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Aug 2015

The gigantic modernization project will be hostinga  number of configuration changes in the existing refinery, along with 6 new units and 4 revamps.
 -- A new CDU of 9.0 MMTPA in lieu of one existing CDU (New configuration : new CDU-IV of 9 MMTPA and existing 2 CDU’s of total 6 MMTPA).
 -- A new Slurry Hydrocracker unit (SHCU) of 2.5 MMTPA
 -- A new Solvent Deasphalting unit (SDA) of 3.1 MMTPA
 -- A new Full Conversion Hydrocracker unit (HCU) of 3.3 MMTPA
 -- A new Isomerization unit (ISOM) of 292 KTPA
 -- A new Propylene recovery unit (PRU) of 96 TPD
 -- Revamp of the Diesel Hydro Treater (DHT) unit to achieve an improvement in capacity of up to 2.64 MMTPA (20% increase)
 -- Revamp of the Continuous Catalytic Cracker (CCR) unit.
 -- Revamp of the Naphtha Hydro Treating Unit (NHT)
 -- Provision for an Alkylation unit (200 KTPA) is also being considered for transition to BS-V norms for MS.
 -- Revamp of the existing NHT and CCR is also in the plan.
 Click on the Reports section for more. Details
HPCL plans to go ahead with a massive modernization project in its Visakha refinery in Andra Pradesh, at a whopping cost of Rs 18412.24 core.
 8As a part of Visakha refinery modernization project (VRMP), the gas major wants to exapnd the capacity of the refinery from the existing 8.33 MMTPA to 15 MMTPA.
 8The residue up-gradation and quality improvement of MS and HSD will also be taken up as a part of the modernization project.
 8The new units are proposed to be located within the refinery and plot area available adjacent to refinery.
 The locations for the project are:
 -- Within existing refinery premises
 -- Contiguous area on the east side of the existing refinery (after re-siting the HPCL Marketing Terminal and the LPG bottling plant).
 -- One plot leased from the Visakhapatnam Port Trust (VPT) on the north ofthe  existing refinery (near HPCL's additional tankage project).
 Click on the Reports section for more. Details
All the aforesaid four dock-lines were constructed as non-piggable lines. These lines were originally laid between 1985 and 1998 and over the years across the line routes particularly on the underground portions, habitations have come up.
 8Over the years, in and around the pipeline route between Korukkupet Terminal and Foreshore Terminal habitations have come up and road infrastructure has also developed over the pipelines and it has become extremely difficult to have access to the underground segments.
 8Hence, maintenance of the underground portion of the lines between Tondiarpet R.S/Korukkupet Terminal and port entry (UG segment) have became extremely difficult. Despite line withstanding enhanced hydrotesting annually but still in case of a minor leak, it becomes very difficult to locate and take corrective action.
 8Aso, these lines were not designed and constructed as piggable and thus taking up periodic integrity assessment study is not feasible. Hence IOC has proposed to replace the UG portion of the pipeline with piggable line for safe and reliable operation.
 8The pipeline will be design considering the loading and unloading of tanker parcels which have to be handled with optimal time and accordingly a flow rate of 1500 KL per hour for 20” W.O line, 600 KL per hour for 14” B.O lines and 200 KL per hour for 12.75” Lube line.
 8The present throughput per annum is 1.1 MMTPA for W.O products, 0.7 MMTPA for B.O products and 0.3 MMTPA for Lubes.
 Click on Reports for details. Details
To take care of the refinery expansion, a new flare system has been considered and it will be independent from the existing flare system.
 8The existing refinery has in place two flare systems:
-- VREP II: 698.5 TPH (HC flaring), 13 TPH (Acid Gas Flaring)
-- VRCFP: 491 TPH (HC flaring), 15 TPH (Acid Gas Flaring)
 8Steam injection facility to maintain adequate steam to fuel ratio is provisioned to achieve smokeless operations in both existing and new flares.
 8Moreover,the  flare stack height will be restricted to 60 m. However, all the stack details including that of flare will be worked out during the design stage only since this will depend on data from Licensors.
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The final products from the refinery post VRMP will be LPG, Propylene, Naphtha, ATF, Kerosene, MS, Diesel, Light Diesel Oil, LDO, Bitumen and few others in small quantities.
 8Detailed shipment facilities of all products are as follows:
 8MS-Diesel-Kerosene: The main evacuation source of the three major products (MS, Diesel and Kerosene) fromthe  refinery is through the 572 km Vizag Vijaiwada Secunderabad cross country pipeline. The design capacity of the pipeline is 5.380 MMTPA.
 8LPG-Propylene: Since no new LPG/ Propylene bullets have been proposed in the  VRMP, existing shipping lines going to the new marketing terminal from the refinery (Max 1.0KM) will be utilized post modernisation.
 8Naphtha: Since no new naphtha tanks have been proposed in the VRMP, the existing facilities will be utilized post VRMP also.
 8ATF-LDO-MTO-JBO-LSHF HSD-Fuel Oil- Bitumen: Post VRM,P the existing facilities will be utilized.
Click on the Reports section for more.
   Details
8List of existing units along with their capacities are as follows:
 -- Three crude distillation units ( 8.33 MMTPA),
 -- MS Block (NHT-1.154 MMTPA ,ISOM-0.229 MMTPA, CCR- 0.769 MMTPA, FCC NTT- 0.89 MMTPA ),
 -- Diesel Hydro desulphurization unit( DHDS- 2.43 MMTPA ),
 -- Two Fluidized catalytic cracking units( FCC UNIT-I :1.187 MMTPA, FCC UNIT-II : 0.967 MMTPA),
 -- Diesel Hydro-treating unit (DHDT- 2.2 MMTPA),
 -- Visbreaker unit (1.0 MMTPA),
 -- Bitumen Blowing unit (0.225 MMTPA),
 -- Sulphur Recovery unit (300 + 3*65) TPD
 Click on the Reports section for more. Details
The existing refinery contains a total 13 crude tanks out of which, 5  tanks are inside refinery premises and  8 tanks are in the ATP area.
 8Post VRMP, thebrefinery will have a total 10 crude tanks, out of which 2 crude tanks will be in the refinery area and 8 crude tanks in the ATP area.
 8ISPRL crude cavern storage of 300 TMT is also considered while working out the new crude storage tanks.
 8Post VRMP High Sulphur crude willl be transported through VLCCs of a capacity 240 TMT each  and off loaded through SPM at ISPRLand brought in through a 48” pipeline.
 8The unloading of a VLCC is expected to be completed in 38 Hours (Including berthing and disconnection formalities).
