PTS (Conductor Design and installation manual for offshore platform)

MANUAL

CONDUCTOR DESIGN AND INSTALLATION MANUAL FOR OFFSHORE PLATFORM

PTS 20.052 DECEMBER 1980

PREFACE

PETRONAS Technical Standards (PTS) publications reflect the views, at the time of publication, of PETRONAS OPUs/Divisions. They are based on the experience acquired during the involvement with the design, construction, operation and maintenance of processing units and facilities. Where appropriate they are based on, or reference is made to, national and international standards and codes of practice. The objective is to set the recommended standard for good technical practice to be applied by PETRONAS' OPUs in oil and gas production facilities, refineries, gas processing plants, chemical plants, marketing facilities or any other such facility, and thereby to achieve maximum technical and economic benefit from standardisation. The information set forth in these publications is provided to users for their consideration and decision to implement. This is of particular importance where PTS may not cover every requirement or diversity of condition at each locality. The system of PTS is expected to be sufficiently flexible to allow individual operating units to adapt the information set forth in PTS to their own environment and requirements. When Contractors or Manufacturers/Suppliers use PTS they shall be solely responsible for the quality of work and the attainment of the required design and engineering standards. In particular, for those requirements not specifically covered, the Principal will expect them to follow those design and engineering practices which will achieve the same level of integrity as reflected in the PTS. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from his own responsibility, consult the Principal or its technical advisor. The right to use PTS rests with three categories of users : 1) 2) 3)

PETRONAS and its affiliates. Other parties who are authorised to use PTS subject to appropriate contractual arrangements. Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) and 2) which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said users comply with the relevant standards.

Subject to any particular terms and conditions as may be set forth in specific agreements with users, PETRONAS disclaims any liability of whatsoever nature for any damage (including injury or death) suffered by any company or person whomsoever as a result of or in connection with the use, application or implementation of any PTS, combination of PTS or any part thereof. The benefit of this disclaimer shall inure in all respects to PETRONAS and/or any company affiliated to PETRONAS that may issue PTS or require the use of PTS. Without prejudice to any specific terms in respect of confidentiality under relevant contractual arrangements, PTS shall not, without the prior written consent of PETRONAS, be disclosed by users to any company or person whomsoever and the PTS shall be used exclusively for the purpose they have been provided to the user. They shall be returned after use, including any copies which shall only be made by users with the express prior written consent of PETRONAS. The copyright of PTS vests in PETRONAS. Users shall arrange for PTS to be held in safe custody and PETRONAS may at any time require information satisfactory to PETRONAS in order to ascertain how users implement this requirement.

EP/23.4

TEL: (070)

Dear Sirs, CONDUCTOR DESIGN AND INSTALLATION MANUAL (EP 52510 - DECEMBER 1980) In response to requests from operating companies for advice on offshore conductor installation we are sending a copies of a Shell Group "Conductor Design and Installation Manual", which we believe will be of assistance on this subject. The manual is of loose-leaf construction to permit easy insertion of updates as they become necessary. As with all operationally oriented subjects, feedback from your local experience offshore is essential for further development of techniques.

Yours faithfully, Shell Internationale Petroleum Maatschappij B.V

CONTENTS INTRODUCTION DEFINITIONS 1. GENERAL DESIGN AND INSTALLATION CONSIDERATIONS Functions of Conductors Sequence of Design and Installation Figure 1.1

2. DATA COLLECTION Site Investigation Bathymetric, Side Scan Sonar and TV Surveys Shallow Seismic Survey Soil Borings Design Check List (i) Penetration (ii) Steel Section and Grade (iii) Special Considerations Installation Equipment (i) Derrick Barge (ii) Hammers (iii) Drilling Rig (iv) Contingencies

3. CALCULATING THE SETTING DEPTH Factors which determine the Setting Depth Formation Breakdown (Hydraulic Fracture) Leak - Off Tests Other Causes of Lost Circulation Setting Depth and Spacing between Conductors and Piles Conductor Installation by Drilling or Drill-Drive Unstable Strata Conductor Tip in Clay

References Figure 3.1 Figure 3.2

4. SPUDDING-IN PROCEDURES Cleaning-out of Conductor Pilot Hole Drilling Techniques Setting the First Casing

5. INSTALLATION METHODS Driving Drill-Drive Drill and Drive Drill and Cement

6. AXIAL BEARING CAPACITY OF CONDUCTORS General Safety Factor The Conductor as a Pile Conductors Installed by Driving Conductors Installed by the Drill-Drive Technique Conductors Installed by the Drill and Drive Technique Conductors Installed by the Drill and Cement Technique Computing the Axial Load on the Conductor References Figure 6.1

7. SELECTION OF INSTALLATION METHOD Assessing Driving for Safety Assessing Driving for Feasibility Assessing Drill-Drive for Safety

Assessing Drill-Drive for Feasibility Assessing Drill-and-Drive Assessing Drill-and-Cement Current Practice

8. RECORDING THE INSTALLATION AND INSTRUMENTATION Why Installation Records are Essential Current Practice Instrumentation General Quality Control Figures 8.1, 8.2 and 8.3

9. CONDUCTOR SHOES Improving Drivability Reducing the Possibility of Damage to the Conductor Tip Directional Control Clearances Length off Shoe References Figure 9.1

10. CURVED CONDUCTORS Reasons for using Curved Conductors Disadvantages of Curved Conductors Limitations on Curvature Drivability Alternatives

11. CONTINGENCY PROCEDURES FOR CONDUCTORS WHICH DO NOT REACH SETTING DEPTH Conductors not Satisfying Axial Capacity Requirements Conductors not Satisfying Formation Fracture Requirements Other Contingency Measures

12. DO's and DON'T's Do's Dont's

APPENDICES APPENDIX I :

Records of Meetings with Personnel of various Shell Group Companies.

APPENDIX II-1 : Soil Parameters Required for Conductor Design and Installation Planning. APPENDIX II-2 : Calculation of the Coefficient of Earth Pressure at Rest (Ko ). APPENDIX III-1 : Use of the Wave Equation in Drivability Analyses. APPENDIX III-2 : Example of Wave Equation Analyses for Conductor Drill-Drive Sequence. APPENDIX III-3 : Extract from "Construction Specification for Installation of Steel Platforms", Prepared by SSB (September 1978). APPENDIX III-4 : Extract from "Outline Installation Procedure for SFDP A", Prepared by SSB. APPENDIX III-5 : Cormorant Alpha Conductor Installation Procedure, Prepared by Shell Expro (October 1978). APPENDIX III-6 : Extract from "Drill and Cement Conductor Installation Specification", Prepared by QPPA APPENDIX IV-1 : American Petroleum Institute (API RP 2A 1979) Axial Capacity Calculations APPENDIX IV-2 : Axial Capacity of a Drilled and Cemented Conductor APPENDIX V-1 : Report prepared by BSP entitled "Conductors for Tender Assisted Drilling Platforms" dated October 1972 APPENDIX V-2 : Calculation of Allowable Stick-up Height. APPENDIX V-3 : Typical Blowcount Record Sheet for offshore use together with a completed example from SBPT APPENDIX V-4 : Instrumentation for Conductors, Piles and Hammers APPENDIX V-5 : "Curved Conductor and Guide Considerations - Gulf of Mexico", Prepared by Shell Oil. APPENDIX V-6 : Use of Wave Equation for curved Conductors. Fugro Report for Shell Expro,U0227 th dated 25 September, 1978.

INTRODUCTION The purpose of this Manual is to serve as a guide for Company staff involved in the design and installation of conductors for fixed steel platforms. It is not a complete and infallible rule book for use in all circumstances. It cannot, therefore, replace common sense, sound judgement based on the knowledge of engineering principles, and field experience. The design and installation of conductors involves engineers from a number of different disciplines. Some may have difficulty in fully appreciating the requirements of others. Problems with conductors most frequently occur because of lack of communication between the different disciplines during the initial stages of the project. It is hoped that the contents of this Manual will enable the dialogue between departments to be improved. For this reason some subjects which are usually dealt with by Drilling Department are discussed, e.g. spudding-in procedures. Such discussions are for background purposes only, and Drilling Department should be consulted for advice on current good practice. A similar comment applies to design procedures which are always the responsibility of a platform design group, e.g. the computation of stress in a conductor due to environmental loading. If advice is required on such matters, Structural Engineering should be consulted. Any document concerning conductors is complicated by the fact that each discipline uses its own terminology and system of units. Therefore, a list of definitions has been provided together with commonly used alternatives. With regard to units it has proved impractical to standardise in this Manual. Sizes are quoted in the vernacular of the relevant discipline, e.g. the majority of the drillers still use inches and pounds, platform designers generally use SI units. The Group's efforts to achieve full metrication are, however, fully recognized. During the preparation of the Manual, discussions were held with Engineers in a number of Group Operating Companies. Brief records of these discussion are presented in Appendix I. From these records it is apparent that there, is considerable diversity of practice around the world. This is not surprising because different environments will result in varying solutions to the same problems. Hence an approach to conductor design and installation which may have proved ideal in one operating area may be less suitable in another. However, a lot can be learnt from the experiences of others and an exchange of knowledge can improve even the best practices. This Manual has been written by Fugro Limited in the U.K., under the direction of SIPM Department EP/23.4. NOTE : There is quite some confusion in the definition of a conductor. The definitions given above are of the Report EP - 40806 "Well Control and Blowout Prevention Manual" and it is perhaps somewhat unfortunate that the names "marine conductor" and "conductor" so closely resemble each other. To add to the confusion, construction engineers tend to drop the prefix "marine" and just speak of "driving the 30" conductor". Since this manual was written by construction oriented engineers, the single word conductor refers to the first pipe installed, typically 30" in diameter, typically driven, with apologies to the authors of the Well Control and Blowout Prevention Manual.

SURFACE STRING : 3 A pipe which is installed inside the conductor, typically of 13 /8" diameter. It is the second casing string, normally cemented to the seabed and serves to provide blowout protection, to seal off shallow water sands and prevent loss of circulation.

SPUDDING-IN : The procedure for drilling the hole for the first casing string.

DEFINITIONS MARINE CONDUCTOR (see NOTE on next page) The first pipe to be installed when drilling an offshore well typically 30" in diameter although other sizes are used. The marine conductor usually extends from the seabed up to the cellar deck of the platform and may have a penetration of a few hundred feet. The purpose is to provide lateral support to the well, to case off very soft formations below the seabottom, to facilitate circulation of drilling fluid and to guide the drill string until the next casing string has been set. The term "marine conductor" relates specifically to offshore drilling from a bottom- supported fixed or mobile platform (as opposed to a floating platform) with above water well control equipment.

CONDUCTORS (see NOTE on next page) A pipe which is installed inside the marine conductor typically 20" in diameter although other sizes are also used. The conductor is run into a predrilled hole and its function is to case off unconsolidated formations and water sands and to provide protection against shallow gas. This string is normally cemented to seabed and is the first string on which blowout preventers are installed. The conductor is considered to be the first casing string of the well.

1.

GENERAL DESIGN AND INSTALLATION CONSIDERATIONS

Functions of Conductors 1.1

The primary functions of a conductor are to facilitate the spudding-in of the well and to provide protection and lateral support to the well casings. The conductor assists spudding-in by providing guidance for the drilling tools, allowing the circulation of drilling fluid and supporting weak formations above the conductor tip level. Also, in conjunction with a diverter system, the conductor enables diverting a possible flow, originating from shallow formations. In the long term the conductor protects the well from external corrosion and provides lateral support against environmental loads by spanning between guides.

1.2

On some platforms the conductor bracing is designed so that the conductors act as laterally loaded piles and assist the foundations in taking-out shear at mudline. This may have the beneficial effect of reducing the number of foundation piles required. However, the conductor must be designed for this mudline shear and this can involve increasing the wall thickness of the conductor pipe. When there are no advantages in using the conductors as laterally loaded piles, guides in the bottom horizontal bracing are either omitted or designed with sufficient clearance to prevent conductors acting as piles.

1.3

If curved, slanted or otherwise "deviated" conductors are used they may provide initial alignment in the preferred azimuth and increase the separation of conductors at tip level. The latter reduces the risk of the drill string colliding with a previously installed casing string.

SETTING DEPTH The depth from some datum to the conductor shoe. This datum is the derrick floor during the drilling phase. In the production stage it may be the bottom flange of the wellhead or seabed. ADD-ON An extension pipe welded to the top of the conductor to permit further penetration to be achieved. Also it generally forms part of the final conductor configuration.

ABBREVIATIONS OPCOS

- Operating Companies

DB

- Derrick Barge

GBS

- Gravity Base Structure

NDT

- Non-destructive testing

SRD

- Soil Resistance at Time of Driving

dia.

- diameter

O.D.

- outside diameter

I.D.

- internal diameter

w.t.

- wall thickness

FIGURE 1.1 DESIGN AND INSTALLATION SEQUENCE

1.4

Under some circumstances the conductor may be required to serve as a temporary support for casing strings during cementation.

Sequence of Design and Installation 1.5

The considerations of paragraphs 1.1 to 1.4 together with information concerning: site and soil conditions platform and foundation design environmental conditions installation equipment determine the diameter, wall thickness and setting depth of the conductor and the method of installing it. A schematic representation of the design and planning procedure is provided on Figure 1.1. The numbers in each box on Figure 1.1 refer to the relevant paragraphs of this Manual.

1.6

A decision on the number of conductors, their diameter, the setting depth and whether they are to be vertical, slanted or curved has to be taken before the commencement of final platform design. This may be up to four or five years before the first well is installed. It is most important that the detailed planning of the installation of the conductor and the well are started at this early stage and are not left, as is the practice of some Oil Companies outside the Shell Group, until after the platform has been launched. The reason why conductor design and installation planning must start so far in advance of well installation is that the conductors have a large influence on the size of the platform, its structural configuration and the wave loads acting upon it.

2.

DATA COLLECTION

2.1

The purpose of this Section is to ensure that the Project Engineer or the members of the Project Team collect or generate sufficient data with which to optimise the design and method of installing the conductors. Some of the information concern physical parameters at the proposed platform location; other data result partly from decisions made by the Project Team, eg. spudding-in procedure, see Section 4.

Site Investigation 2.2

A site investigation has to be made as part of the design procedure for the platform foundation. Its scope should be such that it also provides data for conductor design and installation planning. Site investigations for platforms may include: (a) bathymetric survey (b) side scan sonar survey (c) shallow seismic survey (d) soil borings and insitu tests (e) TV inspection

It is common practice to carry out the first three items simultaneously from one vessel equipped for geophysical work. The soil borings would be made from a different vessel, usually under a separate contract and at a different time. The TV inspection of the seabed can be made in conjunction with either the soil or geophysical survey. Alternatively it can be performed as part of a "submarine" survey.

Bathymetric, Side Scan Sonar, and TV Surveys 2.3

These surveys provide data on water depth, seabed topography and obstructions on the seabed such as wrecks, pipelines and boulders. The requirements for platform design will be adequate for the conductors.

2.4

If there are any obstructions on the seabed, such as boulders, it will be necessary to remove them prior to platform or conductor installation, whichever is first. This is usually done by a "trawling" technique.

2.5

Before installing the conductors of a platform, it may be necessary to carry out an additional survey for "junk" (material dropped from the platform during installation). A number of techniques are available for carrying out this survey, for example TV can be used if there is no guide at bottom bracing level. In other cases each guide might have to be "fished".

Shallow Seismic Survey 2.6

The shallow seismic survey is made for a number of reasons? for the conductors the most important being: (a)

to indicate whether shallow gas is likely to be encountered within the foundation soils (in conjunction with deep seismic records)

(b)

to provide information on soil stratification in conjunction with the soil borings

(c)

to detect "boulders" below seabed

2.7

The information obtained on the presence or absence of shallow gas is important for the whole casing and drilling programme, including the setting depth of the conductor and the "spudding-in" procedure. A pocket of shallow gas shows up as a "bright spot" on the seismic record. However not all "bright spots" are caused by shallow gas and the survey may not detect every pocket of gas. Therefore the results of the seismic survey provide a good indication, but not absolute proof, as to whether or not gas is present.

2.8

Boulders below seabed may act as major obstructions to conductors (and to foundation piles). If their presence is suspected, this may influence the selection of the site and of the conductor installation technique, ie. drilling may be preferred to driving. A large boulder will produce a reflection on the seismic record. The reflection from a boulder has similar characteristics to that produced by folded bedding within clay strata. A geological assessment is required to determine the most likely cause of such a reflection and the assistance of an expert in interpreting the shallow seismic record is recommended, e.g. EP/12 can assist.

2.9

It is essential that the equipment which is to be used for the shallow seismic work will provide information to the depths required for conductor design.

Soil Borings 2.10

To provide data for conductor installation at least one of the soil borings should be taken 15m (50ft) or more below the expected setting depth of the conductors. This involves estimating the expected setting depth using a combination of (a) past experience in the Operating Area (b) data obtained during the drilling of the exploration wells (c) calculations of setting depth as described in Section 3. The drilling, sampling, insitu testing and laboratory testing requirements for conductors are very similar to those for piled foundations. Because of this, there is no need to regard one borehole as the "conductor borehole" and other boreholes as "foundation boreholes". However, the brief to the Geotechnical Consultant should include ensuring that the scope of the soil investigation is sufficient for the conductors.

2.11

The soil parameters to be determined from the survey and subsequent laboratory testing are listed in Appendix II-1 and are used for: (a) calculating the setting depth (b) determining the "bearing capacity" of the conductor (c) providing input for the decision on installation method (in conjunction with other considerations) (d) computing the response to lateral loading

Design Check List 2.12

Having ensured that the data concerning the site is available, the Project Team must check that the conductor has been designed to satisfy all requirements. These include:

(i)

Penetration Has the setting depth been calculated,? (see section 3) Do the parameters used in the computation correspond to the proposed spudding-in procedure? (see Section 4) Have the correct values of discharge height and mud density been used? Are there any other criteria governing conductor penetration, eg. proximity of piles, unstable shallow strata? (see Section 3) At the design setting depth does the conductor have sufficient bearing capacity (in outside friction alone) to support its own weight and that of all equipment and casings hung off it? In this context are the weights used in the calculation realistic? Have curvature and buoyancy effects been included? (see Section 6)

(ii)

Steel Section and Grade Would a stock size, e.g. 30in. O.D. x 1 in. w.t. or 26in. O.D. x ½ in. w.t., be suitable? Is there sufficient clearance on the inside diameter (allowing for the shoe and stabbing points) for the maximum bit size to pass up and down the conductor when spudding-in?

Is there any possibility of the drillstring or next casing string standing-up on, or being caught underneath an internal shoulder? Remember that the outside diameter of the conductor usually determines the guide size. Once the design is frozen and the guide size fixed it is difficult to alter the conductor O.D. Have the structural designers satisfied themselves that the conductor section and grade of steel are sufficient to protect the well from environmental forces by acting as: (a) a beam spanning between guides? (b) a laterally loaded pile? If the conductor is to carry axial load has it been checked for combined stresses? If the conductor is to be driven, have drivability and driving stresses been checked? (see Section 5) Finally in case of high steel stresses, are there any possibilities of increasing the section or upgrading the steel to bring stresses within allowable limits?

(iii)

Special Considerations Will corrosion be a particular problem? Could this involve increasing the steel section in the splash zone? Should thermal effects be considered?. This might lead to increased stresses in the conductor if the inner casing strings are cemented up to the top of the well. Will settlement of soil around the conductor impose additional loads upon it? Is the platform in a mudslide area and have the conductors been designed to resist, or are they protected against, mudslides? Is the platform in an earthquake zone and have the conductors been designed accordingly?

Installation Equipment 2.13

A variety of methods are commonly used to install conductors. They are listed on Figure 1.1 and are described in detail in Section 5. However the number of options which can be considered for a particular platform may be limited by the equipment available:

(i)

Derrick Barge Is it feasible to drive the conductors to the specified setting depth using the derrick barge which installed the piles? This would have to be done shortly after the completion of pile driving. If the conductors cannot be driven would it be worthwhile stabbing the lead sections with the derrick barge and completing their installation later from the platform drilling rig?. It is not normally advisable to plan to drive the conductors part way by the derrick barge and subsequently drive to the setting depth from the drilling rig. This is because the "freeze-up" during the inevitable delay can cause serious restart problems.

(ii)

Hammers What hammers are available? The use of steam hammers is only really practical when a derrick barge is alongside the platform (to lift the hammers and to generate enough steam). If the drilling mast or derrick is to be used to handle the hammer then, normally only diesel and compressed air hammers can be considered (note - "steam" hammers can operate on compressed air). The use of hydraulic hammers to install conductors is feasible but up to now this has not been tried by any Group Company. Will the hammer overstress the conductors ? Could this problem be solved by increasing the conductor section or by using a higher grade of steel?

(iii)

Drilling Rig Has the rig been designed to handle hammers and what is the maximum weight of hammer that may be used? What is the maximum length of add-on that can be handled within V-door, derrick and pipe rack constraints? Add-ons should preferably be in one of the standard lengths that are delivered by the mills, i.e. 6, 8, 12 and 16m.

(iv)

Contingencies What plant is available if contingency procedures have to be employed? (see Section 11)

3.

CALCULATING THE SETTING DEPTH

Factors which determine the Setting Depth 3.1

The setting depths of marine conductors are generally determined on the basis of the following considerations: (i)

the conductor shoe level should be such that drilling for the first casing does not have an adverse effect on the foundations of the platform, eg. reduce the bearing capacity of a pile.

(ii)

when drilling below the conductor tip for the first casing string, formation breakdown should not occur. Formation breakdown takes place when the drilling fluid pressure is sufficient to crack the soil forming the borehole wall. This increases the permeability of the soil to such an extent that fluid flows freely into the formation. It is then impossible to obtain returns to drill floor. This phenomenon is termed "lost circulation", cuttings cannot be lifted from the bottom of the borehole and the hole cannot be advanced.

(iii)

the penetration of the conductor below mudline should be sufficient to generate the required "bearing capacity" in outside skin friction, see Section 6.

(iv)

the tip of the conductor should be below any unstable formations.

(v)

whenever feasible the conductor tip should be in an impermeable strata such as clay rather than in porous soil such as sand.

The relative importance of each of the criteria listed above will vary from site to site. In fact, in some operating areas some of the above may not be considered at all. For example some Group Companies ignore item (ii) and are prepared to drill "blind", for the first casing. "Blind" drilling is drilling without returns of the, drilling fluid, which is pumped into the formation. Under these circumstances the first casing string is normally set at shallower depths. (See minutes of meetings with QPPA, SSB, and SOC). However, unless there is considerable experience in the operating area at similar platform locations, "blind" drilling cannot be recommended, (see minutes of meeting with SIPM ). In blind drilling formation fracture occurs, circulation is lost, cuttings are not lifted and the drilling is proceeding without returns. The principal objection to blind drilling is that drilling fluid is being pumped into the soil. This may cause cratering and channelling, which may affect the bearing capacity of adjacent piles and/or cause the conductor to settle unexpectedly, particularly a shallower driven conductor.

Formation Breakdown (Hydraulic Fracture) 3.2

Formation Breakdown of the soil below the conductor tip will occur during drilling for the first casing if the hydrostatic pressure of the drilling fluid exceeds the strength of the soil formation. Instead of the drilling fluid being returned to the drill floor it is pumped into the soil formation. Remedial measures, other than "blind" drilling, for this situation are discussed in Section 11. Formation breakdown should be avoided because: (a)

remedial measures are costly in rig time and materials

(b)

mud losses may have an adverse effect on the foundations of the platform and on the conductor.

(c)

mud is expensive.

3.3

In most circumstances the soil formation strength at any depth can be obtained from the lesser of: (i) the effective overburden pressure of the soil (ii) the effective horizontal earth pressure

The effective overburden pressure is the difference between the density of the soil and the density of seawater multiplied by the depth below mudline. The effective horizontal earth pressure is equal to the effective overburden pressure multiplied by the "at rest earth pressure coefficient" for the soil,"Ko,". The value of Ko is a function of the soil properties and is generally 0.5 to 3.0. Thus to avoid hydraulic fracture

3.4

The inequalities of paragraphs 3.3 may be arranged as:

and

Thus the setting depth to avoid formation breakdown is sensitive to the discharge height above sea level, the drilling fluid density and the depth of water. Also soil type may have a considerable effect on the setting depth. For example a normally consolidated clay or sand could have a Ko value of 0.5 and the vertical cracking criterion would govern. A heavily overconsolidated clay might have a Ko of 2 or more in which case formation breakdown would occur due to horizontal cracking, the first criterion. All other things being equal, the setting depth below mudline of the conductor in the normally consolidated soil could be up to twice that required in the overconsolidated clay.

3.5

It is recommended that the results of the calculations are presented graphically as on Figure 3.1. A method for computing Ko is described in Appendix II-2. A more rigorous approach to calculating the formation strength may be found in Ref. 3.1.

Leak-Off Tests 3.6

The formation strength may be measured in the field by performing a leak-off test. In outline the test is carried out a follows:-

(a)

drill-out to a depth of 3m to 6m (10 ft to 20 ft) ahead of the conductor shoe: cap conductor and connect to a pump.

(b)

fill the entire conductor with fluid and commence pumping.

(c )

raise the fluid pressure in small increments of approximately 10% of the effective soil over burden pressure. At each increment plot the fluid pressure versus the measured flow rate. The points should fall on a straight line until the "formation intake pressure" is reached. At pressures greater than this very much greater flow rates will occur for a given pressure increment, see figure 3.2, and the points will deviate from the straight line to form a curve of reducing gradient. Attempts to increase the pressure further will lead to formation breakdown. There are a number of different techniques for performing these tests. The method used will depend on the circumstances and the equipment available. A description of the standard method used by the drillers may be found in Appendix 15 of EP- 40806, "Well Control and Blowout Prevention Manual".

3.7

An alternative form of this test is the "limit test". This is exactly the same as the leak-off test except that the fluid pressure is not increased beyond the "maximum required mudholding capacity". It will confirm that the formation strength is sufficient for the proposed drilling programme without indicating what the strength is, see Fig.3.2.

3.8

The drillers have strong reservations concerning the performance of leak-off tests at conductor shoe level. This is because of the risk of fracturing the formation which could give rise to problems during subsequent drilling. The preferred method would then be a "circulating test" using a mud with a density which is required for drilling the hole below the marine conductor. During development drilling carefully controlled and supervised tests have been performed from North Sea platforms for assisting in the determination of conductor setting depths.

Other Causes of Lost Circulation 3.9

In highly permeable strata such as coarse sand, gravel, cobbles, shell beds etc., the natural permeability may be so great that circulation is lost without formation fracture, i.e. at depths deeper than those computed from paragraph 3.4. Rock strata which are heavily jointed and fissured will also have locally high permeability. If circulation is lost because of high natural permeability, it can usually be restored by forming a "mud cake" or by use of lost circulation material, LCM. Setting the tip of a conductor in highly permeable strata should be avoided.

3.10

If a conductor is installed by drilling or by a drill drive technique, precautions must be taken to ensure that there is an adequate seal between the outside of the conductor and the soil. This is to prevent drilling fluid returning up the outside of the conductor to mudline. For drill-drive techniques this may involve driving the conductor into virgin soil for the last add-on length. For drill and cement techniques the utmost care should be exercised to ensure proper cementation.

Setting Depth and Spacing between Conductors and Piles 3.11

Having calculated the setting depth to avoid formation breakdown it is necessary to check whether or not such a depth will be detrimental to the piles. if the conductors were driven to a significant depth below the tip of the piles, there would be little likelihood of the piles being affected by the drilling procedure for the first casing. This is why some oil companies operating in the Gulf of Mexico, but not SOC, insist that all conductors be taken below the tip of the piles, (see minutes of meetings with SOC).This rule, although safe, may be unnecessarily conservative in some cases. However, if there is a chance of encountering shallow gas during drilling, the conductor of the first well to be drilled should be set at least 15 m below the tip of the piles.

