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

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RECORD OF AMENDMENTS Rev. No.

Description of Changes


By

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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.


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Table of Contents 1

INTRODUCTION ......................................................................................................................................... 5

2

WORLDWIDE DEEPWATER DRILLING ACTIVITIES ......................................................................... 6 2.1 2.2

3

INTRODUCTION ...................................................................................................................................... 6 LOCATIONS OF MAJOR DEEPWATER DRILLING ACTIVITIES .................................................................. 6

TECHNICAL ISSUES ................................................................................................................................. 9 3.1 3.2 3.3 3.4 3.5 3.6 3.7

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

4

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

5

ABBREVIATIONS..................................................................................................................................... 48


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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).


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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:

2.2.2

Atlantic Margin (UK, Ireland, Faeroes) & Norway

Gulf of Mexico

Brazil

Mediterranean

West Africa

Other locations include South East Asia, Australia, Caribbean and the Caspian.

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. Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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 Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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


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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 (Eaton’s 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

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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

Fugro’s 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 Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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have so far been detected West of Shetland (there is a far greater danger in West of Africa and Barents Sea). Norway’s 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.


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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

3.2.9

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.

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.


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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 year’s 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 Elf’s 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 model’s 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. Fugro’s 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.


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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 mud’s 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:

3.3.4

Loading

Acoustic propagation

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.


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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 rig’s 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 owner’s 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 operator’s schedule. On the other hand, the previous operator’s programme timing (including their Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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delays) would also affect BG’s 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

th

$ 123k - $ 157k

rd

$ 122k

4 Gen. 3 Gen. Drill ships:

$ 185k

e.g. Jack Bates semi, April ’99: $156k /day in 5200ft WD operation. Norway: 4th Gen. / Deepwater cf. 1998: Standard Semis

$ 90k - $140k (August fixture) $ 140 - $ 190k $ 107k - $ 115k (August fixture)

N. Sea: 4th Gen. / Deepwater cf. 1998: Standard Semis

$ 90k - $150k (July fixture) $ 150k - $ 200k $ 31.5k - $ 39.5k (Sept fixture)

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

5th Gen.


$ 174k – $ 200k

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4th Gen. rd

3 Gen. Drill ships: 3.4.3

$ 65k - $ 130k $ 45k - $ 90k $ 95k (probably too low spec. for Atlantic margin)

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 nonconservative 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 Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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: Drill ships:

winter downtime

= 0.1% to 11% of time

summer downtime

= 0.1% to 1.6% of time

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, prelaid 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.


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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 Transocean’s “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. Smedvig’s “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. Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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 DnV’s POSMOOR (e.g. Global Maritime). Mooring system analysis is principally an assessment of the planned system’s adequacy based on riser analysis requirements. Optimisation of configuration could be achieved to a Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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

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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 Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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 Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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. Maersk’s “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. Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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 system’s 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 system’s 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 Petroleum’s “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 Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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.


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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.


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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 Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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: Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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 Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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. Schlumberger’s “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 ¾” BOP and 21” riser diverter and telescopic joints will be used. It will be necessary to lose the 17 ½” 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 ½” 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 Aker’s 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), subbottom profiling to adequate depth (for example conductor setting depth),


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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. Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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 beforehand. Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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Lightweight cements These have been developed for deepwater applications. An example is Dowell’s CemCRETE which has a low slurry weight (<12.5 ppg) which enables cementing to the mudline for both the conductor and surface casing strings. Additional desirable properties are low fluid loss and low permeability in order to inhibit gas migration; and also a low heat of hydration in order to inhibit the release of in –situ gas hydrates. Foamed cement has been used West of Shetland (Mobil) (as well as commonly in GoM) due to potential for SWF / SG / and to enable cementing to seabed of a weak formation. This is expensive and equipment needed deploying from Norway. Halliburton’s Deepwater Flow Stop is an example of such a cement. Conventional lightweight slurry would be acceptable were it not for the above fears. 3.5.7

Structural Foundation Design Issues

Swathe bathymetry data should be used for guidebase installation. Piston cores and CPTs do provide soil shear strength and density data for mats/ guidebase design purposes. Expensive geotechnical boring can provide the best localised data for design purposes. Boring is system specific, with target areas in the soil profile. One boring to 30m is normally taken with soundings for lateral variation. The data can be used for the following:

Pile Design

Pre-Pile Platform Stability

Template / Manifold – (the required boring is shallower)