 8There are 2 undergound crude caverns out of which one will be dedicated for HPCL with capacity of 0.3 MMT capacity.
 8The maximum discharge from the cavern tothe  refinery (via 48” line) is designed to be 6400 m3/hr per hour.
 8Since this 48” line joins the existing 36” line (OSTT to Refinery), the net ransfer rate is governed by the 36” line which is around 5500 m3/hr.
 Click on the Reports section for more. Details
GAIL has now gone one step further to contest the very validity of the regulations that govern the fixation of tariffs for gas pipelines by the PNGRB.
 8The gas major's argument is based on a Supreme Court judgement that says that the PNGRB has no right to fix the tariff for a City Gas Distribution company though it will have a right to fix it for those customers who utilize the CGD infrastructure on a common carrier basis.
 8GAIL now claims that the same logic can be extended to gas pipelines under its control as well.
 8The regulator can fix tariffs for those entities which use the pipeline on common carrier basis and not for the gas major's own use, the argument goes.
 8This means that customers that are directly served by GAIL cannot avail of tariff rates fixed by PNGRB and that such rates are only meant for those using the pipelines on a common carrier basis.
 8If this argument is accepted then most buyers of gas will not be entitled to relief from PNGRB's tariff orders.
 8Then again, GAIL is arguing that the regulator can fix tariff rates only for those pipelines that are authorized as common carrier pipelines and not those that are not so authorized.
 Click on Reports for more Details
Clearly what GAIL is arguing for is not in the interest of the buyer and the government must intervene in favour of the buyer.
 8GAIL's tariff rates are a text book example of  monopolistic pricing, where the buyer is completely at the mercy of the seller.
 8A tariff rate is fixed arbitrarily under the monopolistic dispensation and the buyer is told to pay up, no questions asked.
 8The very fact that a statutory regulator like the PNGRB, empowered by none other than the Parliament of India, is finding it difficult to ensure that the GAIL falls in line shows that unbridled power enjoyed by the monopoly.
 8GAIL has used every weapon at its disposal to stop the regulator from declaring corrected tariff rates which are, at times,just a fraction of those charged earlier by GAIL.
 8A government monopoly is entitled to a 12% post tax rate of return but clearly GAIL, as is evident by the steep cuts in tariff rates, was enjoying a far higher rate of return.
 8Even as the global market for gas becomes more competitive and an array of sophisticated vehicles and packages for gas delivery are now available to the actual buyer, the Indian market is constrained by monopolies like GAIL that keeps the market fettered.
 8It is high time that the government frees up the market by reviving the PNGRB's earlier proposal for splitting up GAIL's transmission and marketing functions so as to avoid a conflict of interest.
 Click on Reports for more Details
Subsequent to the series of interim revisions in tariff rates, an irate GAIL had appealed against the PNGRB orders to the Appellate Tribunal of Electricity but the tribunal had told the regulator to go ahead with the process of determining the final tariffs for these pipelines.
 8The tribunal has said that the regulator must go ahead with the job and pass a "speaking and reasoned order".
 8The tribunal said that if PNGRB were to independently come to the view that the interim orders were justified, then this would not be held against the regulator.
 8GAIL has been ordered by the tribunal to go back to the PNGRB and submit its views.
 8The gas major has not yet submitted all the data that has been demanded by the regulator yet though the last date for submission of information is already over.
 8Some of the cost data submitted by GAIL has been found to be contradictory but the gas company is yet to fully clarify the contradictions.
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GAIL has to shell out a whopping Rs 450 crore on a retrospective basis on account of the downward revision of tariffs enforced by the PNGRB on a bunch of six pipelines operated by the public sector gas major.
 8The PNGRB has found that GAIL had grossly gold plated the cost of these pipelines to charge significantly higher tariffs than what was warranted.
 The regulator found that many cost elements submitted by GAIL-- in terms of past and future capital investments, pipeline replacement costs, O&M expenses, capex, opex estimates and common corporate expenditure -- were grossly inflated.
 Tarrifs have been revised sharply downwards for the following pipelines:
 --Dabhol-Bangalore gas pipeline
 --Kochi-Kottanad-Bangalore-Mangalore pipeline
 --Chainsa Jhajjar-Hissar line
 --Narimananm and Kuthalam sub-network and the Ramnad sub-network pipelines
 --Dukli-Maharajganj gas pipeline
 --Gujarat natural gas pipeline network.
 8PNGRB has held that the tariff rates will be effective retrospectively.
 Click on Reports for more Details
IOC is now conducting a study of the project and it will involve carrying out an analysis of the project in terms of feedstock sourcing from the naptha cracker, utility requirement (cooling water, fire water, raw water, nitrogen, steam and power ),waste generation and the consequent facilities required either on standalone basis or in integration with the cracker.
 8Requirement of other offsite facilities like feed/product storage, warehouse, flare, incinerator and HCR product evacuation through road or rail will also be included in the estimation process.
 8The cost estimation will be done with an accuracy level of +/- 30%.
 Click on the Reports section for more.  Details
The C5 separation unit will be implemented by Indian Oil, whereas the HCR production facilities will be implemented by Indian Oil under a joint venture.
 8The proposed separation unit will extract the components from the debutanizer bottom stream and the rest will again be directed back to the existing naptha cracker unit.
 8The extracted components such as dicyclopentadiene and piperylene will be utilized as a feedstock to produce various grades of HCR.
 8This complex would comprise of three blocks for producing three different HCR grades.
 Click on the reports section for more. Details
IOCL has chalked out a plan to add value to its naphtha cracker complex (NCC) in Panipat,Punjab.
 8This will be done by recovering the C5 components from the naptha cracker unit (NCU) and then upgrading them to high value hydrocarbon resin (HCR).
 8As per the original design of the complex, the C5 stream produced from the cracker unit is either hydrogenated and recycled back to the cracker as feed or for the production of MS.
 8The C5 components includes dicyclopentadiene and piperylene among others in small quantities.
 Hence the project is envisaged to comprise of following two complexes:
 -- C5 separation unit
 -- HCR Production Facilities
 8The C5 Separation Unit will be located within the cracker complex whereas the HCR facilities are planned to be located adjacent to the cracker complex.
 Click on the reports section for more. Details
It is high time now for Petronet LNG Ltd (PLL) to begin re-negotiating the one-sided contract with Qatar for supply of long term LNG.
 8The floor price of LNG indexed to the price of crude is too high and needs to be freed as oil prices seem to be inexorably on the decline.
 8Or else very soon PLL will be unable to sell any of its long term cargoes given that spot prices are far cheaper. There is already wide spread consumer resistance.
 8If Qatar resists, then PLL should go for a mix of a Henry Hub and crude indexed pricing matrix as that will soften the blow for the supplier.
