Decarbonizing strategies for the Upstream Oil and Natural Gas industry

1 The importance of Oil and Natural Gas

Oil and Natural Gas play an indispensable role in our lives, providing energy for transportation, heating, manufacturing, as well as feedstocks for the vast Petrochemical industry. Though only a few regions and countries produce Oil and Gas, the energy and products from this global industry impact the daily lives of people in every corner of the world. It would not be an exaggeration to say that the industrialized world would come to an absolute standstill if Oil and Natural Gas production were to cease.

IEA has estimated that in the year 2020, Oil and Natural Gas  provided 30% and 23% respectively, of global energy supplies. In this decade, Oil demand is projected to climb from pre-pandemic levels of 98 million barrels per day (mb/d) in 2019 to plateau at around 104 mb/d by year 2030. Natural gas demand which was 3900 billion Cubic metres (bcm) will climb to about 4600 in the year 2030 [1].

The approximate  sectoral demand pattern of Crude Oil and Natural Gas, globally, is indicated in Table 1 [2]:

In future, the demand from sectors such as power, transportation and buildings are projected to diminish as green energy supplies displace Crude Oil and Natural Gas. In the Industrial sector, particularly Petrochemicals, initiatives such as the direct Crude oil to Chemicals technology being pursued by Saudi Aramco [3], indicate that in the future, Crude Oil is being viewed as a feedstock rather than a fuel. This is understandable, since Electric vehicles and Hydrogen power represent the future vision of land transportation. Even in the Hydrogen economy, Natural Gas will be a major raw material for Blue Hydrogen production through SMR /ATR technologies. It will be many years before Green Hydrogen can match the cost and scale of  Blue Hydrogen. It is expected therefore that Crude Oil and Natural Gas will continue to be important global energy and feedstock sources  for several decades to come.

2 Decarbonization of the Oil and Natural Gas Industry

Given the urgency of addressing climate change and the global consensus on achieving Net Zero emissions of Carbon Dioxide by 2050, the Oil and Natural gas industry will risk losing its license to operate, unless it makes progress on decarbonization . This is the minimum that investors, societal stakeholders, and regulatory authorities expect. Additionally, punitive taxes on Carbon emissions could make it an existential issue for the industry.

Decarbonization is therefore recognized as a necessity for the Oil and Natural Gas industry. The upside for the sector lies in recognizing the opportunity here, given the scale and resources available to this industry. The Oil and Gas sector has the capability to lead the way in decarbonization and set the benchmark for a sustainable energy future for the world. Many of the leading National Oil Companies especially in the  OPEC grouping have already set in motion their plans to decarbonize operations, to achieve competitive advantage on sustainability parameters, in addition to low cost of production. Figure 1 illustrates the decarbonization transition planning of selected NOCs including the OPEC leaders [4].

The measurement of Carbon footprints as per agreed protocols is fundamental to any structured decarbonization programme. Most Carbon footprint estimation protocols, such as those by World Resources Institute(WRI) or Business Council for Sustainable Development (WBCSD), define Carbon footprint inventories in increasingly bigger scopes or “Tiers”. The “Tier-1” definition consists of the direct emissions of the organization itself (e.g., the Carbon Dioxide emissions coming out of a firm’s factories and vehicles). “Tier-2” expands the boundary to include the Carbon emissions of energy inputs used by the organization. This is significant, given that the energy sector is a leading source of GHG emissions. Organizations can meet Tier-2 obligations for example, by purchasing renewable power, rather than fossil-fuel based power.

Carbon Dioxide and Methane constitute the  primary Carbon emissions of  concern from the Upstream Oil and Natural Gas industry. This is attributed to their high Global warming potential and abundance, relative to the other Greenhouse gases.

In the following sections of this article, we examine sources of Carbon emissions in the Upstream Oil and Natural Gas industry and review  various decarbonization opportunities that are available for implementation. The focus of this article is on Tier-1 emissions.

