Design aspects of an ultra deep-water drillship with crude oil storage capacity

Design aspects of an ultra deep-water driliship

with crude oil storage capacity

TU Deift

Design aspects of

an

_{ultra deep-water driliship}

Design aspects of an ultra deep-water driliship

with crude oil storage capacity

COURSE WORK

E.F.J. van Leeuwen

M. Spilker

IHC Gusto Engineering BV

Supervisor: Jr. J. Lusthof

Document nr. 6204.1000.301

Schiedam, 1998

TU Deift, Maritieme Techniek

Supervisor: Jr. H. Boonstra

Professor: Prof. Jr. A. Aalbers

TU Deift

Report nr. OvS 98/10

IJGUSTO

Preface

This report forms part of our graduation work at TU Deift, Maritieme Techniek. The entire work is performed by order of JHC Gusto Engineering By.

The interest of this report is twofold:

Readers, who are interested in design aspects of a driliship with storage capacity, should read chapter 4 and 7.

One, who is more interested in the economical comparison of different concepts, should read chapter 5, 6 and 9.

We would like to express our gratitude to Ir. H. Boonstra and Jr. J. Lusthof for their support. We really appreciated the freedom we got to sail our own course.

Schiedam, June 25 1998 E.F.J. van Leeuwen M. Spilker

tntroduction

The latest trend in the offshore industry is ultra deep-water oil field exploitation. Current driliships are not capable of drilling the required wells. Therefor, new designs

will have to be developed. This report has two goals.

To define all design aspects required for the design of a driliship capable of drilling in waterdepths up to 3000rn,

To investigate how such oil fields can be exploited in the most profitable way. In this report we will only set up a frame for drillship design. In a later stage the actual design will be made.

The first chapter contains a literature study to get familiar with recent developments. In chapter two, all major regulatory restrictions on overall design, as required by several organisations, will be summarised. Chapter four deals with operational details of all stages of oil field development. In chapter five several concepts of developing an oil field will be proposed. In order to compare those concepts economically, an evaluation method is stated in chapter six. In chapter seven, a concept exploration model will be composed to be able to generate the required dimensions of the proposed concepts. Also many design aspects will discussed. Chapter eight treats motion characteristics and downtime calculation. In the final chapter an economical judgement of the proposed concepts will be made.

TABLE OF CONTENTS

1 Literature

1.2.3 Drilling riser technology 7

1.3 New ultra-deepwater rig with dual rotaries will reduce costs. 8

1.3.1 Discoverer Enterprise 8

1.3.2 Technical data of the Discoverer Enterprise 8 1.4 A new generation DP drillship, the GUSTO 10.000 and GUSTO P 10.000 9

1.4.1 GUSTO 10.000 9

1.4.2 GUSTO P 10.000 10

1.4.3 Technical data of "GUSTO 10.000" and "GUSTO P 10.000" 11 1.5 Ultra deepwater dynamically positioned (lrillship 12

1.5.1 Extended well testing and storage 12

1.5.2 Technical data of the Drillship 1 & 2 12

1.6 Design of Maritime Tentech's next generation FPDSO 14

1.7 Comparison of the RamRig versus conventiotial drilling systems 16

1.7.1 Introduction 16

1.7.2 The hoisting function 16

1.7.3 Heave compensation 18

1.7.4 Weight savings 18

1.7.5 Safety and working environment 19

1.7.6 Further developments 19

1.7.7 Conclusions 19

1.8 Deepwater extended well testing in the Gulf of Mexico 21

1.8.1 Conventional well testing 21

1.8.2 Extended well testing 22

1.9 Riserless drilling circumventing the cost cycle in deep water 23

1.9.1 Depth constraints 24

I .9.2 Benefits 24

1.9.3 Rig upgrading 25

1.9.4 Technical objectives 25

1.9.5 Conclusion 25

1.10 Some challenges and innovations for (leepwater developments 26

1.10.1 Drilling concepts 26

.10.2 Materials 26

1.11 Conclusions 28

I II .1 Vessel dimensions and hull form 28

II .2 Transit speed 28

II .3 Wave direction & motions 28

2.2 Environmental conditions 34 2.2.1 Wind 2.2.2 Waves 34 2.2.3 Current 34 2.3 Freeboard 35 2.4 Intact Stability 36

2.5 Subdivision and damage stability 38

2.6 Area classification and ventilation 40

2.6.1 Location and separation of spaces. 41

2.7 Size and arrangement of cargo tanks 43 2.7.1 Limitation of size and arrangement of cargo tanks 43

2.7.2 Damage assumptions 43

2.7.3 Hypothetical outflow of oil 44

2.7.4 Oil tankers used for the storage of oil 45

2.7.5 Protective location of segregated ballast spaces 45

2.8 Dynamic positioning systems 46

3 Drillship fleet related to the rules

49

3.1 Introduction 49

3.2 Freeboard 49

3.3 Hazardous areas 49

3.4 Damage stability 50

3.5 Dynamic positioning 50

4 Stages in oil field development

4.1 Introduction 52

4.2 Drilling and completion 53

4.2. 1 Accommodation 53

4.2.2 Equipment 53

4.2.3 Main dimensions 54

4.2.4 Layout 54

4.2.5 Motion characteristics 55

4.2.6 Station keeping provisions 56

4.2.7 Storage capacity 56

4.2.8 Transit speed 57

4.3 Extended well testing 58

4.3.1 Introduction 58

4.3.2 Accommodation 59

4.3.3 Equipment & processes 59

4.3.4 Production rates & storage capacity 59

4.3.5 Layout 60

4.3.6 Motion characteristics 60

4.3.7 Station keeping provisions 60

4.3.8 Transit speed 60

2 Rules and regulations

33

4.4 Production 61 4.4.1 Accommodation 61 4.4.2 Topsides facilities 61 4.4.3 Main dimensions 61 4.4.4 Layout 62 4.4.5 Motion characteristics 63 4.4.6 Regulations 63

4.4.7 Station keeping provisions 64

4.4.8 Storage capacity 65

4.4.9 Hull shape & transit speed 65

4.5 Combining stages of development 66

4.5.1 Drilling & EWT 66

4.5.2 Drilling, EWT & production 68

5 Generation of concepts

70

5.1 Introduction 70

5.2 Definition of function groups 7!

5.3 Layout 72

5.3.1 Limiting conditions 72

6 Evaluation method of proposed concepts

78

6.1 Introduction 78

6.2 Cost analysis 78

6.2. I Introduction 78

6.2.2 Discounted cash flow 79

6.2.3 Net present value 79

6.2.4 Internal rate of return 80

6.2.5 Comparison of net present value and internal rate of return models 80

6.2.6 The owner 81

6.2.7 The oil company 82

6.3 Safety 84

6.4 Multi-functionality 84

7 Concept exploration model

88

7.1 Introduction 88

7.2 Stability 89

7.3 Determination of natural perio(ls of uncoupled motions 92

7.3.1 Heave 92

7.3.2 Roll 94

7.3.3 Pitch 96

7.4 Weight calculation 98

7.4.1 Steel weight calculation E. Hagen, 1. Johnson and B. øvrebo 98

7.7 Deck Area 107

7.8 Determination of main (limensions 108

8 Downtime analysis

110

8.1 Calculation procedure 110

8.2 Description of hull shapes

8.2.1 I-lull shape concept I - TV 8.2.2 Hull shape concept V - VIII 8.2.3 Hull shape concept IX 8.2.4 Hull shape concept X

9.2 Input for the economical comparison 117

9.3 Results 118

9.3.1 Cashflow owner 118

9.3.2 Cashflow oil company 118

9.4 Sensitivity analysis 121

9.5 Conclusions 123

9.6 Which concept should a contractor purchase? 124

References

9 Evaluation of concepts

1 Literature

1.1 Introduction

The first stage of this graduation work is a literature study. There are many reasons

for doing this.