 8It is high time that PLL gets into trading too. If an opportunity arises for swapping a cargo or disposing it elsewhere it should go ahead and do so,   
 8There is no doubt that PLL did receive LNG at prices cheaper than spot deals when crude prices were high but the predictions are that crude prices will remain low for the foreseeable future because of the shale gas revolution in the US.
 8PLL cannot be saddled with expensive LNG cargoes for too long.
 8The point to note is that in a similar situation Oman did not succumb to Indian government pressure when it renegotiated a gas supply deal with OMIFCO, a fertilizer JV between Oman Oil Company, IFFCO and KRIBHCO.
 8So far, some of the take of pay obligations have been deferred by PLL but that is just deferring the burden. Books have to be squared at the end of the year.
 8It is time to throw the gauntlet down at Qatar and insist that the floor price for LNG be renegotiated as soon as possible
 Click on Reports for more Details
For reference purposes, the website carries here detailed estimates of shipping costs from LNG plants in Australia, Russia, US and Canada to the LNG buying hub of Himeji in Japan.
 8The cost is calculated on the basis of a 140,000 m3 LNG tanker notionally hired at $32,000 per day.
 8The costs take into account Panama and Suez canal tariffs as well as longer waiting time navigating them. Trips across the arctic are also factored in.
 8Clearly shipping costs are different depending upon the destination.
 8These shipping costs are important determinants of what the landed costs are going to be for LNG in an increasingly competitive environment where every cent/mmbtu will be taken into account by picky buyers.
 8It has also been speculated that that LNG tankers could have to compete with other ships for Panama Canal capacity therefore leading to bottlenecking at the canal and this will eventually reflect on the end price of LNG.
 8It is not known yet whether GAIL has the sophistication needed to take all these parameters into account while arriving at the conclusion that it requires to employ 12 new LNG carries to ship LNG from the US to India.
 8Is it possible that freight costs will plummet if enough LNG terminals are not built and if the demand for gas slows down as is predicted by the IEA.
 8The new vessels contracted by GAIL will be expensive to build and if their costs are hard coded into freight, the gas major may end up paying more than others a few years down the line if world trade in LNG is less robust than what is predicted resulting in a fall in freight rates.
 Will GAIL be at a disadvantage in relation to those who will have more flexible delivery models?
 8Given the massive uncertainty that has engulfed the gas trading business, GAIL's exposure to the US shale gas business involving tens of billions of dollars can emerge as a point of worry if things go wrong.. 
 8Does GAIL really have the balance sheet to take into account the wide gyrations that may take place in the future?
 8What will happen if it takes a wrong turn where the road forks? A wrong decision can just about wipe out the company, for the tsunami that has descended today on the world oil and gas market is testing the strength of not just the world's biggest oil and gas companies but also of countries such as Saudi Arabia and Russia. 
 8Only the strongest will survive in this business and while the GAIL brass is known to be risk takers in comparison to their staid public sector cousins, is it taking too much of a risk?
 8This is a question that only time will answer.
 Click on Reports for more Details
Price forecasts by the EIA show that in a high oil price environment, a Henry Hub price increase will follow due to increased demand for Henry Hub prices and decreased demand for oil-linked prices.
 8Alternatively, if US gas output goes up, downwards pressures will come to hear on Henry Hub prices, but all of this is unpredictable.
 8All this exemplifies the volatile nature of the Henry Hub prices and although cost-competitive, they come with more risk and less security. 
 8Another new pricing option out of the US will be tolling agreements, as exhibited by the US Freeport project’s contract with Chubu Electric, a Japanese energy firm. The contract enables Chubu to offtake 2.2 MMTPA of LNG with no destination restrictions; therefore if bringing Henry Hub linked LNG into Japan is not economically viable they are able to sell their contracted supply to European or South American markets and find arbitrage opportunities.
 8GAIL has similar contracts for US LNG supplies.
 8The uncertainties in gas pricing is reflected best by projections of how Henry Hub prices are going to behave between 2015-2040. Base price range from around $4/mmbtu to a high of $10/mmbtu.
 8The only sobering point for India in all this volatility is that the base price is unlikely to go beyond a certain point, and that is something that the Indian industry can take into account while doing their long term planning for gas consumption in the years ahead.
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The very sharp fall in crude prices has upset the gas on gas (GOG) Henry Hub based pricing system for LNG that was slowly taking precedence over traditional oil indexed (OPE) sales.
 8Europe was increasingly switching to GOG formats but Asia was slower on the uptake. Since 2005, OPE pricing in Asia went up 6% while oil index matrices lost 3% whereas in Europe there was a 46% increase in gas on gas pricing during the same period. 
 8A new game will be played out when the Americans enter the market with full force from this year onwards. US based Cheniere's Sabine Pass LNG has negotiated sales contracts with gas priced at 115% x Henry Hub + USD 2.50-3.50/ mmbtu as fixed charge. 
 8Japan and other Asian buyers found the price incredibly attractive -- with Henry Hub linked LNG working out to $ 8.28/mmbtu as against $ 16.3/mmbtu for oil indexed gas when the price of crude was at $100/bbl in June 2014  -- and there was talk of replacing all of Japan's oil indexed LPG with GOG contracts. 
 8Moving forward into June 2015, oil linked gas price was at $ 7.60/mmbtu leaving Henry Hub at $ 6.20/mmbtu. 
 8The attractive spreads have severely shrunk. 
 Click on Reports for more Details
The crash in crude and gas prices has unleashed a global chain effect that is still to play itself out. 
 8Technological developments, dramatic prices changes and new supply-price paradigms have sent shock waves around the world and no one really knows what is coming next.
 8Normal wisdom dictates that a fall in gas price should herald a new era in LNG trading but that is turning out to be far from true. 
 8In fact fewer LNG terminals may come up now than before for the simple reason that arbitrage opportunities between low Henry Hub prices and higher oil-linked gas prices for new developers have all but disappeared because of the drastic fall in crude prices.
 8The cost of LNG liquefaction plants has shot up and environmental clearances have become more difficult to get.
 8The situation has come to such a state that the number of LNG plants that are likely to reach completion by the year 2020 can be counted on finger tips out of the many dozens that were planned just a year ago.
 Click on Reports for more Details
Given the rapid changes occurring in the oil and gas business, the Indian government is poorly equipped with skills and technology to handle the coming onslaught.
8There is more to the global markets than just lower prices for crude and whether Shastri Bhavan is in a position to come to grips with all aspectsof the energy paradigm remains a moot point.
8The need to build institutions like the IEA of the US or the IEEJ of Japan cannot be overlooked.
