It is a shame to spoil natures natural beauty as we can see from the picture that leads this article, Indonesia is blessed with many such areas, in order to preserve nature and what has been given to all of us, we need to explore in an environmentally friendly way and adapt to new ideas, after all, if mankind is to survive, resources will always be required.
Richard Fuller recently published a very interesting article in the Jakarta Post (JP) titled “The risk of losing an important asset – natural gas”. In this article, he mentioned that the cost of 2D, 3D seismic over ten years would be $2 billion, a figure that makes one eyes water, with an extremely long time frame (10 years). It was also stated that by continuing to pursue oil and gas exploration under the historic and current procedures that Indonesia would lose $1.1 trillion in economic benefits, another eye-watering figure, even in Rupiah too many of us.
The Vice President of Indonesia, Jusuf Kalla made a statement at the opening ceremony for the IIGCE conference on 2 August that the cost of exploration for geothermal is quite high, considering the cost of exploration required for the development of one Geothermal Working Area (WKP) is approximately US $20-25 million. We need to bear in mind that one WKP is normally forty to fifty Square Kilometre in size and that the total length of the geothermal arc in Indonesia is 5100 km.
I made the following statements at the IIGCE conference during my presentation which was titled "Exploration Requirements to Achieve the Geothermal Development 2025 Target” that “Speculation should not be a part of the geothermal vocabulary, neither should the common belief that exploration costs are high. Yes, they are if we insist on not accepting or adapting our exploration methods to Innovative Exploration Tools (IET) that do reduce the Time, Cost and Risk of Exploration”.
“Many parts of Indonesia are unexplorable by traditional methods of exploration, large parts of Indonesia's resources potential has not been explored, actual resources are not known. Current pre-drilling practices for geothermal exploration methods are time-intensive, costly and do not achieve active reservoir imaging”.
IET will provide the information and data that will encourage license tender participation and investment, which in turn will generate further interest in the Indonesian geothermal and resource industry”. This also applies to oil, gas, and minerals.
Another article in the JP that was titled “Oil crisis lurks as production drops, consumption soars”, in this article it states that Indonesia has depleted more than 90% of their oil reserves within a period of sixty years, this can not be a true, as Indonesia does not know the actual reserves that it had or has, neither does it know the full potential of the geothermal and mineral resources available, all estimations are speculation, based on extremely experienced consultants and geoscientists reports, who by the way get paid vast sums of money very often from the taxpayers money. These reports are speculation and only become reality when they have been confirmed by exploration, which is unlikely to happen when we look at the eye-watering figures that are being quoted.
There is a Roadmap Project called “Geothermal Island Flores” with cooperation from the British government through FCO-UK at the British Embassy and the World Wide Fund for Nature (WWF). The project is developing a related study "Tariff Model Geothermal Energy and Geothermal Roadmap. It is intended to make Flores a Geothermal showcase for Indonesia. This is a very good idea, although exploration is required.
One of the problems, in my opinion, is that there are far too many companies that have self-interest, they have invested in certain exploration tools and of course want this expensive equipment to be used, drilling companies want to drill more holes, seismic companies want to run more kilometres, do they care if a resource is found or nature is destroyed? The owner of a block, mine or geothermal working area should care as it is them that are paying for very expensive methods of exploration, which by the way has not changed in many years, seismic has been around for 100 years, it makes a noise, we get a return, this is what it did 100 years ago, the principle is the same, the tools have improved tremendously over the years, especially with the processing power with the advent of powerful computers, but at the end of the day, the principle is the same. These tools were designed out of necessity.
Is it not time that new ideas for exploration that enhances our way of doing exploration are used, tools that have been designed by geoscientists, geologists, people of the trade, based on sound and proven geoscience and geology which by the way has also not changed so much over the years. Drilling and seismic companies will be doing more as the overall cost of exploration is reduced, instead of today where they are doing very little work.
Should we not be accepting IET as part of the exploration toolbox? Of course we should, the same way that we accepted in the mid 1980’s new ways of conducting hydrographic surveys which improved the output and the quality of surveys, no one lost jobs, in fact more jobs were created as the ships were able to spend more time at sea collecting data instead of drawing the results by hand.
Innovative exploration programs will provide the information and data that will encourage license tender participation and investment, which in turn will generate further interest in the Indonesian geothermal and resource industry at a fraction of the costs that have been suggested in this article and in far less time, months rather than years.
