A Review on the Water Invasion Mechanism and Enhanced Gas Recovery Methods in Carbonate Bottom-Water Gas Reservoirs

Abstract

Carbonate gas reservoirs are crucial in gas field development, with carbonate bottom-water gas reservoirs being a significant subset. However, the development of these reservoirs often faces challenges such as water invasion, leading to a low gas recovery rate. Enhancing gas recovery is a primary goal for researchers in this field. This study provides a systematic review of the mechanisms, identification, and dynamic prediction of water invasion in these gas reservoirs. The technical adaptability and application range of different enhanced recovery methods are summarized, and their application effects are evaluated. The results indicate that carbonate gas reservoirs have diverse types of storage and permeability spaces, with a wide distribution of pore size scales, leading to various types of enclosed gas caused by water invasion. The prediction accuracy of water invasion models for bottom-water gas reservoirs with fractures and vugs is relatively low. Therefore, numerical simulation research on the basis of fine reservoir characterization is the key technology. The control of bottom-water invasion and the rescue measures after the bottom-water invasion are the keys to improving gas recovery, which can be divided into four types: drainage gas recovery, water control production, active drainage, and injection medium. Gas production by drainage is the main technology for improving gas recovery, among which foam drainage is the most widespread. The optimization of development parameters in production by water control has a good effect in the early stages of development. The active drainage technology on the water invasion channel is the bottom-up technology for the effective development of strong water-flooded gas reservoirs. CO₂ injection may have great potential to improve the recovery of bottom-water gas reservoirs, which is one of the important research directions under the background of “carbon peaking and carbon neutrality”. The research provides theoretical and technical reference significance for enhanced recovery of carbonate bottom-water gas reservoirs.

1. Introduction

China is optimizing its energy system towards cleanliness and low carbon to achieve the development goals of “carbon peaking and carbon neutrality” [1]. A practical option for achieving the dual-carbon target is natural gas, with carbonate gas being a key area of natural gas growth in China [2]. The edge and bottom water of the majority of carbonate gas reservoirs worldwide are typically impacted by water flooding during the process of extraction and development [3]. As a result, a significant portion of natural gas is “water sealed”, which has a negative impact on the gas reservoirs’ recovery rate [4].

The development of a bottom-water gas reservoir is more challenging than that of edge-water gas reservoirs because the water in the bottom-water gas reservoir is located in the lower portion of the reservoir and its water energy and water invasion channel are more difficult to characterize. Compared with sandstone reservoirs, carbonate reservoirs are prone to developing fractures and vugs, and their strong heterogeneity leads to greater uncertainty in the direction and volume of bottom-water invasion [5]. The lithology of carbonate rock reservoirs mainly includes dolomite, limestone, and bioherms. Due to the well-developed fractures and caves, the types of carbonate rock bottom-water gas reservoirs both domestically and internationally are diverse, primarily categorized as fractured-type and fractured–porous-type. Statistical data on relevant parameters of domestic and foreign carbonate rock bottom-water gas reservoirs are presented in

Table 1. Summary of development parameters for carbonate bottom-water gas reservoirs.

Gas Reservoir Name	Country	Depth (m)	Geological Reserves (108 m3)	Lithology	Water Energy	Reservoir Type	Reservoir Effective Thickness (m)	Permeability (mD)	Recovery (%)
Weiyuan	China	3000	400	Dolomite	Strong	Fracture–Vuggy Type	90	0.46	36.7
Yuanba		6800	1943.1	Dolomite	Medium	Porous Type	57.8	0.34	18
Orenburg	Former Soviet Union	1750	17,600	Dolomite	Weak	Fractured–Porous Type	89–254	11	(Stable Production Stage)
Wilburton	America	3709	113	Limestone	/	Fractured–Porous Type	134	0.03	66
Beaver River	Canada	3600	413.4	Dolomite	Strong	Fractured Type	270	2–200	78.7
Caroline		3800	17,815	Dolomite	Weak	Fractured Type	40	100	12
Pointed Mountain		4115	226	Dolomite	Strong	Fractured Type	205	7–200	77
B-P on the Right Bank of the Amu Darya River	Turkmenistan	2900	767	Limestone	Weak	Fractured–Porous Type	50	0.1	39
Suez	Pakistan	1000	2440	Limestone	Weak	Fractured–Porous Type	70	3.5	71

. The ultimate recovery rates of these reservoirs range from 12% to 78%, which is significantly lower than the average recovery rate of dry gas reservoirs. Thanks to more advanced development technologies and comprehensive geological research, the recovery rates of foreign carbonate gas reservoirs are generally higher than those in China. The statistical results indicate that fractured–porous-type reservoirs tend to have higher overall production. Especially when the bottom-water energy is strong and high-angle fractures are developed, water encroachment has a significant impact on the development of gas reservoirs. For example, the Beaver River fracture-type dolomite gas reservoir in Canada did not effectively prevent bottom-water intrusion during the development process, resulting in an ultimate recovery rate of only 12%. Therefore, gaining an in-depth understanding of the water encroachment mechanisms in carbonate rock bottom-water gas reservoirs and formulating methods to improve recovery rates at different stages of development are crucial for the efficient exploitation of these types of gas reservoirs.

This study begins by summarizing the features of carbonate gas reservoirs, followed by a summary of the micro and macro mechanisms of water invasion. The methods for accurately identifying and warning of water invasion in bottom-water gas reservoirs are summarized, as well as the dynamic features and forecast methods of water invasion under various water invasion modes. On this basis, the technical adaptability and application range of four types of extraction methods (gas production by water drainage, production by water control, active drainage, and medium injection) for carbonate bottom-water gas reservoirs are evaluated. Finally, based on the development practice of three typical carbonate bottom-water gas reservoirs, the application effect of various extraction methods in these types of gas reservoirs is examined, providing a reference for similar gas fields to enhance recovery.

2. Reservoir Characteristics and Water Invasion Mechanism of Carbonate Gas Reservoirs

Water invasion greatly decreases the gas reservoir’s effective seepage channel during the development of carbonate gas reservoirs, which causes a substantial volume of gas to be contained in the underground storage space and lowers recovery efficiency. This is also the primary reason why people require waterproofing, water control, and water management while developing bottom-water gas reserves. A thorough understanding of the water invasion mechanism in bottom-water carbonate gas reservoirs is required to predict macroscopic water invasion dynamics and develop appropriate techniques for recovery [6].

