Deep Water Drilling Guidelines

Document Number: WEMS-01-A10 Date: October 2002

DEEP WATER DRILLING GUIDELINES

Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01 Page 1 of 49


RECORD OF AMENDMENTS

Rev. No. Description of Changes By



Executive Summary Drilling in deepwater, particularly when the metocean environment is harsh, is a high cost, high risk activity compared with drilling a conventional well. The increase in both technical and financial risk means that more careful, lengthy and detailed planning is required for most stages of the process. The location, weather, water depth, and resulting equipment requirements, rig capability, and operating procedures make detailed well planning complex and crucial. The shortage of capable rigs (limited world wide availability) and equipment for such a demanding operation further extend the planning lead times, and increases the risk of large cost overruns. Experienced contractors are vital. With high rig rates, complex (technically high risk) environment and a high risk of wait on weather in harsh environments, smooth operations using swift and simple procedures to reach total depth are the key to success. A minimal number of trips, and a simple casing design, must of course be balanced against managing the hazards detailed in this document. Effective characterisation of the metocean environment for rig operability and engineering design assessment will be necessary in harsh environments- this will require on-location current profile measurements. Whilst some technical issues are generic to deepwater, most are location specific; and the combination of a harsh metocean environment with deepwater leads to a step change increase in complex engineering design and operation considerations, extensive data requirements, planning lead times, costs, and rig availability. On the other hand, local subsurface conditions can present great challenges of their own: a key example being the Gulf of Mexico. This document is split into two parts, in order to capture both the location dependent nature of deepwater drilling and the key technical issues. The first chapter reviews the major worldwide locations and highlights the key technical concerns for each, which are cross referenced to the following chapter, which deals with these issues in detail. This second, technical chapter covers the problems and also the engineering methods, operational procedures and planning requirements to effectively manage these problems.



Table of Contents 1 INTRODUCTION ......................................................................................................................................... 5

2 WORLDWIDE DEEPWATER DRILLING ACTIVITIES ......................................................................... 6 2.1 INTRODUCTION ...................................................................................................................................... 6 2.2 LOCATIONS OF MAJOR DEEPWATER DRILLING ACTIVITIES .................................................................. 6

3 TECHNICAL ISSUES ................................................................................................................................. 9 3.1 PORE PRESSURE PREDICTABILITY ....................................................................................................... 9 3.2 SHALLOW HAZARDS TO BE INVESTIGATED AND ASSESSED BY SITE SURVEY ..................................... 9 3.3 METOCEAN DATA GATHERING REQUIREMENTS ................................................................................. 13 3.4 RIG SELECTION ................................................................................................................................... 15 3.5 SUBSEA AND SUBSURFACE ENGINEERING DESIGN AND EQUIPMENT ............................................... 20 3.6 RIG OPERATIONS PLANNING............................................................................................................... 36 3.7 TENDERING FOR ENGINEERING DESIGN COMPANIES WITH SIGNIFICANT HARSH ENVIRONMENT DEEPWATER EXPERIENCE .................................................................................................................. 45

4 KEY REFERENCE DOCUMENTS ......................................................................................................... 47

5 ABBREVIATIONS..................................................................................................................................... 48



1 INTRODUCTION This document is one of a series of documents within the Well Engineering Management System intended to provide Assets with a reference to best practice technical information relating to various areas of well engineering. The information will allow Assets to make informed decisions during both the design and operational stages of projects. In addition, Assets will have a better understanding of important issues and therefore know what to ask the experts when the need arises (i.e. to be informed buyers of these services).



2 WORLDWIDE DEEPWATER DRILLING ACTIVITIES

2.1 Introduction Drilling in deepwater, particularly when the metocean environment is harsh, is a high cost, high risk activity compared to drilling a conventional well. The increase in both technical and financial risk means that more careful, lengthy and detailed planning is required for most stages of the process. The location, weather, water depth, and resulting equipment requirements, rig capability, and operating procedures make detailed well planning complex and crucial. The shortage of capable rigs (limited world wide availability) and equipment for such a demanding operation further extend the planning lead times and risk of large cost overruns. Experienced contractors are vital. With high rig rates, complex (technically high risk) environment and a high risk of wait on weather in harsh environments, smooth operations using swift and simple procedures to reach total depth are the key to success. A minimal number of trips, and a simple casing design, must of course be balanced against managing the hazards detailed in this document. Effective characterisation of the metocean environment for rig operability and engineering design assessment will be necessary in harsh environments- this will require on-location current profile measurements. Whilst some technical issues are generic to deepwater, most are location specific; and the combination of a harsh metocean environment with deepwater leads to a step change increase in complex engineering design and operation considerations, extensive data requirements, planning lead times, costs, and rig availability. On the other hand, local subsurface conditions can present great challenges of their own: a key example being the Gulf of Mexico.

2.2 Locations of Major Deepwater Drilling Activities

2.2.1 List of Locations

The key locations of major deepwater drilling activity are as follows: Atlantic Margin (UK, Ireland, Faeroes) & Norway Gulf of Mexico Brazil Mediterranean West Africa Other locations include South East Asia, Australia, Caribbean and the

Caspian.

2.2.2 Location Review and Specific Technical Issues

Technical issues of major concern are highlighted below for each major deepwater drilling location. In each case, the relevant section of Chapter 2 is cited. Chapter 2 provides the technical information on each issue.

Atlantic Margin (UK, Ireland, Faeroes) & Norway (deepwater)

BG are operators of Tranche 19 (which is to be relinquished), and have JV interests in West of Ireland and Faeroes White Zone (but T53 West of Hebrides is to be relinquished). The rig market particularly tight in this region. Very severe metocean conditions require very high spec vessels. Rig rates as a result are very high. The region is largely exploration territory with the exception of Foinaven/ Schiehallion.


Document Number: WEMS-01-A10 Date: October 2002 Technical issues that are regarded as being of particular relevance to this region are:

Rig availability Rig rates Riser VIV (vortex induced vibration) management Station keeping and marine engineering Hydrate formation in drilling fluids Geotechnics Shallow water flows

Technical sections in this document of particular relevance are: 2.1, 2.2, 2.3, 2.4, 2.5, 2.6, 2.7

Gulf of Mexico

BG have no current interests in this area. This area has a largely benign metocean environment (although conditions are location dependent), except for hurricanes and loop currents. The area is mature, with most key prospects licensed. Activity levels are high, and even bucked the low oil price. Many large field developments exist and are planned. Technical issues that are regarded as being of particular relevance to this region are:

well control shallow water flows casing design geotechnics loop currents

Technical sections in this document of particular relevance are: 2.1, 2.2, 2.5 (Conductor Design, Casing Design, Well Control), 2.6

Brazil

BG have a prospective Campos Basin play, and possibly Argentina. The rig market is particularly tight as the region moves to open competition. The area has a harsh metocean environment, particularly with regard to currents. The complexity of the current layers makes VIV management a great challenge. Soil conditions are particularly weak in some locations. Significant field developments exist. Technical issues that are regarded as being of particular relevance to this region are:

geotechnics riser VIV management rig availability

Technical sections in this document of particular relevance are: 2.1, 2.2, 2.3, 2.4, 2.5, 2.6, 2.7

Mediterranean

BG have interests and activities in Egypt, Palestine and Israel; and are a key player. The area has benign metocean conditions and no significant subsea currents. There has been a


Document Number: WEMS-01-A10 Date: October 2002 recent subsea blowout in the Adriatic. Technical issues that are regarded as being of particular relevance to this region are:

geotechnics well control

Technical sections in this document of particular relevance are: 2.1, 2.2, 2.5 (Conductor Design, Casing Design, Well Control), 2.6

West Africa

BG have no plays in this area. The area has benign metocean conditions. Significant field developments exist. Activity is increasing. Further opportunities do nevertheless exist.