3.12

If the conductors are sufficiently distant from the piles and provided formation breakdown does not occur and shallow gas is not encountered, drilling for the first casing, or the conductor itself, will have no effect on pile capacity. In these circumstances the conductor setting depth need not be related to the pile tip level. At this "sufficient distance" there must be enough clear space such that there is no danger of the conductor being driven into the side of a pile and that washout does not affect the soil in which the pile develops its capacity. To allow for the use of contingency procedures, such as drilling ahead of conductors which refuse prematurely, it is recommended that all conductors have this safe clearance from the piles. This distance will depend upon: (a) the diameters of the pile and conductor (b) the soil conditions (c) whether the pile capacity is developed mainly by friction or mainly by end bearing

3.13

The experience of operating companies is useful in determining the required clearance -

for well head jackets installed after a mud line suspension well, it has been noted that spacings of 6ft centre to centre between pile and conductor may affect pile driving, (see minutes of meeting with QPPA)

-

when drilling for the first casing, returns are occasionally noted adjacent,conductors, (see minutes of meeting with SSB). This presumably indicates washout at conductor tip level

-

a rule of thumb is that the minimum distance between a pile and conductor should be greater than 10ft, (see minutes of meetings with SOC)

-

conductors may deviate from their proposed alignment, (see minutes of meeting with Shell Expro, SSB, SOC). Directional surveys indicate this may be as much as 2 degrees per 100ft locally

-

supposedly straight conductors may have a small curvature, (see minutes of meetings with Shell Expro)

-

for conductors set in a sand strata, drilling through one of them may cause an adjacent conductor to settle, (see minutes of meeting with SOC)

-

collisions between conductors occurred on a 5ft x 5ft grid, (see minutes of meeting with SOC).

up

3.14

3.15

From the observations in paragraph 3.13 the following conclusions may be drawn: (a)

in sand, drilling may result in a hole several times the diameter of the bit. There are indications that, in extreme cases, the washout zone may extend to a distance of four times the nominal hole diameter.

(b)

over relatively shallow depths driven conductors may deviate from proposed alignments by 3ft and deviations of one degree per 100ft are common.

To ensure that there is no reduction in the capacity of a pile, the zone of soil within 2 pile diameters of the centre of the pile should not be disturbed by drilling. Thus the minimum centre to centre spacings between piles and conductors for the clearances to be safe are -

for piles embedded in CLAY:

S = (2 x D) + 3 + d

3.5

where: S = the minimum centre to centre spacing between a pile and conductor D = pile diameter d = conductor diameter and all dimensions are in feet. The 3ft term is for deviation and the formula allows for drilling an oversize hole. -

for piles obtaining much of their capacity from end bearing in SAND: S = (2 x D) + 3 + (4 x d)

3.6

where all dimensions are in feet. The "4 x d" term assumes that washout will occur in the founding sand stratum.

3.16

If the pile penetration exceeds 300ft the allowance for deviation should be increased to 6ft (2m); for penetrations in excess of 400ft the allowance for deviation should be 10ft (3m).

3.17

As an example, for a 48in diameter pile and a 30in diameter conductor the required minimum centre to centre spacings are: for friction piles in CLAY, 8 + 3 + 2.5 = 13.5ft for end bearing piles in SAND, 8 + 3 + 10 = 21ft The value calculated above for a friction pile is in reasonable agreement with the rule of thumb used by SOC. For the same pile and conductor SOC would calculate a centre to centre spacing of 2 + 10 + 1.25 = 13.25ft.

3.18

If for some special reason the conductor to pile spacings were less than the minimum specified here, the conductors would have to be driven to a depth of at least 4 pile diameters below the tip of the piles. However, in these circumstances drilling below the tip of the conductor before it reached this depth could not be allowed until the effect this could have on the piles had been carefully evaluated.

3.19

The centre to centre spacings between conductors is a separate matter and should be decided by the drilling department.

Conductor Installation by Drilling or Drill-Drive Technique 3.20

Drilling ahead at relatively shallow depths will be required for conductors installed by the drilldrive technique. The same comment obviously applies to drilled and cemented conductors. It is essential that the drilling for the conductors does not result in formation breakdown. Most operating companies overcome this problem by using seawater as the drilling fluid and discharging the returns at some convenient level below the drill floor. For example, Shell Expro when using the drill-drive technique employ a circulating gravity connector which allows discharge below sea level. QPPA, who use drilled and cemented conductors, use seawater for drilling and clean out the hole with slugs of viscous mud. Because of the small air gap and shallow water depth at most platform sites offshore Qatar, hydraulic fracture during conductor drilling is not a problem for QPPA, see paragraph 3.4

3.21

Drilling close to mudline may result in surface washout or collapse of seabed formations. This will cause a cone of depression around the conductors and if it extends towards a pile, may reduce the lateral capacity of the pile. This phenomenon has been observed by QPPA, see minutes of meetings. Washout can also have a serious effect on drilling templates, causing them to tilt. To overcome these problems it is recommended that conductors penetrate at least 20ft (6m) before drilling commences. With soft soils the self weight of the conductor will often be sufficient to cause this penetration. With harder soils, driving, vibrating or some other means will have to be employed.

Unstable Strata 3.22

Unstable strata are defined here as those which under some design or installation conditions may suffer collapse or movement. They are usually encountered near seabed level and conductors should be driven through them if possible. In certain circumstances they may occur deeper down. For example, in a seismically active area, loose granular strata even at depths of 100ft or more below seabed may liquefy during an earthquake. Specialist advice must be sought with respect to liquefaction potential.

3.23

Sites with sloping seabeds may be susceptible to mudslides. Conductors must always be taken below the sliding zone to protect the casing strings. However in many cases the conductors have not the structural strength to resist the mudslide and must be protected themselves. For example in the Gulf of Mexico this is done either by driving a caisson, 10 to 15ft (3m to 5m) in diameter to below the sliding zone and installing the conductors inside it; or by installing the conductors inside a foundation pile. In the latter case they must be driven at least 4 pile diameters below the tip of the pile. The piles cannot be considered to have any end bearing since the soil plug inside the pile is removed before conductor installation.

Conductor Tip in Clay 3.24

If it is possible, without significantly increasing the penetration, to set the conductors in a soil of very low permeability (such as clay) rather than a soil which is prone to washout (such as sand) then this should be done. It will make spudding-in safer by reducing the possibility of the conductor (or an adjacent conductor) suddenly dropping, (see minutes of meeting with BSP and SOC) It will be easier to obtain returns and facilitate the cementing of the next casing string.

References 3.1

BJERRUM, L. et al. "Hydraulic Fracturing in Field Permeability Testing" Geotechnique Vol. 22 1972 pp319-3 32.

FIGURE 3.1 PLOT OF HYDROSTATIC MUD AND SEAWATER PRESSURE AND LIMITING STRESS CONDITION AGAINST DEPTH

FIGURE 3.2 TYPICAL LEAK-OFF AND LIMIT TEST RESULTS

4.

SPUDDING-IN PROCEDURES

4.1

In this Manual the term "spudding-in" is used to describe the drilling procedures for the first casing. It is necessary that all those involved in conductor design and installation have an appreciation of spudding-in procedures since they are the next stage in drilling the well after the conductor has been set. Because of this, conductor design and installation and spuddingin procedures are interdependent. For example in Section 3 it is explained how the drilling procedure for the first casing string determines the conductor setting depth if formation breakdown is to be avoided. Therefore, this Section of the Manual is included to provide engineers who are unfamiliar with drilling techniques with some background data on spudding-in procedures. It is not intended to be a definitive guide to spudding-in practice.

Cleaning-out of Conductor 4.2

For driven conductors the soil plug in the conductor is removed by drilling. For conductors installed by the drill and cement technique the residual cement plug above the float shoe must be drilled out. After the conductor has been cleaned out it is common practice to drill a pilot hole which is subsequently opened to the size required for the first casing. However, prior to drilling the pilot hole it may be advisable to drill a full size hole approximately 3m ahead of the conductor shoe. The reasons for drilling this short hole are:(a) to check that the shoe is not damaged (b) to centralise subsequent holes (c) to confirm that the axial external skin friction capacity exceeds the weight of the conductor.

Pilot Hole 4.3

Having cleaned out the conductor it is the practice of a number of operating companies to drill a pilot hole to the setting depth of the first casing. A typical procedure for a 16in. casing would be: (i) place BOP stack (or diverter) on top of conductor 3 (ii) using a 13 /4" bit, drill the pilot hole with returns to deck level

(iii) remove BOP stack (or diverter) (iv) if this is the first well on a platform run logging tools (v) open hole with hole opener or bit. (vi) set 16" casing. Of course the sizes of bits used vary with conductor and casing dimension.

4.4

The pilot hole is used for two reasons. First, it is a precaution against shallow gas. If any gas is encountered the flow will be less than for the main hole. In the example quoted above, the 3 flow from a 13 /4" hole would be less than one half of that from a 20" hole and with a smaller bit, standard BOP stacks can be used. It should be noted that with this technique no protection is available when opening the hole to final size. The second reason for the pilot hole is to allow standard logging tools to be run.

Drilling Techniques 4.5

When drilling for the first casing it is recommended by all Shell Group companies that, if possible, returns should be obtained at deck level. One advantage is that the driller has an earlier warning of a shallow gas influx. To achieve returns, drilling with a controlled penetration rate may be required to reduce annular pressures and the risk of formation breakdown.

4.6

Some Shell Group companies use seawater as a drilling fluid; others use mud. If seawater is used slugs of viscous mud are periodically spotted to prevent sticking of the drillstring. After completing drilling, the hole must be filled with lightweight viscous mud to keep it open prior to setting the first casing. These considerations do not arise if mud is used as the drilling fluid.

Setting the First Casing 4.7

The casing string is lowered into the hole from the derrick floor. It is fitted with a float shoe to facilitate cementation. Normal practice is to cement the annulus between the casing and the hole, and extend the cementation for some distance up the conductor, typically to 30ft or 40ft below mudline.

4.8

It is common practice to specify that the cement should not be taken above mudline. The reasons for this are: a)

the abandonment is easier and the conductor can be recovered and re-used (particularly important for exploration wells)

b)

the stress in the conductor at mudline can be determined using simple analytical techniques (i.e. there are no thermal or secondary axial effects)

c)

also it is preferable that the conductor should not take any vertical load (except its own weight) above seabed so that its full strength is available for resisting wave and current action.

Typically it is recommended that the cementation of the conductor to casing annulus should not be taken above a level of 40ft below mudline. However some group companies take the cementation to deck level. This has to be accounted for in the conductor design, see Section 6.

5.

INSTALLATION METHODS

5.1

Although in areas with a long operating experience established practice is usually followed, for new and larger platforms or in new areas the method of installing the conductors should be determined on the basis of a time and cost analysis of various techniques. Important parameters which influence the viability of different methods are: the setting depth the soil conditions the conductor section the equipment available

5.2

The most commonly used installation techniques are: driving (continuous driving) drill-drive (repeatedly alternating drilling and driving) drill and drive (single drilling operation followed by continuous driving) drill and cement (single drilling operation followed by cementation) jetting Jetting is not recommended as an installation technique for conductors on platforms. This is because jetting may adversely affect the integrity of the platform foundations. The other four methods are described and discussed below. In addition specifications for driving prepared by SSB are presented in Appendices III-3 and III-4, for drill-drive prepared by Shell Expro in Appendix III-5 and for drill and cement prepared by QPPA in Appendix III-6.

Driving 5.3

The drivability of conductors can be determined using the same analytical Approach as for piles. The soil properties are used to calculate the soil resistance at the time of driving (SRD). The hammer and conductor dimensions are used as input to a computer program (the wave equation) which can determine whether or not a particular hammer is capable of overcoming this maximum anticipated SRD. The output of the program also provides the maximum wall stress during driving. Thus it is possible to assess whether or not a conductor can be driven with a given hammer to the specified setting depth without damage. On many platforms for which driven conductors are used, foundations piles are driven prior to conductor installation. The results of the pile driving can be used to check or amend the drivability analyses of the conductors. This was done by SBPT for the Maui A platform.

5.4

Drivability analyses are described in detail in Appendix III-1. However, a general appreciation of the effect of various parameters on drivability is required. The SRD generally increases with soil strength and depth of penetration. The SRD which can be overcome increases with hammer energy and conductor wall thickness.

5.5

Driving is generally a fast installation technique. It results in the least disturbance of the foundation soils and there is no danger of washout at any level due to conductor installation.

5.6

5.7

There are a number of different approaches to driving to be considered: (i)

drive the conductors as soon as pile driving is complete using the derrick barge and steam hammers. This method of installing the conductors is extensively used by NAM, SSB, BSP and SOC. It was used initially by SBPT for Maui A. However, it is weather dependent and derrick barges are expensive. Therefore, even for conductors which can be driven easily, it may not be the best solution in all operating areas.

(ii)

drive the conductors from the drilling floor using the drilling derrick or a "pile" handling rig. This approach is much less weather dependent than item (i) above but may restrict the choice of hammer to diesel or steam hammers driven by air. These hammers are usually less powerful than those available from a derrick barge and therefore drivability may not be so good and installation can take longer.

(iii)

stab the lead sections with the derrick barge and drive the conductors from the drill floor as in (ii) above. This enables the boom height of the derrick barge to be employed together with the "weather independence" of the jacket. Under no circumstances should the conductors be driven to refusal with the derrick barge in the expectation that it will be possible to advance them further with the drilling derrick. In fact, apart from the stabbing operation, it is not recommended to install conductors partly with the derrick barge and partly with the drilling derrick.

For conductors which are to be installed by driving it is necessary to connect add-ons by welding. It may be possible to use a mechanical joint provided its fatigue life can be shown to be satisfactory. However, there is little Shell Group experience on the use of mechanical connectors with conductors on permanent platforms.

Drill-Drive 5.8

At a number of Shell Expro's platforms the setting depths are so great and the soil conditions so hard that it is impossible to drive conductors to the required penetrations. It was considered that "drill and drive" or "drill and cement" techniques might result in an unacceptable amount of washout at seabed level. ( Shell Expro have a number of GBS's beneath which washout must be avoided.) To solve their conductor installation problems Shell Expro developed a "drill-drive" technique.

5.9

The drilling derrick is used to handle add-ons, hammers and drilling equipment. A follower with a modified driving head is used to hang the drillstring inside the conductor during driving. A circulating gravity connector is incorporated in the lead section of the conductor. It is opened during drilling and allows returns to be discharged below decklevel.

5.10

The main characteristic of this method is that the drillstring remains inside the conductor during driving and does not have to be pulled and re-run at each change from drilling to driving and vice versa. This enables the drilling of short pilot holes ahead of the conductor without losing a lot of time. A typical procedure would be: (a) (b) (c) (d) (e)

drive the tip of the conductor from seabed level to the depth at which the first add-on is made. drill out and form pilot hole to the depth at which the next add-on will be made. drive to the bottom of the pilot hole. repeat until conductor tip approaches setting depth for the last few add-ons drive a sufficient length of conductor without a pilot hole to generate the required axial capacity of the conductor. This length must be calculated, see Section 6.

Shell Expro generally use 30in diameter conductors. For cleaning-out the conductor and drilling the pilot hole they use a 17 ½ in. bit with a 26 in. hole opener. The hammer is usually a heavy diesel hammer such as a Delmag D55 or D62A. Seawater is used as drilling fluid with pills of drilling mud being used to clean the hole. Welded connections are used for add-ons to the conductor.

5.11

An assessment of whether or not the drill-drive technique will be successful at a particular site can be made using a modified version of the drivability analyses. The calculation of the SRD must take into account the effect of cleaning-out the conductor (no inside friction) and pilot hole (reduced outside friction and end bearing). The wave equation analysis is the same as for a driven pile. An example is provided in Appendix III-2.

Drill and Drive 5.12

5.13

In the "drill and drive" method a pilot hole is drilled from mudline to the setting depth before any attempt is made to drive the conductors below seabed. Open-hole drilling using seawater is employed, i.e. cuttings discharged at seabed level. At Auk, Shell Expro used the following technique for 30 in. conductors with welded add-on connections: (i)

run conductor to a few feet above seabed

(ii)

drill a 26" hole and fill with mud to prevent borehole collapse.

(iii)

drive the conductor to the bottom of the hole and beyond until sufficient capacity is obtained. This distance must be calculated, see Section 6.

This technique will result in mudline washout which may affect the lateral analyses. The wave equation can be used to determine driving stresses and it is possible to make approximate estimates of the SRD.However, if the hole exceeds its nominal diameter, such low driving resistances may result that the conductor runs away under the hammer blows, i.e. suddenly drops several (or many) feet.

Drill and Cement 5.14

The "drill and cement" technique can be used in most situations although it may prove time consuming and expensive. For example QPPA use this method because many of their platforms are underlain by soil strata containing bands of rock. Trying to drive through the rock is difficult and could damage the tip of the conductor. Also for the calcareous soils found in QPPA's operating area, the axial capacity of driven conductors may be very much lower than drilled and cemented conductors.

5.15

The installation procedure is to drill "open hole"using seawater as the drilling fluid. The hole opener must have a larger diameter than that of the conductor so that an oversize hole is formed. Slugs of viscous mud may be required in certain strata to stabilize and clean the hole. On reaching the required setting depth, the borehole is filled with lightweight mud. The conductor (fitted with a float shoe) is then lowered into the borehole and the annulus between the borehole wall and the outside surface of the conductor is cemented. A salt water cement may be used. It is normal to allow for 100% more volume of cement slurry than the nominal volume of the annulus. Since driving is not required "squnch" joints may be used between add-ons.

6.

AXIAL BEARING CAPACITY OF CONDUCTORS

General 6.1

As a general rule, well casings should not be hung from conductors. In principle, conductors should only be required to take lateral forces, not axial forces. The reasons for this are: (i)

depending on the span between supports, the magnitude of environmental forces and man other factors, the strength of the conductor section may be committed to taking bending.

(ii)

the axial bearing capacity may be relatively small and difficult to calculate with any degree of reliability.

(iii)

the stress distribution in a series of cemented casing strings is difficult to analyse. There will always be uncertainties as to the magnitude of the load on the conductor, particularly when considering temperature effects.

However, every conductor must be able to support its own weight and that of any equipment placed on it, e.g. a diverter, and because of this an estimate must be made of its bearing capacity. 6.2

If despite the reservations of paragraph 6.1, it is decided to support well casings and other equipment on the conductor, then the system must be very carefully engineered. It can never be assumed that the conductor can take a load simply because it has a deep penetration below seabed.

Safety factor 6.3

The ultimate axial capacity of a conductor must be at least twice the sum of its self weight and that of any equipment or casings it supports. The methods of calculating the capacity vary with the installation technique and are described in paragraphs 6.10 to 6.17.

The Conductor as a Pile 6.4

Offshore steel platforms are generally supported on foundations made up of open ended pipe piles. This type of pile develops its capacity by mobilising end bearing at the tip and friction between the shaft and the soil. In some cases, the end bearing is limited by the friction which can be developed between the soil plug and the inside of the pile.

6.5

Superficially a conductor is similar to a pipe pile. However, to install casings the soil plug inside the conductor must be drilled out and there can be no end bearing component. Thus the bearing capacity of a conductor is developed only by friction between its outside surface and the soil.

6.6

In most situations the bearing capacity of a pile increases with time to some maximum value. The foundations of a jacket do not usually have to carry their design load until several months (or years) after they have been installed. These two factors are taken into account, to some extent, in the pile design methods used for offshore piles. On some platforms the same considerations will apply to the conductors but on others the conductors may have to carry their maximum loads a few weeks (or days) after they have been installed. This must be reflected in a slightly more conservative approach to conductor design.

6.7

An indication of the capacity of a driven pile may be obtained from its driving records. Frequently, piles are driven to refusal in a sand layer to develop as much end bearing as possible and "refusal" with a specified hammer is used as an acceptance criterion. However, the situation with driven conductors is completely different. Because the end bearing is removed during spudding-in, see paragraph 6.5, refusal cannot be used as an indication of the capacity of a conductor.

6.8

The fact that "refusal" is not an acceptance criterion for conductors does not mean that driving behaviour may be ignored. In fact for conductors installed by the drill-drive or drill-and-drive techniques the driving record may provide the only reliable data by which to estimate capacity. This is because the pilot hole is of a similar diameter to that of the conductor, typically a 26in. nominal hole diameter for a 30in. O.D. conductor. Washout and other factors may result in a hole which is larger than its nominal value. Locally the size of the hole may exceed that of the conductor. Under these circumstances, the normal techniques of predicting outside skin friction from the results of soil testing are inapplicable. However, with there being little or no end bearing and no inside frictional resistance to driving, the SRD is generated only by outside friction. Thus by backfiguring the SRD versus depth relationship from the blowcount records, an estimate may be made of the bearing capacity of the conductor. This involves equating that part of the SRD which is clearly attributable to the outside soil resistance to the bearing capacity.

6.9

The estimation of the bearing capacity of conductors may be further complicated by the relatively small centre to centre spacings between conductors, typically 7ft 6in. and sometimes 5 ft. The capacity of a conductor could be reduced by installation of subsequent adjacent conductors, see paragraphs 3.11 to 3.19, particularly if drilling is involved.

Conductors Installed by Driving 6.10

For conductors installed by driving only, the ultimate axial capacity may be computed by the method recommended in API RP2A (Ref. 6.1) for piled foundations. These are summarised in Appendix IV-1 which also contains an example calculation. The ultimate capacity is calculated on the basis that skin friction acts over the outside surface of the conductor except where there is scour at mudline or washout at the tip.

6.11

The allowance for scour will vary with the soil conditions at mudline, the waterdepth, current, environmental conditions etc. In most cases it will have little if any effect on capacity. In the absence of reliable data it is recommended that at least 3ft (1m) of scour is assumed. If there is sand at seabed level the scour depth should be at least 1.5 times the conductor diameter.

6.12

If the conductor is set in a sand or silt stratum the possibility of washout occurring during drilling for the first casing must be considered. This could result in the soil immediately above the tip being loosened or collapsing. To account for this it should be assumed in the calculations that no friction is developed over the bottom 10 ft (3m) length of the conductor. This allowance for washout need not be made for conductors with their tips in clay.

Conductors Installed the "Drill-Drive" technique 6.13

The capacity of conductors installed by the "drill-drive" technique is difficult to predict because of the uncertainties regarding the skin friction which can be developed in soil through which a pilot hole has been drilled. The friction will be a function of hole size, conductor size, drilling practice and soil type but there is insufficient data to provide guide-lines. Shell Expro have used their experience to draw-up a detailed installation specification which they strictly enforce by providing tight supervision. The capacity can be assessed in two ways. First by backfiguring an SRD from the blowcount record and equating this to the capacity. Secondly by assuming that outside friction is developed only over a length near mudline and a length near the tip where pilot holes were not used. An example calculation is provided in Appendix IV-1.

Conductors Installed by the "Drill and Drive" technique 6.14

The same considerations apply to the capacity of a conductor installed by the "drill and drive" technique as for the "drill-drive" conductor of paragraph 6.13.

Conductors Installed by the "Drill and Cement" technique 6.15

The "drill and cement" technique is described in paragraphs 5.14 to 5.16. There are two constraints on the capacity of such conductors; the limiting bond stress between grout and steel and the skin friction at the grout/soil interface. The first is referred to the outside surface of the conductor, the second to the nominal diameter of the hole. To avoid confusion and the possibility of error it is recommended that the limiting bond stress be converted to an equivalent limiting friction at the grout/soil interface, thus fg =

d • σg T

6.1

where fg

=

equivalent limiting skin friction

d

=

outside diameter of conductor

T

=

nominal hole diameter

σg

=

limiting bond stress

If no other data are available it is common practice to assume a limiting bond stress between the grout and steel of 185 kN/m 2 (3.9 ksf, 27 psi). This assumes that the hole has been drilled with mud or with water and subsequently filled with mud. Higher values might apply if water alone were to be used. The quality control on site must ensure that the cement grout is batched, mixed and placed in accordance with the specification (Refs. 6.2 and 6.3).

6.16

The ultimate unit skin friction between the grout and the soil may be computed using a modification of the method described in API for driven piles (Ref. 6.1). For sands and normally consolidated clays the API recommendations are unchanged. However, for heavily over consolidated clays the skin friction factor (α) should be taken as 0.4 rather than 0.5, i.e. the ultimate unit skin friction (fs) in a hard clay stratum would be 0.4 multiplied by the undrained shear strength.

6.17

To determine the ultimate axial capacity of a "drilled and cemented" conductor, the ultimate unit skin friction of the soil (f s ) in each layer is computed. In strata in which f s exceeds fg, the value of f g applies. The remainder of the computations follow the standard procedures and an example calculation is provided in Appendix IV-2.

Computing the Axial Load on the Conductor 6.18

The axial load depends upon a number of factors some of which are difficult to determine and must be simplified (or ignored) in order to make the analysis possible. They are: (a)

the weight of the casings

(b)

the precise details of the installation sequence of well casings

(c)

the densities of the drilling fluid and the cement for the first casing string

(d)

the degree of deviation of the well

(e)

temperature gradient

(f)

the level of cementation in annulus between first casing and the conductor.

(g)

rig tensioning and overpull

(h)

the mechanical properties of the grout

The complexity of the situation is one reason why some Group companies avoid carrying axial forces on the conductors and do not cement above seabed, eg. Shell Expro. Other Group Companies use arbitrary rules which, experience has shown, provide reasonable guidance in a particular operating area, eg. SSB require the ultimate capacity of a conductor to be at least twice the sum of the weights of the BOP stack plus 2000ft of 20in. casing plus the conductor self weight. QPPA specify that 200ft penetration is required for axial capacity. Such rules cannot be exported from one operating area to another, they are only valid locally.

6.19

Consider a conductor from which it is proposed to hang a well casing. The casing is placed inside a deviated hole full of drilling mud. The annulus between the hole and the casing is cemented through a float shoe, mud remaining inside the casing. The casing support is then transferred to the conductor, see Fig.6.1 What is the axial force acting on the conductor due to this casing? Should the curved length or the resolved vertical length be considered? How can buoyancy effects between mud and grout be included in the computation? Buoyancy should be included and the curved length of the casing considered. Thus the axial force at the top of the conductor is

References 6.1

AMERICAN PETROLEUM INSTITUTE, "Recommended practice for planning, designing and constructing fixed offshore platforms", API RP2A 1979.

6.2

REESE, L.C. and COX, W.R., "Pullout tests of grouted piles in stiff clay", Offshore Technology Conference 1976, Paper OTC 2473.

6.3

EHLERS, C.J. and ULRICH, E.J., "Design criteria for grouted piles in sand", Offshore Technology Conference 1977, Paper OTC 2941.

Figure 6.1

7.

SELECTION OF INSTALLATION METHOD

7.1

The selection of the most appropriate installation procedure for the conductors on a particular platform is not always a simple matter. There is a temptation to adopt the method which was used on previous platforms in the operating area concerned. On many occasions this is the correct choice. However, changes in platform type, setting depth, soil conditions, casing programme, conductor size, equipment availability and technology will affect the economic and technical viability of a given procedure vis-a-vis the others available. It is recommended that for each new project the conductor installation procedure is selected on the basis of an engineering judgement and not necessarily on precedent.

7.2

Descriptions of the various methods currently used within Shell Group companies to install conductors are provided in Section 5. The methods are: driving

drill-drive

drill-and-drive

drill-and-cement

jetting (not recommended)

The purpose of this Section of the Manual is to provide guidance in assessing the suitability of each of the above against the others.

