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. 2024 May 6;9(19):20807–20818. doi: 10.1021/acsomega.3c09154

Distribution and Main Controlling Factors of Gas and Water in Tight Sandstone Gas Fields: A Case Study of Sudong 41-33 Block in Sulige Gas Field, Ordos Basin, China

Tong Xu †, Ailin Jia †,*, Yougen Huang ‡, Shixiang Fei ‡, Zhi Guo †, Dewei Meng †, Naichao Feng †, Ruohan Liu †, Chenhui Wang †, Suqi Huang †
PMCID: PMC11097201  PMID: 38764684

Abstract

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Studying the gas–water distribution characteristics is essential in guiding the efficient development of gas fields. The relationship between gas and water in the Sudong 41-33 Block is complicated and has not been adequately researched. In recent years, gas wells have suffered from increased water/gas ratios and significant liquid loadings, which greatly affect the development of the block. A comprehensive analysis of formation water, log interpretation, and production data was conducted to determine the gas–water distribution characteristics and main controlling factors in the Sudong 41-33 Block. The findings indicate the following. (1) The formation water in the study area consists mainly of CaCl2 brine with high total dissolved solids (TDS) (with an average value of 36.06 g/L). The hydrochemical characteristics indicate that the formation water is typical sedimentary buried water under well-sealing conditions, which is markedly different from shallow river water and seawater. (2) The formation water can be categorized into three types: edge–bottom water under the gas layer (Type I), stagnant water in tight sandstone (Type II), and isolated lenticular water (Type III). The water layer distribution in the plane is mainly concentrated in the northwest region, whereas it is dispersed in other regions. On the vertical, the water layer mainly appears in P2x8–1, P2x8–2, and P1s2 Members. (3) The physical properties of the reservoir, hydrocarbon generation intensity (HGI), source rock–reservoir relationship, and mini-structure are the main factors affecting the gas–water distribution in the study area. Based on the clarification of the characteristics of gas and water distribution and its main controlling factors, it is of great importance to accurately identify the water layer, avoid the direct development of the water layer, adopt the proper production pressure differential, and carry out drainage gas production measures in time to ensure the effective development of the gas field.

1. Introduction

China is abundant in tight gas resources and ranks third in tight gas production globally. The fourth resource assessment shows that China’s geological resources of tight gas total 21.85 × 1012 m3, primarily located in the Ordos Basin,1,2 Sichuan Basin,3,4 Tarim Basin,5,6 and Songliao Basin,7,8 among others, with significant development potential. The discovery and exploitation of tight gas in North America commenced in the 1970s, with notable examples, including the Carthage and Jonah gas fields and so on.9,10 These gas reservoirs are characterized by thick gas layers and a stable distribution. Compared to North American tight gas reservoirs, China’s tight gas reservoirs have characteristics such as thin gas layers, low recovery, and complex gas–water relationships,11,12 which result in complicated development conditions. In particular, excessive water production and liquid loading in gas wells during the production process severely affect the natural gas yields and pose significant challenges to field development efforts.13 Therefore, the identification of the gas–water distribution and its primary controlling factors of the gas field is crucial in guiding the field’s development and accomplishing efficient production.

Sulige gas field, located in the northern Ordos Basin, is China’s most extensive natural gas field.14−18 Natural gas production has increased significantly in recent years and has achieved 3 × 1012 m3 in 2022. Previous researchers have analyzed the gas–water distribution pattern of the Sulige gas field and its main controlling factors to a certain extent, mainly focusing on the western district,19−25 while relatively little research has been done on the eastern district. Sudong 41-33 Block, located in the eastern district of the Sulige Gas field, is an important gas-producing area in the field, with an annual natural gas output of 6.81 × 108 m3 in 2022. However, the distribution of gas and water layers in the study area is complicated, resulting in a relatively increased water–gas ratio in recent years. Additionally, 66% of the wells suffer from liquid loading, which presents significant challenges for stable production and deployment of production wells in the study areas.

This paper analyzes the formation water chemical characteristics, gas–water distribution pattern, and its primary controlling factors of the study area by collecting a large amount of formation water analysis data, production data, and logging interpretation conclusions of P2x8–1, P2x8–2, P1s1, and P1s2 Members, to provide assistance for the subsequent development and production of the gas field.

