NrgEdge Editor

Sharing content and articles for users
Last Updated: March 6, 2019
1 view
Petroleum Geoscience
image

"The best geologist is the one who has seen the most rocks" is a mantra often repeated to student geoscientists. Sadly, not everyone has the opportunity to undertake field trips, and are therefore not benefitting from the learning opportunities and skills development gained from conducting measurements and observations in the field environment.

The Rationale

PetroEDGE provides technical training to the oil and gas industry through taught courses, workshops and field trips, but recently there has been a significant decrease in the number of requests for field trips, primarily due to a reduction in training budgets. Since virtual reality (VR) modules focusing on facilities and equipment were already available, it was decided to extend this to VR geological field trips, presented in a style consistent with physical field trips.

The Hilbre Islands off the north-west coast of England were chosen as a pilot location. They are well visited by field groups, and of particular interest to oil and gas geoscientists as they comprise the Lower Triassic Ormskirk Sandstone Formation of the Sherwood Sandstone Group, which is producing oil and gas from fields 25 km away in the East Irish Sea Basin.

The VR field trips are intended to create an immersive and realistic environment designed to encourage exploration. Users are supplied with a virtual field guide, accessible at all times, and have access to various tools to make appropriate measurements. Guidance at the start of the field trip encourages the user to make the same observations they would in the field and to develop their fieldwork skills. Areas of particular interest have 'hotspots' providing more detail when selected, such as core or log images, photomicrographs, depositional models, illustrations of sedimentary structures, or annotation of the outcrop. The range of information that can be displayed in the hotspots is vast, and can include video footage, seismic imagery, animations and 3D models.

The Challenges

There are numerous VR field trips available, with different strengths and disadvantages. Many exploit the freedom, scale and accessibility that drone image capture can provide; this has certainly excited me as, having spent years assuring field trip attendees of the features that can be seen at the top of outcrops, we can finally fly up and see for ourselves.

Our initial photogrammetric models did not provide high enough resolution when converted into VR, primarily because drones are unable to fly too near to outcrops and acquire close-up imagery. Many VR field trips have a resolution equal to 3 cm per pixel or lower, but to illustrate meaningful sedimentological features higher resolution is needed, and our aim was to resolve to coarse-grain size. Many months of experimentation with a combination of different methods of image capture and processing techniques achieved the required results, but also highlighted technical problems that would be encountered at future localities. 

For example, the presence of deep shadows confuses the processing software as it relies on an algorithm that identifies similarities in adjacent areas. Occasional shadowed areas can be processed manually, but that process is time consuming and is best avoided whenever possible. Virtual field trips to carbonate outcrops in the Middle East are planned, but filming when the sun is high in bright conditions will produce numerous areas of deep shade contrasting with brightly lit areas, creating extensive processing problems.

On a conventional field trip, it is possible to move behind foliage and boulders to access the outcrop, but these can obstruct drone image capture, so can limit the selection of locations. Also, some of the filming requires access to the outcrops on foot and cannot rely on flying drones into less accessible areas if high-resolution imagery is required.

Lengthy filming and processing of large outcrops can be overcome by using a combination of VR with embedded fly-past and 360- degree videos. As the user is provided with a geographical map, different sections of more extensive outcrops can be imaged and the user is transported to each area when selected on the map.

Integration with Other Training Methods

VR field trips cannot replicate all the skills transfer and learning opportunities provided by physical field trips, but we all need to be pragmatic in a changed financial landscape. Conventional field trips are costly in terms of travel, accommodation, downtime and logistics, so it is better to be able to experience many of the benefits of a field trip, albeit virtually, than to never experience them at all. The skills required to make appropriate observations and conclusions can still be taught, and serve as a reminder that the various data we are using elsewhere relates to real rocks and that interpretations should comply with our understanding of geological processes.

Using VR field trips to illustrate various aspects of training courses can be more incidental, allowing trainees to experience field trips as part of classroom courses or workshops, where travel to each locality is impractical or costly. VR modules can be tailored to include information pertinent to the course, or be integrated with other learning resources. However, it is vital that the VR field trips are valuable in their own right, and not just a new technology to play with. Unnecessary graphics and sound effects have been eliminated to help the user forget they are in VR and focus on the geology.

