(1. China Petroleum Exploration and Development Research Institute, Beijing100083; 2. China Youshi University (Beijing) School of Resources and Information, Beijing 102249)
In order to deeply study the reservoir-forming mechanism of Ying 1 1 lenticular sandstone reservoir in Dongying Depression and master the main influencing factors of this kind of reservoir-forming, the two-dimensional numerical simulation of its reservoir-forming process was carried out by using the basic principle of oil-water two-phase seepage in compressible porous media. In the simulation process, a series of processes and parameters such as stratum deposition (erosion), stratum thickness change, rock porosity and permeability condition change, fluid physical properties change, capillary pressure, relative permeability and oil and gas generation are considered. The accumulation process of oil in sand body is simulated and reproduced, and the final oil saturation and distribution of simulated sand body are basically consistent with the actual situation. The simulation analysis shows that the capillary pressure difference between surrounding rock and sand body is the fundamental driving force of oil accumulation in lenticular sandstone reservoirs such as Ying 1 1, which is formed by the physical differences between surrounding rock and sand body and the joint action of oil and gas generation.
Numerical simulation of accumulation process of lenticular sandstone reservoir: Two-phase flow; Capillary pressure; Dongying sag
Two-dimensional numerical simulation of trapping process in Ying 1 1 lenticular sandstone reservoir in Dongying sag
Xie Guozhong -jun 1, 2, Jinzhi -jun 1
(1. China Petrochemical Exploration and Development Research Institute, Beijing100083; 2. School of Resources and Communication, China Shiyou University, Beijing 102249)
In order to deeply study the reservoir-forming mechanism of Ying 1 1 lenticular sandstone reservoir in Dongying Depression and master the main influencing factors of this kind of reservoir, based on the two-phase flow theory of dense porous media, the reservoir-forming process of this kind of reservoir was simulated by two-dimensional numerical simulation. Various related processes and parameters considered in the simulation process are deposition/denudation, formation thickness, porosity and permeability of rocks, physical properties of fluids, capillary pressure, relative permeability and oil generation. The simulation reproduces the reservoir-forming process, and the oil saturation and distribution are in line with the actual situation. It is pointed out that the basic driving force of reservoir formation in British 1 1 sandstone reservoir is the capillary pressure difference between source rock and reservoir, which is the result of the difference of physical properties between source rock and reservoir and the joint action of oil generation.
Keywords numerical simulation of lenticular sandstone reservoir formation process capillary pressure of two-phase fluid flow Dongying sag
Primary lenticular sand body reservoir is a typical sandstone lithologic reservoir, which is generally formed by turbidite sand body surrounded by low permeability shale, and the oil and gas in the sand body comes from the surrounding source rocks. Ying 1 1 sand body reservoir in Dongying sag is a typical example of this kind of reservoir. Because it is completely surrounded by mudstone, the oil-water alternation mechanism formed by this reservoir is different from that of structural or stratigraphic reservoirs. There have been many beneficial experimental studies and theoretical explorations on the reservoir-forming mechanism and influencing factors of such sand bodies. Chen Zhangming et al. [1] and Li Pilong et al. [2] analyzed the accumulation process and influencing factors of primary lithologic sand bodies through the physical simulation experiment of reservoir formation. Wang Ning and others considered two factors: reservoir-forming power and resistance during the formation of lithologic oil and gas reservoirs [3]: Pang et al. analyzed the reservoir-forming control conditions of sandstone lens from the perspective of reservoir-forming threshold [4]. Li Pilong and others put forward the theory of "phase" and "potential" oil control, and analyzed the formation mechanism of subtle reservoirs including lenticular sand body reservoirs [5]. Sui Fenggui quantitatively analyzed the main controlling factors of oil and gas accumulation in turbidite sand bodies [6].
However, both the above experimental research and theoretical analysis are basically qualitative or semi-quantitative discussions on the reservoir-forming mechanism of this kind of reservoirs, or only the oil-bearing related factors of this kind of reservoirs are analyzed, and the reservoir-forming mechanism is not involved, so it is impossible to understand the whole process and control mechanism of primary lithologic reservoirs in more detail. Because the accumulation process of lenticular reservoir is closely related to its surrounding rock, the evolution process of sand body and surrounding rock must be considered together to understand the accumulation process of sand body. In this paper, from the perspective of evolution, the whole process of reservoir formation in Ying 1 1 surrounding rock lenticular reservoir is simulated quantitatively, and the reservoir formation mechanism and main controlling factors of oil-bearing property are analyzed. Through the two-dimensional numerical simulation of the reservoir-forming process, we can deeply understand the oil-water alternation process and its mechanical mechanism in this kind of reservoir-forming process, which provides a good example for discussing the reservoir-forming mechanism and its influencing factors.