To find out what the market is demanding

To find out the technical advancement of the industry To find out critical features in design

To get familiar with the industries language

Driliships with storage capacity, capable of drilling in water depths up to 10.000 feet, are a new development. Therefor this study concentrates on recent articles. The oil industry is rooted in the US. Consequently, English units are used rather than S.I. units. For calculation and comparison applications English units are converted into

S.I. units, in colloquial text English units are used.

Firstly the deep-water driliship fleet is briefly overviewed. Then some articles about modern deepwater driliships and one FPDSO are summarised. Later on specific recent developments on deep-water drilling techniques are lined out. Finally some

1.2 Deepwater technology

Source: supplement to Hart's Euroil, May, 1997

1.2. 1 Deepwater drilling

Exploration drilling and well completion in deep and ultra-deep waters is currently a matter of availability of technology, including the availability of rigs to drill those wells. A serious shortage of units with the payload capacity and technical capabilities required for deepwater drilling is now emerging. The first reaction of the industry has been to upgrade existing rigs. Recently the branch has begun looking at alternative technologies. Even though it is possible to modify existing fourth generation semisubs for work in 10.000ft depths, there is now a clear trend towards the re-introduction of the drillship in the offshore industry. Besides basic economics, this is obviously a response to the most critical needs arising from drilling deepwater. The needs are mostly related to weights, i.e. mooring systems, riser loads, mud volumes etc. Below a list is inserted, giving an over-all picture of drillships capable of drilling in water depths of 4.000ft or more - units in operation and under construction.

Drilishins in oneration

Drilishins under construction

1.2.2 Rig moorings

The search for new technologies that can reduce the weight on rigs to drill in deepwater is much directed towards reducing weights of, or even eliminating, mooring systems. The options currently considered for station keeping in deepwater drilling include:

Dynamic positioning Steel spread moorings

Polyester taut leg mooring lines

Reliability of a DP system is an important issue. While some operators seem to depend entirely on DP systems, other maintain that DP today should be used only for assistance to a simplified mooring system in deep water. In several deepwater

development programs a comparison between the two mooring systems was made.

Unit name Max. w. depth Area Available

Discoverer 534 7.800 ft GOM 1999

Neddrill 1 4.500 ft Brazil 2001

Neddrill 2 6.000 ft Brazil 2002 Peregrine 1 6.000 ft Brazil 1999

Unit name Max. w. depth Status Delivery Contract Peregrine IV 9.200 ft Newbuild 12/1 997 Available

Discoverer Enterprise 7.000 ft Newbuild 02/1998 Amoco US

Glomar Explorer 7.500 ft Newbuild 03/1998 Chevron US

Driliship 1&2 7.500 ft Newbuild 10/1998 Conoco US No name 10.000ft Newbuild 04/1999 Shell US

For ultra deepwater applications the weight of the catenary mooring system becomes an insurmountable problem. The use of taut leg mooring systems is then preferred. 1.2.3 Drilling riser technology

The problem of the drilling riser in deepwater operations is not limited to its weight and its charge on rig variable load capacities. In deeper waters and more harsh environmental conditions, dynamic loading on the riser becomes increasingly severe

and fatigue response of the riser and welihead become design issues of major concern.

Large current speeds typical of those observed in a number of deepwater

developments can give rise to vortex-induced vibrations (VIV), whereby the drilling riser vibrates normal to the predominant direction of the current flow. High levels of fatigue damage can be generated in this way, along the entire riser length. Reduction of VIV motion amplitudes can be achieved by increasing the riser tension. However, the increase in tension must be reacted through the conductor and while riser response

1.3 New ultra-deepwater rig with dual rotaries will reduce costs.

Jon C. Cole, Robert P. Hen mann, Robert J. Scott, Transocean Offshore Inc. Houston John M. Shaughnessy, Amoco Corp. Houston

Source: Oil and Gas Journal, May 26, 1997

This paper deals about the Discoverer Enterprise. Transocean Offshore received a contract from Amoco to build this rig back in 1996. It is scheduled to come into operation in July 1998. Note that the authors are employees of the involved

companies.

1.3.] Discoverer Enterprise

The increasing demand for deepwater rigs has inflated day rates arid improved

contract terms for the drilling contractor. In response, contractors have begun

upgrading existing equipment and are converting non-drilling semisubmersible units in order to meet operator demand. Because capital costs for conversion have increased rapidly, new construction is becoming a viable alternative. Higher capital costs for deepwater rigs, with respect to ordinary drilling rigs, result in higher dayrates to provide an adequate return. To justify these higher rates a more cost-effective drilling approach is needed. One way of achieving this is by reducing the well-construction time. Timesaving can be accomplished by removing activities out of the critical path. Current drilling rigs are equipped with a single rotary table. Consequently, any additional activity that requires use of the rotary will place itself within the "critical path" of completing the well. Therefor the Discoverer Enterprise will be equipped with two rotaries, two top drives and two drawworks. As planned, the drilling riser will run off the primary rotary, the auxiliary rotary can be used to drill riserless on a template. To support the primary rotary efficiently, extensive planning should be carried out on the use of the secondary rotary. All this effort is made to enable the rig to drill uninterrupted. The 75-rn. high derrick can accommodate quadruples, rather than triples. Casing will be placed back as triples, rather than singles. Amoco expects to utilise the Discoverer Enterprise mainly for development work because completion

and testing activities are incorporated in its design. 15.900 m3 of crude oil can be

stored in the hull. This considerably reduces the cost to test and complete. Another

favourable aspect in that respect is the dedicated well-testing area on the large deck.

The rig is assumed to be able to travel at a speed of 1-2 knots with the riser suspended below the hull. It can perform a wide range of additional activities. Well-construction

simulation indicates that a 40% timesaving is achievable, justifying the high dayrates.

1.3.2 Technical data of the Discoverer Enterprise

Length overall 254,5 m

Breadth 38,1 m

Displacement 100.000 t

Deadweight 30.000 t

1.4 A new generation DP drills/up, the GUSTO 10.000 and GUSTO P 10.000

Bob Rietveld and Jeroen LusthoflHC Gusto Engineering B. V.

Deepwater drilling requires specialised vessels, enabling economic exploration and

further exploration of deepwater prospects. In this paper IHC GUSTO's new

generation driliship and extended well testing vessel are described.

Two concepts have been developed, being the "GUSTO 10.000" and "GUSTO P

10.000", which are respectively a full blown drillship suitable for operations in waterdepths up to 10.000 ft and a driliship I extended well testing unit also suitable

for l0.000ft waterdepth.

1.4.1 GUSTO 10.000

The main dimensions of the vessel are designed to provide a high payload capacity to

optimise field logistics and to have superior motion behaviour minimising downtime.

The vessel has especially been designed to work offshore west of Africa, Gulf of Mexico and offshore Brazil.

The hull size provides low costs due to reduced steel construction and delivery time,

less than 20 months.

Costs are presently less than 140 million $, excluding drilling equipment.

