Upstream major projects

A high-quality and material portfolio of projects, underpinning growth to 2020 and beyond

By 2020, we anticipate that we will add 800 mboed of new production net to BP from our current suite of major projects which have passed through the final investment decision and are complete or well under construction. You can find more information on our projects in the construction and design stages in the map below.

Looking beyond 2020, we have a deep hopper of projects that are currently under appraisal. Our focus here is to ensure we maximise the business opportunity and select the optimum project concept before we move it forward into design. We do not expect to progress all of the projects - only the best.

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Angelin

Location
Trinidad
Operator
BP
Partners
100% owned by BP Trinidad and Tobago which is owned by BP (70%) and Repsol (30%)
Project type
LNG
Start-up
2019
Peak annual average production, gross
~65 mboed
Peak annual average production, net
~65 mboed

The Angelin project features the construction of a new platform 40 miles off the southeast coast of Trinidad in water-depth of approximately 215 feet. The development will include four wells and will have a production capacity of approximately 600 million standard cubic feet of gas per day. Gas from Angelin will flow to the Serrette platform hub via a new 13-mile pipeline.

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Atoll Phase 1

Location
Egypt
Operator
Pharaonic Petroleum Company (PhPC)
Partners
BP (100%)
Project type
Conventional gas
Start-up
2018
Peak annual average production, gross
~55 mboed
Peak annual average production, net
~30 mboed

The Atoll field contains an estimated 1.5 trillion cubic feet of gas and 31 million barrels of condensates. The Atoll Phase 1 project is an early production scheme (EPS) involving the recompletion of an existing exploration well as a producing well, the drilling of two additional wells and the installation of the necessary tie-ins and facilities required to produce from the field. Onshore processing will be handled by the existing West Harbour gas processing facilities. Success of the Atoll Phase 1 project could lead to further investment in the Atoll Phase Two full field development.

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Clair Ridge

Location
UK – North Sea
Operator
BP
Partners
BP (28.6%), Shell (28%), Conoco Phillips (24%), Chevron (19.4%)
Project type
Conventional oil
Start-up
2018
Peak annual average production, gross
~110 mboed
Peak annual average production, net
~30 mboed

The Clair Ridge Project develops new resources from the giant Clair Field which is located approximately 40 miles west of Shetland and extends over an area of 85 square miles, in water depths of approximately 460 feet. The project scope includes provision of new production, accommodation and drilling facilities on two bridge-linked platforms. In addition, the project will deliver new development wells and brownfield modifications to the Clair Phase 1 and the Sullom Voe terminal. New subsea pipelines will be tied into the existing export systems. A LoSal water injection unit will be provided to enhance oil recovery. Production capacity is expected to be 120,000 barrels per day, with provision for future subsea tiebacks.

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Constellation

Location
US – Gulf of Mexico
Operator
Anadarko
Partners
Anadarko (33.33%), BP (66.67%)
Project type
Deepwater oil
Start-up
2018
Peak annual average production, gross
~15 mboed
Peak annual average production, net
~10 mboed

Constellation is a Pliocene discovery located in central Green Canyon. Production from Constellation will be tied-back to Anadarko’s Constitution spar in approximately 5,000 feet of water.

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Culzean

Location
UK – North Sea
Operator
Maersk
Partners
Maersk (50%), BP (32%), JX Nippon (18%)
Project type
High pressure gas
Start-up
2019
Peak annual average production, gross
~100 mboed
Peak annual average production, net
~30 mboed

Culzean is a 1.2 Tcf High Pressure High Temperature (HPHT) lean gas condensate field located approximately 140 miles east of Aberdeen in Block 22/25a of the Central North Sea in water depths of 300 feet. The project scope includes a stand-alone three bridge-linked platform development with dry gas export via Central Area Transmission System (CATS) and liquids export via a new-build Floating Storage and Offloading tanker (FSO). A new Heavy Duty Jack Up (HDJU) rig, the Maersk Highlander, has commenced drilling of the six production wells and one produced water re-injection well.

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Juniper

Location
Trinidad
Operator
BP
Partners
100% owned by BP Trinidad and Tobago which is owned by BP (70%) and Repsol (30%)
Project type
LNG
Start-up
2017
Peak annual average production, gross
~95 mboed
Peak annual average production, net
~95 mboed

The Juniper project includes the construction of a normally unmanned platform, together with corresponding subsea infrastructure. The Juniper facility will produce gas from the Corallita and Lantana fields located 50 miles off the south-east coast of Trinidad, in water depth of approximately 360 feet. The development includes five subsea wells and has a production capacity of approximately 590 million standard cubic feet per day. Gas from Juniper will flow to the Mahogany B hub via a new six-mile flowline.