7.3

The overriding consideration must be the safety of the platform. The first step in the selection procedure is to rule out any conductor installation method which might lower the safety factors of the foundations or reduce the integrity of the well to below acceptable levels. The nextstage is to assess which of the remaining installation methods are likely to be successful. If a theoretical analysis shows that a particular technique will not achieve the required setting depth then it must be modified or rejected. Finally, a time and cost study should be made of those methods which are both safe and feasible. A rational selection based on the requirements of the field development programme may then be made. This was done by BSP in 1972 and their study forms Appendix V-1 of this Manual.

7.4

It is understood that Shell Expro developed the drill-drive technique as a result of a selection procedure similar to that described above. For some of their GBS platforms in the North Sea, Shell Expro required conductor setting depths of over 350ft below sea bottom. The foundation soils are sands and hard clays. For a GBS an important safety consideration is that the base should not be undermined by washout of the seabed soils. This ruled out "drill-and-drive" and "drill- and-cement" techniques. Wave equation analyses and field experience showed that conductors could not be driven through these soils to the depth required. The driving method was therefore modified, by a number of standard procedures such as soil plug removal and pilot hole drilling, to produce the basic drill-drive technique. The refinement, which reduces the time and cost considerably, is that the drillstring remains within the conductor during driving.

Assessing Driving for Safety 7.5

Provided that there is no danger of the conductors running into the piles, see paragraphs 3.12 to 3.20, conductors installed by driving are unlikely to have an adverse effect on the safety of the platform foundations. With respect to damage to the conductor itself it must be checked that driving stresses do not exceed permissible values using wave equation techniques, see Appendix III-1. If it is possible that a ledge of rock or coral will be encountered special precautions may have to be taken to prevent damage to the conductor tip, see paragraph 9.5. it is recommended that add-ons be connected using welded joints. There is little group experience of mechanical connections on driven conductors. The add-on length may be limited by the maximum permissible stick-up height, which is governed by allowable steel stress criteria. The method for calculating maximum stick-up height is identical to that for piles and is described in Appendix V-2. Stick-up height is the distance from the last point of restraint to the top of the conductor.

Assessing Driving for Feasibility 7.6

Determine whether or not the conductors can be driven to the specified setting depth using:(i)

the hammers available on the derrick barge, usually steam hammers.

(ii)

the hammers which can be handled from the drilling derrick, usually diesel or small steam hammers operated by compressed air.

The method of computation used to assess drivability is described in Appendix III-1. Should it appear that the conductors would refuse before the setting depth is reached, assess whether soil plug removal would enable them to be driven to grade.

7.7

If the specified conductor cannot be driven, investigate whether it is possible to, increase the wall thickness. This possibility will be constrained by internal clearance, structural, manufacturing and handling considerations. Wave equation analyses must be repeated for every conductor make- up considered.

Assessing Drill-Drive for Safety 7.8

The spacing between each pile and the nearest conductor should be at least that recommended in paragraphs 3.8 to 3.16. This may be quite significant for piles which obtain a large proportion of their capacity from end bearing in sand. All the comments of paragraph 7.5 again apply.

Assessing Drill-Drive for Feasibility 7.9

Using the conductor make-up determine whether or not the conductors can be installed to the required setting depth using the drill-drive technique. The methods of analyses are described in Appendix III-2. Remember that the hammers will have to be handled by the drilling derrick. Check that the axial capacity requirements are satisfied. Also ensure that the technology is available in the particular operating area. If not consult SIPM to see if it can be introduced in the time available. Should there be a problem of drivability investigate whether the wall thickness can be increased as in paragraph 7.7.

Assessing Drill-and-Drive 7.10

The safety aspects of the drill-and-drive method are the same as in paragraphs 7.5 and 7.8. However, there is an additional aspect in that erosion and washout of surface soils is possible. This may have an adverse affect on some types of foundation. The analytical procedures for assessing feasibility are the same as in paragraph 7.9. In general the drilldrive technique is to be preferred if the technology is available.

Assessing Drill-and-Cement 7.11

With the drill-and-cement technique there is little danger of damaging the conductors themselves and mechanical connections may be used. The principle safety considerations involve the effect the technique may have on the surrounding soil and the platform foundations. The spacing between the piles and conductors must be checked against the recommendations of paragraphs 3.12 to 3.20. Surface washout may be a problem. Installation should be feasible provided hydraulic fracture of formations with either drilling fluid or cement can be avoided. The method of computation to check this is described in Section 3.

7.12

For a number of recent field development projects wells have been drilled through a seabed template before a jacket was placed. For such cases a 30" conductor is also set, although it does not extend above the template. In these circumstances the conductors are usually installed by the drill-and-cement technique from a jack-up or semi submersible rig. The cementation procedures must be designed so that grout losses into the soil strata are minimised. This means that formation fracture by the grout pressures must be avoided. This is because the presence of grout in the soil, particularly for sand layers, may make subsequent pile driving much more difficult than anticipated. Also formation fracture may affect the bearing capacity of the piles supporting the template.

Current Practice 7.13

From time to time most Group Companies have carried out analyses such as those described above. These studies have resulted in a variety of techniques being adopted and the current practice of some Companies together with relevant parameters are listed below.

8.

RECORDING THE INSTALLATION AND INSTRUMENTATION

Why Installation Records are Essential 8.1

Over a period of many years, a large number of wells may be installed in any one part cular field or concession. It is important that data obtained from previous conductors are considered when selecting the techniques to be used in the future. Due to personnel movements between OPCOS it is essential to initiate recording procedures to permit continuity. Without such records it is possible that the same difficulties with conductor installation will arise time after time.

8.2

There are a number of reasons, other than continuity, for making conductor installation records. They are: (a)

to ensure that the conductors fulfil all aspects of the specification.

(b)

the taking and checking of records is a Quality Assurance procedure.

(c)

if conductor installation does not proceed as planned, the records can be used to determine what has gone wrong and to design appropriate remedial measures.

(d)

records will provide a data base for improving methods of conductor installation.

Normal practice is to oblige the contractor to take the records. The Shell representative is responsible for checking and approving them.

Current Practice 8.3

Most Group Companies prepare, as a matter of routine, installation records for driven conductors. These are virtually identical to pile driving records and consist of a plot of blowcount versus depth, annotated where necessary. An example of such a record prepared by SBPT is shown on Fig. 8.1. A similar record processed by computer for BSP is given on Fig. 8.2. A form, suitable for compiling this data offshore, is included in Appendix V-3 together with a completed example by SBPT.

8.4

Shell Expro have developed a standard presentation for conductors installed by the drill-drive technique. This is shown on Fig. 8.3.

8.5

. Records are not generally kept for conductors installed by the drill-and-cement technique This is probably because the specification can be followed precisely on most occasions. However, the lack of records makes realistic economic comparisons with other methods difficult. It is recommended that a format for such records be developed.

i

Instrumentation 8.6

Hammer performance can be monitored by instrumentation, and instrumentation provides the only method of assessing the efficiency of a diesel hammer. Both Shell Expro and SOC have suspected that conductors have refused prematurely because of poor diesel hammer performance, but without instrumentation have not had data to substantiate their views. For steam hammers, a qualitative assessment of efficiency may be obtained by observing the free fall. However, if a reliable estimate of efficiency is required instrumentation must be employed.

8.7

SBPT used strain gauges and accelerometers on a conductor on Maui A to monitor the performance of a diesel hammer. The theory and practice of such measurements for both piles and conductors is described in Appendix V-4.

General Quality Control 8.8

Consideration should be given to setting up a Quality Assurance Procedure for both welding (NDT) and cementation. These are outside the scope of this Manual but the Construction Department or EP 23.4 can provide advice.

FIGURE 8.1

FIGURE 8.2

FIGURE 8.3

9.

CONDUCTOR SHOES

9.1

It is common practice for there to be an internal driving shoe at the toe of a conductor. Generally, such shoes increase the wall thickness at the toe to 1 .5 times the nominal wall thickness, eg. the shoe of a 26"dia. x 0.5" wt conductor would increase the wall thickness at the toe to 0.75". It is essential that the dimensions of the shoe allow the drilling bits to pass with adequate clearance. Also the transition from the nominal conductor wall thickness to the shoe should be gradual both to allow easy passage of tools and casings, and to reduce stress concentrations during driving. Although conductor shoes are widely used, they are not obligatory and in some circumstances serve no useful purpose. External conductor shoes, i.e. those which increase the outside diameter of the conductor, should be avoided. This is because they may reduce the bearing capacity of a conductor and, if a weak path is formed up the outside of the conductor, they may reduce well security.

9.2

The reasons for using conductor shoes are: (a)

to make driving easier by reducing the friction between the conductor and the soil plug inside it (see paragraph 9.3)

(b)

to reduce the probability of damage at the end of the conductor when driving through hard strata (see paragraph 9.5)

(c)

to cause the conductor to deviate in a preferred direction during driving, a special configuration being required to do this (see paragraph 9.6).

From the above it is apparent that the use of a shoe only benefits driven conductors. Because there are some disadvantages associated with driving shoes (such as an increased risk of drilling tools or casing strings standing up or snagging on the reduced pipe diameter) they should not be used unnecessarily. For example, it would be pointless to use a driving shoe on a conductor which is to be installed by the drill-and-cement technique (a float shoe is however required for annulus cementation).

Improving Drivability 9.3

An internal driving shoe is a relatively cheap and simple method of improving drivability. It is most effective in hard clays where it may reduce the internal skin friction during driving by between 30% and 50%. In sands and normally consolidated clays, experience to date indicates that a shoe has only a slight effect on drivability.

9.4

If a further improvement in drivability is required, it may be advisable to dispense with the driving shoe altogether and increase the wall thickness of the whole conductor to the maximum possible compatible with bit clearance. This has been done by SSB and SOC who use 26" dia. x 0.75" wt pipe without a shoe for curved conductors. The equivalent straight conductor with a shoe is described in paragraph 9.1.

Reducing the Possibility of Damage to the Conductor Tip 9.5

The increased wall thickness of the shoe should reduce driving stresses at the conductor tip and this may prevent distortion if a local hard spot is met, eg. a cobble. However, the change of section at the top of the shoe may result in stress concentrations and stress wave reflections during driving. A shoe will not reduce overall driving stresses in the remainder of the conductor and may increase them in that portion of the conductor immediately above the shoe. The provision of a shoe should not be regarded by itself as sufficient protection against

damage. If it is expected that the conductors will have to be driven through a hard layer, such as a ledge of rock or coral, a detailed study must be made of the implications using wave equation techniques. The results of the study should include; predictions of driving stresses; limits on the blowcount; recommendations regarding wall thickness and drilling out. A common practice is to drill ahead once the limiting blowcount has been reached.

Directional Control 9.6

Shell Expro have developed a conductor shoe which, in conjunction with their drilldrive technique, is expected to cause a conductor to deviate from the vertical during driving. The intention is to increase the spacing between conductors at tip level and to have the conductors aligned in preferred directions. A schematic drawing of the Shell Expro shoe is provided on Fig. 9.1 A proprietary systems is also available (Ref.9.1) but as far as is known there is no group experience of its use.

9.7

The Shell Expro shoe has been used on a number of projects in the North Sea. The results of directional surveys (Sperry Sun) to confirm that the technique works were awaited at the time of writing this manual.

9.8

Other methods of increasing the spacing of conductor tips are described in Section 10.

Clearances 9.9

To allow the bit and drillstring to pass through the conductor it is normal practice to have the minimum conductor internal diameter at least one inch greater than the maximum bit size. This involves interaction between the drilling and structural aspects of conductor design. The minimum conductor i.d. usually occurs at the shoe. If stabbing points are used it should be checked that this i.d. is not reduced. However even with these clearances, NAM have had occasional problems with the drill string snagging on the shoe when it is being withdrawn. To facilitate retrieval of drilling equipment NAM now use an internal bevel on their shoes.

Length of Shoe 9.10

For shoes which are fitted solely to improve drivability, lengths of approximately 1.5 times the conductor diameter have proved satisfactory. If the shoe is required to prevent damage to the tip, the wave equation analyses mentioned in paragraph 9.5 should allow the optimum lengths to be determined. It will probably be in excess of 1.5 times the conductor diameter. As a first trial 3 times the diameter may be considered.

References 9.1

SIMPSON, J.K., "Drive shoe controls conductor pipe", Oil and Gas Journal, Sept 10, 1979.

FIGURE 9.1

10.

CURVED CONDUCTORS

10.1

If it is proposed to use curved conductors it is normal practice to install the lead sections through the guides prior to float-out. The uppermost guides are usually vertical, the remainder following the specified conductor curvature. The lead section is fabricated to the same alignment as the guides. Straight add-ons may be used for the remainder of the conductor length. This means that straight sections of conductor may eventually be driven through curved guides resulting in the guides being subjected to static and dynamic lateral forces. If curved add-ons are used a straight follower should be used for driving. A brief note on the use of curved conductors in the Gulf of Mexico, prepared by Shell Oil, is presented in Appendix V-5.

Reasons for using Curved Conductors 10.2

The principal advantages of using curved rather than straight conductors are: (a)

they allow increased coverage of the reservoir from one platform.

(b)

the centre to centre spacings at the conductor tips are greater than at deck level. This reduces the possibility of one casing running into another

Disadvantages of Curved Conductors 10.3

There are several disadvantages associated with the use of curved conductors. These are: (a)

the detailed design and fabrication of the jacket is more complicated and stronger conductor guides are required to resist the additional lateral forces

(b)

the decision to use curved conductors must be taken at the start of jacket design. If reservoir maps are revised prior to installation, the conductors may be orientated in the wrong direction

(c)

it leads to greater casing wear.

Limitations on Curvature 10.4

Conductor curvature is usually expressed in degrees per 100ft, the angle being that subtended by a 100ft arc at the centre of its circle. The curvature is limited by: casing and well head wear casing joint design fatigue of the drillstring strain in outer fibres of the conductor

10.5

All Group Companies which have had experience of installing curved conductors agree that curvature should not exceed 7º per 100ft. Most specify smaller values. SOC restrict curvature to 6º per 100ft because at higher values there is a danger of overstressing the threaded connections of the casing strings. Similarly SSB set a limit of 5 º per 100 ft. BSP have found it difficult to run a 20in. dia. casing through a 26" dia. x 0.75in. wt conductor if the curvature exceeds 5° per 100ft. However by substituting a 185/8in. casing for the 20in. they have been able to run casings through 7 º per 100ft.

10.6

Conductors may wander and the results of Sperry Sun surveys indicate that the curvature in the soil may be 2 º less than expected, (see minutes of meetings with SOC, SSB and BSP).

Drivability 10.7

A wave equation program suitable for analysing the driving of curved conductors has been developed by SOC and is available through SIPM . In addition to providing data on drivability it predicts the forces induced in the conductor guides by driving. A description of the program and an input guide is provided in EP 42513 "Driving Analysis for Initially Curved Marine Conductors". However, this may be difficult to follow for a new user and for this reason a Fugro Report to Shell Expro which comments on its use forms Appendix V-6 of this manual.

10.8

It is the practice of SOC, SSB and BSP to use the maximum possible wall thickness for curved conductors, ie. they use 26in. dia x 0.75in. wt for curved conductors and 26in. dia x 0.5in. wt for straight conductors. This means there is no shoe on their curved conductors. With this increased wall thickness SOC report that they are just as easy to drive as straight conductors.

10.9

Shell Expro are proposing to use curved conductors on their North Cormorant jacket. The conductors will be installed using the drill-drive technique. A theoretical analysis indicates that pilot holes may have to be shorter than for straight conductors, but that overall driving should be no more difficult than for straight conductors.

Alternatives 10.10

The advantages of curved conductors may be obtained, but to a lesser degree, by using slanted or mitred conductors. A mitred conductor is in essence a curved conductor fabricated from a series of straight sections, the joint between each section being made at a small angle. Slanted conductors are straight conductors driven at a batter.

11.

CONTINGENCY PROCEDURES FOR CONDUCTORS WHICH DO NOT REACH SETTING DEPTH

11.1

If a conductor fails to reach its setting depth the methods proposed for spudding-in and installing the first casing string may have to be revised. Generally the drillers have a number of contingency procedures available to them, some of which may affect the structural integrity of the conductor. It is therefore essential that the drillers and designers jointly agree any contingency procedures.

Conductors not Satisfying Axial Capacity Requirements 11.2

On some projects SOC design conductors to carry the weight of the casing string. If the specified setting depth is not reached and the conductor has inadequate "bearing capacity" SOC would either: (a)

vary the well design so that internal casings can be carried on the first casing string or

(b)

cement the annulus between the conductor and first casing string up to the well head and use the conductor plus casing string as a composite pile.

As described in paragraph 6.1 (iii) the analyses required to justify the latter are complex and secondary effects become important. For this and other reasons SIPM recommend that conductors should not be required to carry axial loads.

Conductors not Satisfying Formation Fracture Requirements 11.3

If the setting-depth is insufficient to allow returns at the drill floor when drilling for the first casing the following contingency procedures may be considered: a)

reduce the drilling rate but maintain the circulation rate, this should reduce the density of returns

(b)

aerate the drilling mud or use oil in the drilling fluid again to reduce density. There may be environmental restrictions in some operating areas which prevent the use of oil

(c)

install a centrifugal pump near sea level to enable cuttings to be lifted to the shale shaker

(d)

use LCM (lost circulation material).

11.4

In many cases the contingency procedures described in paragraph 11.3 are either not suitable for a particular project or do not restore circulation. Under these circumstances a commonly used procedure is to cut slots in the conductor at a few feet above sea level and discharge the returns into the sea. When using this technique attention should be paid to the remaining structural strength of the conductor. Also environmental and/or economic considerations may require that seawater is used as the drilling fluid. Most Group Companies have experience of this technique, (see minutes of meetings).

11.5

If the procedures described above fail to restore circulation and/or remove the cuttings it is the practice of some Companies to use "blind" drilling, (see minutes of meetings with SOC). However for the reasons given in paragraph 3.1 this is not generally recommended.

Other Contingency Measures 11.6

SSB have reported that if a conductor has refused prematurely during driving from a derrick barge, they subsequently try to pull the conductor out with the drilling derrick and reinstall it using a drill-drive or drill-and- drive technique. However, on no account should this procedure be relied upon as a "cure-all" for conductor installation. On many occasions the drilling derrick may have insufficient capacity to pull the conductor. For further comments on this matter see minutes of meeting with NAM and paragraph 5.6.

12.

DO'S AND DON'T'S

12.1

This Section is a summary of the discussions which were held with the Group Companies, and the contents of the Manual itself. Its purpose is to briefly highlight accepted good practice and assist the reader in avoiding the mistakes of others.

Do's 12.2

The majority of the points listed below may appear obvious. However, pressures on time and cost have caused them to be omitted on some projects, occasionally with serious consequences. Do: 1.

have a soil investigation made at the location of the platform.

2.

ensure that there is sufficient clearance inside the conductor for the drilling bit to pass freely ,up and down. This is particularly important if there are any local reductions in diameter due to shoes, stabbing points etc.

3.

calculate a setting depth of the conductor which is compatible with the drilling and casing programme and the soil conditions.

4.

have a drivability study performed if driving is part of the installation procedure.

5.

specify a minimum acceptable blowcount at final setting depth if bearing capacity is to be assessed on the basis of driving records.

6.

check that there is adequate spacing between the foundation piles and the conductors.

7.

specify the procedures to be followed if the blowcount suddenly rises and quantify this blowcount. This is particularly important if the soil borings indicate that layers of rock may be encountered during conductor driving and should avoid damage to the conductor tip.

8.

design the shoe to suit the method of installation and soil conditions.

9.

consider what contingency procedures should be taken if the conductors do not reach the specified setting depth.

10.

specify any spare or back-up equipment which should be available offshore.

11.

make sure a responsible person who is conversant with the platform design and the conductor design is either offshore or available for consultation on a 7 day week, 24 hour basis during installation.

12.

ensure that the add-on lengths are within the capacity of the handling equipment and that at maximum stick-up height the conductors are not overstressed. Also specify the lengths of any cut-off.

13.

put all of the above in an installation specification, take records (at least sufficient to check the contractor's records) and incorporate them in an "as- built" report.

Don't's 12.3

A list of things not to do obviously includes the opposites of many of the items in paragraph. In addition to these, 1.

do not economise on materials, e.g. wall thicknesses, to such an extent that the conductors are difficult to install.

2.

unless there are overriding reasons to the contrary do not plan to (a)

support casing strings on the conductor

(b)

use blind drilling techniques

c)

cement the annulus between the conductor and first casing string above mudline

3.

do not use square shoulders on the inside of the conductor. These may snag the drillstring or casing string and may cause stress concentrations.

4.

do not use mechanical connectors for driven conductors unless there is satisfactory evidence of their field performance.

5.

do not abdicate all control responsibility to the installation contractor.

6.

do not assume that the installation will go exactly as planned.

APPENDIX 1 RECORDS OF MEETINGS WITH PERSONNEL OF VARIOUS SHELL GROUP COMPANIES

Discussions on the content notes of this Manual were held with a number of Shell Group Companies. The range of topics covered at each meeting varied from company to company. Frequently the agenda was influenced by the outcome of previous meetings and the particular installation problems in the operating area concerned. In this Appendix the meeting records are presented in chronological order;

Company

Date

SIPM

12 October 1978

SBPT

15, 16 and 22 November 1978

Shell Expro

16 November 1978

NAM

29 November 1978

QPPA

5 and 6 December 1978

BSP

11 to 14 December 1978

SSB

14 and 15 December 1978

SOC (Houston)

22 and 24 January 1979

SOC (New Orleans)

23 January 1979

It should be noted that, except for the meetings with BSP, the records have been compiled by the writer without reference of the other attendees at the meetings. They are not intended to be official minutes of meetings and should be regarded as the informal notes of the writer alone. On some subjects contradictory viewpoints were expressed by different companies. No attempt was made in the meetings to reconcile such differences in the belief that this could best be done in the Manual itself. The original Content Notes were based on a concept of a Manual of twelve Sections, the same number as in this final version. However the original Section 12 "Case Histories" has been absorbed into Sections 5 and 7. The Section "Do's and Don't's" was not in the original concept. Otherwise there is general agreement between the Sections in this Manual and the Content Notes.

SESSION 1 E. Toolan

Fugro Ltd.

M. Brinded

EPE/4

M. Langereis

OPE/1

C. Shepherd

OPE/15

G. Bayer

ECC/22

J. Caminada

EDA/23

J. Dawson

EDA/22 (Reporter)

This was a generalised discussion to cover the purpose, style, scope and format of the Manuals.

A.

GENERAL POINTS

1)

The questionnaire, mentioned in the S.I.P.M. notes on the project, had not in fact been sent to operating companies, as S.I.P.M. and Fugro agreed that mare useful information would be obtained from visits to the operating companies.

2

B.S.P. would like to receive the manuals in their Final Draft form, to permit scrutiny and comment prior to publication by S.I.P.M. and Fugro. A time limit would be imposed for submission of comments. (say 1 month) Mr. Toolan would raise this point with S.I.P.M., and B.S.P. should do so independently. (Action: EDA/22)

3)

Updating of Manuals. B.S.P. would like to see the Manuals updated at specific intervals to incorporate new experience by operating companies, new developments in equipment and techniques, and changes in design and installation criteria. Mr. Toolan agreed that the layout of the Manuals would be designed for ease of revision. B.S.P. would propose to S.I.P.M. that a provision for regular updating be incorporated into the Fugro/ S.I.P.M. contract. (Action: EDA/22)

B.

PURPOSE

4)

Mr. Toolan stated that in his brief these Manuals were intended primarily to cover installation criteria for conductors and piles. They were for presentation of recommended procedures.

5)

B.S.P. stressed that in their view an important function of the Conductor Manual would be to itemise and specify the design considerations for the structural, operational, and drilling departments.

6.

An additional purpose was to identify areas, in which data gathering would be required.

C.

STYLE

7.

The style proposed for the Manuals was generally agreed, with the proviso that all formulas used should be derived or referenced, with constants and parameters specified. In each section, basic principles would be highlighted, with references where subjects were not covered in detail.

D.

SCOPE

8.

There was a request from B.S.P. for greater emphasis, in the pile Manual, on design methods and parameters.

9.

Mr. Toolan stated that to expand the manuals to include all aspects of design would make them very large and somewhat clumsy.

NOTE: In subsequent discussions, certain topics were pinpointed for coverage of design factors in greater depth in the manuals. 10.

A section will be included on Freestanding and guyed conductors, mudline suspension wells, and tie-ins to jackets.

11.

The main points of interest from Operational Viewpoints were emphasised to be formation strength, conductor setting depths, and casing cementing setting levels. Mr. Toolan was able immediately to provide information on calculation methods to determine the correct conductor setting depth for avoidance of formation fracture. More detailed discussions on Conductor criteria are covered in subsequent notes.

E.

FORMAT

12.

As stated in the notes on the manuals, the main part of the Manuals will be sections covering basic principles in general terms, with detailed specific information contained in appendices.

13.

Where sections will cover installation procedures, examples will be quoted wherever possible of operating Companies who use these procedures. Examples of Good Practice and Bad Practice will be included, as well as alternative methods.

SESSION 3 M. Langereis

OPE/1

A. Schouten

OPE/13

C. Shepherd

OPE/15

M. Brinded

EPE/4

J. Caminada

EDA/23

J. Dawson

EDA/22 (Reporter)

This session concentrated on the Drilling/operational criteria for conductor Specifications. Drilling Department have found from experiences over the past few years that the old conductor installation criteria dating from about 1972 have not been completely satisfactory and have suggested that those procedures should be revised. The following points summarise the main areas of concern among Drilling, Operational and Engineering Departments of B.S.P., for inclusion into the Conductor Installation Manual being compiled by Fugro. 1.

A general point was made that criteria governing free- standing conductors should be included - with references.

SECTION 3 - Conductor Setting Depths 2.

The manual should describe how to calculate conductor setting depths using normal soil data, so as to satisfy the following requirements. a)

Enable Drilling Department to obtain mud returns to surface when drilling surface casing (normally diameter 20")

b)

Have sufficient axial conductor capacity.

c)

Ensure that pile capacities of structure are not adversely affected.

d)

Locate the conductor shoes in clay rather than sand, as far as possible within the above constraints.

SECTION 4 - Spudding-in Procedures 3.

The manual should advise that prior to drilling a pilot hole in spudding procedure in the conductor shoe be drilled through to a depth approx. 10' below the conductor shoe, using the largest bit to be used for drilling the next casing. The reasons for this are:-

4.

a)

To check the shoe is not damaged.

b)

To centralise the subsequent holes.

c)

To confirm that the axial external skin friction capacity of the conductor exceeds it's own weight.

There was a strong request that the criteria for cementing the first casing to surface or to mudline be closely examined. This should be covered in depth by the manual.

SECTION 7 - Selection of Installation Method 5.

This section or an appendix should include the results of a wave equation analysis for the conductor sizes and hammers commonly used by B.S.P. For this Mr. Toolan has been provided with information on all hammers used in B.S.P. offshore areas, also information on common conductor sizes and material strengths.

SECTION 9 - Conductor Shoes 6.

It was recommended that internal conductor shoes should be used generally 1.5 x conductor wall-thickness.

SECTION 10 - Curved Conductors 7.

The section of the manual dealing with curved conductors should be expanded to discuss mitred and slanted conductors and any other techniques used in the Group to maximise separation of conductor shoes.

8.

A note should be included that it has been B.S.P.'s experience that diameter φ 20" casing cannot be run through a diameter φ 26"x 3/4 conductor at a dogleg severity or more than 5° per 100'. Furthermore, diameter φ 18 5/8" casing has become an important size in B.S.P. and has been run inside a diameter φ 26" curved conductor thro' a dogleg severity of 7º per 100'. Data on the directional survey for Magpie D/P, and installation planning data was provided for Mr. Toolan by OPE/15.

