Structural hydrocarbon reservoir prediction method, electronic device and medium

Abstract

An embodiment of the present invention discloses a method for predicting structural hydrocarbon reservoirs, an electronic device, and a medium. Among them, the method for predicting structural hydrocarbon reservoirs includes: constructing a three-dimensional model of the fault structure in the study area based on the acquired seismic data volume; determining the paleo-stress field parameters during the fault formation period and the stress field parameters during the fault hydrocarbon control period based on the three-dimensional model; predicting the fracture-derived fractures during the fault formation period based on the determined paleo-stress field parameters during the fault formation period to obtain the prediction result of the fracture-derived fractures during the fault formation period; predicting the fracture opening degree during the fault hydrocarbon control period based on the stress field parameters during the fault hydrocarbon control period to obtain the prediction result of the fracture opening degree during the fault hydrocarbon control period; and predicting the hydrocarbon reservoir based on the prediction result of the fracture-derived fractures during the fault formation period and the prediction result of the fracture opening degree during the fault hydrocarbon control period. The purpose of accurately predicting the location of the hydrocarbon reservoir is achieved.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil exploration, and more specifically, relates to a method for predicting structural oil and gas reservoirs, an electronic device, and a medium. Background Art

[0002] The purpose of oil and gas exploration is to find oil and gas reservoirs, and the prediction of the spatial distribution of oil and gas reservoirs is crucial. There are the following three existing technologies.

[0003] (1) Basin simulation method

[0004] Basin Modeling is based on the geological mechanism of physical chemistry, and quantitatively simulates the formation and evolution of oil and gas-bearing basins, the generation, migration, and accumulation of hydrocarbons by computer in time and space to reveal the essence of the oil and gas laws in the basin. Among them, the reservoir-forming dynamics simulation can preliminarily simulate the oil and gas migration path and the invaded horizons in three-dimensional space. Currently, the well-accepted commercial simulation software includes TEMISPACK (French Petroleum Institute), BasinMod (PlatteRiver Company, USA), and PetroMod (Institute of Organic Geochemistry, Germany).

[0005] The deficiencies of this method are as follows:

[0006] ① When simulating the migration of oil and gas along faults according to the basin simulation method, the opening degree of the faults needs to be artificially assigned. In addition, as a long-term technical problem, basin simulation faces difficulties and challenges in many aspects such as the accurate solution of simulation algorithms, the consideration of geological factors such as faults and diagenesis, the restoration of intermittent mutation processes of oil and gas migration, and the reconstruction of paleo-hydrodynamic processes. Currently, applying basin simulation software cannot accurately predict the possible locations of oil and gas reservoir development.

[0007] ② The existing oil and gas migration and accumulation simulations by basin simulation methods and commercial software are only applicable to clastic rock particle pore media, and are not applicable to fracture pore media such as carbonate rocks.

[0008] (2) Geophysical method

[0009] There are differences in physical properties between underground oil and gas reservoirs and surrounding rocks, which can be reflected in the gravity, magnetic, and electrical anomalies of surface gravity, magnetic, and electrical prospecting, as well as the seismic wave differences in seismic prospecting. Based on this, oil and gas reservoir prediction can be achieved.

[0010] The deficiencies of this method are as follows:

[0011] The geophysical method is greatly affected by the quality of data, and there are also human factors in the data processing process. More importantly, the processed results have multiple solutions, thus affecting the accuracy of the prediction results.

[0012] (3) Geological mapping method

[0013] From the perspective of the formation process of oil and gas reservoirs, various maps such as source rock, reservoir, cap rock, migration, accumulation, and preservation maps are compiled, combined with ancient and modern structural maps and ancient and modern geomorphic maps, and the favorable oil and gas distribution areas are comprehensively analyzed to achieve the purpose of prediction.

[0014] The deficiencies of this method are as follows:

[0015] The geological mapping method can only predict the favorable zones of oil and gas reservoir distribution, and cannot predict the specific location and depth of a certain oil and gas reservoir.

[0016] In the process of implementing the present invention, the inventor found that there are at least the following problems in the prior art:

[0017] The location of the oil and gas reservoir cannot be accurately predicted. Summary of the Invention

[0018] In view of this, the embodiments of the present invention provide a method, an electronic device, and a medium for predicting structural oil and gas reservoirs, which can at least solve the problem that the location of the oil and gas reservoir cannot be accurately predicted in the prior art.

[0019] In a first aspect, an embodiment of the present invention provides a method for predicting structural oil and gas reservoirs, including:

[0020] Constructing a three-dimensional model of the fault structure in the study area based on the acquired seismic data volume;

[0021] Determining the paleo-stress field parameters during the fault formation period and the stress field parameters during the fault-controlled reservoir period based on the three-dimensional model;

[0022] Predicting the fracture-derived fractures during the fault formation period based on the determined paleo-stress field parameters during the fault formation period to obtain the prediction result of the fracture-derived fractures during the fault formation period;

[0023] Predicting the fracture opening degree during the fault-controlled reservoir period based on the stress field parameters during the fault-controlled reservoir period to obtain the prediction result of the fracture opening degree during the fault-controlled reservoir period;

[0024] Predicting oil and gas reservoirs based on the prediction result of the fracture-derived fractures during the fault formation period and the prediction result of the fracture opening degree during the fault-controlled reservoir period.

[0025] Optionally, the seismic data volume includes a two-dimensional seismic data volume and a three-dimensional seismic data volume.

[0026] Optionally, the paleo-stress field parameters during the fault formation period include:

[0027] Fault formation time, azimuth of the principal stress of the paleo-stress field, and value of the principal stress of the paleo-stress field.

[0028] Optionally, the fracture formation time is determined by a balanced profile orthogonal to the fracture, a fracture growth index, and the formation age of the strata involved in the deformation beside the fracture;

[0029] The azimuths of the principal stresses of the paleo-stress field are determined according to Anderson's law based on the geometric, kinematic, and fold structural characteristics of the fractures of this period, to obtain the azimuths of the maximum horizontal principal compressive stress, the minimum horizontal principal compressive stress, and the vertical principal stress when the fractures in the study area were formed;

[0030] The values of the principal stresses of the paleo-stress field are based on the actual measured data of exploration wells and development wells to compile depth profiles of the three principal stress values and pore fluid pressure, obtain the stress-depth profile, then determine the paleo-burial depth when the fractures were formed, obtain the burial depth value, and project this burial depth value onto the stress-depth profile to determine the magnitudes of the corresponding principal stress values.

