What industry leaders expect for 2021
Making petroleum great again
In 2019, the United States achieved record production of over 12.2 MMbopd. This success set up the U.S. as the world’s top exporter of crude. Over 2.9 MMbbl of crude and 5.5 MMbbl of refined petroleum products were shipped to over 40 international destinations daily.
Shale gas and tight oil development set the stage for growth and sustainability in the petroleum industry. The Covid-19 crisis hit in early 2020, resulting in global lockdown and oil demand destruction, particularly in transportation fuels. Commodity prices dropped, and investments in growing production shifted to asset protection and free-cash flow generation. Consumption of petroleum in the U.S. fell 60%, to levels not seen since the 1960s. On the global stage, the story was similar, with restricted air travel and lockdowns. However, global electric demand remained growing despite the pandemic.
Climate change. With the global lockdown and reduced transportation, greenhouse gas emissions have declined slightly, but why only slightly? Because transportation fuel emissions are minute, compared to electric power generation. OECD countries represent 16% of world population. The remaining 84% are developing nations that require increased electrical power to support their growing social and industrial infrastructures. The largest risk to globally reducing greenhouse gas comes from developing nations, such as India, China and Southeast Asia, where many new coal-fired electrical generating plants are being built. Roughly half the world uses coal for electrical generation, a major source of greenhouse gasses.
LNG to the rescue. The U.S. is the world leader in reducing greenhouse gas emissions, but this reduction is far offset by developing nations that are increasing coal-fired electrical generation. The way to combat these coal-fired emissions is to increase the development of shale gas while also capturing associated gas from oil production. Converting these products to LNG for export could supplant the use of coal in non-OECD electrical power generation needs. This strategy would have the greatest impact globally in reducing greenhouse gases while supplying ample electrical power needs.
Currently, the U.S. is able to export 8 Bcfd as LNG to 38 different countries. New LNG terminals are being built, and once commissioned, the U.S. will be capable of 15.5 Bcfd of exports; more than any other country and able to supply 33% of global demand. The U.S. DOE has approved additional LNG facilities to be built. If all of these projects are completed, the U.S. shale gas industry could support 90% of global demand and reduce global greenhouse gas concentrations.
The future is bright. Renewables will have a place in the energy mix, but nothing other than nuclear beats the energy density of fossil fuels. Coal is nearly pure carbon, oil is complex hydrocarbons, but natural gas is mostly hydrogen. That makes it the clear winner, for the foreseeable future, as a climate-friendly fuel.
Global LNG demand has increased every year since 2012. It is relatively inexpensive, emits virtually no particulate matter, and is easily transported globally. Beyond just a preferred replacement for coal-fired electrical power plants, natural gas is essential as feedstock for making the chemicals, fertilizers, pesticides, plastics and synthetic materials that are in nearly everything we use.
Green energy better for the environment. Not really. Wind turbines and solar panels used to generate electricity, along with batteries for electric vehicles, require more than 10 times the quantity of materials, compared with machines using hydrocarbons to deliver the same amount of energy to society. The energy equivalent of 100 bbl of oil is used in the processes to fabricate a single battery that can store the energy-equivalent of 1 bbl of oil. The Manhattan Institute estimates that by 2050, the quantity of worn-out solar panels will be double the tonnage of all of today’s global plastic waste, along with over 3 MMt per year of unrecyclable plastics from worn-out wind turbine blades. By 2030, more than 10 MMt per year of batteries will become garbage.
Making petroleum great again. Global demand for energy and stakeholder expectations for a lower-carbon future have never been higher. Natural gas helps fulfills these requirements. Our industry has talked about natural gas as a bridge fuel for years but the public really doesn’t appreciate the significance. The public has been seduced by the green new deal without understanding the real consequences of such a plan. Our industry must do a better job of communicating the benefits of natural gas and the impact that LNG exports can have to achieve real positive reductions in global greenhouse gas emissions. Supporting shale gas development will lead to increased LNG exports and ultimately a reduction in global greenhouse gases. Thus, making petroleum great again.
The view from Norway
What a weird world! Corona turned “normal” upside down in one day. I live in Norway, and the government locked down the country on March 12. I was in Houston at the time and had to get home within a few days before the land border closed down completely. Once I was home, 10 days in quarantine awaited me.
