Carbon Capture and Storage Subsurface Study for a Natural Gas-Burning Power Plant in Oltenia, Romania

Abstract

The article presents carbon capture and storage, CCS, as a climate change mitigation method. Many industrial processes, such as the manufacture of cement, the metallurgical industry, and the production of electricity from fossil fuels, produce large CO₂ quantities. Carbon capture and storage is a method for these industrial areas to become carbon neutral for the environment. To combat climate change, the EU wants to achieve climate neutrality by 2050, and this goal, along with an intermediate goal of reducing emissions by 55% by 2030, is enshrined in the European Climate Law. The EU has launched various initiatives to achieve these goals, one of which is the ‘Fit for 55’ legislation. The first step that countries wanting to apply these technologies must take is the evaluation of the underground CO₂ storage potential. The potential for CO₂ storage in the depleted hydrocarbon reservoirs in Oltenia, one of the eight regions of Romania, makes it possible to develop safe long-term storage projects for the neighboring power plants currently producing energy from burning coal or hydrocarbons. The results of dynamic simulations of CO₂ storage in one of these geological structures, Bradesti, which hosts depleted hydrocarbon reservoirs, using a numerical simulator are successfully presented for the neighboring Isalnita Power Plant. In this case, the impact on the environment and climate will be minimal and in alignment with the European Union’s long-term objectives. Our study also opens the path for future similar analyses.

1. Introduction

Although the share of renewable energy production is increasing, fossil fuels are expected to continue playing an important role in Europe in the short and medium terms. CO₂ emissions from burning fossil fuels for power generation contribute to approximately 30% at the EU level. Furthermore, process industries such as cement, iron and steel, aluminum, paper, and refineries have inherent CO₂ emissions resulting from the conversion of raw materials. Carbon capture and storage, CCS, technologies aim to capture up to 85–90% of CO₂ emissions from power plants and heavy industry before transporting them through pipelines or ships and storing them permanently and safely at least 800 m below the Earth’s surface. Therefore, CCS has been recognized as an important research and development priority of the European Union to achieve the 2050 climate goals in a cost-effective way. According to the Net Zero Industry Act, by 2030, the imposed commitments must be met for CCS in the oil and gas industry [1].

As per the proposed Net Zero Industry Act, Romania would need to store up to 10 Mt of CO₂ annually by 2050, but unfortunately, the draft national long-term strategy is not ambitious enough, committing up to 2.6 Mt annually [2].

Moreover, in “Romania’s long-term strategy for reducing greenhouse gas emissions–2050 Neutral Romania”, the implementation of carbon capture, utilization, and storage, CCUS, technology is proposed in the non-metallic minerals industry in order to reach the target of at least 50% captured emissions by 2050.

The average energy production of Romania’s National Grid System for 2023 is reflected in

Table 1. Energy mix in 2023 for Romania’s National Energy System.

Conventional Energy Sources	56.93%
coal energy	18.69%
nuclear energy	19.98%
energy from natural gas	17.22%
fuel oil	0.05%
other conventional sources	0.99%
Renewable energy sources	43.07%
hydro energy	26.04%
wind energy	12.75%
biomass energy	1%
solar energy	3.27%
other renewable sources	0.01%

below. Specifically, 56.93% is given by conventional sources and 43.07% by unconventional sources. A significant 36% is outputted by coal and natural gas-burning power plants, which have CO₂ by-products [3].

Out of the total carbon dioxide emissions from Romania, 40% come from the production of electricity, 16% from the manufacture of cement, 12% from the manufacture of ferrous metals, 5% from the production of fertilizers, 5% from the processing of crude oil, and 1% for the manufacture of bricks, plaster, and basic inorganic chemicals [4].

To avoid climate change, the emitted CO₂ needs to be captured and stored. Hydrocarbon reservoirs present many advantages for geological CO₂ storage. These are the presence of surface and ground facilities and equipment that can be adapted for CO₂ storage (usually with some modification), sealing and establishing caprock integrity that have maintained oil in place over geologic time, and the availability of geologic, hydrogeologic, geophysical, and engineering data to characterize the reservoir and other elements of the petroleum system, among others [5,6,7,8].

