Introduction

In the present era, the increasing demand for energy, coupled with the non-renewable nature of oil and gas resources, has made the efficient extraction of these resources crucial. However, a major challenge in the oil extraction process is managing associated water production, known as “water cut” in oil reservoirs (Ahn et al. 2023; IVANOVA et al. 2023). This phenomenon can significantly impact the efficiency and economic feasibility of extraction operations (Ullattumpoyil 2023). Produced water in oil reservoirs involves the movement of water from the reservoir to the surface along with oil and gas. This water may originate from various sources: the intrinsic water in the reservoir, water injected to increase pressure and facilitate extraction, or infiltrated water from adjacent underground aquifers (Kundu 2023). The presence of water not only complicates the extraction process but can also significantly increase operational costs (Abdelaziem et al. 2023; Cairns et al. 2023).

Key challenges associated with water production in oil reservoirs include increased costs related to the transportation and treatment of water, reduced efficiency of the extraction process due to excessive water, and the environmental implications of disposing of produced water (Alkandari et al. 2023; Rajendran et al. 2023). Furthermore, inadequate management of produced water can reduce the reservoir’s lifespan and lower the ultimate recovery rate of oil (Eyitayo et al. 2023). Despite the numerous techniques available, managing water production remains a major concern for the oil industry. The costs associated with transporting and managing water vary based on its composition, intended use, and the logistical options available to operators. A review estimated that the transportation costs due to produced water are around 40 billion dollars, as shown in Table 1 (Abdullayeva 2022; Amaral and Gama 2022; Joseph and Ajienka 2010; Permana et al. 2015). Identifying the factors that lead to excessive water production is crucial for reducing its occurrence. This study introduces and examines the factors causing excessive water production. For managing produced water in oil reservoirs, we consider two approaches: mechanical and chemical technologies. The discussions include using optimization methods to minimize water entry into oil wells and developing new techniques to enhance oil recovery with minimal produced water involvement (Joseph and Ajienka 2010).

Table 1 Value of managing produced water (Joseph and Ajienka 2010)
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In the management of produced water, costs vary depending on the methods used. Table 1 shows the value of managing produced water based on different methods, including CAPEX/OPEX costs, utility costs, and chemical costs. For example, the methods of lifting, separation, de-oiling, filtering, pumping, and injecting each have different costs.

Given that various factors can lead to water cut, understanding these factors is essential for designing effective strategies to control and manage water production. One of the main factors of water production is the infiltration of water from aquifers or natural water layers near oil reservoirs (Meng et al. 2023; Roozshenas et al. 2021). This water can infiltrate the reservoir due to increased pressure caused by oil extraction, leading to increased water production (Al-Mahasneh et al. 2023). Additionally, injected water, which is often used to increase reservoir pressure and improve oil recovery, can result in water production, especially if the amount and location of injection are not carefully controlled. Moreover, heterogeneities in the reservoir structure can also affect water production (Mbouombouo et al. 2023; Wang et al. 2023a, b). Areas with high permeability, such as fractures, channels, faults, and discontinuous layers, can provide pathways for easier water movement, thereby facilitating water production (Vo et al. 2023; Zhang et al. 2023). The lower viscosity of water compared to oil is another factor that can lead to water production, particularly under water flooding conditions or water injection into the reservoir. Due to its lower viscosity, water can easily move through the oil and flow towards the production wells (Cairns et al. 2023; Chowdhury et al. 2023; Poplygin et al. 2022).

Moreover, improper well completion can lead to water cut. Factors that can cause water cut include casing leaks, as shown in Fig. 1a, improper positioning of well completion relative to water zones, and mechanical failure of barriers, which can create pathways for water to enter the well. Identifying and addressing these factors is the first step in controlling and managing water cut in oil reservoirs. Figure 1 illustrates two different scenarios of potential problems that may occur during oil and gas well drilling operations. In Fig. 1a, a leak in the well casing is shown, where produced fluid and excess water enter the production well through a fracture in the casing. In Fig. 1b, a leak in the packer is observed, which is responsible for sealing between the drilling pipes and the wellbore. Both scenarios can negatively impact the safety and efficiency of drilling and oil production operations.

