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Article

Reservoir Characteristics of Tight Sandstone and Sweet Spot Prediction of Dibei Gas Field in Eastern Kuqa Depression, Northwest China

by
Guangjie Zhao
1,2,
Xianqing Li
1,2,*,
Mancang Liu
3,
Caiyuan Dong
3,
Daye Chen
4 and
Jizhen Zhang
5,6
1
State Key Laboratory of Coal Resources and Safe Mining, China University of Mining and Technology (Beijing), Beijing 100083, China
2
College of Geoscience and Surveying Engineering, China University of Mining and Technology (Beijing), Beijing 100083, China
3
Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, China
4
China Coal Research Institute, Beijing 100013, China
5
Key Laboratory of Exploration Technologies for Oil and Gas Resources, Ministry of Education, Yangtze University, Wuhan 430100, China
6
College of Resources and Environment, Yangtze University, Wuhan 430100, China
*
Author to whom correspondence should be addressed.
Energies 2022, 15(9), 3135; https://doi.org/10.3390/en15093135
Submission received: 17 March 2022 / Revised: 19 April 2022 / Accepted: 21 April 2022 / Published: 25 April 2022
(This article belongs to the Topic Drilling, Completion and Well Engineering for the Natural Energy Resources Extraction, Storage and Sustainable Management)
Browse Figures
Versions Notes

Abstract

:
Great progress has been made in the exploration of tight sandstone gas resources in Kuqa depression. Great progress has been made in Dibei structural belt, which proves the previously unproven favorable area for tight sandstone gas. The physical properties, controlling factors, and characteristics of tight sandstone from the Ahe (J1a) Formation in the Dibei gas reservoir are analyzed. The results show that the tight sandstone of the J1a Formation is mainly feldspar lithic sandstone, with low porosity (average 9.1%) and low permeability (average 0.09 mD). Compaction (average compaction rate 61.9%) reduces porosity more than cementation (average cementation rate 14.3%). Secondary dissolution pores (average thin section porosity is 3.4%) dominate. The homogenization temperature has two peaks; the first peak is 85–110 °C, and the other peak is 115–140 °C, indicating that oil and gas experienced two filling stages at 12 Ma and 4.5 Ma, respectively. Eodiagenesis, A substage of mesogenetic diagenesis, and B substage of mesogenetic diagenesis happened in the area. Tight sandstone is developed in the B substage of mesogenetic diagenesis. The main controlling factors of diagenesis are: strong dissolution and structural pore increase; oil and gas charging and overpressure. The reservoir forming mode of the Dibei gas reservoir is: crude oil filling in the Late Neogene (12 Ma); reservoir densification in the late deposition of Kangcun Formation (7 Ma), mature natural gas filling in the early deposition of Kuqa Formation (4.5 Ma), and gas reservoir formed after transformation and adjustment in the deposition period of Quaternary (2 Ma). According to this model, it is predicted that the favorable area of the Dibei gas reservoir is in the southeast of the Yinan 2 well. This study provides guidance for the study of tight sandstone gas in other areas of the Kuqa Depression.

1. Introduction

With the advancement of oil and gas exploration, unconventional oil and gas have become an attractive subject [1,2,3,4]. Tight gas is an unconventional natural gas resource with huge reserves in many countries around the world, such as China, the United States, Canada, Russia, Europe, and Saudi Arabia in the Middle East [4,5,6,7,8,9]. Tight sandstone reservoirs were discovered in China’s Tarim, Sichuan, Ordos Basin, Songliao, and Bohai Bay Basin, and great achievement has been made [10,11,12,13,14]. The favorable exploration area of tight oil in these basins is 16 × 104 km2, and the oil geological resources are about (160–200) × 108 t [15].
The Dibei tight gas field is large and is discovered deep in the Jurassic in the Kuqa depression [16]. By contrast, the Dina, Dabei, Keshen, and other large tight gas fields are located in the Cretaceous and Eocene layers [17,18,19]. The reserves report provided by the PetroChina Tarim Oilfield (PCTO) predicts that the reserve of the Dibei gas field is 1.64 × 1011 m3 [16]. Moreover, compared with other gas fields in the depression, the distribution of gas and water in the area is irregular [16]. Therefore, studying the sweet spot prediction and accumulation mode of the Dibei gas field is beneficial to provide a basis for the deep Jurassic tight gas exploration in the basin. There are a lot of natural gas and a little liquid hydrocarbon in the Dibei gas reservoir. The Jurassic Ahe Formation (J1a) has a commercial-grade gas layer, and the overlying Lower Jurassic Yangxia Formation (J1y) has a poor gas layer [20].
The sandstone reservoir of the J1a Formation is a typical tight reservoir with poor porosity and permeability and high pore pressure [21]. In order to explore the formation mechanism of relatively high-quality reservoirs, many studies have been carried out [16,22,23,24]. Diagenesis is a key geological process that affects reservoir quality [25,26]. However, the development of good-quality tight sandstones in different oil and gas basins is affected by different diagenesis [27,28,29]. Therefore, the influence of diagenesis needs to be further studied. The tight sandstone of the J1a Formation has strong heterogeneity [22], which provides a useful example for researching the changes of tight sandstone diagenesis. In addition, studying the process of diagenesis provides a basis for the development of good-quality tight sandstones.
The research objectives are as follows: (a) to study in detail the physical characteristics (composition, structural pore system, physical properties, and diagenetic minerals) of the J1a tight sandstone; (b) to reveal the types, characteristics, and diagenetic stages of diagenesis; (c) to reveal the controlling factors of tight sandstone reservoir; (d) to establish the accumulation mode of tight sandstone gas reservoirs and point out favorable sweet spots. The result provides a scientific basis for other tight sandstone reservoirs in the Kuqa depression and other areas.