And as we all know, the gas and oil prices plummeted, and our industry experienced a new, tough downturn, yet again.
In mid-April, I retired from NOV, after almost 20 fantastic years working for a great company. Retirement from NOV gave me the opportunity to join several boards in small technology companies, here in Norway. And I learned that in a downturn, creativity is flourishing.
Digitalization. Digitalization has been a big focus for many years, and the Coronavirus has been a catalyst in speeding up this process. Travel restrictions, home office, and meetings via Skype or Teams have become the norm, and it has actually worked pretty well. Surprisinglywell! But this also opens up new possibilities within digitalization, since we now are more comfortable with these solutions.
Wellit is a technology company that has created WELS, a logistics management software-as-a-service, for companies in the global energy industry. WELS compiles information and workflows on a single digital platform, and minimizes the need for phone calls, emails and spreadsheets. WELS enables streamlined operations and simplified workflows, in addition to reducing on-site workloads. Typically, WELS will unleash efficiencies that secure customers better overview, reduced costs and minimized CO2 emissions. WELS can seamlessly share logistical data between companies and projects. This collaborative force ensures one client’s best practice can be made available to all other customers.
Another company I have been involved with is FORCE Technology Norway, which has developed a service called FiGS®. FiGS® is an award-winning, non-contact field gradient sensor that can be used to assess the condition of the corrosion protection (CP) system (coating combined with cathodic protection) on subsea assets, such as pipelines, templates, manifolds, jackets, etc. It is an advanced integrity management inspection tool, with 50 times the detection level of any other technology available. With FiGS®, CP survey, maintenance and inspection operations can be planned, using a risk-based approach on a long-term basis, extending inspection intervals, as well as optimizing the offshore vessel time and minimizing interventions required. The “challenge” with FiGS is that this is a service, and due to Coronavirus, travel restrictions have limited or postponed several jobs this year.
The third company that I’m involved with is Stinger Technology AS, a fast-growing, innovative subsea technology and service company offering robotic underwater solutions. The goal is to become the go-to provider of lightweight, smart and rapidly deployable underwater drones for resident applications with semi-autonomous and autonomous characteristics. Stinger specifically targeted intervention, maintenance, and repair (IMR) services for the energy, telecom, aquaculture, mining and renewables markets. The services provide customers the necessary data and manipulation capability to support maximizing production and improving asset value while minimizing operating footprint, operating cost, carbon footprint, and offshore HSE exposure.
The year ahead. I am a firm believer that the oil and gas industry will recover as soon as the Coronavirus outbreak is under control. Third-quarter 2021 is a good estimate for that, I hope.
Since I have been spending more time in Norway and Europe the last few months, I must admit that the focus on Environment, Social and Governance (ESG) is much higher than what I experienced in Houston. “Everybody,” including the operators, is stating zero emissions to the environment within 2050 (in some cases, earlier). A lot of different technologies are being developed, such as Carbon Capture & Storage (CCS) and hydrogen production from natural gas liquids (NGLs).
In addition, a new concept or idea is being discussed: “Offsets.” Offsets means that a reduction in CO2 at one place can compensate for emissions produced at another place. A typical example of this is forest protection and restorations to compensate for CO2 emissions from oil and gas production. Several of the large consultancy companies are looking at pricing of “offsets”. How can “green” companies make money on offsets? Can this be a new business model?
Currently, I’m working part-time in a small start-up company called Desert Control, which has a patent to use Liquid Nano Clay (LNC) in dry areas to preserve water, in order to produce more food in desert-like environments. This is another way for operators to gain “offsets,” in their goal to achieve zero emissions. Desert Control is using oil and gas technology to develop their solution.
As I see this, we are now at a point in time, where we can use our oil and gas technology and develop this into new and greener areas. Oil and gas will definitely exist for many years to come, but I think it’s important to have more than a single thought in our heads at one time.
