Chief Engineer at the country’s Federal Power Ministry, Ghanshyam Prasad, said coal capacity is likely to reach 238GW by 2022
India expects coal-fired power capacity to grow by 22% in three years. That’s according to the Chief Engineer at the country’s Federal Power Ministry, Ghanshyam Prasad, who Reuters reported as stating coal capacity is likely to reach 238GW by 2022.
India’s Coal Minister, Pralhad Joshi previously said annual coal demand rose by 9.1% during the year ending March 2019, noting the figure hit 991.35 million tonnes, driven primarily by utilities, which accounted for three-quarters of total demand.
India’s electricity demand rose by 36% in the seven years up to April 2019, while coal-fired generation capacity during the period rose by three-quarters to 194.44GW.
The vast expenditure on renewables during the past decade has seen installed capacity equivalent to a mere 2% of global energy demand. The world remains and will remain dependent on fossil fuels well into the 21st century if not beyond.
A new report by Woods MAckenzie forecasts that coal, oil and gas will still contribute about 85 per cent of primary energy supply by 2040, compared with 90 per cent today, jeopardising efforts to contain the worst impacts of climate change.
Energy consultancy Wood Mackenzie said 1 TW of installed solar and wind capacity makes up around 8 per cent of total power generation as of 2019. This equates to just a fraction of total energy consumption.
The deamnd for energy is not coming from teh developed western economies, it is the emergining economic playing catch-up in Asia and Africa that will see an increase in energy deamnd of 25% though 2040.
If the World was to aggressively pursue compliance with the PAris accord and the Green New Deal, developing countries would be forever remain in energy deficit and the wealth transfer that is renewable subsidies would continue to enrich the top 1%.
Renewables have a role to play where they can be supported by economics, particularly in remote areas lacking energy infrastructure, but for much of the world, fossil fuels will remain the energy source of choice for at least the next 50 years.
On April 20, 2010, in the Gulf of Mexico on the BP-operated Macondo Prospect, a catastrophic failure on the Deepwater Horizon platform resulted in a massive oil spill considered to be the largest marine oil spill in the history of the petroleum industry and estimated to be 8% to 31% larger in volume than the previous largest, the Ixtoc oil spill, also in the Gulf of Mexico.
The U.S. Federal Government estimated the total discharge at 4.9 million barrels (210 million US gal; 780,000 m3). After several failed efforts to contain the flow, the well was declared sealed on September 19, 2010.
The ultimate cause of the blow-out was a poor cement job, undetected because a Bond Log was not conducted. This resulted in ingress of formation fluids into the well-bore when heavy drilling mud was circulated out and replaced with sea-water, placing the well in an under-balanced situation, prior to planned well suspension as a producer.
This should not have produced the uncontrolled flow to surface however and the BOP should have been capable of controlling flow. This video examines the failure of the BOP and does so well. Differential pressure between the tubing and annular pressures resulted in flexing of the drill-string out of the path of the blind-shear rams which would normally have sheared the drillpipe and contained the well.
However, there was one decision that ultimately lead to the inability of the crew to control the well. In their haste to de-mob the rig, instead of circulating out the drilling mud to monitored mud tanks on the rig, the crew elected to dump the mud directly off-rig to a waiting barge. The barge had no ability to accurately monitor mud volumes. If the mud tanks on the rig had been used the crew would have quickly seen that the volumes being reported to the mud tanks were increasingly greater than the volumes of seawater being circulated into the well. The crew would immediately have realised that they had a well control issue, would have circulated heavier mud weights and would likely have controlled the well.
The US Government reports on the Deepwater Horizon investigation are available below.
Sonoro Energy Ltd (TSXV: SNV) with it local partner PT Menara Global Energi has won the Selat Panjang PSC in the 2019 Conventional Bid Round in Indonesia.
Deputy Minister of Energy and Mineral Resources Arcandra Tahar announced the winner of 2019 Phase I Oil and Gas Working Area Offers with Regular Auction mechanism at EMR Ministry Building in Jakarta, on Tuesday (05/07). Photo by TheInsiderStories.
Indonesian Ministry of Energy and Mineral Resources (MEMR) announced on 7th May 2019 that the Sonoro Energy Ltd-PT Menara Global Energi consortium was the winner of the 2019 Phase I Oil and Gas Working Area Offer on the Selat Panjang PSC area in the Central Sumatra Basin. The total commitment value and signature bonus was US$ 116.7 million. The PSC tender process is important to the Government of Indonesia as during the last two years 14 blocks were successfully tendered which resulted in signature bonuses totaling US$865 million and Definitive Work Commitments totaling US$2.13 billion.
It is unlikely that the PSC will be formalized and executed before the end of Ramadan on June 5th, 2019.
