Awarded Orders

A selection of recently awarded prominent orders.

shah-deniz
Customer: BP Exploration / AMEC
Project: Shah Deniz
Location: Azerbaijan
Products: 5 x Flare Gas Metering Systems

The Shah Deniz oil field lies between Mobil’s Oquz, Chevron’s Asheron and Exxon’s Nakhchiuan fields. Its name is translated as ‘King’s Sea’. The prospect is situated in the South Caspian Sea, off the Azerbaijan shore, approximately 70km south-east of Baku. It lies in water depths ranging from 50m in the north-west, to 600m in the south-east. The production sharing agreement (PSA) area covers approximately 860km².

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BP, with a share of 25.5% in the project, is the operator. The other PSA partners are StatoilHydro with 25.5%, Socar, LUKOil, TOTAL and NICO with 10% each and TPAO with 9%. The PSA was ratified in October 1996.

In 2010, the Shah Deniz project required $170.4m in operating expenditure and $389.6m in capital expenditure.

Shah Deniz reserves

The Shah Deniz structure lies 35km south-east of the Bahar field and 70km south-west of the supergiant Gunashli-Chirag-Azeri oilfield complex. With a vertical relief of over 1.5km (1 mile), the mapped structure encloses an area in excess of 300km².

The main reservoir rocks within the structure are expected to be at a total depth of 5km to 6.5km and they have been folded into a relatively simple dip-closed anticline structure.

Recoverable reserves for the first stage of development are put at 22.1trn cubic feet of gas and 750m barrels of condensate. Development of the reserves at depths of 600m has been carried out using technology originally developed for the northern North Sea and the Gulf of Mexico.

Shah Deniz exploration

Shah Deniz’s first three exploration and appraisal wells (SDX-1, 2 and 3) were started in 1999 and were designed to appraise and delineate the reserves in the northern flank of the field.

They focused on two structures – the Fasila Suite and the Balakhany VIII interval – which form the basis of the field’s first stage of development.

In November 2007, BP announced it had discovered a new, high-pressure reservoir in a deeper structure beneath the northern flank.

The SDX-4 well was drilled to a Caspian-record depth of 7,300m in the southwestern part of Shah Deniz, and tests showed a flow of 35m standard cubic feet per day, with likely reserves similar to if not larger than those in stage one.

This will form the basis of the second stage of development once appraisal over the next few years has delineated this new structure.

In December 2007, BP spudded the first platform-drilled well, SDA-5, which is designed to reach a depth of 7,180m.

Shah Deniz development

Stage one of the Shah Deniz project includes an upstream and a midstream development. The upstream development consists of a 15 well-slot TPG 500-type production, a drilling and quarters platform installed in 105m of water; three subsea pipelines of 90km each – a 26in pipeline for gas and a 12in pipeline for condensate, and a 4in monoethylene glycol pipeline – from the TPG 500 to the Sangachal terminal in the Azerbaijan capital, Baku; and gas and condensate processing facilities in the onshore terminal.

The midstream development consists of a new gas export system, the South Caucasus Pipeline (SCP), from Azerbaijan through Georgia to the Turkish border. The 690km, 42in SCP has a capacity of about 565bn cubic feet / year and has been built in the same corridor as the 1,760km Baku-Tbilisi-Ceyhan (BTC) oil export pipeline – the second longest in the world. It then links up at the Georgian-Turkish border to a 250km Turkish state-owned BOTAS pipeline that runs to Erzurum, where it enters Turkey’s domestic supply. This stage of production supplies Azerbaijan, Georgia and Turkey.

Stage two of Shah Deniz, known as Shah Deniz Full Field Development, will triple the field’s production. It will involve drilling of up to 30 subsea wells and construction of two offshore production platforms with 16 billion cubic metres per year of gas capacity and 100,000 barrels of condensate capacity.

Production will be routed via 500km of subsea pipelines, which are yet to be built. The South Caucasus pipeline will be extended by 400km to a capacity of over 20 billion cubic metres per year. The Sangachal terminal will also be expanded.

Engineering studies on the full field development are being carried out. First gas from stage 2 is expected in 2016.

Production

Gas and condensate production started in December 2006. In 2007, the field produced a total of about 110bn cubic feet of gas and 0.8m tonnes of condensate. In 2010, the production stood at about 243.6bn cubic feet of gas and 1.9m tonnes of condensate.

