kristin hpht field development - · pdf file · 2013-06-17developments of natural...

Developments of Natural Gas Market

XVII Gas Convention, AVPG, Caracas, Venezuela, May 23 - 25 th, 2006

KRISTIN HPHT FIELD DEVELOPMENT

Håvard LidalStatoil ASA

[email protected], Norway

Hogne PedersenStatoil ASA

[email protected] Stavanger, Norway

1. ABSTRACT

The Kristin gas and condensate Field is located in the Norwegian Sea atsea water depths of about 320 meters. The Kristin field development wassanctioned by the license holders in August 2001. The Kristin semisubmersible gas production platform was anchored at the field March 2005,and first gas was produced on November 3 in the same year. These areimportant milestones achieved on schedule on this extremely challengingproject, where the high pressure and temperature of the reservoir fluidscontributes significantly to the complexity of the entire project requiring newtechnology to be developed for the field development to become feasible.Combined with constituents such as mercury, hydrogen sulphide andcarbon dioxide in the production fluids, this has lead to utilizing innovativetechnology to combat the technical challenges.

This paper describes some of the lessons learned from the projectexecution and some of the first operational experiences encountered.Furthermore it gives an overview of the HPHT design premises for theKristin Field development and how this has influenced the choice oftechnical solutions, particularly on the subsea equipment. Kristin is locatedin a harsh part of the world when it comes to climate and weatherconditions, and particular attention is paid on using technology based onsound environmental practice. This will be described, as well as theorganizational principles of the project.

Project experiences relevant for Venezuelan offshore gas projects, such asPlataforma Deltana, is also highlighted.



2. INTRODUCTION

The Kristin field is located approximately 240 km west of the mid-Norwegiancoast, 16 km south west of the Åsgard field. The reserves are expected tobe 43 GSm3 of rich gas and 38 millon Sm3 of hydrocarbon condensate.During peak production, the rich gas design rate is 18.3 MSm³/sd, and thecondensate rate is at maximum expected to be approximately 20 000Sm³/sd.

The final cost of the Kristin field installations was approximately 2 billionUSD.

The Kristin development project comprises one floating production unit (asemi submersible platform), four subsea production templates and six 10"flowlines transporting the well stream from the templates to Kristin. Thegas-condensate field, which is classified as HPHT, was developed with 12subsea wells distributed on 4 subsea templates. The two 4-slot templateslocated in the central region of the field (R and S) are each tied in to Kristinby 2 off 10" ID flowlines. The two 4-slot templates in the northern region (Pand N) are each tied in to the Kristin semisubmersible by a single 10" IDflowline. A subsea High Integrity Pressure Protection System (HIPPS) isused to protect flowlines and flexible risers from over-pressure. Directelectrical heating (DEH) is required for hydrate control and one DEH cablehas been installed with each of the flowlines.

Two control umbilical systems with 3.5" service lines, one to the northerntemplates and one to the central templates, supports the templates withpower, signal, hydraulics and chemicals.

The condensate is stabilised at Kristin and transferred by a 12" pipeline toÅsgard C. The condensate pipeline connects to 12" flexible risers at Kristinand Åsgard C.

Rich gas is processed at Kristin to Åsgard Transport specifications andtransported to the 42” Åsgard Transport pipeline by an 18" pipeline loop witha length of approximately 30 km. The gas pipeline connects to ÅsgardTransport pipeline with a crossover spool and to Kristin with two flexiblerisers.

A fibre optical cable connects Kristin to the Halten-to-onshorecommunication network.

The project was sanctioned late 2001 with engineering and procurementbeing performed in 2002 and 2003. The majority of the installation work wasperformed in 2004 with riser installation, tie-in and hook-up in 2005. The



field had first gas produced on November 3 2005, and the startup was madewithout gas leakages.

Figure 1: Kristin Subsea & Export systems field layout

The flowline system for the Kristin HPHT (High Pressure High Temperature)subsea development has been developed to accommodate its shut-inwellhead pressure of 740 bar and flowing wellhead temperature of 157 degC.

This has required development of a HIPPS system (High Integrity PressureProtection System) to protect the flowlines and risers from overpressure,upgrading of DEH system technology (Direct Electric Heating) for hydrateprevention in shut-down situations, implementation of a new CP system(cathodic protection) of the flowlines and extensive qualification work relatedto flowline materials and flexible risers. Significant dynamic flow assurancework has been performed as the basis for all qualification and developmenttasks.

The living quarters at the Kristin platform was designed to accommodate104 persons in single bedrooms, and the minimum staff during normaloperation is anticipated to be 29 persons.