2. Geological Setting

Kuqa depression is in the northern Tarim Basin, which is adjacent to the Tianshan fold belt in the north [30] (Figure 1). It is a Mesozoic–Cenozoic foreland basin, which developed in the late Hercynian, and the superposition of multiple tectonic movements occurred, such as the extension depression stage during Jurassic–Paleogene and the development stage of intracontinental foreland thrust during Neogene–Quaternary [31]. It includes eight secondary structural units, including four structural belts: Northern monoclinal, Kelasu, Yiqikelike, Qiulitage, and Southern slope belt as well as three sags: Baicheng, Yangxia, and Wushi Sag [32,33].
There are sedimentary strata in Kuqa depression: Triassic, Jurassic, Cretaceous, Paleogene, and Quaternary sediments [34]. Source rocks in the area mainly include lacustrine mudstones in the Triassic and the coal seams, carbonaceous mudstone, and lacustrine mudstone in the Jurassic [35] (Figure 2). The favorable reservoirs comprise J1a and J1y Formation in Jurassic, Cretaceous Bashijiqike (K1bs), Suweiyi (E3s), and bottom conglomerate of Kumugeliemu (E1–2 km) in Paleogene, Jidike (N1j) Formation in Neogene. The cap rocks of Jurassic and Cretaceous strata in Mesozoic are mainly mudstone, which is widely distributed throughout the depression. The Neozoic cap rocks are mainly in the E1–2 km and the N1j strata, which mainly include the gypsum and salt layers.
The Dibei tight gas field is in the middle of the Yiqiklike thrust belt. Oil, gas, and water all exist at the top of the anticline in this tight gas field, and there is a lot of natural gas in the tight reservoirs on the slope [16,36]. According to the oil and gas exploration results, commercial gas was discovered in the YN2, DX1, DB102, and DB104 wells along the slope, while the YN4 and YS4 far away from the slope have no commercial value. Studies on source rocks indicated that the oil and gas in the J1a reservoir mainly came from the Jurassic source rocks, and the Middle-Upper Triassic strata also provided some natural gas [37,38].

3. Samples and Methods

In order to study the porosity and permeability and diagenesis characteristics of the reservoir, core samples were collected from PCTO. These samples are relatively uniformly distributed from 8 typical wells, with depths ranging from 4000 to 5100 m.
The CMS-300 automatic porosity and permeability measuring instrument was utilized to determine the porosity and permeability under a confining pressure of about 30 MPa. Scanning electron microscopy (SEM) was used to detect the types of clay minerals in the reservoir to determine the reservoir space type and condition of the clay minerals in the reservoir. QUANTA 200 SEM was used to detect representative samples. A total of 105 samples from 8 wells were analyzed for particle size, diagenetic characteristics, and porosity. The thin section is dyed with blue epoxy resin to mark the reservoir space, and the porosity of the thin section is calculated by the point method.
The DSG600 transparent reflection polarization fluorescence microscope was used to analyze the fluid inclusions of 31 samples from 8 wells in the Dibei gas reservoir to determine the hydrocarbon charging time. Petrographic and micro temperature methods were used to analyze the shape, size, distribution, color, and fluorescence of inclusions. The fluid inclusion was heated from room temperature to 0.5 °C/min until the phase boundary disappeared; the temperature was recorded in the state and maintained at a stationary temperature for 2 min. Then, the temperature of fluid inclusions dropped. When there were some other bubbles, the process was repeated to achieve the same uniform temperature.
By integrating data such as formation thickness, lithology, absolute age, erosion thickness, measured vitrinite reflectance (Ro), and borehole temperature, the burial and temperature history was reconstructed using BasinMod 1D software. In order to reconstruct the evolution of tight sandstone reservoirs and point out the influence of diagenesis, the model from Ruifei Wang, 2011 [39], was used to estimate the influence of different diagenesis on the reservoir. The model links reservoir porosity evolution to diagenetic stages, thereby quantifying the contributions of different diagenesis.