INTERNAL DISCUSSION Arising out of this discussion, it was agreed that the following installation procedures should be recommended for trial by B.S.P. in the near future. a)

ECO will attempt to drive marine conductors on the drilling platform to or below the setting depths calculated in point (2) above. Notes have been left with EPE/4 on this procedure, and relevant parameters are being received by Telex from Fugro, U.K.

b)

If required by Drilling Department, one conductor will be stabbed by the installation barge, but not driven. This will usually be a conductor furthest away from adjacent piles. Normally, this decision should of course be made before placing of the jacket.

c)

Drilling Department can then install this conductor using the most appropriate techniques, and perform formation leak-off test at any depths desired. The conductor will finally be set to a depth 50' - 150' below the pile tips. It is intended that the first well from the platform be drilled through this conductor, setting the diameter φ 20" casing following current normal practice.

d)

Should difficulties be encountered in this first well, either from loss of circulation or from shallow gas pockets, it is agreed that for the remaining conductors on the jacket the φ 20" casing would be set at a shallow depth of typically 75' - 150' below pile tips. For this situation, it is recommended that, as in the past, sea-water would be used for drilling, with the casing being set and cemented as in normal practice.

APPENDIX II-1 SOIL PARAMETERS REQUIRED FOR CONDUCTOR DESIGN AND INSTALLATION PLANNING

SOIL PARAMETERS REQUIRED FOR CONDUCTOR DESIGN AND INSTALLATION PLANNING

The soil parameters required for the design and installation planning of conductors are given in the Table below. Also included in this Table are the types of laboratory tests which are used to obtain these parameters. In addition to the soil parameters, it is also necessary to know the specific gravity of any drilling fluids to be used and the discharge height of drilling returns above sea level.

SOIL PARAMETER

TEST

_

Visual description

Bulk density

density test

Submerged density Moisture content

Moisture content test

Undraine Shear Strength

Unconsolidated undrained triaxial test; pocket penetrometer; torvane; fall cone; consolidated undrained triaxial test (if insitu stresses can be estimated)

Remoulded Shear Strength

plasticity index; moisture content; remoulded triaxial test

Strain required to mobilise 50% of maximum soil shear strength (cohesive soils only)

unconsolidated undrained triaxial test

Overconsolidation

oedometer test; unconsolidated

Ratio

undrained triaxial test

Coefficient of Earth

consolidated undrained traixial

Pressure at Rest

test; plasticity index

unconsolidated undrained triaxial test

APPENDIX II-2 CALCULATION OF THE COEFFICIENT OF EARTH PRESSURE AT REST (Ko )

CALCULATION OF THE COEFFICIENT OF EARTH PRESSURE AT REST (Ko )

The method of calculation of Ko is dependent upon the soil type under consideration. Basically the methods differentiate between cohesionless and cohesive soils.

COHESIONLESS SOILS For a cohesionless soil which has not experienced an overburden pressure greater than the existing value, i.e. the precompression ratio (PCR) is unity, the value of Ko is obtained from the expression:Ko = 1 - sin φ' where φ is the angle of internal friction of the soil. If the PCR of the soil is greater than unity, Schmertmann (Ref. 1) has developed the formula:0.42 x (1 - sin φ') Ko = (PCR)

COHESIVE SOILS For a normally consolidated cohesive soil the theoretical value of Ko is the same as for a cohesionless material:Ko = 1 - sin φ' Due to the difficulty in assessing whether a clay is normally or lightly overconsolidated it is preferable to carry out laboratory tests to obtain a Ko value. These tests are relatively inexpensive and can be performed on standard soils laboratory equipment. In addition to laboratory testing, various relationships have been developed linking Ko to the index properties of the material. For a heavily overconsolidated clay, the following procedure is used to assess the Ko value of the soil:1)

Calculate the ratio of (c/p') on the basis of the results of the laboratory testing where c = the undrained shear strength p' = the effective overburden pressure

2)

Calculate the ratio of (c/p') nc applicable for a normally consolidated clay, based on the relationship proposed by Skempton (Ref. 2) c ( /p') nc = 0.11 + 0.0037 (PI)

where PI is the plasticity index of the soil c

c

3)

Determine the ratio of ( /p')/ ( /p') nc and use this value to determine the overconsolidation ratio (OCR) of the clay, based on the relationship proposed by Ladd and Foott (Ref. 3).

4)

Estimate the value of Ko from published relationships between Ko, the OCR and the PI of the soil, Brooker and Ireland (Ref. 4), Vijayvergiya (Ref. 5).

References 1)

SCHMERTMANN, J., "The measurement of in-situ shear strength". Proceedings ASCE specialty conference on in- situ measurements of soil properties Vol. 2 1975.

2)

SKEMPTON, A.W., Discussion on "The planning and design of New Hong Kong Airport". Proc. Institution of Civil Engineers 7. 1957.

3)

LADD C. and FOOTT, R. (1 974), "New design procedure for stability of soft clays", A.S.C.E., J-GED, July, p 769.

4)

BROOKER, E.W., and IRELAND, H.O., (1965) "Earth Pressures at rest related to stress history" Canadian Geotechnical Journal Vol. II No. 1 (Feb.).

5)

VIJAYVERGIYA, V.N. "Procedure for computing axial pile capacity" Fugro Internal Paper. July 1977.

APPENDIX III-1 THE USE OF THE WAVE EQUATION IN DRIVABILITY ANALYSIS

THE USE OF THE WAVE EQUATION IN DRIVABILITY ANALYSIS

General For most conductor installations, use is made of driving methods for at least part of the installation. With computer programs based on the wave equation, the ability of a particular hammer to drive a conductor to its required penetration may be assessed. Such programs can also determine whether or not the conductor is overstressed during driving. To use the wave equation correctly it is necessary to have a basic understanding of the phenomena involved in pile driving. The impact of the hammer generates a compressive stress wave in the conductor. This stress wave travels down the conductor at the velocity of sound in steel, 5000 m/s. If the wave meets a resistance or discontinuity a proportion is reflected back up the conductor, reducing the magnitude of the downward travelling wave by an equal amount. Once the wave has reached the portion of the conductor shaft within the soil, the downward movement of the conductor behind the wave front generates a frictional resistance at the soil/conductor interface. This causes a reflection which reduces the intensity of the wave. Eventually the wave reaches the conductor tip. If there is sufficient power left in the wave to cause permanent deformation in the soil below the conductor tip, or if only elastic movements occur in the soil below the tip, the conductor will be in the same position after the blow as before it. In this situation the conductor is said to have refused. Most conductor driving analyses use computer programs based on one dimensional wave transmission. Those available within the Shell Group employ finite difference techniques for the numerical analyses. The hammer is modelled as a falling weight striking a cushion and/or anvil, see Fig. 1. The conductor is modelled as a series of lumped masses of the conductor. The soil springs are defined by; an ultimate static resistance (Ru); a displacement over which the soil behaves elastically, the quake (Q); and a damping factor which increases the static soil resistance as a function of the conductor velocity (J). The soil springs are shown on Fig.2. The input data for hammer and conductor are simple to prepare and field measurements indicate that the mathematical model is sufficiently realistic. Standard values have been established for soil quake and damping. These values have been backfigured from instrumented driving tests in conjunction with soil resistances obtained from static load tests. The only input data which has to be specially prepared by the user is the Soil Resistance at time of Driving, SRD. Experience gained from back analysing driving records indicates that the SRD is not equal to the ultimate static capacity. For conductors in soft clays the capacity tends to increase with time and so the SRD is generally much less than the static capacity. In hard clays the increase in capacity with time is less, marked and the SRD may be of the same order of magnitude as, or greater than, the calculated static capacity. Generally in all types of clay the majority of the SRD is developed in the skin friction whereas in sand a large proportion may be developed at the tip. In sands the calculated SRD is greater than the calculated static capacity, see Refs. 1 and 2 for Shell Group experience. There are a number of published methods for calculating the relationship between SRD and depth (Refs. 3 to 7). Since in each case SRD's, quakes and damping values have been developed in tandem, it is not necessarily valid to use the SRD's calculated from one reference with quakes and damping factors quoted in another. The methods given in this Appendix will provide SRD values suitable for use with the wave equation programs available within Shell . An example calculation is presented in Appendix III-2 and the results in the form of a plot of SRD versus depth are given in that Appendix. These SRD values should be used in conjunction with quake and damping factors quoted on Fig. 2. Comparisons between predictions and field experience indicate that the method will predict harder than average driving, i.e. it provides reasonable correlations for the conductors which were hardest to drive (Ref. 5). This is deliberate. if it predicted average driving behaviour there would be a danger of a considerable proportion of conductors in the field refusing at shallower penetrations than anticipated. This could have costly consequences. The other methods listed in the references have been found to predict average driving. In addition to calculating the SRD during continuous driving, it may be necessary in clay soils to compute the SRD after set-up. This is simply done by substituting the static skin friction

by API method 1 or 2 (whichever is higher, see Appendix IV-1) for the calculated shaft friction during driving. The rest of the computation is as before. In some hard clay soils the SRD computed after setup may be less than that calculated for continuous driving. This indicates that set-up effects may be ignored.

Calculation of SRD versus depth relationship The SRD at any depth is determined from the following considerations. If the soil inside the conductor (soil plug) remains stationary during driving the SRD must be made up of inside and outside friction and wall end bearing. In this situation the magnitude of the inside friction which can be mobilised may be limited by the end bearing capacity of the soil plug. Alternatively the soil plug may move down during driving in which case the inside friction must be equal to or greater than the plug end bearing. Generally the conductor will behave in the manner which produces least resistance to penetration. Thus at any depth the SRD will be the least of:-

where :

fs' = unit shaft friction during driving (outside) fi' = unit shaft friction during driving (inside) qp' = unit point resistance during driving

These concepts for predicting SRD are shown on Figs.3 and 4.

Calculation of point resistance during driving The Cone Penetration Test (CPT) is a model test for the penetration of a conductor. The point resistance during driving (qp') may be calculated from the cone resistance (qc). When the conductor is plugged (i.e. the inner soil plug moves down with the conductor) the unit base resistance may be calculated by the method shown on Fig. 5. No limits are applied. Thus, qp' = qu ……….. ........................... (3) When the conductor is unplugged (i.e. the inner soil plug remains stationary as the conductor tip penetrates the ground) the unit resistance acting on the conductor wall annulus is taken to be equal to the cone resistance at that depth, qp' = qc ………… ........................... (4) In clays in which CPT's have not been made a cone resistance for use in drivability studies can be estimated as 18 times the undrained shear strength. In sand strata it is difficult to assess drivability without the results of CPT's.

Calculation of shaft friction in cohesive soils The contribution of skin friction to total SRD is calculated on the basis of laboratory test results. Along the length of the conductor, the soil at the interface with the conductor wall is strained to failure by every hammer blow. In a cohesive material the soil is. compressed to accommodate the volume of the conductor as it penetrates. The displacement, shearing and compression remould the soil and cause excess pore water pressures to be developed. Thus during continuous driving in a clay:

In many cases it may prove impossible to perform sufficient meaningful remoulded triaxial tests in the time available. This is particularly the case with heavily overconsolidated clays which may have to be ground down, reconstituted and reconsolidated prior to shearing. In order to overcome this problem, considerable reliance is placed on empirical relationships between remoulded shear strength and other properties of a soil such as those developed by Skemption and Northey (Ref. 8) and Houston and Mitchell (Ref. 9). The remoulded shear strength according to Skempton and Northey depends on a relationship between ιr and plasticity and liquidity indices derived from laboratory measurements. This relationship is shown on Fig.6.

Calculation of shaft friction during driving in granular soils In granular oil it is assumed that the unit shaft friction during driving is equal to the static unit shaft friction :-

and may be calculated using the cone resistance as described previously. A limit of 0.12 MN/m² should be applied but no allowance should be made for lateral displacement effects. Equation (6) should be applied at all levels.

Results of Wave Equation Analysis The input to the wave equation program may be divided into three parts, hammer data soil data pile data The output includes the permanent set per blow (the reciprocal of the blowcount) and the stresses in the conductor during driving. Normal practice is to vary the SRD, while keeping all other input data constant. In this manner for a given hammer, conductor penetration and soil profile a relationship between SRD and blowcount can be obtained. This is normally presented in the form of blowcountresistance curves, see Fig. 7.

Two relationships have now been developed, SRD versus depth and SRD versus blowcount. These are used to determine the predicted blowcount versus depth relationship, see Appendix III-2. However, the situation is complicated by the fact that the SRD versus blowcount relationship varies with hammer efficiency (which may change during a drive) conductor penetration (distribution of SRD between tip and shaft, soil damping increasing with depth, different soils at tip of conductor) Prior to describing drivability analyses in detail it is essential to return to first principles and consider the effect of various parameters on drivability.

Parametric Considerations The discussion of wave transmission earlier in this Appendix-enables some simple conclusions to be drawn on the effect on drivability of various parameters. A given hammer will transmit approximately the same amount of energy, E, to any conductor irrespective of the conductor's dimensions. The energy in the conductor may be expressed as:

Since the mass is directly proportional to the cross sectional area of the wall, (A):-

The force F in the conductor which is available to overcome the soil resistance, is determined by the amplitude of the stress in the compression wave and the amplitude of the stress in the compression wave and the cross sectional area of the conductor.

From wave theory, the stress amplitude is proportional to the ratio of the velocity of the lumped mass to that of the wave front, i.e. the speed of sound, c.

And from equation (3)

Hammer Energy It would appear from equation (13) that for a given conductor the maximum soil resistance which can be overcome is proportional to the square root of the hammer's delivered energy. The improvement in drivability due to increased energy is less favourable than the ratio of square roots since higher energies involve higher velocities, stresses and elastic compression of the conductor, see equation (9). These lead to increased losses from side friction and damping. Thus trying to improve drivability by increasing hammer size is subject to the "law of diminishing returns". Eventually a stage is reached at which the hammer is so powerful (or heavy) that permissible driving (or static) stress levels in the conductor are exceeded. It is concluded that more powerful hammers are useful but they cannot solve every driving problem. This is confirmed by theoretical study and field experience.

Wall Thickness If a conductor is to be installed with a given hammer, its drivability will improve in proportion to the square root of its wall thickness. This results from equation (13). However, equation (9) indicates that the benefit of increased wall thickness will be greater than this since velocities, stresses and elastic pile compression are reduced. The consequence is that attenuation of the wave due to side friction and side damping is lessened. The conclusion is that drivability improves with increasing wall thickness and this is confirmed by theoretical studies, see Fig. 7, and field experience, e.g. SOC found that 26" x 3/4" curved conductors were easier to drive than straight 26" x ½" conductors. It should be noted that there may be penalties involved in increasing the wall thickness of conductors. These are firstly the straightforward material costs and secondly increased fabrication costs.

Diameter For a given wall thickness an increase in the diameter of a conductor will produce a linear increase in its cross sectional area. In accordance with equations (9) and (13) drivability will be improved by a proportion slightly greater than the square root of the diameter. However, at a given penetration the soil resistance to be overcome will be increased by a similar amount. Thus with a given hammer, the larger diameter conductor may not be able to be driven as deep as the smaller but the larger conductor will have a higher axial capacity.

Penetration in Uniform Soils As a conductor is driven deeper, the length of shaft in contact with the soil increases. Hence a greater proportion of energy is lost in soil damping. Thus for a given conductor hammer, the greater the pile penetration the lower will be the soil resistance which causes refusal. However for penetrations which are within approximately ±30% of that analysed significant errors do not occur, i.e. an analysis made for 50m would be valid for penetrations within the range 35m to 65m. The length of conductor above mudline has little if any effect on drivability.

Penetration in Stratified Soils The drivability of a conductor is affected by the distribution of the soil resistance. Generally the greater the proportion of soil resistance at the tip the harder driving becomes. There are a number of reasons for this: (a)

high tip resistance is usually associated with sand and much higher point damping is applied in sand than in clay', see Fig. 2.

(b)

if the soil resistance on the shaft is low, velocities are high and energy losses due to soil damping are proportionately higher.

(c)

the permanent movement of the conductor is governed by the situation for driving may arise when the conductors reach maximum penetration, or at some shallower depth when the tip is in sand.

Yield Strength The higher the yield strength of the pile the higher is the allowable driving stress. There is little guidance given in codes of practice as to a permissible driving stress. However experience in the North Sea and Gulf of Mexico (see record of meeting with SOC in New Orleans, Appendix 1) indicate that a value of 80% of yield has often been used. This has not resulted in any unusual distress in conductors. Referring to the paragraph on hammer energy, it appears that in some cases the use of high strength steels may allow the use of more powerful hammers. This may be an alternative to increasing the wall thickness.

References 1)

"Pile driving in the North Sea", Paper 307, Shell 1978 Offshore Engineering Conference, Houston.

2)

"Pile driving in the Gulf of Mexico", Paper 309, Shell 1978 Off shore Engineering Conference, Houston.

3)

YOUNG, A.G., SULLIVAN, R.A. and RYBICKI, C.A., "Pile design and Installation Features of the Thistle Platform". EUR 12, European Offshore Petroleum Conference and Exhibition, London 1978.

4)

HEEREMA E.P. "Predicting Pile Drivability: Heather as an Illustration of the 'Friction Fatigue' Theory". EUR 50, European Offshore Petroleum Conference and Exhibition, London, 1978.

5)

TOOLAN, F.E. and FOX, D.A., "Geotechnical planning of piled foundations for offshore platforms". Proceedings of the Institution of Civil Engineers, Part 1, May 1977, pp 221-244.

6)

DURNING, P.J., and RENNIE, I.A., "Determining Pile Capacity and Pile Drivability in Hard, Overconsolidated North Sea Clay". EUR 47, European Offshore Petroleum Conference and Exhibition, London 1978.

7)

NAUGHTON, H.R., and MILLER, T.W., "The Prediction and Subsequent Measurement of Pile Driving Behaviour at the Hondo Platform in Santa Barbara". EUR 11, European Offshore Petroleum Conference and Exhibition, London, 1978.

8)

SKEMPTON, A.W. and NORTHEY, R.D., "The sensitivity of clays". Geotechnique, III, 1, 1952.

9)

HOUSTON, W.N. and MITCHELL, J.K., "Property interrelationships in sensitive clays". Journal of the Soil Mechanics and Foundation Division, ASCE 95, SM4, July 1969.

FIGURE 1

IDEALISATION OF HAMMER PILE AND GROUND FOR WAVE EQUATION ANALYSIS

FIGURE 2 SUMMARY OF INPUT QUAKE AND DAMPING FACTORS FOR WAVE EQUATION

FIGURE 3 BASIC CONCEPTS FOR PREDICTING SOIL RESISTANCE DURING DRIVING FOR AN UNPLUGGED CONDUCTOR

FIGURE 4

BASIC CONCEPTS FOR PREDICTING SOIL RESISTANCE DURING DRIVING FOR A PLUGGED CONDUCTOR

FIGURE 5 COMPUTATION OF THE ULTIMATE UNIT END BEARING OF A PILE FROM A CONE PENETRATION TEST

FIGURE 6

LIQUIDITY INDEX .V. REMOULDED SHEAR STRENGTH

FIGURE 7

SOIL RESISTANCE AT TIME OF DRIVING VS BLOW COUNT

APPENDIX III-2 EXAMPLE OF WAVE EQUATION ANALYSIS FOR CONDUCTOR DRILL-DRIVE SEQUENCE

EXAMPLE OF WAVE EQUATION ANALYSIS FOR CONDUCTOR DRILL-DRIVE SEQUENCE

1)

The first stage of the analysis is to determine the soil resistance to driving (SRD) of the conductor, using the standard procedures described in Appendix III-1. An example of such an SRD calculation for a 28in. diameter conductor, at a North Sea site, is presented on Fig. 1.

2)

For a drill-drive sequence, the computed SRD will need modification to allow for the effects of drilling-out. The amount of modification is difficult to predict on a purely theoretical basis. Wherever possible, use should be made of back-analyses of conductors installed by similar methods at nearby sites. An example of this approach is shown on Figs. 2 to 4 of this Appendix. Figs. 2 and 3 show the observed soil resistance at the time of driving conductors at Shell 's Dunlin Field in the North Sea. From the relationships shown on Figs. 2 and 3 the generalised relationship shown on Fig. 4 has been obtained. It can be seen that the drilldrive procedure adopted at Dunlin generally inhibited the development of skin friction along the length of the conductors. Beyond the initial drive into virgin soil (necessary to form a seal to avoid washout at the mud-line) no significant build up in soil resistance occurs with depth. Where resistance has built up, it is due to tip resistance resulting from the conductor reaching the bottom of the predrilled pilot hole. This resistance is destroyed on drilling out the next length of the pilot hole.

3)

The next stage is to plot out the calculated SRD versus depth for a purely driven conductor, see Fig. 5. Combining this relationship with the results of a wave equation analysis performed for the proposed installation plant, it is possible to calculate what percentage of total SRD can be overcome by the conductor/hammer combination. An example of the wave equation analysis is given on Fig. 6. In this example only approximately 25% of the calculated SRD at setting depth could be overcome by a Delmag D-55 hammer.

4)

The drill-drive sequence is then developed on the basis of the above information. After driving the conductor for an initial penetration, generally governed by the requirement to minimise washout due to subsequent drilling operations, blowcount should be limited to a prescribed value. In the example shown, blowcount must not exceed a figure which would indicate that 25% of the theoretical value SRD value at any particular depth has been accumulated. This blowcount is obtained from Figs. 5 and 6.

FIGURE 1 : 28" CONDUCTOR - SRD 1 ½" W.T

FIGURE 2 SOIL RESISTANCE DURING DRIVING AGAINST DEPTH DUNLIN A

FIGURE 3 SOIL RESISTANCE DURING DRIVING AGAINST DEPTH DUNLIN A

FIGURE 4 SOIL RESISTANCE DURING GENERALISED DRILL-DRIVE SEQUENCE DUNLIN A

FIGURE 5 SOIL RESISTANCE AT THE TIME OF DRIVING DUE TO EXTERNAL SKIN FRICTION ONLY

FIGURE 6 SOIL RESISTANCE AT THE TIME OF DRIVING VS BLOW COUNT

APPENDIX III-3 EXTRACT FROM "CONSTRUCTION SPECIFICATION FOR INSTALLATION OF STEEL PLATFORMS" PREPARED BY SSB (SEPTEMBER 1978)

a)

The CONTRACTOR shall continue to drive the pile with a higher number of blows per foot, or

b)

The CONTRACTOR shall jet out the soil plug inside the pile (in accordance with sub-section 5.13) and then continue to drive the pile. or

c)

The CONTRACTOR shall drill out the soil plug inside the pile and drill a pilot hole (in accordance with sub-section 5.14) and then continue to drive the pile. The above procedures shall be approved by the COMPANY.

5.3.13 The CONTRACTOR shall carry out buckling analyses to ensure that add-on lengths/pile driving hammer to be utilized are compatible.

5.4

Shims

5.4.1

Every attempt shall be made to centralize all piles by using the largest shim plates possible. They should be driven in if necessary. Before commencement of welding shim plate fit-up shall be subject to inspection and approval by the COMPANY.

5.4.2

The number and size of shim plates issued for each installation is as shown on the Contract Drawings.

5.4.3

The shim plates shall be blast cleaned before fitting Once the shim plates are fitted the pile/leg area where the fillet, welds are to be made shall also be blast cleaned to a white metal finish.

5.4.4

Before all piles are driven to final penetration no welding between a shim and a pile is permitted. If shim have been installed on certain piles while driving continues on another pile , making of welds only between shim and jacket top is permitted. No welding during driving operations is permitted .If welding of shims to the jacket top can is temporarily suspended to allow further driving(of any pile , the weld made shall be inspected prior to recommencing the weld.

5.4.5

If need to be welded-off to the jacket so as to maintain the jacket level, use shall be made of plates so as to 'dog-off' the piles, and not the shim plates

5.4.6

Fillet welds on the shim plates shall be in accordance with the Contract Drawings and standard drawing S-0121,and shall be inspected on completion, in accordance with Section 4 of this specification.

5.

Conductors

5.5.1

The CONTRACTOR shall exercise controlled driving to minimise set-up and arrange that conductors can be driven to the required target penetration by straight driving alone , without recourse to jetting or drilling

5.5.

It is recommended that the CONTRACTOR provides a hammer having a rated striking energy of about 50,000 ft. lbs. for driving the conductors

5.5.3

The conductors shall be as stated once pile driving is complete and the pile shims are at least 50% welded out at each jacket leg. The maximum number of conductors which may be simultaneously hung off from the jacket top brace elevation is as shown on the Contract Drawing or specified in the outline Installation Procedures.

5.5.4

No driving of a conductor is permitted while other conductors are still hung off from the jacket top brace elevation i.e. all conductors must be self-supporting; or when welding out shims

5.5.5

Curved conductor sections shall be accurately lined up to ensure the correct curvature when making field joints in curved sections

5.5.6

All field welds in conductors shall be made and inspected in accordance with Section 4 of this Specification. Cut offs shall be held to a minimum

5.5.7

The conductors shall be driven to the target penetration, at which penetration a ' good' driving resistance should be achieved. 'Good driving' resistance is defined as approximately 40 blows per foot with a hammer having a rated striking energy of about 50,000 ft. Ibs. In the event that this 'good' driving resistance is not met at target penetration, driving must be continued until this requirement is achieved, or until all available conductor length is utilized.

5.5.8

In general the blowcount should always be limited to a maximum of 200 blows per foot for the type of hammer recommended above. In the event that such blowcounts are encountered before the target penetration is reached, driving must be discontinued when such hard driving resistance is obviously caused by a hard layer at the tip of the conductor and not due set up in clay (e.g while making an add-on connection).

5.5.9

Conductors shall be cut off at the correct level, extended up to deck level and cover plates installed, as indicated on the Contract Drawings or in the Outline Installation Procedures.

APPENDIX III-4 EXTRACT FROM "OUTLINE INSTALLATION PROCEDURE FOR SFDP-A" PREPARED BY SSB

Before stabbing the initials of skirt piles SA-2 and SB-2 the skirt pile sleeves must be flooded. The procedure for the installation/driving of the four skirt piles shall be similar to that for the centre piles. Skirt pile add-ons shall be reworked, and the skirt piles cut off underwater, in accordance with the Contract Drawings. The piles shall be driven with hammers having the rated striking energy recommended in Construction Specification No.7, and in accordance with the following criteria: (a)

(b)

Design (Target) Penetration is 220 ft. for the main piles, 260 ft. for the skirt piles, whereby over the last 10 consecutive feet, without driving stoppage, the blowcount should be at least:

HAMMER ENERGY

BLOWCOUNT/FOOT

200,000 ft. lbs

100

300,000 ft. lbs

60

Maximum penetration. If, at the target penetration, the blowcounts is less than the acceptable blowcount criteria under (a) driving must continue until the acceptable blowcount given under (a) is reached or until all available pile length is utilized.

It is emphasized that once pile driving has commenced, stoppage(e.g for welding of add-ons ) should be kept to a minimum to avoid possible pile-freeze up. The piles shall be shimmed-out in accordance with 6.4 below and cut-off in accordance with Contract Drawings.

Installation of Shims The shim plates shall be installed and welded out in accordance with Construction Specification No.7 and the Contract Drawings.

Conductor Installation The conductors shall be installed in accordance with Construction Specification No. 7, and driven to a penetration of 100 ft. The following sequence shall be followed:

Curved Conductors (a)

Fill the four seal curved conductors with water, and then remove the covers at both ends of these conductors.