The design premises, project execution and technical challenges of theKristin project have previously been presented at numerous occasions, suchas Lidal [2002], Sirevaag et.al. [2005], and Lidal and Heimset [2005].

3. SYSTEM DESIGN - HPHT PRESSURE MANAGEMENT

The high reservoir pressure of 911 bar results in a maximum shut-inpressure at the wellhead of 740 bar. However, the flowline and flexibleriser system has a design pressure of 330 bar due to limitations in thedesign of 10” ID flexible risers. Hence a pressure protection system isrequired for the flowlines and risers.

The operational pressure of the flowlines can vary between 90 and 240bar. The pressure will be adjusted by both topside and subsea choking. Ifthe pressure exceeds 260 bar at the template, the primary pressureprotection system will be activated. A process shutdown will close the X-mas tree’s master and wing valve when reading high pressuredownstream the subsea choke. If this operation fails and the pressureincreases to 280 bar, the HIPPS will be activated. The HIPPS consist oftwo 10” valves with independent pressure sensors and activation systemlocated at the production headers. If two out of four pressure sensorsmeasure a pressure above 280 bar, the valves will close within 12seconds. The HIPPS has a very high availability, and would normally besufficient for pressure protection of the risers. However, due to the flexiblerisers a third pressure protection system is required to achieve the overallsafety acceptance criteria.

The flexible risers have lower pressure integrity than the steel flowlines.Hence, if the flowline system is over pressurized, it is likely that the flexiblerisers will burst before the flowlines. Normally, the flowlines will have anincreased wall thickness at a distance less than 500 m from the topsidefacility. This will assure that the flowline will not burst close to thefloater/platform. Due to the flexible risers this cannot be achieved for theKristin development. This problem is solved by installing PSVs at the topof the risers. These PSVs are designed to handle a flow rate ofapproximately 8 MSm3/d. Figure 2 shows the 3 different pressureprotection systems for the Kristin flowlines:



Figure 2: Pressure protection system

Activation of the pressure protection system will increase pressure andtemperature loads on the production system. These loads are described inthe HPHT temperature management section.

4. SYSTEM DESIGN - HPHT TEMPERATURE MANAGEMENT

Reservoir and flowing wellhead temperaturesEstablishing design temperatures for the reservoir and the flowingwellhead temperatures has been important for the thermal design of theproduction system. The highest temperature for the producing reservoirzone has been estimated to 169°C (at 911 bar). Due to difficulties in theinterpretation of well test data, it has been challenging to establish adesign flowing wellhead temperature (FWHT). In order to establish anaccurate and verified prediction of the wellhead temperature, the so-calledJoule-Thomson inversion effect, seen for elevated pressures must bequantified. Predictions of the effect from PVT simulations and estimates ofthe effect from well tests were used.

A detailed thermal analysis of the flowing well, taking into account theestimate of the Joule-Thomson effect, was used to establish the FWHT.

Normal operation During normal operation the flowrate from each well will initially vary from1 to 3.5 MSm3/d. This will give a flowing wellhead temperature ofapproximately 157°C. Due to choking on the wellhead, the temperaturedownstream the subsea choke will be 152°C. Taking into account theuncertainties in the simulation models and measurements, the templatepiping upstream the choke, template piping downstream the choke and theflowlines were given design temperatures of 162 ºC, 157 °C and 155°C

Tem plate design pressure: 740 bar

Flowline des ign pressure: 330 bar

1. Master valveW ing valve(set point: 260 bar)

2. H IPPS (set po int: 280 barg)

3. R iser PSV(set point:300bar)

Pressure protection system s

Tem plate design pressure: 740 bar

Flowline des ign pressure: 330 bar

1. Master valveW ing valve(set point: 260 bar)

2. H IPPS (set po int: 280 barg)

3. R iser PSV(set point:300bar)

Pressure protection system s



respectively. The flexible risers (pressure shield material) have a designtemperature of 132°C, and substantial cooling of the wellstream isrequired in order to keep the temperature below 132°C at the riser base.This has limited the thermal insulation of the flowlines.

The coating system is based on poly-propylene (PP), and the insulationthickness of 33 mm gives an overall U-value of 8 W/m2/K. In addition tothe coating there are extra contributions to the overall thermal insulation ofthe lines: parts of the flowline will be covered by gravel, parts of theflowline will penetrate into the mud, and a PP protection structure for theDEH cable is strapped onto the flowline. Taking into account these extrainsulation effects the arrival temperature at the riser base will be 132°C atmaximum operating pressure (240 bar into the flowline) and designflowrate (4 MSm3/d).