[0031] Optionally, the values of the principal stresses of the paleo-stress field are determined based on the maximum principal compressive stress, the minimum principal compressive stress, and the intermediate principal compressive stress when the fractures were formed.

[0032] The intermediate principal compressive stress is determined according to the following formula:

[0033] Sv = hρg, where h is the burial depth, ρ is the density of the overlying strata, g is the acceleration due to gravity, and Sv is the intermediate principal compressive stress;

[0034] The minimum principal compressive stress is determined according to the following formula:

[0035] Sh = Sv × v,

[0036] Sh is the minimum principal compressive stress, v is the stress ratio coefficient, and μ is the Poisson's ratio.

[0037] Optionally, the stress field parameters during the fracture-controlled hydrocarbon accumulation period include:

[0038] The fracture-controlled hydrocarbon accumulation time, the azimuth of the stress field during the fracture-controlled hydrocarbon accumulation period, and the magnitude of the stress field during the fracture-controlled hydrocarbon accumulation period.

[0039] Optionally, predicting the fracture opening degree during the fracture-controlled hydrocarbon accumulation period based on the stress field parameters during the fracture-controlled hydrocarbon accumulation period to obtain the prediction result of the fracture opening degree during the fracture-controlled hydrocarbon accumulation period includes:

[0040] Predicting the fracture opening degree during the fracture-controlled hydrocarbon accumulation period based on the slip trend. The slip trend is the ratio of the shear stress to the normal stress on a certain fracture surface, and the value of the slip trend is between 0 and 1.

[0041] Optionally, predicting the favorable parts of the hydrocarbon reservoir based on the prediction result of the fractures-derived fractures during the fracture formation period and the prediction result of the fracture opening degree during the fracture-controlled hydrocarbon accumulation period, the favorable parts of the hydrocarbon reservoir are:

[0042] The intersection area of the high-value area of the fracture density derived from fractures during the fracture formation period in the prediction results of fracture-derived fractures during the fracture formation period and the high-value area of the fracture slip coefficient during the hydrocarbon accumulation period in the prediction results of the fracture opening degree during the fracture-controlled hydrocarbon accumulation period.

[0043] Second, an embodiment of the present invention further provides an electronic device, which includes:

[0044] A memory storing executable instructions;

[0045] A processor that runs the executable instructions in the memory to implement the structural hydrocarbon reservoir prediction method according to any one of the first aspects.

[0046] Third, an embodiment of the present invention further provides a computer-readable storage medium, which stores a computer program that, when executed by a processor, implements the structural hydrocarbon reservoir prediction method according to any one of the first aspects.

[0047] The present invention determines the paleo-stress field parameters during the fracture formation period and the stress field parameters during the fracture-controlled hydrocarbon accumulation period through the constructed three-dimensional model, predicts the fracture-derived fractures during the fracture formation period and the fracture opening degree during the fracture-controlled hydrocarbon accumulation period, and predicts the hydrocarbon reservoir, so as to achieve the purpose of accurately predicting the location of the hydrocarbon reservoir.

[0048] Other features and advantages of the present invention will be described in detail in the subsequent specific implementation part. BRIEF DESCRIPTION OF THE DRAWINGS

[0049] By describing the exemplary embodiments of the present invention in more detail in conjunction with the drawings, the above and other objects, features, and advantages of the present invention will become more obvious, wherein, in the exemplary embodiments of the present invention, the same reference numerals generally represent the same components.

[0050] Figure 1 Shows a flowchart of the structural hydrocarbon reservoir prediction method according to an embodiment of the present invention;

[0051] Figure 2a Shows a schematic diagram of a three-dimensional model according to an embodiment of the present invention;

[0052] Figure 2b Shows a schematic diagram of determining the paleo-stress field parameters during the fracture formation period according to an embodiment of the present invention;

[0053] Figure 2c Shows a schematic diagram of predicting the fracture-derived fractures during the fracture formation period according to an embodiment of the present invention;

[0054] Figure 2d Shows a schematic diagram of determining the stress field parameters during the fracture-controlled hydrocarbon accumulation period according to an embodiment of the present invention;

[0055] Figure 2e Schematic diagram for predicting the fracture opening degree during the fracture-controlled hydrocarbon accumulation period of an embodiment of the present invention;

[0056] Figure 2f Schematic diagram for predicting hydrocarbon reservoirs of an embodiment of the present invention;

[0057] Figure 3 Schematic diagram of the current structure of the top surface of the Yijianfang Formation in the Ordovician of the Shuntuogoule Low Uplift of an embodiment of the present invention;

[0058] Figure 4a and Figure 4b Schematic diagram of the geological structure cross-section of the study area of an embodiment of the present invention;

[0059] Figure 5a and Figure 5b Schematic diagram of the fracture model in the Shunbei 5 Well Area from different perspectives of an embodiment of the present invention;

[0060] Figure 6a 、 Figure 6b 、 Figure 6c and Figure 6d Comparison diagram of the fracture density interpreted from the imaging logging of Well Shunbei 5-3 and the fracture density simulated under the action of three different maximum principal compressive stress azimuths of an embodiment of the present invention;

[0061] Figure 7 Schematic diagram of the predicted result of the fracture density in the Shunbei 5 Well Area of an embodiment of the present invention;

[0062] Figure 8 Schematic diagram for determining the stress field azimuth during the fracture-controlled hydrocarbon accumulation period of an embodiment of the present invention. Detailed implementation manners

[0063] The preferred embodiments of the present invention will be described in more detail below. Although the preferred embodiments of the present invention are described below, it should be understood that the present invention can be implemented in various forms and should not be limited by the embodiments set forth herein.

