In 2013 we spent about $772 million in operating expenditure and $2,833 million in capital expenditure on ACG activities. In 2014 we expect to spend $1,052 million in operating expenditure and $2,068 million in capital expenditure on ACG activities.
During 2013 ACG produced on average 655,370 barrels per day (b/d) (over 239 million barrels or over 32.2 million tonnes in total) from the Chirag, Central Azeri, West Azeri, East Azeri and Deepwater Gunashli platforms.
At the end of the year, a total of 81 oil wells were producing, while 37 wells were used for injection in the ACG field, as follows:
Chirag produced on average 69,670 b/d and had 18 wells operating (13 oil producers and 5 water injectors).
Central Azeri (CA) produced on average 151,760 b/d and had 24 wells operating (17 oil producebrs, 1 water injector and 6 gas injectors).
West Azeri (WA) produced on average 188,160 b/d and had 26 wells operating (20 oil producers and 6 water injectors).
East Azeri (EA) produced on average 106,700 b/d and had 20 wells operating (15 oil producers and 5 water injectors).
Deepwater Gunashli (DWG) produced on average 139,080 b/d and had 30 wells operating (16 oil producers and 14 water injectors).
In 2013, BP as operator of the ACG field continued to deliver associated gas from the DWG platform via the 28” gas subsea pipeline directly to the Sangachal terminal and from there into Azerigas’ national grid system for domestic use.
Gas from the three Azeri platforms - CA, WA and EA – continued to be sent via in-field subsea gas pipelines to the compression and water injection platform on CA from where it was partly re-injected to maintain pressure in the reservoir and partly delivered to the Sangachal terminal via the same 28” subsea pipeline for further hand over to the national grid system. Gas injection activities currently continue from six wells on CA.
Some of the associated gas produced from the Chirag platform was sent to the SOCAR compression station at the Oil Rocks via the existing 16” subsea gas pipeline. BP continued to work closely with SOCAR to minimise flaring on Chirag and maximise recovery of associated gas for delivery to SOCAR. In support of this effort BP completed upgrades to the flash gas compressor and successfully re-started the unit during the third quarter of 2013.
By the end of 2013, ACG associated gas flaring was 2.6%. This represents 45% reduction from 2012. As result of further improvement measures ACG associated gas utilization rate has reached 97.4% which is in line with the best European standards. BP as operator of ACG will continue its efforts to minimize associated gas flaring while maintaining safe operations.
In 2013, we delivered around 6 million cubic metres (212 million standard cubic feet) per day of ACG associated gas to SOCAR (2.19 billion cubic metres or 77.4 billion cubic feet in total).
Drilling and completion activity
In 2013, ACG delivered 12 oil producer wells, one gas injector and three water injector wells. In addition, one data acquisition well was successfully delivered.
Chirag - The A16w producer well drilling was completed and handed over to production in April 2013. This was followed by intervention activities on A09 well and then we started drilling operations on A14u side-track oil producer in May. This well was completed on 31 August followed by intervention works which were completed on A03, A20 and A10 wells. Re-completion operations were conducted on A10 well followed by rig maintenance. Drilling of another producer well - A06x started at the end of December with completion scheduled for the first quarter of 2014.
Central Azeri - In January 2013, intervention activities were conducted on the B18y and B14 wells. We then drilled B23z producer well and delivered it in April. This was followed by further intervention activities on B10 and B05 wells.
In early May, we commenced drilling the new gas injector well B26 and delivered it in September. We then conducted intervention operations on B02, B20 and B26 wells. In the meantime critical maintenance work was also conducted on CA and three conductors were installed on slots 35, 36 and 40. This was followed by the drilling of another new oil producer well - B27 which was delivered in December. In December we also started drilling the new oil producer well – B28 with delivery scheduled for the early third quarter.
West Azeri - The C27 oil producer well was delivered and handed over to production in March. This was followed by intervention operations on wells C06 and C03. In early May, we commenced drilling a new oil producer well - C30, and this well was delivered in July followed by an intervention campaign and rig maintenance. The drilling of another new oil producer well - C29 commenced in September and was completed in November. This was followed by re-completion of C25 which was delivered in December. In December we also commenced drilling another new oil producer well - C28 with delivery scheduled for the early second quarter.
