Mechanism of Salt Precipitation Blockage in Low-Producing Gas Wells and the Method of Acidification Blockage Removal

Abstract

In the Changqing area, over 23.6% of gas wells produce less than 0.1 × 10⁴ m³/d of gas daily, posing a challenge to gas field sustainability. Laboratory analysis of scale samples from three wells and formation water analysis via inductively coupled plasma revealed soluble salt as the primary well blockage, with sodium chloride and calcium chloride comprising 48.0–81.2% of total content. The G3# well blockage contains a small amount of quartz from acid-insoluble components of carbonate acidification. Formation water from all wells exhibited high salinity (up to 153 g/L) with a calcium chloride water type. Scanning electron microscopy and EDS confirmed halite and quartz features in blockage samples. Theoretical calculations show salt crystallization when tubing pressure falls below 10 MPa and daily water production is <1.0 tons/day. Lower production leads to lower tubing pressure and higher salt precipitation at the bottom of the well. For G1# and G2# blockages, HCl dissolves >90%, and water >85%, making them suitable removal agents. For 3# blockage, mud acid with >80% dissolution is recommended. Chemical methods effectively clean the wellbore and formation. Optimized blockage removal measures increase tubing pressure and daily production by 2.18 and 4.05 times, respectively. This study offers insights into addressing well blockage challenges in low-producing gas wells.

1. Introduction

Natural gas resources represent a crucial source of clean fossil energy, and Changqing gas field, as one of China’s four major natural gas production bases, plays a pivotal role in the country’s energy development.¹⁻³ However, with the passage of time, the proportion of low-producing gas wells in the Jingbian area has been steadily increasing,^4,5 posing a significant threat to the sustainable development of natural gas resources. Preliminary analysis suggests that the surge in blocked wells can be attributed to two primary scenarios. First, low-producing gas wells often exhibit limited liquid carrying capacity, leading to substantial water accumulation in the wellbore, resulting in pronounced effusion and water blockage issues.^6,7 Second, low-flow-rate natural gas, containing corrosive gases such as H₂S and CO₂, continuously carries saturated water vapor, which increases mineralization levels at the well’s bottom, contributing to scaling and sand deposition within the wellbore.^8,9 However, a comprehensive understanding of the blockage types, mechanisms, and appropriate treatment methods remains elusive.

Due to complex oil and gas reservoir conditions, various types of wellbore blockages exist, including sand blockages,¹⁰ scale blockages,¹¹ hydrate blockages,¹² and wax blockages.¹³ These blockages can be broadly categorized into organic and inorganic types. Organic blockages encompass substances like wax, asphaltene,¹⁴ residues from the manual addition of reagents such as corrosion inhibitors¹⁵ and oil-displacing agents,¹⁶ as well as hydrates formed during production due to low temperature and high pressure, occasionally leading to composite blockages.¹⁷ In contrast, the formation of inorganic blockages is mainly attributed to factors such as high salinity or corrosion in the formation water, involving substances like NaCl, CaCO₃, CaSO₄, BaSO₄, and FeS.^18,19 To identify the root cause of these blockages, it is essential to take samples from field wells, separate them, and then conduct comprehensive analysis and identification.

In the case of organic blockages, oxidants,²⁰ organic solvents,²¹ and surfactant solutions are commonly utilized. Based on different wellbore blocking conditions, various blockage removal agents have been employed. For inorganic blockages, options include hydrochloric acid (HCl),²² mud acid,²³ chelating agents,^24,25 and other blockage removal fluids. In instances of composite blockages, certain studies have demonstrated that microemulsion acid systems can effectively dissolve both organic and inorganic scales simultaneously,^26,27 facilitating the one-step removal of various scales. However, the selection of the removal liquid system hinges on the type and composition of the blockages. Given the composition and mechanism of blockages in the Jingbian area of the Changqing gas field, investigating blockage removal fluids becomes imperative for addressing blockages in low-producing gas wells.

