Snorre TLP - Development and operations

The paper presents the basis for selection of

the TLP concept for development of the

Snorre field, and outlines important aspects of the design and operational philosophy for the selected TLP concept.

Furthermore, lessons learnt from the design, fabrication, installation and operational phases

are summarised, together with

recommendations for design improvements

and simplifications. For the operational phase,

emphasis is put on the liP-specific aspects sucti as influence of platform motions, weight

management and design-feedback from the instrumentation system for monitoring of platform responses.

The paper also includes a description

of

current and planned modifications

of the

Snorre TLP to accommodate new functional requirements.

Finaly, status on a recent development of a

deep water TLP is given.

INTRODUCTION

The Snorre Field is located in the blocks 34/4 and 34/7 in the Norwegian sector of the North Sea, 170 km west of the Norwegian coast, close to the UK border. The water depth at the field ranges from 300 to 350 meters, and the soil conditions are characterised by soft clay. The field is located close to other large oil fields such as Statfiord and Guilfaks.

The history of the Snorre field started in 1979 when Saga Petroleum was awarded the

production license on block 34/4. Initial

'SYMPOSIUM

BY

Stein Fines, Saga Petroleum a.s

Oddvar Alfstad, Saga Petroleum a.s

ABSTRACT

THE TEXAS SECTION OF

ThE SOCIETY OF NAVAL ARCHITECTS

AND MARINE ENGINEERS TI.? TECHNOLOGY SYMPOSIUM; 1995

Mekalwog 2. _{C Deft}

TeL 015.. 7b _{OlSe 781835'}

exploration indicated existence of a promising oil field extending to the south into block 34/7.

In 1984, Saga Petroleum was granted

production license also of this block, and an agreement was later established between the license owners of the two blocks for a joint development of the unitized Snorre field with Saga Petroleum as operator for both development and operations.

In 1984, a' three year work program was

launched, comprising extensive exploration

work and field development studies.

This phase was concluded by submittal of 'the Plan for Development and Operations (PDO) to the authorities for approval on September 1, 1987. Pre-engineering was started in December the same year,

and the PDO was formally

approved in May 1988. Major fabrication work started

early 1989, and the platform and

subsea production system were installed in

May 1992. First oil was produced ahead of plan in August 1992, and the full production

was reached less than half a year later.

CHALLENGES

The selection of a development scenario for the Snorre field, Included' a lot of challenges. The developments so far in the North Sea had taken place in moderate water depth less than 200 m, and with good soil conditions.

As stated earlier, at the Snorre fleld we were faced with much deeper water and very soft

soil. Another complicating factor was the very

complex reservoir, which required a large

number of wells over a relatively large area.it. should also be mentioned that a relatively

large percentage of the recoverable oil was

located in Lunde formation in the northern part

of the field,

where no

prior production

information was available. Thus a staged

development, where the major part of the

development of the Lunde formation could be

done in a phase 2 of the project, utilising

production information from a small number of wells in phase 1, was selected.

The biggest

challenge was however of

economical nature. Since the oil activity started in Norwegian waters, the oil price had been high, with oil prices

up to

35-40 USD/barrel. At the time of development of the Snorre field, the oil price had fallen to 20-25 USD/barrel, and analyses indicated that the price could fall as low as 10-15 USD/barrel. It was therefore essential to establish a

development scenario that could sustain

periods with low oil price. The problem was, however, that the technology and the mode of operation were aimed at a much higher oil price, such that new and innovative solutions had to sought.

Another challenge was that Saga Petroleum was a young oil company, and that the Snorre field was the first development project for the company in Norwegian waters. This Situation could also be looked upon as a large asset, as the óompany was willing and able to introduce new technologies and modes of operations,

and was not 'tied down' by old traditions.

CONCEPT SELECTION

The concept selection was driven by the

fundamental functional requirement in terms of number of wells and total production capacity, matched with the need for reduction of the investment cost due to the low oil price. A large number of concepts for substructures

àid production systems were evaluated, in

cOmbination with possibilities for utilisation of exiting;infrastructure at nearby fields. Large

efforts were put into evaluation of extension of existing technology beyond the current state of

art with regard to functional requirements,

environmental criteria and safety requirements. The most promising concepts were selected based on both technical and economical criteria.

On pure

economical analyses, it was concluded that a development

with two floating production units (semis or shipshaped) combined with subsea

production facilities, was the most attractive scenario. However, considering the project risks and the necessary development work needed to facilitate a development with up to 100 subsea wells, it was concluded that this scenario was too futuristic to be launched as

our first

field development project , since

feasibility could be questioned in some areas within the time frame set for the project.