4. Results

4.1. Lithofacies Characteristics

According to the classification scheme of Folk [40] and the results of thin section analysis, the sandstone from the J1a Formation in the Dibei structural belt is dominated by lithic sandstone and feldspar lithic sandstone (Figure 3). In the lithic sandstone, the relative content of rock fragments is 27.3%~86.4%, with an average of 81.2%; the content of feldspar is 5.65%~62.7%, with an average of 39.4%; the content of quartz is 1.2%~73.6%, with an average of 52.7%. The sorting of sandstone is medium-good, the roundness is mainly sub-angular-sub-round, the compositional maturity of the rock is low, and the structural maturity is medium. The sorting of sandstone is medium-good, the rounding is mainly sub-angular and sub-circular, the compositional maturity of the rock is low, and the structural maturity is medium.

4.2. Reservoir’s Porosity and Permeability

The relationship between porosity and permeability of 93 sandstone core samples from J1a sandstone is indicated in Figure 4. The porosity values of the J1a Formation range from 1% to 12%. The porosity values of most samples are between 2% and 10%, with an average of 9.1%. The range of permeability values is between 0.01 and 86.8 md, with 85% of the values varying from 0.01 to 1 mD (average 0.09 mD), which has the typical characteristics of tight sandstone gas.

4.3. Pore Systems

Based on the thin section observation and SEM analysis, there exist three types of storage space, namely primary intergranular pores (Figure 5a), secondary dissolution pores (Figure 5b–d), and fractures (Figure 5e,f). The thin section porosity (by point counting) of the tight reservoir of the J1a Formation ranges from a trace level (less than 1%) to 9.9% (average 4.4%). The range of primary intergranular porosity is between a trace level and 5.6% (average 1.8%). The skeleton particles are dissolved to form secondary pores, which range from trace to 7.8% (average 3.4%). The J1a Formation is buried deeply (more than 4000 m), so the original pores are severely damaged; therefore, primary intergranular pores are not the major storage space in the reservoir. The pores formed by dissolution, namely intergranular dissolution pores (Figure 5b) and intragranular dissolution pores (Figure 5c,d), are the second type of storage space. Because of the high ratio of feldspar and rock cuttings, lots of dissolution pores are generated, providing good storage space for oil and gas. The third type is a fracture (Figure 5e,f), which can be observed in the samples.

4.4. Diagenesis Types

4.4.1. Compaction

The main factor causing the decrease in porosity of clastic rocks is compaction [7,41]. The degree of compaction can be determined by the contact relationship of the particles. Compaction significantly reduces the porosity of tight reservoirs in the J1a Formation. Firstly, the cuttings deform during the compaction process, resulting in point contact, line contact, and suture contact, which fills the intergranular pore and blocks pore throats (Figure 6a,b). Secondly, in the middle diagenetic stage, the acid generated from organic matter dissolved the feldspar debris and led to the weakening of the rock framework, which further compacted the framework particles [42]. Finally, the J1a Formation is currently buried at a depth of about 4000–5000 m, which results in highly effective stress in the overburden and strong compaction through dissolution.
The relationship between total intergranular volume and cement content shows that compaction reduces porosity more than cementation (Figure 7), with three exceptions. The compaction rate is 27.9%~76.8% (average 61.9%), and the cementation rate is 4.3%~62.9% (average 14.3%). According to the porosity evolution model of [39], the porosity loss during compaction is calculated. The average reduction rate of compacted porosity is 62.3%, and the average reduction rate of cemented porosity is 15.2%, which basically corresponds to the result in Figure 7. Comprehensive analysis shows that compaction is the main diagenesis causing porosity damage.