Sonoro has a 25% interest in the project with an option for up to an additional 24%.
Menara Global Energi has an initial 75% interest and shall be responsible for the signature bonus and for funding the first year G&G program. Sonoro interest to be repaid on terms to be agreed.
Signature Bonus: US$5 million
2D: 500 line km
3D: 200 km2
The 923 km2 Selat Panjang PSC is situated in Riau province, Central Sumatra and is approximately 925 km from Jakarta and 110 km from Pekanbaru (capital city of Riau Province).
In 2015 the Indonesian Ministry of Energy awarded the Selat Panjang PSC, then totalling 1,316 km2 to Petroselat NC Ltd. part owned by Petrochina International. The agreed work program included a G&G Study and data compilation, 2D seismic and 1 exploration well. The PSC was terminated by the Ministry in 2018 and the development program proposed by the previous operator was not implemented.
The previous operator reported that the PSC had produced since 1994 with average annual production of 100,000 barrels with remaining 2P reserves of 7 MMBO. Petroselat identified 7 leads and prospects on the PSC with reported potential for 320 MMBO and 1.5 Tcf.
The Central Sumatran Basin
The Central Sumatra Basin along with the North and Southern Sumatra Basins formed as a result of back-arc extension resulting from the subduction of the Indian oceanic plate beneath western Indonesian portion of the Sundaland Plate. During the Eocene to Early-Oligocene, extension resulted in rifting which generated a series of half-grabens. These grabens filled with syn-rift nonmarine facies, including fluvial, deltaic, marginal lacustrine sandstones, and shallow to deep-water lacustrine shales. With the cessation of rifting, thermal relaxation resulted in a sag phase which increased accommodation and saw further deposition and increased thermal maturity of the lacustrine source rocks. Renewed subduction or more likely a change in subduction rate saw compression in the back-arc environment from the middle Miocene to the Holocence producing many structural traps for conventional hydrocarbon accumulations.
Reservoirs formed in upper Pematang Group (Palaeogene) non-marine sandstones however the principal reservoirs in this system formed in the Early Miocene Sihapas Group marine sandstones. The Pematang Group was deposited in a series of small en-echelon grabens which have a Lower Red Bed fluvial-alluvial unit, overlain by the Brown Shale lacustrine unit and capped by the Upper Red Bed unit.
The basal transgressive unit of the Sihapas Group, the Menggala Formation consists of well-sorted quartzose to sub-arkosic sandstones which typically constitute more than 50% of the formation. The Menggala Formation has an average porosity of >20% and an average permeability of 1500 mD.
An abnormally high thermal gradient has resulted in a shallow oil window with the Oligocene Brown Shale of the Pematang Group being the principal petroleum source rock. The Brown Shale Formation (lacustrine) of the Pematang Group with the Sihapas Group sandstones is one of the most important lacustrine oil systems in SE Asia. Source Rock summary
Principle source rock is the Pematang lacustrine brown shale;
Type 1 source rock average TOC 2-23% with an average of 4%(Williams et al 1985, Yarmanto et al 1995 & Katz abd Dawson 1997). HI 200-950;
Derived oil gravity API 20° to 47°; <2% S; Pour Point 4 to 46º and paraffinic
The Pematang reservoirs are generally small and occur with the rift basin. The giant fields of Minas and Duri with Sihapas reservoirs occur principally along the eastern margins of the rift basins. Most of the oil-fields are located in drape structures of basement highs along the eastern flanks of the half-grabens up-dip of the Pematang formation source rocks while others are related closure generated by basin bounding faults. The lack of gas within the fields of the Central Sumatra Basin is notable reflecting the maturity of the Pematang-Sihapas system and the dominance of lacustrine source rock.
With an excellent source rock package and an anomalously high thermal gradient the Central Sumatra Basin is a prolific producer from shallow depths and has the highest petroleum endowment of the major basins in Asia-Pacific. 25 billion barrels STOIIP has been identified within the Central Sumatra Basin of which 4 billion and 8 billion barrels are in the Duri and Minas fields respectively, making them amongst the largest in SE Asia.
What’s Warren Buffett doing with a $10 billion bet on the future of oil and gas, helping old-school Occidental Petroleum buy Anadarko, a U.S. shale leader? For pundits promoting the all-green future, this looks like betting on horse farms circa 1919.
Warren Buffet finances Occidental acquisition of Anadarko – US$10 billion;
Market sentiment is broadly bearish on hydrocarbons. The oil and gas share of the S&P 500 Energy index is now US$225 billion, less than 1% of the index and the lowest in more than 40 years;
What happens if investments in renewables stutters, subsidies evaporate, or renewable delivery fails?
