst pressure being exerted on that particular string. This feature is not always possible if the annulus may is either cemented to the surface or not cemented into the previous casing shoe.

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The key to this problem is to recognise the rare and exceptional well circumstances that may require or result in a hard dry gas shut-in. The decision process should be based on the initial adoption of a ‘middle ground’ design. The Eni-Agip Drilling Engineering Department evaluated these key design considerations and have decided to use the most conservative method and to reduce the obtained results by 40%. 8.1.2.

Company Design Procedure To evaluate the burst loading, surface and bottom-hole casing burst resistance must first be established. Surface Casing a)

Internal Pressure 1)

The wellhead burst pressure limit is arbitrary, and is generally set equal to that of the working pressure rating of the wellhead and BOP equipment but with a minimum of 140kg/cm2. See ‘BOP selection criteria’ in section 12.1. With a subsea wellhead, the wellhead burst pressure limit is taken as 60% of the value obtained as the difference between the fracture pressure at the casing shoe and the pressure of a gas column to surface but in any case not less than 2,000psi (140atm). Consideration should be given to the pressure rating of the wellhead and BOP equipment which must always be equal to, or higher than, the pressure rating of the pipe. When an oversize BOP having a capacity greater than that necessary is selected, the wellhead burst pressure limit will be 60% of the calculated surface pressure obtained as difference between the fracture pressure at the casing shoe with a gas column to surface. Methane gas (CH4) with density of 0.3kg/dm 3 is normally used for this calculation. In any case it shall never be considered less than 2,000psi (140atm). The use of methane for this calculation is the ‘worst case’ when the specific gravity of gas is unknown, as the specific gravities of any gases which may be encountered will usually be greater than that of methane.

2) 3)

The bottom-hole burst pressure limit can be calculated and is equal to the predicted fracture gradient of the formation below the casing shoe. Connect the wellhead and bottom-hole burst pressure limits with a straight line to obtain the maximum internal burst load verses depth.

When taking a gas kick, the pressure from bottom-hole to surface will assume different profiles according to the position of influx into the wellbore. The plotted pressure versus depth will produce a curve.

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b)

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External Pressure In wells with surface wellheads, the external pressure is assumed to be equal to the hydrostatic pressure of a column of drilling mud. In wells with subsea wellheads: • •

c)

At the wellhead - Water Depth x Seawater Density x 0.1 (if atm) At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm)

Net Pressure The resultant load, or net pressure, will be obtained by subtracting, at each depth, the external from internal pressure.

Intermediate Casing a)


The wellhead burst pressure limit is taken as 60% of the calculated value obtained as the difference between the fracture pressure at the casing shoe and the pressure of a gas column to the wellhead. In subsea wellheads, the wellhead burst pressure limit is taken as 60% of the value obtained as the difference between the fracture pressure at the casing shoe and the pressure of a gas column to the wellhead minus the seawater pressure.

3)

The bottomhole burst pressure limit is equal to that of the predicted fracture gradient of the formation below the casing shoe. Connect the wellhead and bottom-hole burst pressure limits with a straight line to obtain the maximum internal burst pressure.

4)

b)

External Pressure The external collapse pressure is taken to be equal to that of the formation pressure. With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should be considered.

c)

Net Burst Pressure The effective burst pressures are obtained by subtracting the external from internal pressure versus depth.

Production Casing The ‘worst case’ burst load condition on production casing occurs when a well is shut-in and there is a leak in the top of the tubing, or in the tubing hanger, and this pressure is applied to the top of the packer fluid (i.e. completion fluid) in the tubing-casing annulus.

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2) 3)

Note:

4) Note:

b)

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a)

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The wellhead burst limit is obtained as the difference between the pore pressure of the reservoir fluid and the hydrostatic pressure produced by a colum of fluid which is usually gas (density = 0.3kg/dm 3). Actual gas/oil gradients can be used if information on these are known and available. The bottom-hole pressure burst limit is obtained by adding the wellhead pressure burst limit to the annulus hydrostatic pressure exerted by the completion fluid. Generally the completion fluid density is equal to, or close to, the mud weight in which casing is installed. It is usually assumed that the completion fluid and mud on the outside of the casing remains homogeneous and retains the original density values’ however this is not actually the case, particularly with heavy fluids, but it is also assumed that the two fluids will degrade similarly under the same conditions of pressure and temperature. Connect the wellhead and bottomhole burst pressure limits with a straight line to obtain the maximum internal burst pressures. If it is foreseen that future stimulation or hydraulic fracturing operations may be necessary, assume: at the perforation depth the fracture pressure at that point and at the wellhead the fracture pressure at the perforation depth minus the hydrostatic head in the casing plus a safety margin of 70kg/cm2 (1,000psi).

External Pressure The external pressure is taken to be equal to that of the formation pressure. With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should be considered.

c)

Net Burst Pressure The resultant burst pressure is obtained by subtracting the external from internal pressure at each depth.

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Intermediate Casing and Liner If a drilling liner is to be used in the drilling of a well, the casing above where the liner is suspended must withstand the burst pressure that may occur while drilling below the liner. The design of the intermediate casing string is, therefore, altered slightly: 1)

2)

Since the fracture pressure and mud weight may be greater or lower below the liner shoe than casing shoe, these values must be used to design the intermediate casing string as well as the liner. When well testing or producing through a liner, the casing above the liner is part of the production string and must be designed according to this criteria.

Tie-Back String In a high pressure well, the intermediate casing string above a liner may be unable to withstand a tubing leak at surface pressures according to the production burst criteria. The solution to this problem is to run and tie-back a string of casing from the liner top to surface, isolating the intermediate casing. 8.2.

COLLAPSE Pipe collapse will occur when the external force on a pipe exceeds the combination of the internal force plus the collapse resistance. It occurs as a result of either, or a combination of: • • •

8.2.1.

Reduction in internal fluid pressure. Increase in external fluid pressure. Additional mechanical loading imposed by plastic formation movement.

Company Design Procedure The design of a string of casing in collapse mode consists of selecting the lowest cost pipe that has sufficient strength to meet with the desired design criteria and design factor. If, when making a selection, a choice exists between a lower grade heavy pipe and a higher grade but lighter pipe, both of which provide adequate strength at similar cost, the higher grade (lighter) pipe should be chosen due to the reduction of tension loading. Note :

The reduced collapse resistance under biaxial stress (tension/collapse) should be considered.

Note :

No allowance is given to increased collapse resistance due to cementing.

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Surface Casing a)

Internal Pressure For wells with a surface wellhead, the casing is assumed to be completely empty. In offshore wells with subsea wellheads, the internal pressure assumes that the mud level drops due to a thief zone.

b)

External Pressure In wells with a surface wellhead, the external pressure is assumed to be equal to that of the hydrostatic pressure of a column of drilling mud. In offshore wells with a subsea wellhead, it is calculated: • •

c)

At the wellhead - Water Depth x Seawater Density x 0.1 (if atm). At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm).

Net Collapse Pressure The resultant collapse pressure is obtained by subtracting the internal pressure from external pressure at each depth.

Intermediate Casing a)

Internal Pressure The worst case collapse loading occurs when a loss of circulation is encountered while drilling the next hole section with the maximum allowable mud weight. This results in the mud level inside the casing dropping to an equilibrium level where the mud hydrostatic equals the pore pressure of the thief zone. Consequently it will be assumed the casing is empty to the height (H) calculated as follows: (Hloss-H) x dm = H

loss x

Gp

H = H loss (dm - Gp)/dm If Gp = 1.03 (kg/cm2/10m) Then H = H loss (dm - 1.03)/dm where: Hloss

=

depth at which circulation loss is expected (m)

dm

=

mud density expected at Hloss (kg/dm 2)

Gp

=

pore pressure of thief zone (kg/cm2/10m) - usually normally pressured with 1.03 as gradient.

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Figure 8.A - Fluid Height Calculation When thief zones cannot be confirmed, or otherwise, during the collapse design, as is the case in exploration wells, Eni-Agip division and associates suggests that on wells with surface wellheads, the casing is assumed to be half empty and the remaining part of the casing full of the heaviest mud planned to drill the next section below the shoe. In wells with subsea wellheads, the mud level inside the casing is assumed to drop to an equilibrium level where the mud hydrostatic pressure equals the pore pressure of the thief zone. b)

External Pressure The pressure acting on the outside of casing is the pressure of mud in which casing is installed. The uniform external pressure exerted by salt on the casing or cement sheath through overburden pressure, should be given a value equal to the true vertical depth of the relative point.

c)

Net Collapse Pressure The effective collapse line is obtained by subtracting the internal pressure from external at each depth.

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Production Casing a)

Internal Pressure Assume the casing worst case is being completely empty. It is a fact of life, that during the productive life of well, tubing leaks often occur and wells. Also wells may be on artificial lift, or have plugged perforations or very low internal pressure values and, under these circumstances, the production casing string could be partially or completely empty. This must be taken into consideration in the design and the ideal solution is to design for zero pressure inside the casing which provides full safety, nevertheless in particular well situations, the Drilling and Completions Manager may consider that the lowest casing internal pressure is the level of a column of the lightest density producible formation fluid.

b)

External Pressure Assume the hydrostatic pressure exerted by the mud in which casing is installed. The uniform external pressure exerted by salt on the casing or cement sheath through overburden pressure, should be given a value equal to the true vertical depth of the relative point.

c)

Net Collapse Pressure In this case of the casing being empty, the net pressure is equal to the external pressure at each depth. In other cases it will be the difference between external and internal pressures at each depth.

Intermediate Casing and Liner 1)

2)

If a drilling liner is to be used in the drilling of a well, the casing above where the liner is suspended must withstand the collapse pressure that may occur while drilling below the liner. When well testing or producing through a liner, the casing above the liner is part of the production string and must be designed according to this criteria.

Tie-Back String If the intermediate string above the liner is unable to withstand the collapse pressure calculated according to production collapse criteria, it will be necessary run and tie-back a string of casing from the liner top to surface.

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ENI S.p.A. Agip Division TENSION

8.3.1.

General

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Tensile failure occurs if the longitudinal force exerted on a pipe exceeds, either the tensile strength of the pipe or its connection. Generally, the connection used in a string of casing is stronger than the pipe body although this must always be confirmed. For situations where a connection coupling has to be special clearance, (i.e. of a smaller diameter than the normal) the connection will be weaker or if flush joint pipe must be used in special circumstances. Tensile loads are imposed on the casing by: • •

• • • • Note:

8.3.2.

The weight of pipe itself. The highest tensile stresses will occur at the uppermost portion of the pipe. The tension is the weight of the pipe in air less buoyancy. Shock loading: a) While lowering casing through unstable formations such as cavings where the casing string may get temporarily stuck before suddenly slipping through thereby inducing tensile shock loads. b) When landing casing in a subsea wellhead from a floater. Upward and downward reciprocating movements carried out where there is a tendency to become differential stuck, etc. in order to become free. To free the pipe considerable pull may be necessary. Bumping a cement plug. High internal pressure will induce tensional stresses caused by radial expansion and, hence, axial contraction. Bending. The varying parameters which can affect tensile loading leads to the estimates used for the tensile forces are more uncertain than the estimates for either burst and collapse. The DF imposed is therefore correspondingly much larger.

Buoyancy Force The effect of buoyancy is generally assumed to be the reduction in weight of the casing string when it is suspended in a liquid compared to its weight in air. The buoyancy or reduction in string weight, as observed on the block is actually the resultant of pressure forces acting on all the exposed horizontal faces and in calculations is defined as negative as it act upwards, hence reducing the pipe weight. The areas referred to are the tube end areas, the shoulders at point of changing casing weights and, to a smaller degree, the shoulders on collars (Refer to figure 8.b).

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a)

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Different casing weights

b)

0

Shoulders on collars

Figure 8.B - Casing Buoyancy Areas The forces acting on the areas of collar shoulders (F3) are for practical purposes negligible in casing design as the upward and downward facing shoulders countered each other over short distances. Note:

When calculating the tension with regard to buoyancy trends, the different weights per unit length of the casing must be taken into account, as they have different cross-sectional areas. In the following example an average weight value is assumed since this does not substantially affect the calculations.

