A method for predicting the degree of geological reserve control in shale oil horizontal well development

Abstract

The present invention discloses a method for predicting the control degree of geological reserves in the development of shale oil horizontal wells, which is specifically as follows: establishing a full life cycle recovery rate prediction model for shale oil horizontal wells; using the basic high-pressure physical property parameters of crude oil and gas and the compression coefficient of rock under different pressures, through the recovery rate prediction model, calculating the recovery rate of the full life cycle of depletion-type development of unsaturated shale oil reservoirs; calculating the recoverable reserves of all horizontal wells in the target block according to the production dynamic data of the target block; calculating the controlled geological reserves of the horizontal wells according to the recoverable reserves and recovery rate of all horizontal wells in the target block; calculating the control degree of geological reserves according to the controlled geological reserves of the horizontal wells and the actual geological reserves, and giving development suggestions according to the control degree of geological reserves. The method of the present invention solves the problems of high prediction difficulty, long cycle and high cost of the existing methods.

Description

Technical Field

[0001] The invention belongs to the technical field of shale oil exploitation and relates to a method for predicting the control degree of geological reserves in shale oil horizontal well development. Background Art

[0002] As an unconventional oil and gas resource, shale oil has become a major strategic resource both internationally and domestically. Due to the low permeability of the reservoir, it is difficult to establish an effective displacement pressure system by injecting water under the economic limit well network. At present, the "horizontal well + volume fracturing" method is usually adopted for quasi-natural energy development. Since the formation energy cannot be effectively supplemented, the production decline in the shale oil development process is large and the recovery rate is low. The geological reserve control degree is the ratio of the geological reserves controlled by the horizontal well to the actual geological reserves. The geological reserve control degree of shale oil horizontal well development is a key indicator for judging whether the development technology policy is reasonable. It is directly related to the design of horizontal well development parameters, including horizontal well length, well spacing, and fracturing parameters. It especially affects the drilling and completion investment and the development benefits of horizontal wells. Through the accurate prediction of the geological reserve control degree, it provides a basis for adjusting the development technology policy and further improving the development effect and benefits of shale oil. The closer the geological reserve control degree is to 100%, the more reasonable the technical policy is. If it is less than 100%, it means that part of the geological reserves are not controlled by horizontal wells, and it is necessary to adjust the well spacing or increase the fracturing scale. If it is greater than 100%, it means that the ability of horizontal wells to control geological reserves exceeds the actual geological reserves, and it is necessary to increase the well spacing or reduce the fracturing scale.

[0003] At present, the degree of geological reserve control is usually measured by numerical simulation. Through the fitting of block geological modeling and numerical simulation, the number of grids to be used is determined according to the change of grid fluid saturation, and the geological reserves in the grids are calculated to achieve the quantification of controlled geological reserves. However, the numerical simulation method requires fine geological modeling and accurate data such as fluids, reservoirs and phase permeability curves. In particular, it is difficult to quantitatively describe the fractures in the geological model after large-scale fracturing, and the accuracy of numerical simulation is also questioned. At the same time, the research cycle of geological modeling and numerical simulation is long and the cost is high. How to quickly and cost-effectively accurately predict the degree of geological reserve control of shale oil horizontal wells is a technical problem that needs to be solved urgently. Summary of the invention

[0004] The purpose of the present invention is to provide a method for predicting the control degree of geological reserves in shale oil horizontal well development, which solves the problems of high prediction difficulty, long cycle and high cost in existing methods.

[0005] The technical solution adopted by the present invention is a method for predicting the degree of geological reserve control in shale oil horizontal well development, which is specifically implemented according to the following steps:

[0006] Step 1: Establish a shale oil horizontal well recovery rate prediction model for the entire life cycle;

[0007] Step 2, using the basic high-pressure physical properties of formation crude oil and gas and the average pore volume compressibility of rocks, and the shale oil horizontal well full-life cycle recovery prediction model established in step 1, calculate the full-life cycle recovery rate of the unsaturated shale reservoir depletion development;

[0008] Step 3: Calculate the recoverable reserves of a single well in the elastic development of shale oil and the recoverable reserves of all horizontal wells in the target block based on the production dynamic data of the target block;

[0009] Step 4, calculating the controlled geological reserves of the horizontal wells according to the recoverable reserves of all horizontal wells in the target block obtained in step 3 and the recovery factor of the unsaturated shale oil reservoir depletion development in the whole life cycle obtained in step 2;

[0010] Step 5: Calculate the control degree of geological reserves based on the horizontal well controlled geological reserves and actual geological reserves obtained in step 4, and make a judgment based on the control degree of geological reserves to give development suggestions.