1 Establishment of simulation model
The formation of Ying 1 1 lenticular sandstone reservoir involves the deformation of surrounding rock and sand body caused by compaction and the flow of oil-water two-phase fluid in it. The deformation of rock and the flow of fluid are interactive, so this is a fluid-solid coupling problem of two-phase flow in deformed porous media.
Compared with secondary migration, it is always an incomprehensible phenomenon that low permeability source rocks expel oil and gas (primary migration). Judging from the phase state of oil and gas discharged from source rocks, it is generally believed that most oil and gas are discharged through independent phase state [7], and the main driving force of oil and gas discharge comes from excess formation pressure caused by compaction and hydrocarbon generation [7 ~ 9]. According to Darcy's law, a general method to describe the low-speed flow of fluid in porous media is given. Although it is doubtful whether Darcy's law is applicable in low permeability shale formation, it is widely used in various hydrocarbon expulsion simulations as an effective means to describe the relationship between pore fluid flow velocity and pressure [10 ~ 13]. In order to simulate the process that oil is discharged from the source rock and accumulated in the surrounding sandstone, the oil-water two-phase seepage model based on Darcy's law is also adopted in this simulation. The pressure difference between oil phase and water phase in the model is capillary pressure.
The relationship between strain and stress can be deduced from the generalized Hooke's law of elasticity of homogeneous media. However, for the simulation of geological process, stratum compaction is different from the small deformation process described in elastic mechanics, and it is a large inelastic deformation process for a long time. The geological description of this process generally adopts an approximate simplified relationship, that is, this deformation is transformed into an exponential relationship between rock porosity and its vertical effective stress [13 ~ 15]. According to Karl Terzaghi equation, the vertical effective stress can be expressed by the difference between the total rock load and the pore fluid pressure [10, 16].
Oil-source mudstone can be regarded as composed of kerogen, inorganic heterobase and pores, in which kerogen and inorganic heterobase constitute the skeleton of oil-source rock. In order to deal with the problem simply, kerogen can be divided into effective kerogen (which has oil-generating potential and can be completely converted into petroleum) and invalid kerogen (which has no oil-generating potential). Therefore, the source rocks can be subdivided into three parts, namely, effective kerogen, incompressible skeleton (including invalid kerogen and inorganic hetero-group) and pores. The model assumes that effective kerogen degradation will produce hydrocarbons of the same quality and reduce the thickness of mudstone skeleton. According to the principle that the volume of incompressible skeleton is constant, the thickness change of rock can be obtained. For sandstone reservoirs, the change of skeleton thickness caused by effective kerogen degradation can be ignored. Hydrocarbons in source rocks are the result of thermal degradation of kerogen, which is approximately described by the first-order reaction law in chemical reaction kinetics [17]. According to the first-order reaction law, the conversion rate of kerogen is directly proportional to the residual amount of kerogen, which can be expressed as multiple parallel first-order reactions. The reaction constant is determined by reaction activation energy, frequency factor and reaction temperature. Assuming that kerogen with the same quality can be effectively degraded to produce oil with the same quality, the rate of oil generation is also the degradation rate of kerogen.
2. Changes in relevant parameters
The density of water and oil is a function of temperature and pressure, which can be described by the exponential equation of state [13]. The viscosity of water and oil is a parameter that affects the seepage of water and oil. Generally, the viscosity of water is a function related to temperature [13, 18], and the Beggs-Robinson formula [19] considering the gravity and temperature of oil is adopted in this simulation.
The permeability of sedimentary rocks plays an important role in the flow of formation fluid and the formation of abnormal pressure. Generally affected by sedimentary rock types, buried depth and other factors, the size sometimes differs by several orders of magnitude. For clastic rocks, in general, the change of permeability can be expressed as a function of porosity, such as Kozeny-Carman equation [10, 18]. In this simulation, the formula [13,20] with a power function relationship between permeability and porosity is adopted.
