Kazakhstan journal for oil & gas industry

2707-42262957-806X

KMG Engineering

109014

10.54859/kjogi109014

MODELING OF MICROBIAL ENHANCED OIL RECOVERY IN RESERVOIRS CONTAINING HIGH-SALINITY FORMATION WATER: A CASE STUDY OF THE UZEN OIL FIELD

Keldibayeva

Svetlana

S.Keldibaeva@kmge.kzhttps://orcid.org/0000-0002-1825-0097

09062026

13102026

The paper addresses the problem of enhanced oil recovery in reservoirs with high-salinity formation water using the Uzen oil field as a case study. The objective of the study is to model the microbial enhanced oil recovery (MEOR) process considering the effects of salinity, temperature, and reservoir petrophysical properties. A coupled hydrodynamic–biokinetic model is developed to describe nutrient transport, microbial growth, and changes in porous media filtration properties. Scenario-based simulations were performed for baseline, moderate, and enhanced microbial treatment cases. The results show that the application of adapted halophilic microorganisms can increase the oil recovery factor by 10–22% compared to conventional water flooding. It is demonstrated that formation water salinity is the key limiting factor affecting MEOR efficiency. The obtained results confirm the potential of microbial technologies for the further development of mature oil fields.

microbial enhanced oil recovery, Uzen oil field, high-salinity formation water, mathematical modeling, hydrodynamic model, biokinetics, oil recovery factor, halophilic microorganisms, water flooding, porous media.

микробиологический метод повышения нефтеотдачи, месторождение Узень, высокоминерализованные пластовые воды, математическое моделирование, гидродинамическая модель, биокинетика, коэффициент нефтеотдачи, галофильные микроорганизмы, заводнение, пористая среда