Technical issues that are regarded as being of particular relevance to this region are:

riser wear Technical sections in this document of particular relevance are: 2.1, 2.2, 2.6 (Shallow Hazards)

Other Locations

BG are considering prospecting Makassar Straits (fairly harsh environment) and also the Caribbean (benign environment). Technical sections in this document of particular relevance are: 2.1, 2.2, 2.5 (Conductor design if soil conditions poor), 2.6 (Shallow Hazards) And in addition for Makassar: 2.3, 2.4, 2.5, 2.6 (Riser Management), 2.7



3 TECHNICAL ISSUES

3.1 Pore Pressure Predictability A key risk to drilling activities is the inherently small margin between pore and fracture pressure in deepwater, particularly in shallow sections. In deeper sections this margin is on the other hand expected to be significantly greater for example on the Atlantic Margin than in the G.o.M. where Shallow Water Flows (SWFs) are a particular problem. Overpressures often occur in deepwater sandstone turbidites with shales; high deposition rates lead to a shallow top to the zone (see later section for SWFs). The likelihood is further increased by laterally connected fan turbidites with a significant dip to give a pressure differential. The typical deepwater combination of shallow overpressure plus no logs near surface means that pore pressure prediction using compaction trends is difficult. Velocity / porosity logs are normally taken in intervals below 5000ft. Obviously a geotechnical soil boring operation would provide much more information, if geotechnical concerns (soil integrity and slope stability for conductor placement) justify the cost. Seismic velocity data (conventional 3D and HR site survey) is really the only data (certainly for shallow sediments) available to infer porosity and hence compaction (Eatons Equation), in the absence of suitable sonic logs on offset wells. The normal compaction trend assumption leads to errors in deepwater that dwarf seismic velocity errors. Above 5000ft there is nevertheless a large error in using seismic velocity. Seismic velocity data can under predict pore pressure. There are forms of overpressure to which seismic velocity is not sensitive, e.g. additional source maturation rather than a fluid retention mechanism. Such insensitivity is also inherent in conventional log interpretation methods. BG and Advantica have studied Deepwater Pore Pressure prediction methods for their Trinidad operations, and it is recommended that such studies should be carried out for future wells, using the methodology developed in the work for Trinidad. BP claims to get round problems of lack of offset data leading to pore pressure under prediction by relating velocity to effective stress, temperature, and lithology- with this method, calibration with offsets is not needed. This method is better than just assuming a shaly lithology, but if the lithology is unknown this method is of questionable value. DEA Project 119 (Knowledge Systems Inc) is currently investigating pre-drill deepwater pore and frac pressure prediction. A UK based project run by Durham, Newcastle and Heriot-Watt Universities: GeoPOP (Geoscience Project Investigating Overpressure) has been underway since 1994, to be completed 2001. BG are members. Real-time pore pressure prediction and its use in modifying Well Plans is treated in the Rig Operations section.

3.2 Shallow Hazards to be Investigated and Assessed by Site Survey

3.2.1 Introduction

Various deepwater shallow hazards are given below as a checklist for analysing the data provided by site surveying methods. Their means of identification are indicated. The impact of these hazards on well design and operational procedures is discussed in more detail in the Casing Design section and particularly in the Rig Ops section. As indicated above, deep soil boring would provide final confirmation. Use of G&G personnel and existing industry data is key to the identification and risk analysis of the hazards detailed below. Many of the hazards exist as thin layers, which cannot be Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01 Page 9 of 49

Document Number: WEMS-01-A10 Date: October 2002 detected using seismic velocities, but can be hinted at by amplitude effects and seismic character. 3D seismic can indicate potential risk areas to be avoided. The localised shallow survey to 1000 ft would identify more details. See previous section on the 3D seismic data, regarding overpressure prediction.

3.2.2 Shallow Water Flows

These are overpressured sands normally in the first 600ft of sediment (but are situated at depths of 900 to 2000 ft in the Gulf of Mexico) below mudline.

Detection Methods

High resolution ((HR) seismic and 3D seismic top data reinterpretation Offset well data Combined with geological history and shallow geology knowledge

Characteristics

invisible to seismics if no free gas is associated structural indicators rather than attributes / amplitude upthrust zone with trap above Fugros method of Seismic Inversion indicates whether shale or sand, and

therefore trap potential Drilling and cementing procedures are given in the Drilling Operations section.

3.2.3 Shallow Gas

Shallow gas may be encountered due to underlying gas zones combined with vents, mud volcanoes or faults. It may also be entrapped in the form of in-situ hydrates. High resolution 3D seismic (acquisition times have in recent operations been reduced down from 23 to 5 days) can be used to predict shallow gas (it appears that it is no longer technically necessary to conduct a shallow gas survey in addition to 3D seismic but Local Government bodies may insist on a shallow survey to back up the 3D seismic). Standard shallow seismic will be shot in the locality when the target has been selected. Shallow gas escaping at the seabed will be seen as pock marks on 3D seismic. Drilling and cementing procedures are given in the Drilling Operations section.

3.2.4 In Situ Hydrates

Naturally migrating gas may form a hydrate layer at shallow depths below the mudline due to ambient low temperatures and high pressures.

Detection methods

2D seismic may indicate any presence, but this needs to be checked with 3D and HR seismic data. The information provided from drop cores is only very shallow, but if they do not explode during recovery this implies the absence of hydrates within 3m of the surface.

Characteristics

In situ hydrates give rise to an anomalous acoustic reflector parallel to the seabed (Bottom Simulating Reflector). A BSR is thus an indicator, not a proof of presence. No clear BSRs


Document Number: WEMS-01-A10 Date: October 2002 have so far been detected West of Shetland (there is a far greater danger in West of Africa and Barents Sea). Norways 15th Licence Round (800m to 1,600 m WD) areas have reported hydrate destabilisation. On the other hand, for a BSR to show up on seismic, large volumes of free gas must be accumulated beneath the hydrate layer. Fractures and faults may have allowed the methane to escape. Such a situation is admittedly more likely in a tectonically active area. Evidence of fluid escape structures may indicate in-situ hydrates or even a geopressured aquifer. With in-situ hydrates, the original fear that pressurised free gas builds up under the hydrate cap appears to be not realistic. Obvious dangers come from resulting seabed instability and gas release. Even then in-situ hydrates are not usually a cause of wellbore failure, but gas in wellbore stops zonal isolation as it creates channels in the cement sheath. Cement with low hydration heat is desirable, and also cement that prevents gas migration. Another danger is that the presence of in-situ hydrates may contribute significantly to slope instability, even if they have not been drilled through.

3.2.5 Ooze Formations

These tend to be a regional issue due to depositional rate and paleobathymetry dependence. A detailed description is included here as the issues are poorly understood by the industry, and little has been published on drilling of these problem formations. Pelagic ooze seabed presence would be revealed by pre-site Bio- and seabed- sampling. A proper study of their likely influence on drilling would be based on the data from Analogue Sub-Bottom Profiling combined with piston cores and/or CPTs. Seabed sediments are typically fine grained shales until deeper waters are reached, when calcium carbonate forms (mineral calcite). In colder waters siliceous organisms form. So called biogenic oozes are pelagic sediments with more than 30 percent of such skeletal material: carbonate ooze or siliceous ooze. Unconsolidated oozes are characterised by a high porosity but may display a fair initial strength due to a web-like texture often together with dissolution and cementation effects. Upon disturbance, oozes produce excess pore water and loss of strength. This may be most severe for siliceous oozes and coarse grained calcareous oozes. Uncemented coarse grained ooze layers may be mechanically weak. In general it seems that homogeneous oozes with no requirement for pressure control are easy to drill in. High permeability ooze layers could cause well bore collapse (with possible sand production) and loss of circulation, developing rapidly into a gas kick scenario. In the Voring Basin for example, sandy oozes are covered by a layer of slightly less permeable mudstone and may be overpressured. The combination of overpressure, high permeability, and lack of consolidation is a threat to well stability. The low density of oozes (1.3 1.5 g/cm3) significantly limits mud weights available for pressure control and stabilization. Collapse and porewater release from disturbed ooze along the cemented casing, may result in vertical fluid migration and pressure communication between permeable layers or to the seabed. Geotechnical coring (conducted by the NDP project) in the Voring area suggests a high water content (50 to 70%) down to 160m and a low shear strength (circa 50 kPa at 100m). The Gjallar Ridge on the Voring Plateau has 600m of ooze sediments. The presence of pelagic oozes may be indicated by seabed slope studies, and the thickness of such layers should be indicated by the 3D seismic and site survey data. If significant layers exist, careful forward prediction of any overpressures should be attempted (based on subsurface structure), together with PWD (pressure while drilling) measurement. Mud and cementing contractors should be contacted for chemical stabilisation options: polymer / particulate blends. Drilling and cementing of conductor through the ooze will be critical in establishing the mechanical integrity of the wellhead and riser.


Document Number: WEMS-01-A10 Date: October 2002 3.2.6 Salt

Salt is very common in the GOM. Drilling and cementing procedures are given in the Drilling Operations section.

3.2.7 Unconsolidated Sand Layer(s)

The so-called Taylor and Ellis Sands have presented wellbore collapse/sloughing problems and complete lost circulation in the W. Shetland / Faroes channel area. Any similar structure should at least be indicated by 3D seismic. This problem is further discussed in the Case Studies in the Conductor Design section, and also the Drilling Ops section. A sodium silicate plug plus overbalance can be used when such zones are encountered.

