The transition to Net Zero emissions: An upstream technology outlook

DR. GHAITHAN A. AL-MUNTASHERI, Saudi Aramco 

INTRODUCTION 

Hydrocarbons have provided affordable energy to the planet for more than 150 years. Providing the fuel for transportation to connect the planet, being the source of the raw materials for manufacturing medical devices, clothes and even food, the oil and gas industry was truly the engine that provided the massive growth for humanity. It will impact the future of the planet as well (Yergin 1991 and 2020; Stevens 2018).  

Today, the industry is faced with the Climate Change challenge. The Paris Agreement involving 196 countries was an international commitment to maintain the global temperature increase to below 1.5^oC by the end of the century. To achieve that, the Green House Gas (GHG) emissions must be suppressed. Quantitatively speaking, this means reducing emissions 46% by 2030 and achieving Net Zero Emissions (NZE) by 2050 (United Nations 2024).  

Greenhouse gases related to upstream oil and gas operations are mainly carbon dioxide (CO₂) and methane (CH₄). Other environmentally harmful gases include nitric oxide (NO_x) and nitrous oxide (N₂O). These gases are emitted in various processes in upstream operations from any of the following: venting, fugitive releases, flaring or fuel combustion for power generation.  

Reporting of the various emission gases is translated into equivalent mass of CO₂. For businesses and companies, the GHG emissions can be classified into four main categories. The first one is direct GHG emissions (scope 1) which are emissions from sources at a facility owned and/or operated by a company. The second is the indirect GHG emissions from imported energy (scope 2), which includes GHG emissions that occur at the point of energy generation for electricity, heat or imported steam. The third (scope 3) includes all other GHG emissions occurring in the whole value chain such as production and transportation of purchased fuels and materials for use on site by the reporting entity. The fourth (scope 4) is the avoided emissions as a result of using energy-efficient systems (World Economic Forum 2024).  

To get more quantitative insights, the world emitted a total of 59 gigatons (Gtons) of CO₂ in 2022 (Wood Mackenzie 2024). Out of that, carbon emissions from fossil fuels and industrial processes represented 37 Gtons of CO₂ (Our World in Data 2022, Wang and He 2023). It is estimated that 5.2 Gtons of CO₂ emissions came from oil and gas operations (IEA 2023; Wood Mackenzie 2024).  

Looking at the upstream part alone, Gargett et al. (2019) cites two-thirds of the total oil and gas operational emissions as upstream emissions. The reference reported 3.5 Gtons of CO_2e being upstream emissions. When looking at the global emission level from fossil fuels and industrial processes, 37 Gtons of CO_2e in 2022, upstream decarbonization can bring an opportunity for a reduction of about 9.5% (which is around 3.5 Gtons of CO_2e) of all energy-related global GHG emissions.  

Fig. 1. Global upstream oil and gas carbon emissions as part of the overall global total emissions (Gargett et al. 2019, Our World in Data 2022, IEA 2023; Wood Mackenzie 2024, Wang and He 2023).

Figure 1 shows the breakdown of emissions data with the 9% contribution of upstream emissions to fossil and industrial processes. This amount is significant. To illustrate the impact that the oil and gas industry can make, there are around one billion vehicles on the planet today. The 3.1 Gtons of CO_2e represent almost 70% of their annual emissions (EPA 2024).  

The Oil and Gas Climate Initiative (OGCI) reported an aggregate 318 million tons (MMtons) of CO_2eq for scope 1 and 2 of its members in 2022 (OGCI Progress Report 2023). One important parameter set to quantify and compare upstream emissions is the Upstream Carbon Intensity (UCI), which is defined as the ratio of the GHG emitted per unit volume of petroleum fluids (OGCI Report 2023). It is reported in equivalent mass of CO₂ per barrel of oil equivalent (kg CO₂/barrel_eq).  

In 2017, the baseline was 23.0, and it is targeted to reach 17 kg CO₂/barrel_eq by 2025. In 2022, UCI is reported to be 18 kg CO₂/barrel_eq, representing a 21% drop from the 2017 baseline and being within 5% of the targeted level by 2025. Note that most upstream emissions are CO₂-related, as methane emissions are low, which will be discussed later in the article. In fact, OGCI reports that 75% of upstream carbon dioxide emissions in OGCI member companies come from energy production and usage (OGCI Report 2023).  