8Providing autonomy and scale to independent institutions such as the PNGRB is of paramount importance.
8New institutions will have to be built of reasonable size and complexity. An economic cell within the ministry will just not do. 
8To begin with the ministry must hire a set of independent global consultants to keep them constantly on the loop on what is going on instead of waiting for a back channel feed from the likes of GAIL or ONGC. Both don't have the wherewithals to abalyse rapidly evolving global trends and their inputs are likely to come with a time lag and coloured by their own interests. 
8Deleveraging the risks that GAIL runs with its huge exposure to the global gas industry is of importance, for if problems arise, the tax payer may end up holding the baby. 
8As for multinational pipelines, the emphasis seems to be on building the pipelines on the assumption that the price of gas will somehow settle at a reasonable level. That may not be the case. An eye must be kept at the landed cost of gas or else the government may end up forcing a pool price down the throats of urea and power units.
8This is also the best time to free up the pricing of domestic gas even if the Modi government is criticized by Rahul Gandhi for favoring Mukesh Ambani. Let these companies sink or swim on their own strengths instead of putting them on the defensive wherein they end up blaming the government for their own failures.
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As this website has said before, the times they are a changing.
 8The biggest blow to innovation was to allow GAIL the absolute monopoly in the supply and pricing of gas under the pooled price system.
 8At best GAIL should have been the aggregator of gas for supply to the fertilizer and power industry but the gas major has instead been given an opportunity to have a stranglehold.
 8The Fertilizer Industry Coordination Industry, the subsidy dispensation arm of the government, should have been the accountant not GAIL for the urea industry.
 8Given that the LNG market is evolving at a breathtaking pace, and new products are in the market, the buyers should now be given the flexibility to sources gas from different sources.
 8The supply chain needs to be de-monopolized and common carrier principles strengthened through the PNGRB. This will allow for more creativity and flexibility.
 8GAIL alone cannot have a monopoly on the technology of gas sourcing and supply because the market has become too complex and it just does not have the capability or the flexibility to keep pace with the rapidity of change.
 8It is time that the multinationals are brought in and given a free hand as should be given to the buyers of gas who between them have enough muscle power to innovate and drive though bargain prices.
 8It is quite possible that IFFCO, the world's largest fertilizer cooperative, could well scoop out LNG cargoes at prices that could be a dollar cheaper from a distressed Australian LNG supplier than the price at which GAIL could supply, for example.
 Click on Reports for more Details
The Russian pipeline deals with China are also going to influence global LNG prices and contracts.
 8Forced into a corner by western economic sanctions, Russia is now wooing the Chinese dragon with giant size gas deals. 
 8Russia signed an estimated $400 billion gas supply deal to deliver 38 billion cubic meters (bcm) of gas through a pipeline to China, with first gas to be delivered in 2018. In early November last year, the two countries also signed a deal for Russia to deliver 30 bcm of gas annually worth $300 billion over 30 years from Western Siberia to North-Western China via the Altai route.
 8Both deals combined would account for almost 17 percent of China’s gas consumption by around 2020.
 8The Russian are looking at a two pronged strategy, of plying gas to Europe but also betting on the Chinese. The Chinese deals were reportedly done at $ 12/mmbtu but the Russian may be willing to negotiate these prices down should Henry Hub levels continue to remain weak.
 8These gas deals may set a floor to global gas prices too.
 8The Chinese have done a spate of LNG deals but with the slowing of its economy and fall in crude prices, it will try and renegotiate some of its LNG contracts now that Russian supplies have been tied in. 
 8Already, the Chinese have sent word that it wants to relook at the price settled with the Australia Pacific LNG project that Conoco Phillips is building with Origin Energy at Gladstone. Many such deals will be re-written to the extent that they will test the very viability of some of these projects.
 8Clearly remote Siberia may well set the global loor price of gas and not Henry Hub in a world where change seems to be the only constant.
 Click on Reports for more Details
For the Americans too setting up LNG terminals is not going to be all the easy.
 8Price volatility is one factor but regulatory approvals are now getting increasingly difficult and time consuming to elicit. 
 8Acquiring an export license for non-FTA countries has also experiencing delays in approval by the DOE. Three recent projects waited an average of 100 days for export approval even after all environmental certificates were obtained. 
 8Another concern is the effects that increased fracking regulation will have on future shale gas production. New federal legislation includes increased government inspection and requires that companies must publicly disclose the chemicals used in fracking. 
 8Russia is another country where LNG projects may not take off at all because of political exigencies and pricing problems.  Russian natural gas production has remained fairly flat since 2005, but has fallen 4% from 2013 to 2014 and Gazprom, which produces around 75% of Russia’ s gas, has forecasted another drop of 6.7% in 2015 production. 
 8LNG accounts for the remaining 7% of exports. Russia’s first and only LNG plant, the Sakhalin 2 unit, became operational in 2009 with a capacity of 9.6 mtpa. 
 8Russia has proposed three additional LNG plans but only the Yamal LNG project is looking the most optimistic at this time of coming up before 2020 because of Chinese support.
 Click on Reports for more Details
The uncertainties in the pricing front seem to be putting all new investments in LNG projects on hold worldwide for the time being.
 8Only those that are under construction are now likely to come to fruition.
 8Take Canada for example. It is one of the four countries in the world that produces commercial volumes of shale gas and relies solely on the US market but as the United States becomes increasingly independent, it is focusing on LNG as a solution. Currently, on the West Coast of Canada there are several proposed LNG terminals at various stages of approval, but not a single project has taken a Final Investment Decision (FID). Canadian projects are greenfield in nature and therefore require significant investments especially due to remote locations and the need for new pipeline systems through difficult terrain. Ever since oil price collapsed, the viability of the capital intensive Canadian LNG infrastructure is being questioned.
 8A recent study showed delivered prices to Japan to be between USD 8.6/mmbtu and USD 16.1/mmbtu, including shipping, tariffs and, tax and by most indications these prices are too high.
 8Then again, looking at Australia, its LNG prices have historically been oil linked, but the next wave of LNG supply using Henry Hub or hybrid pricing mechanisms from the United States could challenge the competitiveness of these traditional pricing agreements. 
 8Australia does not yet have a fully functioning nationwide gas hub and may experience higher liquefaction costs in the new projects as cost overruns have been unprecedented because of bunching of projects.
 8For example, Gorgon LNG’s budget has increased by 46% and QCLNG’s has spiked by 36% from their initial budgets. Australian projects have much of their LNG already contracted but they are likely to face  trouble when renegotiating contracts as prices in Australia may be less competitive than spot market cargoes from North America.