Power plant

The vessel is designed for dual- and even triple redundant dynamic positioning (NMD 2 / NMD 3). Two engine-rooms each supply 50% of the power; both have their own

cooling water, fuel oil and auxiliary systems. Two separate pump rooms and auxiliary engine rooms are located next to the engine rooms. Power is generated by six 4.860 kW diesel generator sets, three per engine room. The vessel will be able to maintain position with one engine room out of order in a 10-year-return-period storm if it is allowed to select its optimum heading.

Riser storage

The vessel has an open riser hold, which is designed to store 10.000 ft of 75-ft long risers. The advantage of the open riser hold is that it allows fast and safe handling of

the risers and reduces the use of overhead cranes. It also contributes to a low vertical center of gravity compared to storage on the main deck. For riser handling a dedicated system is installed over the open hold. In case of failure of the riser handling system,

Derrick, substructure and drillfloor

The vessel is designed to accommodate a single derrick suitable for dual handling operations. Triple pipe or riser stands can be made-up in the powered mousehole independent of drilling operations and placed in the setback prior to any drilling operation. The BOP can be handled in one piece and can be serviced and tested on main deck and cellar deck.

Thrusters

The vessel is equipped with two underwater mountable azimuthing thrusters aft, three

retractable azimuthing thrusters in the midship part and two bow tunnel thrusters. The two aft thrusters deliver sufficient propulsive power for a service speed of 13 knots. All thrusters are retractable and can be inspected and maintained inside the hull. 1.4.2 GUSTOP 10.000

The extended well testing version of the GUSTO 10.000 has all the same features as

the drillship, but has a storage capacity for crude oil of 200.000 bbls. The vessel can test and process the well fluids before storage.

Production

The vessel will be able to produce and test oil from at least one subsea well and will include the following functions:

Control of subsea welihead tree Choke and kill for the well stream

Testing, 1stand 2h1I stage (where required) separation of crude oil, produced water

and gas of the well stream

Export metering including a prover ioop Offloading to a shuttle tanker

The vessel is also classed as an FPSO and fulfils all necessary statutory requirements.

Crude oil storage and offloading capacity

The crude oil storage capacity of the p 10.000 is 200.000 bbls. This will allow for 20 days production at a design flowrate of 10.000 bbl/day. Deepwell pumps in the crude oil tanks enable offloading within 10 hours.

Modular concept

Because of the required crude oil storage capacity in the hull, all drilling and production equipment is arranged in modules. The mud and process modules are located aft of the derrick at 3 m elevation above the main deck, because of hazardous area requirements. Consequently, the vessel is wider due to maintain stability; the vessel length has been increased only slightly.

1.4.3 Technical data of "GUSTO 10.000" and "GUSTO P 10.000"

Main dimensions

Storage crude oil

GUSTO P 10.000 230,3 m 211 m 35,8 m 17,8 m

urn

1.5 Ultra deepwater dynamic ally positioned drills/up

Source: the naval architect June 1997

Reading & Bates home page Internet (http://www.rdgbat.com)

Affiliates of Conoco and Reading & Bates have joint forces to build an advanced ultra deep-water driliship. The ship is designed for ultra deep work in the Gulf of Mexico and represents a new generation of dynamically positioned drillships able to work in

7.500-ft water depths but plarmed, with modification, to work down to 10.000 ft. She

is equipped to American Bureau of Shipping's DP3 notation, thus providing the highest levels of safety, redundancy and reliability in dynamic positioning.

Continuous drilling will be possible in sea states up to 10-year Gulf of Mexico storm

level.

1.5.1 Extended well testing and storage

Extended well test capability, also simultaneous drilling and testing will be possible.

The vessel will incorporate EWT utilising 100.000 barrels of oil storage and

offloading. This capability will provide the operator a much better understanding of the reservoir associated with a discovery well, allowing optimisation of the production

facility should the reservoir prove commercial. The vessel could also carry out the next stage of a staged field development by drilling the subsequent delineation well while simultaneously testing the discovery well. The vessel is also designed to allow eventual conversion to an FPSO vessel. This involves installation of a full process facility and utilising 400.000 barrels of storage capacity onboard. Thus, the capability of the vessel to carry out exploration drilling and EWT operations, followed by development drilling and eventual conversion to an FPSO, would allow drastic reduction in the time and cost to bring a development project onstream when compared to conventional approaches.

Highly mechanised handling systems for riser, drilling tubulars and casing enhances safety and efficiency. The rig floor functions will be largely automated with the driller and the derrickman controlling operations from dual computer-based consoles in the

control module.

1.5.2 Technical data of the Driliship 1 & 2

Length overall 221,5 m Length b.p.p. 213,Om Breadth 42,Om Depth 20,Om Draft 13,Om Deadweight 93.442 t

41 \ L'

I--

I

--

-__-_

I- -::

'='::

-1.6 Design of Maritime Tente ch 's next generation FPDSO J. Beek, Maritime Tentech

Source: Stavanger seminar, May 21, 1997

This paper presents the design evaluations of combining drilling and production from

a newly developed Maritime TentechFPDSO.

Ten years ago there was a common attitude that the combination of production, drilling, turret, drilling facilities was unpractical and not serviceable. The main arguments were:

Handling and storing BOP, drillpipes, casing, riser tensioners, guideline tensioners and drilling risers in an already crowded moonpool is difficult.

Additional flexible lines for mud control systems required. Complicated swivels, swivel support, hard piping, dragchain, etc. Reduced cargo load capacity.

As basis for all design evaluations FPSO Tentech 850 S was used. Generally assumed drilling through the turret is the best option because placing the rig elsewhere would take a vast amount of space. When the vessel is moored on the turret, there is no other option than drilling through the turret. One of the primary concerns for the FPDSO

concept, is the foundation of the drilling rig. The rig may either be supported directly

on the turret, or on a purpose built support structure spanning over the turret. Studies determined that for shallow to medium water depths, supporting the rig on the turret is feasible. For deeper operations, the rig should be supported on a structure spanning over the turret. The turret system incorporates many systems, including subsea equipment. Unfortunately no relevant information about turret layout is given in this paper. A lot of attention is being given to the RamRig. Maritime Hydraulics AS designed a rig with two large rams providing the hoisting force. More information about the RamRig concept is given in the next paper (Comparison of the RamRig versus conventional drilling systems). Although the author doesn't enervate the

mentioned arguments for not combining production and drilling, he believes it is just a matter of time when drilling and well maintenance from production vessels will become more attractive as from dedicated drilling units.

RamRig on a turret

1. 7 Comparison of the RamRig versus conventional drilling systems

Vidar Skjelbred, Maritime Hydraulics AS

Source: OTC 8461, 1997

The drilling rig technology has basically been more or less identical over the last twenty or thirty years. Challenging technical requirements for exploring and

exploiting harsh environments has motivated the industry to search for new solutions.

One of the solutions is the RamRig.

