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  1. Horizontal drilling reduces environmental impacts, increases gas production

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    Horizontal drilling is a technique used to develop larger oil and gas resources from a single well.

    Horizontal drilling and horizontal wells have been common practice in the oil and natural gas industries since the 1970s, but the US Department of Energy notes the concept was first introduced as early as 1929.

    In Australia, horizontal or “directional” drilling has been common since the 1990s and has been used more recently to target deep shale gas resources in South Australia and NT.

    Australia’s first horizontal shale gas well was drilled by Santos in SA’s Cooper Basin in 2013 and the most recent example was Origin’s Amungee NW-1H well in the Beetaloo Basin in the NT.

    The Amungee well was drilled in 2015 and hydraulically fractured in 2016. It resulted in an important natural shale gas discovery for the Northern Territory.

    These and other horizontal wells have been drilled safely with no impact on water resources or the environment.

    Larger wells do of course use more water, sand and other additives, but the technology means fewer wells are drilled overall and the environmental impact is thus reduced.

    Today, companies can drill multiple horizontal well paths from a single surface location.

    Clustering wells onto a single surface location dramatically reduces the overall amount of surface land required for wells and related infrastructure.

    Reducing oil and gas wells’ surface impacts while also improving production is an important advantage of horizontal drilling.

    Also called deviated drilling, directional drilling involves deliberately shifting a well’s path from the vertical. Wells can be deviated until they are running horizontally. They can even be steered – in real time – upwards or downwards once the horizontal direction is established.

    Reasons for directional drilling include:

    • Avoiding a surface site that is operationally difficult or environmentally sensitive
    • Targeting a larger gas resource from a single well
    • Reducing costs or surface impact by drilling several wells in different directions from the one surface location
    • Targeting an offshore resource from an onshore site
    • Enhancing oil and gas production by drilling in a way that exposes more of the reservoir to the wellbore.

    To steer the well path, rotary steerable equipment is mounted on the drill pipe just behind the drill bit. These systems are controlled from the surface to redirect the drill bit to steer the well on any desired path.

    Directional drilling is precise. Wells kilometres deep can be directed to within centimetres of their targets.

    This technology developed for the oil and gas industry is now also being used in other industry applications, including:

    • tunnelling
    • construction and civil engineering
    • drilling water wells
    • laying water pipelines and telecommunication cables.
  2. CSG water can be safely reinjected into aquifers: CSIRO

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    Water produced during coal seam gas extraction can be safely re-injected hundreds of metres underground, according to new CSIRO research. This can help replenish aquifers used by farmers and communities.

    See this link.

  3. Queensland expands drill core storage and access

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    Queensland’s resources exploration industry now has access to more geological information thanks to a $5 million expansion of the state government’s Exploration Data Centre.

    The Exploration Data Centre offers the resources exploration industry a comprehensive catalogue of core samples from more than 11,600 drill holes collected by the Geological Survey of Queensland over the last 130 years. The oldest sample is from the Mitchell town bore drilled in 1886.

    exploration-data-centre

    This new expansion will provide storage for an estimated 500 km of additional core samples, adding to the 800-plus kilometres of core samples currently stored at the facility.

    The Geological Survey of Queensland also provides HyLoggerTM digital spectral scanning technology.

    hylogger

    HyLogging™ is an advanced technique from CSIRO that helps geologists to non-destructively assess the mineralogical distribution of an entire drill core, with minimal sample preparation or removing from its original tray.

    hylogging

    The virtual online library offers geologists the chance to examine detailed mineralogical results remotely from their desks, eliminating the need  for physical inspection. For more information, see this link.

    The Exploration Data Centre expansion benefits not only industry, but also universities, researchers and Government scientists.

    The centre is open from 8am to 5pm Monday to Friday or other times by appointment.

    Address and contact details:

    • 68 Pineapple Street, Zillmere 4034 QLD
    • Telephone: +61 7 3096 6810
    • Facsimile: +61 7 3096 6817

    For more information about the Exploration Data Centre, see this link.

  4. Water from coal

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    Producing water from coal is a common practice.

    The first water well was drilled into the Walloon coals in 1928, many decades before CSG technology was developed.

    Currently 1,647 bores unrelated to the gas industry are producing 11.4 billion litres of water every year from Queensland’s Walloon coals [1]  (the state’s main coal seam gas-producing geological formation).