Carbon intensity of reserves: The next step to Net Zero
The longest record of direct measurements of CO2 in the atmosphere began with the Scripps Institution of Oceanography in 1958 at Mauna Loa Observatory, in Hawaii. Long-term atmospheric data are inferred from air bubbles entrained in well-preserved layers of ice collected from core samples taken from Antarctica (dating back 800,000 years) or Greenland (dating back 130,000 years). The National Science Foundation (NSF) collects, stores and studies ice cores, primarily at NSF Ice Core Facility in Lakewood, Colo.
Carbon emissions. Combining the above data sets, experts conclude that the atmospheric concentration of CO2 has risen from approximately 280 parts per million (ppm) in the pre-industrial period to 417 ppm in 2020, representing approximately 40 billion tons of CO2 emitted by humans each year. Even if humans eliminated CO2 emissions entirely, it would take thousands of years for the natural carbon sinks of the world’s oceans and forests to sequester CO2 from the atmosphere and return atmospheric CO2 to pre-industrial levels.
A new wave of investor sentiment regarding carbon emissions is driving changes in behavior for exploration and production companies. Many have launched Net Zero initiatives, created consortia to accelerate industry transition, and increased disclosures on a variety of metrics to convince investors of the long-term viability of the oil and gas industry. These are critical steps that must be taken, but a new challenge is emerging—the management of
fragmented carbon intensity reporting standards.
By harmonizing measurement standards and reporting metrics across our industry, we have an opportunity not only to provide investors with the clear, actionable data they require, but also to prove to
all stakeholders our commitment to self-monitoring and meeting our stated objectives.
Interestingly, our industry has faced and conquered a similar challenge before: reserves reporting. In 1987, SPE and the World Petroleum Congress (WPC) each published independent guidance for reserves. Over the next 10 years, the two organizations worked to jointly release a single set of standards, and by 1997, the groups had succeeded. By the year 2000, AAPG had joined in the effort, and the three bodies released a classification system for all petroleum resources. Progress continued until 2007, when standards were culminated into the Petroleum Resources Management System (PRMS), supported by SEG. Adding the various contributions of the Society of Petroleum Evaluation Engineers (SPEE), on which the original SEG standards were built, five independent industry organizations took 20 years to create, publish and standardize reserves reporting.
Carbon intensity reporting. As our industry continues to commit to sustainability targets ranging from 2030 to 2050, we simply do not have time for another 20 years to align on carbon intensity reporting standards.
A deeper similarity exists between the reserves process and the carbon intensity challenge we face—much more substantive, but perhaps less obvious. It is a critical challenge to map backward-looking, point-in-time measurements to high-quality, actionable forecasts. Reflecting on unconventional development, operators use all available information (subsurface measurements, geologic models, analog sets, well construction procedures, etc.) to make multi-decade predictions of well performance, based on a relatively small set of early-life production data.
As we’ve seen, early-life well performance is not always indicative of full-cycle well performance. Over time, some wells significantly underperform the underwritten case, but incremental capital for resource development already has been spent.
Our industry has seen great advancements in software supporting unconventional development. Modern cloud computing, paired with data science techniques (like Machine Learning), allows for probabilistic well forecasting underwriting P10, P50 and P90 outcomes. The result is a range of possible forecast outcomes feeding capital development decisions.
I see an opportunity to leverage the outstanding work this industry has already done to rise to the challenge of carbon intensity and sustainability reporting. Rather than creating new procedures, reporting protocols, and forecasting methodologies, we can layer sustainability initiatives on top of established reserves practices. Having already conquered the challenges of standardization, adopting best practices for statistical forecasting, and creating modern software that unites the two, our industry is ready to adapt to this new normal of sustainability reporting.
If you would like to participate in the growing community of experts working toward the pragmatic delivery, reporting and forecasting of sustainability metrics, I would invite you to join me in shaping the Carbon Intensity Reserves Management System (CIRMS). To learn more, please visit https://petro.ai/cirms.
Arctic oil field of the future
With a global pandemic, and the subsequent drop in demand for oil, our industry once again finds itself at a low point with many operators just getting by. Consolidation and a focus on low cost of supply assets is the name of the game these days. At a time like this, it is also easy to fall back to old habits, such as cutting costs and halting any sort of technology development, innovation campaigns or pilot projects. But it is in exactly these times, when we need to put our focus on technology and innovation to come out of this low point stronger and better positioned; a new North Slope development is trying to do just that.
