2021 Year in Review: No Shortage of Interesting Engineering Problems To Solve
The mood in the global oil and gas business is looking up, but the times are changing as reflected in this selection of some of the most-read JPT articles of the year.
2021 turned out quite a bit better than expected.
Oil and gas prices rallied to levels not seen in years. For some, it has felt like a stratospheric vault from the historic lows suffered in 2020.
In what is an ongoing development, tight supplies of natural gas in Europe and Asia are reminding the world that hydrocarbons remain a critical energy source—and that keeping them affordable is also critical. Still, the continual talk of the energy transition has been a source of both concern and intrigue for those working in the industry.
This selection of 2021's most-read JPT articles reflects as much. It also shows that with the transition, engineers in the oil and gas business have an opportunity to solve a greater number of problems than perhaps ever before. Most of those are still strictly oil and gas problems, but a growing number involve tapping into new forms of energy and other resources.
As we say goodbye to 2021, take this chance to learn about some of these fresh ideas, big challenges, and the major advances that were covered in JPT over the past year.
The key message in the story by Medhat Kamal was a positive one—the demand for oil and gas, and the people who produce it, remains at a high level in the decades to come. But he also advised engineers to prepare to be agents of change. “Climate change is real,” and engineers need to “transform our industry in every possible way” to minimize its emissions. It is one of the many puzzles for engineers to solve. There are a lot of promising new tools, from data analytics to automation. But it is up to engineers to use their knowledge to maximize the value of those tools.
The relationship between legacy production wells and newly completed wells has been both a source of intrigue and frustration across the shale spectrum for at least the past 5 years. However, the industry has come to learn a lot about how frac hits, or fracture- driven interactions, really work and why. Not all of the questions have been answered, but a new joint industry study is trying to provide as many as possible. It examines the worst that can happen during a frac hit, what is most likely not happening, and how they can best be mitigated.
Calgary-based Proton Technologies is trying to be the first to prove that spent oil fields can be converted into geologic reactors that produce clean-burning hydrogen. The novel approach relies on years of oil and gas know-how and technology born from decades of producing heavy oil in Canada. If successful, the approach will give mature oil fields around the world a second life and petrotechnicals a chance to use their subsurface skill sets in the emerging hydrogen business.
The story of the Raptor Rig, Canada’s entry in the race to build the world’s first fully automated rig, ended in liquidation this year. Its assets were finally sold a few months before Nabors began drilling wells for ExxonMobil with its fully automated machine, the Pace R801. A critical difference between the two was that the Raptor lost its first customer before the much-delayed rig was finished. Now, ExxonMobil is testing Nabors' one-of-a-kind rig to see if what is technically possible is actually adding value in drilling long lateral wells. The race is moving closer to the goal of total automation. But the final definition of that will be up to the customers.
The goal of petroleum engineering can be described as drilling holes from which profits will flow. The source of that cash for some explorers has become helium, which has sold for hundreds of dollars per Mcf at a time when demand from high-tech applications is high and supplies are tight. Companies in this niche business are applying their oil and gas exploration experience to identify promising spots, often discovered by drilling natural gas dry holes that produce mostly nitrogen. A Canadian company in the business said a good well could produce about 2% helium along with all that nitrogen.
Operators in China have spent years experimenting with the country’s large but complex unconventional reservoirs in a bid to ramp up domestic gas production. Recently the nation's second largest producer, the China National Petroleum Company (CNPC), offered a look at how it has adapted and overcome some of its challenges using new technologies. To boost production from tight-gas wells in the Sichuan Basin, CNPC is using what it calls “enhanced hydraulic-fracturing” designs along with real-time completions data for performance feedback. In tight-oil rocks, it has adopted an “intensive fracture-cluster” strategy that also involves using a new flowback technology.
The oil industry’s rush to begin using digital tools has scrambled traditional relationships with oilfield service companies and brought in new players, from tech giants to startups. Oil companies see digital partnerships as a competitive weapon, arming their technical teams with advanced problem-solving tools, rather than the proprietary software solutions they long relied on. Engineers don’t need to be programming experts, but they need to know enough to be the subject matter experts that link the precise realm of advanced statistical analysis with the messy reality of a producing reservoir.
Automating gas lift creates opportunities. Digital injection-control equipment makes it possible to precisely control injection and constantly adjust those amounts. It replaces equipment where neither of those adjustments was possible. Potentially, that level of control could mean better performance, but only if those setting the controls have some understanding of the interactions of the water, oil, and gas flowing though the well and how to apply multiphase flow analysis to maximize the value of the well.
Shale producers have only recently begun to focus on the damage that could be caused by fracturing chemicals reacting with the reservoir rock. That always struck Stanford Professor Anthony Kovscek as odd since “shales are among the most reactive surfaces on earth.” This year there were signs of change as operators began looking for ways to evaluate friction- reducer performance and identify hazards, such as iron compounds in the well, to reduce the risk of fracturing additives subtracting from long-term results.
Petrotechnicals at Equinor claimed a major technological achievement with the introduction of what they called a reservoir-fluid-identification system. The technology relies on machine learning to analyze in real-time the mud gas flowing up wells during a drilling operation. Inside that gas are signs of whether the rock being bored through will be highly productive or not. Equinor is trying to extrapolate those insights and generate predictions on the rock’s future oil-to-gas ratio. Since this is done in real time, drillers can opt to stop drilling and tap a different, potentially more profitable pay zone. The fluid-identification system is in active use in Equinor’s offshore exploration projects.
Ahead of its next manned missions to the Moon, NASA has decided to do a little drilling. Two lunar projects involving robotic landers will collect subsurface soil and ice samples using methods that have been compared to how core samples are taken during oil and gas exploration activities here on Earth. The overarching goal is to find out whether in-situ resource utilization can be achieved, chiefly to yield water, or what interplanetary experts call “the oil of space.” In both missions, a rotary-percussive drill that has been adapted from oil and gas technology will be used to see what lies just a few feet below the Moon’s surface.
Russia has for years led the world in gas flaring, but can bitcoin mining help change that? Moscow-based Gazprom Neft is trying to find out after it joined the ranks of mostly North American oil and gas companies trying to turn otherwise flared gas into cryptocurrency, which in turn, can be converted into cash. Gazprom Neft’s first gas-to-bitcoin pilot took place in western Siberia using a shipping container filled with 150 mining units and in a month generated 1.8 bitcoin using 49,500 cubic meters of gas.