2.1. Characteristics of Carbonate Gas Reservoirs

Carbonate gas reservoirs differ from sandstone gas reservoirs in that they have several storage and permeability spaces, a wide range of pore-scale distribution, and medium wettability with generally uniform wettability. The specific features are as follows: (1) The types of storage and permeation space are diverse. During the formation of carbonate gas reservoirs, they are significantly influenced by intense diagenetic processes, such as dissolution, precipitation, dolomitization, and stress-induced fracturing, resulting in a variety of storage and permeation space types. According to the national standard “GB/T 26979-2011 Classification of Natural Gas Reservoirs”, the types of storage and permeability space in carbonate rock reservoirs are classified into five types based on different combinations of pores, fractures, and vugs [7]: porous type, fractured–porous type, fractured–vuggy type, porous-fractured type, and fractured type. (2) There is a wide pore-scale distribution. Due to the strong heterogeneity of the storage and permeable space of carbonate gas reservoirs, the pore-scale distribution of porous media usually exhibits bimodal or even trimodal characteristics [8], with the scale ranging from the micrometer to the meter level. We reconstructed multi-scale pore network models of carbonate rocks using CT scan images with different resolutions, as shown in Figure 1. (3) They are predominantly characterized by moderate wettability, with relatively uniform wettability. Sandstone reservoirs have a diverse range of mineral types, and minerals such as quartz and clay, which exhibit strong hydrophilicity, often result in strong water wetness. In contrast, carbonate reservoirs have a more homogeneous mineral composition, exhibiting weak water wetness [9]. Due to the diverse types of storage and permeability spaces in porous carbonate media and the wide distribution of pore size scales, accurately characterizing and predicting their water invasion multiphase flow behavior has long been a challenging issue in the oil and gas industry.

2.2. Microscopic Water Invasion Mechanism of Carbonate Gas Reservoirs

The behavior of the gas that the water invasion is sealing and the dynamic features of water invasion in the pore space of carbonate reservoirs are the key topics of discussion in the micro-scale water invasion process. Compared to dry gas reservoirs, the sealing of natural gas induced by water invasion is a critical component in the low recovery rate of water-containing gas reservoirs, and visual etching simulation is commonly used in studies.

The storage and permeability space of carbonate gas reservoirs is complex, so there are various types of water invasion and gas sealing, mainly influenced by the size and distribution of fractures and vugs. Li et al. created a microscopic visualization model using laser etching technology, revealing for the first time the mechanism of four types of trapped gasses in a porous medium during water invasion: circumferential fingering, cut-off, blind end/corner of pores, and “H-shaped” channels [10]. It is demonstrated that invading water in porous material advances unevenly due to hydrodynamic force, viscous force, capillary force, and other factors, resulting in the formation of distinct trapped gases.

To clarify the impact of fractures on water invasion, Fan et al. further used the micro-etching model to observe that water quickly surrounded matrix pores after invading fractures, resulting in a significant amount of gas being sealed in the pores [11]. Similar conclusions were also confirmed by the etching experiment results of Wang et al. and the core NMR monitoring results of Chen et al. [12,13]. The existence and distribution of fractures and vugs will significantly change the dynamic characteristics of water invasion and its impact on the trapped gas. Fang et al. designed a flat panel visualization physical model that considers different vug and fracture distributions [14]. According to the experiment, fractures and vugs have a major impact on the local water invasion but not much effect on the water invasion front as a whole when they are relatively isolated. When fractures and vugs communicate with porous media, water quickly fills the cavities along the fractures, utilizing only the gas in the fractures and vugs. Feng et al. [6] summarized the development experiences of various carbonate gas reservoirs and found that the likelihood of non-uniform water invasion and the speed of its impact decrease in the following order: fractured reservoirs, fractured–porous reservoirs, fractured–vuggy reservoirs, and porous reservoirs.

The accurate prediction of water invasion multiphase flow in complex storage and permeability spaces of carbonate rock has always been a goal pursued by people. In recent years, the development of real-time online scanning technology for core displacement and high-resolution 3D printing technology has enabled more accurate capture of multiphase flow behavior in the real three-dimensional space of porous media [15,16]. At the same time, a series of pore-scale simulation methods have gradually developed and applied to the simulation of water invasion multiphase flow in carbonate porous media [17]. For instance, as shown in Figure 2, the multi-relaxation color gradient LBM method can be applied to carbonate reservoirs, given that existing experimental methodologies cannot finish gas–water two-phase studies under conditions of pressure and temperature in deep carbonate reservoirs. The reliability of the LBM simulation was confirmed by comparing the type of trapped gas in porous media after water invasion and the corresponding gas–water distribution characteristics. Nevertheless, because of the high heterogeneity of the reservoir and permeability space of carbonate porous media, there is still no relatively reliable analytical method to predict pore-scale water invasion behavior. Li et al. used an online X-ray to constantly monitor the water invasion process of dolomite rock samples, and the results showed that the power law indices of the three power law relationships between the volume of trapped gas and its specific surface area were lower than those predicted by traditional seepage theory [18]. Therefore, current simulation studies of carbonate gas reservoirs still cannot meet the requirements for predicting the microscopic water invasion dynamics of different reservoir types. It is necessary to further investigate the microscopic water invasion mechanisms and develop quantitative prediction methods in the future.

2.3. Macroscopic Water Invasion Mechanism of Carbonate Gas Reservoirs

The macroscopic water invasion mechanism is the macroscopic performance of the microscopic water invasion mechanism. When there are large fractures or vugs, it becomes hard to observe the water invasion mechanism using the visual micro research method, so we must employ a bigger-scale research method, such as physical simulation experiments on a large scale, long core displacement experiments, and so on.

