Greenhouse gas mitigation strategies for the oil industry - bottom-up system analysis on the transition of the Colombian oil production and refining sector
Yanez Angarita, Edgar
DOI:
10.33612/diss.158071720
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Publication date: 2021
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Yanez Angarita, E. (2021). Greenhouse gas mitigation strategies for the oil industry - bottom-up system analysis on the transition of the Colombian oil production and refining sector. University of Groningen. https://doi.org/10.33612/diss.158071720
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7 CONCLUSIONS
_________________________________________________
7.1 RESEARCH CONTEXT
Under the Paris Agreement and in line with the sustainable development scenario from the
International Energy Agency (IEA), a target of net “zero” CO2 emissions by 2070 has been
introduced as essential to limit the global average temperature rise to 1.8°C 1. The European
Commission plans to reduce GHG emissions by petroleum refineries by 83-87% below the 1990
level by 2050 373. Colombia is committed to a 20% reduction with respect to the projected
Business-as-Usual Scenario (BAU) by 20306, which has also been adopted by the national
industrial sector. The country accounts for approximately 0.4% of the global emissions 7;
however, regarding its vulnerability to climate change, it ranked 19th in 20178.
Globally, industrial final energy use reached 157 EJ in 2018, with an annual average growth of
0.9% since 2010 399. This accounts for 37% of the total global final energy use and around 26%
of primary energy use 38. In 2013, the chemical and petrochemical sector reported that oil and
natural gas (O&G) accounted for 76% (30 EJ) of the final energy consumption as an energy source and 99% (24 EJ) as feedstock. Of the former, O&G represented 39% of the total global
industrial final energy consumption (59 EJ) in 2013 38. In the O&G industry, extracting,
processing, and marketing fuels account for 27% of the total global primary energy use 39. The
International Petroleum Industry Environmental Conservation Association estimates energy consumption by the O&G industry to be 10% of gross oil and gas production (25 EJ per year),
Colombia is a net exporter of fossil fuels. According to the IEA9, Colombia’s energy production
was 5.3 EJ in 2015, with a final consumption of just 1.1 EJ and a net export of 1.6 EJ of oil and 2.1 EJ of coal. In the coming decades, Colombia oil export is likely to decline due to shrinking
oil reserves as observed from 2007 400. Colombia increased its GHG emissions by 15% from
1990 until 2010, reaching a total of 281 million tonnes of carbon dioxide equivalent (MtCO2-eq)
7. The most updated GHG inventory for Colombia was issued in 20127, with a total of 258
MtCO2-eq.
The oil and gas industry is responsible for 6% of total global CO2 emissions, from exploration
and production, to refining and downstream petrochemical production. In addition, the use of the final products in power generation, heating and transport represents approximately 50% of global
GHG emissions 374. To achieve the mitigation target, the oil industry will require a broad
portfolio of GHG mitigation options that is able to meet the set targets. It is, however, expected that the share of oil in the world primary energy demand will decrease steadily from 31% in
2018 to 29% in 2040, but with an absolute increase of 25% to 236 EJ in 2040 1. The transport
sector (road, aviation, and shipping) represents 49% of the total oil demand, and this figure is
expected to increase to 60% by 2040 (0.5 EJ/d) 1. Crude oil is and will stay important for
decades. The dominance of crude oil in the transport sector can be attributed to the vast established infrastructure, large scale of production, low cost, and availability of
high-energy-density fuels 2.
Of the range of GHG mitigation options, CO2 capture and storage (CCS) is a technology option
with a recognised potential for mitigating CO2 emissions in the fossil energy industry 199. The
deployment of CCS on industries of high-value chemical products (e.g. oil refining, iron/steel production, ethylene manufacture, and ethanol production, among others) rather than power
plants, can more easily absorb the additional CO2 capture cost on the price of their products 200.
For the refining sector, CO2 enhanced oil recovery (CO2-EOR) is currently another potential
option, as it allows for the use and storage of captured CO2 to reduce the emissions in the
industry while maintaining oil production. CO2 injection for incremental oil recovery has been
performed commercially for decades, worldwide. A recent update by the IEA 201 estimates that in
oil production of CO2-EOR projects is approximately 0.5 million bpd 201. This volume accounts
for about 20% of the production of EOR operations, which in turn represents 2% of the world oil
production. Forecasts predict that 1.64 million bpd will be produced with CO2-EOR out of 4.5
million bpd from EOR in 2040201 (which would represent 4% of the global production).
Regarding the CO2 storage potential, the IEA18 estimates a cumulative storage of 360 GtCO2,
through maximum-storage EOR+ processes on a global scale.
On the liquid fuel-based emissions for the transport sector, there is a range of options to lower GHG emissions, from improved fuel efficiency, low carbon fuels to electric/hybrid vehicles. Regarding low-carbon intensity fuels, to date, several technology options have been proposed to
reduce CO2 emissions during oil production and refining. However, it has been estimated that
emissions outside the refinery (i.e., in the final use of oil) account for about 80% of the total
life-cycle emissions 257. Therefore, other options are needed to achieve lower net fuel-cycle
emissions.
One potential solution to this problem lies in the final use of fuels produced from sustainable biomass, as they release carbon that has been absorbed during plant growth through
photosynthesis. These fuels can provide low net fuel-cycle emissions, under the condition that biomass resources are sustainably sourced, or even achieve negative emissions if the
co-produced CO2 is captured and stored underground, as described by Hailey et al.2.
Technology measures such as energy efficiency, carbon capture and storage (CCS), bioenergy
and fuel switching have been considered in CO2 mitigation portfolios for industrial sectors.
Boulamanti and Moya 375, for instance, estimated the mitigation potential for the chemical
industry in Europe by 2050 by focusing on best available and innovative technologies. Fais et.
al., 376 proposed different technology portfolios to estimate CO
2 reduction potential for the UK
industry, but without giving insights into suitable strategies and associated investment costs.
Johansson et al. 377 assessed the CO2 mitigation potential for the oil industry in Europe without
determining deployment pathways or the combined mitigation potential. The authors
options are implemented altogether. Berghout et. al. 37 assessed combined deployment pathways
from measures such as EEM, CCS, biomass gasification, and pyrolysis oil-based biofuels. All these studies, however, are constrained by the level of detail and the options covered. Also,
estimating the CO2 mitigation potential and avoidance cost in the oil industry still lacks a
comprehensive system analysis. Such analyses require further integration with the surrounding energy system through the consideration of a wider technology portfolio including alternative energy sources and raw materials such as biomass and hydrogen, but also renewable electricity.