East Azeri - In January, we completed intervention activity on well D07. This was followed by drilling the oil producer well D22 which was completed and handed over to production in April.
Following this, well intervention activities commenced on well D05 to perform sand shut off operations. The intervention campaign continued through mid-May including well work on D03 and D08, and critical inspection operations. In May, we started a new water injector well - D23, which we delivered in November. This was followed by D13 gas lift retrofit and D01 intervention work. In late December we started D03 intervention activity which was completed in January 2014.
Deepwater Gunashli (DWG) - Intervention activities on well E01 were completed in January. Following this, we started drilling a new oil producer well - E17, and it was delivered in May followed by a five-yearly rig maintenance programme.
Intervention activities on E11 was conducted through June and July followed by the drilling of the producer well E18. This well was delivered in December followed by intervention activities on two wells - E09 and E02y. We then conducted re-completion works on well E02y which were finished in January.
In 2013, the Dada Gorgud drilling rig delivered two subsea water injector wells - H06 and H05, followed by rig maintenance activities and installation of manifold piles. In addition, in early May we started the H07 pilot data acquisition well, which was completed at the end of July. In August we commenced drilling well GCA07 and after completion of the planned data acquisition programme the well was plugged and abandoned in December. We then started drilling the water injector well H07z which is currently ongoing with delivery expected during the first quarter.
Oil and gas from ACG and Shah Deniz continued to flow via subsea pipelines to the Sangachal terminal.
The daily capacity of the terminal’s processing systems is currently 1.2 million barrels of oil and around 970 million standard cubic feet or 27.4 million standard cubic metres of Shah Deniz gas, while overall processing and export capacity for gas, including ACG associated gas is about 41.5 million standard cubic metres per day.
Gas is exported via the South Caucasus Pipeline (SCP) and via a SOCAR gas pipeline connecting the terminal’s gas processing facilities and Azerigas’s national grid system.
During 2013, the Sangachal terminal exported about 286.2 million barrels of oil. This included 248.7 million barrels through Baku-Tbilisi-Ceyhan (BTC), 29.9 million barrels through the Western Route Export Pipeline (WREP), 5.7 million barrels by rail and 1.9 million barrels via a condensate export line.
On average, 26.6 million standard cubic metres (about 939 million standard cubic feet) of Shah Deniz gas was exported from the terminal daily in 2013.
Chirag Oil Project (COP)
In 2013, significant progress was made in safely progressing COP activities.
In April, the jacket for the West Chirag platform sailed away from the Heydar Aliyev Baku Deepwater Jackets Factory and was safely installed on the pre-installed template in its permanent location. The jacket transportation, launch and installation activities took 45 days to complete.
The topsides unit fabrication at the ATA yard was completed during the third quarter. The topsides unit sailed away for offshore installation on 12 September and was safely installed onto the jacket on 14 September followed by offshore hook-up and commissioning activities which continued through January 2014.
On 28 January 2014, First Oil was achieved from the West Chirag platform and this completed the Chirag Oil Project (COP) sanctioned in 2010.
West Chirag production began from one of the pre-drilled wells - J05. Production will increase through 2014 as the other pre-drilled wells are brought on line.
Note: On 28 March 2013, ONGC Videsh Limited (OVL) completed the acquisition of the respective interest of Hess (BTC) Limited, and Hess (BTC) Limited has since been renamed to ONGC (BTC) Limited.
During 2013, BTC spent over $75 million in capital expenditures. In 2014, BTC capital expenditures are expected to be about $119 million.
BTC’s throughput capacity is currently 1.2 million b/d.
Since 4 June 2006 up to the end of 2013, 2,390 tankers were loaded at Ceyhan with a total of 1,835 million barrels (245.4 million tonnes) of crude oil transported via BTC and sent to world markets.
In 2013, BTC exported about 247.2 million barrels (33 million tonnes) of crude oil loaded on 329 tankers at Ceyhan.
The BTC pipeline currently carries mainly ACG oil and Shah Deniz condensate from Azerbaijan. In addition, crude oil from Turkmenistan continues to be transported via BTC. Starting October 2013, we have resumed transportation of some volumes of Tengiz crude oil through the BTC pipeline.
