A method for evaluating pressure system of tight sandstone gas reservoir based on source-break-sand configuration

Abstract

The application provides a method for evaluating a pressure system of a tight sandstone gas reservoir based on a source-break-sand configuration, comprising the following steps: 1. characterizing a "source" in a "source-break-sand" system; 2. characterizing a "break" in the "source-break-sand" system; 3. characterizing a "sand" in the "source-break-sand" system; and 4. predicting a formation pressure of the tight sandstone gas reservoir based on the "source-break-sand" configuration. The application carries out a systematic evaluation on the geological genesis of the tight sandstone formation pressure, can provide a geological basis for predicting the tight sandstone formation pressure with the "source-break-sand" system, and significantly improves the prediction accuracy of the tight sandstone formation pressure.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas reservoir exploration technology, and particularly relates to a pressure system evaluation method for tight sandstone gas reservoirs based on source-fault-sand configuration. Background Technology

[0002] Formation pressure refers to the pressure generated by geological fluids such as formation water, oil, and natural gas within the pores of rocks; it is also called formation pore pressure or pore pressure. Under any geological background, normal formation pressure is equal to the net water column pressure from the surface to the target layer. Pressure deviating from the normal pressure trend line is considered abnormal formation pressure. When formation pressure exceeds the hydrostatic column pressure, an abnormally high-pressure phenomenon occurs in the formation. Abnormally high-pressure formations not only severely affect wellbore stability during drilling but may even lead to drilling accidents such as well kicks and blowouts. Abnormal formation pressure also has a significant impact on the efficiency of initial production and reservoir quality. Formation pressure is an important basis for the rational design of drilling pressure density and wellbore structure; accurate prediction of formation pressure is a necessary condition for preventing wellbore instability, improving drilling efficiency, and saving drilling costs. Years of practice have gradually led to the recognition that formation pressure, as a geological parameter, plays an extremely important role in oil and gas geological exploration, oil and gas well engineering, oil and gas development, and reservoir engineering.

[0003] There are many methods for predicting abnormal formation pressure. Currently, the prediction of formation pore pressure mainly relies on well logging and seismic methods. For predicting formation pore pressure using well logging data, the more mature and widely used methods both domestically and internationally are the equilibrium depth method (Xu Zhixing, 2015), the Browser method (Brower et al., 1996), and the Eaton method (Eaton, 1972). The equilibrium depth method is more effective for high pressure generated by undercompacted formations, while the Browser and Eaton methods provide good predictions for high pressure formed in formations other than undercompacted formations. For predicting formation pore pressure using seismic layer velocities, common calculation formulas include the compaction balance equation (Xu Zhixing, 2015), the equivalent depth method, the Eaton method, the Stone method, the Fillippone method, and improved Fillippone methods (Wang Yingming et al., 2011).

[0004] As the exploration and development of tight sandstone oil and gas deepens, the accuracy requirements for formation pressure prediction continue to increase. Relying solely on mathematical calculations and empirical formulas is insufficient to meet the needs of practical production. Even if the formation pressure of the target layer in the study area is predicted using mathematical calculations and empirical formulas, the prediction results are unreliable due to a lack of mechanistic analysis of geological factors, leading to numerous uncertainties and unreliability in well location deployment and scheme design. On the other hand, there are many mathematical formulas and prediction methods, each with different applicable conditions. However, the underground geological conditions and environment of oil and gas fields are extremely complex. Without targeted selection of empirical formulas for specific regions, it is difficult to achieve accurate formation pressure prediction. In conclusion, establishing a geological evaluation basis for formation pressure prediction by region is crucial.

[0005] Currently, previous studies have extensively investigated the formation mechanism of high pressure in argillaceous strata of sedimentary basins, generally agreeing that abnormally high pressure is mainly caused by undercompaction of mudstone, organic hydrocarbon generation, fluid thermal expansion, and tectonic compression. However, the mechanism of high pressure or relative high pressure in tight sandstone remains unclear. In recent years, with the continuous discovery of relatively high-pressure sandstone reservoirs (Swarbrick and Osborne, 1998; Yardley and Swarbrick, 2000; Li Weilian et al., 2008), it is believed that there are significant differences between sandstone reservoirs and low-permeability mudstones in terms of the causes and characteristics of high pressure. Reservoir high pressure is often a direct manifestation of the transmission and redistribution of high pressure caused by the flow of fluids within the high-pressure source towards the reservoir. The fluids (oil, gas, water) within sandstone are formed at a specific "source," and their flow direction and capacity are a direct reflection of redistribution. The fluids (oil, gas, water) inside sandstone are formed from a certain "source". The direction and flow capacity are related to the permeability of the sandstone itself, as well as the "faults" that break through the sandstone strata. Due to its poor permeability, the flow of fluids inside dense sandstone is mainly affected by faults, forming a unique "source-fault-sand" system inside dense sandstone. Summary of the Invention

[0006] The purpose of this invention is to overcome the shortcomings of the existing technology and provide an evaluation method for the pressure system of tight sandstone gas reservoirs based on source-fault-sand configuration.