As of mid-2008, daily Shah Deniz production stood at about 700m standard cubic feet of gas and about 40,000 barrels of condensate from four wells. Production will increase as new platform-drilled wells are brought on stream later in 2008 and during 2009. Plateau production from stage one will be 317.8bn cubic feet of gas per year and 50,000 barrels of condensate per day.

Project information courtesy of www.offshore-technology.com

montrose
Customer: Talisman Sinopec / CB&I
Project: Montrose
Location: United Kingdom
Products: 14 x V-Cone Flow Meters / 7 x Oil in Water Analysers

The MonArb Area Redevelopment Project (MAR) or Montrose Area Redevelopment (MAR) plan comprises redevelopment of the Montrose, Arbroath, Brechin, Arkwright, Carnoustie and Wood fields, and development of two new fields Cayley and Shaw. The two main fields Montrose and Arbroath are located in blocks 22/17 and 22/18 about 209km east of Aberdeen.

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The project, which is being carried out by Talisman (51%) and Sinopec (49%), was approved by the UK Government in October 2012. The MAR project will extend the life expectancy of the existing six oilfields to 2030 to produce a further 100 million barrels of oil equivalent. First gas and oil from the Shaw and Cayley fields are expected in 2015.

The project is being carried out with a brown field allowance (BFA) of £1.6bn ($2.4bn) creating up to 2,000 jobs. A $285m contract for the subsea development works of the project has been awarded to Subsea 7.

Geology, discovery and location of the oilfields

Hydrocarbons and oil at Montrose and Arbroath are found in kimmeridge clay formation within the Palaeocene forties sandstone and in mudstones of the Sele Formation. Montrose was discovered in 1971 and began production in 1976, while Arbroath was discovered in 1969 and began production in 1991.

Cayley was discovered in 2007 by the well 22/17-3 which was drilled about 10km west of Montrose at water depths of 91m. The field will be developed through two production wells.

Shaw was discovered in 2009 by the well 22/22a which was drilled by Talisman in collaboration with Marubeni. The field is located about 17km north of Montrose and will be developed through three production wells and two water injectors. The wells will be ultimately tied to the new Montrose bridge-linked platform (BLP).

Project details of the MonArb area redevelopment

A bridge-linked platform will be constructed and attached to the redeveloped Montrose Alpha Platform, which was originally installed in 1976. The bridge-link will measure 71m in length and weigh 350t.

Project information courtesy of www.offshore-technology.com

in-amenas
Customer: Sonatrach BP, Statoil, Petrofac
Project: In Amenas
Location: Algeria
Products: Fire & Gas / Field Instrumentation Bulk Package (222 Items)

In Amenas is the largest wet gas development project in Algeria. The project includes the development of four primary gas fields in the Illizi Basin in south-eastern Algeria and the associated gas processing facility.

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The In Amenas Gas Project, located close to the Libyan border in the Sahara desert, around 1,300km away from the capital city Algiers, commenced production in 2006.

The gas project is owned and operated by a joint venture between Algeria’s state-owned oil company Sonatrach, UK-based multinational BP and Norway’s Statoil. BP and Statoil’s working interests in the project are 46% and 45.9% respectively.

In Amenas produces nine billion cubic metres of natural gas and 50,000 barrels of condensate per year. It accounts for the one tenth of Algeria’s gas output.

A compression project was launched at In Amenas in 2011, to maintain the plateau production. The project was scheduled to be completed in 2013. However, a terrorist attack on the In Amenas facility in the beginning of 2013 has significantly brought down the In Amenas production. The development projects planned for the gas production facility are also on hold due to security concerns.

The four primary gas fields

In Amenas Gas project comprises of the exploitation of four gas fields, namely Tiguentourine, Hassi Farida, Hassi Ouan Taredert and Hassi Ouan Abecheu in the Illizi Basin of the In Amenas region. The In Amenas fields cover an area of more than 2,750km². The initial natural gas reserves in these fields were estimated at 85 billion m³.

Development history of the Algerian gas project

Sonatrach signed a contract with US-based Amoco Corporation in 1998 to jointly develop the four In Amenas gas fields. BP took over Amoco Corporation in the same year and concluded a production-sharing contract (PSC) with Sonatrach for the In Amenas licence. In June 2003, BP entered into a farm-out agreement with Statoil, which bought 50% of BP’s interest in the In Amenas fields.