Willow development. The Willow development, on the western North Slope of Alaska, which recently received the Bureau of Land Management’s Environmental Impact Statement Record of Decision, has an aspiration to create the Arctic Oil Field of the Future. Multiple technologies are being pursued to achieve this, and Closed Loop Reservoir Management (CLRM) is the solution for the subsurface, wells, and production disciplines. The vision is to automate the reservoir management process, drive better and faster decisions for more accurate forecasting, and become predictive in how the field is operated. By combining into one platform, data from instrumented wells, geological models, full-field reservoir models and integrated production models, one will be able to fully automate (close) the reservoir management process (loop) to minimize costs and maximize recovery. This essentially creates a subsurface and production digital twin.
This field will be operated under an enhanced oil recovery (EOR) scheme, with an alternating producers and injectors pattern. To reduce surface footprints, up to 70 extended-reach wells are being drilled per pad. Without any downhole instrumentation in the lateral, it is nearly impossible to have an accurate full-field reservoir model, unless multiple production logs are performed, which are costly and unrealistic on a development this size. Without either, one is left to infer what is happening up to 2 mi away by just a single tubing gauge at the heel, if one is lucky enough to have that.
Modern completion designs are a must to support CLRM through instrumented wells and flow control. Instrumented wells are key to granular well data needed for accurate models. Fiber optic technology continues to evolve and can be used for frac efficiency, flow profiling, and conformance. New pressure/temperature array instrumentation gives an important variable missing in fiber optic technology—pressure. But this is just data. Without any way to control inflow, there is less value. The key is to incorporate flow control, the ability to control parts of the lateral, to manage the EOR flood. These can be as sophisticated as the “Smart” interval control valves controlled remotely from surface, to as simple as an open/close frac sleeve that can be shifted with coil or e-line tractor.
Technology performance. An internal benchmarking study, using publicly available industry data performed by our corporate technology group, found operators, who trialed this technology in various assets around the globe, quoted NPV increases of up to 8% or recovery factor increases from 2% to 6%. Service companies are developing platforms to support this vision, such as Schlumberger DelfiTM and Halliburton LandmarkTM. But operators that are at the forefront of advancing this technology have chosen to develop their own platforms to maintain flexibility and build it the way that they want with their data sources; in this way, they are not tied to a specific software.
Apex, a surface production digital twin developed by BP, has, according to the company, “delivered 30,000 barrels of additional oil and gas production a day during 2017 across BP’s global portfolio.” Equinor, with their surface digital twin Echo, claims to have increased collaboration between onshore and offshore, and improved efficiency and safety. The digital space is evolving quickly, with cloud computing, artificial intelligence and machine learning starting to be adopted in the industry. Companies like Amazon Web ServicesTM, Microsoft AzureTM and many others are starting to enter the E&P industry, and it is not slowing down. This cloud-based computer processing power is on its way to making a real-time subsurface digital twin a reality.
Some may argue this is not the time to incur additional well costs, in order to collect more data; rather we should be trying to reduce overall well costs, as this is the only way to improve the cost of supply. Many managers will want an engineer to spend countless hours on creating a value case to justify the technology. But what if you could find out on those first wells you drilled, that the last third of the lateral is not producing? How about if you can detect water breakthrough at a heel zone that is easily controlled by shifting a frac sleeve closed? There are a multitude of uses for the technology. Many that have taken the plunge will tell you that what they have learned was not a predicted outcome, but none will say they regret the decision or did not see value at the end of the day.
I strongly believe this is where our industry is headed. We need modern completion designs with instrumentation and flow control to reap the benefits of Closed Loop Reservoir Management. We have to remember that cost is only one component in cost of supply, and CLRM is the way to significantly drive lower cost of supply through increased recovery factors and production rates. And it is for these motives that the Willow development is taking the polar plunge to become the Arctic Oil Field of the Future.
This is not your dad’s oil industry anymore!
DOUGLAS C. NESTER, Co-Founder and Chief Operating Officer, Compadre Resources, LLC; and Co-Founder, PetroAi LLC.