2. Geological Setting

A considerable amount of research has been conducted on the sedimentation, tectonics, and formation of the Ordos Basin. Briefly, the Ordos Basin is located in the center of China and is China’s second-largest sedimentary basin, which contains a significant volume of oil and gas resources.14,26 Based on the tectonic morphology and evolutionary history of the basin, it can be divided into six primary tectonic units: the Yimeng Uplift, the Yishan Slope, the Tianhuan Depression, the Weibei Slope, the Jinxi Flexural Belt, and the Western Margin Thrusting Belt.27−31

Sulige gas field, located in the northwest of Yishan Slope, is a gentle west-dipping monocline32,33 (Figure 1a). It is divided into four parts: the eastern district, western district, southern district, and central district during exploration and development. The effective reservoir thickness is generally thin in the western and southern districts and medium thick in the eastern district (Figure 1b).

Figure 1.

Figure 1

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Location of Sulige gas field and study area. (a) Tectonic subdivision of the Ordos Basin and the location of the Sulige field. (b) Location of the Sudong 41-33 Block. (c) Composite histogram of the Sudong 41-33 Block.

The Sudong 41-33 Block is located in the eastern district of the gas field and adjacent to the central district (Figure 1b). The exploration area of the entire block is approximately 779 km2.34 Besides numerous nose-like structures, there are no significant structures; the amplitude of nose-like structures is mostly between 10 to 20 m.35 The Upper Paleozoic strata in the study area can be divided from bottom to top into the Benxi Formation of the Carboniferous, the Taiyuan Formation, the Shanxi Formation, the Shihezi Formation, and the Shiqianfeng Formation of the Permian.

The upper and lower Shihezi Formations are divided into eight members from P2sh1 to P2x8 (Figure 1c). The P2x8 Member can be further separated into the P2x8–1 Member and P2x8–2 Member, which are the primarily reservoir-developed members. The development of coal seams and dark mudstones in the Benxi Formation, Taiyuan Formation, and P1s2 Member of the Shanxi Formation provides excellent conditions for hydrocarbon generation.

3. Materials and Methods

To examine the chemical properties of formation water and the gas–water distribution pattern in the study area, 48 formation water analysis data from 45 wells, thickness of hydrocarbon source rock from 518 wells, production data from 345 wells, and logging interpretation data from 568 wells are collected. All of the data collected were obtained from the Research Institute of Exploration and Development, PetroChina Changqing Oilfield Company.

3.1. Analysis of Formation Water

Condensate water is frequently produced alongside natural gas during the production process. In general, condensate water has lower Cl– and Na+ content, significantly lower total dissolved solids (TDS) than normal formation water, and is mostly of the NaHCO3 and CaCl2 type.36−38 The Sudong 41-33 Block’s condensate water has a low TDS, typically less than 10 g/L. Its pH value ranges between 6 and 8, and its formation water types are NaHCO3 and CaCl2.

Additionally, tight reservoirs frequently undergo acidification and fracturing treatments during the development phase. The incomplete back draining of acidification fluids, fracturing fluids, and drilling fluids will undoubtedly pollute the formation water and change its chemical composition.39−41 The TDS of formation water in the study area, affected by residual backdraft, generally exceeds 100 g/L. The water composition is dominated by Ca2+, Mg2+, and Cl– ions, resulting in a CaCl2-type water according to the Surin classification.42 When subjected to acidizing fluids, the pH value is usually below 5, while the pH value generally surpasses 8 when subjected to drilling fluids and fracturing fluids.

3.2. Source Rock HGI Calculation

Hydrocarbon generation intensity (HGI) refers to the number of hydrocarbons produced per unit area of the source rock.43 The hydrocarbon-generating potential of the source rock is assessed using a mix of parameters, including thickness, abundance of organic matter, and extent of thermal evolution,44 which can be calculated by eq 1

3.2. 1

where Qgas is the HGI of the source rock (×108 m3/km2), H means the thickness of the source rock (m), ρrock is the density of hydrocarbon source rock (t/m3), TOC is the total organic carbon content (%), and g is the gaseous hydrocarbon rate of the source rock (mg/g TOC).