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KGD6 R-Series

Location
India
Operator
Reliance
Partners
Reliance (60%), BP (30%), Niko (10%)
Project type
Dry gas
Start-up
2020
Peak annual average production, gross
~90 mboed
Peak annual average production, net
~25 mboed

The R-Series project is the first of three projects in Block KGD6 off the east coast of India. The gas field is located approximately 45 miles offshore in water-depths of more than 6,500 feet. The R-Series project will be developed as a six well subsea tieback to the existing control and riser platform off Block KGD6. The project is expected to produce up to 425 million standard cubic feet of gas a day.

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 Khazzan Phase 1

Location
Oman
Operator
BP
Partners
BP (60%), Oman Oil (40%)
Project type
Tight gas
Start-up
2017
Peak annual average production, gross
~200 mboed
Peak annual average production, net
~115 mboed

This first phase of the onshore Khazzan field development plan involves drilling approximately 200 wells and constructing a two-train central processing facility. The project is expected to develop circa seven trillion standard cubic feet of gas and deliver plateau production of one billion standard cubic feet of gas per day and 25,000 barrels per day of gas condensate.

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Mad Dog Phase 2 

Location
US - Gulf of Mexico
Operator
BP
Partners
BP (60.5%), BHP Billiton (23.9%), Chevron (15.6%)
Project type
Deepwater oil
Start-up
2021
Peak annual average production, gross
~120 mboed
Peak annual average production, net
~65 mboed

The Mad Dog Phase 2 project includes a new semi-submersible floating production platform with the capacity to produce up to 140,000 gross barrels of crude oil per day from 14 production wells and inject up to 140,000 barrels of water per day using a LoSal system to enhance oil recovery. The new platform will be moored approximately six miles southwest of the existing Mad Dog platform, which is located in 4,500 feet of water about 190 miles south of New Orleans.

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Persephone

Location
Australia
Operator
Woodside
Partners
BP (16.67%), BHP, Chevron, Shell, Woodside and Mitsubishi-Mitsui (16.67% each)
Project type
LNG
Start-up
2017
Peak annual average production, gross
~50 mboed
Peak annual average production, net
~8 mboed

The Persephone gas field is located 85 miles north-west of Karratha, Western Australia, in a water depth of approximately 415 feet. The development concept is a two well subsea tieback to the existing North Rankin complex.

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Quad 204

Location
UK - North Sea
Operator
BP
Partners
BP (36.3%), Shell (54.0%), Siccar Point (9.7%)
Project type
Conventional oil
Start-up
Started May 2017
Peak annual average production, gross
~125 mboed
Peak annual average production, net
~45 mboed

The Quad 204 project provides a new Floating Production, Storage and Offloading (FPSO) vessel, installed to the west of Shetland in water depths of approximately 1,300 feet, to extend and expand the recovery of oil from the Schiehallion field through to 2035. It includes an extension of the existing subsea system with 15 new flow lines, 21 new risers, 2 new dynamic controls umbilicals and 14 new wells. The project is designed to produce 130,000 barrels a day of oil and 220 million standard cubic feet of gas. The gas will be primarily used for artificial lift.

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Shah Deniz Stage 2

Location
Azerbaijan
Operator
BP
Partners
BP (28.8%), SOCAR (16.7%), PETRONAS (15.5%), Lukoil (10%), NICO (10%), TPAO (19%)
Project type
Conventional gas
Start-up
2018
Peak annual average production, gross
~325 mboed
Peak annual average production, net
~110 mboed

The Shah Deniz Stage 2 project entails several elements. These include drilling and completion of 26 subsea wells and construction of two bridge-linked offshore platforms. The subsea wells are grouped in five clusters, three of which are in deep water, and all five clusters will produce via flowlines to the platform hub. Hydrocarbons will be exported to shore via two 32” diameter gas export lines and a 16” condensate line. Onshore, new processing and compression facilities are being installed at the Sangachal terminal in Azerbaijan. An expansion of the existing South Caucasus Pipeline System and two new pipelines, the Trans Anatolian Gas Pipeline (TANAP, BP Share 12%) and the Trans Adriatic Pipeline (TAP, BP share 20%) will carry gas almost 2,200 miles - delivering energy to Georgia, Turkey, Bulgaria and Italy. Shah Deniz 2 plans to develop an additional 565 billion standard cubic feet per year of gas (at plateau) and has a designed condensate rate of 105,000 barrels per day.