4.4.2. Cementation

Cementation is another major factor affecting the porosity of the reservoir. Calcite is a widely distributed cement in the J1a unit, and its content is uneven (0–31%, average of 18.6%). Occasionally, calcite blocks of cement were distributed around the detrital grains (Figure 6c and Figure 8a), but calcite cement usually filled the intergranular pores as microcrystalline (Figure 6d), indicating a high degree of carbonate cementation. Although cement can limit compaction, some of the original porosity damaged by compaction is preserved, but in general, the destructive effect of carbonate cement on the reservoir is more apparent.
Silica cementation is a key diagenetic process that causes the deterioration of sandstone reservoir quality. Silica cement is overgrown around single-crystal quartz grains. Quartz overgrowth is distributed on the surface of the quartz particles (Figure 6e,f). The volume content of quartz overgrowth in sandstone ranges from 51% to 79% (average of 67.9%). Feldspar overgrowth was occasionally detected (Figure 6g), which provided material for the corrosion process.
The total content of clay minerals determined by XRD was from 3.9% to 14.5%, with an average of 12.3%. There are three kinds of clay minerals in the sample, and their contents are: kaolinite (10.9%~27.8%, average of 38.6%), illite (7.9%~25.2%, average of 36.3%), and chlorite (8.5%~26.2%, average of 24.6%). Kaolinite is an important clay mineral in the J1a Formation. The morphology of kaolinite is usually booklet form, and it occupies intragranular and intergranular pores. The kaolinite clay minerals are closely associated with dissolved feldspar crystals, indicating that the kaolinite minerals are formed by the dissolution of unstable feldspar. Moreover, the chemical reaction of feldspar with CO2 resulted in the formation of kaolinite on the feldspar surface. Kaolinite is usually associated with illite and mixed illite/montmorillonite layers. During the middle diagenetic stage, a large amount of unstable feldspar was dissolved by the meteoric water, which may cause the feldspar to transform into kaolinite. It may be the reason for the low feldspar content [44]. Illite is another important clay mineral found in the J1a Formation. Illite usually exists in a flake form. At times, illite seems to grow at the expense of kaolinite. However, illite is not fully developed (Figure 8c), probably because the kaolinite that formed illite was not buried deeply. Chlorite is another minor clay mineral in this sandstone. The morphology of chlorite clay is dominated by pore-filling crystals. Chlorite cladding is at the edge (Figure 8d), which is thought to form during the early diagenetic stage. The intergranular pores are mainly filled with chlorite, accompanied by minerals such as kaolinite and illite.

4.4.3. Dissolution

Dissolution is a critical factor in forming good-quality reservoirs [45,46]. According to the above analysis, compaction and cementation severely damaged the primary pores. However, the dissolution of feldspar and clastic rocks in the later stage formed secondary pores, which are the main pores of the J1a tight sandstone. The thin section observation results indicate the secondary pores of the J1a Formation are widely distributed, indicating that dissolution is major diagenesis. Feldspar usually dissolves partially along cleavage planes and fractures, resulting in the formation of numerous secondary intragranular pores (Figure 6h). In the regions with strong dissolution, the secondary intergranular and intragranular pores are widely developed, and the porosity is high. Therefore, the dissolution of feldspar is a decisive factor in the development of secondary pores [47].
It is worth mentioning that the thrust structure in the Dibei area is strong and lateral pressure is obvious, which causes the pores to be reduced [22]. However, structural fractures also make the fractures more developed (Figure 6i).

4.5. Burial History and Fluid Inclusion Characteristics

The burial-thermal evolution history was reconstructed to clarify the diagenetic process and pore evolution, as shown in Figure 9. The burial curve is taken from well DB102. In the Paleogene, the J1a group began to deposit at a faster rate, and when the J1a was deposited, the group was uplifted and eroded; Then, the J1a layer continued to be buried rapidly. At about 4.5 Ma ago, the deposition rate increased significantly; in the early Quaternary, the J1a Formation was buried at a depth of more than 4000 m.
The fluid inclusion characteristics of the samples are shown in Figure 10. The aqueous inclusions in the same period as the hydrocarbon inclusions exist in wells DB102, YN2, YN4, and YN5. The homogenization temperature of the inclusion has two peaks, indicating the two periods of oil and gas charging. The temperature range of the first peak is 85~110 °C (12 Ma), and the second is 115~140 °C (4.5 Ma) (Figure 10). Under ultraviolet light, the first group of fluid inclusions showed yellow fluorescence (Figure 11a), indicating that the charged hydrocarbons have low maturity. The second group shows blue fluorescence (Figure 11b), suggesting that the charged hydrocarbon was of high maturity.

5. Discussion

5.1. Diagenetic Evolution

According to the structural relationship [16,33] and diagenetic characteristics, three basic diagenetic stages in the Dibei area have been determined. Based on the standard “Diagenetic Stages of Clastic Rocks” (SY/T5477-2003) from China, the J1a Formation has experienced three stages: Eodiagenesis, A and B substage of mesogenetic diagenesis. During Eodiagenesis, the paleo-temperature range was from paleo-normal temperature to 85 °C. The pore types were mainly primary pores with a little secondary pore. Ro was usually less than 0.5%; during A substage of mesogenetic diagenesis, the paleotemperature ranged from 85 °C to 14 °C, and the Ro ranges from 0.5% to 1.3%. The organic acid yield was high, and the pore types were mainly secondary pores; during the B substage of mesogenetic diagenesis, the paleotemperature range is 140–175 °C, the Ro range is 1.3–2.0%, and the rocks are densified with fractures. The diagenetic stages and pore evolution are shown in Figure 12.
Eodiagenesis: The first stage: the sandstone of the J1a Formation has undergone long-term shallow burial and late rapid deep burial. It is the Eodiagenesis stage dominated by compaction, with the development of siliceous cement and kaolinite; A substage of mesogenetic diagenesis: this stage is the Paleocene–late Pliocene, low-maturity organic matter produces organic acid, and secondary pores are formed in soluble minerals such as dissolved feldspar and rock fragments. The third stage is the B sub-stage of Mesozoic diagenesis from Late Neogene to Quaternary, with high maturity of organic matter [22]. The content of organic acid decreases, the carbonate cementation increases in the late stage, and the reservoir quality continues to deteriorate [16]. Under the strong tectonic compression, the compaction is further strengthened, and the porosity is further reduced [22].