[0064] The ultimate goal of petroleum exploration is to find hydrocarbon reservoirs, and predicting the location of hydrocarbon reservoirs runs through the entire process of petroleum exploration. There are many types of hydrocarbon reservoirs, including unconformity hydrocarbon reservoirs, lithologic hydrocarbon reservoirs, structural hydrocarbon reservoirs, etc. Among them, structural hydrocarbon reservoirs are often related to fractures. How to predict structural hydrocarbon reservoirs related to fractures is the issue concerned in the embodiment.

[0065] (1) Basic principle

[0066] In sedimentary basins, some oil and gas reservoirs are developed near faults. In such oil and gas reservoirs, faults are the most important migration channels for oil and gas, enabling oil and gas to accumulate in suitable reservoirs nearby. For oil and gas to enter the faults for migration, the hydrocarbon accumulation period must match the fault formation period. The relationship between the two can be divided into three cases: the hydrocarbon accumulation period is earlier than the fault formation period, the hydrocarbon accumulation period is simultaneous with the fault formation period, and the hydrocarbon accumulation period is later than the fault formation period.

[0067] In the first case, if the fault cuts through the already formed oil and gas reservoir, on the one hand, it may lead to the dissipation of oil and gas, and on the other hand, it will also cause the secondary migration and redistribution of oil and gas along the fault to form oil and gas reservoirs. In this case, the fault formation period is also the fault-controlled reservoir period. As long as the fault is active, each fault will be opened as a whole without discrimination to conduct oil and gas. At this time, what plays a key role in hydrocarbon accumulation is the development degree of the fracture reservoirs derived from the fault and the sedimentary reservoirs, rather than the fault. From a structural perspective, the prediction of the density of the fracture reservoirs derived from the fault is crucial.

[0068] In the second case, just as the faults formed during an earthquake generally reach the surface, during the migration of oil and gas along the fault, due to the activity of the fault and the lack of some overlying caprock caused by tectonic uplift, the oil and gas will be degraded and damaged. Of course, there will also be some faults that do not reach the surface and capture a part of the oil and gas in the fracture reservoirs derived from the fault near the fault or in the sedimentary reservoirs with better porosity near the fault. Similarly, in this case, the fault formation period is also the fault-controlled reservoir period. Similarly, at this time, what plays a key role in hydrocarbon accumulation is the reservoir, rather than the fault. At this time, the prediction of the density of the fracture reservoirs derived from the fault is equally crucial.

[0069] In the third case, the fault is formed first and the hydrocarbon accumulation period is later. During the hydrocarbon accumulation period, the source rock discharges a large amount of hydrocarbons, and the oil and gas will quickly surge upward along the already formed fault into the sedimentary reservoir. In the case of the lack of sedimentary reservoirs, the fracture network derived from the fault formation period around it will become the main flow direction of oil and gas migration. At this time, the reactivation of the fault and the oil and gas migration form the best configuration. Which faults the oil and gas will surge upward into the fracture reservoir along, or which section of a fault, depends on the opening degree of the fault. In this case, the reservoir and the opening degree of the fault are very important. At this time, in order to achieve the purpose of predicting the spatial location of the oil and gas reservoir, two aspects of prediction work need to be done: one is the development degree of the fractures derived from the fault formation period near the fault. The greater the fracture density, the better the reservoir space; the other is the opening degree of the fault during the hydrocarbon accumulation period. The higher the opening degree of the fault, the more conducive it is for the oil and gas to enter the fault from here. Combining these two aspects of prediction constitutes the purpose of the oil reservoir prediction in this embodiment. In the first and second cases, only by predicting the spatial location of the fracture reservoir can the purpose of predicting the location of the oil and gas reservoir be achieved.

[0070] (2) Application conditions

[0071] As described above, the core content of this embodiment is the fracture structure. The fracture has derived fractures and also become the migration channel of oil and gas. This embodiment focuses on the fracture structure. It should be noted that the prerequisite for applying this embodiment is that it is considered that the fracture has communicated with the source rock. In the area under study, this invention can be applied only when the fracture is considered to have communicated with the source rock.

[0072] A method for predicting structural oil and gas reservoirs, comprising:

[0073] Constructing a three-dimensional model of the fracture structure in the study area based on the acquired seismic data volume;

[0074] Determining the paleo-stress field parameters during the fracture formation period and the stress field parameters during the fracture reservoir-controlling period based on the three-dimensional model;

[0075] Predicting the fractures derived from the fracture during the fracture formation period based on the determined paleo-stress field parameters during the fracture formation period, and obtaining the prediction result of the fractures derived from the fracture during the fracture formation period;

[0076] Predicting the fracture opening degree during the fracture reservoir-controlling period based on the stress field parameters during the fracture reservoir-controlling period, and obtaining the prediction result of the fracture opening degree during the fracture reservoir-controlling period;

[0077] Predicting oil and gas reservoirs based on the prediction result of the fractures derived from the fracture during the fracture formation period and the prediction result of the fracture opening degree during the fracture reservoir-controlling period.

[0078] Optionally, the seismic data volume includes a two-dimensional seismic data volume and a three-dimensional seismic data volume.

[0079] Optionally, the paleo-stress field parameters during the fracture formation period include:

[0080] Fracture formation time, azimuth of the principal stress of the paleo-stress field, and value of the principal stress of the paleo-stress field.

[0081] Optionally, the fracture formation time is determined by a balanced profile orthogonal to the fracture, a fracture growth index, and the formation age of the strata involved in the deformation beside the fracture;

[0082] The azimuth of the principal stress of the paleo-stress field is determined by the geometric and kinematic characteristics of the fracture and the fold structure characteristics of this period, and in accordance with Anderson's law, the azimuth of the maximum horizontal principal compressive stress, the azimuth of the minimum horizontal principal compressive stress, and the vertical principal stress azimuth when the fracture is formed in the study area are determined;

[0083] The value of the principal stress of the paleo-stress field is based on the measured data of exploration wells and development wells, and the present-day profiles of the three principal stress values and pore fluid pressure with depth are compiled to obtain a stress-depth profile. Then, the paleo-burial depth when the fracture is formed is determined to obtain a burial depth value, and this burial depth value is projected onto the stress-depth profile to determine the corresponding principal stress value size.