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Well Depth (m)

0

Casing Weight (kg)

Casing Data Size (ins) 95/8 95/8 95/8

0-1000 1000-2000 2000-3000

Unit Weight lbs/ft (kg/m) 47.0 69.9 43.5 64.7 40.0 59.5 Hydrostatic Head (atm (*)) 150 300 450

Well Depth (m) 1000 2000 3000

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Cross Sectional Area (Af cm2) 87.6 81.0 73.9 Total Casing Weight Buoyancy (kg) 150 (87.6-81) = 300 (81-73.9) = 450 (73.9) = Total Buoyancy

Table 8.A - Buoyancy Example Calculation * Mud density, dm = 1.5kg/dm 3 The average buoyancy for the whole profile is: S

=

194,100 - (194,100 x 0.808)

=

37,267kg

The difference (37,267-36,375) is 892kg and thus negligible in the calculations. Refer to table 8.b for buoyancy factors.

69.900 64.700 59.500 194.100

990 2.130 33.255 36.375

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Fluid Head

Density Degrees API

Specific Gravity

lbs/gal

lbs/cu ft

g/cc

psi/ft

kg/sp cm/m

Buoyancy Factor*

60 55 50 45 40 35 30 25 20 15 10

0.738 0.758 0.779 0.801 0.825 0.849 0.876 0.904 0.933 0.985 1.000 1.007 1.031 1.055 1.079 1.103 1.127 1.151 1.175 1.199 1.223 1.247 1.271 1.295 1.319 1.343 1.367 1.391 1.415 1.439 1.463 1.487 1.511 1.535 1.559 1.583 1.607

6.160 6.325 6.499 6.683 6.878 7.085 7.304 7.537 7.786 8.052 8.337 8.400 8.600 8.800 9.000 9.200 9.400 9.800 9.800 10.00 10.200 10.400 10.600 10.800 11.00 11.200 11.400 11.500 11.800 12.000 12.200 12.400 12.600 12.800 13.000 13.200 13.399

46.08 47.31 48.62 49.99 51.45 53.00 58.64 56.38 58.24 60.23 62.36 62.63 64.33 65.82 67.32 68.82 70.31 71.81 73.30 74.80 75.30 77.79 79.29 80.78 82.28 83.78 85.27 86.77 88.27 89.76 91.26 92.75 94.25 95.75 97.24 98.74 100.23

0.738 0.765 0.779 0.801 0.825 0.848 0.876 0.904 0.933 0.965 1.000 1.007 1.031 1.055 1.079 1.103 1.127 1.151 1.175 1.199 1.223 1.247 1.271 1.295 1.319 1.343 1.367 1.391 1.415 1.439 1.463 1.487 1.511 1.535 1.559 1.583 1.607

0.320 0.328 0.336 0.347 0.357 0.368 0.379 0.391 0.404 0.418 0.433 0.435 0.446 0.457 0.467 0.477 0.488 0.498 0.509 0.519 0.529 0.540 0.550 0.561 0.571 0.581 0.592 0.602 0.612 0.823 0.633 0.644 0.654 0.664 0.675 0.585 0.696

0.0738 0.0758 0.0779 0.0801 0.0825 0.0649 0.0876 0.904 0.0933 0.0965 0.1000 0.1007 0.1031 0.1055 0.1079 0.1103 0.1127 0.1151 0.1175 0.1199 0.1223 0.1247 0.1271 0.1295 0.1319 0.1343 0.1367 0.1391 0.1415 0.1439 0.1463 0.1487 0.1511 0.1535 0.1559 0.1583 0.1607

0.905 0.903 0.900 0.897 0.894 0.891 0.688 0.884 0.680 0.675 0.872 0.871 0.868 0.865 0.662 0.859 0.856 .0852 0.849 0.846 0.843 0.840 0.837 0.834 0.831 0.828 0.825 0.822 0.819 0.816 0.613 0.810 0.806 0.803 0.800 0.797 0.794

BF = 1 − ρm / ρs

BF = Buoyancy Factor ρm = Mud Density

ρs = Steel Density

Fluid Density Pressure and Buoyancy Factors(60oF) (Continued Over Page)

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Fluid Head

Density Degrees API

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Specific Gravity

lbs/gal

lbs/cu ft

g/cc

psi/ft

kg/sp cm/m

Buoyancy Factor*

1.631 1.655 1.679 1.703 1.727 1.751 1.775 1.799 1.823 1.847 1.871 1.895 1.919 1.943 1.967 1.991 2.015 2.039 2.063 2.087 2.111 2.135 2.159 2.183 2.207 2.231 2.255 2.278 2.326 2.350 2.374 2.398

13.600 13.800 14.000 14.200 14.399 14.600 14.800 15.000 15.200 15.399 15.600 15.800 16.000 16.200 16.400 16.600 16,800 17.000 17.200 17.400 17.600 17.800 18.000 18.200 18.400 18.600 18.800 19.000 19.400 19.600 19.800 20.000

101.73 103.23 104.72 106.22 107.71 109.21 110.71 112.20 113.70 115.20 116.89 118.19 119.68 121.18 122.68 124.17 125.67 127.16 128.66 130.18 131.65 133.15 134.54 136.14 137.64 139.13 140.63 142.12 145.12 146.61 148.11 149.61

1.631 1.655 1.679 1.703 1.727 1.751 1.775 1.799 1.823 1.847 1.871 1.895 1.918 1.943 1.967 1.991 2.015 2.039 2.063 2.067 2.111 2.135 2.159 .2183 2.207 2.231 2.255 2.278 2.326 2.350 2.374 2.398

0.706 0.716 0.727 0.737 0.748 0.755 0.768 0.779 0.789 0.799 0.610 0.820 0.831 0.841 0.851 0.862 0.872 0.863 0.893 0.903 0.914 0.924 0.935 0.945 0.955 0.955 0.976 0.987 1.007 1.018 1.028 1.038

0.1831 0.1655 0.1579 0.1703 0.1727 0.1751 0.1775 0.1799 0.1823 0.1547 0.1871 0.1895 0.1919 0.1943 0.1967 0.1991 0.2015 0.2039 0.2063 0.2087 0.2111 0.2135 0.2159 0.2183 0.2207 0.2231 0.2255 0.2278 0.2326 0.2350 0.2374 0.2398

0.791 0.788 0.785 0.782 0.779 0.776 0.773 0.770 0.767 0.764 0.761 0.757 0.754 0.751 0.748 0.745 0.742 0.739 0.736 .0733 0.730 0.727 0.724 0.72 0.718 0.715 0.712 0.708 0.792 0.699 0.696 0.693

Buoyancy factor is used is used compensate for loss of weight when steel tubulars are immersed in fluid. Applicable only when tubing or casing is completely filled with fluid. Apparent Weight = Weight in Air - Buoyant Force Buoyancy Force =

Weight in Air x Mud Density Steel Density

Apparent Weight =

 Steel Density − Mud Density   Wieght in Air  Steel Density  

Apparent Weight = Weight in Air x Buoyancy Factors Steel Density = 7.85 kg/l

Table 8.B - Fluid Density Pressure and Buoyancy Factors(60oF)

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Company Design Procedure 1) 2)

Calculate the casing string weight in air. Calculate the casing string weight in mud by multiplying the previous weight by the buoyancy factor (BF) in accordance with the mud weight in use. Example: Weight of casing in air

= 250,000kg

Mud weight

= 1.70kg/dm 3

Buoyancy factor

= 0.782

Weight of casing in mud

= 250,000 x 0.782 = 195,500kg

Buoyancy force 3)

= 54,500kg

Add the additional load due to bumping the cement plug to the casing string weight in mud.

Note:

This pull load is calculated by multiplying the expected bump-plug pressure by the inside area of the casing.

Example: 95/8" 43.5 lbs/ft casing Pressure when at bumping plug

= 180kg/cm2

Inside casing area, Ai

= 388.39cm2

Additional pull load

= 388.39 x 180 = 69,910kg

A calculation of this kind is an approximation only because the assumption has been made that: • •

No buoyancy changes occur during cementing. The pressure is applied only at the bottom and not where there are changes in section. As seen with the previous case, the differences in the calculated values are quite small, which justifies the preference for the simpler approximation method. Once the magnitude and location of the forces are determined, the total tensile load line may be constructed graphically. Note: 8.3.4.

More than one section of the casing string may be loaded in compression.

Example Hook Load During Cementing The following is an example of casing load and therefore hook load when conducting a casing cement job. This calculation includes the use of temperature data.

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Example Data Estimated top of cement Cemented length of casing Casing size Steel grade Weight (imperial) Weight (metric) Internal diameter Casing shoe depth Mud weight during cementing operation Average cement slurry density Expected mud weight at end of next phase Estimated bump plug pressure Next phase total depth

2,800m 1,250m 7ins P 110 38lbs/ft 56.55kg/m 5.898ins 4050m 1.93kg/l 2.00kg/l 2.16kg/l 140kg/cm2 4400m

Calculation of Cross-Sectional Areas Casing external area Casing internal area Cross-sectional area

248.28cm2 176.26cm2 72.02cm2

Input Temperature Data Average flowing temperature at casing shoe Average static temperature at casing shoe Estimated flowing temperature at next phase depth Estimated static temperature at next phase depth

65oC 95oC 95.5oC 120.0oC

Estimated Total Hook Load (at end of cement operation) Weight of casing in air Internal fluid weight plus bump plug Buoyancy effect Back pressure Total load at the end of cementing

229t 162t 196t 0t 195t

Total Hang-Off Weight Weight in air of uncemented casing Stress due to the variation in internal pressure Stress due to the variation in external pressure Delta T m1 at casing shoe Delta T m1 at end of next phase Average delta T

158t -3t 0t 75.4oC 103.3oC 27.9 oC

Stress due to temperature variations Critical shock load If negative ignore)

52t -28t

Total required hang-off load

207t

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Guidelines For Landing The Casing The load conditions in the casing do not consider the additional axial stress placed in the casing when it is landed. Casing practices make it difficult to estimated the various stresses when it is landed in the wellhead. The API have identified four common methods for landing casing: • • • •

In tension which was present when cement displacement was completed. In tension at the freeze point, which is generally considered to be at the top of the cement. In neutral point of axial strength at the freeze point. In compression at the freeze point.

API recommendation is to land the casing with the same tension at the end of the displacement in all wells where the mud density does not exceed 12.5ppg (1.50kg/l) in the next section. The second option is used when excessive mud weights are anticipated, to prevent any tendency of the casing to buckle above the freeze point.

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ENI S.p.A. Agip Division BIAXIAL STRESS

8.4.1.

General

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When the entire casing string has been designed for burst, collapse and tension, and the weights, grades, section lengths and coupling types are known, the reduction in burst resistance needs to be applied due to biaxial loading. The total tensile load, which is tensile loading versus depth, is used to evaluate the effect of biaxial loading and can be shown graphically. By noting the magnitude of tension (positive) or compression (negative) loads at the top and bottom of each section length of casing, the strength reductions can be calculated using the ‘Holmquist & Nadai’ ellipse, see figure 8.c Note:

8.4.2.

The effects of axial stress on burst resistance are negligible for the majority of wells.

Effects On Collapse Resistance The collapse strength of casing is seriously affected by axial load, but the correction adopted by the API (API Bulletin 5C3) is only valid for D/t ratios of about 15 or less. In principle collapse resistance is reduced or increased when subjected to axial tension or compression loading. As can be seen from figure 8.c, increasing tension reduces collapse resistance where it eventually reaches zero under full tensile yield stress. The adverse effects of tension on collapse resistance usually affects the upper portion of a casing string which is under tension reducing the collapse resistance of the pipe. After these calculations, the upper section of casing string may need to be upgraded. Note:

Fortunately for instances, the biaxial effects of axial stress on collapse resistance are insignificant.