Introduction Enhanced oil recovery (EOR) remains one of the most important challenges in the modern petroleum industry, particularly under conditions of depletion of easily recoverable reserves and the transition of most oil fields to the late stages of development [1–4]. At this stage of reservoir exploitation, declining reservoir pressure, increasing water cut, and reduced efficiency of conventional production methods are commonly observed, necessitating the implementation of new technological solutions aimed at recovering residual hydrocarbon reserves. One of the major factors complicating oil field development is the high salinity of formation waters. Elevated salt concentrations in the aqueous phase alter the physicochemical properties of the pore system, reduce the effectiveness of chemical agents, and limit the applicability of several conventional enhanced oil recovery methods [7,18,23]. Furthermore, high salinity may adversely affect reservoir filtration characteristics and oil displacement processes, thereby reducing the overall efficiency of waterflooding operations. In this context, microbial enhanced oil recovery (MEOR) technologies have attracted considerable attention due to their reliance on the metabolic activity of microorganisms [6,8,9,16,17]. During their life cycle, microorganisms are capable of producing biosurfactants, gases, organic acids, and biopolymers that reduce interfacial tension, improve oil mobility, and facilitate the recovery of oil from previously unswept reservoir zones. A significant advantage of these methods is their environmental compatibility and adaptability to a wide range of geological and reservoir conditions. Despite the considerable potential of microbial technologies, their application in reservoirs containing highly mineralized formation water requires additional investigation. This is primarily associated with the limited tolerance of many microorganisms to elevated salinity levels and the need to select adapted microbial strains and optimize nutrient injection strategies [7,19,23]. The objective of this study is to model the microbial enhanced oil recovery process considering the specific characteristics of highly mineralized formation waters at the Uzen oil field and to evaluate the conditions required for effective implementation of MEOR under complex hydrochemical conditions. Geological and Reservoir Characteristics of the Uzen Oil Field The Uzen oil field is one of the major oil fields located within the Caspian petroleum province [22]. It has a long production history and is classified as a mature field at a late stage of development. During the prolonged production period, a significant decline in reservoir pressure, an increase in produced water cut, and a growing proportion of hard-to-recover reserves have been observed. The geological structure of the field is characterized by a complex multilayered architecture comprising productive horizons associated with terrigenous deposits [13,28]. The pronounced heterogeneity of the stratigraphic section has a substantial impact on reservoir petrophysical properties and oil displacement behavior. The reservoirs of the Uzen field are predominantly represented by sandstones exhibiting varying degrees of cementation and grain-size heterogeneity. The pore space is unevenly distributed, resulting in the formation of zones with different permeability characteristics. Reservoir petrophysical properties vary over a wide range, leading to significant heterogeneity of fluid flow within the formation. The presence of high-permeability channels promotes the premature breakthrough of injected water to production wells, thereby reducing sweep efficiency. In addition, clay-rich intervals are present in certain sections of the reservoir, which may decrease permeability and complicate filtration processes. One of the distinguishing features of the Uzen oil field is the high salinity of its formation waters. The concentration of dissolved salts reaches considerable levels, significantly affecting the physicochemical properties of the aqueous phase and the efficiency of oil displacement processes [7,18,23]. High salinity alters the ionic composition of the reservoir system, increases the density and viscosity of the water phase, and reduces the effectiveness of several chemical agents used in enhanced oil recovery operations. Furthermore, elevated salinity creates unfavorable conditions for the survival and metabolic activity of most microorganisms, thereby limiting the application of microbial technologies without prior adaptation of microbial strains. Table 1. Geological and Reservoir Parameters of the Uzen Oil Field <table> <tbody> <tr> <td> Parameter </td> <td> Value </td> <td> Unit </td> </tr> <tr> <td> Reservoir depth </td> <td> 1200–1500 </td> <td> m </td> </tr> <tr> <td> Porosity </td> <td> 0.18–0.26 </td> <td> fraction </td> </tr> <tr> <td> Permeability </td> <td> 50–450 </td> <td> mD </td> </tr> <tr> <td> Reservoir temperature </td> <td> 55–75 </td> <td> °C </td> </tr> <tr> <td> Formation water salinity </td> <td> 80–200 </td> <td> g/L </td> </tr> <tr> <td> Oil viscosity </td> <td> 8–20 </td> <td> mPa·s </td> </tr> <tr> <td> Initial oil saturation </td> <td> 