Mills states that the prevailing wisdom has renewables adding 250% more energy to the world in the next 20 years, more than shale has added in the past 15 years;
Oil and gas demand continue to rise and is forecast to continue this trend albeit at a more muted rate;
All the growth predictions assume that 75% of the renewable growth will come from the least wealthy countries, the emerging economies. Mills concludes this is unlikely unless radical cost reductions evolve. Note that none of the wealthy countries met their green targets but that energy production was driven by increases in fossil fuel production. 70% of the growth was increased fossil fuel production;
“The reason? Using wind, solar and batteries as the primary sources of the nation’s energy supply remains far too expensive.” Any mention of subsidy reduction exposes the full fury of the green lobby … who receive ample funding from the renewables industry!
Already countries are reducing or removing renewable subsidies usually the result of unstable energy supplies, for example Sweden and Australia;
In the USA utilities have been adding massive fossil fuel burning diesel generators as backup to unreliable wind and solar, with little fanfare or comment;
Will electric cars solve the energy gap? Even a 100-fold increase in electric vehicles would only replace 5% of global oil demand of two decades.
‘Green advocates can hope to persuade governments – and thus taxpayers – to deploy a huge tax on hydrocarbons to ensure more green construction. But there is no chance that wealthy nations will agree to subsidize expensive green tech for the rest of the world. And we know where the Oracle of Omaha has placed his bet.” Full Article
Solstad Offshore ASA has been awarded a contract by Ophir Thailand (Bualuang) Limited to perform the offshore installation of the Bualuang Charlie wellhead platform structure as part of the Bualuang Phase 4B Development Project. The Charlie platform will have 12 slots at full production will increase field production to 11,000 BOPD.
The project is located in the Gulf of Thailand and comprises the installation of a bridged-linked wellhead platform structure along with the retrofitting of extension structures to existing in-field platforms. Offshore activities are planned to commence in July 2019 and will be performed using the Derrick Lay Barge “Norce Endeavour”. Solstad Offshore will perform all project management, engineering and installation activities from its offices in Singapore.
Bualuang Oil Field
The Bualuang oil field in the Gulf of Thailand has been on-stream since 2008. The field was initially thought to contain 15 mmbo of 2P reserves and have a productive life of approximately five years. However, the field has undergone numerous reserve upgrades and year-end 2018 it had produced over 35 million barrels of oil, with a further 27 mmbo of 2P reserves and 10.3 mmbo of 2C resource.
The Bualuang field has been on-stream since 2008
Stable production with over 99% uptime in 2018. 7,800 BOPD during 2018, to be increased to 11,000 BOPD
OPEX US$13/BOPD increase to US$16 BOPD in 2018.
A facilities debottlenecking project in 2016 increased water handling capacity, and therefore allowed for increased rates of oil production
A three well infill drilling campaign in 2017 saw two wells in the deeper T2 reservoir and and infill well under the platform guided by data from the Ocean Bottom Node seismic survey completed in 2015.
Phase 4 commenced in 2018 with drilling of three new wells and four workovers.
Phase 4B Development
A third platform with 12 slots allowing expansion of water disposal to 100k BPD;
10 slots to be used for increased production with conversion of some wells on the Bravo platform to water disposal.
CAPEX: US$138 million
Development drilling from July 2019 with first oil from Charlie in October 2019
Medeco to Acquire Ophir Energy
On 30 January 2019, the boards of Medco, Medco Global and Ophir announced that they had reached agreement on the terms of a recommended acquisition pursuant to which Medco Global will acquire the entire issued and to be issued ordinary share capital of Ophir for GBP 0.55 per share (later revised upwards to GBP 0.575). This all cash bid valued the company at US$ 550 million.
A number of activist institutional investors were unhappy with the bid and on 8 March 2019, the Ophir Board received an unsolicited and highly preliminary indication of interest from Coro Energy PLC regarding a possible offer for the entire issued and to be issued share capital of Ophir. Coro proposed that Ophir Shareholders would receive 40 pence in cash, and, in addition, shares in Coro for each Ophir Share, resulting in an ownership by Ophir Shareholders of between 85 per cent. and 95 per cent. of the enlarged company. The cash component would be funded with debt.
Following a modest increase in the offer price by Modeco, Coro withdrew its offer after discussions with their financiers, Sand Grove Capital Management.
Schlumberger introduces new and novel diamond composite drill-bit which allows for deeper cutting – which will improve steerability on the curve.
The distinctive geometry of Hyper* hyperbolic diamond cutting elements that cut 20% deeper into rock compared with conventional polycrystalline diamond compact (PDC) cutters. A thicker, precision-molded diamond table makes the Hyper element tougher and more durable for drilling soft and plastic rock formations, while armored cutting edges withstand high-impact transitions.