 8Then again viability of sustained Coal Seam Gas production is being questioned as reserves are proving harder to develop and becoming increasingly expensive. The East Coast projects initially believed they had adequate captive reserves to supply their LNG projects, but they have all had to sign agreements to purchase gas supplies outside of the own production.Supply concerns and increasing concern over the environmental effects of CSG production have created a whole lot of uncertainity.
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BPCL is planning to conduct comprehensive testing of its LPG Horton spheres and associated pipelines in the LPG plant located at Ajmer.
 8There are three LPG Horton spheres which are due for inspection and testing by CCOE approved parties on the following dates:
 -- Horton Sphere no.1 - 17.03.2016
 -- Horton Sphere no.2 - 03.12.2015
 -- Horton Sphere no.3 - 10.04.2016
 8Among them, the hydro testing of LPG pipeline is also due on 31.10.2015.
 Click on the Reports section to get complete details of the schedule. Details
8The comprehensive testing exercise will include the following:
 -- Isolation and degassing of the horton spheres
 -- Supervision, Inspection and submission of a detailed report, documentation, drawings  and certification.
 -- Scaffolding: inside and outside to be constructed as per the specification (confirming BIS 1139  and 4047 or approved equivalent)
 -- NDT Test
 -- Ultrasonic flow detection
 -- Radiography (Optional and if any defect found )
 -- Servicing and testing of safety relief valve
 -- Hydrotesting as per BS 5500 class 1 category
 -- Purging of Vessels
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GAIL has now gone one step further to contest the very validity of the regulations that govern the fixation of tariffs for gas pipelines by the PNGRB.
 8The gas major's argument is based on a Supreme Court judgement that says that the PNGRB has no right to fix the tariff for a City Gas Distribution company though it will have a right to fix it for those customers who utilize the CGD infrastructure on a common carrier basis.
 8GAIL now claims that the same logic can be extended to gas pipelines under its control as well.
 8The regulator can fix tariffs for those entities which use the pipeline on common carrier basis and not for the gas major's own use, the argument goes.
 8This means that customers that are directly served by GAIL cannot avail of tariff rates fixed by PNGRB and that such rates are only meant for those using the pipelines on a common carrier basis.
 8If this argument is accepted then most buyers of gas will not be entitled to relief from PNGRB's tariff orders.
 8Then again, GAIL is arguing that the regulator can fix tariff rates only for those pipelines that are authorized as common carrier pipelines and not those that are not so authorized.
 Click on Reports for more Details
Sintex Oil and Gas Limited (SOGL) is expected to start its project soon as the clearances from the ministry has been granted by the government.
 8The company has proposed to drill 10 exploratory wells in CB-ONN-2009/2 block, located in Mahesana and Ahemedabad districts of Gujarat.
 8The block CB-ONN-2009/2 is located in the north Cambay Basin near Modhera and Asjol oil fields.
 8It covers an area of about 68 Sq.kms and is adequately covered by gravity and magnetic surveys.
 8The block have a number oil and gas fields, of which the prominent are: Kalol, Jotna, Sobhasan, Becharaji, Balol, Lanwa and south Patan fields.
 8SOGL intends to drill wells to a depth of 4000 m, taking around 40 to 60 days time for each well.
 8The power requirement of each drilling rig will be met through the two diesel generator sets onboard.
 8HSD will be used as a fuel to run both the drilling rig and the DG sets during the operation.
 8Two DG sets of 1000 HP which will consume 217 lit/hr of HSD.
 Click on the Reports section for more. Details
IOC's pipeline building exercise so far has been confined to creating evacuation facilities to synchronize with the commissioning of the Paradip Refinery. When ready, the two major pipelines,the Paradip-Raipur-Ranchi pipeline and the Paradip-Hyderabad pipeline, will further strengthen product availability in eastern and southern regions of the country. 
 8The company is steadily raising the contribution of heavy crude oil grades in its refinery crude mix and its crude oil pipelines are in a position to pump these heavy crude varieties. 
 8Of the three crude oil pipelines, two are already pumping heavy crudes as well as Rajasthan crude in a mix with normal crude oil.
 8IOC is now planning a further augmentation of the Salaya-Mathura pipeline (SMPL) and the Paradip-Haldia-Barauni pipeline (PHBPL). Upon completion of this augmentation, IOC's pipeline system would be ready to supply heavy crude oil grades as per the processing capacity of its refineries.
 8The company's next focus is in building LPG pipelines as LPG imports account for around 40 per cent of India's product imports and building a nationwide LPG pipeline grid for bringing imported LPG and domestic LPG to the consuming centres is a special area of focus 
 8A number of LPG pipeline projects are presently under implementation. Upon commissioning of the Paradip-Haldia-Durgapur LPG pipeline, for example, evacuation through the pipeline would be possible from refineries at Paradip and Haldia and also from the Haldia port. 
 8The company is now planning an extension of this pipeline up to Patna and Muzaffarpur, along with construction of LPG import facility at Paradip.
 8In addition to this, the Ennore-Trichy-Madurai pipeline, which is also under implementation, would be used for LPG evacuation from the newly commissioned Ennore import facility.
 Click on our Reports section for more   Details
Spot LNG price in India fell to $7/mmbtu in June compared to $16.24/mmbtu in April, 2014, according to a report released by IOC.
 8While domestic gas production continued to decline to 33.7 BCM in 2014-15, which was 4.9 per cent lower due to declining offshore production, LNG imports rose to 11.5 MMT (15.6 BCM) in 2014-15 from 10.8 MMT (14.8 BCM) in the previous year. 
 8In comparison, the long-term LNG price for Qatar gas, which is the main source for LNG in India, continued to be high as it is based on a formula linked to five-year average of Japan Crude Cocktail (JCC) price.
 8IOC claims that the natural gas market is undergoing rapid change  with  North American LNG expected to be available in Asia from 2016, but sizeable volumes will only come in from 2019-2020 onwards. 
 8For the next few years, however, Asia will continue to rely on LNG from its traditional supply sources such as the Middle East, Australia and Russia.
 8Meanwhile, the company's Rs 5,151 crore,  5-MMTPA LNG terminal at Ennore and is targeted for completion in 2018.
 Click on our Reports section for more Details
For reference purposes, the website carries here the details on the following items related to Indian Oil Corporation Ltd
 8Ongoing projects
 8Future projects
 8Refinery wise energy efficiency projects in terms of cost and energy saved
 8List of imported technology used along with the names of the technology providers
 8List of R&D projects undertaken by the company.
 Click on our Reports section for more Details
RIL already has a well developed (and "gold plated" as the government seems to claim) infrastructure in place in the KG Basin and this should lower costs significantly for the consortium whereas this is not the case for ONGC which will have to be build brand new processing facilities. 
