Oil India seeks more hydrocarbon concessions globally

India's second largest public sector company Oil India Limited (OIL) is seeking more hydrocarbon concessions across the globe, including Brazil and Mexico."We are aggressively looking for a lot of good property from where we can bring crude oil into India," Sunil Kumar Srivastava, chairman and managing director, told PTI yesterday.

"The government of India is very supportive of our overseas ventures. They are encouraging us to go global to help reduce energy import volumes," he said."The more oil and gas we bring into the country, it would help reduce the country's energy import bill," he said on the sideline of the Singapore International Energy Week.

India imports about 75 per cent of its crude oil and 30 per cent of its natural gas requirements a year.Among its major ventures abroad, OIL has invested USD 900 million on four per cent farm-in stake in offshore Mozambique.

OIL and ONGC Videsh (OVL) had announced a 10 per cent farm-in acquisition with Mozambique in January this year.The company operates in 11 overseas countries and produces small quantities of hydrocarbon in the United States, Venezuela and Russia.

Srivastava, along with B C Tripathi, chairman and managing director of GAIL and Nishi Vasudeva, chairman and managing director of Hindustan Petroleum were among the eight nominees for Platts Asia CEO of Year award which went to Chengyu Fu, chairman of China Petrochemical Corporation (Sinopec Group).

Source: ET

India likely to strike deal with Vietnam for oil exploration

Looking to deepen its economic ties with Vietnam, India is likely to strike a deal for exploration and production of oil and gas during the visit of South East Asian nation's Prime Miniter Nguyen Tan Dung on October 27. 

Ahead of its prime minister's two-day visit here, Vietnam has also evinced keen interest in greater cooperation in key areas of defence, security and oil exploration and has hoped that some pacts will be signed during the trip. 

"We are looking at enhancing India's cooperation in the fields of hydrocarbons and oil exploration," oil minister Dharmendra Pradhan told PTI. 

He said he interacted with Vietnamese authorities on further cooperation in the oil sector during President Pranab Mukherjee's visit to Vietnam in September and wants this cooperation to be taken further. 

"We are exploring more options to further our cooperation with Vietnam in the oil sector," he said, hinting at further talks and some possible tie-ups during the Vietnam Prime Minister's visit. 

Pradhan said a team of officials of state-run Indian Oil Corporation had visited Vietnam and explored some business ventures which may come to fruition during the Vietnamese President Pranab Mukherjee's visit. 

During Mukherjee's visit in September, ONGC Videsh Ltd, the overseas arm of state-run explorer Oil and Natural Gas Corp (ONGC), had signed an agreement to expand its oil and gas exploration in offshore Vietnam. 

The Indian flagship firm agreed to consider exploring in 2-3 blocks out of the 5 areas in South China Sea that Vietnam had offered on nomination basis in November last year. 

The five blocks or areas - 17, 41, 43, 10 & 11-1 and 102&106/10, offered in November last year lie outside the territory claimed by China in the South China Sea. 

OVL forayed into Vietnam as early as 1988, when it bagged the exploration license for Block 06.1. The company got two exploration blocks - Block 127 and Block 128, in 2006. 

However, Block 127 was relinquished after completing the work programme, and the other Block 128 is currently under exploration. 

Additionally, ONGC Videsh and PetroVietnam have been engaged in further discussions for possible expansion of cooperation in hydrocarbon sector of Vietnam. 

OVL had relinquished Block 127 in offshore Phu Khanh Basin after it failed to find any oil or gas in the area. 

Though it had decided to withdraw from adjacent Block 128, it has decided to stay put because of India's strategic interests in the region. The exploration period for the block has been extended until June 15, 2015. 

China claims sovereignty over most of the South China Sea where Block 127 and 128 are located and had warned the Indian arm from drilling in the region. 

OVL continues to own 45 per cent in Vietnam's offshore block 6.1 and its share of production was 2.023 billion cubic metres of gas and 0.036 million tonnes of condensate. 

During his visit, Tan will be accompanied by a delegation of a number of businessmen, who will hold talks with the top Indian leadership on strategically-important bilateral issues of security and energy as well as regional matters.

Source: TOI

Challenges of digging a well; undersea!

It is said that in the good ol'days, digging an oil well was an easy business. If you were at the right place (like say in Texas), a dedicated knock on the ground would send black-gold gushing forth. In fact, so much of it was freely available that it upset people back then. For instance, a rancher in Texas in 1902, WT Waggoner was irritated when he came across oil while digging for water. An annoyed Waggoner is reported to have wailed:  "I wanted water, and they got me oil. I tell you I was mad, mad clean through. We needed water for ourselves and for our cattle to drink."

A century later, things have changed dramatically. From a situation of low demand and oversupply, we are now in an era where crude oil supply is struggling to keep pace with rapidly growing demand.
The trouble is, even as demand for crude oil keeps growing, output from the known oil wells is showing signs of plateauing. According to the Association for the Study of Peak Oil and Gas, many oil-rich countries have already passed their peak rate of oil production; an indication that the world peak of production could now be around the corner.[5] At the same time, there is no let up in demand. This means new wells need to be identified and dug; some of them in places where extracting oil can be a formidable task.

And when 70 percent of the planet is water, drilling for oil in the sea becomes more than just an option.

