This article provides a vision of upstream operations in a Net Zero emissions (NZE) future and reviews state-of-the-art technologies and future concepts that will enable the NZE scenario for the upstream sector.
GHAITHAN A. AL-MUNTASHERI, Saudi Aramco
Last month, Part 1 of this article laid out the case for how the global upstream industry could transition to Net Zero operations, with technology leading the way. This month, Part 2 offers specific details on strategies and opportunities to implement such a transition.
DECARBONIZATION STRATEGIES AND OPPORTUNITIES FOR CO2 REDUCTION
Electrification of the full upstream cycle: Exploration, drilling, completion and production. Several upstream processes require diesel-intensive generators, from exploration to production. In this section, we will review potential methods that can be used to electrify these carbon-intensive operations.
Starting with exploration, the seismic acquisition process requires driving many heavy vehicles to acquire the data. The trucks operating on diesel emit carbon dioxide and other gases. Plus, there are the long cables needed to cover large areas for seismic acquisition. Thus, it is appealing to bring a new airborne method that can acquire the data efficiently. Yashin et al. (2022) reported the first large-scale use of an Autonomous Seismic Acquisition Device (ASAD) for acquiring seismic. The unmanned aerial vehicle (UAV) is equipped with seismic sensors that can reach difficult locations, eliminate the use of cables, and introduce major efficiencies.
Power used at the wellsite during various operations can present another area of emission reduction. The use of electric-driven pumps and compressors for many activities, such as drilling, stimulation, enhanced oil recovery (EOR) and gas compression, can enable that.
Power consumption at the wellsite differs from one upstream operation to another. Drilling and hydraulic fracturing are among the top energy consumers. Artificial lift and EOR come next in power consumption (Smith and Rao 2023). Currently, many drilling rigs are operated on power sourced from the grid, but most are running on power that is generated onsite using diesel generators. A typical rig would consume around 3,300 gal of LNG or 2,300 gal of diesel (McEvers and Kent 2015).
Diesel will need to be trucked in, let alone its emissions footprint. In fact, burning diesel results in combustion products like CO, NOx and particulate matter. Most calculations for carbon emissions during drilling are based on the volume of fuel (such as diesel), and that amount is converted into equivalent carbon emissions (Allen 2022). For example, burning 2,300 gal of diesel produces around 22.9 tons of CO2.
Natural gas, if available at the wellhead, can be used to provide power for the operation. Mobile gas turbines have been reported to produce power as high as 40 MW. The power will be a function of the temperature at the operational site. Higher temperatures will reduce the maximum power output. These units replace the diesel-based generators used at wellsites. When it comes to fuel cost, it is estimated that natural gas costs $1/gal equivalent, which is less than diesel. Krieger et al. (2002) reported drilling the first well in the Arctic with a rig that operated purely on natural gas. It is worth mentioning that gas turbines can produce electricity and heat. The heat is utilized to produce steam, thus avoiding more emissions that could result from burning gas to generate steam alone. This was reported to reduce the global gas turbine emission factor by 46% (Dumoulin 2023).
Although electrification using renewable sources, such as solar, wind, and sea waves can present a unique opportunity for offshore applications, challenges associated with power storage would still need to be addressed. Meteorological conditions will have a major impact on the efficiency of these sources. Florio et al. (2023) discussed how Pumped Storage Hydropower (PSH) represents a proven power storage means. Power storage using batteries for these power-consuming applications is still another opportunity for upstream NZE. There is no one size that fits all; a careful cone sideration of every asset is needed.
For example, Nassar et al. (2023) showed that using a mixture of natural gas, wind, wave and floating solar panel can reduce emissions, but the cost can increase significantly. The case study included an offshore asset in the North Sea. This is an area of research that can add a lot of value to the future Upstream NZE. It must be noted that electrification alone, without looking at the source of power, will not be useful if the source of electric power is a high-carbon-intensity fuel.
Hydrogen as a future fuel. About three-quarters of global hydrogen production comes from natural gas (Gillick and Babaei 2024). Most of it is produced without CCUS. The year 2022 had a total of 95 MMt of hydrogen production (IEA 2023b), with most of it being utilized by the ammonia, methanol and steel production industries. Scientific literature predicts the growth of the hydrogen market to reach around 530 MMta by 2050 (Nnabuife et al. 2023). This is 5.6 times the production figure of 2025. Interestingly, 54% of total hydrogen production will come from gray and blue sources. Thus, it is a major opportunity for upstream oil and gas operations to use this window in various aspects.