This leaves no margin for the riser design temperature at maximumoperating pressure. However, by decreasing the pressure in the flowline,the cooling over the subsea choke will increase. This will lower thewellstream temperature into the flowline. When operating at minimumoperating pressure (130 bar into the flowline), the temperature at the riserbase will be reduced to 123°C. This will give sufficient temperature controlat the riser base. As the pressure in the reservoir decreases, the expectedflowing wellhead temperature decreases, since the expansion heatingeffect is avoided. Figure 3 presents the design temperatures for theflowline system.

Figure 3: Design temperatures

W ell & X-m as tree162°C

T em pera ture m anagem ent- D es ign tem pera tures

F lo w line – 6 km155°C

F lex ib le r ise r132°C

F lo w line : U -va lue o f 8 W /m 2/k p rov ides coo ling from 155 to be lo w 132°C



Hydrate preventionThe main hydrate control strategy for a planned shutdown is to inhibit theflowline system prior to shutdown. During restart, the wellstream will beinhibited at the wellhead until the temperatures are above HET (hydrateequilibrium temperature). This will be performed as long as the waterproduction is low (below 1500 Sm3/d).

For unplanned shutdowns, available hydrate control measures are limited.Neither displacement of wellstream in the flowline system nordepressurisation of the flowlines are feasible due to limited liquid handlingcapacity during shutdowns. Also the cooldown time to hydrate formation(23°C) is relatively low (6 hours) due to the limited thermal insulation onthe flowlines. Hence, a direct electric heating system (DEH) has beenselected for the flowlines to keep the fluid above the hydrate formingtemperature (23 °C) during unplanned shutdowns, and for scenarios ofplanned shut-ins with high water production. The end zones will bedisplaced/inhibited with hydrate inhibitor. This applies for the X-mas tree,manifold, spool and riser.

The principle behind the direct electric heating (DEH) system is to sendelectric current through the pipe wall, thereby generating heat. The currentis fed through two electric cables connected to each end of the flowline.The cable is strapped on the flowline inside a protection structure. Theelectric current generates an electromagnetic field, which keeps theelectric current in the flowline wall. Only a small percentage is lost to thesurrounding sea.

For the information contained in sections 4 and 5 reference is made toSirevaag et. al. [2005], where further details are also described,particularly related to material challenges and corrosion considerations.

5. SEMI SUBMERSIBLE AND PROCESS CONSIDERATIONS

GeneralThe Kristin semi submersible platform hull construction was made at theSamsung yard in Korea. The topside modules made in Norway and Spainand the living quarter from Emtunga in Sweden were all assembled at theAker Stord yard at the Norwegian west coast, where the sail-away to thefield and anchoring took place in March 2005, see picture below.



KRISTIN SEMI SUBMERSIBLE

The topside process scheme is described in Figure 4. It consists of a threestage stabilisation of the condensate, and recompression of the gas from2nd and 3rd stage separator, combined with the gas from 1st stage. Thisgas is dried in a TEG contactor, and then compressed to about 210 bar.The gas is after compression transported in the Åsgard Transport pipelinetogether with gas from Åsgard B, Heidrun and Norne to the Kårstøterminal about 700 km further south.

The condensate is pipelined to the Åsgard C tanker some 23 km awayfrom the Kristin platform.

H2S and mercury removal facilities are installed topside at Kristin, anddescriptions of these parts of the plant are given below.



Figure 4: Kristin Process Scheme

Key reservoir data from the two production zones at Kristin is given inTable 1.

Field Kristin,Ile formation

Kristin, Garn formation

Depth below MSL (m) 4720-4800 4600-4690Initial Reservoir Pressure 911@4795 m MSL 894@4618 m MSL

Reservoir Temperature (°C) 169 (+/-2)@4795 mTVD MSL

164 (+/- 2)@4618mTVD MSL

GOR (Sm3/Sm3) above dew point 1096 (Full process)1243 (Single flash)

853 (Full process)953 (Single flash)

CO2 (mole%) 3.6 3.6H2S (ppmv) 14 16

Mercury Hg(1) (µg/m3) 5 24

Table 1: Key reservoir data.

