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Jul 2015
The long-term production profile envisages bringing six wells online annually and ramping up production to a peak of 13,200 STB of oil and 54.8 MMSCF/day of gas till year 2020-21.
8Thereafter, the field will decline gradually to 3550 bbl/d Oil and 6.3 mmscf/d gas by March, 2035.
8It is estimated that cumulative 39.1 mmbbl Oil and 70.1 bcf of gas will be recoverable from the field.
8Techno-economic analysis of the proposed combined development strategy of the Raghavapuram and Gollapalli pays in Nagayalanka field, having a project NPV of approximately 5,262 crore and an IRR of 38%, indicates a healthy project and potentially justifiable for commerciality to deliver positive investment returns. Details
8Thereafter, the field will decline gradually to 3550 bbl/d Oil and 6.3 mmscf/d gas by March, 2035.
8It is estimated that cumulative 39.1 mmbbl Oil and 70.1 bcf of gas will be recoverable from the field.
8Techno-economic analysis of the proposed combined development strategy of the Raghavapuram and Gollapalli pays in Nagayalanka field, having a project NPV of approximately 5,262 crore and an IRR of 38%, indicates a healthy project and potentially justifiable for commerciality to deliver positive investment returns. Details
GSPC, the operator of the Gujarat onland block CB-ONN-2000/1, has requested the environment ministry to allow it to go ahead with its plan to set up the three Surface Production Systems (EPS) so that production from the field can be started as soon as possible.
8The operator, for quite some time, has been pursuing to set up the three EPS in the contract area but could not move ahead in the absence of statutory clearances.
8GSPC has now submitted a revised proposal to the environment ministry for setting up the three production systems.
8The three EPS will be set up at the following locations: EPS SE-1 (Cluster wells SE1-1 and SE1-A), EPS SE1-A1 (Cluster wells and SE1-A1 and SE Dev-1) and EPS PK-1.
8The proposed wells were initially drilled in 2003, and oil was discovered in these wells. Though all the requisite facilities have already been put up in place at the site, the operator plans to commence production once the approval from the environment ministry is received.
8Around 138-198 m3/day of crude oil and 4600-6600 m3/day of associated gas is likely to be produced from the three wells. Details
8The operator, for quite some time, has been pursuing to set up the three EPS in the contract area but could not move ahead in the absence of statutory clearances.
8GSPC has now submitted a revised proposal to the environment ministry for setting up the three production systems.
8The three EPS will be set up at the following locations: EPS SE-1 (Cluster wells SE1-1 and SE1-A), EPS SE1-A1 (Cluster wells and SE1-A1 and SE Dev-1) and EPS PK-1.
8The proposed wells were initially drilled in 2003, and oil was discovered in these wells. Though all the requisite facilities have already been put up in place at the site, the operator plans to commence production once the approval from the environment ministry is received.
8Around 138-198 m3/day of crude oil and 4600-6600 m3/day of associated gas is likely to be produced from the three wells. Details
GSPC will transport the crude produced in the block CB-ONN-2000/1 to ONGC for further processing.
8The surface production facility in the block, which has been designed considering the potential of the oil wells, mainly comprises of production, separation, storage, heating, crude loading
including fire fighting pump, fire hydrants and other safety provisions as per statutory guidelines.
8Reservoir pressure at the sites is sufficient for the production of crude oil and natural gas. Initially oil will be produced due to the naturally occurring pressure, that is, self flow at the site.
8After depletion of the reservoir pressure, artificial lift will be installed to lift the fluid from the well bore up to the surface.
8Once crude oil and associated gas are extracted from the ground either due to self pressure or with the help of Sucker Rod Pump (SRP), they will be diverted to the separator.
8After being separated, associated gas will be used in bath heaters and excess of it will be flared at the site.
8Crude oil will be transferred to the temporary storage tanks and transported to Navagam-COCTF and further to ONGC-CTF Tank for processing. Details
8The surface production facility in the block, which has been designed considering the potential of the oil wells, mainly comprises of production, separation, storage, heating, crude loading
including fire fighting pump, fire hydrants and other safety provisions as per statutory guidelines.
8Reservoir pressure at the sites is sufficient for the production of crude oil and natural gas. Initially oil will be produced due to the naturally occurring pressure, that is, self flow at the site.
8After depletion of the reservoir pressure, artificial lift will be installed to lift the fluid from the well bore up to the surface.
8Once crude oil and associated gas are extracted from the ground either due to self pressure or with the help of Sucker Rod Pump (SRP), they will be diverted to the separator.
8After being separated, associated gas will be used in bath heaters and excess of it will be flared at the site.
8Crude oil will be transferred to the temporary storage tanks and transported to Navagam-COCTF and further to ONGC-CTF Tank for processing. Details
The Field Development Plan (FDP) for the SE-1 discoveries in the GSPC-operated block CB-ONN-2000/1 has been approved by the DGH with the following parameters:
8Estimated oil in-place volume (OIIP): 2.11 MMBBLS
8Drilling: One development well, along with production facilities
8Estimated Cumulative Production: 0.182 MMSTB during 15 years (field life) of production with an initial oil production of 70 bbl/day.
8Delivery Point: Will be decided later as per PSC provision within the contract area. As of now, the operator has decided to send crude oil to to ONGC-CTF Tank for processing.
8As per the co-ordinates of the discovery, the mining lease area measures upto 1.68 sq km.
8The block CB-ONN-2000/1 was awarded to a consortium of GAIL and GSPC under NELP-II. Details
8Estimated oil in-place volume (OIIP): 2.11 MMBBLS
8Drilling: One development well, along with production facilities
8Estimated Cumulative Production: 0.182 MMSTB during 15 years (field life) of production with an initial oil production of 70 bbl/day.
8Delivery Point: Will be decided later as per PSC provision within the contract area. As of now, the operator has decided to send crude oil to to ONGC-CTF Tank for processing.
8As per the co-ordinates of the discovery, the mining lease area measures upto 1.68 sq km.
8The block CB-ONN-2000/1 was awarded to a consortium of GAIL and GSPC under NELP-II. Details
8Three Directors of EIL cease to hold office: Engineers India Ltd (EIL) has informed the BSE that Bijoy Chatterjee, Dr. R K Shevgaonkar and Dr. J P Gupta, Non-official Independent Directors, have ceased to be Directors of the company with effect from July 4, 2015, in terms of Ministry of Petroleum and Natural Gas letter dated July 4, 2012.
--The petroleum ministry, vide its letter dated July 4, 2012, had conveyed the approval for appointment of Bijoy Chatterjee, ex-Secretary, Government of India, Dr. R. K. Shevgaonkar, Director, IIT, Delhi and Dr. J. P. Gupta, Director, Rajiv Gandhi Institute of Petroleum Technology (RGIPT), Rae Bareli, as non-official part-time (Independent) Directors on the Board of EIL for a period of three years.
8Greatship (India) incorporates a wholly-owned subsidiary, Greatship OilfieId Services Limited: Great Eastern Shipping Company Ltd has informed the BSE that Greatship (India) Limited (GIL), a wholly-owned subsidiary of the company has incorporated a new wholly-owned subsidiary, christened Greatship OilfieId Services Limited. Details
--The petroleum ministry, vide its letter dated July 4, 2012, had conveyed the approval for appointment of Bijoy Chatterjee, ex-Secretary, Government of India, Dr. R. K. Shevgaonkar, Director, IIT, Delhi and Dr. J. P. Gupta, Director, Rajiv Gandhi Institute of Petroleum Technology (RGIPT), Rae Bareli, as non-official part-time (Independent) Directors on the Board of EIL for a period of three years.
8Greatship (India) incorporates a wholly-owned subsidiary, Greatship OilfieId Services Limited: Great Eastern Shipping Company Ltd has informed the BSE that Greatship (India) Limited (GIL), a wholly-owned subsidiary of the company has incorporated a new wholly-owned subsidiary, christened Greatship OilfieId Services Limited. Details
The entire processing will be done from the existing central processing platform.
8The facilities in the platform includes dual separation facilities for low pressures (150 psi/10.5 kg/cm2 ) oil production with the capacity to handle 45,000 BOPD (7 mm3 /d), 110,000 BWPD (18 mm3 /d) and 180 MMCFD (5.2 MMm3 /d) of associated gas.
8Use of multiple trains allows for continuous production through one train if problems develop in a train vessel. The crude is separated, dehydrated and then pumped to the SBM and moored storage tanker. Associated gas is dehydrated and either compressed for sales or used as fuel. Compression is provided by a two body three stage, 12,000 HP turbine driven compressor units.
8The gas is taken from 200 psig to 1,350 psig. Dehydration is done inter-stage at 1,000 psig. This allows for the down grading of the materials used in the last stage of compression and optimization of the glycol unit sizing.
8Water is treated through hydro-cyclone separators then flowed through a flash separator prior to discharge overboard. The hydro-cyclone separator shell is larger than required for initial rates and is designed for expansion through the addition of hydro-cyclone elements for future water rates which may reach 100,000 BWPD.
8The fuel/lift gas sweetening system utilizes methyl diethanolamine to absorb H2S from natural gas. This is a regenerative process designed for a nominal 25 MMSFCD, reducing the H2S concentration from approximately 1000 ppm to less than 10 ppm. In this absorptive process, the gas flow counter current to the amine in a trayed contact tower.
8The sweetened gas proceed to a glycol contactor for dehydration prior to use as fuel gas, instrument gas or lift gas. The rich amine flows through a regeneration process which releases vapours to the low pressure flare, heats the rich amine and then steam strips the H2S from the rich amine. The lean amine is filtered and returned to the process for re-use.
8The released acid gas, composed of CO2, H2S and any amine carryover, is vented through a pressure control valve into the low Pressure Flare Header, where it is mixed with assist gas and burned in an incinerating pilot flame.
Click on our Reports section for more. Details
8The facilities in the platform includes dual separation facilities for low pressures (150 psi/10.5 kg/cm2 ) oil production with the capacity to handle 45,000 BOPD (7 mm3 /d), 110,000 BWPD (18 mm3 /d) and 180 MMCFD (5.2 MMm3 /d) of associated gas.
8Use of multiple trains allows for continuous production through one train if problems develop in a train vessel. The crude is separated, dehydrated and then pumped to the SBM and moored storage tanker. Associated gas is dehydrated and either compressed for sales or used as fuel. Compression is provided by a two body three stage, 12,000 HP turbine driven compressor units.
8The gas is taken from 200 psig to 1,350 psig. Dehydration is done inter-stage at 1,000 psig. This allows for the down grading of the materials used in the last stage of compression and optimization of the glycol unit sizing.
8Water is treated through hydro-cyclone separators then flowed through a flash separator prior to discharge overboard. The hydro-cyclone separator shell is larger than required for initial rates and is designed for expansion through the addition of hydro-cyclone elements for future water rates which may reach 100,000 BWPD.
8The fuel/lift gas sweetening system utilizes methyl diethanolamine to absorb H2S from natural gas. This is a regenerative process designed for a nominal 25 MMSFCD, reducing the H2S concentration from approximately 1000 ppm to less than 10 ppm. In this absorptive process, the gas flow counter current to the amine in a trayed contact tower.