 8There was talk of collaboration in the sharing of infrastructure with RIL but talks have faltered since. 
 8Aker which had been involved in the building of RIL's subsea infrastructure was meant to be roped in by ONGC to look at collaborative tie-ins but the attempt did not bear fruition.
 8It does make sense for ONGC to team up with RIL for infrastructure sharing between the D-6 field and the adjoining discoveries of the E&P major even though this has not been factored in in the Rs 53,000 crore development plan of ONGC.
 8In today's stressed environment, infrastructure sharing makes sense. 
 8What ONGC needs to do is to convince the political brass of the cost economics of doing so. 
 Click on our Reports section for more Details
What are the implications of these developments for the deepwater developments of ONGC and the RIL-BG combine in the KG Basin?
 8The point to note is that except for the existing fields in the D-6 block, the other discoveries are at the initial state of development. 
 8This means that expensive development contracts need not be renegotiated midway. 
 8The full impact of cost de-escalation in deepwater equipment and services can be harvested by both the operators.
 8RIL is known to drive hard bargains and with the help of BP it can leverage falling prices to their advantage.
 8The deflation in costs is likely to continue over the next three years and this is good news too.
 8Assuming a 25% initial deflation and going up to 30% over the development cycle of deepwater gas discoveries in the KG basin, the development cost for the RIL-BP combine in the KG basin can come down from the earlier break-even cost of $10-11/mmbtu to around $7.5/mmbtu or even lower. 
 8Will this make the discoveries viable? This will clearly depend on the landed cost of LNG in India but assuming that Henry Hub prices do not decline from current levels of around $2.8/mmbtu, the cost economics would clearly depend on the "premium" that is meant to be given by the government for these discoveries. 
 8As it is, breaking even is going to be a tough call for deepwater plays, particularly in India given that they are tight oil reservoirs which are HPHT in nature.
 8The rapid decline in the D-1 and D-3 fields go to indicate that keeping production going in these reservoirs is a tough job even for a company like BP with all the technology in their hand.
 8If the "premium" is going to allow a percentage of the gas produced to be priced at market rates, it may not make economic sense in today's environment.
 Click on our Reports section for more Details
So where does the deepwater oil and gas industry go from here? There is far too much riding on this segment for it to just shut down all fresh developments because of competition from shale plays.
 8What is now happening is that costs are coming down to the extent that deepwater oil and gas can perhaps compete with shale output.
 8Clearly a lot of projects will be unviable but as deepwater costs decline, lower costs of infill drilling could slow deepwater decline rates.
 8But there are, no doubt, distinct disadvantages to deepwater development compared to shale. For one, investment dynamics can be revised every 20 days in shale plays whereas this is far from possible with deepwater investments. Then again cost deflation is happening at a faster pace in shale than in deepwater.
 8Then again, it is possible for shale cost deflation to pass through quickly in the US because that's the way the taxation regime is structured whereas for deepwater assets this is difficult as operators have to deal with inflexible governments in different regions of the world.
 8Execution risks are also much lower in shale compared to deepwater.
 Click on our Reports section for more Details
The following reduction in costs has already been obtained in the deepwater business over the last one year.
 Finding cost
 8Drilling rigs make up about 30 to 25% of the exploration cost and there is already a 25% fall in price and this is likely to come down more.
 8Well services make up the bulk of the finding cost, at around 40 to 45% of the total, and this has shown a 10% fall so far
 8Seismics and overheads have declined by 20 to 30% and prices are continuing to head southwards.
 Development cost
 8Drilling rigs account for 20% of the cost and hire rates are down 30%
 8Similarly well services make up 20% of the cost and are lower today by 10%
 8Cost of facilites are lower by 15%, subsea production hardware by 25% and SURF and pipelines (that can make up a good 25% of the total cost) by 20%.
 Click on our Reports section for more Details
It is not just shale oil and gas costs that are going down but conventional offshore exploration and production costs have also shown a dramatic decline in the last one year.
 8There has been a deflation in both capex and opex in deepwater plays but unlikely in the shale industry where the transmission of savings is almost immediate, it will take several years to fully pass on the benefits due to contract cycles and technical project complexities. 
 8But there are now clear indications that offshore break even cost will drop by at least 20%.
 8In fact marginal deepater floater rig costs are down by a whopping 50% and may come down another 25%. Historically, a 15% drop in rig utilization can lead to a 50% crash in day rates.  The expectation is that utilization could drop 10% this year and another 8% between 2015 to 2017. Offshore rig utilization rates are falling on account of competition from shale gas and oil.
 8The point to note however is the break even costs will go down and reach 20% or more but it will happen over the next several years.
 Click on our Reports section for more Details
The work oil and gas markets are evolving at a breathtaking fast pace, so much so that oil companies are finding it difficult to keep track of these developments.
 8The changes are more rapid in the shale oil and gas sector and all of this is happening in the US but with worldwide implications.
 8Recently reports suggest that shale well costs have plummeted by a massive 20-25% and there is more to go.
 8Producers will see significant cost compressions due to the collapse of drilling and completion costs as well as on account sharp decline in steel and diesel inputs.
 The decline in cost has been reported in the following items:
 --Well stimulation work consume about 40% of the total cost and this item has seen a massive 25% deflation in cost in 2015.
 --Drilling rigs eat up 19% of the budget and costs have come down by 20%
 --Items such as OCTG (tubular steel), technical services, production equipment and fluids make up about 22% of the total cost and they have registered declines in the range 10 to 30%
 --Cementing work can be done 25% cheaper. 
 --Cost of drilling bits and completion rigs are down 35%
 8Utilization also drives drilling rig rates (which make up 15% of total well costs) and falling demand for rigs should drive overall drilling rig costs by more than 20%. Improved drilling efficiency leading to declines in average drill times and higher initial production is expected to further decrease drilling costs by ~3%.
 Click on our Reports section for more Details
The cost decline has to be juxtaposed against sharp gains in productivity in the shale oil and gas business in the US.
 8Productivity gains has been as high as 30 to 40% this year. This happens because drilling is concentrated in more productive areas and then there is also production and technology improvements.
 8The combination goes to keep cost per barrel down so that production remains profitable at current prices.
 8What is more these efficiency gains are going to continue into the future as producers get used to low prices. Efficiencies in drilling and completion techniques coupled with operational and process improvements will continue well into the future.
 8The IRR remains very attractive for shale oil and gas producers assuming a crude price of $60/bbl and a Henry Hub price of $ 2.8/mmbtu.
