Current Status of Enhanced Oil Recovery Projects Using Carbon Dioxide (EOR CO2) in Croatia (2024)

2.1. Global Review of CCUS

Carbon capture, utilization, and storage (CCUS) can play a pivotal role in aiding the EU’s efforts to achieve climate neutrality by 2050. CCUS could be essential for capturing and storing CO₂ emissions from point sources, such as industrial processes and fossil fuel power plants, which are significant contributors to overall emissions. The EU is planning to put forward a CCUS strategy [8] with the following milestones:

CCUS is expected to reduce emissions, especially from ‘hard-to-abate’ industries like the petrochemical industry, waste incineration, cement, and steel production. CCUS will accelerate the decarbonization of the power grid, especially in regions that still rely on fossil fuels. CCUS is also a means to generate negative carbon emissions when coupled with direct air capture for the removal of atmospheric CO₂ and with bioenergy processes.

The Global Status Report on Carbon Capture and Storage identified 41 operational CCUS facilities, with a total installed capacity of 49 Mtpa in 2023 [9]. Currently, there are 26 facilities under construction, with a total combined capacity of 32 Mtpa. Figure 1 shows the development of the total global capture capacity of CCUS facilities for the period from 2010 to 2023. Under various stages of development, there are 325 CCUS projects with a total combined capacity of 300 Mtpa. The following industries are implementing CCUS technology: natural gas processing (34.3 Mtpa), chemical industry (10.7 Mtpa), power generation (1.7 Mtpa), oil refining (1.4 Mtpa), and iron and steel production (0.9 Mtpa). The two most common storage practices are enhanced oil recovery (EOR), with 37.8 Mtpa, and permanent storage in geological formations, with 11.2 Mtpa.

In the past, each CCUS facility included a capture unit, a compression unit, a transport pipeline, and a dedicated storage site. More recently, CCUS facilities with shared transport networks and storage systems are becoming the preferred technological solution in the continuing attempt to reduce costs and increase system flexibility. The CCUS shared networks reduce operational costs through economies of scale. The CCUS Report [8] estimates that 4200 Mtpa of CO₂ could be captured and stored in 160 CCUS hubs established globally with an estimated cost of 85 USD per ton of CO₂. Shared CCUS networks and hubs are expected to become crucial if climate neutrality is to be achieved by 2050.

Among the 41 CCUS facilities worldwide, 21 are operational in the USA and Canada, mostly in the natural gas processing and petrochemical industries. Among these, 17 facilities capture and supply the CO₂ to EOR projects, while only 4 facilities use dedicated geological formations. This comes as no surprise since the USA introduced tax credit incentives for carbon capture in 2008. Under the 45Q tax credit program, each ton of captured CO₂ is incentivized with 85 USD for permanent storage, 60 USD for use in the industry or EOR, 180 USD for DAC and permanent storage, and 130 USD for DAC and utilization. The eligibility to the 45Q program is determined through the minimum annual capture capacity, which is 18,750 tons for power plants with no less than 75% carbon capture efficiency, 1000 tons for DAC units, and 12,500 tons for any other facility.

Over time, CCUS projects have increased in capacity, costs, and technological complexity. The ExxonMobil’s Shute Creek CCUS project started operation in 1986 for an investment cost of 170 million USD and was expanded in 2010 at a cost of 86 million USD. This facility processes raw natural gas from the gas fields in Wyoming (USA) with high contents of sour gases. The gas composition of the inlet gas stream is 65% CO₂, 21% CH₄, 7% N₂, 6% H₂S, and 1% He [10]. The facility uses a single-step cryogenic process that separates CO₂ and H₂S by solidification at low temperatures. The CCUS capacity of the project is 7 Mtpa, and the captured CO₂ is sold and transported to EOR projects. The facility also produces 40 million Sm³ of 99.99% pure helium per year, which represent 20% of the world’s helium production. The Shute Creek project was the world’s largest CCUS facility until it was recently surpassed by the Petrobras Santos Basin project and the Alberta Carbon Trunk Line (ACTL) project.