3.2.8 Seabed Drilling Obstructions

Sidescan sonar maps seabed sediments to avoid obstructions. A carbonate reef on the seabed may exist. These are very environmentally

sensitive. Coral is common in cold water. Boulders e.g. 100ft below seabed have been encountered on Shetland /

Faroes channel. Unconformity protrusions, sub seabed, but close to surface- will show up on

3D seismic as clearly visible slumps (anomalies). These may be difficult to drill.

3.2.9 Slope Stability and Seabed Sediment Consolidation

Seabed structural integrity is in general poor in deepwater, but its local properties depend on such issues as slope stability. Seabed structural properties for anchors and base design can be obtained from the analysis of drop cores. Surface faults are localised and should be avoided by their identification using shallow seismic. They may be common on the slope. Slope stability issues may be studied in the following ways:

Site surveys can easily miss that the target location is downslope of a potentially active mudslide. Geological history, shallow geology and a good data set is needed for understanding sediment mass movement.

There is potential for continual seabed movement- age tests on seabed samples e.g. drop cores in deepwater should be routinely performed to investigate slope stability. Age tests that revealed new seabed sediments would imply lack of consolidation but no seabed current scouring and localised turbidite currents; Eocene aged sediments found on the seabed would imply firmness and few loose sediments, but also would imply current scouring and catastrophic turbidity currents (typically once every 1000 years).

HR seismic can reveal boulders e.g. as they have done 100ft below seabed on Shetland / Faroes channel. This may be considered as evidence of mass transport in general.

3D and HR seismic can identity weak layers and in-situ hydrates that can trigger sediment flows.

Detailed bathymetry will show details of any channels implying sediment flow or slumps. This would not show sheet flow.

The Analogue sub-bottom profile also provides an indication of slope stability.


Document Number: WEMS-01-A10 Date: October 2002 3.3 Metocean Data Gathering Requirements

3.3.1 Background

Metocean data (Meteorological and Oceanographic data) provides extreme and operational design criteria on winds, waves and currents. This data can then be used for feasibility studies and planning. Examples of the use of this data are given in this document in the sections on Rig Selection, Engineering Design, and Rig Operations.

3.3.2 Strong Current Environments

Strong Currents at all depths; as well as causing large static loading on subsea equipment; produce an effect know as Vortex Induced Vibration (VIV) which can quickly lead to fatigue failure of critical system parts such as the drilling riser. As a result, careful desk study engineering assessment must be conducted on designs of riser (particularly with regard to VIV, to establish tensioning requirements and fatigue life) and mooring/DP requirements. Six months of on-site concurrent current profile measurements is preferred for VIV integrity initial assessment, however a shorter duration over the drilling window may be acceptable. Current data are also required for dispersion modelling of cuttings. There is no defined requirement for the quantity or quality of data. However, the best data available at the time should be used.

On-location Current Data for Surface and Subsea

Typical quotes for tethered buoys for a year of current vs. depth measurements are 0.5 million plus maintenance plus insurance. In the case of a specific season for drilling being guaranteed; a minimum period of three months data is required. Six months is a more desirable duration for data gathering for seasonal drilling. This is a long lead activity that could put a desired spud date at risk unless properly incorporated into the project plans. Note that a full years set of data is advisable for field development purposes. An alternative or additional option to the predictive approach may be to produce charts of (riser) fatigue damage accumulation versus current speed, which enable monitoring of fatigue damage accumulation during the actual operation this is good practice anyway.

Current Modelling

Various models exist for different parts of the world. The following (for the Atlantic Margin) is illustrative of the issues that can be encountered. The approach adopted by FugroGEOS in their work for Elfs Tranche 53 was to use the Proudman Oceanographic Laboratory (POL) Extended Continental Shelf Hydrodynamic Model (CSX) plus data collected during the Continental Slope Experiment (CONSLEX). They themselves underline the fact that extreme currents will be significantly underestimated for T53. The models validity in deepwater is unknown. The current profile cannot be estimated. The model attempts to extrapolate from a 172 day data set. CONSLEX data comprises 20 mooring locations with 4 to 6 month data records each. Extreme currents require many years of data or a well validated model. Fugros recommendation is that a site specific oceanographic measurement campaign needs to undertaken, at least during the winter season. Other current modelling studies are being undertaken at: Plymouth Marine Laboratory, Southampton Oceanographic Centre and the Nansen Environ-mental and Remote Sensing Centre.


Document Number: WEMS-01-A10 Date: October 2002 3.3.3 Temperature, Salinity, Density

The above three parameters all vary as a function of depth down the water column. They all impact the well plan and operations in different ways given below. Data as a function of depth is therefore required. Low ocean temperatures give rise to the following problems:

Hydrate formation potential during shut-in or at the connectors. The former affects the muds NaCl content requirements and hence the mud weight margin compared to the fracture pressure.

Riser / wellhead vertical expansion during a well test. Increased Mud ECD- 0.8ppg difference between circulating and static

equivalent densities: 0.3 ppg from compression, 0.5 from friction pressure losses- leads to wellbore breathing of up to 40 bbl upon pump shut down, which could be misinterpreted as a kick. 8 hrs would then be taken to circulate bottoms up. Can use PWD sensors and flowback characterisation to avoid this problem.

Acoustic propagation velocity variation with depth- used for rig positioning and site survey.

Salinity versus depth has impact on the following: Salinity variation with depth affects the fluid loading on the riser. This is

because salinity of the seawater affects its density, which in turn affects: hydrostatic pressure, Reynolds number, drag, inertia & lift; and hence loading. Acoustic propagation velocity is water density dependent- this is used particularly for positioning and site survey.

Corrosion Density versus depth, as stated above, affects:

Loading Acoustic propagation

3.3.4 Data Sources

1. Local Data Collection JIPs.

2. Local National Meteorological Offices: models and buoy data.

3. Local Data Collection and Metocean (Currents and/or Wind and Waves) Modelling JIPs.

4. Weather Buoys tends to be only surface data and will not include currents. Can include hourly data of air temperature (degC), dew point (degC), wind speed and direction, sea surface temperature, wave height (m) and period (s).

5. Vessel data e.g. NODC (USA). Depth, temperature and salinity reported. Wind and wave data may also be available.

6. BODC (British Oceanographic Data Centre) is a comprehensive central cataloguing group for relevant data sets.

7. Navy- navigational information, bathymetry, tides.

8. Fisheries industry data.

9. Oil Industry published Metocean design criteria for locality.


Document Number: WEMS-01-A10 Date: October 2002 3.3.5 Typical Data that should be provided in a Climate Summary

Monthly, seasonal and all-year percentage exceedence of wind speed. Climate summary of wind speed by month. 1, 10, 50, and 100 year design wind speeds Joint frequency distribution of wind speed and direction. Monthly, seasonal and all year percentage exceedance of significant wave

height. Climate summary of significant wave height by month. 1, 10, 50, and 100 year design significant wave heights. Joint frequency distribution significant wave height and direction. Joint frequency distribution of tidal, residual and total current speeds and

directions. Harmonic constituents of tidal current speed. 1, 10, 50, and 100 year total current speeds.

The lists of data specifically required for various analyses (mooring, riser, and conductor) are given in the relevant sections of the Engineering Design section. As an example; the surface conditions design criteria (the rigs so called drilling window) is based on environmental loading, water depth and consequent riser maximum base angle (see the AMDRILL Riser Guidelines Document and the Riser Analysis section of this document).

3.4 Rig Selection

3.4.1 Introduction

Water Depth Limit Specification

This will in all parts of the world severely restrict the availability of suitable vessels, and must be the first criterion applied.

Operability

The individual suitability of a rig will be based on its operability: the likely percentage of time that the unit will be actually capable of drilling. This is based on the vessel, mooring / DP, and riser system motion characteristics; the rig owners limitations on allowable metocean conditions; and the statistical metocean conditions for the planned location and time of year. Operability prediction is therefore based on detailed metocean data, riser and mooring / DP analyses, and the study of seabed conditions. Operability therefore needs to be studied on a case by case basis by a variety of specialist contractors. The section below on Preliminary Vessel Assessment is simply based on generic metocean data and basic vessel data, and is indicative only.