 The following are the estimated IRRs for the key shale plays in the US at these prices:
 --Eagle Ford: 80%
 --Eagle Fort-oily 140%
 --Bakken: 25%
 --Permian: 27%
 --Andarko Mississippian: 42%
 --Utica: 20%
 --Marcellus: 22%
 8The return is near zero however for the Haynesville play and is marginally negative for the Granite Wash play but both of them can go into the positive territory with father improvements in productivity and cost.
 8The point to note is that the cost of money in the US is extremely low, unlike in India, and given the high IRRs, and improvements in productivity, these plays will remain viable at even lower crude and gas prices going ahead.
 8In this context, American shale output is unlikely to be hurt unless prices really collapse.
 Click on our Reports section for more Details
IOCL has finally been able to get the nod from the ministry to expand the warf at Port Blair harbor so that it can berth normal sized LPG tankers.
  8Due to the short length of the wharf, normal size LPG tanker were not able to berth and IOC has to put extra efforts to bring smaller tankers by spending extra money towards ocean freight for ensuring adequate availability of LPG at Port Blair.
  8The existing Hope Town wharf is of 140 m in length with a 10 m draft. The LPG tankers were berthed here to supply gas to the LPG Bottling plant nearby.
  8To meet with the requirement of berthing of regular 160 m ilong LPG tankers, the existing jetty has to be extended by 60 m, so that final length reaches 200 m for safe berthing of these tankers.
  8Sometimes there are shortage of special vessels that could handle the narrow berth and this had the capacity of causing a shortage in Port Blair.
  Click on the Reports section for more. Details
8This project broadly envisages the following components:
  -- Extension of wharf by 60 m x 20.50 m founded on bored cast-in-situ RCC piles of 800 mm dia.
  -- Dredging a 3000 Sq. m area (100 m X 30m) to clear route of the vessel while berthing alongside the jetty.
  -- At present baseline data collection is in progress.
  8Details of commonly operated Indian LPG tankers are:
  -- Nanga Parbat(GRT: 17778, DWT: 17601, Length× Breadth: 160m × 26m, Draft: 8.1 m)
  -- Annapurna (GRT: 17778, DWT: 17562, Length × Breadth: 160m × 26m, Draft: 8.3 m)
  Click on the Reports section for more.  Details
 India's appetite for West African crude has surged in recent months as one of the world's biggest consumers of oil looks to shift its focus away from the Middle East.
 8There are host of reasons Indian demand for West African crudes has risen significantly in the past three or four months, including the narrow Brent/Dubai spread, lower ICE Brent, and weaker WAF crude differentials.
 8Indian demand for light and medium sweet grades from West Africa has also risen amid stronger gasoline and middle distillate cracks, ably supported by strong refining margins.
 8India imported 2.45 million mt of crude oil in May from Nigeria, up 34.64% year-on-year and a near five-fold jump from April, according to shipping data obtained by Platts.
 8India is the largest buyer of Nigerian crude, which is largely light and sweet, and fits the appetite of the Indian state refineries.
 8Indian state-owned refiners like Indian Oil Corp., Bharat Petroleum Corp. Limited and Hindustan Petroleum Corp. Limited, and private refiner Reliance are all key and consistent buyers of Nigerian crudes like Qua Iboe, Bonny Light, EA Blend, Erha, Usan and Agbami.
 8In 2014, 18% of Nigerian crude exports went to India, according to data from the US Energy Information Administration.
 8According to Platts data, more than 25% of Nigerian crude imports have been going to India for May, June and July loading.
 Click on the Reports section. Details
The absence of an independent consortium to implement the TAPI pipeline is being acutely felt by promoter countries.
 8For the time being the promoters are going to put in effort to start work by the hunt for an independent consortium continues to be on.
8The President of Turkmenistan Gurbanguly Berdimuhamedov has now sent out invitations to Turkish companies to participate in the implementation of the pipeline.
8This was confirmed by Turkish Petroleum Corporation (TPAO). The company is now actively looking the prospect.
8The problem is that a lot of other big companies have also looked at the proposal but developed cold feet later. Will TPAQ be any different?
8The basic problem seems to be that security in the transit countries, which the pipeline should cross, is very fragile.
8Blowing up infrastructure in these countries is commonplace.
8For the years since the emergence of the idea of ??the TAPI gas pipeline, the situation has not improved.
8On the contrary, with the withdrawal of US and NATO troops from Afghanistan in 2014, the terrorist threat in the region only increased. Under these conditions, in case of the project implementation, its participants will have to take huge risks, without any guarantee.
Click on details for more. Details
ONGC has approved six major projects in 2014-2015, leading to a massive investment of Rs 27,964 crore.
 The following are the details:
 8Integrated development of Daman fields: This is the most exciting prospect with total expected production being 5.01 MMm3 of condensate and 27.67 BCM respectively by the year 2024-25. The total approved cost is Rs 6086 crore.
 8Mumbai High south redevelopment phase-III: With an approved cost of Rs 6068 crore, ONGC wants to increase its oil and gas production to 7.547 MMT and 3.864 BCM respectively by the year 2029-30.
 8Mumbai High north redevelopment phase-III: The total out will be 6.997 MMT of Oil and 5.253 BCM of gas by the year 2029-30, the gas major has approved an investment of Rs 5813 crore.
 8Enhanced Recovery from Bassein field: This involves the integrated development of Mukta, Bassein and Panna fields by which the company wants to reach to 19.36 BCM of gas,1.97 Mm3 of condensate and 0.183 of oil till 2027-28. Approved cost is Rs 4619 crore.
 8Aditional Development of Vasai field: Development at Vasai will raise the total production to1.827 MMT of oil and 1.971 BCM of gas by the year 2029-30, at an initially approved cost of Rs 2476 crore.
 8Pipeline replacement Project-IV is also being planned with an approved cost of 2899 crore.
 Click on the Reports for more. Details
ONGC has used a host of new technology tools last year and among them are the following additional items:
 82D long-offset seismic data reprocessing tool using TGS software: This tool will improve the image by using a linear transform (SMELT) module and proprietary software, dubbed CLARI-FI. This tool has helped in understanding Basin architecture, sedimentation history and in identifying prospective locales for Mesozoic exploration in the Kutch and Kerala-Konkan basins.
 8Gas Sweeting Facilities at the Offshore B193 Process Platform commissioned in November, 2014 in the of B193 Cluster fields have high H2S gas concentrations. It is for the first time that sour gas processing and sweetening facilities have been installed and operated in these facilities.
 8Float over method for installation of platforms: ONGC's HRD process platform has been installed in January, 2015 by using the state-of-the-art “Float-Over Technology” resulting in saving of offshore construction time for installation. Earlier the successful installation of B-193 AP Deck in the company's B&S Asset, in December, 2012 using the Float Over method was the first endeavor of ONGC in this direction.
