Core Flooding Experiments on the Impact of CO₂-EOR on the Petrophysical Properties and Oil Recovery Parameters of Reservoir Sandstones in Kazakhstan

Abstract

This study investigates the impact of CO₂-enhanced oil recovery (CO₂-EOR) on the petrophysical properties and oil recovery potential of sandstone reservoirs in the oilfields located in the east-southern Precaspian region of Kazakhstan. Despite the recognized potential of CO₂-EOR for improving oil recovery and aiding carbon sequestration, there is limited understanding of how CO₂-EOR specifically affects the petrophysical properties of sandstone reservoirs in this region. Laboratory experiments were conducted using two core samples from the selected oilfields to examine changes in porosity, permeability, and oil recovery coefficients. The results demonstrated that porosity changes ranged from a slight increase of 1.1% to a decrease of 1.5%, while permeability reduction was significant, with decreases ranging from 29% to 50% due to clay alteration and halite precipitation. The oil recovery coefficient after CO₂ flooding was found to be between 0.49 and 0.54. These findings underscore the complex interactions between CO₂ and reservoir rocks, emphasizing the need for tailored EOR strategies in different geological settings.

1. Introduction

Greenhouse gases, CO₂ in particular, are considered as the main cause of climate change and global warming. They significantly influence regional climates, health, agriculture, water resources, and ecosystems. According to the Intergovernmental Panel on Climate Change [1], global temperatures could rise between 1.5 °C and 4.5 °C by 2100. The rapid warming of polar regions, especially the Arctic, which is heating four times faster than the rest of the planet, is a major concern. This warming reduces critical ice habitats and disrupts weather patterns, leading to more extreme and unpredictable weather globally. Higher temperatures increase evaporation, intensifying droughts, and can lead to heavier precipitation and stronger storms. The Clausius–Clapeyron equation explains that each 1 °C rise in temperature increases the air’s moisture capacity by 7%, which can enhance storm intensity [2]. Additionally, GHGs degrade air quality, exacerbating respiratory and cardiovascular diseases. For instance, ground-level ozone, formed from CO₂ and CH₄, causes respiratory issues. In agriculture, climate change alters temperature and precipitation patterns, reducing crop yields and shortening growing seasons [3]. Water resources are also affected, with shifts in precipitation patterns leading to more frequent and intense droughts and floods, impacting water supply and quality [4]. In water-scarce regions like Central Asia, the decrease in soil moisture is closely linked to variations in regional precipitation and temperature-driven evapotranspiration [5]. According to the United Nations Sustainable Development Goals (UN SDGs) Report [6], energy-related CO₂ emissions increased by 6% in 2021 worldwide. In Kazakhstan, greenhouse gases (GHGs) lead to an excess concentration of suspended particles (NO₂, SO₂, and O₃) in the air [7]. Their concentration exceeds the limits set by the World Health Organization in 18 out of 21 cities and likely is linked to the increased mortality rates across the country.

The use of carbon capture, utilization, and storage (CCUS) might play a significant role in helping Kazakhstan achieve its carbon reduction targets. As oil production declines, Kazakhstan is exploring the development of CO₂-enhanced oil recovery (EOR) techniques in its oil fields as a strategy to reduce carbon emissions and boost oil output simultaneously [8,9,10]. The IEA reports [11,12] that Kazakhstan possesses 3226 million metric barrels of oil that can be technically recovered using CO₂-enhanced oil recovery methods, with the potential to store up to 1.1 gigatons of CO₂.

