How Natural Gas is Changing the Energy Landscape in China

China is in a pickle. It is a pickle it is well aware of – and trying to fix – but a pickle nonetheless, as it tries to wean itself off coal and ramp up its natural gas consumption. So here are some of the trials and tribulations faced by the world’s largest energy consumer around natural gas:

1) China is the world’s largest power generator, and has historically relied on coal to meet approximately 65% of its electricity generation needs (accounting for a half of the world’s coal demand). Natural gas on the other hand, accounted for approximately 3% of China’s electricity generation mix in 2012.

2) Driven by its need to tackle rising carbon emissions and pollution, the Chinese government has accordingly set an aggressive target of meeting 10% of its total energy consumption from natural gas by the end of this decade. This means demand would triple from 2012 levels to 420 Bcm (14.8 Tcf).

3) Accordingly, China is set to lead global natural gas demand growth in the coming years. Non-OECD nations are to account for 85% of global natural gas demand growth from 2013-2019, with China accounting for a third of this.

4) China’s aggressive target is going to have to in part be met by imports, as China has just halved its shale gas production target from 60 – 100 Bcm (2.1 – 3.5 Tcf) to 30 Bcm (1.06 Tcf) by 2020. This would meet only 1% of China’s electricity generation.

5) The reduction in this production target is despite China having the largest technically recoverable shale gas reserves on the planet at 1,115 Tcf (31,600 Bcm). Problems arise in pursuing these reserves because they are in remote, mountainous regions, with a lack of infrastructure in place and at deeper levels than in the US. And this is all before addressing the issue of water scarcity.

6) Imports are in the form of both pipeline imports and LNG. China is expected to have 16 LNG import terminals operational by 2015, with 7 currently under construction. China received its first LNG imports in 2006, with pipeline imports starting in 2010:

7) There is some positive news despite the downward production revisions: drilling costs in China are down 35% from two years ago as Chinese operators join forces with North American services companies.

8) Regarding imports, Australia is China’s largest LNG supplier. This relationship will only strengthen given a number of joint ventures in place, and as Australia quadruples its LNG export capacity to become the world’s largest exporter (passing Qatar) by the end of the decade.

9) China is also making strides on the pipeline import front, with CNPC entering into a 30-year, $400 billion agreement with Russia’s Gazprom to receive 38 Bcm (1.34 Tcf) a year of natural gas from Siberia starting in 2018.

10) Nonetheless, China is attempting to meet the majority of its natural gas needs from domestic production by 2040: So there you have it – China’s predicament of being in a pickle. Regardless of how it meets its natural gas targets in the coming years – from domestic production or imports – the sheer increase is going to have considerable impact on the global energy landscape. Thanks, as ever, for playing!

Source: http://fuelfix.com/

Cairn gas at $8.4, RIL, GSPL may have to wait till September end

The likes of RIL and GSPL may have to wait till September-end to learn if they can charge more than $4.20 per unit of gas, but in a little-noticed development, Cairn India has been allowed to sell gas from its Rajasthan block at about $8.40 per unit to Gujarat based firms, including a fertilizer plant, since March 2013. 

Explaining the seeming anomaly, oil ministry officials said Cairn's production sharing contract (PSC), which was signed before the launch of the New Exploration Licensing Policy (NELP) in the late 1990s, allows pricing and marketing freedom to the company. In contrast, the PSCs of Reliance Industries and Gujarat State Petronet(GSPL) — applicable to blocks awarded under NELP — stipulated a higher level of government involvement, these officials said. Notably, the pricing formula for gas found in the NELP blocks has to be approved by the government. 

"There is no specific formula in the PSC signed with Cairn and the price discovered by the company does not require prior government approval, unlike under the NELP PSCs," an oil ministry official said. 

In June this year, the Cabinet deferred implementation of a gas pricing formula approved by the UPA regime that would have doubled the rate of most of the natural gas produced in the country to about $8.40 per unit from April 1 this year. Currently, gas is sold at rates ranging between $3.5 per unit and $8.40 per unit, according to government and industry sources. The UPA government had decided to have a uniform gas rate based on the formula suggested by the Rangarajan committee, but implementation of this policy was vetoed by the Election Commission as the general elections were underway. 

According to industry estimates, Cairn's gas fields are expected to produce about 7 million standard cubic meters per day (mmscmd) of gas, which is about half of the current output from the Reliance-operated KG-D6 block. Cairn is currently supplying 8-10 million standard cubic feet (mscf) per day of gas and plans to ramp up output from new reserves by financial year 2017, company sources said. It is supplying natural gas to consumers such as Gujarat Narmada Valley Fertilizers Company, Gail India, Gujarat Gas Company and CLP India, they added. 

A Cairn spokesman declined to disclose the price of gas produced in the Rajasthan block. "As per the guidance given in our Q1 FY15 filings, the average price realisation for gas across all assets is $5.6/mscf. The Rajasthan PSC (pre-NELP) provides for the sale of gas in the domestic market at prices obtained as per the arm's length principle," he said. Although Cairn's Rajasthan oilfield started commercial production of natural gas in small quantities in March last year, it recently announced that there was a substantial quantum of gas in the block.

Source: ET

Natural gas storage market

When it comes to natural gas storage Markets and Markets has said that it is playing a significant role in managing the reliability and security of supply. 10 years ago, when natural gas was a regulated commodity, storage was only seen as part of the product sold however, now that gas is deregulated storage is sought for commercial and operational purposes. Seasonal demand is the main use for natural gas storage at the moment and comes in two main forms, underground and above ground.

