In its report submitted in November, 2015, De-Golyer and MacNaughthon [D&M] – a consultant appointed by Union government [following dispute between Oil and Natural Gas Corporation’s [ONGC] and Reliance Industries Limited [RIL] over alleged migration of gas from former’s G4PML and D1/E1 discoveries in KG-DWN-98/2 to latter’s D1 and D3 fields in KG-DWN-98/3 off Andhra coast [better known as KG-D6]] – estimated that 0.4 trillion cubic feet [tcf] of gas had migrated from ONGC ‘idle fields’ to RIL.
Following this, the government set up a committee under justice A P Shah in December, 2015 to examine the matter and recommend measures to be taken against RIL for “the unjust benefit” it received from the migration of gas taking in to account the findings of the D&M report. The committee has now finalized its report.
It opines that RIL was well aware of the migration [as far back as 2003] and yet went ahead with commercial exploitation without informing the authorities/oil ministry. It recommended that whatever benefit RIL received in terms of migrated gas is liable to be returned to the government [not to ONGC]. While, these actions [determination of restitution amount, penalties etc] will take their sweet time, meanwhile it is important to take a look at the big picture on future gas supply scenario which is worrisome.
Prior to 2000, domestic gas supplies were coming primarily from major gas finds in the Bombay High and South Bassein area in west offshore discovered in late 70s. A second bout of major discoveries came after 2000 mainly from KG-D6 [RIL] and KG-OSN-2001/3 operated by Gujarat State Petroleum Corporation [GSPC] – awarded in the first and second round of new exploration and licensing policy [NELP] – besides KG-DWN-98/2 of ONGC.
As per an approved plan, RIL had committed to produce 80 million standard cubic metre per day [mmscmd] from KG-D6 linked to in-place reserves of 12 tcf and recoverable reserve [RR] of 10-11 tcf. Production commenced in 2009 and reached 60 mmscmd in 2010. Thereafter, it plummeted to a low of around 10 mmscmd currently. In 2012, the operator revised in-place reserves to 2.9 tcf and RR to 1.9 tcf. At present, it has only 0.183 tcf left.
Plus, it has residual of 0.064 tcf out of total 0.4 tcf that migrated from KG-DWN-98/2 area to KG-D6 as estimated by D&M. That gives a total of 0.247 tcf or 6.675 billion cubic meter [bcm] [37 cubic ft = 1 cubic meter]. Even at current measly flow rate of 10 mmscmd, this will get exhausted in less than 2 years. In other words, from 2018-19, there won’t be any production from this area.
As regards, KG-DWN-98/2, ONGC did not take steps to develop it for more than a decade; its field development plan [FDP] is yet to be approved. According to the original declaration of commerciality [DoC] submitted by ONGC, it had 1.7 tcf of in-place reserves and RR 1.2 tcf. But, according to D&M, it has RR of only 0.5 tcf [after netting migration] or 13.5 bcm. On the basis that production starts in 2018 and output of 16-17 mmscmd [as planned by ONGC], there won’t be any gas left after 2020 .
As for KG-OSN-2001/3 [GSPC], the ministry had approved in-place reserves of 10 tcf and RR 1.6 tcf. After having invested over US$ 3 billion, it is struggling to start commercial production [there is even pressure on ONGC to bail it out]. During trial run conducted in August, 2014, it could reach flow rate of 0.5 mmscmd a meager 10% of the target output of 5.4 mmscmd. Besides, there are doubts about the veracity of RR.
Early this year, Prime Minister’s Office (PMO) had taken a meeting with oil ministry to review all gas fields whose FDPs have been approved. It was estimated that domestic gas output will increase from current 92 mmscmd [33.6 bcm] to 160 mmscmd [58.4 bcm] by 2020-21. When, juxtaposed with projected demand of over 500 mmscmd, this would leave uncovered gap of 340 mmscmd to be met mostly from imported LNG [liquefied natural gas].
But, reaching the production target of even 160 mmscmd is a remote possibility. This is because the aforementioned three high profile fields which were expected to contribute bulk of the projected increase have met with a fiasco. The output could at best reach 129 mmscmd [knocking off 31 mmscmd: KG-D6 ‘10’; KG-DWN-98/2 ‘16’; KG-OSN-2001/3 ‘5’]. This will widen the deficit to 371 mmscmd leading in turn, to even greater reliance on LNG.
The government has taken several steps to improve the policy and regulatory environment for giving a boost to exploration and development of gas fields. In March, 2016, it even issued guidelines giving an incentive price for extracting gas from deep water & ultra-deep water and high pressure–high temperature [HPHT] areas [the 3 high profile fields fall in this category] which works out to US$ 6-7 per million Btu, almost double the normal price [based on formula under October, 2014 guidelines].
For the future, it has switched over to revenue sharing model [from extant profit sharing]. Under it, the bidder can specify the revenue that government will receive depending on stage of production and overall fuel market scenario. It will provide certainty of policy environment, minimize scope for government intervention, reduce interface with bureaucracy, eliminate delays and catapult the operator in a commanding position.
However, all these efforts will come to a naught if exploration and production [E&P] companies do not strengthen their technological and project execution capabilities to optimize production from discovered fields. When, actual reserves turn out to be a fraction of what they initially project and are unable to generate output from them, any amount of help either by way of higher price or minimal government intervention will be rendered meaningless!
It is time E&P companies set their house in order.