The development of pores, vugs, and fractures with different dimensions and distribution densities in carbonate gas reservoirs plays a significant role in the differentiation of water invasion patterns in gas reservoirs [19,20,21]. The relative permeability curves are usually obtained from core flooding experiments. (1) For porous reservoirs, the water invasion front advances relatively uniformly and slowly, and the gas–water permeability curve resembles that of homogeneous tight sands. (2) For fractured reservoirs, the front edge of water invasion in fractured reservoirs advances non-uniformly along the fractures, and the advancing speed is tens to even hundreds of times faster than that in the matrix. The relative permeability curve of fractured reservoirs shows the characteristics of a small two-phase co-permeability interval, high irreducible water saturation, and a sharp increase in water relative permeability. This illustrates how fractures are the primary seepage channels for water and gas movement throughout the water invasion process. Bottom water “channeling” along the fractures divides the gas reservoir by closing off the gas areas on both sides of the fractures and creating a dead gas area. At the same time, water channels quickly along the fracture and infiltrates into the matrix as a consequence of wettability and capillary pressure. This increases the matrix’s water saturation on both sides of the fracture, decreases or plugs the gas-phase seepage channel, and lowers the matrix’s capacity for gas-phase seepage [22]. (3) For porous–vuggy reservoirs, vugs enhance the reservoir’s ability to accommodate water influx. The water invasion front edge is convex locally in the development of vugs, but the overall progress is approximately uniform. The relative permeability curve of porous–vuggy carbonate rocks is similar to that of medium- to high-permeability homogeneous sandstones. When a porous–vuggy reservoir contains fractures, the bottom water first fills the lower vugs when meeting the vugs and then quickly “channels” along the fractures. Then, it continues to fill the upper vug and spreads to the surrounding matrix. Finally, it enters the bottom of the well, easily forming a trapped gas in the fracture network [23]. Its curve is characterized by a slight rise in relative permeability of the water phase at low to medium water saturation and a rapid increase at high water saturation [24]. The development of this kind of gas reservoir demonstrates that the early indicators of water invasion activity are somewhat overlooked or lagging behind, but once the damage caused by water invasion is evident, it becomes harder to stop the trend [6].

Due to the strong heterogeneity of the storage and permeability space of carbonate porous media, especially when there are large vugs (flow state or even free flow), there is no characterization unit in the whole porous media system, which is a great challenge for simulation [25]. Therefore, determining how to coordinate the scale differences of carbonate reservoirs, developing cross-scale multiphase flow simulation methods, and accurately describing the water invasion laws of various scales and types of reservoir spaces under complex development conditions are the key and challenging points of the study.

3. Water Invasion Dynamics of Carbonate Bottom-Water Gas Reservoirs

Due to the complex storage and seepage space of carbonate gas reservoirs, the dynamic characteristics of bottom-water invasion have unique features compared to other types of edge-water gas reservoirs, mainly reflected in aspects such as water invasion patterns and prediction models. Therefore, accurately identifying and providing early warning for water invasion, clarifying the source and direction of water invasion, conducting dynamic characteristic analysis and prediction of water invasion, and then formulating targeted measures to enhance recovery are crucial for managing water production in gas wells and ensuring the stable development of gas reservoirs [6].

3.1. Water Invasion Identification and Warning

3.1.1. Water Invasion Identification Method

The current methods for identifying water invasion mainly include production dynamic data analysis, the material balance method, and the well-test monitoring method. (1) Production dynamic data analysis can determine the type, source, mineralization degree, and water–gas ratio of produced water by analyzing its characteristics. Although the characteristics of produced water are easy to obtain and analyze, this analysis cannot achieve the goal of identifying water invasion in advance [26]. (2) Appearing geological reserves, water invasion volume coefficient, and pressure drop curve methods are the three main categories of the material balance method. By analyzing the theoretical charts of the three methods, water invasion can be identified. This method can be identified only through the corresponding data calculation, which is simple and efficient, but there are certain applicable conditions for each plate [27]. (3) The well testing monitoring method judges the degree of formation water invasion based on the characteristics of the well testing curves at different periods of the gas wells, and the prediction is relatively accurate. However, this method requires multiple well tests at different periods and requires high accuracy in data interpretation [28].

3.1.2. Water Invasion Channel Type

Water invasion channels mainly include faults, fractures, and high-permeability bands in the matrix. In carbonate reservoirs, the primary channels for both seepage and reservoir water invasion are fractures. In order to precisely determine the geographical distribution of high- and low-permeability zones in gas reservoirs, Wang et al. combined dynamic data with a well testing model based on a multi-scale discrete fracture model [29]. Predictions are made on the predominant water invasion channel and method. He et al. established a set of effective water invasion model analyses and meticulous prediction methods in combination with well seismic reservoir analysis, which can accurately establish gas reservoir water invasion patterns and characterize the dominant water invasion channels [30]. Su used dynamic and static data from the gas field to describe and predict water invasion channels by defining water invasion channel factors [31]. Cai et al. proposed principles, methods, and implementation suggestions for systematic fracture description based on the needs and contradictions in the carbonate gas fields’ developmental stage [32]. In summary, the distribution and types of water invasion pathways are mainly influenced by geological structures, pore characteristics, and fluid properties. Furthermore, the focus of identifying water invasion pathways in carbonate reservoirs lies in recognizing the distribution characteristics of fractures within the reservoir.