Flexibility

The information in the hotspots and field guides can easily be tailored to different audiences, including non-geoscientists, engineers, administrative staff and geophysicists. Many of these groups might not normally attend conventional field trips, but do attend classroom courses that can be enriched by examining real rocks. 

The field trip leader can be in the classroom with attendees, or can join them remotely, guiding the trainees in the same way as on a physical field trip. However, the VR field trips are designed as stand-alone modules that can also be accessed by an individual without any need for a leader or instructor. Undertaking a particular module can be used as a refresher for staff, to acquaint themselves with a new environment of deposition, or as part of their personal development programme. VR field trips may also be used to equip students with field skills or to familiarise them with the locations prior to a real field trip. This serves to build their confidence and maximise their time in the field. They can be reviewed many times and help to refresh understanding, or provide easy comparison between different localities.

There is also interest from various organisations anxious to preserve educational outcrops that are threatened by weathering, quarrying or development. Putting these outcrops into VR ensures access for future students and field trippers, and provides consistency for any teaching modules that utilise these localities.

Inclusivity

When planning a physical field trip, it can be difficult to include access to a number of good outcrops that tell a coherent story, while restricting the amount of travelling between localities. With VR field trips, a wide range of geographical locations can be combined to provide a comprehensive understanding, or for comparison of different localities.

The cost of creating VR field trips is mitigated by the unlimited number of users able to access each trip, the absence of travel and logistical costs, and the variety of roles the VR field trips can fulfil.

It must be stressed that VR field trips are not intended to replace physical field trips, but do provide additional features, such as aerial and panoramic views, and the ability to overlay data, interpretation and models onto the outcrop. They also provide inclusive access to less mobile users, or those unable to travel. Inclusivity also extends to non-geoscientists, junior staff and others who may not normally get an opportunity to visit the field. Remote localities, outcrops with restricted accessibility or ones that present particular health and safety risks can still be experienced, providing the filming team can overcome these issues safely.

However, virtual reality field trips should not just be considered a cost-effective, risk-free alternative to real field work. They offer unique opportunities to incorporate activities and features unavailable in the field, and deliver a more integrated and flexible learning resource.

Carol Hopkins is the Geosciences Technical Director for PetroEdge (Oil & Gas Training Provider). Carol's article was first published in GEO ExPro Magazine, the upstream oil and gas industry’s favourite magazine, and a PetroEdge (Oil & Gas Training Provider) industry partner. Visit GEO ExPro at https://www.geoexpro.com


#PetroEdge #virtualfieldtrips #VR #thebestofVR #CarolHopkins
3
2 4

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

Natural gas prices fall to lowest level since 2016, the lowest February prices in 20 years

This winter, natural gas prices have been at their lowest levels in decades. On Monday, February 10, the near-month natural gas futures price at the New York Mercantile Exchange (NYMEX) closed at $1.77 per million British thermal units (MMBtu). This price was the lowest February closing price for the near-month contract since at least 2001, in real terms, and the lowest near-month futures price in any month since March 8, 2016, according to Bloomberg, L.P. and FRED data.

In addition, according to Natural Gas Intelligence data, the daily spot price at the Henry Hub national benchmark was $1.81/MMBtu on February 10, 2020, the lowest price in real terms since March 9, 2016. Henry Hub spot prices have ranged between $1.81/MMBtu and $2.84/MMBtu this winter heating season (since November 1, 2019), generally because relatively warm winter weather has reduced demand for natural gas for heating. Natural gas production growth has outpaced demand growth, reducing the need to withdraw natural gas from underground storage.

Dry natural gas production in January 2020 averaged about 95.0 billion cubic feet per day (Bcf/d), according to IHS Markit data. IHS Markit also estimates that in January 2020 the United States saw the third-highest monthly U.S. natural gas production on record, down slightly from the previous two months.

IHS Markit estimates that U.S. natural gas consumption by residential, commercial, industrial, and electric power sectors averaged 96 Bcf/d for January, which was about 4.4 Bcf/d less than the average for January 2019, largely because of decreases in residential and commercial consumption as a result of warmer temperatures.