The relatively low price of the CO₂ Emissions Trading System, ETS, over the past 20 years has led to the slow development of CCS projects that are not just for demonstration and research purposes. CCS projects were initiated and are currently under development and exploitation in the Norwegian Continental Shelf. Such projects are Smeaheia and Sleipner. Since 2018, the ETS price has increased almost constantly, with the CO₂ ETS price reaching a maximum of 95 Euro/tCO₂ on 13 February 2022, making it attractive for CCS projects that must also meet economic returns [4,9,10,11].

According to the study European CO₂ storage database, CO₂ Storage Potential in Europe (2013), the total storage capacity in hydrocarbon deposits in Romania is estimated at 514 Mt CO₂. The split between gas and oil reservoirs is almost equal: 246.78 Mt in oil reservoirs and 267.56 Mt in gas reservoirs [4].

Natural CO₂ reservoirs have safely stored billions of tons of CO₂ for millions of years. They provide an understanding of CO₂ storage processes and represent the input data in the selection process of rock formations for safe storage as part of the full CCS chain. Stored CO₂ is kept safe by physical and chemical processes that increase the security of storage over time. Injected CO₂, held in place by multiple impermeable rock layers, is trapped in isolated traps/deposits, dissolves into fluids in the rock, and can eventually react with the rock to produce new minerals.

Romania has great potential for using CO₂ captured from industrial sources for injection into oil fields to simultaneously increase oil recovery and store CO₂ in the long term. Geological formations that are suitable for safe storage and are marked by a high degree of geological and physical knowledge are widely distributed throughout the country. In the selected locations, it is necessary to evaluate both the opportunities and challenges generated by CO₂ clusters in the economy, as well as social acceptability.

Publicly available data show that there are 29 hydrocarbon reservoirs that can be used to store CO₂ [4,12]. The largest deposit is a gas field near Copșa Mică (Sibiu), with an estimated capacity of 100 Mt CO₂, followed by three deposits, each with an estimated capacity of 50 Mt, located in Ghergheasa (a gas field in Buzau County), Băbeni (an oil field in Vâlcea county), and Bibești-Bulbuceni (an oil field in Gorj county) [12].

Previously, Dumitrache et al. (2023) simulated the greenhouse gas (CO₂) injection through injection wells into adjacent depleted natural gas reservoirs using commercial numerical simulators (CO₂ storage) for one of the most important natural gas (CH₄) plants in Romania (Iernut). In addition to the assessment of the underground storage capacity of CO₂ generated by the combustion of gases in the Iernut gas-fired power plant estimated to be 26.46 Mt CO₂, the CO₂ storage mechanisms in the geological formations reflected in the study were also reviewed [13].

Regarding the storage capacity according to the type of hydrocarbons, namely oil or gas, we can observe the following:

• For gas deposits, the largest CO₂ storage capacities are in Copșa Mică (Sibiu, 100 Mt), Ghergheasa (Buzău, 50 Mt), Târgu Mureș, and Sângeorgiu de Pădure (Mureș, 25 Mt storage capacity) [12].
• For oil deposits, the largest CO₂ storage capacities are in Băbeni (Vâlcea, 50 Mt), Bibești-Bulbuceni (Gorj, 50 Mt), and Târgu Jiu (Gorj, 15 Mt) [12].

Not far from Bibești-Bulbuceni, in the same Oltenia region, there is the Bradesti reservoir structure, which is near the Isalnita Power Plant, both of which were chosen for this study, as shown in Figure 1. In a previous study, Bosa C. et al. (2021) investigated in-depth CO₂-EOR business opportunities in Romania and Turkey on two possible candidate oil fields (the Brădești oil field in Romania and the Bati Raman oil field in Turkey), combining the CO₂-EOR technique with permanent CO₂ storage in an attempt to create a mechanism to produce revenue to support the business case for CO₂ storage [14].