Based on a balance between economical potentials, the amount of development work involved, and evaluation of project risks, the Tension Leg Platform (TLP) was selected as

the basic concept for development of the

Snorre field.

It was also concluded that a

staged development of the field Should be performed, in order to reduce project risks.

Due to

limited information

of the Lunde

formation, the first phase of the development

should consist of a TLP placed on the

southern part of the field draining the Stathord formation, while the Lunde formation should initially be drained with a limited number of

wells from a subsea production system placed

some 6 km north of the TLP. The second

phase of the deveiopment should either

consist of a relocation of the TLP to the

northern part of the field after some 15 years service in the southern location, or a

development with further subsea production systems in the north. The TLP was therefore designed for relocation, and with connection points

for hook-up of

flexible risers and

umbilicals for the possible subsea production systems. Later it has been concluded that

further development should be performed with subsea developments, i.e. the TLP will not be relocated. The reason for this is that increased oil

reserves have been discovered in the

south, making it more profitable to keep the

TLP at the southern location longer than

originally planned. Furthermore, the resent

development in subsea technology, where the

cost per subsea well has been dramatically reduced over the last

years, makes this

solution much more attractive. As a

consequence, the Snorre TLP is now being used as a 'field centre' when planning further development of new oil fields in the area. This will be discussed more in detail later in this

paper.

It was chosen to install process equipment for

only two stages of processing onboard the TLP. The final processing of the oil and gas

would be performed on

the Stat! iord A platform, where also offloading of

oil and

export of gas would take place.

THE SNORRE TLP

To select

a TLP concept

for the first development project, could seems as a very risky decision for a relatively inexperienced oil company. At the time of selection, only one TLP. project

had been

realised, namely

Conoco's Hutton project, a TLP which was much smaller than the Snorre TLP in size,

production capacity and investment. However, as operator we established a program for risk management early in the planning phase. This program was called 'Major Technical Element Program', and was established as a joint effort between Saga Petroleum and Esso (Exxon) who was our technical advisor on the project, and one of the owners in the Snorre licenses.

This program was actively used by both

management and engineers to follow up all issues that could have an adverse effect on

the project cost and schedule until they were closed.

The selé ted TLP concept was in general

based, on. design principles that were wefi known from the Hutton TLP and other North Sea offshOre projects. New technology was only introduced where significant investment or operational cost reductions could be

documented, and after in.depth qualification of the technical solutions.

The hull of the Snorre TLP is a four-column

steel

structure based on well

established design principles from ship design. The deck is a conventional integrated deck well known from the Norwegian concrete platforms. This

deck design was chosen for

its cost and

weight benefits. The main structural girders comprise a combination of longitudinal truss girders and transverse plate girders. This solution provides a safe segregation between 'hazardous and non-hazardous areas, and provides flexibility for pipe and cable routing within the different areas. The fully equipped deck was mated to the hull structure inside a sheltered fiord.

The selected tether system was a multi-piece system, where the indMdual components were connected by threaded pin and box

connectors, and deployed through tether conduits from a mooring compartment inside each of the platform columns. The tethers

were equipped with flexible articulations in 'the anchor connectors in the foundations, and in the cross-load bearings in the lower part of the

hull. The tethers have dry tie-off at the

mooringflat some three meters above sea level. The design of the tether system is more or less identical to the Hutton TLP, except that

the diameter was much larger and the wall

thickness smaller.

Also for the riser system, the design sOlutions were more or less as for the Hutton TLP, i.e. top-tensioned steel risers for all export- .and production risers. For tie-in of the subsea production station, freehanging flexible risers

were selected. The pretensioned risers were supported by hydraulic tensioners at the deck level, and the riser joints were made up by threaded connectors or flanged and bolted connectors depending on the fatigue loading on the actual riSer joint All production risers and the gas export riser were terminated at the. seabed with a steel stressjoint, while the larger diameter oil export riser and the high pressure drilling riser were terminated with

elastomeric flexjoints.

The key-parameters of the Snorre TLP is as

follows:

Displacement 104900 tonnes

Column diameter 25.Om

Column c-c distance 76.0 m

Pontoon dimensions 11.5x 11.5 m

Platform draft 37.5 m

No of tethers 16

Tether pretension 25000 tonnes Hull steel weight 24000 tonnes Total deck weight 39500 tonnes

Deck payload 25000 tonnes

Risertension 3500 tonnes

No of well slots 44

INNOVATIVE SOLUTIONS

As mentioned earlier, the need to reduce cost and weight led to introduction of new

technology and innovative solutions in some

areas. Some of the major ones are listed

below:

Aluminium living quarters. By introducing a stress-skin aluminium living quarter it was possible to save about 800 tonnes of weight compared to a traditional steel structure.