However, IHS Markit estimates that overall consumption of natural gas (including feed gas to liquefied natural gas (LNG) export facilities, pipeline fuel losses, and net exports by pipeline to Mexico) averaged about 117.5 Bcf/d in January 2020, an increase of about 0.2 Bcf/d from last year. This overall increase is largely a result of an almost doubling of LNG feed gas to about 8.5 Bcf/d.

Because supply growth has outpaced demand growth, less natural gas has been withdrawn from storage withdrawals this winter. Despite starting the 2019–20 heating season with the third-lowest level of natural gas inventory since 2009, by January 17, 2020, working natural gas inventories reached relatively high levels for mid-winter. The U.S. Energy Information Administration’s (EIA) data on natural gas inventories for the Lower 48 states as of February 7, 2020, reflect a 215 Bcf surplus to the five-year average. In EIA’s latest short-term forecast, more natural gas remains in storage levels than the previous five-year average through the remainder of the winter.

lower 48 states working natural gas in storage

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and Short-Term Energy Outlook

According to the National Oceanic and Atmospheric Administration (NOAA), January 2020 was the fifth-warmest in its 126-year climate record. Heating degree days (HDDs), a temperature-based metric for heating demand, have been relatively low this winter, which is consistent with a warmer winter. During some weeks in late December and early January, the United States saw 25% to 30% fewer HDDs than the 30-year average. This winter, through February 8, residential natural gas customers in the United States have seen 11% fewer HDDs than the 30-year average.

U.S. natural gas customer-weighted heating degree days

Source: U.S. Energy Information Administration, based on National Oceanic and Atmospheric Administration Climate Prediction Center data

February, 17 2020
Your Weekly Update: 10 -14 February 2020

Market Watch   

Headline crude prices for the week beginning 10 February 2020 – Brent: US$53/b; WTI: US$49/b

  • The demand destruction caused by the Covid-19 pandemic – also known as the Wuhan coronavirus – has dragged crude prices to fresh lows, with OPEC+ struggling to present a united front to respond to the demand crisis
  • Earlier indications that OPEC+ was preparing to call for an emergency meeting mid-February to discuss the pandemic’s impact on the oil market were dashed, hinting at divisions within the oil club
  • Reportedly, OPEC’s technical committee was proposing to extend the club’s supply quota agreement through June 2020; Saudi Arabia – along with Iran and Bahrain – were the strongest supporters, but Russia remains reticent to commit
  • A group of key Russian oil producers are in support of extending the OPEC+ cuts, with Gazprom, Lukoil and Rosneft indicating that it ‘made sense’
  • In the face of the huge impact of Covid-19, the so-called Brent red spread sank into contango, indicating an intensely bear-ish market
  • Although the fatality rate of the new coronavirus is much lower than SARS, the spread has been far more severe and wider, with confirmed cases nearing 70,000 and deaths nearing 1,500
  • After being on lockdown for weeks, Chinese factories and businesses have gradually returned to work at a glacial pace, impacting gasoline, gasoil and - most significantly – jet fuel demand, causing Chinese refineries to slash output
  • News that China and the US would both implement tariff cuts on the pre-Phase 1 trade deal levies on February 14 failed to calm the market, supporting the floor for prices rather than raising the ceiling
  • Amid that chaos, the US active rig count dropped four rigs, falling down to 790 total and down 255 sites y-o-y; however, the relationship between this proxy and actual production has diminished over the past two years, as the US continues to produce more oil from less rigs
  • Hopes that the outbreak might have peaked has supported crude oil prices this year, although a major spike in confirmed cases from a wider diagnosis tool nipped that in the bud; expect crude oil prices to continue hovering around the US$50/b mark, at US$51-53/b for Brent and US$49-51/b for WTI


Headlines of the week

Upstream

  • Chevron and Petrobras will be selling their stakes in the heavy oil Papa-terra field in the Campos Basin, seeking new operatorship for the BC-20 concession asset that is currently split 62.5/37.5 between Petrobras and Chevron
  • Shell plans to boost its output in the Permian Basin to some 250,000 b/d by end-2020, up from a current production level of 100,000 b/d as it announced plans to invest up to US$3 billion per year in the prolific US shale area
  • Eni’s oil production in Libya has halved to 160,000 b/d, as the country continues to grapple with a blockade started by military strongman Khalifa Haftar
  • Disappointing results in Africa have forced Tullow Oil to reduce its headcount in Kenya by 40%, with operations in Kenya, Uganda and Ghana all yielding either poor results or in danger of significant delays
  • BP and Shell have brought the Alligin field in the UK West of Shetlands region online, with initial output at a better-than-expected 12,000 b/d
  • Guyana’s oil riches keep increasing; after ExxonMobil upped estimates at the Stabroek block last month, Eco Atlantic (together with Tullow Oil and Total) have upped reserves in the Orinduik block from 3.98 mmboe/d to 5.14 mmboe/d