Fig. 1
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a Casing leaking, b packer leaking

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The phenomenon of water coning occurs when water, influenced by higher pressure relative to oil or gas, moves towards a production well in a hydrocarbon reservoir. This typically happens during the extraction of oil and gas from reservoirs containing a water layer (Omer et al. 2023; Tan et al. 2023). In such scenarios, water from lower reservoir layers flows upwards into the oil well, as depicted in Fig. 2, where the water layer is represented with a blue arrow entering the production well and forming a conical shape. This process can contaminate and reduce the quality of the extracted oil. The balance between the reservoir’s inherent pressure and the rate of oil or gas extraction is crucial. Water pressure is consistently higher than the oil pressure in the upper layers. As the extraction rate increases, the internal reservoir pressure decreases, prompting water from the lower layers to move upwards. If this movement is excessive, water can quickly reach the well and mix with the oil or gas, potentially leading to operational challenges and decreased hydrocarbon quality (Vo et al. 2023).

Fig. 2
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Impact of water coning phenomenon on oil production

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It should be noted that minimizing water production is a multistage process that starts with a precise selection of the perforation zones to be as high as possible from the water zone and as low as possible from the gas zone based on available data (Azamipour 2023). In combined drive reservoirs (bottom water and gas cap), the perforation distance from the water zone and the gas cap is not the same due to the higher mobility of gas compared to water in invading the oil stream at the perforation. Another critical step towards efficient oil production with minimal water cut is through an accurate design of production rate to maximize oil production while minimizing reservoir pressure changes (Abdulhadi et al. 2018).

Furthermore, it is important to consider the best production mode regarding thick versus thin oil zones. Techniques such as extended reach drilling, lateral drilling, and horizontal drilling are more effective and economical than horizontal perforations in vertical wells (Izadi et al. 2022). By integrating these strategies, careful selection of perforation zones, optimized production rates, and suitable drilling techniques, effective control of water coning and minimization of water production can be achieved, ensuring better oil quality and operational efficiency (Azamipour et al. 2023).

As illustrated in Fig. 2, a significant challenge that can adversely affect oil production is the phenomenon known as “Water Coning.” This occurs when water accumulates at the entrance of the production well and eventually enters the oil well. Initially, as depicted in Fig. 3, oil production begins at high levels with minimal water output. However, over time, as water encroaches towards the well, changes in oil production occur. Figure 3 clearly demonstrates how water coning impacts oil production trends. With the intensification of water coning, there is a gradual decrease in oil output, while the production of water substantially increases.

Fig. 3
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Impact of water coning on oil production

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Table 2 summarizes the issues of water cut production and factors affecting water cut production, along with proposed solutions.

Table 2 Summary of problems, causes and solutions of water cut production
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Due to the scarcity of review articles on methods for controlling water production in oil reservoirs and the lack of solutions and existing challenges, this paper aims to address these issues and determine appropriate conditions. In the first section, the process of selecting operational wells is explained, focusing on identifying problems in well and reservoir operations, conducting comprehensive reservoir evaluations, and making economic decisions related to well operations. Subsequently, the paper addresses the identification and management of water intrusion in wells, identifying water entry points in oil production, effective parameters on water production, and managing produced water. Furthermore, the process of gelation and gel kinetics is examined, which is essential for understanding how to control water production in oil wells. The comparison of chemical and mechanical treatment methods, presentation of proposed treatment methods, review of various fields and their treatment outcomes, and finally, providing recommendations are other topics discussed in this paper (see Fig. 4).

Fig. 4
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Comprehensive outline of the article

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Operational well selection process

Selecting the appropriate well is a complex task that involves a systematic three-stage process. The first stage is identifying the problem, which includes understanding the specific challenges and objectives associated with the well. The second stage involves a comprehensive assessment of the reservoir, where geologists and reservoir engineers analyze geological data, reservoir characteristics, and production potential. The third stage is decision-making based on economic evaluations, where the economic viability of different well options is analyzed to ensure the most cost-effective and efficient choice is made. This entire process requires close collaboration among geologists, reservoir engineers, and exploitation specialists to integrate their expertise and insights, ensuring the best possible outcomes for the well selection (Dawar et al. 2021; Liu et al. 2010).