    About 42% of this water is used for agriculture, and 53% for stock and domestic purposes.

    To produce natural gas from coal, the pressure must be reduced by pumping water from the coals.

    In our dry country, this water is an important resource that cannot be wasted.

    CSG produced water has several possible uses, depending on its quality, quantity and level of treatment, including:

    • supplying local farmers and communities
    • irrigating crops or forestry plantations
    • replenishing weirs and dams, or restoring flows in rivers exposed to heavy irrigation demand
    • recharging aquifers.
    • dust suppression
    • industrial purposes such as drilling, coal washing, power station cooling.

    All produced water is considered for beneficial use. How it is used depends on local needs and priorities.

    The figure below indicates where most CSG water is used:

    CSG and water production

    In Queensland, when a CSG company produces water from coals (including the Walloons) for beneficial use, a ‘Beneficial Use Authority’ is required from the government.  There is one for irrigation [2] and another for other [3] purposes.

    Special Authorities [4] may also be used for specific projects.  These Authorities specify what must be tested for and how often, as well as who should do the testing and which authority should receive the reports.

    For irrigation use, tests include electrical conductivity, sodium absorption ratio (for soil integrity), pH (acidity) and 16 heavy metals and metalloids.

    The water processing technology most commonly used by CSG operators to meet these standards is reverse osmosis.  This is the same technology used to process drinking water in major cities around the world, including London, Singapore and Dubai.

    There is a long history of water usage from coals, and rigorous processing and testing regimes are used when CSG companies produce this water and make it available for beneficial use. We can be confident that CSG production water processed for beneficial use meets the high standards required for our agriculture industry and regional communities.

    [1] https://www.dnrm.qld.gov.au/__data/assets/pdf_file/0016/31327/underground-water-impact-report.pdf

    [2] https://www.ehp.qld.gov.au/management/non-mining/documents/general-bua-irrigation-of-associated-water.pdf

    [3] https://www.ehp.qld.gov.au/management/non-mining/documents/general-bua.pdf

    [4] http://www.gasfieldscommissionqld.org.au/resources/gasfields/csg-water-treatment-and-beneficial-use-2.pdf

  5. Robots dive into environmental protection

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    One of the most recent developments in the world of high-tech offshore oil and gas operations is the introduction of marine robots.

    These robots can not only extend flexibility and hours of operation, but also reduce the risks associated with using divers many kilometres out to sea.

    One form of marine robots is underwater autonomous vehicles (UAVs), which are now being used to identify and combat biofouling – or the spread of unwanted plants or animals in the marine environment.

    Organisations such as CSIRO and Fastwave in Perth have appeared at recent APPEA conferences to demonstrate how UAVs can detect and neutralise marine biosecurity risks.

    New designs, such as CSIRO’s Starbug UAV, are small enough to be operated by one person without the need for cranes and other specialised equipment.

    These UAVs can be used to autonomously inspect offshore vessels and rigs to look for potential biofoulling.

    The UAV can take samples or use microwave, ultraviolet or other methods to neutralise threatening species.

    APPEA has written some more facts on biosecurity that can be accessed on our website at http://www.appea.com.au/industry-in-depth/technical-information/environment/biosecurity/ .

    For more information, see these links: Fastwave and CSIRObotics

  6. CSG water – thoroughly tested and safe to use

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    The coal seam gas (CSG) industry produces water from coal seams to reduce pressure within the seams and release natural gas. The produced CSG water is prioritised for beneficial use for agriculture, domestic purposes and local industries.

    How do we know that this CSG water is safe to use for domestic or agricultural purposes?

    Since the 19th century, farmers have been using water in large volumes from bores drilled into coal seams without any processing.

    Each year, more than 7 billion litres (GL) of water sourced from coal seams are used for agriculture . However, not all of this water is suitable for direct use. Processing is required in such circumstances.

    Near Chinchilla, in the heart of Queensland’s CSG fields, the state-owned water wholesaler, SunWater buys up to 85 million litres of processed water a day from a CSG company and resells it to local users, including farmers.

    The processed water is extensively tested. Water quality samples are taken weekly and sent to a NATA accredited laboratory for independent analysis and reporting. SunWater reports publicly every quarter on what is measured and what the tests found.