Prior to 1947, drilling beyond the shore was impossible, and often unnecessary. The first 'true' offshore oil well was drilled off the Louisiana coast in the Gulf of Mexico by Kerr-McGee Oil Industries. Some 17 kms away from the shore, the well was dug at a depth of some 15 feet.[2][3]  Today, in the same waters, the deepest and the biggest oil rig named Perdido is operational. Located in the Gulf of Mexico, Perdido draws oil from a depth of about 2450 metres (8000 feet).[1] Thus in a matter of 6 decades and more, we have moved from a depth of 15 feet to 8000 feet.
Going for the dig

Yet, with all the technological advances, drilling in the sea is still fraught with challenges, and a costly proposition. Right from locating a deposit to reaching it and from transporting oil to finally closing the well, there is a long chain of processes
Typically, a deep-sea oil well operates in depths of 1,500 metres plus where one faces the HP-HT (High Pressure and High Temperature) combination. Temperatures dramatically vary when it comes to deep-sea wells. For instance, on the surface of the sea-bed, the temperature can be several notches below freezing point (but the water does not freeze because of salinity and high pressure). However, as you dig deeper under the sea-bed, there is a sharp rise in temperatures. In fact, it can go as high as 230°Celsius.

Another major obstacle is high pressure, which can go up to as much as 35,000 psi. In fact, drilling into rock-layers increases the pressure at every given point. According to estimates, the pressure within the underground reservoir can be extremely high and dangerous, wherein every square centimetre area is subject to pressure equivalent to the weight of a medium-sized car. The challenges of drilling so deep are particularly notable because the fields in question are often so deep that they can’t be visited by humans, even in submersibles.

Hitting bull’s eye

Nonetheless, the biggest challenge for any oil company is to hit the 'sweet spot'. Locating an oil deposit in the sea-bed is feat in its own. Keeping in mind the depth, location of the field and type of sea-bed, the possibility of an oil deposit is much varied. If the hit is not ‘spot on’, huge losses will be incurred. According to an industry rule of thumb, drilling a deepwater "dry-hole" can be set one back by as much as US $100 million. Even so, according to industry experts only 2 out of 10 digs actually yield oil (or gas).

Little wonder, oil exploration companies deploy the latest in technology to minimise, if not altogether avoid, such dry-holes. One such methodology is to dig a reference well, after undertaking extensive geological mapping of the region, including conducting a gravity-magnetic map to ensure the oil reservoir.

Other factors like existing infrastructure, depth of the well, weather and currents, seabed conditions, cost of construction and commissioning of permanent structures, time to first production, equipment reliability, well accessibility for future monitoring or intervention; make drilling in the sea a fairly complex and costly proposition. Hence, there are only a few companies in the space, who have the expertise, and the wherewithal to undertake such explorations.

Finding the right partner
But that is as far as machine or technology goes. At the end of the day, one still needs skilled manpower to deploy the technology effectively. Getting the right people for the job is another big challenge.  Even after you have identified them, retaining them is equally a challenge, especially given the long lead times before a find is executed. Because of the challenging working conditions and the high level of technical expertise need, there is only a small pool of people who have the right mindset and knowledge fit for deep sea exploration. Same holds true for companies that exploration firms have to partner with. For instance, GE is among the handful of players with a proven track record, having provided systems for subsea exploration for over 40 years, and has over 1,000 systems installed worldwide.

Lessons from Deepwater
In spite of all the safety and safeguards, things can go horribly wrong on an offshore oil rig. The two biggest disasters in exploration history happened at some of the biggest rigs. One was Piper Alpha in North Sea, where an explosion in 1988 destroyed the rig and resulted in the death of 167 workers. The second was in 2010 at Deepwater Horizon in Gulf of Mexico, off the US coast, where an explosion caused by a blowout killed 11 people and caused the largest offshore oil spill in history.
The lesson learnt from such incidents is that there just cannot be any room for complacency. Given the technology deployed and the associated risks, offshore drilling is a fairly costly proposition. Around 30 per cent of global oil production is obtained through offshore drilling, with less than 1 per cent of wells deeper than 1,500 metres.  According to International Energy Agency estimates, oil extraction through deep-sea drilling currently costs between US $35-$65 per barrel. With crude prices hovering over US $100 a barrel, there are decent profits to be made from offshore drilling.

Deep sea – The next big thing in India?
Finally, keeping in mind India's peninsular nature and the fact that offshore gas deposits have been found both in the West (Arabian Sea) and East (Bay of Bengal), there is big potential for deep sea drilling.  The quality of crude extracted from India’s sedimentary basins is said to be better than that of the crude imported from the Middle East. With much of India’s offshore assets yet to be explored,   deep sea could be the next big thing in India's pursuit of energy security.

Source: Moneycontrol

The current scenario in India’s natural gas market

According to EY, India’s expanding economy and growing population have led to increased consumption of primary energy resources such as coal, oil and natural gas in the country.

In line with this, its primary energy consumption grew at a compounded annual growth rate (CAGR) of 6% to 563.5 million t of oil equivalent (toe) in 2012 from 420.1 million toe in 2007.