7.2 OBJECTIVE AND RESEARCH QUESTIONS
In this context, the main objective of this thesis was to assess the techno-economic and CO2
mitigation potential for decarbonization pathways for the crude oil industry on a detailed level for existing facilities. This assessment considered relevant alternatives throughout the value
chain such as energy efficiency measurements (EEM), carbon capture and storage (CCS), CO2
enhanced oil recovery (CO2-EOR), electrification, low-carbon energy sources, and
biomass-based alternatives.
This thesis used the Colombia oil sector as specific case study. The aim was addressed by answering the following sub-questions:
4. What are the promising technological options, their potential and mitigation cost for decarbonizing the oil industry?
5. In which way potential deployment pathways can be developed for a decarbonization strategy of the oil industry?
6. What is an effective design for a methodological approach to assess and quantify mitigation options and decarbonization pathways for existing industrial facilities? Table 2-1 gives an overview of the chapters of this thesis in which these research questions were addressed.
Table 2-1. Structure of the thesis
Chapter Topic RQ 1 RQ 2 RQ 3
2 Unravelling the potential of energy efficiency in the
Colombian oil industry +++ + ++
3
Rapid screening and probabilistic estimation of the potential for CO2-EOR and associated geological
CO2 storage in Colombian petroleum basins
++
4
Exploring the potential of carbon capture and storage-enhanced oil recovery as a mitigation strategy in the Colombian oil industry
+++ + ++
5 Assessing bio-oil co-processing routes as CO2
-mitigation strategies in oil refineries. +++ + ++
6 Fully integrated CO2 mitigation strategy for an
existing refinery: Case study in Colombia + +++ +++
The symbols (+) indicate the level of the research question addressed by a chapter.
7.3 SUMMARY
Chapter 2
This chapter presents insights into the potential of energy efficiency measures (EEM) and their
implications for CO2 abatement in the value chain of the Colombian oil industry. It also assesses
the potential cost of conserved energy and mitigated CO2-eq. A bottom-up approach was used to
identify energy efficiency measures based on an assessment of specific operational data at the process unit level.
In total, 20 measures and technologies for 48 cases were identified and assessed throughout the value chain. This accounts for energy savings in the order of 16 PJ and GHG savings of 0.75 Mt CO2-eq per year (25% and 19% of the total energy consumption and total emissions of the
processes-chain, respectively). Ninety-six percent of the total energy savings comes from measures that are already cost-effective and could be implemented in the short term.
According to our model, primary energy consumption accounts for about 13% of the total energy
indicated an energy consumption of around 10% of total gross oil and gas production. Crude treatment at the production stage, and the fluid catalytic cracking (FCC) in the refinery, are identified as the most energy-intensive processes in the value chain. In the production stage, this is mainly due to flaring (which accounts for 47% of the total primary energy consumed in the process) associated with inefficient recovery of gas from the gas/oil separators and losses of vapour from diluent used to reduce oil viscosity during pumping. In the refinery, the energy consumption of the FCC is due to its steam demand, representing 95% of the total energy consumed in the process. The largest direct consumer of primary energy in the refinery is steam and power production, representing 78% of the total energy consumption.
In terms of energy and GHG emissions savings, process optimization and gas recovery appear to have the largest EEM potential, as these measures are characterized by low investments and high savings. Furthermore, most of the identified measures are short-term and cost-effective.
Around 16 PJ of GHG savings in the full value-chain come from cost-effective measures that
could lower CO2 emissions by 700 kt/year. Improvements in the refinery steam network could
result in savings of around 5.3 PJ (34% of the cost-effective savings). In addition, recovering flare gas and venting gas at crude treatment facilities could also result in significant savings (38%). Interestingly, the energy savings potential at the production stage are as high as those at the refinery, while in literature, the refinery stage is generally the one identified with the highest potential for energy savings in the oil industry. There is a wide range in the specific cost of conserved energy (CCE) for the measures evaluated at the production stage, ranging from -440 $/GJ for progressing cavity pumps for oil lifting to 1.4 $/GJ for the use of organic Rankine cycle (ORC) in the gas turbines. However, the main group of profitable measures ranges between -29 to 0 $/GJ. The use of ORC in gas-powered engines to drive pumps in oil transport stage presents the highest CCE (around 100 $/GJ).
In terms of the level of investment, the biggest investments (around $48 million) are in the refinery gas network optimization, followed by the use of ORC to improve gas turbine efficiency in power generation at the production stage ($32 million). Nevertheless, for this specific case study, the yearly financial benefits from energy savings at the production stage can double those
from the refinery, which would mean a shorter period to recover the investment. For the global EEMs portfolio, total investment at the production stage is three times higher than that in the refinery. Most of the 48 cases (around 60%) correspond to short-term measures, i.e., they have low technological complexity, high implementation potential, and relative low to medium cost. While this group represents just about 12% of the total investment of the portfolio, it corresponds to around 60% of the total energy and GHG savings. In financial terms, the short-term measures account for half of the yearly economic benefits from energy savings. For the medium-term measures, a 30% discount rate reduces the cost-effective potential to around 2 PJ and 20 kt
CO2eq. Measures that are not cost-effective in the medium term reach a cost of up to $200 per GJ
or $1,000 per tCO2-eq whilst for the short-term the cost is lower than $5 and $100, respectively.
The approach used in this chapter provides a value chain perspective to support the oil sector and policy makers in understanding the critical stages for energy savings potential, and the economic order of the investment needed. The method has universal value for quantifying GHG mitigation potential for the oil industry in general, which clearly highlights the importance of using bottom-up, plant-specific data. Also, it shows the importance of assessing the full value chain because stages such as production and transport, which tend to be overlooked in studies of energy efficiency, can provide significant cost-effective options in the short-term.
Chapter 3
Estimating the oil recovery potential using CO2 (CO2-EOR) is high resources-intensive activity
that is not usually available for studies at country-level. The aim of this chapter was two-fold.
First, the potential for CO2 storage and enhanced oil recovery (EOR) through CO2-EOR in
Colombia was evaluated, and second the results from two different calculation methods (stochastic and deterministic) were compared when there is lack of information for the quick screening of suitable oil fields at the country level. The deterministic approach was based on expert insights and information found in literature; while, the stochastic method used statistical data from two different databases to run a Monte Carlo simulation. Despite the fact that the input values used by the determinist method were within the range used by the stochastic method, the estimated potential varied significantly. The stochastic potential for Colombia was estimated at
and 36 MtCO2 were estimated using the deterministic method. The results indicate that a
combination of the two approaches can reduce the time and data required, providing early insights into the feasibility of this technology.