Although Digital Oilfield (DoF) technologies have been used for the past 15 years, the 2020 pandemic has accelerated our transition into a digitalized industry. This acceleration was driven by companies that needed to maintain operations while managing costs, reducing workforces and supporting work-at-home efforts to mitigate virus risk to remaining employees. I believe that DoF technologies and methodologies will establish a standard set of practices that companies will use, as we emerge from the shadow of this virus. This editorial provides some insight into the growing importance of the DoFs in our industry.
Covid impact. The global economic response to the growing pandemic was swift and dramatic. Domestically, the U.S. experienced its greatest macroeceonomic shock since the Great Depression, as growth in the second quarter fell 31% from the previous year. In addition, unemployment spiked to 14.7%, which is the highest rate recorded since WWII. Like many global businesses, the oil and gas industry was deeply impacted by this economic contraction. In some ways, it was the perfect storm, as the demand for petroleum products collapsed at a time when global output was ramping up, and as disagreements emerged between Russia and OPEC on daily oil production limits. As a result, global oil prices collapsed for the third time in the last 13 years, with WTI dropping below $20/bbl in April.
In response to the rapid drop in oil demand, operators and service companies took the necessary cost-saving measures needed to survive this period of uncertainty. As reported by Deloitte, some 107,000 energy-related positions were eliminated between March and August of this year. In addition to this workforce reduction, many companies encouraged staff to work at home, to mitigate the virus. Industry reports indicate that between 30% and 40% of U.S. employees are currently working at locations away from company offices. While applications, such as ZOOM and Microsoft Teams, sustained business communications, companies were driven to increase their use of DoF technologies and solutions to safely support day-to-day field operations with remaining staff.
Contributions from digital oilfield technology. The ongoing digital transformation of the industry involves combining emerging technologies, such as artificial intelligence (AI), the Internet of Things (IoT), augmented reality (AR), and mobile connectivity, to gather, analyze and respond to production-related information collected in the field. The ability to connect physical objects, such as sensors, meters, vehicles and equipment, to the internet network via IoT technologies enables companies to fully obtain critical operational data without human interaction.
The use of remote monitoring and automated solutions is enabling operators to optimize key functions, such as production performance, reservoir optimization and predictive maintenance. Production performance and operational costs are being optimized, using smart sensors to monitor and automate routine processes at each well site in real time. Environmental sensors and video feeds providing 24-hr surveillance are now becoming requirements of companies’ HSE policies to better safeguard workers and prevent serious damage to assets and the environment.
Big Data analysis, including machine learning and AI predictive analytics, provides companies with new insights from information that was previously inaccessible or unusable. To optimize reservoir management, operators incorporate all data available to describe reservoir conditions, such as seismic, well, drilling and production data to identify trends and anomalies to reduce uncertainties. This enables companies to make more informed, faster development decisions to increase production and enhance well performance. Predictive data analytics allow for automated preventive maintenance programs that better manage equipment availability and reduce interruptions and shutdowns, due to predicted component failures.
With 90% of digital data being created in just the last two years, the need for digital solutions during this fourth industrial revolution will continue to grow rapidly. To help meet our industry’s demand for DoF solutions, an emerging market of independent providers specializing in hardware, software and analytical solutions is now affording these technologies to operators of all sizes. In addition, companies are expanding their use of collaborations with service and technology providers to support their operational needs. Some collaborations will be formed to address specific challenges, such as the one between Microsoft, Chevron and Schlumberger to advance virtual twin technology. Others will involve international collaborations with companies from highly innovative countries, such as South Korea, to gain access and share the highly specialized personnel and equipment required to develop DoF technologies.
Therefore, and even during the ongoing workforce reductions and corporate restructurings that are reshaping our industry, I remain encouraged that the availability of these DoF technologies will enable us to emerge in late 2021 with a roadmap providing for leaner operations that are efficient, cost-effective and able to optimize production.
Why counting matters in uncertain times
ROBERT E. “BOB” WARREN, President, Baclenna, Inc.