Indonesia must elevate the value and level of information given to investors and it must invest to do this, but invest wisely, not with methods that we know carry high-risk. New thinking and new strategies are required to meet this challenge. The government and the industry need to work together to achieve their mutual goals. An examination of government policy related to the exploration industry is also in order, but first and foremost we must further de-risk exploration investment, and use innovative, cost-effective tools which can bridge the gap and at the same time save the unnecessary destruction of our environment by carrying out exploration looking for something that may not exist.
“With the technology at our disposal, the possibilities are unbounded. All we need to do is make sure we use it” – Stephen Hawking
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When asked in December about the projected slowdown in American shale output, the new US Energy Secretary shrugged off the notion, describing it as a mere ‘pause’. Blaming the expected slowdown to the ‘natural adjustments’ of oil and gas prices instead of a structural decline in production, Dan Brouilette is painting a rosy picture of US shale – where riches still lie underneath, waiting for the right price to be extracted. Of course he would paint such a picture. Brouilette is the new Energy Secretary, replacing Rick Perry. He couldn’t come in on a message of doom and gloom. But his pretty picture isn’t accurate either.
Schlumberger just posted a US$10 billion loss for the full year 2019, despite relatively flat y-o-y revenues. CEO Oliver Le Peuch called its international performance ‘positive’, but blamed ‘land market weakness’ causing a sharp decline in North American revenues and profits. Land market is code word for shale, and Schlumberger isn’t the only one facing problems. Halliburton announced a loss of US$1.1 billion in 2019, taking a US$2.2 billion charge on weakening US shale activity as North American revenue for Halliburton fell by 21% in 4Q19 and 18% for the whole year. While its results managed to beat analyst predictions – already stung by Schlumberger’s results – Halliburton doesn’t expect things to get rosier either, signalling that it expected ‘customer spending’ in North America to be down again in 2020.
And it isn’t just service companies suffering. US supermajor Chevron booked a US$11 billion write-down on a collection of assets in its latest set of financials, including on a major deepwater project in the Gulf of Mexico, the Kitimat LNG project in Canada and onshore Appalachian shale assets. Taken as a whole, the total impairment might coming from Chevron’s lowered forecast for oil and gas prices to the US$55-60/b range for 2020, but that shale was singled out is a major factor. And Chevron isn’t the only one. BP, Repsol and even ExxonMobil are expecting weakness. Only Shell and Total, who haven’t devoted as much attention to US shale, particularly the Permian, have been relatively insulated.
Why is this happening? There are two different factors operating. From a producers’ standpoint, the rising tide of US shale output is contributing to weakening global prices for oil – and that has a lot to do with the debt burden of existing US shale players, who have to keep drilling to pay off loans. Added conventional production coming online from Guyana, Brazil and Norway at the same time aren’t helping with prices either, despite OPEC+’s best intentions. From a service company’s perspective, firms like Schlumberger and Halliburton derive their revenue from drilling activity, not drilling output. And US drilling activity has dropped steeply over the past year, currently down by over 250 rigs according to the Baker Hughes weekly rig count. Much of this is onshore, principally in the Permian but also in other basins, as the once nimble and dynamic drillers are forced to stop activity either through bankruptcy or to shut shop temporarily as crude prices fall to uneconomical levels.
The US EIA has issued a new forecast, predicting that US shale output will slow down to a 1.1 mmb/d gain over 2020. That’s still optimistic, taking total US production to 13.3 mmb/d. In 2021, however, the EIA think output growth will fall even further, to an annual gain of just 400,000 b/d. Implicit to that forecast is that the EIA expects prices to remain subdued over the new two years, because shale drillers would respond to higher prices with increased drilling. There is also production structure to consider. Shale well produce immediate results, but show steep declines after. From 2012 to 2019, the amount of drilled but uncompleted (DUCs) wells – ie. wells that can be exploited within a short time frame – grew and grew; in the last 9 months, the glut of DUCs has shrunk – suggested that the industry is not drilling new wells as fast as they are completing already-drilled. Drilling activity has declined, and the chronic decline in the Baker Hughes active rig count – 18 of the last 21 weeks showed a net loss of rigs – is just proof of that.
It may not be the picture that Dan Brouilette wants to paint, but it is reality. The shale slowdown is real. It is also true that shale activity would increase if prices rose to more viable levels – say the US$65-70/b range – but let’s be honest, what are the odds of that happening when shale itself is the cause of weakening prices.