3.1.3. Water Invasion Prediction Model

One of the main challenges in developing bottom-water gas reserves is bottom-water coning. For sensible production and enhanced gas recovery of bottom-water gas reservoirs, it is essential to precisely forecast the water breakthrough time of gas wells and delay the premature coning of bottom water. At present, predictions of the bottom-water coning pattern and water breakthrough time are mainly divided into analytical mathematical model methods and numerical simulation methods. Tang assumed that there are two types of seepage models for bottom-water reservoirs: a planar radial flow in the upper part of the perforated section and a hemispherical centripetal flow in the lower part of the perforated section [33]. A homogeneous and isotropic bottom-water gas reservoir water breakthrough time prediction model has been established. Chen and Liu developed the prediction model and conducted an in-depth analysis of the water breakthrough time in actual wells, taking into account the effects of skin factor, initial gas saturation, high-speed non-Darcy effect, and other parameters [34]. Li et al., Guo et al., and Fan et al. established the prediction models of water occurrence time for fractured wells in bottom-water gas reservoirs, gas wells in high-sulfur bottom-water reservoirs, and horizontal wells, respectively, and conducted model comparison and parameter sensitivity analysis [35,36,37]. In addition, Li et al. established a separator critical production model based on the separator water control theory [38]. Li, Zhao and Zhu, and Huang et al. then successively developed a model for predicting water breakthrough in bottom-water gas reservoirs with separators, analyzing the influence of factors such as separator position and length on breakthrough time [39,40,41]. For the numerical simulation of bottom-water rising patterns, Yang et al. established a three-dimensional two-phase fully implicit numerical model based on the finite difference method [42]. Feng et al. and He used Simbest-II software (Scientific Software-Intercomp, St. Paul, MN, USA), and Cheng et al. and Chen et al. used Eclipse software (Eclipse Foundation, Brussel, Belgium) to establish a single-well numerical model and conduct bottom-water invasion dynamics and parameter sensitivity analyses [43,44,45]. Our team established a fine numerical simulation model of a single well in a bottom-water gas reservoir with large-scale discrete fractures using the finite volume method and unstructured grids and validated the accuracy of the model. We analyzed the influence of fracture development characteristics on the bottom-water rising pattern, as shown in Figure 3. As illustrated in Figure 3a, when there are no fractures between the bottom water and the well, the gas–water interface advances uniformly in the early stage, and later, the interface gradually bulges with a low bulging height. Figure 3b–f show that when fractures develop between the bottom water and the well, the bottom water rapidly flows along the fractures. Once the water reaches the top of the fractures, it gradually diffuses into the matrix; after the water is seen in the well, the gas on both sides of the fractures is isolated. From Figure 3b,c, it can be observed that as the height of the fractures increases, the speed of bottom-water flow accelerates, while the diffusion of water into the matrix along the fractures decreases, leading to an increase in the gas isolation on both sides of the fractures. Figure 3d indicates that when the fracture angle is low, the lateral advancement of bottom water along the fracture direction slows down the vertical flow of water directly into the well. As the fracture angle increases, the time to see water becomes earlier, and the amount of isolated gas increases, as shown in Figure 3d–f. The research results indicate that compared to analytical models, numerical simulation methods can provide a more comprehensive analysis of the impacts of different parameters and visually present the dynamic characteristics of bottom-water production, offering broader application prospects.

3.2. Dynamic Characteristics and Prediction of Water Invasion

3.2.1. Water Invasion Mode

According to the difference in water invasion caused by different reservoir types, scholars divide the water invasion modes for bottom-water gas reservoirs into four types: water cone invasion mode, vertical channeling water invasion mode, transverse water invasion mode, and composite water invasion mode [43,46,47], as shown in Figure 4. (1) In the water cone type invasion mode, microfractures around the gas well are extensively developed, whereas enormous fractures are not, and the reservoir is approximately homogenous. The formation water moves slowly toward the bottom hole in the shape of a water cone along the microfracture as gas is produced due to pressure difference, as shown in Figure 4a. As shown in Figure 4b, the water output is quite little once the gas well generates water. The rising speed is relatively gentle, and the impact on development and production is not obvious. (2) In the transverse water invasion mode, the horizontal fractures or low-angle fractures near the gas well are relatively developed, and most of the bottom water is not active, as shown in Figure 4c. With the production of gas, formation water will first move vertically upward along the fracture and then invade the gas well laterally along the low-angle fracture, and the output of the gas well will be seriously reduced, as shown in Figure 4d. (3) In the vertical channeling water invasion mode, high-angle massive fractures are developed around the gas well, which are related to the water and wellbore, as shown in Figure 4e. As shown in Figure 4f, with gas production, reservoir water rapidly flows into the wellbore through high-angle massive fractures, and water invasion is especially active. Once the gas well produces water, the amount produced is considerable, and the rate of increase is rapid. As a result, gas output will be significantly reduced, water will overflow, and production may be halted abruptly. (4) In the composite water invasion mode, high-permeability pore layers are developed near the gas well, and high-angle large fractures are connected to the high-permeability layer. When gas is produced, formation water moves longitudinally over high-angle large fractures before horizontally entering the well along the high-permeability layer. This mode combines two modes of transverse invasion and vertical channeling and is a common water invasion mode with the greatest impact on production and development.

3.2.2. Calculation of Water Influx

Water influx calculation techniques are divided into empirical and material balancing methods based on the various dynamic features of water invasion and the needed calculation data. The empirical methods derived from seepage theory are typically divided into three types: steady-state water invasion method, unsteady-state water invasion method, and pseudo-steady-state water invasion method. These methods are static, but there are problems with the inaccurate prediction of the size and shape of a gas reservoir’s edge and bottom water. The material balance method based on gas well production performance data is mainly assigned to the difference method, chart method, and apparent geological reserves method. This kind of method is independent of reservoir type, only related to fluid properties and formation pressure testing, and does not require estimating water body dimensions and shapes, so the calculation process is relatively simple.

Chen conducted thorough research on water influx calculation in different gas reservoirs, utilizing a comprehensive material balance equation specific to water-driving gas reservoirs [48]. Kuang et al. improved the method of calculating water influx rooted in the material balance method and proposed an optimization method for the comprehensive total objective function [49]. It resolves the problem wherein the optimum outcome of the real gas reservoir is not appropriate with the lowest index in the one-goal optimization approach. Li proposed the difference method, which was based on the material balance equation of the constant volume gas reservoir to create the production indicator curve of water-driving gas reservoirs [50]. The curve was compared with the actual production indicator curve to determine the water storage coefficient, and then the water influx was obtained. Chen et al. used the material balance approach to calculate the water influx in fractured water-bearing gas reservoirs [51]. Hu et al. developed a theoretical chart of dimensionless potential pressure and recovery degree based on the material balance equation and fitted the chart to obtain water influx [52]. Yuan et al. calculated the current formation pressure, water saturation, and gas volume factor by combining the two-phase productivity formula with the relative permeability curve and production dynamic data and then obtained the water influx, which simplified the process of water influx calculation [53]. By integrating the material balance equation, Yan et al. applied the material balance principle, deduced the calculation model of water influx, and established a new method for estimating the dynamic reserves and water influx of water drive gas reservoirs [54]. Based on the above, different scholars have proposed various methods based on the material balance equation, and the research has continuously deepened. These studies have not only improved the accuracy of water influx calculations but also simplified the calculation process, providing an important theoretical foundation and practical guidance for the development and management of water-driven gas reservoirs.