Coal seams and dark mudstones are the primary hydrocarbon source rock types in the study area, and their thicknesses can be obtained from logging response characteristics. The coal seams exhibit high RT, high AC, and high CNL, as well as low GR, low PE, and low DEN in the logging features. The dark mudstone shows a low AC, high GR, and high SP in contrast.45 The densities of coal seams and dark mudstones are 1.55 and 2.60 t/m3, respectively. The coal seams exhibit a variable TOC content ranging from 55 to 75%, with a mean value of 65%.44 Correspondingly, the dark mudstone displays a TOC content variation between 0.3 to 3.5%, with a mean value of 1.9%.46 The Qgas is closely related to the vitrinite reflectance (Ro) of the hydrocarbon source rock. The organic matter of the Upper Paleozoic hydrocarbon source rock is dominated by type III kerogen and is in the high-maturity and overmaturity stages. Previous research shows that the total yield of gaseous and liquid hydrocarbons in the coal seams of the Shanxi Formation is much more than that of the Benxi and Taiyuan Formation, given similar thickness and thermal evolution degree conditions.44,47 Mainly because of the variation in the organic matter, the Shanxi Formation coal seam has formed hydrocarbon components with high richness.

4. Results

4.1. Chemical Characteristics of Formation Water

Analysis of the screened formation water test data reveals that the primary ionic components of the formation water in the Sudong 41-33 Block comprise (Na+ + K+), Ca2+, Mg2+, HCO3–, SO42–, and Cl–. The cation content is mainly dominated by (Na+ + K+), with Ca2+ following, and the Mg2+ content is the lowest. The anion content is mainly dominated by Cl–, which can account for 90% of the anionic components and significantly affects the TDS of the formation water. The contents of SO42– and HCO3– are relatively low.

The composition of ions and the type of formation water, along with the lithology of the surrounding rock, can be used to deduce the water–rock reaction it has undergone.38,48 The TDS of the formation water ranged from 19.56 to 75.71 g/L, with an average value of 36.06 g/L, which is classified as CaCl2 water. The pH of the formation water ranged from 5.5 to 6.8, with an average value of 6.1, indicating weak acidity. These characteristics differ significantly from those of the Moline River and seawater (Table 1), indicating that the formation water is typical sedimentary buried water and has had a strong water–rock reaction with the surrounding rocks, such as dissolution of feldspar by the formation water, albitization of plagioclase, and desulfurization.

Table 1. Chemical Characteristics of Different Types of Watera,b.

  TSD (g/L) γNa+/γCl– (γCl––γNa+)/γMg2+ water type
Sudong 41-33 Block Inline graphic Inline graphic Inline graphic CaCl2
Molin River in Ordos Basin Inline graphic Inline graphic Inline graphic NaHCO3 Na2SO4
seawater 35.00 0.85 0.75 MgCl2
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a

Water data of the Molin River are cited from ref (49). The chemical characteristics of the formation water in Sudong 41-33 Block, Molin River, and seawater are different.

b

Inline graphic.

The Piper diagram provides a visual representation of the compositional characteristics of distinct formation water types,50 enabling the identification of their origins clearly. Analysis of the Piper diagram reveals that formation water in the Upper Paleozoic of Sudong 41-33 Block exhibits notable chemical distinctions from both river water within the inner basin and seawater (Figure 2).

Figure 2.

Figure 2

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Piper diagram of formation water in the Sudong 41-33 Block. The ionic composition of formation water in Sudong 41-33 Block is significantly different from those of Molin River and seawater.

In addition, the ion-proportionality coefficients of the formation water can be used to reflect the underground hydrogeological environment. Generally, a lower sodium–chlorine coefficient (γ Na+/γ Cl–) (lower than 0.85) and higher metamorphism coefficient [(γCl––γNa+)/γMg2+] (greater than 3) indicate better sealing conditions of strata. However, when the sodium–chlorine coefficient is greater than 0.85 or the metamorphic coefficient is negative, the formation water may be affected by atmospheric precipitation.42 It can be seen from Table 1 that the average sodium–chlorine coefficient in the research area is less than 0.85, while the average metamorphic coefficient is higher than 3, and these characteristics are very different from those of the Molin River and seawater. These values indicate that the formation water does not originate from the shallow river or seawater. Rather, the source of formation water should be sedimentary buried water, which is found under good sealing conditions.