(b)

install, weld-out and lower down the 1st. curved add-on for conductor nos. 4 and 5,

(c)

install, weld-out and lower down the 2nd. add-on, until self-supporting, for conductor nos. 4 and 5.

(d)

repeat (b) and (c) for conductor nos. 10 and 15,

(e)

install, weld-out and lower down the 1st. add-on, until self-supporting, for conductor nos. 3 and 13,

(f)

repeat (e) for conductor nos. 6 and 14,

(g)

repeat (e) for conductor nos. 2 and 12,

(h)

drive curved conductor nos 3,5,6,13 and 15 down to the cut-off level shown on the Contract Drawings,

(i)

install and weld-out last add-on on all five conductors and drive to penetration,

(j)

repeat (h) and (i) for conductors nos.2,4,10,12 and 14.

Straight Conductors (a)

hang-off conductor initial in conductor slots 1,11 and 9

(b)

install, weld-out and lower down the 1st. add-on until self-supporting,

(c)

repeat (a) and (b) for conductor slots 7 and 3,

(d)

drive all five conductors,

(e)

install and weld-out 2nd. add-on for all five conductors,

(f)

drive all five conductors to final penetration.

The conductors shall be cut off, extended up to the cellar deck level and cover plates installed, all in accordance with the Contract Drawing.

Jacket Top Walkways After pile installations is complete the jacket top walkways shall be installed, all in accordance with the Contract Drawings.

Deck Installations The stub piles shall be installed in accordance with Construction Specifications No. 7 and cut off horizontally at the correct level to accommodate the decks. The decks shall be installed in three separate lifts, as shown on the Contract Drawings. The Drop-in section shall be accurately located and jacked into position as required . All field splices shall be made in accordance with the Contract Drawings, and all field installed timber, grating, handrails, pump caissons and drain lines accurately positioned and located.

APPENDIX III-5 CORMORANT ALPHA CONDUCTOR INSTALLATION PROCEDURE PREPARED BY SHELL EXPRO

CORMORANT ALPHA CONDUCTOR INSTALLATION PROCEDURE

CORMORANT ALPHA RELATIVE POSITIONS OF GUIDES/DECKS

Each Conductor Comprises:

CONDUCTOR DRILL/DRIVE PROCEDURE In order to achieve a projected penetration of 360 ft. with ± 40º angle of deviation at the shoe, a reference mark has to be made on the drill floor in the direction of the desired azimuth of each well. 1.

Fit 35 ft. x 2½" dia. slings in the ears of the hook which is set to swivel. elevator via 55 ton shackles to the slings.

Attach a lifting

2.

Pick up the shoe joint on a lifting elevator, correctly positioned in the lifting strips. Align the high side of the deviated shoe to the reference mark and hang off on the rotary using the lifting elevator. Unshackle.

3.

Pick up the second joint using a second lifting elevator as above. If connectors are fitted, stab and connect; otherwise weld as per attached procedure (Appendix I) having first aligned the joints by laser.

4.

Lift the conductor a few inches and remove the lower lifting elevator. Lower the conductor through the rotary and in turn through the upper air-spider which is connected via 35 ft. long x 2½" dia. slings to the B.O.P. jacks, and the lower air-spider (if connectors are used) which is resting on a spider support frame located en the production deck. Land the conductor on the rotary as before, using the upper lifting elevator. Note:

Ensure the line denoting the high side of the deviation shoe has been followed through on this and every subsequent joint.

5.

Continue with joints 3 through to 8, as above, if a "slack" sea is running (otherwise see Appendix 2). Take care when locating and running through the guide frames.

6.

With 8 joints, the total string length is ± 425 ft.

7.

a) For welded conductor, land the conductor on the R.T. and shackle (35 ton) the slings through two holes in the top. Release the elevator and lower the conductor through the rotary. b)

If connectors are fitted, lower the string such that the elevator is a few inches above the R. T. Close the lower spider, remove the elevator and change over to 60 ft. long slings. Attach these slings to the upper spider and raise same as high as possible. Close upper spider, open the lower spider and lower the conductor.

c)

Whether a) or b) applies, lower the conductor gently through the top of the caisson (459 ft, B.D.F.). Pull it back so that the shoe is 457 ft. B.D.F. and suspend it in the lower spider.

8.

Make up and run 14" Magnet assy. to the bottom seal (649 ft. B.D.F.). until no recovery. Before reaching the bottom seal, circulate 5 minutes with 300 G.P.M. seawater.

9.

Make up and run the following drilling assy.

17½"

Bit

26"

H.O.

26"

Stabiliser

30' x 9 ½"

D.C.

26"

Stabiliser

30' x 9 ½"

D.C.

26"

Stabiliser

60' x 9 ½"

D.C.

H.W.D.P.

to surface

Tag bottom to see if any grout is on the seal, drill and ream to 658 ft. B.D.F. (5 ft. penetration) with 5/10,000 W.0.B., 50/60 R.P.M. and 350 G.P.M. P.O.H. and remove collars run back with H.W.D.P. to 2 ft. from bottom (656 ft. B.D.F.). Spot a H.V. slug of the corrosion inhibitor (see Appendix 3) at bottom and then pump 300 bbls of the same through the drill pipe as it is slowly pulled back to the caisson top (459 ft. B.D.F.). P.O.H. the H.W.D.P. 10.

Pull back the conductor through the R.T. by reversing either a) or b) in 7 above. Add joints 9 and 10.

11.

Add joint 11 (C.G.C.). Open the C.G.C. prior to lowering and test its operation. Note.

12.

If transport strips are lowering.

fitted to the C.G.C. these have to be ground flush before

Add joints 12 and 13. Total conductor length is ± 670 ft. Lower the conductor to seabed (653 ft. B.D.F.) and work through the bottom of the caisson to ensure no drag or overpull. ORIENTATE the shoe and run into seabed.

13.

Pick up the hammer and chaser and drive to a maximum blow count of 50/60 B.P.F. Set back the hammer and chaser, close upper spider and open the C.G.C. using the B.O.P. jacks.

14.

R.I.H. as under 9 and drill a pocket (± 15 ft) with 10/15,000 W.O.B., 60 R.P.M. and 450 G.P.M. such that the top of the conductor will arrive at the connecting station (55 ft. B.D.F.) Circulate 30 bbls H.V. mud, chase out with 450 bbls seawater and spot 30 bbls H.V. mud. Note:

15.

H.V. mud is hydrated bentonite in fresh water or cellosize 2ppb in seawater with marsh funnel viscosity ± 60.

Pull back 2 stands of D.P., close the C.G.C. and open the spider Pick up hammer and chaser. Latch the chaser hang-off assy. on to the drill string, set aside the bushings, stab the chaser and drive the conductor (max. 50/60 B.P.F.) Set back hammer and chaser.

16.

Pick up joint 14 (on shackles if welding, or on the single joint handling tool if connectors are fitted) having first inserted 100 ft. long slings and D.P. elevator through the joint. Latch the D.P. elevator on to the drill assy., set aside the bushings, lower the joint through the rotary and add to the existing conductor.

17.

Open the C.G.C. and R.I.H. Drill 40 ft. below the shoe using 20/25,000 W.O.B., 50/60 R.P.M. and 450/500 G.P.M Circulate 50 bbls and spot 50 bbls H.V. mud.

18.

P.O.H. two stands, close C.G.C. and drive conductor to a max. 60 B.P.F., otherwise re-ream hole if connecting station is not reached. Note:

19

A close watch is to be kept on the hammer blow-count. If high blow-counts persist during the first 3 to 5 ft. of hammering, or if a sudden rise occurs, the hole is to be rereamed.

Continue adding joints of conductor, until a penetration of 350 ft. is achieved (i.e. ± 1,003 ft. B.D.F.). After the last drill-out to 1,003 ft. B.D.F., pull out the whole drill assy. and drive the conductor to refusal (250/300 B.P.F.) with a final penetration of 355-360 ft. (1,008-1,013 ft. B.D.F.). The seam of the C.G.C. is to be ± 5 ft. above the caisson at refusal.

20.

Cut the conductor above the production deck - 59-04 ft. B.D.F. (see Appendix 4). Install the neoprene packers (3 x 90º segments) between the conductor and guide sleeve located just below the production deck.

APPENDIX I WELDING PROCEDURE 1.

Weld preparation will be a single V bevel with 35º on the leading end and 15º on the trailing edge.

2.

The weld area is to be preheated to 200º F, 6" either side of the bevels.

3.

Root run with E7010 Nos. 10 rods (e.g. Shield-Arc 85).

4.

Fill and cap with E7016 or E7018 Nos. 6 or 8 rods (e.g. ESAB OK -Unitrode 48.00).

5.

The interpass temperature is not to exceed 750º F.

6.

The weld is to be allowed to cool slowly and to be protected from air streams.

7.

Cleaning of slag is to be done using needle-guns.

8.

No water/rain is to enter the weld area during welding and cooling.

9.

The weld is to be allowed to cool slowly.

LASER ALIGNMENT Prior to each weld made on the drill floor, the butt area is to be aligned by laser, as follows: 1.

Attach the laser target to the incoming joint, approximately 2 ft. below the lifting elevator, whilst this joint is horizontal in the V-door.

2.

Stab the joints, clean the bevels and connect the laser running tool below the levels. Affix the two lasers to the running tool and, using the target , align the incoming joint to the outgoing joint(s).

3.

Preheat and root the weld. Recheck the alignment by laser. If O.K., disconnect the running tool and complete the weld.

APPENDIX - 2 In order to locate the 1st guide (below sealevel) during "heavy seas", the following procedure may be adopted: A

Offshore Welded Conductor 1.

Following the addition of joint 3, land the conductor on the R.T. Disconnect the slings from the lifting elevator and shackle them through two holes in the top of the conductor. 14ft the conductor, release the elevators and lower the conductor 5 ft. below the R.T. Suspend the conductor in the (upper) spider.

2. Make up and run the following assembly:

Note:

Take care when stabbing the assembly through the first guide.

3.

Pick up joint 4 via shackles through holes in the top of this joint, having first threaded 100 ft. slings and a D.P. elevator through it.

4.

Latch D.P. elevator to drill assy. and lift it together with the joint.

5.

Set aside bushings, attach two 15 ft. long slings to D.P. elevator and shackle these through the two holes in the conductor beneath it.

6.

Open spider, pull back conductor and land on R.T. using a lifting elevator.

7.

Rebevel the conductor and stab and weld incoming joint. In this position shoe is ± 145 ft. B.D.F. (string length being 205 ft.). Using the centraliser assembly to locate the first guide (176.97 ft. B.D.F.) run the conductor through it, such that the top is again 5 ft. B.D.F. and close the spider.

8.

Set back the centraliser assy. and then pull back the conductor using 35 ft. slings and land on the R.T. as before. The shoe will then be ± 200 ft. B.D.F . Continue adding joints.

B. Connected Conductor 1

Following the addition of joint 3, lower the conductor such that lifting elevator is a few inches above the R.T. Close the upper spider ensuring the B.O.P. jacks are in their upper position.

APPENDIX 2 (contd) Release the lifting elevator and lower the conductor on the B.O.P. jacks. Close the lower spider, raise B.O.P. jacks, close upper spider, open the lower and lower conductor again on the B.O.P. jacks. Continue until top of conductor is 5. ft. B.D.F.

2.

Make up and run assy. as in A.2. above.

3.

Pick up joint 4 using a lifting elevator with 100 ft. slings and D.P. elevator through it.

4.

As in A.4. above.

5.

Pull the existing conductor back through the R.T. by reversing the lowering procedure of B.1. above and land on the R.T.

6.

Make the connection, lower the conductor through the first guide as in A.7. and then further below the R.T. as in B.1.

7.

Set back the centraliser assy., pull back conductor by reversing B.1. and land on the R.T. as before. Continue adding joints.

APPENDIX 3

CORROSION INHIBITOR From: UETA/123 of 3/8/78

1)

Fill tank with required fresh water.

2)

Add caustic soda + 0.5 lbs/bbl. to give pH of 11-11.5.

3)

Add bentonite, 20 lbs/bbl through hopper, allow to hydrate for 15 minutes.

4)

Add saltgel, 20 lbs/bbl.

The resulting mixture gives: pH

-

11-11.5

PV

-

17 cp

YP

-

66 lbs/l00 ft

Gels

-

55 lbs/100 ft 2

2

140 lbs/l00 ft

2

(10 minutes)

API fluid loss - 20 ccs

After 24 hours: pH

-

11

Pv

-

15 cp

Yp

-

17 lbs/100 ft2

Gels

-

29 lbs/100 ft (initial)

2

84 lbs/100 ft2 (10 minutes) API fluid loss - 16 ccs

APPENDIX 4

CONDUCTOR SLOT No. 3 In order to keep the circulating gravity connector open upon completion of the installation of the conductor in slot No. 3 (the -first in the conductor drilling sequence), the following procedure is to be adopted:

1)

Upon driving the conductor to refusal, mark a circumferential line around the conductor 43" above the production deck (i.e. 62.62 ft. B.D.F.), before cutting!

2)

Open the C.G.C. via 60 ft. slings (or the 30" Varco Spider suspended from the B.O.P. jacks).

3)

Position the landing frame around the conductor.

4)

Weld the pad-eyes (2 off) to the conductor such that they rest on the landing frame. (Remove frame during welding). -

5)

Reposition the frame and bolt together. Take the weight off the slings supporting the conductor and cut the conductor at the aforementioned mark (item 1)

For the remaining seven conductors -of this sequence, cut the conductor with the C.G.C. closed, 55" above the 62.62 ft. B.D.F. level; then cut 2 x 3" dia. holes at 4" centres from the top.

P.A. KIDD, UEOA/53.

3rd October, 1978.

APPENDIX III-6

EXTRACT FROM

"DRILL AND CEMENT CONDUCTOR INSTALLATION SPECIFICATION"

PREPARED BY QPPA

OPE/5/78

APPENDIX 3

LOC MM NORTH FLANK (WELL MM-26) MUD PROGRAMME Anticipated Problems

1.

Possible losses in tertiary formations, resulting in H2S attack, washouts, poor logging, bad cementation, etc

2.

Laffan, Nahr Umr and Hawar shales : Washed out holes, cavings, sloughing.

3.

Differential sticking and/or losses due to slightly depleted reservoirs (Yamama/Sulaiy/Arab-I/ArabII)

4.

Unknown formation strength near fault (Mishrif/Kharaib).

5.

Differential pressure between Arab-III/IV, depleted reservoirs and overlying Arab-I/-Il.

A.

Programmes I - 26-inch Hole (sea bed to 430 ft) Objectives

1.

To clean hole thoroughly while drilling.

2.

To prevent hole collapse prior to running 20-inch casing.

1.

Drill with sea water.

2.

Slug hole at every connection and at bottom with 50 bbl high viscous SMR pill (ca. 3 ppb SM(R) in sea water, pH 9.5, vis. > 120 sec. M.F.).

3.

Prior to pulling out to sea bed and pulling out of hole (refer item 1 (b), (c) of main Programme), spot Ca. 250 bbl high viscous SM(R) pill (composition as above) to fill up hole contents + 50% excess).

CASING AND CEMENTATION PROGRAMMES

Summary

A. Programme I to V

Runnig and cementation of 20", 13 3/8" , 9 5/8" casings, and of 7" and 4½" liner.

B. Minimum stock requirements

_____________________________________ A.

Programmes

I :

20-inch Conductor

1. a)

b) 2.

Run 20-inch (94-K55-BCSG) conductor to ca.410 ft (i.e. ca.200 ft penetration) as follows: a)

Float shoe.

b)

20-inch conductor to surface, with one centraliser per joint on bottom 3 joints.

Suspend casing on elevators. -

Run stab-in tool (with 2 centralisers) on 5-inch drill pipe and stab into shoe.

-

Fill up 5-inch/20-inch annulus with sea water to check seals.

3

Circulate clean with sea water (twice hole contents).

4.

Pump a 16.0 ppg slurry containing class G cement, seawater and 2% CaCl2 (by weight of cement). Mixing water requirement

0.118 bbl/sx

Slurry Yield

0.201 bbl/sx

Pump either annulus contents, assuming 30" hole plus 100% excess (i.e. ca.1000 sks) or until divers observe returns at seabed, whichever occurs first.5.

Observe for backflow: -

If backflow ensure cement has been just displaced out of DP and close DP, after surface samples are hard, unlatch and pull out of hole.

-

If no backflow unlatch at once and pull out of hole.

Note: 6.

If divers do not observe returns at sea bed, top fill cernentation(s) will be carried out as required, but at a later stage.

Revert to Main Programme.

LIST OF APPENDICES I.

Prognosis

2.

Casing cement and other requirements.

3.

Mud Programme.

4.

Casing and cementation programme..

5.

Evaluation programme (coring, logging, open hole testing)

6.

Optimisation of drilling parameters in 12¼-inch hole (to be issued separately)

7.

Time and Cost Estimates. _____________________________________

PROGRAMME Summary :

- Phases I, II, III, IV and V (Drilling 26", l7½", 12¼", 8½" and 6" hole sections)

Phase I - Drilling 26-inch Hole Section 1.

a) - Spud with 17½-inch bit (at slack tide). - Drill 20 ft. Pull back above seabed. - Run back to bottom (if unable to re-enter hole, spud again) - Pull out of hole. b) - Drill 26-inch hole to ca. 480 ft with sea water, slugging hole with 30 bbls high viscous pill at every connection. - Circulate hole clean with high viscous pill. - Spot high viscous pill to fill-up hole contents. - Pull back 10 ft below seabed. c) - Wait 6 hours. - Run to bottom, checking for fill - Circulate clean, spot high viscous pill to fill-up hole contents - Pull out of hole. Note:

See Appendix 3-I for mud engineering.

2.

Run and cement 20-inch conductor at ca. 460 ft (i.e. ca. 250 ft penetration) as per Appendix 4-1

3.

- While waiting on cement, secure 20-inch conductor to barge using 3½-inch pipe, 20-inch clamp and turn buckles. Back off landing joint. - Install

- 20-inch casing head housing. - 20-inch hydril (+ diverter). - 20-inch flow riser.

PROGRAMME - Phases I, II, III, IV and V (Drilling 26", 17½", 12¼", 8½" and 6 1/8" hole sections).

Summary:

- Phase VI (Completion).

Phase

- Drilling 26-inch Hole section

Note:

1.

a)

b)

c)

Check that bit guide for 20-inch lower 61amp (below sea level) has been installed.

- Spud with 17½-inch bit (at slack tide). -

Drill 20 ft. Pull back above seabed.

-

Run back to bottom (if unable to re-enter hole, spud again).

-

Pull out of hole.

-

Drill 26-inch hole to ca.430 ft with sea water, slugging hole with 30 bbl high viscous pill at every connection.

-

Circulate hole clean with high viscous pill.

-

Spot high viscous pill to fill-up hole contents.

-

Pull back 10 ft below seabed

-

wait 6 hours

-

Run to bottom, checking for fill.

-

Circulate clean, spot high viscous pill to fill-up hole contents..

-

Pull out of hole.

Note:

2.

See Appendix 3-I for mud engineering.

Run and cement 20-inch conductor at ca. 410 ft (i.e. ca. 200 ft penetration) as per Appendix 4-I. Note:

1) Remove bit guide prior to running 20-inch conductor. 2) Space out to have 20-inch collar 1 ft above grating.

3.

- While waiting on cement, secure 20-inch conductor to jacket. Back off landing joint. - Install

- 20-inch casing head housing. - 20-inch hydril (+ diverter). - 20-inch flow riser.

APPENDIX 4

LOCATION BH NORTH NOSE (WELL BH-23) OPE/7/78 RIG-103

Summary A.

3

5

Programmes I to IV : Running and Cementation of 20" , 13 /8" 9 /8" Casing and 7" Liner.

Programmes I : 20-inch Conductor 1.

2

Run 20-inch (94-K55-BCSG) conductor to ca. 460 ft (i.e. ca. 250 ft penetration) as follows: a)

Halliburton float shoe.

b)

20-inch conductor to ca. 5 ft above sea bed, with one centralizer per joint on bottom 3 joints.

c)

20-inch Cameron mudline suspension housing.

d)

20-inch Cameron MLS running tool.

e)

20-inch running string

-

Run Halliburton stab-in tool (with 2 centralizers) on 5-inch drill pipe and stab into shoe.

-

Fill up 5-inch/20-inch annulus with sea water to check seals.

3.

Circulate clean with 50 bbl viscous pill (SMR, viscosity ca.l20 sec. MF), followed by sea water(twice hole contents).

4.

Pump a 16 ppg slurry containing class G cement, sea water and 2% CaCl2 (by weight of cement): Mixing water

0.118

bbl/sx

Slurry yield

0.201

bbl/sx

Pump either theoretical annulus contents (26" hole) plus 150% excess (i.e. ca. 1000 sks) or until divers observe returns at surface, whichever occurs first. Note :

Have 2000 sks on site.

5.

Observe

- If backflow:

ensure cement has been just displayed out of DP and close DP, after surface samples are hard, unstab and pull out of hole.

- If no backflow: unlatch at once and pull out of hole.

Note:

If drivers do not observe returns at sea bed, top fill cementation(s) will be carried out as required later stage.

6.

After cement is hard, divers to check top of cement.

7.

Revert to main programme.

APPENDIX IV-l

AMERICAN PETROLEUM INSTITUTE (API RP 2A 1979) AXIAL CAPACITY CALCULATIONS

AMERICAN PETROLEUM INSTITUTE (API RP 2A 1979) AXIAL CAPACITY CALCULATIONS

The axial capacity of a conductor is usually calculated using the API RP 2A. 1979 method. This method gives the short term capacity of a conductor, which is the most applicable condition to be considered. This is because a conductor usually has to support the maximum axial load shortly after its installation. This axial load is due to the weight of the first inner conductor casing, which is suspended from the outer conductor prior to being grouted. Using the API method, unit values of shaft friction (f) and end bearing (q) are calculated using the design criteria showing Figs. 1 and 2.

However, due to their shape and method of installation,

conductors can normally only develop axial capacity due to external shaft friction.

An example of an axial capacity calculation for a conductor is presented on Figs. 3 and 4. Axial capacity is developed due to external shaft friction only, and also no contribution to axial capacity is assumed for that portion of the conductor shaft affected by the drill-drive sequence (14m to 50m below ground level).

FIGURE 1 DESIGN CRITERIA FOR ULTIMATE BEARING CAPACITY OF PILES IN COHESIVE SOIL (METHOD 2)

FIGURE 2

DESIGN CRITERIA FOR ULTIMATE BEARING CAPACITY OF PILES IN COHESIONLESS SOIL (METHOD 1 & 2)

FIGURE 3 PILE CAPACITY

FIGURE 4 ULTIMATE STATIC BEARING CAPACITY

APPENDIX IV-2 AXIAL CAPACITY OF A DRILLED AND CEMENTED CONDUCTOR

AXIAL CAPACITY OF A DRILLED AND CEMENTED CONDUCTOR The axial capacity of a drilled and cemented conductor may be calculated using a modification to the API RP 2A 1979 method. Values of unit shaft friction (f) and unit end bearing (q) are calculated using the design criteria shown on Figs. 1 and 2. The major alteration to the standard API method is the way in which unit shaft friction in cohesionless soils is calculated. For a drilled and cemented conductor, the shaft friction developed is a function of the effective lateral stress on the wall of the hole. If the grout in the annulus around the conductor is in a fluid state, the grout pressure and therefore the lateral stress adjacent ot the hole, increases linearly with depth. Theoretically the available unit shaft friction will also increase linearly with depth. However, the allowable shaft friction will in practice be limited by the need to avoid failure of the band between the grout and the conductor (Ref.1) Another important consideration is to choose a grout density such that the resulting fluid pressure will not cause hydrofracture of the soil formation.

Such a failure may occur in either a vertical or

horizontal plane, see Section 3 of the Manual for details. In cohesive soils the recommendations of API RP 2A 1979 are followed more closely, with the exception that in overconsolidated clays a reduced α value of 0.4 is adopted. References 1.

EHLERS, C.J., and ULRICH, E.J., "Design criteria for grouted piles in sand". Paper OTC 2941, Offshore Technology Conference, Houston 1977.

An example of the bearing capacity calculation for a 1.07m pile to be installed by a drill and cement sequence is given below.

FIGURE 1 DESIGN CRITERIA FOR ULTIMATE BEARING CAPACITY OF PILES IN COHESIVE' SOIL

FIGURE 2 DESIGN CRITERIA FOR ULTIMATE BEARING CAPACITY OF PILES IN COHENSIONLESS SOILS

FIGURE 3 ULTIMATE STATIC BEARING CAPACITY

CONDUCTORS FOR TENDER ASSISTED DRILLING PLATFORMS

BY D. HENERY

BRUNEI SHELL PETROLEUM COMPANY LIMITED OCTOBER 1972 CONFIDENTIAL

APPENDIX V-1 REPORT PREPARED BY BSP ENTITLED "CONDUCTORS FOR TENDER ASSISTED DRILLING PLATFORMS" OCTOBER 1972

CONTENTS 1.

Introduction

2.

Conclusions

3.

Conductors for drilling platforms

4.

METHODS of installation of conductors available to BSP and SSB at present or in near future.

5.

Technical aspects of the six methods of installation of 26" x ½" conductors and 20" casing.

6.

Technical aspects of the six methods of installation of 30" x 1" conductors and 20" casing.

7.

Financial and probability study of the six methods of installation of 26" x ½" and 30" x 1" conductors and 20" casing.

8.

Effect of tender platform and jacket design and construction of replacing 26" x ½" conductor by 30" x 1" conductors.

APPENDICES APPENDIX I

- Financial assumption and equipment performance for installation of 26" x ½" and 30" x 1" conductors and 20" casing.

APPENDIX II

- Cost of the six methods of installation and materials costs of 26" x ½" conductors and 20" casing.

APPENDIX III

- Cost of the six methods of installation and materials costs of 30" x 1" conductors and 20" casing.

FIGURES FIG.1

- 6 pile jacket tender assisted drilling platform for 10 wells.

FIG.2

- pile, conductor and casing penetrations - case (A) 120 feet water depth

FIG.3

- pile, conductor and casing penetrations - case (B) 205 feet water depth

FIG.4

- decision tree for installation of 20" casing and/or 26 inch diameter, 0.5 inch wall conductor - case (A) 120 feet water depth

FIG.5

- decision tree for installation of 20" casing and/or 26 inch diameter, 0.5 inch wall conductor - case (A) 120 feet water depth

FIG.6

- decision tree for installation of 20" casing and/or 30 inch diameter, 1.0 inch wall conductor - case (B) 205 feet water depth

FIG.7

- decision tree for installation of 20" casing and/or 30 inch diameter, 1.0 inch wall conductor - case (B) 205 feet water depth

FIG.8

- average costs (from the decision tree) for materials and installation of 20" casing and/or 26" x ½" conductor in a 10 well platform case (A) 120 feet water depth

FIG.9

- average costs (from the decision tree) for materials and installation of 20" casing and/or 30" x 1" conductor in a 10 well platform case (A) 120 feet water depth

FIG.10

- average costs (from the decision tree) for materials and installation of 20" casing and/or 26" x ½" conductor in a 10 well platform case (B) 205 feet water depth

FIG.11

- average costs (from the decision tree) for materials and installation of 20" casing and/or 30" x 1" conductor in a 10 well platform case (B) 205 feet water depth

1.

INTRODUCTION

Brunei Petroleum Company Limited and Sarawak Shell Berhad between there have to date installed 4 self contained multiwell drilling platforms and 10 tender assisted drilling platforms in the South China Sea (neglecting the shallow water Marine platform offshore Seria). Twenty six inch outside diameter, half inch wall conductors or fixed marine risers have been installed in the platforms prior to spudding. the wells.

