tep 30 – lecture 2008-10-01folk.ntnu.no/cadorao/courses/tep10/files/tep102008-10-01... ·...
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Classification: Internal Status: Draft
TEP 30 – Lecture 2008-10-01
1. Description of the Snøhvit Value Chain
2. Multi-phase flow and receiving facilities
3. Flow assurance
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Opportunities at the Arctic frontierOil and gas reserves in the Barents Sea
Snøhvit – opening the Barents Sea
Large oil and gas resources to be exploited in our neighborhood
Cost challenge to be overcome
Strong environmental focus
Snøhvit190G (*)
1050G2100G
840G
(*) GSm3 recoverable reserves
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Snøhvit LNG projectValue chain
Fielddevelopment Pipeline LNG plant Shipping Receiving
terminal
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New challenges at new frontiersSnøhvit: A milestone project for Statoil – and for the NCS
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Snøhvit factsThe first gas development project in the Barents Sea
Discovered:1981 – 84Fields: Snøhvit, Albatross and Askeladd fields in the Barents SeaWater depth: 250 – 340 mDistance to shore: 140 kmGas in place (GIIP): 317 GSm3 / 11.2 TCF (terra cubic feet)Condensate: 34 MSm3
Owners:
3.26%Amerada Hess Norge AS
2.81%RWE Dea Norge AS
12.00%Gaz de France Norge AS
18.40%Total E&P Norge AS
30.00%Petoro AS
33.53%Statoil ASA (Operator)
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The Snøhvit area Tromsøflaket
71°30'
Kilometre
7120/6-1
7120/7-17120/7-2
7120/7-3
7120/8-1
7120/8-2
7120/8-3
7120/9-17120/9-2
7121/4-1
7121/4-2
7121/5-1
7121/5-2
7121/7-1
7121/7-2
20°20' 20°40' 21°00' 21°20' 21°40' 22°00'
71°30'
PL099
PL110
PL110PL097
PL097
PL100
PL078PL077
Askeladd Vest
Askeladd S°rGamma
Albatross Sør
Albatross
Sn°hvit
Sn°hvit Nord7121/5-Beta
7121/5-Delta
PL064 PL110
Askeladd Nord
7120/5-1
0 5 10 15 20 25
Gas: 127 GSm3
Oil: 71 MSm3
Gas: 70 GSm3
Gas: 114 GSm3
Gas: 134 GSm3Oil: 73 MSm3Condensate: 20 MSm3
Gas: 114 GSm3Condensate: 8 MSm3
Gas: 69 GSm3Condensate: 6 MSm3
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Field and pipeline layout
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04/13
04/2404/2304/22
12/0412/03
04/21
Snøhvit
Albatross Nord
Askeladd
Goliath
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425
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35030
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Hammerfest
20°E
20°E
21°E
21°E
22°E
22°E
23°E
23°E
24°E
24°E
71°N71°N
71°30'N71°30'N
Rørtrase pr.28.3.2003CENTERLINE-MAIN
Grenser* Grunnlinje
! ! ! 4 NMil
0 5 10 15 20 252.5 Kilometers
PTT/TTJ/NKG/20030402vle_snohvit_a4_centerline-main
Fiskeriområde/lokalitet04/13,04/22,m.m.
WGS84 UTM34
1:600 000
Well stream pipeline 143 km 26.8”IDCO2 pipeline 152 km 8” IDMEG pipeline 2 x 143 km 4” IDUmbilical 143 km
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Snøhvit – a subsea developmentSnøhvit 8 wells + 1 CO2 injector
6 wells + CO2 in 2004/2005, 2 wells in 2011
Albatross 4 wells3 wells in 2005/2006, 1 well in 2014
Askeladd 8 wellsAll wells in 2013/2014
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First NCS remote controlled fieldNew world record
Statoil introduces remote control and multiphase transport over 143 kilometres.