This paper utilizes analyses of water and blockage samples, along with an examination of reservoir characteristics,²⁸ to identify blockage types in low-pressure gas wells G1#, G2#, and G3# in the Jingbian area. It investigates the underlying reasons and mechanisms behind gas well blockages, conducts dissolution experiments, and optimizes blockage removal agents. Ultimately, it proposes safe, efficient, cost-effective, and environmentally friendly blockage removal systems. The findings indicate that the mineral composition of Jingbian blockages primarily comprises inorganic soluble salts, with negligible organic substances. It is presumed that the elevated salinity of formation water, coupled with continuous water evaporation during late-stage gas production, contributes to wellbore blockages. Theoretical calculations reveal that when tubing pressure drops to <10 MPa, and daily water production falls below 1.0 tons/day, salt crystallization inevitably precipitates at the well’s bottom or within the reservoir. Lower daily production corresponds to reduced tubing pressure and higher salt precipitation positions in the wellbore. One of the well’s blockages contains a small amount of quartz, likely originating from acid-insoluble residues during carbonate gelled acid acidification. For G1# and G2# blockages, HCl exhibits a dissolution rate exceeding 90%, while water dissolution exceeds 85%, making them suitable removal reagents. In the case of the 3# blockage, mud acid demonstrates a dissolution rate exceeding 80% and is recommended. Chemical methods prove effective in cleaning both the wellbore and formation. Optimized blockage removal measures yield significant stimulation effects, doubling tubing pressure and daily production by 2.18 times and 4.05 times, respectively.

2. Materials and Methods

2.1. Experimental Materials

Blockage samples were collected from the G1#, G2#, and G3# gas wells at the Jingbian Gas Field in 2023. Additionally, water samples were obtained from the same G1#, G2#, and G3# gas wells at the Jingbian Gas Field in 2023 for analysis. Chemical agents used in the study included hydrofluoric acid (HF) (48–51% aqueous solution, Shanghai Titan Technology Co., Ltd.), HCl (35–37% aqueous solution, Tianjin Fuyu Fine Chemical Co., Ltd.), organic acid (provided by Kemes Oil and Gas Field Technology Co., Ltd. as an industrial product), EDTA·2Na (analytical pure, supplied by Beijing Yongchang Haoran Biotechnology Co., Ltd.), mud acid (with a composition of HCl/HF = 12:3%), and HEDP (80% aqueous solution, from Shanghai Aladdin Biochemical Technology Co., Ltd.). These samples and chemical agents were utilized in various aspects of the research and analysis conducted in this study.

2.2. Separation of Blockages

The blockages were collected from wells G1#, G2#, and G3# in the Jingbian Gas Field. A mass of 20 ± 0.5 g of blockage samples was weighed and then subjected to drying in an oven at 105 °C for a duration of 24 h. The samples were periodically weighed until their weight remained constant (within a margin of ±0.02 g). The water content was subsequently calculated using eq 1.

1

Water content (W_s, %) is calculated using the formula where m₁ represents the weight of the dried blockage sample (in grams), and m₂ is its weight before drying (in grams).

The dried blockage samples were ground into a powder with a particle size ranging from 100 to 140 mesh (refer to Figure 1). Subsequently, 5 g of this powder was placed in a filter paper cylinder and inserted into a Soxhlet extractor (refer to Figure 2) for a duration of 7 days. Dichloromethane (DCM) served as the solvent for Soxhlet extraction, maintaining a heating temperature of 90 °C. The solution within the flask underwent concentration and distillation under reduced pressure, leading to the extraction of the organic component of the blockage. This component, after being dried in an oven at 105 °C for 2 h, had its content calculated according to eq 2.

2

Figure 1.

Blockages before and after Soxhlet extraction by DCM from well: (a) G1#, (b) G2#, and (c) G3#.

Figure 2.

Soxhlet extractor.

The organic component content (W_o, %) is calculated using the following formula: W_o = (m₃/m_2′) × 100. Here, m_2′ represents the total mass of the blockage (in grams), and m₃ denotes the mass of the organic component (in grams).