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Figure 8.C - Ellipse of Biaxial Yield Stress

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Company Design Procedure The value for the percentage reduction of rated collapse strength is determined as follows: 1) 2) 3) 4)

Determine the total tensile load. Calculate the ratio (X) of the actual applied stress to yield strength of the casing. Refer to .figure 8.d and curve ‘effect of tension on collapse resistance’ and find the corresponding percentage collapse rating (Y). Multiply the collapse resistance by the percentage (Y), without tensile loads to obtain the reduced collapse resistance value. This is the collapse pressure which the casing can withstand at the top of the string. Figure 8.D - Stress Curve Factors X=

0 0

Collapsresistence with tensile load Collapse resistence without tensile load

0.1 0.2 0.3 0.4 0.5 0.6

Y=

0.7 0.8 0.9 1 1.1

0.1

0.2

0.3

0.4

Tensile load Pipe body yield strength 0.5

0.6

0.7

0.8

0.9

1

1.1

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Example Collapse Caclulation Determine the collapse resistance of 7", N80, 32lbs/ft (4 kg/m), BTR casing with the shoe at a depth of 5,750m and a mud weight of 1.1kg/dm 3. Collapse resistance without tensile load

= 8,610psi (605kg/cm2)

Pipe body yield strength

= 745,000lbs (338t)

Buoyancy factor

= 0.859

Weight in air of casing

=

Weight in mud of casing

= 274 x 0.859 = 235t

x=

5,750 x 47.62 = 274 t 1,000

Weight in mud of casing 235 = = 0.695 Pipe Body Yield Strength 338

From the curve or stress curve factors in figure 8.g, if X = 0.695 then Y = 0.445 and the collapse resistance against tensile load can be determined: Collapse resistance under load = Nominal Collapse Rating x 0.445 Refer to figure 8.e for a graphical representation of this calculation.

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Figure 8.E - Graphical Representation

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ENI S.p.A. Agip Division BENDING

8.5.1.

General

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When calculating tensile loading, the effect of bending must also be considered, if applicable. The bending of the pipe causes additional stress in the walls of the pipe. This bending causes tension on the outside of the pipe and in compression on the inside of the bend, assuming the pipe is not already under tension (Refer to figure 8.f).

Figure 8.F - Bending Stress Bending is caused by any deviation in the wellbore resulting from side tracks, build-ups and drop-offs. Since bending load increases the total tensile load, it must be deducted from the usable rated tensile strength of the pipe.

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Determination Of Bending Effect For determination of the effect of bending, the following formula should be used: TB = 15.52 x α x D x Af

Eq. 8.A

where: α

=

Rate of build-up or drop off (degrees per 30m)

D

=

Outside diameter of casing (ins)

Af

=

Cross-section area of casing (cm2)

TB

=

Additional tension (kg)

The formula is obtained from the two following equations: σ=

MB × D 2×J

Eq. 8.B

where: MB

=

Bending moment (MB = E x J/R) (kg x cm)

D

=

Outside diameter of casing (cm)

J

=

Inertia moment (cm4)

σ

=

Bending stress (kg/cm2)

ExJ

=

Bending stiffness (kg x cm2)

R

=

Radius of curvature (cm)

θ=

MB × L E×J

Eq. 8.C

where: MB

=

Bending moment (kg x cm)

L

=

Arch length (cm)

E

=

Modulus of elasticity (kg/cm2)

J

=

Inertia moment (cm4)

θ

=

Change in angle of deviation (radians)

Obtaining MB =

σ=

θ ×E × J from equation 2), equation 1) becomes: L

θ × E× D 2×L

Eq. 8.D

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Then, by using the more current units giving the build-up or drop-off angles in degrees/30m, we obtain the final form of the equation for ‘TB’ as follows: TB Af θ × E × D × Af TB = 2× L

Eq. 8.E

180 × 30 π×α 1 L= R π × α × E × D × Af TB = 180 × 2 × 30

Eq. 8.F

σ=

R=

E = 21,000Kg/m m2 = 2.1 x 106kg/cm2

Eq. 8.G

π x α x (2.1 x 10 6 ) (25 x 4) x D x Af x 2 x 180 30 x 100 TB = 15.52 x α

TB =

When: Af

=

Square inches

α

=

Degrees/100ft

TB

=

218 x α x D x Af (lbs) or 63 x α x D x W (lbs)

W

=

Casing weight (lbs/ft)

Note:

Since most casing has a relatively narrow range of wall thickness (from 0.25 to 0.60ins), the weight of casing is approximately proportional to its diameter. This means the value of the bending load increases with the square of the pipe diameter for any given value of build-up/drop-off rate. At the same time, joint tension strength rises a little less than the direct ratio. The result is that bending is a much more severe problem with large diameter casing than with smaller sizes.

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Company Design Procedure Since bending load, in effect, increases tensile load at the point applied, it must be deducted from the usable strength rating of each section of pipe that passes the point of bending. The section which is ultimately set through a bend must have the bending load deducted from its usable strength up to the top of the bend. From that point up to the top of the section the full usable strength can be used.

8.5.4.

Example Bending Calculation Data: • • • • • • • •

Casing: OD 133/8", 72lbs/ft (107,14kg/m), C75, BTR Directional well with casing shoe at 2,000m (MD) Kick-off point at 300m Build-up rate: 3°/30m Maximum angle: 30° Mud weight : 1.1kg/dm 3 Pipe body yield strength: 1,558,000lbs (707t) Design factor : 1.7

Calculation: 1)

Casing weight in air (Wa) Wa = 107.14 x 2,000 = 214t

2)

Casing weight in mud (Wm) Wm = 214 x 0.859 = 184t

3)

Additional tension due to the bending effect (TB) TB = 15.52 x 3 x 13.375 x 133.99 = 83,441kg = 83t This stress will be added to the tensile stress already existing on the curved section of hole.

4) 5) 6) 7)

Tension in the casing at 300m(TVD)=156 t. 5) Total tension in the casing at 300m = 156 + 83 = 239t Tension in the casing at 600m (MD) =129t. Total tension in the casing at 600m (MD) = 129 + 83 = 212t.

See figure 8.g for the graphical representation of the example.

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Figure 8.G - Bending Load Example

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ENI S.p.A. Agip Division CASING WEAR

8.6.1.

General

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There is no reliable method of predicting casing wear and defining the reduction in casing properties due to the reduction in casing performance through decreases in burst and collapse values which are proportional to the reduction in wall thickness. However, theoretical predictions may be made as described in this section. For most purposes, consideration of wear allowances can be restricted to deviated wells with the most likely wear spot at the kick-off point where burst reduction will be the greatest consideration. In a vertical well , casing wear is usually in the first few joints below the wellhead or intervals with a high dogleg severity. In deviated wells, wear will be over the buildup and drop off sections. Figure 8.H - Casing Wear

The major factors affecting casing wear are: • • • • • •

Rotary speed. Tool joint lateral load and diameter. Drilling rate. Inclination of the hole. Severity of dog legs. Casing wear factor.

The location and magnitude of volumetric wear in the casing string can be estimated by calculating the energy imparted from the rotating tool joints to the casing at different casing points and dividing this by the amount of energy required to wear away a unit volume of the casing. The percentage casing wear at each point along the casing is then calculated from the volumetric wear.

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Eni-Agip acceptable casing wear limit is
Mud properties. Lubricants. Drill solids. Tool joint roughness. Tool joint hardness.

Note:

8.6.2.

The chemical action of gases such as H2S, CO2 and 02 tends to reduce the surface hardness of steel and, thus, contributes significantly to the rate of wear.

Volumetric Wear Rate The volume of casing worn away by the rotating tool joint equals: V=

Energy Input Per Foot Specific Energy

Eq. 8.H

where: V

=

Wear volume per foot

Specific Energy

=

The amount of energy required to wear away a unit volume of casing material.

The frictional energy imparted to the casing by the rotating tool joint equals: Energy Input Per Foot = Friction Force Per Foot x Sliding Distance

Eq. 8.I

where: Friction Force Per Foot = Friction Factor x Tool Joint Lateral Load Per Foot Sliding Distance = n x TJ Diameter x Rotary Speed x Contact Time and Tool Joint Contact Time =

S x TJL DPJL

where: S

=

Drilling distance(ft)

TJL

=

Tool joint length (ins)

P

=

Rate of penetration (ft/hr)

DPJL

=

Drill pipe joint length (ft)

Eq. 8.J

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The lateral load on the drill pipe equals: L=

TJLLPF x TJL DPJL

Eq. 8.K

where: L

=

Drill pipe lateral load per foot

TJLLPF = Tool joint lateral load (lbs/ft) TJL

= Tool joint length (ins)

DPJL

= Drill pipe joint length (ft)

The Wear Factor controlling the wear efficiency is defined as: Wear Factor = Friction Factor/Specific Energy

Eq. 8.L

Combining eq. 8.h-eq. 8.l shows that the Wear Volume ’V’ equals: v=

60 x π x F x L x D x N x S P

Eq. 8.M

where: V

=

Wear volume per foot (in3/ft)

F

=

Wear factor (ins 2/lbs)

L

=

Lateral load on drill pipe per foot (lbs/ft)

D

=

Tool joint diameter (ins)

N

=

Rotary speed (RPM)

S

=

Drilling distance (ft)

P

=

Penetration rate (ft/hr)

The tool joint and drill pipe lengths do not appear in Equation 6 because they do not effect the amount of casing wear in the linear model. Note:

Wear volume increases non-linearly against wear depth, because grooves become wider as the wear depth increases.

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Figure 8.I - Wear Rate

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Factors Affecting Casing Wear (Example)

Figure 8.J - Example Well

Figure 8.K - Factors Affecting Casing Wear

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Figure 8.L - Wellbore Displacement

Figure 8.M - Factors Affecting Casing Wear

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Figure 8.N - Affect of Tool Joint Diameter on Casing Wear

Figure 8.O - Casing Wear

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Figure 8.P - Lateral Tool Joint Loads in Smooth Ideal Well

Figure 8.Q - Lateral Forces in Actual Well

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Wear Factors Tool Joint

Wear Factor (F) (10-1 psi-l)

Water+Betonite+Barite

Smooth

0.5 to 1

Water+Betonite+Lubricant (2%)

Smooth

0.5 to 5

Water+Betonite+Drill Solids

Smooth

5 to 10

Water

Smooth

10 to 30

Water+Betonite

Smooth

10 to 30


Slightly Rough

20 to 50


Rough

50 to 150


Very Rough

200 to 400

Drilling Fluid

Table 8.C - Typical Casing Wear Factors When tool joints are smooth, casing wear is minimised when the mud consists of water, bentonite and barite, (F = 0.5 to 1.0). The small particles of barite appear to act as ball bearings and prevents the tool joint and casing materials from coming into intimate contact. Casing wear is increased tenfold when the mud is weighted with drill solids instead of barite, (F = 5 to 10). This shows the importance of having good solids control when running heavily weighted muds. Water (without solids) causes high wear, (F = 10 to 30) because there are no solids to prevent the sliding metals surfaces from coming into contact and causing galling wear. In extreme cases, the surface can weld together resulting in chunks of metal being torn from the surfaces. When tool joints have rough hardbanding, the wear is controlled primarily by the roughness of the tool joint and is almost independent of the mud properties. In this case, the rough tool joints tend to machine away the casing in even larger pieces (similar to the cutting action of a mill) resulting in rapid failure of the casing. table 8.d gives comparisons of casing wear with twelve different hardmetal materials tested in the DEA-42 project.

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Tool Joint

Tool Joint Wear (Open Hole)

Casing Wear, %

Wear Factor

Friction Factor

Remarks

Smooth Steel

0.043

18.2

5.6

0.21

AISI Steel 4145

75

1417

0.29

Mesh size 14/24 (20 min test)

27.8

10.8

0.20

Mesh size 14/24 (field worn surface)

21.8

7.6

0.15

Tungsten Carbide (spherical granules)

7.6

1.95

0.21

Tungsten Carbide (spherical)

Agip Tungsten Carbide

17.2

5.5

0.19

Low vibration

Agip Austenite

14.6

4.3

0.18

Low vibration

Aluminium Bronze

9.5

2.3

0.32

High friction

Rough Tungsten Carbide Smooth Tungsten Carbide

0.014

Hughes Smooth X Drilco Sphere

Armacor-M

0.027

5.9

1.1

0.15

Amorphous material

Arnco-200X

0.018

7.0

1.43

0.14

Chromium Carbide

Colmonoy 5

0.016

5.9

1.06

0.15

Nickle base

Triboloy-800

0.020

4.2

0.65

0.12

Duocor

9.7

2.24

0.24

Titanium Carbide

Stellite 6

9.7

2.19

0.17

Cobal base

6.6

1.27

0.15

Sensitive in salt mud

BP-1

10.2

2.53

0.19

Steel machine ground smooth

BP-2

18.6

6.74

0.21

Steel hand ground finish

Polished Chrome

Cobalt Molybdenum

Table 8.D - DEA-42 Comparable Tool Joint Hardmetal Test Results (N 80 with 3,000ft/lbs load and Water Based Mud)

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figure 8.r below shows casing wear versus tool joint passes.