[0084] Optionally, the principal stress value of the paleo-stress field is determined based on the maximum principal compressive stress, the minimum principal compressive stress, and the intermediate principal compressive stress at the time of fracture formation.

[0085] The intermediate principal compressive stress is determined according to the following formula:

[0086] Sv = hρg, where h is the burial depth, ρ is the density of the overlying formation, g is the acceleration due to gravity, and Sv is the intermediate principal compressive stress;

[0087] The minimum principal compressive stress is determined according to the following formula:

[0088] Sh = Sv ×,,

[0089] Sh is the minimum principal compressive stress, is the stress ratio coefficient, and μ is the Poisson's ratio.

[0090] Optionally, the stress field parameters during the fracture-controlled hydrocarbon accumulation period include:

[0091] The fracture-controlled hydrocarbon accumulation time, the orientation of the stress field during the fracture-controlled hydrocarbon accumulation period, and the magnitude of the stress field during the fracture-controlled hydrocarbon accumulation period.

[0092] Optionally, predicting the fracture opening degree during the fracture-controlled hydrocarbon accumulation period based on the stress field parameters during the fracture-controlled hydrocarbon accumulation period to obtain the prediction result of the fracture opening degree during the fracture-controlled hydrocarbon accumulation period includes:

[0093] Predicting the fracture opening degree during the fracture-controlled hydrocarbon accumulation period based on the slip trend. The slip trend is the ratio of the shear stress to the normal stress on a certain fracture plane, and the value of the slip trend is between 0 and 1.

[0094] Optionally, predicting the favorable part of the hydrocarbon reservoir based on the prediction result of the fracture-derived fractures during the fracture formation period and the prediction result of the fracture opening degree during the fracture-controlled hydrocarbon accumulation period, the favorable part of the hydrocarbon reservoir is:

[0095] The intersection area of the high-value area of the fracture density of the fractures derived during the fracture formation period in the prediction result of the fracture-derived fractures during the fracture formation period and the high-value area of the fracture slip coefficient during the hydrocarbon accumulation period in the prediction result of the fracture opening degree during the fracture-controlled hydrocarbon accumulation period.

[0096] Example 1:

[0097] As Figure 1 and Figures 2a to 2f shown,

[0098] 1. 3D model of the fracture structure in the study area:

[0099] The strike of faults often varies, and the strata penetrated upward and downward may also be different, as well as their dips. All these variations need to be characterized in three-dimensional space, and the three-dimensional model of fault structures is very important. For faults developed in sedimentary basins, two-dimensional and three-dimensional seismic data volumes are the data that must be used in the modeling process. Obviously, three-dimensional seismic data volumes are superior to two-dimensional seismic data volumes.

[0100] 2. Determination of paleo-stress field parameters during fault formation

[0101] Determination of fault formation time: The fault activity period can be determined through balanced profiles orthogonal to the fault, fault growth indices, the ages of strata involved in deformation beside the fault, etc.

[0102] Determination of the azimuths of principal stresses in the paleo-stress field: The azimuths of the maximum horizontal principal compressive stress, the minimum horizontal principal compressive stress, and the vertical principal stress during fault formation in the study area can be determined according to Anderson's law through the geometric and kinematic characteristics of the faults of this period and the characteristics of fold structures.

[0103] Determination of the magnitudes of principal stress values in the paleo-stress field: First, based on the measured data of exploration wells and development wells, depth profiles of the current three principal stress values and pore fluid pressure are compiled; secondly, the paleo-burial depth during fault formation is determined; this burial depth value is projected onto the previously compiled stress-depth profile to determine the corresponding principal stress value magnitudes. The determined principal stress values are only preliminary references; finally, stress value data from the acoustic emission Kaiser effect and triaxial stress test data also need to be referred to for determination.

[0104] 3. Prediction of fracture-derived fractures during fault formation

[0105] Fractures close to faults are usually derived from the faults, which is a fact recognized by the academic community, such as T-joints, R-joints formed along the main strike-slip faults. It is also often seen in the field that the fracture density is greater closer to the fault, and on the contrary, the fracture density is sparser the farther away from the fault. The reason lies in the change of the stress field near the fault. Even under the action of the regional stress field, when the regional stress field is transmitted to the vicinity of the fault, the regional stress field is disturbed, and stress concentration and stress shadow phenomena will occur near the fault.

[0106] 4. Determination of stress field parameters during fault-controlled hydrocarbon accumulation

[0107] 5. Prediction of fault opening degree during fault-controlled hydrocarbon accumulation

[0108] The methods for calculating the fault opening degree are extremely limited. Among them, the relatively well-known method is the fault gouge smear coefficient method for clastic rocks. However, for carbonate rock strata, currently only the stress azimuth method can be used.

[0109] According to the stress orientation method, the factors leading to the reactivation of early-stage (fracture formation stage) fractures are the orientation of the maximum horizontal principal compressive stress during the hydrocarbon accumulation control period and the magnitude of its stress. When the angle between the orientation of the maximum horizontal principal compressive stress and the fracture strike is smaller and reaches a certain stress value, the early-stage fractures are more likely to open. The opening degree of the fractures formed in the early stage during the hydrocarbon accumulation period can be evaluated using the parameter of slip tendency proposed by predecessors. The slip tendency refers to the ratio of the shear stress (τ) to the normal stress (σn) on a certain fracture surface. This value ranges between 0 and 1, and the higher the value, the greater the possibility of slip (shear failure) on the fracture surface.

[0110] 6. Hydrocarbon Reservoir Prediction

[0111] The favorable areas for hydrocarbon reservoir development are the intersection areas of the high-value areas of fracture-derived fracture density during the fracture formation stage and the high-value areas of fracture slip coefficient during the hydrocarbon accumulation stage.