This paper outlines differences between the RamRig (RR) and the conventional

drawworks based rig (DWBR). Improvements are specifically for the following

topics:

Hoisting and compensating system

Weight and centre of gravity

Tubular handling BOP handling

Safety and working environment

1. 7.1 Introduction

The DWBR was developed early this century and as technical requirements have increased, all new developments have been added to the existing concept. New technical requirements related to challenging deep water drilling and subsea completion have stretched the conventional rig to its limits and made the industry open to new rig concepts. The RR technology adopts these new requirements. Main

features of the concept are:

Improved operability to conventional rig

Improved personnel safety and reduced manpower

Reduced cost by lowering overall topside weight and the amount of equipment

1. 7.2 The hoisting function

The RamRig consists of the following basic elements for hoisting:

The hydraulic power unit and the piping system Hydraulic cylinders

The ram guide The travelling yoke

The equaliser assembly including lifting wires

The topdrive with guide dolly

The lifting forces to both rams are supplied from the hydraulic power unit. A travelling yoke mechanically connects the rams. The travelling yoke includes wire sheaves. The lifting wires are fixed length parallel lines with one end anchored to the drill floor and the other end to the topdrive. Underneath the drill floor the wires are connected to the equaliser assembly. This arrangement enables the RR to obtain twice the speed and the travelling height on the top of the drive compared to the stroke

length and velocity of the ram. When hoisting the entire load is transferred from the

travelling assembly, into both rams and further to the drill floor. The ram guide structure is for guiding only. The hoisting wires are sized with a safety factoragainst

breaking of 4, compared to 2 for DWBR. The lifetime of the wire is set to one year or I million cycles. No slip and cut operations are required.

Regarding availability as well as reliability of the RR an analysis based on theoretical models has been performed which concluded the following:

Expected downtime for the RaniRig is 1/3 compared to the DWBR

MTTF (mean time to failure) is estimated to be 50% higher compared to the DWBR.

The reason for reduced downtime is fewer mechanical components included in the RR

compared to the DWBR.

The following figures show time distribution of a drilling operation and the estimated timesavings gained with the RR.

Drilling time distribution

Figure 1.4

NPD statistics 1991 expl. wells, average well at 3.595m Table 1.1 Remarks I .500m waterdepth DWBR RamRig Savings Drilling 85Ohrs 808h.rs 5%' Tripping 4lShrs 332hrs 20%2 Casing 400hrs 392hrs 2% Riser/BOP 4lShrs 228hrs 45%4 Reamlothers 31 Shrs 299hrs 5%5

1. 7.3 Heave compensation

The RR has a passive and an active heave compensating system together with the hoisting system built into one common unit. All functions are controlled by a common

system.

1.7.4 Weight savings

The RR includes several elements which are favourable compared to the DWBR regarding both weight and centre of gravity (COG), and they can be summarised as

follows.

Drilling tubular setback is located in the substructure

Drill string compensator is integrated in the hoisting system

Derrick is only for guiding since all vertical forces are transferred by hydraulic

rams

Compact drill floor taking all loads in a relative small area surrounding the rotary table

A comparison has been made to verify potential savings.

Weight comparison

Table 1.2

Subject RamRig 650 tons Conventional drawworks based rig 650 t Weight tonnes COG above main deck (m) Ton meter above baseline Weight tonnes COG above main deck (m) Ton meter above baseline Drillfloor, substructureincl. Outfitting 286,5 11,42 3.273 349 11,67 4.072 Standpipe, manifolds, handling equipment, travelling assy., drawworks/rams, R.T., compensator, cabin, pipehandling, winches 89 30,1 4.448,5 208 21,1 16.380 Riser handling, chutes, catwalk machine, riser tensioners, telescope arms, handling baskets, APV's, diverters, BOP handling, HPU 3 38,5 7,82 2.648,3 5 373 6,99 2.604,9 Total 909,7 14,3 13.049,9 1.350,9 20,33 27.466 RamRig savings 441,2 5,99 14.416

1.7.5 Safety and working environment

The RR has built into the design some elements, which will contribute to improved

working environment and safety level for personnel.

Mechanised handling of all tubular with latching I unlatching of elevators at drill floor level.

Preparation of sub-sea assemblies will take place on deck

Reduced noise level at drill floor Water based hydraulic fluid

1. 7.6 Further developments

To further optimise the RR concept emphasis has been given to mainly two new

systems:

TOPIN coiled tubing system PSJ power slip joint

The TOPIN coiled tubing system development for the RamRig is designed for

efficient rig up and execution of coiled tubing operations on a floating rig.

The PSJ is a system to tension the riser without wires in the moonpool. Instead of

applying the tension force by means of wires the slip joint itself is powered.

1. 7. 7 Conclusions

The derrick is designed for guiding purposes only with the setback lowered in the substructure, which reduces overall weight and COG.

The hoisting efficiency for the hydraulic RR is equal or better than the conventional rig

All pipe-handling functions are carried out at drill floor level by means of safe and

simple equipment, this eliminates the need for a derrick man.

The RR is equipped with fail-safe braking system that reduces the risk of crashing

the travelling assembly onto the floor and reduces the risk for operator error.

Passive-, active heave compensation and hoisting are built into one system, which

is a simplification over conventional systems.

The RR layout opens a possibility to run long marine risers joints with higher

efficiency and reduces the time for same operations by 40%.

BOP handling is simplified with access from two sides of substructure and height

for all handling to take place at main deck level.

The open top configuration with no travelling block gives easy integration of

coiled tubing TOPThI technology.

Reduced noise level due to less moving / rotating mechanical parts and improved breaking system.

RarnRig for floating rigs

1.8 Deep water extended well testing in the Gulf of Mexico

M.E. Cribbs Jr., J.D. Voss, Texaco E&P Inc. L.J. DeCarlo, Conoco Inc.

Source: OTC 7265, May 3, 1993

This paper examines deepwater Gulf of Mexico well testing and the need for extended

well testing from the oil company's perspective.

In deepwater projects, development costs are so high that they can endanger a companies' economic survival. To minimise the risk, development decisions need to be made on accurate and reliable infonnation. Gathering reservoir information is expensive. An appropriate mix of drilling additional delineation wells, well testing and extended well testing is required to establish a development decision on an acceptable level of risk. About extended well testing the following conclusions have

been drawn:

Production from extended well tests would not generate sufficient revenue to

support a leased extended well test facility.

The longest duration for any GOM extended well test would most likely not

exceed two month, with typical duration being less than one month.

The cost of an extended well test on its own is not justified relative to the new information that it will provide.

1.8.1 Conventional well testing

Conventional well testing usually comprises short duration stabilised flow testing (48

hours) and provides a significant amount of information about the reservoir and well. To improve the accuracy of the obtained data two methods exist:

Extension of the duration of the well's stabilised flowing period. This allows a

greater radius of investigation during the test.

Drill additional wells and test another part of the reservoir.

Produced hydrocarbon disposal includes routine flaring in other parts of the world.

Due to possible problems associated with incomplete combustion of the well fluids, flare burners may not be sufficient and alternatives must be explored. Two technical

alternatives exist for the GOM operators:

Upgrade the well test separator size and the burner systems.

Flare the hydrocarbon vapours and collect the hydrocarbon liquids into a barge.

1.8.2 Extended well testing

Extended well testing is conducted, in addition to the conventional well test, to acquire data concerning reservoir size and time-dependent flow characteristics. The accuracy of well test analysis often is disappointing. Incontradiction to the

complexity of the reservoir, the reservoir models are simplistic. More accurate predictions call for running extended tests, which is expensive. Several joint industry projects have been performed that identify other extended well test facility

alternatives. Regardless what the extended well test equipment are, sustained single well production rates in the GOM are not expected to completely pay the facility's operating costs. Therefor, all extended well test operations have to be justified upon the basis of the knowledge gained regarding long time reservoir production behaviour

and the effect this has on reducing project risk.

An alternative to deep water extended well testing is the installation of an early production system. The objective is proving the reservoir's production capability while establishing an early cash flow. The early production system that will provide superior information about the reservoir to determine whether a full field development is justified while optimising the cost required reaching this decision.