Underground

More gaseous forms of natural gas are usually stored underground in salt caverns, aquifers and depleted reservoirs. The growing demand for natural gas has been a major contributor to exploration and therefore the increased number of reservoirs available for storage purposes. Markets and Markets expect sound growth in the storage market due to this over the coming years. The Americas are tipped in the report as the largest market for underground storage. Last year, the Americas had the highest working gas capacity at 152 billion m2 and this is projected to increase by 158.6 billion m3 to 2019.

The CIS region follows the Americas in the underground storage stakes in the report. The region had a working capacity of 122.4 billion m3 last year and this is forecast to grow by 135.4 billion m3 by 2019.

Aboveground

When it comes to above ground storage, Markets and Markets has included LNG in its analysis. The Americas once again has the highest level, but this is when it comes to liquefaction capacity. The Asia Pacific is the region dominating the regasification market. Global LNG requirements are anticipated to increase over the next five years by 279.7 million tpy according to the report and by 2019, liquefaction capacity is anticipated to be 704.9 million tpy.

When it comes to regasification, the report highlights that Asia Pacific holds 306.8 million tpy and this is expected to increase to 764.7 million tpy by 2019.

Source: energyglobal.com

Hike gas prices now: Energy giants RIL, ONGC, BP, Cairn tell govt panel

Energy giants led by Reliance Industries, ONGC, BP and Cairn India today unanimously demanded an immediate hike in natural gas prices, saying current sub-market price of USD 4.2 was impeding development of over a dozen discoveries.

As the government began consultations with stakeholders on raising gas prices, gas producers and consumers met a committee of secretaries (CoS) separately with their pleas on the issue.

The panel, whose meeting was chaired by Power Secretary PK Sinha, gave a patient hearing to both sets and asked them to present their views in writing by 28 August.

Expenditure Secretary Ratan P Watal skipped the meeting of the CoS to which Fertilizer Secretary Jugal Kishore Mohapatra is member and Rajive Kumar, Additional Secretary, Ministry of Petroleum and Natural Gas, is member secretary.

Kumar said there will be another meeting of the panel this week.

According to sources, while gas producers said as many as 10 Trillion cubic feet of gas cannot be developed at current below market rate of USD 4.2 per million British thermal unit, power generators said they cannot afford a rate more than USD 5/unit.

Fertilizer makers too stated that doubling of rates, as had been approved by the previous UPA government before its implementation from April 1 was postponed first by the Election Commission and then by the new BJP government till September-end, would lead to increase in subsidy.

While producers, who were invited separately, attended in full strength with the sole exception of Gujarat State Petroleum Corp (GSPC), consumer sectors were represented by their associations - Association of Power Producers and Fertilizer Association of India, besides some individual companies.

Sources said producers gave 35 minutes of their unanimous view to the committee, which throughout the session was mostly listening and offered neither counter suggestion nor argument. Sinha suggested that the participants should send their written submission addressed to Oil Secretary Saurabh Chandra, who is not part of the committee, by Thursday morning.

The meeting was perfunctory with all operators in sync on issue of gas price except some vague remarks from state-owned Oil and Natural Gas Corp (ONGC), which acknowledged the fact that increase in gas price was required for both their existing production and new development but also mentioned that it was for the government to decide on a balanced rate.

Sources said producers reiterated that the sanctity of Production Sharing Contracts (PSC), which the government has entered into with them, should be maintained. The PSC provides for a market discovered gas price.

They also stated that the best option was the implementation of the 2006-07 recommendation of the Committee headed by PK Sinha, who was then Additional Secretary in oil Ministry, where it was stated that gas price should be discovered by asking consumers to bid. Sinha as Power Secretary is now taking of protecting interest of consumers.

Source: First Post

Fight climate change with natural gas

Today’s heated debates about natural gas production in the Marcellus Shale often boil down to a single issue: the environmental impact from fracking. But a troubling aspect of the divide over shale gas production is that its dramatic effect on reducing America’s carbon footprint is one that few people can discern.

To be sure, there are many reasons to favor horizontal drilling and fracking — thanks to this great technological innovation, natural gas production in the United States has increased as much as 27 percent since 2007 and the United States has eclipsed Russia as the world’s No. 1 gas producer.

The shale revolution has contributed greatly to America’s energy supply, produced a lot of revenue and jobs in Pennsylvania and other states, spurred a comeback in manufacturing, provided clean-burning fuel for transportation and bolstered our nation geopolitically. But don’t lose sight of its environmental benefits, which in less than a decade have been game-changing.

The shale revolution is generating real-world consequences in the battle against climate change. For anyone concerned about the release of heat-trapping greenhouse emissions that are warming the planet, the switch from coal to natural gas is already producing a host of good effects.

Here in Pennsylvania, coal accounts for 39 percent of the state’s electricity use, down from 48 percent in 2005, while the use of natural gas for power production has increased from 14 percent to 24 percent and is rising. Over the past decade, a reduction in airborne emissions of sulfur dioxide, mercury and other particulates from coal burning has improved air quality, with beneficial results for public health, especially the elderly and people with asthma and lung ailments.