3 Carbon Emissions of Upstream Oil and Natural Gas Operations

Upstream operations in the Oil and Natural gas industry comprise Exploration (which is mainly drilling, Well construction and testing), and  Production operations, spanning Well operations, intra-field gathering, transport and processing operations. Exploration and Production are different in the nature of their operations and equipment. There are also significant differences between Onshore and Offshore sectors, in terms of resources deployed as well as operating methodologies and technologies involved. Hence there are differences in the emission patterns of Onshore and Offshore operations. The Tier-1 emission sources of Methane and Carbon Dioxide emanating from Upstream Exploration and from Production operations are discussed separately, as follows:

3.1 Emissions from Upstream Exploration

Drilling and Well Construction: Drilling emissions are estimated to contribute 10% of all Exploration and Production related emissions [5]. Exhausts from large horsepower internal combustion engines or electrical generator sets running either on Diesel or Natural gas ,which are used in these operations. constitute a major source of CO2 emissions.

Well Completion Gas Venting: These emissions occur when Natural Gas is vented before a Well is brought into production. in the case of production after reservoir fracking, the Gas is entrained with the flowback fluids and is vented out from the top of flowback tanks. Figure 2 illustrates a typical Natural Gas cold venting operation.

Well Testing Flares: Gases from Well testing operations during the Exploration phase are combusted in temporary local flares. Though flaring is better than cold venting, it is a major source of Carbon Dioxide emissions.

Drilling Fluid Emissions: Drilling Mud  is circulated through the drill-bit into the well bore, to cool the drill bit, flush out  drill cuttings, and maintain wellbore pressure. The Drilling Mud absorbs or entrains gases which migrate through the reservoir pores into the well bore. Hence the Mud needs to be degassed at the surface of the rig, before being recirculated. This ensures that the correct mud density is maintained and prevents cavitation problems in Mud pumps. Mud degassers are special gas separation devices on the rig. Separated gas is generally cold vented, since quantities are small. In some cases, the gases may be routed to a common flare if available at the rig. Cold vents are sources of Methane, whereas flare emissions add Carbon Dioxide to the Carbon footprint.

Fugitive Emissions: Escaping Hydrocarbon emissions from sources such as leaking flanges, connectors, valves and pump or compressor seals are termed fugitive emissions. The GHG component of concern is primarily Methane. This may happen during operation or during rig disassembly after completion of drilling work.

Vehicular Transport Emissions: Heavy Rig trucks and other vehicles transporting equipment, manpower, supplies travelling to and from the drilling site utilise Diesel fuel and contribute to the Tier-1 Carbon Dioxide footprint.

Construction Machinery Emissions: Onshore Well drilling also involves construction of civil infrastructure and deployment of heavy Diesel engine driven construction machinery in the Well pad and surrounding areas. Emission from all these engines constitute Tier-1 emissions associated with Onshore drilling. As indicated earlier, Offshore and Onshore Exploration operations involve different kinds of drilling equipment. Offshore drilling is conducted from jack-up rigs, semi-submersibles and other drillship arrangements which are huge when compared to the land rigs used in Onshore drilling.

Figures 4 and 5 provide a perspective on typical sources of emission during offshore and onshore exploration operations respectively [6].

3.2 Emissions from Upstream Production

Once a Well has been constructed, tested, and brought into production, all the operations downstream of the Wellhead Choke are in the domain of  Upstream Production operations. The scope comprises flowlines, headers to various gathering and processing stations  and injection back into subsurface for pressure maintenance  or for artificial lift. The performance of each Well is monitored and controlled to manage field production. In the case of Offshore production, the Wells may be located on wellhead platforms connected by  headers to production platforms. In deeper waters the Wells may be subsea, tied back to processing platforms or floating production storage and offloading ships (FPSO). In some cases, especially in the case of high-pressure gas Wells in deep-water, the subsea Wells may be tied back to an Onshore processing station.