CO₂-EOR is particularly significant as it also has the potential for carbon sequestration, contributing to greenhouse gas mitigation efforts. This CO₂-EOR process is divided into two main categories: miscible CO₂ displacement, where CO₂ mixes completely with the oil, and immiscible CO₂ displacement, where it does not [13,14]. Several factors impact the efficiency of CO₂ in displacing crude oil, such as the pressure and temperature of the reservoir, the composition of the crude oil, the phase behavior of the CO₂-oil mix, and the rock heterogeneity [15,16,17,18]. When the reservoir pressure exceeds the minimum miscibility pressure (MMP), making the injected CO₂ and the remaining oil miscible, the barrier created by interfacial tension effectively vanishes. This results in the enhanced transfer (extraction/vaporization) of light to intermediate hydrocarbons, thereby diminishing the saturation of residual immobile oil. Moreover, the expansion or swelling of the CO₂-enriched oil phase improves its mobility. Enhancements in mass transfer are observed with higher pressures, cooler reservoir temperatures, and lighter oil. Additionally, lowering the viscosity of mobile oil and increasing pressure can further reduce oil saturation [19]. CO₂ trapping during the CO₂-EOR process happens through various mechanisms, including physical barriers, dissolution in formation fluids, residual saturation trapping, and mineralization within the rock pores [20,21,22,23,24,25,26]. Mineralization, in particular, plays a crucial role in the long-term storage and sequestration of CO₂. Several types of mineralization processes contribute to CO₂ storage: (1) Carbonate mineralization: CO₂ reacts with calcium, magnesium, and iron-bearing minerals to form stable carbonate minerals. The process not only traps CO₂ but also contributes to the permeability reduction by filling the pores with these newly formed minerals. (2) Silicate mineralization: silicate minerals react with CO₂ to form carbonate minerals and silica. This type of mineralization is typically slower than carbonate mineralization but can significantly contribute to long-term CO₂ sequestration. (3) Clay mineral alteration: CO₂ can cause the alteration of clay minerals, resulting in the formation of new minerals that trap CO₂. (4) Precipitation of salts: the injection of CO₂ can lead to changes in the chemical equilibrium of formation waters, causing the precipitation of salts such as halite. This process is primarily associated with permeability reduction.

Various preparatory tasks must be undertaken before initiating a field-scale CO₂-enhanced oil recovery (EOR) operation. These include preliminary experimental investigations to estimate the potential oil recovery and to assess potential issues such as mineral deposition, asphaltene precipitation, and other related problems.

Experiments investigating CO₂ injection and its behavior have been carried out using core flooding equipment [27]. A typical core flooding apparatus includes a core holder and tanks for water, oil, CO₂, and other liquids, depending on the experiment. The diversity in experimental designs enables the testing of various CO₂-EOR technologies, such as Water Alternating Gas (WAG) and CO₂ foam injection, allowing researchers to identify the most suitable technology for specific oil field conditions.

These experiments aim to (1) assess the injection potential and storage capacity of subsurface geological formations at a field scale; (2) track the movement of CO₂ plumes in laboratory experiments; (3) evaluate the petrophysical parameters and their variations under multiphase flow conditions; (4) explore the impact of supercritical CO₂ dissolution on fluid displacement and imbibition processes; (5) observe the behavior and rate of CO₂ mass transfer; (6) analyze the effects of different CO₂ concentrations in injected water on dissolution and displacement processes; and (7) study the impact of chemical reactions and mineral alteration on the efficiency of CO₂ flooding [28,29,30,31,32,33,34,35,36].

In general, the effect of CO₂ injection on oil recovery is influenced by several factors, including the mineral composition of the rock, oil composition, and temperature and pressure conditions. Consequently, results can vary significantly depending on specific oil field conditions. Thus, porosity increase was observed in Latrobe shales due to K-feldspar dissolution [37]. On the other hand, the precipitation of $Ca{\left(HC{O}_3\right)}_2$ and $NaCl$ leads to porosity and permeability reduction in Midyat carbonates [38]. A decrease in permeability also was observed in Indiana limestones due to asphaltene precipitation and mineral precipitation [39]. Authors in [40] showed the significance of pore structure and pressure dependence of the oil recovery in tight sandstones. Clays within sandstone formations play a crucial role in CO₂-enhanced gas recovery and the adsorption of CO₂ in exhausted gas reservoirs [41]. The distribution of minerals on the sandstone surface, along with its heterogeneity, governs the adsorption of CO₂.

As can be seen, the complex composition of reservoirs and their interactions with reservoir fluids and CO₂ can lead to unexpected results that cannot be predicted based on previous studies of different reservoirs. The feasibility of CO₂ sequestration in Kazakhstan [9] ranked the Precaspian basin as the top candidate. However, the analytical nature of the study required further experimental verifications. The current study in turn stands as a pioneering laboratory effort in the investigation of the CO₂-EOR method using core samples sourced from two oilfields in the Precaspian basin in Kazakhstan. This study investigates the changes in reservoir properties of core samples from these oilfields caused during CO₂-EOR experiments, aiming to conduct a preliminary assessment of the process at a laboratory scale.