Nationally, the switch from coal to natural gas is the principal reason carbon dioxide emissions have dropped to 1990s levels, according to the International Energy Agency. Indeed, the United States has taken the lead globally in cutting carbon emissions. Credit for this goes to the increased use of natural gas in power production.

How so? For each unit of energy produced, a megawatt-hour of natural gas-fired generation produces less than half the amount of carbon dioxide emissions as coal-fired generation.

Those who question whether the expanded use of gas for power production in the United States is sustainable, given the multiple demands on its use, should consider that natural gas resources in the United States are virtually inexhaustible. The U.S. Geological Survey reports that the United States has more than 100 years’ worth of natural gas. What’s more, geologists have only scratched the surface of potential shale resources. Most of the gas is still trapped in shale after initial fracking, and engineers are trying to come up with a practical and cost-effective way to reach it.

If replicated in other countries with sizable shale resources, fracking could stimulate a global shift from coal to gas. By making such technology available to countries like China, Australia and Argentina, which have sizable shale formations, further reductions in the world’s carbon emissions would become possible.

The Obama administration could be doing a lot more to show that it recognizes the crucial role of natural gas in carbon mitigation. While energy production on private and state lands has increased in recent years, it has declined on federal land. Particularly in western states like Nevada and Utah where much of the land is owned by the federal government, restrictive permitting policies for energy development are holding back natural gas production. This practice runs counter to the administration’s claim that it is serious about combating climate change.

We need action at all levels of government to ensure that the percentage of low-carbon power generation is growing sufficiently to stave off the worst effects of climate change. Encouraging the production of natural gas — and its export for use in other countries — is probably the single most effective way to do that.

Source: post-gazette.com

Natural gas serves growing portion of Chinese energy demand

According to the US Energy Information Administration (EIA), China relies heavily on domestic coal to meet rising energy consumption. In order to reduce air pollution and carbon dioxide emissions, the Chinese government is attempting to replace some of the country’s coal and oil use with natural gas.

Natural gas accounted for only 4.9% of China’s total energy consumption in 2012, but large investments in domestic natural gas production and infrastructure, along with growing imports, are likely to underpin a significantly larger role in the future. The government anticipates increasing its natural gas share of total energy consumption to approximately 8% by the end of 2015 and 10% by 2020.

China has more than triples natural gas production since 2003, producing 3.8 trillion ft3 in 2012. The government is targeting production to reach approximately 5.5 trillion ft3/y of natural gas by the end of 2015. Most of the anticipated production growth is from large onshore fields in the eastern and north central regions of China as well as from offshore deepwater regions in the South China Sea.

China’s natural gas consumption has outstripped domestic supply since 2007, leading to rising imports of LNG and pipeline gas. China’s natural gas consumption rose at an average annual rate of 17% from 2003 through 2013, reaching nearly 5.7 trillion ft3 in 2013.

The EIA highlights that China imported nearly 1.8 trillion ft3 of LNG and pipeline gas in 2013. Imported natural gas met 32% of China’s demand for the year, up from 2% in 2006. China is rapidly developing its LNG import capacity in the urban coastal areas and currently has 10 major regasification terminals with 1.7 trillion ft3 capacity.

In 2013, China rose to become the third largest LNG importer in the world, after Japan and South Korea, and in 2013, the country imported 870 billion ft3 of LNG. Estimates for the first half of 2014 show LNG imports growing at faster levels than in previous years.

China is also increasingly investing in natural gas pipeline infrastructure that will link production areas in the western and northern regions to demand centres along the coast. This new infrastructure will accommodate greater imports from neighbouring countries.

In 2010, the first pipeline imports from Turkmenistan flowed to China through the Central Asia Gas Pipeline (CAGP), and by 2013 natural gas supplies from Turkmenistan, Uzbekistan and Kazakhstan reached 974 billion ft3.

China and Russia recently finalised a natural gas agreement that allows China to purchase and transport gas from eastern Russia through a proposed pipeline. The deal, valued at US$ 400 billion, will supply China with up to 1.3 trillion ft3/y of natural gas, starting in 2018.

Source: energyglobal.com

Russia-China deal will supply Siberian natural gas to China’s northern, eastern provinces

China's natural gas demand has been growing as the government seeks to move away from coal in favor of cleaner fuels. According to EIA's International Energy Outlook 2013 (IEO2013) Reference case, demand will more than triple from 5.2 Tcf in 2012 to 17.5 Tcf by 2040.

Russia's largest natural gas company, Gazprom, finalized a deal with the Chinese National Petroleum Corporation (CNPC) in May. Under the first phase of the new 30-year contract, Russia will supply China 38 billion cubic meters (bcm), or 1.3 trillion cubic feet (Tcf), per year of natural gas starting in 2018. Future phases could increase this volume to as much as 60 bcm (2.1 Tcf) per year. The contract links the natural gas price to international crude oil prices and operates as a take-or-pay scheme: the buyer, CNPC, must pay for the contracted natural gas even if it decides not to receive it.

New natural gas production in Russia will mainly come from fields in eastern Siberia, which currently lack export infrastructure. The planned Power of Siberia pipeline will export gas south to China and east to a liquefied natural gas (LNG) plant on Russia's east coast.

This contract is Gazprom's largest to date. Gazprom has a monopoly on pipeline natural gas export contracts made by Russia. The situation differs from that in LNG markets, where other companies such as Rosneft and Novatek may participate.