Mudmat design

Shallow pin / Alignment Piles

Such a boring study should be undertaken if there is lack of confidence in offset soil data and soil integrity in general, plus an identified risk of geohazards. For more information, refer to the Shallow Hazards section. If the soil is found to be too soft to provide adequate support for the guidebase, so called “skirts” may be fitted to redistribute the load to lower (and hopefully firmer) soils. Mudmats have been considered in the past, in order to redistribute the load of the conductor and first casing string whilst waiting for the cement to set. They have been known to sink into soft seabeds beyond trace. The size of mudmats realistically required is impractical. 3.5.8

ROV Requirements

At least one heavy duty, high performance work class ROV should be permanently on the rig. Two ROVs are really necessary until the riser is connected, to cover for breakdowns during weather sensitive operations. Delays have been experienced due to ROV station keeping problems in large currents near the seabed. A 50 hp vehicle should be minimum a requirement. 100 hp is a much better specification, although it should be noted that the specification does not include power losses. Other specifications are as follows:

the ROV should be cage supported /protected (“TMS”)

two manipulators


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three TV cameras (two on ROV, one on TMS)

depth and heading control

minimum 3 knots speed in all horizontal directions

ability to operate in a minimum of 2 knot current at the BOP level

spare parts to allow full repair on location

launch within one hour of being notified to dive.

Inspections should be as follows:

Riser inspection once every two days

BOP stack, wellhead and bull’s eye inspected each dive

Look for leaks, hydrates, and compare riser angle with the electric riser angle indicator

Contract with the ROV company Clear, comprehensive and detailed procedures should be agreed. The ROV personnel and company must have deepwater experience. The ROV must have full specification for deepwater. The ROV operator should practice stabbing in the hydraulic BOP intervention tool, when on the rig. Other ROV uses: A powerful zip pump is required to clean the wellhead area prior to running the BOP. The cuttings pile can block the side valves on the 36” conductor (which are used for returns and stopping SWFs) - and an ROV cleaning up operation is required. Cuttings build up can even obscure the PGB; in one case a 13.5 hr clean up time was required (in order to fabricate a tool and conduct the jetting) to enable the wellhead to be seen. The presence of the well will disturb the seabed current pattern and sediment transport. This could lead to a build up of sediments around the well which may need clearing using an ROV before disconnecting riser and abandoning, and for access to the BOP. There is a visibility issue if currents are low (which is unlikely in the Atlantic margin but delays have been known in the G.O.M.). One suggested policy is to have the ROV sitting on the seabed whilst not in use – and only brought up for a tool change. It is necessary to confirm whether this is acceptable or not with the ROV contractor. 3.5.9

Casing Design

Whilst preliminary designs for lower casing strings may be performed based on offset data, the upper casing setting depths and conductor design must wait for detailed seismic analysis and geotechnical boring data regarding the likelihood of shallow hazards and the structural integrity of soil to a few 100 metres. Useful geotechnical data for prediction of the likes of shallow geopressured aquifers is: pore pressure (up to 580m below mudline), stress-strainstrength, density, compressibility, stress history, permeability, temperature, and frac gradient. Lab tests: consolidation, permeability, static shear & triaxial tests. Such a level of detail can only be provided by an advanced boring operation, or a close offset well. In the G.o.M. extra casing strings are required due to shallow water flow risk. Overpressures further down, leading to very narrow margins between pore and fracture, cause the need for further casing strings. The result has been that many G.o.M. wells have not achieved desired TD with a desired hole size; in execution if not in planning. This should not be an issue Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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W.o.S., for example, as overpressures are less likely. An extra casing string to isolate a shallow geopressured aquifer could well be a costly necessity; either predicted by seismic interpretation / coring, or careful monitoring of PWD. Contingency designs to include such a problem should be made, and rig crew made aware of the risks in shallow sections. Preliminary study of pore and frac pressure prediction, lithology and needs for zonal isolation must be made. This provides estimates of CSDs and mud weights, which are used in casing design analysis, and riser design analysis. Well Control studies will indicate if the gas kick load case may assume a constant bottom hole pressure. The use of real time drilling pressure data to alter well plans can lead to great cost savings, as deepwater pre-drill pore pressure prediction can be inaccurate. Flexibility in well design, such as providing contingency designs ready for use is advisable. Hydrate inhibition is limited by maximum allowable mud weight requirements. 3.5.10 Well Control Studies If casing shoe depth optimisation is sought, both a conventional gas kick load case, and also kick simulation studies should be considered. Where a narrow margin between pore and fracture pressure exists, a review of choke line ID requirements dependent on rheology range and worst case temperatures and pressures should be considered. This will identify if chokeline friction losses can cause well control difficulties, and give guidance on suitable SCRs. Such simulations will also indicate choke control requirements as gas “swaps out” into the chokeline. Mud gas separator sizing studies should be conducted. Riser kick studies should be conducted- e.g. collapse rating, and the use of a riser fill valve. Riser gas handling studies should be conducted. Procedures, training and equipment are detailed in the “Rig Operations Planning” chapter. See also the GRTC Report: 2967. The margin between pore and fracture pressure is much less of a concern W.o.S. than in G.o.M. 3.6