2.3. Water Analysis and Mineral Analysis

This study aimed to thoroughly investigate the composition of formation water in gas wells and its relationship to wellbore blockages. Field water samples were collected and analyzed for ions including Ca²⁺, K⁺, Na⁺, Mg²⁺, SO₄^2–, HCO^3–, and Cl^– using an inductively coupled plasma spectrometer. Additionally, the pH value of these samples was determined using a pH tester.

Analyzing the composition of wellbore blockages is crucial for their effective removal. Understanding the mineral and clay content within these blockages assists in selecting appropriate removal reagents. For this purpose, formation cores and wellbore blockages from gas wells G1#, G2#, and G3# were collected. These samples were first cleaned of oil and salt and then dried in a 105 °C oven until reaching constant weight. They were then ground into 200–400 mesh for mineral analysis (see Figure 3). An X-ray diffractometer was employed for determining mineral compositions. For clay analysis, Whole-Rock-Rockquan 2020 software was utilized. Additionally, selected dried blockage samples were subjected to electron microscopy and energy dispersive spectroscopy (EDS) elemental analysis to further investigate their structure and composition. This analysis primarily utilized the Quanta 200F field emission environmental scanning electron microscope. The samples were prepared by adhering them to a metal sheet with conductive adhesive, coating them with gold in a gold sprayer to enhance conductivity, and then examining them using SEM for observation and EDS elemental analysis.

Figure 3.

Samples preparation for mineral composition analysis.

2.4. Test Method for the Dissolution Rate

Various scale removers were selected for this study, including 8% HF, 10% HCl, 10% organic acid, 10% chelating agent EDTA·2Na, a mud acid mixture of 3% HF and 7% HCl, and 10% organic phosphoric acid HEDP. The blockage powder, prepared to 100–140 mesh following drying and grinding, conformed to China’s standard SY/5886-93. The experimental procedure was as follows: (1) 100 mL of different scale remover solutions was added into a 150 mL plastic beaker. (2) 1 g of scale sample (m₄) was weighed and added, and the beaker was sealed with plastic wrap and placed in a water bath. (3) The temperature was set to the formation temperature of 90 °C and the reaction was maintained for 2 h. (4) The beaker was allowed to cool, a dried filter paper (m₅) was weighed, the reaction liquid was weighed using a Brinell funnel, and the residue was washed thrice with water. (5) The reaction residues were dried at 120 °C until reaching a constant weight, noting the combined weight of the filter paper and scale sample as m₆. (6) The dissolution rate was calculated using eq 3.

3

where C_R represents the sample dissolution rate (in percent); m₄ represents scale mass (in grams); m₅ represents filter paper mass (in grams); and m₆ represents total mass of filter paper and residues after reaction (in grams).

3. Results and Discussion

3.1. Water and Organic Matter Content

Table 1 illustrates the water and organic composition contents of wellbore blockages from the three wells. The overall water content in these wells was found to be less than 5%, with well G1# exhibiting the highest at 4.12%. The organic composition content across the three wells was notably low, ranging between 0.012 and 0.032%. As depicted in Figure 4, the Soxhlet-extracted organic composition solution appears very clear, further suggesting a low concentration of organic compounds. This observation leads to the conclusion that organic matter is unlikely to be a primary cause of wellbore blockages and exerts minimal influence on their formation.

Table 1. Water Content and Organic Composition Content of Wellbore Blockages.

well number	water content %	organic composition content %
G1#	4.12%	0.032%
G2#	2.32%	0.025%
G3#	1.24%	0.012%

Figure 4.

Organic composition solution extracted by Soxhlet.

