**Fundamentals of Enhanced Oil Recovery**

Editor

**Marcin Kremieniewski**

MDPI • Basel • Beijing • Wuhan • Barcelona • Belgrade • Manchester • Tokyo • Cluj • Tianjin

*Editor* Marcin Kremieniewski Oil and Gas Institute—National Research Institute Poland

*Editorial Office* MDPI St. Alban-Anlage 66 4052 Basel, Switzerland

This is a reprint of articles from the Special Issue published online in the open access journal *Energies* (ISSN 1996-1073) (available at: https://www.mdpi.com/journal/energies/special\_issues/ Fundamentals\_of\_Enhanced\_Oil\_Recovery).

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## **Contents**

## **About the Editor**

#### **Marcin Kremieniewski**

Dr. Marcin Kremieniewski is an expert in the field of technology, selection and processing of cement slurries and drilling fluid compositions. He carries out research and design work for many entities related to the energy and oil industries. He has extensive knowledge in the field of drilling technology, hydraulic binders, drilling fluids, environmental engineering as well as energy and geoengineering. He deals with issues related to reducing energy consumption, increasing the efficiency of extraction, rational energy management in the oil industry, proper well sealing, rational selection of drilling fluids, increasing the efficiency of oil extraction, reducing investment costs in the oil sector and environmental aspects in the oil sector. Author or co-author of over 100 scientific publications, 8 scientific monographs, as well as many national and international conference presentations. He is also the creator of numerous inventions that have patents at international inventions exhibitions. He is supervisor to doctoral dissertations and a reviewer of many scientific magazines. He is in charge of research teams implementing various projects in the field of drilling technology. He holds the Mining Director, 3rd degree and Meritorious for the Oil Mining and Gas Industry distinction.

## *Editorial* **Improving the Efficiency of Oil Recovery in Research and Development**

**Marcin Kremieniewski**

Oil and Gas Institute-National Research Institute, 25A Lubicz Str., 31-503 Krakow, Poland<EMAIL_ADDRESS>
#### **1. Introduction**

By creating a special edition entitled Fundamentals of Enhanced Oil Recovery, the editors focus on the problem of the global increase in energy demand. In recent years, there has been a trend towards switching to alternative energy sources, but despite this, oil and natural gas will continue to be the main source of energy for the next several decades. However, it should be borne in mind that renewable energy resources have some limitations in terms of quantity. The progressive exploitation of the deposits contributes to the increasing degree of oil depletion, and this makes extraction more and more difficult, even though the deposits are not yet completely empty. Such a situation results in the necessity to search for new methods of increasing oil and gas production. Intensifying oil production is a very rational use of energy that has not yet been fully used. Production intensification methods are used to utilize these energy reserves. Such activities can be implemented and carried out at any stage of the well implementation, from the well design stage, through drilling, to oil and gas production. For this purpose, it is extremely important to conduct research and design works that include issues related to increasing the efficiency of oil extraction. It is also very important to improve the effectiveness of sealing the borehole and the correct selection of cement slurries, drilling fluids and borehole washing liquids. In addition, the issues related to the reduction in energy consumption and energy management in the oil industry are very important at the present time, both from the economic point of view and in terms of the rational use of energy. The focus should also be on innovations that include modern technologies supporting the efficiency of extraction and the latest technical, technological and operational challenges in the oil sector. All these factors are discussed in the international industrial arena, and the most important topics, after a rigorous assessment procedure by eminent specialists from around the world, find their way to prestigious magazines, such as MDPI *Energies* Special Issue.

#### **2. A Short Review of the Contributions in This Issue**

Many articles can be grouped under the title Fundamentals of Enhanced Oil Recovery. As for the improvement of oil recovery, in the first article [1], the authors discuss the problem of gas migration through fresh cement slurry and hardened cement slurry [2]. Gas transfer is an unfavorable phenomenon that can be minimized and sometimes even eliminated by using an appropriate cement slurry recipe [3]. According to the authors, the appropriate selection of the quantity and quality of components enables the design of slurries with the required static strength values [4]. Additionally, the cementitious sheath of such anti-migration slurry has a low porosity and a very low proportion of large pore spaces. Furthermore, the mechanical parameters do not deteriorate during long-term deposition in borehole conditions [5]. The authors designed a solution in the form of a cement slurry, the cement sheath of which has high corrosion resistance. The presence of appropriate additives and admixtures favors the design of the slurry, which contributes to the improvement of gas recovery by eliminating the negative phenomenon of gas migration.

**Citation:** Kremieniewski, M. Improving the Efficiency of Oil Recovery in Research and Development. *Energies* **2022**, *15*, 4488. https://doi.org/10.3390/ en15124488

Received: 9 June 2022 Accepted: 16 June 2022 Published: 20 June 2022

**Publisher's Note:** MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.

**Copyright:** © 2022 by the author. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

The next article presents the technology of preparing drilling fluids with a high content of internal phase [6]. The correct selection of drilling fluid is very important from the point of view of improving oil recovery [7]. Various types of drilling fluids are used for drilling boreholes, but most often, due to the economic aspect, a water-based mud is used [8]. However, for drilling in difficult geological conditions, an inversion mud is used, in which the oil phase to the water phase most often occurs in the range from 70/30 to 90/10 [9]. The authors in publication [6] present a solution where the oil to water ratio is 50/50 to 20/80, and such a mud can be used to drill a borehole in HPHT conditions. According to the authors, the new drilling mud solution contributes to the improvement of the improved oil recovery. Additionally, inversion drilling muds are characterized by high electrical parameters; the ES stability is above 300 V [10]. They also have stable rheological parameters and low filtration. Due to the reduced oil content, the developed drilling fluid system is more economical and has limited toxicity.

Issues related to the geological sequestration of acid gases, including CO2, are now an increasingly common solution to prevent the progressive changes in the Earth's climate. In the publication [11], the authors focus on the analysis of the research carried out in the Borz ˛ecin sequestration area [12]. The area is located in western Poland. The tests are aimed at examining the migration paths of the injected acid gases (mainly mixtures of CO2 and H2S) to the aquifers under the natural gas deposit [13]. As part of their research, the authors conduct two well sampling actions, during which they take samples of the waters lying under the Borz ˛ecin reservoir and then examine their physicochemical parameters. Such tests have not been conducted so far. Tests of reservoir waters from selected wells were also carried out, including isotope analyzes [14]. The work carried out was aimed at broadening the state of knowledge, which is valuable for the risk assessment of the acid gas sequestration process taking place on a specific example, and to improve the efficiency of gas injection.

During the improvement of oil recovery, one of the basic problems accompanying the use of water in EOR processes is the precipitation of inorganic sediments [15]. As the authors write in the publication [16], these are the most common deposits of calcium carbonate and deposits of calcium, barium and strontium sulphates, with calcium carbonate being the most common one [17,18]. In order to eliminate this unfavorable phenomenon, appropriate types of inhibitors are used, which was presented in the publication [16]. However, in order to carry out such tests, it is necessary to develop the research technology and build a test stand. Such a solution was presented by the authors of the publication [16] and they discussed the most important research results.

Fundamentals of Enhanced Oil Recovery is strongly associated with the improved adhesion of cement to pipes and rock formation [19]. On the other hand, the adhesion is strongly influenced by proper preparation of the borehole and cleaning of the annular space after drilling and before cementing [1,20]. It is connected with the fact that low values of adhesion of the cement sheath to the rock formation and to the surface of the casing cause the formation of uncontrolled gas flows [4]. Additionally, the lack of adhesion also reduces the stabilization of the pipe in the borehole [21]. In [22], the authors focus on determining the impact of cleaning the annular space on the adhesion of the cement sheath to the rock formation. The issues related to the preparation of the borehole for cementation by appropriate cleaning of the rock formation from mud cake residues contribute to the improvement of oil recovery, which contributes to the improvement of drilling works [23].

The increase in oil production translates into shell gas exploration [24,25]. Therefore, in the publication [26], the authors discuss the developed method of finding similarities between particular geological structures in terms of their hydrocarbon-generating properties and hydrocarbon resources. The measurements and geochemical studies of holes located in the Ordovician, Silurian and Cambrian formations of the Polish part of the East European Platform are used here [27,28]. The classification of objects is based on a cluster analysis, where the focus is on the issue of generating clusters that are grouped into samples in gas, condensate and oil windows [29]. The characteristic geochemical properties of the samples

classified into selected clusters are also determined [30]. Researchers successfully classified the samples into individual windows and determined their percentages in Silurian, Ordovician and Cambrian units.

In work [31], the authors rightly state that flooding technology is an important measure for increasing the recovery of crude oil in oil fields. In this paper, the authors used the direct numerical simulation (DNS) method, which is based on the Navier–Stokes equation and the fluid volume (VOF) method, to investigate the dynamic behavior of oil-water flow in a low-permeability pore structure [32,33]. On the basis of the results obtained from the research, the authors concluded that the variability in the non-uniformity of the viscosity action results from the difference in the viscosity of oil and water. On the other hand, the complex dynamic behavior of the two-phase oil-water flow on the pore scale, demonstrated by capillarity, play a decisive role in determining the area of spatial sweep and the final index of oil recovery [34,35]. From the work, they conclude that the absolute viscosity of oil and water has a significant influence on the degree of oil recovery by adjusting the relative importance between the action of viscosity and capillarity.

Enhanced Oil Recovery is also about the correct selection of drilling fluids. Therefore, an appropriate design of the cement slurry to seal the borehole is important [36]. For this purpose, the additives and admixtures for the cement slurry should be properly selected in order to obtain the required parameters of the hardened cement slurry [37]. Such requirements depend on the geological conditions of the drill hole. There are very high regimes in deep boreholes, which must be met by cement slurries; therefore, the necessity to use advanced, innovative measures is implied [38]. An example of the above is the possibility of using the addition of nanosilica, as discussed in [39], in order to improve the technological parameters of both the liquid cement slurry and the resulting cement sheath. The authors of the work presented the results of research on the mechanical parameters for cement stone with the addition of silica nanoparticles. The samples are deposited in an environment of elevated temperature of 90 ◦C. The cement sheath made of cement slurry, which contains an admixture of nanosilica, shows an improvement in mechanical properties. This is manifested by an increase in compressive strength. It is very important from the point of view of undertaking further works in the borehole and improving the efficiency of production.

The issue of the tightness of the borehole is of key importance for its long-term durability; thus, it is part of the broad thematic spectrum of Enhanced Oil Recovery. To ensure durability for many years, the column of pipes is sealed with cement slurry [40]. However, slurry that is pumped down the mud, if it comes into contact with the mud cake, may not seal well the annular space of the borehole [41]. Therefore, it is important to properly clean the hole, which is a big problem, because there are many variables affecting its stability [42]. The contact time of the well with the scrubber is important. On the one hand, insufficient contact time does not guarantee the correct removal of the mud cake. On the other hand, long contact times can damage the borehole wall. Therefore, in [43], the researchers conducted a study to evaluate the impact of the contact time of the washer on cleaning the annular space. The study of the degree of mud cake removal depending on the contact time is based on the determination of the adhesion of the cement sheath to the rock formation [44]. By comparing the obtained adhesion with a reference sample, the researchers determine the effectiveness of the deposit removal. On the basis of these studies, they determined the optimal contact time with the cleaner.

In [45], the author deals with the issue of the influence of temperature on the gradation of oil pipes. Corrosion in the oil industry is an important aspect when extracting natural gas from a deposit with high temperatures [46]. According to the author [47], the water in the tank is often in the form of steam with a pressure of up to several dozen MPa. As a result of its extraction, it cools, which causes [48] condensation. Condensed water in contact with the acidic components of the gas causes corrosion, especially in the presence of aggressive gases. Therefore, a very important issue is to determine the effect of water condensation as a result of the changes in the temperature of gases containing CO2 and H2S [49,50] on the corrosion of steel, which is in contact with extraction pipes and casing pipes. On the basis of the obtained results, the author answers the question of what effect temperature, gas components and pressure have on the corrosion of the borehole construction material, and indicates the selection of the borehole material to prevent corrosion in aggressive environments.

Fundamentals of Enhanced Oil Recovery is also an operational challenge. These include the new analytical procedure for the preselection of gas wells for water shutoff procedures, as discussed in the next paper [51], based on the available results of the integrated geological and deposit data analysis. The basis for assessing the possibility of cross-flow formation is the assessment of the presence or absence of impermeable barriers at intervals, supplemented by perforation [52,53]. The authors used data from wells obtained in different years from measurements with different types of probes. Based on the modified quantitative and qualitative interpretation techniques, permeable and impermeable layers are distinguished in the analyzed drilling sections. The process of verifications carried out for eight boreholes initially selected by the operator located in the Carpathian Foredeep in Poland is discussed [54,55].