Identifying issues in well and reservoir operations

This process involves a comprehensive analysis of the reservoir’s characteristics, focusing on the distribution of remaining oil and the pressure distribution within the formation (Duthie et al. 2023; Liu et al. 2010). Additionally, the performance of the well and its interaction with the reservoir are carefully evaluated to optimize production strategies. Several advanced techniques are employed in this assessment, including injection profile logging, production logging, temperature surveys, single well testing, inter-well evaluation technology, multi-well testing, and cross-well seismic tomography imaging (Neog et al. 2023; Zhao et al. 2023). Injection profile logging and production logging provide insights into fluid movement and well performance, while temperature surveys help detect anomalies in the reservoir. Single well testing is commonly used for quick calculations of permeability and identifying fractures within the reservoir. However, it is less effective in detecting formation heterogeneity, which refers to variations in the reservoir’s properties. On the other hand, cross-well seismic tomography imaging excels at identifying surface heterogeneity and providing detailed images of the reservoir structure. Despite its effectiveness, this technique is used less frequently due to its higher costs (Liu et al. 2010; Mousavi Mirkalaei et al. 2023). Overall, the integration of these various techniques allows for a thorough understanding of the reservoir and well performance, enabling more informed decision-making and improved oil recovery strategies.

The Comprehensive evaluation of the reservoir

A thorough evaluation of a reservoir involves analyzing several critical aspects, including its architecture, pay zones, petrophysical properties, production history, and fluid distribution (Ansari 2023; Wang et al. 2023a, b). This process uses detailed descriptions and simulations to provide a comprehensive understanding. Decision-making at this stage is guided by proprietary well data, which includes information on injection pump pressure, well conditions, and the surrounding environment. Additionally, various tests and evaluations are conducted, such as injection profile logging, production profile logging, and tracer movement studies (Liu et al. 2010; Motaei et al. 2023). These tests help in understanding the flow dynamics within the reservoir and identifying potential issues. Integrating geological, geophysical, petrophysical, and engineering data is crucial for enhancing reservoir characterization (Koray et al. 2023; Sofolabo and Nwakanma 2022).

Economic decision-making in well operations

Economic evaluations are a primary driver for the techniques used in well operations. Decisions are based on various factors, including the cost of chemicals, operational expenses, and the potential to increase oil production while reducing water output. In well selection, several crucial parameters inform the decision-making process (Liu et al. 2010; Obidike and Nwosi-Anele 2023; Shi et al. 2023):

  • 1. Precise Identification of Water Sources: Accurate information on water sources is essential for controlling water cut production, which helps in minimizing water intrusion and optimizing oil extraction.

  • 2. Understanding of Fractures: A thorough understanding of fractures within the reservoir is necessary to manage and predict the flow of oil and water, ensuring more effective extraction strategies.

  • 3. Knowledge of High Permeability Channels: Identifying channels or paths with high permeability is critical for optimizing oil recovery.

  • 4. Identification and Blockage of Inappropriate Paths: Recognizing inappropriate paths that may lead to unwanted water production and blocking them can significantly enhance the performance of injection wells and overall production efficiency.

Water intrusion detection and management in wells

Effective water shut-off operations crucially depend on the accurate identification of water entry points into the well, achieved through production logging tools and in-depth well data analysis (Dai et al. 2023; Proboseno et al. 2023).The process of reducing excess water production starts with the gathering of existing reservoir data and the application of control tools. These tools help detect the source of water ingress, assess the data, and implement suitable methods for managing water production (Birkle et al. 2023; Sharma and Kudapa 2022). Various techniques and technologies are employed to regulate the volume of water cut production. As incorrect diagnoses of water production issues can lead to inefficiencies in water control, an accurate diagnosis is essential for selecting the right technology for water management. (Al-Azmi et al. 2023; Moradi and Moldestad 2021) Identifying factors such as the location of water entries, the heterogeneity of the reservoir rock matrix, the primary production mechanism, and well logs are also crucial (Tang et al. 2023; Yue et al. 2021). Generally, drilling operation reports, logs, and production histories are utilized to improve water control operations, boost oil production, and reduce water transportation costs (Taha and Amani 2019). Based on reservoir engineering research, classifications and guidelines for diagnosing water production control are suggested, as detailed in Fig. 5 (Seright et al. 2003).