3.2. Mineral Composition of Blockages

Table 2 reveals that the predominant mineral in well G1# blockage is NaCl salt, comprising 44.2% of the total mineral content. This high concentration of NaCl salt likely results from the elevated levels of Cl^– and Na⁺ in the formation water. During the gas production process, the water in the wellbore evaporates and is transported to the natural gas. Consequently, the concentration of NaCl in the remaining water may surpass its solubility limit near the wellbore, leading to its precipitation and the subsequent formation of blockages. Additionally, the blockage from well G1# contains 31.2% quartz, which might originate from sand production in the reservoir, causing sand accumulation near the well and potentially contributing to wellbore blockage. Therefore, the combined presence of NaCl salt and quartz, which constitute 75.4% of the blockage material in well G1#, appears to be the primary cause of blockage in this well.

Table 2. Mineral Composition of Three Blockages.

well number	mineral composition (%)
	quartz	potassium feldspar	plagioclase	calcite	dolomite	CaCl2·2H2O	NaCl	hematite	hornblende	anhydrite	clay
G1#	31.2	2.9	4.4	2.6		3.8	44.2	7.1		1.8	2.0
G2#	0.2			8.5	4.1	55.3	25.8	1.5	1.9		2.7
G3#		1.4	3.1	21.0	9.0	41.0	21.2	1.3			2.0

In the G2# well, the most abundant mineral found in blockages is CaCl₂·2H₂O salt, constituting 55.3%, followed by NaCl salt at 25.8%. Combined, these two minerals represent 81.1% of the blockage composition. The formation of these blockages is attributed to the high concentrations of Cl^–, Ca²⁺, and Na⁺ in the formation water. During natural gas production, the continuous evaporation of water from the wellbore results in the accumulation of CaCl₂ and NaCl, forming soluble salt blockages over time.

The blockage in well G3# shows a similar trend, with CaCl₂·2H₂O salt comprising 41% and NaCl salt 21.2%. Additionally, approximately 21.0% of the blockage is composed of calcite. While the blocking mechanism in G3# is akin to that in G2#, a distinctive factor in G3# is the presence of calcite, potentially precipitated due to a pressure drop in the wellbore. This suggests a unique aspect of the G3# well, warranting further investigation. As presented in Table 3, the clay content in blockages from all three wells predominantly consists of Illite, albeit in low concentrations. Thus, clay, specifically Illite, is not a major component of the blockages and does not significantly influence wellbore blockage.

Table 3. Clay Composition of Three Blockages^a.

well number	clay composition (%)					mixed layer ratio (%)
	S	I/S	It	K	C	C/S	I/S	C/S
G1#	0	0	100	0	0	0	0	0
G2#	0	0	100	0	0	0	0	0
G3#	0	0	100	0	0	0	0	0

^aS: montmorillonite I/S: I/S mixed layer It: Illite K: kaolinite C: chlorite C/S: C/S mixed layer.

3.3. Formation Water and Core Mineral Analysis

Formation water samples from three wells were collected and analyzed, as summarized in Table 4. The analysis indicates that the formation water is predominantly of the calcium chloride type, with a pH around 6.0 and high Ca²⁺ concentrations. The high salinity of this water suggests that during natural gas production, part of the water vapor is carried away with the gas flow. Consequently, as pressure and temperature decrease within the wellbore, the concentration of soluble salts in the formation water exceeds their solubility limit, leading to precipitation and blockage formation. This finding aligns with the observed mineral composition of the blockages. Additionally, the water quality analysis revealed a minor presence of HCO₃^–. When the formation water’s pH exceeds 7, and it enters the wellbore, the reduction in pressure coupled with CO₂ release could facilitate the formation of calcium carbonate scale. This phenomenon might explain the detection of calcite scale in the G3# well.