In a seepage system containing two or more immiscible fluids, it is necessary to consider the capillary pressure characteristics of rocks. Because the simulation basically deals with the process of oil generation, oil drainage and reservoir formation, only the characteristics of displacement capillary pressure curve of rocks need to be considered. The formula [2 1] adopted in this simulation study is a power law relationship between displacement capillary pressure and water saturation:
Oil and gas accumulation theory and exploration and development technology
Among them: Pcb is capillary breakthrough pressure; γ is the pore size distribution index; Sw is water saturation. The capillary radius corresponding to the breakthrough pressure can be expressed by its empirical relationship with porosity and permeability [22]. According to Laplace equation, capillary pressure is a function of interfacial tension, wetting angle and capillary radius. The interfacial tension of water-hydrocarbon system can generally be expressed as a function of system temperature and oil-water density [19]. In addition, this simulation assumes that the rock is completely wetted by water, and the wetted contact antenna is 0. Therefore, the breakthrough pressure Pcb of rock capillary can be obtained. If the capillary pressure curve needs to be displaced, the pore size distribution index needs to be determined. The mercury injection curve fitting analysis of 28 sandstone samples in Dongying Depression shows that the pore size distribution index is basically a parameter independent of physical parameters such as rock porosity and absolute permeability, and the average value of this simulation is 0.34. The same breakthrough capillary pressure formula and pore size distribution index value are also used for mudstone in this reservoir-forming simulation.
The relative oil-water permeability is expressed by Brooks-Corey empirical relation [13,2122], in which the relative oil-water permeability is related to water saturation and pore size distribution index.
Simulation of Accumulation Process of Sanying 1 1 Sandstone Reservoir
3. Overview of1camp 1 1 sandstone reservoir
Ying 1 1 sandstone reservoir is located in the southwest of Dongxin Oilfield in Dongying Depression, adjacent to Jiahao Oilfield in the west and Xianhezhuang Oilfield in the south. Structurally, it is located in the west of the central uplift belt of Dongying sag, and the center of the sag between Dongxin, Jiahao and Xianhezhuang structural fault zones. This simulation is the middle and lower member of the third member of Shahejie Formation of Ying 1 1 sand body, with proven petroleum geological reserves of 1248× 104t, which is the largest independent sand body reservoir discovered in Dongying Depression so far. See attached figure 1 1 for the structural map of the middle and lower sand bodies in the third member of Ying 1 Shahejie Formation and the position of the simulated section line.
Figure 1 English 1 1 structural map of the top of middle and lower sand bodies in the third member of Shahejie Formation and the position of simulated section line.
3.2 Camp 1 1 Preparation for sandstone reservoir simulation
The preparatory work for simulation includes section gridding, restoration of original sedimentary section, inversion of overlying strata deposition process and determination of parameters of simulated evolution process.
3.2. 1 section gridding
The length of the selected interval takes Ying 75 well as the demarcation point, and the sand body extends 5600 meters upwards, and the sand body extends 2400 meters downwards, with a total interval length of 8000 meters ... The vertical depth of the profile body ranges from 2700 meters (about the bottom interface of the upper third member of Shahejie Formation) to 3600 meters (about the bottom interface of the upper fourth member of Shahejie Formation). From the middle sub-member of Shahejie Formation to the upper sub-member of Shahejie Formation, sandstone deposits gradually dominate. Because sandstone has good conductivity and is not easy to form obvious abnormal pressure, the pressure boundary condition at the top of the profile is considered as positive pressure. The upper member of Shahejie Formation is dominated by downward gypsum mudstone, so the bottom boundary of the upper member of Shahejie Formation can be used as the closed boundary of the section. It can be seen that the section is 8000 meters long and 900 meters high. In grid division, both accuracy and computational workload should be considered. Therefore, the grid should be dense in the length and height direction corresponding to the sand body, while in other places, the grid should be as coarse as possible to reduce the calculation workload.
3.2.2 Restoration of Original Sedimentary Profile
Because the profile shows the current sedimentary thickness and porosity characteristics, it is necessary to restore the profile to the state of simulating zero time in order to simulate the sand body accumulation process forward. The zero time of this simulation is set at the end of sedimentation in the upper third member of Shahejie Formation, so it is necessary to restore the simulated profile from the top of 2700 meters to the zero profile state. The restoration is based on the principle that the bone volume remains unchanged when the stratum is compressed. Formation porosity changes exponentially with depth, and related parameters are obtained by regression of formation data of actual exploration wells in Dongying sag.