8The sweetened gas proceed to a glycol contactor for dehydration prior to use as fuel gas, instrument gas or lift gas. The rich amine flows through a regeneration process which releases vapours to the low pressure flare, heats the rich amine and then steam strips the H2S from the rich amine. The lean amine is filtered and returned to the process for re-use.
8The released acid gas, composed of CO2, H2S and any amine carryover, is vented through a pressure control valve into the low Pressure Flare Header, where it is mixed with assist gas and burned in an incinerating pilot flame.
Click on our Reports section for more. Details
One of the challenges that IOC is trying to tackle is move waste oil collected across the country to refineries for reprocessing and recovery of light oil.
The collected oil has to be moved safely in road tankers but before that is done, the oil has to be heated using electrical barrel heaters and the oil is then transferred from barrels in which they are collected to a slop oil tank.
The oil again heated in tank upto pumping temp and re-circulated through nozzle to make the oil homogeneous. Which is then transferred to road tankers.
The facility will comprises of the following sub-systems:
-- Over ground slop of 15 KL capacity;
-- Steam boiler with steam generation at the rate of 100 Kg/h at 7 bar supply pressure;
-- Four barrel heaters with capacity of 2-3 KW;
-- Feeding pump;
-- Electrical heat tracer;
IOC`s R&D division is now setting up a pilot project, and if found commercially viable, it will be scaled up for implementation across the country
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The collected oil has to be moved safely in road tankers but before that is done, the oil has to be heated using electrical barrel heaters and the oil is then transferred from barrels in which they are collected to a slop oil tank.
The oil again heated in tank upto pumping temp and re-circulated through nozzle to make the oil homogeneous. Which is then transferred to road tankers.
The facility will comprises of the following sub-systems:
-- Over ground slop of 15 KL capacity;
-- Steam boiler with steam generation at the rate of 100 Kg/h at 7 bar supply pressure;
-- Four barrel heaters with capacity of 2-3 KW;
-- Feeding pump;
-- Electrical heat tracer;
IOC`s R&D division is now setting up a pilot project, and if found commercially viable, it will be scaled up for implementation across the country
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IOCL approved third party inspection agencies for stage wise and final inspection of Slop Tank are given below:
-- M/s Mecon Limited
-- Ms Certification Engineers India Ltd
-- M/s Projects & development India Ltd
-- M/s Indian Register of Shopping
-- M/s SGS India Pvt. Ltd
-- M/s Bureau Veritas
-- M/s Rites Limited
-- M/s Lloyds register of Shipping
-- M/s TUV India Pvt ltd
-- M/s Del Norske Veritas
-- M/s HSB Global Standard (India) for ASME code certified inspectors only.
-- M/s TUV Rheinland (I) Pvt. Ltd.
-- M/s Velosi Certification Services India Pvt. Ltd
Comment: Public sector companies have a way of building lists. This list has some of the best companies in the world. But then again, do some of the companies deserve to make the grade? Have some big names been left out?
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-- M/s Mecon Limited
-- Ms Certification Engineers India Ltd
-- M/s Projects & development India Ltd
-- M/s Indian Register of Shopping
-- M/s SGS India Pvt. Ltd
-- M/s Bureau Veritas
-- M/s Rites Limited
-- M/s Lloyds register of Shipping
-- M/s TUV India Pvt ltd
-- M/s Del Norske Veritas
-- M/s HSB Global Standard (India) for ASME code certified inspectors only.
-- M/s TUV Rheinland (I) Pvt. Ltd.
-- M/s Velosi Certification Services India Pvt. Ltd
Comment: Public sector companies have a way of building lists. This list has some of the best companies in the world. But then again, do some of the companies deserve to make the grade? Have some big names been left out?
Click on Tender section for more. Details
Inefficiencies in internal gas consumption by ONGC`s oil and gas processing stations have been a major problem for ONGC.
There is a general perception, that the combustion systems within these stations can be made more efficient so that they consume less and gas and more of it is then made available for sale.
Gas is internally consumed to separate the gas from oil and oil from water.
To remove gas, crude oil is sent for treatment for further separation using heaters that work on internal lean natural gas as fuel for furnace.
The job of smoothening out the inefficiencies has been handed over the Petroleum Conservation Research Association.
The job entails figuring out the following:
-- Measurement of gas consumption per day in various equipment
-- Mass balance of gas coming to the plant battery, based on annual data.
-- Heat balance of the plant battery.
-- Identification of saving potential.
-- Recommend a viable Waste Heat Recovery System and its cost benefit analysis.
-- Establish the existing burner’s efficiency and suggest replacements if needed.
-- Suggest leading suppliers and manufacturers of these equipments.
A consultant is expected to come out with a detailed project report, based on which action will be taken to bring in the equipment that will improve the efficiency of gas consumption.
Click on Tenders for more Details
There is a general perception, that the combustion systems within these stations can be made more efficient so that they consume less and gas and more of it is then made available for sale.
Gas is internally consumed to separate the gas from oil and oil from water.
To remove gas, crude oil is sent for treatment for further separation using heaters that work on internal lean natural gas as fuel for furnace.
The job of smoothening out the inefficiencies has been handed over the Petroleum Conservation Research Association.
The job entails figuring out the following:
-- Measurement of gas consumption per day in various equipment
-- Mass balance of gas coming to the plant battery, based on annual data.
-- Heat balance of the plant battery.
-- Identification of saving potential.
-- Recommend a viable Waste Heat Recovery System and its cost benefit analysis.
-- Establish the existing burner’s efficiency and suggest replacements if needed.
-- Suggest leading suppliers and manufacturers of these equipments.
A consultant is expected to come out with a detailed project report, based on which action will be taken to bring in the equipment that will improve the efficiency of gas consumption.
Click on Tenders for more Details
BG has left space for future improvements in its drilling operations.
Among the measures that are likely to be taken are:
8Dual completions: Slot saving by effectively drilling two wells from the same conductor. Ideal if alternative gas is to be accessed in future from the same slot in dual zones.
8Auto Gas Lift: Use of gas from A zone gas cap or Alternations zone gas accumulation as the sources of gas lift will prevent scaling and offer a more optimized gas lift method
8To summarize, under the proposed infill one drilling rig will be used to undertake the activities in an uninterrupted sequence with intervening rig movements.
Click on our Reports section for more. Details
Among the measures that are likely to be taken are:
8Dual completions: Slot saving by effectively drilling two wells from the same conductor. Ideal if alternative gas is to be accessed in future from the same slot in dual zones.
8Auto Gas Lift: Use of gas from A zone gas cap or Alternations zone gas accumulation as the sources of gas lift will prevent scaling and offer a more optimized gas lift method
8To summarize, under the proposed infill one drilling rig will be used to undertake the activities in an uninterrupted sequence with intervening rig movements.
Click on our Reports section for more. Details
BG India achieved first oil production from Mukta-B (MB), a four legged wellhead unmanned platform in the offshore Bombay basin.
8The facilities include not just the platform but also a 5.2 km well fludi line and two gas lift lines with lengths of 20.5 km and 25 km
8BG has a 30% interest in the Panna-Mukta oil and gas fields alongside its partners, ONGC and Reliance Industries Ltd.
8The MB and MA pipelines have also been successfully completed as part of the project, enabling a restart of production from the MA platform, which had been shut-in due to pipeline integrity issues for the last two and half years.
8The project clocked more than 2 million “LTI free” man-hours and has several firsts to its credit, including the use of green technology involving hybrid solar panels and wind turbines remote monitoring facilities for process optimization and VOIP protocol for better communication.
8Shaleen Sharma, President & Managing Director, BG India said, “This is a significant milestone for BG India and the culmination of an integrated team effort by all functions and contract parties.”
8Incremental development of the existing fields via well intervention and infill drilling campaigns, as well as evaluating new projects and further development opportunities, is being planned.
Click on our Reports section for more. Details
8The facilities include not just the platform but also a 5.2 km well fludi line and two gas lift lines with lengths of 20.5 km and 25 km
8BG has a 30% interest in the Panna-Mukta oil and gas fields alongside its partners, ONGC and Reliance Industries Ltd.
8The MB and MA pipelines have also been successfully completed as part of the project, enabling a restart of production from the MA platform, which had been shut-in due to pipeline integrity issues for the last two and half years.
8The project clocked more than 2 million “LTI free” man-hours and has several firsts to its credit, including the use of green technology involving hybrid solar panels and wind turbines remote monitoring facilities for process optimization and VOIP protocol for better communication.
8Shaleen Sharma, President & Managing Director, BG India said, “This is a significant milestone for BG India and the culmination of an integrated team effort by all functions and contract parties.”
8Incremental development of the existing fields via well intervention and infill drilling campaigns, as well as evaluating new projects and further development opportunities, is being planned.
Click on our Reports section for more. Details
The Rs 1350 crore Mukta-B development in the Panna-Mukta oil and gas fields involves drilling of lateral wells from a new unmanned platform (known as the MB platform).
8BG did not consider horizontal wells because the geological structural configuration limited the drilling of horizontal section due to small structural highs. There was also the associated high risk to opening up water bearing zone while drilling the horizontal section.
8The TVD tolerance for the future horizontal wells are specified in the range of +/-1.0 metres for an average drilled length of 1000 metres.
8The company has gone in for Liner Segmentation and Inflow Control in the Reservoir Completion Section as this increases recovery through even distribution of flow along the wellbore and facilitating shut-off of premature gas or water ingress.
8Reservoir monitoring is being done through a combination of surface-readout permanent downhole pressure/temperature gauges, memory gauges set in side-pocket mandrels (SPM) and distributed temperature system (DTS) for monitoring inflow along the reservoir section. This will provide data to improve the understanding of inflow distribution and coning along the horizontal sections.
8The tubing size is also been kept at a uniform 3.5 -inch not just for this operation but for all upcoming Panna completions based on expected optimal off take rates and operational considerations
8BG says that conventional gas lift will be used in the future and scaling problems will be mitigated by optimized gas conditioning and/or downhole chemical injection
8A downhole chemical injection process will avoid scaling issues by providing a reliable means of delivering known dosage rates of scale inhibitors below gas lift depth through a dedicated 3/8 “ control line
Click on our Reports section for more. Details
8BG did not consider horizontal wells because the geological structural configuration limited the drilling of horizontal section due to small structural highs. There was also the associated high risk to opening up water bearing zone while drilling the horizontal section.
8The TVD tolerance for the future horizontal wells are specified in the range of +/-1.0 metres for an average drilled length of 1000 metres.
8The company has gone in for Liner Segmentation and Inflow Control in the Reservoir Completion Section as this increases recovery through even distribution of flow along the wellbore and facilitating shut-off of premature gas or water ingress.
8Reservoir monitoring is being done through a combination of surface-readout permanent downhole pressure/temperature gauges, memory gauges set in side-pocket mandrels (SPM) and distributed temperature system (DTS) for monitoring inflow along the reservoir section. This will provide data to improve the understanding of inflow distribution and coning along the horizontal sections.
