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    [GGP] Where the gas will come to fill the SGC pipelines?

Summary

The year of 2018 will be remarkable for the Southern Gas Corridor project. The gas from the Shah Deniz Phase 2 will start flowing and reach the...

by: Gulmira Rzayeva

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Global Gas Perspectives

[GGP] Where the gas will come to fill the SGC pipelines?

The year of 2018 will be remarkable for the Southern Gas Corridor project. The gas from the Shah Deniz Phase 2 will start flowing and reach the Turkish market by June, when the official inauguration will be held thanks to the President Aliyev’s efforts. The start up volume of gas deliveries through SCPx and TANAP will be 2 bcm/a, doubled in 2019 and reach its 6 bcm of plateau level by 2020. As it is known, both the SCP and TANAP pipelines are scalable till 30+ bcm and to increase the netback margin for the pipeline consortia and make the shipping cost lower for the shippers it is vital to fully fill the pipeline.       

As President Aliyev said at the Fourth Ministerial Meeting of the Southern gas Corridor Advisory Council held in February, ‘Azerbaijan together with its foreign partners will invest in developing new fields and substantially increase the gas production in the country’ to export bigger volumes. To achieve this, it is necessary to look at existing fields for which PSAs are already in place and that are at different stage of exploration, appraisal, and development, as well as analyzing structures that have been discovered and where there is a firm intention to develop the block, but where no wells have yet been drilled and no data is yet available (with the exception of seismic data). The existing fields and structures in the country comprise two groups of reserves and resources: (i) Fields and structures that are in the international consortia’s production portfolios (SD I & II, Absheron I & II, Umid, Babek, Garabagh), as well as structures/blocks that are expected to be released under a PSA with an IOC/IOCs. This group of reserves and resources comprises both (i) contracted gas and (ii) un-contracted gas, so-called ‘free gas’ that will show a growing surplus, potentially available for new exports (Shafag-Asiman). The second group of fields includes all the reserves that are included in the SOCAR/Azneft production unit gas production portfolio, which mainly supply the domestic market, with the excess of gas exported by SOCAR to Georgia and Turkey. The security of gas supply to the domestic market largely depends on the future development of these fields and the amount of gas that SOCAR will receive and/or produce. 

Country’s gas balance

The country’s gas balance last year looked as follows: In 2017 SOCAR imported 2.1 bcm  of gas from Russia (1.6 bcm/year) and Iran (0.5 bcm/year) and exported to Georgia the same volume (2.1 bcm/year). It received, free of charge, 2.9 bcm/year from ACG associated gas and 2.8 bcm/year as its share from SD1. SOCAR’s own gas production last year was 5.8 bcm, with gas losses of around 800 mcm. The total gas volume that was available to SOCAR for the domestic market, excluding volumes for export and losses, was 11.4 bcm/year. In addition, SOCAR withdrew 0.7 bcm/year from storage, giving a total of 12.2 bcm/year (Table 2). As such, SOCAR should have had around 1.6 bcm of excess gas in storage, but in fact faced shortages, and as a result cut gas supplies in winter time to residential and industrial users and greenhouses in some regions of the country. According to SOCAR, the company has 2.3 bcm of gas reserves in storage for the 2017/2018 winter season.

Azerbaijan’s gas balance in 2017

Activity

BCM

Imported

2.1

Exported

2.1

ACG

2.9

SD1

2.8

SOCAR production

5.8

Storage withdrawal

0.7

Total

12.2

Losses

Total

Consumption

Gas stored  

0.8

11.4

9.8

1.6 (for 2018)

Source: SOCAR.

SDI

Given the fact that the SD1 field started producing in late 2006 and reached its plateau level in 2010, the field’s geological tail-off period should begin in 2025–2026. During the tail-off period, production levels may decrease by around 1-2 bcm/year year-on-year, depending on well productivity. This leads us to assume that there might not be sufficient gas to extend the long-term contract with the Turkish BOTA┼×, which expires in 2021, to provide 6.6 bcm/year on a LTC basis. We assume that the contract with BOTA┼× might be extended, but more likely as a short- to mid-term contract with reduced volume. This means that transportation through the system will be decreased by around 1 bcm/a from 2025 and 2-3 bcm/a from 2027.  

Absheron phases 1 

The Absheron field is currently under development through a joint venture of Total and SOCAR based on equal interest. It is planned that the production of 1.3 bcm/a will start from 2020 and will be sold to SOCAR for the domestic market. 

The Umid field

This field is already producing however the Service Risk Agreement with an IOC is expected to be signed this year to substantially increase the production. After the SRA signed the maximum production level may reach 3 bcm/a in 2023 and stay at this level up to 2030.

The Garabagh block

According to preliminary estimates the block may be the second major contract for oil field development in the Caspian Sea after the ACG project, with an initial oil reserves of 100 million tonns and probable 40 bcm of natural gas[1]. The gas production may start in 2022 and may reach possible peak production of 2 bcm in 2024 and 2025 and start gradually declining from 2026.  

