ENI - Casing Design Manual

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<p>A RPOENI S.p .A.Ag i p Di vi si onORGANISINGDEPARTMENTTYPE OFACTIVITY'ISSUINGDEPT.DOC.TYPEREFER TOSECTION N.PAGE.1OF 134STAP P 1 M 6110The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used forreasons different from those owing to which it was givenTITLECASING DESIGN MANUALDISTRIBUTION LISTEni - Agip Division Italian DistrictsEni - Agip Division Affiliated CompaniesEni - Agip Division Headquarter Drilling &amp; Completion UnitsSTAP ArchiveEni - Agip Division Headquarter Subsurface Geology UnitsEni - Agip Division Headquarter Reservoir UnitsEni - Agip Division Headquarter Coordination Units for Italian ActivitiesEni - Agip Division Headquarter Coordination Units for Foreign ActivitiesNOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni -Agip Division Headquarter)Date of issue: Issued by P. MagariniE. MonaciC. Lanzetta A. Galletta28/06/99 28/06/99 28/06/99REVISIONS PREP'D CHK'D APPR'D28/06/99A RPOENI S.p.A.Agi p Di vi si onIDENTIFICATION CODEPAGE 2 OF 134REVISIONSTAP-P-1-M-6110 0INDEX1. INTRODUCTION 51.1. PURPOSE OF CASING 62. CASING PROFILES AND DRILLING SCENARIOS 72.1. Casing Profiles 72.1.1. Onshore Wells 72.1.2. Offshore Wells - Surface Wellhead 72.1.3. Offshore Wells - Surface Wellhead &amp; Mudline Suspension 72.1.4. Offshore Wells - Subsea Wellhead 72.2. Drive, Structural &amp; Conductor Casing 82.2.1. Surface Casing 82.2.2. Intermediate Casing 92.2.3. Production Casing 102.2.4. Liner 113. SELECTION OF CASING SEATS 123.1. Conductor Casi ng 153.2. Surface Casing 153.3. Intermediate Casing 153.4. Drilling Liner 163.5. Production Casing 173.6. CASING AND relative HOLE SIZES 173.6.1. Standard Casing and Hole Sizes 214. CASING SPECIFICATION AND CLASSIFICATION 224.1. CASING SPECIFICATION 224.2. API CASING CLASSIFICATION 234.3. NON-API CASING 255. MECHANICAL PROPERTIES OF STEEL 285.1. General 285.2. Stress-Strain Diagram 285.3. Heat Treatment Of Alloy Steels 306. TUBULAR RANGE LENGTHS &amp; COLOUR CODING 366.1. Range lengths 366.2. api tubular marking and colour coding 386.2.1. Markings 386.2.2. Colour Coding 39A RPOENI S.p.A.Agi p Di vi si onIDENTIFICATION CODEPAGE 3 OF 134REVISIONSTAP-P-1-M-6110 07. APPROACH TO CASING DESIGN 417.1. WELLBORE FORCES 427.2. DESIGN FACTOR (DF) 427.2.1. Company Design Factors 447.2.2. Application of Design Factors 458. DESIGN CRITERIA 468.1. BURST 468.1.1. Design Methods 468.1.2. Company Design Procedure 478.2. COLLAPSE 508.2.1. Company Design Procedure 508.3. TENSION 548.3.1. General 548.3.2. Buoyancy Force 548.3.3. Company Design Procedure 598.3.4. Example Hook Load During Cementing 598.4. BIAXIAL STRESS 628.4.1. General 628.4.2. Effects On Collapse Resistance 628.4.3. Company Design Procedure 648.4.4. Example Collapse Caclulation 658.5. BENDING 678.5.1. General 678.5.2. Determination Of Bending Effect 688.5.3. Company Design Procedure 708.5.4. Example Bending Calculation 708.6. CASING WEAR 728.6.1. General 728.6.2. Volumetric Wear Rate 738.6.3. Factors Affecting Casing Wear (Example) 768.6.4. Wear Factors 808.6.5. Detection Of Casing Wear 868.6.6. Casing Wear Reduction 868.6.7. Wear Allowance In Casing Design 878.6.8. Company Design Procedure 888.7. SALT SECTIONS 898.7.1. General 898.7.2. External Loading Due To Salt Flow 898.7.3. Company Design Procedure 949. CORROSION 969.1. General 969.1.1. Exploration and Appraisal Wells 969.1.2. Development Wells 969.1.3. Contributing Factors to Corrosion 979.2. Forms Of Corrosion 989.2.1. Sulphide Stress Cracking (SSC) 989.2.2. Corrosion Caused By CO2 And Cl-105A RPOENI S.p.A.Agi p Di vi si onIDENTIFICATION CODEPAGE 4 OF 134REVISIONSTAP-P-1-M-6110 09.2.3. Corrosion Caused By H2S, CO2 And Cl-1079.3. Corrosion Control Measures 1089.4. Corrosion Inhibitors 1099.5. Corrosion Resistance of Stainless Steels 1099.5.1. Martensitic Stainless Steels 