A properly designed cement slurry is one of the most important elements in the Fundamentals of Enhanced Oil Recovery through improved borehole sealing [56]. Therefore, the publication [57] discusses the influence of the Hblock fine-grained material on selected parameters of the cement slurry. The fine-grained additive used shortens the setting time and the transition time from the value of the initial setting time to the final setting time [58]. It shortens the time needed to bind the cement slurry and proceed to further work [59]. Moreover, such action helps to eliminate the possibility of the gaseous medium penetrating into the structure of the liquid cement slurry [60]. The publication discusses the effect of the additive on the technological parameters of the cement slurry and the possibility of using fine-grained material as an innovative technology in fluids for oil wells.

Innovative technologies in oil wells are part of the Special Issue Fundamentals of Enhanced Oil Recovery. One of these technologies is the use of jet pumps for the utilization of the associated petroleum gas, as discussed in [61]. This is a very important issue because the combustion of this gas causes environmental degradation and poses a potential threat to the human body [62]. The possibility of simultaneous use of a suction-piston pump driven by a shuttle and jet machine in the oil well was proposed after prior estimation of the pressure distribution along the borehole. The authors used the well-known methods of Poettman-Carpenter and Baksendel. In order to carry out the work, the researchers developed a methodology for the practical use of these equations in order to calculate the parameters of the jet pump based on the independent parameters of the oil well [63,64]. The final result of the work [61] is a list of recommendations for the selection of the location of an oil-gas ejector inside a selected oil well and a generalization of the principles of selecting the ideal location of such ejectors for other shafts. The second result is a reasonable method to rationally determine the location of the ejector in the oil well and calculate its geometry, which ensures complete selection of the petroleum gas released into the oil well ring. Such activities will contribute to the intensification of oil extraction from boreholes and the improvement of the environment in the oil field.

The correct selection of drilling fluids is also an issue that contributes to Enhanced Oil Recovery. Therefore, in the article [65], the authors presented the influence of enzymatic and oxidizing factors on polymers used in drilling mud technology. The concentration of calcium hypochlorite, urea peroxide, sodium persulfate, amylase and cellulase was determined to reduce the rheological parameters of drilling fluids. Additionally, researchers developed a method of treating drilling fluid prior to cementation, and developed a drilling fluid containing enzymatic or oxidizing agents to prepare the borehole for cementation [66,67]. On the basis of the work carried out, the authors obtained positive results regarding the possibility of diluting the drilling fluid immediately before cementing, and it is possible to use oxidants and enzymes in the composition of the drilling fluids [68,69].

#### **3. Conclusions**

The present publication focuses on issues related to improved oil recovery technology. The articles presented in this Special Issue show various related challenges, including the following: increasing the efficiency of oil recovery, improved borehole sealing, correct selection of drilling fluids, reducing energy consumption, appropriate energy management in the oil industry, new technologies supporting the efficiency of recovery, technical and technological challenges, operational challenges and innovative technologies in oil drilling. The works included in this Special Issue cover important elements not only of the exploitation of oil and gas fields, but most of all the most important aspects, which include the elements of borehole implementation. The published submissions cover a broad spectrum of technologies that address the fundamentals of improved oil recovery. The task of editing and selecting articles for this collection was both stimulating and rewarding. We would like to thank the staff and reviewers very much for their efforts and contributions. Thanks to their hard work, a very interesting Special Issue has been created, which will contribute to increasing knowledge and to the further development of technology to improve oil recovery.

**Conflicts of Interest:** The author declares no conflict of interest.

#### **References**

## *Article* **Possibilities of Limiting Migration of Natural Gas in Boreholes in the Context of Laboratory Studies**

**Marcin Kremieniewski 1, Rafał Wi´sniowski 2, Stanisław Stryczek <sup>2</sup> and Grzegorz Orłowicz 2,\***

**Abstract:** Gas migration through fresh and hardened cement slurry is an ongoing problem in the oil industry. In order to eliminate this unfavourable phenomenon, research is being conducted on new compositions of slurries for gas wells. The article presents the results of research for slurries with low and high resistance to gas migration. The proper selection of the quantity and quality of components makes it possible to design slurry with the required static structural strength values. In addition, the cement sheath of such anti-migration slurry has low porosity and a very low proportion of large pore spaces. Additionally, the mechanical parameters do not decrease during long-term deposition in borehole-like conditions. By obtaining these results, it was possible to design slurry whose cement sheath has high corrosion resistance. The new slurry has a lower water-cement ratio. Additionally, GS anti-migration copolymer, anti-filter additive and latex are used. The presence of n-SiO2 aqueous solution and microcement allows for sealing the microstructure of the hardened cement slurry. Such modifications significantly improve the technological parameters of the cement slurry and the cement coat formed from it.

**Keywords:** gas migration; well cementing; cement slurry; cement sheath; corrosion resistance; gas outflows

#### **1. Introduction**

Limitation of uncontrolled natural gas flows from the ring and/or annular space of a borehole is one of the crucial aspects during sealing of casing in boreholes drilled in formation with a higher risk of gas migration (the so-called exhalation). It relates to the main objective of casing sealing, i.e., ensuring durability and tightness between the lowered casing, on the one hand, and the drillhole wall and the previously cemented casing string, on the other [1–5]. As there are cases of gas invasion into the structure of the bonding slurry, resulting in leaks in the structure of the cement coating, it is necessary to carry out research and development work aimed at continually improving the quality of cement slurries formulations and the slurry injection technology [2,5–7]. During cement slurry bonding, in the process of its hydration, gel structure is created and at that time a clear decline of hydrostatic pressure in the ring space of a drillhole is observed. When slurry changes its structure, it is very likely that gas moves in the gelled slurry structure, which may consequently result in gas migration both through fresh and hardened cement slurry [2,3,5,8–13].

#### **2. Uncontrolled Flows of Fluids in a Borehole**

Interhorizontal flows of drilling fluids (natural gas, crude oil, brine, drilling fluid) are caused by the lack of balance between formation and hydrostatic pressures in the ring space of a wellbore.

**Citation:** Kremieniewski, M.; Wi´sniowski, R.; Stryczek, S.; Orłowicz, G. Possibilities of Limiting Migration of Natural Gas in Boreholes in the Context of Laboratory Studies. *Energies* **2021**, *14*, 4251. https:// doi.org/10.3390/en14144251

Academic Editor: Rouhi Farajzadeh

Received: 7 June 2021 Accepted: 12 July 2021 Published: 14 July 2021

**Publisher's Note:** MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.

**Copyright:** © 2021 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

Uncontrolled natural gas flows within particular horizons being drilled are called migrations (drillhole no. 1, Figure 1), whereas gas flow from rock formation on the ground surface is called exhalation (drillhole no. 2, Figure 1).

**Figure 1.** Example of gas migration and exhalation.

The first issues of this kind were observed in the 1960s when making a borehole for gas storage. The topic of uncontrolled natural gas outflows from ring and/or annular spaces of a wellbore is very important in the context of the influence on safety, environmental protection, in terms of legal regulations, with regard to suitable management and exploitation of the borehole area. The results of studies conducted by oil companies (Schlumberger, Halliburton) prove that ca. 15% of failed cementing of a casing string in wellbores are caused by gas migration [4,14].

Presently, this problem occurs to a much higher extent, mainly on some gas formations and in boreholes prepared for gas storage. The above is confirmed by the analysis of the state of cementation of boreholes carried out (in the years 2008 to 2011) in the area of the Carpathian Foredeep and in the Carpathians, which is presented in Figure 2 [15].

**Figure 2.** Gas outflows from the ring space in boreholes drilled in the Carpathian Foredeep and Carpathians in the years 2008—2011. P-4—Pogwizdów 4, P-5—Pogwizdów 5, P-25—Pruchnik 25, T-6—Terliczka 6K, L-3—Łapanów 3, M-63— Mirocin 63.

In extreme situations, where an abnormally high pressure occurs after cementing of the casing on a wellhead, it may be necessary to decommission the borehole. In most cases, however, this problem is solved by using different techniques to cement the leaking zone in order to eliminate the gas flow or to reduce the pressure to a value that allows further work to be carried out in compliance with the applicable standards. Such procedures, however, are very costly, so the optimum solution is to minimise uncontrolled gas flows from the design stage of the formulation and the technological parameters of the slurry, while conducting laboratory tests [3,16–20].

#### **3. Minimizing of Uncontrolled Gas Flows**

The sealing slurry changes its physical state during hydration from the liquid phase during injection, through the transition phase—gel (slurry bonding), to the solid phase (bonded) slurry. Taking the technological properties of the sealing slurry as a criterion, it can be noted that the potential factors minimising the exhalation of natural gas after cementing include:

**Figure 3.** Diagram of hydrostatic pressure reduction below formation pressure.

**Figure 4.** Apparatus for testing gas migration during slurry bonding—hydraulic press (OGI-NRI design).

**Figure 5.** Diagram for the build-up of static structural strength and the formation of a transition period.

**Figure 6.** Apparatus for testing the build-up of static structural strength in slurry—two-chamber UCA SGSM Ofite model 120-53.

When developing sealing slurry formulations, various additives and admixtures are used in order to reduce the possibility of uncontrolled gas flows in boreholes through the setting slurry and after it has set, i.e., microcements, microsilicas, nanosilicas, which tighten the microstructure, as well as latex and cationic polymers, which shorten the gelling time of the slurry and thus reduce the possibility of natural gas flowing through the hardened cement slurry [2,13,21–24].

#### **4. Research Findings**

Laboratory tests conducted by the Oil and Gas Institute, the National Research Institute and AGH University of Science and Technology show significant differences in effectiveness of removing uncontrolled gas outflows as a result of comparing technological parameters of the base slurry, on the one hand, and the slurry after modification with selected additives and admixtures, on the other. Table 1 shows the control slurry formulation (Contr slurry) and the modified formulation (Mdf slurry). The technological parameters of the fresh slurries are summarised in Table 2. There was a significant reduction in the filtration of the slurry from a value of 150 cm3/30 min to just over 2 cm3/30 min. The values of rheological parameters have also decreased. In order to minimise the possibility of uncontrolled gas outflows at the contact between the cement coating—rock formation and the cement coating—casing pipes, the presence of gravitational water was eliminated. The changes made to the slurry formulations result in short thickening times from 30 Bearden Consistency units (Bc) to 100 Bc, thus minimizing the occurrence of gas migration during slurry bonding.

**Table 1.** Base slurry and slurry with selected additives and admixtures.

**Table 2.** Technological parameters of the fresh slurries.

Figures 7 and 8 show the gas migration test and static structural strength build-up tests for the control slurry. This slurry obtained the end of bonding time after lowering the hydrostatic pressure value below the formation pressure. The consequence of this can be gas intrusion into the structure of the cement coating and the subsequent creation of gas migration paths. Additionally, a large amount of filtrate in the upper part of the measuring

cylinder indicates a low anti-migration efficiency of the slurry in question. During the static structural strength test (Figure 8), no transition period was obtained from a value of 50 Pa to 250 Pa.

**Figure 7.** Course of the gas migration test during bonding for slurry with low anti-migration resistance.

**Figure 8.** Static structural strength build-up for slurry with low anti-migration resistance.

Figures 9 and 10 show the results of tests on modified slurry which is guaranteed to reduce the possibility of uncontrolled gas flow. This slurry reaches the end of bonding (EB) before the hydrostatic pressure drops below the formation pressure. Thus, it shows a very good ability to maintain the hydrostatic pressure at a high level (Figure 9). Slurry filtration at the top of the cylinder was low, confirming the effectiveness of this slurry in counteracting gas migration. Furthermore, a short transition time of 52 min from 50 Pa to 250 Pa and a steady increase in structural strength were obtained (Figure 10).

**Figure 9.** Course of the gas migration test during setting for slurry with high anti-migration resistance.

**Figure 10.** Static structural strength build-up for slurry with high anti-migration resistance.

#### **5. Analysis of the Quality and Durability of the Cement Coating with Regard to the Possibility of Uncontrolled Gas Flows**

When analysing the problem of gas outflow through the cement coating, corrosion of the hardened slurry in the annular space must also be taken into account. Test results available in the literature indicate that after 30 years, the cement coating has corroded in approx. 60% of the boreholes and deteriorated its tightness, as shown graphically in Figure 11. The main factors causing corrosion of cement coating in a borehole are formation brine, high temperature and pressure at a given depth [1,11]. The combination of this groups of factors results in chemical compounds with reduced mechanical strength and sometimes no bonding ability [4]. Therefore, in order to design the sealing slurry formulation with improved corrosion resistance, it is necessary to:

The destructive effect of ions present in reservoir brines on hardened cement slurries can be represented by the following chemical reactions [11,19,25]:

• Double exchange between magnesium and calcium cations, e.g.,

Magnesium ions (Mg2+).

• Transformation of portlandite into brucite

$$\text{Ca(OH)}\_{2} + \text{MgCl}\_{2} \rightarrow \text{Mg(OH)}\_{2} + \text{CaCl}\_{2}$$

• Extraction of calcium ions Ca2+ from the CSH phase and formation of brucite

$$\rm C\_{1,75}SH\_n + MgCl\_2 \to C\_{1,75\cdot x}SH\_n + x\rm CaCl\_2 + x\rm Mg(OH)\_2$$

• Formation of expansive hydrated basic magnesium chloride

2Ca(OH)2 + 3MgCl2 + 2H2O → Mg3Cl2 (OH)4 · 2H2O + 2CaCl2

C1,75SHn + 3MgCl2 → Mg3Cl2 (OH)4 · 2H2O+C1,75-xSHn

Sulphate ions (SO4 <sup>2</sup>−) present in the pores of hardened cement slurry cause the formation of salts that are difficult to dissolve. This process is accompanied by a significant increase in the volume of the slurry, and consequently the formation of high tensile stresses in the cement matrix. The swelling compounds formed are gypsum dihydrate and tricalcium aluminate trisulphate hydrate called ettringite.