1.9 Riserless drilling circumventing the cost cycle in deep water Allen Gault, Conoco

Source, Offshore may, 1996

Conoco, Hydril project seeks enabling technologies to drill in deepest water depths

economically.

The capacity of a currently used 21-in, marine riser

is about 400bbl of mud for every 1 .000ft of length.

The mud volume within the riser constitutes a majority of the total mud system and is of no benefit to the drilling process. The long mud column introduces hydrostatic pressures, which requires numerous casing points if a lower pressure at the mudline is necessary. Numerous casing points require a larger subsea wellhead, which requires a larger marine riser, which means that a larger drilling rig is needed to support the riser and the mud column. For large water depths it is essential to break this cycle, the hydrostatic pressure needs to be reduced to near that of a column of seawater. In order to achieve this fact, the riser, as an annulus, has to be removed and replaced with a mud return line at the welihead. Over the years wellhead size has increased. The common size for a welihead is 18-3/4 in.

Increasing the diameter of the welihead and marine riser to drill in deeper water depths, however, greatly increased the weight and space requirements for floating drilling rigs. For

example, the weight attributed to the marine riser, mud volume, additional mud pumps, and solids separation for a drilling rig in 6.000ft water depths has been estimated at 4.000-5.000 tons. The large riser diameter also requires tight station keeping while drilling. A usual rule of thumb is 5% of water depth. For drilling without riser this is about

15-20% of water depth.

Deeper water

Longer colunm of mud in riser

'V

More casing points for low fracture gradient

Larger wellheads for more casing strings

Well control more difficult

I'

Larger riser for larger welihead

I

Larger rig to support larger riser

1.9.1 Depth constraints

For drilling in ultra deep-water (lO.000ft) there are three problems with existing

technology:

The 21-in, riser cannot be pushed much further.

Even if the rig could support the riser length, the riser cannot withstand the

stresses.

Well control is marginal at best at maximum water depths now.

Several concepts to overcome the problems met while drilling in deep water were not implemented because of limits in technological capabilities in the past. Various

concepts put forth in the past included the following: Diverting the flow at the sea floor to a return line.

Gas lifting, mud density reduction, or pumping the drilling riser/return line. Isolating the riser from the welihead and reducing the hydrostatic column within

the riser.

Using a reduced diameter-drilling riser.

Combining these concepts can derive numerous configurations.

1.9.2 Benefits

There are many benefits to drilling without a riser:

Stationkeeping: relaxation of the stationkeeping will reduce waiting on weather time or a less expensive mooring system could be deployed. In the case of a DP-rig, this would reduce the incidents of drive of and provide for fewer/smaller

thrusters.

Wider well pattern: In development scenarios, a wide pattern of subsea wells

could be drilled with a more flexible mooring system.

Smaller production structure: The reduction in weight and space would greatly

reduce the cost of the floating production structure.

Time and cost: Elimination of casing points will reduce the number of days

required to drill the well, in addition to the average $1 million per casing point.

Alternative fluids: Use of a closed system to support riserless drilling will allow other drilling methods not normally considered in floating operations to be used. They include foam drilling fluids, air drilling, underbalanced drilling, and reverse circulation drilling.

Circulate out kicks: Another benefit to the use of a return line is the additional system to circulate out gas kicks, which expand rapidly above the BOP on the seabed. An 11-in, mud return line with a surface choke could handle up to 5.000psi, while the conventional choke and kill lines would be able to handle higher pressures at the seabed. Conventionally, with a 21-in, marine riser in deep water, well control consists of "bullheading" an influx back into the formation. No attempt is made to circulate the kick in a normal manner. There is little or no kick tolerance in conventional deep water drilling because the differential between mud weight and fracture gradient is about 0,3 lb./gallon. With this differential,

predictive programs are not utilised since the analysis suggests the well not to be drilled. With a mud-return line and a surface choke in place, the well can be secured and the expanding gas handled separately from the well system located on

the seafloor. Kicks could be detected by an increase in pressure at the seafloor,

minimising the influx. 1.9.3 Rig upgrading

The current deepwater market is extremely tight. Fourth generation semisubmersibles and drilling ships are all under long term contract. Third and second generation semisubmersibles are being upgraded to extend their water depth capability. The target group for conversion would be the more numerous second-generation rigs. The water depth limit would be determined by the mooring system. Were it not for the additional weight due to drilling gear, a second generation drilling rig could be moored in 4.000ft water depths. The average age of second-generation

semisubmersibles is 20-25 years, which is close to the projected useful life. This life

can be extended another 10-15 years. A purpose built rigwould have the benefit of a 25-year life. An economic evaluation is necessary.

1.9.4 Technical objectives

The Conoco / Hydrill program's objective is to identify the most likely concept of riserless/return line drilling that can be implemented with existing technology. Several concepts are proposed in the paper. The hydraulic behaviour should be analysed for each of the cases considered. The configuration of the equipment will be dynamically analysed as to practically use in floating drilling operations. The emphasis will be on interference between return lines, risers, and exposed drillstrings. Characteristic vessel motion will be included.

1.9.5 Conclusion

The development of a deepwater system to reduce casing points, in conjunction with reducing drilling costs and making more drilling units available for deepwater work, are critical to working in depths beyond the 7.000-8.000ft contour. Without it, development drilling will be enormously expensive and limit the development of discoveries with medium and small reserves. Further, if the industry is to be able to

drill, develop, and produce successfully in water depths beyond 10.00011, alternatives

1.10 Some challenges and inn ovations for deepwater developments Mamdouh M. Salama, SPE, Conoco

Source: OTC 8455, may, 1997

As the oil industry continues its effort to exploit oil and gas reservoirs in deeper waters, new technologies are required to enable the industry toproceed with effective exploration and development programs under the pressure of low oil prices. Therefor,

serious efforts are being devoted toward the evaluation and the application of

innovative approaches to reduce exploration, development and operating costs. This paper reviews the different conceptsthat are currently being considered for deepwater development and summarises the current effort to develop cost-effective composites for many critical deepwater applications.

1.10.] Drilling concepts

One of the major concerns in deepwater drilling is the large weight of risers, mud

column, etc. In order to achieve weight reduction, both equipment modifications and

material changes are applicable. Two of the main concepts that are currently being pursued by the industry to reduce weight and space involve the application of the RamRig and Riserless Drilling. The RamRig concept offers many advantages that

include lower weight (+ 30% less than conventional rig), lower centre of gravity and

consumption of less power (+ 40%). Riserless drilling replaces the conventional 21-in

marine riser with a slender mud return line, resulting in substantial weight savings.

1.10.2 Materials

Although the traditional engineering material for offshore structures is steel, synthetic

materials and advanced composites have been receiving much attention by the oil

industry lately. Components made of these materials are more expensive than their

steel counterparts. However, the economic benefit of composite components

comprises reduced system and full cycle costs. Weight savings have a direct impact on platform cost because the primary function on the platform is to support the platform payload.