8The tubing size is also been kept at a uniform 3.5 -inch not just for this operation but for all upcoming Panna completions based on expected optimal off take rates and operational considerations
8BG says that conventional gas lift will be used in the future and scaling problems will be mitigated by optimized gas conditioning and/or downhole chemical injection
8A downhole chemical injection process will avoid scaling issues by providing a reliable means of delivering known dosage rates of scale inhibitors below gas lift depth through a dedicated 3/8 “ control line
Click on our Reports section for more. Details
Gujarat State Fertilizers & Chemicals Ltd (GSFC) is planning to set up a petrochemical complex at Dahej (Gujarat) with an estimated capital outlay between Rs 8,000 to 10,000 crore.
8As of now, a feasibility study and a detailed project report (DPR) for the complex is underway.
8GSFC is also shortlisting technology suppliers for the project.
8This will be the second petrochemical complex in Dahej. The first, being set up by ONGC at a whopping cost of Rs 27,011 crore, is likely to be commissioned this month (July 2015). The plant was planned to come on stream by 2012 but delays led to two revisions in completion dates. Details
8As of now, a feasibility study and a detailed project report (DPR) for the complex is underway.
8GSFC is also shortlisting technology suppliers for the project.
8This will be the second petrochemical complex in Dahej. The first, being set up by ONGC at a whopping cost of Rs 27,011 crore, is likely to be commissioned this month (July 2015). The plant was planned to come on stream by 2012 but delays led to two revisions in completion dates. Details
GAIL's Surat-Paradip gas pipeline has already missed its completion target and is still nowhere near completion.
8The pipeline was originally scheduled to be completed by April 2015.
8The authorization for the pipeline was granted in April 2012, to be completed within a time frame of 36 months, that is, by April 2015.
8However, the project got delayed on account of absence of demand tie-ups with customers.
8The pipeline, having a total length of 2112 kms has been planned with a capacity of 74.81 MMSCMD. Of this, 18.70 MMSCMD will be available on a common carrier basis by any third party.
8Though the project has already missed its scheduled completion date, a realistic deadline has not been prepared by GAIL in the absence of customers along the pipeline.
8The pipeline will fulfill the natural gas demand of various districts and regions in Gujarat, Maharashtra, Madhya Pradesh, Chhattisgarh and Odisha.
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8The pipeline was originally scheduled to be completed by April 2015.
8The authorization for the pipeline was granted in April 2012, to be completed within a time frame of 36 months, that is, by April 2015.
8However, the project got delayed on account of absence of demand tie-ups with customers.
8The pipeline, having a total length of 2112 kms has been planned with a capacity of 74.81 MMSCMD. Of this, 18.70 MMSCMD will be available on a common carrier basis by any third party.
8Though the project has already missed its scheduled completion date, a realistic deadline has not been prepared by GAIL in the absence of customers along the pipeline.
8The pipeline will fulfill the natural gas demand of various districts and regions in Gujarat, Maharashtra, Madhya Pradesh, Chhattisgarh and Odisha.
Click here for more information Details
Shortage of domestic gas has not only impacted user industries like fertilizer and power but has also endangered projects that were meant to build transportation infrastructure for the fuel.
8GAIL's Surat-Paradip pipeline is one such project.
8As the work for the construction of the pipeline had failed to take-off, the government had even mulled to issue show-cause notice to GAIL, asking it as to why the pipeline project should not be cancelled for lack of progress on the ground.
8There were also reports that the government might consider cancellation of the contract and re-auction of the project with viability gap funding (VGF) support.
8In the VGF model, a one-time grant is provided to projects that are economically justified but fall short of financial viability. Natural gas pipeline projects, such as the Surat-Paradip pipeline can potentially fall short of viability owing to lack of gas availability or slower growth in demand and also due to market risk from unattractive pricing compared to alternative fuels.
8As of now, it seems, the government has decided to give more time to GAIL to lay the Surat-Paradip pipeline.
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8GAIL's Surat-Paradip pipeline is one such project.
8As the work for the construction of the pipeline had failed to take-off, the government had even mulled to issue show-cause notice to GAIL, asking it as to why the pipeline project should not be cancelled for lack of progress on the ground.
8There were also reports that the government might consider cancellation of the contract and re-auction of the project with viability gap funding (VGF) support.
8In the VGF model, a one-time grant is provided to projects that are economically justified but fall short of financial viability. Natural gas pipeline projects, such as the Surat-Paradip pipeline can potentially fall short of viability owing to lack of gas availability or slower growth in demand and also due to market risk from unattractive pricing compared to alternative fuels.
8As of now, it seems, the government has decided to give more time to GAIL to lay the Surat-Paradip pipeline.
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The Surat-Paradip pipeline was also recently in news when GAIL objected to the Expression of Interest (EOI) submitted by H-Energy -- which is setting up a 6 MMTPA Floating Storage and Re-gasification Unit (FSRU) in the offshore Digha region of West Bengal -- for laying of a natural gas pipeline from Contai (Purba Medinipur district, West Bengal) to Dattapulia (Nadia district, West Bengal) and Paradip (Jagatsinghpur district, Odisha).
8The gas major had argued that there is no requirement for laying of the proposed trunk line from Contai to Dattapulia as the gas demand at Paradip, Bhubaneshwar, Cuttack, Haldia and Kolkata has already been considered on its two authorized gas pipelines -- Jagdishpur-Haldia pipeline (JHPL) and the Surat-Paradip pipeline (SPPL) -- more cost effectively.
8On a ball-park estimate basis, laying down about 250 kms of trunkline (from Contai to Dattapulia) and about 49 kms of spur-lines (to Kolkata, Haldia, Kolaghat and Uluberia) would entail an investment to the tune of Rs 900-1,000 crore, whereas, laying down of an additional 30 kms of spurline from JHPL (upto Dattapulia) and a few spurlines from JHPL to cover Kolaghat and Uluberia would entail an investment to the tune of only Rs 350 crore.
8As per the EOI submitted to the PNGRB, H-energy will lay the pipeline from Contai to Haipur (West Bengal) from where it will go to Paradip, with spur lines to Cuttack and Bhubaneswar and also to Dattapulia with more spur lines to Haldia, Kolaghat, Uluberia and Kolkata.
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8The gas major had argued that there is no requirement for laying of the proposed trunk line from Contai to Dattapulia as the gas demand at Paradip, Bhubaneshwar, Cuttack, Haldia and Kolkata has already been considered on its two authorized gas pipelines -- Jagdishpur-Haldia pipeline (JHPL) and the Surat-Paradip pipeline (SPPL) -- more cost effectively.
8On a ball-park estimate basis, laying down about 250 kms of trunkline (from Contai to Dattapulia) and about 49 kms of spur-lines (to Kolkata, Haldia, Kolaghat and Uluberia) would entail an investment to the tune of Rs 900-1,000 crore, whereas, laying down of an additional 30 kms of spurline from JHPL (upto Dattapulia) and a few spurlines from JHPL to cover Kolaghat and Uluberia would entail an investment to the tune of only Rs 350 crore.
8As per the EOI submitted to the PNGRB, H-energy will lay the pipeline from Contai to Haipur (West Bengal) from where it will go to Paradip, with spur lines to Cuttack and Bhubaneswar and also to Dattapulia with more spur lines to Haldia, Kolaghat, Uluberia and Kolkata.
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With a view to tighten its existing norms, PNGRB is in the process of making suitable changes to its regulations related to setting up of CGD networks and laying of gas and product pipelines.
8The regulatory body collects information and data from entities coming under its purview but now it has decided to seek more details, information and data to improve and strengthen its data bank.
8As per the existing provision, an authorized entity is required to provide, on a quarterly basis, a progress report detailing the clearances obtained, targets achieved, expenditure incurred, works-in-progress and any other relevant information for all the pre-commissioning activities.
8But as per the amended clause, the authorized entity will not only have to provide the pre-commissioning data on a quarterly basis but it will also have to provide additional information and data on a monthly basis.
8Then again, the information and data sought by the Board will also have to be provided post-commissioning of the project.
8Not only this, the authorized entity will have to designate an official for submitting the requisite data to the Board.
8The PNGRB has sought comments and views of all stakeholders on the proposed amendments within a period of 30 days
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8The regulatory body collects information and data from entities coming under its purview but now it has decided to seek more details, information and data to improve and strengthen its data bank.
8As per the existing provision, an authorized entity is required to provide, on a quarterly basis, a progress report detailing the clearances obtained, targets achieved, expenditure incurred, works-in-progress and any other relevant information for all the pre-commissioning activities.
8But as per the amended clause, the authorized entity will not only have to provide the pre-commissioning data on a quarterly basis but it will also have to provide additional information and data on a monthly basis.
8Then again, the information and data sought by the Board will also have to be provided post-commissioning of the project.
8Not only this, the authorized entity will have to designate an official for submitting the requisite data to the Board.
8The PNGRB has sought comments and views of all stakeholders on the proposed amendments within a period of 30 days
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The website carries here, for reference purposes, the revised formats of Schedules (separate for gas pipelines, CGD networks and product pipelines) which will have to be duly filled and submitted to the PNGRB by the authorized entities. The formats of following Schedules are carried:
8Quarterly Progress Report for Natural Gas Pipelines (Schedule E-1-NGPL)
8Monthly Natural Gas Pipeline Report (Schedule E-2-NGPL)
8Quarterly Progress Report for CGD networks (Schedule E-1-CGD)
8Monthly PNG Customer Enrolment Report (Schedule E-2-CGD)
8Monthly CNG Progress Report (Schedule E-3-CGD)
8Monthly Natural Gas Sales Report (Schedule E-4-CGD)
8Quarterly Progress Report for Petroleum Pipelines (Schedule E-1-PPL) Details
8Quarterly Progress Report for Natural Gas Pipelines (Schedule E-1-NGPL)
8Monthly Natural Gas Pipeline Report (Schedule E-2-NGPL)
8Quarterly Progress Report for CGD networks (Schedule E-1-CGD)
8Monthly PNG Customer Enrolment Report (Schedule E-2-CGD)
8Monthly CNG Progress Report (Schedule E-3-CGD)
8Monthly Natural Gas Sales Report (Schedule E-4-CGD)
8Quarterly Progress Report for Petroleum Pipelines (Schedule E-1-PPL) Details
IL&FS Engineering and Construction Company Ltd has successfully commissioned the Gujarat State Petronet Limited's (GSPL) Halol-Godhra-Dahod pipeline project in Gujarat.
8The project included laying 103 kms of high pressure gas transmission pipeline on an EPC basis.
8The pipeline network constitutes a main gas trunkline which will take gas from the existing despatch station of Padmala-Halol pipeline at Halol to the receiving station at Dahod in Gujarat.
8GSPL has developed this infrastructure to cater to the customers in the East Gujarat region.
8The pipeline project passes through wet and dry cultivated fields, rocky terrains and forest zones, which includes major crossing through rivers, canals, roads and railway tracks. Details
8The project included laying 103 kms of high pressure gas transmission pipeline on an EPC basis.
8The pipeline network constitutes a main gas trunkline which will take gas from the existing despatch station of Padmala-Halol pipeline at Halol to the receiving station at Dahod in Gujarat.
8GSPL has developed this infrastructure to cater to the customers in the East Gujarat region.
8The pipeline project passes through wet and dry cultivated fields, rocky terrains and forest zones, which includes major crossing through rivers, canals, roads and railway tracks. Details
Russia's top oil producer Rosneft will buy 49% stake in Essar Oil for about $3.2 billion.