Why hydrogen? Hydrogen has unique physical and chemical properties. It has the highest heating value, compared to natural gas and gasoline. Thus, per unit of mass, hydrogen can produce around 2.2 to 2.7 times the energy produced by natural gas and gasoline, respectively. Table 1 lists the differences between hydrogen and common hydrocarbon-based fuels. Another important aspect for hydrogen is its clean combustion route, as it reacts with oxygen, producing energy and water. In fact, the use of 60% hydrogen as a component in the natural gas mixture to generate power from gas turbines will reduce the CO2 emissions by 30% (Prasad 2020). Hydrogen is also considered to be non-toxic. However, issues associated with its volume, density and flammability remain as challenges, preventing its wide utilization as a fuel.
Hydrogen can exist in the subsurface with high purity. This is referred to as gold or white hydrogen. Boschee (2023) reported on the various discoveries of hydrogen-producing fields. These included: the 1987 discovery in Mali, where hydrogen was produced to supply power for the local community, and 24 wells were drilled with a hydrogen purity of 98%. Similar hydrogen exploration efforts led to discoveries of gold hydrogen in the U.S., France, Australia and Oman.
A study by Milkov (2022) has looked into thousands of gas samples, where hydrogen existed at a concentration of around 3.5%. To make use of this resource, many challenges will need to be addressed in the area of exploration, logging, well testing and building infrastructure. Strapoc et al. (2022) reported on the challenges of logging wells for hydrogen. The paper showed that hydrogen can also be a byproduct of the reaction between certain mud additives. Previous literature has reported detection of hydrogen as a result of excessive heat produced while drilling. This is the result of drill bit metamorphism (DBM), and mud motor failures can show hydrogen presence while drilling (Keller and Rowe 2017). It should also be mentioned that hydrogen can be present as a component of gas well streams.
Another potential source of hydrogen in the upstream oil and gas industry is the decomposition of hydrogen sulfide gas (H2S) into hydrogen and sulfur. The benefits of this source can be two-fold, as it eliminates the toxic hydrogen sulfide and at the same time produces hydrogen. Lab-based research showed many routes for this to take place. However, the large-scale applications are yet to be efficient.
Han et al. (2023) provided a detailed review of the available electrochemical methods with their technological limitations. For example, direct electrolysis of H2S can provide an energy-efficient route, yet the passivation of the solid sulfur at the anode can be a challenge that ceases the electrolysis process. The authors summarized many approaches that worked around the passivation issue including: use of a surfactant, the injection of a toluene and basic sulfide solution mixture into a continuous stirred tank electrochemical reactor (CSTER) design of a continuous reactor.
More recent work utilized the power of light at the ultraviolet region to excite chemical conversion of H2S into hydrogen. Several papers highlighted preliminary work in this area. The use of a high-power laser to produce hydrogen from H2S via photocatalysis reactions was reported (Khan et al. 2023). Although these are in the early stages of research, they present a promising technology in view of their ability to produce hydrogen at room temperature.
It is evident from literature that the most established technique for the generation of hydrogen is the use of natural gas. Such a route produces either gray or blue hydrogen, depending on the CO2 capture of the process. A typical Steam Methane Reforming (SMR) process can produce around 10 kg of CO2/kg of H2 generated (Incer-Valverde et al. 2023).
Hydrogen can be generated from many processes. Recent work showed the potential of producing hydrogen from methane via pyrolysis. The process generates hydrogen and carbon black as a byproduct (sold at around $1.5 to $2.5/kg) (Stusch 2022). This carbon intensity can be reduced by altering the SMR process. Gillick and Babaei (2024) reported a new concept, whereby the wellbore is converted into a reactor to produce hydrogen from natural gas.
Green hydrogen is produced via electrochemical decomposition of water to its basic components: oxygen and hydrogen. However, in this case, the power is produced from renewable sources, such as solar and wind. The cost of producing this type of hydrogen is heavily dependent on the energy costs. Hence, it will vary from one place to another. To show the cost dimension, Table 2 summarizes data from various sources on the cost of producing hydrogen. Although the power plays a critical role, it is also expected that advances in electrolyzer technologies will bring overall green hydrogen costs down. It should be mentioned that 9 kg of water would be needed to produce one kg of hydrogen (Incer-Valverde 2023). This is going to be another obstacle for areas with no access to water.