Remote control
Fibre optic cable instead of electric
Use of 3 kVAC electric current instead of 0.8 kVAC
Multiphase track record
Statfjord and Gullfaks satellites
Troll onshore
Åsgard – Midgard/Mikkel
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48
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87
143
0 50 100 150 200
Sygna
TOGI
Midgard
Mikkel
Snøhvit
km
Snøhvit a new step in the technology ladder
NCS = Norwegian continental shelf
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The Hammerfest area
Melkøya AirportHammerfest
Polarbase
Rypefjord
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Melkøya
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HAMMERFEST LNG PLANT
Slug catcher
HP flare
LP flareCamp area
Condensate storage tank
LNG storage tanks
Production jettyLPG storage tank
Storage & loading substationN2 cold box
NG Cold box
Process substation
Electrical power generation
Compression area, barge
Process area, barge
Construction jetty
Subsea road tunnel
Administration building / control room
Sea water outlet /sea water inletHolding basin / waste water treatment
Utility substationMDEA storage / fuel gas
Compressed air and inert gas facilities
LandfallOffshore utility substation
MEG process area
MEG substationMEG storage tank area
Hot oil and chemical storage
tanks
Pig receiver
Grid substation
14Gas and CO2 flow
ONSHORE
OFFSHORE
CO2
Wellstream
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Process bargeBarge topside
Weight: 25 000 tonHeight: 40 m (above
deck)
Barge hull Weight: 10 000 tonLxWxH: 154x54x9m
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Storage area1 Condensate tank75 000 m3
Diameter: 62 mHeight: 43 m
1 LPG tank45 000 m3
Diameter: 54 mHeight: 36 m
2 LNG tanks125 000 m3
Diameter: 78 mHeight: 47 m
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Prefabrication a necessity
Harsh weather conditions and limited infrastructure make prefabrication a necessity
Compact layout
Method that can enable projects in other remote areas
The largest industrial development in Finnmark, Norway
LNG plant layout
Process barge layout
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Block Flow Diagram
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Sailing routes
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LNG trade
Source: Cedigaz, BP, 2002
76 %
19 %
5 %
Domestic Piped gas LNG
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Importers of LNG
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120
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160
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1964 1968 1972 1976 1980 1984 1988 1992 1996 2000
Bcm
USAEuropeTaiwanKoreaJapan
Source: PEL
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Statoil – entering a new marketStatoil’s entry into the LNG market.
Building on market competence and strengthening established positions in the US and Spain.
Statoil sells annually 1.9 bcm equity and 1.7 bcm on behalf of the Norwegian state of total Snøhvit sales.
New Statoil entity, Statoil Natural Gas LLC, is the buyer of Snøhvit LNG to Cove Point
Contract period 17-20 years
Cove Point
annually 2.4 billion cubic metres
Iberdrola S.A.
annually 1.6 billion cubic metres
LNG the fastest growing energy market
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Income, investments and manpowerInvesting in the future
Income 250 billion NOK
Total development including vesselsInvestments 56 billion NOK 20 - 30 000 man years50% Norwegian contracts1500 persons at Melkøya on peak
Operation160 man yearsAppr. 350 man years indirectly
Value creation
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Persons that have performed work at MelkøyaPer January 2005
Total: 7 626 persons
Norwegian: 5 508 persons
Three northernmost counties 2 236 persons
Locally (Hammerfest/Alta) 1 480 persons
Foreigners: 2 118 persons / 46 nationalities
Personnel diversity
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Regional / local deliveriesPer January 2005
Aggregate 29.1 bill NOK
Norway 14.9 bill NOK
International 14.2 bill NOK
Northern Norway 2.0 bill NOK
Hammerfest/Alta 1.5 bill NOK
51.1% Norwegian deliveries
Classification: Internal Status: Draft
Multi-phase flow and receiving facilities
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Long distance multiphase flowNew world record
Statoil operated
In operationConstruction/planned
Transfer length (km)
Liqu
id R
atio
(bbl
/ M
MSC
FD)
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20
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60
70
0 50 100 150 200
MalampayaMikkel
East SparGoldeneye
KuduMensa
Popeye
North Alexandra
Western HubEM
TrollTOGI
Midgard
West deltaCorrib
Current operational limit
Snøhvit
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Pipeline operation at Snøhvit
Challenges in operation
- Long Distance Multiphase Flow
- Corrosion control