2. Materials and Methods

2.1. Geological Settings

The two candidate fields selected in this study are the Dos and Akk oilfields situated in the east-southern part of the Precapsian region (Figure 1). The region is mostly known for Paleozoic oilfields; however, Mesozoic sediments have also been known for hosting oil and gas fields for more than a century. The strata of the region is associated with pre-salt and post-salt reservoir rocks with a Kungurian salt layer separating them (Figure 2) with a thickness of up to 3 km.

The selected Dos and Akk oilfields are found within post-salt layers and both reservoirs are hosted in Jurassic rocks. Jurassic, Cretaceous, and Paleogene-Neogene layers are composed of terrigenous and carbonate rocks in different combinations [43].

Middle Jurassic deposits of the Dos field are composed of gray coarse- and fine-grained sandstones [44,45], with isolated interlayers of clay and coal. Jurassic deposits of Akk are composed of sandstones of various grain sizes, from fine-grained to coarse-grained, siltstones, clays, mudstones, coals, and their interlayering [46].

2.2. Materials and Sample Preparation/Characterization

2.2.1. Core Samples

Two sandstone core samples were selected for this study, one from each field (

Table 1. Petrophysical properties of the core samples before the CO₂ flooding.

	Oilfield	Depth, m	Porosity before the Experiment, %	Permeability before the Experiment, mD
Sample #1	Dos	2171.43	24.6	348.8
Sample #2	Akk	1904.61	23.7	233.3

). The samples were cleaned using a Soxhlet extractor with organic solvents for rinsing. An alcohol-benzene mixture was used as the solvent. After thorough cleaning, all samples were dried in a drying oven (DKN 600) at a temperature of 60 °C to a constant weight. After obtaining the basic parameters of volume and weight, the samples were placed in a glass desiccator to reduce the adsorption of atmospheric moisture. A calibrated helium porosimeter (ULTRA-PORE 300) and nitrogen permeameter (ULTRA-PERM 600) were used to measure the porosity and permeability of the core samples, respectively. Table 1 shows the initial petrophysical properties of the core samples before flooding, clearly indicating that the chosen samples have a similar porosity, but sample #1 has higher permeability.

Additionally, a thin disk, approximately 5 mm thick, was sliced from the center of each core sample. This disk was examined with SEM (Scanning Electron Microscopy) before and after the flooding experiments to identify any changes in microstructure the samples may have experienced as a result of the flooding process. The ends of the disks were polished to ensure the production of high-quality SEM images. X-ray diffraction (XRD) analyses were conducted on both samples to ascertain their precise mineral composition and concentrations.

2.2.2. Oil and Brine Used for Core Flooding

Two types of oil from each oilfield were used in the experiments. The properties and composition of each oil type are shown in

Table 2. Component composition of oil gas, degassed, and reservoir oil (mole content, %) for sample #1.

Item	One-Stage Degassing under Standard Conditions		Reservoir Oil
	Released Gas	Oil
H2S	0	0	0
CO2	0.8	0	0.1
N2+rare	3.8	0	0.89
Methane	41.4	0	12.99
Ethane	10.8	0.01	2.96
Propane	18.9	0.71	5.3
Iso-butane	6.8	0.53	2.19
n-butane	9.6	1.39	3.43
Iso-pentane	8.1	2.15	1.84
n-pentane	0	2.68	1.83
Hexane	0	7.6	3.28
Heptane	0	10.62	4.08
C8+	0	74.67	61.04
The molecular weight	32.9	255.9	-

and

Table 3. Component composition of oil gas, degassed, and reservoir oil (mole content, %) for sample #2.

Item	One-Stage Degassing under Standard Conditions		Reservoir Oil
	Released Gas	Oil
H2S	0	0	0
CO2	0.2	0	0.2
N2+rare	2.8	0	0.7
Methane	0	0	0
Ethane	49.6	0	12
Propane	8.1	0	2
Iso-butane	13.5	0.59	3.7
n-butane	5.3	0.69	1.8
Iso-pentane	10.1	2.13	4.1
n-pentane	10	2.35	2.8
Hexane	0	2.86	3
Heptane	0	5.87	4.9
C8+	0	10.49	8.1
H2S	0	75.02	56.9
The molecular weight	34	209.75	-

.

Table 4. Composition of the brine.