The share of natural gas in its primary energy mix increased marginally from 8% in 2008 to 8.7% in 2012. This is fairly low, compared to the global average of 24%, primarily due to supply side constraints. Furthermore, in terms on individual consumption, India’s natural gas consumption of 44 m3 per capita is far behind the global average of 470 m3 per person.

Significant gas deficit

Despite low gas consumption relative to global trends, India’s natural gas market is nevertheless seeing a supply deficit, primarily due to low domestic production and an inadequate transmission and distribution infrastructure. According to EY, domestic gas production received a significant impetus with commencement of production at the KG-D6 field, located in the country’s east coast in 2009, however the field’s output has steadily declined and has hit a trough of 12 million m3/d in the third quarter of 2014.

According to Reliance Industries Limited (RIL), the fall in KG-D6’s production is mainly due to geological complexity and a natural decline in the fields. The decline in most of the country’s ageing fields has further compounded the supply deficit.

On the other hand, the demand for natural gas in India has increased significantly due to the demand from the power and fertilizer sectors, and cumulatively accounted for more than 61% of gas consumption in 2013. The demand is also driven by its growing usage in the city gas distribution (CGD) sector and industrial sectors, such as refining and petrochemicals. Rising concerns in regards to carbon emissions have also contributed to the demand for natural gas in the country.

This has led to increased Indian dependence on imported LNG. The country’s LNG imports have increased from approximately 8 million t in fiscal year 2009 (FY09) to 11 million t in FY13, accounting for 28% of total supply. India is currently the world’s fourth largest importer of LNG in the world, according to the BP Statistical Review of World Energy 2013.

Rising production and imports

EY expects that the shortfall in natural gas in the country will continue over the next few years, with supply trailing demand. Shortage of gas is likely to reach its peak in FY15, with approximately 37% of the demand being unmet. However, from FY16 onwards, the deficit may decrease, primarily due to the planned production of private and joint venture companies and increased LNG import capacity. Power and fertilizers are expected to remain the anchor segments that consume natural gas and are likely to account for approximately 68% of the total demand for it in FY17. Furthermore, deregulated pricing of petroleum products and an increasing focus on addressing environmental concerns are expected to drive the demand for natural gas from industrial users, residential users through piped natural gas (PNG), and in the transportation segment through the demand for compressed natural gas (CNG). However, this demand is highly price sensitive and will depend on the price affordability of end users, especially in the power and fertilizer sectors.

EY expects the total supply of natural gas to reach 359 million m3/d in FY17, a CAGR of 15% from FY14 in india. Most of this incremental supply will fail to keep pace with the anticipated rise in demand. The country’s potential to import LNG is expected to increase to 150 million m3/d in FY17, contributing approximately 42% of the total supply.

EY additionally expects domestic production to increase at a CAGR of approximately 12%. This is likely to come from new discoveries which are currently under development, expectation of partial recovery in the output from KG-D6 and increased production from unconventional sources, particularly coal bed methane.

Source: Energy Global

Indian Oil Corporation to invest in shale-gas and liquefied natural gas projects in Canada

Indian Oil Corporation will invest USD 4 billion in the British Columbia province, Canada, to source liquefied natural gas from the region.

Premier of British Columbia, Canada Christy Clark said: "Indian Oil is poised to make its biggest investment in Canada to secure natural gas for India from BC."

She said the state-run firm will invest USD 4 billion for securing LNG supplies from the Canadian province. IOC, in May, signed a deal to buy 10 per cent stake in shale-gas assets and a linked liquefied natural gas (LNG) project in British Columbia.

The Canadian asset will produce as much as 19.68 million tonnes of LNG a year for 25 years starting in 2018.

That apart, Clark said, GMR Group of India and IC-Impacts of her province will now work together on safe and sustainable infrastructure like innovative pavement technology, construction design and water and waste water infrastructure.

Wooing domestic investors, she said: "We, in British Columbia, would like to partner with this great country to realise its potential by providing LNG to power its future. We recognise that there will be a mix of energy sources - coal, oil, solar, wind.

"India needs a million skilled workers a year, every year, for the next 15 years. We can help. If we can help train 3,000 and 300 of them help us build an LNG industry -- it's good for you and good for us."

Reliance Industries has also signed on with IC-Impacts to share research, training and develop new technologies in such areas as specialised building materials for infrastructure like bridges, roads and buildings.

The state government of Punjab and BC have committed to work together on skills training, education and agriculture.

Projecting BC as an attractive destination for investment in the LNG space, Clarke said: "There are several advantages -- short transportation time to Asia to save cost, lower operating costs, vast gas reserves, stable and reliable jurisdiction and a strong regulatory regime."

The Canadian province is also expecting big ticket investments in its energy space from other geographies as well. It is likely to finalise USD 36 billion from Petronas of Malaysia by this new year.

Earlier this week, Clark announced a funding for 20 scholarships, worth a total of 50,000 dollars, to support and encourage two-way exchange of students between the University of the Fraser Valley (UFV) and Sanatan Dharma (SD) College in Chandigarh.

Source:ET

Investment decision only after clarity on gas price: Reliance Industries

 Reliance Industries has said it will make a final investment decision on producing gas from the R-Cluster discovery in the flagging KG-D6 block only after the government decides on gas price hike.