Rig Operations Planning

3.6.1

Rig Locationing

In deepwater there is uncertainty in the horizontal spud location in relation to the rig location. The offset tolerances allowable for drilling, running in and out of template and latching should be identified by the riser analysis and rig owner’s specifications. When the spud BHA tags seabed, an ROV fitted with a beacon interfacing with the rig’s Honeywell acoustic positioning system may be used. With the ROV on bottom located against the drilling string, the spud location may be determined relative to the intended position. If this is within tolerance, the well can be spudded without any repositioning of the rig. Three hole markers can be deployed by the ROV to facilitate the stabbing of the conductor. Calculation of the well spud position at seabed critically depends on acoustic propagation factors (water temperature, salinity, and density across the full water column. Tide tables for the location should be consulted on the rig. In the G.O.M., Marathon used DGPS and hydroacoustics for positioning DP Ship Class1. 3.6.2

Drillstring

Drillstring bending / buckling and clash with guidelines can occur before the riser is in use. Careful control of weight on bit is necessary. A packed assembly should be used. For the 36” Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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X 42” hole the use of a motor in the BHA allows the start of drilling without rotation. This minimises string vibration and helps to maintain the top of the well vertical. This procedure should be coupled with the use of MWD. Vibration analysis and VIV analysis may be performed if this is thought to seriously delay operations. 3.6.3

Conductor Placement Procedures; Cements and Cementing Procedures and Equipment

These topics are addressed in the engineering design section. Well integrity is vitally dependent on competent execution of these activities. Note should also be made of the drilling hazard requirements regarding cements. 3.6.4

Drilling Operations Deepwater Specific Hazards: Indicators and Procedures.

Crew Awareness and General Preparation Rig crew must be aware of deepwater specific procedures and hazards, and be attentive to indicators. Open hole drilling guidelines are given within the conductor design section. This section focuses on shallow hazards. Clearly specific muds, cements and equipment need to be arranged well in advance of the operations. The procedures for the detecting and handling of shallow hazards including the use of MWD should also be made clear to the rig crew. The prediction of their presence was discussed in the Shallow Hazards section. Shallow Water Flows Shallow water flows are from overpressured sands in the first few 100m (900 to 2000 ft in Gulf of Mexico) below the mudline. Casing setting depth selection, drilling and cementing practices are discussed in their appropriate sections. SWFs are particularly common in the G.o.M.: in the first section below the drivepipe there is a risk of 9.3ppg EMW SWF: one can use a 10.5 to 11.5 ppg mud, riserless with returns to the ocean floor. It is a mistake to drill these zones underbalanced to avoid fracture. SWF ruins inplace cement jobs. Muds should be used that give a “tenacious” filter cake through the porous sands, and have some plugging material to get tip screen –out to stop fracture propagation. Marathon recently used Dowell Nitrified Class C /Gypsum cement slurry. Foamed cement is a favoured option in the G.o.M. MWD / LWD must be used to spot the top of any SWF zones. The consequence of shallow water flow can be 9 days’ re-spudding if it occurs (Shell, VoringNorway). Shallow Gas The use of casing centralisation, mud rheology for cleaning, and special low temperature cements to prevent gas migration should all be employed. Use conventional diverter procedures and have plans for abandonment. In Situ Hydrates In-situ hydrates are not usually a cause of wellbore failure, but gas in the wellbore stops zonal isolation – as it creates channels in the cement sheath. Cement with low hydration heat Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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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. Ooze Formations 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. 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. NPD project geotechnical coring 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 (Norway) has 600m of ooze sediments. A very strong conductor was used there by Saga: 36” ID and 1.5” wall thickness, as support for riser and BOP. Prediction of any overpressures should be together with PWD measurement. Mud and cementing contractors should be contacted for chemical stabilisation options: polymer / particulate blends. Drilling and cementing of the conductor through the ooze will be critical in establishing the mechanical integrity of the wellhead and riser. 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 in the planned drilling area should at least be indicated by 3D seismic. This is further discussed in the Case Studies in the Conductor Design section. A sodium silicate plug plus overbalance can be used when such zones are encountered. Obviously the usual use of LCMs, cross linking polymers, and slow circulation rates for mitigating fluid loss may be employed for more consolidated sands. Seafloor Washout Seabed currents remove cement in the annulus near the mudline, and wellhead / riser bending can result. The currents are too large to use a top-out string even with ROV: BJ Services have a “Titus” system specifically to address this problem. Salt Salt is very common in G.o.M.: long sections of salt make ROP an issue. Normally salt saturated WBM is used (ROP = 12-15 ft/hr). OBMs give a 15-20 ft/hr ROP but lost circulation is then an issue in the rubble zone beneath the salt. Baker have found it necessary to use a straight hole drilling tool with a 6-5/8” drillpipe. 3.6.5