Figure 8.R - Effect of Hardmetal Roughness on Casing Wear Tool Joint

Wear Factor (10-1 psi-l)


Rubber Protector

1 to 2

Water

Rubber Protector

4 to 10

Drilling Fluid

Table 8.E - Typical Casing Wear Factors (Shell-Bradley, 1975) The data given in table 8.c and table 8.e show that drill pipe rubber protectors (F= 1 to 10) will reduce casing wear under all conditions except when using smooth tool joints with water base mud weighted with barite, (F = 0.5 to 1.0). In applications where very rough hard metal tool joints (F= 200 to 400) are being used, the rubber protectors (F = 1 to 10) can reduce casing wear by 95 to 99 percent. Limited casing wear data for oil based muds is also available. These limited tests indicate that casing wear rates are nearly identical for oil based and water based muds. Shell (Bol. 1985) found that the addition of barite to the mud significantly reduces casing wear (Refer to figure 8.s). The barite apparently acts as ball bearings and keeps the sliding metal surfaces from coming into contact with each other and causing galling wear as already described in the previous section.

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Figure 8.S - Effect of Barite on Casing Wear (Bol, 1985) The barite reduced the wear factor from 25 using no barite to 1 to 2 with barite. Shell (Bol, 1985) conducted tests which showed that a 10ppg mud weighted with drill solids produced significantly more casing wear then a 10ppg mud weighted with barite (Refer to figure 8.t below).

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Figure 8.T - Effects of Barite on Casing Wear With lateral loads of 900 to 1,800lbs (4 to 8kN), the wear factor ranged from 5 to 10 with drill solids compared to 0.5 to 1.0 with barite. Apparently the small diameter of the barite contributed to this reduced wear. Shell (Bol, 1985) conducted tests with muds weighted with different weighting materials and found that weighting materials significantly reduce casing wear.

Figure 8.U - Effect of Weighting Materials on Casing Wear (Bol, 1985)

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Drilling Fluid

Mud Weight (lbs/gal)

Tool Joint

Weighting Material

Wear Factor (10-l0psi-1 )

Oil+Bentonite

10

Smooth

Barite

0.9 to 1.2

Water+Bentonite

10

Smooth

Barite

0.8 to 1.6

Water+Bentonite

10

Smooth

Iron Oxide

3 to 4

Water+Betontite

10

Smooth

Drill Solid

5 to 11

Water+Betontite

10

Smooth

Sand

11 to 13

Water+Betontite

8.8

Smooth

None

22 to 27

Table 8.F - Effect of Weighting Material on Casing Wear Factor (Bol, 1985) Weighting materials were found to reduce casing wear in all cases. Wear was greatest (F= 22 to 27), when no weighting material was present to act as a buffer between the tool joint and the casing. The addition of silica sand to the bentonite and water reduced the casing wear in half, (F = 11 to 13). Drill solids (F = 5 to 11) produced less wear than silica sand. Iron oxide (F = 3 to 4), which is often considered very abrasive, produced less wear than all of the other weighting materials except barite. This is apparently due to the small size of the iron oxide weighting particles. These tests indicate that the size of the weighting particles may be more important than the composition of the particles. Oil based and water based muds weighted with barite produced minimal wear (F = 0.8 to 1.6). This shows the importance of having good solids control when using heavily weighted muds. Shell (Bol, 1985) found that the addition of 2% lubricant to an unweighted mud consisting of water and bentonite significantly reduced casing wear refer to figure 8.v.

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Figure 8.V - Effect of Lubricant on Casing Wear The addition of 2% lubricant reduced the wear factor with the bentonite mud from between 30 to 5 with 1,800lbs lateral load (8kN) on the tool joint to between 30 to 0.5 with 900lbs load (4kN). These tests show that lubricants may be useful in wells where casing wear may be a problem. 8.6.5.

Detection Of Casing Wear Detecting casing wear can be achieved by two methods: • •

8.6.6.

Use of magnets in the mud flow return. Running a caliper survey after setting the casing to provide a base log. A wear log can then be run at any time throughout the life of the next section.

Casing Wear Reduction If there are fears about casing wear, it stands to reason practices to reduce it should be considered, including: • • • • • •

Using down hole motors and turbines. Using rubber drill pipe casing protectors. Using drill pipe without hard facing. Keeping doglegs to a minimum. Keeping sand content low. Using oil based mud.

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Wear Allowance In Casing Design With the design loads recommended it is highly unlikely that a reduction in collapse resistance due to wear will be critical at shallow depths or similarly that the reduction in burst resistance will be critical at the lower end of the casing string. The most likely wear points in a deviated wells are at the kick-off point and near surface in the vertical portion where buckling may occur (particularly at the top of cement). In the vertical wells, wear points may also develop at the top of cement if buckling occurs but unless there are known sudden changes in formation dip, which could cause a large ‘drilled dogleg’, wear is likely to be small and uniformly spread over the entire length of the string. For most purposes, consideration of wear allowances can be restricted to deviated wells, with the most likely wear point at the kick-off point where burst reduction will be the prime consideration. Since wear estimates are order of magnitude calculations, it is recommended that wear allowances be considered only in cases where the burst (or collapse) resistance of the casing at the wear point will be approached during the anticipated operating time in the string. In marginal cases, it may well prove cost effective to run a base caliper survey to re-survey the casing prior to entering a hydrocarbon bearing zone (or pressure test the casing to the equivalent of the burst pressures anticipated from the zone) than to run heavy walled casing through all the anticipated wear sections. The recommended procedure is therefore: 1) 2)

3) 4)

Conduct the casing design. At the wear points, calculate the allowable reduction in wall thickness so that the burst (or collapse) resistance of the casing just equals the burst (or collapse) load, including the appropriate Design Factor applied. Estimate the wear rate in terms of loss of wall thickness per operating day. Calculate, from the allowable loss in wall thickness and the rate of wear, the allowable operating time in the string.

If the allowable operating time is less than the anticipated operating time, use heavier casing (or increases the grade) 100m above and to 60m below the wear point until the allowable operating time exceeds the anticipated operating time. If the allowable operating time is greater than the anticipated operating time (say estimated 50 days allowable versus estimated 20 days operating) do not include a wear allowance. If the allowable operating time and the anticipated operating time are about the same, either: a)

Include a wear allowance or

b)

Monitor casing wear during drilling, and commission an intermediate string if the worn casing strength approaches the design loads.

In any given situation whether option a) or b) is exercised will be dependent upon a number of factors, many of which are beyond the scope of routine casing design.

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Option a) Is the conservative approach, but it may be too high, given the gross uncertainties inherent in wear estimations. However, in rank wildcats, particularly in remote locations, it may be justified. Option b) Requires a base caliper survey to be run immediately after installing the casing string, followed by runs at discrete intervals during the drilling phase. If wear is proven to have occurred, and an intermediate string has to be commissioned early, the deeper objectives of the well may not be reached. However, conditions as drilling proceeds may indicate that the design loads assumed are not going to be encountered and the reduction in casing strength is acceptable. In any event, valuable data on casing wear in the area will be obtained and field practices may be improved as result of the attention paid to wear, eventually leading to a reduction in overall wear rates. In most cases, option b) is preferred. 8.6.8.

Company Design Procedure There is no reliable method of predicting casing wear and defining the corresponding reduction in casing performance. Because the reduction in burst and collapse rating is directly proportional to wall thickness the revised theoretical value may be calculated. The normal procedure to cater for possible wear when designing casing is to select the next casing grade or wall thickness, therefore, in a vertical well, casing wear is usually in the first few joints below the wellhead or intervals with a high dog-leg severity. Consideration should be given to increasing the grade or wall thickness of the first few joints below the wellhead. In deviated wells, wear will be over the build-up and drop-off sections. Again the casing over these depths can be of a higher grade or heavier wall thickness.

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ENI S.p.A. Agip Division SALT SECTIONS

8.7.1.

General

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Salt formations often exhibit plastic flow properties which can cause exceedingly high loads on casing. The rate of salt flow is a function of its composition, temperature, depth or overburden pressure and also probably influenced by how it is bedded or interbedded with other formations. The problem of salt formations has to be assessed on an individual well to well and/or area to area basis. The objectives for drilling through salt zones should be: a) b)

To achieve trouble free drilling. Prevent casing collapse during the drilling and the production life of the well.

With regards to trouble free drilling, sticking due to salt flow, mud problems from salt contamination, hole enlargement and the well's overall casing programme, are the prime factors to be considered. There are other factors that have to not be under evaluated such as: • • •

Control of gas flows from porous zones interbedded in the salt, differential sticking in porous zones. Abnormal pressure due to entrapment of pressure by salt. Shale sloughing from interbedded or boundary shales.

To prevent casing collapse, the designer should plan for non-uniform salt loading, obtaining the best possible cement job, using casing with higher than normal collapse ratings and possibly two strings of casing through the salt section. Running casing in salt sections is rather a cementing problem than a casing design problem. In some cases, two strings may be more advantageous as experience has demonstrated that it is not practical to design a casing string to resist collapse. This technique is probably the most reliable and safest approach for preventing casing collapse but is probably not necessary for the majority of salt sections. 8.7.2.

External Loading Due To Salt Flow Traditional analyses of casing response to external loading are not adequate when considering all of the possible effects caused by salt formation flow. Three additional factors have to be analysed for casing design in areas where there is salt flow: a) b) c)

Uniform external loading. Non-uniform or non symmetric external loading. Asymmetrical formation loading.

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Uniform External Loads

Figure 8.W - Uniform External Loading If there is a possibility of salt loading, several remedial actions may be taken. The first group of precautions may be classified under the general heading of filling the casing internally, either, with gravel, other solids or a fluid. For production casing, such actions are usually not possible. The alternative is to run a scab liner inside the casing opposite the suspect formation and cement the annulus between the two casing strings refer to figure 8.x. The benefits gained from running such a liner are substantial.

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Figure 8.X - Casing With Liner Installed and Cemented

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Another source of non-uniform loading is bending of the casing as a result of curvature of the wellbore. Consider an initially straight casing length under external pressure and axial loads that are insufficient to result in collapse. Now assume that the casing is gradually bent by an additional external force as for example due to salt flowing (Refer to figure 8.y below).

Figure 8.Y - Non-Uniform Loading In the lower portion of the figure, the flowing formation has come in contact with the casing thus restricting its movement. Above this point of contact, additional flow of the formation is depicted as being in progress. Subsequent formation movement above the frozen point will cause severe bending loads and, thus, reduce the casing cross-sectional integrity. Problems may be observed before final catastrophic failure of the cross section e.g. the ovality of the cross section may be sufficient enough to result in restrictions in the casing that will prohibit the passage of bits or production equipment. However, even in the presence of non-uniform external loads, the structural benefits of using concentric casing strings are substantial.

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Asymmetrical Formation Loads For straight casing the most severe loading situation that could be expected from the salt environment is 'point loading’. If for some reason cement placement results in only a partial sheath around the casing, the remainder of the annulus being filled with mud, subsequent movement of the salt formation will result (Refer to figure 8.z below). The result of point loading is devastating leading to complete casing collapse. In fact, no casing is strong enough to resist point loading in its extremist form. Figure 8.Z - Point Loading

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Company Design Procedure In designing casing for any application, the accepted design load is the one for which the casing is subjected to the greatest conceivable loads. In the particular case of casing design opposite salt formations, certain guidelines can be considered: • • • • •

For production casing exposed to salt formations, assume the casing will be always evacuated at some point during the well life. The uniform external pressure exerted by salt on the casing (or cement sheath) due to overburden pressure should be given a value equal to the true vertical depth to the point in question. Proper cement placement opposite a salt section is often difficult due to washout. Any beneficial effects of the cement sheath should be ignored during design of the casing. If the wellbore is deviated, additional axial forces due to hole curvature should be considered when determining the collapse resistance of the casing.