The  common sources of Methane  and Carbon Dioxide emissions in Production operations are as follows:

• Engine driven artificial Lift pumps: In cases where the bottom hole pressure is insufficient to permit continuous flow, artificial lift is used. The artificial lift could be provided by beam pumps or downhole pumps depending on the type of Crude Oil. In the absence of centralized electrical infrastructure, it is economical to drive the  pumps by internal combustion engines using either Crude Oil or associated Gas from the well. Engine exhausts are sources of Carbon Dioxide.
• Engine driven fluid moving machinery: Examples are Pumps and Compressors. The engines could be Diesel engines or Gas turbines.
• Fired heaters: These include Heater Treaters, Steam Boilers, Line Heaters, Crude Oil Heaters. These are used for various processing functions such as Demulsification, Steam injection and Hydrate prevention. Exhaust gases from the fire-tube of these equipment are sources of Carbon Dioxide.
• Glycol and Solvent Regenerator vents: Gas processing plants utilize Glycols for Dehydration and various solvents like Amines for Acid Gas removal. The term Acid gas refers to Carbon Dioxide and Hydrogen Sulphide. Regeneration of these solvents consumes a lot of thermal energy, in the regenerator reboilers. In case of fire-tube reboilers the exhaust gases contain Carbon Dioxide from combustion, while Acid gases are released to atmosphere from the regenerator vent. In installations that use Steam heated reboilers, the combustion exhaust gases containing Carbon Dioxide are emitted from the Steam Boiler stack.
• Vents from storage tanks: These include Well pad tank batteries used in smaller production installations, as well as large Surge and Dehydration tanks or storage tanks in large production stations.
• Associated Gas flaring : Many operators find it uneconomical to collect small volumes of associated Gas produced along with Crude Oil. In such cases the produced Gas is flared. This is a major concern that the industry needs to address as it is a waste of energy and significantly adds to the Carbon burden.
• Production Station Flares: All equipment with volatile Hydrocarbon inventories must be connected to  flare systems to ensure that vapor is released in case of emergencies, to protect against over-pressurization and loss of containment scenarios. These flare  systems are also used during maintenance operations. Such operational situations are unavoidable but infrequent. Routine flaring however, is a major contributor to the Carbon footprint.
  
• Pigging operations: Opening Launchers and Receivers including venting and draining the contents, leads to emissions of Hydrocarbon vapors, including Methane. However, these are not significant sources of GHG emissions.

4 Emission reduction strategies

4.1 Strategies for Upstream Drilling Operations

4.1.1 Low emissions engines

Both Diesel and Natural gas-powered engines of high horsepower must comply with stringent emission limits imposed by regulatory requirements. In the USA, the EPA has specified emission limits for non-road diesel engines which are intended to mitigate the GHG emissions from this source. Therefore, cleaner Diesel and better engines are one way of mitigating Carbon Dioxide and other GHG emissions from Diesel engine exhaust. In general, wherever possible, use of Natural gas fuelled engines is better than using Diesel.

4.1.2 Reduced-Emission Well Completions

Green Completions are a way to mitigate GHG emission from Well completion or after workover. In this technique flowback that would normally be vented is instead routed through  a separation and collection system, avoiding direct release of Well fluids to the atmosphere

Figure 8 illustrates the concept of reduced emission (green) completions. In this illustration, Oil and  Gas  are separated at the wellhead. The produced Oil and Gas are connected to respective flowlines, while Water may be reused for injection or fracking. Sand is disposed of with other solids generated during drilling.

4.1.3 Hybrid Power Systems

Drilling operations, both Onshore and Offshore are characterised by high peak loads at certain times. The concept of hybrid power systems involves storing excess energy that is generated during low load operations, in large batteries. Whenever there is an increase in operating power demand beyond the capacity of running generators, stored energy from the batteries fills the gap. This hybrid arrangement enables the drilling operation to function with fewer generators running at higher load factor and efficiencies. Maersk and Transocean are examples of two major offshore drilling players who are pioneering this concept in their Offshore drilling rigs. Offshore operations have the additional advantage that wind energy can be tapped more efficiently, and this may in future be an additional green input into the hybrid system.

