Awarded Orders

The Flyndre field straddles three Blocks 30/13c and 30/14 in the UK sector of the North Sea and 1/5a in the Norwegian sector. The Cawdor field lies across two blocks, 30/13c and 30/14 both of which are in the UK sector.

The Flyndre field was discovered in 1974 and straddles the UK/Norway median line. Cawdor was discovered in 2008. The fields will be co-developed as a subsea tie-back to the Talisman Sinopec Energy UK Limited operated Clyde platform. Flyndre will be developed with a single production well. The Cawdor field will be developed initially with a single production well, with potential development of two further wells based on field performance. As development operator, Maersk Oil UK Limited holds a 59.966% interest in Flyndre and a 60.6% interest in Cawdor.

The Flyndre well is expected to peak at around 10,000 barrels of oil per day (gross production) with first oil expected in 2016, with Cawdor expected to peak at around 5,000 barrels per day (gross production) with production beginning in 2017. Total recoverable resources are expected to be approximately 30 MMboe for the initial development phase, with further upside depending on performance and further development phases. Maersk Oil UK Limited’s investment in the field developments is expected to be approximately £300million.

“Approval of this plan supports our long-term strategy for growth and our aim to double production in the UK North Sea by 2020. Together with approval of the Balloch field development in 2013, Flyndre/Cawdor underscores our momentum in progressing the development opportunities from our strong North Sea portfolio,” said Martin Rune Pedersen, Managing Director of Maersk Oil in the UK.

Both the fields will be co-developed as tiebacks to the existing Clyde platform, operated by Talisman, through a new common pipe-in-pipe pipeline system, including a 4.2km section running from Flyndre to Cawdor and a 20.46km section running from Cawdor to Clyde.

Oil from Flyndre and Cawdor fields will be exported through the Norpipe system. The gas from the fields will be exported via the UK SEGAL pipeline to the UK Fulmar platform.

A new 1,600t reception module will be established at the Clyde platform that will include a three-phase separator, water treatment and CO2 removal facilities. It will also include chemical injection and storage facilities.

The drive pumps are to be installed on a newly completed petrochemical complex at the Map Ta Phut Industrial Estate in Thailand’s Rayong province. It is the country’s largest industrial estate and the world’s eighth-largest petrochemical industrial hub. It was founded in 1990 and is managed by the Industrial Estate Authority of Thailand, a government agency under the Ministry of Industry. The site is operated by the Map Ta Phut Olefins Company Limited (MOC), a subsidiary of SCG Chemicals. The complex produces 900,000 tpa of ethylene and 800,000 tpa of propylene, which is used in downstream plants to produce 400,000 tpa of high density polyethylene (HDPE) and 400,000 tpa of polypropylene.

Work will include a complete overhaul of the engine, main propulsion and steering systems and replacement of six diesel generators. Accommodation on the ship will also be improved and the weapons systems overhauled.

At over 200m long and weighing 36,580 tonnes, the vessel is the largest in the Royal Fleet Auxiliary’s fleet and has just returned from a three year deployment during which she targeted pirates off the coast of Somalia. After its refit, the ship is due to return to service early next year, supplying the Navy’s warships with fuel, food, ammunition and any other stores anywhere in the world.

Project information courtesy of www.royalnavy.mod.uk

The current concept for Shah Deniz Stage 2 includes:

• Two new bridge-linked offshore platforms.
• 26 gas production wells which will be drilled with 2 semi-submersible rigs.
• 500 km of subsea pipelines will link the wells with the onshore terminal.
• Upgrade of the offshore construction vessels
• Expansion of the Sangachal terminal to accommodate the new gas processing and compression facilities.

Transportation of Shah Deniz gas from the Caspian Sea across 3,500 kilometres to Europe requires enhancement of some existing infrastructure and development of a chain of new pipelines.

• South Caucasus Pipeline (SCP) will be expanded with a new parallel pipeline across Azerbaijan and Georgia.
• In Turkey, Shah Deniz gas will be transported through a new Trans Anatolian Pipeline (TANAP).
• In Europe, Trans Adriatic Pipeline will be built to take gas through Greece and Albania to Italy.

First gas is targeted for late 2018, with supplies to Georgia and Turkey; gas deliveries to Europe are expected just over a year after first gas is produced offshore Azerbaijan.

Project information courtesy of www.bp.com

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

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

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