The hydration products most frequently attacked by sulphate ions are portlandite and C3A and hydrated calcium aluminates:

$$\text{Ca(OH)}\_{2} + \text{SO}\_{4}^{2-} \rightarrow \text{CaSO}\_{4} \cdot 2\text{H}\_{2}\text{O} + 2\text{OH}^{-}$$

$$\text{Gypsum dihydrogen}$$

3 CaO · Al2O3 + SO4 <sup>2</sup><sup>−</sup> +nH2O + Ca(OH)2 → 3 CaO · Al2O3 · 3CaSO4 · 32H2O+mH2O Ettringite

On the basis of an analysis of long-term laboratory test results on corrosion of hardened cement slurries, the following conclusions can be drawn [3,9,16,17,25]:

Tests to determine the durability of hardened sealing slurries are based on the following procedures [9]:

Samples of hardened slurries are deposited under corrosive conditions for a defined period of time. In autoclaves the temperature reaches 120 ◦C and the maximum pressure can reach 20 MPa. A reference sample is stored in one chamber of the autoclave in tap water, which represents the reference environment.

Figure 13 shows the values of parameters describing the pore microstructure, while Figure 14 compares the mechanical parameters of samples 1 and 2. Sample 1 is a hardened cement slurry with very low corrosion resistance. This sample has a porosity factor (ratio of the volume of space between the grains to the volume of the entire sample) of 40.8%, a large proportion of the largest pore spaces, and its mechanical parameters decrease significantly during deposition. This sample deteriorated almost completely after 18 months of deposition under conditions of increased corrosivity. Sample no. 2, which was modified to achieve improved corrosion resistance, has a low share of macropores (Figure 13), a low porosity index of 28.7% and a high compressive strength, which is almost constant over time.

**Figure 12.** Autoclaves for storing samples of cement slurries.

**Figure 13.** Porosity coefficient values and shares of individual pores for samples 1 and 2.

**Figure 14.** Compressive strength values for samples 1 and 2.

#### **6. Conclusions**

When developing sealing slurries to minimise uncontrolled gas leaks, it is important to modify them at the design stage with additives such as microcement, microsilica, latex, high molecular weight cationic polymers, nanosilica or expansive additives.

The modified formulations discussed in this publication are characterised by appropriate densification times for the given conditions. Such values for the time of thickening allow the slurry to be pumped efficiently into the annular space to be sealed, within the time necessary to carry out the procedure. This time is increased by a safety buffer in the event of complications arising in the preparation of the slurry in the field. The designed cement slurry is characterised by a rapid transition from a consistency value of 30 Bc to a value of 100 Bc during the thickening time test. This short transition time of 10 min goes a long way towards minimising the possibility of gas migration through the binding cement slurry. After injection, the slurry begins to gel and a gas-impermeable cement sheath is formed. The designed slurry with anti-migration properties also has the required rheological parameters, which allow it to be pumped efficiently into the cemented annular space, and to efficiently displace the drilling fluid previously present in the borehole. The newly developed slurry for cementing boreholes with an increased risk of gas migration has a low filtration value and does not show any water retention. As a result, the setting and thickening time is maintained at the required level, because the slurry does not "give off" water in the absorption zones that are often found in the area where gas migration occurs. In addition, a slurry with low filtration and no water retention has a homogeneous structure in the liquid state and does not fractionate. The slurry designed for sealing gas wells is resistant to gas migration during setting, as confirmed by the Static Gel Strength Measurement (SGSM) test. With a transition time of 52 min, it can be concluded that the gas will not be able to penetrate the structure of the cement slurry once it is injected.

When analysing the results of tests on the structure of the cement sheath made of slurry with increased resistance to gas migration, it is found that such a formulation has a significantly lower porosity than standard slurries, and a smaller proportion of pore spaces with the largest diameters. Such conditions confirm the required sealing of the borehole and the elimination of microflows through the cement sheath structure. The mechanical strength values obtained for 18 months of deposition under borehole conditions confirm the erosion resistance of the designed slurry. The samples have comparable strength throughout the storage period, with strengths of over 25 MPa. In contrast, the strength of the control sample decreased due to erosion. The strength of this control sample decreases until, after a final period of exposure to erosive conditions, the sample is destroyed.

Long-term tests of changes in mechanical strength, gas permeability, porosity and microstructure are very important in designing an anti-migration slurry. Such tests allow an objective assessment of the course of destructive processes occurring in the cement sheath during long-term exposure in borehole conditions. Research into the durability of hardened cement slurries is required to improve formulas and develop new slurries for sealing boreholes in various geological and technical conditions.

**Author Contributions:** Conceptualization, M.K.; methodology, M.K.; validation, R.W. and S.S.; formal analysis, R.W. and S.S.; investigation, M.K., R.W. and S.S.; resources, M.K., R.W., S.S. and G.O.; data curation, R.W.; writing—original draft preparation, R.W.; writing—review and editing, G.O.; visualization, S.S.; supervision, S.S.; project administration, M.K., R.W. and S.S.; funding acquisition, M.K. All authors have read and agreed to the published version of the manuscript.

**Funding:** The paper was financially supported by Ministry of Science and Higher Education Warsaw (Internal order Oil and Gas Institute—National Research Institute Project No. 0015/KW/21).

**Data Availability Statement:** Not applicable.

**Conflicts of Interest:** The authors declare no conflict of interest.

#### **References**

### *Article* **Invert Drilling Fluids with High Internal Phase Content**

**Sławomir Błaz, Grzegorz Zima, Bartłomiej Jasi ´ ˙ nski and Marcin Kremieniewski \***

Oil and Gas Institute–National Research Institute, 31-503 Krakow, Poland<EMAIL_ADDRESS>(S.B<EMAIL_ADDRESS>(G.Z<EMAIL_ADDRESS>(B.J.)

**\*** Correspondence<EMAIL_ADDRESS>
**Abstract:** One of the most important tasks when drilling a borehole is to select the appropriate type of drilling fluid and adjust its properties to the borehole's conditions. This ensures the safe and effective exploitation of the borehole. Many types of drilling fluids are used to drill holes for crude oil and natural gas. Most often, mainly due to cost and environmental constraints, water-based muds are used. On the other hand, invert drilling fluids are used for drilling holes in difficult geological conditions. The ratio of the oil phase to the water phase in invert drilling fluids the most common ratio being from 70/30 to 90/10. One of the disadvantages of invert drilling fluids is their cost (due to the oil content) and environmental problems related to waste and the management of oily cuttings. This article presents tests of invert drilling fluids with Oil-Water Ratio (OWR) 50/50 to 20/80 which can be used for drilling HPHT wells. The invert drilling fluids properties were examined and their resistance to temperature and pressure was assessed. Their effect on the permeability of reservoir rocks was also determined. The developed invert drilling fluids are characterized by high electrical stability ES above 300 V, and stable rheological parameters and low filtration. Due to the reduced content of the oil, the developed drilling fluid system is more economical and has limited toxicity.

**Keywords:** oil-based mud; invert drilling fluid; water phase; oil phase; emulsion stability; emulsifier

#### **1. Introduction**

Invert drilling fluids are one type of fluid that can be used to drill boreholes in almost any geological condition. The invert drilling fluid consists of two phases: the oil phase and the water phase. The oil phase consists most often of mineral or synthetic oils. The oil phase is the continuous phase of the emulsion, and very often it is also referred to as the dispersion medium. Sometimes the emulsion phases are called the inner and outer phases. In this case, the concept of the outer phase is synonymous with the continuous phase, while the inner phase is the dispersed phase. The water phase, on the other hand, is most often brine solution, which is the internal phase of the emulsion. In addition to the oil and water phases, weighting agents that regulate the drilling fluid are added to the fluid [1–5]. The first invert drilling fluids were made on the basis of crude oil, which was successively replaced with diesel oil, and then with mineral oil. Each of the replaced oils has a lower amount of polycyclic aromatic hydrocarbons, which makes it less toxic to the environment. The next step towards reducing the toxic impact of invert drilling fluids on the environment was the use of enhanced mineral oil (EMO) or linear paraffin (LP) in their composition. These oils are characterized by limited toxicity due to the low amount of aromatic hydrocarbons. Environmental legislation imposes specific restrictions on the use of invert drilling fluids for offshore drilling. A particular problem is related to oil-contaminated drilled material that must be disposed of on the offshore platform or transported to the shore. It should be disposed of in an environmentally safe manner [6–10]. The increase in these requirements gave rise to multidirectional research aimed at developing chemical compounds with properties similar to diesel fuel, harmless to the natural environment. Based on these experiments, it is concluded that these compounds can be oils of plant and animal origin. However, the lack of thermal

**Citation:** Błaz, S.; Zima, G.; Jasi ´ ˙ nski, B.; Kremieniewski, M. Invert Drilling Fluids with High Internal Phase Content. *Energies* **2021**, *14*, 4532. https://doi.org/10.3390/en14154532

Academic Editor: Min Wang

Received: 6 July 2021 Accepted: 24 July 2021 Published: 27 July 2021

**Publisher's Note:** MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.

**Copyright:** © 2021 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

stability at higher temperatures and the rapid biodegradation of these compounds makes it impossible to use them in practice. Studies show that it is possible to obtain synthetic compounds from vegetable oils characterized by greater thermal and oxidative stability. The conducted research contributes to the development of chemical compounds such as esters, polyalphaolefins, ethers and acetyls, linear alkylbenzene (LAB), linear alpha-olefine (LAO) and internal (isomeric) olefin. Among the presented chemical compounds, the esters and chemical compounds from the olefin group have the greatest application in drilling fluid technology [11–16].

Invert drilling fluids are recommended to be used when drilling clay-shale and salt rock formations. Due to their low density, they can also be used for drilling boreholes in areas with low formation pressure. The excellent lubricating properties of the invert drilling fluids allow the drilling of directional and horizontal holes. They make it possible to reduce frictional resistance and torque. Invert drilling fluids also contribute to increasing the drilling speed, extending the lifetime of the drill bit and reducing the adhesion force of the drill string to the filter cake on the borehole wall. These are just some of the advantages of invert drilling fluids that are taken into account when choosing the type of drilling fluid in difficult geological and technical conditions [17–19].

The ratio of the oil phase to the water phase in inversion drilling fluids ranges from 65/35 to 90/10, with the most common ratio being from 70/30 to 80/20. Several factors determine such ranges. These are, among others: the solid phase content in the drilling fluid, including the weighting agents used to ensure the appropriate density of the drilling fluid adapted to the geological and technical conditions. An increased content of the oil phase in the invert drilling fluid is also needed in order to render the weighting agents and cuttings sufficiently oil wettable. At such ratios of the oil phase to the water drilling fluid, they are characterized by high temperature resistance and appropriate rheological and structural parameters that allow drilling in HTHP conditions [20–23].

One of the disadvantages of invert drilling fluids is their cost (due to the oil content) and environmental problems related to waste and the management of oily cuttings. Sometimes high costs are reduced by using a drilling fluid after proper cleaning to drill a few or several boreholes. Invert drilling fluids are also difficult to service in comparison to water dispersion drilling fluids. Drilling fluid losses during drilling in areas with caverns and rocks of high porosity are also costly. When drilling with an invert drilling fluid, special precautions must be taken to avoid direct contact with the invert drilling fluid. It is important to avoid inhaling its vapors and pay special attention to the fire hazard resulting from the possible ignition of its vapors. The use of invert drilling fluids requires special cleaning of the borehole prior to cementing and the near-hole area prior to operation. It is necessary to use special washing liquids based on solvents and surfactants. They enable the dissolution and removal of oil deposits and the reversal of the wettability of the borehole wall before the cementing procedure and of the near-hole area before exploitation [24–26].

#### **2. Related Works**

Al-Ajmi et al. [27] presented the laboratory tests invert emulsion fluids to protect the reservoir core from drilling fluid. Invert drilling fluids contained no damaging materials, such as barite, asphaltic material, or organophilic clay. Invert drilling fluids are more resistant to weighting material sag than conventional invert fluids systems of similar rheology.

Askø et al. [28] present laboratory tests for invert drilling fluids designed for drilling long horizontal wells in extremely depleted chalk reservoirs within the limitations of a narrow mud weight window, high overbalance, high solids contamination when drilling a water injection well on the Valhall Flank North in the southern Norwegian Continental Shelf.

Wagle et al. [29] describe the formulation of medium density organoclay-free invert emulsion drilling fluids. These fluids were formulated with acid-soluble manganese tetroxide as a weighting agent and specially designed bridging agent package. The tests carried showed that invert emulsion drilling fluids formulated with nanoparticles and rheology modifiers were stable at 120 ◦C and 150 ◦C.