    Tests are made for some 55 different substances, including:

    • endocrine disrupting compounds
    • disinfection by-products
    • industrial organics
    • inorganics
    • metals
    • nitrosamines
    • nutrients
    • polycyclic aromatic hydrocarbons
    • radionuclides
    • total petroleum hydrocarbons
    • volatile organic compounds.

    This ensures the quality of the water provided to SunWater is consistently of a standard that protects public health and safety.

  7. Water science and the gas industry

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    Australia’s oil and gas industry is contributing more than $6 million every year to support water research and modelling of precious water resources.

    Some of these water models are the most extensive ever developed in Australia. The Office of Groundwater Impact Assessment Surat-Bowen Basin model covers an area the size of Germany with 22,000 water wells.

    The large and complex groundwater flow model has 19 layers and more than three million individual cells. It models changes over decades to make sure all water movement dynamics are understood.

    It also identifies water wells that will be affected by gas industry activity before the impacts are seen. This enables advanced planning and proper preparation for make-good arrangements.

    Water has been co-produced with oil or gas production ever since the start of the industry in Australia in the early 1900s. In the case of coal seam gas (CSG) the water is pumped from wells deep in the coals to reduce pressure and release the natural gas.

    Government and industry agree that this water should be put to beneficial use.

    But oil and gas wells produce from depths of 300 to 4,000 meters, so the water tends to be brackish with higher salt content than the shallower aquifers normally used for agriculture or domestic use.

    The water is generally not usable without desalination treatment or blending with less saline water.

    About 97% of the water produced from CSG wells is processed using technologies such as reverse osmosis, and is made available for beneficial use outside of the oil and gas industry.

    More than half is used by agriculture, which reduces the demand for water from the Great Artesian Basin’s shallower, less saline aquifers.

    This, in itself, will help recharge these shallow aquifers over time.

    Condamine feedlot owner Simon Drury is one farmer using treated water from gas production.

    Mr Drury uses seven pivot irrigators to grow fodder for his cattle and brings in about 20,000 tonnes of grain per year.

    According to the Queensland Gasfields Commission, universities, State Government agencies and CSG proponents are conducting 188 water‐related science and research projects on Queensland’s coal seam gas regions.

    Much of this work is in addition to the enormous environmental and technical assessments that companies undertake as part of the project approval phase.

    A recent survey by the Australian Water Association showed many water industry professionals want to know more about the impact of gas production on water sources. The oil and gas industry accepts it has a responsibility to help provide answers.

    The same survey showed a strong majority of water professionals supported the current level of regulation relevant to managing unconventional gas production.

  8. Coal seam gas – our next renewable energy source?

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    CSIRO scientists are investigating whether injecting coal seams with certain kinds of bacteria and carbon dioxide can produce commercially viable quantities of natural gas.

    Australia is blessed with large volumes of natural gas – enough to last centuries at current consumption rates. One of the biggest sources of natural gas comes from underground coal seams. This is often referred to as coal seam gas (CSG).

    CSG can be either biogenic or thermogenic. Biogenic natural gas occurs as a product of microorganisms under the surface of the earth, whereas thermogenic natural gas results from chemical reactions that occur without the presence of microorganisms. These decomposition reactions are instead triggered by the application of extreme heat.

    Most, but not all CSG is thermogenic. Researchers are now interested in the nature of biogenic CSG, and how it can be enhanced. The challenge is to find a way to encourage the microbes to produce more methane or natural gas to either replace gas reserves that have been used, or to supplement existing reserves.

    The CSIRO is currently developing a program on microbial enhancement of coal seam gas production. This is aimed at understanding the processes involved and finding ways to replenish depleted and unproductive coal seams.

    The trick is to find and supply nutrients to the right microbes, which occur naturally in the environment, to produce methane.

    In effect, these microbes produce methane as they grow and live, much as we produce carbon dioxide when we breath.

    These ‘bugs’ can feed on carbon dioxide , converting it to usable methane, and on buried coals or special food injected underground to stimulate the gas production. These processes are already going on naturally, and scientists are looking for ways to exploit this activity. The result could be an important new source of renewable energy.

    CSG: potentially the next renewable energy source!