One way to store hydrogen is the utilization of depleted gas reservoirs and saline aquifers (Delshad et al. (2023)). The exploration for underground hydrogen resources is another area of required development. These activities would require advancements in geomechanical models, hydrogen leakage detection, analysis of hydrogen and rock interaction in terms of adsorption. On the logistical side, corrosion, permeation of the hydrogen through the pipe material/joints, and safety are all critical parameters that need to be addressed (Rodgers et al. 2010). It is also known that the infrastructure of hydrogen pipelines is lacking, whereby only 5,000 km of hydrogen pipelines exist, compared to a 3,000,000-km network for natural gas (International Renewable Energy Agency (IRENA) 2021a).
In summary, hydrogen provides a potential valuable resource towards the transition to NZE. It can be used in power generation for various upstream operations. Blue and gray hydrogen will remain to be among the economically feasible hydrogen types. Naturally occurring hydrogen is still in the early stages of development to be a standalone fuel. Research in the area of hydrogen sulfide to hydrogen carries a lot of potential.
CARBON CAPTURE, UTILIZATION AND STORAGE (CCUS)
CCUS presents several approaches to capture, store and utilize CO2. In this approach, stationary sources of CO2 are utilized. Sources of CO2 include oil refineries, gas processing plants, steel industries, cement factories, power plants and chemical plants. The purity of produced CO2 varies. Generally, CO2 with more than 40% purity can be obtained from petrochemical plants and certain natural gas processing facilities.
The collected CO2 can be used for CCUS purposes in different ways. First, CO2 can be injected into petroleum reservoirs for EOR purposes. It also can be injected into saline aquifers. In such a case, CO2 reacts with the divalent cation (calcium) present in the water to form carbonate-based salts. Another storage mechanism is the utilization of depleted gas reservoirs to permanently store CO2.
For geologic sequestration applications, in which the CO2 is stored underground, there are three main cost components: capture, transportation, and storage (which encompasses injection and monitoring). The cost of capture is typically several times greater than the cost of both transport and storage. In fact, Orr (2018) estimates this to be around 60% to 85% of the total sequestration cost. The cost of capturing carbon from stationary sources varies from one industry to another. Table 3 gives a summary of ranges reported by the IEA. As an example of the technology impact on the cost reduction, the Boundary Dam plant (coal-fired plant) built in 2014 used to cost around $110 to capture one ton of CO2. In 2017, the cost dropped to $65 at the Petra Nova project.
CCUS has long been practiced in our industry. For example, Snohvit and Sleipner are in operation for decades (whereby CO2 is injected into saline sandstone formations). In fact, currently, there are 30 active CCUS projects in the world, with 19 projects in North America and the remaining 11 distributed in the rest of the world (Ismail and Gaganis 2023). Figure 7 shows the amount of operational CO2 capture capacity across the announced projects globally.
Gorgon CCS in Australia is one of the upcoming large projects capturing CO2 from LNG plants. It is expected to store up to 4 MMt of CO2 upon operation at full capacity. Aramco has announced the Jubail Carbon Capture Hub, which will have a capacity of 9 MMt of CO2. This will be the largest capacity for a single project in the world. The project demonstrates a new concept, whereby CO2 is captured from multiple CO2 industrial sources. This is thought to bring cost-effectiveness to the sequestration process.
In fact, the company announced that 3 MMt of CO2 will come from other industrial emitters other than oil and gas processing facilities. Capturing CO2 from stationary sources necessitates the construction of pipelines that could be long and costly, especially if the injection sinks are far.
Depleted gas reservoirs can benefit from Direct Air Capture (DAC). The process refers to the removal of CO2 by capturing it from the atmosphere. The technologies available for DAC are still on the expensive side. Literature reported around $600-to-$1,000/ton (World Economic Forum 2023). Although DAC has been reported for more surface applications, the option of using DAC in upstream offshore facilities in depleted reservoirs can be another opportunity, if the platform is close to the CO2 injection site, thus avoiding the transportation of CO2.
The CCUS in the subsurface reservoirs has the advantage of large-volume capacity. For example, the Gulf Council Countries (GCC) have the potential of storing one full year of global CO2 emissions in their depleted reservoirs (Gaffney Cline 2022). CCUS is a capital-intensive sequestration option. The IEA data suggest that the world would need 1.25 Gt of CO2 CCUS capacity to achieve the Net-Zero target by the year 2030. As of now, the CCUS projects around the globe can only handle 45 MtCO2. Also, only an extra 16 MtCO2 capacity is under actual construction in 2023 (Global Status of CCS 2023).