Table 4. Water Sample Analysis of Three Wells.

well number	K+ + Na+ (mg/L)	Ca2+ (mg/L)	Mg2+ (mg/L)	Cl– (mg/L)	SO42– (mg/L)	HCO3– (mg/L)	salinity (g/L)	water type	pH
G1#	19,948	29,523	4942	93,641	4880	231	153.17	CaCl2	5.9
G2#	35,829	10,016	3101	79,152	3429	514	132.04	CaCl2	6.0
G3#	36,294	11,810	2740	80,944	4995	857	137.84	CaCl2	6.4

To ascertain whether the wellbore blockages originated from the reservoir, formation cores from the three wells were analyzed in Table 5. The primary mineral composition of these cores was identified as dolomite, with minor quantities of quartz and calcite present. In the case of well G1#, the blockage material showed a significant presence of quartz, constituting 21%. This contrasts with the reservoir rock of G1#, which only contained a small amount of quartz as per the mineral analysis. Furthermore, investigation into the operational history of G1# revealed that acidification had been performed during well completion. This suggests that the quartz in the blockage likely originated from the residues of acidification, implying that acid-insoluble quartz might have migrated into the wellbore.

Table 5. Mineral Composition Analysis of Three Wells’ Cores.

well number	mineral composition (%)
	quartz	calcite	dolomite	anhydrite
G1#	1.8	0	98.2	0
G2#	2.7	7.5	89.8	0
G3#	0.3	8.9	90.8	0

3.4. Morphology and EDS Element Analysis

A selection of scale samples, notably those from well G2# with the highest halite content, were examined using electron microscopy across three distinct regions (Figure 5). These regions were imaged with varying resolutions, ranging from 1 to 100 μm. At a lower resolution of 100 μm, a dense aggregation of particulate matter was evident. Increasing the resolution to 20.0 μm revealed variable particle sizes, with some areas showing loosely arranged particles forming cracks, and others demonstrating densely adhered particles. Further magnification at 10.0 and 5.0 μm exposed layered deposits and pore structures within the samples. These features are characteristic of halite crystals.

Figure 5.

SEM image of the G2 # sample.

The EDS analysis specifically targeted samples with larger particles for elemental assessment (Figure 6). The experimental findings revealed the presence of elements such as sodium, oxygen, chlorine, and silicon. These results align with the X-ray diffraction (XRD) analysis, which indicated the presence of halite and quartz in the samples, as detailed in Table 6. The layered crystal structure observed in the samples suggests that they are likely composed of rock salt.

Figure 6.

Element analysis of bulk particles in the G2# scale sample.

Table 6. Elements’ Analysis Results of Large Particles in the G2# Scale Sample.

element type	intensity	intensity (standard deviation)	mass ratio %	mass ratio % (uncertainty)	atomic ratio (%)
O K	27.94	0.5106	35.25	0.63	51.88
Na K	12.77	0.8269	9.95	0.23	10.19
Mg K	0.85	0.6535	0.84	0.10	0.82
Al K	3.06	0.7733	2.55	0.11	2.22
Si K	9.93	0.8546	7.49	0.17	6.28
S K	0.64	0.9308	0.45	0.08	0.33
Cl K	49.37	0.8130	39.13	0.45	25.98
K K	2.68	0.8690	1.99	0.12	1.20
Ca K	0.89	0.8635	0.66	0.09	0.39
Fe K	2.21	0.8361	1.70	0.16	0.72
Total			100.00

3.5. Blockage Mechanism of Salt Precipitation

The Jingbian Gas Field is characterized by its low porosity and low permeability, with a burial depth ranging from 3200 to 3800 m. The porosity of the reservoir varies between 2 and 10%, while its permeability lies within the range of 0.01–1.0 millidarcies (mD). This field experiences an original formation pressure between 25 and 33 MPa and temperatures ranging from 87 to 115 °C. Notably, the formation water exhibits high salinity levels, from 52.3 to 431.9 g/L, which significantly contributes to the precipitation of salt scales. The formation and deposition of these salt crystals are intricately linked to variations in temperature and pressure in wellbore.

In the context of pressures ranging from 0.1 to 100 MPa, Zhu et al.²⁹ have proposed a method to calculate the variable water content in natural gas as a function of temperature (T) and pressure (P), as delineated in eqs 4 and 5.