Real-time Pore Pressure Prediction

It is advisable to integrate pore pressure data (LWD resistivity and sonic logs, drilling exponent, mud gas levels, drilling parameters) in real time and compare to the CSD decision Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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tree: this can lead to removing a string or setting deeper e.g. $7m saving (as reported by Shell / Eamonn Doyle Geopressure Systems Inc). Such procedures indicate Shell’s discomfort with deepwater pre-drill pore pressure correlations, and also the scope for cost savings by remaining flexible to real time data. Schlumberger use Forward Modelling of Log Responses in geopressured formations. It is advisable to take sonic logs from shallower hole sections than is normal, to relate shallow velocities and pressures. The continuous review of the well plan using MWD, density and resistivity for real time pressure prediction is a lesson implied by BG’s experience in Trinidad’s water depths. In the event of MWD failure, single shot surveys should be dropped and retrieved every 500 ft. One should check in advance the compatibility of MWD sensors and cabin hardware. A fairly new method of seismic measurements while drilling (Baker Atlas “Tomex” / Schlumberger) should be considered, but is only applicable to roller cone bits in hard shale formations. 3.6.6

Drilling Riser Management

General Issues Each Rig will have specific riser operating limits (“drilling window”) and riser design limits (a surface conditions design criteria based on maximum riser angle) and guidelines which must be followed. These will often exceed API specifications. A very large riser tensioner capacity will be required. This is specified by analysis work, and can often be non-conservative. Quick and easier to use connectors should be considered. One example is “CLIPRiser” (Kvaerner Oilfield Products): a 3.5Mlb tension breech-block type connector –which is much quicker to make up and run. Their ratings should take into account the riser analyses. Riser deployment procedures should be in place. Note the difficulties and delays if fairings are employed. A riser fill-up valve should be installed at circa 450 ft BWL. It is good practice to test the Choke and Kill lines at the stages where they have been deployed down to 1/3 and also 2/3 of the total WD. A riser degasser of 1.5 times the size of a poorboy degasser has been used in the G.o.M. The specification will in practice be constrained by whatever the rig has available. Impact of Riser Analysis Study on Operations The Riser / Wellhead / Conductor system design will have assessed the capability and operability of the vessel for the location (water depth, seabed) and drilling slot (weather conditions). The “operating envelopes” 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 in a particular short term forecast seastate. VIV analysis in particular indicates top tensioning requirements for the rig. The VIV analysis will predict fatigue lives and hence monitoring and inspection requirements (see below). Riser Disconnect and Trip Procedures These are normally very slow, particularly on a DP vessel. Hydril claim to reduce it to as low as 6 to 8 hours using a Near Surface Disconnect Platform at 300 to 2,500 ft depth (below Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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large currents) providing a shorter trip time. Station Keeping Management and Disconnect Decision Making Real time visual display of riser angles, slip joint stroke and rig position is crucial. Any decisions for action should be based on these parameters and also weather forecasts compared to operating envelopes (from engineering analyses). DP failure consequences on maximum riser angles and slip joint stroke should also be considered. The decision to adjust vessel position or suspend drilling or even disconnect riser may then be taken. The decision making process can be optimised using software such as Global Maritimes “Skaas” system, installed by Mobil on the Jack Bates semisub. Riser Monitoring Requirements Measurements of riser response can be used for monitoring fatigue damage accumulation and calibrating the results of the riser analysis. Measurements may be taken using strain gauges to give riser stresses directly or accelerometers to give displacements. 2H can supply accelerometers and the associated data interpretation service, for example. The accuracy of the riser analyses can be determined and the fatigue life of the riser updated accordingly. This rationalises riser inspection schedules in terms of severity of riser operating conditions rather than a simple time based approach. Monitoring devices may be either “passive” or “on-line”. Passive devices store the data; online devices transmit the data to the vessel. Passive devices are more suited to drilling risers that are regularly disassembled. This approach has been successfully implemented W.o.S. and in the Voring Basin (Norway). The main benefit of monitoring fatigue is for fatigue damage prediction for subsequent development drilling in the same region. The same comment applies to current profile measuring while on location. Current velocity profiles may be determined using an acoustic Doppler current profiler. This may be less accurate than actual subsea measurements. Riser joint fatigue history should be recorded. Each joint is tagged. The remaining fatigue life of each joint should be provided by the supplier. Riser Wear See previous section on Riser Design. Wear may be detected when the riser is connected by sonic logging. Motion compensation Accurate tide tables for the location are needed. 3.6.7

Well Control Issues

Reference should be made to the IADC Deepwater Well Control Guidelines and the GRTC Report No.: 2967- “Deepwater Well Control and Design”. The following technical issues should either be addressed, or considered for further investigation:

Relevant Rig Staff should be trained in Deepwater Well Control procedures. Awareness of choke control difficulties during “gas swap out” is particularly important.