 8Floating Production, Storage and Of floading (FPSO) system: The new installed FPSO ("Armada Sterling-II") is a floating oil production system successfully commissioned in March, 2015 in in ONGC's western offshore asset to produce oil and gas from the Cluster-7 fields.
 Click on the Reports section for more. Details
With an urge to curb cost and to stay ahead, ONGC has brought in new technology into its E&P exploration and production matrix.
 Among them are:
 8Broadband seismic technology: It was used in Mumbai High Field for identification of porosity sweet spots in carbonate reservoirs and thin bed identification within clastic reservoirs. Moreover the broadband data is expected to help in Basement imaging for prospectively within locales with intense fracture developments.
 8Micros seismic surveys: These are performed to monitor hydraulic fracturing. Initiatives have been taken with in-house efforts for acquiring data using this technology. Feasibility study for monitoring the progress of hydro fracturing using micro seismic information is under progress in the Cambay Basin.
 8Drill bit seismics technique: It uses the vibrations produced by a drill bit while drilling a down hole. The seismic data has been acquired around a well in Gandhar area of Cambay Basin using 3C sensors and drill bits as a source of generating vibrations.
 8Advance NGS system: It allows simultaneous display and management of different spectra for desired presentation and effective management of data files. It has the latest digital signal processor (Orion) and MCA (Multi Channel Analyser), both of which will improve data acquisition, analysis and interpretation capabilities.
 8New modules in MOVE suite: Geomechanical Modeling (GM), Fracture Modeling (FM) and Stress Analysis tools have been added in this module.
 Click on the Reports section for more. Details
During the year 2014-15, ONGC has made 22 Oil and gas discoveries in domestic acreages being operated by ONGC.
 8Out of 22, 10 discoveries are in offshore and 12 in onshore. Of these, 10 discoveries were made in the new prospects whereas 12 were new pool discoveries.
 8Seven discoveries were made in NELP blocks and 15 in nomination blocks. Two discoveries (Rudrasagar-184 & Gandhar-699) during 2014-15  in nomination blocks have already been put on production and efforts are on for bringing the other discoveries on production as early as possible.
 8Seven discoveries in NELP blocks (5 Onland, 2 Offshore) are governed by the PSC guidelines .
 8Out of the 114 NELP blocks awarded or acquired by ONGC as operator, 49 blocks are currently active while the balance 65 blocks have been relinquished. Exploration and appraisal programmes are underway in all the active blocks.
 8A total of 47 discoveries as per latest date (16 in deep-water, 13 in shallow water and 18 in onland) have been made by ONGC in all and 22 of these are in NELP blocks (6 deep-water, 6 shallow water and 10 onland) while the others in nomination blocks.
 8Commencement of production from these discoveries is governed by stipulations laid down in the respective PSCs and is to be taken up after successful completion of appraisal programmes followed by submission of DOCs and approval of field development activities will be taken up keeping in view the timelines of the respective blocks.
 Click on the Reports section to get the details of the discoveries. Details
ONGC has commissioned its C2, C3 and C4 extraction plant at Dahej with a capacity to produce 5 MMTPA of LNG provided by Petronet LNG Ltd.
8The extracts are meant to go as feedstock into the ONGC promoted petrochemical company ONGC Petro-additions Ltd (OPaL). which is constructing a mega petrochemical unit at the SEZ in Dahej.
8The C2+ components will make up 40% of the feedstock for the OPaL plant.
8But while the extraction plant is ready the OPaL unit is still to be commissioned. The plant has been delayed by cost and time overruns. The project cost is now pegged at a massive Rs 27,000 crore.
8According to latest estimates, the project is 95% complete even though only Rs 23,000 crore has been spent till date.
8Phase wise commissioning of the complex has begun and stabilization exercises will be completed by Q-3 2015-16.
8And what happens to the C2+ extracts till the OPaL unit is commissioned? They will be used to produce LPG by blending C3 & C4 in the requisite ratio and sold to public sector oil marketing companies.
 Click on Repots for more Details
For reference purposes, the website carries the following updates on ONGC's activities:
8The entire spectrum of R&D activities undertaken by the company
8Shale gas exploration
8Underground coal gasification
8Coal Bed Methane
8Significant alliances, acquisitions and operation highlights of OVL
8Latest update on OPaL
8Significant alliances and partnerships by the company
8Opening oil and gas reserves, additional reserves and closing reserves of ONGC in 2014-15 both in India and abroad.
 Click on Repots for more Details
ONGC is betting heavily on the KG Basin to take it out of the current stagnation in production.
8The company is planning on establishing between 500-700 MMT of in-place hydrocarbon reserves from the entire basin.
8It is not just the High Pressure-High Temperature and tight and deepwater plays in basin but it is also the KG onland and shallow water offshore areas that will eventually add to the tally.
8The company plans a cumulative production of an impressive 70-90 MMT (O+OEG) from both onland and already 180 MMT of in-pace hydrocabon reserves have been established.
8ONGC believes that very good potential exists in the Bhuvnagiri, Malleswaram, Periyakudi, Kottalanka, Bantimulli South, Yanamshallow offshore,GS-OSN-2004 and G-4-6 discoveries in the KG basin.
8Services of Blade Energy Partners of the US has been hired to study the six discovered HP-HT and tight reservoir fields in the KG basin.
 Click on Repots for more Details
India has been very slow to cash in on the shale oil and gas revolution. The US is today a large producer of hydrocarbons from shale deposits and China too has established large reserves of shale oil and gas.
8In India however not much is happening. The government did come out with a policy that allowed ONGC and OIL to look for shale discoveries in their nomination blocks.
 ONGC has identified 50 nomination blocks - 28 PMLs in Cambay, 3 PMLs in A&AA, 10 PMLs in Krishna-Godavari and 9 PMLs in Cauvery basins for shale gas exploration within three years.
8During 2014-15, ONGC has drilled five exploratory wells for shale gas exploration (4 dual purposes ones that will also explore conventional reserves of gas and 1 exclusively for shale gas) in Cambay, Cauvery, Krishna-Godavari and Assam-Arakan Basins and samples have been collected for assessment of Shale Gas potential.
8Most of the studies in wells drilled last year have been completed and the integration/ assessment exercise is in progress.
8Based on the review of data collected in wells, prospective intervals have been identified in Cambay Shale which are planned to be hydrofractured shortly.
8Presently, 2 shale gas wells and 1conventional well with dual objectives are under drilling in the Cambay basin
 Click on Repots for more Details
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