4. Enhanced Gas Recovery Methods in Carbonate Bottom-Water Gas Reservoirs

Different from oil reservoirs, gas reservoirs are often developed in a one-time manner, and the main methods for improving recovery are gas reservoir engineering methods, including well network encryption, old well sidetracking, reservoir transformation, production system optimization, surface pressurization, and other measures. Water intrusion will significantly lower the recovery of bottom-water gas reservoirs. In addition to the gas reservoir engineering techniques mentioned above, controlling bottom-water invasion and taking rescue action after it occurs are crucial. Four sorts of enhanced gas recovery techniques for carbonate bottom-water gas reservoirs are presented in this section. They are gas production by drainage, production by controlling water, active drainage, and media injection, and they are explained separately in the following subsections.

4.1. Gas Production by Drainage

Gas production by water drainage is always accompanied by the development of gas wells after water production and is the main technology for stable production and enhanced gas recovery in bottom-water gas reservoirs [55]. Compared with sandstone gas reservoirs, carbonate gas reservoirs are more prone to negative water invasion because of their strong heterogeneity. In addition, the diversity of the reservoir and permeability space of carbonate rock bottom-water gas reservoir leads to the complex features of gas well water output. (1) For low-production, low-water gas wells, plunger gas lift drainage and gas extraction are commonly used. In recent years, there has been a basic realization of equipment localization, tool series standardization, and automation of control systems, significantly improving the efficiency and effectiveness of plunger gas lift. (2) For medium- and low-production water-producing gas wells, measures such as foam drainage, optimization of pipe strings, and mechanical pumping are often used. Foam drainage is the most widely used drainage and gas production process, and it has the characteristics of simple equipment and tools, easy operation, low cost, and fast effectiveness. For some high-temperature and high-pressure acidic carbonate gas reservoirs, various foaming agents and defoamers with high-temperature resistance (150~180 °C), acid resistance, and salt resistance have been developed in recent years [56]. (3) For serious liquid accumulation gas wells with good production capacity or water-flooded shut-in wells, measures such as electric submersible pumps, conventional gas lifts, and jet pumps are mainly used. Among them, gas lift drainage has the characteristics of strong adaptability to wellbore conditions, no downhole moving parts, less influence of well type and downhole corrosion, and a wide drainage range. It is the main technology for the strong drainage of gas reservoirs and single-well flooding recovery [57].

The new drainage-based gas production technology has advanced quickly in recent years. Permanent downhole packers finish most gas wells in carbonate gas reservoirs. To establish the implementation channel of drainage gas recovery technology, pre-installed type, isolated type, and cross-separated drainage gas recovery tools have been independently developed in China, and they meet the technical requirements of different stages of gas production by water drainage in gas wells completed with permanent packers. To further enrich recovery by drainage technology and meet complex needs of gas production by water drainage, new technologies such as gas lift drainage gas recovery under packer, vortex tool drainage gas recovery, downhole gas-liquid separation reinjection gas recovery, polymer water control gas recovery, ultra-deep atomization drainage gas recovery, and microwave heating drainage gas recovery have been developed [58,59]. For example, in a deep-water oil field in South America, the ultra-deep atomization drainage gas extraction technology was adopted. By using atomization technology to refine the liquid, the contact area between the liquid and gas was increased, enhancing the fluidity of the gas. The optimization results of gas well gas production by water drainage process under different water output characteristics are shown in

Table 2. Gas well recovery by water drainage processes with different water output characteristics.

Water Output Characteristic	Low-Water-Producing Gas Well		Low–Middle-Water-Producing Gas Well				Serious Effusion Gas Well/Water-Flooded Shut-Off Well
Production by Drainage Technology	Plunger Lift	Foam Drainage	String Optimization	Wellhead Pressurization	Sucker-Rod Pump	Screw Pump	Conventional Gas Lift	Electrical Submersible Pump	Jet Pump
Maximum Liquid Discharge Rate/m3/d	50	120	100	none	100	100	500	1000	300
Maximum Well Depth/m	3000	4500	4600	none	2500	1500	4000	3500	2800
Maximum Temperature/°C	none	<120 °C	none	none	none	<120 °C	none	<120 °C	none
Packer Impact	Impact	Impact	No Impact	No Impact	No Impact	No Impact	Impact	Impact	No Impact
Wellbore Condition	Limited	Suitable	Quite Suitable	Suitable	Limited	Limited	Suitable	Limited	Suitable
High Gas–Liquid Ratio	Quite Suitable	Very Suitable	Very Suitable	Very Suitable	Generally Suitable	Quite Sensitive	Suitable	Suitable	Generally Suitable
Investment Cost	Quite Low	Low	Low	Average	Average	Average	Quite Low	High	High
Flexibility	Good	Adjustable	System Adjustable	Adjustable	Production Adjustable	Frequency Adjustable	Adjustable	Frequency Adjustable	Chock Adjustable
Maintenance-Free Period/Year	0.5~1	>2	>2	>2	0.5~1.5	>1	>1	0.5~1.5	0.5~1.5

. Additionally, for gas fields with ultra-high pressure (≥120 MPa), ultra-deep burial (≥6000 m), and ultra-high formation temperatures (≥165 °C), conventional drainage gas production techniques face challenges related to insufficient drainage. Therefore, it is necessary to conduct pilot tests and field applications based on foam drainage technology and gas lift drainage technology. This will provide a reference for developing the final drainage gas production technical scheme to ensure normal gas production [60].

After years of practice and improvement of theory and technique, water-bearing gas reservoir development has gradually changed from “gas well drainage and gas recovery” to “overall water control of gas reservoirs” systematically and scientifically and has achieved remarkable application results in the Sichuan Basin [61]. As carbonate bottom-water gas reservoirs are developed, the overall water control of gas reservoirs must be adhered to and improved upon, the organic combination of gas production by water drainage and gas reservoir engineering must be strengthened, and the integral water control of gas fields must be thoroughly explored. At the same time, to further improve the optimization effect of gas wells’ whole life cycle production in carbonate bottom-water gas reservoirs, it is essential to vigorously develop the gas production by water drainage process assisted by big data technology and intelligent technology to achieve the intelligence and digitization of gas well working condition diagnosis, gas production by water drainage process selection and design, and process control [62].