Nagman has diversified into dealing with Flow meters or Instruments viz Electro-Magnetic Flow Meters, Coriolis Mass Flow Meter, Positive Displacement Flow Meter, Vortex Flow Meter, Turbine Flow Meter, Ultrasonic Flow Meter.
Electro-Magnetic Flow Meter:
Size : DN 3 to DN 3000 mm
Flow Velocity : 0.5 m/s to 15 m/s
Accuracy : ±0.5%, ±0.2% of Reading
Coriolis Mass Flow Meter:
Size : DN8~DN300
Flow Range : 8 to 2500000 Kg/hr (for liquids)
4 to 2500000 Kg/hr (for gases)
Accuracy : 0.1% 0.2% 0.5% of Normal Flow Range
Positive Displacement Flow Meter:
Size : DN 15 ~ DN 400
Max. Flow Range : 0.3 m3/hr to 1800 m3/hr
(Will vary based on the measured media & temperature)
Accuracy : 0.1% 0.2% 0.5%
Vortex Flow Meter:
Size : DN 25 to DN 300
Flow Range : 1.3 m3/hr to 2000 m3/hr (Water)
8.0 m3/hr to 10000 m3/hr (Air)
Accuracy : ±1.0% of Reading
Turbine Flow Meter:
Size : DN 4 to DN 200
Flow Range : 0.02 m3 /hr to 680 m3 /hr
Accuracy : 1.0% or 0.5% of Rate
Ultrasonic Flow Meter:
Type : Hand held Ultrasonic Flow meter with S2, M2, L2 Sensors
Accuracy : ±1% of Reading at rates > 0.2 mps
Measuring Range : DN 15 – DN 6000
In its Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that U.S. natural gas exports will exceed natural gas imports by an average 7.3 billion cubic feet per day (Bcf/d) in 2020 (2.0 Bcf/d higher than in 2019) and 8.9 Bcf/d in 2021. Growth in U.S. net exports is led primarily by increases in liquefied natural gas (LNG) exports and pipeline exports to Mexico. Net natural gas exports more than doubled in 2019, compared with 2018, and EIA expects that they will almost double again by 2021 from 2019 levels.
The United States trades natural gas by pipeline with Canada and Mexico and as LNG with dozens of countries. Historically, the United States has imported more natural gas than it exports by pipeline from Canada. In contrast, the United States has been a net exporter of natural gas by pipeline to Mexico. The United States has been a net exporter of LNG since 2016 and delivers LNG to more than 30 countries.
In 2019, growth in demand for U.S. natural gas exports exceeded growth in natural gas consumption in the U.S. electric power sector. Natural gas deliveries to U.S. LNG export facilities and by pipeline to Mexico accounted for 12% of dry natural gas production in 2019. EIA forecasts these deliveries to account for an increasingly larger share through 2021 as new LNG facilities are placed in service and new pipelines in Mexico that connect to U.S. export pipelines begin operations.
Net U.S. natural gas imports from Canada have steadily declined in the past four years as new supplies from Appalachia into the Midwestern states have displaced some pipeline imports from Canada. U.S. pipeline exports to Canada have increased since 2018 when the NEXUS pipeline and Phase 2 of the Rover pipeline entered service. Overall, EIA projects the United States will remain a net natural gas importer from Canada through 2050.
U.S. pipeline exports to Mexico increased following expansions of cross-border pipeline capacity, averaging 5.1 Bcf/d from January through October 2019, 0.5 Bcf/d more than the 2018 annual average, according to EIA’s Natural Gas Monthly. The increase in exports was primarily the result of increased flows on the newly commissioned Sur de Texas–Tuxpan pipeline in Mexico, which transports natural gas from Texas to the southern Mexican state of Veracruz. Several new pipelines in Mexico that were scheduled to come online in 2019 were delayed are expected to enter service in 2020:
U.S. LNG exports averaged 5 Bcf/d in 2019, 2 Bcf/d more than in 2018, as a result of several new facilities that placed their first trains in service. This year, several new liquefaction units (referred to as trains) are scheduled to be placed in service:
In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction capacity to 10.2 Bcf/d (baseload) and 10.8 Bcf/d (peak). EIA expects LNG exports to continue to grow and average 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021, as facilities gradually ramp up to full production.
Source: U.S. Energy Information Administration, Natural Gas Monthly