Unfortunately, more investments are needed to develop additional storage projects. In fact, it is estimated that the potential storage capacity of CCUS projects under all stages, including early development, can reach around 360 MMt of CO2 which is still less than 25% of the required capacity for a net-zero scenario (Global Status of CCS 2023). CCUS will be useful in projects with EOR objectives. In such a case, extra oil is recovered, and a significant portion of the injected CO2 is stored. However, in the case of saline aquifers and depleted gas reservoirs, the economics will be different. Therefore, another challenge with subsurface CCUS is the critical need for supporting governmental policies to ensure economic viability of this method.
Carbon taxing is pivotal in facilitating the implementation and economic viability of CCUS projects. Recently, the U.S. government announced an increase in the 45Q Tax Credit from $50 to $85 per ton of CO2 sequestered (The White House 2023). The 45Q Tax Credit is a federal incentive designed to promote the capture and storage of carbon dioxide by providing a financial reward for each ton of CO2 permanently stored underground or used in enhanced oil recovery (IEA 2023). This tax credit encourages gas-fired power plants, cement, steel, hydrogen, and petrochemical facilities to integrate CCUS technologies into their operations. Although the U.S. tax credit may not directly influence every company exploring CCUS, it plays a critical role in demonstrating the technology's commercial viability. By increasing financial incentives, the policy enhances the confidence of both developers and investors, thereby accelerating the adoption of CCUS.
In contrast, the UK government has committed up to £20 billion to establish a robust CCUS sector within the country (Department of Energy Security and Net Zero 2023). This substantial financial commitment underscores the importance of government support in the successful deployment of CCUS technologies. Comprehensive policies and significant investments are essential to create a competitive market for CCUS, ensuring these projects are sustainable and contribute effectively to the transition to a low-carbon economy. Overall, government initiatives, such as tax credits and direct investments, are instrumental in fostering the growth of CCUS. These measures not only incentivize industries to adopt innovative technologies but also provide the necessary financial backing to make such projects economically viable. Through these efforts, both the U.S. and UK governments are paving the way for a cleaner, more sustainable future by promoting the large-scale implementation of CCUS technologies.
CONVERSION OF CO2 INTO OTHER MATERIALS
The conversion of CO2 into other useful commercially viable materials is a promising NZE transition route. In the year 2020, research estimated that around 6% of the CO2 emitted worldwide is diverted towards chemicals and materials manufacturing (National Academy of Sciences, Engineering and Medicine 2019). Other literature estimates that 10% of the emitted CO2 can be used with most of it in producing CO2-based fuels (Chauvy and De Weireld 2020).
The EIA predicts that utilization of CO2 in producing fuels and chemicals will increase by a factor of 7 by 2060, to reach around 870 MMt of CO2. Accordingly, it is expected that the market for CO2 utilization will be around $800 billion by the year 2030 (National Academy of Sciences, Engineering and Medicine, 2019). Although this is still not sufficient to be the primary decarbonizing route, the use of CO2 conversion on the surface is receiving attention within the scientific community with many concepts. The amount of basic research in this domain is indicative of the promising potential. It is not too optimistic to state that the future will bring many of these into realities.
To utilize this approach, it is necessary to have an understanding of the current CO2 emission volumes and purity levels from the various industrial processes. Figure 8 shows U.S. data, as extracted from the report by the National Academy of Sciences, Engineering and Medicine, 2019. Some of the data were also extracted from other references cited from EPA. The figure shows that the highest purity CO2 is associated with ammonia production.
On the other hand, CO2 associated with energy production represents large CO2 volumes, but the purity is low. The hydrogenation of CO2 into useful chemicals, such as methanol, ethanol and formic acid, has been reported as a potential profit-generating route for CO2 conversion. The existing processes for CH4 and CO2 utilization, requiring the generation of syngas (CO2, CO and H2) by dry reforming at high temperatures (> 700°C), followed by converting syngas into methanol at high pressures, are energy-intensive. The following equations show chemical reactions involved (Dalena et al. 2018):
CH4 + H2O -> CO + 3H2 (1)
CH4 + 2O2 -> O2 + 2H2O (2)
CO + 2H2 -> H3OH (3)
The hydrogenation of CO2 to produce methanol received attention recently, which is shown in equation 4 below (Rodriguez et al. 2015; Chang et al. 2017; Dalena et al. 2018; Goeppert and Prakash 2022). This presents an option, as it consumes CO2 by using it as a feedstock. In such a two-step process, CO2 is reduced to CO via catalysis. Then, CO goes through a reduction reaction with hydrogen to produce methanol. The second approach is the direct hydrogenation of CO2. In the second case, the source of hydrogen will play a critical role. In some examples, the source of hydrogen is electrolysis of water or the oxidization of water. These are still expensive options.
