Shale gas wells are characterized by low porosity and low permeability, necessitating volume fracturing for industrial gas flow initiation. Given the difficulty in recovering a large volume of fracturing fluid (Meng et al., 2023a), it is assumed that shale gas wells will produce a certain amount of injected water (Zou et al., 2021; Meng et al., 2023b). In the initial production stage, shale gas wells often have high output, but most wells experience a rapid decline in production of 40%–80% within a year (Oyewole, 2016). The production characteristics of high initial output and rapid decline post-fracturing necessitate the use of artificial lift techniques (Kaisare et al., 2013). For low-producing shale gas wells in the middle and late stages of production, plunger lift can achieve optimal economic benefits (HASSOUNA, 2013).

The plunger lift is currently one of the most economically effective methods for removing accumulated liquid in gas wells (Chen et al., 2021), but its applicability is not yet clear (Hassouna, 2013; Hingerl et al., 2020), and there are still some challenges in its application in horizontal wells (Sask et al., 2010).As early as the 1950s, experts and scholars from the United States and the Soviet Union began researching plunger lift. In 1965, Foss and Gaul proposed the classic plunger lift model based on force balance, derived from experience in gas fields, which later influenced most subsequent research (Foss and Gaul, 1965; Lea, 1982). Maggard et al. (2000) established a new dynamic model for plunger lift specifically for tight gas wells, enabling in-depth analysis of the entire gas lift process in such wells. In 2007, plunger lift was applied in 40 tight gas wells in the San Juan Basin’s northern area, resulting in an increase in daily production of over 11 × 10⁴ m³/d (Oyewole and Garg, 2007). Advances in related technologies have greatly expanded the application range of plunger lift technology, especially the rise of gas-assisted-plunger-lift (GAPL) and plunger-assisted-gas lift (PAGL), further extended plunger lift’s capabilities in horizontal wells (Burns, 2018). In 2011, the plunger reached a 74 well inclination in Marcellus shale gas wells, demonstrating the applicability of plunger lift in horizontal wells (Kravits et al., 2011).

Currently, there is limited research on comprehensive evaluation methods for plunger lift in the industry. Lea et al. (2007) proposed an empirical method for monitoring plunger movement, liquid column height, and circulation time, optimizing the control parameters of plunger lift. Bello et al. (2011) developed a simple analysis model for plunger lift systems, assessing the feasibility of the technology. Hosein and Mohammed, (2017) used the Foss and Gaul model to determine optimal plunger rise speed and gas requirements. Teymourifar and Ozturk (2018) adopted a neural network heuristic algorithm to solve the production scheduling problem of plunger lift. Liu et al. (2020) proposed a method to implement a work system according to the average production of plunger lift Wells. Yang et al. (2022) established an evaluation method of plunger lift application timing, process parameters, and operational regimes in the shenmu Gas Field based on the production situation.

As an economically effective measure for stabilizing production, the plunger lift has been extensively implemented in over 200 wells in Changning Block (Wang et al., 2023). However, challenges remain, including the dispersion of Plunger lift wells, and a lack of comprehensive evaluation methods. Current practices involve adjusting process parameters based on individual well production without a complete plunger lift applicability evaluation system. Therefore, it is necessary to carry out comprehensive evaluations of plunger lift. This paper summarizes key evaluation indicators for plunger lift based on field production situations, classifies typical field plunger lift wells, and comprehensively evaluates the effectiveness of plunger lift in gas wells.

Plunger lift propels the plunger up and down, utilizing the well’s own energy to expel accumulated liquids and prolong the life of the gas well, thereby effectively restoring gas production. This method is a special form of intermittent gas lifting, primarily powered by formation energy, but can be supplemented by injecting high-pressure gas into the wellbore. The plunger, acting as a solid interface, separates the accumulated liquids above from the gas below, reducing liquid loss and gas channeling, thus improving operational efficiency. Typically, the entire movement process of plunger lift is divided into four stages: plunger descent, pressure recovery, plunger ascent, and sustained production (Zhao et al., 2021; Xiong et al., 2023) as shown in Figure 1.

(a) Plunger descent

After the end of the sustained production stage, the well is shut in, and the plunger starts to descend from the wellhead under its own gravity. The casing pressure and tubing pressure gradually recover, and the plunger passes through the gas and accumulated liquid, eventually descending to the catcher position. If the pressure recovery meets the requirements at this point, the well is reopened to start a new cycle, otherwise, it enters the pressure recovery stage.

(b) Pressure recovery

When the reservoir’s liquid and gas supply capacity is low, the plunger should remain on the catcher for a period, allowing the pressure to recover sufficiently to push the plunger from the wellbore to the wellhead. During this stage, oil and gas continue to accumulate around the wellbore, and the energy at the bottom of the well gradually recovers.