Water injection system. Probably the best example of weight and space reduction within the deck itself is the water injection

system. By

using. new

technology,

comprising cartridge filters, a Hydro Minox deoxygenation .package, and vertical

pümps it was possible to save some 560

tonnes of .weight compared to a conventional system.

Guyed flare stack. Compared to a conventional flare tower, a weight reduction

of 50% (80 tonnes) and cost reduction of

80% was obtained.

Large diameter tethers. By making the

diameter of the tethers so large that they

are close to

neutrally buoyant, it was possible to reduce the effective load on the

hull structure, and therefore also the

required displacement of the TLP, with

about 2000 tonnes.

Concrete suction anchors.. By selecting

concrete suction anchors for the tether

foundations, significant cost . savings

compared to piled steel templates were

obtained. Specially for the soft soil

conditions at the Snorre field, the foundation solution was very cost effective.

Other areas where new technology was

introduced, were in the drilling area with fully hydraulic drawwork. All these elements involved cost savings either on the investment

side or with respect to reduced operational

costs or improved operational regularity.

FABRICATION AND COMMISSIONING

The hull structure was fabricated in sections at different sites and transported to Stavanger for assembly. The ring-pontoon was assembled across a dry dock, lifted off by a submersible barge, and brought afloat outside the dock.. The column sections were lifted in by

shearlegs and welded together in the floating

condition. This proved to be a very cost

effective assembly method.

Major parts of the deck structure were built in Finland and transported to Stord where it was assembled

across a

dry-dock. After the prefabricated equipment assemblies and

modules were lifted in and hooked up, the deck was transported out into the fiord on a

barge and mated with the deck structure. After the deck mating, the platform remained in the mating mooring system for more than

half a year, while the

final hook-up and commissioning were performed. During this

period, the platform was operated as an

offshore installation, where the personnel lived

on the platform for periods of 14 days at a

time.

During this period extensive testing and

training activities were performed. This included among others:

Inshore drilling test, including running of

risers and drilling of a well into the sea

bottom

Tether deployment system trials and

training. This included deployment of tethers from atl conduits fbr verification of

procedures and training of personnel in an around the clock operation for 14 days. Inshore production tests, involving testing of the process facilities at full flow rates with a mixture of diesel oil, water and nitrogen. TFL system trials, invoMng pumping of TFL tools trough the

topside systems and

hardpipe risers.

In addition an extensive testing of the water injection plant was performed prior to the plant being lifted onto the deck at the assembly

yard.

For all tests there were positive effects

in training of personnel and in

use of the

operational procedures. In addition, the tests

uncovered errors and faulty equipment that

otherwise would have caused delays and extra costs. offshore.

INSTALLATION

The fully commissioned platform was towed out by 7 tugs to the field in the middle of April

1992,

one month ahead

of the original schedule. Arriving

at the field,

the SSCV M7000 was at the location, moored with 12 mooring lines. The TLP was connected to M7000 by two interconnecting mooring lines, which were kept tight by the 7 tugs in a star-formation. After waiting for a few days on an acceptable weather forecast, the two first

rounds of tethers were deployed with the TLP some meters off the location of the foundations. The TLP was then brought in

position by the station keeping spread, and the first tether in each corner was stabbed into the

foundation receptacle, using the

Tensioner-Motion Compensator (TMC). When all the four tethers were stabbed and locked, the heave-suppression Was performed using the TMCs. The platform was now tethered with only four tethers, and it was essential to stab, lock-off and 'perform deballasting such that the TLP could survive a 1 0-year seasonal storm. This

work was performed timely and efficiently

without any kind

of problems. After this, however, the operation had to be interrupted for more than a week due to bad weather.

Finally, on the May 11, the platform was safely moored with all

16 tethers, and the final

preparations for start-up of production could commence.

One lesson learnt from this operation is that April and early May is not the ideal period of the year to perform weather-sensitive marine operations in the northern North Sea. However, in the periods with acceptable weather conditions, the operations were performed timely and safely without any kind of problems. Another experience from the operation was that the stationkeeping could

have been performed effectively with tugs

only, i.e without the use of the large.and costly SSCV.