8The deal does not include Essar's five coal-bed methane (CBM) blocks, holding up to 10 trillion cubic feet (TCF) of gas resource as well as Ratna and R-Series oil and gas fields in the western offshore.
8As part of the transaction, the Russian firm will supply 10 million tonnes a year (MMTPA) of crude to Essar Oil's 20 MMTPA Vadinar refinery in Gujarat for 10 years.
8A long-term Crude Oil Supply Agreement (COSA) has been signed between the two companies.
8The COSA signed with a large integrated oil company like Rosneft will help Essar to diversify its supply sources, expand geographical market coverage and enhance supply security.
8The proposed transaction, however, is conditional upon various factors such as due diligence, determination of the transaction price, execution of definitive transaction documents and receipt of requisite approvals.
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8The deal does not include Essar's five coal-bed methane (CBM) blocks, holding up to 10 trillion cubic feet (TCF) of gas resource as well as Ratna and R-Series oil and gas fields in the western offshore.
8As part of the transaction, the Russian firm will supply 10 million tonnes a year (MMTPA) of crude to Essar Oil's 20 MMTPA Vadinar refinery in Gujarat for 10 years.
8A long-term Crude Oil Supply Agreement (COSA) has been signed between the two companies.
8The COSA signed with a large integrated oil company like Rosneft will help Essar to diversify its supply sources, expand geographical market coverage and enhance supply security.
8The proposed transaction, however, is conditional upon various factors such as due diligence, determination of the transaction price, execution of definitive transaction documents and receipt of requisite approvals.
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The US Energy Information Administration (EIA) has projected India's petroleum and other liquids consumption will increase by 0.2 million b/d in 2015 and 2016, compared with 0.1 million b/d in 2014.
8This is on account of rising economic and manufacturing growth.
8Consumption for 2nd, 3rd and 4th quarter for the year 2015 is projected as 4.06 , 3.72 and 4.02 million barrels per day, which averages to 3.97 million barrel per day in 2015.
8Consumption for the year 2016 projected to be 4.16 million barrel per day.
8Crude oil and liquid fuels production growth for India during 2015 and 2016 will remain flat at 0.98 million barrels per day, the same as in the 2014.
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8This is on account of rising economic and manufacturing growth.
8Consumption for 2nd, 3rd and 4th quarter for the year 2015 is projected as 4.06 , 3.72 and 4.02 million barrels per day, which averages to 3.97 million barrel per day in 2015.
8Consumption for the year 2016 projected to be 4.16 million barrel per day.
8Crude oil and liquid fuels production growth for India during 2015 and 2016 will remain flat at 0.98 million barrels per day, the same as in the 2014.
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Our columnist M.K. Malik in an interview with this website, said that the vagaries of the gas pooling system were already known to policy makers and it is rather surprising that these problems are spoken of as of they were unexpected. He is of the view that an input subsidy regime would have been a better option. "The vice lies in the fact that a legal liability is created for GAIL due to the system in place. A input subsidy system, as proposed earlier in this column, would have been a better proposal since subsidy is not treated as a legal liability of the government. It would, further, have been flexible enough to allow the government to either pay the input subsidies along with the other subsidies OR treat it as a separate system and pay input subsidies even while budgetary constraints do not allow payment of regular subsidy," he said," .
Here are the excerpts of the interview:
The gas pooling system seems to be already throwing up some problems?
Malik: The possibility of higher amounts being stuck, awaiting budgets, for units that had, hitherto, been paying lower gas prices was always there and should have been obvious - unless the fertilizer industry and GAIL had assumed that the Government would, somehow, manage to balance its books and retain its fiscal deficit targets while allocating a sufficiency of funds for fertilizer subsidy.
It is surprising that these problems are being spoken of as though they were unexpected hurdles in the way of operationalising gas pooling. In the nature of things, units with lower gas prices originally would end up with increase in working capital requirements, exacerbated by the delays in release of subsidies. Correspondingly, units paying higher gas prices, hitherto, would end up with lowered working capital requirements.
Overall, it should be a zero sum game for the fertilizer industry as a whole.
The problem is essentially that of arranging adequate funding, isn`t it?
Malik: The issue, though, for GAIL is the possibility that the debit notes do not get honored on time whereas the credit notes may need to be honored. The problem, however, is primarily one of financing the amount. Any such system would provide for penal interest for delayed payments and, given that the subsidy shall become payable later and delayed payments can be set off, there cannot be a major issue of default. GAIL, thus, is likely not to lose money on the issue but, yes, it may become liable to stretch its financial resources to pay off credit notes, while some debit notes are honored later than expected.
The vice lies in the fact that a legal liability is created for GAIL due to the system in place. A input subsidy system, as proposed earlier by me in my column, would have been a better proposal since subsidy is not treated as a legal liability of the government. It would, further, have been flexible enough to allow the government to either pay the input subsidies along with the other subsidies OR treat it as a separate system and pay input subsidies even while budgetary constraints do not allow payment of regular subsidy. Since the Input subsidy, itself, is a Zero-sum subsidy - with units cross-subsidizing each other - it would not need budgetary support. AND, as is feared, if some units delay payments, the payments to be made by the government can be similarly delayed. The Government can take the call on passing on the penal interest assessable against the delayed payments.
Will an input subsidy regime work for everyone?
Malik: The system would be as fair, or as unfair, as the one currently in place if both subsidies are kept in abeyance since the previous system anyway left the burden of funding the full cost of the gas to the units till such time subsidies were cleared. If it is delinked, and input subsidy is kept operational even while the regular subsidy is not being paid, it would put an additional burden on units with low direct gas costs (Without input subsidy) and reduce the burden on units with higher direct gas costs. If the fixed costs for the units, which should include the costs of financing working capital, are computed based on their actual gas costs, then it would be unfair to so shift the burden since the interest on working capital for the low-cost units would have been worked out on lower gas costs. One may argue, though, that the low cost units also stand to benefit due to the higher valuation given to their energy savings.
So where does one go from here?
Malik: In any sector of the economy where markets cannot be allowed free reign and systems are put in place to mimic the markets, the results will always be sub-optimal. The issue here, though, is primarily a lack of funds with the government and the perceived importance of maintaining fiscal deficit targets in the budget. Unless a more lasting solution is found to rein in fertilizer subsidy levels, such issues shall continue to plague the industry.
It is tough, though, to sympathize with GAIL since this was an issue that did not even need a genius to anticipate. How it could have escaped them while they rushed in to manage the gas pool is something that very few shall be able to understand. Details
Here are the excerpts of the interview:
The gas pooling system seems to be already throwing up some problems?
Malik: The possibility of higher amounts being stuck, awaiting budgets, for units that had, hitherto, been paying lower gas prices was always there and should have been obvious - unless the fertilizer industry and GAIL had assumed that the Government would, somehow, manage to balance its books and retain its fiscal deficit targets while allocating a sufficiency of funds for fertilizer subsidy.
It is surprising that these problems are being spoken of as though they were unexpected hurdles in the way of operationalising gas pooling. In the nature of things, units with lower gas prices originally would end up with increase in working capital requirements, exacerbated by the delays in release of subsidies. Correspondingly, units paying higher gas prices, hitherto, would end up with lowered working capital requirements.
Overall, it should be a zero sum game for the fertilizer industry as a whole.
The problem is essentially that of arranging adequate funding, isn`t it?
Malik: The issue, though, for GAIL is the possibility that the debit notes do not get honored on time whereas the credit notes may need to be honored. The problem, however, is primarily one of financing the amount. Any such system would provide for penal interest for delayed payments and, given that the subsidy shall become payable later and delayed payments can be set off, there cannot be a major issue of default. GAIL, thus, is likely not to lose money on the issue but, yes, it may become liable to stretch its financial resources to pay off credit notes, while some debit notes are honored later than expected.
The vice lies in the fact that a legal liability is created for GAIL due to the system in place. A input subsidy system, as proposed earlier by me in my column, would have been a better proposal since subsidy is not treated as a legal liability of the government. It would, further, have been flexible enough to allow the government to either pay the input subsidies along with the other subsidies OR treat it as a separate system and pay input subsidies even while budgetary constraints do not allow payment of regular subsidy. Since the Input subsidy, itself, is a Zero-sum subsidy - with units cross-subsidizing each other - it would not need budgetary support. AND, as is feared, if some units delay payments, the payments to be made by the government can be similarly delayed. The Government can take the call on passing on the penal interest assessable against the delayed payments.
Will an input subsidy regime work for everyone?
Malik: The system would be as fair, or as unfair, as the one currently in place if both subsidies are kept in abeyance since the previous system anyway left the burden of funding the full cost of the gas to the units till such time subsidies were cleared. If it is delinked, and input subsidy is kept operational even while the regular subsidy is not being paid, it would put an additional burden on units with low direct gas costs (Without input subsidy) and reduce the burden on units with higher direct gas costs. If the fixed costs for the units, which should include the costs of financing working capital, are computed based on their actual gas costs, then it would be unfair to so shift the burden since the interest on working capital for the low-cost units would have been worked out on lower gas costs. One may argue, though, that the low cost units also stand to benefit due to the higher valuation given to their energy savings.
So where does one go from here?
Malik: In any sector of the economy where markets cannot be allowed free reign and systems are put in place to mimic the markets, the results will always be sub-optimal. The issue here, though, is primarily a lack of funds with the government and the perceived importance of maintaining fiscal deficit targets in the budget. Unless a more lasting solution is found to rein in fertilizer subsidy levels, such issues shall continue to plague the industry.
It is tough, though, to sympathize with GAIL since this was an issue that did not even need a genius to anticipate. How it could have escaped them while they rushed in to manage the gas pool is something that very few shall be able to understand. Details
The High Court of Gujarat has directed the PNGRB to dispose off the application of Essar Power -- seeking relief from paying ship-or-pay charges in the wake of fall in KG-D6 production -- within a time frame.
8The HC has further directed that till a final decision is taken by the PNGRB, GSPL shall not take any coercive action against Essar Power.
8Essar has now been given 10 days time to file its reply in respect of GSPL`s application for modification of the Board`s interim order dated September 27, 2013.
8The PNGRB, through its interim order dated September 27, 2013, had directed Essar to maintain the value of its Letter of Credit equivalent to the GSPL`s outstanding invoices towards "Ship or Pay Charges" within a month (from September 27, 2013).
8Subsequently, GSPL too will be given a time of 10 days to file its additional version, thereafter.
8After the reply and counter-reply are received, the PNGRB will take a final call on the matter.
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8The HC has further directed that till a final decision is taken by the PNGRB, GSPL shall not take any coercive action against Essar Power.
8Essar has now been given 10 days time to file its reply in respect of GSPL`s application for modification of the Board`s interim order dated September 27, 2013.
8The PNGRB, through its interim order dated September 27, 2013, had directed Essar to maintain the value of its Letter of Credit equivalent to the GSPL`s outstanding invoices towards "Ship or Pay Charges" within a month (from September 27, 2013).
8Subsequently, GSPL too will be given a time of 10 days to file its additional version, thereafter.
8After the reply and counter-reply are received, the PNGRB will take a final call on the matter.
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Gujarat State Petroleum Corporation Ltd (GSPC), the operator of the CB-ON/2 block in Tarapur, has drawn up and exploration and development plan totaling up to Rs.1235 crore.