Fig. 5
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A diagnostic approach to water production

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A structured decision-making process is crucial for identifying and addressing water production issues in the oil industry. This process begins by determining the presence of a water-related issue. Subsequent investigations delve into potential causes, such as casing leaks, channeling behind the casing, fractures in the reservoir rock, or crossflow. For each identified issue, a variety of solutions are proposed. These include the application of cement, mechanical repairs, cross-linked polymer gels, mud containing sand, carbonate injections, and the use of mechanical packers, each tailored to specific conditions. This structured approach aids engineers in systematically pinpointing and mitigating the complex factors contributing to water production problems (see Fig. 5) (Imqam 2015).

One of the major issues in oil wells is excessive water production, often caused by fractures in the reservoir formation. These fractures, when hydraulically active, act as pathways that allow water to migrate toward the well, significantly increasing water production and negatively impacting oil output. To address this problem, gels are injected directly into the fractures to serve as a physical barrier. This barrier effectively blocks water flow, thereby reducing water production and enhancing oil extraction. Implementing this technique is essential for improving the oil-to-water ratio and increasing the overall efficiency of the well. Figure 6a illustrates the simultaneous production of water and oil through the existing fractures in the reservoir formation before gel injection. In this situation, the fractures act as open pathways for water flow, causing a significant increase in water production alongside oil, which can reduce the efficiency of oil extraction. Figure 6b depicts the state after gel injection into the fractures. At this stage, the injected gel acts as a physical barrier that blocks the water flow pathways. This blockage results in a substantial reduction in water production, thereby allowing for a greater focus on oil production. This figure clearly demonstrates how the use of gel injection techniques can reduce unwanted water production, improve the efficiency and productivity of oil extraction, and increase the oil-to-water ratio in the well’s output.

Fig. 6
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a Water and oil production through fracturing before gel injection. b Stopping water production later by injecting gel into the fracture

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Identification of water entry points in oil production

In petroleum engineering research and operations, it is crucial to pinpoint the origins of water production. Several methods are pivotal in this process:

  • The use of cross-flow detection methods:

    • These include simulation, seismic operations, inter-layer pressure testing, and various logging techniques to assess radius, permeability, porosity, lithology, and other production or injection-related parameters (Nath et al. 2006).

  • Inter-Layer Pressure Testing Mechanism and Layer Pressure Differential Study: This method involves several specific tests and analyses (Nath et al. 2006):

    • Analyzing ion concentration in samples.

    • Conducting tests to determine the quantity of salt and produced seawater, based on the production flow rate.

    • Studying hydrocarbon levels mixed with water in the reservoir.

    • Temperature logging.

    • Collecting production logs under two scenarios: 1) Well shut-in and 2) Well producing.

    • Radioactive logging, used for detecting channeling, flow profiles, etc.

    • Resistivity logs, used for detecting fluid movements within the reservoir (Nath et al. 2006).

  • Ultrasonic logs, used for identifying minor leaks and casing integrity. These logs reveal the location and depth of leaks and the underlying damage mechanisms, based on well data (Farooqui et al. 2007; Johns et al. 2006).

  • Magnetic Resonance Imaging (MRI) Method: This technique identifies the volume of free fluids (water and hydrocarbons), the types of fluids present, and the areas of free water accumulation (Hwan 1993).

  • Derivative-Based Diagnostic Charts: To better understand the mechanisms behind water and gas overproduction in oil wells, a three-dimensional simulation model is used to explore the effects of water coning and channeling through fractures (Abass and Merghany 2011; Chan 1995).