A joint industry project was carried out to develop data on a 22 -inch composite

low-pressure drilling riser. The air weightof the composite system was 50% of the steel system. The total costs were about twice as high. Composite materials also are being

considered for manufacturing the mud return and choke and kill lines for riserless

drilling. A study was conducted to assess the application of composites on several

critical components. These components could be readily replaced using off-the-shelf

Weight comparison steel & composites

Table 1.3

To assess the full cost advantage of composites, the application of composites should be evaluated in a system context rather than in a one-to-one material replacement of

components. Component Steel wt (Ib) Composites cost ($) wt (ib) cost ($)

Two C&K lines 386.400 1.472.000 128.800 2.760.000

Mud separator 7.700 70.000 5.500 88.500

30 APV's 360.000 900.000 37.500 720.000

Mud pit 2.400 9.000 800 10.000

1.11 Conclusions

While reading papers on deepwater drilling, it becomes clear that there is a great interest in the market. Many designers and constructors are working on new

developments, in order to accomplish an efficient concept. They are facing problems never met before. Creative solutions are proposed; only few have actually been taken into service. Above all, profitability is a key parameter. Therefor this should be the main objective when designing such a rig. For a technical engineer, it is difficult to choose the best economical solution rather than the best technical solution. The operator's opinion strongly influences the final design. Consequently the designer

should be well aware of the operator's desires. Combining drilling and early

production, by means of storing the oil produced during extended well tests, seems to be lucrative. It is a technical challenge to produce a design that meets all

requirements.

Drilling rigs are substantially different from other ships. Some important features are:

1.11.1 Vessel dimensions and huilform

The principal particulars of a number of drillships and FPSO's have been collected (see appendix 1.1) Since transit speed is low and the ship will be stationary most of

the time a relatively high Cb and a low L/Bratio is seen on most of the ships. A rather

full and simple hull form can be applied for ease of fabrication and efficient use of

space however much attention must be paid to the motion characteristics of the vessel. For purpose built drillships the following ratios have been found:

The average transit speed of current deep-water drillships is about 12 knots.

1.11.3 Wave direction & motions

In drilling mode the vessel revolves around its drilistring, using its DP system. Predominantly head waves are encountered. Typical relative wave direction distribution is: 180° for 40% of the time, 150° for 60% of the time.

Drilling equipment (also subsea) makes demands on motion-characteristics. The vessel should be capable of drilling up to a significant wave height of 6m. Typical heave period 8 s, pitch period 7 s, roll period 12 s and over.

L1

ratio varies from 4,4 to 6,4 L1

ratio varies from 10,6 to 12 D1

ratio varies from 1,7 to 1,8 Cb varies from 0,78 to 0,90

1.11.4 Storage ofdrillingfluids

The drilling process requires many fluids. It is likely that the amount of drilling fluids increases at greater drilling depths. However, no clear relation between drilling depth and the capacity of the fluid storage can be found. For a rough estimation of these capacities the average of drilling fluid capacities of ships with a large drilling depth

(+9000 m) has been taken. The following table gives an overview of the required

storage capacity.

Drilling fluids capacities Table 1.4

1.11.5 Mud handling

The mud system includes pumps, separators, agitators and piping. All these items need to be situated near the moonpool area.

1.11.6 Derrick

The derrick is a high (up to 80 m) construction on the deck, used for hoisting operations. During drilling operations, assemblies of drillpipe, riser and casing are

stored in the derrick. Due to the large weight of all this, it has a great impact on vcg.

The RamRig concept is an improvement in this respect. 1.11.7 Moonpool

Every drillship has a moonpool through which the drillstring, casing and

riser-handling occurs. The moonpool must have appropriate space for storage and riser-handling of BOP's and X-mas trees. Square shapes as well as circular shapes are applied. The

average size is about 75 m2 but there is a clear trend toward larger moonpools sized

about 120 m2. Dual string derricks double moonpool size.

Density (tim3) Weight (t)

Liquid mud 1.000 m3 1,4 1.400 Bulk mud 800m3 1,4 1.120 Cement 800 m3 1,6 1.280 Sacks 13.000pcs

l5kgapiece

1.11.8 Station keeping ability

Thrusters keep driliships on location. Currents in the order of one knot are to be expected. Number of thrusters ranges from 5 to 12. Reliability of the DP system is an

important issue. Therefor recent designs include a triple redundant DP system.

Generally accepted, a vessel should stay on location up to a 10-year-return-period

storm.

1.11.9 Crew

Driliships with a single derrick have a crew of about 120 men. Drillships equipped

with a dual derrick are operated by a double drilling-team, resulting in a crew of about

200 men.

1.11.10 Storage of risers, drillstring and casing

Many tubular elements have to be stored on the vessel. The following table will give an overview of the required elements for a deepwater drilling operation. Be aware of the fact that every operation has its own demands.

Tubular characteristics

Table 1.5

1.11.11 Self-supporting for a long period

The vessel must be able to stay on location without supply for a period of 90 days. This has many consequences:

Food-stores for the large crew are extensive. 90 day stocks.

Stores with spare parts have to be present because repairs must be carried

out immediately; the drilling must go on! Workshops for Repair & Maintenance The ship should contain recreation rooms.

Required length (m) Number of tubulars Maximum length (m) Weight (kg/rn) Total weight (t) Casing 30" 200 14 14,6 460 90 Casing 20" 800 55 14,6 200 160

Casing l3"/8

95/

Drillpipe 5" landing string 3.000 323 9,3 45 135

Drillpipe 3" workover 9.000 968 9,3 25 225

Drillcollars±7" 1.000 108 9,3 150 150

Riser 21" drilling 3.000 139 21,7 760 2.280

Riser 10" workover 3.000 200 15 140 420

Riser 7" completion 3.000 200 15 50 150

Tubing 7" tie back 3.500 240 14,6 65 230

1.11.12 Danger of explosion/fire

Drilling for oil and gas is a dangerous thing to do, you're dealing with highly

flammable and explosive mixtures at high pressures. This very much influences the layout of the ship. Some striking features seen on other ships are:

Living quarters and heli-deck up-wind and remote from moonpool area

Burner booms located at the stem of the vessel and thus down-wind of the rest of

the ship

Process equipment 3 m above main deck

Explosion wall to protect living quarters

1.11.13 Logistics

Transportation of equipment takes place with 10-lOOt offshore cranes. Dedicated

systems for BOP & X-mas tree handling usually are applied. Transportation and erection of risers and drillpipes happens over a dragway. Recently many dedicated systems are being developed.

2.2 Environmental conditions 34 2.2.1 Wind 2.2.2 Waves 34 2.2.3 Current 34 2.3 Freeboard 35 2.4 Intact Stability 36

2.5 Subdivision and damage stability 38

2.6 Area classification and ventilation 40

2.6.1 Location and separation of spaces. 41

2.7 Size and arrangement of cargo tanks 43 2.7.1 Limitation of size and arrangement of cargo tanks 43

2.7.2 Damage assumptions 43

2.7.3 Hypothetical outflow of oil 43

2.7.4 Oil tankers used for the storage of oil 45

2.7.5 Protective location of segregated ballast spaces 45

1.8 Dynamic positioning systems 46

2 Rules and regulations

₃₃

2 Rules and regulations

2.1 Introduction

The ocean is a harsh environment. In order to keep all activities safe; agreements have been made between countries all over the world. To be able to insure a rig, it has to satisfy the rules of a classification society. All these rules influence the design. They

are limiting conditions. Some impose greatrestrictions; some are minor details. Finding your way in all those regulations is not that easy. In this chapter all major restrictions on overall design, required by several organisations, will be sun-imarised. No effort has been made to summarise minor details, although sometimes seemingly small insides caii pull heavy strings on overall design. Rules are arranged on topic, rather than on society. This provides a quick access to the rules.

Storing oil on a drillship is a new concept. In fact, it is a combination of a drillship and a FPSU or, if the ship sails of fully loaded after an extended well test it is to be considered a tanker and both the rules for driliships and tankers have to be satisfied.

