Azerbaijan has plenty of history to be rightly proud of. Having first produced oil from the offshore Neft Dashlary Field in 1949 and plenty more before that onshore (in 1901 it was producing 11 MM tons of oil), it has an impressive track record.
Oil drilling first took place in 1846 on the Bibi-Heybat Field a full 13 years before it started in Pennsylvania in the U.S. If you delve deeper into history, you can find references to hand-dug wells descending 35 m (115 ft) in the 15th century and its petroleum being noted by the 14th century Venetian traveler Marco Polo.
In the modern era it also has a large investment record: The total sunk to date in the oil and gas sector is put at $59 billion, and in the long term the spend between 2015 and 2025 is put at $110 billion on the upstream, midstream and downstream segments, according to the U.K. government body U.K. Trade & Investment (UKTI).
The country undoubtedly has a rich vein of opportunities in its waters, but the problem is that they mostly remain on the drawing board while the global offshore investment hiatus continues. As a result, it is suffering a very real production dip.
The latest official figures available show crude oil and condensate production fell to 27.9 MM tonnes in the first eight months of 2015 from 28.6 MM tonnes a year earlier, due largely to gradual declining output from BP’s Azeri, Chirag and Deepwater Gunashli (ACG) fields. The full-year oil production figure is believed to have hit 40.7 MM tonnes, with about 30.2 Bcm (1 Tcf) of gas. It continued a trend, with total oil and condensate production having fallen to 41.9 MM tonnes in 2014 from 43.1 MM tonnes in 2013.
The above trio of BP fields are the country’s production mainstay, flowing almost half of Azerbaijan’s oil. However, output from these fields fell to an average of 641,000 bbl/d in first-half 2015 from 656,000 bbl/d a year earlier, BP revealed last year.
Azerbaijan also suffered offshore tragedy in December last year, with a violent storm sweeping across the inland sea, which claimed the lives of 33 workers. These were mostly those onboard a lifeboat that broke up after falling from a Gunashli field platform operated by state oil company SOCAR that suffered a blaze after sustaining storm damage to production and pipeline equipment. It was the worst tragedy in the country’s history.
Safety measures on many of SOCAR’s older shallow-water platforms—many of which were built during the Soviet era—have been and still are being substantially reviewed for improvement.
Azerbaijan is tackling its concern over the sector’s gradual decline by pushing its western partners to develop some of the most promising discoveries and continue with ongoing brownfield enhancements, but the expectation of SOCAR is that total production will further dip to about 40 MM tonnes of oil and 30 Bcm of gas in 2016.
Showing how crucial BP’s ACG fields are, about 32 MM tonnes of that output will come from these fields. BP and its partners also have about 9 Bcm/year (328 Bcf/year) of production flowing from the first phase of the Shah Deniz gas and condensate field (in which $8.25 billion has been invested since 2003).
So where is Azerbaijan’s future oil and gas to come from, and where will the investment dollars be spent?
According to UKTI regional specialist Sue Whitbread, the ongoing second phase of BP’s Shah Deniz project is closest to fruition, planned to start producing by December 2018.
It entails the building and installation of two bridge-linked platforms connected to 26 subsea wells to be drilled by one or two semisubmersible rigs. It also will feature 360 km (224 miles) of subsea pipelines and 125 km (78 miles) of flowlines in water depths of up to 550 m (1,805 ft).
Once onstream, the deeper high-pressure reservoir that is the basis of Phase 2 is expected to flow about 17 Bcm/year (565 Bcf/year) of export gas to the Turkish and European markets. This will be via a planned expansion of the South Caucasus Pipeline to Turkey, bringing Shah Deniz’s total output to about 26 Bcm/year (918 Bcf/year).
Another high-profile project is Total’s proposed Absheron high-pressure gas development.
Not yet approved, this project’s proposed plan revolves around an unmanned Single Stage Separation Platform with a planned production plateau of 14 MMcm/d (500 MMcf/d). According to Whitbread in a recent presentation, the plan will see an initial four vertical high-rate subsea wells (up to 5.7 MMcm/d or 200 MMcf/d) with 10,000-psi christmas trees producing to the platform and on to an onshore treatment plant.
Each well is expected to take between 220 and 250 days to drill, although the total well costs are likely to be less than previously forecast (between $250 million and $350 million) as rig day rates continue to plunge. No rig has yet been contracted.
The fixed platform itself will have a topsides measuring 24 m by 24 m (79 ft by 79 ft) and a topsides gross dry weight of 4,500 tonnes, with power coming from shore.
A final investment decision is currently down for 2017, with capex estimates put at more than $6 billion. First gas could flow by late 2021 or early 2022.
BP also is planning a seismic survey this year in the shallower waters of the Absheron Peninsula, which it has under a joint production-sharing agreement with SOCAR, with analysis of the results due for completion by year-end 2016.
There are other projects in the medium to long term, according to Whitbread, including the possible development of a deep gas layer underlying BP’s ACG oil reservoir. Possible investment in that could total up to $12 billion and feature a new platform.
Beyond that, BP also is expected to eventually start the third development phase of Shah Deniz. This has previously been flagged as likely to need production-enhancing technologies such as subsea compression, and output is not expected before the late 2020s.
Another future project is the shallow-water Umid gas and condensate field, already producing since 2010 via two wells but which in the potential future expansion also would include the Babek and Mashal satellites, which sit in deeper water to the east and are estimated to actually be substantially larger than Umid. Some 40 km (25 miles) offshore, the SOCAR-operated field is currently subject to an ongoing development tender, so any likely sanction is not expected for at least two or three years. Potential investment, the UKTI said, is put at up to $16 billion.
A further potential development on the backburner is Aspheron Stage 1 in the Araz-Alov-Sharg Block, the second largest offshore concession issued to date by Azerbaijan. Early estimates for investment have been put by the UKTI at up to $17 billion, but that fi gure is hard to quantify at present, especially as the ownership of all three prospects—estimated to hold up to 700 Bcm (25 Tcf) of gas and condensate—is being disputed by a resurgent Iran.