Conclusions: • • •

Running casing in salt sections is rather a cementing problem than a casing problem. If the pipe is well cemented, it is sufficient to design for collapse load in the traditional mode (overburden pressure/design factor). If the casing is poorly cemented the collapse effect may be very high. In this case, it may help to run heavier wall casing (Refer to figure 8.aa).

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Figure 8.AA - High Collapse Resistance Casing For Deep Wells

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9.1.

GENERAL

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A production well design should attempt to contain produced corrosive fluids within tubing. They should not be produced through the casing/tubing annulus. However, it is accepted that tubing leaks and pressured annuli are a fact of life and as such, production casing strings are considered to be subject to corrosive environments when designing casing for a well where hydrogen sulphide (H2S) or carbon dioxide (CO2) laden reservoir fluids can be expected. During the drilling phase, if there is any likelihood of a sour corrosive influx occurring, consideration should be given to setting a sour service casing string before drilling into the reservoir. The BOP stack and wellhead components must also be suitable for sour service. 9.1.1.

Exploration and Appraisal Wells Routine measures to be taken during drilling include: • • •

Use of casing and wellhead equipment with a metallurgy suitable for sour service. Use of high alkaline mud to neutralise the H2S gas. Use of inhibitors and/or scavengers.

These measures will provide a degree of short term protection necessary to control corrosion of the casing in the hole during the drilling phase. 9.1.2.

Development Wells Casing corrosion considerations for development wells can be confined to the production casing only. •

Internal corrosion The well should be designed to contain any corrosive fluids (produced or injected) within the tubing string by using premium connections. Any part of the production casing that is likely to be exposed to the corrosive environment, during routine completion/workover operations or in the event of a tubing or wellhead leak, should be designed to withstand such an environment.

•

External corrosion Where the likelihood of external corrosion due to electrochemical activity is high and the consequences of such corrosion are serious, the production casing should be cathodically protected (either cathodically or by selecting a casing grade suitable for the expected corrosion environment).

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Contributing Factors to Corrosion Most corrosion problems which occur in oilfield production operations are due to the presence of water. Whether it may be present in large amounts or in extremely small quantities, it is necessary to the corrosion process. In the presence of water, corrosion is an electrolytic process where electrical current flows during the corrosion process. To have a flow of current, there must be a generating or voltage source in a completed electrical circuit. The existence, if any, of the following conditions alone, or in any combination may be a contributing factor to the initiation and perpetuation of corrosion: •

Oxygen (O2) Oxygen dissolved in water drastically increases its corrosivity potential. It can cause severe corrosion at very low concentrations of less than 1.0ppm. The solubility of oxygen in water is a function of pressure, temperature and chloride content. Oxygen is less soluble in salt water than in fresh water. Oxygen usually causes pitting in steels.

•

Hydrogen Sulphide (H2S) Hydrogen sulphide is very soluble in water and when dissolved behaves as a weak acid and usually causes pitting. Attack due to the presence of dissolved hydrogen sulphide is referred to as ‘sour’ corrosion. The combination of H2S and CO2 is more aggressive than H2S alone and is frequently found in oilfield environments. Other serious problems which may result from H2S corrosion are hydrogen blistering and sulphide stress cracking. It should be pointed out that H2S also can be generated by introduced micro-organisms.

•

Carbon Dioxide (CO2) When carbon dioxide dissolves in water, it forms carbonic acid, decreases the pH of the water and increase its corrosivity. It is not as corrosive as oxygen, but usually also results in pitting. The important factors governing the solubility of carbon dioxide are pressure, temperature and composition of the water. Pressure increases the solubility to lower the pH, temperature decreases the solubility to raise the pH. Corrosion primarily caused by dissolved carbon dioxide is commonly called ‘sweet’ corrosion. Using the partial pressure of carbon dioxide as a yardstick to predict corrosion, the following relationships have been found: Partial pressure >30psi usually indicates high corrosion risk. Partial pressure 3-30psi may indicate high corrosion risk. Partial pressure <3psi generally is considered non corrosive.

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•

Temperature Like most chemical reactions, corrosion rates generally increase with increasing temperature.

•

Pressure Pressure affects the rates of chemical reactions and corrosion reactions are no exception. In oilfield systems, the primary importance of pressure is its effect on dissolved gases. More gas goes into solution as the pressure is increased, this may in turn increase the corrosivity of the solution.

•

Velocity of fluids within the environment Stagnant or low velocity fluids usually give low corrosion rates, but pitting is more likely. Corrosion rates usually increase with velocity as the corrosion scale is removed from the casing exposing fresh metal for further corrosion. High velocities and/or the presence of suspended solids or gas bubbles can lead to erosion, corrosion, impingement or cavitation.

9.2.

FORMS OF CORROSION The following forms of corrosion are addressed in this manual: Corrosion caused by H2S (SSC) Corrosion caused by CO2 and ClCorrosion caused by combinations of H2S, CO2 and ClCorrosion in injection wells and the effects of pH and souring are not included. The procedure adopted to evaluate the corrosivity of the produced fluid and the methodology used to calculate the partial pressures of H2S and CO2 will be illustrated in the following subsections.

9.2.1.

Sulphide Stress Cracking (SSC) The SSC phenomenon is occurs usually at temperatures of below 80°C and with the presence of stress in the material. The H2S comes into contact with H2O which is an essential element in this form of corrosion by freeing the H+ ion. Higher temperatures, e.g. above 80°C inhibit the SSC phenomenon, therefore knowledge of temperature gradients is very useful in the choice of the tubular materials since differing materials can be chosen for various depths. Evaluation of the SSC problem depends on the type of well being investigated. In gas wells, gas saturation with water will produce condensate water and therefore create the conditions for SSC. In oil wells, two separate cases need to be considered, vertical and deviated wells: a)

In vertical oil wells, generally corrosion occurs only when the water cut becomes higher than 15% which is the ‘threshold’ or commonly defined as the ‘critical level’ and it is necessary to analyse the water cut profile throughout the producing life of the well.

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In highly deviated wells (i.e. deviations >80o), the risk of corrosion by H2S is higher since the water, even if in very small quantities, deposits on the surface of the tubulars and so the problem can be likened to the gas well case where the critical threshold for the water cut drops to 1% (WC >1%).

The following formulae are used to calculate the value of pH2S (partial pressure of H2S) in both the cases of gas (or condensate gas) wells or oil wells. Firstly, the potential for SSC occurring is evaluated by studying the water cut values combined with the type of well and deviation profile. If the conditions specified above are verified then the pH2S can be calculated. Gas Or Condensate Gas Well H2S partial pressure is calculated by: pH2S = SBHP x Y(H2S)/100 where: SBHP

=

Static bottom-hole pressure [atm]

Y(H2S) =

Mole fraction of H2S

pH2S

Partial H2S pressure [atm]

=

SSC is triggered at pH2S >0.0035 atm and SBHP >4.5 atm. Oil Bearing Well The problem of SSC exists when there is wetting water; i.e.: Water cut >15% for vertical wells Water cut >1% for horizontal or highly deviated wells (>80o) or if the GOR >800 Nm 3/m 3 The pH2S calculation is different for undersaturated and oversaturated oil. Undersaturated Oil In an oil in which the gas remains dissolved, because the wellhead and bottom-hole pressures are higher than the bubble point pressure (Pb) at reservoir temperature, is termed undersaturated. In this case the pH2S is calculated in two ways: • •

Basic method. Material balance method.

If the quantity of H2S in gas at the bubble point pressure [mole fraction = Y(H2S)], is not known or the values obtained are not reliable, the pH2S is calculated using both methods and the higher of the two results is taken as the a reliable value. Otherwise the basic method is used.

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Basic Method This method is used, without comparison with the other method, when the H2S value in the separated gas at bubble point conditions is known and is reliable or if Y(H2S), molar fraction in the separated gas at bubble point pressure (Pb) is higher than 2%. The pH2S is calculated by: pH2S = Pb x Y(H2S)/100 where: Pb

=

Bubble point pressure at reservoir temperature [atm]

Y(H2S) =

Mole fraction in the separated gas at bubble point (from PVT data if extrapolated)

pH2S

Partial H2S pressure [atm]

=

Material Balance Method This method is used when data from production testing is available and/or when the quantity of H2S is very small (<2,000ppm) and the water cut value from is lower than 5% (this method cannot be used when the WC values are higher). The value of H2S in ppm to be used in the calculation must also be from stable flowing conditions. Note: H2S sampled in short production tests, is generally lower than the actual value under stabilised conditions. The following algorithm is used to calculate the pH2S: pH2S is calculated at the separator (pH2Ssep): pH2Ssep = (Psep x H2Ssep)/106

Eq. 9.A

where: Psep

=

H2Ssep =

Absolute mean pressure at which the separator works (from tests) in atm Mean H2S value in the separator gas (generally measured in ppm)

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The mean molecular weight of the produced oil, PM :

PM =

γ 1000 GOR γ 1000 + (d 29) GOR 23. 6 − PMres 23. 6

Eq. 9.B

where:

 n    ∑ CiMi  / 100    i = 1 

PM res =

mean molecular weight of the reservoir oil =

Ci

=

Mole% of the ith component of the reservoir oil

Mi

=

Molecular weight of the ith component of the reservoir oil

d

=

Density of the gas at separator conditions referred to air =1

The quantity of H2S in moles/litre dissolved in the separator oil is calculated: [H2S]oil = (pH2Ssep/H1 x (γ x 1000)/ PM )

Eq. 9.C

where: H1

=

Henry constant of the produced oil at separator temperature (atm/Mole fraction). (See Procedure for calculating Henry constant)

PM

=

Mean molecular weight of the produced oil

γ

=

Specific weight g/l of the produced oil

The quantity of H2S in the gas in equilibrium is calculated (per litre of oil): [H2S]gas = (GOR/23.6 x H2Ssep/106)

Eq. 9.D

where: GOR

=

Gas oil ratio Nm 3/m 3 (from production tests)

23.6

=

Conversion factor

The pH2S is calculated at reservoir conditions: pH2S = (([H2S]oil + [H2S]gas)/K ) x H2

Eq. 9.E

where: K

=

(γ x 1000/ PM + GOR/23.6) total number of moles of the liquid phase in the reservoir

H2

=

Henry constant for the reservoir temperature and reservoir oil. (See procedure for calculating Henry constant)

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In general, H2S corrosion can occur at either the wellhead or bottom-hole without distinction. There is SSC potential if pH2S >0.0035 atm and STHP >18.63 atm. Procedure For Calculating Henry Constant The value of the Henry constant is a function of the temperature measured at the separator. The mapping method can be applied for temperatures at the separator of between 20°C and 200°C. Given the diagram in figure 9.a which represents the functions H(t) for the three types of oils: •

Heptane PM

=

100

•

N-propyl benzene PM

=

120

•

Methylnaphthalene PM

=

142

Remarks On The H1 Calculation Having calculated the molecular weight of the produced oil PM using the formula in eq. 9.b, the reference curve is chosen (given by points) to calculate the Henry constant on the basis of the following value thresholds: •

If PM > 142, the H(t) curve of methylnaphthalene is used.

•

If PM = 120, the H(t) curve of propyl benzene is used.

•

If PM < 100, the H(t) curve of heptane is used.

•

If 100 < PM < 120, the mean value is calculated using the H(t) curve of propyl benzene and the H(t) curve of methylnaphthalene.

• •

If 120 < PM < 142 the mean value is calculated using the H(t) curve of heptane and the H(t) curve of propyl benzene. Given FTHT, wellhead flowing temperature, the H1 value is interpolated linearly on the chosen curve(s). For this purpose the temperature values immediately before and after the temperature studied are taken into consideration.

Comments On The H2 Calculation Having calculated the molecular weight of the reservoir oil PM res, using temperature measured at the separator, H2 is measured in a similar way as H1.

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Henry atm/Y[H 2 S]

130

120

110

100

90

methylnaphthalene PM = 142 80

N-propylbenzene PM = 120 heptane PM = 100

70

60

50

40

30

20 20

30

40

50

60

70

80

90

100 110 120 130 140 150 160 170 180 190 200

T C°

Figure 9.A - H(t) Reference Curves Oversaturated Oil Oil is considered oversaturated when the gas in the fluid separates because the pressure of the system is lower than the bubble point pressure. Two situations can arise: Case A FTHP < Pb FBHP > Pb Case B FTHP < Pb FBHP < Pb

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Calculation Of Partial Pressure In Case A: 1)

Calculation is of the partial pressure in the reservoir: In this case pH2S is calculated in the way described for undersaturated oil.