2.2 Environmental conditions

DNV classification notes no. 30.5

2.2.1 Wind

Wind velocities change both with time and with height above the sea surface. For this reason the averaging time and height must always be specified. Common averaging times are 1 minute, 10 minutes or 1 hour. Wind velocity averaged over 1 minute is often referred to as sustained wind velocity. The statistical behaviour of the average wind speed may be described by the Weibull distribution.

In the short time range the wind may be considered as a random gust wind component with zero mean value, superposed upon the constant, average wind component. Gust wind velocity, defined for instance as the average wind velocity during an interval of 3 seconds, may normally be assumed to follow the Weibull distribution law.

2.2.2 Waves

Wave conditions, which are to be considered for design purposes, may be described either by deterministic design wave methods or by stochastic methods applying wave spectra. For deep water the linear wave theory is the most appropriate wave theory. Thanks to the fact that it is a linear model, it is appropriate for spectral description of random seas.

For description of short-term wave conditions the Pierson-Moskowitz spectrum is generally applied for open, deep waters and fuiiy developed seas. The Jonswap spectrum is normally used for fetch-limited, growing seas and without swell. The long-term variation of the seas may conveniently be described by a set of sea-states, each characterised by the wave spectrum parameters, that is, significant wave height (Hs) and average zero-crossing wave period (Tz). There are currently three

ways to describe the marginal long-term probability distribution of Hs: The three-parameter Weibull distribution

The generalised gamma distribution The log-normal Weibull distribution

When specific wave data for a site are not available, Weibull parameters can be obtained, for the most relevant regions in the world, from tables.

2.2.3 Current

When detailed field measurements are not available, wind and tidal forces determine the variation in current velocity with depth. The variation in current profile with variation in water depth due to wave action is to be accounted for.

2.3 Freeboard

Freeboard should be calculated according to the 1966 Load Lines Convention. Regulations 1-26

These regulations deal with definitions and details like hatchway covers, doors, air-pipes, machinery space opening, etc. These regulations do not restrict the overall

design much.

Regulation 27 (IMO resolution A.320 (IX))

For the purpose of freeboard calculation ships are divided into type 'A' and type 'B'. Type 'A' ships are ships that:

Are designed to carry only liquid cargoes in bulk

Have a high integrity of the exposed deck with only small access openings to cargo compartments, closed by watertight gasketed covers of steel or equivalent

material

Have low permeability of loaded cargo compartments

All ships that do not come within these provisions are type 'B' ships. Consequently drillships are to be treated as type 'B' ships.

Regulation 28

Freeboard tables for both types of ships Regulation 30, 31, 32, 37, 38

30 Correction for block coefficient (only if Cb> 0,68)

31 Correction for depth (only if D > L/15)

32 Correction for position of deck line

37 Deduction for superstructures and trunks

38 Correction for sheer

Regulation 40

2.4 Intact Stability

MODU Code Res. A. 649(16)

Curves of righting moments and heeling moments should be prepared covering the full range of operating draughts, including those in transit condition, taking into account the maximum deck cargo and equipment in the most unfavourable position applicable. Curves of wind heeling moments should be drawn for wind forces calculated by the following formula:

F =

jcsc,pv2A

Cs shape coefficient (table 3-1)

CH height coefficient (table 3-2)

P air density (1,222 kg/rn3)

A projected area

V wind velocity normal operating conditions: 36 mIs

severe storm conditions: 51,5 mIs

heeling moment angle of indlinatioH righting moment downflooding angle second intercept

Righting moment lever

Figure 2.1

The stability of a unit in each mode of operation should meet the following criteria: The area under the righting moment curve to the second intercept or downflooding angle, whichever is less, should be not less than 40% in excess of the area under the wind heeling moment curve to the same limiting angle.

The righting moment curve should be positive over the entire range of angles from

upright to the second intercept.

Each unit should be capable of attaining a severe storm condition in a period of time consistent with the meteorological conditions.

NMD Part 6, M, §20

Static angle of inclination due to wind shall not exceed 170 in any condition. The second intercept shall occur at an angle of 30° or more.

Part 6,Q,J6

Regulations for mobile offshore units with production plants and equipment.

A collision with a supply vessel of 5.000 tons displacement with a speed of 2 rn/s

shall not cause a discharge of crude oil from storage tanks or from process equipment

on deck. The production plant shall be capable of withstanding the inclinations

occurring without resulting in critical events.

The effect on stability of a quick release of risers and/or anchor lines according to emergency procedures shall not result in a dynamic angle of inclination in the most

2.5 Subdivision and damage stability

MODU Code Res. A. 649L16)

The unit should have sufficient freeboard and be subdivided by means of watertight decks and bulkheads to provide sufficient buoyancy and stability to withstand in general the flooding of any one compartment in any transit consistent with the damage assumptions.

The unit should have sufficient reserve stability in a damaged condition to withstand the wind heeling moment based on a wind velocity of 25,8 m/s. In this condition the final waterline, after flooding, should be below the lower edge of any downflooding opening.

The ability to reduce angles of inclination by ballasting compartments or application of mooring forces should not be considered.

Extent of damage to be assumed between effective watertight bulkheads:

Horizontal penetration: 1,5 m

Vertical extent: from the baseline upwards without limit

All piping, trunks, etc., within the extent of damage should be assumed to be

damaged.

NMD Part 6, M, §21-25

In flooded condition the final waterline should be below the lower edge of any downflooding opening. The angle of inclination < 17°

The area under the righting moment curve shall be at least equal to the area under the inclining moment curve up to the second intercept of the curves.

Two main categories of damage are to be considered: One-compartment damage

One-compartment damage shall be assumed for any compartment, which is wholly or partially under the waterline in question, and in addition either is limited by the sea or containing piping systems which lead to the sea.

Collision damage to drilling ships

Extent of damage: Longitudinal extent 3,0 m

Horizontal penetration 1,5 m

Vertical extent from baseline upward

At least one watertight bulkhead may be assumed to be damaged.

NMD Part 6,0, §10

The relevant parts of the NMD's regulations concerning oil tankers shall apply to mobile offshore units storing crude oil on board.

SOLAS, Part Bi

Probabilistic damage stability calculation should be carried out.

A collision bulkhead shall be fitted, which shall be watertight up to the freeboard deck.

Distance from forward perpendicular> 5% of Lpp or 10 m, whichever is less.

Distance from forward perpendicular < 8% of Lpp.

Marpol Annex I, Ch 3, reg. 25 Side damage

Longitudinal extent 1/3 L213 _{or 14,5 m, whichever is less}

Transverse extent B15 or 11,5 m, whichever is less

Vertical extent from baseline upward without limit

Bottom damage

Longitudinal extent Transverse extent Vertical extent

for 0.3L from forward any other part

1/3 L213 _{or 14,5 m} 1/3 L213 _{or 5 m}

B/orl0m

B/or6m

B15 _{or 6 m, measured from baseline}

Criteria:

In flooded condition angle of inclination < 25° (can be increased to 30°)

In flooded condition the righting lever curve has at least a range of 20° beyond the

'position of equilibrium in association with a maximum residual-righting lever of at

least 0,1 m within the 20° range.

The area under the curve within this range shall not be less than 0,0175 mrad.

2.6 Area class jfication and ventilation

DNV Mobile offshore drilling vessels pt5,ch3sec2.

The following requirements apply to drilling vessels for oil and gas exploration.

G 101 If the vessel is to be used for oil and gas production, the arrangement and equipment will be specially considered.

The vessel is to be classified into hazardous and non-hazardous areas.