4.1.4 Algorithmic Optimization of Energy Usage

This approach employs real-time monitoring of energy used by various drilling operations, in conjunction with emission efficiency software to optimize energy consumption. For example,  if engines are running idle and can be safely switch off till they are required again, the software provides the necessary input.

4.2 Strategies for Upstream Production Operations

4.2.1 Reduced Flaring

Natural gas flaring  has been recognized as a major cause of Carbon Dioxide emissions for many decades. Most global Oil majors had initiated so-called zero flaring philosophies many decades ago. Globally however, flaring of associated as continues to be a major problem. The IEA has estimated that in the year 2019, around 150 billion cubic metres (bcm) of Natural Gas was flared globally, which is an astonishing 16 percent of the 935 bcm of associated Gas that was produced during the same period. Interestingly an additional 55 bcm of Methane was also released directly to the atmosphere by venting. If this were diverted to flares, the flared quantity would be much higher. The global data collected by IEA on flaring and venting of Natural Gas are largely derived from satellite data and hence provide a realistic picture [8].

It is possible to reduce routine Gas flaring by modifying plant designs, operating procedures, and finding ways to utilise stranded Gas supplies productively. It is sobering to note that as per  the IEA, some 54% of all volumes flared in 2019 took place at sites that were less than 20 km from existing Natural gas pipelines (and at least 87% of these flares were located onshore). Clearly, in an energy starved world, this situation needs correction and the decarbonization impetus within the Oil and Natural Gas industry provides a great opportunity to rectify the situation.

4.2.2 Tank Vent Gas Recovery

Oil production operations typically utilize large low-pressure tanks for various processing and storage functions. Examples are Surge tanks, Free Water Knockout (FWKO) tanks, Dehydration tanks, and storage tanks for Crude oil and Condensates. In some smaller production operations, it is common to use tank batteries to store the Crude Oil at the Well  pad. Hydrocarbon vapors are vented  from the vapor spaces of these tanks when the tank is being filled or due to thermal expansion. In large facilities, these vents are routed to a flare system. However, by installing a Vent Gas recovery compressor system, routine disposal to flare can be avoided. Instead, the recovered Vent Gas can be combined with Sales Gas, or utilised as Fuel Gas within the production facility.

4.2.3 Energy Conservation

Upstream operators have traditionally not been as energy conscious as their downstream counterparts. Indiscriminate  wastage of energy in the form of venting  and routine flaring has already been discussed. Additionally, equipment designs usually have significant design margins, dictated partly by the uncertainty of production forecasts and also because reservoir and Well performance will change during the lifetime of a producing field. This built-in overcapacity leads to equipment such as Pumps and Compressors operating well below their best efficiency points. Similarly, opportunities for  heat integration and waste heat recovery are not utilized probably  due to availability of cheap energy, right at the production source. From the viewpoint of decarbonization, the industry definitely has plenty of opportunities to improve energy conservation practices. The availability of hardware and software to monitor energy consumptions on real-time basis at the level of individual equipment has made it  practical and convenient for operating companies to optimize this aspect of their operations.

4.2.4 Electrification

Shifting to electrically driven equipment instead of Diesel engines or Gas Turbine drives, will reduce Tier-1 emissions. This is possible only if power supplies are available from  centralized sources and a robust high voltage transmission grid is available. In some of the smaller Oil producing countries the Onshore power grid network is geared to provide reliable electricity to Oil and Gas production operations countrywide.

With regard to Offshore production operations, due to distances from shore, it is not always possible to provide centralized electric power supply. It  is worth noting however, that Norway which has an excellent onshore power grid based on Hydroelectric power, will go ahead, and provide  electrical power to Offshore platforms as part of the decarbonization strategy. By the year 2023, the Norwegian Petroleum Directorate plans at least sixteen offshore installations powered by electricity from shore, resulting in 25% reduction in emission as compared to 2019 [9].