(c) Plunger ascent

When the casing pressure and tubing pressure recovers to a certain extent, the well is opened for production. The expanded gas in the annulus flows into the tubing, lifting the plunger and the upper liquid column towards the wellhead along with the formation gas until the plunger reaches the wellhead, where it is captured by the wellhead catcher. The liquid column above the plunger completely enters the production pipeline, and the gas well enters the continuous sustained production stage.

(d) Sustained production

If the reservoir has sufficient energy, the gas well can be put on intermittent production for a period of time. However, with the production of the gas well, the formation water and accumulated liquid in the annulus gather at the bottom of the well again, causing the well-bottom flow pressure increases continuously. If the gas well energy cannot carry the liquid, it indicates the end of the working cycle.

Key evaluation indicators for plunger lift include casing pressure changes, production variations, plunger height in the liquid segment, changes in tubing-casing pressure differential, and blowdown differential. These indicators are crucial for classifying and evaluating the performance of typical field plunger wells.

(1) Casing Pressure Change after Shut-In

The cycle gas production of plunger lift wells increases with casing pressure and the duration of sustained flow after reopening. The higher the set opening casing pressure, the longer the shut-in time required for pressure recovery, resulting in a longer lift cycle. This is partly due to the larger volume of gas needed to achieve higher casing pressures and partly because the pressure difference between the well-bottom flow pressure and the formation pressure decreases at higher casing pressures, slowing the recovery rate.

(2) Plunger Ascent Speed

Due to a minimum gap of 1.25 mm between the plunger and the tubing wall, liquid loss occurs. The plunger must reach a certain speed during ascent to effectively seal gas and liquid, known as “velocity sealing”. Numerical simulations indicate that the critical ascent speed to prevent liquid leakage is 3.7 m/s (Han, 2016). If the plunger’s ascent speed is too low, gas channeling increases dramatically, reducing production efficiency. Conversely, too high a speed can cause significant liquid leakage, decreasing lifting efficiency.

When the liquid segment plunger reaches the wellhead, the smaller size of the wellhead pipeline compared to the tubing can delay liquid discharge, creating backpressure. The plunger ascent time is from the moment of opening the well until the tubing backpressure returns to atmospheric pressure as shown in Figure 2.

(3) Plunger Descent Speed

During plunger descent, a dynamic fluid level exists in the tubing, so the plunger experiences both falling through gas and liquid phases. Both too fast and too slow descent speeds are detrimental. For wells with inflection points in the pressure recovery curve, the plunger undergoes both descent and settling in the catcher, with the descent time being from shut-in to the inflection point in the pressure recovery curve. For wells without inflection points: slower plunger descent speeds mean the plunger only experiences the descent phase, with the descent time equal to the shut-in duration as shown in Figure 3.

(4) Tubing-Casing Pressure Differential

For plunger lift wells, one method to judge the effectiveness of plunger lifting is to observe whether there is a height of the liquid column above the plunger. Using data from the Ning 209-2well, a “WellFlo numerical model” was developed to simulate the relationship between tubing-casing pressure differential and liquid column height as shown in Figure 4.

Results show that the tubing-casing pressure differential reflects the height of the liquid inside the wellbore (Figure 5). And the difference between “opening tubing-casing pressure differential” and “shut-in tubing-casing pressure differential” indicates changes in the height of the liquid column during opening and shut-in.

(5) Pressure relief

The pressure relief is defined as the difference between the “tubing pressure in the gas well before opening” and the “stable production tubing pressure in the gas well after opening.” The magnitude of the pressure relief before and after opening reflects the pressure exerted by the gas to push the liquid column above the plunger and is indicative of the pressure recovery during the shut-in period. As a special form of intermittent gas lifting, plunger lift is essentially a high-frequency “intermittent production” as shown in Figure 6.

For plunger lift wells, the change in tubing-casing pressure differential is an important evaluation indicator for the plunger lift. An important method to determine the effectiveness of plunger lift is to observe the height of the liquid column above the plunger. Classifying based on the liquid column height is not only simple and intuitive, but also has a certain corresponding relationship with the oil tubing-casing pressure differential as shown in Table 1. Generally, it is believed that in the case of sufficient gas volume, wells with a liquid column height >100 m have a better effect in reducing pressure by plunger lift for deliqufication. For wells with a liquid column height of 20–100 m, plunger lift can have a certain effect in reducing pressure for deliqufication. For wells with a liquid column height <20 m, plunger lift for deliqufication is ineffective.

(1) This paper analyzes the production characteristics of on-site gas wells and summarizes the key evaluation indicators of plunger lift, including casing pressure changes, production changes, liquid column plunger height, tubing-casing pressure differential changes, and differential size of pressure relief. Combined with numerical simulation methods, a complete set of methods for judging, classifying, and evaluating the effectiveness of plunger lift is proposed.