As companies work toward developing alternative sources for a world with ever-increasing energy demands, energy minerals are moving to the forefront of the conversation.
AAPG’s Energy Minerals Division finds itself in the spotlight these days for its work in prospecting alternative energy sources, such as geothermal and hydrates, for commercial use.
“We’ve got good momentum right now with interest in alternative energy,” said Ursula Hammes, AAPG Member, EMD president and president at Hammes Energy and Consultants.
At the 2020 online AAPG Convention and Exhibition, EMD committee chairs highlighted the latest developments in energy minerals as well as innovative possibilities for transition fuels.
Geothermal energy is an up-and-coming alternative energy, currently lagging behind the oil and gas industry by one or two decades, explained Bruce Cutright, AAPG Member and CEO at GeoFrame Energy.
“Geothermal development has not reached the technological sophistication of oil majors in terms of determining the geology of deep sedimentary formations, but we are now incorporating the drilling technology and data analysis that the oil and gas industry developed that resulted in the shale gas revolution,” he said.
The economics of geothermal energy dictate that there is little room for mistakes, or “dry holes,” he explained. While oil can be economical at roughly $25 a barrel, geothermal brines are valued at only $.05 to $0.25 per barrel, based on the electrical energy that they can produce, Cutright said.
The geothermal industry needs to incorporate the knowledge and methodologies that the oil industry has developed with huge capital investments in subsurface technology over the last 100 years, he said. While 3-D and 4-D seismic technology has been honed by the oil and gas industry, there is a crucial need to understand how to apply that technology to geothermal formations.
“If you bring the right technology and data analytics to the geothermal industry it will become a full-time employment program for petroleum science and engineers. We would just be mining heat instead of hydrocarbons,” Cutright said. “Heat reservoirs are tens of orders larger in magnitude than the typical oil or gas producing zone. If you understand heat flow, you can develop cost-competitive geothermal energy with zero carbon emissions.”
He added that geothermal energy is, in fact, competitive with wind, solar, coal and nuclear in the world market. It is the only baseload-capable renewable energy source available, with the exception of nuclear energy.
And, the world is seeing a big move toward nuclear power again, but “we need to get over past public perceptions of problems,” said Michael Campbell, AAPG Member and chief geologist/chief hydrogeologist of I2M Consulting, LLC in Houston.
He explained that scientists have learned to manage nuclear meltdowns, such as those that occurred at Three-Mile Island and Fukushima in Japan. (Chernobyl, he reminded, was a result of expedient Soviet-era designs and mismanagement of operations.)
Currently, there are approximately 95 nuclear power reactors in operation in the United States, and 441 are in operation in other countries with more under construction.
As it stands, uranium mining and nuclear power reactors in the United States have been a safer source of energy than generating oil and gas, coal and renewables, in terms of injuries and fatalities, Campbell said.
In the coming decade, he predicted that the United States will see the construction of small modular reactors, which are small nuclear power plants that offer strong safety features, lower capital costs and are reasonably priced to operate and require minimal waste handling.
Over the past 40 years, uranium typically has been imported from “insecure” countries, such as Russia, Uzbekistan and Kazakhstan, but efforts are currently being made to produce it locally for utilities from more secure sources, including the United States, Campbell said.
Regarding the cost of electricity, Campbell indicated that uranium fuel costs represent only about 5 percent of the operating cost of nuclear plant generation of electricity, whereas fuel costs of power plants using natural gas are much higher. And, nuclear power produces almost zero emissions and creates thousands of high-paying jobs.
The Cleanest Hydrocarbons
Recalling a time when the oil and gas industry believed nothing could be extracted from shale, Dan McConnell, AAPG Member and global product manager at Fugro, said, “that’s what they say about methane hydrates now.”
McConnell explained that there are “hundreds of thousands of TCF” in gas hydrate in the world. Some have been successfully extracted in tests from Arctic and marine sands.
“So if they are everywhere, why are they not on the radar of oil and gas companies?” he asked. “Huge parts of the planet are cold enough and under enough hydrostatic pressure where you could host gas hydrate.”
The answer is that gas hydrate deposits are not as easy to find as it would seem. Seismic attributes have been identified for gas hydrates in some settings but they are invisible in others. More challenges, however, lie in extraction, he said.
There are three ways to produce gas hydrates: reduce pressure, increase temperature or use chemical inhibitors. Reducing the pressure holds the most promise. A limited short-term production test in Japan produced gas hydrate from deepwater thin-bed, sand-prone reservoirs. In China, there was a promising production test from gas hydrate in marine clays.
Producing dissociated gas hydrate is complex. Whether in the Arctic or deepwater, the challenges will be many: low temperatures, low pressures, low production rates, higher gas-to-water production, solids and fines, compaction of reservoirs and even subsidence of the seabed.
Solve all those issues and gas hydrates could “cost significantly less than deepwater oil and gas production now,” McConnell said.
“We can find high saturation gas hydrates in marine sands. The next challenge is to predict the distribution in clays, such as the gas hydrates discovered in China. If we can solve that, we’ll have something like a shale gas situation,” McConnell said. “Methane hydrate is the cleanest of all the fossil fuels and could be the transition fuel from coal and oil as we move to natural gas.”