The findings of this study suggest that combining the deterministic and stochastic methods offers
a useful approach to explore the potential for oil recovery and CO2 storage at a regional level
when there is insufficient data (publicly) available. Furthermore, after using a deterministic approach for a preliminary estimation, results can be improved through a probabilistic estimation
of the CO2-EOR potential. The stochastic method can deal with the uncertainty of the input
values without involving substantial simulation efforts and, therefore, help providing a better
understanding of the feasibility of CO2-EOR at the country level.
Chapter 4
As introduced in chapter 3, the use of CO2 for enhanced oil recovery (CO2-EOR) is a promising
alternative for reducing the cost of carbon capture and storage (CCS). In this chapter, the techno-economic potential of integrated CCS-EOR projects for reducing greenhouse gas (GHG) emissions in the Colombian oil industry was estimated. For this purpose a source-sink matching was carried
out between the potential of CO2 capture at key point sources (petroleum, cement, power
generation, and bioethanol industries) and the potential of CO2 storage in suitable oil fields for
EOR. The results indicated that a total of 142 MtCO2 could be stored, while delivering 465 MMbbl
oil through five CCS-EOR projects in four clusters identified in the country.
The CO2 capture cost is responsible for the largest share of the total levelised cost of CO2 for
CCS-EOR projects. This process showed values ranging from 12 €/tCO2 for the fermentation
processes in ethanol production to 209 €/tCO2 for low-volume sources in the oil refinery. The
CO2 transport cost varied between 1 €/tCO2 for a cluster with the highest volume to transport
(2.7 MtCO2/year) and the shortest distance (9 km), up to 23 €/tCO2 where there were showed the
longest network pipelines (500 km) and a relatively low CO2 volume (0.9 MtCO2/year). The cost
of the CO2-EOR operations range from 24 to 59 €/tCO2), which included the injection,
The CO2 mitigation potential of CCS-EOR represents about 25% of the forecasted oil industry
emissions in Colombia for the period of 2025-2040. Compared to the intended nationally determined contribution (INDC) target set by the Colombian government, CCS-EOR projects could contribute to 7% of the total accumulated emissions reductions by 2040.
In terms of capture, the results indicate that although approximately 18 MtCO2 per year could be
captured, only 5.9 MtCO2 were found to be techno-economic feasibly for EOR projects. The oil,
cement, and power generation industries represent 59%, 21%, and 16% of this potential,
respectively. The potentials for CO2 storage and oil recovery through CCS-EOR were estimated
at 142 MtCO2 and 465 MMbbl. They represent 57% and 58% of the CO2 storage capacity and oil
recovery capacity, respectively, as determined by the screening of oil fields in Colombia carried
out by 203.
Chapter 5
This chapter aimed to evaluate the CO2-mitigation potential of using sustainable biomass into the
refinery for delivering low carbon fuels through several bio-oil co-processing pathways, gasification of solid biomass and vegetable oil. A techno-economic analysis was conducted of various different pathways for biomass use in existing refineries and their GHG mitigation potentials were compared. Thirteen pathways with different bio-oils were analysed, including vegetable oil-(VO), fast pyrolysis oil-(FPO), hydro-deoxygenated oil-(HDO), catalytic pyrolysis oil-(CPO), hydrothermal liquefaction oil-(HTLO), and Fischer-Tropsch fuels. However, no single pathway could be identified as best option as this dependents on the criteria used and the goal of the co-processing route.
The results indicated that up to 15% of the fossil-fuel output in the refinery could be replaced by biofuel without the need for major changes in the core activities of the refinery. The consequent
reduction in CO2 emissions over the entire life cycle varied from 33% to 84% when compared to
equivalent fossil fuels produced (i.e., gasoline and diesel). The production costs varied from 17
to 31 €/GJ (i.e. 118-213 $/bbleq). Co-processing with VO resulted in the lowest overall
performance among the evaluated options (33% reduction in CO2 emissions), while
the highest potential for CO2 avoidance (69% of refinery CO2 emissions), and reduction in CO2
emissions (84% compared to fossil fuel). The cost of CO2 avoided for the assessed routes was
found in the range of 99–651 €/tCO2.
Bio-oil co-processing could accelerate the transition of refineries towards the production of more sustainable fuels. In this case study, up to 15% of fossil fuel could be replaced by bio-oil co-processing. This threshold was defined by technical co-processing limits based on modifications in the operational conditions and the need for additional infrastructure. The bio-oil co-processing
pathways analysed in this study can reduce by 6%–81% CO2 emissions of the case-study
refinery. The overall mass yield for biofuel production ranged from 9% (vegetable oils) to 33% (FPO co-processed in FCC). Thermochemical bio-oils resulted in yields of 12%–33%. These
results are in agreement with the yields reported by Van Dyk et al., 260 for jet-fuel production
using FPO, CPO, and HTLO (21% – 37%). They also reported a GHG reduction of 74%, while in our study thermochemical bio-oils resulted in a GHG reduction of 46%–84%.
Biofuel-production costs were estimated at 17–31 €/GJ. Recently, Van Dyk et.al., 24 reviewed the
production costs of biofuels using thermochemical oils and reported costs of 17–42 €/GJ
(adjusted to €2018). Our findings are also consistent with the production costs reported by
Maniatis et al., 344 regarding the hydrotreatment of vegetable oils and Fischer-Tropsch (FT) fuels
(14–25 and 25–39 €/GJ, respectively). Based on a conservative capital-cost estimate for refinery co-processing, the final blended fuel production cost would increase by 10%–50%, depending on
the technical limits of co-processing. The cost of CO2 avoidance varied from 99–651 €/t CO2
when using the average Brent crude oil price of 64 €/bbl of 2018. In pathways with the highest
potential for CO2 avoided, the cost varied in the range of 124–337 €/t CO2.
The highest potential for mitigating emissions from the refinery were shown by co-processing
HTLO in the HDT. FPO in the FCC led to the highest CO2 avoidance (69% of refinery CO2
emissions) and reduction in CO2 emissions (84% compared to the fossil fuel). Moreover, these
routes showed good performance for criteria such as production cost and energy and mass yields. Co-processing with vegetable oils resulted in the lowest overall performance among the
Chapter 6
This chapter estimated a bottom-up CO2 mitigation potential for a medium-level conversion
refinery for portfolios of combined mitigation technologies and considering techno-economic interactions over short, medium, and long-term.