[0112] Example Two:

[0113] As Figure 3 shown, the grayscale shows the elevation of the top surface of the Yijianfang Formation in the Ordovician. Negative values indicate below the sea level of the tectonic surface. In addition, faults and mining rights lines are also shown in the structure map, where the faults are shown as tortuous gray lines and the mining rights lines are shown as gray wireframes. Figure 3 The Figure 4a and Figure 4b two profiles in Figure 7 and Figure 8 are marked, and the Figure 7 location is within the dotted-line frame where Well Shunbei 5 and Well Shunbei 5-3 are located. Figure 8 The location is larger than the Figure 7 range and encompasses the solid-line frame where Well Shunbei 5, Well Shunbei 5-3, and Well Shunbei 1 are located. The profile location is shown by the dotted line in Figure 3 . The fault plane location is shown in Figure 7 . The fault model is established based on the interpretation of 3D seismic data. The well location of Well Shunbei 5-3 is shown in Figure 3 , Figure 7 and Figure 8 . Figure 7 The Figure 3 plane location is shown by the black dotted-line frame in Figure 8 . The dotted frames in this figure are areas with relatively large fracture density, and the lighter-colored parts reflect areas with large fracture density. The calculation results of fracture density are based on the Mohr-Coulomb failure criterion under tectonic stress. Figure 3The black solid line frame shows the display result of the coherence attribute in gray scale. The darker the color, the greater the difference between geological bodies. The short black solid lines are the en echelon fractures shown by the coherence attribute and are further marked. These en echelon fractures reflect the movement characteristics of these en echelon fractures (the arrows show the movement direction), and thus reflect the azimuth of the action of the maximum principal compressive stress (σ1) in the area.

[0114] There are multiple shear strike-slip fault zones developed on the Shuntuogole Low Uplift between the Tabei Uplift and the Tazhong Uplift in the Tarim Basin. A large number of oil and gas reservoirs have been found in the Ordovician carbonate rock series within these fault zones. Their reservoirs are jointly controlled by faults, fractures and karst, which are called fault-karst bodies in the industry. This feature is not only manifested in the loss of drilling fluid when drilling through these faults, but also in the rapid decline of oil and gas production away from the faults. However, there is not oil and gas everywhere within the fault zone, and the distribution of high-quality and efficient fault-controlled reservoirs and their oil and gas saturation levels are still unclear. In order to reveal the distribution law and controlling factors of oil and gas reservoirs in the fault zone and improve the drilling success rate in the exploration stage, the distribution locations of oil and gas reservoirs in the Shunbei 5 well area were predicted.

[0115] Regional geological background

[0116] On the current tectonic map of the Lower Paleozoic, the Shuntuogole Low Uplift is lower than the Tazhong Uplift and the Tabei Uplift on its north and south sides, showing a depression within a uplift; at the same time, the east and west sides of the Shuntuogole Low Uplift are adjacent to the Manjiaer Depression and the Awati Depression, and it is also a uplift within a depression. The Lower Paleozoic strata are saddle-shaped on the current tectonic map. See Figure 3 , Figure 4a and Figure 4b .

[0117] The Cambrian-Ordovician strata developed on the Shuntuogole Low Uplift are relatively complete, and are a sedimentary system of inner-platform, margin and slope of marine carbonate rocks. The tectonic deformation is relatively weak, and the development of shear strike-slip faults is the main feature of its tectonic deformation. Among them, the Shunbei 5 fault zone, from south to north, shows NE and NNE trends and gradually turns to NNW trend, with a total extension of more than 300 kilometers. The Shunbei 5 well area is in the compression section of the strike-slip fault zone. According to the drilling results of the Lower Paleozoic in the Shunbei 5 well, the well drilled through the Santamu Formation (O3s), Lianglitag Formation (O3l), Qerbake Formation (O3q), Yijianfang Formation (O2yj) and Ying Mountain Formation (O 1-2y) Upper part. The Ordovician encountered in other exploration wells on the Shuntuogole Low Uplift is generally similar to that in Well Shunbei 5, indicating that the tectonic movement was not intense during the Early Paleozoic in the Well Shunbei 5 area and even the entire Shuntuogole Low Uplift. However, the existence of internal fault structures in the Lower Paleozoic indicates that the tectonic movement in the Shuntuogole Low Uplift was mainly concentrated in the fault zones. It is precisely the existence of these fault zones that makes it a favorable place for oil and gas migration and accumulation. From the current exploration and development situation, oil and gas reservoirs are mainly developed in the Yingshan Formation of these fault zones.

[0118] 3D Structural Modeling

[0119] To achieve the purpose of fracture prediction, fine interpretation was carried out on the east-west survey lines at 25-meter intervals in the Well Shunbei 5 area, and a total of 150 survey lines were interpreted for faults and horizons. This model contains 38 fault planes. In addition, it also contains 8 stratigraphic interfaces, namely, from top to bottom: the top surface of the Ordovician (T7 0 ), the top surface of the Yijianfang Formation (T7 4 ), the top surface of the lower section of the Yingshan Formation (T7 6 ), the top surface of the Penglaiba Formation (T7 8 ), the top surface of the Upper Cambrian (T8 0 ), the top surface of the Middle Cambrian (T8 1 ), the top surface of the Lower Cambrian (T8 3 ), and the top surface of the Proterozoic (T9 0 ).

[0120] Since the establishment of the fault model is related to the accuracy of fracture prediction, when interpreting these 38 fault planes on each seismic profile, both the original amplitude profile and the corresponding maximum curvature profile were referred to, so as to reflect as accurately as possible the scale of the vertical extension of the faults, the horizons penetrated, and the intersection relationships between the faults such as Figure 5a and Figure 5b .