The approximate distance between Isalnita and Bradesti is around 30 km, as shown in Figure 1.

The Ișalnița Power Plant is operated by the Oltenia Energy Complex, which also includes the Turceni, Rovinari, and Craiova II plants, as shown in Figure 1. This energy complex can supply up to 18 Twh to the national energy grid, covering 33% of Romania’s energy demand. This industrial facility is located in Dolj County and was built between 1964 and 1968, with two lignite condensing energy blocks. The installed capacity is 630 MW (2 blocks of 315 MW each). The energy produced since commissioning is approximately 216 TWh.

As for the annual emissions of this power plant, in 2019, it was the fourth largest CO₂ emitter in Romania, with 1.82 MtCO₂, after the Rovinari, Liberty Galați, and Turceni Power Plants, which together had over 11 MtCO₂ at the time.

The existing coal-fired power plant is to be converted to a natural gas combined cycle power plant with a capacity of 850 MW. The deadline for putting the gas plant into operation is 2027.

The new power plant will consist of a gas turbine and a steam turbine. The gas turbine will have a power of about 593 MW, a heat recovery boiler with steam production, without additional combustion, and a stepped steam turbine with a power of about 257 MW [15].

The conversion itself results in much lower CO₂ emissions, as per the comparative analysis of the released CO₂ quantity for the different generated energy types shown in

Table 2. Specific CO₂ emissions according to the primary energy source in Romania [16].

Primary Source of Energy	Specific CO2 Emissions [g/kWh]
Coal	812.87
Natural Gas	382.11
Oil	585.27
Other conventional sources	513.07
Renewable sources	0
Average	223.05

.

As per above, among the fossil fuels used, natural gas has the lowest CO₂ emissions, which gives it an advantage compared to other primary sources of energy based on fossil fuels.

The construction of the gas plant will result in the annual reduction in CO₂ emissions by more than 3 MtCO₂, which represents 10% of the objective of the National Integrated Plan for Energy and Climate Change [15,16].

Our study suggests that the CO₂ released from the converted hydrocarbon gas-burning power plant should be stored underground in the Brădești structure, as shown in Figure 2. Among the arguments in favor of choosing a depleted hydrocarbon reservoir are the following: well-known capacity storage and 3D image from exploration and production data; proven impermeable capacity of the caprock; and possible reusable field and pipeline infrastructure.

2. Geographical and Geological Setting for Bradesti

Bradesti structure is located in Dolj County, approximately 25 km northwest of Craiova City, as shown in Figure 2, in the western part of the Moesian Platform in the Craiova-Optasi Uplift (Figure 3) and represents a typical structure for oil reservoirs specific to a platform unit.

The Moesian Platform is a mature petroleum province and is one of the most prolific petroliferous regions in South-Eastern Europe, with thousands of wells drilled and over 145 oil and gas fields discovered over more than 60 years of exploration. Currently, the Moesian Platform produces approximately 30% of the Romanian production of hydrocarbons, with the important oil and gas deposits belonging to this major province being Caragele, Videle, Cartojani, Ciuresti, Padina, Bradesti, Mamu, and others. The larger thickness of the sedimentary cover of the Moesian Platform offers an exceptional record of the Phanerozoic evolution of the continental margin of the East European plate. Recent oil and gas discoveries made by major operators (OMV-Petrom, Romgaz, Hunt Oil, etc.) in the Moesian Platform, like the Mamu gas field (248 BCF gas reserves) (TD 4300 m) in 2006, West Negreni 1 well (TD 1531 m) in 2011, the Padina North discovery (100–120 MMboe reserves) (TD 2500 m) in 2014, the Caragele gas discovery (25 BCM gas reserves) (TD 3600 m) in 2016, and the 4317 Mamu well (TD 4400 m) (60–70 MMboe reserves) in 2018, show the great oil and gas potential of this large geological unit.