4.2. Gas–Water Distribution Characteristics

4.2.1. Classification of Formation Water Types

Combined with the collected logging interpretation results, the formation water in the study area can be categorized into three types based on the distribution characteristics of the gas layer, water layer, and sand body. These types are I Edge–bottom water under the gas layer (Figure 3a,b); II Stagnant water in tight sandstone (Figure 3c); and III Isolated lenticular water (Figure 3d).

Figure 3.

Figure 3

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Classification of formation water types in the study area: (a, b) I edge–bottom water under the gas layer, (c) II stagnant water in tight sandstone, (d) III isolated lenticular water. The water type II is the most abundant in the study area.

The occurrence of Type I is limited and predominantly found within the sand layer and has excellent physical characteristics in comparatively lower tectonic settings. Typically, the upper region of the sand body hosts gas, while the lower section contains water. This water type exhibits a bell-shaped amplitude ranging from medium to high on the GR logging curve. It is challenging to detect during the initial phases of gas well development, and severe watering-out may occur in lower parts of the reservoir during production. Such water layers are infrequent, representing 7.4% of all water types, and are mostly found in the P1s2 Member.

The stagnant water in tight sandstone (Type II) is primarily influenced by the reservoir’s heterogeneity and generally occurs within the margins or the interior of the sandstone. Owing to the poor physical properties of the reservoir, it is difficult for the natural gas to drain the water within the sandstone completely, resulting in the generation of stagnant water. This type of water is mainly a gas-bearing water layer and displays a toothed box pattern with a medium to high amplitude on the GR logging curve. During production, the volume of water produced is small and stable, the water–gas ratio is relatively low, and the gas wells are prone to suffer liquid loading. The stagnant water in the tight sandstone was distributed in all members, accounting for 65.3% of all water types.

The isolated lenticular water (Type III) is mainly present in the lenticular sand body surrounded by the mudstone. Due to the tightness of the reservoir and the lack of tectonic fractures, it is difficult to transport the generated gas over long distances. When the natural gas filling intensity is insufficient, the water is trapped within the sandstone due to the sealing off by the mudstone, resulting in isolated lenticular water. This type of water appears as a box shape on the logging curve and is commonly interpreted as a water layer. In the initial stages of production, large volumes of water were produced. However, as production continued, both gas and water outputs experienced a decrease. Such a water type is limited in the study region, comprising 27.4% of all water types, and is mostly observed in the P2x8–1 Member due to its considerable distance from the hydrocarbon source rock.

4.2.2. Distribution Characteristics of Gas–Water Layers

Combined with the conclusion of logging interpretation and water type classification, the distribution characteristics of gas layers and each type of formation water in distinct members were mapped on the plane (Figure 4).

Figure 4.

Figure 4

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Plane distribution characteristics of gas and water layers in different members in the study area. (a) Gas and water layers distribution characteristics in P2x8–1, (b) gas and water layers distribution characteristics in P2x8–2, (c) gas and water layers distribution characteristics in P1s1, and (d) gas and water layers distribution characteristics in P1s2. The water layers are primarily present in P2x8–1, P2x8–2, and P1s1 members.

The water layer in the P2x8–1 Member on the plane has been found throughout the area and predominantly consists of stagnant water in tight sandstone (Type I) and isolated lenticular water (Type III). The water layer is widespread in the northwest region (Figure 4a), while it is sporadically distributed in other regions. The gas layer in the P2x8–1 Member is discontinuous, with the thickness typically less than 8 m and primarily distributed in the southwest (Figure 4a).

The P2x8–2 Member is additionally the primary member for formation water occurrence. Similar to the P2x8–1, the distribution of the water layer in the study area is mainly concentrated in the northwest region, with sporadic occurrences in the northeast region. However, nearly no water layer is present in the southwest area. The type of water layer is predominantly stagnant water in tight sandstone. The gas layer within P2x8–2 is much more developed and is distributed in strips from north to south. Most gas layers in this member exceed 8 m in thickness, and it is the primary production layer within the study area (Figure 4b).

The water layer in the P1s1 member is undeveloped and is only occasionally apparent in the northwest region. However, the gas layer is fully developed and remains the dominant productive member of the study area along with P2x8–2. The gas layer is thicker in the northeast, generally exceeds 8 m, and is relatively thinner in the northwest region (Figure 4c).