3.2.3 Inversion of sedimentary process of overlying strata
Because the reservoir-forming process is a forward simulation process, it is necessary to know the deposition rate of overlying strata in different deposition periods and the content of sandstone and mudstone in the simulation profile. Therefore, we must first understand the thickness of sedimentary strata and the content of sandstone and mudstone. Table 1 gives the formation thickness, sand content and average sedimentation rate of representative wells in Ying 1 1 sand body area. The sand content in the formation is calculated by natural potential or natural gamma logging data; Formation deposition rate refers to the deposition rate of sediments on the deposition surface, which is given according to the content of sand and mudstone in the formation, the thickness and depth of the formation and the deposition duration. At the end of Dongying period, the sedimentary discontinuity was calculated as the Dongying Formation eroded by 200m, and the average erosion rate was obtained according to the sedimentary discontinuity time 10.6Ma.
Table 1 English 1 1 Simulation parameters of overlying strata in sand body
3.2.4 Parameter Determination of Simulated Evolution Process
The paleogeothermal gradient in Ying 1 1 sand body area adopts the paleogeothermal gradient in Dongying Depression, and the paleogeothermal gradients at 43Ma, 38Ma, 36Ma, 32.4Ma, 24.6Ma, 5. 1Ma, 2Ma and 0: 00 are 5.15℃ respectively. 4.61℃100m, 4.49℃/100m, 4.2℃/100m, 4℃/100m, 3.68℃//kloc-.
Parameter values related to sandstone rock compression are obtained by regression of sandstone porosity, depth and effective stress in Dongying sag, while parameter values related to mudstone compression come from Mudford et al [24]. The parameter value in the relationship between sandstone permeability and porosity comes from the data regression of Dongying sag, and the parameter value of mudstone comes from Luohe [13].
The hydrocarbon generation potential of rocks can be defined as the mass ratio of effective kerogen (which can be converted into hydrocarbons) of source rocks to the total amount of rock skeleton, while the original hydrocarbon generation potential refers to the hydrocarbon generation potential of source rocks at the initial time of evolution. S2 value in rock pyrolysis analysis is generally regarded as the hydrocarbon generation potential value of rocks, so to get the hydrocarbon generation potential value of grid rocks, a large number of pyrolysis analysis data of organic rocks in this area are needed, but the reality is that this analysis data in this area is very limited and can not reach the hydrocarbon generation potential value of grid rocks. Therefore, the hydrocarbon generation potential of this simulation grid is calculated by using the logging data of Ying 1 1 sand body area. The δδLgR method based on porosity and resistivity logging data proposed by Passey et al. [25] can be improved to predict the original hydrocarbon generation potential of source rocks in the early stage of evolution. The original hydrocarbon generation potential of grid body is through drilling Ying 1 1 sand body and its adjacent wells Ying 76, Ying1kloc-0/,Ying 102, Xinying 69, Ying 75, Ying 70, Ying 67, Ying 68 and Ying 78. As none of the above wells have drilled into the upper sub-member of Shahejie Formation, the original hydrocarbon generation potential of the upper sub-member of Shahejie Formation in the simulation profile is calculated by He88 and Haoke 1.
Considering that the source rocks of the upper fourth member of Shahejie Formation, the lower third member of Shahejie Formation and the middle third member of Shahejie Formation in Dongying Depression are mainly type I kerogen, the initial kerogen content and frequency factor in the source rocks determined according to the activation energy of reaction are all based on the type I kerogen data provided by Schenk et al.
3.3 Simulation process and result analysis
The simulation of reservoir formation in Ying 1 1 sand body began 38.6Ma ago, that is, the time point of simulation, and then the changes of related parameters of grid body were recorded every 1Ma.
3.3. 1 oil saturation
Fig. 2 shows the distribution of oil saturation in the grid space of 10Ma, 20Ma, 30Ma and 38.6ma..
Fig. 2 Oil saturation of Ying 1 1 sand body simulation profile at four simulation times.
There is obvious oil and gas accumulation in Ying 1 1 sand body, which started at 5 ~ 100 Ma. In the process of formation evolution, oil has been in the state of accumulation in sand bodies, and oil saturation has been increasing, which can be verified by the more detailed trend of oil saturation changing with time. By the end of 38.6Ma simulation, the whole sand body is full of oil, and the average oil saturation is about 73%, which is very close to the actual sand body average oil saturation (69%).
3.3.2 Oil phase pressure and water phase pressure
Fig. 3 shows the distribution of oil-phase pressure and water-phase pressure in the grid space at 30Ma simulation time point. The distribution characteristics of oil-phase pressure and water-phase pressure at this time point basically represent the pressure distribution characteristics at every moment of the whole simulation process, but the absolute magnitude of pressure is different. The overall change trend of oil phase pressure in grid body is that the pressure gradually decreases from deep to shallow. On this overall background, there is a relatively low oil phase pressure area in sand body. The change trend of water phase pressure from deep to shallow is gradually decreasing, and the overall pressure increases with the increase of grid depth.