8Block was awarded to the consortium of GSPC, ONGC and GEO GLOBAL BARBADOS INC., GSPC is operator for the block.
8Total of 66 wells will be drilled, The produced associated and non associated gas will be sold to local buyers and also to be used internally in Indirect Bath heater to heat the oil for maintaining the mobility of crude oil for transportation.
8Eight early production systems ( EPSs) would be setup to facilitate handling of produced hydrocarbons from the wells.
8Wells will be connected through underground 4-inch or 6-inch pipe lines to the nearest EPS.
8Individually, the average cost of drilling per well has been pegged at Rs. 18 crore (3000m depth) and Rs 5.8 crore per EPS.
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8Block was awarded to the consortium of GSPC, ONGC and GEO GLOBAL BARBADOS INC., GSPC is operator for the block.
8Total of 66 wells will be drilled, The produced associated and non associated gas will be sold to local buyers and also to be used internally in Indirect Bath heater to heat the oil for maintaining the mobility of crude oil for transportation.
8Eight early production systems ( EPSs) would be setup to facilitate handling of produced hydrocarbons from the wells.
8Wells will be connected through underground 4-inch or 6-inch pipe lines to the nearest EPS.
8Individually, the average cost of drilling per well has been pegged at Rs. 18 crore (3000m depth) and Rs 5.8 crore per EPS.
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The MRPL Board has okayed the company`s amalgamation with ONGC Mangalore Petrochemicals Ltd (OMPL).
8This has been done to bring about better synergy across the group and to ensure that the businesses of these entities are operated in a most efficient and cost-effective manner.
8The Scheme of Amalgamation has been approved by the MRPL board.
8While MRPL is a subsidiary of ONGC, OMPL is a subsidiary of MRPL wherein the company (MRPL) holds 51% and ONGC holds the remaining 49% of the issued, subscribed and paid-up share capital.
8The transaction is between related parties and is being undertaken on an arms’ length basis.
8MRPL is primarily engaged in operating an oil refinery located in Mangalore for processing of crudes and manufacture of petrochemicals, while OMPL is engaged in developing and operating a green field petrochemical project consisting of an aromatic complex.
8Operation of the aromatic plant being integrated with the refinery will provide higher returns for stakeholders adding value to refinery product streams and flexibility to the refinery to optimize its gross refinery margin (GRM).
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8This has been done to bring about better synergy across the group and to ensure that the businesses of these entities are operated in a most efficient and cost-effective manner.
8The Scheme of Amalgamation has been approved by the MRPL board.
8While MRPL is a subsidiary of ONGC, OMPL is a subsidiary of MRPL wherein the company (MRPL) holds 51% and ONGC holds the remaining 49% of the issued, subscribed and paid-up share capital.
8The transaction is between related parties and is being undertaken on an arms’ length basis.
8MRPL is primarily engaged in operating an oil refinery located in Mangalore for processing of crudes and manufacture of petrochemicals, while OMPL is engaged in developing and operating a green field petrochemical project consisting of an aromatic complex.
8Operation of the aromatic plant being integrated with the refinery will provide higher returns for stakeholders adding value to refinery product streams and flexibility to the refinery to optimize its gross refinery margin (GRM).
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The stand-off between Essar Power and GSPL is over payment of ship-or-pay charges.
8Essar Power had entered into a Gas Transmission Agreement (GTA) for KG D-6 gas with Gujarat State Petronet Limited (GSPL) on December 31, 2008, for supply of gas for its Hazira Power Plant in Gujarat having a capacity of 515 MW.
8Under the Gas Transmission Agreement (GTA), GSPL was to raise fortnightly invoices towards billing and payment. It was also provided in the agreement that in case of failure on the part of Essar to make payment on time, GSPL would be entitled to call upon Essar`s Letter of Credit in respect of outstanding amounts.
8Essar, on April 24, 2009, entered into a Gas Sale and Purchase Agreement (GSPA) with RIL and Niko to buy gas from their KG-D6 field
8In 2009, the GTA was amended in part where it was provided that Force Majeure circumstances and events shall not include, among other things, failure or loss of Shipper`s or Transporter`s market for non-availability of gas from the seller.
8On March 31, 2011, the petroleum ministry directed RIL and Niko that due to the reduction in KG-D6 production level, the gas was to be supplied only to the priority core sectors, such as, Fertilizer, LPG, Power and City Gas Distribution (CGD) to meet their firm demands.
8It was further directed that pro-rata cuts would be imposed on the firm demand of the remaining sectors in the event of shortfall in the supply of KG-D6 gas. Accordingly, RIL intimated Essar that a cut in gas supply would be put in force from May 9, 2011.
8Being aware of the matter, the PNGRB, in November 2012, formulated new guidelines -- the Petroleum and Natural Gas Regulatory Board (Development of Model GTA) Guidelines, 2012 -- under which the "Ship or Pay Charges" would exclude gas quantities which have been reduced due to the directions of the government.
8In March 2013, RIL informed Essar that the supply of gas to its Hazira power plant will be fully curtailed due to shortage of KG-D6 gas. Subsequently, Essar sent a notice to GSPL declaring the invocation of Force Majeure as the curtailment of gas supply was because of loss of production from the KG-D6 gas field.
8Essar claimed that no transportation charges would be payable as the event was a Force Majeure.
8However, GSPL sent a few letters to Essar complaining about the non-payment of invoices in respect of transportation of gas and asked it to clear the outstanding amount failing which it would invoke the payment security. Details
8Essar Power had entered into a Gas Transmission Agreement (GTA) for KG D-6 gas with Gujarat State Petronet Limited (GSPL) on December 31, 2008, for supply of gas for its Hazira Power Plant in Gujarat having a capacity of 515 MW.
8Under the Gas Transmission Agreement (GTA), GSPL was to raise fortnightly invoices towards billing and payment. It was also provided in the agreement that in case of failure on the part of Essar to make payment on time, GSPL would be entitled to call upon Essar`s Letter of Credit in respect of outstanding amounts.
8Essar, on April 24, 2009, entered into a Gas Sale and Purchase Agreement (GSPA) with RIL and Niko to buy gas from their KG-D6 field
8In 2009, the GTA was amended in part where it was provided that Force Majeure circumstances and events shall not include, among other things, failure or loss of Shipper`s or Transporter`s market for non-availability of gas from the seller.
8On March 31, 2011, the petroleum ministry directed RIL and Niko that due to the reduction in KG-D6 production level, the gas was to be supplied only to the priority core sectors, such as, Fertilizer, LPG, Power and City Gas Distribution (CGD) to meet their firm demands.
8It was further directed that pro-rata cuts would be imposed on the firm demand of the remaining sectors in the event of shortfall in the supply of KG-D6 gas. Accordingly, RIL intimated Essar that a cut in gas supply would be put in force from May 9, 2011.
8Being aware of the matter, the PNGRB, in November 2012, formulated new guidelines -- the Petroleum and Natural Gas Regulatory Board (Development of Model GTA) Guidelines, 2012 -- under which the "Ship or Pay Charges" would exclude gas quantities which have been reduced due to the directions of the government.
8In March 2013, RIL informed Essar that the supply of gas to its Hazira power plant will be fully curtailed due to shortage of KG-D6 gas. Subsequently, Essar sent a notice to GSPL declaring the invocation of Force Majeure as the curtailment of gas supply was because of loss of production from the KG-D6 gas field.
8Essar claimed that no transportation charges would be payable as the event was a Force Majeure.
8However, GSPL sent a few letters to Essar complaining about the non-payment of invoices in respect of transportation of gas and asked it to clear the outstanding amount failing which it would invoke the payment security. Details
Breakdown of cost for following three contracts has been worked out as follows:
8Construction of jetty head and approach trestle
-- Preliminaries: Rs.2.0 crore
-- Jetty head Construction: Rs.64.3 crore
-- Boat Landing and Control Tower Building: Rs.11.6 crore
-- Approach Trestle Construction: Rs.254.8 crore
-- Miscellaneous: Rs.34.6 crore
-- Total Cost: Rs.367.3 crore
8Mechanical, electrical and fire fighting facilities
-- Preliminaries: Rs.2.0 crore
-- Mechanical, Electrical and Fire fighting: Rs.78.1 crore
-- Pipelines Supply and Construction: Rs.131.4 crore
-- Overhead Electric Line and Substation: Rs.22.0 crore
-- Conversion of existing ONGC Pipeline: Rs. 9.0 crore
-- Miscellaneous: Rs.34.6 crore
-- Total Cost: Rs.277.2 crore
8Dredging
-- Preliminaries: Rs. 2.0 crore
-- J Dredging: Rs.70.0 crore
-- Total Cost: Rs.72.0 crore
8The cost of building the J5 berth is 716.5 Crore.
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8Construction of jetty head and approach trestle
-- Preliminaries: Rs.2.0 crore
-- Jetty head Construction: Rs.64.3 crore
-- Boat Landing and Control Tower Building: Rs.11.6 crore
-- Approach Trestle Construction: Rs.254.8 crore
-- Miscellaneous: Rs.34.6 crore
-- Total Cost: Rs.367.3 crore
8Mechanical, electrical and fire fighting facilities
-- Preliminaries: Rs.2.0 crore
-- Mechanical, Electrical and Fire fighting: Rs.78.1 crore
-- Pipelines Supply and Construction: Rs.131.4 crore
-- Overhead Electric Line and Substation: Rs.22.0 crore
-- Conversion of existing ONGC Pipeline: Rs. 9.0 crore
-- Miscellaneous: Rs.34.6 crore
-- Total Cost: Rs.277.2 crore
8Dredging
-- Preliminaries: Rs. 2.0 crore
-- J Dredging: Rs.70.0 crore
-- Total Cost: Rs.72.0 crore
8The cost of building the J5 berth is 716.5 Crore.
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Cairn India`s target recovery rate is an ambitious 50% of its hydrocarbon reserves of 2.2 billion barrels oil equivalent reserves in its core oil fields of Bhagyam, Mangla and Aishwariya in the Rajasthan block RJ-ON-90/2
8Gross Hydrocarbons In-Place discovered in the block is a massive 4.2 billion boe till FY13 while in FY 14-15, another 1.5 billion boe reserves has been drilled and tested and 0.8 billion boe has been drilled but not tested. These are very large reserves by all standards.
8The company has claimed that its first polymer injection plan as part of the the company`s Enhanced Oil Recovery (EOR) scheme in the flagship Mangla field beginning October, 2014 has been successful and it is currently injecting around 25,000 bbls/day of polymer solution into the field.
8Plans are to extent the EOR programme to the Bhagyam and Aishwariya fields.
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8Gross Hydrocarbons In-Place discovered in the block is a massive 4.2 billion boe till FY13 while in FY 14-15, another 1.5 billion boe reserves has been drilled and tested and 0.8 billion boe has been drilled but not tested. These are very large reserves by all standards.
8The company has claimed that its first polymer injection plan as part of the the company`s Enhanced Oil Recovery (EOR) scheme in the flagship Mangla field beginning October, 2014 has been successful and it is currently injecting around 25,000 bbls/day of polymer solution into the field.
8Plans are to extent the EOR programme to the Bhagyam and Aishwariya fields.