China's northern and eastern provinces have growing natural gas demand that cannot be met by existing pipelines or LNG, and the new Russian natural gas will mostly go to meet demand in these regions. China has also committed to purchasing 38 bcm (1.3 Tcf) per year of natural gas from Turkmenistan by 2016, increasing to 65 bcm (2.2Tcf) per year by 2020.

Although China continues to import more LNG, the government is committed to expanding Chinese domestic production, which increases from 4 Tcf in 2012 to 10 Tcf by 2040 in the IEO2013 Reference case. Developing China's shale gas reserves is also an important part of the government's natural gas strategy. According to EIA's assessment of world shale gas resources, China has 1,115 Tcf of technically recoverable shale gas. New production along with imports of LNG will meet rising demand in China's eastern and southern coastal regions

Source: EIA

RIL partner Niko Resources demands market-linked gas prices

Canadian energy explorer Niko Resources Ltd (Niko), a partner of Reliance Industries Ltd in the D6 block of the Krishna-Godavari (KG) basin, has asked the Indian government to allow a market-linked price for gas produced from the field. Niko told shareholders late on Thursday, when it released its latest financial results, that it had sought a market-linked gas price in line with the production sharing contract signed with the government. “The company has provided input to the GoI (Government of India) about the requirement for market price for natural gas sales as per the production sharing contracts awarded during the New Exploration Licensing Policy rounds and the fundamental principle of sanctity of contract as a required underpinning for long-term investments in any country,” Niko said in a statement. 

Niko added that RIL and its partners will not make any further investments in the absence of market-linked pricing. In June, as part of its annual earnings statement, Niko said investments would be deferred until there was clarity on gas pricing, but had stopped short of demanding a market-linked price. Niko is a 10% partner in the D6 block operated by RIL in which British oil and gas firm BP Plc. is a 30% partner. 

RIL did not immediately reply to an email sent on Friday morning. Friday was a holiday on account of Independence Day. On 25 June, the National Democratic Alliance (NDA) government said that a decision on gas pricing is likely by 1 October. An earlier decision to hike gas prices taken by the United Progressive Alliance (UPA) government was put on hold due to the election code of conduct ahead of the general election. According to the formula approved by the UPA government, the price of domestic gas was to be doubled to $8.4 per million British thermal units (mmBtu) from 1 April. The change in prices was based on a formula suggested by a committee headed by C. Rangarajan. After the gas price hike was put on hold, RIL slapped an arbitration notice on the government on 6 July. “While the company is disappointed with the progress on gas price hike, the contractors (D6 partners) under protest but in good faith, have kept supplying the gas to customers and charging them for the gas supplied under the terms of the sales contracts that expired on 31 March 2014, that is, at $4.2 per mmBtu,” said Niko in its earnings statement. Analysts said the company was trying to keep up the pressure on the government. 

“The PSC allows for arm’s length gas pricing which means that the prices have to be determined between two players—the buyer and the seller—and the government will have no say in it. But the ball is now in the government’s court and it cannot allow a market-linked price,” said Dhaval Joshi, an analyst Emkay Global Financial Services Ltd. According to Platts, a global energy research firm, the price of liquefied natural gas in the global spot market had gone up to $20 per mmBtu in December 2013. The price has now come down to $10 per mmBtu. An analyst at an international brokerage, who requested anonymity, said the long-term price of imported gas is currently hovering around $12-13 per mmBtu—still higher than the price calculated on the basis of the Rangarajan formula. Apart from the arbitration over gas pricing, RIL and its partners have challenged the government’s move to disallow cost-recovery from the D6 block for falling short of production targets. 

Between fiscal 2011 and fiscal 2014, the government disallowed cost-recovery of $2.38 billion. RIL is currently producing just about 8 million standard cubic metres per day (mscmd) from the D1 and D3 fields—a part of the D6 block and the only two producing fields in the KG basin, which were discovered to have substantial resources of gas in 2002. This is against the original stated target of 80 mscmd.

Source: Livemint

Natural gas 'greener, more efficient' says Foster as plans move closer

Northern Ireland Energy Holdings and Scotia Gas Networks are the preferred applicants for new licences to take forward a £200 million project to extend natural gas to the West.

This follows the publication yesterday of the Utility Regulator’s consultation on the ‘preferred applicants'.

Up to £32.5million has been granted by the European Commission for the Northern Ireland Executive to support the licensees in constructing the main pipelines within the project.

In a statement, Enterprise Minister Arlene Foster said extending the gas network to the West will offer natural gas to up to 40,000 business and domestic consumers.

“As the cleanest burning fossil fuel, natural gas offers a greener, more efficient and convenient alternative to oil and coal. It will help to lower manufacturing and production costs for companies and improve business competitiveness.

“In addition, it will provide domestic consumers with greater choice and benefits such as easier budgeting of energy costs by opting for a gas pre-payment meter,” said Minister Foster.

The Minister added: “Once the Utility Regulator’s competition is complete, I look forward to the formal award of the new gas conveyance licences which will allow the developers to obtain planning and other consents. I hope to see the start of works on the ground to provide the new gas networks as soon as possible.”

It's understood Quinn Glass in Derrylin could be one of the first local companies to switch to gas.