RIL and its partners BP plc of UK and Canada's Niko Resources plan to produce about 13 million standard cubic meters per day of gas for 13 years from D-34 discovery, known as R-Cluster, in the KG-DWN-98/3 or KG-D6 block by 2017-18.

The planned output from D-34, which is estimated to hold an in place gas reserve of 2.2 Trillion cubic feet, is equivalent to the combined current production from Dhirubhai-1 and 3 (D1&D3) gas field and MA field in the KG-D6 block.

In a presentation to investors post announcing its second quarter earnings, RIL said it has completed Front End Engineering Design (FEED) as well as geo-mechanical studies for the R-Cluster development. Contracting activity was underway for long lead items.

However, "clarity on gas price (is) required for FID (final investment decision)," RIL said in the presentation.

The government last month for the third time postponed a decision on raising natural gas prices. Now, it is looking at announcing a decision by November 15.

For RIL, a revision in natural gas prices was due on April 1, 2014, when the $4.2 per million British thermal unit rate fixed for first five years of production expired.

A panel appointed by the previous UPA government had proposed a formula which would have at least doubled the rates but the same is under review with the new government looking at moderating the increase to keep the burden on consuming power and fertiliser industry minimal.

"Clarity on gas pricing to enable achieving goal of enhanced production towards ensuring India's energy security," RIL said in the presentation.

RIL has so far made 19 gas discoveries and 1 oil find in the KG-D6 block. Of these, D1&D3 gas fields were brought to production in April 2009 while MA oilfield began pumping oil in September 2008.

D-34 is part of what is known as R-Cluster of discoveries. R-Cluster comprises four discoveries - D-29, 30, 31 and 34. Of these, only D-34 has so far been declared commercially viable while the Declaration of Commerciality (DoC) of others has been refused in absence of DGH prescribed tests confirming the discoveries.

Last year, the government approved RIL proposal to invest $3.18 billion in bringing D-34 to production.

RIL estimates that output from KG-D6 can reach up to 60 mmscmd by 2019 when all of the satellite fields are put into production.

The government has already approved $1.529 billion investment in four satellite fields that can produce 10 mmscmd. Investment plans for rest are under consideration.

Source: ET

Why Subsea Oil & Gas Could Be The Next Big Thing For India

Elephants and oil have little and almost nothing in common; yet there is one anecdotal legend that links both together. Sometime in late 1880s, a dedicated bunch of engineers and labourers were working in the jungles of Upper Assam, extending the Dibru-Sadiya railway line to Ledo for the Assam Railways and Trading Company. To clear the forested path, elephants were employed. Apparently, on one occasion an elephant party returned after hauling the goods, and someone discovered that the mud on one pachyderm's feet was black and smelt of oil.

Since, just a few decades earlier oil had been struck in USA and was being used as a wonder medicine to treat a number of ailments, the British Engineers were aware of what the black smelly thing was. An engineer in the party, William Lake, was much enthused and excited by the discovery.[1] On finding the spot where brackish liquid was oozing out of the ground, the excited Englishman exhorted the labourers, "Dig Boy Dig". Fortunately, the labourers did heed to his implorations. By 1889, a 20-meter high thatch covered wooden structure was erected, and so the first oil well in all of Asia was established at a town that was named Digboi. Subsequently, in the 20th century, more such wells were dug up in the region and with time, Assam became the oil-hub of India.

There was little change in the scenario, till the Union Jack was replaced by the tri-colour in 1947. A young and exuberant India on a tryst of destiny was hungry for growth and self-reliance. Thus, not surprisingly, while framing the Industrial Policy Statement of 1948, the development of petroleum industry was given much prominence. Over the next few decades, various sites in India were geo-scientifically mapped and exploratory drilling was undertaken in Gujarat, Assam and Bengal Basin. With further passage of time, new sites and locations were added to the list -- UP, Bihar, Tamil Nadu, Kutch and Andhra Pradesh.[3]
While oil was being struck in different parts of India, it was all land based. Sometime between 1964-67, Russian and Indian teams from the seismic exploration vessel Academic Arkhangelsk were scouring the Arabian Sea and struck gold, albeit black gold. And so, Bombay High (rechristened as Mumbai High) came in to being in 1976, with the establishment of an offshore oil rig. It was India's first deep sea well and remained so for a long time.

Over the years, the Eastern frontier came to light with the KGN Basin opening up. But even so, the production of oil domestically has been lagging much behind the consumption in India. To state it simply, India roughly produces 1,000 barrels of oil a day, and consumes almost 4,000 daily, making the equation 1:4. This tilted equation makes India dependent on imports from the Western nations, primarily the OPEC of Middle East, and makes it vulnerable to price rise and disruption.
In fact, many significant events in Indian political history have been shaped by oil crisis globally. One of the prime examples is, when Iraq was invaded in 1991 and the price of oil had shot through the roof, India had to pledge its gold reserves to be able to pay for the oil imports. Little wonder, finding oil is not merely a matter of saving money but also of self reliance.
Yet, oil production has largely remained stagnant over the years. Sample this: Mumbai High became operational in 1976, but it still produces around 80% of offshore oil production and almost 45% of the total oil production in India.