[0011] The present invention is also characterized in that

[0012] Step 1 is as follows:

[0013] (1) When the formation pressure is greater than the saturation pressure, the reservoir driving mode is elastic drive, and the elastic drive recovery factor expression is:

[0014]

[0015] in,

[0016] (2) When the formation pressure is lower than the saturation pressure, the reservoir driving mode changes to solution gas drive, and the recovery factor of solution gas drive is expressed as:

[0017]

[0018] Among them, B t =B o +(R si -R s )B g (4);

[0019] The recovery factor of shale oil horizontal wells throughout their life cycle is expressed as:

[0020]

[0021] In formulas (1)-(5), R represents the total recovery factor, %; R e represents elastic flooding recovery, %; R r Indicates solution gas drive recovery, %; B oi Indicates the original crude oil volume coefficient, decimal; pi Indicates the original formation pressure, MPa; p b Indicates crude oil saturation pressure, MPa; B ob Indicates the volume coefficient of crude oil at saturation pressure, decimal; B t Represents the two-phase volume coefficient at the abandoned reservoir pressure, a decimal; R p represents the average production gas-oil ratio, m 3 / m 3 ; R si represents the original gas-oil ratio, m 3 / m 3 ; B g Indicates the volume coefficient of gas released under the abandoned reservoir pressure, decimal; C t Indicates the comprehensive compression coefficient, 1 / MPa; C o Indicates the compressibility coefficient of crude oil, 1 / MPa; C w Indicates the compressibility coefficient of formation water, 1 / MPa; S wc Indicates bound water saturation, decimal; C f Indicates the average pore volume compression coefficient of rock, 1 / MPa; B o It represents the volume coefficient of degassed formation crude oil at the abandoned reservoir pressure, a decimal; R s represents the dissolved gas-oil ratio of the formation crude oil after degassing at the abandoned reservoir pressure, m 3 / m 3 .

[0022] Step 2 is implemented as follows:

[0023] Step 2.1, obtaining basic high-pressure physical property parameters of crude oil and gas through phase calculation simulation software;

[0024] Step 2.2: By testing the compression coefficient of the shale oil core in the target block, the rock pore volume compression coefficient at the original formation pressure and the saturation pressure is obtained. The average value of the two is the average pore volume compression coefficient C of the reservoir rock from the original formation pressure to the saturation pressure. f ;

[0025] Step 2.3, the basic high-pressure physical properties of crude oil and gas obtained in step 2.1 and the average pore volume compressibility coefficient obtained in step 2.2 are substituted into formula (5) to obtain the recovery factor of the unsaturated shale oil reservoir during the whole life cycle of depletion development.

[0026] Step 2.1 is implemented as follows:

[0027] Step 2.1.1, testing the total hydrocarbon components of the crude oil and the produced gas after ground degassing by gas chromatography;

[0028] Step 2.1.2, using phase calculation simulation software to perform oil and gas combined calculation on the total hydrocarbon components of the ground degassed crude oil and produced gas, the original gas-oil ratio, and the density of the ground degassed crude oil obtained in step 2.1.1, to obtain the formation crude oil components;

[0029] Step 2.1.3, dividing the formation crude oil components obtained in step 2.1.2 into components to obtain a pseudo-component split crude oil model;

[0030] Step 2.1.4, using phase state software to perform phase state calculation on the split crude oil model of the pseudo-component obtained in step 2.1.3 to obtain characteristic parameters of the split crude oil model of each pseudo-component, wherein the characteristic parameters of the split crude oil model of each pseudo-component include: molecular weight, density, critical temperature, critical pressure, deviation factor, and volume shift coefficient;

[0031] Step 2.1.5: Perform constant mass expansion experiments on the degassed crude oil and produced gas to obtain the crude oil volume coefficient B at the original formation pressure. oi , Crude oil volume coefficient B at saturation pressure ob , Volume coefficient B of degassed crude oil at abandoned reservoir pressure o and crude oil compressibility C o ;

[0032] Step 2.1.6, conduct multi-stage degassing experiments on the crude oil and produced gas after ground degassing to obtain the degassing gas volume coefficient B under the abandoned reservoir pressure g , R of dissolved gas-oil ratio of crude oil after degassing at abandoned reservoir pressure s and the average gas-oil ratio of produced gas.

[0033] In step 2.1.3, the components are divided into N2, CO2, C1, C2-C6, C7-C 15 , C 16 -C 20 , C 21 -C 27 , C 28 -C 80 to be divided.