The Moesian Platform contains geological formations belonging to all sedimentary cycles, with various reservoirs of different types and ages, presenting different trap conditions as well as different fluid types. Sedimentary deposits of the Moesian Platform have been widely analyzed, simultaneously with the hydrocarbon exploration activity. The wells drilled in the Bradesti structure have crossed geological formations belonging to the four sedimentary cycles that characterized the evolution of the Moesian Platform: Cambrian-Westphalian, Permian-Triassic, Dogger-Malm, and Badenian-Pleistocene.

The Bradesti structure contains oil and gas deposits in the Triassic, Jurassic, and Sarmatian. The region is covered by Romanian deposits and Quaternary fluvial accumulations. The wells drilled in Bradesti crossed a succession of deposits reaching the Upper Devonian inclusively, which is overlain by the Upper Visean. The Silesian (without the Stephanian) follows after the discontinuity of sedimentation and then the Triassic follows stratigraphic unconformably. Triassic deposits, in turn, are directly overlain by the Sarmatian because of the Miocene erosion; the latter was caused by a paleo valley (The Older Jiu) originating in the Prebalkans and having an outlet in the Precarpathian Miocene Basin. The Sarmatian is followed by the Pliocene. The main geological deposits of the Bradesti structure are deposits accumulated in the Permian-Triassic cycle that have been grouped in three major formations: two predominantly continental to neritic clastic deposits named the Rosiori Formation and Segarcea Formation and one characterized by neritic limestones and dolomites with interbeddings of marlstones and anhydrite named the Alexandria Formation. A typical electric well log of the Triassic deposits recorded for the Bradesti structure is presented in Figure 4, with the continuous left curve representing the spontaneous electric potential, the continuous right curve representing the shallow electrical resistivity, and the discontinuous right curve representing the deep electrical resistivity. Pz—Paleozoic, Triassic (T1a, T1b, T1c—Triassic Inferior subdivisions, T2a, T2b2, T2b3—Mid Triassic subdivisions, and T3a, T3b—Upper Triassic subdivisions), Dogger, and Malm are stratigraphic layers successively deposited.

In the study of the deposition of the Triassic formations in the Bradesti area, it was found that it functioned in a littoral deposition regime, with frequent local regressions and transgressions, a fact that determined the erosion to the point of disappearance of some complexes within the Triassic suite. Also, this littoral depositional regime is responsible for the large lateral variations of facies encountered within the productive layers.

The structural map of the Triassic paleorelief shows the presence of a paleovalley, which separates the two sectors, northern and southern, of the structure. Here, areas where the successive formations of the Triassic were deposited and then eroded are also present, so one can follow the sequence of deposits starting from the oldest ones in the zone of maximum erosion of the aforementioned paleo valley.

From a tectonic point of view, the Bradesti structure is tributary to the existence of two lifted, horst-type areas, at the basement level, which had the effect of forming, at the level of the post-Paleozoic paleo-relief, two tectonic uplifts from the south and the north over which the Triassic deposits were molded. The Triassic deposits mold these uplifts, forming, in turn, a paleo-relief that largely molds the previous tectonic uplifts due to the vertical tilting and differentiated erosion that followed the periods of subaerial emergences (discontinuous on the surface). Also, the very varied thicknesses of the Triassic suite have the effect of remodeling certain surfaces of the structure and creating the post-Triassic paleo-relief pattern. The Jurassic and Cretaceous series arranged discordantly have relatively reduced spreading and show a tendency to equalize the altitudinal variations of the post-Triassic relief. The Badenian suite represents the last term with remarkable discontinuities, which, like the Jurassic-Cretaceous series, tends to preferentially fill areas of the structure. The Sarmatian-Pliocene deposits have a relatively continuous layout and show some folding superimposed on previous tectonic uplifts, being noteworthy alongside drape folds and folds due to differential compaction. From the cross-sections built on the structure, it can be observed that the fault system affecting the basement was reactivated in successive stages affecting the entire sedimentary series up to the Badenian formations; it can be considered that their age, depending on the last reactivation, is post-Badenian, before the onset of Sarmatian-Pliocene sedimentation.