Midstream/Downstream

  • Reports suggest that Chinese independent teapot refineries in Shandong have slashed their utilisation rates by 30-50%, scaling down in response to severely diminished fuel and petrochemicals demand due to the Covid-19 pandemic
  • Chinese state refiners are following suit with slashing output, with CNOOC, Sinopec and PetroChina all lowering their throughput rates by 10-15%
  • Shell has finalised the sale of its Martinez refinery in California, selling it to PBF Energy for some US$1.2 billion, including its supply/offtake agreements
  • Botswana is accelerating its US$4 billion coal-to-liquids refinery project, now expecting to complete the site by 2025, with the aim of tapping into the country’s major coal reserves that are some of the largest in Africa
  • The UK has extended its goal to end the sale of all gasoline- and diesel-powered vehicles in the UK by 2035 to include hybrid vehicles, which would move transport fuel demand entirely to electric vehicles then

Natural Gas/LNG

  • Abu Dhabi and Dubai report that they have made a major natural gas find, with the Jebel Ali reservoir located between the two largest sheikhdoms in the UAE holding some 80 tcf of resources - the world’s largest gas find in 15 years
  • The government of Papua New Guinea has walked away from talks over the P’nyang gas field, impacting the planned expansion of ExxonMobil’s PNG LNG project; the government had previously tried a similar tactic with Total
  • The EU has imposed sanctions on Turkey, in retaliation for its continued exploration of gas resources in the disputed waters off Cyprus that Turkey claims is part of the breakaway Turkish province in the north of the island
  • CNOOC has declared force majeure on some LNG contracts due to the ongoing impact of the Covid-19 outbreak, but two of the world’s largest LNG traders – Shell and Total – have rejected the Chinese attempt to nullify contractual terms
  • Centrica will take a major write-down on its gas assets in Europe, continuing a trend of the global natural gas glut eroding the value of gas assets worldwide
  • GeoPark has made a new natural gas discovery in Chile, with the Jauke Oeste field in the Fell block of the Magallanese Basin yielding small-but-significant gas flows of some 4.4 mscf/d
February, 14 2020
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • EIA expects global petroleum and liquid fuels demand will average 100.3 million barrels per day (b/d) in the first quarter of 2020. This demand level is 0.9 million b/d less than forecast in the January STEO and reflects both the effects of the coronavirus and warmer-than-normal January temperatures across much of the northern hemisphere. EIA now expects global petroleum and liquid fuels demand will rise by 1.0 million b/d in 2020, which is lower than the forecast increase in the January STEO of 1.3 million b/d in 2020, and by 1.5 million b/d in 2021.
  • EIA’s global petroleum and liquid fuels supply forecast assumes that the Organization of the Petroleum Exporting Countries (OPEC) will reduce crude oil production by 0.5 million b/d from March through May because of lower expected global oil demand in early 2020. This OPEC reduction is in addition to the cuts announced at the group’s December 2019 meeting. EIA now forecasts OPEC crude oil production will average 28.9 million b/d in 2020, which is 0.3 million less than forecast in the January STEO. In addition to these production cuts, EIA’s lower forecast OPEC production reflects ongoing crude oil production outages in Libya during the first quarter. In general, EIA assumes that OPEC will limit production through all of 2020 and 2021 to target relatively balanced global oil markets.
  • Global liquid fuels inventories fell by roughly 0.1 million b/d in 2019, and EIA expects they will grow by 0.2 million b/d in 2020. Although EIA expects inventories to rise overall in 2020, EIA forecasts inventories will build by 0.6 million b/d in the first half of the year because of slow oil demand growth and strong non-OPEC oil supply growth. Firmer demand growth as the global economy strengthens and slower supply growth later in the year contribute to forecast inventory draws of 0.1 million b/d in the second half of 2020. EIA expects global liquid fuels inventories will decline by 0.2 million b/d in 2021.
  • Brent crude oil spot prices averaged $64 per barrel (b) in January, down $4/b from December. Brent prices fell steadily through January and into the first week of February, closing at less than $54/b on February 4, the lowest price since December 2018, reflecting market concerns about oil demand. EIA forecasts Brent prices will average $61/b in 2020; with prices averaging $58/b during the first half of the year and $64/b during the second half of the year. EIA forecasts the average Brent prices will rise to an average of $68/b in 2021.