In the article by Elkatatny [30], he presented the effect of using a new copolymer (based on styrene and acrylic monomers) on the rheological properties and stability of invert emulsion drilling mud. The deflection test was performed under static conditions (vertical and 45 inclination) and dynamic conditions to evaluate the ability of the copolymer to strengthen the suspension properties of drilling mud.

Ramasamy and Amanullah [31] conducted a comparative study has out by formulating invert emulsion OBM using commercially available emulsifier and the emulsifier derived from used (cooking)/vegetable oil.

Sheer et al. [32] describe the formulation of laboratory tests to analyze the optimal approach to drill invert drilling fluids of ratio o/w 60:40. The designed system reduces the use of diesel consumption by 26% in total oil-based mud formulation, lowers the percentage of Low Gravity Solids (LGS) compared to the 80:20 OWR mud, and decreases the impact on the environment. The articles presented show the standard compositions of invert drilling fluids with an o/w ratio of 60/40 to 80/20. There are no examples of invert emulsion fluids with an o/w ratio below 50/50 in the analyzed articles.

One of the examples of such scrubbers with an o/w ratio below 50/50 is invert emulsion fluid [33], which is designed to carry a gravel packing a wellbore in a subterranean formation. The present emulsion contains oil as the external phase, clear brine as the internal phase and an effective emulsifier with an HLB value of 3 to 8. In addition, the emulsion contains a wetting agent with an HLB value of about 4. An emulsifier was used to prepare the emulsion which was selected from the group consisting of amides and imidazolines. The invert emulsion fluids contained an oil-to-brine ratio of 45/55.

The second example is an invert emulsion fluid [34] in which the oil phase ratio is less than 50:50. The role of emulsifier in this type of emulsion was played by alkoxylated ether acid. The presented emulsion compositions were characterized by the electric stability of the emulsion depending on the ratio of the oil phase to the water phase in the range from 25 to max. of 287 Volt.

The article presents one of the methods of reducing the cost of an invert drilling fluid and reducing its toxic impact on the environment by developing invert drilling fluids with a reduced oil phase content and an increased water phase content. Formulated Drilling fluids with an o/w ratio less than or equal to 50/50 differ from conventional invert drilling fluids in their composition and properties. Due to the higher concentration of the dispersed internal phase, these drilling fluids are characterized by reduced stability and high values of rheological and structural parameters. The appropriate values of the drilling fluid's parameters and high stability can be maintained by use of new emulsifiers adapted to a given emulsion system with a specific oil phase to water phase ratio.

#### **3. Materials and Methods**

#### *3.1. Materials*

Mineral oil made by Brenntag is used to prepare an invert drilling fluid with a high concentration of the water phase. It has a boiling point above 200 ◦C and a low aromatic content below 0.2%.

The primary emulsifier used is ENI, which is the reaction product of unsaturated fatty acids with diethylenetriamine and fatty alcohol polyoxyalkylene glycol ether. The second type of emulsifier is an agent called ENII. It is a mixture of sorbitan monooleate and ethoxylated coconut oil fatty acid amides. The aqueous phase is a 35% solution of calcium chloride. Organophilic clay purchased from Polski Serwis Płynów Wiertniczych Sp. z o.o. Polska is used to modify the rheological and structural parameters of the emulsion.

The composition of applied drilling muds is shown in Table 1.

**Table 1.** Composition of applied drilling muds.

#### *3.2. Preparation of the Invert Drilling Fluid*

In order to compare the properties of drilling fluids with different concentrations of the oil phase to the water phase, invert drilling fluids with the following coefficients are prepared: o/w = 50/50, o/w = 40/60, o/w = 35/65, o/w = 30/70, o/w = 25/75, o/w = 20/80. The emulsions are prepared as follows: organophilic clay is added to a specific amount of oil and mixed for 5 min at a speed of 16,000 rpm. Then, selected emulsifiers are introduced into the prepared emulsion and mixed for 5 min. Next, the water phase, which is made up of 35% CaCl2, is added to the mixture and stirring is continued for 30 min. Then the type of the resulting emulsion is checked, and its properties are determined.

#### *3.3. Experimental Procedures*

The following procedure is performed to evaluate the feasibility of developing an invert drilling fluid with reduced oil phase content and increased water phase content.

Invert drilling fluids with different oil phase to water phase ratios were prepared.

#### 3.3.1. Testing Procedures

The technological properties of drilling fluids, such as density, rheological parameters, filtration and electric emulsion stability were determined in accordance with the PN-EN ISO 10414-2 standard. Petroleum and natural gas industries–Field testing of drilling fluids—Part 2: Oil-based fluids (ISO 10414-2:2011).

#### 3.3.2. Density Measurement

The density of the drilling fluids was determined by means of a Baroid type fluid balance at a temperature of 20 ◦C and at atmospheric pressure. The fluid balance is designed in such a way that the vessel for drilling fluid situated on one end of the arm is balanced by a fixed counterweight placed on the other end of the arm. The balance arm is equipped with a weight moved along the scale and a level, enabling precise weighing [35].

#### 3.3.3. Measurements of Rheological Parameters

The rheological parameters of drilling fluids are measured at 20 ◦C using an Ofite 900 viscometer. The viscometer is used to directly determine the relationship between the shear rate of a liquid and the existing shear stress, enabling the calculation of plastic viscosity, apparent viscosity, the yield point, and the measurement of the gel strength [35,36]. The

Ofite 77 high-temperature and high-pressure viscometer was used to measure rheological parameters at higher temperatures. The drilling fluids are tested in both the heating and cooling cycles in the temperature range from 20 to 120 ◦C with shear rates from 5.1 to 1020 s<sup>−</sup>1.

#### 3.3.4. Filtration Measurement

The filtration of drilling fluids at ambient temperature is determined using a lowpressure filter press at a pressure of 0.7 MPa for a period of 30 min. On the other hand, at a temperature of 120 ◦C, filtration is measured with a static HTHP filter press at a differential pressure of 3.4 MPa [36].

#### 3.3.5. Stability Tests of Invert Drilling Fluids

The stability of the resulting emulsion is determined by the Emulsion Stability Meter, which measures the ES value by applying a voltage between plate electrodes immersed in the liquid. The resulting current remains low until the threshold voltage (61 ± 5A) is reached. Then the voltage of the current is increased to the point where a so-called puncture occurs. The voltage value is given in volts. If the breakdown occurs at a low voltage level, then this indicates an o/w emulsion. In the event of an electric breakdown only at high voltage, it indicated a w/o emulsion. The higher the ES value, the more stable the emulsion is [36].

Stability studies of invert drilling fluids with different oil phase to water phase ratios were also tested using the Turbiscan Tower device. It allows to measure the stability of suspensions, emulsions and foams. The analyzer works by analyzing multiple scattered light (transmitted and reflected back). Thanks to the moving head and two detectors working synchronously, the device collects data on the intensity of the transmitted and reflected light at a specific frequency. Then all signal changes in the sample are summed up to give a unique TSI number reflecting the destabilization of a given sample. The greater the number of TSIs, the more unstable the sample.

3.3.6. Test of the Influence of the Developed Invert Drilling Fluids on the Permeability of Reservoir Rocks

In the first stage of the test, the initial gas permeability of the sandstone cores (nitrogen) is determined. The measurement is made by passing nitrogen at a pressure of 2.2 MPa (inlet) through the core to a pressure of 2MPa (outlet) at a temperature of 120 ◦C. Using Darcy's law and the measurement data, the initial baseline permeability of the cores is calculated.

The next stage of the test is saturation of the core with selected invert drilling fluids. The pressure of the drilling fluid at the inlet to the core (P1) is 5MPa and the pressure at the outlet from the core (P2) is 2MPa. The core saturation process at a differential pressure of ΔP = 3MPa is carried out for 30 min.

Nitrogen is then passed through the core from the formation side, in the opposite direction to the direction of saturation with the drilling fluid, resulting in a pressure depression value of 2 MPa. The next step is to measure the permeability, which allows us to determine the degree of damage to the deposit by a given drilling fluid.

#### 3.3.7. Determination of Loss of Permeability of a Sample

The coefficient of loss of permeability, WU (1), is defined as the percentage decrease in the permeability of the initial sample after the solid phase and filtrate particles penetrate into its pore space, and is expressed by the formula:

$$\text{WU} = \left(1 - \frac{k\_d}{k\_0}\right) \cdot 100\% \tag{1}$$

where: *kd*—permeability of damaged porous rock (after exposure to drilling fluid), taking into account the Klingenberg correction, [mD]; *k*0—initial permeability (undamaged porous rock), taking into account the Klingenberg correction, [mD].

#### **4. Results and Discussion**

#### *4.1. Properties of the Invert Drilling Fluid Depending on the Ratio of the Oil Phase to the Water Phase*

Table 2 shows the properties of invert drilling fluids with an oil phase to water phase ratio of 50/50 to 20/80, prepared with the use of specially selected emulsifiers ENI and ENII. The electric stability ES of the prepared drilling fluids ranged from 610 Volt with an o/w 50/50 to 630 Volt ratio in drilling fluids with an internal phase content of 80% (Table 2). The differences between the drilling fluids can be seen mainly in the rheological and structural parameters, TSI value, and density. The lowest drilling fluid density of 1.1 g/cm3 was obtained with an o/w phase mixing ratio of 50/50. This drilling fluid is also characterized by the lowest stability defined by the TSI index of 6.9 and the lowest values of rheological parameters (PV = 15 mPa·s, YP = 2.4 Pa). The TSI instability of 3.6 is defined in a drilling fluid with an oil to water ratio of 40/60. Increasing the proportion of the water phase to 40% increases the plastic viscosity to 27mPas and the yield point to 4.8Pa. Higher TSI values and low values of the yield point of drilling fluids with an o/w ratio of 50/50 and 40/60 indicate the necessity to increase the rheological and structural parameters in these drilling fluids by introducing organophilic clay into their composition or modifying the oil fraction composition. Therefore, 2% organophilic clay is added to the drilling fluid composition with an oil phase to water phase ratio of 50/50 (Table 2, item 2). Due to the use of hydrophobic bentonite in the invert drilling fluid with an oil phase to water phase ratio of 50/50, the yield point of the drilling fluid is now 4.3 Pa, and the sample stability index decreased from 6.9 to 0.5. (Table 2). On the other hand, in a drilling fluid with an oil phase to water phase ratio of 40/60, the use of 1% organophilic clay increases the yield point to 5.7 Pa and reduces the TSI index to 0.7 (Table 2, Figure 1).

The reduction of the oil phase to water phase ratio in invert drilling fluids causes an increase in rheological and structural parameters and slight changes in the electrical stability of the drilling fluids, ranging from 610 Volts to 690 Volts (Table 2). A properly selected composition of emulsifiers allows for obtaining invert drilling fluids with a water phase content of up to 75%. Above this value, the drilling fluid is characterized by high rheological and structural parameters, a plastic viscosity of 85 mPa·s and a yield point of 30.1 Pa (Table 2).

The increase in the water phase content in the invert drilling fluid makes it possible to increase the density of the drilling fluid to 1.23 g/cm<sup>3</sup> without the need to add any weighting materials. In this type of drilling fluid, the rheological and structural properties can be partially controlled by slightly changing the ratio of the oil phase to the water phase. Reducing the o/w ratio increases the rheological parameters while increasing the ratio reduces them.

**Figure 1.** Destabilization kinetics of selected invert drilling fluids with a different ratio of oil to water phase.

#### *4.2. Determining the Influence of Elevated Temperature on Rheological and Structural Properties and Filtration of the Developed Invert Drilling Fluids*

Two invert drilling fluids with an oil phase to water phase ratio of 40/60 and 30/70 were selected for the research. For comparative analysis, the drilling fluids were weighted with barite to the same density of 1200 kg/m3. The drilling fluids were tested in both the heating and cooling cycle in the temperature range from 20 to 120 ◦C. The measurement results are presented in Figures 2–5 in the form of a graph of changes in the plastic viscosity and the yield point versus temperature.

**Figure 2.** Changes in the plastic viscosity of invert drilling fluids with an oil to water ratio of 40/60 depending on temperature changes.

**Figure 3.** Changes in the yield point of invert drilling fluids with an oil phase to water phase ratio of 40/60 depending on temperature changes.

**Figure 4.** Changes in the plastic viscosity of invert drilling fluids with an oil to water ratio of 30/70 depending on temperature changes.

**Figure 5.** Changes in the yield point of invert drilling fluids with an oil phase to water phase ratio of 30/70 depending on temperature changes.