4

5

The water content (W_H2O) in natural gas is calculated using eqs 4 and 5, in conjunction with the McKetta–Wehe correction chart. Figure 7 demonstrates that as the pressure decreases to below 10 MPa, there is a marked increase in the saturated vapor content of the natural gas. Focusing on the G2# well for illustrative purposes, its initial production tubing pressure was approximately 20 MPa with a daily gas production of about 200,000 m³/day and a water production rate of around 4.0 tons/day, as shown in Figure 8. After approximately three years of operation, the tubing pressure decreased to less than 10 MPa, resulting in a reduction of daily gas production to less than 50,000 m³/day and water production to under 0.5 tons/day. Concurrently, the water content in the natural gas exceeded 0.46 g/m³ and continued to rise rapidly as pressure further decreased. This trend suggests an escalating risk of salt blockage under these conditions.

Figure 7.

Water content in natural gas at different pressures (20 °C).

Figure 8.

Tubing pressure and production curve of G2#.

The model developed by Gomez et al.³⁰ was utilized to calculate wellbore temperature and pressure distributions under three different production scenarios, as outlined in Table 7. Subsequently, these data, combined with eqs 4 and 5, facilitated the calculation of water vapor evaporation and changes in formation water salinity for each production stage. The volatilized water’s salinity was then compared with the solubility of sodium chloride and calcium chloride at the wellbore temperature to determine the precise location of salt formation. As illustrated in Figure 9, no salt formation occurs in the wellbore at a daily production of 200,000 m³. However, salt formation begins below 3000 m (Figure 10) when production decreases to 50,000 m³/day and occurs below 2000 m (Figure 11) at a reduced output of 10,000 m³/day. Notably, a decrease in daily production correlates with lower tubing pressure and higher elevation of salt precipitation within the wellbore. It is predicted that, when production falls below 100,000 m³/day, salt deposition will extend to the surrounding formation areas as well. To address these blockages, dissolution experiments using various chemical agents were conducted.

Table 7. Setting of Key Calculation Parameters for Various Production Stages of Well G2#.

production stage	well depth (m)	gas production (104 m3/day)	wellhead pressure (MPa)	water–air ratio (10–4)	bottom-hole pressure (MPa)
initial	3600	20	20	0.1	30.16
medium	3600	5	10	0.1	30.16
late	3600	1	5	0.1	30.16

Figure 9.

Comparative analysis of soluble salt content and its saturation in produced water at various well depths with 200,000 m³/day.

Figure 10.

Comparative analysis of soluble salt content and its saturation in produced water at various well depths with 50,000 m³/day.

Figure 11.

Comparative analysis of soluble salt content and its saturation in produced water at various well depths with 10,000 m³/day.

3.6. Dissolution Efficiency of Different Chemical Agents

Six different chemical agents were tested for their ability to dissolve blockages in the dissolution test. The results indicate that mud acid achieved the highest dissolution rate for G1# blockage, reaching 83.99% (Figure 12). The scale dissolved by different acids in Figure 13. HF also demonstrated substantial efficacy with a dissolution rate of 74.51%. In comparison, other acid systems exhibited lower effectiveness. According to Table 2, the primary constituents of the G1# blockage are NaCl salt and quartz. HF, a component of mud acid, is particularly effective in dissolving quartz, contributing to the high dissolution rates observed for mud acid and HF. Therefore, mud acid is recommended as the preferred scale removal agent for G1# blockages.

Figure 12.

Dissolution rate of G1# blockage by six liquids.

Figure 13.

Dissolution effect of six acid recipes.

In the case of G2# well blockages, all tested acid formulations demonstrated high dissolution rates, each surpassing 88% (Figure 14). XRD analysis of the blockage, as presented in Table 2, identified its main components as soluble salts. Consequently, aqueous solutions are effective in removing such salts. Notably, HCl achieved a dissolution rate of 99.60%, indicating its potential to almost completely dissolve the wellbore blockage. HF showed a dissolution rate of 88.50%. This slightly lower rate is attributed to the presence of calcium chloride in the blockage, which may lead to secondary fluorinated precipitation. Water itself had a dissolution rate of 86.48%, suggesting that it can also serve as an effective agent for blockage removal.