Effective parameters influencing water production

Over the life of a well, the volume of water produced is affected by several factors (Veil et al. 2004):

  • The drilling location of the well.

  • The method of well completion.

  • Types of water separation and treatment facilities.

  • Water injection techniques used for enhanced oil recovery.

  • Damage to the casing and well structure.

Management of produced water

Managing produced water involves two options: reuse or disposal. Prior to selecting either option, the water must be treated and the chemical composition adjusted to suit the disposal or reuse site’s conditions. Key considerations for managing produced water include (Burnett and Siddiqui 2006; Patrick et al. 2004):

  • Preventing ingress of reservoir-produced water into the wellbore.

  • Stopping produced water from reaching the surface.

  • Reinjecting produced water back into the reservoir to maintain pressure and enhance oil production.

  • Disposing of produced water in abandoned oil and gas wells.

  • Disposing of produced water in deep underground formations.

  • Treating and reusing produced water on the surface.

Figure 7 provides an overview of various methods used to control water production in the oil and gas industry. At the heart of the diagram, Water Shut-Off Methods are categorized into chemical and mechanical approaches:

  • Chemical methods These include the use of water-swelling polymers, micro matrix cement, and relative permeability modifiers.

  • Mechanical methods These encompass the utilization of inflow control valves and gel injections.

Fig. 7
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An overview of various methods to prevent water cut production

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Moreover, the diagram differentiates between operational techniques in hydrocarbon-rich areas versus water source pathways. In regions abundant with hydrocarbons, the emphasis is on reducing permeability and utilizing techniques such as horizontal or deviated wells, multilateral wells, and repurposing old wells. For water source pathways, the focus is on maximizing the penetration of blocking agents into water sources and minimizing their movement into hydrocarbon-rich zones. These strategies are crucial for enhancing production efficiency and maximizing oil and gas recovery, while simultaneously minimizing reservoir damage.

Gelation and gel kinetics

The gelation process transforms a liquid solution into a gel by creating a three-dimensional network of molecular bonds, which enhances the solution’s viscoelastic properties (Guo et al. 2023). Gelation kinetics focus on the rate and conditions under which this transformation occurs, emphasizing how temperature impacts the sol-to-gel transition based on concentration (Avallone et al. 2021). This transformation progresses through three stages: initiation, acceleration, and equilibrium (Yi et al. 2017). Studies indicate that factors such as reservoir temperature, pH, fluid salinity, polymer concentration, and additives significantly influence the viscosity, gelation speed, and gelation time. Temperature plays a pivotal role in controlling the kinetics of chemical gel reactions, as increases in temperature generally accelerate the gelation process (Amir et al. 2019; El-Karsani et al. 2015; Molloy and Cowling 2000).

Temperature effect

Temperature has a profound impact on the kinetics of chemical gel reactions. Higher temperatures accelerate molecular movements, thereby speeding up the gelation process due to increased mobility of gel molecules induced by heat. The relationship between temperature and gelation time can be understood using the Arrhenius equation (Zhu et al. 2017a, b):

$${\text{T}}_{{{\text{gel}}}} = {\text{Ae}}^{{\text{Ea/R}}}$$
(1)

Equation (1) illustrates the relationship between the activation energy (Ea), the gas constant (R), the absolute temperature (T), and the pre-exponential factor (A) as described by the Arrhenius equation (Zhu et al. 2017a, b). This equation shows that as temperature increases, the gelation time decreases. This phenomenon has been observed in studies such as those conducted by El-Karsani and colleagues (El-Karsani et al. 2015).

Initial pH effect

The pH of a gel solution can change due to various factors such as exposure to acidic gases, dilution by formation fluids, and interactions with reservoir rocks. Different types of polymeric gels, such as those linked with phenolic resin, operate within specific pH ranges essential for maintaining their stability. Additionally, studies have been conducted to investigate how the pH of a polymeric gel evolves over time, indicating that the pH tends to decrease as the process unfolds (Amir et al. 2019; Gu et al. 2018; Molloy and Cowling 2000).