In 2022, the Petrobras project injected 10.6 Mtpa into offshore oil and gas layers for EOR operations using WAG [11]. The technology involves separating CO₂ from sour natural gas (25% CO₂ content) using polymer membranes and subsequently compressing and reinjecting the CO₂ stream into pre-salt reservoirs beneath the ocean. According to Petrobras, the oil and gas reserves are found in the Southern Atlantic Ocean, off the coast of Brazil, in water depths of around 2200 m, beneath thick sediments and salt layers between 4000 and 6000 m [12,13]. The oil and gas reserves are thus found between 6000 and 8000 m below sea level, making drilling and extraction very challenging.

The ACTL project is a 240 km long CO₂ pipeline operated by Wolf Midstream. The source of CO₂ is industrial emitters: the Sturgeon oil and gas refinery and the Redwater Fertilizer plant. The CO₂ is compressed and transported to aging oil and gas fields for EOR operations. At the moment, the ACTL transports 0.5 Mtpa from the Redwater Fertilizer plant and 1.3 Mtpa from the Sturgeon Refinery, but in the future, it is expected to reach 14.6 Mtpa at full capacity [14]. The ACTL is designed with multiple entry points, which will collect CO₂ from point emitters such as refineries, coal power plants, petrochemical plants, and natural gas processing plants. The project is expected to store 2 billion tons of CO₂ and produce 1 billion barrels of crude oil from CO₂ EOR alone. In Europe, two large CCUS offshore facilities are operating in the North Sea and Norwegian Sea. These two CCUS projects are operated by the Norwegian state-owned company Equinor at the Sleipner and Snøhvit natural gas fields. The two CCUS projects have been operating since 1996 and 2008, respectively, with a combined annual capacity of 1.7 Mtpa and have stored a total of 25 Mt of CO₂ to date. Sleipner is the first large-scale CCUS project in the world. The project motivation was both financial and technical. The natural gas from Sleipner contains 9% CO₂, and it had to be reduced to at least 2.5% in order to satisfy transport and customer needs. On the other hand, being a CCUS project, Sleipner is exempt from paying CO₂ taxes and receives carbon credits from the EU’s Emissions Trading Scheme (EU-ETS). Three years into CCUS operation at the Sleipner site, evidence was found that the CO₂ had migrated from its original injection point to a higher-up layer in the Utsira sandstone formation. Fortunately, this top layer was proven geologically bound, and no further evidence of leakage was found. Shortly after commencing CCUS operations at the Snøhvit gas field, a geological analysis revealed that the storage capacity was much less than previously thought. Emergency drilling and fracturing of the formation was initiated in 2010 to increase the Snøhvit’s capacity. The targeted storage site is also monitored for any possible signs of CO₂ rejection.

The Norwegian experience testifies that each CCUS project has its own specificities, from technical and economic circ*mstances to the storage site properties and behavior over time. This stresses that each CCUS project should be carefully approached to reduce the risk of unforeseen events, and in case of emergencies, contingency plans should be readily available to respond effectively. Scaling up CCUS will become critical for achieving climate mitigation targets. Flexible and feasible CCUS chains should be developed through supportive policies, including tax incentives, fair mechanisms for carbon pricing, stronger interaction between stakeholders in the CCUS chain, raising public awareness, and community engagement.

2.2. Thermodynamic Constraints of CCUS

Assuming a CO₂ capture rate of η = 0.85 and taking that the mole fractions of CO₂ in the inlet streams of DAC, PCC, and oxy-fuel are x = 0.04%, 12%, and 80%, respectively, from (9), the mole fractions of CO₂ in the outlet streams become y = 0.006%, 2%, and 37.5%, respectively. The minimum energy for a CO₂ capture rate of 85% is determined from (4), and it is equal to 462 kJ/kg for DAC, 149 kJ/kg for PCC, and 23 kJ/kg for oxy-fuel. Relative to the energy requirements for an ideal CO₂ capture rate (η = 1.0), a more reasonable capture rate of η = 0.85 reduces the minimum energy requirements by 3.8% for DAC, 10.6% for PCC, and 32.1% for oxy-fuel. Again, this proves that carbon capture from gas streams with higher CO₂ concentrations is more advantageous in terms of energy expenditure.

At present, real-world CCUS technologies achieve second-law efficiencies that are not even close to the thermodynamic minimums. Second-law efficiencies are about 5% for DAC, 14–21% for oxy-fuel combustion, and 19–25% for amine-based PCC [18].