Rig Slots

BG would require a short exploration drilling programme duration, therefore the preferred option would be to utilise an available rig slot whilst the rig is under contract with another operator. This causes obvious uncertainty and flexibility regarding the start date of activities. BG are not necessarily likely to obtain a favourable summer slot with this option. Any WOW has rig rental cost implications for BG, but BG are not liable for affecting the next operators schedule. On the other hand, the previous operators programme timing (including their


Document Number: WEMS-01-A10 Date: October 2002 delays) would also affect BGs spud date. Rig availability at the time of planning may be determined by reference to World Rig Locator magazine which includes programmes of work.

Mobilisation

The costs of mobilising a rig from another part of the world, or modifying a vessel are prohibitively large (millions and 10millions respectively). Any likely exploration drilling budget could not support these options, nor would they be economically viable unless as part of a consortium. Harsh weather issues may in particular rule out using some drill ships (and some semis) from milder locations- note that the G.o.M. and particularly W. Africa are benign environments, and vessels designed for these areas will probably need upgrades or be inappropriate for the Atlantic Margin. The individual suitability of a rig will be based on its operability, which is determined using rig specific operating limits used in detailed riser and mooring analyses. The results of these analyses are in turn based on metocean and seabed conditions plus water depth. Riser buoyancy or fairings may well be necessary; these can be costly and lead to problems with the moonpool, which may require modification or prevent at least the fairings option, and add to running time and total operation duration significantly. Note also that G.o.M. deepwater activity for example is expected to increase dramatically, and rigs may not be available for relocation.

3.4.2 Rig Rates

Rig Day Rates of course depend on vessel Generation, vessel type, the time of year, current market (supply versus demand) and location (which also reflects different metocean conditions). The following values demonstrate the cost variation of day rates.

N.W. Europe: (August 1999 figures)

Semisubs: 5th Gen. $ 185k 4th Gen. $ 123k - $ 157k 3rd Gen. $ 122k Drill ships: $ 185k e.g. Jack Bates semi, April 99: $156k /day in 5200ft WD operation.

Norway:

4th Gen. / Deepwater $ 90k - $140k (August fixture) cf. 1998: $ 140 - $ 190k Standard Semis $ 107k - $ 115k (August fixture)

N. Sea:

4th Gen. / Deepwater $ 90k - $150k (July fixture) cf. 1998: $ 150k - $ 200k Standard Semis $ 31.5k - $ 39.5k (Sept fixture)

G.o.M.: (August 1999 figures)

Semisubs: 5th Gen. $ 174k $ 200k


Document Number: WEMS-01-A10 Date: October 2002 4th Gen. $ 65k - $ 130k 3rd Gen. $ 45k - $ 90k

Drill ships: $ 95k (probably too low spec. for Atlantic margin)

3.4.3 Minimum Rig Spec. for Harsh Environment, 2000m WD

4th Generation Semisub (VDL > 6,500 mt ) Triple redundancy DP system, (a chain and wire mooring system if the water

depth is significantly less than 2000m, e.g. 1200m) 1280 kips marine riser tensioner capacity Fully buoyed riser Summer only: DP drill ship, VDL > 6,500 mt

Few vessels do not require modification for 2000m. Typical costs at Dec 1996 prices and timescales are: 4th Generation Rig Upgrade Costs

DP Installation: $40M 3 months Additional riser/1000 $3M 1 month Additional columns $20M 3 months Additional sponsons & blisters $25M 3 months New drilling package $80M 12 months

Drilling in 1000m water depth in the Atlantic Margin would require the following upgrades to 3rd Generation Rigs (again at Dec 1996 prices):

$ 5 30 M for summer season $ 40 60 M + $ 40 M for DP system for year round drilling.

Note that if a rig with an extremely high tensioner capacity were selected, then the prediction and monitoring of VIV may not be necessary, as any VIV experienced during the operation may be eliminated. This is not guaranteed without conducting at least basic VIV studies of tensioner capacity effects at the pre-selection stage. A Conceptual Study of the likelihood of VIV should be conducted at that stage, to give early indication of the likely tensioner capacity required. It is possible that requirements may even exceed the highest tension capacities available (for 2000m water depth). One cannot guarantee in advance that VIV can be eliminated, and as a consequence current data gathering must be conducted, particularly as it is a long lead item. This is advisable, as there is little industry experience to support a non-conservative approach to VIV management. Completion operations are best left to summer months due to increased sensitivity to the weather.

3.4.4 Semi-submersible or Drill ship

Semisubs are less weather sensitive, as their motion characteristics are much better, particularly in low period seastates (such as large storm waves). They have particular advantages with respect to heave, although new drill ships have dampening systems. In a harsh environment, a semisub should typically expect one necessary riser disconnection in a winter season, whereas disconnects would be more frequent for a drillship. Ship shaped vessels are generally not as stable, as they must always head into the direction of the


Document Number: WEMS-01-A10 Date: October 2002 resultant environmental load. Harsh environment wind, waves and current are generally not co-linear and at times can be perpendicular. Larger hulls are preferred for winter months. On the other hand, drill ships generally have a greater load bearing capacity which is useful for isolated exploration activities and allows high riser tensioning values. Drill ships are not really proven for a harsh environment (not including the newbuild designs). A DP drillship should only really be considered for summer months. The newbuild drill ships, with better motion characteristics and a large storage capacity, should be a serious option at least for summer months. The following operability statistics were estimated by Global Maritime based on publicly available data in 1998 on rigs for operations in 1000m water depth W.o.S.: Semisubs: winter downtime = 0.1% to 11% of time

summer downtime = 0.1% to 1.6% of time Drill ships: winter downtime = 6% to 70% of time Majority of vessels would have major downtime. summer downtime = 0.6% to 25% of time Over half > 5%. Majority of better performers are newbuilds or Discoverer Class. Based on this, it is clear that drill ships are generally unsuitable for winter months in a harsh environment.

3.4.5 Station Keeping Alternatives

Moored versus moored with Thruster Assist

Thruster assist systems have an advantage due to allowing a significant reduction in anchor cable, allowing the vessel a greater load bearing capacity.

DP versus Mooring

Selection should be based on economics and rig availability. Longer term operations and concerns about DP reliability favour mooring with thruster assistance. Mooring systems are limited to 2000m WD with costly alterations required (1200m WD being a more comfortable water depth for mooring), are more reliable, only drift-off rather than drive-off on failure, pre-laid anchoring is possible, but anchor wire maintenance is required. Anchor handling operations can take 24 hours, compared to 2 hours DP system checks. Savings in rig time using a DP system can easily outweigh the fuel costs on an exploration well. Global Maritime quote the following failure statistics:

Mooring failure with no position loss probability = 1.86 x 10-2 per year Mooring failure with position loss probability = 2.43 x 10-1 per year, Mooring failure with critical position loss = 8.87 x 10-2 per year, DP drift off probability = 0.035 for a 90 day drilling programme, DP drive off probability = 0.076 for a 90 day drilling programme.

Drive off may be non critical, depending on recovery time and emergency disconnect time. The data clearly shows that DP is much less reliable.


Document Number: WEMS-01-A10 Date: October 2002 3.4.6 Miscellaneous Issues

Use of Older Generation Vessels

3rd Generation rigs such as the Pacesetter class have drilled during the summer W.o.S. in up to 1000m WD. Older rigs are more of an option if a slender well design is used. They are clearly an option for benign environments.

Deckload and Space Requirements

This is a significant issue in deepwater drilling due to the larger riser weight in addition to the casing weight prior to deployment, but also the large mud pits / storage requirements. 5000 bbl storage is ample if the sacrificial mud system used in the G.o.M. for 26 hole is not used (see the Rig Operations section on Drilling Fluids).

Riser Issues

A very large riser tensioning capacity is required. The harsh environment VIV issues are discussed in the Riser Management part of the Rig Operations section. Riser analysis will indicate the general adequacy of the existing system. The moonpool size must be considered for the use of a faired riser. A suitable riser recoil device must be fitted. Riser Analysis studies feed into rig selection by assessing the capability and operability of the vessel for the location (water depth, seabed) and drilling slot (weather conditions). The studies provide an operability / wait on weather prediction and risk of an emergency disconnect prediction for whatever period (1 year, summer months, short vessel operating slot) one wishes to consider. This provides a realistic basis for costing an operation based on day rate and duration including downtime. It also enables a feasibility study of using the vessel during winter months: although the percentage downtime will be likely to be higher, rig day rates may be significantly lower- and indeed the vessel slots may only be available during unfavourable seasons. VIV analysis in particular indicates top tensioning requirements for rig.

Anchors

Soil geotechnical studies will indicate what anchor types are required, and may influence vessel selection.