Similarly, China’s CNOOC is planning to provide AC electrical supply from their onshore grid to two fixed offshore platform in the country’s first foray into platform electrification. ADNOC in Abu Dhabi will electrify offshore production facilities via subsea power cables from onshore power generation, in the region’s first high voltage direct current(DC) subsea transmission. Similar initiatives are underway in the UK continental shelf (UKCS) where subsea power transmission is being considered from renewable generation assets [9].

4.2.5 Decarbonizing Thermal Energy:

Replacing all Hydrocarbon fuels used in upstream operations by Hydrogen would make a significant contribution the reduction of Tier-1 emissions. Hydrogen can be produced easily by the well-established Steam Methane Reforming (SMR) process. Of course, the Hydrogen generation unit would have to be planned as a Tier-2  facility, that would in turn adopt Carbon mitigation strategies such as CCUS. The advantage of using Hydrogen is that the end product of combustion is Water. In fact, the world is viewing Hydrogen as the fuel of the future. Already, Downstream operators are looking at low Carbon fuel replacements strategies as part of their decarbonization roadmap and this trend will inevitably catch-on with Upstream players as well.

SMR technology can be  used to produce Hydrogen from feedstocks such as Natural gas  and Condensates. It is in fact the is the most widespread technology used  to manufacture Hydrogen in the Process industry. Broadly, the SMR process involves the following steps:

Feedstock purification:

Removal of impurities, primarily Sulphur compounds that can poison the reformer catalyst.

Steam Reforming

This involves the reaction of Methane and higher Hydrocarbons (such as Naphtha)  with Steam in a series of steps using a Nickel base catalyst, resulting in Hydrogen liberation from Hydrocarbons as well as from Water. This endothermic rection is performed at 800 to 880 degrees Centigrade and pressures between 20 barg to30 barg. In larger facilities, a pre-Reformer may be added to reduce the size of the main Reformer. The gas stream leaving the Reformer is a mixture of Hydrogen (H2), Carbon monoxide (CO), Carbon dioxide (CO2), Methane and Water. This mixture is termed Syngas.

Typical reactions that occur in the reformer are:

CH₄ + H₂O = CO + 3H₂

C_nH_2n+2+ nH₂O = (2n+1)H₂ + nCO

Water-Gas Shift reaction:

After Reforming there is still potential to produce more Hydrogen from the CO, CH4 and H2O components of Syngas. This is done catalytically in a shift converter. The CO and Water in Syngas undergo a Water Gas shift reaction to form CO2 and H2 in the shift converter. This is an exothermic, equilibrium reaction that utilizes Chromium-based catalysts.

CO + H2O = CO2 + H2

The gases leaving the shift reactor are then cooled down to about 35 to 40 degrees Centigrade via heat recovery systems, before typically going to a Pressure Swing Adsorption PSA unit for H2 and CO2 separation. The PSA unit can deliver high purity Hydrogen (99.999%) and Hydrogen recovery varies between 70 to 95 %.

4.2.6 Utilize Renewable Energy:

Many operators have started direct integration of renewable energy within their Upstream facilities. Solar PV systems have been used in remote locations for many years at wellhead installations, as part of SCADA. The scope of solar power both  as PV and thermal systems  is now being enlarged. There are examples of remote Solar-powered Oil and Gas wells in Onshore Australia, Saudi Arabia, and Canada. In Oman, solar power has been employed to generate steam for Steam injection, to recover Heavy Oil. Offshore projects provide a lot of opportunities to harness wind power. The  Equinor led Hywind Tampen project is one such example and will be the world’s first offshore floating windfarm. This project will also supply power to Norway’s Offshore Snorre and Gullfaks operations [10].

4.2.7 Carbon Capture Utilization and Sequestration (CCUS)

CCUS has been considered as one of the key pillars of decarbonization, to achieved Net Zero Carbon emissions by 2050 [1]. The term Carbon is used here to refer exclusively to Carbon Dioxide, since the Net Zero target is sought to be achieved by focusing on reduction of Carbon Dioxide in the atmosphere. Technical and economic assessments suggest that over the coming century, CCS may contribute up to 20% of CO2-emission reductions, equivalent to reductions expected from efficiency improvements and large-scale deployment of renewable energy resources [11]. It is believed that CCUS provides the quickest and easily implementable option for the major Oil and Gas operators to reduce their Carbon footprints.