Source: impartialreporter.com

Rediscovering India’s oil & gas reserves

Technologies such as time-lapse seismic (4D) and advanced spectral decomposition can help produce additional oil and gas, extending the economic life of our fields

Imagine the quality of life today if the mobile and internet technologies had been used as widely in India during 1960s as they are being used today. Exploring sedimentary basins for oil and gas is a long process of elimination. Based on data gathered, one eliminates areas where conditions for accumulation of oil and gas did not exist, to zero in on areas where conditions existed, of course millions of years ago. To gather geotechnical data, deploying latest technology and tools are critical.

What were the technology and tools India used during the 1960s to explore for oil and gas? I asked a good old geologist, who served ONGC for over 30 years, and this is what he said, “those were the days when western countries remained completely indifferent and unsupportive. The only country that extended support to our oil and gas exploration efforts was former Soviet Union and the tools we had to use were naturally outdated even then.”

During the 1970s, three-dimensional (3D) seismic surveys entered the oil and gas sector with a big bang and changed it forever. This one technology doubled the Probability of Success (PoS) in exploration, decreasing the risk significantly. It opened up global offshore exploration in a big way.

Offshore seismic survey triggers an artificial seismic event (small earthquake). A survey vessel (ship) towing a network of cables usually employs airguns to release compressed air pulses into the seawater which travel to the sea floor. Seismic energy so generated in the form of sound waves pierce through the water column and formations of the earth’s outer surface. Later, it reflects back to the surface of the water where it is recorded by a set of hydrophones. The reflected sound waves convey information about the terrain’s structure. Collected data is then analysed to construct a 3D image of the subsurface. This 3D image aids a geologist in the same way an ultra-sound image aids a physician.

Appreciating the importance of 3D seismic surveys to the success of offshore hydrocarbon exploration, several countries acquire wealth of multi-client seismic data and provide easy data access to international energy companies to attract risk investment. But these best practices are yet to be adapted by India.

One of the oil and gas fields in India where application of best-in-class discovery and recovery technologies have paid rich dividends is the Ravva oil and gas field. The word ravva in Telugu means diamond; the field, discovered in 1987 and brought into production in 1993, has so far produced over 250 million barrels of oil and 300 billion cubic feet of gas, more than double its initial estimates. In today’s prices, that is cumulatively worth over R1,50,000 crore ($25 billion).

Staged and appropriate use of geophysical technologies and multi-disciplinary integration has helped in extending the life of this field. As a result, Ravva oil and gas field is set to achieve a recovery rate more than 50%, while the average for other fields in India is less than 35%. This will be a unique distinction that India needs to be proud of. Let us look at just two technologies applied that made a difference and added significant value to all the stakeholders.

Time-lapse seismic (4D) technology

4D seismic is an advanced method of acquiring, processing and interpreting repeated 3D seismic surveys at different time stamps. 4D technology brings fourth dimension (time) for identifying areas of bypassed oil reserves. A 4D OBC seismic survey was carefully planned, executed and interpreted on the Ravva field, first time in India. This was achieved with the systematic implementation of a 4D workflow from feasibility study to the multi-disciplinary interpretation in order to identify the unswept oil and gas pools. The 4D seismic technology also helped in optimisation of reservoir management plan and in placing the new infill wells successfully.

Advanced spectral decomposition technology

Ravva main reservoirs middle miocene are overlaid by thin late miocene reservoirs. These are thin and isolated reservoirs that are difficult to map using conventional seismic interpretation methods. Spectral decomposition is an invaluable tool for imaging and mapping thin bed reservoirs and revealing seismic geomorphology. This technology was applied in Ravva and attributes at different frequencies computed, co-blended and visualised using advanced 3D visualisation environment to highlight the thin channels and their geometries. These channels were subsequently drilled as secondary targets in the infill drilling campaigns to achieve incremental production.

The objective behind deploying these technologies is to identify bypassed oil and gas pools and thin isolated oil and gas filled channels in order to drill and produce them so that the economic life of the field gets extended.

Over the last 10 years, India could drill on an average less than 600 wells in a year, against over 20,000 wells being drilled very year in Canada alone, and there are more than million wells on production in the US. While the Indian sedimentary basins spread across a 35 lakh sq km area, 3D seismic surveys have so far been conducted in less than 15% of the area only and 4D seismic survey has been done only in Ravva. Interestingly, out of the total of 5 lakh sq km area covered by 3D, more than 50% has been carried out post the entry of private players into the sector.

India has over 450 oil and gas producing fields, some of them commenced first production during the 1960s when none of the above technologies existed. But today they are available and have been successfully deployed in multiple fields around the world.

The questions to be asked and answered are: (1) Why the exploration activity in the country is so low? (2) Why is there a reluctance to deploy proven discovery and recovery technologies? (3) How much funds are being allotted for R&D in upstream oil and gas sector that holds the potential to transform the country?

India holds over 750 million metric tonnes of oil and over 1,300 billion cubic metres of gas reserves. Imagine the benefits to the country if these technologies could be deployed across all the appropriate producing fields to improve the recovery factor by a modest 5%. Such an increase in the recovery rate would enable us to produce additional oil that would be slightly more than the current annual domestic oil production.

Source: FE

The World's Largest Natural Gas-Powered Ships Are Almost Ready to Sail

Getting a fully-laden cargo ship across an entire ocean requires enormous amounts of energy—usually derived from pollutant-rich diesel fuel. But one environmentally-minded shipping company has bucked that convention and instead begun construction on a pair of hybrid containerships—the first of their kind—that run primarily on cleaner burning liquefied natural gas.