[0034] The specific process of step 3 is:

[0035] Based on the actual monthly production data, use Excel to make a scatter plot with the cumulative oil production as the horizontal axis and the daily oil production of a single well as the vertical axis. Select at least 12 months of data from late to early to add a trend line. The trend line type is a straight line. According to the regression formula, calculate the recoverable reserves of a single well in the elastic development stage;

[0036] The sum of recoverable reserves of a single well in the elastic development stage is the recoverable reserves of all horizontal wells in the target block.

[0037] In step 4, the expression of the geological reserves controlled by the horizontal well is:

[0038]

[0039] In formula (6), N c Indicates the geological reserves controlled by horizontal wells, 10 4 t;N R represents the recoverable reserves of all horizontal wells in the target block, 10 4 t, R represents the recovery factor of the whole life cycle of depletion development of unsaturated shale reservoirs, %.

[0040] In step 5, the expression of geological reserve control degree is:

[0041]

[0042] In formula (7), N represents the actual geological reserves, 10 4 t; S represents the oil-bearing area of ​​the horizontal well area, Km 2 ; h represents the average effective thickness, m; φ represents the average effective porosity, %; ρ o Indicates the density of ground crude oil, g / cm 3 ; S wi Indicates bound water saturation, %.

[0043] The criteria for judging the degree of geological reserve control are as follows:

[0044] 1) If γ = 100%, it means that the development technology policy is reasonable, which is an ideal state;

[0045] 2) If γ < 100%, it indicates that part of the geological reserves are not controlled by horizontal wells;

[0046] When 90%<γ<100%, it indicates that the geological reserve control degree of horizontal wells is high, and it is recommended to maintain the current development technology policy;

[0047] When 70%≤γ≤90%, it indicates that the geological reserve control degree of horizontal wells is moderate. It is recommended that the distance between horizontal wells for new wells in the same area be reduced by 10%-30% or the scale of fracturing be increased by 10%-30%;

[0048] When γ<70%, it indicates that the geological reserve control degree of horizontal wells is low. It is recommended that the distance between horizontal wells and new wells in the same area be reduced by 1-γ times or the scale of fracturing be increased by 1-γ times.

[0049] 3) If γ>100%, it indicates that the ability of horizontal wells to control geological reserves exceeds the actual geological reserves. In order to reduce investment, it is necessary to increase the well spacing or reduce the scale of fracturing.

[0050] When 100%<γ<110%, it indicates that the geological reserve control degree of horizontal wells is high, and it is recommended to maintain the current development technology policy;

[0051] When 110%≤γ≤130%, it indicates that the geological reserve control degree of horizontal wells is moderate. It is recommended that the horizontal well spacing of new wells in the same area be increased by 10%-30% or the fracturing scale be reduced by 10%-30%;

[0052] When γ>130%, it indicates that the geological reserve control degree of horizontal wells is low. It is recommended that the horizontal well spacing be increased by γ-1 times or the fracturing rule be reduced by γ-1 times for new wells in the same area.

[0053] The beneficial effect of the present invention is that the method for predicting the degree of geological reserve control in shale oil horizontal well development of the present invention only requires basic physical properties and production dynamic data of formation crude oil, produced gas and rock under different reservoir pressures, and can simply and quickly realize the prediction of the degree of geological reserve control in shale oil horizontal wells. The prediction difficulty is low and the cycle is short, and there is no need for geological modeling and numerical simulation to calculate a large amount of static and dynamic data, so the prediction cost is greatly reduced, thereby providing a basis for the formulation of shale oil horizontal well development policies. BRIEF DESCRIPTION OF THE DRAWINGS

[0054] Figure 1 It is a schematic diagram of horizontal well pattern and well spacing deployment in an embodiment of a method for predicting the degree of geological reserves control in shale oil horizontal well development of the present invention;

[0055] Figure 2 It is a crude oil volume coefficient diagram under different pressures in an embodiment of a method for predicting the degree of geological reserves control in shale oil horizontal well development of the present invention;

[0056] Figure 3 It is a diagram of crude oil compression coefficient under different pressures in an embodiment of a method for predicting the degree of geological reserves control in shale oil horizontal well development of the present invention;

[0057] Figure 4 It is a diagram of the volume coefficient of degassed gas and the dissolved gas-oil ratio in the crude oil after degassing at different pressures in an embodiment of a method for predicting the degree of geological reserves control of shale oil horizontal well development of the present invention;

[0058] Figure 5 It is a rock pore volume compression coefficient diagram under different pressures in an embodiment of a method for predicting the degree of geological reserves control in shale oil horizontal well development of the present invention;

[0059] Figure 6 It is a cumulative oil production-daily oil production relationship curve and regression diagram in an embodiment of a method for predicting the degree of geological reserve control in shale oil horizontal well development of the present invention. DETAILED DESCRIPTION

[0060] The present invention is described in detail below with reference to the accompanying drawings and specific embodiments.