Hard Shut In should be employed if a kick is suspected. No prior flow check


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should be undertaken. In this way any kick size is minimised.

State of the art kick detection equipment should be used.

Gas handling requirements: MGS sizing studies should have been conducted, a riser gas handler and drillstring valves installed (or at least considered).

Non-conventional choke and kill lines may be recommended by Well Control studies. This is unlikely for the Atlantic Margin and likely for the Gulf of Mexico.

Control lines should use a MUX system.

A funnel for guiding the BOP into place when it is deployed should be included as a part of guidelineless wellhead systems (which are recommended for beyond 500m WD).

The BOP needs a high pressure rating. The use of 10K or 15K should be assessed against water depth, well design and kick control analysis including underground blowout.

The BOP stack should allow ROV intervention.

A pressure gauge as part of the BOP stack is strongly advisable for well control purposes. Choke line friction loss effects make surface control confusing.

The LMRP should have test valves to allow pressure testing of choke and kill lines while running the LMRP without the BOP stack.

Procedures must also be in place to manage the following:

Riser Kick.

Subsurface blowout.

Subsea blowout.

The Driller’s Method of Well Control is advisable to minimise shut-in period, due to the risk of hydrate formation blocking the BOP. Gelling of lines can occur- pre-circulating choke and kill lines may be advisable before conducting a well control operation. Rig based kick simulators should be considered–especially if overpressures are a risk and crew are inexperienced. Such a tool can be used to compare “ideal control” against actual control, and indicate whether an underground blowout will occur, or whether a dynamic kill is possible. 3.6.8

Drilling Fluids

Note should be made of the drilling operations section regarding the use of drilling fluids for deepwater hazards management. W.o.S. Top Hole Drilling It is standard practice W.o.S. to use seawater and viscous (bentonite and /or guar gum) sweeps (8.7 – 9.0 ppg) with returns to seafloor for the top hole. Before running the 20” casing, the use of simple gels for the high vis sweeps avoids storage problems for this phase, as not much barite is used, and 1000 to 1500 bbl kill mud is needed, along with enough cement for the 20”. One should then sweep the hole with 5m3 of mud each joint and 10m3 prior to taking a teledrift survey each stand e.g. for a 17-1/2” hole for 13-3/8” casing on Elf’s UK 205/17A-1 (460m to 1000m in 365m WD). Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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G.o.M. Top Hole Drilling The following issue is relevant to the G.o.M. Due to cost, environmental impact, and lack of knowledge of the extensiveness or otherwise of shallow geopressured aquifers; it is unlikely that such a sacrificial mud system and procedure would be employed. As knowledge of Atlantic Margin shallow geology grows, this may be an option to consider there. The riserless drilling phases mean that 1000s bbls of fluid are lost: when riserless drilling of 26” hole (due to risk of SWF / SGF), 1000ft of hole implies 20,000 to 30,000 bbl of fluid can be lost in a day. The cost is obvious; the storage capacity of most deepwater vessels does not exceed 30,000 bbl- causing serious logistics delays. There are 3 alternatives: 1) Pump the fluid from workboats, which are very weather sensitive; 2) Store a lower volume of heavy weight mud and add seawater as pumped e.g. 15ppg of 10.5 ppg 30,000 bbl equivalent still takes up more space than allowable on all but the newest vessels; 3) A new concept: store 30,000 bbl in the semisub’s ballast tanks, which causes drill contractors concern over corrosion from salt. In one G.o.M. example, the rig’s ballast tanks can take 26,000 bbl premixed fluids, with seawater pumped into tanks for stability during the job: the pre-mix must be solids free and biostatic and leave no residue. This solution avoids weather issues. This option may well be blocked by the rig owner. The second option has been used by Marathon in the G.o.M. They used Saltwater / Polymer of 15.5 to 12 ppg diluted on the fly. Special Deepwater Formulations or Requirements Hydrate inhibition is limited by a maximum allowable mud weight requirement. Hydrate formation is more of an operational concern in WBMs where a gas kick does not dissolve downhole and therefore migrates to the BOP during shut-in. Formation envelope prediction is non trivial due to salinity effects. Please refer to GRTC Reports No: 2679 and 2967, and the IADC Deepwater Well Control Guidelines for more details. Other Issues Twice the hole volume should be made up at any time OBM policy: treatment for re-use; ship to shore and cuttings treatment. The UK will almost certainly require the use of WBMs. Should also consider the use of supply vessels for OBM cuttings ship to shore- this is expensive and can lead to serious wait on weather problems. Awareness of mud gellation times and shear strength upon pumping start up is advisable. Circulation of choke and kill lines before starting a kill procedure may be necessary. 3.6.9