  9. A question of skills

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    In the final part of a series on the future of gas exploration in Australia, New Scientist asks whether the country can meet the huge demand for skilled engineers and scientists generated by an industry expanding at an unprecedented rate

    In 2007, the Australian oil and gas company Woodside began work on an ambitious facility on the Burrup Peninsula on the coast of Western Australia. This facility was designed to liquefy natural gas from an offshore field called Pluto, about 200 kilometres off the coast. When construction began, the company expected the plant to be completed by February 2011 at an estimated cost of US$11.2 billion. In reality, the project was eventually completed in April 2012, by which time it had racked up extra costs of US$3.7 billion.

    One of the main problems for Woodside was a tight labour market, according to David Ledesma at the Oxford Institute for Energy Studies, UK, and his colleagues, who published a report in September on the future of Australian liquefied natural gas (LNG) exports. A shortage of skills drove up employment costs, and employees also took strike action over pay and conditions.

    Gas construction projects in other parts of Australia have also suffered from skills shortages – as well as financial issues or management and design problems. Ledesma’s report points to seven big projects that have suffered delays, some of more than a year, while incurring additional total costs of as much as $17 billion.

    The country is clearly gearing up to take advantage of the country’s huge gas reserves. With the current spending on LNG projects accounting for more than a third of all business investment in Australia, an important question is whether the country’s workforce is up to the challenge.

    The unprecedented investment in Australian gas is the result of the discovery of several large natural gas reserves in the 1990s. “In Western Australia, very big offshore discoveries were made between Perth and Darwin,” says James Hendersen, also at the Oxford Institute for Energy Studies and a co-author of Ledesma’s report. And in the east, new gas reserves have been found in coal seams.

    With international demand for gas rising, energy companies are now racing to take advantage of these discoveries. And they are all leaping into action at the same time, hence the seven new projects under construction and scheduled to begin operating between 2015 and 2018. These include drilling units to extract the gas, and LNG production plants that make the gas easier to export to countries such as China and India. “There’s a big demand in Asia for Australian gas,” says Eric May, the Chevron Chair in Gas Process Engineering at the University of Western Australia.

    Once up and running, these projects are expected to make huge contributions to Australia’s economy. Currently, natural gas contributes around A$12 billion to the Australian economy. “By 2018, when these projects come on stream, natural gas will contribute A$60 billion,” says Hendersen.

    But the construction of drilling units and processing plants is already behind schedule, in part due to a lack of skilled workers. “There have been skills shortages across the board, from welders and truck drivers to more skilled engineers,” says Hendersen.

    But the skills in demand are set to change soon, and rapidly, as construction winds down. “We’re heading from a construction phase to an operating phase,” says May. “There will be more of a demand for engineers and operators.” This demand will come in the form of about 1800 new engineering roles in the next few years, says May.

    A 2013 report by the Australian government’s Australian Workforce and Productivity Agency (AWPA) found that the number of people employed in the construction of oil and gas projects will peak this year at 83,300, and then decline to about 7700 by 2018. The number of people employed in operating these projects, however is set to rocket from around 39,000 in 2013 to 61,200 in 2018.

    If you’re hoping to take on one of these new roles, an engineering degree will come in useful, says May. “Flow assurance, process, mechanical and civil engineering degrees will be valuable,” he says. Geophysics is also important: teams of scientists need a full understanding of rock formations to understand where gas may be located, and how best to drill down to it. And for those who will be conducting remotecontrolled undersea investigations, electrical engineering degrees and mechatronics are vital qualifications.

    University courses on these topics are growing in number and course size, says May. “We’re trying to expand the intake as much as we can,” he says. And even if you’ve already started a science degree, it’s not too late to switch to engineering, May adds. “A lot of engineering degrees are becoming a lot more flexible, so you can move between degrees,” he says.

    But such courses can only be taken by people who already have some level of scientific understanding. That is why schools have a key role to play in meeting the demand for engineers, says Stephen Durkin, CEO of Engineers Australia, a group that represents professional engineers. “As engineering is a profession that relies heavily on advanced science and mathematics, it is crucial that we invest heavily in promoting education in these areas from an early age,” he says. “Australia as a whole should be concerned that participation in subjects like advanced mathematics is only around 10 per cent.”

    The government shares Durkin’s concerns. In October, it announced plans to inject A$12 million into primary and secondary schools across the country to improve the resources, exposure to and participation in science, technology, engineering and mathematics. The bulk of this investment will go into mathematics resources.