Additionally, bit balling is mitigated by the chip-breaking profile at the center of the element, which improves cuttings removal during drilling. With the combination of these features, the HyperBlade bit maintains steerability and directional tracking, and increases average ROP by more than 20% compared with conventional PDC cutters.
The HyperBlade bit has undergone extensive field testing in North America, specifically in the Denver-Julesburg and Appalachian Basins. In the Marcellus Formation in northern Pennsylvania, the HyperBlade bit drilled an 8 ½-in section with a measured depth of 6,891 ft in 16.6 drilling hours. The operator achieved an on-bottom ROP of 415 ft/h, resulting in a 62% improvement compared with offset runs using conventional PDC bits.
Australia is on the brink of opening up a massive, untapped coal province after Adani committed to begin construction of its controversial Carmichael mine project in central Queensland before Christmas and the approval by the Queensland Government of the Mac-Mines coal mine
After almost a decade of delays, legal challenges and protests, the Indian conglomerate is planning to begin exporting high-quality thermal coal from the Galilee Basin, west of Mackay, by the end of 2020.
Adani’s decision to self-fund a scaled-down version of its original mine-rail proposal — involving what would have been Australia’s biggest-ever coalmine — could pave the way for five other proposed mines in the basin. Its planned rail link to the Abbot Point port will be opened for use to Adani’s rivals, with an initial coal-hauling capacity of 40 million tonnes a year that could be doubled within a few years.
After much lobbying APPEA has announced the Western Australian Government’s decision to lift the hydraulic fracturing moratorium on existing onshore gas projects.
How many studies need to be done to confirm that fracking kilometres beneath the surface of the planet has no material impact on the surface or the near surface waters? We all know this has nothing to do with actual environmental impact and everything to do with a small subset of the left that detests Capitalism – the one “ism” that has made the world a better place as distinct from the others that have merely killed tens of millions.
“The independent scientific inquiry has confirmed that properly regulated, hydraulic fracturing is a safe practice. Hydraulic fracturing has been used safely in Western Australia since 1958,” said APPEA Chief Executive Dr Malcolm Roberts.
“The inquiry shows there is no environmental or public health justification for maintaining the moratorium. The inquiry also rejects claims that onshore projects will mean a significant increase in emissions.
“While the industry would have preferred the removal of the moratorium across the state, this decision will give communities in regional WA the choice to support local projects and jobs.
“More than any other state, WA relies on investment in resource projects to sustain jobs and economic growth. The government has made the right decision to respect the substantial investments already made by projects in the Kimberley region and the Perth basin.
Dr Roberts said prohibiting hydraulic fracturing would have crushed the viability of some of these projects, damaging WA’s reputation as a safe place for investment.
“The government has added a new regulatory requirement which will only allow these projects to use hydraulic fracturing for producing gas with the approval of the landowner,” Dr Roberts said.
“The industry respects that we operate on someone else’s land to develop a natural resource owned by the community.
“WA producers have close working relationships with traditional owners and pastoralists.
“During the inquiry, many regional communities expressed strong support for local gas projects. The right of these communities to make their own decisions must be respected, including by anti-gas activists.”
The head of the energy company that is seeking to become the first in the UK to start commercial fracking for gas has warned the government that its regulatory system risks “strangling” the nascent industry.
Francis Egan, chief executive of Cuadrilla, called on the government to relax operating rules that have forced the company to halt work several times after it unleashed earth tremors at its fracking site in northern England.
Fracking has revolutionised the US energy industry, and Cuadrilla is hoping to replicate this success in the UK, although it has encountered strong opposition from environmental protesters worried about pollution and earthquakes.
Since it began fracking tests on October 15 at its Little Plumpton site near Blackpool, Cuadrilla has caused 31 tremors, including three that were of sufficient magnitude under its operating rules to require the company to stop work.
Mr Egan said the government needed to move “within weeks” to relax the rules covering Cuadrilla or it may never discover if the UK’s shale gas resources are commercially viable.
“It could be strangled before birth, this thing,” he told the Financial Times.
Hydraulic fracturing — or fracking — involves pumping water, sand and chemicals deep under the ground at high pressure to release gas from rock formations, often in wells that run horizontally rather than vertically.
Under Cuadrilla’s operating licence, the company has signed up to a so-called traffic light system devised by the government that requires it to stop work if activity above 0.5 on the Richter seismic scale — a level imperceptible to humans — is detected.
Over the past two weeks, three tremors measuring more than 0.5 have been recorded — the highest one being 1.1. These three constitute “red lights” that require a halt to operations.
Mr Egan said the government should allow Cuadrilla to maintain operations amid tremors measuring up to 2.0 on the Richter scale — a level he insisted would pose no risk of damage to the surrounding area.
Other countries including Canada and the US allow seismic activity well above 2.0, he added.