[0121] Judging from the results of fault interpretation, faults can be divided into primary and secondary faults. There are two main fault planes (F1 and F2 in Figure 5a and Figure 5b ), located on the southeast side and northwest side of the Well Shunbei 5 area respectively. Against the overall NNW trend background, the two main faults bend eastward and westward respectively at their overlapping sections. These two main faults cut down into the Precambrian basement and cut through the top surface of the Yijianfang Formation (T7 4 ), but did not cut through the top surface of the Ordovician (T7 0 ). The east-west two main faults have a relatively high angle in the Cambrian and a gentler dip angle in the Ordovician, and dip towards the area between them ([[]] Figure 5a and Figure 5b)。In the plane, two major faults are arranged in the left row spatially, and a part of them overlap and juxtapose each other. In the spatial overlapping part between the two, the Ordovician is deformed to form a domed anticline with an aspect ratio of approximately 1.5:1, and the long axis is consistent with the fault strike, indicating that the area between the two major faults is a tectonic compression zone. The two major faults in the left row also have the characteristics of compression, reflecting the right-lateral strike-slip characteristics of the major faults in the Shunbei-5 Well Area.

[0122] Secondary faults are developed on both sides of these two major faults. Most of these secondary faults converge downward to the major faults and incline towards their respective major faults, reflecting that these secondary faults branch from the major faults ( Figure 5a and Figure 5b ). They break through the top surface of the Yijianfang Formation (T7 4 ), and individual branched faults can break through the top surface of the Ordovician (T7 0 )( Figure 5a and Figure 5b ).

[0123] In addition, there are also a small number of smaller independent faults developed between the top surface of the Yijianfang Formation and the top surface of the Ordovician (between T7 4 and T7 0 ) in the Santamu Formation series. These are rootless faults ( Figure 5a and Figure 5b ).

[0124] Determination of paleostress field parameters during the fault formation period

[0125] Determination of the fault formation time:

[0126] Judging from the horizons broken through by the faults in the Shunbei-5 Well Area, since the major and minor faults as well as the anticline structure are mainly developed in the Lower Paleozoic Cambrian-Ordovician System, especially below the T7 4 interface, overall, the fault structure was mainly formed in the Middle Caledonian period. Of course, the deformation was not completed in one go. Judging from the entire Caledonian period tectonic background of the Tarim Basin, the basin compression started from the end of the Middle Ordovician when the Paleo-Kunlun Ocean subducted. This was first manifested in the unconformity characteristics of the anticlinal uplift strata in the Central Tarim and the Northern Tarim. The strike-slip faults developed between and even on the two uplifts were likely the result of the tearing of the basin cover layer due to the difference in the shortening amount in the plane during the further shortening process of the basin cover layer.

[0127] Azimuth of the maximum principal compressive stress during the fault formation period - Middle Caledonian

[0128] As mentioned above, the established tectonic model of the Shunbei-5 Well Area contains 38 faults and is restricted between the top surface of the Ordovician (T7 0 ) and the bottom surface of the Cambrian (T9 0) After the model is built, an external force (tectonic stress) is applied to the model. The orientation and magnitude of the external force are related to the accuracy of the final fracture prediction, which requires an appropriate estimated value based on the characteristics of the entire regional structure.

[0129] As mentioned above, the fracture zone in the Shunbei-5 well area is a right-lateral shear strike-slip fault with a mid-Caledonian age. Since the strike of the Shunbei-5 well area fracture zone is about 350°, from the mechanical mechanism of the formation of the Shunbei-5 well area fracture zone, the maximum principal compressive stress is between 350° and 80°. Considering that the force source comes from the West Kunlun Mountains, the maximum compressive stress can be limited between 0° and 80°. However, this range is still too broad. It is best to have other data to further narrow the range of the maximum principal compressive stress orientation. At this time, the Shunbei-1 fracture zone on the east side of the Shunbei-5 fracture zone can be considered.

[0130] The Shunbei-1 fracture zone is a relatively large-scale secondary strike-slip fracture zone branching out from the Shunbei-5 fracture zone, trending about NE45° ( Figure 3 ). It was formed in the same period as the Shunbei-5 fracture zone in the Caledonian period, but its strike-slip direction is left-lateral. Judging from the mechanical mechanism of the formation of the Shunbei-1 fracture zone alone, the orientation of the principal compressive stress formed is between 255° and 45°. Since these two fracture zones were formed in the same tectonic stress field, considering both fracture zones, the maximum principal compressive stress in the Caledonian period is approximately between 0° and 45°. During numerical simulation, four different maximum principal compressive stress orientations of 0°, 10°, 20°, and 30° were taken within this range for simulation. By comparing the fractures generated under the action of the maximum principal compressive stress in these four orientations with the actual well fractures, the maximum principal compressive stress orientation with the best fracture fitting was finally selected.

[0131] Well Shunbei-5-3 is the only exploration well with imaging logging data in the Shunbei-5 well area. Logging interpretation shows that the fractures in the Yingshan Formation of this well are mainly NNW-trending, with a total of 24 ( Figure 6a ). Figure 6a The main trunk fracture is Figure 5b the F2 fracture in Figure 6a . The fractures in Figure 6b are secondary fractures beside the main trunk fracture. Well Shunbei-5-3 is located between the main trunk fracture and the secondary fracture. In the inclined well section of the imaging logging, the small discs distributed along the well trajectory (black line) are the attitude projections of each fracture. Figure 6c 、 Figure 6d show the fitting degree between the true fracture attitude in the well and the fracture orientations simulated by the maximum principal compressive stress orientations of 0°, 10°, and 20°. In the figure, the abscissa is the fitting degree, with the highest value being 1, and the ordinate is the number of fractures reaching a certain fitting degree. It can be clearly seen that Figure 6bThe histogram in shows that there are more fractures with a high degree of fitting between the two, so it can be considered that the 0° azimuth is the most likely tectonic stress azimuth in the middle Caledonian period.

[0132] Magnitude of the maximum principal compressive stress during the fracture formation period - Middle Caledonian

[0133] According to the Anderson fracture formation model, when a strike-slip fracture forms, the maximum principal compressive stress (σ1) and the minimum principal compressive stress (σ3) are in a horizontal plane, while the intermediate principal compressive stress (σ2) is in the direction perpendicular to this plane.