The water layer of P1s2 is less developed than that of P2x8 and is mainly distributed in the northern part of the study area. It mainly consists of edge–bottom water under the gas layer (Type I) and stagnant water in tight sandstone (Type II). The thickness of the gas layer is relatively thin, generally less than 8 m. The continuity between the gas layers is poor, with a reticulated distribution (Figure 4d).

Based on the analysis of the water–gas ratio changes in each gas gathering station in the study area over time, it is evident that the water–gas ratio in all gas gathering stations, with the exception of the SD 41-4 gas gathering station, has displayed a gradual increase over the past two years. When considering the spatial distribution of gas gathering stations, it is apparent that SD 41-2 and SD 41-3 gas gathering stations, located in the northwestern region, exhibit a higher water–gas ratio (Figure 5). Specifically, the water–gas ratio for the SD 41-2 gas gathering station in 2022 reaches a level of 1.10 m3/104 m3 and an average of 1.18 m3/104 m3, indicating a significant water production characteristic. On the contrary, SD 41-1 gas gathering station, located in the northeast of the study area, as well as SD 41-4 and SD 6-7 gas gathering stations in the south, have a comparatively low water–gas ratio, indicating a normal production state.

Figure 5.

Figure 5

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Characteristics of the water/gas ratio of different gas gathering stations in the study area. The water–gas ratio in all gas gathering stations, except the SD 41–4 gas gathering station, has displayed a gradual increase over the past 2 years.

5. Discussion

5.1. Main Controlling Factors of Gas–Water Distribution

5.1.1. Influence of Reservoir Physical Properties on Gas–Water Distribution

The eastern Sulige gas field is characterized by low porosity, low permeability, and low gas saturation, and the reservoir displays strong nonhomogeneity.51−53 Previous studies have investigated the transport and aggregation of natural gas in tight sandstones, indicating that the key to natural gas transportation in such formations is the relationship between the magnitude of filling pressure and capillary resistance.54−56 Reservoirs with relatively high porosity and permeability exhibit lower capillary resistance, allowing natural gas to enter and form a gas reservoir. Conversely, sand bodies with poor physical properties present increased resistance to gas transport, which can lead to difficulties in driving out the water in the sandstone and result in the generation of a water layer, a gas-bearing water layer, or a gas–water layer. This is the primary reason for the widespread occurrence of stagnant water in tight sandstone (Type II) in the study area.

By plotting the scatter plots of porosity, permeability, and gas saturation of different types of gas–water layers and their corresponding normal distribution curves, it is apparent that the average values (the values corresponding to the peak position on the right Y-axis) of porosity and permeability for the water layers and gas-bearing water layers are significantly smaller than those of the gas layer (Figure 6a,b). This suggests that the physical properties of the reservoir play a major role in controlling the distribution of the gas–water layer.

Figure 6.

Figure 6

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Diagram of the relationship between gas saturation and porosity (a) and permeability (b). The average values of porosity and permeability for different types of gas–water layers correspond to the peak position on the right Y-axis.

Additionally, the porosity, permeability, and gas saturation characteristics of distinct regions and different members within the study area were analyzed (Table 2). It was observed that the reservoirs’ porosity, permeability, and gas saturation in the northwest region were lower than those in other areas (the division of the regions is shown in Figure 4a). This finding explains why the northwest region has a wider distribution of Type II water and a higher water–gas ratio compared to other regions and also suggests that the physical properties of the reservoirs play a central role in regulating the gas and water distribution in the Sudong 41-33 Block.

Table 2. Characteristics of Average Porosity, Permeability, and Gas Saturation in Different Members and Regionsa.
member region porosity (%) permeability (mD) gas saturation (%)
P2x8–1 northwest region 8.64 0.53 40.11
northeast region 8.77 0.61 44.48
southwestern region 8.99 0.65 43.66
P2x8–2 northwest region 8.78 0.57 44.75
northeast region 9.04 0.65 47.36
southwestern region 8.00 0.45 48.68
P1s1 northwest region 8.08 0.40 49.61
northeast region 8.65 0.54 54.12
southwestern region 7.82 0.44 55.13
P1s2 northwest region 7.08 0.40 51.60
northeast region 7.85 0.42 53.56
southwestern region 7.57 0.47 54.20
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a

The reservoir porosity and permeability of different layers in the northwest region are lower than those in other regions, which results in lower gas saturation of the reservoir.