Opportunities exist to decarbonize upstream oil and gas operations. Although some of these opportunities lie in energy efficiency, portfolio management and optimization, the emission reduction resulting from these levers will not be sufficient to achieve the net zero target. Thus, more work needs to take place in terms of technological advancement to achieve net zero.  

The economics of the so-called energy transition are not feasible. It is estimated that an economic transition scenario by 2050 will only be possible with a temperature increase scenario of 2.6^oC. Hence, the Paris Agreement is not met. Moreover, such a transition will cost $215 trillion (BNEF 2024a). Unfortunately, energy access, security and affordability are still unavailable in many parts of the world. The UN Development Program (UNDP) reports that 733 million people on the planet have no electricity (UNDP website). Moreover, 2.4 billion people have no access to clean cooking solutions.  

While the oil and gas industry has the new Climate Change mandates to reduce emissions, it still has the moral mandate towards providing energy to the planet and the duty to continue the growth of the planet. The balance between the two objectives of humanity’s growth and environmental protection is a must. Technology will be the key to achieving that. Therefore, the objectives of this article are to 1) shed light on the decarbonization opportunities in upstream oil and gas operations; 2) provide a technology overview of the various decarbonization strategies; 3) present a roadmap for researchers from all related disciplines to focus on the impactful projects to support the NZE; and 4) highlight successful examples of technologies for decarbonization from an upstream perspective.

Fig. 2. A futuristic illustration of the sustainable upstream lifecycle.

FUTURE UPSTREAM OPERATIONS IN A NET ZERO SCENARIO 

The future upstream sector will continue to provide oil and gas but in a less impactful manner to the environment as shown in the schematic of Fig. 2. Starting with the exploration phase, advancements in seismic acquisition and processing are poised to significantly reduce emissions and mitigate risks associated with discovering new petroleum resources. In seismic acquisition, the use of drones presents a substantial improvement over traditional methods, such as truck-based systems and cable-connected geophones. Drones enable faster, more efficient data collection while minimizing environmental impact, as they consume less energy and cause less surface disturbance. This streamlined approach not only reduces emissions but also enhances overall operational efficiency.  

In seismic processing, the integration of technologies, such as quantum computing and satellite imaging, is driving transformative advancements. Quantum computing offers the capability to process vast amounts of seismic data with unparalleled accuracy and efficiency, allowing geoscientists to pinpoint subsurface resources with greater precision. Once the well site is specified, it is envisioned to be less dependent on gas- or diesel-based generators and, thus, less combustion products will be released into the atmosphere.  

To replace combustion-based generators, solar and wind power will be used. In addition, hydrogen-based generators will come into the picture. This should bring sufficient power to operate the well site, starting with the drilling process, then the hydraulic fracturing operations, all the way to the production phase to power the monitoring devices, downhole equipment, leak detection devices and Electrical Submersible Pumps (ESPs).  

On the reservoir side, advanced sensor networks, data analytics, and predictive modeling will enable real-time monitoring of reservoir conditions. Advanced analytics and artificial intelligence (AI) will be used to monitor, detect and eliminate any on-site gas leaks. There will be no waste heat at the flaring points in surface facilities, as methane will be converted into other products using that energy. Technology will be advanced enough to utilize the natural gas produced at the wellhead site to generate hydrogen for powering the site, or to capture CO₂ emissions as a result of methane combustion and convert it to useful materials.  

Fig. 3. Methane emissions from oil, gas, coal and bio energy sources for the year 2023 (IEA 2023).

Oilfield produced brines—recycled, or disposed in various upstream operations—will be a valuable source of precious metals with the right minerals extraction technologies. In order for this vision to become a reality, several technological advancements need to be made. These challenging but exciting R&D mandates will put the upstream at the forefront of the energy transition. In what follows, we will shed light on various areas of focus to enable this futuristic vision.  

CHALLENGES AND GAPS 

Methane emissions. Scientific analysis reports that methane is more impactful to the atmosphere than CO₂. Its chemical structure allows it to store more energy and absorb more heat, compared to CO₂, and therefore, it has higher global warming potential (GWP). It is estimated that methane can be 80 times more powerful than CO₂ over a period of 20 years.  