[0061] The present invention provides a method for predicting the control degree of geological reserves of shale oil horizontal well development, which is specifically implemented according to the following steps:

[0062] Step 1: Establish a shale oil horizontal well recovery rate prediction model for the entire life cycle;

[0063] (1) When the formation pressure is greater than the saturation pressure, the reservoir driving mode is elastic drive, and the elastic drive recovery factor expression is:

[0064]

[0065] in,

[0066] (2) When the formation pressure is lower than the saturation pressure, the reservoir driving mode changes to solution gas drive, and the recovery factor of solution gas drive is expressed as:

[0067]

[0068] Among them, B t =B o +(R si -R s )B g (4);

[0069] The recovery factor of shale oil horizontal wells throughout their life cycle is expressed as:

[0070]

[0071] In formulas (1)-(5), R represents the recovery factor of the unsaturated shale reservoir during the whole life cycle of depletion development, %; R e represents the elastic flooding recovery rate, %; R r Indicates solution gas drive recovery, %; B oi Indicates the original crude oil volume coefficient, decimal; p i represents the original formation pressure, MPa; p b Indicates crude oil saturation pressure, MPa; B ob Indicates the volume coefficient of crude oil at saturation pressure, decimal; B t Represents the two-phase volume coefficient at the abandoned reservoir pressure, a decimal; R p represents the average production gas-oil ratio, m 3 / m 3 ; R si represents the original gas-oil ratio, m 3 / m 3 ; B g Indicates the volume coefficient of gas released under the abandoned reservoir pressure, decimal; C t Indicates the comprehensive compression coefficient, 1 / MPa; Co Indicates the compressibility coefficient of crude oil, 1 / MPa; C w Indicates the compressibility coefficient of formation water, 1 / MPa; S wc Indicates bound water saturation, decimal; C f Indicates the average pore volume compression coefficient of rock, 1 / MPa; B o It represents the volume coefficient of degassed crude oil at the abandoned reservoir pressure, a decimal; R s represents the gas-oil ratio of crude oil after degassing at the abandoned reservoir pressure, m 3 / m 3 ;

[0072] Step 2, using the basic high-pressure physical properties of formation crude oil and gas and the average pore volume compressibility of rocks, and the shale oil horizontal well full-life cycle recovery prediction model established in step 1, calculate the full-life cycle recovery rate of the unsaturated shale reservoir depletion development;

[0073] Step 2.1, obtaining basic high-pressure physical property parameters of formation crude oil and gas through phase calculation simulation software;

[0074] Step 2.1.1, testing the total hydrocarbon components of the crude oil and the produced gas after ground degassing by gas chromatography;

[0075] Step 2.1.2: the total hydrocarbon components and the original gas-oil ratio R of the degassed crude oil and produced gas obtained in step 2.1.1 are si 2. The density of crude oil after ground degassing is calculated by phase calculation simulation software to combine oil and gas and obtain the composition of formation crude oil;

[0076] Among them, phase calculation simulation software includes CMG-WINPROP, Eclipse-PVTi and FMG-Cloud;

[0077] Step 2.1.3: The formation crude oil components obtained in step 2.1.2 are divided into N2, CO2, C1, C2-C6, C7-C 15 , C 16 -C 20 , C 21 -C 27 , C 28 -C 80 The components are split to obtain a split crude oil model with eight pseudo components;

[0078] The split crude oil model that can be split into other pseudo-components in the actual process belongs to the protection scope of the present invention;

[0079] Step 2.1.4, using phase state software to perform phase state calculation on the eight-pseudo-component split crude oil model obtained in step 2.1.3 to obtain characteristic parameters of the split crude oil model of each pseudo-component, wherein the characteristic parameters of the split crude oil model of each pseudo-component include: molecular weight, density, critical temperature, critical pressure, deviation factor, and volume shift coefficient;

[0080] Step 2.1.5: Perform constant mass expansion experiments on the degassed crude oil and produced gas to obtain the crude oil volume coefficient B at the original formation pressure. oi , Crude oil volume coefficient B at saturation pressure ob , Volume coefficient B of degassed crude oil at abandoned reservoir pressure o and crude oil compressibility C o ;

[0081] Step 2.1.6, conduct multi-stage degassing experiments on the crude oil and produced gas after ground degassing to obtain the degassing gas volume coefficient B under the abandoned reservoir pressure g , R of dissolved gas-oil ratio of crude oil after degassing at abandoned reservoir pressure s and the average gas-oil ratio of produced gas;