CO2 + 3H2 -> H3OH + H2O (4)
As an illustrative example of economic feasibility, we use methanol, whose production was at 95 MMt in 2021 (IRENA report 2021b). About 65% of that comes from steam methane reforming, which is an energy intensive process. Figure 9 shows average cost data for various methanol types extracted from the same reference. The production costs of methanol from fossil fuels are in the order of $100 to $250 per Mt. This compares to around $550 to $750 per Mt for producing methanol from bio sources.
Methanol production cost goes even higher to around $1,300 per Mt for methanol produced from CO2 captured from DAC. These data clearly show that the production of methanol from fossil fuels is the most economic option, so far. Although mature production of methanol for some technologies, as well as tax credits, could bring the costs down, it is still considerably higher than production costs of methanol using fossil fuels.
The carbonation of CO2 is another conversion route. In this case, in addition to CO2, a source of metal is needed. CO2 is captured from point sources. Both barium and calcium metals were reported to be used in producing barium and calcium, carbonates, respectively. As an example, a power plant in China is producing 2,300 tonnes of calcium carbonate. The Guodian Electric Power plant uses CO2 in the flue gas from power generators and the calcium carbide waste to form calcium carbonate solid. Another commercial example is barium carbonate.
On the lab experimentation front, many approaches were reported in literature. We report a few examples that are summarized in Table 4. Kodama et al. (2008) reported the use of steelmaking slag as a source of calcium silicate. The study showed production of calcium carbonate upon reacting the slag with CO2 in the presence of ammonium chloride. Before the carbonation reaction producing calcium carbonate, the first step is the extraction of the metal from the slag. The overall process produced high-purity calcium carbonate with morphology being dependent on the reaction temperature. Zhang et al. (2019) produced the same precipitate by using brine as a source of calcium. This was done in a continuous reactor in the presence of a nickel catalyst.
Jang et al. (2024) utilized cement kiln dust, which was 62% by weight (wt) calcium and around 22 wt% silicon, and the balance was a mixture of other elements. The method involves multiple steps, including leaching of calcium, purification, recovery and carbonation. Yet, the reaction temperature was at 25oC. Zhang et al. (2020) provided a comprehensive review on the chemical reactions associated with mineralization of CO2 in the presence of metals while Ragipani et al. (2021) provided a review on the mineralization of CO2 using steel slag that cited more than 200 references. The main chemical reaction involved in the process is the reaction of the solid calcium oxide with CO2 below to produce solid calcium carbonate.
CaO + CO2 -> CaCO3 (5)
CO2-to-concrete is also another example of using CO2 to create valuable byproducts. Through a controlled reaction mechanism, CO2 is absorbed into a calcium-rich solution, prompting the formation of CaCO3 crystals. These crystals are then aggregated and processed into a variety of concrete products, including aggregates, cements, and supplementary cementitious materials.
MINING OF TRANSITION ELEMENTS FROM OILFIELD BRINES
It has been reported that the number of hybrid Electric Vehicles (EVs) increased by 50% between the years 2021 and 2022 (Krishnan and Gopan 2024). The growth in the manufacturing of EVs will eventually require more materials. For example, it is reported that EVs require three times more copper, compared to gasoline-powered vehicles (Jones et al. 2020). Similarly, the use of batteries in EVs will require more metals and materials such as cobalt, lithium, nickel, manganese and graphite. In fact, studies report that cobalt demand has increased by almost a factor of 2 between the years 2018 and 2021. Moreover, half of the cobalt demand today is consumed in battery manufacturing (Shojaeddini et. 2024).
Lithium carbonate has also witnessed an increase in demand, whereby its price increased by a factor of 5 in 2021 (Zhang et al. 2024; Yang et al. 2021). In fact, since 2013, it is estimated that lithium carbonate production increased from 65,000 to around 200,000 in 2021 (Wojewska et al. 2024). In the long term, by the year 2050, the demand for lithium and energy transition metals is expected to grow by a factor of 1.5 to 4 in various parts of the world, compared to the year 2020 (BNEF 2024b).