4.2. Production by Controlling Water

The purpose of water control production is to maintain stable production from gas wells while controlling the water production rate of the wells. At present, the water control methods used in gas wells mainly include mechanical water control, chemical water control, and water control by development parameter optimization. (1) The mechanical water control method usually uses the downward water control pipe column or other water control tools to adjust the inflow profile in the production well interval, which has the characteristics of high reliability, long service life of the tools, and quick effect of water control [63]. The main water control tools used include a central pipe column, variable-density slotted pipe, ICD (inflow control device), etc. (2) The main principle of the chemical water control method is to achieve effective sealing and control of bottom water within a certain range by injecting chemical water control agents [64]. For bottom-water gas reservoirs with a distinct gas–water interface, non-permeable permanent water control agents such as cement slurries, solid particles, resins, and high-strength gels are commonly injected. These materials can effectively block the permeation pathways of the bottom water, preventing its upward movement and thus increasing gas recovery rates. Experimental studies indicate that using high-strength gel water control agents can enhance gas recovery by 20% to 50%. Injecting water control agents composed of solid particles and cement slurries can improve recovery rates by about 30%. In cases of gas–water mixed flow, water-soluble polymers or other phase permeability enhancers are primarily injected to create gas flow channels during gel formation and improve gas–water phase permeability, thereby reducing gas flow resistance and increasing gas–water separation rates. Field application results of water-soluble polymers show recovery rate increases of 15% to 25%. Additionally, injecting surfactants can lower the surface tension between the two-phase fluids, making it easier for gas to move through water. Experimental results show that using specific cationic surfactants can increase gas recovery by approximately 30%. (3) Water control by development parameter optimization is achieved by optimizing development parameters such as gas well production allocation, vertical well opening degree, horizontal well length, water avoidance height, and production pressure difference [65,66,67,68]. In the beginning stages of development, bottom-water cones for gas reservoirs with a bottom-water content can frequently be slowed down by controlling the opening angle of vertical wells and the height of water avoidance in horizontal wells. This produces the effect of production by controlling water. However, gas reservoirs driven by bottom water face the risk of water breakthrough in the mid-to-late production stages. Existing mature water control techniques, such as expandable packers, water-blocking gels, water-absorbing expandable polymers (WSPs), and inflow control devices (ICDs), are primarily applicable to oil wells. For gas well development, there are currently no effective water control methods available. Since gas well operations cannot implement water-blocking interventions through workover during the later production stages, intermittent gas production technology can be employed. This involves timely adjustments to the gas well production regime based on the simulation results of water cone advancement, thereby achieving water control [69].

4.3. Active Drainage

The active drainage method is a technique that improves the recovery rate of bottom-water gas reservoirs by actively lowering the water level. It typically increases the recovery rate by about 10% to 30%. The specific increase depends on the geological conditions of the gas reservoir, the properties of the bottom water, and the specific techniques and management measures implemented. This method is a key aspect of the active water management technology concept and has been widely applied in the overall water management practices of fractured carbonate gas reservoirs in the Sichuan Basin in recent years [61]. During the development process of carbonate gas reservoirs containing fractures, the bottom water is prone to swiftly and unevenly advancing along the fractures, resulting in water flooding and stopping gas well production. This phenomenon greatly reduces the recovery rate of gas reservoirs. (1) When the bottom-water volume is small, in order to achieve similar pure gas reservoir development, bottom-water invasion and damage can be prevented by deploying drainage wells at the gas–water interface at low positions and coordinating water control production at high positions early in the development process. (2) When the bottom-water volume is large, deploying a large number of drainage wells at low positions can result in high drainage costs and can easily lead to more severe water invasion. Based on accurately identifying and predicting the characteristics and patterns of water invasion, it is necessary to arrange well drainage along the water invasion channels, coordinate production by water control of high-position gas wells, and avoid irreversible damage caused by continuous large amounts of water invasion [70,71].

The gas–water interface is damaged if the fractured carbonate gas reservoir reaches the middle or final stages of development. This is because an extensive amount of bottom water enters the higher gas layer. When the use of vertical wells for drainage at low positions is no longer sufficient, horizontal wells can be drilled around the water invasion and breakthrough area for drainage. By utilizing the advantage of large seepage areas in horizontal wells, the connecting range of gas wells can be expanded, the upward migration of bottom water can be blocked, and the falling back of early invasion water can be promoted. Then, the gas seepage condition inside the gas reservoir can be improved, and the gas recovery with water in the vertical well can be increased. Active drainage technology has also been applied in the development of some fractured oil and gas reservoirs with bottom water abroad [72,73], but its manifestations are slightly different. The same wellbore is used to drill a dual-branch well; one branch is located at a high position for gas production, and the other branch is located at the gas–water interface for drainage. Gas and water are separately produced using casing and tubing to prevent water invasion.

4.4. Medium Injection

Injecting CO₂ during gas reservoirs’ early development and injecting chemical water control agents during production are the two main kinds of media injection used for enhancing the recovery rate in bottom-water gas reservoirs.

Injecting media to improve the recovery rate of bottom-water gas reservoirs can be mainly divided into two categories: (1) injecting chemical water control agents in production by water control and (2) injecting CO₂ into the early development of bottom-water gas reservoirs. Regarding chemical water control agents, relevant explanations have been provided in Section 4.2. This section mainly introduces the methods proposed in recent years to improve the recovery rate of bottom-water gas reservoirs by injecting CO₂. In the early stage of bottom-water gas reservoir development, when there is a clear gas–water interface, injecting CO₂ into the gas–water interface can achieve the following two effects: (1) It can delay water invasion. On the one hand, the density of CO₂ is between methane and water, and the injected CO₂ can serve as a separator between gas and water layers [74]. On the other hand, the interaction between CO₂ and highly mineralized formation water may generate precipitation, blocking the high-permeability area [75]. (2) It can increase gas reservoir pressure. After CO₂ injection into the gas reservoir, it is equivalent to increasing the pressure coefficient of the gas reservoir and improving the production capacity of the gas reservoir’s self-flowing. As a result, the CO₂ injection technique for increasing bottom-water gas reservoir recovery rate has the significant potential to both store greenhouse gases and increase the recovery rate of gas reservoirs.

In addition, field tests have shown that induced fractures are formed during the injection of the medium. Combined with the fractures that naturally develop in the carbonate reservoir, the fracture network structure becomes more complex, which is beneficial for increasing the coverage area of the injected medium. However, the presence of fractures can lead to the rapid advancement of the injected medium, exacerbating crossflow issues [76].