3.1. The EOR Project in Northern Croatia

At present in Croatia, there is one CCUS project using CO₂ for enhanced oil recovery (EOR), which was developed by the oil and gas company INA and started operations in 2014. The CO₂ source is at the natural gas processing plant (NGPP) Molve, serving the gas fields of Molve, Kalinovac, Stari Gradac, Gola, etc., in northern Croatia. The process chart of the CO₂ EOR project is shown in Figure 2. These natural gas fields in northern Croatia contain high volume fractions of CO₂: from 9% in Stari Gradec up to 23.8% in Molve and 53.6% in Gola. The wet sour gas is dehydrated and sweetened in the NGPP Molve. The CO₂ stream is compressed up to 30 bar and transported through an 88 km long and DN500 size pipeline to the compression and liquefaction unit CLU Etan, which is 14 km from the site of the EOR project (Ivanić Grad and Žutica-North). The pressure drop across the pipeline is less than 1 bar. At the CLU Etan, the CO₂ stream is compressed to 90 bar, liquefied, and finally pumped to 200 bar. The liquid CO₂ is distributed to water-alternating-gas (WAG) injection wells and pumped into the oil fields. The injection capacity is 600,000 standard cubic meters of CO₂ per day (Sm³/day), which is equivalent to 0.41 Mtpa.

Between 2014 and 2019, about 300,000 Sm³/day of associated gas was resurfacing from the EOR fields, containing a 40% volume fraction of CO₂. The resurfaced CO₂ (120,000 Sm³/day) represented 20% of the originally injected CO₂ and was vented into the atmosphere [19]. In 2019, the EOR project was upgraded with a recompression unit (CLU Etan), which separates the CO₂ from the associated gas, compresses it, and reinjects it into the EOR fields. The separation of CO₂ from the associated gas is performed in membrane separators and in an amine unit. The total separation capacity is 500,000 Sm³/day of associated gas, which is intentionally oversized to accommodate for possible future upgrades in the EOR project. The membrane separators and the amine unit are each sized at 180,000 Sm³/day of CO₂ (total 360,000 Sm³/day or 0.24 Mtpa). The associated gas is first treated in the membrane separator unit, the principal function of which is to maintain constant CO₂ fraction at the inlet of the amine unit and ensure its optimum operation.

The CO₂-enriched stream is processed in the amine unit, which uses an aqueous solution with the gas sweetening agent methyldiethanolamine (MDEA) to remove sour gases such as CO₂ and H₂S. In the absorber column, the lean amin solution absorbs sour gases at high-pressure and low-temperature conditions (40 bar and 40 °C) in counterflow with the incoming gas stream. Sweetened natural gas exits the absorber column and is further processed, including dehydration, fractionation, and compression, prior to being supplied to transport pipelines. The fractionation includes isolating individual hydrocarbon products, such as ethane, propane, butane, and pentane. The rich amine solution is regenerated in the stripper column at low-pressure and high-temperature conditions (1.5 bar and 120 °C). Wet sour gases from the stripper column are dehydrated and compressed up to 200 bar in a four-stage compression and intercooling process.

Figure 3 shows the pressure–enthalpy charts for the five-stage compression–intercooling process of the primary CO₂ stream and the four-stage compression–intercooling process of the secondary (resurfaced) CO₂ stream implemented for the EOR project in northern Croatia.

The primary CO₂ stream (Figure 3-left) from the NGPP Molve plant is compressed to 30 bar using a three-stage compression (1.5–4.5 bar, 4–12 bar, and 11.5–30 bar); then, it is transported for 88 km to the location of CLU Etan. The pressure drop in the pipeline is less than 1 bar because the DN500 pipeline is oversized, making the CO₂ velocity and flow friction rather low. At the CLU Etan, the primary CO₂ stream is compressed to 90 bar, then converted into a supercritical dense liquid phase and finally pumped to 200 bar and injected into the EOR fields of Žutica and Ivanić-North. The specific compression work is equal to 354 kJ/kg, and the cooling requirement is 602 kJ/kg. Taking that the capacity of the CO₂ primary stream is 600,000 Sm³/day, the compression duty turns out 4.6 MW and the cooling duty 7.8 MW. It was assumed that the CO₂ is cooled to 35 °C in each intercooling stage (C_1out–C_2in, C_2out–C_3in, C_3out–C_4in) except for the liquefaction stage (C_4out–P_5in), which needs to be cooled down to 22 °C. The isentropic efficiency of all compressors and the pump is constant and equal to 0.80.