Unlike other countries like US, China, Japan, Korea, Brazil and even Malaysia, India has been laggard when it comes to offshore and deepwater drilling. According to estimates, India has a sedimentary area of 3.14 million sq km, comprising of 26 basins.[5] However, a large part of it remains unexplored. According to estimates, a total of 28 billion tonnes of prognosticated resources have been estimated with 67% of them being offshore.[4] It was to promote this exploration that the Indian government came out with NELP or New Exploration Licensing Policy, under which 249 blocks were awarded. Yet, NELP could not create the kind of exploration excitement, and India's deepwater reserves remain mostly unexplored.

While Mumbai High on the western coast continues to pump out significant oil, the outlook for the east coast looks even more promising.[2] Sometime back, ONGC made an ultra deep water discovery in KG offshore at a depth of 2841 metres. Meanwhile the Andaman & Nicobar deepwater sector is envisaged to hold substantial potential, given that the Yadana and Yetagun offshore fields of Myanmar coast are in the vicinity.

Keeping in mind the rising consumption, the ever-increasing costs of oil and the geo-political scenario, what India needs now is a forward-looking policy and a brave outlook when it comes to deepwater exploration. Besides, Indian companies, especially ONGC through its joint-ventures, have now the technological wherewithal to explore deep water basins.
Probably, what we really need is an embodiment of someone like William Lake to exhort, implore and encourage us yet again, uttering repeatedly, Dig India Dig!

Source: Moneycontrol

Indian oil demand to grow faster than China: Energy expert

Crude has been facing pressures with global supplies rising. The prices have fallen around 15 percent this year. Discussing the current trend and outlook, Miswin Mahesh, Energy Analyst at Barclays, said the Indian oil demand is poised to grow faster than Chinese demand this year, which is going to become a significant market changer for balances. According to him, the Indian oil demand has been sustaining strong growth rates on the back of gasoline demand. Even the diesel price deregulation will “sort of help refineries as well, given that they can get more of their under-recoveries before the quarter ends”.

Sumaira: We have seen nearly a 15 percent fall in crude this year. Till when do you expect this correction to continue and what would be your outlook on the prices?

 A: In terms of why prices have fallen, it is to do with two things. There have been a lot of concerns recently on how oil demand growth globally has faded away over the last quarters. And then on top of that, we have also had a lot of supplies coming to the market and that is why we have had WTI fall close to USD 85 per barrel level, brent as well fall close to USD 90 per barrel. In terms of how low we can go from here, it looks very different from how we had sort of seen prices fall over 2009-2010 time series so as to say and that was when OPEC was much more in control of the market. Southeast who normally balance the market in terms of production and in terms of keeping an eye on prices although much active at that period this time around they are a bit more passive. So I think we will see a bit more of a weakness come into the market especially since the supplies are not being bounced away.

Sumaira: What are the factors which you attribute for this fall in crude? Is it an increase in supply on the looming global slowdown fears?

A: Yes, so a couple of things - in terms of supplies, we have seen a lot of crude oil come back from Libya and that was a surprise for the markets given how politically Libya is now almost two different countries, several rebels fighting over different aspects of the country. So the big surprise was from Libya -- which was average producing almost nothing just two months ago and has been producing close to 800,000 barrels per day now. On top of that a lot more of the US oil production is having its side effects being felt in the Atlantic basin of the market. Lot of South African crude oil has been accumulating and that is being weighing on the supply side as well. Added to that, as you mentioned the demand side you have Chinese oil demand that is growing at the slowest pace in 24 years and that just means that Asian demand in general has been fairly weak as well.

Source: MoneyControl

Petronet LNG chief seeks govt’s help in getting pipelines laid

AK Balyan, Managing Director and CEO of Petronet LNG Ltd, has urged the Kerala Government to take a ‘positive initiative’ in getting the gas pipeline laying work in northern Kerala completed.

The laying of pipelines, he said, is crucial for the gas sector and its completion will benefit the neighbouring Tamil Nadu and Karnataka in receiving natural gas from the ₹4,600-crore LNG Terminal in Kochi, which is underutilised.

Public protest
Speaking at a workshop on LNG here on Thursday, Balyan pointed out that the terminal’s capacity utilisation was only one per cent of the 5-million-tonne capacity and the government should give top priority to the pipeline-laying work for the successful utilisation of the LNG terminal at Puthuvypeen.

Work on the over-1,000-km pipeline in the Kochi-Bangalore-Mangalore sector by the Gas Authority of India Ltd was stalled following public protest and less than 50 km has been covered so far.

Pipeline networks
According to Balyan, India is far behind the developed countries in pipeline networks. The US has a pipeline network of about 2.5 million km, while it was only 14,000 km in India.

Kerala is lucky to get LNG while the other South Indian States do not have access to this green fuel, Balyan said. He was of the view that people would soon become aware of the importance of LNG and demand gas connectivity. The city gas will be will be safer and cheaper than LPG for domestic consumers, he added.

Discussions with KSRTC are at an advanced stage for use of LNG as fuel. Hindustan Life Care has already started use of LNG in its Thiruvananthapuram unit by transporting gas through tankers, he added.

Gas pricing
Paul Antony, Chairman, Cochin Port Trust, said there should be a change in the mindset of the people to get the benefits of the massive investment made in the gas terminal.

Favouring a uniform pricing policy for natural gas to benefit users, he suggested pooling of gas pricing to avoid the high disparity in price in different parts of the country.