2)

Calculation is of the partial pressure at the wellhead, i.e. when FTHP
Basic Method pH2S = STHP x Y(H2S) / 100 where: STHP

= static tubing head pressure [atm]

Y(H2S)

= mole fraction in separated gas at STHP pressure and wellhead temperature

pH2S = partial H2S pressure [atm] The SSC phenomenon is triggered off at the wellhead if pH2S >0.0035 atm and STHP >18.63 atm. Calculation Of Partial Pressure In Case B: Calculation of partial pressure in the reservoir: In the reservoir the gas is already separated, FBHP
the PVTs are reliable, Y(H2S) >0.2%, the partial pressure is calculated as: pH2S = Y(H2S)(1) x FBHP where: Y(H2S) = molar fraction in gas separated at FBHP and at reservoir temperature (from PVT)

•

the PVTs are not reliable, the material balance method can be used as in the case of undersaturated oil; these are the worst conditions. The error made can be high when Pb >FBHP.

Calculation Of Partial Pressure At Wellhead The calculation method is that used for case A (FTHP
If the percentage (ppm) of H2S in the gas under static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead.

(2)

If the percentage (ppm) of H2S in the separated gas under static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead.

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Corrosion Caused By CO2 And ClIn the presence of water, CO2 gives rise to a corrosion form which is different to those caused by the presence of H2S. It also occurs only if the partial pressure of CO2 exceeds a particular threshold. As in the case of SSC, the possibility that corrosions exist in water cut values combined with the type of well and deviation profile, is evaluated. If the conditions described in section 9.2.1 exist, then the pCO2 is then calculated. Gas Or Condensate Gas Wells The partial pressure is calculated: pCO2 = SBHP x Y(CO2)/100 where: SBHP

=

Static bottom-hole pressure [atm]

Y(CO2) =

Mole fraction of CO2

pCO2

Partial pressure of CO2 [atm]

=

Corrosion occurs if pCO2 >0.2 atm. Oil Bearing Wells The problem exists where there is wetting water; i.e.: • •

Water cut >15% for vertical wells. Water cut >1% for horizontal or highly deviated wells (> 80 degrees).

Undersaturated Oil Wells The partial pressure of CO2 is calculated: pCO2 = Pb x Y(CO2)/100 where: Pb

=

Bubble point pressure at reservoir temperature

Y(CO2) =

Mole fraction of CO2 in separated gas at bubble point pressure (from the PVTs)

pCO2

Partial pressure of CO2 [atm]

=

Corrosion occurs if pCO2 >0.2 atm. The pCO2 values calculated in this way are used to evaluate the corrosion at bottom hole and wellhead; i.e. pCO2 at wellhead is assumed as corresponding to reservoir conditions.

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Oversaturated Oil The oil is considered oversaturated when the gas separates in the fluid because the pressure of the system is lower than bubble point pressure. Two situations may arise: Case A FTHP Pb Case B FTHP Pb pCO2 is calculated in the same way as undersaturated oil wells earlier in this section. pCO2 = Pb x Y(CO2)/100 where: Pb

= bubble point pressure at reservoir temperature

Y(CO2)

= mole fraction in separated gas at bubble point pressure (from the PVTs)

pCO2

= partial pressure of CO2 [atm]

Corrosion occurs if pCO2 >0.2 atm. Calculation Of PCO2 At Wellhead: pCO2 = STHP x Y(CO2)/100 where: pCO2


Y(CO2)

= mole fraction in separated gas at STHP (3)

STHP


Corrosion occurs if pCO2 >0.2 atm. Note: (3)

If the percentage (ppm) of CO2 in the gas under static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead.

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Calculation Of Partial Pressure In Case B: Calculation of pCO2 at reservoir conditions: pCO2 = FBHP x Y(CO2)/100 where: FBHP

= flowing bottom-hole pressure [atm]

Y(CO2)

= mole fraction in separated gas at pressure FBHP (from the PVTs)

pCO2


Calculation Of pCO2 At Wellhead: The calculation method is the same as the one used in the wellhead conditions in case A: pCO2 = STHP x Y(CO2)/100 where: pCO2


Y(CO2)

= mole fraction in separated gas at STHP (4)

STHP


There is corrosion if pCO2 >0.2 atm. 9.2.3.

Corrosion Caused By H2S, CO2 And ClIt is possible to encounter H2S and CO2 besides Cl-. In this case the problem is much more complex and the choice of suitable material is more delicate. The phenomenon is diagnosed by calculating the partial pressures of H2S and CO2 and comparing them with the respective thresholds.

Note: (4)

If the percentage (ppm) of CO2 in the gas under flowing/static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead.

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CORROSION CONTROL MEASURES Corrosion control measures may involve the use of one or more of the following: • • • • • • • • • • • • • • • • •

Cathodic protection Chemical inhibition Chemical control Oxygen scavengers Chemical sulphide scavengers pH adjustment Deposit control Coatings Non metallic materials or metallurgical Control Stress reduction Elimination of sharp bends Elimination of shock loads and vibration Improved handling procedures Corrosion allowances in design Improved welding procedures Organisation of repair operations.

Refer to table 9.a below. Measure

Means

Control of the environment

• • • • • • • • •

Surface treatment

• Plastic coating • Plating

pH Temperature Pressure Chloride concentration CO2 concentration H2S concentration H2O concentration Flow rate Inhibitors

Improvement of the corrosion resistivity of the Addition of the alloying elements micro structure steel Table 9.A - Counter Measures to Prevent Corrosion

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CORROSION INHIBITORS An inhibitor is a substance which retards or slows down a chemical reaction. Thus, a corrosion inhibitor is a substance which, when added to an environment, decreases the rate of attack by the environmental on a metal. Corrosion inhibitors are commonly added in small amounts to acids, cooling waters, steam or other environments, either continuously or intermittently to prevent serious corrosion. There are many techniques used to apply corrosion inhibitors in oil and gas wells: • • • • • •

9.5.

Batch treatment (tubing displacement, standard batch, extended batch) Continuous treatment Squeeze treatment Atomised inhibitor squeeze - weighted liquids Capsules Sticks.

CORROSION RESISTANCE OF STAINLESS STEELS Stainless steel is usually used in applications for production tubing, however it is occasionally used for production casing or tubing below the packer depth. The main reason for the development of stainless steel is its resistance to corrosion. To be classed as a stainless steel, an iron alloy usually must contain at least 12% chromium in volume. The corrosion resistance of stainless steels is due to the ability of the chromium to passivate the surface of the alloy. Stainless steels may be divided into four distinct classes on the basis of their chemical content, metallurgical structure and mechanical properties these are:

9.5.1.

Martensitic Stainless Steels The martensitic stainless steels contain chromium as their principal alloying element. The most common types contain around 12% chromium, although some chromium content may be as high as 18%. The carbon content ranges from 0.08% to 1.10% and other elements such as nickel, columbium, molybdenum, selenium, silicon, and sulphur are added in small amounts for other properties in some grades. The most important characteristic that distinguishes these steels from other grades is their response to heat treatment. The martensitic stainless steels are hardened by the same heat treatment procedures used to harden carbon and alloy steels. The martensitic stainless steels are included in the ‘400’ series of stainless steels. The most commonly used of the martensitic stainless steels is AISI Type 410. The only grade of oilfield tubular used in this category is 13Cr. As their name indicates, the microstructure of these steels is martensitic. Stainless steels are strongly magnetic whatever the heat treatment condition.

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Ferritic Stainless Steels The second class of stainless steels, is the ferritic stainless steels, which are similar to the martensitic stainless steels in that they have chromium as the principal alloying element. The chromium contents of ferritic stainless steels is normally higher than that of the martensitic, stainless steel, and the carbon content is generally lower. The chromium content ranges between 13% to 27% but are not able to be hardened by heat treatment. They are used principally for their temperature properties. Ferritic stainless steels are also part of the ‘400’ series, the principal types being 405, 430, and 436. The microstructure of the ferritic stainless steels consists of ferrite, which are also strongly magnetic. Ferrite is simply body cantered cubic iron or an alloy based on this structure.

9.5.3.

Austenitic Stainless Steels The austenitic stainless steels have two principal alloying elements, chromium and nickel. Their micro-structure consists essentially of austenite which is face cantered cubic iron or an iron alloy based on this structure. They contain a minimum of 18% chromium and 8% nickel, with other elements added for particular reasons, and may range up to as high as 25% chromium and 20% nickel. Austenitic stainless steels generally have the highest corrosion resistance of any of the stainless steels, but their strength is lower than martensitic and ferritic stainless steels. They are not able to be hardened by heat treatment although they are hardenable to some extent by cold working and are generally non-magnetic. Austenitic stainless steels are grouped in the ‘300’ series, the most common being 304. Others commonly used are 303 free machining, 316 high Cr and Ni which may include Mo, and 347 stabilised for welding and corrosion resistance. These steels are widely used in the oilfield for fittings and control lines, but due to its low strength is not used for well tubulars.

9.5.4.

Precipitation Hardening Stainless Steels The most recent development in stainless steel is a general class known as ‘precipitation hardened stainless steels’, which contain various amounts of chromium and nickel. They combine the high strength of the martensitic stainless steels with the good corrosion resistance properties of the austenitic stainless steels. Most were developed as proprietary alloys, and there is a wide variety of compositions available. The distinguishing characteristic of the precipitation hardened stainless steel is that through specific heat treatments at relatively low temperatures, the steels can be hardened to varying strength levels. Most can be formed and machined before the final heat treatment and the finished product being hardened. Precipitation in alloys is analogous to precipitation as rain or snow. These are most commonly used for component parts in downhole and surface tools and not as oilfield tubulars. Refer to figure 9.b for the various compositions of stainless steels.

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Figure 9.B- Stainless Steel Compositions 9.5.5.

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Duplex Stainless Steel

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In general, ferritic-austenitic (duplex) stainless steel consists of between 40-70% ferrite and has a typical composition of 22% Cr-5.5% Ni-3% Mo-0.14% N. The resulting steel has properties that are normally found in both phases: the ferrite promotes increased yield strength and resistance to chloride and hydrogen sulphide corrosion cracking; while the austenite phase improves workability and weldability. This material is used extensively for tubulars used in severe CO2 and H2S conditions. As a general note, there is a large gap between the 13CR and Duplex Stainless Steels used as tubulars for their good anti-corrosion properties. This gap is attempted to be filled with ‘Super 13CR’ tubing being developed.

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CASING FOR SOUR SERVICE OCTG Materials For Corrosion By H2S Only In Oil Wells Conditions Material

0.0035< pH2S max < 0.1 0.0035< pH2S max < 0.1 0.0035< pH2S max < 0.1 pH2S max < 0.1

o

FBHT >80 C 60oC< FBHT >80oC FBHT >80oC

J55, K55, N80, C95, P110 J55, K55, N80 L80 L80 Mod, C90-1, T95-1

OCTG Materials For Corrosion By H2S Only In Gas Wells Conditions Material 0.0035< pH2S max < 0.1 0.0035< pH2S max < 0.1

FBHT >80oC FBHT <80oC

J55, K55, N80-2, C95 L80

OCTG Materials For Corrosion By CO2 And Cl Conditions Material 0.2< pCO2S max <100 0.2< pCO2S max <100 0.2< pCO2S max <100

FBHT <150oC o 150 C< FBHT <200oC

Cl- <50,000

0.2< pCO2S max <100e pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.005< pH2S max <0.1 pCO2S max <100e 0.005< pH2S max <0.1 0.2< pCO2S max <100e 0.005< pH2S max <0.1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e pH2S max >1

25% Cr-SA

FBHT <150oC

Cl- <50,000

13% Cr-80KSI Max

FBHT <200oC

Cl- >50,000

22% Cr CW 25% Cr CW 22% Cr 25% Cr

200oC< FBHT <250oC

Alternately L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1

Alternately

22% Cr

200oC< FBHT <250oC

150oC< FBHT <200oC

L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1

13% Cr

OCTG Materials For Corrosion By CO2 , H2S And Cl Conditions Material 0.2< pCO2S max <100e 0.0035< pH2S max < 0.005

Alternately

Cl- <50,000

25% Cr

Alternately 22% Cr 25% Cr

Cl- <50,000

25% Cr

Cl- >50,000

25% Cr CW

FBHT <250oC

Cl- <20,000

25% Cr

FBHT <250oC

Cl- <50,000

25% Cr CW

Cl- <50,000

28% Cr

FBHT <200oC

Cl- <50,000

22% Cr SA

FBHT <250oC

Cl- <50,000

25% Cr SA

FBHT <200oC

Cl- >50,000

28% Cr

Incoloy 825

28% Cr

Incoloy 825

200oC< FBHT <250oC

200oC< FBHT <250oC

Table 9.B - OCTG Materials for Sour Service

22% Cr, 25% Cr Incoloy 825 28% Cr Incoloy 825

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ORDERING SPECIFICATIONS When ordering tubulars for sour service, the following specifications should be included, in addition to those given in the above table. 1) 2) 3) 4) 5)

6) 7)

Downgraded grade N80, P105 or P110 tubulars are not acceptable for orders for J55 or K55 casing. The couplings must have the same heat treatment as the pipe body. The pipe must be tested to the alternative test pressure (see API Bulletins 5A and 5AC). Cold die stamping is prohibited, all markings must be paint stencilled or hot die stamped. Three copies of the report providing the ladle analysis of each heat used in the manufacture of the goods shipped, together with all the check analyses performed, must be submitted. Three copies of a report showing the physical properties of the goods supplied and the results of hardness tests (Refer to step 3 above) must be submitted. Shell modified API thread compound must be used.