[0007] Currently, most formation pressure prediction methods rely solely on measured formation pressure values ​​to calibrate relevant sensitive parameters from well logging and seismic data. These parameters, along with measured values, are used to calculate formation pressure values ​​for unmeasured areas across the entire region using empirical formulas and mathematical calculations. This process involves numerous formulas, methods, and parameter choices, with the selection largely based on trial and error. However, the formation and evolution of formation pressure are closely related to the evolution of the formation and its internal fluids, exhibiting regularity and regional zonation. A lack of geological mechanism analysis inevitably leads to unreliable prediction results, introducing significant uncertainties into well location deployment and scheme design. Furthermore, while formation pressure prediction work for mudstone is relatively comprehensive, work on formation pressure prediction for tight sandstone is relatively weak.

[0008] This invention conducts a systematic evaluation of the geological genesis of pressure in tight sandstone formations, which can provide geological basis for the prediction of pressure in tight sandstone formations with a "source-fault-sand" system and significantly improve the accuracy of pressure prediction in tight sandstone formations.

[0009] This invention adopts the following technical solution: a method for evaluating the pressure system of tight sandstone gas reservoirs based on source-fault-sand configuration, comprising:

[0010] Step 1. Delineation of the "Source" in the "Source-Break-Sand" System

[0011] ① By investigating the macroscopic geological background of the target layer in the study area, and based on previous research results and understanding, the possible sources of natural gas (i.e., source rocks) in the tight sandstone of the target layer in the study area are clarified.

[0012] ②Analyze natural gas samples from different wells in the target layer of the study area to clarify the material type and composition ratio of natural gas produced from different wells. Compare these samples with the material type and composition ratio of gas produced from different source rocks as recorded by previous researchers to preliminarily determine the possible sources, quantities, and types of natural gas in different areas of the target layer of the study area.

[0013] ③ Calculate the intensity and proportion of gas supply from different source rocks in different regions of the target layer in the study area, and quantitatively characterize the degree to which the natural gas enriched in different regions is affected by different source rocks.

[0014] Step 2. Depicting the "Broken" in the "Source-Broken-Sand" System

[0015] ① The faults of the target layer in the study area were sorted out. Faults that did not cut through the sand body and faults that only cut through a single or isolated sand body were excluded as invalid faults, and the remaining faults were considered as valid faults.

[0016] ② Describe the communication capability of each effective fault. Faults that do not cut through and communicate with source rocks but only cut through and communicate with different sand bodies are defined as Class O faults. Faults that cut through and communicate with one set of source rocks are considered Class I faults. Faults that cut through and communicate with two sets of source rocks are considered Class II faults. Faults that cut through and communicate with three sets of source rocks are considered Class III faults, and so on. Faults that cut through and communicate with N sets of source rocks are considered Class N faults. Since strata or source rocks are stacked in layers, it is obvious that a Class III fault must also communicate with one set of source rocks communicated by a Class I fault or two sets of source rocks communicated by Class II faults.

[0017] ③ Based on the gas supply intensity calculation in steps 1-③, assess the gas supply capacity of the fault and divide the area according to the assessment results.

[0018] Step 3. Characterization of "Sand" in the "Source-Break-Sand" System

[0019] ① Based on the relationship between sandstone and internal mudstone interlayers, the sandstone in different areas of the target layer in the study area is divided into three types of sand-mud assemblages: pure sand, sand-mud interlayer, and mud-sand interlayer. The amount of mudstone content in different assemblages has a significant impact on the enrichment of natural gas in the assemblages. The thicker the mudstone, the less likely natural gas is to accumulate, the lower the formation pressure, and the greater the need for faults to break through mudstone interlayers to guide natural gas into the sandstone.

[0020] ② The three types of sand and mud combinations—pure sand, sand-mud mixture, and mud-sand mixture—are coupled and matched with the partitions in steps 2-③ to form the pure sand I "source-break-sand" system, the pure sand II "source-break-sand" system, the sand-mud mixture I "source-break-sand" system, the mud-sand mixture I "source-break-sand" system, and so on, and the distribution range of different systems is divided on the plane.