After the discovery of the deposits in 1970, it was found that the deep structure of the Bradesti area is much more complicated than indicated by the seismic image and that the exploration activity raises difficult problems. Interpreting the whole available material, one can conclude that the Triassic molds the Paleozoic structure and is therefore likely implicated in a sealing vaulting, which is crossed by numerous apparently impervious longitudinal and transversal faults. After the deposition of the Middle Triassic, the region uplifted, being subject to denudation. On this occasion, the running waters removed, partially or totally, the Triassic deposits from an important area of the region, reaching the Paleozoic here and there. Later, likely in the Upper Triassic, the negative relief was buried by predominantly lutite deposits constituting lithological barriers within the distribution area of the Lower Red formation and the Triassic carbonatic formation that show reservoir properties. In the Neogene, a new generation of valleys (it is a question of the inheritance of the riverbed direction) sank both in the old riverbed zone and laterally, partially removing the Triassic deposits. The Sarmatian transgression that follow also filled these valleys with lutite deposits forming other impervious barriers. After the northward sinking of the platform margin in the Sarmatian or later, the old hydrodynamic equilibrium was destroyed, determining the redistribution of the hydrocarbons previously accumulated. Thus, the oil and gas migrating laterally from the north impregnated the Lower Triassic sandstones, the Middle Triassic dolomites, the horizon with breccias, and the Upper Triassic limestones, all of them which were situated among the channels sealed with impervious sediments. According to another hypothesis, the Triassic hydrocarbons might have regenerated after the sinking of the region beginning with the Upper Miocene. Moreover, the deposit formed during or after the Sarmatian since the Volhynian marly clays were the protection cover of the Bradesti accumulations.

In the Bradesti structure shown in Figure 4, the layers belonging to the Lower Triassic (T1a, T1b, T1c), the Middle Triassic (T2a, T2b2, T2b3), and the Upper Triassic (T3a, T3b) have proven to be productive. The Lower Triassic consists of red continental deposits represented by ferruginous, gray or reddish-brown clays and siltstones, sands, quartz sandstones, calcareous sandstones and reddish-brown microconglomerates, and rare intercalations of marlstones, limestones, and dolomites. The Middle Triassic, consisting of limestones, marls, calcareous dolomites and dolomitic limestones, anhydrite intercalations, clays and sandstones with anhydrite, and dolomite cement, is placed transgressively and discordantly over the Lower Triassic. The Upper Triassic consists of reddish-brown deposits represented by clays, siltstones, marls, sands, sandstones, and microconglomerates, with intercalations of limestone, gypsum, anhydrite, and, rarely, salt.

Based on the geophysical and geological information as well as the production data, it was found that in the Bradesti structure, there are 17 hydrodynamic units for crude oil (with or without a primary gas cap) and 17 hydrodynamic units for gas.

3. Materials and Methods

The main material of our work was a subsurface model, which was fed into numerical simulation—the method used to assess the CO₂ injectivity and total injected quantities. In this chapter, we describe how this model was built and simulated from the beginning of exploitation until 1 January 2027, with the time frame representing the initial hydrocarbon production stage. In the next chapter, the CO₂ injection and storage assessment simulations are presented. The numerical simulator used was an industry-renowned compositional simulator, Eclipse, which is a professional reservoir simulation software used primarily for mathematical modeling and numerical simulation of multiphase fluid flow, including oil, gas, and water, in subsurface reservoirs. The Eclipse stack has a compositional simulator with a cubic equation of state, a pressure-dependent K-value, and black oil fluid treatments. The input parameters for the simulator were porosity, permeabilities, fluid properties, multiphase flow properties, and capillary pressures, among others such as well locations, etc. [19].