5.1.2. Hydrocarbon-Generating Intensity and Source Rock–Reservoir Relationship

The HGI has a degree of influence on the macroscopic distribution of gas and water.22,57,58 The Upper Paleozoic hydrocarbon source rocks in the Sulige gas field comprise coal seams and dark mudstones in the Benxi Formation, Taiyuan Formation, and P1s2 Member of the Shanxi Formation. In the study area, there is a substantial hydrocarbon-generating intensity with a range of 12 to 26 × 108 m3/km2 overall, with the northwest region exhibiting a hydrocarbon-generating intensity of no less than 16 × 108 m3/km2 (Figure 7). However, owing to the inadequate physical properties of the reservoirs in the northwest region, the produced natural gas necessitates greater displacement pressure for penetration into the reservoir, causing the gas-bearing water layer to be more developed in comparison to other regions. Gas wells in this region produce relatively high volumes of water, and the ratio of total gas production volume (104 m3) to total water production volume (m3) is mostly less than 1 (Figure 7), indicating higher water and lower gas production characteristics.

Figure 7.

Figure 7

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Plane distribution characteristics of HGI in the Sudong 41-33 Block. There is a substantial HGI with a range of 12 to 26 × 108 m3/km2 overall.

The reservoir’s physical features are superior in the northeast region, and the natural gas generated drives out the water in the pore space more effectively under conditions of relatively high HGI. The ratio of total gas production volume (104 m3) to total water production volume (m3) is usually greater than 1 (Figure 7), showing higher gas but lower water production characteristics.

The relationship between the hydrocarbon source rock and reservoir also influences the macroscopic distribution of the gas and water layers. The natural gas is generated from the hydrocarbon source rock at the bottom and transported to the upper reservoir under the effect of pressure difference, and reservoirs close to source rocks are more favorable for gas layer generation. As a result, the reservoirs located in the P1s1 and P2x8–2 Members are preferentially charged by natural gas, whereas the P2x8–1 reservoir primarily consists of gas-bearing water layers and water layers, as the pressure is inadequate to discharge the water present within the sand body during natural gas charging (Figure 8). This conclusion explains why Type II and Type III waters are more developed in P2x8–1 relative to other members.

Figure 8.

Figure 8

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Diagram of the hydrocarbon generation model in the study area. Natural gas is transported from the bottom up by pressure differentials. Therefore, reservoirs closer to the hydrocarbon source rock are more favorable for gas layer generation.

The distribution characteristics of the gas and gas-bearing water layers in various members are illustrated by pie charts. The P2x8–2 and P1s1 Members demonstrate the highest proportions of gas layer, accounting for 36.6 and 41.4%, respectively, while the P2x8–1 Member has only a minimal amount, 6.6%. The gas-bearing water layer is mainly present in the P2x8–1 Member, making up almost half of it (49.7%), whereas the P2x8–2, P1s1, and P1s2 sections have relatively small portions (Figure 9).

Figure 9.

Figure 9

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Distribution characteristics of gas layers and gas-bearing water layers in different members. (a) Gas layer. (b) Gas-bearing water layer. The gas layer is mainly distributed in P2x8–2 and P1s1, while the gas-bearing water layer is mainly distributed in P2x8–1.

5.1.3. Influence of Structural Characteristics on Gas–Water Distribution

Mini-structures exert an impact on the distribution of gas and water. The study area is tectonically stable with little undulation in different members; thus, the top tectonic surface of the P1s2 Member was selected as the base map to depict the plan distribution of the average daily production rate in the first year. The map illustrates that wells located in the nose-like uplift and higher segment of the tectonic slope exhibit greater average daily production rates in the first year in contrast to those adjacent to the comparatively lower part of the tectonics. In the study area, for instance, wells like SD40-19C3, SD40-19C1, SD40-22C5, SD40-22C3, and SD40-22C1 have first-year average daily productions ranging from 0.4 × 104 to 1.9 × 104 m3, as the tectonic position shifts from low to high (Figure 10).

Figure 10.

Figure 10

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Plane distribution of the average daily production rate in the first year (104 m3) of the wells produced only in the Upper Paleozoic reservoir. Wells located in the nose-like uplift and higher segment of the tectonic slope exhibit a higher average daily production rate in the first year.