“Truth is still truth, even if no one believes it. A lie is still a lie, even if everyone believes it." Anonymous
“Fools are the only Folk on earth, who can absolutely count on getting what they deserve.” Stephen King
“Be more concerned with your character than your reputation, because your character is what you really are, while your reputation is merely what others think you are.” John Wooden
In times past, during years of Presidential elections, this column has speculated on new—or continued—administrations, and various new—or continued—national policies, including (selfish as it may be), potential impact on U.S. energy policy. Some Presidential outcomes, with their inbred ideologies, have touched the energy trajectory to a greater or lesser extent, but they all affect the curve in some way. The year, 2020, will be remembered as an unprecedented bad dream: opening with another horrific energy downturn, joined by an exacerbated global pandemic, then tucked into a brutal election for the soul of the nation, where fossil fuels were often tossed into the fight for votes … as evil.
The 2020 election has turned out to be a brawl of brawls across our land. While the White House occupant through 2024 is now decided, with the attendant energy policies, we would have termed this experience a year ago, even a month ago, as impossible. Now, as the election journey (thankfully) has finished, we’ll project change—but no prognostication.
Political insanity: Instead, we shall pivot from the endless vote counting, the legal challenges, and the uncivil accusations, to count some individuals who solidly represent our future every day, especially in uncertain times. To be clear, there are uncountable champions in this business, so these folks are a tiny sampling of the unique people in oil & gas, making integrity of purpose the mission every day:
Trent Latshaw (Latshaw Drilling, Tulsa, Okla.): Celebrates recognition of quality crews and leadership in operations. Selected to host separate Permian rig visits by Vice President Mike Pence in 2019, followed by President Donald Trump in 2020. Unabashed support of conservative values, university internships, independent support of industry programs, named IADC Contractor of the Year in 2018;
Paul Mosvold (Scandrill, Houston): Early adopter of technology efficiencies and environmental applications in operations. Purposeful leadership and attention to crews and family, and support of community through giving personally/corporately. Unabashed supporter of conservative values. Frequently hosts elected officials and academics to rig sites in the continuous education effort;
Andy Hendricks/Mike Holcomb/Mike Garvin (Patterson-UTI, Houston): Donation of a 15,000-ft triple-derrick drilling rig package to Texas Tech University’s Petroleum Engineering Department, during two years, valued at several million dollars (crews not included). Appreciation to Brady Trucking (Healdton, Okla.) for their significant rig moving donation. An incredible effort to benefit training of next-generation leaders and oilfield workers;
Harold Hamm (Continental Resources, Oklahoma City): fierce spokesman for fossil fuel energy and national energy independence. A clear voice in the political wilderness, closely aligned with the Trump Administration for domestic and international energy policy. Instrumental in driving legislation lifting ban on oil exports during the Obama Administration. Chair of Domestic Energy Producers Alliance for supporting energy policy;
Wayne Christian (Commissioner, Texas Railroad Commission): Fierce spokesman for fossil fuel energy and national energy independence. A regulator known for staunch conservative values, and rational energy policy. Unflinching efforts to develop energy workforce opportunities in vocational programs across Texas—and beyond;
Julie Robertson (Noble Corp, Houston): Executive Chairman, and, until recently, Chairman, President & CEO. Forty-plus years serving with this legacy international drilling company, and the drilling industry. Named IADC Contractor of the Year in 2013 and served as the first woman Chairman of IADC in 2020. A poised leader in a rough-and-tumble energy world.
Constance White (Spindletop Charities, Houston): Retiring after 38 years of serving as Executive Director of the energy industry’s major charitable organization for at-risk children. Touched tens of thousands of young lives over the years. Past Chairman, Texas Ranger Association Foundation, Developed Emerging Leaders Program at Spindletop, Director of Impact a Hero. Among those making a difference in the lives of others and the energy industry.
Counting matters in uncertain times: Countless others like these are never counted among the champions of our industry, because they don’t seek recognition, and that’s what makes them remarkable. So when you’re on the road late some night and see a lighted derrick in the distance, you might thank these and the tens of thousands of our crewmates working morning tours in remote oil fields of our land … who help keep the lights burning and the wheels turning for the rest of us.