Dual Activity Rigs

Transoceans Discoverer Enterprise for example has a dual activity rig on a DP drillship two drilling stations under a single derrick. The size and stability of the vessel is comparable to that of semisubs. Station keeping is possible in a 50 year G.o.M. storm. Discoverer Spirit and Discoverer Deep Seas have a similar design. The obvious benefit comes from reduced non productive time, as activities may be conducted in parallel.

RamRig

In this new type of rig, the top drive is raised and lowered using hydraulic cylinders (rams), dispensing of derrick and draw works. In addition, tubulars are racked vertically down from the floor, not limiting the made up length. The tower is lighter, with a lower centre of gravity. The Vertical Deckload capacity is increased. RamRig design therefore enables continuous drilling for extended periods and reduced downtime: it saves trips in and out, reduces stuck pipe, and improves bit control and ROP. All these features are particularly desirable for deepwater. Smedvigs West Navion has had two RamRig towers installed. West Navion has an 8,000 ft WD capacity. Two wells have been drilled by Norsk Hydro in Oseberg East.


Document Number: WEMS-01-A10 Date: October 2002 3.4.7 Rig Contract Issues

The Drilling Contractor should have the following credentials: significant deepwater experience is essential, a set of rig specific environmental procedures, and a set of deepwater safety procedures.

Similar comments apply to service companies- deepwater experience and procedures are essential.

Crew operating performance & training requirements need to be addressed in the Contract Tendering stage.

Well control procedures trained staff or training for staff is required. This should include Riser Gas control procedures. Familiarity with IADC Deepwater Well Control Guidelines is desirable.

Well control equipment: 15k BOP, BOP pressure gauge, large MGS, and riser gas handler.

Consideration of the possibility and cost of upgrading riser tensioning capability and moonpool size. Very large riser tensioning capacity will be required. The riser analysis will indicate the adequacy of the existing system. Moonpool size must be considered for the use of a faired riser.

Costs, timescale and arrangements of any upgrades required by engineering analyses or water depth.

Performance Issues Operational times that are mutually acceptable, such as: - BOP running times of typically: 56 hrs to 7,200 ft (2195m) (G.o.M.,

Marathon), 38.5 hrs to 1,198 ft (365m) - to run and latch. 1hr to move rig to enable latching. - Downtimes, non productive / non drilling time anticipated e.g. on 205/17A-1, drilling the 12-1/2 hole: each stand was reamed once to ensure that the hole was kept vertical and clean, MWD was taken each stand.

Vessel deployment arrangements should be included, such as shipping lanes, mobilisation, deployment, and installation time.

3.5 Subsea and Subsurface Engineering Design And Equipment

3.5.1 Introduction

As stated in the Rig Selection section, rig operability and hence suitability must be assessed by detailed engineering studies: particularly the mooring design or DP operating limits and reliability, and riser design including options for the use of fairings and buoyancy and including VIV analysis. The need for integration of mooring, riser, wellhead and conductor design is discussed.

3.5.2 Mooring Systems

Design Analysis

The general design code for moorings is API RP 2SK (used by e.g. Noble Denton). Other contractors use DnVs POSMOOR (e.g. Global Maritime). Mooring system analysis is principally an assessment of the planned systems adequacy based on riser analysis requirements. Optimisation of configuration could be achieved to a


Document Number: WEMS-01-A10 Date: October 2002 small degree through altering line length (where available) and line pretension to minimise vessel excursions and therefore increase uptime. Winching optimisation would also be undertaken to optimise station keeping and uptime. It is not standard to consider optimisation by altering the mooring system itself or the fairleads, winches or anchors. These could be considered if uptime could be gained through alterations to the mooring spread. Mooring system analysis should be conducted by at least two independent studies e.g. Global Maritime and Reading & Bates, as it is a critical factor in vessel operability.

Design Analysis Input Data

The data required for a Mooring System analysis (and also a station keeping assessment of DP vessels) is as follows:

Location Data

Coordinates and water depth. Wind, wave and current data for various return periods 1yr, 5yr, 100yr.

Directional data and seasonal data if appropriate. Current exceedance data (say, 50%, 10%, 1% exceedance). Scatter diagrams for availability/downtime analyses. Hindcast data of wind,

wave and current over 20 years improves analyses.

Vessel Data

General Arrangement (GA) drawings and/or Lines Plans. Draft, displacement, hydrodynamic inertias etc. Environmental force coefficients wind and current Hydrodynamic data Response Amplitude Operators (RAOs) including

phases for all 6 degrees of freedom for a range of vessel headings. Quadratic Transfer Functions or mean drift coefficients for 3 degrees of freedom (surge, sway, yaw) for a range of vessel headings.

Station Keeping Mooring and DP

Mooring line details chain/wire, grade, diameter, length, and winch stall capacity.

Fairlead locations. Anchor types. DP class details and footprint. To be integrated with Riser System (see directly below).

Riser, Mooring and Vessel Study Integration

The following data from the riser analysis is used for the mooring analysis: Permissible vessel offsets with riser latched. Riser loading on vessel (principally tension).

It is not normal for data from Mooring studies to be fed back into riser study e.g. mooring system stiffness is not considered- different vessel excursions are analysed to determine riser operating envelopes e.g. by 2H Offshore Engineering Ltd. Noble Denton on the other hand, do use Mooring system stiffness to study low frequency riser oscillations (a less Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01 Page 21 of 49

Document Number: WEMS-01-A10 Date: October 2002 conservative approach). The allowable offsets from riser studies are eroded by poor performance of mooring in deepwater. If polyester / hybrid mooring is considered, time dependent stiffness behaviour should be studied as part of the mooring analysis. Reported vessel RAOs may differ from those with a riser attached.

Mooring Reliability

Global Maritime quote the following failure statistics: Mooring failure with no position loss probability = 1.86 x 10-2 per year Mooring failure with position loss probability = 2.43 x 10-1 per year, Mooring failure with critical position loss = 8.87 x 10-2 per year.

In addition to this, mooring line parting is often due to line clashing on retrieval, rather than weather during operations.

General Comparison of Mooring Alternatives

Mooring of drilling semisubs is possible in up to 2000m WD, but with significant upgrades required. Superior moored semis can cope in up to 1200m WD, with only some non-major alterations. A combination of wire and chain is the best option for catenary mooring in deepwater. Conventional catenary mooring has practical limit of 1600m WD. Catenary mooring water depth capabilities may be extended using subsea buoys. FPSO information is only included here (directly below) to indicate likely water depth dependent trends for a semisub, and for consideration as a Development scenario: For an FPSO, rough guidelines are: below 1000m WD conventional mooring is acceptable, beyond this to about 2000m semi-taut-leg with steel rope mooring is the cost effective option, and from 2000m to beyond 3000m synthetic taut mooring should be considered. Taut leg systems in 1,200m WD are 2.5 times cheaper than wire/chain for an FPSO. Taut leg mooring has such a long deployment time that it is generally unsuitable for exploration drilling. In addition, the drilling vessels would require extensive modifications to the winches and fairleads for using taut line mooring. It is an option for future consideration.

Mooring System Technical Developments

(related to depth & seabed conditions)

As water depths increase beyond 500m; mooring loads, restoring forces and requirements for holding ground all force a complete re-design of the conventional catenary mooring system, ultimately towards a taut leg design. In addition, anchor pattern (especially size) and cost, and the handling of large lengths of chain and wire are limiting, particularly on catenary designs. The angle at which the anchor load applies to the floating structure is water depth dependent. Chain weight increases and the floaters required become bigger (requiring even heavier chains) with water depth. Chain weight affects its effective strength and hence efficiency. The angle of lines with the horizon increase, restorative forces drop, and mooring strength decreases. The soft deepwater soils worsen the problem. Industry solutions have been to develop lighter anchor lines and up-lift anchors (see below). Lines have been made lighter and shorter without losing restoration, e.g. steel wire can lead


Document Number: WEMS-01-A10 Date: October 2002 to a 20% weight reduction, lighter chains lead to a 10-15% weight reduction, and submarine buoys also assist. Polyester lines have also been developed, and may be used in hybrid designs with chain and wire. High capacity winches and special winches for polyester have been developed.

Taut mooring system developments (more applicable to Developments)

Catenary mooring has low horizontal stiffness leading to large vessel excursions. Taut leg mooring with polyester ropes and vertical load anchors reduces vessel excursions by a factor of 2 to 5 (a study of rope characteristics, design, costs, anchoring, installation and retrieval has been conducted by N. Hydro and Saga and reported at OTC). Taut leg mooring adds significant vertical load to the rig, despite the use of drag anchors with chains. Taut leg systems have a significantly reduced footprint compared to catenary systems. Shell and Delmar Systems have used a semi-taut leg system with suction anchors in Gulf of Mexico clay/silt seabed. It took 30 days to install with an anchor handling boat and ROV. Hook-up to rig was less than 1 day. In 1645m water the maximum movement off station has been 30m. The system is operable in up to 2134m WD. Polyester systems have been deployed off Brazil. There are still uncertainties over polyester modulus and durability and how to monitor fatigue and damage. Riser design, which depends on mooring system stiffness, can in turn be affected.