However, not all wells located in relatively high areas are high-yield wells, and the production capacity of gas wells is also influenced by various factors, including reservoir properties, HGI, and others. For instance, well SD40-25C5, situated next to well SD40-22C at a higher position, has a first-year average daily production of only 0.3 × 104 m3 (Figure 10). This is because SD40-25C5 was drilled at the edge of the river with poor reservoir properties. Such a situation also happens to wells SD40-23, SD40-24, and other wells in the study area.

5.2. Guidance for Subsequent Gas Field Development

Illustrated with the example of the Sudong 41-33 Block, this study details the distribution and main controlling factors of gas and water in tight sandstone gas fields. The findings indicate that the gas and water distribution characteristics are primarily affected by reservoir physical properties, HGI, source rock–reservoir relationship, and mini-structures. The formation water in the study area can be classified into three main categories, and each of these water types can significantly impact gas well production, making it necessary to precisely identify and avoid fracturing such layers during the development process. Condensate water is also very common in the production process of gas wells. Typically, the water has low TDS below 10 g/L, a production rate below 2 m3/d, and a stable water–gas ratio of less than 0.25 m3/104 m3. The effect of condensed water on production is insignificant.

In addition to avoiding direct development of the water layer, it is also crucial to pay attention to the occurrence of water invasion and water channeling. Take the well SD 55-09 as an example. The conclusion of the logging interpretation shows that the reservoirs drilled in this well are all gas layers, and there is no water layer. Initially, the well’s casing pressure was stable, with high levels of gas production and low levels of water production. The water–gas ratio at this stage was almost less than 0.6 m3/104 m3. However, following one year of production, there was a swift, considerable decline in the casing pressure and a marked surge in water production, reaching 8.24 m3/d. Meanwhile, gas production diminished, and the water–gas ratio quickly rose as high as 3.85 m3/104 m3 (Figure 11). This was attributed to the precipitous loss of formation pressure, which allowed movable water in the sands to infiltrate the gas well and cause water invasion, resulting in a significant impact on productivity. Appropriate measures, such as foam drainage and velocity string, are promptly implemented for gas wells in this situation. Furthermore, the proper production pressure differential is also crucial to prolong the productive lifespan.

Figure 11.

Figure 11

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Production performance curve of well SD 55–09. Initially, the gas well exhibits a high casing pressure, high gas production, low water production, and a low water–gas ratio. Following one year of operation, the casing pressure drops rapidly, resulting in water invasion and a significant increase in water production.

It also should be noted that basically no significant fractures were found in the Sudong 41-33 Block, and thus the effect of fractures on gas–water distribution has not been discussed in this study. Nevertheless, the gas fields located in the margins of the basin have experienced more intense tectonic activities and developed a significant number of connectivity faults. Therefore, it is still vital to direct attention toward the water layer resulting from fracture communication and its consequential impact on gas well production during the future development of the gas field.

6. Conclusions

  • (1)

    The Sudong 41-33 Block features a CaCl2-type brine with high TDS. The chemical characteristics of the formation water suggest that it is sedimentary buried water currently confined in a sealed geological environment, which is notably distinct from the chemical features of river water and seawater.

  • (2)

    The formation water can be divided into three categories: edge–bottom water under the gas layer (Type I), stagnant water in tight sandstone (Type II), and isolated lenticular water (Type III). The water layers appear to be more developed in the northwest region of the study area, whereas they are relatively scattered in other regions. On the vertical, the water layers are principally found in the P2x8–1, P2x8–2, and P1s2 Members.

  • (3)

    The distribution of gas and water layers in the study area is primarily impacted by reservoir physical properties, HGI, source–reservoir relationship, and mini-tectonic features. Accurately identifying the water layer, avoiding direct development of the water layer, adopting reasonable production pressure differential, and carrying out timely drainage gas production measures are of significant importance to ensure the development of the gas field.

Acknowledgments

This research was funded by the Science and Technology Major Project of PetroChina, No. 2021DJ1703 and Science and Technology Major Project of PetroChina, No. 2021DJ2104. The authors sincerely thank the Research Center of Ordos Basin of PetroChina Research Institute of Petroleum Exploration and Development and Research Institute of Exploration and Development of PetroChina Changqing Oilfield for providing support and geological data.

The authors declare no competing financial interest.

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