Minerals	Content, g/L
NaHCO3	0.289
Na2SO3	1.065
MgCl2*6H2O	15.475
CaCl2	14.898
NaCl	196.953

shows the composition of the brine used in the experiments.

2.3. Minimum Miscible Pressure Estimation

Minimum miscibility pressure values were determined for each core sample, taking into account the specific oil composition of each oilfield.

Three different empirical correlations were used to estimate MMP adopted from the studies by Cronquist [47]; Li, Qin, and Yang [48]; and [49], respectively:

$$MMP=0.11027·T^{\left(0.744206+0.0011038·M_{C5+}\right)}$$

(1)

$$MMP=7.30991\times {10}^{-5}{\left[\ln \left(1.8T+32\right)\right]}^{5.33647}·{\left[\ln \left(M_{C7+}\right)\right]}^{2.08836}·{\left(1+\frac{m_{vol}}{m_{int}}\right)}^{0.201658}$$

(2)

$$MMP=0.101386e^{\left(10.91-\frac{2015}{255.372+0.5556\left(1.8T+32\right)}\right)}$$

(3)

where $T$ is reservoir temperature in °C, $M_{C5+}$ is the molecular weight of the C5+ fraction, $M_{C7+}$ is the molecular weight of the C7+ fraction, $m_{vol}$ is the mole fraction of volatile components including N₂ and CH₄, and $m_{int}$ is the mole fraction of intermediate components including CO₂, H₂S, and C2–C4.

Table 5. The estimated MMP values.

	Cronquist, 1978 [47]	Orr and Jensen, 1984 [49]	Li, Qin, and Yang, 2012 [48]	Average Estimated MMP
Sample #1	20.74	16	15	17.25
Sample #2	14.24	14.3	13	13.85

shows the estimated MMP values for samples #1 and #2. The average estimated MMP values are less than the corresponding reservoir pressures for both samples, thus, CO₂ injection can be conducted under reservoir conditions to have miscible displacement.

2.4. Core Flooding Setup and Procedure

Figure 3 shows a schematic representation of the core flooding setup used in this study. This equipment is engineered to accommodate experiments at pressures up to 100 MPa and temperatures up to 200 °C. The core holder, fluid accumulators, and the flow lines that transport the fluids are all housed within a convection oven to maintain a steady temperature throughout the experiments. The core flooding experiments were conducted under reservoir conditions. The specific values for temperature and confining pressure are provided in

Table 6. Experiment conditions.

Parameter	Sample #1	Sample #2
Temperature, °C	72	65
Confining pressure, MPa	22	20

.

The sequence of the experiment was as follows:

• The sample was placed in a core holder and the confining pressure was increased to the set value, then brine was pumped into the sample under the determined pressure and temperature.
• Next, oil was pumped into the core sample at reservoir pressure and temperature until no water came out. After this, the system was in standby mode for 24 h.
• CO₂ was injected under the reservoir pressure at a constant rate. The volume of the displaced liquid was measured.

3. Results and Discussion

3.1. Core Samples’ Characterization before CO₂ Flooding

Core sample #1 is a fine-grained, silty sandstone with clay cement and a homogeneous texture. The detrital component predominantly consists of quartz grains, with a lesser amount of feldspar and mica fragments ranging from angular to sub-rounded shapes, with linear and point contacts between grains. The cement is primarily represented by clay minerals of the kaolinite group (Al₄[Si₄O₁₀](OH)₈) and illite group (K_1-1.5Al₄[Si_7-6.5Al_1-1.5O₂₀](OH)₄), with weak crystallization, appearing as massive clusters of irregularly shaped scaly plates filling the pore space.

Core sample #2 is a fine-grained, polymictic gray sandstone with clay cement and a homogeneous texture. The detrital component mainly consists of quartz grains, with a substantial amount of feldspar and mica fragments. Quartz sometimes exhibits a microquartzite texture. Feldspar fragments are subject to processes of dissolution. The cement is a mix of clay and carbonate. The clay cement is represented by the illite group clays and smectites ((1/2 Ca, Na)_0.7(Al, Mg, Fe)₄(Si, Al)₈O₂0₄*n H₂O). The carbonate cement is represented by crystalline calcite.

Table 7. Composition of core samples.

Mineral	Sample #1	Sample #2
Quartz	70	59
Albite	19	33
Kaolinite	5	-
Illite	6	1
Smectite	-	1
Calcite	-	7

shows the composition of the samples before the experiment.