Figure 14.

Dissolution rate of G2# blockage by six acid recipes and water.

Figure 15 illustrates that HCl is the most effective solvent for G3# blockage, achieving a dissolution rate of 96.02%. In contrast, HF shows a lower effectiveness with a rate of 77.40%. The XRD analysis, detailed in Table 2, reveals that the primary components of the G3# blockage are soluble salts and calcite, with soluble salts constituting 62.2% of the blockage. The presence of calcium chloride is likely responsible for the reduced efficacy of HF in dissolving the blockage. Consequently, HCl is identified as the optimal agent for removing blockages in G3#. Additionally, water, with a dissolution rate of 85.1%, presents itself as a viable alternative for blockage removal.

Figure 15.

Dissolution rate of G3# blockage by six acid recipes and water.

Based on the dissolution experiments conducted for the G1#, G2#, and G3# well blockages, it is recommended to utilize mud acid for scale removal in the G1# well, while HCl is advised for eliminating scales in G2# and G3# wells.

4. Discussion and Field Application

Research and analysis indicate that salt precipitation, primarily due to tubing pressures lower than 10 MPa, is the cause of wellbore blockage. It is also considered that blockages may occur in the reservoir near the wellbore. Therefore, simultaneous blockage removal and stimulation are necessary to maintain production pressure.

In response to this, a specific treatment was deployed in the G2# well, which was affected by salt blockage. This treatment involved acidification and stimulation using a specially optimized 10% HCl solution. The procedure entailed saturating the blocked area with this solution to dissolve any blockages in or around the wellbore and to clean up the production string. The detailed composition and dosages for the blockage removal and stimulation process in the G2# well are outlined in Table 8. This process is divided into three stages: prefluid, blockage removal fluid, and displacement fluid. During the prefluid stage, a demulsifier was added to prevent negative interactions with the existing G2# chemicals, and a clay stabilizer was used to avert damage from the migration of clay minerals. The main component of the blockage removal fluid was 10% HCl, enhanced with a 4% HCl corrosion inhibitor to safeguard the pipeline. Indoor experiments show that increasing the temperature to 120 °C, adding corrosion inhibitors, corrosion rate of 6.72 g/(m²*h), less than the temperature of the pipe corrosion of the first class standard 10–20 g/(m²*h), which can be made to the oil pipeline steel to get effective protection. In the displacement phase, the prior additives were substituted with a clay stabilizer. After the construction, the residual acid returned to drainage is centralized and disposed, with no negative impact on the reservoir or the environment.

Table 8. Formula and Dosage of Blockage Removal Liquid.

SN	liquid stage/name	liquid formula	preparation volume (m3)
1	pre liquid	1% demulsifier + 1% cleanup additive + 2% clay stabilizer	20
2	blockage removal liquid	10% HCl + 4% special corrosion inhibitor + 1% demulsifier + 2% cleanup additive + 2% clay stabilizer	110
3	displacement liquid	2% clay stabilizer	15

The G2# well’s blockage removal and stimulation operation follow a specific pumping program, as detailed in Table 9. The procedure begins with wellhead safety testing, confirming a tubing pressure of 55 MPa. Initially, 10 m³ of prefluid is injected at a slow rate. For effective blockage removal, a low displacement injection ranging from 0.3 to 1.5 m³/min is utilized, maintaining a tubing pressure below 30 MPa. Following this, 10 m³ of the blockage removal solution is gradually applied to soak and dissolve the blockage. A portion of this fluid is anticipated to penetrate the formation near the wellbore. The operation then proceeds with an additional 10 m³ of prefluid, followed by a pause to allow a 60 min reaction time with the blockage. In the second stage, 50 m³ of the blockage removal solution is injected to further dissolve and expel residual blockages, cleansing the production string and stimulating the reservoir. The final step involves introducing 15 m³ of displacement fluid to replace the prefluid and blockage removal fluid, preventing their prolonged interaction with the wellbore. Throughout the process, pumping must remain stable, with a maximum stage pressure not exceeding 30 MPa.