Mooring System Installation

Installation time is lengthy. The Jack Bates Rig (R& B Falcon), for example, took 46 hrs to moor in 4000 (1219m) (no WOW). The use of pre-installed mooring is being considered by the industry.

3.5.3 Anchors

Background

In deepwater, soil is mostly soft and comparable to soft soil at shallower depths, so in general anchors may be of a similar design. Soil data for anchoring purposes is provided by piston core / CPT and the analogue sub-bottom profiler study (see Site Survey chapter). Local soil properties will imply what anchor types are required, which may in turn influence rig selection. Minimum anchor pretension requirement will be high due to the water depth, environment, possibly soft and/or unconsolidated seabed, and potential slope angle. Anchoring issues should be considered in Rig Tendering stage, as a change in anchoring type will probably require a rig to be sent to yard- a prohibitively expensive option. The anchor size and type must be confirmed to provide acceptable holding capabilities. This is done by an assessment based on the line loads predicted by the mooring analysis and soil conditions.

Anchor Types

Traditional fluke anchors capacity may well be inferior to deepwater design requirements. Drag embedment may require breaking hard clays deeper down into the soil. Anchor holding in slope areas is often not very good. Delta Flipper Anchors are hinged rather than straight, and are suitable for 914m (plus) water depths. Pile anchors are only suitable for production operations. They require a large installation vessel and heavy lifting capacity, and have a narrow installation weather window- hence using this system is expensive. Deep penetrating anchors can take a large uplift force, but deepwater vertical loading prevents their use. Drilled Pile Anchors have been developed by


Document Number: WEMS-01-A10 Date: October 2002 Trident. Suction anchors have been used on large vessels in shallow water- their vertical loading capacity has yet to be fully proven in deepwater, they are expensive, and have a small weather window. They can allow 4th generation vessels to operate beyond 1520m when combined with semi-taut leg mooring (see below). They are supplied by Suction Pile Technology. They work using ambient water hydrostatic pressure and the pumping of water out of the anchors. The pile must withstand a large pressure differential and is therefore heavy and expensive, as is installation which requires a pump, umbilicals and ROV. They are most suited to production operations, but can be used in drilling vessel operations. Vertical Loading Anchors (VLAs) are deeply embedded (and soft soil is therefore an advantage) and can take higher angles which cause them to penetrate deeper. They are not fully field proven yet. VLA are ideally suited for taut line mooring, compared to the low angle anchors for catenary mooring. They are supplied by Vryhof Anchors. A Position Penetrated Anchor Tool is being developed by Viking Mooring- it is an installation tool and a plate anchor giving accurate positioning with vertical and horizontal load bearing for taut and catenary mooring of up to 10,000 kN pre-tension. It can be used for FPSO/FPUs and semisubs in up to 2,500m water depth. Anchors are retrievable, but anchor handling vessels will still be required. Field trial in Sept. 1999. Minimum sea temperature requirement of 2 degC may be a limitation in certain locations.

Anchor Handling

Anchor handling has proved to be the biggest problem in exploration drilling West of Shetland. The weight of equipment to be handled by the AHTs (Anchor Handling Tugs) and the short weather windows available have been the cause of these problems. To deal with these problems, the following specifications are given:

A minimum of three AHTs for mooring and anchor deployment: two operating vessels and one redundant vessel.

Bollard pulling capabilities of around 150 tonnes are required due to line weight. Also larger vessels are more stable.

AHT selection is to be based not just on power, but also on chain locker capacity and powered wire reel capacity. The stowage of wire reels on deck is to be avoided.

The specifications mean that top class vessels are advisable (e.g. Maersks Deepwater Workers). The rig owner normally specifies anchor handling vessels (number, type). Anchor handlers have a spot price: anything from 6.5k per day to 70k per day depending on availability. Mooring operations have been inhibited by the poor performance of rig winches, cause by the weight of the lines. Improvements in the maintenance and repair of winches are needed to minimise delay in mooring operations. A back up electrician and possibly barge engineer should be considered during mooring operations. It is advisable to use a single length of new work wire on each of the anchor handling vessels to prevent the possibility of the connectors between short lengths of wire damaging successive layers of wire rope as the wire is spooled and un-spooled from the drum. It takes at least 14 hours to fit the new work wire.

3.5.4 DP Capacity and Reliability

The Need For DP Station Keeping

Data requirements for a DP station keeping analysis is given in the Mooring section.


Document Number: WEMS-01-A10 Date: October 2002 In water depths approaching 2000m, catenary mooring becomes impractical, and in the absence of newer mooring design alternatives which are yet to be fully proven in harsh environments; DP station keeping becomes the only option. In addition, DP is ideal for short duration operations and extreme weather conditions. Triple redundancy of thrusters is required by UK regulations. 40 to 50 tonnes of fuel oil per day is required for station keeping.

DP Capability Assessment

The DP systems thrust capacity must be sized for harsh environments. It should then provide a better operability level than a moored unit (operability levels are very rig specific, so this generalisation may be unfair). Loads for the assessment should be based on the analysis of the deployed riser. Thruster efficiency is seriously affected by high currents. A drift analysis should be combined with the riser and vessel motion characteristics to determine the systems operability. Drift off time may be compared to riser disconnect time. The worst case scenario for DP station keeping is a drive off, where a failure in the thruster control system causes the rig to be propelled off location. A risk analysis of the DP system failure should be conducted by an expert such as Noble Denton. The key stage in operations where DP reliability is critical is well testing. Global Maritime quote the following failure statistics:

DP drift off probability = 0.035 for a 90 day drilling programme, DP drive off probability = 0.076 for a 90 day drilling programme.

Drive off may be non critical, depending on recovery time and emergency disconnect time.

3.5.5 Drilling Riser Design

Guideline Documents and Scope of Work

Design and assessment should be at least to the following specifications: API RP 16Q plus AMJIG Riser Management Guidelines (written by 2H Offshore Engineering Ltd) for harsh environments. The Institute of Petroleums Guidelines For Routine and Non-Routine Subsea Operations From Floating Vessels should also be used for reference. The AMJIG document provides additional deepwater harsh environment requirements to supplement the API Specification. For example, it suggests the use of concurrent current profile frequency for VIV analysis, and an additional extreme loading case with 0.8 safety factor. The duration (and associated cost) of a drilling riser and conductor analysis study is dependent upon the location, the riser system and the vessel /vessels to be considered. A typical study duration ranges from 6 weeks (standard riser configuration in a relatively benign environment) to 15 weeks (novel concept risers or difficult environmental conditions) with associated budgets from 15k to 50k. The above estimate is from 2H Offshore Engineering Limited. Noble Denton roughly estimate 12k for a basic study, which cannot be compared with the 2H estimate, because it is essentially an integrity assessment of a single design than a design optimisation, and does not include tensioner system design, conductor fatigue analysis or as many parametric studies (e.g. mud weight range) as the proposed 2H study. Noble Denton can estimate cumulative VIV damage, but not to the AMDRILL standards, and the cost quote does not include this key VIV fatigue assessment, simply a check on whether it would occur. It also does not include an uptime analysis. VIV is a key design issue for deepwater, harsh environment risers; as many modes of oscillation are stimulated by the strong, sheared current profile. These often cannot be completely removed by top tensioning, and a fatigue rate / life estimate must be made for


Document Number: WEMS-01-A10 Date: October 2002 design and monitoring purposes. VIV analysis tends to produce conservative operating envelopes. The rig owners will often specify operating limits and design limits and guidelines in excess of API and equipment guidelines, in order to protect the rig system. These need to be used as analysis input, and can include riser angles and seastate limits.

Design Data Requirements

Riser Data

Riser joint details including in-air/water weights, lengths, OD and ID, internal tubular ODs, and material specification, structural properties.

Subsea equipment (BOP/LMRP) dimensions and in-air/water weights. Type, size and weight of buoyancy modules. (Upper and lower) flex /ball joint details, maximum angle and stiffness. Connector properties and fatigue details. Slip-joint details and range/stroke. Kill/choke line details. Details of available VIV suppression- fairings, hydrofoils etc.

Environmental Data

Location coordinates. Water Depth. Wave data: Extreme storm and long term (scatter diagram). Current profiles. Current exceedance data (50%, 10%, 1% exceedance).