[0082] Step 2.2: By testing the compression coefficient of the shale oil core in the target block, the rock pore volume compression coefficient at the original formation pressure and the saturation pressure is obtained. The average value of the two is the average pore volume compression coefficient C of the reservoir rock from the original formation pressure to the saturation pressure. f ;

[0083] Step 2.3, the basic high-pressure physical property parameters of the formation crude oil and gas obtained in step 2.1 and the average pore volume compressibility coefficient obtained in step 2.2 are substituted into formula (5) to obtain the recovery factor of the unsaturated shale oil reservoir during the whole life cycle of depletion development;

[0084] Step 3: Calculate the recoverable reserves of a single well in the elastic development of shale oil and the recoverable reserves of all horizontal wells in the target block based on the production dynamic data of the target block;

[0085] Based on the actual monthly production data, use Excel to make a scatter plot with the cumulative oil production as the horizontal axis and the daily oil production of a single well as the vertical axis. Select at least 12 months of data from late to early to add a trend line. The trend line type is a straight line. According to the regression formula, calculate the recoverable reserves of a single well in the elastic development stage;

[0086] Then the sum of recoverable reserves of a single well in the elastic development stage is the recoverable reserves of all horizontal wells in the target block;

[0087] Step 4, calculating the controlled geological reserves of the horizontal wells according to the recoverable reserves of all horizontal wells in the target block obtained in step 3 and the recovery factor of the unsaturated shale oil reservoir depletion development in the whole life cycle obtained in step 2;

[0088] The expression of geological reserves controlled by horizontal wells is:

[0089]

[0090] In formula (6), N R Indicates the recoverable reserves of all horizontal wells in the target block;

[0091] Step 5, calculating the geological reserve control degree according to the horizontal well controlled geological reserves and actual geological reserves obtained in step 4;

[0092] The expression of geological reserve control degree is:

[0093]

[0094] In formula (7), N represents the actual geological reserves, 10 4 t; S represents the oil-bearing area of ​​the horizontal well area, Km 2 ; h represents the average effective thickness, m; φ represents the average effective porosity, %; ρ o Indicates the density of ground crude oil, g / cm 3 ; S wi represents bound water saturation, %;

[0095] The criteria for judging the degree of geological reserve control are as follows:

[0096] 1) If γ = 100%, it means that the development technology policy is reasonable, which is an ideal state;

[0097] 2) If γ < 100%, it indicates that part of the geological reserves are not controlled by horizontal wells;

[0098] When 90%<γ<100%, it indicates that the geological reserve control degree of horizontal wells is high, and it is recommended to maintain the current development technology policy;

[0099] When 70%≤γ≤90%, it indicates that the geological reserve control degree of horizontal wells is moderate. It is recommended that the distance between horizontal wells for new wells in the same area be reduced by 10%-30% or the scale of fracturing be increased by 10%-30%;

[0100] When γ<70%, it indicates that the geological reserve control degree of horizontal wells is low. It is recommended that the distance between horizontal wells and new wells in the same area be reduced by 1-γ times or the scale of fracturing be increased by 1-γ times.

[0101] 3) If γ>100%, it indicates that the ability of horizontal wells to control geological reserves exceeds the actual geological reserves. In order to reduce investment, it is necessary to increase the well spacing or reduce the scale of fracturing.

[0102] When 100%<γ<110%, it indicates that the geological reserve control degree of horizontal wells is high, and it is recommended to maintain the current development technology policy;

[0103] When 110%≤γ≤130%, it indicates that the geological reserve control degree of horizontal wells is moderate. It is recommended that the horizontal well spacing of new wells in the same area be increased by 10%-30% or the fracturing scale be reduced by 10%-30%;

[0104] When γ>130%, it indicates that the geological reserve control degree of horizontal wells is low. It is recommended that the horizontal well spacing be increased by γ-1 times or the fracturing rule be reduced by γ-1 times for new wells in the same area.

[0105] Taking a typical shale reservoir in the western oil field as an example, the basic situation is: the shale reservoir has no edge and bottom water, and the reservoir crude oil formation pressure p i is 16.2MPa, saturation pressure p b The average permeability of the reservoir matrix is ​​0.1mD, the porosity is 9.0%, the average thickness of the oil layer is 9m, the crude oil viscosity is 1.21mPa·s, and the density is 0.74g / cm 3 、Original gas-oil ratio R si 107.6m 3 / m 3 , reservoir temperature 58℃, irreducible water saturation S wc The density of ground degassed crude oil is 0.84 g / cm 3 The components of ground degassed oil and produced gas are shown in Tables 1 and 2. The sand body area in the southeast of the reservoir is 2.0 km 2 , deploy 5 horizontal wells for development, the horizontal well length is 1500m, the well spacing is as follows Figure 1 As shown, 1-5 are the well numbers, and the well spacing is 250m.