[0021] Step 4. Formation pressure prediction of tight sandstone gas reservoirs based on the "source-fault-sand" configuration

[0022] Within the different "source-fault-sandwich" system areas defined in step 3-②, zoned and detailed well-seismic formation pressure prediction is conducted using the equilibrium depth method, the Browser method, the Eaton method, the Stone method, and the Fillippone method. Within each "source-fault-sandwich" system area, based on geological conditions, different most suitable technical solutions and prediction parameters are selected to precisely predict formation pressure within different system areas. By combining the formation pressures from different system areas, the distribution characteristics of formation pressure across the entire region are revealed.

[0023] The beneficial effects of this invention are:

[0024] This invention was applied to the research project on formation pressure prediction in the Shaximiao Formation tight sandstone natural gas reservoir of the Jinqiu Gas Field of Southwest Oil and Gas Field Company of China National Petroleum Corporation. It successfully revealed the geological causes of the differential distribution of formation pressure in this gas reservoir. The innovative idea of ​​subsystem prediction has been promoted and used by production units, making formation pressure prediction more reliable, systematic and accurate.

[0025] Specifically, based on this invention, well-seismic joint prediction of formation pressure coefficient was carried out in the Jinqian 5H block of the Jinqiu gas field, and the average accuracy of the prediction results was 11% higher than that without using this invention. Attached Figure Description

[0026] Figure 1 This is a flowchart of the steps of the present invention;

[0027] Figure 2 This is a map showing the scope of the "source-fault-sand" system for a specific stratigraphic segment in the Shaximiao Formation of the Jinqian 5H block. Detailed Implementation

[0028] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions of this invention are described clearly and completely below. Obviously, the described embodiments are only some embodiments of this invention, not all embodiments. Based on the embodiments of this invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this invention.

[0029] like Figure 1 As shown, a pressure system evaluation method for tight sandstone gas reservoirs based on source-fault-sand configuration includes:

[0030] 1) Depiction of the "Source" in the "Source-Break-Sand" system

[0031] ① By investigating the macroscopic geological background of the target strata in the study area, and based on previous research results and understanding, the possible sources of natural gas (i.e., source rocks) in the tight sandstone of the target strata in the study area are clarified. For example, the target strata in the study area may have three sets of source rocks, A, B, and C;

[0032] ②Analyze natural gas samples from different wells in the target layer of the study area to clarify the material type and composition ratio of natural gas produced from different wells. Compare these samples with the material type and composition ratio of gas produced from different source rocks as recorded by previous researchers to preliminarily determine the possible sources, quantities, and types of natural gas in different areas of the target layer of the study area.

[0033] For example, if the natural gas type in the northern part of the study area is similar to the gas production types of source rocks A and B, but completely different from that of source rock C, then the northern part is considered to be produced by source rocks A and B.

[0034] ③ Calculate the intensity and proportion of gas supply from different source rocks in different regions of the target layer in the study area, and quantitatively characterize the degree to which the natural gas enriched in different regions is affected by different source rocks.

[0035] For example, in the northern part of the study area, source rock A accounts for 20% of the gas supply intensity, while source rock B accounts for 80%; in the southern part of the study area, source rock A accounts for 45% of the gas supply intensity, while source rock B accounts for 55%.

[0036] 2) Depiction of "Broken" in the "Source-Broken-Sand" System

[0037] ① The faults of the target layer in the study area were sorted out. Faults that did not cut through the sand body and faults that only cut through a single or isolated sand body were excluded as invalid faults, and the remaining faults were considered as valid faults.

[0038] ② Describe the communication capability of each effective fault. Faults that do not cut through and communicate with source rocks but only cut through and communicate with different sand bodies are defined as Class O faults. Faults that cut through and communicate with one set of source rocks are considered Class I faults. Faults that cut through and communicate with two sets of source rocks are considered Class II faults. Faults that cut through and communicate with three sets of source rocks are considered Class III faults, and so on. Faults that cut through and communicate with N sets of source rocks are considered Class N faults. Since strata or source rocks are stacked in layers, it is obvious that a Class III fault must also communicate with one set of source rocks communicated by a Class I fault or two sets of source rocks communicated by Class II faults.

[0039] ③ Based on the gas supply intensity calculation in steps 1-③, assess the gas supply capacity of the fault and divide the area according to the assessment results.