START-UP AND PRODUCTION

The hook-up of the export risers, and

completion and hook-up of the first of the pre-drilled

well was completed such

that oil production started August 3,1992. By the end of the year, all the six pre-drilled wells were

completed and hooked up with a stable

production of about 160,000 barrels/day, versus the design capacity of 190,000

barrels/day At the end of 1992, the subsea

production station should also be put on

stream, but this was delayed due to a failure in

the electrical power circuit on the subsea

production station. This resulted in half a year delay of the start-up of the production from the subsea system, as a new by-pass system had to be installed. ThiS was successfully

completed by mid 1993, with only diverless

operations,

and was

perhaps the most challenging technical taSk in the whole Snorre

project. By the end of

1993 the subsea production station was producing from four

wells, without any kind of problems.

Since the production Started up in August 1992, there has only been three incidents that have resulted in shut down of the production due to bad weather. One occurred in January 1993 when one of the burner booms were

damaged due to wave run-up. The Wells were shut in and the production temporarily stopped

until the burner boom was secured and the extent and consequences of the damages

quantified. Even in this storm, which

corresponded to a return period around 10

years,, the performance of the process facilities did not require a shut-down.

The two other occasions with

production shutdown due to weather has been caused by liquid motions in the separators.

As mentioned earlier, the design production

capacity was specified to 190,000 barrels/day. The:;' ptattcrm has however performed much better than this. In periods with no operational problems, it has been possible to maintain a stable production above 215,000 barrels/day, or more than 10% above the design capacity. The maximum weekly production so far was reached in week 43 of 1994, with an average production per day of 227,300 barrels, while the maximum daily production is 235,000

barrels.

There has of course been some technical

problems on the pletform that have influenced

the production regularity, but none of the

problems are caused by the fact that the

platform is a TLP. As an example it can be

mentioned that the production was reduced for

some time due to failure of one of the gas compressors, resulting

in an average daily

production of about 135,000 barrels for that period. During the winter with long periods of bad weather, it is experienced now and then that that the production has to reduced or shut down due to limited oil storage capacity at the Stafford field, as the shuttle tankers are not

able to load the

oil. Other reasons for shutdowns have been shutdown and alarms at Stafford A , which also trigger a similar action

at the Snorre platform, as the final processing is performed at the Stafford a platform.

In general it

can be concluded that the

production regularity is very good. In average for 1994 the daily production, including periods

with planned shutdowns, is above 170,000

OFFSHORE VERIFICATION PROGRAMME

The Snorre TLP is instrumented for measurement of platform responses. This is part of a verification program

that was

established early in the engineering phase. The intention was that the information from

these measurements should be used

to validate design, update inspection programs and operational criteria, as well as providing information of value for design of future TLPs. The system is set up to record 34 minutes of measurements every third hour with sampling frequency 1

or 4 Hz. The system will be

trigged for more frequent measurement in case some predefiried values of certain

parameters are exceeded, or a logging is

initiated by the operator on board.

The. system includes measurement of the

following parameters:

Environmental data, i.e. wind, waves, current, atmospheric pressure and dynamic water pressure at selected hull points

Platform motions, i.e. platform position, linear accelerations, angular velocities and airgap

Strain in selected points in hull and deck Skirt pressure, tilt and settlement of

concrete foundations

Tension in all tethers, as well as strain, accelerations and inclinations at selected points for some tethers

Top tension for all rigid risers, as well as strain and accelerations at selected points for some risers.

In general the system has functioned satisfactorily except for a few areas. The field instrumentation has in general been very

reliable, except for some areas were we have had problems. The biggest problem has been the -wáve.. measurements, an area which shoUld héve been the most trivial part of the system, as long time experience with such

systems existed.

For the wave measurements, a wave buoy

moored about 400 m from the TLP was

selected in order to give time histories as well as spectral information. For the purpose of the

verification activities, the time histories were essential. However, the buoy has been lost

twice due to failure of the mooring system, and

damaged once due to

collision

with the

standby vessel or a supply vessel. In addition, there has been problems with hardware and software compatibility. The net result of this is that at present very little wave data is available

for the most interesting time periods, i.e. the winter seasons, which reduces the value of all the good quality platform response data. We have tried to. compensate for this by using wavedata from other platforms in the area,

and by using the airgap data to get wave

information. The airgap data is diffióult to use due to large diffraction effects from the hull

structure. To improve the situation for the

fUture, a wave radar is planned to be installed on the platform deck to give spectral information.