The 3,100 TEU Marlin-class containerships are currently under construction at the General Dynamics' NASSCO shipyard in San Diego for TOTE Shipholdings. These $350 million vessels will measure 764 feet in length when completed late next year, making them the largest ships primarily powered by LNG ever produced. They're not the only LNG-powered ships on the sea mind you, more than 40 LNG-powered vessels are already operating around the world but the Marlins will be the first to use the fuel for hauling cargo.

Each Marlin-class ship will utilize a 8L70ME-GI gas-injected, dual-fuel, low-speed diesel engine capable of running on either conventional fuel oil or LNG. When burning natural gas (stored in the 380 ton cryogenic tanks shown below), the ships are expected to produce 98 percent less sulfur oxides, 71 percent fewer nitric oxides, 71 percent less carbon dioxide, and a jaw-dropping 99 percent reduction in particulate emissions, all while increasing the vessels' fuel efficiency compared to conventional diesel engines. What's more, these ships will carry 60 percent more cargo per trip than TOTE's current class of Sea Star ships and also include a ballast water treatment system to prevent the introduction of invasive species.

Once completed, the ships will operate out of Jacksonville, Florida, transporting goods to and from San Juan, Puerto Rico. If these Marlins prove successful, TOTEs has the option to build three more in the coming years. Hopefully, the rest of the maritime shipping industry will follow suit.

Source: gizmodo.com/

India approves pricing parity between CBM and natural gas

The Indian government has agreed to a proposal for coal bed methane (CBM) operators to price their production on par with domestic natural gas, an official in Ministry of Petroleum and Natural Gas said.

However, the pricing parity would only be effective after the government revised natural gas pricing, which has been hanging fire in the last year, the official said.

The price parity approval would be effective in the case of three CBM operators, Great Eastern Energy, Essar Oil and ONGC Limited. The approval in the case of Reliance Industries Limited (RIL) has been withheld with the government seeking additional information from the company.

Great Eastern Energy operated the Raniganj South block, Essar Oil the Raniganj East block and ONGC, Jharia block, all in eastern India.

The operators would have to price CBM on par with domestic natural gas only after the government was able to finalize revision of gas prices, the official said.

While the final price of natural gas was yet to be decided by the government, it was likely that an uniform gas price, irrespective of source, would force CBM operators to lower their prices since most of them were charging a rate higher than current natural gas price of $4.2 per million British thermal unit (mBtu).

CBM operators’ prices ranged between $8/ to $22/mBtu and would have to lower it considering that it was unlikely that the present government would agree to doubling of natural gas price to $8.4/mBtu.

The previous Indian government had announced doubling of natural gas prices from current rate of  $4.2/mBtu effective from April 2014.

This was, however, kept in abeyance by the Election Commission of India in view of the national elections and at the same time, the sharp hike in natural gas prices has been entangled in political and legal challenges.

The new Indian government, on assuming charge in May, opposed the gas hike proposals of the previous dispensation and set up a new panel to frame a gas pricing mechanism within August 31. The ministry has set a deadline of October 01, to complete fresh consultations with various stakeholders and announce a higher gas price.

This in effect scrapped the recommendations made by two previous panel based on which the previous government had finalized doubling of gas prices.

In a related development, the Petroleum and Natural Gas Ministry has identified ten CBM blocks to be put up for auction for bidding by private operators. Six of the blocks were in western Indian province of Gujarat, two in Madhya Pradesh in central region and the rest in Maharashtra.

As on date, 33 CBM blocks had been awarded for exploration through competitive bidding of which eight have been declared under development with total established reserves of 9.9-trillion cubic feet.

According to ministry data, coal bed methane production in the country during April-June 2014 was estimated at 0.58-million standard cubic meters per day and forecast to increase to four-million standard cubic meters a day by 2017.

Source: miningweekly.com

Fifth India-US Energy Summit to focus on renewable energy

Renewable energy and energy security would be the focus of the two-day annual India-US Energy Summit to be held in Washington next month.

Noting that energy security is critical for both the US and India, Dr R K Pachauri, president of The Energy and Resources Institute, North America (TERI), said the two countries must work together, both in energy security as well as on policy fronts, so as to bring in some positive changes.
The two-day event from September 30, being organised by TERI and Yale University, is likely to be attended by top officials and energy experts from both the countries.

Prime Minister Narendra Modi, who is expected to be in the city to meet President Barack Obama, has been invited to address the meeting in energy, a subject close to his heart.
According to a TERI statement, the focus of the Summit will be on bilateral cooperation in the energy sector and related areas.

"Energy security is critical for both the US and India," Pachauri said.
"The recent geo-political developments in the region from where we import the bulk of our oil, can lead to a drastic increase in oil prices. The devaluation of the rupee has added to the crisis. But I am confident that we are on the cusp of change in the use of our renewable energy resources," he said.
"We should be investing more on renewable energy sources in the coming years. India and the US must work together, both in energy security as well as on policy fronts, so that we can bring in some positive changes," Pachauri said.

Hosted annually since 2009 by TERI North America and Yale University, the fifth US-India Energy Partnership Summit will broadly look at 'Accelerating Resilient Growth and Development', while addressing various issues related to energy efficiency, security, access and technology.
Stakeholders from various sectors will discuss new collaborations in clean technologies and renewable energy, green buildings and sustainable cities, decentralized energy access, alternatives such as shale gas, etc.
Climate change will also form a key component of the discussions, with the proceedings at the General Assembly and Climate Summit providing significant inputs to the Summit deliberations, the statement said.