- Hydrate Control
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Flow PatternsOnly two flow patterns relevant for Snøhvit
1) Stratified flow
2) Slug flow
Væskeslug
Taylor-boble
Video Clip
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Pressure dropEquilibrium situation for steady state production
70 bar outlet pressure
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2 0 0 0
4 0 0 0
6 0 0 0
8 0 0 0
1 0 0 0 0
1 2 0 0 0
1 4 0 0 0
6 8 10 12 14 16 18 20
Flowrate (MSm³/sd)
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Pre
ssur
e dr
op (b
ar)FriksjonskontrollGravitasjonskontroll
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Pressure and Temperature profile
Pressure & temperature profile,main pipeline. 20 MSm³/d and 70 bara
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0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150
Distance from PLEM (km)
Pre
ssur
e (b
ara)
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Tem
pera
ture
(°C
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Pressure profileTemperature profile
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Kondensat mot Vann/MEGEquilibrium situation for steady state production
70 bar outlet pressure
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4000
6000
8000
10000
12000
14000
6 8 10 12 14 16 18 20
Flowrate (MSm³/sd)
pip
elin
e liq
uid
cont
ent (
m³)
Total liquid content (m³)
MEG/water content (m³)
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LIKEVEKT / TIDSFAKTORER
Equilibrium situation for steady state production70 bar outlet pressure
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14000
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Flowrate (MSm³/sd)
pip
elin
e liq
uid
cont
ent (
m³)
Total liquid content (m³)
MEG/water content (m³)
t < 2 days
t < 0.5 day t = 33 days
t = 4 days
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”WORST CASE” corrosion rates
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Slug Catcher• The purpose of the slug catcher and inlet facilities is to expand the feed
stream from the pipeline, to buffer and handle liquid slugs from the pipeline system and to recover the rich MEG from the feed stream liquids.
• The slug catcher must be capable of taking the largest slug possible without overfilling.
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Slug Catcher and Pigtrap
Photo: Torstein Tyldum Photo: Kjell Alsvik
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Slug catcher at Melkøya
Liquid working volume (4.3 % of pipeline) : 2700 m3
Fabriction weight : 6.000 tonsSize: 110m x 85m x 15m
MEG/Water : 12.7 m3/hCondensate : 182.7 m3/hGas : 8721.3 m3/h
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Inlet facilities• Metering system
• Integral filter for removing contaminants
– prevent foaming in CO2 removal unit
– operation problems in the MEG loop
• Connection to feed gas system
• Feed gas compressor
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Classification: Internal Status: Draft
Flow Assurance
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Hydrate ControlHydrate equilibrium curves
Snøhvit Gas Condensate 7121/4-1 DST 4
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-20 -15 -10 -5 0 5 10 15 20 25 30
Temperature (C)
Pres
sure
(bar
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60 wt% MEG/40 wt% water 20 wt% MEG/77 wt% water/3 wt% NaCl Fresh water
Hydrat dannes over og til venstre for kurvene. Microsoft werPoint Presentat
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MEG RecoveryDesign Intento Mono Ethylene Glycol (MEG) is used as a hydrate inhibition fluid in the subsea gas pipeline by continuous
injection of Lean MEG (90 wt-% MEG, 10 wt-% water) at the Offshore Production Facilities. Lean MEG also acts as a carrier fluid for chemicals like NaOH for pH-control and corrosion inhibitor. In case of a formation water breakthrough, Clean Lean MEG (90 wt-% MEG, 10 wt-% water, no pH stabilizing products, salts or solids) is injected at the Offshore Production Facilities. Clean Lean MEG is also used for offshore services.
o The injection rate of the Lean MEG is controlled to obtain an on-shore rich MEG phase from the Slugcatcherof 60 wt. % MEG and 40 wt. % water.
o In order to save operating costs, the arriving Rich MEG is processed in the MEG Recovery and Lean MEG is recycled back to the Offshore Production Facilities. The following substances have to be removed to produce Lean MEG for recycling:
o Condensed and formation water from the wells. Water contained in the pH-stabilizer is also removed.
o Dissolved ions from formation water (up to 170 g/l salts contained in the formation water), corrosion and pH stabilization products
o Physically dissolved and entrained hydrocarbons, CO2
o Suspended solids (carbonate scale and corrosion products)
o Storage facilities for both Rich and Lean MEG have also to be provided.