Note:

Recommendations for casing to be used for sour service must be specified according to the API 5CT for restricted yield strength casings.

The casing should also meet the following criteria: • •

The steel used in the manufacture of the casing should have been quenched and tempered. (This treatment is superior to tubulars heated/treated by other methods e.g. normalising and tempering). All sour service casing should be inspected using non-destructive testing or impact tests only, as per API Specification 5CT.

9.8.

COMPANY DESIGN PROCEDURE

9.8.1.

CO2 Corrosion The following guidelines should be used for the appropriate corrosive environment. • •

In exploration wells, generally the presence of CO2 in the formation causes little problems, and will have no influence on material selection for the casing. In producing wells, the presence of CO2 may lead to corrosion on those parts coming in contact with CO2 which normally means the production tubing and part of the production casing below the packer.

Corrosion may be limited by: • •

The selection of high alloy chromium steels, resistant to corrosion. Inhibitor injection, if using carbon steel casing. Generally, wells producing CO2 partial pressure higher than 20psi requires inhibition to limit corrosion.

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9.8.2.

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H2S Corrosion In exploration wells, if there is high probability of encountering H2S, consideration should be given to limit casing and wellhead yield strength according to API 5CT and ‘NACE’ standard MR-01-75. In producing wells, casing and tubing material will be selected according to the amount of H2S and other corrosive media present. Refer to figure 9.c and figure 9.d for partial pressure limits.

Figure 9.C - Sour Gas Systems

Figure 9.D - Sour Multiphase Systems

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Figure 9.E - Sumitomo Metals

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Domain

Mild Environment

Domain “A”

Sulphide Stress Corrosion Cracking (medium pressure and temperature)

Domain “B”

Sulphide Stress Corrosion Cracking (high pressure and temperature)

Domain “C”

Wet CO2 Corrosion

Domain “D”

Material

Domain “E”

Domain “F”

SM 95G SM 125G

API

SM 80S SM 90S SM 95S SM 85SS SM 90SS SM C100 SM C110 SM 9CR 75 SM 9CR 80 SM 9CR 95 SM 13CR 75 SM 13CR 80 SM 13CR 95 SM 22CR 65* SM 22CR 110** SM 22CR 125** SM 25CR 75* SM 25CR 110** SM 25CR 125** SM 25CR 140** SM 2535-110 SM 2535-125 SM 2242-110 SM 2242-125 SM 2035-110 SM 2035-125 SM 2550-110 SM 2550-125 SM 2550-140 SM 2060-110*** SM 2060-125*** SM 2060-140*** SM 2060-155*** SM C276-110*** SM C276-125*** SM C276-140***

L 80 C 90 T 95 1Cr 0.5Mo Steel Modified AISI 4130

9Cr 1Mo Steel

22Cr 5Ni 3Mo Steel

25C -35Ni 3Mo Steel 22Cr 42N -3Mo Steel 20Cr 35Ni 5Mo Steel

Most Corrosive Environment

Domain “G”

SM’ Designation

J 55 N 80 P 110 (Q 125) Cr or Cr Mo Steel

25Cr 6Ni 3Mo Steel

Wet CO2 with H 2S Corrosion

0

API

13Cr Steel Modified AISI 420 Wet CO2 with a little H 2S Corrosion

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Application (Refer to figure 9.e)

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25Cr 50Ni 6Mo Steel



Notes

Higher yield strength for sour service Quenched and tempered Quenched and tempered Duplex phase Stainless steels *

Solution Treated

** Cold drawn As cold drawn

As cold drawn

*** Environment with free Sulphur

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10.

TEMPERATURE EFFECTS

10.1.

HIGH TEMPERATURE SERVICE

0

For deep wells, reduction in yield strength must be considered due to the effect on steel by the temperature. It no information is available on temperature gradients in the area, a gradient of 3°C/100m is to be used. Use the values in figure .a10.a for reduction in yield strength. where:

K0.2

=

Yield strength as per ISO normative with permanent deformation of 0.2%. Figure .A10.A - Temperature Effects

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LOW TEMPERATURE SERVICE Operations at low temperatures require tubulars made from steel with high ductility at low temperatures to prevent brittle failures during transport and handling. (Refer to figure 10.b below)

Figure 10.B - Arctic Service

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11.

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LOAD CONDITIONS When running casing, shock loads are exerted on the pipe due to: • •

Sudden deceleration forces (e.g.: if the spider accidentally closes or the slips are kicked-in when the pipe is moving or the pipe hits a bridge). Sudden acceleration forces (e.g.: picking the pipe out of the slips or if the casing momentarily hangs up on a ledge then freed).

Either of the above will cause a stress wave to be created which will travel through the casing at the speed of sound. This effect is quantified as follows: SL = 150 x V x Af where: SL V Af 150 11.1.

= = = =

Shock load (lbs x ins 2) Peak velocity when running (ins/sec) Cross-sectional area (ins 2) Speed of sound in steel (lbs x sec/ins)

SAFE ALLOWABLE TENSILE LOAD A safe allowable pull on the pipe should be calculated, stipulated during the casing string design process and specified in the Geological Drilling Programme or communicated to the well site prior to running casing. This is particularly important when reciprocating pipe during the cementing procedure. The application of the pulling load should only be considered as an emergency measure to retrieve the casing string from the wellbore. It is normal to incorporate an overpull contingency of 100,000lbs (45tons over the weight of the string in the mud as part of the casing string design).

11.2.

CEMENTING CONSIDERATIONS

11.2.1. Casing Support The cement sheath can protect the casing against several types of potential downhole damage including: • • •

Deformation through perforating gun detonations. Formation movement, salt flows, etc. (Refer to previous section 8.7). The loss of the bottom joint on surface or intermediate strings during drilling.

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However, the following aspects also need to be noted: • •

Adding resistance to casing collapse for design purposes is questionable. In fault slippage zones, doglegs and certain sand control failures, the cement sheath may contribute to problems.

11.2.2. Cementing Loads As a cement slurry is pumped into the casing, the weight indicator increases to a maximum when mud has been displaced from the casing by the full amount of cement. The maximum weight of the string occurs when the cement reaches the casing shoe or when the top cement plug is released. This weight increase can approach the remaining allowable pull margin of the string. If reciprocation is contemplated, this remaining margin may be so small to prevent reciprocation and, hence stretching of the pipe. After considering this issue, the design engineer may decide that a higher allowable pull contingency is required. For design calculation, the worst case situation is assumed as follows: • • •

The mud weight in the annulus is the lowest planned for the section. The inside of the casing is full of cement slurry, with mud above. The shoe instantaneously plugs off just as the cement reaches it and the pressure rises to a value of approximately ‘1,000psi’ before the pumps are able to be shut down.

The load in this situation is calculated as follows: CCL = [(Cw - Mw) x D + 1,000] x Ai where: CCL

=

Cementing contribution load (lbs)

Cw

=

Cement weight (psi/ft)

Mw

=

Outside mud weight (psi/ft)

D

=

Length over which Cw & Mw act(ft)

Ai

=

Internal area of casing (ins 2)

1,000

=

Pressure increment (psi)

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PRESSURE TESTING Casing pressure tests will be carried out according to the pressure stated in the drilling programme. The leading criteria for pressure testing will be the maximum anticipated wellhead pressure. 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 WP. When establishing an internal casing pressure test, the differential pressure due to a difference in fluid level and/or fluid density, inside and outside the casing, shall be taken into account. Consideration should be taken on the maximum allowable tensile strength of the casing thread considering the relevant tensile design factor. Each casing shall be pressure tested at the following times: • • •

When cement plug bumps on bottom with a pressure stated in the drilling programme. When testing blind/shear rams of the BOP stack against the casing. After having drilled out a DV collar.

A cemented liner overlap will be positively tested applying a pressure greater than the lea-off pressure of the previous casing. If there is any doubt, an inflow test could be carried out, with a sufficient drawdown to test the liner top to the most severe negative differential pressure that will exist during the life of the well. The test pressure shall be held and remain stable for at least 10-15 mins The test pressure and method for each well are determined on an individual basis and shall be included in the Geological and Drilling Programme. 11.4.

BUCKLING AND COMPRESSIVE LOADING The following buckling and compressive loads must also be considered.

11.4.1. Buckling Buckling is a failure of stability which can occur at stress levels well below the yield stress of the material. Buckling cannot occur where the casing is supported by cement. Factors responsible for buckling and the degree of buckling are: • • • • •

Length of casing, supported by cement. Hole size and degree of washout. Tensile loads on the casing string. Changed pressure conditions across the pipe. Temperature increases downhole.

All these factors are interrelated but the first three are generally considered major contributors to buckling, while temperature and pressure changes are primarily the mechanisms that cause the initial buckling.

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A buckling potential may exist in the uncemented portion of a string of casing, if the: • • • • •

Internal mud density is increased. Internal surface pressure is increased. Annular fluid removed or its density reduced. Casing is landed with less than full hanging weight. Temperature of the casing increases.

Buckling of long, uncemented portions of the casing string, in vertical wells, can be prevented by: • • • •

Cementing the casing up above the neutral point. Pre-tensioning the casing after landing. Limiting the increase in mud density used after drilling out the casing. Rigidly centralising the casing below the neutral point.

Provided that all casing strings can be landed with full hanging weight, the buckling calculation is only required on the small percentage of deep vertical wells in which the mud density is to be raised during the drilling of the next open hole section. Thus, for the majority of wells, buckling is not a major design problem. 11.4.2. Compressive Loads Compressive loads can occur in casing strings as a result of: • •

Landing inner strings within or on top of an outer string. Restricting length changes that would occur as the result of increasing downhole temperatures. This condition occurs when casing strings are anchored firmly at both ends with an unsupported interval between.

In most well designs, the total compressive load is the buoyant load of the intermediate casings, the tubing to production packer overpull and the weight of the wellhead. This compressive load is carried by the outer casing string. This outer casing is usually the conductor or surface casing. When discussing compressive loads it is convenient to consider three types of well where: a) b) c)

The wellhead is at ground level or at the seabed. The wellhead is above seabed (i.e.: platform wells). The mudline suspension takes the weight of the casing at the seabed, but the wellhead is above seabed.