In 2013, the Shah Deniz field continued reliable deliveries of gas to markets in Azerbaijan (to SOCAR), Georgia (to GOGC) and Turkey (to BOTAS and the BTC company).
Last year the field produced about 9.8 billion cubic metres (about 345.5 billion cubic feet) of gas and 2.48 million tonnes (19.6 million barrels) of condensate or about 26.8 million cubic metres of gas per day (946 million standard cubic feet per day) and 53,740 b/d of condensate.
Since the start of Shah Deniz production in late 2006 till the end of 2013, about 47.3 billion standard cubic metres (1,671 billion standard cubic feet) of Shah Deniz gas, and about 99.5 million barrels (12.6 million tonnes) of Shah Deniz condensate has been produced.
As a result of debottlenecking of existing facilities, Shah Deniz Stage 1 capacity has been increased to around 970 million standard cubic feet per day and approximately 55,000 barrels per day of condensate. The Shah Deniz partners have recently agreed terms with SOCAR for further expansion of production capacity to around 1,040 million standard cubic feet per day by the end of 2014.
Shah Deniz Stage 1
In 2013, Shah Deniz continued drilling activities on well SDA-03Y. This well is currently in the completion phase with delivery expected in 1Q 2014.
Shah Deniz Stage 2
In September, the Istiglal rig completed drilling activities on well SDC-02, in the north of the field. Following this, drilling commenced on well SDC-03 with expected completion later in 2014.
The Heydar Aliyev rig completed drilling activities on well SDX-07Ay in September. This was followed by a rig modification and certification programme. Drilling activities are planned to resume on well SDD-02 in the west of the field with well completion expected later in 2014.
Shah Deniz Stage 2 project
Shah Deniz (SD) Stage 2 is a giant project that will bring gas from Azerbaijan to Europe and Turkey. This will increase gas supply and energy security to European markets through the opening of a new Southern Gas Corridor. It is one of the largest gas development projects anywhere in the world.
The total cost of the Shah Deniz Stage 2 project, including the South Caucasus Pipeline (SCP) expansion, will be around $28bn. 16 billion cubic metres per year (bcma) of gas produced from the giant Shah Deniz field will be carried some 3,500 kilometres to provide energy for millions of consumers in Georgia, Turkey, Greece, Bulgaria and Italy. First gas is targeted for late 2018, with sales to Georgia and Turkey; first deliveries to Europe will follow approximately a year later.
The Stage 2 development of the Shah Deniz field, which lies some 70 kilometres offshore in the Caspian, includes two new bridge-linked production platforms; 26 subsea wells drilled with two semi-submersible rigs and 500km of subsea pipelines built at up to 550m of water depth and expansion of the Sangachal terminal.
On 17 December 2013 the Shah Deniz consortium approved the final investment decision for the Stage 2 development. This decision has triggered plans to expand the South Caucasus Pipeline through Azerbaijan and Georgia by 16 bcma (comprising a new 48’’ diameter pipeline in Azerbaijan and two compression stations in Georgia), to construct the Trans Anatolian Gas Pipeline (TANAP) across Turkey and to construct the Trans Adriatic Pipeline (TAP) across Greece, Albania and into Italy. Together these projects, as well as gas transmission infrastructure to Bulgaria, will create a new Southern Gas Corridor to Europe.
The Stage 2 project will provide for delivery of some 10 bcma of Shah Deniz gas for 25 years to customers in Italy, Greece and Bulgaria. In addition, some 6 bcma of Shah Deniz Stage 2 gas will be delivered to consumers in Turkey. All gas sales and transportation contracts will be managed by the Azerbaijan Gas Supply Company.
Following the final investment decision the consortium announced a number of contract awards including for the construction and commissioning support of the Shah Deniz Stage 2 onshore terminal facility at Sangachal near Baku; for the fabrication, load out and offshore hook-up and commissioning of the topsides units of the two Stage 2 platforms; and for provision of detailed engineering, project management and procurement support services for the offshore and onshore facilities.
In 2014, further contracts will be awarded. These include subsea pipeline installation and marine transportation and installation. Work will commence at the fabrication yards for jackets and decks, as well as at the onshore terminal construction sites. Drilling will continue using the Istiglal and Heydar Aliyev rigs.