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The website also carries here, for reference purposes, the following details on the Rs 7,255 crore Mallavaram-Bhopal-Bhilwara-Vijaipur (MBBVPL) gas pipeline project:
8Reconnaissance survey
8Detailed route survey
8Pipeline route selection and description
8Salient points and characteristics of the pipeline route
8Cost estimate for ROU acquisition
8Soil stratification and classification survey
8Boreholes and sampling
8Soil resistivity survey
8Soil chemical analysis
8Seismic analysis of pipelines
8Cadastral survey
8Topographical land survey for stations
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8Reconnaissance survey
8Detailed route survey
8Pipeline route selection and description
8Salient points and characteristics of the pipeline route
8Cost estimate for ROU acquisition
8Soil stratification and classification survey
8Boreholes and sampling
8Soil resistivity survey
8Soil chemical analysis
8Seismic analysis of pipelines
8Cadastral survey
8Topographical land survey for stations
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Details of feed-in pipelines connectivities, upgradation and capacity booking rights of promoters for Mallavaram-Bhopal-Bhilwara-Vijaypur pipeline (MBBVPL) are as under:
8Mallavaram end of the pipeline is in immediate vicinity of land-fall point of domestic gas sources of KG-D6 of RIL and Deendayal West (DDW) field of GSPC. It is in close proximity to the proposed LNG terminals on the eastern coast (PLL`s Gangavaram & GAIL/ Shell FSRU at Kakinada).
8The Kakinada-Srikakulam natural gas pipeline will provide ready connectivity to RLNG from the Gangavaram LNG terminal (midway from Kakinada to Srikakulam) being planned by PLL to Mallavaram end.
8Further, connectivity to MBBVPL is also envisaged from Gujarat based LNG Terminals through the Ratlam-Dahod spurline to be connected to GSPL`s Gujarat network.
The promoters would be required to book capacities in the feed-in pipelines for the required volumes. All the feed-in pipelines are being planned to have adequate capacities for requisite volumes.
8GITL has now invited EOIs from prospective industrial consumers who may be interested in obtaining natural gas connections from the MBBVPL.
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8Mallavaram end of the pipeline is in immediate vicinity of land-fall point of domestic gas sources of KG-D6 of RIL and Deendayal West (DDW) field of GSPC. It is in close proximity to the proposed LNG terminals on the eastern coast (PLL`s Gangavaram & GAIL/ Shell FSRU at Kakinada).
8The Kakinada-Srikakulam natural gas pipeline will provide ready connectivity to RLNG from the Gangavaram LNG terminal (midway from Kakinada to Srikakulam) being planned by PLL to Mallavaram end.
8Further, connectivity to MBBVPL is also envisaged from Gujarat based LNG Terminals through the Ratlam-Dahod spurline to be connected to GSPL`s Gujarat network.
The promoters would be required to book capacities in the feed-in pipelines for the required volumes. All the feed-in pipelines are being planned to have adequate capacities for requisite volumes.
8GITL has now invited EOIs from prospective industrial consumers who may be interested in obtaining natural gas connections from the MBBVPL.
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GSPL India Transco Limited's (GITL) Mallavaram-Bhopal-Bhilwara-Vijaipur (MBBVPL) gas pipeline has already missed its completion target and is nowhere near completion even after one year of missing its deadline.
8The pipelines was originally scheduled to be completed by July 2014.
8The pipeline, having a total length of 2042 kms (with spurlines), has been planned with a capacity of 76.25 MMSCMD.
8The authorization for the pipeline was granted in July 2011, with a scheduled completion deadline of July 2014.
8However, the project got delayed on account of statutory clearances and absence of demand tie-ups with customers.
8Engineers India Ltd (EIL) is the project management consultancy (PMC) for the cross-country natural gas pipeline project.
8GITL, the company laying the pipeline, has been formed as a Special Purpose Vehicle (SPV), with GSPL as the lead partner of the consortium with 52% equity holding, followed by IOC with 26% and HPCL and BPCL holding 11% each.
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8The pipelines was originally scheduled to be completed by July 2014.
8The pipeline, having a total length of 2042 kms (with spurlines), has been planned with a capacity of 76.25 MMSCMD.
8The authorization for the pipeline was granted in July 2011, with a scheduled completion deadline of July 2014.
8However, the project got delayed on account of statutory clearances and absence of demand tie-ups with customers.
8Engineers India Ltd (EIL) is the project management consultancy (PMC) for the cross-country natural gas pipeline project.
8GITL, the company laying the pipeline, has been formed as a Special Purpose Vehicle (SPV), with GSPL as the lead partner of the consortium with 52% equity holding, followed by IOC with 26% and HPCL and BPCL holding 11% each.
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Along with the Mallavaram-Bhopal-Bhilwara-Vijaipur (MBBVPL) gas pipeline, GITL has also been authorized to lay a pipeline from Dahod (Gujarat) to Ratlam (Madhya Pradesh) which will be connected to MBBVPL.
8The Dahod-Ratlam pipeline will have a capacity of 2 MMSCMD.
8The total project cost of the MBBVPL is estimated at Rs 7,255 crore, including the Dahod-Ratlam connectivity.
8With this pipeline, gas will also be made available to customers in the Dahod district of Gujarat. Overall, the 2042-km-long pipeline, will transport gas from the KG basin in Andhra Pradesh, East Coast of India and also from Chittorgarh to Vijaipur traversing through six states and will cater to all the demand centers along the route in Andhra Pradesh (2 districts), Telangana (4 disctricts), Maharashtra (4 districts), Madhya Pradesh (16 districts), Rajasthan (2 districts) and Gujarat (1 district).
8A pictorial map of the pipeline is also carried by the website.
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8The Dahod-Ratlam pipeline will have a capacity of 2 MMSCMD.
8The total project cost of the MBBVPL is estimated at Rs 7,255 crore, including the Dahod-Ratlam connectivity.
8With this pipeline, gas will also be made available to customers in the Dahod district of Gujarat. Overall, the 2042-km-long pipeline, will transport gas from the KG basin in Andhra Pradesh, East Coast of India and also from Chittorgarh to Vijaipur traversing through six states and will cater to all the demand centers along the route in Andhra Pradesh (2 districts), Telangana (4 disctricts), Maharashtra (4 districts), Madhya Pradesh (16 districts), Rajasthan (2 districts) and Gujarat (1 district).
8A pictorial map of the pipeline is also carried by the website.
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The 2042 km long Mallavaram-Bhopal-Bhilwara-Vijaipur (MBBVPL) gas pipeline (including spurlines and the Dahod-Ratlam section) will have an initial pipeline capacity of 54.86 MMSCMD with a provision for ramp up upto 78.25 MMSCMD.
8The pipeline will also work on a common carrier principal.
8In the first year of operations, the MBBVPL will have a pipeline capacity of 54.86 MMSCMD, with 13.71 MMSCMD to be transported on a common carrier principal.
8In the 13th year, the capacity will be raised to 58.99 MMSCMD, with 14.75 MMSCMD as the common carrier capacity.
8In 20th year, the total capacity will got up to 71.16 MMSCMD, with 17.79 MMSCMD as common carrier gas.
8By 24th year, the pipeline capacity will reach 78.25 MMSCMD, with 19.56 MMSCMD as the common carrier capacity.
8The MBBVPL will be hooked up with the Mehsana-Bhatinda (MBPL) at Bhilwara (Rajasthan).
8The pipeline has been designed in such a way that gas can be injected in the pipeline at both Mallavaram and Bhilwara.
8This will help in flowing of volumes from Mehsana into central India and volumes from the KG basin (Kakinada) into central as well as north India.
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8The pipeline will also work on a common carrier principal.
8In the first year of operations, the MBBVPL will have a pipeline capacity of 54.86 MMSCMD, with 13.71 MMSCMD to be transported on a common carrier principal.
8In the 13th year, the capacity will be raised to 58.99 MMSCMD, with 14.75 MMSCMD as the common carrier capacity.
8In 20th year, the total capacity will got up to 71.16 MMSCMD, with 17.79 MMSCMD as common carrier gas.
8By 24th year, the pipeline capacity will reach 78.25 MMSCMD, with 19.56 MMSCMD as the common carrier capacity.
8The MBBVPL will be hooked up with the Mehsana-Bhatinda (MBPL) at Bhilwara (Rajasthan).
8The pipeline has been designed in such a way that gas can be injected in the pipeline at both Mallavaram and Bhilwara.
8This will help in flowing of volumes from Mehsana into central India and volumes from the KG basin (Kakinada) into central as well as north India.
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The following facilities are planned:
8Storage facility:
-- Four overhead tanks having capacity of 45 m3.
8Separation Facility:
-- Two vertical phase separator with handling capacity of 1500 BBL per day and 3.5 MMSCFD, working pressure to be maintained at 10 Kg.cm2.
8Heating Facility:
-- One Indirect water bath heater with heating capacity of 20-30 Deg C( Inlet) and 50-70 Deg C( Outlet).
-- Amount of fluid to be heated is 15.0 MT/Hr.
8Treatment Facility:
-- One heater treater with handling capacity of 1500 BBL/day.
-- Two chemical dozing reciprocating metering pump.
8Oil Loading Platform
8Effluent water drain pit:
-- Two RCC tank with 100 SCM capacity.
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8Storage facility:
-- Four overhead tanks having capacity of 45 m3.
8Separation Facility:
-- Two vertical phase separator with handling capacity of 1500 BBL per day and 3.5 MMSCFD, working pressure to be maintained at 10 Kg.cm2.
8Heating Facility:
-- One Indirect water bath heater with heating capacity of 20-30 Deg C( Inlet) and 50-70 Deg C( Outlet).
-- Amount of fluid to be heated is 15.0 MT/Hr.
8Treatment Facility:
-- One heater treater with handling capacity of 1500 BBL/day.
-- Two chemical dozing reciprocating metering pump.
8Oil Loading Platform
8Effluent water drain pit:
-- Two RCC tank with 100 SCM capacity.
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Power requirement will be of 662.5 KVA, both for rig and lighting purposes, which is to be met through two DG sets.
8Fuel consumption per well will be 5-10 KLPD diesel used mainly during drilling rig operation.
8Water requirement per well site wil be 40 KLD.
8Power requirement for early production systems (EPS) will be sourced from Gujarat Electricity Board.
8Each EPS will consume 100HP for its operation and 20 KVA for lighting.
8In case of power failure, fuel consumption of 10 to 15 Liters per hour of diesel is required in D.G. set( 82.5 KVA capacity).
8Required 15 KLPD of water will be made available through water bore wells.
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8Fuel consumption per well will be 5-10 KLPD diesel used mainly during drilling rig operation.
8Water requirement per well site wil be 40 KLD.
8Power requirement for early production systems (EPS) will be sourced from Gujarat Electricity Board.
8Each EPS will consume 100HP for its operation and 20 KVA for lighting.
8In case of power failure, fuel consumption of 10 to 15 Liters per hour of diesel is required in D.G. set( 82.5 KVA capacity).
8Required 15 KLPD of water will be made available through water bore wells.
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Mumbai Port Trust (MbPT) is planning to construct a fifth oil berth (dubbed J5) that can berth 150,000 DWT oil tankers (Fully Laden Suezmax) and 250,000 DWT tankers (lightly loaded VLCC’s).