Core sampling

The issues that relate to downhole wireline logging and coring in offshore wells drilled in deep water, are the same as those drilled in 30m to 61m of water. Obviously coring may be unsuccessful from any unconsolidated sands. A more likely scenario is that the target zone has been weakened by drilling fluid in interbedded zones. Careful mud mixtures are necessary for these zones. 3.6.10 Well Testing For drilling an exploration well in deepwater, a DST will be a more likely choice than an EWT, mainly due to rig rental costs and legislation limiting “exploration” flowing time to 96 hours. EWTs are considered below for development purposes.


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Electrohydraulic MUX Disconnect Control Systems In deeper waters, where the use of DP vessels becomes increasingly necessary, the requirements for a swift disconnection procedure limit the choice of control system to an electrohydraulic MUX. Typical disconnect times are 10 secs, compared to a typical DP vessel drive-off time of 15 secs (based on a reasonable allowed excursion zone). The MUX system is interfaced with the DP control system for immediate response. A sequenced closure and unlatching then takes place, a retainer valve keeping the contents above it in the landing string. Environmental spills may be avoided by employing this system. Both Schlumberger and Expro are suitable vendors. Electrohydraulic pods need to be ordered well in advance, as they are limited in number. Most of the other DST equipment is standard. Hydraulic Disconnect Control Systems Less effective control systems that may be used in shallower water depths are hydraulically actuated in up to 1500m WD, and lead to disconnect times of 20 secs- clearly inadequate for DP vessels, but may be adequate for moored systems. Petrobras have conducted dozens of deepwater well tests using hydraulic systems which met their 30 second unlatching time requirements. Operations Planning Each element of the design and programme should be HAZOPed to identify possible failures and consequences. This allows any problems to be properly managed. Equipment design can help (particularly for EWTs) in hazard prevention and control. DP well stem testing operations have been successful in harsh environment water of up to 1500m WD. A risk analysis of DP unit DSTs or EWTs should be conducted to assess vessel offsets, weather conditions, drive off and drift off situations (including DP system reliability), and disconnect time. DP well testing should have carefully determined safe operating weather windows and vessel offsets. Hydrates Chemical injection is required for hydrate prevention. Chemical injection is normally at the mudline (which has proved adequate in Brazil), but can be both below seabed or (additionally) in the riser, as required. Thermodynamic studies or field experience is required to make this decision. Coiled tubing intervention is possible, but expensive and complex in mid-test. BP have employed thermal tubing (see lessons learned below). Care needs to be taken in controlling any gas, as it will expand significantly as it moves from the depth of the seabed to surface. Lessons Learned BP (Barden project, deepwater Norway) reported a two year pre-plan with the operating group and NPD approval. A very complex DST string was required. 15k DWCS and subsea pod were used, a thermal landing string was used (as hydrate prevention would have required a 20 degC shift). A surface shroud was specially fitted to divert any gas to the poorboy degasser. The test took 15 rather than 10 days (with a $1.3 million incremental cost). The operation was in 1000m water in Feb/March.


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Completions Design In the G.o.M., large flow rates and minimum intervention requirements imply 4 to 4.5” ID tubing and single completions. Gas hydrates and paraffin are tackled by mudline inhibitor and solvents injection. Wear on completion risers in deepwater has been reported. Extending DST Information The following technique will probably be prohibited for an exploration well by the 96 hours’ flowing time limit. This technique is a new compromise between DST and EWT (mainly for Development Wells): In deepwater in particular, the choice between DST and EWT is frugal data upon which to base field investment, compared to the added rig time and cost. Centrilift (Baker) have developed a compromise which uses an ESP with a variable speed controller in the DST. This enables the well to be assessed for an assumed range of inflow and deliverability. The DST is therefore not relied upon, but rather provides information upon which to decide on an EWT. This process can also capture rather than flare oil (the so-called “EDOR” technique). The EDOR system provides a diminished risk of progressing to an EWT, environmental benefit, and oil sales which may partly pay for a prolonged test. Two EDORs have been conducted in the North Sea, one offshore East Canada. Other Issues Most of the other reported difficulties reported with respect to deepwater well testing refer to HPHT reservoirs. These problems are: Riser vertical expansion during the well test.