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MEG RecoveryFunctional Requirements
oThe MEG Recovery is divided into six units:
o Pre-treatment
o Rich MEG Storage
o Solids Removal
o Ion Removal
o Water Removal
o Lean MEG Storage and Injection
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MEG RecoveryBlock Diagram
Rich MEGStorage
Rich MEGPretreatment Ion Removal
Impurities and Waterfrom Wells
Salty RichMEGStorage
CleanLean MEG
Storage
Solids Removal Water Removal
NaOH (30 wt%)
Salts and pHStabilizingProducts
Water
Process Watercontaining MEG
Lean MEG to Pipeline
Solids
Corrosion Inhibitor
Lean MEGStorage
Off-shorePipeline
Lean/Clean Lean
MEGInjection
Clean Lean MEG to Pipeline
Special WasteDisposal
EffluentTreatment
Special WasteDisposal CO2 Drying and
Compression
Off-gas Off-gasOff-gas
CondensateTreatment
Liquid Hydrocarbons
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MEG RecoveryPre-treatment
oThe Rich MEG phase from the Slugcatcher is sent to the Pre-treatment unit in the MEG Recovery. In the Pre-treatment, entrained hydrocarbons, dissolved hydrocarbons and CO2 are removed from the Rich MEG phase.
oThe Pre-treatment is designed to process up to 45.4 m3/h of Rich MEG in case of a Slugcatcher drainage (duration approx. 2 days). The normal flowrate is approx. 13 m3/h. The inlet pressure may vary between 35 and 115 bara. The inlet temperature may vary between - 5°C and + 4°C (continuous conditions). It is not allowed to vent the off-gas into the atmosphere.
oThe Pre-treatment is divided into two sections and each section has a capacity of approx. 175% compared to normal operation. During normal operation, only one train will be in operation while the other train is maintained or in standby.
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MEG RecoveryRich MEG Storage
o The Rich MEG phase from the Pre-treatment is sent to the Rich MEG Storage unit in the MEG Recovery. The Rich MEG tank provides storage capacity of up to 10 days for Rich MEG based on normal operation with pH-Stabilization.
o The Salty Rich MEG tank provides storage capacity for Salty Rich MEG during a 20 day formation water breakthrough.
o It is possible to route Rich MEG from the Pre-treatment during a Slugcatcher drainage to both the Rich MEG or Salty Rich MEG tanks (approx. 45.4 m3/h).
o Both tanks are atmospheric and the normal operating temperature varies from 20 to 30°C.
o The maximum drainage rate of the Rich MEG Tank corresponds to a Rich MEG flowrateduring normal operation plus the emptying of the tank within 20 days following a 10 day period where the Rich MEG from the Pre-treatment was stored. This flowrate is approx. 150% of the normal flowrate (20.2 m3/h).
o The normal emptying flowrate of the Salty Rich MEG tank is 2.5 m3/h. Following a formation water breakthrough, the salty Rich MEG is bled into the normal Rich MEG for processing.
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MEG RecoveryWater Removal
o Water is removed from the Rich MEG to produce Lean MEG (90 wt% MEG and 10 wt% water). It is also possible to produce 80 wt% MEG and 20 wt% water at reduced Lean MEG injection rates. To enable the possible fallout of wax in the Lean MEG Tank, the Lean MEG from the unit is delivered at 10°C.
o The water produced has a maximum limit of 50 wt ppm for MEG and a maximum limit of 50 wt ppm for Aromatics (Benzene, Toluene, Xylene). The maximum temperature allowed in the Effluent Treatment is 30°C.
o The normal flowrate to the unit is approx, 13 m3/h. The feed temperature is 30°C and the column operates at 1.3 bara. It is not allowed to vent the off-gas into the atmosphere.
o In order to process the normal flowrate plus the emptying of the Rich MEG tank within 20 days, approx. 150% processing capacity is installed. Due to the criticality of producing Lean MEG at all times, 2 X 75% sections are installed.
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MEG RecoveryLean MEG Storage and Injection
o The Lean MEG from the Water Removal unit is sent to the Lean MEG Storage and Injection unit in the MEG Recovery. The Lean MEG tank provides storage capacity of up to 10 days for Lean MEG based on normal operation.
o The Clean Lean MEG tank provides storage capacity for Clean Lean MEG for the duration of a 20 day formation water breakthrough.
o Both tanks are atmospheric and the normal operating temperature is 10°C.
o For normal operation, 8.3 m3/h of Lean MEG is injected into the Offshore Production Facilities via a dedicated Lean MEG offshore line. During a formation water breakthrough of up to 50 m3/day, 11 m3/h of Clean Lean MEG is injected into the Offshore Production Facilities via a dedicated Clean Lean offshore line. The maximum delivery pressure at B.L is 363 bara.
oLean MEG is also used as an onshore hydrate inhibition fluid. Clean Lean MEG is also used as an offshore service fluid.