Table 9. Two Stages Design for Blockage Removal Operation and Pump Injection Program.

SN	operation steps	liquid volume (m3)	oil pressure (MPa)	displacement (m3/min)
1	the wellhead is depressurized, connected to the high-pressure pipeline, and tested to 55 MPa
2	pre extrusion liquid	10	<30	0.5–1.5
3	squeezing blockage removal fluid with low flow rate	40	<30	0.5–1.5
4	squeezing pre liquid with low flow rate	10	<30	0.3–0.5
5	stop the pump and react for 60 min
6	squeezing blockage removal fluid with low flow rate	50	<30	0.5–1.5
7	squeezing displacement fluid with low flow rate	15	<30	0.3–0.5
8	stop the pump and measure the pressure drop for 20 min, shut in the well and react for 2 h before releasing for production

Following the implementation of blockage removal and reservoir stimulation measures, G2# well resumed operations, with subsequent pressure monitoring results presented in Figure 16. This figure compares the variations in tubing pressure and daily gas production of G2# well, both before and after the blockage removal procedure. Prior to the intervention, the well’s oil pressure was below 5 MPa, with daily gas production under 10,000 m³. The application of a 10% HCl solution, enhanced with additives for blockage removal, led to a significant improvement. After treatment, the oil pressure recovered to 11.9 MPa, and daily gas production increased to 40,500 m³. These represent increases of 2.18 times and 4.05 times in tubing pressure and gas production, respectively. These results substantiate the efficacy and cost-effectiveness of the optimized solution and procedure in removing blockages and stimulating the well.

Figure 16.

Daily production and tubing pressure before and after blockage removal.

5. Conclusions

Based on a comprehensive analysis encompassing experimental data, production metrics, and theoretical evaluations, we have identified the types of blockages and underlying causes in low-producing gas wells within the Jingbian gas field. Correspondingly, effective solutions for blockage removal have been proposed. The key findings of this study are summarized as follows:

• (1)The formation water in the Jingbian gas field predominantly comprises calcium chloride water with high salinity. Core mineral composition is largely dolomite with traces of quartz and other minerals, potentially leading to the precipitation of soluble salts or scales during gas production.
• (2)The primary composition of blockages in the field is soluble salts, with minimal organic matter and water content. This is attributed to the high salinity of formation water and progressively decreasing production pressure.
• (3)Some wells exhibit calcite scaling, likely due to a flowback fluid pH greater than 7 and a reduction in wellbore pressure. Additionally, quartz in certain well blockages originates from acid-insoluble residues in carbonate gelled acid acidification.
• (4)SEM and EDS elemental analyses reveal that the analyzed blockage samples contain layered deposits, pore structures, and elements such as sodium, oxygen, chlorine, and silicon, indicative of typical halite crystals.
• (5)Theoretical calculations suggest that salt crystallization will occur at the well bottom or in the reservoir when tubing pressure drops below 10 MPa and daily water production falls under 1.0 tons/day. Lower daily production correlates with reduced tubing pressure and higher salt precipitation in the wellbore.
• (6)For blockages consisting of soluble salts and scales, HCl proves to be the most effective solvent, with a dissolution rate exceeding 90%. Water removal efficiency also reaches around 85%, making both viable options for blockage removal.
• (7)In wells with quartz-containing blockages, HCl shows lower dissolution rates, whereas mud acid is more effective, exceeding 80% dissolution. Mud acid demonstrates a significantly higher removal efficiency.
• (8)Chemical methods effectively cleanse wellbores and enhance production pressure. The optimized blockage removal process has shown a notable stimulation effect, with increases in tubing pressure and production by factors of 2.18 and 4.05, respectively.

The authors declare no competing financial interest.