Figure 9 provides a snapshot of ongoing integrated CCS projects worldwide  at various stage of development [12].

The overall concept of CCUS is based on discrete and complex technological components dealing with Carbon Dioxide Capture, Utilization of captured Carbon Dioxide and its geological sequestration. Fortunately, the Oil and Gas industry has significant expertise and several decades of collective experience in each of these areas. Considering its importance as a major potential contributor to decarbonization, the following sections discuss each component of CCUS in detail.

Carbon Capture

The Oil and Gas Industry has a long history of developing gas reserves containing high levels of Carbon Dioxide. The sweetened gas after Carbon Dioxide removal, has been utilized for NGL and LNG production, power stations and fertilizer projects . Many of the Carbon Dioxide  removal technologies in existence, are mature, while newer technologies continue to emerge to address the specific requirements of the emerging Carbon capture markets.

Table 2 summarizes the available technologies for Carbon Dioxide capture:

Table 2: Technologies for Carbon Dioxide Removal from Gases

In the context of Upstream Oil and Gas decarbonization, Carbon Dioxide emissions from various sources as discussed in previous sections are generally at low pressure, such as in flue gases or atmospheric vents. The most economical and well-established process for capturing these low-pressure Carbon Dioxide emissions is Amine technology.

There are several types of  Amines employed, depending upon the gas composition, operating conditions and treated gas specifications. Some of the well-known Amine solvents are listed below. It may be noted that many licensors offer proprietary formulations.

• Monoethanol Amine (MEA)
• Diethanol Amine (DEA)
• Triethanol Amine (TEA
• Methyl Diethanol Amine (MDEA)
• Diglycol-amine (DGA)
• Diisopropanol amine (DIPA)

For bulk Carbon Dioxide removal in the absence of Sulphides, the most popular Amine is MEA. The MEA Carbon Dioxide capture process is briefly described in the following section with reference to a typical Amine process flowsheet.

Inlet gas, which is typically at atmospheric pressure, is compressed using either a blower or compressor such as K-101. Increasing the operating pressure reduces the diameter of the Absorber Column but increases OPEX due to compression power. Flue gases tend to be hot, with the exit temperature depending on heat recovery in the fired heater/boiler convection sections and also on Oxides of Sulphur present, which restrict cooling to avoid Sulphuric acid condensation. Flue gases must be cooled to at least 50 degrees Centigrade before entering the absorber.

The Gas containing Carbon Dioxide enters the absorber column (C-101) via an inlet gas cooling section, after which it flows upwards into absorption section. Lean Amine from the Stripper column (C-102) flows down from the top of C-101, in counter current fashion, absorbing Carbon Dioxide from the incoming gases. The sweetened gas, after Carbon Dioxide removal, is washed by Water to remove any entrained Amine solution at the top of C-101, after which it leaves the column. Flue gases which mainly contain Nitrogen are vented to atmosphere after Carbon Dioxide is captured. In case the sweetened gas contains Methane and other Hydrocarbons, it can be sent to a fuel gas system.

The Rich Amine containing absorbed Carbon Dioxide reaches the bottom of the absorber and is then pumped by the Rich solvent pump (P-102) through a Lean/Rich heat exchanger (E-102) to the solvent stripper (C-102), for regeneration. The reboiler (E-104) may be directly fired or Steam heated. It provides the provides the heat necessary to strip out the Carbon Dioxide from the Amine solvent. Stripping steam from the reboiler flows upwards while rich Amine flows downward, and Carbon Dioxide is stripped out in the process. The stripper column may be of packed or trayed type.

The stripped Carbon Dioxide along with Water and Amine vapor enters the Stripper Condenser (E-105), where Amine and Water are condensed and Saturated carbon Dioxide is sent for further compression, to be used in Enhanced Oil Recovery or Sequestration.