Figure 10 shows the expected growth in demand for lithium and nickel metals (IEA 2022b). It is worth noting that most of the production of transition metals is coming from Brazil, Chile and China. Figure 11 shows the distribution of commercial lithium carbonate production in the year 2021 by producing country. The data were extracted from Wojewska et al. (2024). Although the year 2021 had only three countries producing major quantities of lithium oxide (LiO2) production, other years have recorded other producing countries, such as Chile, Australia, China, Argentina, Russia and the U.S. (Chandrasekharam et al. 2024).
Oilfield brines present another opportunity for lithium extraction, as highlighted in many recent studies across the globe (Rassenfoss 2023; Jakaria et al. 2024; Disu et al. 2023). Research in this area is increasing over the past several years. In general, the lower the Mg+2/L+ ratio, the higher the efficiency of lithium extraction from the brine and the more cost-effective the process becomes (Mackey et al. 2024). Methods to extract the lithium transition metal from these water solutions include electrodialysis with membranes, nanofiltration with membranes, and adsorbent systems. In membranes, a difference in electrical potential or pressure can lead to the lithium extraction. For adsorbents, they are made out of materials that have affinity to lithium. Thus, lithium adsorbs on their surfaces, and then a solvent is run through the column packed with the resin to desorb lithium, which is usually in the form of lithium chloride. Vera et al. (2023) reports a detailed description of the processes involved.
In brines having lithium concentration above 500 ppm, solar ponds can be used to evaporate the water and leave lithium concentrated. Such ponds represent what is referred to as continental brine deposits. Then, lithium is produced by adding chemical compounds to precipitate lithium carbonate or lithium chloride (Krishnan and Gopan 2024). Lithium is then extracted after processing the solids further. However, this process takes up to one year, can create large footprint, and may cause soil pollution (Zhang et al. 2024; Vera et al. 2023; Kumar et al. 2019).
Improvements in the precipitation step using the solar evaporation process included the use of phosphate compounds instead of carbonate-based compounds. The reason is the solubility of the phosphate being lower, compared to lithium carbonate. Hence, accelerating the precipitation reaction (Chen et al. 2017; Kumar et al. 2019). This method has been scaled up in many operating facilities that are actively extracting lithium from brines (Vera et al. 2023; Flexer et al. 2018). The method produces waste that has been questionable in terms of impact on the environment.
In order to address these limitations with the evaporation ponds methods, Direct Lithium Extraction (DLE) technologies were introduced. In this approach, packed columns containing ion exchange resins represent a second class of lithium extraction technologies. Metal oxides can be packed in columns for that purpose. However, their processing time takes longer, compared to other materials (Kumar et al. 2019). The challenge with this technology is the selectivity towards lithium, since other metals are present in the produced water at higher concentrations. Aluminum-loaded resins and solvent-impregnated resins were reported to be more selective towards lithium recovery (Kumar et al. 2019; Burda et al. 1984). Other metal types were also reported earlier and were summarized by Kumar et al. (2019).
Lithium concentration in the brine is critical to the economics of the process. Produced water from the Marcellus shale was reported to have around 200 ppm of Li (Mackey et al. 2024). Formation brines in Arkansas were reported to have as high as 400 ppm of lithium (Knierim et al. 2024). For produced water with low lithium concentration, pre-treatment steps to concentrate the treated water were reported to produce 60 ppm of lithium from a much lower concentration of lithium-containing feed (Alshammari et al. 2024). In summary, at lower concentrations of lithium, technologies are yet to be successfully tested.
CONCLUSIONS
Opportunities to balance economic growth with environmental protection can sustain upstream oil and gas operations. These yield to the NZE transition, where the balance is met. The paper from which this article is derived highlighted several fronts for technology gaps in various applications. The following conclusions can be made:
Addressing upstream oil and gas emissions will result in avoiding CO2 equivalent to 70% in one year by all vehicles on the planet.
Methane emissions by OGCI companies are making significant progress towards the near-zero target by 2030.
Conversion of CO2 into useful products can present a major opportunity for researchers to pursue
The use of hydrogen to power upstream assets/operations represents a new window of opportunity
Mining of transition metals from produced water can significantly increase value, once the right technologies are developed
Research is the key to bringing new cost-effective methods to sustain upstream oil and gas operations. WO
Editor’s note
This is Part 2 of a two-part article. Part 1 appeared in our March issue.
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DR. GHAITHAN A. AL-MUNTASHERI is 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 Chief Technologist of the 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 BS and MS degrees 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.