Riser annular fluid selection. Heavy mud may settle and be “baked” during an extended high temperature test. The alternative of a clear brine may cause a large underbalance for HP reservoirs.

“Baking” of O-rings and seals on DST tools.

3.6.11 Abandonment Any well drilled in deepwater will almost certainly not be suspended, but rather abandoned. This is a consequence of the high rig rates for vessels capable of drilling in such water depths. Moreover, even if the well could be re-entered in theory, re-entry is unlikely due to the well being quickly buried. Deepwater specific abandonment issues: 1. Cutting depth for 9-5/8” casing (if cutting, pulling and recovering is economical):

If the pressure test is OK: then cut 100 ft below wellhead

If the pressure test is negative: then cut 1000 ft to allow a cement plug to be set in the previous casing to isolate any exposed formation.

2. Explosive cutting may need to be run on drillpipe rather than wireline. 3. The presence of the well will disturb seabed current pattern and sediment transport. This could lead to a build up of sediments around the well which may need clearing using an ROV before disconnecting riser and abandoning. Case Studies: Conoco /Arco- the stack was released in a 2 knot current: the riser fell onto the side of the moonpool and was stuck for 3 days. Abandonment tools also stuck in the wellhead. This Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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lesson learnt is generally relevant to riser running- engineering studies to indicate acceptable weather windows would be useful. Similarly (205/17A-1, Elf): it took 74hrs to set and test all plugs, a further 37.5 hrs to pull the BOP and riser (the riser swung across the moonpool and up against the sides). Cutting the wellhead took 3hrs, recovering the wellhead and PGB took 33.5hrs total. 3.7

Tendering For Engineering Design Companies With Significant Harsh Environment Deepwater Experience

3.7.1

The Purpose of The Following 2 Sections

The use of “standard” or “preferred” contractors must be challenged for drilling a well in extreme conditions of deepwater and harsh environment. The size of the financial risk involved in many of the operations means that compromises in the standard of selected contractors cannot be justified. The fact that a particular contractor does have practical experience of deepwater harsh environment drilling projects demonstrates both the confidence of other Operating companies in their competence, and that they will be much more effective by applying their in-house practical learning experience. Deepwater harsh environment drilling project experience must therefore be a basic requirement. The services required can be highly specific, therefore a generally high reputation does not prove contractor suitability. What follows is far from an exhaustive list of suitable contractors. It simply gives recognised industry leaders in their particular field. These companies should be used as benchmarks in a tendering exercise. Their proposed necessary scope of work should in particular be noted and used in combination with the detailed technical specifications given in this document, as a basis for cost quotations; as other contractors may otherwise offer a more superficial service (due perhaps to lack of ability or experience) and thereby give a lower cost quotation. 3.7.2

Riser Design, Particularly VIV Analysis

This is a critical component of the system. Rig rates and operational complexity combined with equipment costs make riser integrity almost as important as the well design itself. The great complexity of the necessary design and assessment process specifically for deepwater harsh environment means very specialised contractors are needed. 2H Offshore Engineering (now part of UWG) have written guidelines on Drilling Riser Management for the AMJIG group, and are now acting as consultant to the Deepstar Drilling group. They are running a Production Risers “STRIDE” JIP (16 Operators involved). They are active members of the “Shear7” MIT JIP. They have been involved in riser analyses including VIV on the likes of Foinaven (with their operating envelope graphs used on the rigs), Schehallion and Nyk High, as well as assessment of the Sovereign Explorer’s W.o.S. operability for Arco, and a detailed study for AHL to determine 20” to 13-3/8” cross over depth to eliminate the 20” casing. They have also developed VIV data logging equipment. They prefer to perform a complete riser study, and work with Noble Denton who handle Mooring Analyses. WS Atkins have had significant experience in VIV design. They are the authors of the widely used offshore structural analysis package suite “ASAS”. They are contributing to a “Conductors” JIP looking at conductor – soil loading interaction in deepwater. MCS have been mainly involved in production riser design and analysis. They are the authors of the industry standard “FLEXCOM 3D” nonlinear time domain riser analysis software package. They have been involved with Noble Denton in developing the integration of (production) riser and mooring analyses (respectively), to study clashing issues etc. Non VIV related riser studies (such as nonlinear time domain analysis) can be conducted by Classification: Restricted to BG Group Personnel Title: Deep Water Drilling Guidelines Rev: A01

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a competent deepwater contractor such as Noble Denton; but an integrated study of riser loads and conductor is highly advisable including VIV, as riser design should be an iterative loop. Noble Denton’s deepwater riser analysis experience includes Sovereign Explorer (1280m water depth) for Amoco, and Sedco 700 in 1200m water depth. 3.7.3

Station Keeping Assessment

Noble Denton Their station keeping analysis experience includes Sovereign Explorer (1280m water depth) for Amoco, Sedco 700 in 1200m water depth, and Ocean Alliance (1400m water depth) for NDP (Norwegian Deepwater Project). They are also experts in DP system reliability, and rig enhancement requirements. Global Maritime, WSAtkins, and MCS are other consultants with deepwater experience.