Lean Amine, after regeneration, is cooled and pumped back by P-103 to the top of  Absorber C-101. A reclaimer (E-107), which is a small reboiler attached to the stripper is used for regenerating a slipstream of the Amine solvent, to avoid build-up of  impurities.

Utilization of Captured Carbon

Enhanced Oil recovery is a well-established method of utilizing captured Carbon Dioxide. The Oil and gas Industry discovered  Carbon Dioxide injection as a means of Enhanced Oil Recovery several decades ago. In fact, the  first patent for Carbon Dioxide EOR technology was granted in 1952 to Whorton, Brownscombe and Dyes and assigned to the Atlantic Refining Company[14]. The first engineered injection of CO2 into subsurface geological formations for EOR, was implemented in Texas in the early 1970’s [11].

EOR is a tertiary recovery mechanism and works on the principle that Carbon Dioxide, in suitable reservoirs, is miscible with  heavy Crude Oils, forming low viscosity, low surface tension fluids that can be suitably displaced toward the Wellbore. The Carbon Dioxide also occupies small pores and displace residual oil trapped there, so that Water can be injected to flush out the displaced oil. Though  EOR is not always applicable, the technique is widely used in the Oil and Gas industry as a means of utilizing captured Carbon Dioxide.

Carbon Sequestration

Carbon Sequestration is the final and crucial element in the CCUS approach to removal of Carbon Dioxide from the atmosphere. Sequestration means the safe placement of Carbon Dioxide into a subsurface formation for permanent storage. Geological storage of Carbon Dioxide is known to be a natural process that has occurred through the millennia. The Earth’s crust is a huge Carbon reservoir, holding Carbon in various forms such as Coal, Petroleum fluids and Carbonate rock [11].The technology of underground storage of gases and also of gas injection is well understood by the Oil and Gas industry.

To enable maximum sequestration volumes in a given reservoir, the Carbon Dioxide must be compressed. The critical point of Carbon Dioxide is 31.1 degrees Centigrade and 73.8 bara. Typically, at depths below 800 meters, the pressure and temperature would exceed the critical point of Carbon Dioxide. In most cases the volume is reduced by a factor of 50 as indicated in Figure 11:

Geological storage of CO2 can be undertaken in a variety of geological settings in sedimentary basins. Within these basins, oil fields, depleted gas fields, deep coal seams and saline formations are some possible storage formations. Suitable formations are usually found below 800 meters depth. They must have  thick seals that can prevent Carbon Dioxide breakout. The reservoir porosity must be sufficient to hold large volumes and permeable enough to allow high injection flow rates without requiring excessive pressure, that pushes up compression costs.

Figure 12 illustrates the concept of geological sequestration:

5 Conclusion

Crude Oil and Natural Gas are expected to be important global energy and feedstock sources  for several decades to come. The Oil and Gas industry has recognized the importance of decarbonization to tackle stakeholder and societal expectations and potential punitive legislations. The pathways to decarbonization, as delineated in this article, are well understood. The Oil and Gas industry possesses vast monetary resources, expertise, and a global footprint that will allow it to be at the vanguard the world’s transition to Net Zero Carbon Dioxide emissions by 2050.

6 References

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5. Drilling Emissions Management: Reduce emissions during well construction through planning, monitoring, and innovation; by Schlumberger, 2022 (slb.com/dem)
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9. Routes to reduce emissions from oil and gas production, in Industry Pulse, in https://epplus.hartenergy.com/issue/January 2021, by Liv A Hoven, CEO DNV GL-Oil and Gas.
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11. IPCC Special Report on Carbon Dioxide Capture and Storage, 2005. https://www.ipcc.ch/report/carbon-dioxide-capture-and-storage/
12. A Chemical Engineering Perspective on the Challenges and Opportunities of Delivering Carbon Capture and Storage at Commercial Scale, April 2018, IChemE Energy Centre.
13. Sweetening Technologies – A Look At The Whole Picture (2009),  by Marco Bergel  et al; (PDF) Sweetening Technologies – a Look at the Whole Picture | Ignacio Tierno – Academia.edu
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