The invert drilling fluid with an oil phase to water phase ratio of 40/60 at 20 ◦C and atmospheric pressure is characterized by a plastic viscosity of 52 mPa·s and a yield point of 10.5 Pa (Figures 2 and 3). As a result of the temperature of up to 120 ◦C, the plastic viscosity of the drilling fluid is gradually reduced. At 50 ◦C it drops to 39 mPa·s, at 90 ◦C to 32 mPa·s, and at 120 ◦C it reaches the value of 29 mPa·s (Figure 2). Changes in the yield point due to the effect of temperature are similar only to the temperature of 50 ◦C. As a result of heating the drilling fluid to 50 ◦C, the yield point decreases to the value of 12.4 Pa, then when the temperature rises to 70 ◦C, the yield point slightly increases to the value of 13.4 Pa (Figure 3). Another increase in temperature to 90 and 120 ◦C does not change the yield point of the drilling fluid. In the drilling fluid cooling cycle to the temperature of 20 ◦C, the drilling fluid restores its rheological parameters to the initial values of the drilling fluid before annealing. Plastic viscosity is 2 mPa·s higher and the yield point is 1 Pa higher.

The invert drilling fluid with an oil phase to water phase ratio of 30/70 at 20 ◦C is characterized by a plastic viscosity of 61 mPa·s and a yield point of 16.3 Pa (Figures 4 and 5). As a result of the gradual increase in temperature, the plastic viscosity of the drilling fluid falls. At 50 ◦C, the plastic viscosity of the drilling fluid drops to 50 mPa·s, at 90 ◦C to 46 mPa·s, and at 120 ◦C to 42 mPa·s (Figure 4). In the cycle of cooling the drilling fluid to ambient conditions, the plastic viscosity is restored to the value of 60 mPa·s (Figure 4). When analyzing the diagram of changes in the yield point of the drilling fluid depending on the temperature, it is stated that the decrease in the yield point value takes place to the temperature of 50 ◦C. At 50 ◦C, the yield point has the lowest value of 17.2 Pa. A further increase in temperature to 120 ◦C increases the yield point to 18.6 Pa (Figure 5). In the cycle of cooling the drilling fluid to the ambient temperature, the yield point is reduced to 15.3 Pa (Figure 5). After cooling the drilling fluid to the ambient temperature, it was observed that the drilling fluid withstood the temperature of 120 ◦C and did not decompose into the water and oil phases, and the electric stability value of the ES invert drilling fluid was 660 Volts.

In the next stage of the research, the influence of temperature and pressure on the filtration of invert drilling fluids was observed. The filtration of the drilling fluids was tested on an HPHT filter press at a temperature of 120 ◦C with a differential pressure of 3.4 MPa. The influence of elevated temperature and pressure on the filtration value was investigated for invert drilling fluids with an oil to water phase ratio of 50/50, 40/60, 30/70 and 20/80. The test results are shown in Figure 6.

**Figure 6.** Filtration loss of invert drilling fluids depending on the ratio of the oil phase to the water phase at the temperature of 120 ◦C and a differential pressure of 3.4 MPa.

The filtration of an invert drilling fluid with a 50/50 ratio of the oil phase to the water phase at a temperature of 120 ◦C is 2.4 cm3/30 min. Lowering the share of the oil phase in the invert drilling fluid to 40% increases filtration of the drilling fluid to 2.8 cm3/30 min (Figure 6). As the concentration of the water phase in the invert drilling fluid increases, the filtration increases. In an invert drilling fluid with a 30/70 ratio of the oil phase to the water phase, filtration increased to 3.6 cm3/30 min. The highest filtration, which is 10 cm3/30 min, was recorded for the invert drilling fluid with an o/w ratio of 20/80 (Figure 6).

The performed tests confirm that the drilling fluid shows high temperature resistance while maintaining the electrical stability of ES of over 570 Volts under variable pressure and temperature.

#### *4.3. Investigation of the Influence of Selected Invert Drilling Fluids on the Change of the Permeability Coefficient of Reservoir Rocks*

The study of the reservoir rock permeability coefficient was carried out on sandstone cores with permeability from 28.57 to 34.55 mD. The results of the study of permeability changes of reservoir rock samples are presented in Figures 7 and 8. To determine the impact of changes in the permeability of reservoir rocks, the developed invert drilling fluids with an oil phase to water phase ratio of 50/50, 40/60, 30/70 and an invert drilling fluid with an oil phase to water phase ratio of 80/20 were selected for comparison.

On the basis of the analysis of the obtained results and the presented drawings (Figures 7 and 8), it is concluded that the tested drilling fluids, depending on the water phase content, have a different effect on the amount of damage to the permeability of the rocks in the near-hole area. The highest value of the sandstone reflux permeability coefficient is obtained by operating the drilling fluid with an oil phase to water phase ratio of 40/60. Measurements of changes in the hydraulic conductivity for gas show that the tested drilling fluid at a differential pressure of 2 MPa causes slight damage to the reservoir rock permeability. The final value of the permeability coefficient after the effect of the drilling fluid decreases from 34.55 to 31.78 mD (Figure 7). The calculated loss of sandstone hydraulic conductivity for gas is 8.02% (Figure 8).

**Figure 7.** Influence of the type of invert drilling fluid on the change of sandstone gas permeability.

**Figure 8.** Loss of permeability of tested samples after the effect of invert drilling fluids for gas.

In comparison, the sandstone permeability coefficient was measured after treatment with an invert drilling fluid with an o/w ratio of 80/20. As a result of the contact of the drilling fluid with the reservoir rock, a decrease in the hydraulic conductivity of the reservoir rock sample is visible from 28.57 to 25.37 mD (Figure 7), which results in a loss of the sample's permeability by 11.20% (Figure 8).

Another permeation test was carried out for an invert drilling fluid with an oil phase to water phase ratio of 50/50. Balancing the amount of the oil phase in relation to the water phase reduces the sandstone permeability coefficient from 31.93 to 26.31 (Figure 7). The drilling fluid damages the sample permeability by 17.60% (Figure 8).

The greatest decrease in reservoir rock permeability among the invert drilling fluids selected for the tests was observed after using a drilling fluid with an oil phase to water phase ratio of 30/70. Permeation studies show that the drilling fluid causes a loss of permeability of the sandstone sample by 42.65% (Figure 8). The permeability coefficient after the effect of the drilling fluid decreased from the value of 32.57 to 18.68 mD (Figure 7).

#### **5. Conclusions**

**Author Contributions:** Conceptualization, S.B., G.Z., B.J. and M.K.; methodology, S.B.; validation, S.B., G.Z., B.J. and M.K.; formal analysis, S.B. and G.Z.; investigation, S.B.; resources, G.Z., M.K. and B.J.; data curation, S.B.; writing—original draft preparation, S.B.; writing—review and editing, G.Z., B.J. and M.K.; visualization, S.B.; supervision, S.B.; project administration, S.B. All authors have read and agreed to the published version of the manuscript.

**Funding:** This research was funded by the Ministry of Science and Higher Education Warsaw (Internal order Oil and Gas Institute—National Research Institute Project No. 0044/KW/20).

**Institutional Review Board Statement:** Not applicable.

**Informed Consent Statement:** Not applicable.

**Data Availability Statement:** Not applicable.

**Conflicts of Interest:** The authors declare no conflict of interest.

#### **Nomenclature**

#### **References**

## *Article* **Study of the Long Term Acid Gas Sequestration Process in the Borz ˛ecin Structure: Measurements Insight**

**Marcin Warnecki \*, Mirosław Wojnicki, Jerzy Ku´snierczyk and Sławomir Szuflita**

Oil and Gas Institute—National Research Institute, 25 A Lubicz Str., 31-503 Krakow, Poland<EMAIL_ADDRESS>(M.W<EMAIL_ADDRESS>(J.K<EMAIL_ADDRESS>(S.S.)

**\*** Correspondence<EMAIL_ADDRESS>
**Abstract:** Geological sequestration of acid gases, including CO2, is now a growing solution to prevent progressive Earth climate change. Disposal of environmentally harmful greenhouse gases must be performed safely and securely to minimise leakage risk and possible uncontrolled emissions of injected gases outside the sequestration structure. The paper describes a series of research activities at the Borz ˛ecin sequestration site located in western Poland, which were designed to study the migration paths of injected acid gases (mainly mixture of CO2 and H2S) into the water-bearing layers underlying natural gas reservoir. Along with understanding the nature and dynamics of acid gases migration within the sequestration structure, the research was also addressed to assess its leak-tightness and the long-term safety of the entire reinjection facility. As a part of the research works, two downhole sampling campaigns were completed in 2018–2019, where samples of water underlying the Borz ˛ecin reservoir were taken and subsequently studied to determine their physicochemical parameters that were never before examined. Compositions of gas dissolved in downhole brine samples were compared with produced and injected gas. Relevant studies of reservoir water from selected wells were performed, including isotopic analyses. Finally, four series of soil gas analyses were performed on the area surrounding the selected well, which are important for the hazardous gas sequestration safety analysis in the Borz ˛ecin facility. All the above mentioned research activities aimed to acquire additional knowledge, which is valuable for risk assessment of the acid gas sequestration process taking place on the specific example of the Borz ˛ecin site operating continuously since 1996.

**Keywords:** CO2 and H2S geological sequestration; acid gas reinjection; acid gas migration; bottomhole sampling; isotopic composition; gas and water chemical analysis; soil gas analysis; leakage risk analysis

#### **1. Introduction**

The safety of carbon dioxide and other acid gases underground storage is an obvious and critical issue for this kind of activity. Geological storage must ensure leak-tightness for the hazardous substances deposited there for many hundreds of years. The paper describes selected research activities conducted by the Oil and Gas Institute—National Research Institute (OGI—NRI) within the SECURe project focused on the acquisition of measurement data confirming (or not) safety of long-term acid gas sequestration process in the Borz ˛ecin site located in Western Poland.

First acid gas (containing significant concentration of acid components e.g., CO2, H2S) reinjection into a depleted oil reservoir was started in 1989 in Alberta, Canada. By the end of 2003, about 4.5 Mt of acid gas (2.5 Mt of CO2, and 2.0 Mt of H2S) was injected into deep saline aquifers and depleted hydrocarbon reservoirs at 48 sites in Canada [1–3]. It should be emphasised that the Borz ˛ecin injection project was the first full scale, acid gas reinjection process of practical value into the producing gas reservoir, put into operation in 1996 [4,5]. In 2004, a similar process at a larger scale has been executed in the Krechba field in Algeria by BP and Statoil [6,7], and the reinjection of produced CO2 started at the K12-B

**Citation:** Warnecki, M.; Wojnicki, M.; Ku´snierczyk, J.; Szuflita, S. Study of the Long Term Acid Gas Sequestration Process in the Borz ˛ecin Structure: Measurements Insight. *Energies* **2021**, *14*, 5301. https:// doi.org/10.3390/en14175301

Academic Editors: Dino Musmarra and Attilio Converti

Received: 18 June 2021 Accepted: 22 August 2021 Published: 27 August 2021

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**Copyright:** © 2021 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

in the Netherlands operated by GDF-SUEZ [8,9]. In the Borz ˛ecin project, acid gas has been reinjected into the water-bearing zone underlying the gas cap, from which natural gas has been constantly produced.

Slightly different projects were then implemented in Sleipner gas field and Weyburn oil field. In the case of gas produced from Sleipner, the recovered CO2 is reinjected into the separate Utsira aquifer, whereas Weyburn is a typical EOR-CO2 project [10]. At that time, the sequestration of acid gas into the same reservoir was in the early stages of development. Together with K12-B, the Borz ˛ecin project was then innovative on a global scale, also in the domain of reservoir engineering. It required the performance of detailed simulations with the assumption that it was possible to rationally reconcile the simultaneous recovery of gas and reinjection of acid gas into the water-bearing zone, and that it would be in accordance with applicable laws and the principles of rational exploitation. The challenge also was to not inject sour natural gas, which was already done in Canada and the Netherlands, but a reactive mixture of H2S and CO2.

Borz ˛ecin is considered to be a unique experimental plant which allows us to investigate the acid gas sequestration process for 25 years of its operation and possibly for a few more years to come. Contrarily to other large reservoirs, the small capacity of the onshore Borz ˛ecin structure enable to effectively control and analyse the detailed mechanisms taking part in the sequestration process at a relatively short term scale [4].

The described unique site of acid gas injection to depleted natural gas reservoir was examined. The goal of the research was to identify the intensity and propagation of acid gas migration within the structure and potential pathways towards the ground surface. A number of tests and measurements were conducted, that directly and indirectly were connected with the assessment of containment, and thus the analysis of safety in the longterm perspective. Most of the tests and measurements described in the paper were never performed at the Borz ˛ecin sequestration structure before, that is why the data obtained are highly valuable.

#### **2. Bottomhole Sampling of Reservoir Water Saturated with Gas**

The reinjected acid gas is a waste product of the amine sweetening plant used for processing produced sour natural gas. The injection of acid gas into the B-28 well is continuous, and injection rate is dependent on the current production rates of four producing wells. The acid components that have been separated from produced sour natural gas are reinjected into the sequestration structure in a closed loop. The current injection rate of acid gas is 0.9 t/day. The acid gas reinjected through the B-28 well partly dissolved in formation water adjacent to the well. Because of full hydrodynamic connectivity, the water- and gas-bearing zones remain in equilibrium. Water underlying the gas reservoir remains naturally saturated with natural gas. The undissolved gas occurs in the aquifer in the form of immobile dispersed bubbles. Having exceeded the critical gas saturation of the brine, the acid gas will gravitationally migrate upwards in the reservoir, and will penetrate the gas zone leading to a gradual mixing with the reservoir gas. Compositional changes of gas produced by the individual wells, and actually the occurrence of increased CO2 or H2S concentrations provides information on the propagation of acid gases plume migration within the gas zone of the Borz ˛ecin sequestration structure. From the beginning of functioning of the acid gases reinjection facility, there were attempts to monitor migration of fluids in the reservoir. In quarterly intervals the composition of natural gas produced from different wells was analysed.