5.2. Controlling Factors of Tight Sandstone

5.2.1. Diagenesis

Destructive Diagenesis

According to Figure 8, the compaction rate is 27.9%~76.8% (average 61.9%). Therefore, compaction is considered to be the main diagenetic process causing porosity deterioration.
Cementation affects reservoir quality [48,49,50]. However, the cementation is not obvious based on the result calculated by [39] (the average cementation rate is 15.2%). In addition, the compaction rate of samples with a high cementation rate is low, indicating that early strong cementation inhibited mechanical compaction (Figure 7). The reason is that carbonate cement is formed by the formation of water with high ion content, and these types of cement fill the space between particles. With the increase in burial, the types of clay minerals change greatly, affecting the reservoir quality [51]. Moreover, because of the enrichment of alkaline and K+ by dissolution, kaolinite is transformed into illite, further reducing the physical properties of the rock, but the depth of illite is not low enough, so illite cement has not been well developed.

Constructive Diagenesis

Although the compaction degree of sandstone is strong, good-quality reservoirs still exist in some areas. The research shows that the secondary dissolution porosity is the main storage space (average thin section porosity is 3.1%), so good-quality tight sandstone reservoirs are mainly affected by dissolution. To evaluate the dissolution effect, the diagram between sheet porosity and feldspar content is drawn. Feldspar is conducive to the occurrence of dissolution, resulting in the generation of secondary dissolution pores (Figure 13). Based on the model from Ruifei Wang, 2011 [39], the dissolution of feldspar and rock fragments increases the porosity by about 10%. Therefore, for high-quality tight sandstone, dissolution is the most important diagenetic process. In addition, the enrichment of kaolinite is also an important part of a high-quality reservoir. The enrichment of kaolinite is also evidence of the strong dissolution of feldspar because the dissolution of feldspar is associated with kaolinite [52].

Tectonism Has Both Destructive and Constructive Effects

Tectonism mostly carries out the secondary transformation of tight reservoirs. This transformation has both advantages and disadvantages for reservoir physical properties, and the overall advantages outweigh the disadvantages. Specifically, in the study area, on the one hand, structural compression leads to further compaction of the reservoir, resulting in the decrease in porosity [53], which has an adverse impact on the physical properties of the reservoir. On the other hand, tectonism will cause the formation of structural fractures in tight reservoirs [54]. Some structural fractures will be further dissolved and expanded under the action of organic acid to form structural dissolution fractures and become a good reservoir space. Some reticular and extended fractures will communicate with isolated residual pores, which greatly improves the permeability of reservoir. Statistics of some core data and cast thin section analysis data [16] show that under the same conditions, the average porosity and permeability values of the reservoir with fracture development are obviously higher than those of the reservoir without fracture development (Table 1). Fractures can effectively improve the porosity and permeability of tight reservoirs. The fracture development area formed by tectonic movement is often a favorable position to form tight sandstone reservoirs. This is consistent with the research results of the literature [2,12].

5.2.2. Oil and Gas Charge and Overpressure

The water in the reservoir can be displaced by charged oil and gas, thereby altering the environment and inhibiting late cementation [55]. Inclusions contain information on the hydrocarbon generation and accumulation, so fluid inclusion is a feasible index to determine the oil and gas charging time [56,57]. The homogenization temperature of fluid inclusions shows that hydrocarbon charging can be divided into two stages at 12 Ma and 4.5 Ma. Late cementation did not form during hydrocarbon charging (Figure 13); therefore, hydrocarbon charging inhibits the formation of late carbonate types of cement, which can also serve as evidence for the lack of late carbonate types of cement. In addition, the overpressure preserves the primary pores well and enables favorable conditions for dissolution [58,59]. The overpressure in the Dibei structural belt originates from hydrocarbon generation [60]. According to the above analysis, the Upper Triassic and Middle-Lower Jurassic source rocks are dominant in the Kuqa depression. With the evolution of source rocks, overpressure originating from hydrocarbon generation is transferred to nearby reservoirs, resulting in abnormal reservoir pressure [61]. The source rocks of the Triassic and Jurassic reached the hydrocarbon generation peak and formed overpressure at 23–12 Ma. In this stage, the sandstone reservoir was not densified (porosity greater than 10%) (Figure 9); the pressure coefficient of the Dibei structural belt generally exceeds 1.7, and the pressure coefficient in some areas exceeds 1.8 [61]. Therefore, the occurrence of overpressure is conducive to preserving the primary pores.