Salinity effect

As the salt concentration in the gel solution increases, the rate of the cross-linking reaction decreases, leading to a longer time required for gel formation. Researchers have noted that salts can act as retardants, disrupting the cross-linking reactions. Such retardants are particularly useful in high-temperature environments, where they can be used to extend the setting time of cross-linked organic polymeric gel systems. Additionally, the concentration of brine influences the cross-linking sites, resulting in a prolonged preliminary phase and, subsequently, an extended gelation time. Consequently, engineers must carefully analyze the salt concentrations in both injection and formation waters to ensure the optimal performance of the gel system (Amir et al. 2019; Broseta et al. 2000).

Polymer concentration effect

The gelation rate is influenced by the amount of PAM polymer present. It is crucial to produce a suitable and high-quality polymeric gel to enhance the rheological properties of the gel and extend the gelation process in oil fields (Du et al. 2024; Jin et al. 2023). Additionally, polymer concentration impacts the onset of gel synergy. With a lower binder concentration, a high HPAM concentration in the polymeric gel can delay the start of gel synergy (Hu et al. 2023). However, maintaining a high polymer concentration is not economically advantageous. Thus, a high polymer loading is essential to achieve a system with acceptable gel strength. The optimal polymer loading rate must be determined for deep reservoir treatments, where factors like gel viscosity, material costs, formation time, and durability are critical (Amir et al. 2019; Jia et al. 2012).

Crosslinking concentration effect

The solubility of a polymeric gel increases as the cross-link density decreases. This is attributed to the production of more carboxyl groups, which are more stretchable and reduce the likelihood of cross-linking. However, this also diminishes the accessibility of alkyl groups for cross-linking. Consequently, petroleum engineers require guidance to effectively adjust the cross-linking system concentration to satisfy various water management needs. It is important to note that polymer concentration has a more significant influence on the rheological properties of the gel system than the concentration of cross-linking agents (Amir et al. 2019; ElKarsani et al. 2015).

Additives effect

Decreasing the polymer concentration reduces the likelihood of cross-linking. Additionally, research indicates that adding MMT significantly prolongs the gelation time of the PAM/PEI gel system. The study suggests that MMT layers may effectively shield the amide groups of PAM, thereby disrupting the reaction between PEI and the carbonyl carbon attached to the amide group. Furthermore, incorporating MMT into the polymer enhances the thermal stability of the gel, attributed to the insulating and barrier properties of MMT, which bolster the gel’s resistance to decomposition (Amir et al. 2019; Pu et al. 2016). The kinetic studies of polymer gels cross-linked with resin are summarized in Table 3 (Amir et al. 2019).

Table 3 Summary of gel kinetic studies
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Temperature is a crucial parameter in the gelation process. Studies have shown that the PAtBA polymer performs best in the presence of carbonate salt as a retarder. Experiments at temperatures higher than 205 °C have been investigated. By increasing the retarder concentration, this temperature range can be expanded, and a flexible gel can be prepared that can reduce permeability by 100%. The AMPSA PatBA N, N-DMA polymer ranks second in performance at high temperatures and shows a significant decrease in permeability. In other experiments, the temperature range is around 80–90 °C. In most polymers, temperature has a direct relationship with gel strength and an inverse relationship with gelation time. Similarly, polymer concentration is directly related to gel strength and inversely related to gelation time. It should be noted that in some cases, depending on the type of polymer, these relationships may not hold. For example, increasing the concentration of terpolymer and resorcinol leads to an increase and decrease in gelation time, respectively, while both lead to an increase in gel strength. The pH and salinity, depending on their range and the type of salt, can either decrease or increase gelation time and strength.

In recent years, chemical polymer gels have become widely utilized due to their cost-effectiveness and durability. These polymer-based gels have demonstrated a high success rate in field trials globally, contributing to their increasing popularity (Sun et al. 2017). During gelation, macromolecular chains interlink, initially branching into soluble polymers depending on the composition and structure of the raw materials (see Fig. 8).