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Tangguh Expansion

Location
Indonesia
Operator
BP
Partners
BP (40.22%) MI Berau B.V. (16.30%), CNOOC Muturi Ltd (13.90%), Nippon Oil Exploration (Berau) Ltd (12.23%), KG Berau Petroleum Ltd (8.60%), KG Wiriagar Overseas Ltd (1.40%), Indonesia Natural Gas Resources Muturi Inc. (7.35%)
Project type
LNG
Start-up
2020
Peak annual average production, gross
~125 mboed
Peak annual average production, net
~40 mboed

The Tangguh Expansion project, located in the Papua Barat Province of Indonesia, will add a third LNG process train (Train 3) and 3.8 million tons per annum (mtpa) of production capacity to the existing facility, bringing total plant capacity to 11.4 mtpa. The project also includes two offshore platforms, 13 new production wells, an expanded LNG loading facility, and supporting infrastructure.

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Trinidad Onshore Compression

Location
Trinidad
Operator
Atlantic LNG
Partners
100% owned by BP Trinidad and Tobago which is owned by BP (70%) and Repsol (30%)
Project type
LNG
Start-up
Started April 2017
Peak annual average production, gross
~35 mboed
Peak annual average production, net
~35 mboed

The Trinidad Onshore Compression project increases production from low-pressure wells in BP Trinidad and Tobago LLC (bpTT)’s existing acreage in the Columbus Basin using an additional inlet compressor at the Point Fortin Atlantic LNG plant. Additional upgrades will be made to bpTT’s upstream facilities, as well as those of third parties to accommodate operations of the compressor.

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Western Flank B

Location
Australia
Operator
Woodside
Partners
BP (16.67%), BHP, Chevron, Shell, Woodside and Mitsubishi-Mitsui (16.67% each)
Project type
LNG
Start-up
2019
Peak annual average production, gross
~75 mboed
Peak annual average production, net
~10 mboed

The Western Flank B project will develop the Keast, Dockrell, Sculptor-Rankin, Lady Nora and Pemberton fields via an eight subsea well tie-back to the Goodwyn A platform.

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West Nile Delta - Taurus / Libra

Location
Egypt
Operator
BP
Partners
BP (82.75%), DEA Deutsche Erdoel AG (17.25%)
Project type
Conventional gas
Start-up
Started March 2017
Peak annual average production, gross
~105 mboed
Peak annual average production, net
~80 mboed

West Nile Delta includes two projects expected to develop 5 trillion cubic feet of gas resources and 55 million barrels of condensates from two BP-operated offshore concession blocks, North Alexandria and West Mediterranean Deepwater. The Taurus / Libra project comprises a nine well subsea development tied-in offshore that produces through BG’s Burullus facilities.

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West Nile Delta – Giza / Fayoum / Raven

Location
Egypt
Operator
BP
Partners
BP (82.75%), DEA Deutsche Erdoel AG (17.25%)
Project type
Conventional gas
Start-up
2019
Peak annual average production, gross
~185 mboed
Peak annual average production, net
~155 mboed

West Nile Delta includes two projects expected to develop 5 trillion cubic feet of gas resources and 55 million barrels of condensates from two BP-operated offshore concession blocks, North Alexandria and West Mediterranean Deepwater. The Giza / Fayoum / Raven project includes 12 wells and will be developed as deepwater long distance tie backs to the shore, where the existing Rosetta plant will be modified for Giza / Fayoum and integrated with a new adjacent onshore plant for Raven

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Zohr

Location
Egypt
Operator
Eni
Partners
BP (10%), Eni (90%)
Project type
Dry gas
Start-up
2017
Peak annual average production, gross
~440 mboed
Peak annual average production, net
~40 mboed

The Zohr field is located in the Mediterranean Sea in the Shorouk concession, approximately 120 miles north of Port Said in waters approximately 4,900 feet deep. Eni has estimated total gas resources in place to be approximately 30 trillion cubic feet of gas. The Zohr project is a 25 well deepwater long distance tieback that will pipe gas to be processed through a new seven-train onshore plant.

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