0.65–0.80 </td> <td> fraction </td> </tr> <tr> <td> Water cut </td> <td> 70–95 </td> <td> % </td> </tr> </tbody> </table> The development of the Uzen oil field is complicated by a combination of geological and technological factors. The most significant of these include strong reservoir heterogeneity, extensive compartmentalization of productive horizons, and the presence of high-permeability flow channels that lead to non-uniform oil displacement. An additional challenge is the high water cut of produced fluids, resulting from long-term waterflooding operations and the breakthrough of injected water through the most permeable reservoir zones. This leads to a decline in oil production rates and an increase in the volume of co-produced water. The negative impact of highly mineralized formation waters should also be emphasized, as it limits the effectiveness of both chemical and microbial enhanced oil recovery techniques. Collectively, these factors necessitate the development and implementation of new reservoir stimulation technologies, including microbial enhanced oil recovery methods. <h1>Specific Features of MEOR Application at the Uzen Oil Field</h1> Microbial enhanced oil recovery (MEOR) technologies are of particular interest for the Uzen oil field due to its high water cut and pronounced reservoir heterogeneity. Under conventional waterflooding conditions, the injected water preferentially flows through high-permeability channels, while a significant portion of the oil remains trapped within poorly swept reservoir intervals. The application of MEOR can partially overcome this limitation through the selective treatment of highly permeable reservoir zones [10,15,25]. The formation of microbial biomass and biopolymers promotes the redistribution of fluid flow pathways and enhances the involvement of previously unswept reservoir regions in the displacement process. Another important factor is the presence of highly mineralized formation water. Although elevated salinity inhibits the activity of most microorganisms, the use of adapted halophilic strains makes it possible to maintain biological activity even under challenging hydrochemical conditions. For the Uzen oil field, the most significant mechanisms contributing to MEOR performance include: <ul> <li>reduction of oil–water interfacial tension;</li> <li>modification of the injectivity profile;</li> <li>redistribution of injected water flow;</li> <li>mobilization of residual oil from low-permeability zones.</li> </ul> The effectiveness of the method is primarily attributed to the fact that microbial activity occurs directly within the reservoir, enabling treatment of hard-to-reach zones where conventional enhanced oil recovery techniques are often less effective. Microbial enhanced oil recovery represents an integrated reservoir treatment technology based on the metabolic activity of microorganisms. For the Uzen oil field, MEOR is considered a promising approach for improving sweep efficiency and recovering residual oil reserves under conditions of highly saline formation waters and heterogeneous reservoir architecture. Modeling of the Microbial Enhanced Oil Recovery (MEOR) Process for the Uzen Oil Field To describe microbial treatment processes within the reservoir system of the Uzen oil field, a multiphase hydrodynamic model coupled with a biokinetic module was employed. The model accounts for the flow of oil, water, dissolved components, and microbial biomass through porous media. Table 2. Biokinetic Model Parameters <table> <tbody> <tr> <td> Parameter </td> <td> Symbol </td> <td> Value </td> </tr> <tr> <td> Maximum specific growth rate </td> <td> μmax </td> <td> 0.18 day⁻¹ </td> </tr> <tr> <td> Half-saturation constant </td> <td> Ks </td> <td> 0.5 kg/m³ </td> </tr> <tr> <td> Microbial decay rate </td> <td> λ </td> <td> 0.03 day⁻¹ </td> </tr> <tr> <td> Salinity inhibition coefficient </td> <td> α </td> <td> 0.012 </td> </tr> <tr> <td> Activation energy </td> <td> Ea </td> <td> 35 kJ/mol </td> </tr> <tr> <td> Biomass influence coefficient </td> <td> γ </td> <td> 0.15 </td> </tr> </tbody> </table> The proposed model integrates: <ul> <li>multiphase flow equations;</li> <li>dissolved-species transport equations;</li> <li>microbial growth and decay kinetics;</li> <li>the influence of geological, petrophysical, and physicochemical factors, including salinity, temperature, and permeability.</li> </ul> The transport of fluid phases and components within porous media is described by the continuity equation: where: (\phi) is porosity; (S_{\alpha}) is the saturation of phase (\alpha); (\rho_{\alpha}) is phase density; (v_{\alpha}) is Darcy velocity; (q_{\alpha}) represents source/sink terms. Fluid flow velocity is determined by Darcy's law: where: (k) is absolute permeability; (k_{r\alpha}) is relative permeability; (\mu_{\alpha}) is phase viscosity. Transport of dissolved components (nutrients and metabolites) is described by the advection–dispersion equation: where: (C_i) is the concentration of component (i); (D_i) is the dispersion coefficient; (R_i) is the reaction term. The dynamics of the microbial population are represented by a Monod-type kinetic equation: where: (B) is biomass concentration; (\mu) is