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Wellhead at Ground Level or at Seabed When the surface casing (i.e.: 20ins or 185/8ins) is cemented to the surface or seabed it can be considered as a rigid foundation capable of carrying the total buoyant weight of the inner strings, the wellhead and any tubing to packer load. If the surface casing is not cemented to surface the uncemented portion will compress in the elastic manner until either the yield is exceeded or buckling occurs (if the unsupported length exceeds a critical length). From this, it is obvious that surface casing should and must be cemented to surface. The surface casing string must be designed to carry the compressive loads placed upon it. No compressive load is carried by the inner strings. Buckling may be ignored if the surface casing is completely cemented to the base of the wellhead. Wellhead above Sea Level (Platform Wells, No Mudline Suspension) Compressive loads in surface strings on wells in which the wellheads is above sea level, can lead to buckling in the free-standing portion of the well. To prevent buckling, every joint of the surface casing must be centralised within the previous string (usually a free standing 30ins or 26ins string) or restrained by a wellhead jacket. The surface casing must be designed for compression loads as outlined in a) above. For every new platform, a full structural analysis should be commissioned. This analysis must assess the adequacy of the conductor/surface casing design for buckling resistance. Mudline Suspension In this case, the weight of the casing strings is taken at the seabed. The surface casing must be designed and cemented as outlined in a) above. The tieback strings above the mudline suspension hanger may be subject to some degree of buckling. Most wellhead hook-ups can be safely supported on a 20ins x 133lbs/ft casing string in water depths up to 300ft (92m). However, if buckling may be suspected to occur in the tied back surface string a full structural analysis should be commissioned. The structural analysis may be carried out by companies involved in the supply of conductors. The analysis is in effect a Riser Tensioner Analysis as is evaluated for semi-submersibles and it takes into account the effect of waves, current and the weight of the pipe in the free standing mode.

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Compressive Loads Due to Temperature Temperature rises in the uncemented portion of a casing string will give rise to axially compressive forces in the string, if the casing is constrained. However, the compressive forces will relieve the tensional forces in the casing and need not be considered in the design unless buckling occurs. Therefore, except in extreme cases such as thermal recovery wells, temperature loads need only be assessed in casing strings on which buckling may occur and need only be treated in this context. Decrease in Temperature a)

Drilling Phase: It is highly unlikely that any routine operation (other than extensive reverse circulation) will cause a long term temperature decrease in the uncemented portion of a casing string, thus, no loading applies.

b)

Production Phase: Temperature induced stresses are of no consequence in the outer strings of casing and attention need only be paid to the production string. Producers are normally subjected to temperature increases under operating conditions and the compressive load induced should be treated in the context of buckling. The tensile loads induced by cooling in high volume injection wells, or in producers during high volume stimulation treatments or emergency squeeze kills, must be taken into account. It should be added to the axial load and included in the design load if the occurrence of such loading is anticipated

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12.

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PRESSURE RATING OF BOP EQUIPMENT This section includes design criteria for BOP equipment which are extracted from the Well Control Policy Manual. The prime considerations, when selecting and procuring pressure control equipment, are the safety of the personnel, rig and maintaining the integrity of the wellbore. In order to assure this safety requirement, several factors need to be considered. Note:

It should be realised that each drilling area may have local regulations unique to that particular area which exceed the general requirements stated in this section, or indeed the Eni-Agip Well Control Policy Manual. In addition, the various operating companies and their contractors may also vary from these general requirements, if dictated by individual company policy and philosophy providing they are not less stringent than described herein.

The anticipated formation pressure is the governing parameter which dictates the casing depth, casing selection, BOP selection and pressure rating of the BOP equipment as described previously in section 2. The weakest element within any pressure control system determines the maximum pressure that can be safely controlled. Individual elements of the pressure control system may exceed the assembly WP, and under no circumstances should components be used which are less than the assembly WP. For instance, a 10,000psi choke may be rigged up with a 2,000psi BOP stack in anticipation of its later use when the 10,000psi BOP stack is nippled up for a subsequent string of casing. The equipment in the well control system which has the lowest pressure rating will set the rating for entire system e.g. 2,000psi stack and 10,000psi choke manifold would be rated to only 2,000psi WP. Since the well control system must be able to contain any anticipated formation pressures that may be encountered, the maximum anticipated surface pressures must first be calculated. Many different methods are available to determine the maximum casing pressures which may be encountered during a kick as described in section 2. 12.1.

BOP SELECTION CRITERIA Blow-out preventer equipment configurations shall consist of an annular preventer and a specified number of ram type preventers. The working pressure of any blow-out preventer shall exceed the maximum anticipated surface pressure to which it may be subjected.

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The graph illustrated in the attached figure 12.a has been prepared to enable the first approximation of the BOP rating necessary for use in drilling an exploration well. To use the graph, the setting depths of the various casings and the relative pore pressure gradients must be found or determined during the design phase. The co-ordinates in the graph are depth and pressure and comprises two groups of lines respectively, one representing the BOPs to be used while drilling and the other the BOPs to be used during well testing. Each group outlines the different solutions available to the various pore pressure gradients. Example:

The casing program assumes that a well test will be carried out at the shoe of 7” casing. From the diagram shown in table 12.a, the maximum test, drilling pressure values and the size of BOP to be used should be obtained which is given in table 12.a below.

Casing (ins)

Shoe Depth (m)

Overburden Gradient (kg/cm2/10m)

Pore Press. Gradient (kg/cm2/10m)

Fracture Gradient (kg/cm2/10m)

BOP Drilling (psi)

Size Production Test (psi)

20

750

2.23

1.03

1.83

2,000

/

3

13 /8

2.620

2.36

1.30

2.01

5,000

/

5

9 /8

4.200

2.42

1.70

2.18

10,000

/

7

4.830

2.43

2.00

2.29

/

15,000

Table 12.A - BOP Selection Example Data The maximum theoretical stress possible at the casing head, Pmax, occurs when the well is full of gas and the fracture pressure has been reached at the shoe of the last casing run. This pressure is: Pmax =

H (Gr - Dg ) (Kg/cm2 ) 10

where: H

=

Casing shoe depth (m)

Gf

=

Fracture gradient of the casing shoe (kg/cm2/10m)

Dg

=

Gas density, assumed = 0.3(kg/dm 3)

In the case of a well test, this pressure roughly corresponds to the limit value required for pumping gas into the formation and is thus actually attainable in practice. This hypothesis however is completely unrealistic in the drilling design, for which 60% of the pressure Pmax will be used as limit value according to company policy in ‘burst design criteria’, section 8.1. This value is also adopted by many other companies as the realistic criterion of choice.

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Figure 12.A - BOP Selection Example

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KICK TOLERANCE Kick tolerance is the term used to define the maximum kick volume which can be safely controlled by any well control method with constant BHP without fracturing the formation below the last casing shoe. The most dangerous situation is when the top of the kick reaches the casing shoe. This is calculated with the following formula:

Ptop =

Gp × H − (Gi × Hi + Gm × Hm ) 10

Ptop < Pfr

PP− Hi =

Gmx (H −Hs −Hi )x Gi xHi = Gfr xHs 10

10

10

[HS (Gf r − Gm ) + Gm × H − 10 × PP ] Gm − Gi

Vshoe = Ca x Hi V1 x P1 = P2 X V2 V1bottom x Pp = Vshoe x Pfr where: Ca H Hi HS Gfr Gm PP Gi Ptop Gp Hm Pfr

= = = = = = = = = = = =

Annular capacity below the shoe, m Total depth, m Height of influx, m Shoe Depth Formation fracture gradient at shoe, kg/cm2/10m Mud weight, kg/ltr Formation pressure at total depth, kg/cm2 Density of the influx Top Influx Pressure Pore gradient Hight of the mud below the influx Fracture pressure

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Appendix A - ABBREVIATIONS API BG BHA BHP BHT BOP BPD BPM BSW BUR BWOC BWOW CBL CCD CCL CET CGR CP CRA CW DC DHM DLP DLS D&CM DOB DOBC DOR DP DST DV ECD ECP EMS EMW EOC ESD ESP FBHP FBHT FPI/BO FTHP FTHT GLR GMS

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American Petroleum Institute Background gas Bottom Hole Assembly Bottom Hole Pressure Bottom hole temperature Blow Out Preventer Barrel Per Day Barrels Per Minute Base Sediment and Water Build Up Rate By Weight Of Cement By Weight Of Water Cement Bond Log Centre to Centre Distance Casing Collar Locator Cement Evaluation Tool Condensate Gas Ratio Conductor Pipe Corrosion Resistant Alloy Current Well Drill Collar Down Hole Motor Dog Leg Potential Dog Leg Severity Drilling & Completion Manager Diesel Oil Bentonite Diesel Oil Bentonite Cement Drop Off Rate Drill Pipe Drill Stem Test DV Collar Equivalent Circulation Density External Casing Packer Electronic Multi Shot Equivalent Mud Weight End Of Curvature Electric Shut-Down System Electrical Submersible Pump Flowing Bottom Hole Pressure Flowing Bottom Hole Temperature Free Point Indicator / Back Off Flowing Tubing Head Pressure Flowing Tubing Head Temperature Gas Liquid Ratio Gyro Multi Shot

0

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GOC GOR GPM GPS GR GSS HAZOP HHP HP/HT HW/HWDP IADC ID IPR JAM KMW KOP LAT LCM LCP LEL LOT LQC LWD MAASP MD MLS MMS MODU MOP MPI MSL MSS MW MWD NACE NDT NMDC NSG NTU OBM OD OH OIM OMW ORP OWC P&A

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Gas Oil Contact Gas Oil Ratio Gallon (US) per Minute Global Positioning System Gamma Ray Gyro Single Shot Hazard and Operability Hydraulic Horsepower High Pressure - High Temperature Heavy Weight Drill Pipe International Drilling Contractor Inside Diameter Inflow Performance Relationship Joint Make-up Torque Analyser Kill mud weight Kick Off Point Lowest Astronomical Tide Lost Circulation Materials Lower Circulation Position (GP) Lower Explosive Limit Leak Off Test Log Quality Control Log While Drilling Max Allowable Annular Surface Pressure Measured Depth Mudline Suspension Magnetic Multi Shot Mobile Offshore Drilling Unit Margin of Overpull Magnetic Particle Inspection Mean Sea Level Magnetic Single Shot Mud Weight Measurement While Drilling National Association of Corrosion Engineers Non Destructive Test Non Magnetic Drill Collar North Seeking Gyro Nephelometric Turbidity Unit Oil Based Mud Outside Diameter Open Hole Offshore Installation Manager Original Mud weight Origin Reference Point Oil Water Contact Plugged & Abandoned

0

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PBR PCG PDC PDM PGB PI PLT ppb ppg ppm PV PVT Q Q/A Q/C RFT RKB ROE ROP ROU ROV RPM RT S (HDT) S/N SBHP SBHT SCC SD SDE SF SG SICP SIDPP SPM SR SRG SSC STG TCP TD TGB TOC TOL TVD TW UAR UR

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Polished Bore Receptacle Pipe Connection Gas Polycrystalline Diamond Cutter Positive Displacement Motor Permanent Guide Base Productivity Index Production Logging Tool Pounds per Barrel Pounds per Gallon Part Per Million Plastic Viscosity Pressure Volume Temperature Flow Rate Quality Assurance, Quality Control Repeat Formation Test Rotary Kelly Bushing Radius of Exposure Rate Of Penetration Radios Of Uncertainty Remote Operated Vehicle Revolutions Per Minute Rotary Table High Resolution Dipmeter Serial Number Static Bottom-hole Pressure Static Bottom-hole Temperature Stress Corrosion Cracking Separation Distance Senior Drilling Engineer Safety Factor Specific Gravity Shut-in Casing Pressure Shut-in Drill Pipe Pressure Stroke per Minute Separation Ratio Surface Readout Gyro Sulphide Stress Cracking Short trip gas Tubing Conveyed Perforations Total Depth Temporary Guide Base Top of Cement Top of Liner True Vertical Depth Target Well Uncertainty Area Ratio Under Reamer

0

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VBR VDL VSP W/L WBM WC WL WOB WOC WOW WP YP

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Variable Bore Rams (BOP) Variable Density Log Velocity Seismic Profile Wire Line Water Base Mud Water Cut Water Loss Weight On Bit Wait On Cement Wait On Weather Working Pressure Yield Point

0

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Appendix B - BIBLIOGRAPHY Document:

STAP Number

Drilling Procedures Manual

STAP-P-1-M-6140

Drilling Design Manual

STAP-P-1-M-6100

Overpressure Manual

STAP-P-1-M-6130

Drilling Fluids Manual

STAP-P-1-M-6160

Well Control Policy Manual

STAP-P-1-M-6150

API Specification 5C Holmquist & Nadai Shell (Bol, 1985) NACE Standard MR-01-75 Sumitomo Metals Literature

ENI - Casing Design Manual

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