To obtain a more consistent picture of acid gas plume migration in the Borz ˛ecin structure it was decided to obtain bottomhole samples (underground sampling—recovery of reservoir samples from the well) of reservoir water, i.e., brine situated immediately below the gas reservoir. In the history of the Borz ˛ecin sequestration operation, such samples were not obtained before. Small volumes of liquid are sampled using a bottomhole samplers driven into the well (Figure 1) [11]. After lowering to a pre-set depth, the sampler is hermetically closed and the fluid (gas/oil/water) remains isolated in its chamber preserving the pressure and temperature at the moment of sampling, hence in situ reservoir conditions [12–15]. Taking such samples allows the determination of the composition of gas dissolved or dispersed in the reservoir water before these gases will penetrate to the gas zone of the structure. After pulling out the sampler from the well, the sample of water saturated with gas was subject to separation, which resulted in obtaining the gas, entirely dissolved or dispersed in the water phase at in situ reservoir conditions, and degassed reservoir water.

**Figure 1.** Sampling of bottomhole samples; (**a**) assembling lubricator at B-24 well; (**b**) pulling out the bottomhole samplers from the B-22 well lubricator.

(**a**) (**b**)

Within the SECURe project, 10 operations of bottomhole sampling of reservoir water underlying the Borz ˛ecin gas reservoir were carried out within two campaigns in 2018–2019. The majority of bottomhole sampling operations were successful. Samples of reservoir water saturated with gas were obtained from wells B-4, B-6, B-22, and B-24. In wells B-4, B-6, and B-24 it was possible to obtain the research material twice—year after year—which is an additional advantage for comparative analyses. Despite attempts, no bottomhole samples from wells B-21, B-27, and B-30 were obtained. The main reason was the lack of water at the pre-set depth of samplers driving—albeit there were attempts to drive them to the maximum safe depth determined by the drift mandrel with an overflow bailer driven down to the well.

In the two producing wells (B-4 and B-22), the gas saturation with water was increased, approximately 0.6 Nm3/m3 (gas dispersed and dissolved), in the others closed, the gas saturation was at dissolved gas level, i.e., 0.3 Nm3/m3. Figure 2 presents the location of wells on the structural map of Borz ˛ecin reservoir. The B-28 injection well is marked with a black square. The wells, where sampling of reservoir water was successful, are marked with green triangles, while those, from which despite efforts made, were not possible, with red ones.

**Figure 2.** Map of Borz ˛ecin reservoir—sampling activities [16].

#### **3. Gas Analyses**

As previously described, after the separation of water and gas phases, gas and water samples for further tests were obtained. Their volume was measured, they were then sealed for transport to the laboratory. Water samples were subject to detailed physical and chemical analyses. The samples of gas released from the reservoir water were subject to chromatographic analyses and isotope composition determinations (abundance of each isotope in atom %). To perform chromatographic analyses of gas, a two-channel gas chromatograph was used—Agilent 7890A. A Nickel Catalyst Tube G2747A connected with a flame detector was used to determine trace amounts of CO and CO2. Argon and nitrogen were used as the carrier gas in gas chromatography. The uncertainty of individual components measurement is 3%. The isotopic composition of stable carbon, hydrogen, and nitrogen isotopes was performed using Trace GC Ultra chromatograph (30-m HP-PLOT/Q capillary column with a diameter of 0.32 mm) coupled with Delta V Advantage isotope ratio mass spectrometer.

#### *3.1. Gas Released from the Reservoir Water*

The recording, in the tested gas composition, of increased (in respect to the natural) concentrations of components of the gas injected to the reservoir (such as CO2 and H2S) is an important piece of information on directions and intensity of acid gases migration within the structure. The simplified results of gas analyses are presented in Figure 3.

**Figure 3.** Composition of the gas dissolved in the Borz ˛ecin reservoir water.

It should be noted that from certain wells (B-4, B-6, B-24) samples were taken twice (in 2018 and 2019), and, in addition, a part of those samples were analysed in separate laboratories. Methane is the main hydrocarbon component of the gas released from the reservoir water, with an average content of approximately 60 mol% based on 10 analyses. The next are: ethane (1.4 mol%) and propane (0.16 mol%)—the other hydrocarbon components are negligible (below the significance level to the studied phenomena), and they were not included in the presented specification. The non-hydrocarbon components are dominated by nitrogen (approximately 20 mol%), followed by carbon dioxide (on average 1.5 mol%, but in samples originating from the B-4 well its amount is highest, reaching 4.6 mol%). Small amounts of helium (on average slightly more than 0.1 mol%) were also identified in each sample. Additionally, strongly varying hydrogen concentrations were determined in the studied gases. For two productive wells (B-4 and B-22), the values are relatively low, i.e., on average, approximately 1.3 mol%, while for the other wells, turned out from gas production, the hydrogen concentrations were much higher—on average 30 mol%. The highest hydrogen concentrations (reaching almost 40 mol%) were recorded in the B-24 well, which will be discussed hereafter. Hydrogen sulphide, on an average level of 3.4 mol%, was identified only in the gas samples from the B-4 well.

To estimate the direction and intensity of acid gases migration, the CO2 and H2S concentration in relation to the distance from the injection well was also analysed. Studies showed that water originating from the Borz ˛ecin-4 well is saturated to the largest extent with carbon dioxide and hydrogen sulphide, hence the acid gases reinjected to waterbearing layers. In each of the three analyses of gas released from the B-4 reservoir water, the determined groups exceeded many times the levels observed in the other wells from which bottomhole samples were taken (B-6, B-22, B-24). The analysis of arrangement and mutual distances of the wells mentioned above to the injecting well helps understand the concentration distribution. As shown in Figure 2, the B-4 well is situated closest to the well injecting acid gases. Moreover, it is located south of B-28, that is in the direction of the expected migration of acid gases upwards the structure, directed by gravity forces, but also by a depression of pressure caused by continuous gas production from the reservoir—now by four wells, i.e., B-4, B-21, B-22 (most productive), and B-27. It also should be noted that the gas containing hydrogen sulphide at an average level of 3.4 mol% was detected only in samples originating from the B-4 well (along a straight line 630 m away from the B-28 well). This is a very high concentration, considering that in samples from the other wells hydrogen sulphide was not identified at all.

Considering the chromatographic results, attention should be paid to the unusually high concentration of hydrogen originating from the B-24 well, which has been out of operation since 2013. During the workover carried out in 2014, the set of tubing section in the well was replaced. Unfortunately, part the of tubing section was lost and left in the well. The last pulled out production tubing section was entirely damaged by corrosion. Despite reconstruction works, no satisfactory gas production was achieved, and the well remains out of operation. Some information on the well history was provided here to explain that in the gas originating from the B-24 well, record hydrogen concentrations of 26 ÷ 40 mol% were registered. Unexpectedly high hydrogen concentrations were the reason for transferring the backup gas samples to an additional laboratory (Lab-2) to verify the analysis. The confirmed very high hydrogen concentration is related to progressing corrosion of the lost part of the tubing. The bottomhole brine was sampled approximately 13 m above the tubing failure. It features a very low degree of saturation with gas, estimated on average at 0.2 Nm3/m3, therefore, already small amounts of hydrogen can substantially increase its percentage concentration. The well remained out of operation for years, resulting in minimal water exchange between the well annulus and the aquifer. This provides favourable conditions for progressive corrosion, which leads to continuous water saturation with hydrogen. The methane, nitrogen, and other gas components contents are necessarily proportionally lower at very high hydrogen concentrations. No hydrogen sulphide was found in any of the analysed samples, which could be partially related to the H2S consumption during the corrosion reaction. The carbon dioxide concentration, on average, is 0.14 mol%, so it maintains a very low level. It should be concluded that the acid gases migration did not also reach the out-of-operation B-24 well.

#### *3.2. Produced Gas*

The gas from the Borz ˛ecin reservoir is currently produced with four wells, i.e., B-4, B-21, B-22, and B-27. Samples of the gas, produced by individual wells and of water produced with gas, were taken from the surface installation in May 2019. The samples for testing were taken from the reduction-measurement lines, separate for each productive well [17,18]. The analyses showed that methane prevails among hydrocarbon gas components, with an average content of 66.77 mol%; the next ones are ethane (1.91 mol%) and propane (0.31 mol%)—the other hydrocarbon components due to their negligible concentrations are omitted. The non-hydrocarbon components are dominated by nitrogen (on average 30.16 mol%), carbon dioxide is next (on average 0.41 mol%, but in samples originating from the B-4 well its amount is highest—0.68 mol%). The analysis of gas released from bottomhole water samples revealed increased CO2 and H2S concentrations only in the B-4. As shown in Figure 2, the B-4 well is located closest to the well injecting the acid gas. Therefore, there is a phenomenon of increasingly rising penetration of the injected gas to the produced gas. Additionally, small amounts of helium (on average 0.18 mol%, at relatively small concentration differences between the wells) were identified in each

of the four producing wells. In addition, small hydrogen concentrations (approximately 0.01 mol%, but in the B-4 again, the highest, 0.03 mol%) were determined in the tested gases. Hydrogen sulphide was identified in the gas from each well. Its amount is highest in the gas from the B-4 (0.18 mol%) and from the B-27 (0.15 mol%), albeit the analysis of historical data shows that H2S concentrations exceeding 0.2 mol% were determined in the past. The results are summarized in Figure 4.

**Figure 4.** Composition of the produced gas.

#### *3.3. Injected Gas*

In February 2020, a pressurized gas sample was taken from the acid gases injection installation. Currently reinjected to the Borz ˛ecin reservoir gas composition, revealed using chromatographic analysis is shown Figure 5. Carbon dioxide prevails among the main gas components (with an average concentration of 79.9 mol%), hydrogen sulphide is next (on average 19.0 mol%). In general, the acid components (CO2 + H2S) constitute 99% of the injected gas composition. Minor amounts of hydrocarbon components are the remainder. Methane was identified with an average content of 0.93 mol%, the next ones are ethane (0.04 mol%), and propane (0.01 mol%). The other hydrocarbon components were omitted in the presented specification due to their negligible concentration. Trace amounts of helium and hydrogen appear occasionally; in most cases, both gases are below the threshold of method detectability (<0.01 mol% for He and <0.001 mol% for H2).

**Figure 5.** Current composition of the injected gas.

#### *3.4. Isotopic Composition*

Molecular and isotopic compositions of gases can provide information on their origin, maturity, and crucially on compositional change due to migration [19]. Their applications for development, production, and operation issues are increasing [20,21]. The determination of isotope composition of stable carbon, hydrogen, and nitrogen isotopes in gas dissolved in brine and in the produced (free) gas was performed. It allowed to investigate the possible temporal and spatial variability and to make an attempt to assess the migration of the injected gas components based on analyses from individual wells. In 2018, isotope determination was carried out for gas from degassing of downhole reservoir brine samples from the B-4, B-6, and B-24. A year later, in addition to repeated isotope determination in the above wells, an analysis for the B-22 well was also successfully completed. These are the first studies of such type at that site. As part of the isotope analyses, the values of carbon (δ13C) in methane, ethane, propane, and carbon dioxide, deuterium (δD) in methane, and nitrogen (δ15N) in molecular nitrogen were determined. In total, in the framework of the SECURe project, the above isotope composition was determined for 11 samples, including 3 brine degassing gas samples drawn in 2018, 4 brine gas degassing samples, and 4 produced gas samples drawn in 2019.

The isotope composition of carbon in methane ranged from −35.9‰ to −34.4‰ (average −35.1‰), in ethane from −30.57‰ to −30.1‰ (average −30.2‰), in propane from −26.4‰ to −26.0‰ (average −26.2‰), and in carbon dioxide from −17.58‰ to −3.71‰ (average −10.4). The isotope composition of hydrogen in methane was in the range of: −133.5‰ ÷ −106.9‰ (average −118.4‰), while the isotope composition of nitrogen ranged from −0.4‰ to 5.2‰ (average 3.4‰).

A relationship of the carbon stable isotopes values in methane and carbon dioxide is used to determine the genetic type of the gas (Figure 6).