G301 1-lazardous areas are divided into zones as follows:

Zone 0: in which an explosive gas/air mixture is continuously present or present for long periods.

Zone 1: in which an explosive gas/air mixture is likely to occur in normal operation.

Zone 2: in which an explosive gas/air mixture is not likely to occur, and if it occurs it will only exist for a short time.

Non- hazardous areas are areas, which are not hazardous according to G30 I.

G400 Spaces in direct or indirect contact with drilling mud are considered to be

hazardous areas, and are again divided into zone 0, 1, and 2.

G405 Equipment for well testing is to be specially considered.

G501 Except for operational reasons access doors or other openings should not be provided between:

A non-hazardous space and a hazardous area.

A zone 2 space and a zone I space.

When the proper measurements have been taken zones with direct access to a

hazardous area may be considered to be a non-hazardous area.

G600 Ventilation

All air inlets for hazardous enclosed spaces are to be taken from non-hazardous areas,

i.e. more than 3 metres from hazardous areas.

1201 Machinery installations in hazardous areas

Internal combustion engines are generally not to be installed in hazardous areas.

Where this cannot be avoided, special consideration will be given to the arrangement.

Fired boilers are not to be installed in hazardous areas.

Air intakes for internal combustion engines and boilers shall be minimum 3m from

2.6.1 Location and separation of spaces. Oil production and storage vessels

DNV vo2,pa5 ,ch9,sec2

B200 Cofferdams are to be provided between crude oil tanks and adjacent

non-hazardous areas.

B204 Crude oil storage tanks are not to have a common boundary with machinery

spaces.

B205 Entrances, air inlets and openings to accommodation spaces, service spaces and control stations are normally not to face the tank and processing area. They are to be

located at a distance not less than 3 m from the end of the superstructure or deckhouse facing the cargo area. For boundaries facing the tank area, special measurements have

to be taken.

B208 All areas likely to be regularly manned and areas containing oil production and processing equipment are to have at least two well marked escape routes situated as far apart as practicable, and leading to abandonment stations.

B209 Escape routes are to be protected from the effects of fire and smoke, they are to be designed for easy access/egress minimising the use of ladders. The escape routes should be straight, minimum 1,0 m wide and 2,10 m high outside the accommodation

area.

Hazardous areas sec4.

The definitions and subdivision of the hazardous areas are identical to that of drilling ships. Extra attention is being paid to the extent of hazardous areas around openings and ventilation shafts.

NMD Regulations for mobile offshore units Same description for zones 0,1,2.

Pt6,F,6

Living quarters shall be adequately separated from danger areas. Living quarters shall not be adjacent to explosion-hazardous areas.

SOLAS Ch 11-2, Part D, Reg 56

Fire safety measures for tankers

Machinery spaces shall be positioned aft of cargo tanks and slop tanks; they shall also

be situated aft of cargo pump rooms and cofferdams, but not necessarily aft of the oil

fuel bunker tanks. Any machinery space shall be isolated from cargo tanks and slop tanks by cofferdams, cargo pump rooms, oil fuel bunker tanks or ballast tanks. Accommodation spaces, main cargo control stations, control stations and service spaces shall be positioned aft of all cargo tanks, siop tanks, and spaces which isolate cargo or slop tanks from machinery spaces but not necessarily aft of the oil fuel bunker tanks and ballast tanks. However, where deemed necessary, the

2.7 Size and arrangement of cargo tanks

Marpol 73/78 Annex I, Reg 22-24

2.7.1 Limitation of size and arrangemeni of cargo tanks'

Cargo tanks shall be of such size and arrangements that the hypothetical outflow

O or O, calculated in accordance with the3provisions, anywhere in the length of the ship does not exceed 3 0.000 m3 or 400 JDWT, whichever is greater, but

subject to a maximum of 40.000 m3.

The volume of any one wing cargo oil tank shall not exceed 75% of the limits of the hypothetical oil outflow (exception possible). The volume of any one-centre

cargo oil tank shall not exceed 50.000 m3.

The length of each cargo tank shall not exceed 10 m or one of the following values, whichever is the greater:

> Where no longitudinal bulkhead is provided: 0,1 L

Where a longitudinal bulkhead is provided at the centreline only: 0,15 L Where two or more longitudinal bulkheads are provided:

For wing tanks: 0,2 L For centre tanks:

Ifb/B?0,2:0,2L

If b1/B <0,2: no centreline long. bulkh.: (0,5 b/B + 0,1) L

a centreline long. bulkh.: (0,25 b1/B + 0,15) L

Marpol 73/78 Annex 1, Reg 15

Dirty ballast residue and tank washings from the cargo tanks should be transferable into a slop tank. The capacity of the slop tank should be 2% of the oil carrying

capacity of the ship where segregated ballast tanks are provided.

2.7.2 Damage assumptions Side damage

Longitudinal extent 1/3 L2'3 _{or 14,5 m, whichever is less (w.i.1.)}

Transverse extent B,5 or 11,5 m, w.i.l.

Vertical extent from baseline upward without limit

Bottom damage

2. 7.3 Hypothetical outflow of oil

The hypothetical outflow of oil in the case of side damage (On) and bottom damage (Os) shall be calculated by the following formulae with respect to compartments breached by damage to all conceivable locations along the length of the ship to the

extent as defined above.

Side damage:

O, =W +K,C1

=1

3 (Z,W + 2Z,C1)

Where:

W1 = volume of a wing tank in m3 assumed to be breached by the damage as

specified above; W1 for a segregated ballast tank may be taken equal to zero.

C1 = volume of a centre tank in m3 assumed to be breached by the damage as

specified above; C1 for a segregated ballast tank may be taken equal to zero.

K1 = 1 - b1/t but always? zero.

Z1 = 1 - h1/v but always ? zero.

b1 width of wing tank in m under consideration measured inboard from the ship's

side at right angles to the centreline at the level corresponding to the assigned summer freeboard.

h1 = minimum depth of the double bottom in m under consideration; where no

2. 7.4 Oil tankers used for the storage of oil Aniiex 1 regulation 13 4.6

When an oil tanker is used for the storage of oil and its propulsion machinery arrangements have been so modified as to immobilize the ship, such a tanker is not required to comply with the provision of regulation 13.

Personal interpretation:

A driliship with storage capacity performing an EWT in DP mode may be considered

as such a vessel. Such a driliship is not required to comply with the provision for e.g.

the protective location and size of segregated ballast spaces. However if the ship sails of after an EWT it's likely to be loaded and propulsion is working, so the

requirements for tankers are to be complied with.

2. 7.5 Protective location of segregated ballast spaces Annex 1 regulation 13E

For new crude oil tankers of 20.000 tons deadweight and above. The segregated ballast tanks which are located within the cargo tank length, shall be arranged in accordance with regulation 13 to provide a measure of protection against oil outflow in the event of grounding or collision.

(2) segregated ballast and spaces other than oil tanks within the cargo tank length (Lt) shall be so arranged as to comply with the following requirement:

PAC + SPAS? J [L (B + 2D)]

Where:

PA = the side shell area in square meters of wing tanks

PA the bottom shell area in square meters

L = length in meters between the forward and after extremities of the

cargo tanks

B = maximum breath of the ship

D = moulded depth in meters

J 0,45 for oil tankers of 20.000 tons deadweight, 0,3 for tankers of

200.000 tons deadweight. For intermediate values the values of J shall be determined by linear interpolation

The minimum width of each wing tank or space shall be not less than 2 meters The minimum vertical depth of each double bottom tank or space shall be