[0134] The intermediate principal compressive stress in the vertical direction is relatively easy to determine. Generally, this value is equivalent to the lithostatic pressure. During the Middle Caledonian period, the burial depth of the Yingshan Formation was not very deep. If the burial depth (h) of the Yingshan Formation is calculated as 100 m and the density (ρ) of the overlying strata is calculated as 2300 kg / m3, then the lithostatic pressure at a depth of 100 m is:

[0135] Sv = σ2 = hρg

[0136] = 100 (m) × 2300 (kg / m3) × 9.8 (N / kg)

[0137] ≈ 2300000 N / m2

[0138] ≈ 2.3 MP

[0139] If 2.3 MP is taken as the magnitude of the intermediate principal compressive stress in the vertical direction during the Middle Caledonian period, the minimum principal compressive stress (Sh) located in the horizontal plane should be less than 2.3 MP, and its value can be determined by the following formula:

[0140] Sh = σ3 = Sv × v,

[0141] where Sh is the minimum principal compressive stress in the horizontal direction, Sv is the intermediate principal compressive stress in the vertical direction, ν is the stress ratio coefficient, and μ is the Poisson's ratio. Here, μ = 0.6 is taken, and the value of Sh is 1.5 MP. According to the measured data of present-day in-situ stresses, generally, the maximum principal compressive stress is less than 5 times the minimum principal compressive stress, even for the measured data at the edge of the Qinghai-Tibet Plateau. If the magnitude of the maximum principal compressive stress is calculated as 5 times the minimum principal compressive stress, its value is 7.5 MP. During numerical simulation, a tectonic stress of 7.5 MP was applied in the azimuth of the maximum principal compressive stress at 0°.

[0142] Prediction of fractures derived from faults during the fracture formation period

[0143] Under the action of tectonic stress, T7 0 to T9 0The various 3D simulation results related to rock mechanics in different strata, among which the most important ones are the simulation results of fracture density and fracture discrete network model. This embodiment only shows the fracture density simulation results of the key strata that can be technically exploited in the Yijianfang Formation and the upper section of the Ying Mountain Formation.

[0144] Figure 7 It is the plane distribution map of fracture density at the top surface of the upper section of the Ying Mountain Formation. The change of stress value shows that the stress decreases in some areas and increases in some areas. The areas where the stress increases are the two ends of the fracture and the parts where two fractures approach each other. From Figure 7 it can be seen that on the north side of Well Shunbei 5-3 ( Figure 7 Area A in it), on the north side of Well Shunbei 5 ( Figure 7 Area B in it) and on the south side ( Figure 7 Area C in it), the fracture density is relatively high, especially in the area on the south side of Well Shunbei 5 ( Figure 7 Area C in it) where the fracture density is better.

[0145] Determination of stress field parameters during the fracture-controlled hydrocarbon accumulation period

[0146] Determination of the fracture-controlled hydrocarbon accumulation time

[0147] Fracture-controlled hydrocarbon accumulation means that hydrocarbon migration and accumulation occur after the formation of fractures, and the formed fractures are reactivated. Many en-echelon fractures are developed on the top surface of the Permian in the Well Shunbei 5 area, indicating that after the formation of the fractures in the middle Caledonian period, they were reactivated in the late Hercynian period ( Figure 8 ). At the same time, based on the achievements of reservoir researchers, it is considered that the hydrocarbon accumulation period of Well Shunbei 5 where oil has been produced is also the late Hercynian period, indicating that the hydrocarbon migration and accumulation period and the fracture activity period are matched, so the fractures control hydrocarbon migration and accumulation.

[0148] Determination of the stress field orientation during the fracture-controlled hydrocarbon accumulation period

[0149] During the middle and late Hercynian periods, the Well Shunbei 1 fault zone and the Well Shunbei 5 fault zone moved left simultaneously, indicating that the maximum principal stress direction deflected to the NNW direction. At this time, the maximum principal stress intersects at a small angle or is approximately parallel to the NNW section in the 3D area of the Well Shunbei 5 fault zone. Therefore, the shear activity of this section is weak, and the developed scale of the en-echelon normal faults formed is small, and its en-echelon angle is less than 10°, indicating that the maximum principal stress direction at this stage is approximately parallel to the deep strike-slip fault.

[0150] Determination of the stress field magnitude during the fracture-controlled hydrocarbon accumulation period

[0151] In the late Hercynian period, the burial depth of the upper part of the Ying Mountain Formation is 3500m. Similar to the algorithm of vertical stress during the fracture formation period, at this time, σ2 is the vertical stress = 72.5MP, σ1 is the maximum horizontal stress = 89.6MP, and σ3 is the minimum horizontal stress = 55.5MP.

[0152] Prediction of fracture opening degree during the fracture-controlled hydrocarbon accumulation period

[0153] As Figure 8 shown, generally, the high - value regions of the slip trend are near Well Shunbei 5 ( Figure 8 in Area A) and Figure 8 several faults in Area B have relatively high slip trends, and these faults are more likely to open during the hydrocarbon reservoir controlling period.

[0154] Hydrocarbon reservoir prediction

[0155] Based on the research results of fracture prediction during the fracture formation period and the fracture opening degree during the hydrocarbon reservoir controlling period mentioned above, the intersection of the two is Figure 7 In Area C of [], it is the most favorable area for hydrocarbon accumulation, and the later exploration results prove the accuracy of this prediction result.

[0156] Example 3:

[0157] An embodiment of the present invention provides an electronic device including a memory and a processor.

[0158] The memory stores executable instructions;

[0159] The processor runs the executable instructions in the memory to implement a method for constructing a hydrocarbon reservoir prediction.

[0160] This memory is used to store non - transient computer - readable instructions. Specifically, the memory may include one or more computer program products, and these computer program products may include various forms of computer - readable storage media, such as volatile memory and / or non - volatile memory. The volatile memory may include, for example, random access memory (RAM) and / or cache memory, etc. The non - volatile memory may include, for example, read - only memory (ROM), hard disk, flash memory, etc.

[0161] The processor may be a central processing unit (CPU) or other forms of processing units with data - processing capabilities and / or instruction - execution capabilities, and may control other components in the electronic device to perform desired functions. In an embodiment of the present invention, the processor is used to run the computer - readable instructions stored in the memory.