Jaiveer Srivastava, Chairman and Managing Director, FACT, expressed the hope that there would be a favourable trend soon in the pricing front so that gas would be available to the company at an affordable rate. The fertiliser company was forced to suspend the use of gas in its ammonia plant because of the exorbitant price of LNG, he added.

About 50 delegates from various companies from power, fertiliser, steel, refinery etc are participating in the three-day workshop.

Source: HBL

Gas production to rise by two-thirds over five years: Oil ministry

India’s domestic gas production is set to rise by two-thirds from 100 million standard cubic metres per day (mscmd) in the current financial year to 163 mscmd, or 59 billion cubic metres (bcm), over the next five years through March 2019.

The petroleum ministry has informed the power ministry about the estimated jump in production at a time when there has been a steep drop in domestic output, leaving 24,000 Mw of gas-based power capacity stranded. The two ministries are also working on a strategy to pool gas prices, to resolve differences between stakeholders in oil and power sectors over the new gas price.

India’s domestic production fell 13 per cent from 111 mscmd in 2012-13 to 97 mscmd the previous financial year (2013-14). Output is expected to pick up marginally to 100 mscmd (or 36 bcm) in the current financial year, including 24 bcm from state-run Oil and Natural Gas Corporation (ONGC), 2.8 bcm from Oil India Limited (OIL) and 9.7 bcm from production sharing contracts (PSC) regime blocks.

The bulk of the additional gas would come from ONGC’s ramp-up in output from the 24 bcm in the current financial year to 35 bcm by 2019, on the back of development of the C-26 cluster next financial year, the Daman offshore block, additional production in east coast from deepwater wells of the G1 field and from commissioning of Nelp  (New Exploration Licensing Policy) block KG-98/2 in the Krishna Godavari basin after 2017.

OIL is expected to increase production from the current 2.8 bcm to 4 bcm by 2018-19. Production begins from the Baghjan field in Assam next financial year and incremental output will be from Nelp blocks in the northeast and KG-basin in 2018-19.

The PSC regime covers production from pre-Nelp exploration blocks as well as Nelp blocks. According to the petroleum ministry, no incremental gas production is estimated from pre-Nelp blocks in the next three years. “The major fields under the pre-Nelp regime, such as Panna-Mukta, Tapti, Hazira and Ravva are matured and ageing, and production from these fields are under natural decline,” the ministry has said.

In the case of Nelp blocks, gas is being produced from D1, D3 and MA fields in Reliance Industries Limited (RIL)-operated KG-DWN-98/3 (KG-D6) block. At present, 13 of 25 wells in the D1, D3 and MA fields are closed due to waterlogging, sand ingress and pressure depletion issues. The block produced 12.9 mscmd  between April and July in the current financial year. Production is expected to rise from 4.6 bcm in the current financial year to 12 bcm in 2018.

The petroleum ministry has clarified to the power ministry a part of the additional production from Nelp blocks over the next two years would have to be utilised to meet the shortfall in supplies to the priority fertiliser sector below the level of 31.5 mscmd, as decided by an Empowered Group of Ministers last year. The remaining volumes would then be supplied to the power sector.

Source: BS

More efficient fracking means more oil and natural gas

The U.S. fracking boom is getting even bigger with advances in drilling techniques that are making oil and natural gas wells more productive.

Each drilling rig in the Eagle Ford shale of south Texas is pumping an average of more than 400 barrels a day than in the dawn of the fracking boom seven years ago, according to the federal Energy Information Administration.

The more efficient drilling has helped Texas to more than double its oil production in the past three years, topping three million barrels a day for the first time since the late 1970s.

“The productivity of oil and natural gas wells is steadily increasing in many basins across the United States,” federal energy analysts said in a research memo.

The United States has surpassed Saudi Arabia and Russia to become the world’s biggest oil producer, with Texas and North Dakota accounting for more than half of American drilling.

The U.S. also is now the world’s biggest producer of natural gas. This American energy boom is because of hydraulic fracturing, known as fracking, in which massive amount of high pressure water with chemicals are pumped underground to break shale rock and release the oil and natural gas trapped inside.

Drillers have honed their fracking techniques since the start of the energy boom and are now getting far more oil and gas from each rig. Five of the six major shale areas in the United States have seen increased production per rig in the last few years, with Eagle Ford leading the efficiency increase in oil drilling and the Marcellus shale of Pennsylvania tops for natural gas.

The number of rigs in the Eagle Ford has actually dropped in the past two years, and wells decline in productivity by some 70 percent after the first year. But total oil production in the area has still skyrocketed with increasingly sophisticated drilling techniques.

“Since mid-2013 the gains have really been from getting more out of each well,” EIA analyst Sam Gorgen said in an interview.

One new technique is a big increase in the amount of sand used to prop open the tiny cracks created when the chemical-spiked water fractures the shale rock. That appears to boost the initial production rates, according to the EIA, although it tends to be followed by a quicker decline in the well than otherwise.

Another method being adopted by drillers is to use geologic data to pinpoint the best spots along the horizontal well to frack. “So rather than spacing them evenly across the five or ten thousand feet of well, they are going in and figuring out where is the best place to put their money along the well bore,” Gorgen said.

The new techniques are more expensive but worth it to the drillers because they can make money faster, he said.