(This is required because often W.o.S. currents are so large that one needs to consider smaller currents to make riser systems pass). In-situ concurrent current profile data is needed for VIV analysis: a data sampling period of six months is ideal for Tranche 19.

Soil data (P-y data to 40m for conductor compliance).

Vessel Data

Dimensions. Draft. Elevation of drill floor. Moonpool clearances. RAOs. Tensioner Arrangement and Capacity. Bail length. Rig specific operational limits for: drilling, tripping, running BOP, running riser,

running casing, testing BOP etc

Operational Data

Casing Programme. Drilling Mud Densities.



Key Issues

The key factors that affect the configuration and operation of deepwater, harsh environment drilling risers are as follows:

Water depth and currents. Rig tension capacity. Variation in riser tension with changes in mud weight. Use of buoyant joints to reduce rig tensioning requirements. Use of heavy wall joints or fill-up valves for collapse resistance. Need for improved vessel position control. Fatigue damage from vortex induced vibrations. Large overpulls to accommodate during disconnect. Light riser in hang-off. Increased wellhead and conductor loading from higher riser base tensions.

Analysis Outputs

Drilling riser analysis must be conducted to determine the optimum riser configuration and operating procedures. Outputs from riser analysis should include all of the following:

Joint arrangement. Top tension. Variation in top tension with mud weight. Operating Envelopes. Hang-off arrangement. Tensioner recoil system settings. Tensioner configuration. Input to inspection assessment. Input to mooring analysis.

Analysis Steps

Drilling riser analysis must be conducted using a system approach, whereby all phases of riser operation and all parts of the system from the conductor through to the rig are considered. It is not sufficient to address the riser in isolation or simply to consider in-place response. The steps involved in analysing riser response to determine a suitable arrangement and operating requirements are as follows:

Preliminary configuration. In-place operations. Completion operations. Fatigue analysis. Riser wellhead conductor interaction analysis.



Hang-off and recoil analysis. Riser conductor and casing installation analysis.

Due to the complexity of riser response in deepwater, riser configuration development is an iterative process, potentially requiring a number of loops. This process is illustrated by the figure below. Not all of the steps need to be conducted for every application. Each of the steps should, however, be assessed and the novelty and difficulty of the operation in the specified water depth and environment evaluated.

For further information please refer to AMDRILL Riser Management Guidelines, API RP 16Q


Document Number: WEMS-01-A10 Date: October 2002 and GRTC Report No: 2493.

Impact of Analysis on Planning, Contracting and Operations.

Riser, Wellhead and Conductor system design feeds into rig selection by assessing the capability and operability of the vessel for the location (water depth, seabed) and drilling slot (weather conditions). The operating envelopes referred to above as analysis output, will graphically show allowable limits (based on stress level and ball joint angle) for combinations of vessel offset, wave height and current for easy use on the rig. This will indicate the need for unlatching, or the permissibility of a particular operation. The same data may be combined with seastate statistics to provide an operability / wait on weather prediction and risk of an emergency disconnect prediction for whatever period (1 year, summer months, short vessel operating slot) one wishes to consider. This provides a realistic basis for costing an operation based on day rate and duration including downtime. It also enables a feasibility study of using the vessel during winter months: although the percentage downtime will be likely to be higher, rig day rates may be significantly lower- and indeed the vessel slots may only be available during unfavourable seasons. In a harsh environment, VIV analysis in particular indicates top tensioning requirements for the rig. For details regarding VIV analysis, please refer to GRTC Report No. 2493. The VIV analysis will predict fatigue lives and hence monitoring and inspection requirements. The analysis assumptions normally result in over-conservative prediction of fatigue damage. Monitoring of VIV is therefore necessary. See Rig Operations section. Note that if a rig with an extremely high tensioner capacity were selected, then the prediction and monitoring of VIV may not be necessary, as any VIV experienced during the operation may be eliminated. This is not guaranteed without conducting at least basic VIV studies of tensioner capacity effects at the pre-selection stage. The standard procedures in the complementary Planning Document suggest a Conceptual Study of the likelihood of VIV is conducted at that stage, to give early indication of the likely tensioner capacity required. It is possible that requirements may even exceed the highest tension capacities available (for 2000m water depth). One cannot guarantee in advance that VIV can be eliminated, and as a consequence current data gathering must be conducted, particularly as it is a long lead item. This is advisable, as there is little industry experience to support a non-conservative approach to VIV management.

Integration of Engineering Studies Issues

Latched Riser, Wellhead and Conductor System

When considering a latched Riser, Wellhead and Conductor System, an isolated riser analysis assuming a wellhead fixed at seabed is a worst case scenario for riser stress and ball joint angle maxima. This may lead to over conservative recommendations of operating envelopes. The real concern is with regard to fatigue analyses, as predictions may not be realistic in soft soils and deepwater. An integrated study may be performed that provides a more realistic riser assessment, and fatiguing assessment of the system (particularly from VIV). The study of conductor fatigue identifies elevations of stress concentration peaks below mudline (e.g. 12m), indicating the serious need to locate welds and connections elsewhere in the conductor design. If necessary a parametric study of conductor thickness may be performed. Accurate soil P-y data down to 40m BML is advisable, the loads being not substantial below this depth in general. It is only of benefit to consider the largest tubular in isolation.

Riser, Mooring and Vessel Study Integration

The following data from the riser analysis is used for the mooring analysis:



Permissible vessel offsets with riser latched. Riser loading on vessel (principally tension).

It is not normal for data from Mooring studies to be fed back into riser study e.g. mooring system stiffness is not considered- different vessel excursions are analysed to determine riser operating envelopes e.g. by 2H Offshore Engineering Ltd. Noble Denton on the other hand, do use Mooring system stiffness to study low frequency riser oscillations (a less conservative approach). If polyester / hybrid mooring is considered, time dependent stiffness behaviour should be studied as part of the mooring analysis. Reported vessel RAOs may differ from those with a riser attached.

Riser Analysis Tools

Flexcom 3D (MCS) is a nonlinear time domain riser analysis industry standard package with good functionality and user interface. Its frequency domain equivalent, Freecom, is less relevant to deepwater harsh environment as its linear analysis is inadequate and modern computing power allows Fourier analysis of time domain results anyway. Riflex (Marintek), is the main competitor to the above, of similar functionality and providing closely agreeing results, but with a less user friendly interface which gives scope for modelling error. Shear7 (MIT) is a sheared flow profile VIV analysis package based on modal superposition. It is used by operators. It is also used by 2H. Viva (MIT) is a VIV analysis package based on a large database. It is used by service companies. It is also used by Noble Denton.

Riser VIV Mitigation

One case study provides a good example of the measures that need to be taken in a harsh environment. One well in 4000 water depth (Mobil, UK Tranche 6), had currents of 1.5 knots surface to 0.5 knots seabed (the maximum recorded in a year): this led to 35% even coverage of the riser with fairings (300 fairings in total, representing significant cost and time to attach and remove). The Jack Bates rig required an upgrade for handling towers etc in moonpool area, plus riser restraints for weather and clashing with caisson. For another well in 5400 (also Mobil, UK T61) a bare riser was used based on the QRA of the use of Fairings based on operations duration: not using fairings had the following consequences: increased risk of VIV (but Jack Bates has sufficient tension capacity to pull to the required 400 kips at the riser base i.e. 1 million lbs of tension with the mud weight used); decreased operability based on riser angle (push off due to increased hydrodynamic drag- actual rig movement was necessary to keep the riser vertical); decrease cost and time to deploy / retrieve. Decision over fairing deployment (or not) depended therefore on expected currents and the time of year. Conoco (50 miles from Suiliven, in 2 knot currents) with 900klbs riser tension applied (the maximum allowable) had riser and guideline VIV. They had planned and predicted that only 600klbs would be needed. A tension wire snapped. The use of staggered buoyancy, or fairings should be considered by weighing up the extra rig operability versus the additional cost and deployment time.

Riser Wear

Riser wear may be caused by drillstring tool joints. It has occurred not just at the base of the riser, but over the length of the riser, due to riser S bending in current profiles that have actual reversals. BG were part of a DEA Riser Wear JIP and own the analysis software


Document Number: WEMS-01-A10 Date: October 2002 produced. The Engineering consultant or Riser Supplier used for Riser Dynamic and VIV analysis should be consulted as to wear risk, and the software used if necessary. It may be detected whilst the riser is connected, by sonic logging, e.g. Schlumbergers USIT, Baker tools etc. The wear has not been known to significantly affect the performance of the riser in exploration drilling, and will be more of a problem in longer operations.