A total of 40 measures were identified linked to the transition of the Colombian energy systems, covering a wide range of technologies such as energy efficiency measures (EEM), carbon
capture and storage (CCS), bio-oil co-processing, blue and green hydrogen (BH2, GH2), green
electricity import, and electrification of refining processes. Five deployment pathways were assessed to achieve different specific targets: base case scenario (or business-as-usual), less
effort (low-hanging fruits options), maximum CO2 avoidance (all possible technical options are
considered), INDC (national commitment target with COP21 agreement), and lower CO2
avoidance cost (competitive mitigation measures below 200 €/t CO2). Two scenarios (maximum
avoidance and measures below 200 €/t CO2) gave the highest GHG emission reduction potentials
of 106% and 98% of refining process emissions, respectively. Nevertheless, the maximum mitigation potential found, although significant, equals 13% of total GHG emissions when including the process emissions and the emissions of the refinery products. Co-processing options account for around 60% of the mitigation portfolio, followed by CCS (23%), GE (7%),
and H2 (6%). The findings show that the oil and gas industry could reach carbon neutral
operation as far as the plant emissions are concerned but excluding the CO2 emissions caused by
end use of the refinery products.
This methodological approach brings more detailed insights as the CO2 mitigation potential per
deployment pathway (DP) is determined by the timing and the interactions between mitigation options. This is due to the lifetime of existing process equipment, the cost development over time of mitigation options, and interdependency of mitigation options (either providing synergy, limiting impact or incompatibility). The implementation order of mitigation options (MOs) relies on its life-span, space availability, technical constraints, technological maturity (based on TRL), economic parameters (total investment), retrofitting order, facility unit targeted for mitigation
and industrial utilities demand. As a result, these insights define possible transformation route of a refinery much more specifically over time in relation to a specific mitigation target.
From a gross 22 Mt CO2/y MOs inventory, based on all identified options, the mitigation
portfolios used in the deployment pathways have a CO2 mitigation potential of 0.4 to 11 Mt
CO2/y by 2050. In general, as more option become available, the mitigation potentials increased
over time, except for the less effort scenario. EEMs provided MOs potential of 0.01 to 0.37 Mt
CO2 /y with CO2 avoided cost ranging of -93 to 20 €/t CO2. CCS had a mitigation potential
varying from 0.06 to 1.3 Mt CO2/y, and avoidance cost of -88 to 318 €/t CO2. Co-processing
bio-oil at the refinery provided the highest mitigation potential of 0.2 to 3 Mt CO2/y, mainly as a
result of the carbon-neutral emissions of fuel final use, with an avoidance cost of 98 to 651 €/t
CO2.
Despite the relevant mitigation potential (2.5-3 Mt CO2/y) of short and medium-term
(2025-2035) measures, long-term (2035-2050) options represent a significant and higher potential for
CO2 emission reduction (8.4 Mt CO2/y). Combined options deployment overall can deliver very
deep emissions reductions for existing refineries, and to a large extent to a relatively competitive
cost. This is the case of the deployment pathway including measures below 200 €/t CO2, which
has an almost equal mitigation potential as the maximum avoidance route, but with a lower avoidance cost.
Many potential conflicting options and technology combination have been identified as well when designing the implementation pathways. Deployment constraints result from technical
interactions such as competing for the same CO2 stream or facility (e.g., heat recovery and CCS
at the FCC unit), as an indirect consequence (e.g., electrification might replace boilers and furnaces which in turn, discards CCS for combustion sources), and economic expectations (e.g.,
CO2 sources with CCS options are locked-in for 20 years due to the economic lifespan of EOR
projects). This study illustrates in a foresight-oriented analysis, how such conflicts can be identified and quantified.
All mitigation options investigated are essential and could lead to an increasing share of biomass
and green hydrogen for other conversions routes (e.g., CO2 chemistry). Despite an exhaustive
quantification of possibilities for normal refineries to bring CO2 emissions down, fundamental
changes in core process (in our case by 2050), should still be done. The mitigation strategies analysed do not fundamentally change the fact that these refineries are still oil processing facilities, which means that fossil carbon is embodied in the product output. In order to tackle this aspect, refineries can increase biomass gasification capacity or using more bio-oil into the
process to replace crude oil. Also, adding more Green-H2 and Green-electricity combined with
CO2 conversion processes to produce synthetic fuels or a mixture of synthetic and biofuels offers
alternatives for crude oil. More research is required to investigate to what extent refurbishing existing refineries versus new low carbon fuel facilities is attractive from an economic and environmental point of view.
7.4 MAIN FINDING AND CONCLUSIONS
The findings in the individual chapters are used in this section to answer the three research questions of this thesis.
Research question 1: What are the promising technological options, their potential and
mitigation cost for decarbonizing the oil industry?
For the refinery case study covered in this thesis, the results show that among the different stages of the oil value chain, the lowest (but still significant) potential was found for the transport stage, as it is based on pipeline infrastructure with high utilization factor and low-carbon electricity
powered facilities using the national electricity grid (0.13 t CO2 /MWh). The oil production stage
presented a significant mitigation potential for flaring reduction and energy efficiency measures
deployment, which accounted for a mitigation potential of 0.75 Mt CO2 /y with an avoidance
cost range from -1100 to 476 €/t CO2. The highest CO2 mitigation potential and promising
opportunities for oil industry decarbonization were found in the refinery. A comprehensive portfolio of mitigation options was considered from typical energy efficiency measures, through
CCS using EOR technology to bio-feedstock co-processing, blue and green hydrogen to process electrification.
For the refinery, CO2 avoidance cost ranges from -93 to 810 €/t CO2, with the highest cost found
by replacing fuel gas with green hydrogen in the furnace of the visbreaking process unit and the lowest cost observed by improving the management of steam losses at the refinery. The highest
mitigation potential was estimated for catalytic pyrolysis oil co-processing (2.9 Mt CO2/y), and
the lowest by replacing steam with air for assisting flaring. The results indicate that refineries might reach carbon neutral operation when biomass co-processing is deployed as the most significant option for a strategy targeting the realization of the maximum mitigation potential. Nonetheless, a deployment strategy based on a different target might change the mitigation potential dramatically on the medium and long-term.