Coalbed methane, on the other hand, is further along in becoming a viable resource. Calling it an “important fuel for the future,” Jack C. Pashin, AAPG Member and professor and Devon chair of basinresearch at the Boone Pickens School of Geology at Oklahoma State University, explained it is an abundant resource, with some 8,000 TCFs of coalbed methane in the world.
“When we think of coal, we think of a solid black rock, but in reality it’s a large polymer with many spaces in it and can store gas at much lower temperatures and pressures,” he said. “A common coalbed methane reservoir will contain seven times as much gas per unit volume as a sandstone reservoir with 10 to 20 percent porosity.”
A coalbed methane reservoir is unusual in that it is a shallow, continuous-type unconventional reservoir. The resource is a mesoporous polymer with high gas storage, and the gas is stored by absorption, so pore pressures must be lowered for recovery. “It requires a different mindset to achieve commercial success,” Pashin said. “The lack of conventional trapping mechanisms necessitates a very different approach to exploration and development.”
Diverse drilling and completion technology can be used, yet the most common ways of extracting coalbed methane are from vertical wells that are multistaged and hydraulicly fractured or cavity completed. The wells produce water through tubing, and gas is released from the annulus of the well. Precision directional drilling increases drainage efficiency and provides access to low permeability reservoirs.
Production can be very inexpensive, and some reservoirs produce gas at near pipeline quality that requires minimal processing. Also, much of the world’s population is in or near coal basins, making coalbed methane a fuel that can easily be brought to market, Pashin explained.
In addition, production is very shallow, generally less than a kilometer in many basins, which facilitates development.
While scientists are currently looking at ways to extract non-petroleum resources – such as lithium, bromine and hydrogen – from tight oil and gas systems, Hammes insisted that tight oil and gas systems should remain on the radar for the future.
“We should not give up on tight formations. Tight shale-gas formations are facilitating a carbon neutral future because it is greener. It will be a good transition fuel,” she said.
Since the COVID-19 outbreak, there has been a 2 million barrel per day drop off in production in tight oil formations, according to the U.S. Energy Information Administration.
“The unfortunate headline for 2019 and 2020 has been that things are tough,” said Justin Birdwell, AAPG Member, president elect of the EMD and research environmental engineer and geochemist at the U.S. Geological Survey.
Birdwell said it is hoped that production will increase in the Permian, Bakken, Austin Chalk, Eagle Ford, Niobrara/Codell and Woodford formations.
Lucy Ko, AAPG Member and research associate at the Bureau of Economic Geology at the University of Texas at Austin, said production in tight formations is booming in parts of China, where the industry is experiencing a “golden age” in shale gas.
“China is still very active, even in this COVID time. They consume a lot of natural gas and they need domestic supplies. In fact, the country is aiming to boost its production of domestic shale, with marine shale showing the highest potential especially in the Sichuan Basin,” she said.
In Europe, however, shale exploration has all but come to a grinding halt because of environmental concerns, heavy regulation and bans on hydraulic fracturing.
However, Canada, Argentina and Brazil are continuing to drill as the economy allows, she said.
Looking at heavy oil and bitumen, Ian Kirkland, AAPG Member and senior geologist at Sproule, said that they are “still an important part of the oil and gas value chain.”
“Projections indicate that the phase-out of oil will take about 30 years, so there is a long time period in which the world will still continue to consume oil,” he explained. “Heavy oil and bitumen make up about 70 percent of the known remaining oil and can be upgraded and refined to make the products we use.”
Kirkland focused on the refining capabilities of the Petroleum Administration for Defense District 3 near the Gulf Coast and the opportunities it offers.
For Mexico, PADD 3 has been an important market for its heavy oil, which is on the decline as its Cantarell Field continues to mature. Venezuela was the largest supplier of heavy oil to PADD 3 but has since fallen off the radar because of mismanagement, corruption and sanctions. Yet for Canada, a prolific producer of heavy oil, PADD 3 represents an opportunity to grow its market.
“Alberta diluted bitumen and heavy oil has really only had meaningful access to PADD 3 since 2012-13 when the Keystone pipeline was extended down to there, but they are limited by pipe capacity to about 500,000 barrels a day plus whatever volumes can get there by rail,” Kirkland said.
At present, there is a 1.7 million barrel a day opportunity in PADD 3, which can process 2.4 million barrels a day of heavy crude. If heavy oil-producing countries such as Canada, Mexico and Venezuela can work through their present challenges and take advantage of PADD 3, it could create a win-win for the countries and the refineries.
“Time will tell who will benefit from this opportunity and who does not,” Kirkland said.
Hammes pointed out that the transition to sustainable energy should not discourage students or professionals from the oil and gas industry. Their skills, including mapping and reservoir characterization, are and will be invaluable as exploration takes off in many new directions.
“We need to promote EMD. We need explorationists for new minerals,” she said. “We are not just oil and gas explorers but explorers of all types of energy sources.”