The $1.2bn first phase of the In Amenas Gas project focused on the development of the Tiguentourine gas field. ENAFOR, a subsidiary of Sonatas, was awarded a contract in 2002 to drill 12 development wells on the field.

The engineering, procurement and construction (EPC) contract worth $745m for the production and processing facilities of In Amenas was awarded in the same year to a joint venture between Japanese Gas Corporation and Kellogg, Brown and Root, a subsidiary of Halliburton.

GE Oil & Gas supplied the gas turbines and auxiliary equipments for the In Amenas gas processing plant under a $70m contract awarded in 2003. The In Amenas facility was brought on stream in June 2006.

The gas produced at In Amenas is marketed by Sonatrach. BP and Statoil are reimbursed with the condensate and liquefied petroleum gas output of the facility.

Gas production infrastructure at In Amenas

The gas gathering system at In Amenas comprises of ten inch flow lines connected to manifold station with each manifold tied to four to six wells.

A total of 100km of intra-field pipelines (ranging from ten inch to 24 inch in diameter) were constructed at the In Amenas facility by LEAD, a company based in Syria.

The In Amenas gas treatment plant has a capacity to process 30 million m³ of gas a day. The plant consists of three parallel trains for gas processing and condensate stabilisation. The treatment plant is equipped with CO2 removal, mercury removal, molecular sieve dehydration, LPG recovery, residue gas re-compression and power generation facilities.

The production facility is connected to the Sonatrach distribution system at Ohanet through three 90km long export pipelines. The diameter of the pipeline carrying dry gas is 36in and the pipes carrying condensate and LPG have a diameter of 12 inch.

In Amenas gas project expansion plan

A $213m contract was awarded to Japanese Gas Corporation in May 2011, to deliver a compression project at In Amenas by 2013. The compression project includes the construction of two train inlet compressions to the existing processing plant, new slug catcher facility, a permanent accommodation camp and utility buildings.

The expansion project aims at improving the recovery of wet gas at In Amenas that will help maintain its production capacity of 30 million m³ per day for next 12 years.

Petrofac was awarded a three year contract for multidiscipline consultancy, design and procurement services in January 2013, as part of the development programme to further boost up the hydrocarbon production at In Amenas.

In Amenas siege / terror attack

The In Amenas gas facility was attacked by Islamist terrorists on 16 January 2013. The workers at the facility, including 48 foreign nationals, were taken hostage by the militants as part of the attack. The gas facility was put under seize by the Algerian security forces for four days. In the process, 40 hostages, including five Statoil employees and four BP employees, were killed.

The processing facility was also partly damaged during the fight between the security forces and the terrorists.

The In Amenas gas facility was shut after the attack. BP and Statoil have withdrawn their employees from the facility until the security situation is thoroughly reviewed.

Sonatrach started limited production from the facility in February 2013, by restarting just one production train on behalf of the joint venture partners. The other two production trains of the facility were damaged during the terror attack.

In the meantime, the expansion projects planned for the In Amenas gas facility have been kept on hold until strict security measures are established by the Algerian state. Any new production from the facility is unlikely until 2014.

Project information courtesy of www.hydrocarbons-technology.com

stanlow-refinery
Customer: Essar Energy
Project: Stanlow Refinery
Location: United Kingdom
Products: 30 x Magnetic Level Gauges

Essar Energy completed the US$350 million acquisition of Stanlow refinery, UK, on July 31, 2011. Stanlow has a nameplate capacity of 296,000 barrels per day but is currently operating at about 70% of this level. The Stanlow Refinery lies near to Liverpool, north west England, on the south bank of Manchester ship canal and is UK’s second biggest oil refinery. It supplies approximately 15% of the country’s transport fuel requirements. Refined fuels from Stanlow are distributed across the UK, mainly by road and pipeline.

bs171-booster-station
Customer: Kuwait Oil Company / Saipem
Project: BS-171 Booster Station
Location: Kuwait
Products: 90 x Radar & Guided Wave Radar Level Transmitters

Kuwait Oil Company (KOC) is building a new gas booster station (BS-171) in west Kuwait. The booster station will comprise three new identical two stage compressor trains high and low-pressure (LP & HP), including gas & condensate dehydration trains. Each train shall be capable of processing 125 million Cubic Feet a Day (CF/D) of sour gas. The booster station feeding gas will come from the existing gathering centers 17, 27, 28 and the new gathering centre 16 so the BS-171 contract will also cover an extensive pipeline network from these units to the booster station.