5. Enhanced Gas Recovery Examples in Carbonate Bottom-Water Gas Reservoirs

This section reviews the application effects of various enhanced gas recovery methods in numerous typical carbonate bottom-water gas reservoirs (Weiyuan gas field, Yuanba gas field, and Orenburg gas field), based on development practices, in an effort to serve as a guide for similar gas fields.

5.1. Typical Bottom-Water Gas Reservoirs in China

5.1.1. Weiyuan Gas Field

Weiyuan gas field is a large fractured–vuggy carbonate bottom-water gas reservoir developed earlier interiorly. The pressure coefficient of the gas reservoir is 1.289, and its median porosity and permeability are 2.05% and 0.08 mD, respectively. The gas reservoir is an asymmetric short-axis anticline with a gentle north and steep south structure, and the objective layer is the Sinian Dengying Formation. Water developed at the bottom position has a unified gas–water interface, and the estimated water reserve range is 4.5~9.92 × 10⁸ m³ [77]. The gas field began to produce spontaneously in 1968, and after the annual gas production reached its peak in 1976, the number of wells that produced water started increasing substantially. In 1985, gas production by water drainage was implemented, and the water–gas ratio remained relatively stable at around 20 m³/10⁴ m³. In 1995, strong drainage was implemented, and the water–air ratio continued to rise to 90 m³/10⁴ m³. In 2007, secondary development began, and the water–gas ratio was further raised to 100 m³/10⁴ m³. The entire water flooding in the middle and late stages of the gas reservoir’s development is caused by the inadequate application of the whole water control technology concept in the early stages of the gas reservoir’s development, and the gas reservoir’s current recovery degree is only 36.7%.

In the Weiyuan gas field’s history of development, enhanced gas recovery methods that have achieved good results mainly include gas production by water drainage and active drainage, which form characteristics in the active drainage technology of “horizontal well drainage and vertical well gas production”. (1) The first method considered is drainage and gas production technology. Water-producing gas wells have made extensive use of drainage and gas production technologies ever since the wells began to generate water in 1976. In practice, it has been found that the electric submersible pump/jet pump/plunger process is severely corroded, with a low drainage capacity of foam drainage and severe blockage of the mechanical pump. However, the gas lift procedure is still the primary drainage and gas production process in the Weiyuan gas field today due to its high degree of adaptability. Since the adoption of gas production by the water drainage process until the final days of 2020, the process measures’ accumulated gas production accounted for more than 30% of the total gas production during that period. (2) The second method considered is production by water control. Premature water outflow from the gas well was caused by uncontrolled water production at the top of the gas reservoir during the early phases of production. From 1980 to 1992, the water avoidance height of newly completed drilling at the top of the gas reservoir was 92–185 m. However, the objective of water control cannot be accomplished since the bottom water has channeled along the fracture to the middle and higher areas of the gas reservoir. (3) The third method considered is active drainage. Vertical wells are used to produce gas, whereas horizontal wells are utilized for drainage. Weiyuan gas field has been completely flooded since 2000, and single-well drainage and gas production cannot fundamentally solve the water invasion damage. On the one hand, long-term gas production by water drainage in the longitudinal middle and upper area of the gas reservoir causes the formation water to continue to enter the gas reservoir and form a significant amount of water-sealed gas. On the other hand, several high-osmotic-pressure-drop funnels have been formed in the well area with good transverse seepage conditions, and straight wells’ impact on gas production and drainage has been decreasing. In 2007, the Southwest oil and gas field drilled horizontal wells around the water invasion breakthrough area to especially drain and coordinate with the top old wells (straight wells), which improved the gas–water relationship to a certain extent. The natural flow production of horizontal Wells W1 and W2 around H1 resumed, and the gas sighting time of newly put in production around the horizontal wells was significantly shortened. Further, combined with the extraction and efficiency of new energy sources (lithium and bromine) in the formation water, it is possible to develop the Weiyuan gas field again.

5.1.2. Yuanba Gas Field

The gas reservoir of the Changxing Formation in Yuanba is situated at the junction of the Jiulongshan anticline and low structural belt in middle Sichuan. It is the deepest reservoir of high-sulfur reef bottom water found in the world and has the characteristics of “one excess, three highs, and five complexities”. The “one excess” refers to an ultra-deep burial depth, with the main layer located between −6300 m and −7200 m. The “three highs” refer to high temperature (149~164 °C), high pressure (66~77 MPa), and high sulfur content (average sulfur content of feed gas is 5.32%). The “five complexities” refer to complex reef reservoirs, complex gas components, complex gas–water relationships, complex pressure systems, and complex topography [78]. The gas reservoir is horizontally divided into four reef zones and one reef beach overlapping area and vertically divided into Changxing upper (reef) and Changxing lower (beach area) reservoirs. Among them, the bottom water is commonly developed in the No. 1 reef zone, No. 2 reef zone, and reef–beach overlap area, but the interaction between gas and water is not uniform, presenting a complex gas–water distribution feature of “one reef, one beach, and one reservoir” [79]. Since the gas reservoir was put into production, there have been a total of 13 water-producing wells and 7 water-producing risk wells. As of October 2022, the gas reservoir’s overall water production condition remained stable, and it is anticipated that the reservoir’s overall recovery rate will reach over 70%.