The analysis of capillary pressure distribution of lattice body shows that there are areas with relatively low capillary pressure in sandstone. According to the fact that the difference between oil-phase pressure and water-phase pressure at the same point in porous media is equal to capillary pressure, we can know that the difference of distribution law between oil-phase pressure and water-phase pressure is caused by the difference of capillary pressure.
3.3.3 Oil potential gradient and water potential gradient
Figure 4 shows the distribution of oil potential gradient and water potential gradient in the grid space at 30Ma time. Among them, the positive value of the potential gradient indicates that the direction of fluid flow is negative to the axis, while the negative value of the gradient indicates that the direction of fluid flow is positive to the axis.
Fig. 3 Distribution of oil phase pressure (left) and water phase pressure (right) at camp 1 1 sand body simulation profile for 30Ma.
Fig. 4 Distribution of oil (above) and water potential gradient (below) at the simulated profile of Ying 1 1 sand body for 30Ma.
The two pictures on the left are horizontal potential gradients, and the two pictures on the right are vertical potential gradients.
Mechanism analysis of 4 reservoir-forming process
Ying 1 1 sand body is a typical lenticular sandstone reservoir surrounded by source rocks, and its oil and gas are derived from hydrocarbons generated by surrounding rocks. There are still some shortcomings in understanding the migration mechanism of oil and water and the process of oil and gas accumulation in this kind of reservoirs. It is generally believed that abnormal high pressure is the main driving force of primary migration of oil and gas. Therefore, it is generally believed that abnormal pressure is the driving force for oil and gas to enter the sand body. However, the fluid in sand body surrounded by source rocks is in the same closed environment as the fluid in rocks, and the porosity of sand body also decreases during the process of stratum settlement and compaction. Therefore, on the whole, the sandstone body also discharges fluid outwards. Therefore, how to understand the migration and accumulation of oil and gas from source rocks to sand bodies is a difficult point in practical understanding.
At present, the general theory of oil and gas migration holds that oil migrates in independent phases, oil and water have their own independent flow paths and pressure systems, and the pressure difference between oil and water at the same point is balanced by capillary pressure between oil and water. Therefore, when understanding the reservoir formation of this kind of lenticular sand body, the pressure difference between source rock and sand body should not be considered from a single fluid phase, but should be considered as a two-phase flow like this simulation.
It can be seen from the distribution of oil phase pressure and the variation characteristics of oil potential gradient in horizontal and vertical directions of Ying 1 1 sand body simulation profile that there is a region with low oil potential relative to surrounding rock in sand body area. The positive and negative oil potential gradient represents the direction of oil flow, so the characteristics of low oil potential in sand body area determine that it must become an oil accumulation area. However, according to the distribution of water phase pressure and the change characteristics of water potential gradient in the simulation area, it can be seen that there is no low potential area of water in the sand body, and the sand body only plays a certain role in disturbing the flow direction of water, but the overall flow direction of water is discharged from bottom to top.
It can be seen that overpressure is the driving force to promote the overall migration of fluid, and for lenticular lithologic sand bodies surrounded by oil-generating surrounding rocks, the capillary pressure difference between surrounding rocks and sand bodies is the fundamental driving force to drive oil and gas to accumulate in them. This driving force is formed by the physical difference between surrounding rock and sand body and the joint action of oil and gas generation.
5 conclusion
(1) Based on the basic principle of oil-water two-phase seepage in compressible porous media, combined with various factors and functions related to oil and gas generation, migration and accumulation, the reservoir-forming process of lenticular sand reservoir similar to Ying 1 1 sand body can be simulated.
(2) According to the distribution characteristics of oil-water phase pressure and oil-water phase potential gradient in surrounding rocks and sand bodies, it can be known that the sand body area becomes a low potential area of oil phase relative to surrounding rocks in the process of reservoir formation, so oil can accumulate in sand bodies, but water has no tendency to accumulate in sand bodies, and its overall migration direction is an upward low potential area.
(3) The basic driving force of reservoir formation in sandstone reservoirs similar to British1/Kloc-0 is the capillary pressure difference between surrounding rock and sand body, which is the inevitable result of the interaction of the physical properties difference between surrounding rock and sand body and the generation of oil in surrounding rock.
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