Another area where there have been problems

is the instrumentation on the risers. Most of

the instrumentation packages which were

placed at two locations on some Selected risers, failed shortly after installation due to

short-circuiting. New and improved instrumentation has been fitted to one of the latest installed production

risers, and this

instrumentation is giving high quality reliable

.d.ata.

Except for the above problems, a

large amount of good quality

data has been

collected, and is of large value for operations

of the

Snorre TLP

and for increased knowledge of TLP-technology as such.

Below are given some of the preliminary

conclUsions from analysis of measured data from the Snorre offshore verification program. TLP motions are analysed in terms of wave-frequency motions, low-wave-frequency motions and

static offset. The maximum total TLP offset

observed to date is 17.0 m,

while the

maximum calculated offset for the 100 year

storm (excluding load factors) is 32.9 m. When

the maximum observed offset is compared

with the calculated offset for the corresponding environmental conditions, it agrees reasonably

well.

Based on preliminary analysis of the TLP

motion data the following conclusions may be

drawn:

Observed wave-frequency motions agrees well with the calculated values. However, it

is important to include wave shortcrestedness and the correct spectral shape in the calculations. It is a tendency

that the motions is not as co-linear as

predicted by the calculations.

The full

scale measurements show a

significant scatter compared to the

calculations and model test results. For

spectral peak periods less than 10

seconds, the measured low-frequency

motions in terms of standard deviation of the response normalised with H is only 0.2 to 0.5 of the model test results. For the longer wave periods, the measured response is scattered around the predicted values. The scatter of the data is believed to be caused by Wave shortcrestedness and differences in spectral shape, while the low response in the short-periodic range is believed to be caused by increased

The ratio between the maximum observed

and the standard deviation of the

low-frequency response is impossible to

establish from the time-histories

of 34

minutes duration. For this purpose, time historieS of 6 hoUrs duration have been

extracted. Analyses of this is still ongoing. Tether tension is perhaps the most important response to verify. The preliminary conclusions in this area is as follows:

The measured wave-frequency tether tensions are smaller than the design values. This is rriainly. due to the fact that the actual COG of the TLP is lower than used in the design calculations. If this is corrected for, together with corrections for spectral shape and wave shortcrestedness, the calculated wave-frequency tether

tensions agree well with the observed

values.

At the time of design of the Snorre TLP, no reliable computer code was available for

calculation of high-frequency tether responses. The design was therefore based on a conservative interpretation of model test results. The measured high-frequency tether tensions agree well with the model test results, indicating that the design is conservative in this area. The

major part of the high-frequency responses for the considered seastates are recognised as tether springing (sum-frequency excitations).

The theory

for calculation of such responses has been improved, and reasonable agreement with the observed values is obtained.

damping due to current

nd wave drift

COMPARISON OF MEASURED VERSUS effects. Calculations with measured wave PREDICTED DATA spp1ra show a systematic overpredictiOn of

Tether ringing received little attention when designing the Snorre TLP simply because it

was not recognised as a problem in the-industry at that time. Later re-analyses has shown that ringingwill not contribute to the extreme loads in the tethers the high

wave-frequency loads dominated the extreme loads, much because of the favourable location of the TLP COG. However, up to now the COG has been significantly lower than originally designed for, such that the TLP has been more subjected to ringing response. Significant ringing response has been observed in high, steep seastates, but with no risk of exceeding the design tether tension.

WEIGHT MANAGEMENT

Correct weight management is essential for the safety of the TLP. For operation of the Snorre TLP, so-called 'Weight Management Curves' have been established. These curves are determined by the reserves in the tether system design

wit

overstressing and

minimum acceptable tension. For the intact platform, the optimal platform weight is 77200 tonnes. In this condition, the horizontal centre of gravity of the platform can accept to vary with +1- 0,7 m, and if the centre of gravity is correct, the weight can vary with +1- 1900

tonnes and still be within the acceptable limits. On Snorre, the weight management is based on 'logged weights'. This means that the total weight is establiShed from logging of weights and COG information for variable loads in addition to the weight and COG of the TLP structure itself. The logging, is performed by level measurement in all tanks, and weight cells for bulk tanks. For small tanks, or tank

where degree of

filling is

more or

less

constant, an average value of tank content is used in the calculations. For the risers, the actual measured top-tension is used, and for weight of miscellaneous equipment and

materials on the deck, the weight status each

week is obtained by manual registration. All this information

is gathered in the ballast

control .computer, which displays the actual weighUaiid COG relative to the weight control

curve.

