SOCAR (State Oil Company of Azerbaijan) expects 19 billion cubic meters (bcm) of gas from the Shah Deniz field in 2019, and production will increase to 24 bcm in 2021. This statement was made by Vice President of Field Development Yashar Latifov.
Azerbaijan celebrated in September the 25th anniversary of the ‘contract of the century’—the landmark Azeri-Chirag-Gunashli (ACG) production sharing agreement signed with 11 international oil companies (IOCs) in 1994.
ACG has been transformative for Azerbaijan’s oil and gas sector. With $36bn invested by the ACG partners over the years, it helped re-establish one of the world’s oldest hydrocarbons provinces as a major energy supplier, producing more than 3.6bn bl of oil thus far.
Twenty-five years on, Azerbaijan’s state-owned oil company Socar’s exploration and production challenge has evolved. While ACG’s contract period has been extended to 2049, Yashar Latifov tells Petroleum Economist that it its production level has now slipped off its plateau. The aim, he says, is to ensure the decline plays out in a manageable manner.
Socar’s wider portfolio comprises 28 offshore and 53 onshore commercial discoveries, as well as more marginal finds—not all of which are under development.
Historically, Azerbaijan has produced more than 2bn t of oil and 850bn m³ of gas. “Production from these fields form the basis of our energy security. Last year, close to 39mn t of oil was produced, of which over 7.5mn was net to Socar, either from its own or partner-operated fields,” says Latifov.
Gas production last year was more than 30bn m³, 6.5bn m³ of which came from Socar-operated and heritage fields. The rest came from Shah Deniz and ACG in the form of associated gas, three-quarters of which was reinjected into the oilfields.
Socar is now aiming for a significant increase in Azeri gas production, primarily due to progress on the Shah Deniz 2 development. “This year will essentially be about producing almost 7bn m³ of gas more than last year,” says Latifov. “We are expecting about 19bn m³ this year from Shah Deniz and then we will go up to 22bn m³ next year, and to 24bn m³ by 2022. The overall trend is towards a material increase in gas production levels.”
It should be noted that the government previously forecasted production of the Shah-Deniz field in the amount of 17 billion 389 million cubic meters of gas in 2019.
There are also major projects in the pipeline that are approaching the FID phase. Socar is pushing for full field development of the Absheron and Karabakh fields, and for future development plans for the Umid gas condensate field and Babek high potential perspective area, among a number of potential field developments with IOC partners.
Projects designed to sustain and enhance production levels are being executed, while exploration plans cover both seismic surveys and exploration drilling. For example, Socar is lining up with its partner BP to drill three wells in the shallow water Absheron Peninsula area.
And this trend of managed production decline in upstream projects—at least as far as Socar’s ‘heritage’ field developments, i.e. assets that Socar inherited from Soviet times, potentially dating back up to a century—is widespread, although without dampening Latifov’s determination for maximising recovery as much as possible. “Despite the advanced age of the fields, we keep them running at a high level of intensity,” he says. “Look at the recovery efficiency ratio: we are developing remaining reserves at an average rate of 5pc. That is a very good number, given that the fields are very old.”
Nor does it mean that Socar is resigned to managing decline across the board. There are more promising fields out there, such as Shallow Water Gunashli field, where the reserve recovery efficiency ratio is measured at a perkier 8-9pc.
“We are discovering more reserves within existing fields, and at deeper layers than traditionally known productive horizons, whether it is in the Shallow Water Gunashli field, Bulla Deniz or others. This signals a promising outlook,” says Latifov.
“There is also an exploration well with [Norway’s] Equinor; we have got approval for the Karabakh development—and other exploration wells are planned for next year,” he says.
Patience, though, remain a watchword. Latifov acknowledges that some of Socar’s major development plans have taken a long time to plan and execute. “Data acquisition, processing and interpretation and selection of targets for exploration wells takes time. But we made good use of the time, and now we have seven or eight exploration wells lined up,” he says.
Socar has supplemented its seismic activities by remobilising vessels in the Shallow Water area of the Absheron Peninsula (Swap) with fit-for-purpose technology. “With the Gilavar seismic vessel we started shooting a campaign in October in the Kadu (Karabakh, Ashrafi, Dan Ulduzu) area, and then the vessel will go to do seismic shooting at D-230 area for BP. We are doing a lot of work with our partners, but we at Socar are also investing in high resolution and 3D seismic surveys in older fields. We are looking for better reserves characterisation and better quality selection for the remaining hydrocarbon accumulations. We are confident that we will be able to identify these and find better targets for production drilling.”
The company is keen to deploy the latest digital technology solutions, forming a joint venture with computing heavyweight IBM and extensively deploying SAP tools to enable the digitalisation of field development, well planning and construction processes.
Ensuring an effective relationship with BP, the operator of the ACG project, and other partnering companies is also central to Socar’s strategy. “The fact that the new contract has been signed and the engagement will run until 2049 is clearly very positive. Now we can plan for a longer perspective,” says Latifov.
What of this year’s media reports of the proposed exit of foreign partners ExxonMobil and Chevron? “We do not know the current status regarding the exit of ExxonMobil and Chevron. Every company has to measure its operational status, its investment and capital management. That is the normal process,” says the Socar executive.
Even when players have reshuffled their portfolios to exit specific Azeri projects, it has not necessarily led to permanent departures from Azerbaijan. For example, while Total withdrew from Shah Deniz, it returned for the Absheron field development. “Similarly, Equinor left the Shah Deniz project, but it has engaged with us on the contract areas covering the Karabakh field and other prospective areas,” says Latifov.
The Absheron field development–distinct from Swap—is one of the fields that is most exciting Socar’s upstream leadership. Having resumed its drilling programme with Total in 2018, it completed the appraisal leg of the scheme earlier this year, confirming reserves at the higher end of the expected range.
Absheron production, of c.1.5bn m³/yr of gas and almost 10,000bl/d of condensate, is due on stream in 2021. “It is great that we can efficiently bring more technically viable reserves to the market, where the buyer is Azerbaijan and Socar,” says Latifov.
And he remains confident that the current vibrant E&P activity in Azerbaijan can be sustained. “We are seeing more and more reserves, increasingly from unconventional wells that are becoming more competitive,” he says.
That activity is reflected in the wider Caspian Sea region, despite recent changes to the investment model there. “One of the challenges in the Caspian before was about creating for investors exclusive and absolute rights–it was all about protectionism and about ringfencing for investors in each part of the region,” says Latifov.
The key now is to be more inclusive and more cooperative. “Maybe it is difficult to achieve, but it is an opportunity as well, with all the infrastructure that has been created in the Caspian over the years. I see the need for an innovative approach [where different Caspian players] complement the efforts of each other,” he says.