    Beyond academic qualifications, experience is also key. That is why energy companies are ramping up traineeships and apprenticeships. In 2008, energy companies in Australia employed 100 apprentices in oil and gas extraction, and 100 in exploration. By the end of 2012, 200 people were taking on apprenticeships in oil and gas extraction, while 400 were training in exploration.

    In times of need, it is also worth stealing people who are working in other industries and retraining them. For example, non-profit organisation Maritime Employees Training aims to re-skill people working in the declining maritime industry so that they can move into careers in the oil and gas sector. The authors of the AWPA report recommend that a similar programme be implemented on a national scale.

    Those who make the leap can expect to be well rewarded. Between July 2013 and June 2014, the average Australian worker could expect to earn A$80,000, but the salaries of those working in the mining, energy and resources industry were earning, on average, just over A$120,000.

    Many of those well-paid jobs will be found in Pilbara in Western Australia and the Darling Downs and Mackay regions of Queensland, according to the AWPA report. But sites across northern and eastern Australia are likely to become employment hotspots, too.

    The sudden, rocketing demand for scientists and engineers to work in Australia’s oil and gas industry is unique, says Ledesma, because of the number of projects that are being undertaken at the same time. “You wouldn’t normally see this number developed in parallel,” he says.

    Consequently, it’s easy to see how the skills shortage has come about. Ledesma doesn’t point a finger of blame at the Australian government for approving so many projects at once. “There has been unprecedented growth in the industry, and it is not the role of the government to police the development of gas,” he says.

    “It is simply the economics of the project that drive whether it goes ahead.”

    The topics in this series were developed by New Scientist in conjunction with APPEA.

  10. Digital prospectors

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    In the third part of a series on the future of gas exploration in Australia, New Scientist examines the sophisticated new sensing and analysis techniques for sniffing out hydrocarbons in ever more complex geological formations

    THIS year the Australian oil and gas company Santos began searching for shale gas in the rocks beneath Tanumbirini, a remote cattle station in Australia’s Northern Territory, 600 kilometres south-east of Darwin. Engineers drilled 4000 metres through an entire layer of shale rock, looking for evidence that it contains natural gas and making this one of the deepest exploratory wells on the continent.

    At the same time, other companies are eyeing the next generation of offshore gas reserves. These will come from ultra-deep wells stretching 1500 metres or more beneath the ocean floor.

    These reservoirs are the last frontier for hydrocarbon discovery. They’re not particularly hard to find: the challenge is to work out what they contain, how much can be extracted and at what cost. The sheer dimensions and depth of these fields make this time-consuming and expensive. But it is the geological complexity of the rock that makes these reservoirs so hard to characterise and this kind of exploration so financially risky.

    That’s why a new generation of engineers is developing techniques that can characterise these regions in greater detail than ever before. The ultimate goal is to develop three-dimensional computer models of vast regions of gas-bearing rock that reveal not only how much gas is trapped but also the geological and chemical environment in which it sits, and even how this will change over time as the reserve is tapped.

    For a conventional gas field, it is relatively straightforward to work out how much gas can be extracted because the gas is free to flow but usually trapped beneath an impermeable layer, like a bubble. Most of this can be extracted by drilling through the impermeable rock, allowing the gas to flow up and out.

    But so-called unconventional resources such as shale gas and coal seam gas are much harder to characterise because the gas cannot flow easily through these rocks. The amount that can be extracted depends on the network of natural cracks in the rock, how easily it can be fractured to produce more cracks and hence release more gas, whether the gas is chemically bound to the rock and so on. Then there is the type of rock, the shape of the formation, how easy it is to drill into – the list goes on.

    Oil and gas companies typically characterise resources through a combination of exploratory drilling and sophisticated computer models. They create these models by first mapping promising sections of geological basins – on land or underwater – by transmitting seismic waves into the ground and measuring the way they are reflected and bent by deep geological features.

    One long-standing problem for these kinds of surveys are vast layers of salt deep underground that tend to blur seismic waves, making it hard to probe what lies beneath. Salt is impermeable to oil and gas so important resources can be trapped beneath this layer.