[0162] Those skilled in the art should understand that, in order to solve the technical problem of how to obtain good user experience effects, this embodiment may also include well - known structures such as communication buses, interfaces, etc., and these well - known structures should also be included in the protection scope of the present invention.

[0163] For the detailed description of this embodiment, reference may be made to the corresponding descriptions in the foregoing embodiments, and details will not be repeated here.

[0164] Example 4:

[0165] An embodiment of the present invention provides a computer-readable storage medium, which stores a computer program. When the computer program is executed by a processor, a method for predicting an oil and gas reservoir is implemented.

[0166] According to the computer-readable storage medium of the embodiments of the present invention, non-temporary computer-readable instructions are stored thereon. When the non-temporary computer-readable instructions are run by a processor, all or part of the steps of the methods of the various embodiments of the present invention described above are executed.

[0167] The above computer-readable storage medium includes, but is not limited to: optical storage media (such as CD-ROMs and DVDs), magneto-optical storage media (such as MOs), magnetic storage media (such as magnetic tapes or external hard drives), media with built-in rewritable non-volatile memories (such as memory cards), and media with built-in ROMs (such as ROM cartridges).

[0168] The various embodiments of the present invention have been described above. The above description is exemplary and not exhaustive, and is also not limited to the disclosed embodiments. Many modifications and variations are obvious to those of ordinary skill in the art in the technical field without departing from the scope and spirit of the described embodiments.

Claims

1. A method for predicting hydrocarbon reservoirs, characterized in that, Including: Constructing a three-dimensional model of the fault structure in the study area based on the acquired seismic data volume; Determining the paleo-stress field parameters during the fault formation period and the stress field parameters during the fault hydrocarbon-controlling period based on the three-dimensional model; Predicting the fracture-derived fractures during the fault formation period based on the determined paleo-stress field parameters during the fault formation period to obtain the prediction result of the fracture-derived fractures during the fault formation period; Predicting the fracture opening degree during the fault hydrocarbon-controlling period based on the stress field parameters during the fault hydrocarbon-controlling period to obtain the prediction result of the fracture opening degree during the fault hydrocarbon-controlling period; Predicting hydrocarbon reservoirs based on the prediction result of the fracture-derived fractures during the fault formation period and the prediction result of the fracture opening degree during the fault hydrocarbon-controlling period.

2. The method for predicting a hydrocarbon reservoir structure according to claim 1, wherein The seismic data volume includes two-dimensional seismic data volume and three-dimensional seismic data volume.

3. The method for predicting a tectonic hydrocarbon reservoir according to claim 1, wherein The paleo-stress field parameters during the fault formation period include: Fault formation time, azimuth of the principal stress of the paleo-stress field, and value of the principal stress of the paleo-stress field.

4. The method for predicting a tectonic hydrocarbon reservoir according to claim 3, wherein The fault formation time is determined by the balanced profile orthogonal to the fault, the fault growth index, and the formation age involved in the deformation beside the fault; The azimuth of the principal stress of the paleo-stress field is determined by the geometric, kinematic characteristics and fold structure characteristics of the faults in this period, and in accordance with Anderson's law, the azimuth of the maximum horizontal principal compressive stress, the azimuth of the minimum horizontal principal compressive stress, and the azimuth of the vertical principal stress when the faults in the study area are formed are determined; For the value of the principal stress of the paleo-stress field, based on the measured data of exploration wells and development wells, depth profiles of the three principal stress values and pore fluid pressure are compiled to obtain a stress-depth profile, and then the paleo-burial depth when the fault is formed is determined to obtain a burial depth value, and this burial depth value is projected onto the stress-depth profile to determine the corresponding magnitude of the principal stress value.

5. The method for predicting a hydrocarbon reservoir structure according to claim 3, characterized in that The value of the principal stress of the paleo-stress field is determined based on the maximum principal compressive stress, the minimum principal compressive stress, and the intermediate principal compressive stress when the fault is formed. The intermediate principal compressive stress is determined according to the following formula: Sv = hρg, where h is the burial depth, ρ is the density of the overlying formation, g is the acceleration due to gravity, and Sv is the intermediate principal compressive stress; The minimum principal compressive stress is determined according to the following formula: Sh = Sv × v, Sh is the minimum principal compressive stress, v is the stress ratio coefficient, and μ is the Poisson's ratio.

6. The method for predicting a hydrocarbon reservoir structure according to claim 1, characterized in that, The stress field parameters during the fault hydrocarbon-controlling period include: Fault hydrocarbon-controlling time, azimuth of the stress field during the fault hydrocarbon-controlling period, and magnitude of the stress field during the fault hydrocarbon-controlling period.

7. The method for predicting a hydrocarbon reservoir structure according to claim 1, characterized in that, The predicting the fracture opening degree during the fault hydrocarbon-controlling period based on the stress field parameters during the fault hydrocarbon-controlling period to obtain the prediction result of the fracture opening degree during the fault hydrocarbon-controlling period includes: Predicting the fracture opening degree during the fault hydrocarbon-controlling period based on the slip trend. The slip trend is the ratio of the shear stress to the normal stress on a certain fault plane, and the value of the slip trend is between 0 and 1.

8. The method for predicting a tectonic hydrocarbon reservoir according to claim 1, wherein In the predicting hydrocarbon reservoirs based on the prediction result of the fracture-derived fractures during the fault formation period and the prediction result of the fracture opening degree during the fault hydrocarbon-controlling period, the favorable part of the hydrocarbon reservoir is: The intersection area of the high-value area of the fracture density of the fracture-derived fractures during the fault formation period in the prediction result of the fracture-derived fractures during the fault formation period and the high-value area of the fracture slip coefficient during the hydrocarbon accumulation period in the prediction result of the fracture opening degree during the fault hydrocarbon-controlling period.

9. An electronic device, characterized in that, The electronic device includes: A memory storing executable instructions; A processor that runs the executable instructions in the memory to implement the method for predicting hydrocarbon reservoir construction according to any one of claims 1-8.

10. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores a computer program, and when the computer program is executed by a processor, it implements the method for predicting the structure of an oil and gas reservoir according to any one of claims 1-8.

Images