Source: BT

Open acreage licensing policy regime to take time

India will have to wait for at least two more years to unveil the open acreage licensing policy (OALP) regime to explore hydrocarbons. This is because the pre-requisite for launching the open acreage model — the national data repository (NDR) — will take two more years to be functional.

The contract to set up the NDR has been bagged by HLS Asia (HLSA), which has foreign collaboration with US-based Halliburton Energy Services. The company was awarded the contract in March this year. It will take a year to set up infrastructure and another year to feed data into the system, said officials at DGH.

To make India a favourable destination globally for exploration and natural gas, the government plans to move to the OALP regime soon. This will enable upstream companies to bid for any oil and gas block without waiting for the announcement of bidding under the new exploration licensing policy (NELP) regime. The idea was floated many years ago when Murli Deora was petroleum minister.

The NDR would be hosted at the DGH office in Noida. The government had amended Rule 19 of the petroleum and natural gas rules to enable DGH to obtain all the data from various operators or licensees, which could be disclosed to prospective bidders as and when required under the open acreage system.

Open acreage will enable bidders to bid for blocks on offer at any time of the year. 

Data for the blocks will be made available to bidders through NDR. Pakistan also has such a system in place. The NDR is expected to play a much larger and significant role in the exploration and production scenario in the years to come. The NDR will also facilitate gathering of all geo-scientific data available in India under one roof so that it is easily available to the agencies that require it.

Source: FE

India eyes $40-bn pipeline from Russia to import gas

In a move aimed at ensuring India’s energy security, the Narendra Modi-led government plans to import huge volumes of natural gas from Russia. The Centre is working out the contours of a $40-billion (Rs 2.4 lakh-crore) mega onland pipeline project carrying gas from Russia to India, in one of India’s biggest energy projects till date.

Top government officials told HT that the move follows Prime Minister Narendra Modi’s recent meeting with Russian President Vladimir Putin in Brazil on the sidelines of the Brics summit.

The Prime Minister’s Office (PMO) along with the ministry of petroleum and natural gas are preparing a blueprint to examine the feasibility of this new project, they added.

An announcement on this initiative is expected to be made in December when the two leaders meet at the India-Russia annual summit to be held in New Delhi.

China has already finalised a similar gas pipeline deal with Moscow for importing gas. New Delhi, sources said, also plans to import crude oil from Moscow and the logistics for the same are being worked out.

“Russia so far has directed majority of its oil and gas supplies to the West… however, the scenario may be quiet different in the coming years especially in the wake of its gas pipeline to China and the one now proposed till India,” a senior oil ministry official said.

Two routes are being considered for the gas pipeline project. One is from Russia’s southern border to India via the Himalayas and the second from Russia - Astrakhan - Khazakstan — Uzbekistan and then along the Turkmenistan-Afghanistan-Pakistan route to India (TAPI gas pipeline).

The proposed project from Russia to India is almost four times the cost of  the $10-billion (or Rs. 60,000-crore) Iran-Pakistan-India (IPI) gas pipeline project, also called the peace pipeline, which has failed to take off due to security concerns over the pipeline traversing through Pakistan and has been on the drawing board for the past many years.

“This government (under Modi) is taking all steps that will lead to a reduction in India’s oil import bill... apart from this proposed pipeline, reviving and pushing the other two projects — IPI and TAPI are also being looked into at the highest level,” he added.

The cost of the other onland gas pipeline project from Turkmenistan to India via Afghanistan and Pakistan (or the TAPI) project is also close to $8-10 billion.
GAIL India Ltd will be associated with this project along with a consortium of other state-owned oil and gas companies including Oil and Natural Gas Corp (ONGC), Oil India Ltd and Indian Oil, the official said.

Source: HT

Gas price review likely to cover uniform pricing

In its review of gas pricing guidelines based on the Rangarajan formula, the government is likely to also examine the issue of a proposed uniform price.

Since there are various regimes applicable to gas pricing in the country, a committee under C Rangarajan, then chairman of the Prime Minister's Economic Advisory Council, had favoured a uniform price. It had argued that the basic difficulty in valuation for determining the government's share was that there was no single gas price.

The panel he chaired had proposed a formula that would have doubled the price of domestic gas to a single rate of $8.4 for every million British thermal units (mBtu), to apply equally to all sectors regardless of their prioritisation for supply under the Gas Utilisation Policy.

The new government had decided to put the implementation of this recommendation on hold till September 30, pending a more detailed examination. However, petroleum minister Dharmendra Pradhan has denied any move to set up another committee for reviewing the Rangarajan guidelines. "These are mere speculations," he'd told Business Standard.

India's domestic natural gas production is divided in three broad categories: APM (administered price mechanism) and non-APM gas from nominated fields of national oil Companies; pre-Nelp (New Exploration Licensing Policy) gas; and Nelp gas. These different categories are being allocated under diverse gas utilisation policies and at different prices.

India consumed 121 million standard cubic metres a day (mscmd) of natural gas in 2013-14. That comprised 48 mscmd of APM gas (at $4.2 a mBtu), 7.5 mscmd of non-APM gas from nomination fields (at $4.2-5.2 an mBtu), 13.5 mscmd of Nelp gas (at $4.2 an mBtu), 10 mscmd of pre-Nelp gas (at $3.5-5.7 an mBtu), 41 mscmd of R-LNG (regasified liquefied natural gas, at $12.9-17.4 an mBtu) and 0.3 mscmd of CBM (coal bed methane) gas (at $5.1-6.7 an mBtu).