8There are four jetties currently, known as J1, J2, J3 and J4, located in offshore to the Jawahar Deep (Island).
8According to MbPT, J4 would outline its useful life by 2014 and what is more, the approach jetty attached to J4 has been badly damaged due to what is being dubbed as "saline culture".
8Oil refineries in the vicinity has insisted with the port authorities that a facility is required to handle fully laden Suez Max tankers for crude import as soon as possible to handle the load.
8With expanding refining capacity of the different oil companies catered by the port, the crude oil traffic is increasing while port handling facilities have not kept pace.
8Therefore, the need to construct an additional jetty for handling fully laden Suez Max tankers has been proposed by MbPT.
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8There are four jetties currently, known as J1, J2, J3 and J4, located in offshore to the Jawahar Deep (Island).
8According to MbPT, J4 would outline its useful life by 2014 and what is more, the approach jetty attached to J4 has been badly damaged due to what is being dubbed as "saline culture".
8Oil refineries in the vicinity has insisted with the port authorities that a facility is required to handle fully laden Suez Max tankers for crude import as soon as possible to handle the load.
8With expanding refining capacity of the different oil companies catered by the port, the crude oil traffic is increasing while port handling facilities have not kept pace.
8Therefore, the need to construct an additional jetty for handling fully laden Suez Max tankers has been proposed by MbPT.
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Cairn has estimated that its gas production potential from the Rajasthan block can go up to 15-20,000 boe per day.
8Reserves could be anywhere between 1-3 TCF of GIIP, with the recovery rate of around 50%.
8The Management Committee of the block has approved an investment plan of $500 million, based on a Field Development Plan that assumes a production of 100 mmscfd (2.83 mmscmd).
8The accompanying gas processing terminal is currently under tendering and LOIs are to be issued subsequently.
8The project is to be completed by end of 2016-17, subject to regulatory approvals.
8Gas sales in 2014-15 was 9 mmscfd against a production of 16 mmscfd.
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8Reserves could be anywhere between 1-3 TCF of GIIP, with the recovery rate of around 50%.
8The Management Committee of the block has approved an investment plan of $500 million, based on a Field Development Plan that assumes a production of 100 mmscfd (2.83 mmscmd).
8The accompanying gas processing terminal is currently under tendering and LOIs are to be issued subsequently.
8The project is to be completed by end of 2016-17, subject to regulatory approvals.
8Gas sales in 2014-15 was 9 mmscfd against a production of 16 mmscfd.
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Cairn India's focus seems to be a new area -- dubbed as the Barmer Hill and Satellite fields -- which has been projected to have more 2 billion boe of reserves. The recovery factor is not as high as in the other fields, and has been taken at around 10-15%.
8That is a big find by any yardstick.
8The company drilled eight horizontal wells and four verticals last year. The laterals were successfully drilled up to lengths of 800 to 1200 metres.
8Barmer Hill is a tight oil reservoir.
8Cairn has shown that the cost of drilling and well completion per well was in the range of $ 5-7 as against the US average of $5-9.
8The company is now confident of high productivity from this reservoirs. Already it claims to have set a record in India by pumping three frac stages in a day.
8Peak production from the area will be around 25,000 kboepd
8Clearly, contractors can look for big business coming out from here.
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8That is a big find by any yardstick.
8The company drilled eight horizontal wells and four verticals last year. The laterals were successfully drilled up to lengths of 800 to 1200 metres.
8Barmer Hill is a tight oil reservoir.
8Cairn has shown that the cost of drilling and well completion per well was in the range of $ 5-7 as against the US average of $5-9.
8The company is now confident of high productivity from this reservoirs. Already it claims to have set a record in India by pumping three frac stages in a day.
8Peak production from the area will be around 25,000 kboepd
8Clearly, contractors can look for big business coming out from here.
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Global oil supply capacity growth looks significantly lower than expected in the years to 2020 as lower prices slash investments, according to the International Energy Agency (IEA).
8Despite a plunge in oil prices of more than 50%, global capacity is expected to increase to 103.2 mb/d over the next six years, a 5.2 mb/d gain.
8Two thirds of this growth will come from non-OPEC producers.
8Despite OPEC’s stated policy of defending market share, its own crude capacity is only projected to gain 1.2 mb/d, an average of 200 kb/d per annum.
8Iraq alone accounts for almost all of the increment, as other producers curtail spending or struggle with low prices and security issues.
8Non-OPEC supply is forecast to reach 60 mb/d by 2020, with growth slowing to an average annual 570 kb/d.
8That growth rate is far below the record gains of 1.9 mb/d in 2014, and down from an average 1 mb/d in 2008-13. Details
8Despite a plunge in oil prices of more than 50%, global capacity is expected to increase to 103.2 mb/d over the next six years, a 5.2 mb/d gain.
8Two thirds of this growth will come from non-OPEC producers.
8Despite OPEC’s stated policy of defending market share, its own crude capacity is only projected to gain 1.2 mb/d, an average of 200 kb/d per annum.
8Iraq alone accounts for almost all of the increment, as other producers curtail spending or struggle with low prices and security issues.
8Non-OPEC supply is forecast to reach 60 mb/d by 2020, with growth slowing to an average annual 570 kb/d.
8That growth rate is far below the record gains of 1.9 mb/d in 2014, and down from an average 1 mb/d in 2008-13. Details
As low oil prices have clear knock-on effects on upstream investments, oil and gas companies are responding to the new market environment by cutting their capital expenditure programs, according to the International Energy Agency (IEA).
8Budgets for 2015 have already shrunk, and in the absence of a meaningful price recovery, deeper cuts will follow.
8Companies are refocusing on core assets while putting large investments through a much tougher vetting process.
8Amid squeezed cash flows, costly, low-return projects are being cancelled.
8As a result, growth in global gas production is set to slow.
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8Budgets for 2015 have already shrunk, and in the absence of a meaningful price recovery, deeper cuts will follow.
8Companies are refocusing on core assets while putting large investments through a much tougher vetting process.
8Amid squeezed cash flows, costly, low-return projects are being cancelled.
8As a result, growth in global gas production is set to slow.
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The refinery has a Captive Power Plant for meeting the requirement of steam and power. There are 5
boilers, each of 75 MT/hr capacity and three Turbo Generators (TG), two of 12 MW capacity
8The power station has a Demineralization plant to meet the boiler feed water requirement and an independent cooling tower.
8In addition to three TG`s, there are two Gas Turbines ( GT`s) of 20 MW each, integrated with HRSG, each of 40 MT/hr steam generation capacity.
8Peak demand for power at the existing refinery operation is of the order of 42 MW. This is being met
from the existing system by operating 5 boilers, each of 75 MT/hr steam generation capacity and 3 turbo generators, two of 12 MW and one of 12.5 MW capacity and the GTs.
8This will go up to 52.5 MW after the commissioning of the new facilities. One Steam Turbine Generator (STG) of 20 MW capacity with one boiler of 150 MT/hr capacity are now to be added, which will be integrated to the existing CPP (Captive Power Plant).
8After implementation of all the facilities, a total 4 boilers (3 Existing + 1 New) and 2 GTs (existing) and 1 TG (new) will be in operation.
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boilers, each of 75 MT/hr capacity and three Turbo Generators (TG), two of 12 MW capacity
8The power station has a Demineralization plant to meet the boiler feed water requirement and an independent cooling tower.
8In addition to three TG`s, there are two Gas Turbines ( GT`s) of 20 MW each, integrated with HRSG, each of 40 MT/hr steam generation capacity.
8Peak demand for power at the existing refinery operation is of the order of 42 MW. This is being met
from the existing system by operating 5 boilers, each of 75 MT/hr steam generation capacity and 3 turbo generators, two of 12 MW and one of 12.5 MW capacity and the GTs.
8This will go up to 52.5 MW after the commissioning of the new facilities. One Steam Turbine Generator (STG) of 20 MW capacity with one boiler of 150 MT/hr capacity are now to be added, which will be integrated to the existing CPP (Captive Power Plant).
8After implementation of all the facilities, a total 4 boilers (3 Existing + 1 New) and 2 GTs (existing) and 1 TG (new) will be in operation.
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IOCL Barauni Refinery`s BS-IV project for quality up-gradation of both MS and HSD has an outlay of Rs.1327 crore.
8Refining Capacity of 6.0 MMTPA will remain the same, however capacity of some units are proposed to be revamped to meet BS-IV standard for petrol and diesel.
8Following are the details:
-- Naphtha Hydro Treating Unit( NHTU) expansion from 0.3 MMTPA to 0.47 MMTPA.
-- Catalytic Reforming Unit( CRU) revamp from 0.3 MMTPA to 0.47 MMTPA.
-- Diesel Hydro Treating Unit( DHDT) revamp from 2.2 MMTPA to 3.3 MMTPA.
-- Additional new Naphtha Splitter Unit( NSU) to enhance the present capacity of 0.464 MMTPA to 0.76 MMTPA.
-- Additional new Cracked Gasoline De-sulphurisation Unit to enhance present capacity of 0.4 MMTPA to 0.76 MMTPA
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8Refining Capacity of 6.0 MMTPA will remain the same, however capacity of some units are proposed to be revamped to meet BS-IV standard for petrol and diesel.
8Following are the details:
-- Naphtha Hydro Treating Unit( NHTU) expansion from 0.3 MMTPA to 0.47 MMTPA.
-- Catalytic Reforming Unit( CRU) revamp from 0.3 MMTPA to 0.47 MMTPA.
-- Diesel Hydro Treating Unit( DHDT) revamp from 2.2 MMTPA to 3.3 MMTPA.
-- Additional new Naphtha Splitter Unit( NSU) to enhance the present capacity of 0.464 MMTPA to 0.76 MMTPA.
-- Additional new Cracked Gasoline De-sulphurisation Unit to enhance present capacity of 0.4 MMTPA to 0.76 MMTPA
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IOCL is planning to convert its Gujarat refinery into a 100% BS-IV quality compliant unit from MS and HSD at an estimated cost of Rs.2166 crore.
8Over the years, capacity of the refinery has been expanded to the current installed capacity of 13.7 MMTPA with addition of new primary and secondary processing facilities.
8At present refinery is producing 1.6 MMTPA MS,out of which 1.0 MMTPA is BS-III MS and 0.6 MMTPA BS-IV is being produced.
8On the other hand, HSD production amounts to 6.5 MMTPA, out of which 5.9 MMTPA of BS-III HSD and 0.6 MMTPA is BS-IV compliant HSD.
8The refinery has hydrogen production capacity of 183 KNm3 per hour against a total hydrogen consumption of 167 KNm3 per hour. This capacity will be augment to meet the need of producing higher quality fuels.
8The project will be mechanically completed within 20 months from capital approval date, and commissioned by 1.5 months thereafter.
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8Over the years, capacity of the refinery has been expanded to the current installed capacity of 13.7 MMTPA with addition of new primary and secondary processing facilities.
8At present refinery is producing 1.6 MMTPA MS,out of which 1.0 MMTPA is BS-III MS and 0.6 MMTPA BS-IV is being produced.
8On the other hand, HSD production amounts to 6.5 MMTPA, out of which 5.9 MMTPA of BS-III HSD and 0.6 MMTPA is BS-IV compliant HSD.