5.3. Sweet Spot Prediction

The geological characteristics of the Dibei gas reservoir are as follows: the faults formed by the tectonic movement in Yanshanian and Himalayan periods connect the source rocks and reservoirs, as well as the source rocks and caprocks, forming an oil and gas transportation system [54]. Because it is close to the center of Yangxia sag and the distance between hydrocarbon and reservoir is close, natural gas has obvious vertical, lateral, and near-source migration paths [16]; there exist two periods of hydrocarbon charging, namely, early oil charging and late gas charging.
A uniform gas water interface does not exist, and the gas reservoir formed at the high part of the structure is damaged by water and becomes a water layer (Figure 14); reservoir densification is earlier than natural gas charging. The reservoir forming mode of the Dibei gas reservoir is: crude oil filling in the Late Neogene (12 Ma); in the late sedimentary period of Kangcun Formation, the reservoir gradually densified (7 Ma); mature natural gas filling in the early deposition of Kuqa Formation (4.5 Ma), and gas reservoir formed after transformation and adjustment in the Quaternary period (2 Ma). The result basically corresponds to the previous conclusion [22].
Based on the previous studies, the natural gas of the J1a Formation mainly comes from the mixture of Jurassic and Triassic, and mainly from Jurassic [37,38]. Moreover, source rocks can provide a sufficient source for oil and gas accumulation [22].
Fractures can not only serve as good seepage channels but also improve the reservoir space of tight sandstone reservoirs [62,63]. The reservoir of the J1a Formation in Dibei section of the Kuqa depression is tighter than most tight reservoirs (porosity < 14%, permeability < 0.1 mD) that produce gas in America [16], but the permeability of section with many fractures is generally high. Through the quantitative relationship between the gas production of drilled wells and the degree of fracture development, it can be found that there is a positive relationship between the degree of fracture development and tight gas production [64]; that is, the higher the degree of fracture development, the higher the tight gas production.
Fracture development areas are mainly distributed at the edge of the Dibei structural belt (Figure 15), while relatively few are in the middle [24,65]. Different from conventional reservoir forming conditions, tight sandstone gas reservoirs are less affected by faults and caprocks [16,22]. Diagenesis is widely developed in this area, which is consistent with the research result of previous scholars [66]. The results of this study and previous studies indicate that dissolution is well developed in the Dibei tectonic belt [24]. Coupling the effective gas intensity of source rock, the fracture development area of the J1a Formation reservoir, and the favorable area of diagenesis, it is predicted that the sweet spot of tight gas of J1a Formation in the Dibei area is in the southeast of YN 2 well (Figure 15).

6. Conclusions

This study aimed to reveal the accumulation model of the Dibei gas reservoir in the Kuqa depression and predict the sweet spot area. By comprehensively using petrology, SEM, thermal burial history simulation, and fluid inclusion analysis, the reservoir physical properties, diagenesis, and accumulation mode of tight sandstone gas reservoirs were studied. This study provides a reference for the exploration and development of other areas in the Kuqa depression. The main conclusions are as follows: The tight sandstone of J1a Formation in the Dibei gas field of Kuqa depression is mainly lithic arkose and feldspathic lithic sandstone, with moderate composition and moderate structural maturity. Secondary dissolution pores are a major part of the pore system. Four important diagenesis processes are determined. Compaction is the main diagenesis that causes porosity reduction, and the contact of suture particles is linear and evenly distributed. The types of cement mainly include carbonate, quartz, and clay cement. The main mineral for dissolution in the J1a tight sandstone is feldspar. The tectonic movement has constructive and destructive effects on diagenetic evolution. Controlling factors to form good-quality tight sandstone include dissolution and overpressure, and dissolution is dominant. Based on the analysis of diagenetic evolution and reservoir controlling factors, the accumulation mode of the Dibei tight gas reservoir is proposed, and the sweet spot prediction is made according to the accumulation mode. The gas generation intensity of Jurassic source rocks, the fracture development area of the J1a formation reservoir, and dissolution are the main factors controlling the distribution of sweet spots. It is pointed out that the sweet spot is mainly on the southeast edge of the Dibei gas reservoir. This model and sweet spot prediction method can be used for the exploration and deployment of other gas reservoirs in the Kuqa depression.

Author Contributions

Conceptualization, G.Z. and X.L.; methodology, M.L.; software, J.Z.; validation, M.L.; resources, C.D.; data curation, J.Z.; writing—original draft preparation, G.Z.; writing—review and editing, D.C.; funding acquisition, X.L. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the National Science and Technology Major Project of China (No. 2016ZX05007–003), Science and Technology Projects of PetroChina (No. T11083), the National Natural Science Foundation of China (No. U1810201), and the Fundamental Research Funds for the Central Universities (Nos. 2020YJSMT02, 2021YJSMT09).