The only operations that require adjustment of the weight or COG by ballasting operations, are skidding of the drilling derrick, or if large quantities of materials are taken on board in connection with drilling operations.

The ballast control computer also displays values for 'measured' weight and centre of

gravity. This is calculated based on the tension

measurements on each tether. To Obtain correct COG, corrections have to be included from static wind and current actions based on measured wind and current velocities. In calm water, the measured weight and COG should be quite accurate. It is important to note that the measured weight and COG is not used for management of the platform. This is different from some of the other TLPs. Our experience is that the logged weights and COG are more reliable than the corresponding measured values. Of course, if the measured values

should be used, the weight management

shOuld be replaced with tension management. To rely on such a system, a very robust and reliable system has to be developed.

OTHER OPERATIONAL EXPERIENCE Of other operational experience related to the

platform as a TLP we may mention the

following:

Material handling onboard the TLP was not paid sufficient attention to in the layout of the deck. Direct visual insight

by the

crane

operator should be planned for

all major

landing areas. The landing areas should be designed with bumpers, such that containers etc. can be landed against the bumper before it is put down on the deck. More attention has to be put into layout of the surrounding of the

r

landing areas to avoid damage to vulnerable eqi.iipment. The crane operators should have more realistic training on beforehand.

Experience from a floating

vessel

like a

semisubmersible drilling rig is of no value, due to the large difference in motion behaviour. Human comfOrt. There has been Occasions when personnel on board has felt uncomfortable in stormy weather. This is

believed to be caused by quite significant

vibrations in the lMng quarter due to wave

induced vibrations (ringing) or due to vibrations

caused by the

wind. These

vibrations may be attributed to the special

design and support of the lMng quarter,

cantilevered at one end of the platform.

The main problem associated with human comfort is the lack of TLP-knowledge. With a baSic course about TLP motion-behaviour and design basis, it is believed that these problems are easily sorted out. Sea-sickness has never been a problem.

Personnel safety. The platform motions have to be considered when planning maintenance operations etc. Maintenance work may take longer time on a TLP than a fixed platform due to

the need for

securing personnel and

equipment. The motions are felt as

unpredictable, and very different from the

motions of a floating vessel where the motions are more harmonic.

Riser protection. The Snorre TLP was

originally equipped with riser protection nets of synthetic fibre ropes on all four sides.

However, the nets were subjected to local

damage from wave action,

and frequent maintenance work was needed. Based on risk analysis, it was concluded that two of the nets could be removed. It seems as design of such nets is not adequate to sustain the loads and wear they will be exposed to, so either the design need to be improved, or the operations with supply vessels close to the TLP changed, such the riser protection nets can be avoided.

Riser system. In the riser area there has

been number of minor incidents. Shortly after installation of the risers, some reduction in the top-tension occurred, due to leakage of nitrogen from the accumulators in the tensioner system. This was easily corrected,

but could had led to serious consequences if it had happened in bad weather. There has also

been reported wear problems wit the nickel

plating on the

hydraulic cylinders

of the

tensioners. More effort should be put into

simplifying the design of the tensioner

systems.

Another area where damages have occurred, is related to antifouling sheeting put on the risers in the splash zone. This sheeting is

baked into the passive fire protection, and has fallen

off due to insufficient quality of the

bonding. This has been corrected for the new riser by improving the manufactunng procedure.

On the drilling riser, all joints are connected

with bolted connections. To ensure that such a connection is functioning, it is essential that bolts get correct pretension. For this purpose,

each bolt were quipped with a devise to

monitor correct pretension. However, this

detail was too vulnerable to damage when handling the riser joints during running and retrieval, such that a lot of the bolts had to scrapped after short use. The system is now modified such that hydraulic tensioning of

each bolt to correct tension can be performed, before they are locked off. The introduction of this tool will also shorten the installation time

of the drilling riser, which was said to be a

problem.

Wave run-up. As mentioned earlier, one of the burner booms was damaged by wave run-up. There has also been other minor damages

related to wave run-up. It is believed that a TLP with relatively large diameter vertical columns, will be more subjected to wave run-up than other types of offshore structures.

motion-behaviour of the TLP, as ft. often is moving 'towards' the waves. This should be taken into account when arranging equipment-close to the columns. This is specially important with respect to location of lifeboats and other life-saving equipment.

MODIFICATIONS OF THE SNORRE TLP

Since the Snorre TLP was installed in 1992, its has been through two large modifications. The

winter of 1993/94 a module for Alternating Water and Gas (WAG) injection was installed on the platform. The primary reason for this was to increase oil recovery. An Other reason was that it was limitations on the amount of

gas that could be sent to the Statfiord A

platform, and this was limiting the oil

production.