8The refinery has hydrogen production capacity of 183 KNm3 per hour against a total hydrogen consumption of 167 KNm3 per hour. This capacity will be augment to meet the need of producing higher quality fuels.
8The project will be mechanically completed within 20 months from capital approval date, and commissioned by 1.5 months thereafter.
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Indian state-owned oil companies are pursuing opportunities to lift additional cargoes of Canadian crude and also enter into long-term offtake contracts, in line with efforts to reduce their dependence on the Middle East, according to Platts' report.
8"OPEC is an important club for our crude oil procurement, but simultaneously we would like to diversify our strategy and go by our economic interests and long-term relations," Indian petroleum minister Dharmendra Pradhan said over the weekend in Calgary, on the sidelines of an energy partnership forum hosted by ONGC Videsh Ltd.
8India is expanding its import base by procuring increasing volumes of crude from Latin America and West Africa and would like to include Canada too, Pradhan said.
8The Middle East currently accounts for 63.5% of IOC's total crude imports, with just 2.2% being sourced from North America including Mexico and Canada.
8Pradhan met Greg Rickford, Minister of Natural Resources of Canada, in Calgary, Alberta, for the 2nd India-Canada Ministerial Energy Dialogue to discuss enhancing energy cooperation between the two countries in the areas of oil, natural gas and clean energy, among others. Details
8"OPEC is an important club for our crude oil procurement, but simultaneously we would like to diversify our strategy and go by our economic interests and long-term relations," Indian petroleum minister Dharmendra Pradhan said over the weekend in Calgary, on the sidelines of an energy partnership forum hosted by ONGC Videsh Ltd.
8India is expanding its import base by procuring increasing volumes of crude from Latin America and West Africa and would like to include Canada too, Pradhan said.
8The Middle East currently accounts for 63.5% of IOC's total crude imports, with just 2.2% being sourced from North America including Mexico and Canada.
8Pradhan met Greg Rickford, Minister of Natural Resources of Canada, in Calgary, Alberta, for the 2nd India-Canada Ministerial Energy Dialogue to discuss enhancing energy cooperation between the two countries in the areas of oil, natural gas and clean energy, among others. Details
During his visit to Canada, Indian petroleum minister, Dharmendra Pradhan, said that IOC's 300,000 barrels/day (b/d) new refinery at Paradip in the East Coast, which is now in the final stages of full commissioning, could process Canadian heavy crude, according to Platts' report.
8Previously Indian refineries were limited in the grades of crude they could process.
8India's capability and capacity has now changed and it can process heavy, sour and lighter grades.
8Based on current forecasts, India's oil imports are likely to double to 6 million b/d by 2030, from 3 million b/d in 2013.
8IOC last year bought about 1 million barrels of White Rose light crude produced by Husky Energy from its offshore acreage in Canada's Newfoundland and Labrador.
8IOC Chairman B. Ashok, who is with Pradhan in Canada, said that though it will be difficult to say with certainty what would be a suitable price for India to lift both Canadian heavy and light grades, the company will look at deriving refining margins of $3-4/barrel from the Canadian grades that it plans to import," according to Platts'.
8"The Middle East has an advantage in terms of proximity to India compared with Canada, reduced shipping time and less time for inventory blockage. However, the process of looking at other oil producers has already started and in financial year 2014-15 we added eight new grades of crudes to our import basket taking our total to 174," Ashok said.
8Of the eight new grades of crudes, three are Canadian grades, namely Western Access Blend, Cold Lake Blend and Western Canadian Select. Details
8Previously Indian refineries were limited in the grades of crude they could process.
8India's capability and capacity has now changed and it can process heavy, sour and lighter grades.
8Based on current forecasts, India's oil imports are likely to double to 6 million b/d by 2030, from 3 million b/d in 2013.
8IOC last year bought about 1 million barrels of White Rose light crude produced by Husky Energy from its offshore acreage in Canada's Newfoundland and Labrador.
8IOC Chairman B. Ashok, who is with Pradhan in Canada, said that though it will be difficult to say with certainty what would be a suitable price for India to lift both Canadian heavy and light grades, the company will look at deriving refining margins of $3-4/barrel from the Canadian grades that it plans to import," according to Platts'.
8"The Middle East has an advantage in terms of proximity to India compared with Canada, reduced shipping time and less time for inventory blockage. However, the process of looking at other oil producers has already started and in financial year 2014-15 we added eight new grades of crudes to our import basket taking our total to 174," Ashok said.
8Of the eight new grades of crudes, three are Canadian grades, namely Western Access Blend, Cold Lake Blend and Western Canadian Select. Details
Mitsubishi Heavy Industries Ltd (MHI), which has been awarded an engineering, procurement and construction (EPC) order for construction of two LNG storage tanks at Ennore by IOC, plans to complete the work by Q2 (April-June), 2018.
8The LNG tanks will be the main facility at the first LNG receiving terminal to be constructed at Ennore on the east coast.
8The ordered LNG tanks are high-capacity storage tanks capable of holding 180,000m3 each.
8The terminal will initially have the capacity to handle 5 MMTPA (million metric tonnes per annum), which will be later increased to 15 MMTPA.
8The LNG imported to the terminal will be supplied as feedstock to fertilizer plants and also to utility company power generation plants for use as an alternative fuel. The company also plans to supply gas to CGD companies in the future. Details
8The LNG tanks will be the main facility at the first LNG receiving terminal to be constructed at Ennore on the east coast.
8The ordered LNG tanks are high-capacity storage tanks capable of holding 180,000m3 each.
8The terminal will initially have the capacity to handle 5 MMTPA (million metric tonnes per annum), which will be later increased to 15 MMTPA.
8The LNG imported to the terminal will be supplied as feedstock to fertilizer plants and also to utility company power generation plants for use as an alternative fuel. The company also plans to supply gas to CGD companies in the future. Details
BPCL has awarded a contract for supply of fresh catalyst for its Catalytic Cracking Unit (CCU) installed at its Mumbai Refinery to WR Grace Singapore Pte Ltd.
8The cost of the contract is Rs 13.05 crore.
8The contract has been awarded on L-1 basis.
8A total of four offers were received against the tender, of which three got disqualified on technical grounds.
8The three bidders which got rejected were: Albarmale Catalyst Co., BASF South-East Asia Pte Ltd and the China Petroleum Technology & Development Corporation (CPTDC).
8The supplies have to be completed before May 14, 2017.
8Fabrication of 2x70 KL tanks and piping works: BPCL has also awarded a contract for fabrication and erection of 2x70 KL above-ground (AG) tanks and piping works at RDI, Lalgarh, to Tridot Engineers.
8There were two other bidders in the fray -- Dee Gee Saw & Metal Works and Reliable Engineering Industries -- but the contract was awarded to Tridot after it emerged as the L-1 bidder.
8The scheduled date of completion is July 27, 2015. Details
8The cost of the contract is Rs 13.05 crore.
8The contract has been awarded on L-1 basis.
8A total of four offers were received against the tender, of which three got disqualified on technical grounds.
8The three bidders which got rejected were: Albarmale Catalyst Co., BASF South-East Asia Pte Ltd and the China Petroleum Technology & Development Corporation (CPTDC).
8The supplies have to be completed before May 14, 2017.
8Fabrication of 2x70 KL tanks and piping works: BPCL has also awarded a contract for fabrication and erection of 2x70 KL above-ground (AG) tanks and piping works at RDI, Lalgarh, to Tridot Engineers.
8There were two other bidders in the fray -- Dee Gee Saw & Metal Works and Reliable Engineering Industries -- but the contract was awarded to Tridot after it emerged as the L-1 bidder.
8The scheduled date of completion is July 27, 2015. Details
The revamp will not entail any new addition of units but will be done in the following manner:
8Diesel Hydrogenating Unit( DHDT) capacity to be revamped and raised by 30% from 2.2 MMTPA to 2.86 MMTPA,
8Diesel Hydro-desulphurization Unit( DHDS) capacity to be hiked from 1.77 MMTPA to 2.2 MMTPA
8Vaccum Gas oil Hydro-Treater( VGO-HDT) unit will be revamped.
8Additional Hydrogen requirement of 42 KNm3 per hour will come from revamping of existing HGU-III by 30%.
Distribution of additional hydrogen requirement in the revamped units will be as follows:
-- DHDT will require 20000 Nm3 per hour
-- DHDS will require 4400 Nm3 per hour
-- VGO-HDT will require 13400 Nm3 per hour
-- Contingency at 10% will require 3780 Nm3 per hour
8Large amount of new piping interconnections will be required to connect all the HSD streams to DHDT feed tanks.
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8Diesel Hydrogenating Unit( DHDT) capacity to be revamped and raised by 30% from 2.2 MMTPA to 2.86 MMTPA,
8Diesel Hydro-desulphurization Unit( DHDS) capacity to be hiked from 1.77 MMTPA to 2.2 MMTPA
8Vaccum Gas oil Hydro-Treater( VGO-HDT) unit will be revamped.
8Additional Hydrogen requirement of 42 KNm3 per hour will come from revamping of existing HGU-III by 30%.
Distribution of additional hydrogen requirement in the revamped units will be as follows:
-- DHDT will require 20000 Nm3 per hour
-- DHDS will require 4400 Nm3 per hour
-- VGO-HDT will require 13400 Nm3 per hour
-- Contingency at 10% will require 3780 Nm3 per hour
8Large amount of new piping interconnections will be required to connect all the HSD streams to DHDT feed tanks.
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The expected schedule for the project implementation is 35 months from obtaining budgetary offer and expected time for completion is 21.5 months from investment approval.
8Detailed Feasibility Report preparation by consultant is expected to be completed by July 2015.
8Submission and approval of DFR should take maximum of 2 month, by Sept 2015.
8EPCM line up and Detail Engineering right up to the purchase order (Enquiry preparation , NIT, Bid submission, Offer evaluation, Price negotiation, approval, order placement) is to be completed in 4months time, by Jan 2016.
8Equipment delivery is to be completed in 16 months time, by June 2017.
8Finally, execution (Installation and commissioning is to be completed in 1.5 months time, by June 2017.
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8Detailed Feasibility Report preparation by consultant is expected to be completed by July 2015.
8Submission and approval of DFR should take maximum of 2 month, by Sept 2015.
8EPCM line up and Detail Engineering right up to the purchase order (Enquiry preparation , NIT, Bid submission, Offer evaluation, Price negotiation, approval, order placement) is to be completed in 4months time, by Jan 2016.
8Equipment delivery is to be completed in 16 months time, by June 2017.
8Finally, execution (Installation and commissioning is to be completed in 1.5 months time, by June 2017.
Click here on our Report section for more. Details
The Pre project activity price tag is cost Rs 53 crore over a period of one year.
8Balance pre-project work, involving 40% of the EPCM fee and 60% of P&M cost will cumulatively add up to Rs 1046 crore during 2nd year.
820% of EPCM cost and 30% of P&M will cost another Rs 508 crore during 3rd year.
8Balance 559 crore will be spent during 4th year.
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8Balance pre-project work, involving 40% of the EPCM fee and 60% of P&M cost will cumulatively add up to Rs 1046 crore during 2nd year.
820% of EPCM cost and 30% of P&M will cost another Rs 508 crore during 3rd year.
8Balance 559 crore will be spent during 4th year.
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