[0106] 1) The total hydrocarbon components of the crude oil and the produced gas after ground degassing were tested by gas chromatography, and the results are shown in Tables 1 and 2;

[0107] Table 1 Results of crude oil composition after ground degassing

[0108]

[0109]

[0110] Table 2 Test results of output gas components

[0111]

[0112] 2) The total hydrocarbon components of the crude oil and produced gas after ground degassing, the original gas-oil ratio and the ground oil density are used to calculate the oil and gas combination according to the gas-liquid equilibrium principle through phase state software to obtain the formation crude oil components, as shown in Table 3;

[0113] Table 3 Formation crude oil composition

[0114]

[0115] 3) The formation crude oil components are split into 8 components, including N2, CO2, C1, C2-C6, C7-C 15 , C 16 -C 20 , C 21 -C 27 , C 28 -C 80 ; The contents of each component after splitting are shown in Table 4;

[0116] Table 4 Content of each component after splitting of formation crude oil

[0117]

[0118] 4) Performing phase calculation on the split crude oil of the eight pseudo-components to obtain the characteristic parameters of the split crude oil model of each pseudo-component, as shown in Table 5;

[0119] Table 5 Characteristic parameters of each component of pseudo-component

[0120]

[0121] 5) Carry out constant mass expansion experiments to obtain the crude oil volume coefficient B oi , Crude oil volume coefficient B at saturation pressure ob , Volume coefficient B of degassed crude oil at abandoned reservoir pressure o and crude oil compressibility C o ,according to Figure 2 Volume coefficient and pressure of crude oil at different pressures Figure 3 The crude oil compression coefficient under different pressures is 1.1632×10 -3 1 / MPa, the compression coefficient of crude oil under saturation pressure is 1.4358×10 -3 1 / MPa; the crude oil volume coefficient at the original formation pressure is 1.18070, and the crude oil volume coefficient at the saturation pressure is 1.19279;

[0122] 6) Carry out multi-stage degassing experiments to obtain the volume coefficient B of the degassing gas under the abandoned reservoir pressure g , R of dissolved gas-oil ratio of crude oil after degassing at abandoned reservoir pressure s and the average gas-oil ratio of the produced gas. The results are as follows Figure 4 As shown; According to the well depth and ground conditions, the initial determination of the abandoned reservoir pressure is 7MPa, and the average production gas-oil ratio of the test area is 150m 3 / m 3 .

[0123] According to the standard of “Method for Determination of Rock Porosity Volume Compression Coefficient”, the compression coefficient of the target block rock under different pressures is tested.

[0124] According to the petroleum and natural gas industry standard SY / T 5815-2016 "Method for Determining the Pore Volume Compression Coefficient of Rocks", the shale oil core was tested for compression coefficient, and the rock pore volume compression coefficient under the original formation pressure and the rock pore volume compression coefficient under the saturation pressure were obtained. The average of the two was taken as the average pore volume compression coefficient of the reservoir rock when the original formation pressure was reduced to the saturation pressure. The results are as follows Figure 5 As shown in Figure 2, the rock pore volume compression coefficient under the original formation pressure is 6.77×10 -3 1 / MPa, the rock pore volume compression coefficient under saturated pressure is 6.17×10 -3 1 / MPa, the average pore volume compression coefficient is 6.47×10 -3 1 / Mpa;

[0125] Substitute the above-obtained basic high-pressure physical property parameters of formation crude oil and gas, and the average pore volume compressibility coefficient of reservoir rock from the original formation pressure to the saturation pressure into formula (5) to obtain the recovery rate of the shale reservoir depletion development for the entire life cycle; among them, the elastic gas drive recovery rate is 7.3%, the solution gas drive recovery rate is 0.32%, and the recovery rate of the shale reservoir depletion development for the entire life cycle is 7.6%; the elastic gas drive recovery rate is 7.3%, the solution gas drive recovery rate is 0.32%, and the recovery rate of the entire life cycle is 7.6%;

[0126] 7) Calculate the recoverable reserves of a single well and all horizontal wells in the target area during the elastic development phase

[0127] Based on the actual monthly production data, use Excel to make a scatter plot with the cumulative oil production as the horizontal axis and the daily oil production of a single well as the vertical axis. Select at least 12 months of data from late to early to add a trend line. The trend line type is a straight line, such as Figure 6 As shown, according to the regression formula, the recoverable reserves of a single well in the elastic development stage are calculated, and the sum of the recoverable reserves of a single well in the elastic development stage is the recoverable reserves of all horizontal wells in the target block;

[0128] According to the regression results, the recoverable reserves of Well 1 and Well 2 are calculated to be 11,500 tons and 8,500 tons. According to this scheme, the recoverable reserves of Wells 3, 4, and 5 are calculated to be 12,500 tons, 13,200 tons, and 9,000 tons, respectively. The recoverable reserves of all horizontal wells in the target block are 54,700 tons.