Block D2, a Triassic structural, stratigraphic, paleogeomorphic trapped reservoir belonging to the Brădești structure, as shown in Figure 5, was chosen as the preferred storage reservoir from the vicinity of the Ișalnița Power Plant. Figure 5 depicts the isobaths map for the top reservoir with the well locations and names, which are, in this case, numbers, e.g., 2274, 3014, etc. Moreover, the green arrows in the image represent the True North direction. The three Triassic subdivisions are saturated hydrocarbon (oil with primary gas cap) at depths of 2200–2500 m. The surface area of this reservoir is approximately 143 ha with a gross hydrocarbon thickness ranging between 8.7 and 43 m. Reservoir porosity ranges between 0.027 and 0.28 with a permeability range of 0.1 to 1581 mD. The initial water saturation ranges between 0.182 and 0.49. The initial reservoir pressure was measured between 210 and 245 bars. Oil viscosity is very low ranging from 0.1 to 0.21 cP. The oil density varies between 820 and 860 kg/m³. The reservoir waters are of chloro-calcic type with mineralizations of 50–70 g/L. The geothermal gradient is within normal limits (33.6 m/DegC) [18].

A compositional fluid model is defined using the Peng Robinson Equation of State with the composition depicted in

Table 3. Subsurface model hydrocarbon composition.

Name	Molecular Weight	Mole %
CO2	44.01	1
N2	28.013	1.5
C1	16.043	60
C2	30.07	8
C3	44.097	6
C4 − 6	66.869	13.5
C7 + 1	107.76	7.2
C7 + 2	198.52	2.3
C7 + 3	335.11	0.5

and the phase envelope shown in Figure 6.

This subsurface static model was further complemented with relative permeabilities, as shown in Figure 7, and rock compaction functions.

The gas–oil contact was defined at 2160 m and the oil–water contact at 2220 m, as shown in Figure 8. This figure also reflects the ternary saturation distribution in 3D after the model was initialized in the dynamic reservoir simulator. Cells in red are cells occupied by gas, cells in green are cells occupied by oil, and cells in blue are cells occupied by water.

The dynamic simulation model was then produced with the oil wells being flown at the beginning, 1 January 1980, until they were invaded by the gas in the gas cap. At this stage, 1 January 1990, new production wells were drilled to exploit the gas from the full model until the end of exploitation, 1 January 2027. In total, there are 23 production wells considered in the model. The field dynamic behavior is reflected in Figure 9. The green curve depicts the simulated oil production rate, and the red curve shows the simulated gas production rate in time.

The reservoir pressure resulting from the simulation at the end of exploitation is approximately 50 bars, as can be noted by the field pressure variation with time on the brown curve.

There was no significant water produced by this field as can be seen in the lower-right part of the chart with the continuous blue line. To show this, the same Y-axis dimension was kept as that for the oil production rate.

Figure 10 shows the ternary saturation distribution in 3D at the end of exploitation. The color explanation given for Figure 8 also stands for this figure. One can notice that the oil phase leg was minimized significantly to almost 0.

4. Results

As mentioned in the introduction section, it is estimated that the Isalnita Power Plant may produce energy at a capacity of 593 MW from gas burning. Considering that it will be functioning throughout the year, the resulting total energy production is 5,194,680 MWh. However, this will not be the case. Most likely, the power plant will step in to supply energy when required by Romania’s National Electric Grid. We can consider half of the original production, 2,597,340 MWh as the On-Stream Factor for the plant, as a reasonable estimate of Isalnita’s yearly energy production due to natural gas only.

The operation of the upgraded power plant will follow the BAT requirements regarding the greenhouse emissions for combustion installations. As per these requirements, the CO₂-specific emissions have a value of 0.360 (tCO₂/MWh product) [20].

A resulting hypothetic CO₂ yearly production of 935,042 tCO₂ is calculated for the Isalnita Power Plant. The daily volumetric flow rate at the standard conditions of the CO₂ produced by Isalnita Power Plant will be 1,367,730 sm³/d.