Kristin Process18.3 MSm³/sd210 bar

50°CPcr ic <105 barg

Subsea

GT Åsgard Transport

MeterScavenger, back -up

Fuel Gas

26°C

31°C

25°C

Meter TVP 0.965bar @ 30°CÅsgard C

26 bar

2 bar

20000 Sm³/sd67 bar

70°C

30°C 30°C 30°C

Test

Innløp121°, 87 bar

Test



Hydrogen sulfideThe H2S content in the sales gas to the European continent will normallybe controlled from the onshore facilities at Kårstø. In the FEED phase ofthe Kristin project an offshore Compact Alkanolamine Plant (CAP) wasconsidered. The CAP process is based on a cocurrent contactingtechnology for the amine/H2S absorber, avoiding a large contacting tower.Amine plant cost, weight, and energy consumption closely correlate to theamine circulation rate. Tests and case studies described in Nilsen et. al.[2002] indicates that the amine circulation can be reduced to well below50% of a conventional amine plant. This made the CAP process anattractive alternative for the Kristin development. However, due to therelatively low H2S content of the gas (maximum 16 ppm expected) and thewish to reduce the complexity of the offshore process facilities, it wasconcluded early in the project to place only a back-up H2S scavengerfacility at the Kristin platform.

The H2S scavenger system on Kristin consists of two separate injectionunits. The units have independent solvent distribution, which facilitatesprocess control and optimization, similar to the cocurrent conceptdeveloped for the CAP process. Statoil installed the first of these systemsin two 24-inch pipe lengths in series at the Åsgard B platform, started up inyear 2000. The scale up was demonstrated and the technology proved itscapability with more than a 35% reduction in scavenger liquid compared toconventional direct injection methods, see Linga et.al. [2003].

MercuryMercuric sulfide fouling of Printed Circuit Heat Exchangers (PCHE) hasbeen observed at other installations, such as Åsgard. At Kristin we haveextensive use of these exchangers in order to save weight and space, andit was decided at a very late project stage to include a mercury removalunit (MRU) in the Kristin design. The Kristin MRU design is based on tworadial flow absorbers of PURASPEC 1157, and it was designed for a feedgas containing 25 µg/Sm3 and a Hg outlet requirement of less than 10ng/Sm3. The MRU is placed downstream the TEG dehydration contactorat process conditions of 31oC and 85 bara.

Gas export vibration challengesA major problem encountered at start-up of the nearby Åsgard B platformwas noise and vibrations in the gas export system. The root cause of thenoise was identified to be the vortex shedding at the carcass groves insidethe risers. A model testing programme was launched where first theÅsgard B export system was modelled in order to check whether thevibration characteristics found on full scale platform could be



demonstrated in model scale. As this was successful, models of Kristinwere made both in 1/10th scale and 1/4th scale.

By maximising riser diameter and pitch length of carcass winding it wasdemonstrated that in normal operation acoustic vibration problems wouldprobably not be encounter in the gas export system, however in case ofreduced pressure or if all production for some reason had to be throughone riser only, the risk for vibrations would be significant. In order tocompensate for this an acoustic full bore three chamber silencer wasintroduced in the topside piping, close to the riser hang-off, showing goodeffect in the model testing.

The first months of operation indicate that the modifications made to thegas export risers have been a success – no vibrations have beenobserved.

6. PROJECT ORGANIZATION

GeneralThe project was organized with an asset management team responsible forthe total project execution, including drilling & completion, reservoir,operations, and field installations. From the field installation part of theproject, the project director (vice president), technical manager and subsea& export manager was a part of the asset management team.

This paper has dealt predominantly with the field development part of theproject, which included the design and delivery of subsea equipment andpipelines and risers, as well as the design and construction of the semisubmersible production platform.

Experienced personnel from the operations department were integrated inthe project organization already from the FEED phase. This integrationturned out to be a significant success factor for the project. The engineersand process technicians from operations had vast experience from previousinstallations, and they could contribute early to create an operator friendlyand safe design, both to subsea and topside solutions. This was donethrough their daily work, but also by participating in HAZOP’s, reviews,inspections and tests.

Marine operations & Interface managementBelow you will find some of the marine operations planned for during theKristin Field Development project period:

• Geotechnical operations / route surveys• Subsea template installation



• Pre-installation of suction anchors for drilling rigs • Drilling and completion• Subsea manifold installation• Subsea protection structures installation • X-mas tree installation / well completion• Flowline and export pipelines laying• Installation of riser base and SSIV's• Control umbilical and service line laying• Laying of fiber optical cable• Spool installation to templates and Åsgard export line• Subsea tie-in of flowlines, export pipeline and umbilicals• Trenching and rock dumping of flowlines, pipelines and umbilicals• Semi mooring system pre-installation• Semi transport and mooring• Risers, dynamic control umbilicals and electrical risers hook-up to

Semi• Subsea intervention during initial production start-up• As-installed subsea inspection of hot systems • First years subsea inspection.