(1) The first method considered is gas production by drainage. Yuanba gas field relies heavily on foam drainage for its gas production process due to its resistance to high temperatures, high salt content, acid gas, and a broad range of mineralization. The combined production process of nitrogen injection with water and foam drainage is implemented for water-flooded wells, which provides a successful case for the resumption of water-flooded production of high-sulfur gas wells both domestically and internationally. In terms of surface construction, the gas field has strengthened the construction of water treatment expansion projects and released the production capacity of production wells, which guaranteed the steady, constant, and effective development of gas reservoirs. (2) The second method considered is production by water control. Based on the reservoir configuration, fluid distribution, and water invasion features of biological reef bottom-water gas reservoirs, the differentiated water prevention and control method for these reservoirs in the Yuanba gas field is proposed, which includes “early delay of water invasion, middle control water cone, and later prevent water flooding”, providing technical guidance and beneficial experience for the efficient development of similar high-sulfur biological reef bottom-water gas reservoirs in China [80]. ① Applying the principle of “early delay of water invasion” to risk wells that produce water allows for stringent control over the production pressure differential, close monitoring of water ion changes in gas fields, and an extension of the water-free gas production time. ② Medium- and low-water-producing wells adopt the whole-cycle differentiated water prevention and control method to achieve stable production. After water was seen, production was proactively reduced based on changes in the water–gas ratio. The pressure drop rate was relatively stable, and the changes in water production and water–gas ratio were relatively gentle, with no obvious increasing trend. ③ For high-water-producing gas wells, established on the concept of water cone control, waterlogging prevention, and “production-invasion balance”, water control measures were formulated to slow down the trend of water-producing deterioration. This kind of gas well has a tight relationship between its production rate and pressure drop rate. Currently, stable production is achieved by controlling the production rate below 100,000 m³/day and greatly slowing down the rate of pressure decrease. (3) The third method considered is reef–beach combined production technology. The primary region of gas production in Yuanba is the reef facies located in the uppermost portion of the Changxing formation’s gas reservoir structure, while the beach facies in the low part have poor physical properties and extensive development of water. By lowering the pressure differential between the gas and water zones, the reef–beach combined production method of upper gas production and lower drainage was implemented in the gas reservoir. This efficiently absorbed the energy of the water in the beach phase and regulated water invasion. The study of water prevention and control strategies throughout the entire cycle will be furthered in the future. One well, one strategy. Targeted development strategies for gas wells in water-bearing areas will be developed, providing a successful experience for the creation of water control and gas stabilization schemes for high-sulfur reef bottom-water gas reservoirs in China.

5.2. Other Typical Bottom-Water Gas Reservoirs

The Orenburg gas field is the largest condensate gas field in the former Soviet Union’s European area, with reservoirs formed along the Orenburg asymmetric anticline in the northern section of the Sol-Iletsk uplift. This field is a fractured–porous carbonate reservoir with a broad gas-bearing region, and the lithology and physical parameters vary greatly in either verticality or horizontality. The average porosity is 5.1%, and the permeability ranges from 0.1 mD to 34.6 mD. The natural gas reserves are 1768.6 × 10⁸ m³, and the current exploitation degree is 67.69%. The gas field had around 850 wells drilled, 352 of which were flooded. Among the 217 wells currently producing, 174 wells with water produced a total of 2200 × 10⁴ m³ formation water. The gas field has a complex gas–water connection. The bottom water migrates vertically upward along the fault and fracture development zone and then invades the gas reservoir along the high-permeability channel and bedding direction.

In the Orenburg gas field’s development history, enhanced gas recovery methods that have achieved good results mainly include gas production by drainage and production by water control, among which chemical water control technology has achieved great success. (1) The first method considered is gas production by drainage. By putting surfactants into the tubing and combining them with mechanical drainage measures (jet pump), the mechanical drainage efficiency was improved, the application range was expanded, a large number of chemical agents were saved, and better gas production by drainage results were achieved. (2) The second method considered is production by water control. ① First, we consider development parameter optimization. The gas field is organized into eleven blocks based on its geological parameters and production characteristics. Different gas production rates (1.89~6.1%) are adopted for each block to achieve balanced depressurization gas production and prevent uneven formation water advance. ② Second, we consider chemical water control. In well sections with severe water flooding or high-permeability layers, cement injection (mechanical plugging) or viscous liquid injection is utilized to establish a seepage barrier and limit bottom water accessing the gas reservoir. A significant amount of conventional and selective water plugging tests were conducted in the gas field, with the findings indicating that 57% of the wells were effective. After the water plugging and workover operation, the single well’s daily gas production increased to 3.5~5 × 10⁴ m³, and the daily water production remained at 55 m³. However, the application effect of chemical water plugging measures in the Weiyuan gas reservoir is poor. This is because, in a bottom-water gas reservoir with high-angle fractures, even if a chemical agent is injected to block a specific formation, bottom water continues to flow into the upper section of the gas reservoir along the high-angle fractures.

6. Conclusions

• Carbonate gas reservoirs, unlike sandstone gas reservoirs, have a variety of storage and permeable spaces, as well as a wide distribution of pore scale. These characteristics lead to various types of trapped gas caused by water invasion, which are significantly affected by the size, distribution, and density of fractures and vugs. A multi-phase flow modeling method across scales is required to coordinate the scale differences in carbonate reservoirs and accurately describe the water invasion laws for various scales and reservoir regions.
• At present, a great number of water invasion detection techniques, prediction models, and calculation methods for carbonate bottom-water gas reservoirs have been developed. However, the prediction accuracy of these methods for gas reservoirs containing fractures and vugs needs to be further improved, especially for water invasion prediction models, which are mostly based on bottom-water coning models established for homogeneous or semi-homogeneous reservoirs. Based on the extensive characterization of fractures and vugs at the reservoir scale, detailed numerical simulations of carbonate bottom-water gas reservoirs remain the primary research direction for the future.
• The keys to improving the recovery of carbonate gas reservoirs are not only traditional techniques for gas reservoir engineering (well pattern infilling, reservoir reconstruction, surface pressurization, etc.); they also include managing bottom-water invasion and implementing rescue actions following it. It can be parted into four categories of enhancing recovery methods: gas production by drainage (foam drainage, optimized tubing string, mechanical pumping, etc.), production by water control (mechanical water control, chemical water control, development parameter optimization water control), active drainage, and medium injection. To improve the recovery rate of carbonate gas reservoirs with bottom water, it is essential to consider various technical methods and develop a reasonable and effective development plan that takes into account specific geological characteristics and production conditions.
• Current practices in the development of bottom-water gas reservoirs indicate that drainage gas production is the primary technological approach for improving recovery rates in water-bearing gas reservoirs, with the application of gas drainage being the most widespread. Optimizing production parameters for water control has shown good results in the early stages of development and is another key technology for enhancing recovery rates in these types of gas reservoirs. Active drainage techniques are increasingly being applied to heterogeneous bottom-water gas reservoirs, especially in the later stages of development, where this technology may serve as a foundational method for effective gas reservoir redevelopment. Injecting CO₂ at the gas–water interface in the early stages can help separate methane from water, increase reservoir pressure, and generate precipitation that blocks high-permeability zones, offering significant potential in the context of “carbon neutrality and peak carbon emissions”.