Considering that in the vicinity of Isalnita there are other coal-burning power plants, such as Turceni, Rovinari, and Craiova II plants, all operated by the Oltenia Energy Complex, the above daily rate of 1,367,730 sm³/d will be further used as a maximum injection target for the group wells present in the field. This scenario is labeled as the maximum injection scenario.

It considers that all wells available for production are also available for injection—23 in total.

The results of this simulation are reflected in Figure 11. The continuous curves, with the exception of the cumulative oil production, which is depicted with a dashed curve for differentiation, represent the hydrocarbon exploitation stage. The dashed curves represent the CO₂ injection stage. The CO₂ injection rate in this case plateaued at 1,367,730 sm³/d. The red color is used for the gas production/injection flow rates. The CO₂ injection rate in this case plateaued at 1,367,730 sm³/d. The brown color is used for the field pressure. The CO₂ injection is stopped when the field pressure reaches the same value as the initial reservoir pressure. This value is approximately 243 bar, with a field pressure of 50 bar at the end of the hydrocarbon exploitation stage on 1 January 2027.

For this scenario, the end of the injection pressure limit is reached in July 2050. The purple color is used for gas production/injection cumulatives. The green curves are used for the field oil production rate and oil production cumulative. The simulated Bradesti oil production cumulative at the end of the exploitation stage is around 830,000 sm³.

Moreover, most likely, the Isalnita plant will supply power to the grid whenever required by national demand, hence the calculated daily injection volumetric flow rate may be overestimated and an additional scenario with a lower injection rate should also be accounted for and simulated. This lower rate is taken at 75% of the daily volumetric flow rate of the produced CO₂, at approximately 1,000,000 sm³/d. This scenario is labeled as a realistic scenario and its simulation results are presented in Figure 12. The continuous curves, with the exception of the cumulative oil production, which is depicted with a dashed curve for differentiation, represent the hydrocarbon exploitation stage. The dotted curves represent the CO₂ injection stage. The previous color explanation given for Figure 11 also stands for this plot. The CO₂ injection rate in this case plateaued at 1,000,000 sm³/d.

Figure 13 presents the comparative analysis of the two scenarios above, where InjExp is short for the expected simulation case injection scenario with a 1,000,000 sm³/d CO₂ injection rate, while InjMax is short for the maximum injection scenario simulation case with a 1,367,730 sm³/d CO₂ injection rate.

Converting the total injection cumulative volume to mass, the total CO₂ mass injected in the expected and maximum scenarios is 20.603 MtCO₂.

5. Discussion

Nowadays, modern societies must move toward an inclusive energy transition path that is achieved, on one hand, by reducing energy poverty, and on the other hand, by controlling the impact of energy production and consumption on the environment through carbon emission.

Energy poverty is a dynamic and complex phenomenon with peculiarities depending on the geographic location and level of development of each country and has been discussed at large in the past [21].

Carbon capture, utilization, and storage is considered an impactful methodology for industries and geographies to diminish global climate change. Underground storage of carbon dioxide in geological formations with existing infrastructure from a previous hydrocarbon exploitation stage makes the methodology very attractive since a wealth of investigations, equipment, and locations sites are already available for these developed fields. The investigations vary from acquired and interpreted seismic data, well wireline and slick line logs, complex PVT analysis for the original hydrocarbon and reservoir water, core data and complex mineralogical analysis, and measured production data.

At this stage, based on the above, one can say that the reservoir considered for CO₂ injection is well known in terms of areal and vertical extensions, original and present hydrocarbons in place, and initial and present reservoir pressures.

The already present equipment in these fields are wells, pipeline systems, gathering centers, manifolds, and surface facilities. Wells, even though some were abandoned, can be reentered and re-equipped for the CO₂ injection requirements. These operations will be significantly less costly than drilling injection wells from scratch for CO₂ injection in an underground saline aquifer, for example. Moreover, the same case is in place for surface facility locations and laid-out pipelines.