During 2013, SCP spent around $50 million in operating expenditure and $250 million in capital expenditure. In 2014, operating expenditure is expected to be $50 million. As a result of the ramp-up in the SCP expansion, capital expenditure will increase to $1,250 million.
The pipeline has been operational since late 2006, transporting gas to Azerbaijan and Georgia, and starting July 2007 to Turkey from SD Stage 1.
In 2013, SCP’s daily average throughput was about 13.4 million cubic metres (about 473 million cubic feet) of gas or 81,600 barrels of oil equivalent per day.
The SCP has a dual operatorship with BP as the technical operator being responsible for construction and operation of the SCP facilities and Statoil, as commercial operator, is responsible for SCP's business administration.
SCP expansion project
A Final Investment Decision on the SCP expansion project was taken on 17 December 2013, coincident with Shah Deniz Stage 2. During 2014 it is planned to award a series of contracts including the early works and pipeline facilities as well as for pipeline construction in Azerbaijan. The first shipment of line pipe is expected to arrive in Azerbaijan later this year.
Since early 2012 when the Gilavar seismic vessel completed the planned 3D seismic acquisition on the Shafag-Asiman structure, the first 3D seismic ever conducted on the contract area, we have been processing the acquired data. This processing is believed to be the largest 3D survey ever processed in-country. Following completion of this phase of the 3D seismic acquisition programme, some 18 months will be required for data interpretation and another year for planning of the first exploration well.
The Shafag-Asiman production sharing agreement (PSA) between BP and SOCAR on joint exploration and development of the Shafag-Asiman structure in the Azerbaijan sector of the Caspian Sea was signed in Baku in October 2010.
The block lies some 125 kilometres (78 miles) to the South-East of Baku. It covers an area of some 1,100 square kilometres and has never been explored before. It is located in a deepwater section of about 650-800 metres with reservoir depth of about 7,000 metres.
BP currently employs directly 2,835 Azerbaijani nationals. In total, 85% of BP’s permanent professionals in Azerbaijan are nationals and many of them are in very senior leadership positions.
In 2013, BP continued to extensively use all existing tools to attract the best local talent both within Azerbaijan and outside. As a result during 2013, BP in AGT newly recruited 474 hires, of them 367 Azerbaijani nationals, including 101 technicians, 57 experienced hires, 85 Challengers, 80 petro-technical resource entry programme - PREP trainees and in addition 44 interns.
The Caspian Technicians Training Centre (CTTC) at Sangachal continued training national technicians effectively. Over the past ten years of its existence the facility has trained over 900 national technicians for BP-operated facilities.
In September BP celebrated the first successful graduation of its world-class petro-technical resource entry programme (PREP) and announced that it had hired 88 graduates from various national and international universities for PREP’s second year. The new trainees were selected from among approximately 3,000 applicants. PREP is a multi-million dollar learning programme designed for national petro-technical graduates and is aimed at supporting capability development of young engineers joining BP.
In addition, BP has developed a nationalization plan for the years 2014–18 with a target to reach 90% professional staff nationalization rate by the end of 2018. This envisages nationalizing some of the professional roles that are currently occupied by the expatriate staff. Non-professional staff is already 100% nationalized. The nationalization agenda also includes further optimization of BP’s learning and development programmes, close participation in the public and private sector initiatives in order to further improve the local talent market and enhancing the rigorous internal performance management process. This plan was agreed with SOCAR resulting in the signing in November 2013 of a protocol on cooperation in the area of nationalization. In addition, BP signed two other documents with SOCAR in support of this plan:
Success of our projects in the Caspian, in part, depends on our ability to create tangible benefits from our presence for the people of the countries where we operate. To achieve this, we continue to carry out major sustainable development initiatives which include educational programmes, building skills and capabilities in local communities, improving access to social infrastructure in communities, supporting local enterprises through provision of access to finance and training, as well as technical assistance to public institutions.
In 2013, BP and co-venturers spent $2.7 million in Azerbaijan alone on such sustainable development projects.
BP and its co-venturers will continue their sustainable development initiatives to support local enterprise development and capacity-building throughout Azerbaijan to assist the country in strengthening its economy.
Some examples of such initiatives are:
Further information: Tamam Bayatly at BP’s Press Office in Baku.
Telephone: (+994 12) 599 45 57