The marine operations activities were coordinated by the use of a meetingcalled Marine and Interface Forum, where all parts of the projects, includingstaff functions, were represented. This proved to be an efficientmanagement tool to enable proper interface management in the project.During the most intensive periods of operations daily meetings between theparties of concern were needed. All marine activities were completedwithout incidents or conflicts. As a maximum there were 15 vessels at thefield at the same time, and in year 2004 alone we had 1200 vessel days atthe field.

The Interface Forum was also responsible for the change management ofthe entire project, where strict rules were enforced in order to obey a nochange philosophy, and at the same time facilitate to deal with changeproposals in a professional and efficient way. An example of a late change,that was deemed necessary despite of bad timing, was the late inclusion ofthe mercury removal plant, described earlier in this paper.

A lesson learned from the Kristin project is to take the interfacemanagement serious, and to focus hard on change management. This wasdone on Kristin, and we capitalized on it.



7. OTHER ACHIEVEMENTS

At Kristin the world has seen major technology leaps related to drilling andcompletion in high pressure, high temperature and high angle drilling andcompletion challenges. These can be summarized as follows:

• In October 2004 Kristin drilled the first high angle subsea gas producerunder such HPHT conditions.

• In May 2005 Kristin completed and clean up tested the same well withexpected productivity.

• In August 2005 Kristin drilled the longest horizontal subsea gasproducer.

• In September 2005 Kristin completed the first HPHT commingled gasproducer with sand control and open hole packers.

An extensive technology qualification program was conducted in parallelwith the Kristin development project. The qualification elements were mainlyrelated to subsea and well equipment, and had mostly to do with materialand equipment expected to stand unusual pressures and temperatures. Allimportant milestones were met. However, a lesson learned is to limit thenumber of elements needed to be qualified during a project execution, to anabsolute minimum.

A late project challenge came during the summer of 2005. In mid-july, just afew days before we were ready to take Kristin gas onboard, Statoil learnedfrom another installation, Veslefrikk, that some lifeboat tests had failed. Wehad to move most of the work force from the offshore installation to onshore,and progress was highly affected for more than two months, while the lifeboats were re-enforced, re-tested, and re-installed. Despite this lateobstacle and challenge, we were able to start production only 1 month late.

What this also shows is how vulnerable a large project often is to the mostsimple challenges and technologies, if they fail. The lesson learned heremust be to “expect the unexpected”, and to not underestimate theconsequences of not having an eye on every detail. On Kristin we did havea strong focus on quality assurance, and we did conduct our ownsupervision activities to a large extent. We established a system calledKristin Supervision, administrating close to 1000 heavy supervisionactivities, such as audits, technical verifications, reviews, and follow-upactivities. More than 9000 observations were reported and closed out priorto startup.



8. CONCLUSIONS

The first months of operations indicates that a robust process plant hasbeen built, and a regularity figure of 99% was obtained during February2006.

As described in this paper, the Kristin field development project hasgathered important experiences related to;

• Mega scale project execution • Deep water offshore challenges• Dealing with high pressures and high temperatures• Subsea production equipment• Drilling and completion experiences at HPHT and high angle • Pipelines• Materials

all of which having considerable relevance to future field developments inother parts of the world, such as in Venezuela. For example in thePlataforma Deltana project one can expect interesting results by combiningthe fresh Statoil Kristin experiences with the local industry experiences fromVenezuelan petroleum operations.

9. ACKNOWLEDGEMENTS

The authors would like to acknowledge the extensive contributions made byindividuals and units in the Statoil organization, the Kristin suppliers and theKristin license, enabling the design, installation and startup of the Kristinfield.

10. REFERENCES

Lidal, H. 19. "Kristin", Paper presented at IBC’s 17th Annual Conference &Exhibition on Floating Production Systems, London , UK, 2002.

Lidal, H., Heimset, B., “Kristin HPHT Field Development Premises,Execution and Lessons Learned”, Paper presented at Deep OffshoreTechnology, Vitoria, Brazil, 2005.

Linga, H., Nilsen, F.P., Knudsen, B.L., “Prediction Model Optimises H2SScavenger Injection Strategies”, Paper presented at Sulphur 2003, Banff,Canada, 2003.



Nilsen, F.P., Lund Nilsen, I.S., Lidal, H., “Novel contacting technologyselectively removes H2S”, Oil & Gas Journal, PennWell, May 13, 2002.

Sirevaag, R.B., Huseby, T., Løseth, S., “Kristin HPHT Flow Assurance,Flowline and Riser Premises, Execution and Lessons Learned”, Paperpresented at Deep Offshore Technology, Vitoria, Brazil, 2005.

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