Slim Riser Design

Saga have for a number of years investigated concepts for slender well design and slim riser and wellhead. This EfEx project aimed to allow the use of lower specification vessels (3rd Gen) with much lower day rates, and also significantly reduce material costs - even in harsh environments. The drawback is that it is initially capital intensive. Enterprise on the other hand are currently planning the use of a 16 riser in deepwater in the Adriatic with very few modifications required. A conventional 18 BOP and 21 riser diverter and telescopic joints will be used. It will be necessary to lose the 17 hole. With a 16 riser, a 3rd Gen vessel could drill deepwater Atlantic Margin. Their concept is ideal for 600m to 1800m water depth, shallow drilling or normally pressured areas, short programmes with high upgrade or mobilisation costs, or long programmes with high day rates. It is optimal if the 17 could be drilled riserless. One possible technical limitation is that a smaller conductor will be constrained by less soil resistance, and casing stresses may be limiting. This should be identified in any conductor analysis feasibility study conducted for the well location.

New Concepts

The Free Standing Riser developed by Cameron/Hydril/Diamond saves running times and 15% construction costs. Riser disconnect is at 500 to 1500 ft below surface, with a positively buoyant riser in place. It can also use user Akers pre-installed mooring and riser system (suction anchor and taut leg polyester rope). Atlantis Concept, developed by Proffshore, and championed by Statoil. Enables the use of a 3rd Gen rig with a Deepwater Mooring system in deepwater harsh environments. This means well cost savings of 30% in 1000m water depth, and 60% in 2000m water depth according to Statoil. Atlantis Concept incorporates an artificial buoyant seabed (ABS) wellhead and BOP - located at a convenient water depth (200 to 300m). This effectively makes the well design, riser, BOP, and well control the same as a conventional subsea well. One of the well casing strings extended above the seabed is used to anchor the ABS. Design assessment has been based on 100 years Voring current profile with 1200m water depth, showing there is no theoretical water depth limit to using Atlantis. The design reduces VIV risk, and is very useful for a poorly consolidated seabed (due reduced localised bending stresses). It obviously simplifies and speeds up ROV maintenance and riser running. A first drilling operation with this system is being actively investigated by Statoil in Norway, UK, Ireland and Nigeria. Feasibility studies have been previously conducted for Saga also.

3.5.6 Conductor Design, Assessment and Installation

Design Guidelines and Scope of Work

The general design code is API RP 2A. For study duration and cost estimates, see the Riser section. For the (stress) analysis of installation operations, see the previous section. Conductor design will use the following Soil Data:

Site survey report including bathymetry, swathe bathymetry (if available), sub-bottom profiling to adequate depth (for example conductor setting depth),



sidescan sonar, seabed sediment data (if available) and interpretation of these data

Geotechnical design parameters for engineering analysis and design, including soil density profile, plasticity data, drained (if available) and undrained shear strength profiles. In-situ, odeometer and advanced triaxial test results would also be useful.

To ensure competent well construction of the shallow strings the following is necessary: adequate knowledge of sediment properties to 100m or below; and identification of hazards, and either avoidance or planning and design to

mitigate their effects. 3D seismic, shallow HR seismic, geotechnical coring, drilling pilot holes, offset wells, drop core tests and BGS Borehole Sites; can all contribute data for a competent understanding of the drill location and adequate design and planning. See the earlier section which discusses prioritisation of these sources of information, based on adequacy and cost. Once shallow structural properties are known (including oozes), and the potential for geopressured shallow aquifers determined; setting depths /string lengths, string sizes / thicknesses and top string landing procedures may be determined. Conductor thickness determination can also use data from riser analysis such as maximum bending moments (tip buckling). For example, one may have a location where the two top joints of conductor require 36 OD x 1.5 wall thickness in over 2,500 ft water depth, to accommodate the maximum wellhead loading defined in the riser analysis. Conductor lengths can be 100m. Saga used a very strong conductor: 36 ID and 1.5 wall thickness for the full length, as support for riser and BOP in a 600m top layer of oozes in Gjallar Ridge deepwater Norway. Typical designs for West of Britain, where shear strengths of top soil can be as low as 10kPa, with a higher strength developing 50m below the seabed; are as follows: In 500m to 1000m WD:

36 OD, 1.5 wall thickness, 20m conductor, crossing over to a 30, 1 thickness conductor for four joints.

In over 1000m WD: as above, but 36 OD, 2 wall thickness for the top 20m instead.

Riser, wellhead and conductor system VIV fatigue analysis can also influence conductor design by identifying depths to avoid placing welds and connections.

Conductor Installation Methods

Conductor installation may be accomplished either by jetting in or cementing in place in a pre-drilled hole. If thick sand layers are known to be present, it will not be jetted, as a complete washout could result. Jetting is a fairly novel approach outside of the G.o.M., which provides considerable time and cost benefits if successful but excessive reciprocation of the string can damage the soil integrity. Controlled jetting and minimised reciprocation should be employed, and if geotechnical data indicates that the conductor cannot be advanced to the required depth, alternative installation methods should be considered. Boulders should be identified by the site survey, as for example UK well 163/6-1 had to be abandoned when jetting encountered a boulder. Conductor setting depths should avoid sand layers, as a competent seal between shoe and formation is necessary.


Document Number: WEMS-01-A10 Date: October 2002 From an operational viewpoint, jetting, drilling and cementing practices are critical for ensuring structural integrity and zonal isolation. Case Studies of these are reviewed below.

Case Studies

Jetting Combined with Drill Ahead, whilst presenting more risk, saves two open water trips (circa 30 hrs), and has been used by Mobil (W. Shetland / E. Faroes): 5 joints of 36 conductor were jetted with V150 HW drillpipe inside, which then was used to drill the hole for the 20 casing. The BHA has been optimised for speed and keeping formation strength. The driller must provide adequate torque. Reciprocation was needed during the jetting phase. The bit must be kept inside the shoe (e.g. 2 ft); otherwise wetting the rock weakens it- returns are taken up the inside of the conductor, dropping back to seabed. A straight (non-tapered) conductor with externally flush connectors was used. These design features are due to Nyk High (Ocean Alliance) sinking of conductors due to a combination of using tapered strings, reciprocation every 20ft and having the bit below conductor. It took 4-5 hrs to jet. Analysis and Gulf of Mexico data suggests 5 hours for jetted soil to regain full integrity. The jetted conductor was found to have enough axial capacity to support hangoff. Then the BHA was released (bumped) and drilled ahead. The conductor was held for 12 hours during cementing and setting (the latter time being unnecessary). The soft clay soil was sufficiently competent, with a surface crust. The pilot hole that had been drilled stayed open throughout the drilling ops. Drilling the hole for the 20 by this open water drill ahead method showed a tendency to build angle. To keep WOB and hence ROP sufficient, it is necessary to use a bent housing assembly. Instead of using 20, it may be worth considering using a 13-3/8 to eliminate the need for anti-VIV helical strakes. In contrast: Conoco/Arco on Shetland /Faroes channel on the slope (50 miles from Suiliven) with Taylor and Ellis sands at the location, had a 36 (100 ft)/30(3 joints)/20 conductor of total length 350 ft, to get below the Taylor sands (a complete lost circulation zone). Jetting was prevented as sticking would occur. The presence of boulders likewise prevented jetting. There was only one open water run. The 13-3/8 casing was run to 7,500 ft, its hole being drilled as fast as possible; as good studies done for Foinaven / Schehallion could be used. Petrobras have had problems with swaying wellheads in deepwater Brazil, and now jet 48 / 42 caisson piles to avoid this. They jet the 30 casing, and then release the drilling assembly to drill the 26 hole. Jetting the 26 hole has been found uneconomical based on geotechnical data and 30 jetting record studies; as soil strengths get harder demanding longer jetting time, which can lead to bad soil adherence to the casing. Normal penetration for the 30 is 36m, but on occasion is as deep as 60m. The detailed data is given above to emphasise that a flexible, site specific approach to design is required.

Integrity of the Cement Job

Cement top up

It is often necessary to top up the cement job on the conductor due to seafloor washout due to strong currents. This top up may be performed using a side-entry rotating circulating head, using the ROV to monitor and cut hoses. See Ocean Environment section for comments on current scouring. This procedure saves having to run a stinger down beside the wellhead. The job should nevertheless be monitored for cement flowing over the PGB.

Cementing procedures

(UK 164/07-1 well lessons learnt): Dedicated U170 drillpipe is used for landing. It takes approximately two hours to clear the cement lines befor