Some experts say it might be feasible but not sensible to have a uniform gas price. "Gas prices have to be attractive enough for supporting long-term exploration activities. Also, the cost of production varies widely between on-shore and off-shore areas," R S Sharma, former Oil & Natural Gas Corporation chairman, told Business Standard.

He said another argument against the move is that there is demand for gas priced at a high rate of $15 an mBtu. "Even city gas distribution is viable at this price. Buyers are willing to pay. So, why not have differential pricing?" he asked.

However, many experts also do share Rangarajan's views on the benefits of uniform pricing. "Any non-uniform pricing becomes discretionary, both in deciding the prices and allocation of the output," said Debasish Mishra, senior director at consultancy firm Deloitte. "Rather than debating whether gas pricing should be uniform or non-uniform, we should debate how soon we should move to market-determined pricing." Only the latter, he said, would be able to attract fresh investment in domestic exploration and production.

The earlier government had on January 10 notified a new domestic gas pricing regime based on Rangarajan's formula. However, general elections were announced before the new price could be formally announced. The Election Commission asked it to leave the decision to the new government and revision of rates was put off to July 1. The new government decided on June 25 to defer a decision until October, pending wider consultation.

Reliance Industries (RIL), operator of the eastern off-shore KG-D6 block, and its partners, BP of the UK and Niko Resources of Canada, had on May 9 served a pre-arbitration notice on the government, alleging the failure to implement the earlier decision on a gas price rise effective April 1 was preventing the sanctioning of investments of around $4 billion.

This was followed by a formal Notice of Arbitration, served on June 17 by RIL-BP-Niko, naming London-based David Steel as their arbitrator. A month later, on July 17, the government appointed former Supreme Court judge G S Singhvi as arbitrator on its behalf, formally joining the process.

Source: BS

Natural gas is best energy alternative

A conviction that has guided President Barack Obama's energy policy since he took office is that solar and wind power, rather than natural gas, is the way to reduce U.S. greenhouse emissions.

It's a way of thinking that reflects his close bond with the environmental community, which shares his preference for investing in renewable energy sources and conservation in the battle against global warming.

In a United Nations accord in 2009, Obama pledged that the United States would cut its greenhouse emissions 83 percent from 2005 levels by 2050. To achieve that difficult goal, the administration endorsed tax credits for wind energy, and a big increase in research and development funding for a spectrum of renewable sources, especially solar energy. Concurrently, 30 states, including New Hampshire, adopted renewable electricity standards requiring investor-owned utilities to produce a share of their power from renewable sources according to a set timetable, typically by 2020. But renewable sources have fallen short of expectations, outpaced by plentiful and cheap natural gas.

A case in point: Just a half decade ago, during the turmoil of 2008, it was widely assumed that a permanent era of energy shortage was at hand. But due to innovative drilling in the Marcellus, Utica and other shale formations, unconventional gas production has jumped from 2 percent of domestic gas production a decade ago to 37 percent of supply today. This is a game-changer that's led not only to environmental gains, but also the creation of 1.7 million jobs across the United States, including in states with no shale gas production such as those in New England and New York state.

Thanks to the shale revolution, the United States has an abundance of natural gas that is replacing coal in electricity production. Whereas solar and wind power combined currently account for less than 5 percent of the nation's electricity, natural gas accounts for more than 30 percent of America's power supply (and 36.5 percent in New Hampshire) — and its growing use is credited with playing the most significant part in a 13 percent drop in U.S. carbon emissions since 2007.

What's most notable about this success is that the decline in carbon emissions is likely to continue as power production shifts to greater use of natural gas, which has roughly half the carbon content of coal. To be sure, coal and nuclear power will remain part of the energy mix in New Hampshire and nationally, though at a reduced level compared to natural gas.

The fact that the United States has an abundance of natural gas is due largely to the use of an innovative technology that combines hydraulic fracturing, or "fracking," with horizontal drilling in shale production. Estimates of recoverable natural gas reserves have more than doubled since 2005, and this has already had a major impact on electricity production, making the fuel more attractive to utilities.

Although solar and wind are emission-free, adding a new combined-cycle gas plant to the electric grid is less costly and more reliable. Today, scores of natural gas plants are being used, along with nuclear power and coal, to provide "base-load" electricity 24/7, whereas solar and wind energy are only available when the sun is shining and the wind is blowing. According to the Energy Information Administration, wind energy has a capacity factor of 32.3 percent and solar energy is even less, at 27 percent. In the years ahead, demand for electricity will grow as our economy becomes increasingly digitalized and improvements to our nation's infrastructure begin. So over-reliance on undependable solar and wind power would be problematic at the very least. Without greater reliability and new technology for large-scale electricity storage, the contribution to our power supply from renewable sources will continue to be relatively small.

Natural gas plants on average operate well over 50 percent of the time, and some at much higher capacity factors. We need to recognize the value of natural gas as a cornerstone of environmental policy, especially its benefit in reducing greenhouse emissions. However, if we fail to make use of what actually works in the real world rather than base energy policy on incorrect assumptions about renewable sources, we will wind up squandering government funds on the wrong energy approach.

Source: seacoastonline.com