Natural gas

  • In January, the Henry Hub natural gas spot price averaged $2.02 per million British thermal units (MMBtu), as warm weather contributed to below-average inventory withdrawals and put downward pressure on natural gas prices. As of February 6, the Henry Hub spot price had fallen to $1.86/MMBtu, and EIA expects prices will remain below $2.00/MMBtu in February and March. EIA forecasts that prices will rise in the second quarter of 2020, as U.S. natural gas production declines and natural gas use for power generation increases the demand for gas. EIA expects prices to average $2.36/MMBtu in the third quarter of 2020. EIA forecasts that Henry Hub natural gas spot prices will average $2.21/MMBtu in 2020. EIA expects that natural gas prices will then increase in 2021, reaching an annual average of $2.53/MMBtu.
  • U.S. dry natural gas production set a record in 2019, averaging 92.1 billion cubic feet per day (Bcf/d). Although EIA forecasts dry natural gas production will average 94.2 Bcf/d in 2020, a 2% increase from 2019, EIA expects monthly production to generally decline through 2020, falling from an estimated 95.4 Bcf/d in January to 92.5 Bcf/d in December. The falling production mostly occurs in the Appalachian and Permian regions. In the Appalachia region, low natural gas prices are discouraging natural gas-directed drilling, and in the Permian, low oil prices are expected to reduce associated gas output from oil-directed wells. In 2021, EIA forecasts dry natural gas production to stabilize near December 2020 levels at an annual average of 92.6 Bcf/d, a 2% decline from 2020, which would be the first decline in annual average natural gas production since 2016.
  • EIA estimates that U.S. working natural gas inventories ended January at more than 2.6 trillion cubic feet (Tcf), 9% higher than the five-year (2015–19) average. EIA forecasts that total working inventories will end March at almost 2.0 Tcf, 14% higher than the five-year average. In the forecast, inventories rise by a total of 2.1 Tcf during the April through October injection season to reach almost 4.1 Tcf on October 31, which would be the highest end-of-October inventory level on record.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. utility-scale electricity generation from natural gas-fired power plants will remain relatively steady; it was 37% in 2019, and EIA forecasts it will be 38% in 2020 and 37% in 2021. Electricity generation from renewable energy sources will rise from a share of 17% last year to 20% in 2020 and 21% in 2021. The increase in the renewables share is the result of expected use of additions to wind and solar generating capacity. Coal’s forecast share of electricity generation will fall from 24% in 2019 to 21% in both 2020 and 2021. The nuclear share of generation, which averaged slightly more than 20% in 2019 will be slightly lower than 20% by 2021, consistent with upcoming reactor retirements.
  • EIA forecasts that U.S. coal production will total 595 million short tons (MMst) in 2020, down 95 MMst (14%) from 2019. Lower production reflects declining demand for coal in the electric power sector and lower demand for U.S. exports. EIA forecasts that electric power sector demand for coal will fall by 81 MMst (15%) in 2020. EIA expects that coal production will stabilize in 2021 as export demand stabilizes and U.S. power sector demand for coal increases because of rising natural gas prices.
  • After decreasing by 2.3% in 2019, EIA forecasts that energy-related carbon dioxide (CO2) emissions will decrease by 2.7% in 2020 and by 0.5% in 2021. Declining emissions in 2020 reflect forecast declines in total U.S. energy consumption because of increases in energy efficiency and weather effects, particularly as a result of warmer-than-normal January temperatures. A forecast return to normal temperatures in 2021 results in a slowing decline in emissions. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.
February, 12 2020