3.2. Core Samples’ Characterization after CO₂ Flooding

Table 8. Outcomes of the flooding experiments.

	Porosity after the Experiment, %	Permeability after the Experiment, mD	Oil Recovery Coefficient (CO2 Flooding)
Sample #1	25.7	247	0.49
Sample #2	22.2	116.6	0.54

compiles the outcomes of the flooding experiments in terms of porosity and permeability changes after the experiment and oil recovery coefficient.

As can be seen from Table 8, after the CO₂ flooding, a slight increase in porosity (from 24.6% to 25.7%) and a larger reduction in permeability (from 348.8 mD to 247 mD) were observed for sample #1. On the other hand, a small drop in porosity (from 23.7% to 22.2%) and a substantial reduction in permeability were observed for sample #2 after the experiment. The oil recovery coefficient after CO₂ flooding in this study was 0.49 and 0.54 for sample #1 and sample #2, respectively.

Figure 4 shows SEM images of sample #1 before and after the experiment. It can be seen that most pores were clogged. The higher-magnification images of the particle surface and pore space and the corresponding EDS graphs are shown in Figure 5 and Figure 6. The results show that kaolinite dissolution takes place on the particle surface and more clay forms the pore space.

Figure 7 shows SEM images of sample #2 before and after the experiment. Similarly to sample #1, one can see a clogging of the pore space. However, unlike in sample #1, halite (NaCl) precipitation covered the particle surface of sample #2, as shown in Figure 7d. EDS graphs in Figure 8 and Figure 9 confirm the presence of sodium chloride on the particle surface and only clay formation in pore space.

Permeability reduction in both samples can be attributed to clay alteration and halite precipitation as a result of the chemical reaction between CO₂ and rock minerals (Figure 10). The mineralogical changes observed can be attributed to the formation of carbonic acid (H₂CO₃). As K-feldspar dissolves, kaolinite is produced and silica is liberated, following this reaction [37]:

$$2KAlS{i}_3{O}_8+2H^{+}+H_{2}0\to A{l}_{2}S{i}_2{O}_5{\left(OH\right)}_4+4Si{O}_{2\left(aq.\right)}+2K^{+}$$

Thus, more clay minerals occupy the pore space in addition to the initial clay cement in both samples. When the phase equilibrium is changed by injected CO₂ sodium salts in formation, brine can precipitate (Figure 10). In addition, the interaction of CO₂ with carbonate minerals results in the precipitation of CaCO₃ and NaCl [16,38]. Thus, the carbonate cement in sample #2 led to the halite precipitation on the particle surface, which resulted in a substantial permeability reduction along with clay alteration.

Possible permeability reduction mechanisms for sample #1 and sample #2 are shown in Figure 10. Precipitates reduce permeability through various mechanisms, including solid deposition on pore walls due to attractive forces between particles and pore surfaces, individual particles blocking pore throats, and several particles forming bridges across pore throats. The permeability drop in sample #1 can be attributed to the clay formation in the pore space, while the permeability reduction in sample #2 can be attributed to both clay formation in the pore space and halite precipitation on the particle surface.

The permeability reduction in the samples due to CO₂-rock interaction during miscible CO₂ flooding led to moderate values of the oil recovery coefficient—0.49 and 0.54 for sample 1 and sample 2, respectively.

4. Conclusions and Future Recommendation

This experimental investigation reveals significant insights into the influence of CO₂-EOR on the petrophysical properties and oil recovery in sandstone reservoirs. The study highlights that while CO₂ injection can enhance oil recovery, the extent of its effectiveness is closely tied to the specific mineralogical and geochemical characteristics of the reservoir. The following conclusions can be made:

• The Dos and Akk samples exhibited contrasting responses to CO₂ flooding, with permeability reduction being a common outcome due to clay mineral alteration and halite precipitation.
• The observed oil recovery coefficients suggest that CO₂-EOR can be an effective method for enhancing oil production in Kazakhstan’s Precaspian region. However, the variability in the results underscores the necessity for site-specific assessments and optimizations.
• Future research will focus on Water Alternating Gas (WAG) experiments to further elucidate the combined effects of CO₂ and water injection on oil recovery, providing a more comprehensive understanding of EOR processes in diverse reservoir conditions.