This report looks at the reasons why a conductor is required, and discusses the six methods of installation for conductors available to the Companies at present or in the near future. The technical aspects of the. six methods of installation of 26" x ½" conductors are listed together with the limitations that are imposed on the methods duo to the limited inherent strength of the 26" x ½" pipe

The report then discusses the technical aspects of the six methods of installation when applied to a larger diameter heavier wall conductor -namely 30" x 1" , which Is the same diameter as the 6 jacket piles of the tender assisted drilling platform.

A financial and probability study is described and decision trees are given for the six methods of installation of 26" x ½" and 30" x 1" conductors in platforms in 120 feet and 205 feet water depth.

Thereafter, the costs of materials and installation and drilling tender hours required by the main methods for installing 26" x ½" conductors and 30" x 1" conductors are given in further detail.

2.

CONCLUSIONS AND RECOMMENDATIONS

(a)

It is concluded that the method of driving 26" x ½" conductor to refusal by the derrick barge Mantorek and subsequently setting 20" casing in every well by the drilling tender is the most attractive method when financial, technical and operational details are considered.

(b)

It is recommended that the method given in (a) above is adopted as soon as possible..

(c)

It is also recommended that if and when a simulation model for scheduling derrick equipment sets is designed that a study be made of the possibility of scheduling the engineering/production workover barge Mendu and the derrick equipment sets for drilling/driving 26" x ½" conductors to target penetration. A study of equipment requirements and a detailed design study will also be required.

(d)

It should be noted that on the advice of Petroleum Engineering Department, it was decided that deffered production should not be taken into account.

3.

CONDUCTORS FOR DRILLING PLATFORMS

There are several reasons by conductors are required, some of which are:(a)

to prevent the washout around and below the jacket piles during spudding in and before setting the first casing in the well.

(b)

to support the surface casing string before the current has set.

(c)

to attempt to control shallow gas blowouts and avoid cratering below the platform.

(d)

to provide a method of getting mud returns to the platform during the drilling operation and before setting the first casing in the well.

(e)

to protect the well casing against wave attack.

(f)

to prevent surface formation collapse before setting the first casing.

The conductor is a steel pipe driven into the seabed by a pilling hammer to a target penetration of about 20 feet below the toe of the deepest jacket pile. The conductor is supported laterally above the seabed by conductor guides into the jacket and platform celler deck. Jetting and/or drilling may be required to assist with obtaining the required conductor target penetration. If the conductor meets resistance beyond which it is impossible to safely proceed without the risk of damaging the conductor, it may be necessary to drill a hole and set a shallow casing string inside the conductor. This casing string (usually 20" casing) is set at about 50 to 100 feet below the toe of the deepest pile. Sketches (1), (2) and (3) indicate the spacing and setting depths of the jacket piles, conductors and 20" surface casing for two typical tender assisted drilling platforms.

4

METHODS OF INSTALLATION OF CONDUCTORS AVAILABLE TO BSP AND SSB AT PRESENT OR IN NEAR FUTURE.

There are 6 method by which. BSP or SSB can, or will, be able to install conductors on tender platform. The 6 methods are given below, following each method are the sequence of methods which are used to ensure that in the event of failure of one method another method is used to complete the surface casing and/or conductor requirements on the platforms. The methods are also shown in Fig. 4

1.

2.

3.

Derrick barge Mantorek, drilling tender and derrick equipment set. (a)

Mantorek stab initial length of conductor, add on further lengths of conductor, weld and drive conductor into seabed. Continue operation until conductor reaches target penetration.

(b)

Mantorek can jet out the plug of soil inside the conductor or below the toe of the conductor to reduce the driving resistance and enable the conductor to reach target penetration.

(c)

Mantorek can attempt to drill in advance of the toe of the conductor. The drilling/driving may be carried out in several stages or alternatively a hole may be drilled to conductor target penetration and the conductor driven into it.

(d)

Failing the above methods, the conductor will be driven to an acceptable hammer blowcount/penetration by the Mantorek and the drilling tender and derrick equipment set will then set 20" surface casing inside the conductors.

Derrick bare Mantorek, drilling tender and derrick equipment set.. (a)

Mantorek stab initial lengths of conductor.

(b)

Mantorek add on further lengths of conductor and drive conductor to an acceptable hammer blowcount/penetration..

(c)

Drilling rig and derrick equipment set - set 20" surface casing inside every conductor.

Drilling tender (Nickle, Pieree, Sidewinder or Jumbo) and derrick equipment set (a)

Mantorek stab initial lengths of conductor

(b)

Drilling rig and derick equipment set drill/drive conductors to target penetration.

(c)

If the drilling/driving method fails to get the conductors to target penetration, the rig will drive the conductors to an acceptable blowcount/penetration and then set 20" surface casing inside the conductors.

4.

5.

6.

Engineering/Production workover barge Mendu and packaged workover rig. (a)

Mantorek stab initial lengths of conductor

(b)

Mendu and workover rig drill/drives conductors to target penetration.

(c)

If the drilling/driving method fails to get the conductors to target penetration, Mendu and the workover rig will drive the conductors to an acceptable hammer blowcount/penetration and then the drilling rig and derrick equipment set - set 20" surface casing inside the conductors.

Engineering/Production workover barge Mendu and derrick equipment set a)

Mantorek stab initial lengths of conductor

(b)

Mendu and DES drill/drives conductors to target penetration.

(c)

If the drilling/driving method fails to get the conductors to target penetration, Mendu and the DES rig will drive the conductors to an acceptable hammer blowcount/penetration and then the drilling rig and derrick equipment set - set 20" surface casing inside the conductors.

Derrick barge Atlas (or similar), drilling tender and derick equipment set (a)

Atlas stab initial length of conductor, add on further lengths of conductor, weld and drive conductor into seabed. Continue operation until conductor reaches target penetration.

(b)

Atlas can jet out the plug of soil inside the conductor or below the toe of the conductor to reduce the driving resistance and enable the conductor to reach target penetration.

(c)

Atlas can attempt to drill in advance of the toe of the conductor. The drilling/driving may be carried out in several stages or alternatively a hole may be drilled to conductor target penetration and the conductor driven into it.

(d)

Failing the above methods, the conductors can be driven to an acceptable hammer blowcount/penetration by the Atlas arid the drilling tender and derrick equipment set will then set 20" surface casing inside the conductors.

5.

TECHNICAL ASPECTS OF THE SIX METHODS OF INSTALLATION OF 26" x ½" CONDUCTORS AND 20" CASING

1.

MANTOREK - DRILLING TENDER AND DERRICK EQUIPMENT SET

A.

Mantorek drive 26" x ½" conductor to target penetration

B.

C.

(a)

Limited to using Shell owned Delmag D22 diesel hammer. (39,700 ft/lbs striking energy, 42-60 blows per minute) or the Brown and Root Vulcan 200C steam hammer (50,200 ft/lbs striking energy, differential action, 98 blows per minute normal speed) with reduced steam pressure and hence reduced blows per minute and greatly reduced efficiency.

(b)

The blowcount of the D22 or 200C hammer on 26" x ½" conductor has to be carefully limited to avoid damaging the toe of the conductor. The low maximum blowcount together with the frequency halts in driving required for greasing the diesel hammers result in a high probability of freezing up of the conductor before reaching target penetration.

(c)

It is essential that Mantorek successfully drives the first conductor to target penetration before attempting to drive further conductors.

Mantorek jet/drive 26" x ½" conductor to target penetration. (a)

An "airlift" will be necessary to assist with removal of the plug materials during jetting.

(b)

The use of a "flexible" jetting string which can be lowered into and out of the conductor by the Mantorek crane should reduce jetting times.

Mantorek drill hole and drive 26" x ½" conductor to target penetration

(a)

D.

The Mantorek has the basic equipment for drilling in piles - a Bowen Power Sub (a hydraulic powered pipe rotating device capable of producing up to 26 000 ft/lbs of torque, the power sub is attached to the top of the drill string) a swivel, a basic 5" drill string, bumper sub and drill collars. More equipment and design effort will be needed to make the drilling- operation by the Mantorek successful and efficient.

Drilling tender and derrick equipment set - set 20" casing inside 26" x ½" conductor a)

Before the rig begins drilling out the conductors to set 20" casing, the conductors should be driven to an acceptable hammer blowcount/penetration (by Mantorek) such that the conductor can support the weight of the 20" surface casing during cementing without the possibility of the conductor settling, end also to minimise the possibility of cratering around the conductor in the event of drilling through a shallow gas pocket before setting the first casing string.

(b)

Extreme care should be taken when drilling from the toe of the conductor down past the jacket piles to avoid washout around the piles. A pilot hole is usually drilled to casing target penetration at a drilling speed of about 1 foot per minute and a pump rate of about 300 gallons per minute. The hole is then "opened" with the pilot bit and a hole opener in the string. Under certain circumstances it may be possible to drill a single stage hole or it may be necessary to drill the hole in 3 stages.

2.

MANTOREK - DRILLING TENDER AND DERRICK EQUIPMENT SET

A.

Mantorek drive 26" x ½" conductor to acceptable blowcount/penetration

B.

(a)

The Mantorek will be limited to using the Delmag D22 or Vulcan 2000 hammer with the same limitations as given in 1A above.

(b)

Neither jetting nor drilling will be necessary since it is accepted that when using this method the conductor will only be driven to resistance and then 20" surface casing set in all the conductors by the drilling tender and derrick equipment set.

Drilling tender and derrick equipment set - set 20" casing inside 26" x ½" conductor in every well. See lD above.

3.

DRILLING TENDER AND DERRICK EQUIPMENT SET

A

Drilling tender and derrick equipment set - drill/drive 26" x ½" conductors to target penetration (a)

The drilling rig is limited to using the Delmag D22 hammer on 26" x ½" conductors.

(b)

The rig will be limited to using 40 feet addons due to the limited headroom below the "A" door of the derrick.

(c) The performances of a drilling tender and D.E.S drilling/driving conductors in two platforms are given below:

NOTE :

Times include time required for skidding derrick equipment set between wells etc.

B.

Drilling tender and derrick equipment set - set 20" casing inside 26" x ½" conductor

(a)

C.

The conductors will have been stabbed to a penetration of about 100 feet by the Mantorek . In the event of the rig not being able to drill/drive the conductors to target penetration, the rig will have to drive each conductor to an acceptable blowcount/ penetration before setting 20" surface casing.

The following table gives a list of tender platforms installed to-date with information about whether conductors were successfully drilled/driven or whether 20" casing was set.

4

MENDU AND WORKOVER RIG - DRILLING TENDER AND DERRICK EQUIPMENT SET

A.

Mendu and workover rig drill/drive 26" x ½" conductor to target penetration (a)

The packaged workover rig proposal includes a 27 ½ inch rotary drive, hence it should be possible to drill and drive 26 inch diameter conductors.

(b)

The workover rig will become available about mid 1973.

(c)

The workover rig will be required for 4 months for offshore workovers and for 3 months for onshore workovers during the next 2 years, thereafter it is anticipated that this rig will be used continuously throughout the year. Hence, scheduling of the Mendu and the workover rig for conductor driving could be difficult if not impossible.

(d)

It is anticipated that a special crow would be assigned to rig-up work and drilling/driving of conductors. After initial training of crews with the packaged workover rig it is anticipated that times for drilling and driving conductors will be about the same as those for the rigs (or marginally better).

B.

5.

Drilling tender and derrick equipment set - set 20" casing inside 26" x ½" conductor (a)

20" casing is set in the first well of each tender platform for protection against the posssibility of shallow gas. If Mendu and the workover rig were used to set the 20" casing it would be necessary for the Mendu to carry out a full scale drilling operation with adequate equipment to deal with a potential gas problem when setting this initial casing. Hence, the Mendu and workever rig will not be used for setting 20" casing.

(b)

The Mendu and workover rig will have to drive the conductors to an acceptable blowcount/penetration before the drilling tender and derrick equipment set - set 20" casing.

MENDU AND DERRICK EQUIPMENT SET - DRILLING TENDER AND DERRICK EQUIPMENT SET

A.

B.

Mendu and derrick equipment set drill/drive conductors to target penetration (a)

This will necessitate the derrick equipment set being fully rigged and operational earlier than normal.

(b)

It is anticipated that a special crew would be assigned for derrick equipment set rig-up work and drilling/driving of conductors. After initial training of crews with the derrick equipment set it is anticipated that times for drilling and driving conductors will be about the same as these for the rigs (or marginally better).

Drilling tender and derrick equipment set - set 20" casing inside 26" x ½" conductor

(a)

The Mendu and the DES cannot set 20" casing inside the 26" conductors for the same reasons as given in 4.B above.

(b)

The Mendu and the DES will have to drive the conductors to an acceptable blowcount/penetration before the drilling tender and DES set 20" casing,

6.

ATLAS - DRILLING TENDER AND DERRICK EQUIPMENT SET

A.

Atlas drive 26" x ½" conductor to target penetration (a)

B.

Atlas jet/drive 26" x ½" conductor to target penetration (a)

C.

Similar to Montorek drive conductors to target penetration.

Similar to Montorek jet/drive conductors to target penetration.

Atlas drill hole and drive 26" x ½" conductor to target penetration (a)

Atlas is equipment with basic drilling equipment. The drilling power units is of the rotary table type, hence weather downtime should be less than with the Bowen Power Sub. It is considered however, that for drilling in 26" x ½" conductor virtually all the points mentioned for the Mantorek drilling and driving will apply to the Atlas.

6

TECHNICAL ASPECTS OF THE SIX METHODS OF INSTALLATION OF 30" x 1" CONDUCTORS AND 20" CASING

1.

MANTOREK - DRILLING TENDER AND DERRICK EQUIPMENT SET

(A)

Mantorek drive 30" X 1" conductors to target penetration (a)

(B)

Mantorek jet/drive 30" x 1" conductor to target penetration (a) (b)

(C)

An "airlift" will be necessary to assist with removal of the plug materials during jetting. The use of a "flexible" jetting string which can be lowered into and out of the conductor by the Mantorek crane should reduce jetting times.

Mantorek drill/drive 30" x 1" conductor to target penetration (a)

(D)

Tender platform jacket piles are composite 30" tubulars inside 33" tubular legs. If 30" x 1" conductors with 1¼" driving shoes are used on the platform, it should be possible to obtain at least the same penetration with the conductors as that of the jacket piles, then it is estimated that further jetting and./ or driving has a reasonable probability (see decision trees) of achieving target penetration (assumed to be 20 feet below the toe of the deepest jacket pile).

Refer to Mantorek drill/drive 26" x ½" conductor

Drilling tender and derrick equipment set - set 20" casing inside 30" x 1" conductor (a)

Before the rig begin drilling out the conductors to set 20" casing, the conductors should be driven to an acceptable hammer blowcount/penetration.

(b)

The times to set 20 inch casing inside 30" conductors should not vary greatly from those to set 20" easing inside 26" conductor.

2.

MANTOREK - DRILLING TENDER AND DERRICK EQUIPMENT SET

(A)

Mantorek drive 30" x 1" conductor to acceptable blowcount/penetration See 1(A)(a)

(B)

Drilling tender and derrick equipment set - set 20" casing in every well See 1 (D) (b)

3.

DRILLING TENDER AND DERRICK EQUIPMENT SET

(A)

Drilling tender and derrick equipment set drill/drive 30" x 1" Conductors to target penetration (a)

The drilling tenders JUMBO, NICKLE and PIERCE have derrick equipment sets with 37½" diameter rotary tables, hence they can pass 30" x 1" conductors through the table without having to remove the rotary drive.

(B)

(b)

The Shell derrick equipment set rotary tales, however, cannot accommodate 30" x 1" conductors for drilling/driving operation it will necessitate removal of the table when adding on and driving the conductor and replacement of the table for drilling or alternatively the purchase of new rotary tables (costs about B$110,000)

(c)

The drilling rig will be limited to using the Shell D44 and/or the M40 diesel hammers. These hammers may present problems of conductor freeze-up during frequent hammer servicing.

Drilling tender and derrick equipment set - set 20" casing inside 30" x 1" conductor. (a)

The times to set 20 inch casing inside 30" conductor should not vary greatly from those to set 20" casing inside 26" conductor.

4.

MENDU AND WORKOVER RIG - DRILLING TENDER AND DERRICK EQUIPMENT SET

(A)

Mendu and workover rig drill/drive 30" x 1" conductors to target penetration

(B)

(a)

The packaged workover rig proposal for a 27½ inch rotary drive would have to be altered to a 37½ inch rotary drive.

(b)

The rig will be limited to using the Shell D44 and/or the M40 hammers. These hammers may present problems of conductor freeze-up during frequent hammer servicing.

(c)

Scheduling of the Mendu and rig could be difficult due to the well repair programme.

Drilling tender and derrick equipment set - set 20" casing inside 30" x 1" conductor (a)

Mendu and workover blowcount/penetration.

rig

would

firstly

drive

(b)

Casing setting times would be as in 3 (B) (a) above.

conductors

to

acceptable

5

MENDU AND DERRICK EQUIPMENT SET - DRILLING TENDER AND DERRICK EQUIPMENT SET

(A)

Mendu and Derrick equipment set drill/drive 30" x 1" conductors to target penetration.

(B)

(a)

Require derrick equipment set being fully rigged and operational earlier than normal.

(b)

The Mendu and DES will be limited to using the Shell D44 and or the M40 hammers.

(c)

The Shell derrick equipment set rotary tables would have to be changed from 27 ½" to 37½" diameter.

Drilling tender and derrick equipment set -set 20" casing inside 30" x 1" conductors.

6.

ATLAS - DRILLING TENDER AND DERRICK EQUIPMENT SET

(A)

Atlas drive 30" x 1" conductors to target penetration. Similar to Mantorek drive 30" x 1" conductors to target penetration.

(B)

Atlas drive/jet 30" x 1" conductors to target penetration. Similar to Mantorek drive/jet 30" x 1" conductors to target penetration.

(C)

Atlas drill/drive 30" x 1" conductors to target penetration. Similar to Mantorek drill/drive 30" x 1" conductors to target penetration.

(D)

Drilling tender and derrick equipment set - set 20" casing inside 30" x 1" conductor. Similar to 1.D (b) above.

7.

FINANCIAL AND PROBABILITY STUDY OF THE SIX METHODS OF INSTALLATION OF 26" x ½" AND 30" x 1" CONDUCTORS AND 20" CASING

The fig (1) gives the layout of a 6 pile jacket - tender assisted drilling platform for 10 wells A financial and probability study was made into two typical platforms - case (A) - a tender platform in 120 feet water depth (see fig 2 for assumed pile, conductor and casing penetrations) and case (B) - a tender platform in 205 feet water depth (see fig. 3 for assumed pile, conductor and casing penetrations). The six methods of installation of 26" x ½" and 30" x 1" conductors in case (A) and case (B) are displayed in decision trees in fig. 4 through 7 respectively. Typical probabilities shown on the tree together with the costs of the various methods of installation and materials costs. The explanation of one method is as follows:Drilling tender and derrick equipment set-install 20" casing and/ or conductor - case (A) (fig 4) (a)

the equipment performances (rig, derrick barge etc.) based on past performance have been evaluate for the different method of installation of conductors. The equipment day rates and material costs are given in Appendix I. The time breakdowns for operations are given in Appendices II and III.

(b)

the total costs of the methods of installation including weather downtime and material costs for each method are given for 26" x ½" and 30" x 1" conductors in Appendices II and III respectively.

(c)

referring to fig 4, the main method of installation by the drilling tender and derrick equipment set is given, followed by the sequence of method which are used to ensure that in the event of failure of one methods, another method is used to completed the surface casing and/or conductor requirements on the platform.

(d)

the cost of each operation as evaluated in Appendices II or III is shown on each branch of the tree.

(e)

a probability is assigned to each node of the tree of success (S) and failure (F) of the method based upon past performances and the technical aspects of the six methods of installation given.

(f)

hence, commencing of the outermost limb of this branch of the tree, a failure by the RIG to DRILL/DRIVE CONDUCTORS TO TARGET PENETRATION will result in the RIG DRIVE CONDUCTORS TO ACCEPTABLE BLOWCOUNT/PENETRATION and then RIG SET 20" CASING, the latter 2 operations costing B$721,000.

Therefore, assuming the rig drill/drive technique to be 40% successful, the average cost of preparing a platform for drilling using this method will be 40% of the cost of RIG DRILL/DRIVE TO TARGET PENETRATION and 60% of the cost of RIG DRIVE CONDUCTORS TO ACCEPTABLE BLOWCOUNT/RESISTANCE and RIG SET 20" CASING i.e.: 40% of B$538,000 and 60% of B$721,000 respectively which amounts to B$648,000. (g)

it can be argued that this is unrealistic for one platform, since we would not contemplate drilling/driving say 4 conductors to target penetration and driving 6 conductors to an acceptable/penetration and setting 20" casing. However, if 5 platforms are considered, it is feasible to drill/drive all conductors on 2 platforms to target penetration and to drive all conductors to an acceptable blowcount/penetration on the other 3 platforms and set 20" casing in all the wells on the 3 platforms..

The fig 4 through 7 give the average equipment and material costs per 10 well tender assisted platform for installing 20" casing and/or 26" x ½" (or 30" x 1") conductors in cases (A) and (B) for the 6 different methods of installation. The average drilling tender vessel hours are also given for each method together with the material costs. For convenience, the total equipment material costs are given in figs. 6 to 11 together with the material costs and the drilling tender hours. The. methods are rated below according to costs, no lost production/ income has been assigned to the drilling tender hours involved in the methods. (On the advice of Petroleum Engineering Department)

(A)

Analysis of decision tree costs for 6 methods of installation of 26" x ½" conductors. Considering figs 8 and 10 i.e.:

for 26" x ½" conductor and 20" casing used on caes A and

case B jackets, and bearing in mind that the costs given are based on assumed probabilities and hence are not precise but indicate the order of magnitude, it can be seen that:(a)

the installation (method 6) by Atlas -- drilling tender and derrick equipment set is the most expensive.

(b)

the installation (method 4) by Mendu and workover rig - drilling tender and derrick equipment set is the second most expensive.

(c)

the installations methods- 1, 2 and 3 are about equally priced. However, the method 1 - Mantorek attempt to drive, jet/drive or drill/drive conductors to target penetration - drilling tender and derrick equipment set - set 20" casing, requires a large amount of Mantorek time which could results in the necessity to mobilise the Atlas and hence the cost for method 1 could increase to about the cost of method 6. Moreover, this method would require additional drilling equipment and further design studies. The method 3 - drilling tender and derrick equipment set drill/ drive conductor or set 20" casing is operationally unattractive to Drilling Departments.

(d)

the installation (method 5) by Mendu and Derrick equipment set-drilling tender and derrick equipment set is financially attractive but would require additional equipment and further design study. This method could also present complex scheduling problems. Therefore, the most attractive method is method 2 - MANTOREK drive 26" x ½" conductors to acceptable blowcount/penetration, DRILLING TENDER and DERRICK EQUIPMENT SET set 20" casing in every well and it is recommended that this method is adopted as soon as possible.

(B)

Analysis of decision tree costs for 6 methods of installation of 30" x 1" conductor. Considering fig. 9 and 11, i.e.: for 30" x 1" conductor and 20" casing used on case A and case B jackets, it can be seen that:-

(a)

methods 1 to 6 inclusive for 30" x 1" conductor are less expensive than method 6 for 26" x ½" conductor, but are more expensive than methods 1 to 5 for 26" x ½" conductor. Hence, the recommendation given in (A) above about method 2 is still applicable.

8.

EFFECT ON TENDER PLATFORM AND JACKET DESIGN AND CONSTRUCTION OF REPLACING 26" X ½" CONDUCTOR BY 30" x 1" CONDUCTOR

1.

The wave forces (inertia and drag) are greater on a 30 inch conductor than on a 26 inch conductor. However it is considered, that the increased stiffness and strength of the larger conductor will result in little or no additional loading being transferred to the jacket and piles.

2.

To date, decks have been ordered abroad and have arrived in a fully fabricated condition, in the near future Brown and Root Contractor will fabricate decks from basic structural members at the Labuan construction yard. Hence, slight modifications to conductor guides in the jacket and deck and deck beam layout will result only in drawing office modifications and minor changes in fabrication costs.

3.

Under certain circumstances e.g.; deep water and poor soil conditions, the initial lengths of conductor have to be supported by the jacket top bracing until they are added onto and driven to a sufficient penetration to enable the soil to support them. When this circumstances are anticipated, it will be necessary to strengthen the jacket top bracing.

APPENDIX I FINANCIAL ASSUMPTIONS AND EQUIPMENT PERFORMANCES FOR INSTALLATION OF 26" ½" AND 30" x 1" CONDUCTOR AND 20" CASING

(A)

The following equipment rates and material costs have been used in the financial analysis

(a)

Mantorek day rate (24 hours) - 23,800 B$ This is the full spread rate for the Brown and Root barge including derrick barge, anchor tug, contractor's transportation barge and tug, contract divers, Shell barges, supply and general purpose boats, Shell helicopter and contract inspection.

(b)

Atlas (or similar) day rate (24 hours) - 64,000 B$ This is the full spread rate similar to that for the Mantorek and also including part mobilisation and dermobilisation costs.

(c)

Drilling tender and derrick equipment set day rate (24 hours) -29,000 B$ This rate is obtained by taking the average of the SSB tariff rates (commencing January 1972) for the drilling tenders J.W. Nickle, I.J. Pierce, Jumbo and Sidewinder and their respective derrick equipment sets - amounting to 25,500 B$/day. The rates for Shell standby boat, supply and general purpose boats, additional personnel and Shell helicopter amount to about 3,500 B$/day. The rate of 29,000 B$/day does not allow for the increase in Sidewinder tariff rate resulting from her extensive refit during 1972. (Note: SSB rates are used instead of BSP rates, since the former include an element of depreciation and the latter do not).

(d)

Engineering /Production workover barge Mendu and packaged workover rig day rate (24 hours) - 16,000 B$ This rate is compounded from a rate for Mendu and a rate for the workover rig. The Mendu rate of 9,000 B$/day is a spread rate based on the SSB tariff rates, including the derrick barge, anchor tug, standby boat and supply boat and personnel. The packaged workever rig rate of 7,000 B$ is an estimated rate based on a capital cost of 4.8 m. B$ depreciated over 5 years, an average usage of 10 months per annum and including personnel, fuel and marine insurance costs.

(c)

Engineering/Production workover barge Mendu and derrick equipment set day rate (24 hours) - 15,000 B$ This rate is compounded from the rate for the Mendu of 9,000 B$ and an average rate for a D.E.S. of about 4,500 B$ and personnel costs etc.

(f)

26" x ½" conductor x 40' joint

- 1,510 B$

(g)

30" x 1" conductor x 40' joint

-

3,700 B$

(h)

20" casing x 40' joint

-

2,046 B$

(i)

cement (per bag of 42.5 kilos)

-

6.7 B$

(B)

The following assumptions have been used in the financial analysis:-

(a)

The tender platform pile penetrations are given in fig. 2 and 3 for the tender platforms in 120 feet and 205 feet water depth respectively. The pile penetrations are based upon soil conditions experienced at West Lutong and South-West Ampa for case (A) -the tender platform in 120 feet water depth and at Fairley and Baram for case (B) - the tender platform in 205 feet water depth.

(b)

Conductor penetrations and casing setting depths are also given in figs. 2 and 3. The 20" surface casing is usually set at a depth of 50 to 100 feet below the toe of the deepest pile of the tender platform. However, for this study the casing setting depth has been assumed to be identical to the conductor target penetration, that is, 20 feet below the toe of the deepest tender platform pile.