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Not applicable.

Data Availability Statement

Not applicable.

Acknowledgments

We are indebted to Zhongyao Xiao (Tarim Oilfield Company, PetroChina) for his insightful suggestions and help in the manuscript.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Tectonic units and location of Dibei gas field in Kuqa Depression. (a) Location of Tarim Basin; (b) location of Kuqa Depression; (c) sample wells and structural outline of Dibei gas field in Kuqa Depression.
Figure 1. Tectonic units and location of Dibei gas field in Kuqa Depression. (a) Location of Tarim Basin; (b) location of Kuqa Depression; (c) sample wells and structural outline of Dibei gas field in Kuqa Depression.
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Figure 2. Mesozoic–Cenozoic stratigraphic system in the Dibei tectonic belt, Kuqa Depression (modified from Xiongqi Pang, 2019 [16] and Xiaowen Guo, 2016 [17]).
Figure 2. Mesozoic–Cenozoic stratigraphic system in the Dibei tectonic belt, Kuqa Depression (modified from Xiongqi Pang, 2019 [16] and Xiaowen Guo, 2016 [17]).
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Figure 3. Figure indicating the composition of J1a tight sandstone from Dibei gas field, eastern Kuqa Depression (number of samples = 105). Note: I—quartz sandstone; II—feldspar quartz sandstone; III—lithic quartz sandstone; IV—arkose sandstone; V—lithic arkose; VI—feldspar lithic sandstone; VII—lithic sandstone.
Figure 3. Figure indicating the composition of J1a tight sandstone from Dibei gas field, eastern Kuqa Depression (number of samples = 105). Note: I—quartz sandstone; II—feldspar quartz sandstone; III—lithic quartz sandstone; IV—arkose sandstone; V—lithic arkose; VI—feldspar lithic sandstone; VII—lithic sandstone.
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Figure 4. Diagram of the relationship between permeability and porosity.
Figure 4. Diagram of the relationship between permeability and porosity.
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Figure 5. Space type of J1a sandstone from Dibei area. (a) YN5, 4931.82 m, intergranular pores; (b) YN2, 4845.8 mm, intergranular dissolution pores; (c,d) YN4, 4189.6 m, intragranular dissolution pores; (e,f) DB102, 5056.5 m, fractures.
Figure 5. Space type of J1a sandstone from Dibei area. (a) YN5, 4931.82 m, intergranular pores; (b) YN2, 4845.8 mm, intergranular dissolution pores; (c,d) YN4, 4189.6 m, intragranular dissolution pores; (e,f) DB102, 5056.5 m, fractures.
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Figure 6. Diagenetic features of the J1a sandstone reservoir. (a) PPL, grain line contact and stylolite contact (Well YN5, 4922.09 m); (b) PPL, grain line contact (Well YN4, 4121.58 m); (c) XPL, calcite cement (Well YN4, 4127.69 m); (d) PPL, calcite cement (Well YN2, 4841.63 m); (e) XPL, quartz overgrowth (Well DX 1, 4854.32 m); (f) PPL, quartz overgrowth (Well DB 102, 5004.39 m); (g) PPL, feldspar overgrowth (Well DX 1, 4858.74 m); (h) PPL, feldspar dissolution (Well YN2, 4839.26 m); (i) PPL, structural fractures (Well YN5, 4839.86 m). PPL—plane-polarized light; XPL—cross-polarized light.
Figure 6. Diagenetic features of the J1a sandstone reservoir. (a) PPL, grain line contact and stylolite contact (Well YN5, 4922.09 m); (b) PPL, grain line contact (Well YN4, 4121.58 m); (c) XPL, calcite cement (Well YN4, 4127.69 m); (d) PPL, calcite cement (Well YN2, 4841.63 m); (e) XPL, quartz overgrowth (Well DX 1, 4854.32 m); (f) PPL, quartz overgrowth (Well DB 102, 5004.39 m); (g) PPL, feldspar overgrowth (Well DX 1, 4858.74 m); (h) PPL, feldspar dissolution (Well YN2, 4839.26 m); (i) PPL, structural fractures (Well YN5, 4839.86 m). PPL—plane-polarized light; XPL—cross-polarized light.
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Figure 7. The relationship between the intergranular volume and the cementation volume of the J1a tight reservoir (modified from Longlong Liu, 2020 [43]).
Figure 7. The relationship between the intergranular volume and the cementation volume of the J1a tight reservoir (modified from Longlong Liu, 2020 [43]).
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Figure 8. Diagenetic characteristics of the Ahe reservoir shown under the SEM. (a) Calcite cement (Well YN2, 4841.63 m); (b) Kaolinite cement (Well DX1, 4855.45 m); (c) Illite cement (Well YN5, 4930.58 m); (d) Chlorite cement (Well DX1, 4856.85 m).