[0040] For example, a Class I fault in the northern part of the study area connects to source rock A, and the gas supply intensity of source rock A at this location is 1×10⁻⁶. 4 m 3 / km 2 The gas supply range is 5km. 2 This area is designated as Zone I; a Class I fault in the western part of the study area connects to source rock A, and the gas supply intensity of source rock A at this location is 5 × 10⁻⁶. 4 m 3 / km 2 It accounts for 70%, and the combined gas supply range is 42.5km. 2 This range is designated as Zone III, and so on. If multiple zones overlap, the overlapping zones are named together, for example, Zone I-II, Zone I-II-III.

[0041] 3) Characterization of "Sand" in the "Source-Break-Sand" System

[0042] Within the same "source-fault" region, such as within the aforementioned Zone I, the sand bodies are different, resulting in different spaces for storing natural gas, varying degrees of enrichment, and different formation pressures. Therefore, it is necessary to characterize the "sand".

[0043] ① Based on the relationship between sandstone and internal mudstone interlayers, the sandstone in different areas of the target layer in the study area is divided into three types of sand-mud assemblages: pure sand type (uniform grain size, sand body stacking pattern mainly scour-cutting type), sand-mud interlayer type (sandstone accounts for a large proportion and mudstone is present inside, sand body stacking pattern is scour-cutting type and scour-contact type), and mud interlayer type (mudstone accounts for a large proportion, sand body stacking pattern is scour-contact type and isolated type). The amount of mudstone content in different assemblages has a significant impact on the enrichment of natural gas in the assemblages. The thicker the mudstone, the less likely natural gas is to be enriched, the lower the formation pressure, and the greater the need for faults to break through mudstone interlayers to guide natural gas into the sandstone.

[0044] ② The three types of sand and mud combinations—pure sand, sand-mud mixture, and mud-sand mixture—are coupled and matched with the partitions in steps 2-③ to form the pure sand I "source-break-sand" system, the pure sand II "source-break-sand" system, the sand-mud mixture I "source-break-sand" system, the mud-sand mixture I "source-break-sand" system, and so on, and the distribution range of different systems is divided on the plane.

[0045] 4) Formation pressure prediction of tight sandstone gas reservoirs based on the "source-fault-sand" configuration

[0046] Within the different "source-fault-sandwich" system areas defined in step 3-②, zoned and detailed well-seismic formation pressure prediction is conducted using the equilibrium depth method, the Browser method, the Eaton method, the Stone method, and the Fillippone method. Within each "source-fault-sandwich" system area, based on geological conditions, different most suitable technical solutions and prediction parameters are selected to precisely predict formation pressure within different system areas. By combining the formation pressures from different system areas, the distribution characteristics of formation pressure across the entire region are revealed.

[0047] Example

[0048] Taking the Jinqiu Gas Field in the Sichuan Basin of my country as an example, this paper systematically elaborates on the application of the present invention in the systematic evaluation of gas reservoir pressure in tight sandstone oil and gas exploration and development.

[0049] Step 1: In this embodiment, the key section of the Shaximiao Formation in the Jinqian 5H block of the Jinqiu Gas Field is selected for investigation. Based on previous research results and understanding, it is determined that the possible sources of natural gas in the tight sandstone of the target layer are two sets of source rocks, A and B. Natural gas samples produced by different wells in the target layer of the study area are analyzed to clarify the material type and composition ratio of natural gas produced by different wells. The sources of natural gas in different areas of the target layer of the study area are confirmed to be three types: source rock A, source rock B, and two sets of source rocks A and B.

[0050] Step 2: After identifying the effective faults, the key faults of the Shaximiao Formation in the Jinqian 5H block were divided into three types. There are three types of faults in the key faults of the study area: Type 0 faults that do not cut through and connect source rocks, and only cut through and connect different sand bodies; Type 1 faults that cut through and connect one set of source rocks; and Type 2 faults that cut through and connect two sets of source rocks. Based on these, the gas supply capacity of the faults was assessed, and the area was divided into two regions, Zone I and Zone II, according to the assessment results.

[0051] Step 3: By comparing the relationship between sandstone and internal muddy interlayers in key strata, sandstone in different regions is classified into three types of sand-mud assemblages: pure sand, sand-mud-interbedded sand, and mud-mud-interbedded sand. Coupled with the source rock classification and fault evaluation results in Steps 1 and 2, the study area is divided into pure sand I "source-fault-sand" system, pure sand II "source-fault-sand" system, sand-mud-interbedded sand I "source-fault-sand" system, mud-mud-interbedded sand I "source-fault-sand" system, etc., and the distribution range of different systems is divided on the plane.