The secondary CO₂ stream (Figure 3-right), which is obtained by separation from the associated gas, is recompressed in the vapor state until reaching the supercritical conditions necessary for EOR injection. Low-pressure gas compression is performed by screw compressors in two stages, which increase the pressure from 1.5 bar to 6 bar in the first stage and from 6 bar to 26 bar in the second stage. High-pressure compression is performed by reciprocating compressors, which increase the pressure from 26 bar to 70 bar in the first stage and from 70 bar to the final 200 bar in the second stage. The specific recompression work is equal to 387 kJ/kg, and the cooling requirement is 635 kJ/kg. The CO₂ recompression capacity of 360,000 Sm³/day turns into a total compression duty of 3 MW and a cooling duty of 5 MW. CO₂ cooling between compression stages is performed by wet cooling towers.

The other possible pathway for CO₂ recompression would be compressing it up to a pressure either lower or higher than the critical pressure of CO₂ (p_crit = 73.77 bar) and then refrigerating and converting it into the liquid state. In that case, the final compression stage would be performed by a pump rather than a compressor. The CO₂ pump would reduce the compression work, but cooling requirements would increase, and the installation of an additional refrigerating unit would be also necessary [20].

Primary oil recovery at the oil field of Ivanić and Žutica started in 1963 and lasted for 10 years. Between 1965 and 1967, oil production exceeded 2 million barrels of crude oil (bbl) per year, but these numbers were halved after 1971. Subsequently, secondary recovery started in 1973 with water injection, and by 1975, oil production rates went once again above 2 million bbl. After 20 years of secondary recovery, oil production rates fell below 0.5 million bbl and further decreased below 0.2 million bbl in the following 20 years of exploitation. Tertiary recovery with CO₂ EOR started in 2015, and by 2020, oil production rates already increased threefold to above 0.5 million bbl. The oil recovery factor of the primary stage was only 9%, and the secondary stage was able to increase it to around 35%. The CO₂ EOR project is expected to further increase the recovery factor to around 50% [21], as shown in Figure 4.

Over a 5-year period, from October 2014 to October 2019, around 1 billion Sm³/day of CO₂ was injected in the oil fields of Ivanić and Žutica-North. The Ivanić oil field produced 1,579,429 barrels of oil equivalent (boe), and the contribution of the EOR is estimated at 43%. At the Žutica-North field, oil production was 390,136 boe, and the EOR share was 77% [22]. The Žutica-North field achieved better relative results than the Ivanić field because of a higher reservoir pressure at the start of the EOR project. The minimum miscibility pressure of CO₂–oil was estimated at 200 bar, while the reservoir pressure was 190 bar at the Žutica-North site and only 120 bar at the Ivanić site.

During the first few years of the EOR project, the share of CO₂ in the associated gas increased more rapidly than previously expected. As a remedy, a water-alternating-gas (WAG) injection process was implemented, aiming for an improved control of oil mobility and for a reduced problem of viscous fingering. After the success at the Ivanić and Žutica-North oil fields, the EOR project was expanded to the Žutica-South and Šandrovac oil fields, with further expansions being planned in the future.

3.2. Future CCUS Projects in Croatia

New CCUS facilities are expected to enter operation by 2030 in Croatia, with a combined capacity of 1.433 Mtpa of CO₂. Two CCUS projects involve cement plants. The CO₂ntessa project will capture 0.7 Mtpa of CO₂ at the cement plant in Našice after converting the kiln to an oxy-fuel technology [23]. The captured CO₂ will be stored in a deep saline aquifer. The CO₂ntessa project is valued at 400 million EUR and is funded by the EU Innovation Fund. The project will be managed by the NEXE Group, and its main goal is to achieve carbon-neutral cement production by implementing advanced CCUS technology. The project will use pure oxy-fuel combustion, which results in a flue gas composed primarily of water vapor and CO₂. The water vapor can be easily condensed by cooling the flue gases, leaving a stream with a high CO₂ concentration. This ensures that the CO₂ capture is less energy intensive and more cost-effective than CCUS projects involving combustion with regular air. In addition, the combustion chamber is less ventilated, and higher flame temperatures can be achieved with pure oxygen combustion. This improves the thermal efficiency of the combustion process and reduces the fuel consumption. Another advantage is the absence of nitrogen (N₂) in the combustion process, thus avoiding NOx emissions and the need for installing DeNOx systems, which are associated with traditional combustion processes.