Energy efficiency measures (EEM) cover mitigation potentials ranging from 3.4 to 355 kt CO2/y,
with an avoidance cost of -93 to 20 €/t CO2. These measures are considered low-hanging fruits,
with mostly negative avoidance cost. However, they represent a lower mitigation potential with regard to other alternatives. The most significant option among EEM refers to improved
management of steam losses, followed by waste heat recovery at the FCC unit, best practices operation during steam production, and LNG/NGL recovery from the refinery gas network. CCS accounted for around 23% of the identified mitigation potential at the refinery. A
significant volume of CO2 capture and storage through EOR operations was found from 63 kt
CO2/y for capture from a small hydrogen production unit to 1.3 Mt CO2/y in a combined
configuration capturing CO2 from the FCC and CHP. CO2 avoidance cost ranged from -88 €/t
CO2 for the small hydrogen unit (highly concentrated CO2, approx. 95%) to 318 €/t CO2 for the
largest facility to produce hydrogen. It must be noted that the overall economic performance and mitigation potential of this option rely on the EOR suitability of the oil fields near the refinery. Co-processing bio-feedstocks options represented around 60% of the mitigation potential at the
refinery. This is due mainly to the carbon neutral CO2 emissions assumed during final use of the
catalytic pyrolysis oil (CPO), hydro-deoxygenated pyrolysis oil (HDO), hydrothermal liquefied oil (HTLO) and biomass gasification to Fischer-Tropsch (BG-FT) to produced renewable liquid
fuels. CO2 mitigation potentials ranged from 0.2 to 2.9 Mt CO2/y for co-processing VO in HDT
and BG-FT respectively, while the avoidance cost varied from 99 to 651 €/t CO2 for FPO
co-processing at FCC and VO to HDT, respectively. Several limitations should be noted, For
instance, biofuel-production and mitigation costs involve a high degree of uncertainty, especially for pathways at early development stage technologies. Also, the threshold of impurities allowed by the refinery is still under evaluation. Such impurities might not only seriously affect catalyst activity and performance of the refining process, but also the integrity of infrastructure. In particular, the long-term effects of co-processing are still being evaluated at the laboratory or pilot-scale level and their commercial-scale reproducibility should be investigated in more detail. Electrification options in the refinery include electricity import from the national grid and
deployment of e-furnaces and e-boilers to supply a share of the electricity and heat demand. The highest mitigation was achieved by implementing e-boilers with a reduction potential of around
0.6 Mt CO2/y, while the lowest CO2 avoidance cost was obtained by electricity import from the
national grid with 46 €/t CO2. E-options are constrained by the temperature level of the heat
demanded by the refining processes. E-boilers can supply low-temperature steam (<200°C). However, this type of steam accounts, on average, for only 15% of the heat demand in oil refineries in the Netherlands. Medium to high-temperature steam (200-400°C) accounts for 75%
of a refinery’s steam demand, which would need e-furnaces and H2-furnaces instead. E-furnaces
are still under development (TRL 5-7) with implementation barriers related to the lack of material to withstand low voltages, high amperes and high temperatures. The use of green hydrogen instead of natural gas, represents an increase of 8 to 10 times the fuel cost for this process. Since the low-temperature steam for the case study refinery accounted for around 51%
of the total steam consumption, this steam can be produced by e-boilers for a 0.6 Mt CO2/y
reduction with an avoidance cost of 170 €/t CO2.
Hydrogen was considered as input for hydrotreating but also as an energy carrier, using two
production routes blue hydrogen (produced with CCS for low CO2) as well as green H2
hydrogen-BH2 (as mentioned in the CCS section), but also green hydrogen-GH2. For the highest
demand scenario (co-processing of CPO or HTLO in HDT), it reaches a mitigation potential of
0.7 Mt CO2/y with an avoidance cost of 382 €/t CO2. The lowest CO2 avoidance cost was
estimated for hydrotreating VO of 159 €/t CO2, but it also has the lowest mitigation potential (40
kt CO2/y). High-temperature demand (>350°C) instead can be supplied by blue or green
hydrogen, which can be used mainly in boilers, furnaces and gas turbines. Hydrogen as an energy carrier was considered to replace fuel gas in the furnaces of visbreaking and
hydrocracking units with the latter having the highest mitigation (0.16 Mt CO2/y) at a cost of 810
€/tCO2. A summary of the mitigation options considered to build a deployment pathway in the
refinery is depict in Figure 7-1.
Figure 7-1. CO2 avoided cost of the portfolio of mitigation options.
Identifying mitigation options for alternative energy use in a typical, highly integrated refinery poses several challenges. Using alternative sources for a particular process represent a potential disturbance on the global energy balance of the refinery, which strongly rely on using their
co-produced fuel streams (60-70% of total fuel consumption 396). Most of the CO
2 emissions in a
refinery comes from the CHP and the FCC process (around 70% and 24%, respectively 132).
Alternative sources for fossil-based heat are blue and green hydrogen or by implementing e-boilers and e-furnaces, which implementation is limited as explained above. Regarding the consumption of heat by core-processes, fundamental technological steps are needed, which
-600 -400 -200 0 200 400 600 800
- 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000
RevampingBase Case BH2-BioC-1/2 BH2-BioC-4 BH2-BioC-5 BioC-1 BioC-2 BioC-3 BioC-4 BioC-5 BioC-6CCS-1 CCS-2 CCS-3 CCS-4 EEM-1 EEM-1 EEM-2 EEM-2 EEM-2 EEM-3 GE-Eboiler GE-GT GE-Mix_BioHGE-Mix_P GH2-BioC-1/2 GH2-BioC-4 GH2-BioC-5GH2-HDTc CO2 Avoided
include alternative heating technology for process streams or even further disruptive changes in processes to separate, crack and reform oil molecules.
The mitigation strategies in this paper do not change the fact that these refineries are still at their core oil processing facilities, and that is dependent on fossil carbon. In order to address those emissions, refineries can consider building more biomass gasification capacity and co-processing
more bio-oil in order to replace crude oil. This, in combination with using more green H2 and
electricity can allow refineries to gradually move away of using fossil carbon. Investigating those pathways in comparison to building new carbon neutral fuel production capacity (or green
electricity and green hydrogen in transport) requires further research, including scenario analysis of the energy system at large.
Research question 2: In which way potential deployment pathways can be developed for a
decarbonization strategy of the oil industry?