Uncertainty dominates outlook for UKCS in 2021
ALEXANDER G. KEMP, Professor of Petroleum Economics, University of Aberdeen, and Director, Aberdeen Centre for Research in Energy Economics and Finance
The year 2020 has been particularly dramatic for the UK oil and gas sector. The industry has experienced many highs and lows since its first development in the later 1960s, but none can compare with recent experience in its intensity. This reflects thecurrent combination of low oil and gasprices in a petroleum province which is now very mature by world standards. Thus, exploration drilling is at an all-time low, with less than 10 wells being drilled this year. In comparison, in 1986 and 1987 when the oil price collapsed to $10, the numbers of exploration wells drilled were in the 70-80 annual range.
Field development activity has also been at a very low level. The average size of new field developments is now just over 20 MMboe. The exceptions are much larger, but their costs per boe are still very high, because either they are high-pressure/high-temperature or have heavy oil features, and all are located in very deep waters. Cost reduction initiatives certainly have been undertaken, and efforts are being made to increase collaboration between operators and their contractors, who undertake much of the work. But inevitable tensions have arisen among the parties in the very difficult operating environment.
Tackling Covid-19, prices and Net-Zero. A major issue is the coincidence of Covid-19 and the associated decline in oil prices, alongside the commitment of the UK and Scottish governments to make rapid progress toward Net Zero emissions by 2050, in the case of UK government, and by 2045 for the Scottish government. These commitments create both problems and opportunities. The problem is how to reduce CO2 emissions, while the opportunity for the industry is the rewards from achievement of emission reductions. The Oil and Gas Authority (OGA), the regulator for the industry, is in the process of changing its central purpose to encompass not only the current Maximum Economic Recovery objective, but to include assistance to meet Net-Zero Emission targets, and to consider the behaviour of the industry, with respect to the maintenance of good environmental, social and governance practices.
What remains unclear are the details of the UK government’s policies to ensure that the Net-Zero objectives can be met. At the time of writing, an Energy Policy statement is imminent. Hopefully, it will indicate clearly details of the policy instruments, which it plans to use. These could include a mixture of carrots and sticks.
They could include clarification of whether the UK will remain within the EU Emissions Trading Scheme, or whether it will introduce its own trading scheme. Another possibility is that a CO2 tax could be introduced, which would apply to the oil and gas sector. A discussion paper on this subject has already been issued by the UK government.
Emission logistics. It is widely recognised that the depleted oil and gas fields on the UKCS have the capacity to hold enormous quantities of CO2. Further, a network of major pipelines already exists which, with additional new spur lines, could readily
transport CO2 from hubs, such as St. Fergus, to these fields. To make such projects viable requires the existence of a CO2 price at a level that encourages investors throughout the integrated chain of capture, transportation and storage. These activities are likely to be undertaken by different parties, which introduces complications before the integrated chain of activities can be successful.
The presence of assets, such as production platforms and pipelines, which can be modified to facilitate non-oil producing activities, requires detailed knowledge of the respective tax positions of oil and gas production and other non-oil activities. The two tax systems are quite different. To encourage investment in carbon capture and storage requires clarification of the tax position with respect to undertaking a change of use.
Currently, much attention is being given by the industry, and by the Oil and Gas Technology Centre (OGTC), on how emission reduction technologies can be made viable. These technologies include the use of windfarms located close to production platforms, to produce electricity sufficient to eliminate the need for using diesel or gas for power generation on the platform. To facilitate this, power from wind generation could be stored in large batteries located on a seabed near the platform, to give back-up power at times when the wind is not blowing. Another idea is to obtain electric power from renewable sources directly from mainland. This already takes place in the Norwegian sector, where electricity prices are much lower than in the UK.
It is encouraging that much research work is being conducted in the UK on these technologies. The long-run prosperity of the sector depends substantially on successful fruits of the R&D activities.
- Applying ultra-deep LWD resistivity technology successfully in a SAGD operation (May 2019)
- Adoption of wireless intelligent completions advances (May 2019)
- Majors double down as takeaway crunch eases (April 2019)
- What’s new in well logging and formation evaluation (April 2019)
- Qualification of a 20,000-psi subsea BOP: A collaborative approach (February 2019)
- ConocoPhillips’ Greg Leveille sees rapid trajectory of technical advancement continuing (February 2019)