    To get around this problem, engineers have developed mapping techniques capable of looking beneath the salt. BP’s Wide-Azimuth Towed Streamer system represents the state-of-the-art for creating 3D seismic images. WATS uses several ships sending acoustic waves into the water from different positions. These are flanked by other boats towing long floating cables carrying hydrophones to record the echoes. These cables can be several kilometres apart (see diagram).

    This distance ensures that the hydrophones receive the same rebounding seismic waves from a variety of angles. This provides a 3D perspective that can reveal what lies beneath salt layers.

    These surveys are also getting faster thanks to new techniques that reduce noise and filter out unwanted reflections. This allows engineers to use natural seismic waves generated by the Earth itself. And a new generation of sensing techniques use a single optical fibre to sense the reflected seismic waves along its entire length. This allows large areas to be monitored continuously for long periods of time. “The cost of seismic acquisition drops to almost nothing,” says geophysicist Roman Pevzner at Curtin University in Perth, Australia. Such long-term monitoring can be useful for tracking which parts of a reservoir are being exhausted and which should be drilled next.

    Seismic data is just the start, however. It can also be combined with electromagnetic surveys – which can distinguish between brine, which acts as a conductor, and gas, which has a higher resistance – and gravity measurements from satellites, which reveal different densities in the layers of rock below the ground, to give a more complete picture without resorting to expensive exploratory drilling.

    “Once we have sufficient confidence from the seismic and geological interpretation that there is a reasonable prospect of finding gas, we may choose to drill an exploration well,” says Shaun Gregory, senior vice-president of sustainability and technology for Woodside, Australia’s largest oil and gas company, based in Perth.

    Drilling is still the only way to be certain that gas is present. It also produces samples that reveal the pore structure of the rock in the formation. These can all be combined, along with mapping data, to create a computer model of the potential reservoir to gain insight into where the “sweet spots” to drill production wells might be.

    The explosion of computing capacity is making these models cheaper and more accurate, says Bill Barkhouse at the Society of Exploration Geophysicists (SEG) in Houston, Texas, which is pioneering these methods.

    The goal is to combine data about the rock at many different scales, from the molecular dynamics of how gas adheres to a substrate, to how gas flows through different types of rock, all the way to the behaviour of an entire gas field. “We are able to look at every level,” says George Moridis, head of the Hydrocarbon Resources Program at the Lawrence Berkeley National Laboratory in California.

    One such advanced model is currently being developed by the SEG with companies such as Chevron and Royal Dutch Shell. Called SEAM (SEG Advanced Modeling Program), the project has four phases, the first of which modelled a chunk of the sea floor 40 kilometres by 35 kilometres in the Gulf of Mexico to a depth of 15 kilometres, with a resolution of just 10 metres.

    The SEAM team has now turned its attention to land-based models of gas reservoirs that have been hydraulically fractured to work out how hydrocarbons flow through these rocks. The team also wants to predict the pressure at different points in a formation, an important factor in drilling operations. The ultimate goal is to simulate the entire life of a gas field as the hydrocarbons are extracted.

    But despite the huge advances made in gathering data and analysing it, Barkhouse says these models are too expensive and time-consuming to be commercially useful at this point. The SEAM phase I cost over $5 million and took 24 experts six years to create, finishing in July 2013. By contrast, a land-based exploratory well costs around $1 million and produces results on a timescale of weeks rather than years. Exploratory marine wells are much more expensive and can cost upwards of $100 million to drill. But again, they produce quicker results, a key factor in a fast-moving industry.

    Nevertheless, engineers are increasingly turning to supercomputers to analyse the flood of data their surveys are generating. BP’s Center for High-Performance Computing in Houston houses a machine capable of more than 2 quadrillion calculations per second (2.2 petaflops) for analysing the data from WATS and other sources. Computer scientists there are developing machine-learning algorithms that comb the data for “promising anomalies”.

    Gregory says the future of this technology is clear. Sensors will continue to get smaller, cheaper and less power-hungry, and they will feed ever growing amounts of data into increasingly powerful computers. He envisions networks of nanoscale sensors that can be injected into a well, giving a detailed picture of its structure and behaviour.

    But sensing and computing will never entirely replace good old-fashioned exploratory drilling, like that in Tanumbirini. As Moridis says: “You cannot produce gas out of a computer.”

    The topics in this series were developed by New Scientist in conjunction with APPEA.