If these mature and depleted hydrocarbon reservoirs are located in the vicinity of significant CO₂ emitters such as coal or hydrocarbon-burning power plants, cement generation plants, fertilizers plants, etc., then they are perfect candidates for carbon capture, utilization, and storage projects, such is the case of the Bradesti reservoir and the Isalnita Power Plant.

Romania has significant potential to store CO₂ both in deep saline aquifers and depleted oil and gas reservoirs. Geological formations suitable for safe CO₂ storage are widely distributed in all major geological units, either platform or orogenic units.

Several broad conceptual studies regarding the potential of CO₂ storage/sequestration in depleted oil and gas fields were prepared in Romania in the recent past. Hence, most of them assessed the potential of CO₂ storage/sequestration at the level of major geological basins. In the Transylvanian Basin, the evaluation of depleted gas fields generated a total CO₂ storage capacity of approximately 2.30 Gt. Additionally, the potential of CO₂ sequestration was assessed on several oil and gas fields in South Romania belonging to the Getic Basin (Bradu-Albota, Silistea, Babeni, Balteni, Bibesti, and Bulbuceni), the Moesian Platform (Samnic-Ghercesti, Plopu, Oprisenesti, Bordei Verde Est, Liscoteanca, Jugureanu-Odaieni, etc.), or the Pannonian Basin (Turnu, Satchinez, Calacea) [22].

As a step forward, our study focused on the Bradesti hydrocarbon field as a CO₂ injection site from the Moesian Platform for the neighboring Isalnita Power Plant and possibly other plants operated by the Oltenia Energy Complex in the context of carbon dioxide capture and storage (CCS) as a necessary requirement for high-emitting CO₂ industries to significantly reduce volumes of greenhouse gases released into the atmosphere and mitigate climate change [23].

The existing acquired data and infrastructure on the identified neighboring reservoirs significantly lower the uncertainty associated with the investments required for the underground storage project.

As a recommendation for further analysis, detailed reporting and insight into each of the CO₂ storage mechanisms in geological formations can be assessed. These mechanisms are physical storage through stratigraphic and structural trapping (1), hydrodynamic trapping through residual CO₂ bound at a molecular level (2), and geochemical storage through solubility and chemical reaction trapping (3), which can lead to modifications in permeability and rock mechanical properties [24].

As a further recommendation, a subsurface uncertainty study can be performed to assess the impact of varying the subsurface uncertain parameters on the total stored quantity of CO₂ [25].

6. Conclusions

In our study using reservoir simulation, we presented an assessment of how the CO₂ released from the Isalnita gas-burning power plant in Oltenia, Romania, can be successfully captured and disposed of through injection wells for underground storage in the existing neighboring Triassic hydrocarbon sedimentary reservoirs of the Bradesti field from the Moesian Platform.

As per our findings, the total CO₂ quantity that will be stored via this proposed carbon capture and sequestration study in Isalnita’s surrounding Bradesti depleted hydrocarbon reservoir is approximately 20.603 MtCO₂ within a time span of 31 years for the expected scenario and 23 years for the maximum injection scenario.

Previous local studies have looked into the analysis of carbon capture utilization and storage in underground reservoirs, either with saline aquifers or depleted hydrocarbon reservoirs located in Romania; however, none of them assessed using depleted oil and gas reservoirs from the vicinity of the Isalnita Power Plant for this process, i.e., Triassic Reservoirs from the Bradesti structure located in the Moesian Platform.

Hence, our work is yet another step forward for the energy generated using fossil fuels at the Isalnita Power Plant or other plants operated by the Oltenia Energy Complex to be considered clean energy. Hence, the impact on the environment and climate will be minimal and in alignment with the European Union’s long-term objectives. Our study opens the path for future similar analyses.

The potential for CO₂ storage in the depleted hydrocarbon reservoirs in the Oltenia Region, Romania, makes it possible to develop safe long-term storage projects for the neighboring power plants currently producing energy from burning coal or, in the future, from hydrocarbons.