microbial growth rate; (\lambda) is the decay rate. Microbial growth is expressed as: where: (C_s) is substrate (nutrient) concentration; (K_s) is the half-saturation constant. To account for reservoir conditions, salinity and temperature correction factors are incorporated: For highly saline formation waters characteristic of the Uzen field, the salinity inhibition function is defined as: where: (S) is formation water salinity; (\alpha) is the microbial salinity sensitivity coefficient. Under elevated salinity conditions, microbial growth rates decrease, biosurfactant production is reduced, and partial microbial inactivation may occur. The temperature effect is described using an Arrhenius-type relationship: where: (E_a) is activation energy; (R) is the universal gas constant; (T) is reservoir temperature. The optimal temperature range determines the maximum activity of the microbial community. Permeability influences nutrient transport, microbial distribution, and the localization of biologically active zones within the reservoir. Effective biomass transport can be represented by a modified dispersion coefficient: where: (D_m) is the molecular diffusion coefficient; (\beta) is an empirical coefficient. In low-permeability zones, substrate delivery is restricted, resulting in reduced MEOR efficiency. Biomass accumulation and metabolite production alter reservoir flow characteristics through: <ul> <li>reduction of oil–water interfacial tension;</li> <li>enhancement of oil mobility;</li> <li>partial plugging of high-permeability flow channels;</li> <li>redistribution of injected water flow paths.</li> </ul> These effects can be incorporated through modification of relative permeability: where: (\gamma) is the biomass influence coefficient. The developed model provides a coupled hydrodynamic–biokinetic framework for describing microbial reservoir treatment processes while accounting for the effects of salinity, temperature, and reservoir flow properties. For the Uzen oil field, high formation water salinity represents the primary limiting factor affecting MEOR performance, necessitating the use of adapted halophilic microorganisms and corresponding calibration of model parameters. Results of Microbial Treatment Simulation To evaluate the effectiveness of microbial enhanced oil recovery (MEOR) under the conditions of the Uzen oil field, three simulation scenarios were considered: <ul> <li>Scenario 1 (Baseline): conventional waterflooding without microbial treatment;</li> <li>Scenario 2 (Moderate MEOR): injection of nutrient solutions and adapted microorganisms with moderate biological activity;</li> <li>Scenario 3 (Enhanced MEOR): application of adapted halophilic microbial strains exhibiting high tolerance to salinity.</li> </ul> The simulations were performed for a representative reservoir sector with fixed petrophysical properties characteristic of the Uzen oil field. The variation of the oil recovery factor (ORF) over time is presented in Figure 1. Figure 1. Oil recovery factor dynamics under different microbial treatment scenarios (Uzen oil field). The figure illustrates the evolution of the oil recovery factor for three development scenarios: conventional waterflooding and two variants of microbial enhanced oil recovery (moderate and enhanced MEOR). The baseline scenario exhibits a trend typical of mature reservoirs. The oil recovery factor increases only slightly, from approximately 0.25 to 0.31, and reaches a plateau after 24–30 months of operation. This behavior indicates that the efficiency limit of conventional waterflooding has been reached due to early water breakthrough through high-permeability channels and reduced sweep efficiency. The implementation of microbial treatment results in a sustained increase in oil recovery, with the magnitude of the effect depending on treatment intensity. In the moderate MEOR scenario, the oil recovery factor reaches approximately 0.42 by the end of the simulation period, corresponding to an incremental recovery of about 10–12% relative to the baseline case. This improvement is attributed to partial modification of flow pathways caused by the formation of biopolymers and biosurfactants, which reduce interfacial tension and redistribute the movement of injected water. The most pronounced effect is observed in the enhanced MEOR scenario, where the oil recovery factor reaches approximately 0.52. This corresponds to an additional recovery increase of about 18–22% compared with conventional waterflooding. In this case, intensive microbial growth not only improves oil displacement efficiency but also selectively reduces the permeability of highly conductive flow channels. As a result, fluid flow is redirected toward previously unswept and poorly drained reservoir zones, thereby increasing sweep efficiency. Table 3. Comparison of Simulation Scenarios <table> <tbody> <tr> <td> <table> <tbody> <tr> <td> Parameter </td> <td> Baseline </td> <td> Moderate MEOR </td> <td> Enhanced MEOR </td> </tr> <tr> <td> Final oil recovery factor </td> <td> 0.31 </td> <td> 0.42 </td> <td> 0.52 </td> </tr> <tr> <td> Incremental recovery </td> <td> — </td> <td> 11% </td> <td> 21% </td> </tr> <tr> <td> Microbial activity </td> <td> — </td> <td> Moderate </td> <td> High </td> </tr> <tr> <td> Salinity tolerance </td> <td> — </td> <td> Partial </td> <td> High </td> </tr> <tr> <td> Permeability modification </td> <td> None </td> <td> Moderate </td> <td> Significant </td> </tr> </tbody> </table> </td> <td> </td> <td> </td> <td> </td> </tr> </tbody> </table> The simulation results demonstrate that microbial treatment exerts a comprehensive positive effect on oil displacement processes. The effectiveness of the method increases with both microbial activity and tolerance to highly saline reservoir conditions. Therefore, MEOR can be considered a promising technology for the further development of mature reservoirs such as the Uzen oil field, particularly during the late stages of field exploitation. Changes in Relative Permeability of High-Permeability Flow Channels During Microbial Treatment Figure 2. Effect of microbial treatment on the relative permeability of high-permeability flow channels over time. Figure 2 illustrates the variation in the relative permeability of high-permeability reservoir channels under different development scenarios. In the baseline waterflooding case, permeability remains essentially unchanged, indicating the persistence of preferential flow paths and the occurrence of early water breakthrough. Under microbial treatment, a gradual reduction in relative permeability is observed due to biomass accumulation and biopolymer formation within the most permeable reservoir intervals. The most pronounced effect is observed in the enhanced MEOR scenario, where the relative permeability decreases to approximately 0.35 of its initial value by the end of the simulation period. These results confirm the ability of microbial treatment to selectively restrict water flow through highly conductive channels and redistribute flow toward less-drained reservoir zones. Consequently, sweep efficiency is improved, leading to enhanced oil recovery. Effect of Formation Water Salinity on MEOR Performance For the Uzen oil field, the primary limiting factor affecting MEOR efficiency is the high salinity of formation waters. In the developed model, this effect is represented through a reduction in the microbial growth rate (Figure 3). Figure 3. Effect of formation water salinity on microbial activity and incremental oil recovery during microbial treatment. The simulation results presented in Figure 3 demonstrate a strong dependence of MEOR performance on formation water salinity. As salinity increases, microbial activity decreases steadily due to osmotic stress and disruption of cellular metabolic processes. An increase in salinity from 50 to 200 g/L results in a decline in microbial activity from approximately 100% to 35%, accompanied by a reduction in incremental oil recovery from about 20% to 6%. This trend indicates the significant inhibitory effect of highly saline formation waters on biotechnological processes occurring within porous reservoir media. Despite the reduction in efficiency, a positive effect of microbial treatment is maintained even at the highest salinity levels considered. This finding suggests that adapted halophilic microbial strains can remain effective under the conditions characteristic of the Uzen oil field. Therefore, the simulation results confirm that formation water salinity is the key limiting factor governing MEOR efficiency, as it directly controls microbial activity and the resulting incremental oil recovery. Overall, the modeling results indicate that the application of microbial enhanced oil recovery leads to a sustained increase in the oil recovery factor compared with conventional waterflooding. The greatest improvement is achieved through the use of adapted halophilic microorganisms capable of maintaining metabolic activity under highly saline reservoir conditions. The enhanced MEOR scenario provides an incremental oil recovery increase of approximately 18–22% relative to the baseline case, demonstrating the considerable potential of MEOR technology for the Uzen oil field. However, the effectiveness of the method remains strongly dependent on formation water salinity, emphasizing the need for optimization of injected bioreagent formulations. Conclusions <ol> <li>A study was conducted to evaluate the effectiveness of microbial enhanced oil recovery under the conditions of the Uzen oil field, which is characterized by highly saline formation waters and a mature stage of reservoir development.</li> <li>Increased formation water salinity was found to negatively affect microbial activity and reduce the efficiency of biological reservoir treatment.</li> <li>The developed coupled hydrodynamic–biokinetic model enabled assessment of the effects of salinity, temperature, and reservoir petrophysical properties on microbial oil displacement processes.</li> <li>Simulation results demonstrated that the use of adapted microorganisms can provide an additional oil recovery increase of up to 18–22% compared with conventional waterflooding.</li> <li>The obtained results confirm the potential of MEOR technology for the further development of mature oil fields containing highly saline formation waters.</li> </ol>

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