1099.5.2. Ferritic Stainless Steels 1109.5.3. Austenitic Stainless Steels 1109.5.4. Precipitation Hardening Stainless Steels 1109.5.5. Duplex Stainless Steel 1119.6. Casing For Sour Service 1139.7. Ordering Specifications 1149.8. Company Design Procedure 1149.8.1. CO2 Corrosion 1149.8.2. H2S Corrosion 11510. TEMPERATURE EFFECTS 11810.1. High Temperature Service 11810.2. Low Temperature Service 11911. LOAD CONDITIONS 12011.1. SAFE ALLOWABLE TENSILE LOAD 12011.2. CEMENTING CONSIDERATIONS 12011.2.1. Casing Support 12011.2.2. Cementing Loads 12111.3. PRESSURE TESTING 12211.4. BUCKLING AND COMPRESSIve loading 12211.4.1. Buckling 12211.4.2. Compressive Loads 12312. PRESSURE RATING OF BOP EQUIPMENT 12612.1. BOP selection criteria 12612.2. Kick tolerance 129A RPOENI S.p.A.Agi p Di vi si onIDENTIFICATION CODEPAGE 5 OF 134REVISIONSTAP-P-1-M-6110 01. INTRODUCTIONThe selection of casing grades and weights is an engineering task affected by many factors,including local geology, formation pressures, hole depth, formation temperature, logistics andvarious mechanical factors.The engineer must keep in mind during the design process the major logistics problems incontrolling the handling of the various mixtures of grades and weights by rig personnel withoutrisk 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 weightsis 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 upgradingthe casing in cases where: Extreme wear is expected from drilling equipment used to drill the next holesection 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 alwaysa major criterion.Most major operating companies have differing policies for the design of casing for explorationand 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 bottomholeflowing pressures and well head shut-in pressures as the limiting factors forinternal pressures expected in the wellbore. These pressures will obviously placecontrols only on the design of production casing or the production liner, andintermediate casing.A RPOENI S.p.A.Agi p Di vi si onIDENTIFICATION CODEPAGE 6 OF 134REVISIONSTAP-P-1-M-6110 01.1. PURPOSE OF CASINGCasing tubulars are placed in a wellbore for the following reasons:a) Supporting the weight of the wellhead and BOP stack.b) Providing a return path for mud to surface when drilling.c) Controlling well pressure by containing downhole pressure.d) Isolating high pressure zones from the wellbore.e) Isolating permeable zones from the wellbore which are likely to cause differentialsticking.f) Isolating special trouble zones which may cause hole problems e.g.: 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.g) Separating different pressure or fluid regimes.h) Providing a stable environment for packers, liner hangers, etc.i) Isolating weak zones from the wellbore during fracturing.j) Isolating permeable productive formations, reducing the risk of undergroundblowouts.k) 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) Providing internal pressure containment when the tubing system leaks or fails.b) Preventing wellbore fluids from contaminating production.c) Providing protection for completion equipment.d) Providing access to producing formations for remedial operations.e) Providing cement integrity across producing formations.A RPOENI S.p.A.Agi p Di vi si onIDENTIFICATION CODEPAGE 7 OF 134REVISIONSTAP-P-1-M-6110 02. CASING PROFILES AND DRILLING SCENARIOS2.1. CASING PROFILESThe following are the various casing configurations which can be used for onshore andoffshore wells.2.1.1. Onshore Wells 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.2.1.2. Offshore Wells - Surface WellheadAs in onshore above.2.1.3. Offshore Wells - Surface Wellhead &amp; Mudline Suspension 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.2.1.4. 