**Figure 6.** Carbon isotopic composition of methane versus carbon dioxide [22].

The location of points corresponding to the analysed samples on the graph of the δ13C-C1 and δ13C-CO2 relationships indicates mainly the thermogenic origin of the gas, although a shift of some points towards the area typical for endogenous gases is also noticeable (Figure 6). The shift of those results towards the area of endogenic gases can be attributed to the enrichment of carbon dioxide in the heavy 13C isotope and it applies to some of the samples of gas dissolved in brine, drawn both, in 2018 and 2019. In the samples of gas dissolved in brine carbon isotopic composition of CO2 could be shifted towards heavier values as a result of easier dissolving of isotopically lighter CO2 in brine. Such dissolution results in enrichment of CO2 with 13C in natural gas. The enrichment of carbon dioxide in a heavier isotope may result from pressure changes in the reservoir caused by annual downtime and release of gas from the blind parts of the reservoir (ventilation/homogenisation). Such an enrichment in the heavier 13C isotope can also result from the reduction of carbon dioxide.

The isotope composition of carbon in methane, ethane, and propane appears to be unchanged and independent of the type of gas sample drawn and the time of sampling. The differences in the extreme values of carbon isotope composition in methane are about 1.5‰ (approximately 4%) and, in ethane and propane, ca. 0.4‰ (approximately 1.5%).

However, some changes in the isotope composition of hydrogen in methane are noticeable. The isotope composition of hydrogen in the extracted gas samples is distinguished

by enrichment in a heavier isotope, the deuterium, relative to gas samples from brine degassing drawn in 2019 (Figure 7).

**Figure 7.** Variability of the isotope composition of hydrogen in methane.

#### **4. Reservoir Water Analysis**

The analyses of physiochemical parameters of bottom water underlying the Borz ˛ecin reservoir were carried out by testing downhole samples drawn from the productive wells B-4, B-6, B-24, and B-22 and surface samples of water drawn from the wells B-21, B-22, and B-27. The tests of the downhole samples in wells B-4, B-6 and B-24 were repeated at approximately one-year interval.

In most cases, the analysed water is in the form of reservoir brine. Only the samples drawn from the B-22 (downhole sample) and B-22 (surface sample) wells bear the marks of condensation water and will not be a part of further considerations.

The liquid was from colourless to yellowish green. In most cases, the liquid had an opalescent suspension of sulphides visible to the naked eye. The odour of hydrogen sulphide was clearly perceptible.

The amount of substances dissolved in the analysed samples falls within the range 228 to 251 g/L, with 243 g/L on average. The density takes values in the range 1.153 to 1.166 g/cm3, 1.156 g/cm3 on average. The conductivity is on average 205 mS/cm. The pH of the samples analysed ranges from 4.5 to 6.5 with an average of 5.4. The chemical composition of the brine analysed is dominated by chloride and sodium ions. The percentage of chloride ion among anions is greater than 99%. While that of sodium ions among cations is ~78%. The averaged percentage of anions and cations (%mval) is shown in Table 1.

**Table 1.** Average ionic composition of the reservoir brine.

Differences in the concentration of individual components between samples drawn from individual wells are insignificant and, in the case of anions, even negligible (on average below 0.1 percentage point). For cations, the differences observed, mainly concerning Ca2+ and K+, are slightly higher and amount to a maximum of ~3 percentage points.

The chemical analyses repeated for the same wells at an annual interval did not show significant changes in the concentration of individual components over time either. A slight increase in the percentage of Na+. NH4 <sup>+</sup> and Mg2+ cations can be observed at the cost of the Ca2+ and K<sup>+</sup> ones. However, those changes are slight, below 1 percentage point.

In the water samples analysed, the presence of dissolved hydrogen sulphide was found in the range of 0.015 to 0.065 g/L (0.039 g/L on average) and sulphides in the range of 0.0016 to 0.0056 (0.0033 g/L on average).

Salinity and alkalinity of brine calculated by the Palmer method [4], take the following averaged values:

Table 2 presents a set of hydrochemical indicators calculated on the basis of the ionic content of individual components

Based on the physiochemical parameters and hydrochemical indicators presented above, it can be stated that the bottom water underlying the Borz ˛ecin reservoir, to which acid gas is injected, is composed of approximately 24% Cl-Na binary brine. According to Sulin classification [23], it is a calcium chloride type. The values of hydrochemical coefficients indicate a high degree of metamorphosis of the brine analysed. It is a quality typical of highly metamorphosed fossil brines originating from formations with very high hydrogeological tightness. Local variability in the chemical composition of brine is highly related to the performance of the wells injecting waste brine. Reservoir water with diverse chemistry account for the majority of waste brine injected, originating from the nearby oil and gas reservoirs.

#### **5. Solubility Study**

Determination of the solubility (Rs) both of the produced gas and the acid gas reinjected to the reservoir brine was a significant test for considerations of migration of the injected gases in the aquifer underlying the Borz ˛ecin reservoir. Solubility tests were carried out at the reservoir temperature and in five pressure steps, based on which the solubility curve was drawn. Similar studies are presented in the number of papers [24–26], however it was crucial to determine the solubility properties of particular fluids originating from the Borz ˛ecin site. The injected acid gas features definitely much higher solubility in the reservoir brine, even 23 times more—depending on the pressure, than the produced gas. Figure 8 present results of solubility study—solubility coefficient versus pressure.

Rs [Nm3/m3]

**Figure 8.** Solubility of gases in Borz ˛ecin reservoir water.

#### **6. Soil Gas Analysis**

For containment evaluation of the Borz ˛ecin sequestration structure and the safety of acid gas storage, it was necessary to perform environmental studies, including soil gas analysis. This task aimed to investigate changes in the soil gas composition of the ground located directly above the reservoir [27,28]. Currently, these areas are mainly agricultural (cultivated fields, and partly forested). The study was conducted in four cycles between October 2019 and March 2020.

At selected sampling points, mainly around the wellheads, drive-in probes were installed, or appropriately designed monitoring wells were dug in to facilitate the inflow and collection of soil gas from a given area. Then, the chromatographic analysis of the collected gas was conducted to reveal its chemical composition. The composition of soil gas was analysed along with its variation potentially resulting from different locations of sampling points, different age, and purpose of the wells around which the probes were placed or different time of sampling (e.g., autumn vs. winter) [29].

#### *6.1. Well Selection and Sampling—Measurement Series 1–3*

In order to determine the potential influence of sour gases injection into the Borz ˛ecin reservoir on soil air composition, the measurements of its composition were performed. The air specimens were sampled from monitoring wells, located at three boreholes, that is B-6—currently inactive, observation borehole, although most of gas from this reservoir has been produced by this borehole; B-22—currently the best producer, and B-28—the borehole injecting sour gases into an aquifer, underlying the natural gas reservoir—Figure 2.

The Borz ˛ecin-28 borehole was drilled in 1987. Despite several intensification jobs, including two-stage acid-treatment, an industrial production of gas was not achieved from it, so it has been intended for liquidation. In 1994, workover jobs have been completed to adapt the well for sour gas reinjection. The B-28 well is the crucial element of sour

gas reinjection on the Borz ˛ecin sequestration facility, and its proper technical condition is principally decisive of whole undertaking safety.

The monitoring wells were installed on October 2019. They were located directly at the wells (at the wellhead within the near well zone) and at a distance of approximately 35 m from the wellhead. An example of the location of the measuring points at the B-6 well is shown in Figure 9.

**Figure 9.** Location of measuring points at the B-6 well.

The gas was sampled from six 2-metre-deep monitoring wells. A monitoring well was made of PE pipe embedded in gravel backfill. In the lower part of the pipe, along an 80 cm section, there was a perforation made enabling the free inflow of soil gas. The sampling was carried out using glass pipettes and a vacuum pump—Figure 10.

**Figure 10.** Soil gas sampling from a monitoring well located within the B-28 well pad: (**a**) from a monitoring well located within the B-28 well pad; (**b**) from a monitoring well located within 35 m of the B-28 wellhead.

(**a**) (**b**)

#### *6.2. Determination of the Sampled Gas Composition—Measurement Series 1–3*

The composition of gas sampled in the first three measurement series was examined. Chromatographic analyses of the sampled gas were performed using a two-channel valve Clarus 680 GC Perkin Elmer-Arnel chromatograph with thermal conductivity (TCD) and flame ionisation (FID) detectors. The apparatus was coupled with TotalChrom Navigator software. A total of three measurement series were completed. No hydrogen sulfide was detected (threshold of 0.0001 mol%) in any of the samples, while carbon dioxide concentrations did not exceeded acceptable natural levels associated with agricultural areas and ranged 0.1 to 0.7 mol%. Simplified chart with hydrocarbons content in samples taken at the B-6, B-22, and B-28 wells (series 1–3) is presented in Figure 11.

**Figure 11.** Hydrocarbons content in samples taken at the B-6, B-22 and B-28 wells.

Among the results from the first three measurement series, no values were observed which could suggest uncontrolled emission (leakage) of injected acid gases into the soil air. However, due to the presence of higher hydrocarbons in some samples, it was decided to perform another series of measurements, taking into account an increased number of measuring points around the indicated productive wells.

#### *6.3. Wells Selection and Sampling—Measurement Series 4*

Two wells were selected for further examination: B-23—the well injecting waste brine into the reservoir and B-24—the well in which progressing corrosion has led to a partial loss of production tubing. The B-23 well has been producing gas from the reservoir since 1988. The well has been inactive since December 1997 due to water encroachment. In 2004, the well was reconstructed to adapt it for waste brine injection (mainly water produced from other reservoirs). In 2005 and 2007, injectivity tests were performed on the well. For two years it has been one of the four wells through which waste brine to the Borz ˛ecin reservoir is injected. The B-24 was productive well since 1985 till 2013, when during workover a section of tubing was lost, and the well remains out of production. Within the SECURe project, the downhole reservoir water sampling was performed twice

in the B-24 well (in September 2018 and July 2019). The sampling depth was 1330 m below ground level. Chemical analyses of the gas separated from the brine demonstrated an increased concentration of hydrogen—over 30 mol%, which, given the above producing tubing issue, can prove the occurrence of electrochemical corrosion and hydrogen release in the well. Therefore, the B-24 well was selected for the extended examination of the soil air composition.

Around the two wells selected for measurements, 18 driven-in monitoring probes were deployed, each with a 1 m depth, 9 units per well. The measuring points were centrally located within approximately 25 m and 50 m distances from the wells and at the wells themselves—Figure 12. A hammer drill was used to make the holes for the probes. Then, a perforated PE pipe with a socket with a built-in measuring connector was placed in the holes. Perforation made on a part of the pipe allowed free flow of soil gas into the probe. The probes were installed in such a manner that the measuring connections were located at the ground surface. After 9 days, soil air samples from the installed probes were drawn into glass bulbs and handed over for further analysis. Samples were taken from 16 holes. Sampling soil air from two probes located beside the B-24 well was unsuccessful. That was presumably caused by the groundwater level being too high, preventing free flow of air into the probes.

**Figure 12.** Location of measuring points around the B-23 well.

#### *6.4. Determination of the Sampled Gas Composition—Measurement Series 4*

Examination of gas composition from 16 samples contained in glass bulbs within the fourth measurement series was performed. As in the measurement series 1–3, no hydrogen sulphide was detected (threshold of 0.0001 mol%) in any of the samples, while carbon dioxide concentrations did not exceeded acceptable natural levels associated with agricultural areas and ranged 0.1–2.1 mol%. Simplified chart with hydrocarbons content in samples taken at the B-23 and B-24 wells (series 4) is presented in Figure 13.

**Figure 13.** Hydrocarbons content in samples taken at the B-23 and B-24 wells.

The potential negative impact of acid gases injection into the Borz ˛ecin reservoir should be considered primarily in terms of the possibility of direct uncontrolled leakage of acid gases into the soil air along the production well structure. That process could then be manifested by an increased content of, in particular, CO2 as the dominant component, and the presence of H2S in the soil air. In order to determine the potential of such hazards, a total of 24 monitoring wells/probes were deployed, and 34 soil air samples were drawn for examination.

Among all the results of analyses carried out in series 1–4, including the B-28 well used for injecting acid gases into the reservoir, no values were observed that could suggest uncontrolled emission of injected gases into the soil air. Analysing the results, it should be kept in mind that carbon dioxide is a gas that is part of typical soil air, and the main factors affecting its level include the activity of microorganisms and the roots of higher plants, temperature, humidity, depth, soil aeration degree, and atmospheric pressure. Furthermore, the area where the research was conducted should be taken into account. In the case of the four wells, it was an agricultural area, and forest for the B-6 well. Organic substances occurring naturally in the soil or penetrating into it as a result of human activity (natural fertilizers, crops residues) are subject to digestion and fermentation processes during which biogenic gas is generated, which consists mainly of carbon dioxide (CO2) and methane (CH4). It can, therefore, be concluded that the low methane concentrations found in some samples are also a consequence of natural processes occurring in the soil. The CO2 levels observed should, therefore, be assumed to be absolutely normal for the type of area [29]. Moreover, the lack of even trace amounts of hydrogen sulphide (H2S) in the samples examined proves the absence of uncontrolled emissions into the soil.