(c)

20" surface casing is set to a depth of 1000-1500 feet in the first well drilled on each tender platform for protection against the possibility of a shallow gas blowout. Hence, when it is necessary to set 20" casing in all wells on the platform owing to the conductors not reaching target penetration, the costs of setting 9 casing strings only (for a 10 well platform) are assessed.

(d)

Cementing of surface casing - the cost has been evaluated on the assumption that 3 times the amount of cement would be required to cement the annulus between the outside of the 20" casing and the opened hole (24" diameter) for the length of casing from setting depth to mudline. The 200% excess cement would be accounted for by possible losses to the formation etc.

(e)

Mooring-up times for floating equipment - these times have not been taken into account for the Mantorek or Atlas since they would already be moored up for placing the tender platform jacket and for piling etc, for the tender and derrick equipment set when the former would be moored up for normal drilling operations, or for the Mendu end derrick equipment set when the former would be moored up for rigging up the derrick equipment set. The mooring up time for the Mendu when drilling/driving conductors with the packaged workever rig has been included in the 72 hour rigging up and 72 hour rigging down of the packaged workover rig.

(f)

Conductor stabbing, add-ons end welding - the initial lengths of conductor stabbed by the Mantorek or Atlas were assumed to be 165 feet for 26" or 30" conductor. Generally, add-on lengths were assumed to be 80 feet of 30" conductors and 60 feet of 26" conductors when added-on by Mantorek or Atlas, and 40 feet of 30" or 26"' conductors when added-on by the tender and derrick equipment set or Mendu and derick equipment set or Mendu and packaged workover rig - the 40 feet add-on is due to the limitations of headroom below the "A" door of the derrick.

The lifting line up and welding times for 26" x ½" conductors were assumed to be 2½" hour: per weld and for 30" x 1" conductors 4 hours per weld. It was assumed that there was no overlap in operations e.g. welding/driving etc. (g)

(h)

(i)

(j)

Equipment operating hours -. the Mantorek, Atlas and drilling tenders are assumed to be fully manned for 24 hours operations. The Mendu, however, is assumed to be operational for 12 hours per day. Transportatin of conductors/casing - the spread rate for Mantorek and Atlas includes transportation barges and tugs. As the rates for the drilling tender and Mendu do not include transportation ,an additional transport charge has been added. Weather downtime has been assessed at the following rate:Mantorek (derrick barge)

-

10.0%

per annum

Atlas (derrick barge)

-

10.0%

"

"

Drilling tender and derrick equipment set

-

0.5%

"

"

Mendu and packaged workover rig

-

5.0%

"

"

Mendu and derrick equipment set

-

0.5%

"

"

Equipment performances - in order to make a realistic comparison of equipment performances, the equipment times have been estimated based on past performances of the equipment.

APPENDIX II

COSTS OF THE SIX METHODS OF INSTALLATION AND MATERIAL COSTS OF 26" x ½" CONDUCTORS AND 20" CASING

Two typical tender assisted drilling platforms are considered:CASE (A)

Tender platform in 120 feet water depth, jacket pile penetration 200 feet, conductor required target penetration of 220 feet and casing setting depth of 220 feet.

CASE (B)

Tender platform in 205 feet water depth, jacket pile penetration 300 feet, conductor required target penetration of 320 feet and casing setting depth of 320 feet.

(Note:

See Appendix I regarding comments about pile penetrations and casing setting depths).

APPENDIX III

COSTS OF THE SIX METHODS OF INSTALLATION AND MATERIAL COSTS OF 30" X 1" CONDUCTORS AND 20" CASING

Two typical tender assisted drilling platforms are considered:CASE (A)

Tender platform in 120 feet water depth, jacket pile penetration 200 feet, conductor required target penetration of 220 feet and casing setting depth of 220 feet.

CASE (B)

Tender platform in 205 feet water depth, jacket pile penetration 300 feet, conductor required target penetration of 320 feet and casing setting depth of 320 feet.

(Note:

See Appendix I regarding comments about pile penetrations and casing setting depths).

APPENDIX V-2 CALCULATION OF ALLOWABLE STICK-UP HEIGHT

1

INTRODUCTION

Calculation of the allowable stick-up length for a particular pile/hammer combination involves a static stress analysis being performed at the critical pile section (the pile section at which the maximum stresses occur). The stress level so determined is then related to a permissible stress level for the particular load conditions being experienced by the pile. This process is in accordance with API recommendations (Section 2.31(d) API RP 2A). However, for the purposes of analysis the loading may be assumed to consist of "combined bending and axial compression", resulting in a requirement of relating permissible stress to actual stress as illustrated by the AISC combined stress equation below:-

Values of Fb and Fa are obtainable from current standards or codes of practice (e.g. AISC Manual of Steel Construction). It should be noted that when the pile add-on has a variable wall thickness, it may be necessary to check combined stresses at a number of control points along the add-on length. It must be borne in mind that all calculation methods are based on the assumption of full fixity at top of first pile guide and this may not always be valid. The results of any stick-up calculation should be tempered with common sense since the deflection under driving is not considered. No rules are at present available but deflection will affect driving efficiency. This is particularly critical with the use of high yield steels and large batters. This matter is subject to further study by SIPM with a view to issuing a revision of this Section containing more firm recommendations.

2

METHODS OF COMPUTATION

Several methods have been proposed for determining allowable stick-up length with the differences between them depending upon the validity of the assumptions made in calculating the critical bending moment sustained by the pile. Three methods are described in this Appendix.

2.1

Vissers Method (Described in EP ...) This method is relatively simple, consisting of a static analysis of the problem based on the assumption that the secondary moments resulting from pile deflexions are not significant (i.e. the pile is considered as a rigid member during moment calculation). Therefore permissible stresses are governed by buckling and Equation (2) is used as a condition for stability.

though correct, this condition is applicable only to members where may not always apply when setting a hammer.

fa > 0.15, . a situation which Fa

The principal advantages of the method are that it is simple to use and that experience indicates that it produces safe and realistic results.

2.2

BSP Method (after M. Brinded) This method involves an iteractive approach to the problem of calculating the critical bending moment. An initial deflection of the pile head is assumed with the appropriate causal moment then calculated, a corresponding pile deflection is then found using the previously established moment; the iteration is continued until an acceptable closure is achieved.

The deflexion finally calculated is doubled to account for dynamic effects during setting of the hammer, and it is this increased deflection which is used for computing the stresses at the critical section

The stresses are considered acceptable if they are less than the yield

strength divided by 1.2.

2.3

Fugro Method (after E.P. Popov)

To overcome the difficulties in establishing the critical bending moment and hence the maximum stress level, a third method of analysis is proposed which involves the use of an approximate solution in the evaluation of the pile deflexion. Equation (3) is used.

Using the deflexion so calculated the maximum moment may be found and so the maximum stress level evaluated. The standard condition for stability in Equation (1) is then applied and an allowable add-on length estimated, thus

This method shows the same form of relationship between combined stress and stick-up as the BSP (Brinded) method. In the same way as in the BSP (Brinded) method it is possible to take account of some of the dynamic effects of stabbing the hammer. This may be done by multiplying the weight of the hammer by two in equation (4) only. (Use the true weight in equations (5) and (6).) The advantages of the method are that it is simple to use and yet accounts for secondary bending effects.

3

SUMMARY

Three methods for estimating add-on lengths have been described and examples of the results of using them are shown on Plate. All computations have been made for a pile of 30 in od x 1 in wt at a batter of 1:8. The hammer is a Vulcan 030. The maximum stick-ups from each method for various types of steel are:

Yield Strength Method:

36 ksi

42 ksi

Stick-up (ft)

Visser

100

114

BSP (Brinded)

100

110

Fugro (1)

90

100

Fugro (2)

97

107

The number in brackets after Fugro indicates the factor by which the hammer weight is multiplied in equation (4). Vissers method and Fugro (1) are based on permissible combined stresses of 0.66 Fy . BSP (Brinded) and Fugro (2) use 0.83 Fy The results on Plate 1

show that for ordinary steels the differences between the results of the

methods are small and Fugro (1) appears to be the most conservative. For high yield steels Vissers method would produce the least conservative results.

It is recommended that BSP (Brinded) method is used if the engineer has access to suitable computer facilities. In other circumstances it is recommended that the allowable stick-up be determined by applying the Visser, Fugro (1) and Fugro (2) methods and adopting the most conservative results.

FIGURE 1 COMBINED COMPRESSIVE AND BENDING STRESS VS ADD-ON LENGTH

APPENDIX V-3

TYPICAL BLOWCOUNT RECORD SHEET FOR OFFSHORE USE TOGETHER WITH A COMPLETED EXAMPLE FROM SBPT

CONTENTS

1

INTRODUCTION

2

TYPES OF MEASUREMENT Hammer Efficiency Measurements Stress and Acceleration Measurements Background to the use of the measurements Scope of offshore and onshore interpretation

3

THE BENEFITS OF INSTRUMENTATION Guidance during pile installation Providing information on piles as driven Providing information relevant to subsequent installation of other platforms Long term benefits

REFERENCES

1.

INTRODUCTION

1.1

This Appendix sets out the potential advantages of making measurements on piles and hammers to supplement high quality driving records made during pile installation.

1.2

Section 2 of this Appendix describes the recording and instrumentation procedures and provides background data on the analytical techniques. Section 3 discusses the potential uses and benefits of instrumentation.

1.3

Some group companies have either used instrumentation on projects or felt instrumentation, if available) would have assisted them. Shell Expro installed strain gauges on some of the piles at Brent 'A' and on the basis of the stress-time measurements obtained information of overall hammer efficiency. SBPT used strain gauges and accelerometers on a conductor pile at Maui A to obtain a better understanding of driving behaviour and to monitor hammer performance. SOC have felt that the premature refusal of some piles and conductors may have been due to hammers operating inefficiently. However, without suitable instrumentation they had no way of proving their suspicions.

2

TYPES OF MEASUREMENT

2.1

The following measurements can be made without difficulty on hammers and piles: i)

hammer efficiency

ii)

stress and acceleration in followers or add-ens

On a research type of project, it is possible to make additional measurements on the length of pile embedded in the soil, these are: iii)

stress and acceleration at various levels on the pile

iv)

total stress measurements of the soil against the pile wall

v)

pore water pressure measurements along the pile

vi)

continuous monitoring of the plug level.

It is not recommended that measurements of the type listed in items (iii) to (vi) should be made on routine projects. Such instrumentation requires structural modifications to any pile on which it is placed. For this reason it is not described in this Appendix but full details may be found in Ref. 1.

Hammer Efficiency Measurements 2.2

For hydraulic hammers instrumentations to measure performance is already built-in. To date diesel hammers have proved impossible to instrument. Past experience on site has shown the inadequacy of visual observations and high speed photography as a means of assessing the performance of steam hammers. The importance whilst the particular pile is being driven has led to the development ram velocity measuring devices for steam hammers.

2.3

One such device for steam hammers involves mounting a small optical sensor and light source on the cross head of the hammer using a support bracket. This is done on deck and does not interfere with installation procedure. At the same time a small vane, the only moving component, is mounted at the head of the hammer control bar. Immediately prior to the ram striking the cushion the vane crosses the optical beam. The time for which the beam is broken is measured and from the dimensions of the vane, the velocity of the vane (and hence ram) is computed. Knowing the mass of the ram, its kinetic energy and hence the hammer efficiency is determined.

2.4

This equipment can be mounted on the hammers at the outset of the installation period and it can be used intermittently or continuously. In the unlikely event of a breakdown (such as due to cable fracture) driving is not interrupted for repair. A new cable can be easily fitted at the next driving interruption which may occur for hammer or chaser changes or when making an add-on.

Stress and Acceleration Measurements 2.5

It is relatively easy to measure both stress and acceleration as functions of time at a suitable point in the follower or pile. The results can be used to calculate. (a)

the total dynamic resistance (SRI))

(b)

the distribution of the resistance

(c)

the total energy entering the follower

(d)

the influence of gravity connectors

The theoretical basis of such calculations are outlined in paras. 2.8 to 2.12.

Background to the use of the measurements 2.6

When a pile is driven into the soil the soil/pile interface is subjected to a failure condition for each blow that achieves permanent set of the pile. It is apparent that this dynamic condition is, in some way, related to the ultimate capacity that the pile would have if it were tested immediately after the blow.

2.7

Considerable research has been carried out on relating the dynamic and static conditions and on measuring the dynamic resistance (Refs. 2 & 3). The contributions by the Goble group in Case Western University, Cleveland, Ohio and by TNO in Delft have been substantiated by well documented full scale load tests. A combined plot of their results is shown on Plate 1.

2.8

The passage down the pile of the stress wave generated by the hammer is resisted by any external frictional or bearing forces and is also greatly influenced by discontinuities in the pile. At any point in the pile material the stress wave generates acceleration, velocity and displacement, and each of these are basic but inter-related parameters. The accurate measurement of the stress, together with any one of the remaining three, uniquely defines the wave motion. Discontinuities and external forces generate reflected waves which return to the point of measurement after periods of time which are linear functions of their distances from the point.

2.9

Wave theory indicates that force, and hence stress, are related to velocity by an impedance function, see equation in Section 3. Thus measurements of stress and velocity made at a point on the pile when a compression wave passes can each be used to compute the "force-time" relationship. For a undirectional compressive wave the two relationships should be identical. However, velocity is a vector (has magnitude and direction) and stress is a

scaler (has magnitude only).

This means that any

compressive reflections of the wave arriving back at the point of measurement are interpreted as "force increases" by the stress readings and "force decreases" by the velocity. Therefore, by subtracting one force time relationship from the other, the reflecting components can be identified. Intergration allows the total dynamic resistance of the soil to be found. This method of analysis is called the impedance method. It should be noted that the soil is not modelled in the analyses and hence the computed soil resistance is "dynamic" rather than "static." to obtain the static resistance use has to be made of the results of correlative studies with pile load test.

2.10

An alternative method of analysis which assesses the static soil resistance, involves the use of a wave equation solution in an iterative cycle. The measured force-time profile resulting from a hammer blow can be used as the (input to) wave equation program. The iterative solution consists of progressive variation of the properties of the known soil profile until the measured acceleration-time function is matched.

2.11

Both methods involve assumptions on pile behaviour which have been substantiated by static load tests on piles elsewhere. This is the same situation which applies to all design methods such as API, but dynamic methods have the advantage of using data relating to the particular soil profile at the pile position. The impedance method, is relatively simple mathematically. This is the type of analysis used by TNO and in the CASE method. Dynamic pile capacity can, if required, be assessed on a per blow basis by this method by using a small micro-processor on site. The wave equation approach is more complex, requiring the use of extensive computing facilities, but it does permit more accurate modelling of the pile configuration and the soil conditions. In this type of solution consideration has to be given to the values of such soil parameters as quake and damping defining the stress-deformation-time behaviour of the soil/pile interface. However the analysis is relatively insensitive to these parameters and reasonable solutions will be obtained provided values grossly in error are not used. Ref. 4.

2.12

Present practice is to use acceleration and force measurements as the basis of this type of dynamic interpretation. The measurements are made by means of bolt-on sensors. Installation involves the drill and tapping of three holes approximately I in deep and 0.25 in diameter in the wall of the follower (or pile add-on). This is naturally done whilst the follower or add-on is idle, as is the fitting of the senors. The use of bolton sensors permits quick installation and their recovery on completion for post measurement recalibration.

"Stick-on" sensors are available for situations in which

drilling holes would have a detrimental effect on the structural integrity of a pile.

2.13

The sensors are connected to the conditioning and recording equipment by means of free hanging cables. Experience has shown that such cables do not influence the normal installation operations and have a lower risk of suffering significant damage than do armoured cables or telemetric systems.

APPENDIX V-4

INSTRUMENTATION FOR CONDUCTORS, PILES AND HAMMERS

2.14

All records are. stored on magnetic tape for subsequent analysis. During driving the force and acceleration signals are also displayed on a storage oscilloscope and facilities can be made available to make hard copies of individual records by means of ultra violet records. These act as a check on the overall electronics since the input signal for these devices could be derived from that stored on magnetic tape a fraction of a second earlier.

Scope of offshore and onshore interpretation 2.15 The possible scope of the data interpretation will be controlled by the extent of the measurements made and piling problems en-countered. The interpretation could include the following: (a)

Offshore

-

Presentation of driving records

-

Presentation of force-time and acceleration time curves for some blows

-

Hammer Efficiency as defined by hammer manufacturer on a per blow basis

-

Impedance type analysis of some blows can be done by use of a small computer.

The results of such analyses could include: (1)

overall efficiency of hammer

(2)

distribution of soil resistance

(3)

end bearing component of resistance

(4)

qualitative assessment of connector influence

(b)

Onshore

-

Production of a conventional post installation report including hammer efficiency effects, set up data etc.

-

Supplementing of above report by detailed analyses of selected blows using both the impedance and the wave equation based on analytical techniques.

-

Assignation of design capacities to piles.

- Conclusions on the piling and installation

techniques together with recommendations for possible future operations etc.

3

THE BENEFITS OF INSTRUMENTATION 3.1

The use of pile instrumentation is more likely to be justified (a)

in conditions in which hard driving is expected

(b)

on the initial platform of a multi platform field development

(c)

in "frontier areas" where there is little or no driving experience

(d)

on untried hammers or on piles with new types of connectors

(e)

on any very large project where potential savings on reduced installation time or material costs for foundations may be substantial.

In the following paragraphs the benefits of instrumentation during and after driving are described in detail.

Guidance during pile installation 3.2

In many situations piles are driven into a founding stratum, e.g. sand, hard clay or soft rock, whose upper horizon may vary in depth over the general area. The presence of this layer will be indicated by an increase in the blow count as the pile tip approaches and then enters it. Since a considerable proportion of the ultimate compressive capacity of the pile may be derived from end bearing it is reassuring to be able to prove that the rise in blow count noted is due to the presence of the founding stratum rather than to reduced hammer efficiency, increased cushion losses or high friction from the upper layers. The combined use of pile and hammer instrumentation can establish the actual situation. Shortly after completion of driving the measurements made on the pile could enable an assessment to be made offshore of the end bearing component of the dynamic soil resistance. This would prove whether or not the pile had penetrated into the founding stratum.

3.3

In the event of a significantly long interuption to driving, e.g. resulting from bad weather, set up may cause piles to refuse prematurely.

In these circumstances the use of

instrumentation will contribute towards determining the pile capacity and deciding whether it can be accepted.

The converse to this would arise if piles were to be driven to their maximum penetration at blowcounts much lower than expected. Doubts would then be raised as to the capacity of the piles. Re-drive tests would have to be performed after a suitable delay to show whether or not the piles had set-up. Instrumenting the hammer and pile will provide data before the set-up is broken. Without instrumentation it may not be certain that the hammer has "warmed-up" and is working efficiently before the blowcount starts decreasing.

3.4

Information on general hammer performance and in particular on cushion losses can be obtained by comparing the energy available at the ram with that transmitted to the follower.

Providing information on piles as driven 3.5

An assessment of the total resistance during the last few blows on a given pile will enable a capacity predicition to be made. If this is based on redrive data or if during it has been possible to assess set-up potential this must be at least as good as those made on the basis of empirical design rules using "undisturbed" soil parameters from adjacent locations, see paragraph 2.12. This would be particularly valuable in the event of premature refusal if the tensile capacity (which can be predicted from the wave equation type analysis of the pile measurements) governs the pile penetration. The reassurance of another capacity assessment would also be valuable where no marked increase in blow count is noted within the structural limit of driving range. Also revised operational requirements sometimes result in increased platform loadings some time after installation. If pile capacities higher than the original design capacities can be confidently assigned future extensive foundation modifications may be avoided.

3.6

The hammer efficiency measurements allow improved back analysis of the pile driving record to a soil resistance at the time of driving-depth profile. This provides a method of checking the soil profile used for pile design and drivability studies.

3.7

Any measurements made before and after a reasonable delay in driving caused by weather, mechanical breakdown etc, can be used to assess the set up behaviour. This can be used to predict the eventual pile capacity and the likely time taken to achieve this.

Providing information relevant to subsequent installation of other platform

3.8

The improved back analysis should allow much better predicitions to be made of the drivability of piles on other platforms in the field. This should lead to cheaper and quicker installation procedures than would otherwise be possible. This assumes that soil conditions are fairly uniform over the field.

3.9

Data on hammers and on drivability will confirm suitability of the hammers used and the general operating level of the hammers for use on future platforms.

Long term benefit 3.10

Data on hammers will eventually lead to improvements in their fatigue life, cushion characteristics etc.

3.11

Better data for back analysis will eventually lead to a better understanding of soil behaviour during driving and hence more accurate drivability predicitions.

3.12

The collection of basic data such as acceleration-time and stress-time can allow reanalysis at any time in the future with the most advanced analytical tools available at that time. This is particularly useful where jackets may be upgraded in the future to accomodate additional facilities.

REFERENCE S

I

SUTTON J.V.R. et al, " Full Scale Instrumented Pile Test in the North Sea " OTC (1979)

2

RAUSCHE, F.M. and GOBLE, G.G., "Soil Resistance Predictions from Pile Dynamics". Journal of Soil Mechanics and Foundations Division, ASCE, September 1972.

3

Institute TNO for Building Materials and Building Structures, "A Simple Method to Determine the Bearing Capacity of Foundation Piles". Report No. BI-78-2/64.1.2005, January 1978.

4

BOWLES, JE., "Analytical and computer methods in foundation engineering", Chapter 11, Mgraw-Hill, Inc., 1974.

PLATES Static Pile Capacity vs SRD

..

..

..

Plate No. I

FIGURE 1

APPENDIX V-5

CURVED CONDUCTOR AND GUIDE CONSIDERATIONS GULF OF MEXICO PREPARED BY SHELL OIL

CURVED CONDUCTOR & GUIDE CONSIDERATIONS GULF OF MEXICO

1.

To save field erection time in stabbing curved sections we preinstall precurved lead conductor sections in the jacket while in the fabrication yard to the extent launch weight and jacket buoyancy will allow. Precurving should be carried out on the bottom part of the conductor over a length at least equal to the design penetration to minimize loss of angle while driving the conductor. In as much as the conductor must be overbent and yield in order to permanently curve it, it's D/t should not exceed 1300/Fy as per API RP 2A for a compact section. Where lead sections are preinstalled in the jacket the guides supporting these must be designed for the weight, buoyancy, and slamming loads imposed during loadout, transport, and launch. The preinstalled conductor sections are tied off at the top conductor guides so as to support conductor weight once upended. This connection and supporting braces must be designed for the maximum hanging weight at the top prior to the conductors being self-supporting in the soil. Care should be taken when lifting conductors to cut off support lugs that conductors are not pulled back out of bottom guide. A larger than normal bell may be appropriate at the bottom guide to facilitate re-stabbing should this occur. Where lead sections are preinstalled bells are not normally required except as noted above unless desired to facilitate installing sections in the fabrication yard.

2.

Where conductor lead sections are not preinstalled or not preinstalled all the way to the mudline conductor guides, larger than normal guide bells may be desired based on tolerance obtained during bending, misalignment, etc. The guides should also be designed for the appropriate weight plus impact as the conductors are stabbed through the guides, considering the maximum expected misalignment. Our guide sleeves for curved conductors are fabricated to the same clearance as our guide sleeves for straight conductors, i.e., 0.500 inches all around. The guides are fabricated with the sleeve and bell at the angle build-up appropriate to its distance relative to the tangent point of the curve. Vertical gusset plates are provided to transfer any stabbing loads and friction loads along the axis of the sleeve into the support arrangement.

3.

Straight sections are normally added onto the precurved lead sections and lowered/driven into the soil. Permanent loads are developed inforcing these straight add-ons into the alignment of the guides and must be resisted by the guides and their supports. An estimate of these loads may be obtained using moment-distribution (Hardy Cross) or some equivalent method. Where appropriate a component of these loads should be applied along the direction of the sleeve axis. Inasmuch as our driving experience (soft soils) indicate blow counts the same or slightly higher than straight conductors there appears to be no need to include an extraordinary frictional driving resistance type load on the guides so long as the guides are normally designed for a reasonable vertical load.

4.

The conductor guides should of course be designed for the normal wave force loads on the conductors in addition to the deflection compatability loads noted in 3 above.

5.

Likewise, the deflection on compatibility loads (moment diagram) should be considered when designing the conductor.

M . P. Cornell July, 1976

REFERENCES

CURVED CONDUCTORS

1.

Coz, B.E., Drive Pipe Study for Shallow Hole Directional Drilling - 1970 General Lease Sale", Shell Oil Company, Southerneastern E&P Region, Construction Division, 1970.

2.

Fischer, F. J., "Driving Analysis for Initially Curved Marine Conductors", Shell Development Company, EPR 57-70-F, October, 1970.

3.

Cox, B. E., "Curved Well Conductors and Offshore Hydrocarbon Development", Shell Oil Company, Southern E&P Region, Offshore Division, Informal Contribution for Presentation at the 1974 Group Offshore Development Conference, September, 1974.

4.

Bradley, W. B., and Fontenot, J. E., "Estimate Field Wear from Lab Data", OJG, February 24, 1975. Although not specifically focused toward curved conductors this article discusses procedures for estimating field-wear rates in casing.

5.

Fischer, F. J., "Driving Analysis for Initially Curved Marine Conductors", Offshore Technology Conference Paper OTC 2309, May, 1975.

6.

Cox, B. E., and Bruha, W. A., "Curved Well Conductors and Offshore Platform Hydrocarbon Development", Offshore Technology Conference Paper .OTC 2621, May, 1976.

7.

Cornell, M. R., Curved Conductor and Guide Considerations, Gulf of Mexico; unpublished, July, 1976.

APPENDIX V-6

USE OF WAVE EQUATION FOR CURVED CONDUCTORS

ENGINEERING REPORT CURVED CONDUCTOR DRIVABILITY NORTH CORMORANT FIELD U.K. SECTOR, NORTH SEA

For:

SHELL U.K. EXPLORATION AND PRODUCTION

Report No:

U0227/A

Shell U.K. Exploration and Production, Shell Centre, London, SEl 7NA 25 th September, 1978 Attention:

Dr. A. Le Messurier

Dear Sirs, Conductor Drivability North Cormorant

We have pleasure in submitting our Engineering Report concerning the drivability of curved conductors at North Cormorant.

Mr. F.E. Toolan and Mr. M.R. Horsnell were Project Engineer and Staff Engineer respectively for this work.

We trust this report fulfills your requirements. If you have any questions do not hesitate to contact us.

Yours faithfully, FUGRO LIMITED

D.W. BIDDLE Director

Enc.

CONTENTS

LIST OF REPORTS SUMMARY 1.

INTRODUCTION

2.

SCOPE OF WORK

3.

SOIL CONDITIONS

4.

APPLICATION OF SHELL'S 2-D WAVE EQUATION PROGRAM TO DRIVING CONDITIONS AT NORTH CORMORANT

5.

ANALYSIS OF CURVED CONDUCTORS

6.

EFFECT OF CURVATURE TOLERANCE

7.

INSTALLATION OF CURVED CONDUCTORS AT NORTH CORMORANT

8.

REVIEW OF ANALYSES

9.

CONCLUSIONS LIST OF REFERENCES

APPENDIX A

NOTES RELATING TO THE RUNNING OF SHELL'S 2-D WAVE EQUATION PROGRAM i

NORTH CORMORANT PROJECT Bl LOCATION

This report is one of a set of reports concerning fieldwork, laboratory testing and engineering studies for the above Location.

Reports submitted to date are:Reference

Type of Report

Date Submitted

and Description

U0227

Engineering Report,

20th Mar. 1978

Curved Conductor Installation, North Cormorant Field, U.K. Sector, North Sea.

U0227/A

Engineering Report,

25th Sept. l978

Drivability of Curved Conductor, North Cormorant Field, U.K. Sector, North Sea.