Right now a more comprehensive modification

has

started. The Snorre TLP has been

selected as the platform for processing of oil and gas from the Vigdis field, a field that is located some 10 km away from the Snorre

TLP, and which will be developed with 12

subsea wells.. For this purpose a new 3 stage processing module will be installed on the

TLP, with an oil production capacity of 113.000

barrels/day. The total capacity of the Snorre TLP after this modification including some additional debottlenecking will be more than 350.000 barrels/day. Not bad for a platform

that was

originally designed for 190.000

barrels/day!

In addition there will also be a lot of other

modifications On the platform including

increased water- and gas injection facilities and a number of new risers. All together the

operational weight of the deck will be

increased with some 3750 tonnes. How is it possible to install so much additional weight

on a such weight-sensitive structure as a TLP, and specially when the weight is installed so high up and out on one corner of the platform

as is the case with the Vigdis modifications? The answer to this is threefold:

The Snorre TLP had some built-in weight margins due to very strict weight control

during engineering and construction phases.

The foundations were installed well within the specified tolerances, and by using the as-installed position of the foundations it is possible to gain some additional weight

capacity.

The design basis for the Snorre TLP was conservative. By using 'state of the art'

criteria for design against minimum tension,

it is possible to gain significant weight

margins. (by state of the art is understood SLS criteria for checking of minimum

tension rather than ULS used in the original design).

After this modification, there is still capacity for the planned Snorre phase 2 modifications, and

maintaining the same operational flexibility

wrt. weight and COG variations as built into

the original design.

TLP FOR THE FUTURE

Based on the experience from the Snorre TLP, Saga Petroleum together with Aker

Engineering have started development of a

TLP for deep water applications. The development is based on environmental conditions typical for the deep water locations on the Norwegian continental shelf, and the water depths used in the studies so far have been 800 and 120Dm. The first phase of this development is now finished, and the aim was

to develop a cost-effective TLP for a deck weight of 39500 tonnes, i.e. the same deck

weight as for the Snorre TLP. The work has so

far been concentrated on the

hull, tether system and marine operations.

After screening a number of concepts, both steel, concrete and hybrid solutions, a steel TLP with three columns was selected as the

most cost-effective solution. The tethers are au-welded steel tubulars, and are tied off externally. The deck is supported by an open. truss structure in the wave-zone.

In

development of the concept, we have

disregarded the traditional 'nice

to hav&

design requirements which normally are introduced for a TLP because it IS physically possible to achieve. Examples of such 'deterministic' design requirements are:

Damage conditions like one tether missing and on tether floOded

Requirements for change-out of tethers Monitoring of tension in all tethers Access for internal inspection of tethers. It is generally recognised, that there is no other offshore structure that is so well documented as

a TLP

wrt. full scale measurements, model testing, and other

research. It should. therefore be possible to design a TLP with sufficient reliability without introducing such 'deterministic' design requirements. Based on this, and the fact that the triangular TLP is a statically determined structure wrt. the loads in the tether groups, it has been possible to design a very simple

tether system, and establish

very siffiple installation procedures. For the 800 m water depth case, it has been estimated that the cost

of the instalJed tether System will be in the order of 60 mill USD, while the corresponding

coSt fat Snorre was nearly three time this

amount, with a much smaller water depth.

Also, for the hull and deOk structure, it has been possible to considerably save weight

compared to Snorre, of 2000 and 6000 tonnes

respectively. The weight saving in the deck structure can be utilized for additiotial riser

tension that will be required in deep water.

Based on the work that is petfrmed up to

now, the triangular TLP looks as a very

promising concept, and we are continuing the development work together with Aker

Snorre Field Develpment Project UK SECTOR MUrch I ThistIe Dunlin Cormorant

\

Hutton Ninian Co'umbia Reserves per Well (MSm3) C Brent

Recoverable reserves pr. Well for Snorre and other Norwegian fields

2°E NORWEGIAN SECTOR Statfjord 4.9 Snorre QTordis 3Vigdis Guilfaks Osebe 3.9 40 E

Oseberg

GuUfaks 1.8 Srtorre 1.3 620 N -61 °N

STATOI L 41.4000% NORSK HYDRO 8.2658 %

SAGA PETROLEUM 11.2559 % ELF 5.5106 %

ESSO 10.3323% AMERADA HESS 1.4559%

DEMINEX 10.0348 % ENTERPRISE OIL 1.4559%

IDEMITSU 9.6000% DNO 0.6888 % 210 120 46 75 117 96 Recoverable Reserves (MSm3) Area (km2) Total Wells 197 78 51 482 81 98

Water depth I Soil conditions

(m) 0 50 100 150 200 250 300 350

Total Investment per Unit of Produced Oil

400 300 200

-

100-0 U (ft) 0 -200 -400 -600 -800 1000 1200 - 10

-B

6

-4

2

0

Oseberg Statfjord Gulifaks Snorre

1989 1976 1990 1992

Total Investment per Unit of Produced Oil

NOK/Sm3 (1988 value) USS /Bl.