[0052] Step 4, within different "source-break-sand" system ranges (e.g.) Figure 2 As shown in the figure, based on the geological conditions of the target stratum of the Shaximiao Formation in the Jinqian 5H block, this study combined multiple methods to carry out regional and detailed well-seismic formation pressure prediction, revealing the formation pressure distribution characteristics across the entire area.

[0053] This embodiment, after clarifying the different "source-fault-sand" system ranges, predicted the formation pressure at well sites in two key sandstone formations of the Shaximiao Formation in the Jinqian 5H block, revealing the formation pressure distribution characteristics across the entire area. Specifically, based on this invention, well-seismic joint prediction of formation pressure coefficients was carried out in the Jinqian 5H block of the Jinqiu Gas Field, and the average accuracy of the prediction results was improved by 11% compared to the case without using this invention. This demonstrates the rationality and effectiveness of this invention.

[0054] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for evaluating the pressure system of tight sandstone gas reservoirs based on source-fault-sand configuration, characterized in that it includes: Step 1. Delineation of the "Source" in the "Source-Break-Sand" System 1.1). By investigating the macroscopic geological background of the target layer in the study area, the source of natural gas in the tight sandstone of the target layer in the study area is clarified based on previous research results and understanding; 1.2) Analyze natural gas samples produced by different wells in the target layer of the study area to clarify the material type and composition ratio of natural gas produced by different wells, and compare them with the material type and composition ratio of gas produced by different source rocks recorded by previous studies to preliminarily determine the source quantity and type of natural gas in different areas of the target layer of the study area. 1.3) Calculate the intensity and proportion of gas supply from different source rocks in different regions of the target layer in the study area, and quantitatively characterize the degree to which the natural gas enriched in different regions is affected by different source rocks; Step 2. Delineation of "Broken" in the "Source-Broken-Sand" System 2.1) Identify the faults in the target layer of the study area, exclude faults that do not cut through the sand body and faults that only cut through a single or isolated sand body, and consider them as invalid faults; the remaining faults are considered as valid faults. 2.2) Describe the communication capability of each effective fault. Faults that do not cut through and communicate with source rocks but only cut through and communicate with different sand bodies are defined as Class O faults. Faults that cut through and communicate with one set of source rocks are considered Class I faults. Faults that cut through and communicate with two sets of source rocks are considered Class II faults. Faults that cut through and communicate with three sets of source rocks are considered Class III faults, and so on. Faults that cut through and communicate with N sets of source rocks are considered Class N faults. Since strata or source rocks are stacked layer by layer, it is obvious that a Class III fault must also communicate with one set of source rocks communicated by a Class I fault or two sets of source rocks communicated by Class II faults. 2.3) Based on the gas supply intensity calculation in step 1.3, assess the gas supply capacity of the fault and divide the area according to the assessment results; Step 3. Characterization of "Sand" in the "Source-Break-Sand" System Within the same "source-fault" region, even within Zone I, different sand bodies result in different spaces for natural gas storage, leading to variations in enrichment levels and formation pressures. Therefore, it is necessary to characterize the "sand". 3.1) Based on the relationship between sandstone and internal muddy interlayers, the sandstone in different areas of the target layer in the study area is divided into three types of sand-mud assemblages: pure sand type, sand-mud interlayer type, and mud-sand interlayer type. 3.2) Couple and match the three types of sand and mud combinations—pure sand, sand-mud-mixed, and mud-mud-mixed sand—with the zoning in step 2.3 to form the pure sand I "source-break-sand" system, the pure sand II "source-break-sand" system, the sand-mud-mixed I "source-break-sand" system, and the mud-mud-mixed I "source-break-sand" system, and divide the distribution range of different systems on the plane; Step 4. Formation pressure prediction of tight sandstone gas reservoirs based on the "source-fault-sand" configuration Within the different "source-fault-sand" system ranges defined in step 3.2), regional and detailed well-seismic formation pressure prediction is carried out by combining the equilibrium depth method, the Browser method, the Eaton method, the Stone method, and the Fillippone method.

2. The method for evaluating the pressure system of tight sandstone gas reservoirs based on source-fault-sand configuration according to claim 1, wherein step 2.3) further includes: if multiple regions overlap, the overlapping regions are named together.

3. The method for evaluating the pressure system of tight sandstone gas reservoirs based on source-fault-sand configuration according to claim 1, characterized in that... In step 4, within each of the "source-fault-sand" systems, different most suitable technical solutions and prediction parameters are selected based on geological conditions to accurately predict the formation pressure within different system ranges. The formation pressure within different system ranges is then combined to reveal the formation pressure distribution characteristics across the entire region.

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