Fig. 8
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Schematic of 3D fiber network assembly in gel

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Polymer gels are capable of forming a state where a three-dimensional network is present. This structure arises from the cross-linking of polymer chains within a liquid medium (see Fig. 9). The solvent becomes encapsulated within this three-dimensional network, resulting in reduced fluidity and the formation of the gel state.

Fig. 9
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Schematic illustrations of a polymer gel

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Numerous chemical polymers have been extensively studied and analyzed (Sun et al. 2017). In Table 4, we examine some of these polymers, detailing the types of binders used, their stability, and their mechanisms of action.

Table 4 The composition of the gels and binders used and the conditions for measuring the gels
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As shown in Table 4, parameters such as temperature, gel composition, and crosslinker significantly affect gelation time and gel strength. For example, at a constant temperature of 120 °C, when the crosslinker is Phenol/Formaldehyde with the gel composition of (AM/AMPS) + Phenol/Formaldehyde, it takes 3–4 days to reach syneresis and 10–11 days to reach 50% syneresis. In contrast, the presence of Oxalate with this gel composition leads to taking more than 100 days to reach 1% syneresis. In another case, with the same crosslinker (PEI), changing the temperature and the gel composition results in constant gel strength, with thermal stability up to 191 °C. Examples include PAtBA + PEI at 85 °C and PAtBA + PEI + Cement at 118–144 °C.

Comparison of chemical and mechanical treatment methods

Methods for mitigating water production from wells continue to evolve. Each method offers specific advantages and disadvantages, despite sharing the ultimate goal of managing water production. Chemical flow control systems excel by potentially eliminating water production entirely. In contrast, mechanical methods halt water flow either above or below a plug or packer. Chemical treatments are permanent and carry higher risks, while mechanical methods are simpler to implement and provide quicker results (Taha and Amani 2019). Chemical treatments penetrate fracture networks to address permeability issues, while mechanical solutions typically operate at or near well sites. For complete wells, chemical methods are effective in water shut-off operations, whereas mechanical methods are suited for temporary well isolation. Chemical approaches use substances both as blocking agents and for thermal zone isolation with packers, while mechanical packers isolate water production and facilitate conditions for subsequent chemical treatments through zone isolation (Xindi and Baojun 2017). Overall, chemical methods offer a cost-effective and reliable solution for water shut-off (Joseph and Ajienka 2010). Chemical treatments are cheaper and more versatile than mechanical treatments, addressing the limitations of mechanical devices and making them increasingly viable in the industry (Joseph and Ajienka 2010; Xindi and Baojun 2017).

Suggested treatment methods

Table 5 presents recommended methods for addressing specific issues, clearly indicating that the choice of treatment depends on the problem’s limitations. For structural issues like leaks in casing, tubing, or packers, mechanical solutions such as cementing operations are typically recommended. It’s important to note that either a mechanical or chemical solution is advised for each problem, except in non-fractured wells where both methods are suggested to manage crossflow.

Table 5 Suggested treatments for problems (Joseph and Ajienka 2010)
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Overview of Various Fields and the Outcomes of Their Interventions.

Overview of various fields and the outcomes of their treatments

Extensive research globally has employed diverse techniques to decrease water cut and enhance oil output in reservoirs. In the Northern Monagas oil fields of Venezuela, gel technology has been effectively utilized to address specific challenges such as high temperatures, high pressures, and the lack of an active aquifer. This approach has substantially curtailed water production while boosting oil recovery. The process involves strategically injecting gel, with meticulous management of both the volume and injection sites. Laboratory simulations and field tests have validated this method. The results indicate that the success of this intervention varies based on factors such as the initial water cut, the volume of gel injected, and the unique properties of the reservoir, ultimately leading to a marked decrease in water cut and improved conditions for oil extraction (Herbas et al. 2004). Several case studies employing the water-shut-off method have been analyzed, with the findings summarized in Table 6.