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The project scope consists of detailed design, procurement, supply, construction, pre-commissioning and commissioning of the following:

1- A new BS-171 facility and associated access roads in West Kuwait.
2- Interconnecting pipelines between BS-171 and the feeder GCs (GC-17, 27, 28 and GC-16 (New) and also between BS-171 and Tie-in Points TP1/TP2.
3- Installation of new equipment and tie-ins at GC-17/27/28 and also GC-16 (New).
4- A new Intermediate Slug Catcher (ISC) facility and associated access roads in South East Kuwait.

The facilities shall be built with processing and exporting facilities for a maximum of 234 MMSCFD of dry and conditioned export gas and 69,000 Act BPD of treated condensate to Mina Al Ahmadi Acid Gas Removal Plant (AGRP).
KOC aims to ensure that 500 MBOPD crude production level and nominal 250 MMSCFD gas export from West Kuwait facilities is sustainable while keeping flaring below 1% per annum.

Project information courtesy of www.gulfoilandgas.com

eldfisk
Customer: Conoco Phillips / Emerson
Project: Eldfisk 2/7S
Location: Norway
Products: 5 x V-Cone Flow Meters

The new Eldfisk 2/7S will be equipped with a new integrated platform with wellhead and processing facilities, 40 new wells, 154 cabins and will be connected to 2/7 E via a bridge.

It will also feature a new local equipment room, pipelines, new electricity cable and umbilical, as well as upgraded facilities and infrastructure.

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Located in the Greater Ekofisk Area in the Norwegian sector of the North Sea, the Eldfisk field commenced production in 1979 and currently produces from 30 wells.

ConocoPhillips expects that Eldfisk II will increase the recovery rate from the Eldfisk field from 22% to 28.5%.

Project information courtesy of www.offshore-technology.com

bradwell
Customer: Magnox / Costain
Project: Bradwell Decommissioning
Location: United Kingdom
Products: Bulk Instrument Package (175 items)

Bradwell, located in the South East of England, one and a half miles from the Essex coastline, is a twin Magnox reactor, now undergoing decommissioning following shutdown in March 2002 after 40 years of operation. The station generated nearly 60 TWh of electricity during its operational life and on a typical day could supply enough electricity to meet the needs of three towns the size of Chelmsford, Colchester and Southend put together.

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The removal of fuel, which accounted for 99 per cent of the radioactive hazard on site, was completed in 2006. Since then the focus has been on further hazard reduction and preparation of the site for its care and maintenance phase.

Accelerated decommissioning

Bradwell is one of two Magnox sites, alongside Trawsfynydd, which is following an accelerated decommissioning programme. It is due to become the first Magnox site to reach its care and maintenance phase in 2015. The approach, which will see care and maintenance achieved 12 years earlier than planned, is designed to gather experience that will help to safely reduce the cost of decommissioning the other Magnox sites – a process known as lead and learn.

Information courtesy of www.magnoxsites.co.uk

clair
Customer: BP / Wood Group PSN
Project: Clair
Location: United Kingdom
Products: V-Cone Flow Meters

The Clair field is the largest discovered, but not yet producing, hydrocarbon resource on the UKCS. The field is located 75 km West of Shetland in water depths of up to 150m and extends over an area of some 220km2.

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It is divided into 9 fault-bounded segments, which have a common free water level and a maximum oil column of some 600m. A gas cap is present in the structurally elevated Ridge segments.
The reservoir is made up of fractured sandstones of Devonian to Carboniferous age with current interpretations suggesting a total volume of oil in place of excess of 410 million metric tonnes of 22 – 23 API oil.
However, there is significant uncertainty both in terms of reserves and the ability to commercially produce the highly fractured reservoir.

The field comprises an extensively layered and fractured sandstone reservoir with significant open fractures and variable matrix quality.

Field Development

Development of the Clair reservoir will be a ‘phased development’. The first phase – ‘Clair Phase 1 Development’ – will target the Core, Graben and Horst segments of the southern area of the reservoir. This first development phase is laterally extensive and relatively shallow, requiring high step-out extended reach wells for maximum drainage from single well access points.
Phase 1 of the Clair development has recoverable reserves of around 250 million barrels of oil. Plateau production is expected to be around 60 thousand barrels of oil a day and 20 million cubic feet of gas per day. Further development phases will be dependent on the performance and success of the Phase 1 Development.

Information courtesy of www.bp.com