Absheron Phase 2

Phase 2 is planned to be explored and developed after Phase 1 comes on-stream. It is planned that the final investment decision regarding Phase 2 will be taken by the mid-2020s depending on marketing arrangements, the price in internal and external markets, and availability of markets. The annual plateau level of production from phase 2 may add 5 bcm/a on top of the 1.3 bcm/year from Phase 1. Some part of these volumes may be kept for the domestic market in case of necessity and the excess of gas could be exported to either the Turkish and/or the European market, depending on the availability of market share, reasonable prices, and other marketing considerations.

The Babek structure

This structure can add substantial volume to gas production in the country once the Service Risk Agreement is signed with an IOC and production from the field is brought online. The estimated gas reserves of this structure are 400 bcm and it is expected that the production at plateau level may reach 8 bcm/year. Despite that the Babek block is relatively bigger, the gas production may not reach the maximum level. If SRA signed this year, commencement of the production from this structure may be from 2022 with starp up small volumes with the gradual increase year-on-year to around 500 mcm/year at plateau level and starting declining in 2027

The Shafag and Asiman

The MOU between SOCAR and BP covering this area was signed in July 2009 and the PSA on joint exploration and development for a period of 30 years (with potential extension of up to 5 more years) in October 2010. It was agreed that the exploration period will be 4 years with possible prolongation for another 3 years. The first stage of exploration works envisions the drilling of two wells. The second one assumes drilling of two more wells, if necessary. If and when the participants move to the production stage, they have agreed to operate the project jointly. The two companies hold equal interests in the project.

This block has never been explored previously. The initial estimates put the probable reserves at between 350 and 500 bcm of natural gas and 65 million tonnes of condensate. The potential annual gas production is estimated to be 4-6 bcm. The 2-D and 3-D seismic study has been done by the Caspian Geophisycal under the BP contract in 2011 and 2012. And the third data interpretation phase has been completed in the first half of 2014.

To date, no exploration wells have been drilled, and it is expected that the exploration and appraisal stage could take from 3 to 4 years. According to BP, the company has already expressed its interest in further exploring the block. However, this will happen no sooner than 2020, when gas from SD2 will start flowing to the European market. Given the current development status of the block and the firm intention of BP to develop the field, we can assume that the first gas could come on stream no earlier than the late 2020s.

Prospects for SOCAR/Azneft gas production

With SOCAR’s own natural gas production declining, the company has launched a strategy of investing to increase recovery and production from these fields. Despite this, given the maturity of its existing fields, SOCAR will be looking more to production from within the joint ventures (currently ACG, Shah Deniz, Umid, Absheron and also from the next wave of production in the future) offshore in the Caspian Sea.

Azerbaijan gas production will be increased significantly by 2021 and reach its peak production in 2023. The peak production period will come to the years of 2021-2027, when production will reach almost 50 bcm/year from around 28 bcm in 2017. The fields that are included to the overall country’s gas production projections are all either producing (SD 1 & 2, fields under Azneft/SOCAR production, ACG associated gas and Umid) or under development based on PSA or JV (Absheron, Garabagh), or PSA concluded, there is a consortium exist and partners have firm intention to develop the fields in mid-and long-run (Absheron Stage 2, Shafag-Asiman). We did not include to the country’s gas production projection the so called technical resources (Nakhchivan, Zafar-Mashal, Inam, Araz-Alov-Sharg, Kapaz/Sardar) as, although these structures have been discovered and some preliminary 3D seismic data exists, however there is no intention and plans of SOCAR and IOCs to invest and develop the blocks and no legal arrangements are in place. The development of this group of structures will largely depend on political, technical (availability of drilling rigs), and commercial (the cost of gas production and marketing arrangements) factors. For that reason any assumptions on possible gas production quantities and timing of production will be indicative.        

If we exclude ACG non-commercial re-injected gas from the country’s total production, somewhat around 10 bcm of extra gas can be available till 2025, with graduate fall in the following years as a result of natural decline. The SGC pipelines, which includes SCPx, TANAP and TAP are scalable to up to 30 bcm/year to transport larger volumes. There are plans to further expand SCP (future expansion, SCP fx) to 30+ bcm/year if additional volumes of gas available for export and if economics allow, with the help of compressors. As TAP is the European infrastructure, any decision to expand the capacity should be in compliance with the EU legislations. The decision will also largely depend on the economics of such investments and availability of markets and the price. The availability of additional volumes of gas in the country will also depend on the future investments in technical resources the Turkmen gas might be another option of filling the pipelines. 

Gulmira Rzayeva

The statements, opinions and data contained in the content published in Global Gas Perspectives are solely those of the individual authors and contributors and not of the publisher and the editor(s) of Natural Gas World.