500 - _{- 12}

Statfjord Oseberg Guilfaks Snorre Snorre

Snorre field screening evaluation

z

UI

>

z

UI U) UI I-Ui

z

I-UI

00

-SHM (1).SJ4M (1) TLP(1)ReJoc GT (1).GT

Snorre TLP

GT(3)+GT(1) SP-3 (3).SP-3 (1) GT(1).SS MT (1)#SS GT (3).SS P.3 (3)+SS (1)+SP.3 (1) eloc SHM (1)4SS 2xFPS.Tanlcer (3) S S PROJECT ECONOMICS INCL DEVELOPMENT COSTS PROJECT ECONOMICS EX. DEVELOPMENT COSTS

Snorre TLP Hull and Deck

Snorre Tether Mooring System

CROSS LOAD BEARING

TLP installations

300 500 600 700 800 900

Oil Production Snorre TLP 1994

250 200- 150- 100- 50-1984 HU7TON 63300 ton

13579

1989 1992 1993 1995

JOLUET SNORRE AUGER HEIDRUN

16600 ton 106 500 ton 66200 ton 292 000 ton

I-636m -310m -872m

--t71/

11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 5 Week no. -345m

,,,,,,,,,,,, ,,/,

Snorre TLP Weight

ManagernefltQUrVe

HCG(m) 0.8 0.6 0.4 0.2

Design Conditions for tether system

I1 _(m) 10-5. 76000 77000 78000 79000 TLP weight (tonfles) Max offset Max tension 10 .1.5 20

100 year design curve Mm teflsion

Max weight

SnOrre TLP weight rnanagemnt

78000 77800 77600 7740Q C C . 17200 77000 76800 76600 76400

Measured and logged weight December 93

Storm of 04.01.93

20- 19- 18- 17- 16- 15- 14- 13- 12- 11-

10-

9-

8-

-7-

6-

5-10 000 year

Lycar

Actual seastate 0 I - - - i 0 5 10 15 20 25 30 Tp (see) 0 10 Date Measured Logged

TLP motionS 04.0193

TLP Position trace 20 15 10 E 5 -5 -10 -5 0 5 meters

TLP motions 04.01193

Total motion North

500 1000 1500 2000 2500 Time (sec) LE moon Nrth 500 .to_0o 1O0 2000 2500 Time (sec) 20 10 15

Snorre Offshore Verfication program

Wave frequency surge and sway

(St. devils)

Spectrum peak period (sec)

irreQffslore Vertication program

Low frequeny surge ad sway

(St.deviH2)

0.20 0.18 0.16 0.14 0.12 0.10 -0.08 0.06 0.04 0.02 -U I U a C C Co

Ii_-C a C iD

I--Arialveis D Full scale -0.00 50 I 6.0 I 7,0 ! 8.0 9.0 _I-10,0 11.0 12,0 13.0 14.0 15,0 16,0 17.0 18,0 19.0 6 7 9 10 11 12 13 14 15

Spectrum peak period Cs)

0.12 0.10 0.08 0.06 0.04 0.02 0.00

Snorre Offshore Vertication program

800- 700- 600-500-P 400- 300- 200- 100-0 250 200 150 100 -50 0 5 5 6

WF Tension in heaviest loaded corner (St. dev. I Hs)

9 10 11

Spectrum peak period(S)

Sflorre Offshore Vertication program

High frequency tether tension

(St. dev Iifs2) 12 13 14 15 Model tests C _{Full scale} Design C

-- ---I

- _ -6 7 8 9 10 11

Spectrum peak period (a)

15

13 14

Tether ringing Snorre TLP

190

High frequency tether tension (tonnes)

TLP wave frequency sway motion (m)

Water surface elevation W (m)

Water surface elevation N (m)

200 210 220 230 240

Time (sec)

250 260 270 280 180 190 200 210 220 230 240 250 26Ô 270 280