A decarbonization strategy for the industry can be the result of different drivers such as technological, economic and policy drivers to reach a mitigation target. Based on the work presented in this thesis, potential deployment pathways can be developed by following the next steps (Figure 7-2).
10. Inventory of existing facilities and value-chains. A detailed inventory of processing units, their performance data and lifetime, as carried out in this work, allows for identifying mitigation potential options not only for broad alternatives portfolio but also avoid under- or over estimation of this potential. More detailed data from the current processing infrastructure and future revamping projects can help to improve the bottom-up assessment of decarbonization potential for the sector full value-chain.
11. Inventory of mitigation options (MO): Map technological mitigation alternatives for
processing units throughout the full value-chain of the industry with significant CO2
emissions (PU) and identify the matches between CO2 sources, process units and
mitigation options. These options are to be rated for the short, medium and long-term based on their Technology Readiness Level. This inventory can include the following main categories:
Figure 7-2. Step plan for developing mitigation pathways in complex industries. [1] – Inventory of existing facilities • Topology definition. • System definition. • Time framework. • Process steps description. • Main Products and
raw material flows. • Global production and Economical data.
INPUTS
OUTPUTS
[1.1]- Database and Mass-energy-GHG Baseline
•Data type requirements at process unit level, technical performance, lifetime, TRL level. • Output variables to be estimated. • Process relevance identification by Energy/Mass/Economic value. • Aggregation criteria definition.
• Process level aggregation by units per process / stage.
• Identification of raw data required. • Functional unit
definition. • Data gathering and
refining by quality and symmetry. • Mass, energy, and
emissions data. • Data with accepted quality and symmetry. [3]- Identify impact on industrial facility •Estimation on process/sub-process level. • Energy index estimation. • GHG index estimation. • Incoming / outgoing
mass / energy flows.
• Mass / Energy Balance. • Emissions estimation by functional unit. [2]- Inventory of mitigation options (MO) • Technical mitigation portfolio. • Process Optimization Measures. • Technologies offer.
• Specific process level analysis (Tech/Econ) to identify potential Measures/Technologies to be deployed. (technical matching process-MO).
• Techno-Economic Analysis per Process-MO. • Investment Cost. • O&M Cost. • Lifetime. • Process Efficiency. • GHG process index. [4-5]- Estimate mitigation potential and interactions of MOs
• Mitigation potential (t CO2/year). • CO2avoided cost. • Total investment. • Investment. • Net emission rate
per MO. • Discount rate. • Lifetime. • CO2saving potential estimation. • Cost of CO2avoided. • Analysis of interactions between MOs. Calculation steps
Inputs: blue color; Calculation steps: black color; Outputs: green color
• Feasible matching inventory. • Parameter from the
Process unit: •Stability and performance of process. •Life-span. •Revamping planning. •Availability of additional utilities demand.
• Parameters from the MO: •Already implemented? •Assure not impact on: process yield, products quality, throughout capacity and no-interfere with other process.
[6-7]- Target and Pathways • Feasible matching inventory • Interaction between MOs • Decarbonization target • Time frame • Define decarbonization target for a pathway assuring sustainability of the industry. • Build a Pathway to
achieve the target for specific time-frame. • Externalities assessment. • Target of a pathway. • TRL. • Operational conditions. • Life-span. • Infrastructure. • CO2sources competition. •Technological strategy. •Capital investment plan. •Market requirement. •Social responsibility. •Profitability assurance for stakeholders. • MOs to be included in a pathway by time-frame. • CO2mitigation potential, total investment and avoidance cost of the pathway.
a. A first group covered in this thesis considered improvements to the heat generation system of the refinery and power demand by no-core related processes. The latter represents around 17% of the total consumption of electricity in the refinery, which can be supplied by low-carbon electricity import from the national grid (already low-carbon in Colombia and expected to reach net-zero by 2050) or by a dedicated renewable energy project. In addition, flaring reduction, CHP optimization process, pinch integration, and heat recovery from the steam network represent primary alternatives to be deployed in the first steps for a refinery.
b. The second group covers co-processing options with a significant mitigation potential and lower infrastructure modification. Fossil carbon displacement by biogenic carbon due to biomass integration results on a large mitigation
impact when considering the entire lifecycle of the CO2 emissions of liquid
fuels. However, the extent of this option is limited by the technical co-processing limit (TcPL) of blending bio-oils, in order to not only keep stable performance and low impurities level in the refinery, but also to assure the integrity of the infrastructure.
c. The third group, CO2 carbon capture, transport and storage (CCS) also shows
significant mitigation potential for primary sources such as FCC, CHP, and H2
production (blue hydrogen). This option is constrained by several factors such as the high investment capital, limited space available for new infrastructure deployment, and higher disturbance to core-process (compared to EEMs and bio co-processing options), which would affect process control and
performance. Besides, CO2 capture itself does not represent a complete
mitigation option as a permanent storage or fixation of CO2 is still needed.
This option might be excluded from the portfolio in a deeper analysis when it
finds no region available for CO2 storage or their cost is too high since most
studies assume CO2 can be stored somewhere at a fixed cost. An alternative to
improve the economics of this option is using CO2 for enhanced oil recovery
(EOR), as considered in this thesis, which stores CO2 underground while
improving current oil production as a trade-off to the high investment of CO2
capture rate with its injection rate for a typically discontinuous CO2 injection
operation in EOR.
d. The fourth group covers deploying green hydrogen, targeting mainly new hydrotreating facilities and high temperature level heat demand (e.g.,
furnaces). This option eliminates the need for finding a final use of CO2
compared to blue hydrogen production. This is particularly important for those
refineries which are not close to the oil fields where CO2 can be used for EOR
or any other final-use process.
e. Process electrification is a fifth group to be considered for medium and long-term, which still show some barriers for implementation such as commercially available capacity, medium-high TRL, reliability, and Capex. A shorter-term option is steam production using electrode boilers but limited to a
low-temperature heat. Then further longer-term applications need to be considered, such as heating of process streams and electro-refining processes. These developments require much stronger interventions in the core refining
processes, first with the energy network and then with the core-process itself, which will require further in-depth study and development of a new concept refinery.
f. Last, e-fuel production (synthetic fuels) is shown as a disruptive technology
option to reduce CO2 emissions by replacing or adding new fuel production
capacity to existing refineries. This option (not included in this thesis) will allow refineries to produce liquid fuels from renewable electricity, green
hydrogen, and biogenic CO2.