However, methane can dissociate faster in the atmosphere. The reason is the shorter lifetime of methane (12 years) in the atmosphere, compared to CO₂ (more than 100 years). Thus, over long periods of time, CO₂ is more harmful, as greater amounts of it get accumulated, while methane has more effects over shorter time scales. To put these two gases into the perspective of oil and gas operations, the International Energy Agency (IEA) estimates there were 78 million tons of methane emissions in 2023 from oil and gas operations, Fig. 3. This represents around 24% of the total global methane emissions in the same year. Over a 20-years period, this is equivalent to 6.6 Gtons of CO₂.  

Fig. 4. Upstream Carbon Intensity (UCI) and methane intensity for OGCI companies (OGCI 2023).

During COP 26, the Global Methane Pledge was launched, with the objective of reducing methane emissions. Later, at COP 28, the Global Methane Pledge stated that 60% of methane emissions need to be reduced by 2030, to meet the 1.5^oC global warming scenario. As one milestone in this commitment, OGCI has set a target for methane emission intensity to be 0.2% by 2025. As of 2021, the methane intensity was already below 0.2% (at 0.17%). This is shown in Fig. 4, along with the Upstream Carbon Intensity (UCI) data for OGCI (OGCI 2023).  

The 2030 target is to reach near zero. Evidently, the industry’s lowest methane intensity was reported by Aramco at 0.05% (Aramco Sustainability Report, 2023). The quantification of methane emissions will be key to achieving the zero methane intensity target. The technologies used for that objective will be discussed in the next section.   

Monitoring & detection of methane. Several technologies exist for the detection and monitoring of methane, such as Optical Gas Imaging (OGI) cameras, handheld devices, remote sensing, satellite images, laser-based sensors, analytics, and predictive tools, Fig. 5.  

In general, the methods can be classified as remote sensing and localized sensing. Remote sensors (such as: satellite images, aerial and road surveys) take longer to execute, and they have lower detection limits. They also have lower accuracy in determining the exact location of the methane source. On the other hand, handheld devices and OGI techniques can provide more accurate measurements and a faster method of leak detection and quantification. However, they are labor-intensive and might incur personnel risks.  

Fig. 5. Methane detection and monitoring technologies.

Thus, to combat these limitations, drones are utilized in hard-to-reach locations within surface facilities. Singh (2023) reported a comprehensive review of these methods. Presley (2023) reported a review of many efforts to reduce methane by several oilfield operators. The paper shows the Leak Detection and Repair (LDAR) program technologies that are being used. A recent report by OGCI (2023) highlighted the use of satellite images to monitor methane emissions in Iraq.  

The method can be used to guide operators on flaring, unnecessary venting, unknown leaks or even scheduling maintenance events. The study included several producing sites that were emitting methane as high as 1.4 tons/hour. However, the method’s lower detection limit was at around 0.07 tons/hour. The main limiting factor of this method is the presence of cloud or dust, which affects the quality of the images, and hence, the methane prediction accuracy. Recently launched satellites can provide a resolution of 0.025 by 0.025 km, with detection limits at 0.1 ton/hour (Schuit et al. 2023; Singh 2023).  

Another way to measure methane emissions is through development of laser spectrometers at the surface for accessible sites. These stationary optical sensors can predict lower emission rates up to 5 kg/hr. Similar to satellite images, this method might be affected by the sensors’ location and weather conditions. The reported methane emissions intensity is already low by the OGCI members. Another demonstration of technology bringing the needed NZE to closer reality.  

Flaring is the intentional process of burning natural gas for safety reasons or for operational needs. In addition to CO₂, the combustion of natural gas (mainly methane), can produce other pollutants, such as black soot, sulfur oxide and unburned fuel. Historical data show that the amount of flared gas was as high as 4.6% of natural gas needs in 2008 (Johnson and Coderre 2012).  

To have a sense of the CO₂ volumes produced as a result of flaring, it is estimated that a volume of around 54 Mtons of CO₂ is emitted as a result of flaring 1 billion standard cubic feet (bcf) of natural gas. In 2022, around 250 Mtons of CO₂ were emitted as a result of gas flaring. Interestingly, this amount is the same as in 2010. The U.S. Department of Energy (DOE) estimates 30 Mtons of CO₂ a year are the result of flaring in the U.S. To reduce flaring for operational needs, natural gas can be re-routed for other uses, such as conversion into other products, recycling or storage underground.   