U0283

Site Investigation Plan and

15th May, 1978

Preliminary Engineering Study

U0283/1

Field Report, May 1978 Survey

8th June 1978

U0283/2

Laboratory Testing Report

19th Aug. 1978

U0283/3

Engineering Report

to be issued

SUMMARY

It is proposed to install curved conductors from a jacket which will be placed at the North Cormorant location in the North Sea. This report presents the results of detailed drivability studies for the 30in. x 1in. curved conductors during installation using Shell's standard drill/drive techniques.

The work described within this Report was carried out under Phase II of the project to investigate the installation of curved conductors at North Cormorant. It should be read in conjunction with the report covering Phase I of the project, in which the general feasibility of installing the conductors was assessed.

The principal conclusions of this report are that driving stresses will be in the order of 38 ksi and that lateral forces on the guides will not exceed 20 kips. Discontinuities in the conductor string due to curvature tolerance would induce an additional lateral force on the guides which is not expected to exceed 6 kips.

The variation in soil conditions at the location is not expected to affect the conclusions and recommendations made within either Phase I or Phase II of this project.

1.

INTRODUCTION

1.1

At the request of Shell U.K. Exploration and Production, Fugro Limited have carried out engineering analyses concerning the drivability of curved conductors from a proposed production platform. The platform will be sited in the North Cormorant Field of the North Sea and will be supported on piled foundations. This Report presents the results of the analyses.

1.2

In this Report the terms Client and Shell refer to Shell U.K. Exploration and Production Ltd.

1.3

This project has been carried out in two phases. The first phase was concerned with the

method

of

installing

the

curved

conductors

at

North

Cormorant

with

recommendations being based upon analyses of straight conductors and driving records from previous conductor installations carried out by Shell in the North Sea. This work has been described in Report No. U0227, "Engineering Report - Curved Conductor Installation - North Cormorant Field - U.K. Sector, North Sea", issued to Shell on the 20th March, 1978 (Ref. 1). The second phase of the project, as reported here, has been concerned with more detailed analyses of the drivability characteristics of the curved conductors.

1.4

The majority of the analyses in this Report were made prior to soils information becoming available from the site investigation carried out by Fugro in late May 1978. It was agreed with the Client that the same soil data as in Phase 1 should be used, i.e. the soils information from Borehole 2, Cormorant Bl location, and that the work should be reviewed when additional soils data became available.

1.5

This report is based upon the following information supplied by the Client:a)

Conductor pipes of 30in. outside diameter with wall thickness of 1.Oin.

b)

Sixteen curved conductors would be floated out with the steel jacket. These conductors would have a curvature of 2.3°/l00ft from mudline (-528.2 ft) to 150.92 ft below mean sea lavel. Above -150.92ft the conductors would be straight. The conductor guide frames would be positioned during fabrication of the jacket on the same curvature of the conductor. Straight add-ons would be used during conductor installation.

c)

Driving to be carried out with either a Delmag D-55 or D-60 diesel hammer.

d)

Conductor guides at the following elevations relative to mean sea level:Guide

1

+ 85.30ft

(+ 26m)

Guide

2

+ 32.81ft

(+ l0m)

Guide

3

- 59.06ft

(- 18m)

Guide

4

-150. 92ft

(- 46m)

Guide

5

-242. 78ft

(- 74m)

Guide

6

-334. 65ft

(-102m)

Guide

7

-426. 51ft (-130m)

Guide

8

-518. 37ft

(-158m)

e)

Lateral stiffness of the guide frames of 720 kips/ft.

f)

Curvature tolerance of +12mm over any 16m length of conductor.

2.

SCOPE OF WORK 2.1

The scope of work was initially defined in a letter headed " Proposal for Drivability Analyses of Curved Conductor Pipes on the North Cormorant Platform, British Sector, North Sea", dated 2nd June, 1978. The order to proceed with the study was contained in a Variation of Contract document, ref. 77.74/012 Variation A, dated 6th June, 1978.

2.2

The scope of work was as follows:i)

Establish that Shell's computer program for analysing the drivability of curved conductors could adequately model the following:a)

diesel hammer characteristics

b)

transmission of stress wave along the conductor

c)

the dynamic soil/pile interaction for the soil conditions at the North Cormorant location.

ii)

For a 30in. diameter by lin. wall thickness conductor, having the design curvature specified by the Client (see section 1.5 (b) ), determine its drivability characteristics when driven by a Delmag D-55 diesel hammer operating at 90% efficiency.

iii)

Determine lateral forces induced on the conductor guide frames and the maximum stresses during driving with the Delmag D-60 diesel hammer for the following cases:a)

Conductor having design curvature at refusal conditions.

iv)

b)

Conductor having design curvature down to elevation -561ft (-171m) , i.e. 30 ft below mudline, followed by a build up in curvature of 1°/l00ft at refusal condition.

c)

As (b) but with a curvature of -2° /l00ft below -561ft.

Establish the effects that kinks, in the conductor string, due to the specified curvature tolerance, may have on the drivability characteristics of the conductor.

v)

Review all work carried out during Phase 1 and 2 in the light of the soils information obtained from North Cormorant during the site investigation carried out by Fugro Ltd during May 1978.

2.3

All computer analyses of curved conductors were carried out by Shell using their own program and their computer system in the Hague.

Input data and technical

support for the analyses was provided by Fugro Ltd.

2.4

The Client requested that details of all software modifications, and associated problems, should be included in this report, to assist Shell personnel with future analyses using their program. These details are contained in an appendix to this report.

2.5

It is Fugro' s normal practice to use SI units for calculations and for presenting results. However, for this study some data was in Imperial units, some in metric units and some in SI. For reasons of clarity, and to be consistent with previous reports the units in which the data was provided have been maintained in this Report.

This has resulted in a mixture of units. When the term tons, ton force or tf are used they always refer to metric tons of l000kgf.

Useful conversion factors are :1

tf

=

9.81 kN

10

m

=

33ft

1

tf

=

2.205 kips

3.

SOIL CONDITIONS

3.1

The soil conditions at Cormorant El location consist principally of overconsolidated clays. The shear strength profile is presented on Plate 1 and a plot of Plasticity Index versus depth is shown on Plate 2.

3.2

Using the shear strength profile shown on Plate 1 and the index properties of the soil, values for soil resistance at time of driving (SRD) had been previously obtained in Phase 1 of this project. Originally the SRD vs. depth relationship had been presented in terms of accumulated SRD. For reasons which will be explained later in this report, this relationship was converted into one of unit ultimate soil resistances vs. depth. This relationship is shown on Plate 3.

4.

APPLICATION OF SHELL's 2-D WAVE EQUATION PROGRAM TO DRIVING CONDITIONS AT NORTH CORMORANT 4.1

It was agreed between Fugro and Shell that all drivability analyses of curved conductors would be carried out using a two dimensional wave equation program developed within Shell by F.J. Fishcher (Ref. 2 & 3).

4.2

Fugro have had considerable experience in predicting the drivability characteristics of piles and conductors installed at a number of North Sea locations and in the development of specialised computer software to assist in these predictions. Based on this experience, Fugro have found that the main factors governing the effectiveness of any drivability program based upon wave equation theory are:i)

The ability of the program to model the peculiarities of the hammer type (i.e. steam, diesel or hydraulic modes of operation).

ii)

The way in which the dynamic soil/pile interaction is modelled.

iii)

The formulation of the difference equations arising from the partial differential equations describing the progress of the stress wave along the length of the pile.

In developing their own drivability program "WAVEQ", Fugro have carried out numerous back analyses based on driving records to ensure that these three items are dealt with realistically. Thus in assessing the potential of other drivability programs it is Fugro's practice to systematically check the way in which a program handles these three factors and to carry out comparative analyses with "WAVEQ".

4.3

Fischer's program has been written for the analysis of steam hammers, the driving force of which is almost entirely due to the falling ram, with a small additional force due to the steam up-lift pressure. The driving force of the diesel hammers to be used at North Cormorant has two components, i) the falling ram and ii) the explosive force which occurs due to compression of gases by the falling ram. It was agreed between Fugro and the Client that before any analyses of curved conductors was carried out it should be ensured that the program could realistically model the driving characteristics of a diesel hammer.

4.4

Information available from the Client regarding the method of solution incorporated within the program did not adequately describe the method by which dynamic soil/structure interaction was modelled. Reference was made to a "viscous damping coefficient", but no recommendations given as to how this coefficient could be obtained from any available soils information. It was agreed between Fugro and the Client that before any analyses of curved conductors were carried out it should be ensured that realistic values for this coefficient could be determined from North Cormorant soils information.

4.5

Fugro informed the Client that in addition to ensuring that both the hammer and the dynamic soil/ pile interaction could be adequately modelled, the formulation of the partial differential equations describing the behaviour of the stress wave along the length of the curved conductor should be verified. It is not within the scope of this report to detail the derivation of these equations, however the partial differential equations describing both one-dimensional and two-dimensional wave equation theories are shown, for comparison, on Plate 4.

4.6

No alternative two-dimensional wave equation program was readily available which could be used to calibrate Shell's program for the factors listed in paragraph 4.2 and the input parameters of North Cormorant. However, Fugro had already carried out drivability analyses for straight conductors, driven by a Delmag D55 diesel hammer, during Phase 1 of the project using their own one-dimensional wave equation program WAVEQ.

It was therefore decided to repeat these analyses using Shell's two-

dimensional wave equation program, for a 30in. diameter by 1 in. wall thickness conductor having a curvature of 0.6 x 10

-7

degrees/ 100ft ( Λ = 1.0

-10

), i.e. over the

length considered the conductor could be considered to be virtually straight.

The

conductor make-up is shown on Plate 5.

4.7

In the analyses using Fischer's program the diesel hammer was modelled using his "Type III" hammer. The idealization of this hammer as a spring-mass system is shown on Plate 6. It is Fugro's standard practice to model all offshore pile driving hammers as a two mass, one spring system. The two masses model the ram and a combined pile cap and cap-block.

The spring models the stiffness of the pile cap.

For diesel

hammers a buffer force equal to the explosive force of the hammer is applied immediately after the ram strikes the cap-block.

4.8

To adapt Fischer's "Type III" hammer to model the Delmag D55 diesel hammer as modelled by Fugro the following hammer characteristics were used:-

Weight of ram

=

12.15 kips

Weight of helmet

=

3.02 kips

Steam uplift force

=

562.5 kips (i.e. the explosive force of the hammer)

Velocity at impact

=

25.l6ft/sec.

Spring stiffness helmet to ram(AKHR)

=

1.37 x 10 5 kips/ft.

Coefficient of restitution helmet to ram

=

0.75

=

1.1 x 1019 kips/ft

(E:HR) Spring stiffness pile to helmet (AKPH)

The effectiveness of this hammer model can be seen from the results presented on Plate 7. This shows the stress/time history immediately beneath the hammer computed by both Fugro's and Shell's (i.e. Fischer's) programs. The comparison was such that It was concluded that Shell's program could be adapted to model diesel hammers.

4.9

In the analyses carried out using Shell's program the dynamic soil/pile interaction was modelled using the same soil damping coefficients as used in Fugro' s program during the drivability analyses of Phase 1 of this project. These were:Side damping coefficient (CLAY) = 0.2 sec/ft. Soil tip damping coefficient (CLAY) = 0.0l sec/ft.

The effectiveness of these parameters in Shell's program can be seen from the results shown on Plates 8 to 10. Plates 8 and 9 show the comparison between the stress/time histories obtained from both Shell's and Fugro's programs for conductor elements located at the mudline and 90ft. below the mudline. Plate 10 shows the comparison between the blow count resistance curves obtained from the two programs. From these results it was concluded that Shell's program could effectively model the dynamic soil/pile interaction at the North Cormorant location.

4.10 The comparison between the stress/time histories shown on Plates 7 to 9 also show that the transmission of the stress wave along the conductor is being modelled realistically by Shell's program.

4.11 Following discussions between Fugro and the Client, it was agreed that the results of the analyses detailed in this section of the report indicated that Shell's program could adequately model straight conductors at the North Cormorant location, and that there was no reason to doubt that it would be able to adequately model curved conductors at the same site.

5.

ANALYSIS OF CURVED CONDUCTORS 5.1

In the first set of analyses the 3Oin. diameter by 1in. wall thickness conductor was modelled with its design curvature and a Delmag D55 diesel hammer. The conductor make-up is shown on Plate 11. The only section of the conductor string which has an inbuilt curvature of 2.30/l00ft. is that which will be floated out with the structure i.e. between guide frames 4 and 8.

The length of conductor above this section is

considered to be made up of sections which are initially straight and are threaded through the guide frames.

Dynamic soil/pile interaction was modelled using the

parameters described in section 4.9.

The soil resistances during driving were

obtained from the relationship shown on Plate 3.

5.2

For the analysis of curved conductors an important parameter is the lateral spring stiffness of the soil. Only realistic modelling of these springs will ensure realistic distribution of stresses and shear forces. To obtain these values, P-Y curves were generated for the 3Oin. diameter pile, using the methods described in Ref 4. and 5 and are tabulated on Plate 12. These curves represent the relationship between the soil resistance experienced by a pile (P-values) for lateral movements of the pile (Yvalues).

5.3

In general, the lateral displacements of a curved conductor during the duration of one blow of the hammer will be relatively small. It was assumed that this displacement would not exceed the displacements at which peak soil resistances would occur. Using this assumption, values for lateral spring stiffnesses were obtained from the slope of the curve between zero and peak resistances. The relationship between lateral spring stiffness and depth is shown on Plate 13.

5.4

The results of the drivability analyses are shown on Plate 14.

This shows the

resulting drivability curve and compares it with the drivability curve of similar straight conductors analysed in Phase 1 of this project. It can be seen that refusal occurs at a soil resistance of 9000kN compared with l0000kN for the straight conductor.

5.5

To investigate the effects that the curvature would have on the guide forces and stresses in the conductor, the analysis at refusal conditions was repeated with the Delmag D55 hammer being replaced by a Delmag D60. Although this hammer would give easier driving the resulting stresses and shear forces would be higher.

5.6

The results of this analysis are shown on Plates 15 and 16. Plate 15 shows the distribution of shear force between the top of the conductor and the mudline. From these results the forces on the guide frames were obtained by equating their values to the change in shear force occurring across each guide. As can be seen from the results, the maximum guide-frame force was found to be 12.05 kips occurring at the 5th guide. The maximum stress during driving was found to be a compressive stress of 38.1 ksi occurring at the fourth guide frame, i.e. the transition point between straight and curved sections of the conductor string. The stress/time history at this point is shown on Plate 16.

5.7

To investigate the effects of deviation of the conductor from its designed curvature, two further analyses were carried out. In the first of these analyses, the conductor was considered to have its design curvature down to a depth of -561ft (30ft below mudline) followed by a build up in curvature of 1º /l00ft. down to the tip of the conductor. The analysis was carried out at refusal conditions for a Delmag D60 hammer.

The results of this analysis are shown on Plates 17 This shows the distribution of shear force from the top of the conductor to the mudline. From this distribution it was found that the maximum shear force was 17.2 kips occurring at the 8th guide. The maximum stress was found to be 38.1 ksi occurring at the fourth guide frame. The stress-time history for this location was found to be almost identical to that shown on Plate 16.

5.8

In the second additional analysis the conductor was modelled with its design curvature down to -561ft. (30ft below mudline) followed by a curvature of -2° /l00ft. Again a D60 hammer at refusal conditions was modelled. The results of this analysis are shown on Plate 18. This shows the distribution of shear force from the top of the conductor to the mudline. From this distribution it was found that the maximum shear force was 14.9 kips occurring at the 8th guide. The maximum stress was found to be 38.1 ksi occurring at the fourth guide frame. The stress-time history for this location was found to be almost identical to that shown on Plate 16.

5.9

Following discussions with the Client, it was decided that the sensitivity of guide forces to changes in guide frame stiffness should be investigated. Two analyses were carried out in which the original guide frame stiffness of 720 kips/ft was increased to 7200 and 72000 kips/ft. The results of these analyses showed that the maximum guide force for each of these values were 17.2 kips and 18.2 kips respectively, and that in both cases they occurred at guide 8.

The shear force

distribution between top of conductor and mudline for the stiffness of 72000 kips/ft is shown on Plate 19. The distribution for 7200 kips/ft was found to be almost identical.

6.

EFFECT OF CURVATURE TOLERANCES 6.1

The Client informed Fugro that the tolerance for curvature of the pre-curved conductors to be installed in the jacket prior to float-out would be ± 12mm over a 16m length of conductor. The effect of this tolerance is shown on Plate 20. If the welding on of the next conductor section is such that the overall curvature of the conductor string is maintained a "kink" in the conductor will result.

6.2

During driving, the stress-wave will pass down the conductor and, as long as any changes in curvature are achieved by a smooth transition, the resulting guide frame forces will be as detailed in section 5.0.

However, if a "kink" or sharp change in

curvature is encountered then an additional lateral force will be generated due to the change in direction of the stress wave passing through the conductor.

6.3

For the curvature tolerance of paragraph 1 the angle of deviation (see Plate 20) is of the order of 0.1º The maximum effect such a kink would have would occur when it was located at the point of maximum stress. It has been shown that the maximum stress during driving is 38.1 ksi i.e. an axial compressive force of 3473 kips for a 30in. diameter by 1in. wall thickness conductor. The additional lateral force will be given by the relationship :-

Thus for the conductors at North Cormorant one would expect an additional lateral force of 6 kips due to a kink located at the fourth guide frame. The effect of the kink at other elevations would be less than this value.

7.

INSTALLATION OF CURVED CONDUCTORS AT NORTH CORMORANT

7.1

During Phase 1 of this project, a back analysis was carried out using driving records from conductor installations at Dunlin, where similar soil conditions to those at North Cormorant had been encountered. From the results of this back analysis it was apparent that the drill-drive procedure adopted at Dunlin generally inhibited the development of skin friction along the length of the conductors, and that the generalised relationship between soil resistance at time of driving and depth of penetration was as shown on Plate 21. It can be seen from this relationship that beyond the initial drive into virgin soil (necessary to form a seal to avoid washout at the mudline) no significant build up in soil resistance occurs with depth. Where resistance has built up, it is due to tip resistance resulting from the conductor reaching the bottom of the predrilled pilot hole. This resistance is destroyed on drilling out the next pilot hole.

7.2

There are two possible explanations for the fact that soil friction on the side of the conductor does not generally increase as the conductor is driven deeper These are:i)

The conductor driving shoe opens up the pilot hole from 26in. diameter to a diameter greater than that of the conductor. This is shown schematically on Plate 22. Under these conditions side friction will be low even if the conductor is curved, because both the conductor and the oversize hole will follow identical paths.

ii)

An oversize pilot hole is produced during the drilling operation. This is shown schematically on Plate 23.

7.3

For curved conductors, the more critical situation will occur if friction is low because the pilot hole is drilled oversize. A straight vertical oversize hole would offer no resistance to a straight vertical conductor, but considerable resistance to a curved conductor. The magnitude of the resistance would increase with curvature. Driving records from Dunlin have shown that some of the straight conductors built up curvature during installation. In some cases this curvature was as high as 2.2º /100ft resulting in a lateral movement at the tip of the conductor of 4ins. over a length of pilot hole of 40ft. To achieve this deviation without any significant build up in side resistance would require an oversize pilot hole of at least 34in. diameter.

7.4

To achieve successful installation of the conductors at North Cormorant, it should be ensured that the amount of soil resistance mobilised by the conductor at the required setting depth does not cause hammer refusal. Drivability analyses carried out during Phase 1 of this project had shown that a Delmag D-55 diesel hammer operating at 90% efficiency could only drive a 30in. diameter by 1in. wall thickness straight conductor to the required setting depth of 120m against 20% of available side resistance. The available side resistance in the outside skin friction during driving which would be experienced by the conductor if it was driven into virgin soil, i.e. no pilot hole. Thus based on the analysis of straight conductors, the limiting criteria for installation of curved conductors at North Cormorant is that during penetration down the pilot hole no more than 20% of the available side resistance should be mobilised.

7.5

As discussed in paragraph 7.3, records from Dunlin had shown that the pilot hole diameter could be opened up to as much as 34in. As a conservative approach a 32in. diameter pilot hole was considered, and it was shown that for a conductor having a curvature of 2.30/100ft entering the pilot hole with a drop-off at 0º, 1º and 2°/100ft., 20% of the available side resistance would be mobilised at depths of 45.5ft., 37ft., and 33.5ft. respectively (see Plates 23 to 25). It was therefore recommended during Phase 1 of this project that to ensure successful installation of the curved conductors at North Cormorant, drives should be limited to 30ft., and that drill-outs lengths should be more than 30ft. but less than 35ft.

7.6

Results of the drivability analysis of conductors with the design curvature being driven by a Delmag D55 hammer at 90% efficiency showed that refusal conditions would occur at a soil resistance of 9OOOkN (see Plate 14).

This represents 18% of

7.6

Results of the drivability analysis of conductors with the design curvature being driven by a Delmag D55 hammer at 90% efficiency showed that refusal conditions would occur at a soil resistance of 9000kN (see Plate 14). This represents 18% of available soil resistance at the setting depth.

7.7

Reference to the results relating mobilised soil resistance to penetration down the pilot hole (Plates 23 to 25) showed that for a 30in. diameter conductor having a curvature of 2.30/100ft with a drop-off of 0º, 1º and 2º /100ft the corresponding depths of penetration to mobilised 18% of available soils resistance would be 42.5ft., 35ft and 31.5ft.

7.8

It is concluded that the recommendations regarding length of drives made during Phase I of this project are still valid, i.e. drives should be limited to 30ft. All other recommendations made during Phase I regarding installation procedure are unaffected by the results of the analyses carried out during Phase II

8.

REVIEW OF ANALYSES

8.1

All analyses carried out to date and reported in Sections 4 to 7 of this Report have been based on soils data from Borehole 2 carried out at Cormorant B1 location. Soils data available from the site investigation carried out during May 1978 has shown that the soil conditions at Boreholes 3 and 4 at the B1 location are similar to those at Borehole B2, all three profiles being composed principally of over-consolidated clays.

8.2

Both Borehole 3 and Borehole 4 were taken to a depth of 60m. It was therefore impossible to calculate setting depths at the locations of these boreholes or to compute soil resistances at time of driving below 60m.

However, comparison of the soil

conditions at Boreholes 2, 3 and 4, based on the results of laboratory tests and field observations, does not indicate that the driving recommendations, put forward in the Report covering Phase 1 of this project, should be modified. The comparison has also shown that the driving stresses and conductor guide forces presented in this report will be unaffected by the variation in soil conditions between the boreholes.

9.

CONCLUSIONS 9.1

The principal conclusions of this report are:-

1)

The maximum driving stress encountered in driving curved conductors will be in the order of 38 ksi.

2)

Lateral forces on the guide frames are not expected to exceed 20 kips. The effect of kinks in the conductor string due to the specified curvature tolerance will produce an additional lateral force of the order of 6 kips.

3)

The driving recommendations presented in the Report covering Phase 1 of this project are unaffected by the variation in soil conditions between Borehole 2 and Boreholes 3 and 4, i.e. drives should be limited to 30ft and drill out lengths should exceed 30ft but be less than 35ft.

REFERENCES

1.

FUGRO LTD., "Engineering Report - Curved Conductor Installation - North Cormorant Field U.K. Sector, North Sea", March 1978.

2.

FISCHER, F.J., "Driving Analysis for Initially Curved Marine Conductors," Shell Technical Progress Report EPR 54-70-F, October 1970.

3.

FISCHER, F.J., "Driving Analysis for Initially Curved Marine Conductors," Offshore Technology Conference, Paper 2309, 1975.

4.

MATLOCK, H., "Correlations for Design of Laterally Loaded Piles in Soft Clay", Offshore Technology Conference, Paper 1204, 1970.

5.

REESE, L.C., COX, W.R., and KOOP, F.D., "Field Testing and Analysis of Laterally Loaded Piles in Stiff Clay", Offshore Technology Conference, Paper 2312, 1975.

Appendix A

NOTES RELATING TO THE RUNNING OF SHELL's 2-D WAVE EQUATION PROGRAM

A. 1

It was found that the value for lateral stiffness of the guide frames was not set to zero prior to reading in its value from a new data. Thus when two analyses were carried out in the same run file it was found that the stiffness accumulated from the first to the second. The program was modified to set the stiffness to zero at the start of each analysis.

A.2

As written the program only produced values of stress, shear and torque at specified locations, with a limitation of only six location and only if the variable NOWRIT was set to 2. The program was modified to output shear forces for all modes at the end of the analysis. This information enabled guide forces to be calculated.

A.3

The "transition point" referred to in the program documentation relates to the point in the conductor string above which the conductors were originally straight. These conductors are then bent to the specified curvature above the transition point in a static analysis carried out prior to the drivability analyses. The computed stresses due to bending plus stresses due to weight of hammer form the initial stress conditions prior to driving.

A.4

It was found that if the transition point was located at the same mode as a guide, then the lateral stiffness of the guide would be ignored.

A.5

The program as written could not be used to model small changes in curvature, such as those due to kinks as any section of conductor had to be composed of at least 5 segments.

A.6

To obtain sufficient data to produce a plot of soil resistance at time of driving against depth then the soil resistances along the length of the conductor had to be factored. This was achieved by varying the perimeter lengths which forms part of the input data.

A.7

The program as written does not output the soil total resistance corresponding to the blowcount output at the end of the analysis.

A.8

For the soil conditions at Cormorant B1 location, the forces induced on the guides were found not to be sensitive to changes in lateral stiffness of the soil, even when these changes were in the order of several magnitudes.

PLATE 1 VARIATION OF MEASURED SHEAR STRENGTH WITH DEPTH

PLATE 2 VARIATION OF PLASTICITY INDEX WITH DEPTH

PLATE 3 VARIATION OF UNIT SOIL RESISTANCE AT TIME OF DRIVING WITH DEPTH

PLATE 4 GOVERNING PARTIAL DIFFERENTIAL EQUATIONS FOR 1-D AND 2-D WAVE EQUATION THEORY

PLATE 5 CONDUCTOR MAKE-UP STRAIGHT CONDUCTORS

PLATE 6 HAMMER IDEALIZATION

PLATE 7

PLATE 8

PLATE 9

PLATE 10 SOIL RESISTANCE AT TIME OF DRIVING VS BLOW COUNT

PLATE 11 CONDUCTOR MAKE-UP FOR CURVED CONDUCTORS

PLATE 12 P-Y DATA FOR 30 INCH DIAMETER CONDUCTOR

PLATE 13 VARIATION OF LATERAL SOIL STIFFNESS WITH DEPTH

PLATE 14 SOIL RESISTANCE AT TIME OF DRIVING VS BLOWCOUNT

PLATE 15

PLATE 16

PLATE 17

PLATE 18

PLATE 19

PLATE 20 FORMATION OF 'KINK' IN CONDUCTOR STRING DUE TO CURVATURE TOLERANCE

PLATE 21 SOIL RESISTANCE DURING GENERALISED DRILL-DRIVE SEQUENCE

PLATE 22 MECHANISM DUE TO CONDUCTORS PRODUCING OVERSIZE PILOT HOLE

PLATE 23 MECHANISM DUE TO DRILLING OVERSIZE PILOT HOLE

PLATE 24 MOBILISED SRD VS DEPTH OF PENETRATION FOR VARIOUS DIAMETER PILOT HOLES WITH 0º DROP-OFF

PLATE 25 MOBILISED SRD VS DEPTH OF PENETRATION FOR VARIOUS DIAMETER PILOT HOLES WITH 1º DROP-OFF

PLATE 26 MOBILISED SRD VS DEPTH OF PENETRATION FOR VARIOUS DIAMETER PILOT HOLES WITH 2º DROP-OFF