[0129] 8) Calculate the controlled geological reserves of horizontal wells

[0130] According to formula (4), the controlled geological reserves of the horizontal well are calculated to be 720,000 tons;

[0131] 9) Calculate the control degree of geological reserves

[0132] According to formula (5), the geological reserve control degree of horizontal wells in the target block is 85.5%.

[0133] Since γ is less than 100%, it indicates that part of the geological reserves are not controlled by horizontal wells. It is judged that the control degree of geological reserves by horizontal wells is moderate. For new wells in the same area, it is recommended to reduce the horizontal well distance by 15% or increase the fracturing scale by 15%.

Claims

1. A method for predicting the control degree of geological reserves of shale oil horizontal well development, characterized in that: Follow the steps below to implement it: Step 1: Establish a shale oil horizontal well recovery rate prediction model for the entire life cycle; The step 1 is specifically as follows: (1) When the formation pressure is greater than the saturation pressure, the reservoir driving mode is elastic drive, and the recovery factor of elastic drive is expressed as: （1） in, (2); (2) When the formation pressure is lower than the saturation pressure, the reservoir driving mode becomes solution gas drive, and the recovery factor of solution gas drive is expressed as: （3） in, (4); The recovery factor of shale oil horizontal wells throughout their life cycle is expressed as: （5） In formulas (1)-(5), R represents the recovery factor of the unsaturated shale reservoir during the whole life cycle of depletion development, %; represents the elastic flooding recovery factor, %; represents the solution gas drive recovery rate, %; It represents the original crude oil volume coefficient, a decimal; represents the original formation pressure, MPa; Indicates the crude oil saturation pressure, MPa; It represents the volume coefficient of crude oil at saturation pressure, decimal; It represents the two-phase volume coefficient at the abandoned reservoir pressure, a decimal; represents the average production gas-oil ratio, m 3 / m 3 ; represents the original gas-oil ratio, m 3 / m 3 ; It represents the volume coefficient of gas released under the abandoned reservoir pressure, a decimal; Indicates the comprehensive compression coefficient, 1 / MPa; Indicates the compressibility of crude oil, 1 / MPa; Indicates the formation water compressibility, 1 / MPa; Indicates bound water saturation, decimal; It represents the average pore volume compressibility of rock, 1 / MPa; It represents the volume coefficient of degassed formation crude oil at the abandoned reservoir pressure, a decimal; represents the dissolved gas-oil ratio of the formation crude oil after degassing at the abandoned reservoir pressure, m 3 / m 3 ; Step 2, using the basic high-pressure physical properties of formation crude oil and gas and the average pore volume compressibility of rocks, and the shale oil horizontal well full-life cycle recovery prediction model established in step 1, calculate the full-life cycle recovery rate of the unsaturated shale reservoir depletion development; Step 3: Calculate the recoverable reserves of a single well in the elastic development of shale oil and the recoverable reserves of all horizontal wells in the target block based on the production dynamic data of the target block; The specific process of step 3 is as follows: Based on the actual monthly production data, use Excel to make a scatter plot with the cumulative oil production as the horizontal axis and the daily oil production of a single well as the vertical axis. Select at least 12 months of data from late to early to add a trend line. The trend line type is a straight line. According to the regression formula, calculate the recoverable reserves of a single well in the elastic development stage; Then the sum of recoverable reserves of a single well in the elastic development stage is the recoverable reserves of all horizontal wells in the target block; Step 4, calculating the controlled geological reserves of the horizontal wells according to the recoverable reserves of all horizontal wells in the target block obtained in step 3 and the recovery factor of the unsaturated shale oil reservoir depletion development in the whole life cycle obtained in step 2; In step 4, the expression of the geological reserves controlled by the horizontal well is: （6） In formula (6), Indicates the geological reserves controlled by horizontal wells, 10 4 t; N R represents the recoverable reserves of all horizontal wells in the target block, 10 4 t, R It represents the recovery factor of the whole life cycle of depletion development of unsaturated shale reservoirs, %; Step 5, calculating the geological reserve control degree according to the horizontal well controlled geological reserves and actual geological reserves obtained in step 4, and making a development suggestion according to the geological reserve control degree; In step 5, the expression of geological reserve control degree is: （7）； In formula (7), Indicates actual geological reserves, 10 4 t; Indicates the oil-bearing area of ​​the horizontal well area, Km 2 ; represents the average effective thickness, m; represents the average effective porosity, %; Indicates the density of ground crude oil, g / cm 3 ; represents bound water saturation, %; The criteria for judging the degree of geological reserve control are as follows: 1) If = 100%, indicating that the development technology policy is reasonable, which is an ideal state; 2) If <100%, indicating that part of the geological reserves are not controlled by horizontal wells; When 90%< <100%, indicating that the geological reserves of horizontal wells are highly controlled, and it is recommended to maintain the current development technology policy; When 70%≤ ≤90%, indicating that the geological reserve control degree of horizontal wells is moderate. It is recommended that new wells in the same area reduce the distance between horizontal wells by 10%-30% or increase the scale of fracturing by 10%-30%; when <70%, indicating that the geological reserve control degree of horizontal wells is low. It is recommended to reduce the distance between horizontal wells for new wells in the same area. Double or increase the scale of fracturing times; 3) If >100%, indicating that the ability of horizontal wells to control geological reserves exceeds the actual geological reserves. In order to reduce investment, it is necessary to increase the well spacing or reduce the scale of fracturing; When 100%< <110%, indicating that the geological reserves of horizontal wells are highly controlled, and it is recommended to maintain the current development technology policy; When 110%≤ ≤130%, indicating that the geological reserve control degree of horizontal wells is moderate. It is recommended that new wells in the same area increase the horizontal well spacing by 10%-30% or reduce the fracturing scale by 10%-30%; when >130%, indicating that the geological reserve control degree of horizontal wells is low. It is recommended to increase the horizontal well spacing for new wells in the same area. times or reducing the fracturing regulation times.