12. Identifying impact on operation and assess required modifications to the refinery. The technical possibilities are combined with a feasibility analysis of covering the ease of implementation and impacts on the operation of the refinery. Determining these impacts of the MO’s in processing units results in an impression of the complexity to implement them. The following aspects need to be considered:
• Stability of the process and good performance
• Life-span of the CO2 source facility or plan for revamping
• Space availability at location-site for new infrastructure • Availability of additional plant utilities
yield, products quality, throughput capacity, and also does not interfere with other processing units.
13. Estimate the mitigation potential, the investment cost, and CO2 avoided cost for the
deployment of each alternative.
14. Analysis of interactions between mitigation options. Techno-economic interactions and TRL of technology options as well as specific operation facilities conditions, define a potential deployment pathway. This analysis step takes into account the
life-span of current and future infrastructure, and competition between CO2 sources and
process facilities for upgrading. Future revamping projects should also be considered, since some of the current facilities might be upgraded, replaced or decommissioned over time. These interactions mostly define the real mitigation potential of a
deployment pathway in a decarbonization strategy of an industrial complex.
Refineries are industrial complexes with a high degree of integration and, therefore, high interdependency between process units. This means any disturbance on any unit usually affects other operation units within the refinery, and could potentially disrupt
the entire refinery. The highest share of CO2 emissions in the refinery comes from
energy use (around 65-75%), and most mitigation options reduce emissions from energy sources. However, due to the high energy-integration of the refinery, these options can represent risks for the stability and energy balance of the refinery. Main deployment constraints due to technical interactions result from competition for the
same CO2 stream or facility (e.g., heat recovery and CCS at FCC unit), exclusion of
CO2 sources (e.g., electrification options replace some boilers and furnaces which
result on discarding CCS deployment for those combustion sources), and economic
(e.g., CO2 sources with CCS for EOR are locked-in for 20 years due to the
life-economic span of EOR projects).
15. Determine the target of a pathway. A clear objective should be defined as a mitigation
target for a decarbonization strategy. Will it be a technical target e.g., reducing CO2 at
any cost, any time, with any impact on current operations? An economic target e.g.,
CO2 mitigation options with avoidance cost below 200 €/t CO2? Or a policy target
e.g., a 20% reduction of the business-as-usual emissions by 2030. These examples illustrate decarbonization targets from different perspectives, and so the mitigation potential and investment cost required will also be different. The mitigation target will dictate a specific strategy, which, in turn, will result in a particular deployment
16. To design decarbonization pathways, the results on the feasible matching inventory of mitigation options, their interactions constraints and defined decarbonization target are used as follows: select MOs for a time frame by combining options, based on
TRL, pathway’s target (e.g. lower investment, lower CO2 avoidance or higher
mitigation first), and matrix of interactions (as shown in chapter 6 of this thesis). In addition, define a merit order to deploy MOs within the period based on ease of implementation, less layout impact, and lower commissioning time.
17. Calculate the result of the pathway for mitigation potential, total investment and CO2
avoidance cost over time. The time dimension is particularly important for meeting targets, because despite potentially high mitigation potentials on longer term, the cumulative avoided GHG emissions in the selected timeframe may be constrained (and vice versa).
18. Last, assessment of externalities and their implications on the deployment of potential pathways should be included to bring comprehensive insights for decision making and an information base for investment decisions, including identification of key
uncertainties, risks, and R&D priorities. Factors outside the company or industry
might include government regulations (e.g. CO2 emission targets and prices),
availability, carbon-intensity and supply of energy carriers such as biomass, green
electricity and H2, presence of CO2 network and a market for use and storage,
licensing/permits, capital access cost, CO2 price market, exchange rate, rate of the
technology learning curves, among others.
The methodological approach presented in this thesis brings additional insights into the estimation of mitigation potentials in industrial complexes as compared to previous studies
375,376,377,37. This novelty includes combining several and additional aspects such as a
bottom-up assessment, based on data on process unit level of existing oil production facilities and a refinery, a broader portfolio of conventional and innovative technologies, determining decarbonization strategies, investment cost, deployment pathways including combined options, and an interactions assessment of mitigation options.
Results obtained by following this methodological approach can not only provide key input for decision making at a high level in a company, but also at the national policy level to determine a realistic mitigation targets, incorporating factors such as emissions reduction
Research question 3: What is an effective design for a methodological approach to assess
and quantify mitigation options and decarbonization pathways for existing industrial facilities?
This thesis focused on developing an improved methodological approach to assess a comprehensive mitigation potential for a complex industry.
A bottom-up approach was built based on primary data obtained at a process unit level to carry out the analysis of mitigation options and estimate their potential. The level of detail and data used is based on existing facilities and preferably measured data for the entire process-chain from oil production, transport to the refining process of the case study. Previous studies and methods highlighted the challenges on having access to process data from field operations and existing industrial facilities. These challenges remain in the literature, allowing this research to advance beyond previous research in this field. The data considered in this work included information about specific process conditions, product mix, capacity, mass and energy balance, oil feeds properties, cost, age of assets, etc., which allow
for a better understanding of CO2 emission sources and implications of feasible technological
measures to be deployed. Measured data were not always available for this research, especially for those technologies with low TRL (4-7) as is for example the case for bio-oil processing. In this case, a novel approach was used for the identification of bio-oil co-processing pathways based on a qualitative analysis to match the properties of bio-oils with the key restriction parameters in refinery processing units (RU). Based on the insertion points described in literature for bio-oils into the refinery process, this study addressed the lack of conclusive information on the suitability of bio-oils to be co-processed by specific RUs. The consideration of this information into the analysis is also part of the methodology presented in this thesis and underlines the importance of knowing the interactions between real process conditions and requirements to determine a GHG mitigation strategy for an industrial
complex.
Mitigation options were selected based on a very extensive technological inventory throughout the process-value-chain in the industry. This inventory included small-specific
the integration of renewable energy carriers such as biomass co-processing, green hydrogen, and green electricity. This approach enabled the identification of potential improvements and technological alternatives for specific process and the fine-tuning of these options to the specific process. Some options required specific and a novelty work, as a bottom-up
screening of oil fields suitable for a high-level estimation of the CO2-EOR mitigation
potential. This analysis used field data of reservoirs for estimating CO2 storage potential and
suitability of EOR technology deployment for a more realistic estimation of CCS-EOR potential.