Table 6 Review of case studies
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Table 6 shows the methods used to reduce water production and estimate oil production. All these methods have been successful in some cases and failed in others. The results of several cases are reviewed and presented below:

Although gel treatment and polymer injection methods sometimes fail, they generally lead to decreased water production and, consequently, a reduction in water cut. These methods also reduce channeling and increase oil production. Perforation often increases produced water, making it an unsuccessful method. Plug cement reduces water cut (WC) and increases oil production by reviving dead wells. Installing packers also leads to satisfactory oil production with minimal water cut. Although this method sometimes fails to produce oil despite reducing water production, it remains one of the most economical mechanical methods.

Recommendations

Water management in oil reservoirs is a critical factor in optimizing hydrocarbon recovery while minimizing environmental and operational costs. As the industry seeks to advance beyond traditional methods, innovative approaches for controlling water production are crucial. This requires a comprehensive understanding of both chemical and mechanical techniques to tailor strategies effectively to specific field conditions. In light of recent advancements and persistent challenges highlighted in the literature, several areas have emerged where further research could substantially enhance the efficacy and sustainability of water control methods. Below are suggested future research directions that could provide significant improvements in the field:

  1. 1.

    Development of Advanced Polymer Systems: Focus on synthesizing new polymer formulations that can withstand extreme reservoir conditions such as high temperatures and salinities, enhancing the effectiveness and sustainability of water shut-off treatments.

  2. 2.

    Real-time Monitoring and Adaptive Control Systems: Research into the integration of sensor technology and real-time data analytics to dynamically adjust chemical injections based on changing reservoir conditions and water production levels.

  3. 3.

    Environmental Impact Assessments: Studies to evaluate the long-term environmental impacts of chemical methods used in water shut-off, including potential contamination risks and strategies for minimizing ecological footprints.

  4. 4.

    Economic Analysis of Water Management Strategies: Comparative studies on the cost-effectiveness of chemical versus mechanical methods, incorporating factors like operational costs, longevity of water shut-off, and overall recovery efficiency.

  5. 5.

    Hybrid Systems for Water Control: Exploration of combined chemical and mechanical approaches tailored to specific reservoir characteristics, aimed at optimizing recovery while ensuring sustainable water management.

  6. 6.

    Advanced Simulation Models: Development of more sophisticated predictive models to simulate water production and the effectiveness of various control methods across different reservoir conditions.

These suggestions aim to foster the development of more effective, economically viable, and environmentally friendly water management strategies in the oil and gas industry.

Conclusions

Effective water management in oil reservoirs is critical for optimizing oil recovery and economic efficiency. Both chemical and mechanical methods play a significant role in achieving these goals. The following results highlight the key findings of this study:

  • 1. Both chemical and mechanical methods control water production in oil reservoirs. Gel treatments manage fractures and coning, while cementing addresses casing leaks.

  • 2. Chemical treatments are beneficial in high water cut reservoirs with complex geology, improving oil recovery rates and economic efficiency.

  • 3. Chemical methods manage reservoir heterogeneity, diverting water flow and enhancing sweep efficiency in high permeability streaks.

  • 4. Higher temperatures accelerate gelation, emphasizing the need for temperature control in optimizing chemical treatments.

  • 5. Reservoir interactions lower pH over time, affecting the gelation process.

  • 6. Additives like MMT prolong gelation time and enhance thermal stability, suitable for high-temperature applications.

  • 7. Increased salt concentration retards cross-linking, extending gelation time and improving control in high-temperature environments.

  • 8. Specific gel compositions and crosslinkers perform best under controlled temperatures and concentrations, crucial for effective water management.

  • 9. Polymer gels, such as PAtBA/d-PEI, can reduce permeability by up to 100%, making them effective for water shutoff.

  • 10. Phenol/formaldehyde and PEI perform best under controlled temperatures and concentrations. These conditions significantly affect gelation time and strength, essential for effective water management in oil reservoirs.

Future studies on new chemical formulations and application methods are recommended to enhance the effectiveness and environmental safety of water control treatments, promoting more sustainable oil production practices. Addressing these key points, this research highlights the importance of using innovative chemical methods for effective water control in oil reservoirs, providing economic and environmental benefits while improving oil recovery efficiency.