Another CCUS project in the cement industry is the KOdeCO project, managed by Holcim Croatia. The goal of this project is to achieve net-zero emissions at the Koromačno cement plant by 2028. The carbon capture capacity of the project is 0.367 Mtpa, and the project is valued at 237 million EUR, with 50% support from the EU Innovation Fund [24]. The core technology involves CCUS, specifically using Air Liquide’s Cryocap FG technology, which captures CO₂ directly from the flue gases generated by clinker production. This technology achieves CO₂ capture rates between 85 and 95% from flue gas streams, with CO₂ volume fractions as low as 15%. The technology combines pressure swing adsorption (PSA) with a condensation process. The benefits of the PSA-assisted CO₂ condensation include enhanced efficiency, energy savings, and applicability to various industries, such as cement production, power generation, and the petrochemical industry. The PSA unit adsorbs CO₂ from a gas stream at high pressures by means of an adsorbent material that selectively captures CO₂. Once the adsorbent is saturated with CO₂, the pressure is rapidly reduced (hence, the “swing” in pressure), causing CO₂ to desorb from the adsorbent. The main function of the PSA unit is to separate flue gases into a CO₂-rich stream and an N₂-rich stream. The CO₂-rich stream is condensed for easier transportation and storage. The liquefied CO₂ will be stored in an offshore geological formation under the Mediterranean Sea. The exact site of the CO₂ storage has not yet been disclosed, but depleted gas fields in the Northern Adriatic Basin are candidate locations. The KOdeCO project will also integrate advanced water treatment and desalination to minimize freshwater usage.

Three other CCUS pilot projects are planned in Croatia. The first pilot project involves upgrading the fertilizer factory of Petrokemija Kutina with CCUS technology. This project will capture CO₂ directly from ammonia production, compress the CO₂, and then inject it underground [25]. The capture capacity is estimated at 0.19 Mtpa; the CO₂ will be transported and injected into the EOR fields of Ivanić Grad. The second pilot project is developed by the oil and gas company INA and involves an advanced bioethanol production plant in Sisak. The plant will produce bioethanol from the giant grass miscantus and will use CCUS to capture the CO₂ at an estimated capacity of 0.055 Mtpa [26,27]. The captured CO₂ will be injected into depleted oil reservoirs, ensuring long-term storage and contributing to carbon neutrality. The third project is a closed carbon geothermal energy (CCGeo) power plant that will produce power and heat with near-zero emissions at the location of Draškovec in northern Croatia. The power plant is valued at 81 million EUR and will have a capacity of 18.6 MW_e in electricity and 60 MWth in heat. The annual energy generation is estimated at 121 GWh of electricity and 137 GWh of thermal energy [28]. The methane dissolved in the geothermal water will be separated using a low-pressure desorption process and burned for running a gas turbine. The CO₂ dissolved in the geothermal water and the CO₂ generated by the gas turbine will be captured and reinjected in the geothermal reservoir. Specific CO₂ emissions from the geothermal power plant are estimated at 1000 kg_CO2/MWh, reflecting the high CO₂ and CH₄ contents in the geothermal fluid [29]. Thus, the annual capture capacity of the Draškovec geothermal power plant would be 0.121 Mtpa. Geothermal waters in the Pannonian Basin are characterized by elevated gas contents, with high fractions of CO₂ and methane. The CO₂ is the result of vertical and horizontal gas migration from carbonate minerals, which are thermally decomposed in the deeper parts of the geothermal reservoirs. The methane originates in a process called bacterial methanogenesis, which occurs at depths between 600 and 1200 m and at temperatures between 40 and 60 °C [30].