Figure 8. Diagenetic characteristics of the Ahe reservoir shown under the SEM. (a) Calcite cement (Well YN2, 4841.63 m); (b) Kaolinite cement (Well DX1, 4855.45 m); (c) Illite cement (Well YN5, 4930.58 m); (d) Chlorite cement (Well DX1, 4856.85 m).
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Figure 9. Burial, thermal history, and geothermal line of well DB102.
Figure 9. Burial, thermal history, and geothermal line of well DB102.
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Figure 10. Homogenization temperatures of aqueous inclusions coeval with hydrocarbon inclusions in the Dibei area. (a–d) Homogenization temperatures for DB102 well, YN2 well, YN4 well, and YN5 well, respectively.
Figure 10. Homogenization temperatures of aqueous inclusions coeval with hydrocarbon inclusions in the Dibei area. (a–d) Homogenization temperatures for DB102 well, YN2 well, YN4 well, and YN5 well, respectively.
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Figure 11. Micrographs of hydrocarbon inclusions in the J1a Formation under UV light in the Well DB102. (a) Yellow fluorescence; (b) blue-white fluorescence.
Figure 11. Micrographs of hydrocarbon inclusions in the J1a Formation under UV light in the Well DB102. (a) Yellow fluorescence; (b) blue-white fluorescence.
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Figure 12. Diagenesis and porosity evolution of the J1a Formation. A is A substage of mesogenetic diagenesis; B is B substage of mesogenetic diagenesis.
Figure 12. Diagenesis and porosity evolution of the J1a Formation. A is A substage of mesogenetic diagenesis; B is B substage of mesogenetic diagenesis.
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Figure 13. Secondary dissolution pores versus feldspar content.
Figure 13. Secondary dissolution pores versus feldspar content.
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Figure 14. Comprehensive reservoir formation pattern in Dibei area (modified from Xiongqi Pang, 2019 [16] and Song Guo, 2018 [22]).
Figure 14. Comprehensive reservoir formation pattern in Dibei area (modified from Xiongqi Pang, 2019 [16] and Song Guo, 2018 [22]).
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Figure 15. Sweet spots area for J1a tight sandstone in the Dibei reservoir (the source rock data are from Caineng Zou, 2011 [37]; fracture data are modified from Hailiang Kang, 2016 [24]).
Figure 15. Sweet spots area for J1a tight sandstone in the Dibei reservoir (the source rock data are from Caineng Zou, 2011 [37]; fracture data are modified from Hailiang Kang, 2016 [24]).
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Table
Table 1. Porosity and permeability of the J1a sandstone in Dibei area (part of the data is from Hailiang Kang [24]).
Table 1. Porosity and permeability of the J1a sandstone in Dibei area (part of the data is from Hailiang Kang [24]).
WellsMeasured Porosity/%Measured Permeability/mD
Samples with
Developed Fractures		Samples without
Developed Fractures		Samples with
Developed Fractures		Samples without
Developed Fractures
MinMaxAveMinMaxAveMinMaxAveMinMaxAve
YN41.1913.189.210.8912.977.390.038316097.60.006631.936
YS43.2612.358.731.6316.218.360.0992681.20.009891.942
YN22.6313.965.620.2815.865.480.34939236.40.013521.09
YN52.369.185.650.6912.635.910.982659258.80.0214765.27
Ave 8.23 6.95 128.37 2.54
Note: Min = Minimum; Max = Maximum; Ave = Average.
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Zhao, G.; Li, X.; Liu, M.; Dong, C.; Chen, D.; Zhang, J. Reservoir Characteristics of Tight Sandstone and Sweet Spot Prediction of Dibei Gas Field in Eastern Kuqa Depression, Northwest China. Energies 2022, 15, 3135. https://doi.org/10.3390/en15093135

AMA Style

Zhao G, Li X, Liu M, Dong C, Chen D, Zhang J. Reservoir Characteristics of Tight Sandstone and Sweet Spot Prediction of Dibei Gas Field in Eastern Kuqa Depression, Northwest China. Energies. 2022; 15(9):3135. https://doi.org/10.3390/en15093135

Chicago/Turabian Style

Zhao, Guangjie, Xianqing Li, Mancang Liu, Caiyuan Dong, Daye Chen, and Jizhen Zhang. 2022. "Reservoir Characteristics of Tight Sandstone and Sweet Spot Prediction of Dibei Gas Field in Eastern Kuqa Depression, Northwest China" Energies 15, no. 9: 3135. https://doi.org/10.3390/en15093135

APA Style

Zhao, G., Li, X., Liu, M., Dong, C., Chen, D., & Zhang, J. (2022). Reservoir Characteristics of Tight Sandstone and Sweet Spot Prediction of Dibei Gas Field in Eastern Kuqa Depression, Northwest China. Energies, 15(9), 3135. https://doi.org/10.3390/en15093135

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