The growth in the drilling boom has environmental downsides, with complaints about industrial sand mining and the huge amounts of water used in fracking. Fracking wastewater disposal wells have been linked to earthquakes, and university researchers last month found drinking water contamination from badly constructed natural gas wells.

It’s also not clear whether the more efficient drilling techniques are going to mean more total oil and gas pumped from each well, or just make the wells run dry faster.

“The engineering isn’t certain because we don’t have any wells that are 20 years old yet, and few that are even five years old yet,” Gorgen said. “So it’s hard to say what the long term effect is going to be.”

Source: newsobserver.com

Oil ministry cuts natural gas supplies to small industry in Gujarat

The oil ministry has cut natural gas supplies to small industries in south Gujarat by 60 percent to feed CNG demand, a move that has threatened their survival and is being seen as a contravention of the stated policy.

The ministry had recently decided to meet 100 percent gas requirement for CNG and piped cooking gas supplies in cities of firms like Indraprastha Gas Ltd, from domestic production.

This was to be ensured by cutting domestic gas supplies to non-priority sectors.

In furtherance to this, APM gas or regulated production of ONGC/OIL to 30 small industries in South Gujarat was late last month cut by almost 60 percent, threatening their survival as they cannot afford imported LNG that costs four times the domestic gas price of $4.2 per million British thermal unit.

The move is seen as contravention of the cabinet-approved 20 June 2005 policy that in "public interest" had decided that "all available APM gas would be supplied to only the power and fertiliser sector consumers against their existing allocation along with the specific end users committed under court orders/small scale consumers having allocation up to 0.05 million standard cubic meters per day".

In case of reduction in supplies, pro-rata cuts were to be applied on all APM consumers.

South Gujarat Small Gas Consumers Association has written to Oil Minister Dharmendra Pradhan saying the 30 small glass consumers in South Gujarat including Pragati Glass, Piramal Glass, Haldyn Glass, Gujarat Borosil and Savana Ceramics are facing closure due to the cut announced by GAIL in the Administered Price Mechanism (APM) natural gas supplies.

The association, in an 1 October letter, said it had represented the case of small industries to Pradhan on 25 September where Pradhan assured to get the matter examined.

"However, to our utter shock, the very next day GAIL abruptly curtailed gas supplies to South Gujarat consumers by 58 percent, thus pushing these small consumers to the brink of closure," it wrote.

It pointed out the 'Guidelines for Allocation of Domestic Gas to City Gas Distribution (CGD) Entities', which were issued in compliance with a Gujarat High Court order seeking parity in supplies to all CNG firms across the country, stated that additional requirement of gas will be met by imposing proportionate cut on all APM/PMT field customers in the non-priority sectors.

Source: First Post

Gas pricing - Administered pricing’s heavy cost

The second part the Kelkar Consultation Paper (CP) discusses gas prices—where they are, where they ought to be, and the transition process thereof.

The sale price regime of the end-product is always a key parameter for any commercial economic activity. We have yet to find an industry which was set up with private capital where the sale price of produce depended neither on the market nor on any pre-defined and stable set of rules. Yet, that is what the gas price debate is about. Given the driving role of product-price in the long-term development and growth of industry, it is important that the rules of the game are set before seeking any investment. The reward also needs to be attractive if investment in a sector is considered a priority, or if the investor has alternative options.

Interestingly, the upstream industry always believed that the pricing regime was clearly specified in the contract. Extra-contractual considerations have, however, created a maze that is challenging the best of the brilliant minds. It is here that the CP provides a solution.

At the outset, the CP distinguishes between producer price and consumer price. This is important, since the consumer is not operating in a free market, but is being provided public goods, whether as a utility or as a critical input to food security. As the consumer sale price in these areas is controlled by the government, the government, ipso facto, takes the responsibility of a reasonable RoCE for these concerns, and is obliged to subsidise them if, in its view, the society cannot bear the fair price. A transparent price and a transparent subsidy for the producer or the consumers is the only way to go. This should have no implication on the demand-supply chain that works in a free market.
The CP rightly identifies that (1) the limited private investment in domestic natural gas (DNG) production is one of the results of risks introduced by the high involvement of the government in setting DNG price; (2) free-market price has a very close relationship with its substitute fuel—whether liquid hydrocarbon or RLNG; and (3) rationing and allocation leads to under-pricing, aggravating the demand-supply imbalance further, which leads to rent-seeking and poor governance. It, thus, votes against any allocation.

The CP has analysed the international experience, and confirms that in domains where cost-plus or administered regimes were followed, the domestic exploration and production suffered. Most of such regimes have moved towards linkages with liquid fuels or gas-on-gas. Allocations and administered prices, even in socialist countries, have not been successful, as shown by the recent changes in Vietnam, China, Malaysia, all of which are transiting from administered to liberalised/free-market regimes, in the direction of the UK, US et al.

As cost-plus or administered pricing models often touted by consumers have serious and adverse implications for domestic production and energy security, the CP votes against the approach.
The Supreme Court had argued that natural resources need to be fairly distributed among the people of India. The committee argues that these resources belong not only to the current generation of Indians, but future generations as well and, therefore, what we use is actually being borrowed from future generations. It is only right that we pay them the right value, because any model like allocation or administered pricing only leads to under-pricing, which is inherently unfair and immoral. To maintain equity, the price must be the best that a molecule of gas can command, which cannot be less than the maximum opportunity value of the resource. This means the value must be set by “a price that is market determined in an environment, where an exchange is conducted in a transparent manner on an arm’s length basis”.