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.A RPOENI S.p.A.Agi p Di vi si onIDENTIFICATION CODEPAGE 8 OF 134REVISIONSTAP-P-1-M-6110 02.2. DRIVE, STRUCTURAL &amp; CONDUCTOR CASINGThe purpose of this first string of pipe is primarily to protect incompetent surface soils fromerosion by drilling fluids. Where formations are sufficiently stable, this string may be used toinstall the full mud circulation system.It also serves the following purposes: Guide the drilling string and subsequent casing into the hole. The conductor inoffshore drilling may form a part of the piling system for a wellhead jacket or piledplatform. Provide centralisation for the inner casing strings which limits column buckling.They do not carry direct axial loads except during initial installation of the surfacecasing. 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 thesettlement and rotational movement of gravity platforms.The conductor casings are usually driven completely to depth or, alternatively, run into apredrilled or jetted hole and cemented. If they are driven, they must be designed to withstandhammering loads.Conductor casings, in offshore drilling with subsea BOP's, are usually either jetted into placeor cemented in a predrilled hole. They support a Temporary Guide Base whichaccommodates and aligns all future wellhead installations for both the drilling and productionphases. They directly carry both the axial and bending loads imposed by the wellhead, but arerigidly connected to the next casing with centralisers and cement in order to dissipate loadingand minimise resulting stresses.2.2.1. Surface CasingThe 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 whichBOPs can be mounted. It is important to appreciate that the amount of protection providedagainst 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 thanattempt 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 limitcolumn buckling.The annulus between the conductor and surface string is usually left uncemented above themudline to minimise load transfer and bending stresses in the surface string.A RPOENI S.p.A.Agi p Di vi si onIDENTIFICATION CODEPAGE 9 OF 134REVISIONSTAP-P-1-M-6110 02.2.2. Intermediate CasingThese are used to ensure there is adequate blow-out protection for deeper drilling and toisolate formations or hole profile changes, that can cause drilling problems.The first intermediate string is the first casing providing full blow-out protection. Its settingdepth is often chosen so that it also isolates troublesome formations, loss zones, shallowhydrocarbons, water sands, or the build-up section of deviated wells. It is usually cementedup 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 akick which could cause breakdown at the previous casing shoe, and/or severe losses in theopen hole section.An intermediate casing string is, therefore, nearly always set in the transition zone above orbelow 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 theknown hydrocarbon bearing intervals as a contingency against the possibility of encounteringa loss circulation zone. Obviously the latter is intended primarily for massive reservoirsections rather than sand-shale sequences with numerous small reservoirs and sub-reservoirs. An intermediate string may also be set simply to reduce the overall cost of drillingand completing the well by isolating intervals which have been found to cause mechanicalproblems 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 singlecasing point. A liner may be used instead of a full intermediate casing and difficult wells mayactually contain several intermediate casings and/or liners. Caution should be taken whenusing liners as it is necessary to ensure the higher casing is designed for the pressures atlower 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, especiallywhere there may be aquifer movement which replenishes the corrosive elements around thewellbore.Longer cement columns are sometimes required to prevent buckling of the...</p>