Several steps and criteria were used for the identification and analysis of mitigation options in order to elaborate a more specific inventory of potential measures to deploy in the industry. The mitigation options were classified by the time frame to be deployed and the potential impact on the current plant layout.
The complexity of the measures was also classified as an add-on, retrofit, replacement, or a new concept. A first analysis of interactions between mitigation options during deployment (i.e., a decrease in GHG reduction potential, cost synergies, economies of scale, lock-in effect) was carried out to identify and assess a GHG reduction potential and avoidance cost of individual and combined mitigation options. Since all measures are focused on the
improvement of current processing infrastructure, which is part of a technological transition, it is highly important to maintain operational performance and quality of the products. These parameters and steps allowed building a tailor-made proposal of a pathway over time for the industry and adjusted under technical, economic, and policy constraints.
A full value-chain perspective was considered in this work, including oil production, transport and refining, and also integration with external systems value chains such as biomass, hydrogen, and electricity but also internal such as the enhanced oil recovery process.
Biomass options were considered as a complete value chain because of the potential
significant impact on the CO2 mitigation potential of the produced fuels due to biomass
production and land use, conversion process (e.g., extraction, pyrolysis, catalytic pyrolysis), logistics, and the technology used for conversion and co-processing routes in the refinery.
Electricity import must be related to the development and future perspective of the national grid in terms of capacity, renewable share in production matrix, average production cost, reliability, infrastructure development, market price regulation and availability factor. This was done by combining the analysis with state-of-the-art scenario analysis of the Colombian energy system over the coming decades.
A process-chain perspective of CO2 Storage in the oil production fields through EOR is not
usually quantified for a mitigation potential estimation. This value-chain integration includes a matching of sources and sink at the national level, based on a screening of suitable oil field
for CO2-EOR, taking into account location-specific parameters such as heavy oil properties in
the Colombian context, transport by pipeline and production and reservoirs constraints. Integration of external value-chains should consider not only the supply cost and characteristics required of the input, but also some fundamental externalities such as
availability, production sustainability, economic feasibility, scale up option, competition, and barriers of foresight development. Furthermore, if the industry aims for a higher
decarbonization level, it is necessary to optimize the integration with alternative energy sources as part of the transition of the (national) energy system. The interface between the industrial complex and combined analysis with the surrounding energy system is needed since both have different evolution overtime, which has been included in this work to some extent.
Determining the deployment pathways for GHG emission mitigation in the industry should consider the specific targets. From a company perspective, these targets are influenced by strategy on technology development and adoption, capital investment plan, market conditions (in terms of price, properties and environmental performance of products), social
responsibility, and profitability assurance for stakeholders around securing the sustainability of the company's operations. Also, compliances of national policy targets in terms of
environmental performance but also on social and economic impact, especially when the companies are state owned can determine the target.
There is a dynamic CO2 mitigation potential over the time frame considered, and for each
mitigation potential in the short, medium, and long-term. MOs therefore need to be considered in a fully integrated analysis which account for detailed interaction assessment between measures and deployment pathway feasibility over time.
A merit order of MOs for their deployment pathway and potential interaction analysis relies on its life-span, current and future layout of the industrial plant, technical constraints, technological maturity (based on TRL), economic parameters (total investment), retrofitting order, facility unit targeted for mitigation, utilities demand, and how they impact the local and global performance of the process plant.
This methodology, although fully demonstrated for an oil refinery in Colombia, can be applied to a broader set of (carbon-intensive) industries. Future assessments at the industrial-sector level can utilise the various insights from this work to identify and propose
decarbonization strategies to design deployment pathways from a broad inventory of mitigation options.
7.5 FINAL REMARKS AND RECOMMENDATIONS FOR FURTHER RESEARCH
1. Biomass co-processing was identified as a very important potential mitigation option, both on short and longer term. Understanding the availability and competition for biomass in a country remains a key topic, even though Colombia has a high potential for a bio-based economy. This availability should be assessed in terms of biomass yield, sustainable production, cost and efficient logistic supply chain in addition to the
CO2 mitigation potential.
2. Further research should be conducted to assess bottlenecks when implementing mitigation options. Issues to be addressed are: 1) Conflict in strategies policies between government and company level. This can be different for a private or national oil company because the latter are steered by national priorities, 2) Due to sometimes opposite policies, there can be constrained flexibility to test, develop and implement GHG mitigation options over time. This can slow down implementation
and lead to suboptimal results, and 3) Understanding the investment risks induced by changes in economic conditions over time.
3. As shown in this thesis, co-processing biomass and green hydrogen allows for further
and deep CO2 mitigation in the oil industry and supply of liquid fuels. However,
deeper decarbonization is only feasible with a greater switch from fossil to biogenic carbon processing and synfuels production (i.e. using renewable electricity and green hydrogen). Further research should look into the extent at which current refineries complexes can transform under ambitions decarbonization strategies and to what extent they are able to compete with new dedicated facilities to produce these low-carbon or even fossil-free fuels.
4. Further research is required to understand the dynamic interactions between the oil industry transformation under a decarbonizing strategy and the surrounding energy system. This interaction should be analysed by modelling and optimising the interface between the (oil) industry complexes and the energy system. Modelling should target GHG emission reduction, affordability and security of supply simultaneously.
5. Further investigation on testing and scaling-up should be conducted on the selected key co-processing routes. Such research should focus on providing more accurate information on the blending limit, yield, costs, quality of fuels produced, and the effect on infrastructure integrity. Also, their impact on the performance of other refinery processing units and downstream petrochemical processes should be analysed.
6. Insights gained from analysing and identification of deployment routes to achieve
specific targets for CO2 mitigation in the industry should be taken into consideration
in decision-making for defining a portfolio of investment projects including insights in terms of risk, profitability, compliance with policies and liability to shareholders. This requires further research and use of obtained results within company decision-making.
7. Net-export oil countries show different levels of vulnerability to the energy transition. Colombia, in this case, presents relatively low-resilience in terms of average GDP per
capita, and the strong dependency on oil in total national export revenues (which is
today 45% share) 401. Without changes to the energy system, Colombia will change in
the coming decades from being an oil exporter to an importer. This will change the strategic position of the oil industry and create an additional driver to introduce alternatives (and low carbon) energy carriers. In this sense, a strong policy for the energy transition in Colombia is required, which must be based on further research and understanding of utilizing the renewable energy potentials (bio-based, green hydrogen, wind and solar energy) and its socio-economic and sustainable impact in the country.