The CP further argues for the implementation of recommendations by end of the 12th Plan (by 2017). It also recommends an early announcement of the decision, so that it is visible and guides the investors who bid for blocks and explore for hydrocarbons.

Having recommended a free-market price, the CP delves into supply-side and demand-side reforms to ensure a smooth transition. On the supply-side, these include (1) closer interaction and credibility building with all stakeholders; (2) gas pipelines as “common carrier” infrastructure; (3) a transparent gas pricing mechanism to be developed by the Petroleum and Natural Gas Regulatory Board, for arm’s length transactions; (4) focused policies to expand gas supply; (5) setting, developing and encouraging gas trading on commodity exchanges, to create a mix of long-term, short-term and spot contracts; and (6) beginning by moving fields below 0.1 mmscmd to free-market and keep increasing this limit to larger fields.
On the demand-side, the CP recommends identifying and isolating the genuine priority-sector that needs fertiliser and power at subsidised rates, and supporting these by direct transparent and targeted subsidies. It also expects a major part of this shall be covered by increased “government take” resulting from higher gas prices. It suggests that the delivery mechanisms of such subsidies be debated and decided in advance through transparent process and the gas prices be increased in the interim period in a transparent and step-wise method to lower the differential between the market and subsidised price.

The CP also points out two subsidy lowering outlooks. Many analysts predict a bearish price outlook for market-price in view of the large unconventional production coming online and the decrease of subsidy when the beneficiaries are properly identified and selectively compensated. Hence, moving to free-market price may not be as much of fiscal burden as is imagined. Other recommendations involve inclusion of gas in GST and waiver of customs duty on LNG to accelerate the move to gas economy.

An important recommendation in the CP is the discontinuation of the gas utilisation policy, as well as the possibility of using oil-linked prices as an intermediate step-wise measure. The exploration and production industry also fully supports these recommendations.

On the producer side, private capital shall move overseas if the contracts are not honoured, fiscal terms are not stable and rewards are not in consonance with the risk on a globally comparable basis. There is also no doubt that administered pricing shall slow down domestic exploration and production, resulting in higher forex outgo and lower energy security.

On the consumer side, there is little doubt that the maximum resistance is over the sale price limitations for fertiliser, and price restriction as well as volume off-take formulas for power producers. These can be solved by targeted subsidies. Such resolutions leave no consumer objections unattended.

The real issue is whether the government reduces its subsidy by appropriating more gas at lower price (through naphtha, RLNG substitution) or increases the subsidy using the higher “government take” from increased prices. Taking the argument further, the ball is in the court of the finance minister—pay more subsidy and incentivise higher hydrocarbon production, i.e. pay now and reap tomorrow, or lower subsidy and increase imports, i.e. enjoy today and pay much higher later with the pious hope that you shall always have the capacity to pay and opportunity to buy.

Source: FE

ONGC puts Mahanadi blocks on back burner

The country's largest explorer, ONGC, has decided to defer development of its two deepwater blocks in the Mahanadi basin — MN-DWN-98/3 and MN-OSN-2000/2. The government- owned exploration firm discovered about 1 trillion cubic feet (tcf) of natural gas in these blocks, which are economically viable only at a gas price of $10.72-$12.63/mmBtu. The current price of domestic gas is $4.2/mmBtu. A director on the board of ONGC told FE that the explorer's focus was on monetising projects that can boost stagnant production at current prices at a faster rate than spending resources on deep water acreages, which require heavy investment and do not even yield returns.

ONGC drilled marginally more crude oil in Q1FY15 at 6.057 million tonne against 6.007 million tonne in the same quarter last year. On the other hand, natural gas output dropped 2.34% to 6.036 bcm in April-June FY15 against 6.181 bcm in the same period previous year.

The Manmohan Singh-headed UPA government had given a go-ahead to the Rangarajan-approved gas pricing mechanism, which would have doubled gas prices from the current $4.2/mmBtu. However, the present government is yet to implement a new pricing regime, deferring it till mid-November.

The ONGC director said the Maharatna’s focus was on projects including Daman, third- phase re-development of Mumbai High, KG-DWN-98/2 in the prolific KG basin and additional development of the South Bassein field in the Western offshore.

ONGC targets to ramp up its standalone gas output manifold to about 100 billion cubic metres (bcm) by 2022 against 23.28 bcm in FY14. According to analysts, the ONGC management has maintained its FY15 production guidance of 27.14 million tonnes for crude oil (up 4.4% year-on-year) and 25.34 bcm for gas (up 2% year-on-year).

“Delay in gas price hike is a concern, raising uncertainty for FY15/16 earnings,” said ICICI Securities in a recent report.
Both MN-DWN-98/3 and MN-OSN-2000/2 were awarded to ONGC in auctioning under Nelp. Earlier, the company, which made about four discoveries in both blocks, was aiming for integrated development. The declaration of commerciality (DoC) of the blocks were already submitted to the regulator,the DGH.

Source: FE