2. The method for predicting the control degree of geological reserves of shale oil horizontal well development according to claim 1 is characterized in that: The step 2 is specifically implemented according to the following steps: Step 2.1, obtaining basic high-pressure physical property parameters of crude oil and gas through phase calculation simulation software; Step 2.2: Test the compression coefficient of the shale oil core in the target area to obtain the rock pore volume compression coefficient under the original formation pressure and the saturation pressure. The average value of the two is the average pore volume compression coefficient of the reservoir rock from the original formation pressure to the saturation pressure. ; Step 2.3, the basic high-pressure physical properties of crude oil and gas obtained in step 2.1 and the average pore volume compressibility obtained in step 2.2 are substituted into formula (5) to obtain the recovery factor of the unsaturated shale oil reservoir during the whole life cycle of depletion development.

3. A method for predicting the control degree of geological reserves of shale oil horizontal well development according to claim 2, characterized in that: The step 2.1 is specifically implemented according to the following steps: Step 2.1.1, testing the total hydrocarbon components of the crude oil and the produced gas after ground degassing by gas chromatography; Step 2.1.2, using phase calculation simulation software to perform oil and gas combined calculation on the total hydrocarbon components of the ground degassed crude oil and produced gas, the original gas-oil ratio, and the density of the ground degassed crude oil obtained in step 2.1.1, to obtain the formation crude oil components; Step 2.1.3, dividing the formation crude oil components obtained in step 2.1.2 into components to obtain a pseudo-component split crude oil model; Step 2.1.4, using phase state software to perform phase state calculation on the split crude oil model of the pseudo-component obtained in step 2.1.3 to obtain characteristic parameters of the split crude oil model of each pseudo-component, wherein the characteristic parameters of the split crude oil model of each pseudo-component include: molecular weight, density, critical temperature, critical pressure, deviation factor, and volume shift coefficient; Step 2.1.5: Perform constant mass expansion experiments on the degassed crude oil and produced gas to obtain the crude oil volume coefficient at the original formation pressure. , Crude oil volume coefficient at saturation pressure , Volume coefficient of degassed crude oil at reservoir abandonment pressure and crude oil compressibility ; Step 2.1.6, conduct multi-stage degassing experiments on the crude oil and produced gas after ground degassing to obtain the degassing gas volume coefficient under the abandoned reservoir pressure , Dissolved gas-oil ratio of crude oil after degassing at abandoned reservoir pressure and the average gas-oil ratio of produced gas.

4. A method for predicting the control degree of geological reserves of shale oil horizontal well development according to claim 3, characterized in that: In step 2.1.3, the components are divided into N2, CO2, C1, C2-C6, C7-C 15 , C 16 -C 20 , C 21 -C 27 , C 28 -C 80 of division.

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