The conversion of natural gas into other products is one useful method. Examples include conversion into liquids that are easily transported, such as methanol, ethanol or acetic acid. Another example is the use of methane to produce carbon-based high-value products, such as carbon nanotubes and graphene sheets (National Academy of Sciences, Engineering and Medicine 2019). Although this is still in the early R&D phase, some concepts have shown promising results.  

One concept was to use the gas with high C2+ content that would be flared. This gas is not used to generate power using gas turbines, due to its composition. However, it can be used to produce hydrogen. Its advantage is the low temperature requirements of around 300^oC compared to the Steam Methane Reforming (SMR) process, which requires heating up to 800^oC. Although the process still produces CO₂ (Snytnikov and Potemkin 2022), it is an improvement, bringing the upstream one step closer to NZE.  

Fig. 6. Major gas storage projects globally.

Underground Gas Storage is a concept that can reduce flaring, as it provides an underground site for excess gas to be stored for future demand (Soroush and Alizadeh 2008). Figure 6 provides an overview of the number of gas storage facilities across different regions globally. Other operational practices that can reduce flaring (especially in unconventional resources applications), is the re-injection of methane in unconventional reservoirs during production operations (Tang et al. 2023). In addition, during hydraulic fracturing operations, the use of portable separators to send gas to generators or storage is reported as a mean of reducing flaring (Singh 2023). 

In summary, the reduction of methane emissions in the upstream by the OGCI companies has been proceeding at a fast pace, and it is close to the near-zero emissions 2030 target. It must be noted that the OGCI group includes a limited number of companies; the rest of the industry would have to do more for methane reduction. The reduction of methane flaring is still an area of opportunity, whereby the CO₂ from flaring is captured or the heat at the flaring point is used to convert methane into other products. The use of methane to produce hydrogen will be discussed in the hydrogen section of Part 2 of this article in next month’s issue. 

Editor’s note: This is Part 1 of a two-part article. Part 2 will appear in our April issue. 

REFERENCES: Part 1 

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• Gargett, P., Hall, S. and Kar, J. (2019) Toward a net-zero future: Decarbonizing upstream oil and Gas Operations, McKinsey & Company. Available at: https://www.mckinsey.com/industries/oil-and-gas/our-insights/toward-a-net-zero-future-decarbonizing-upstream-oil-and-gas-operations (Accessed: 16 December 2024). 
• International Energy Agency (IEA), 2023a. Emissions from Oil and Gas Operations in Net Zero Transitions. A World Energy Outlook Special Report on the Oil and Gas Industry and COP28, June 2023. 
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• Presley, Jennifer, 2023. Innovative Thinking Drives Emissions Mitigation." J Pet Technol 75 (2023): 16–21. doi: https://doi.org/10.2118/0823-0016-JPT
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DR. GHAITHAN A. AL-MUNTASHERI is the Director of the EXPEC Advanced Research Center (EXPEC ARC) at Saudi Aramco in Dhahran, Saudi Arabia, overseeing Aramco’s Upstream Research and the Saudi Aramco Upstream Technology Company with global R&D activities across nine Aramco Global Research Centers. He previously served as R&D Director for Aramco Americas in Houston, Texas, and has held various leadership roles within Saudi Aramco over his 23-year career including the Chief Technologist of Production Technology Team under EXPEC ARC. Dr. Al-Muntasheri has authored/co-authored one book chapter, over 100 peer-reviewed papers, and holds more than 42 U.S. patents. He is a globally recognized expert, having served as the Chairman of the SPE Saudi Arabia Section (SPE SAS) for the term 2011/2012 and received over 15 awards, including the 2022 SPE Distinguished Service Award and the 2018 SPE Distinguished Membership Award. He has also been named among the Top 2% of scientists worldwide in a Stanford study. Dr. Al-Muntasheri holds a BS and MS in Chemical Engineering from King Fahd University of Petroleum & Minerals and a PhD in Petroleum Engineering from Delft University of Technology. He has also served as an Adjunct Associate Professor at Rice University.