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4

KEY REFERENCE DOCUMENTS

1. Watson A.G. & Munday K., “Cuttings Disposal: Ship To Shore” GRTC R 3147, BG Technology, August 1999. 2. “Generic Solutions For The Deepwater Drilling Programme (2000-2001)”, Noble Denton for Elf Exploration UK plc, February 1999. 3. “The Technical Requirements and Vessel Capabilities Required For Atlantic Ridge Drilling”, Global Maritime for Elf Exploration UK plc, August 1998. 4. “Riser Management Guidelines”, 2H Offshore Engineering Ltd, for AMDRILL (AMJIG), 1999. 5. “Guidelines For ‘Routine’ and ‘Non-Routine’ Subsea Operations From Floating Vessels”, The Institute of Petroleum, London, August 1995. 6. Stewart M.A., “Vortex Induced Vibration – Implications For Deepwater Drilling Operations”, GRTC R 2493, BG Technology, December 1998. 7. “Deepwater Well Control Guidelines”, IADC, 1999. 8. Stewart M.A., “Deepwater Well Control and Well Design”, GRTC R 2967, BG Technology, April 1999. 9. Tribbe C. & Stewart M.A., “Hydrates In Deepwater Drilling Operations: Formation, Prevention and Remediation”, GRTC R 2679, BG Technology, December 1998. 10. “Deep Water Drilling Feasibility Study Vol 1&2”, Global Marine Integrated Services on behalf of BG E&P, December 1996.


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5

ABBREVIATIONS

ABS

Artificially Buoyant Seabed

AFEN

Atlantic Frontier Environmental Network

AHL

Amerada Hess Limited

AHT

Anchor Handling Tug

AMDRILL

Atlantic Margin Joint Industry Group, Drilling Subcommittee

AMJIG

Atlantic Margin Joint Industry Group

API

American Petroleum Institute

BGS

British Geological Society

BHA

Bottom Hole Assembly

BML

Below Mud Line

BODC

British Oceanographical Data Centre

BOP

Blow Out Preventer

BRT

Below Rotary Table

BSR

Bottom Simulating Reflector

BWL

Below Water Level

CPT

Cone Penetrometer Test

CSD

Casing Setting Depth

DEA(E)

Drilling Engineering Association (Europe)

DnV

Det Norske Veritas

DP

Dynamic Positioning

DST

Drill Stem Test

ECD

Equivalent Circulating Density

EIA

Environmental Impact Assessment

EMW

Equivalent Mud Weight

ESP

Electrical Submersible Pump

EWT

Extended Well Test

Ft

feet

G&G

Geology and Geophysics

G.o.M.

Gulf of Mexico

GRTC

Gas Research and Technology Centre

HR

High Resolution

HSE

Health and Safety Executive

HW

Heavy weight

IADC

International Association of Drilling Contractors

ID

Internal Diameter


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LCM

Lost circulation material

LMRP

Lower Marine Riser Package

LOT

Leak Off Test

M

metres

MGS

Mud gas separator

MIT

Massachusetts Institute of Technology

MUX

multiplex

MWD

Measurement while drilling

NDP

Norwegian Deepwater Project

NESS

North East Storm Study

NPD

Norwegian Petroleum Directorate

NWAG

North Western Approaches Group

OBM

Oil Based Mud

OD

Outer diameter

PGB

Positioning Guide Base

Ppg

Pounds per gallon

PWD

Pressure While Drilling

QRA

Quantitative Risk Analysis

R&B

Reading and Bates

RAO

Response Amplitude Operator

RKB

(below) Rotary Kelly Bushing

ROV

Remotely Operated Vehicle

SG

Specific gravity

SGF

Shallow Gas Flow

SWF

Shallow Water Flow

TD

Total Depth

UKOOA

United Kingdom Offshore Operator’s Association

VIV

Vortex Induced Vibration

VLA

Vertical Loading Anchors

WBM

Water Based Muds

WD

Water Depth

WOB

Weight on Bit

W.o.B.

West of Britain

W.o.S.

West of Shetland

WOW

Wait on weather


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Deep Water Drilling Guidelines

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