Out of the first three measurement series, completed at the B-6, B-22, and B-28 wells, the results of the third measurement series at the B-6 well and the first and third series at the B-22 well depart from the typical soil air composition that can be found in agricultural areas. The high level of methane (approx. 2.5%) and, in particular, the presence of higher hydrocarbons is likely to result from local gas exhalations from the reservoir. Those exhalations may take place along casing and cement, which may be indicated by higher

levels of contaminants in the samples drawn directly at the wells. Increased methane and ethane values in samples drawn from the B-28 well, in the first and third series, due to the trace content of C3 and higher hydrocarbons, are most likely caused by natural processes occurring in the soil. Those compounds may also have an anthropogenic origin, e.g., soil pollution by ongoing farming and the use of heavy equipment. The remaining samples from series 1–3 contained insignificant amounts of methane, which can be considered as the regional geochemical background.

The fourth measurement series was completed at the B-22 and B-24 wells. The presence of small amounts of methane in soil air samples (up to 0.01%) is a consequence of digestion and fermentation processes (e.g., natural fertilisers), during which biogenic gas is produced. In none of the samples was the content of higher hydrocarbons found in quantities which could imply significant gas exhalations from the reservoir.

#### **7. Summary and Conclusions**

The extensive sampling and testing campaign results, including reservoir fluids and soil gas analyses, are vital sources of knowledge concerning the phenomena occurring in the sequestration structure due to acid gas injection. All the activities conducted are summarised in Table 3.

**Table 3.** Sampling and testing activities.

\* Repeated twice.

Downhole samples of water saturated with gas are very valuable material for research, and their proper utilisation gives a lot of useful information for better understanding of the processes occurring within the Borz ˛ecin reservoir. So far, such samples have never been obtained before.

Conducted actions and measurements allowed to reach the main goal of the research, which was the identification of acid gas migration characteristics within the structure and

potential leakage pathways. The results of solution gas analysis revealed that the acid gas injected into the aquifer through the B-28 injector well migrate southwards towards the B-4 well. The investigations proved that this is the main direction of the injected acid gas plume propagation. Water taken from the B-4 well is most intensely saturated with reinjected carbon dioxide and hydrogen sulphide. In each of the three analyses of gas separated from B-4 reservoir water, the concentration of CO2 and H2S exceeded many times the levels observed in the other downhole-sampled wells. The B-4 well is closest to the B-28. Moreover, it is located in the direction consistent with the expected migration of acid gas upward the structure, driven by gravity forces as well as by pressure depletion caused by continuous gas production from the reservoir (especially by the B-4 and B-22 wells, where B-22 accounts for 80% of current production).

Research actions were also related to the surface sampling of gas and associated water. As in the case of gas separated from the reservoir water, the chemical analysis of produced gas confirmed the inflow of the injected acid gas into the gas produced (especially) by the B-4 well. Furthermore, an increased concentration of CO2 was also recorded in the gas produced by the B-22 well, which may indicate that the migration zone of the injected acid gas is going to affect the major production well.

Samples of the acid gas were also taken from the reinjection facility. The results of the chemical analysis confirmed stability in the composition of the gas over time. Currently, after the modernisation of the acid gas sweetening facility, the reinjected gas is composed mainly (in 99 mol%) of carbon dioxide and hydrogen sulphide, while the hydrocarbon components represent less than 1 mol%.

The high dynamics of individual phase systems occurring in the structure of the Borz ˛ecin reservoir implies temporal and spatial variability in the isotope composition of the analysed gas from brine degassing and of the produced gas. The system is subject to periodic disturbances related to the process of reservoir exploitation, repeated injection of acid gases and waste brine coming from outside the reservoir. Moreover, the solubility of CO2 in brine and isotope fractionation (hydrogen between methane and brine) may also affect the isotope composition of carbon in CO2 and hydrogen in methane for the brine degassing samples. Additionally, other processes, as microbial or abiotic oxidation of C1 might play role in the d2H (C1) variations.

Based on the physiochemical parameters and hydrochemical indicators, it can be stated that the water underlying the Borz ˛ecin reservoir, to which acid gas is injected, is composed of approximately 24% Cl-Na binary brine. According to the Sulin classification [23], it is a calcium chloride type brine. Local variability in the chemical composition of brine is highly related to the performance of the wells injecting waste brine. Reservoir water with diverse chemistry account for the majority of waste brine injected, originating from the nearby oil and gas production facilities.

Among others, the ability to dissolve the produced and reinjected gases in the reservoir water was also examined. The studies showed that acid gas has excellent solubility in Borz ˛ecin reservoir water. In the current thermobaric reservoir conditions, the solubility of acid gas is about 20 times higher than of the produced gas. This feature indicates that a significant volume of acid gas injected directly into the aquifer dissolves in water and migrate within the structure, remaining in the water zone. This is a positive phenomenon when concerning acid gas sequestration within an active gas reservoir. The dissolution of CO2 and H2S in the reservoir water certainly delays the breakthrough of these components into the natural gas zone.

The soil air analyses carried out so far did not reveal surface leaks of acid gases injected into the Borz ˛ecin structure. Periodically elevated hydrocarbon concentrations at the B-6 and B-22 wells are likely to occur due to natural gas exhalation. To ascertain what their origin is, it is recommended to perform long-term monitoring tests on the identified wells that could be the future venues of research.

**Author Contributions:** Conceptualisation, M.W. (Marcin Warnecki) and M.W. (Mirosław Wojnicki); methodology, M.W. (Marcin Warnecki) and M.W. (Mirosław Wojnicki); investigation, M.W. (Marcin Warnecki); J.K., S.S. and M.W. (Mirosław Wojnicki); writing—original draft preparation, M.W. (Marcin Warnecki); writing—review and editing, M.W. (Mirosław Wojnicki). All authors have read and agreed to the published version of the manuscript.

**Funding:** This report is part of a project that has received funding by the European Union's Horizon 2020 research and innovation programme under grant agreement number 764531. Project acronym and title: SECURe—Subsurface Evaluation of Carbon capture and storage and Unconventional Risks. D2.2 Report on effects of long-term sequestration process in the Borz ˛ecin structure—observation evidence of the injected gas migration and possible leakage.

**Institutional Review Board Statement:** Not applicable.

**Informed Consent Statement:** Not applicable.

**Conflicts of Interest:** The authors declare no conflict of interest.

#### **References**

## *Article* **An Experimental Investigation of WAG Injection in a Carbonate Reservoir and Prediction of the Recovery Factor Using Genetic Programming**

**Mirosław Wojnicki 1,\*, Jan Luba´s 1, Mateusz Gawro ´nski 2, Sławomir Szuflita 1, Jerzy Ku´snierczyk <sup>1</sup> and Marcin Warnecki <sup>1</sup>**

**Abstract:** Production from mature oil fields is gradually declining, and new discoveries are not sufficient to meet the growing demand for oil products. Hence, enhanced oil recovery is emerging as an essential link in the global oil industry. This paper aims to recognize the possibility of increasing oil recovery from Polish carbonate reservoirs by the water alternating gas injection process (WAG) using various types of gases, including CO2, acid gas (a mixture of CO2 and H2S of 70/30% vol/vol) and high-nitrogen natural gases occurring in the Polish Lowlands. A series of 17 core flooding experiments were performed under the temperature of 126 ◦C, and at pressures of 270 and 170 bar on composite carbonate cores consisting of four dolomite core plugs. Original reservoir rock and fluids were used. A set of slim tube tests was conducted to determine the miscibility conditions of the injected fluids with reservoir oil. The WAG process was compared to continuous gas injection (CGI) and continuous water injection (CWI) and was proven to be more effective. CO2 WAG injection resulted in a recovery factor (RF) of up to 82%, where the high nitrogen natural gas WAG injection was less effective with the highest recovery of 70%. Based on the core flooding results and through implementing a genetic programming algorithm, a mathematical model was developed to estimate recovery factors using variables specific to a given WAG scheme.

**Keywords:** enhanced oil recovery; WAG; carbonate reservoir; CO2; acid gas; high-nitrogen natural gas; water alternating gas; EOR; recovery factor; genetic programming

#### **1. Introduction**

The oil recovery factor in conventional reservoirs varies from field to field since it depends on many different variables. The worldwide average is about 30% IOIP (initial oil in place) which means that there is great potential to recover more [1]. That is why enhanced oil recovery (EOR) has been one of the most investigated areas in the petroleum industry in the last decades. Tremendous work has been done so far which has resulted in a vast range of published papers concerning lab-scale research, reservoir modelling, and the outcome of field applications of different EOR methods [2,3]. Despite that, the ultimate profit from EOR applications is below expectation (<10% of total production), and recent studies show that EOR is still in the top priority research and innovation areas in the energy industry [4]. The need to further explore EOR concepts comes from the fact that every EOR process is strongly case-specific and it is difficult to make an analogy to another case, thus requiring specific research, optimization, expertise, and trial field demonstration.

Carbonate reservoirs are of special interest, because they contain more than 60% of the world's remaining conventional oil reserves and account for over 30% of the world's daily oil production [5–8]. Due to the complex oil recovery process in carbonates caused by their

**Citation:** Wojnicki, M.; Luba´s, J.; Gawro ´nski, M.; Szuflita, S.; Ku´snierczyk, J.; Warnecki, M. An Experimental Investigation of WAG Injection in a Carbonate Reservoir and Prediction of the Recovery Factor Using Genetic Programming. *Energies* **2022**, *15*, 2127. https:// doi.org/10.3390/en15062127

Academic Editor: Reza Rezaee

Received: 20 January 2022 Accepted: 13 March 2022 Published: 14 March 2022

**Publisher's Note:** MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.

**Copyright:** © 2022 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

unfavorable reservoir characteristics, recovery factors are even lower with an average of 20% [9–11]. The above include high heterogeneity, mixed- to oil-wet conditions, and dual permeability—poor in rock matrices and high in fractures [12,13].

Most of the EOR projects in carbonates are gas injections (nearly 60%), and the vast majority use CO2 (continuously or alternately with water). Currently, a majority of CO2- EOR projects utilize CO2 from natural sources, but as global discussion on climate change and worldwide efforts on carbon emission reduction intensifies, it is expected that anthropogenic CO2 sources will be more frequently used. Hydrocarbon gas injection projects have a significantly lower contribution for EOR in carbonates. Others such as nitrogen or acid gas (mixture of H2S and CO2) are even less common [1,3,14].

However, EOR gas injection poses significant challenges connected with the high mobility ratio (caused by the significantly lower dynamic viscosity of the injected gas compared to reservoir oil), including viscous fingering and early breakthrough of the injected fluid into production wells [15,16].

To counteract that, a Water Alternating Gas (WAG) injection method was initially designed to control gas mobility and stabilize the gas displacement front during continuous gas injection (CGI) and finally improve sweep efficiency. The method, which combines CGI and waterflooding (continuous water injection—CWI) methods, was first implemented in 1956 in the North Pembina field (Alberta, Canada), and since then has been effectively used worldwide [16–19]. The combination of improved microscopic displacement of CGI with an improved macroscopic sweep of CWI led, in most cases, to enhanced oil recovery. Water slugs stabilize the displacement front and help to sweep crude oil from the lower part of the reservoir [20]. A further essential benefit of WAG is that less gas is required for injection, in favor of the usually cheaper water. In the WAG method, both water and gas are injected to the same well. There are different WAG injection schemes where, e.g., water and gas are injected simultaneously (SWAG) [21,22], a huge slug of gas is followed by a number of conventional WAG cycles—HWAG [23], or the volume of injected gas is gradually reduced over time—TWAG [24].

Gas can be injected under miscible (MWAG) or immiscible (IWAG) conditions that are differentiated by the Minimum Miscibility Pressure (MMP). When the injection pressure is slightly lower than MMP, it is hard to distinguish between miscible and immiscible types because of the subsequent mass transfer mechanisms involved (swelling/stripping), and such conditions should be referred to as "near-miscible" regime (nMWAG) [21,25]. Both MWAG and nMWAG are considered more effective than IWAG [17,26], but many studies revealed that IWAG is also efficient in enhancing oil recovery [27,28]. Miscibility development is not always required for successful WAG implementation, but helps to achieve better results in most cases [10]. The general scheme of WAG injection is shown in Figure 1.

WAG injection has been comprehensively studied with a particular consideration of factors affecting its performance such as reservoir parameters including wettability [29,30] heterogeneity [31–33], and fractures [34], injected fluid parameters including water salinity [35–37] and gas type [15,38], the WAG parameters including the WAG ratio [39,40], the number of cycles, slug sizes [41,42], the timing of injection [43], and finally the injection rates of the gas and water phases [11].

The cyclic nature of WAG leads to an increase in water saturation during the water injection half cycle and a decrease of water saturation during the gas injection half cycle involving associated hysteresis phenomena resulting in complex three phase-flow which makes the prediction of WAG performance very difficult. This was extensively studied by Fatemi, Sohrabi, and Shahverdi [44,45].

**Figure 1.** General scheme of WAG injection (miscible).

Physical simulation of the WAG process in the laboratory is generally done using the core flooding test, which is also used in the presented paper. Several important works were also conducted using micromodel visualization [46–49]. Over the years, a number of experimental studies has been performed in mixed wet carbonates, revealing different process issues and enabling the more effective use of WAG in complex reservoir conditions.