Method and apparatus for predicting production from a reservoir undergoing fracturing

Abstract

This invention discloses a method and apparatus for predicting the production of fracturing reservoirs. The method includes: taking the wellhead oil, gas, water, and sand produced by the fracturing reservoir wells as the total produced solid-liquid volume; determining the underground equivalent volume of the produced wellhead oil, gas, water, and sand based on the total produced solid-liquid volume; taking the sum of the volumes of fracturing fluid and proppant injected into the ground as the total injected volume; determining the flowback rate of the total injected volume based on fracturing operation parameters, the underground equivalent volume or the total produced solid-liquid volume, and the total injected volume; establishing a fitting prediction chart of well flowback rate versus oil pressure and cumulative oil production based on the flowback rate and production dynamics of the wells; determining the well production status based on the morphological characteristics of the prediction chart; and determining the cumulative oil production of each well in the fracturing reservoir based on the well production status and the linear segment characteristics of the prediction chart. This invention can accurately predict the production of wells in fracturing reservoirs based on the fitting prediction chart of well flowback rate versus oil pressure and cumulative oil production.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, and in particular to a method and apparatus for predicting the production of fracturing reservoirs. Background Technology

[0002] This section is intended to provide background or context for the embodiments of the invention set forth in the claims. The description herein is not an admission that it is prior art simply because it is included in this section.

[0003] With the continuous advancement of oilfield exploration and development, accurate understanding and research of production change trends are crucial for resource assessment, development planning, and investment decisions. Oilfield production forecasting occupies a central position in the planning, decision-making, and management of the petroleum industry. Extensive literature review reveals that, with advancements in exploration and development technologies, numerous scholars and research institutions have conducted extensive research on oil and gas field production forecasting methods.

[0004] The technology disclosed in patent publication number CN119129159A involves a method for predicting the production of horizontal wells after volumetric fracturing in unconventional oil reservoirs. The method includes: obtaining the horizontal well parameters of the horizontal well to be predicted; obtaining the production of surrounding vertical wells of the horizontal well to be predicted; constructing a production prediction formula for the horizontal well after fracturing; determining the coefficients of the production prediction formula; and calculating the production of the horizontal well to be predicted. This method uses regression analysis based on actual field data to calculate the production of horizontal wells after volumetric fracturing, considering the influence of oil and gas enrichment and fracturing stimulation on the production improvement effect. Simultaneously, by introducing the production of surrounding vertical wells, it reduces the differences in production improvement effects between different blocks and locations, and has been well applied in the exploration and development of low-grade oil reservoirs. However, while constructing an optimal classification hyperplane or regression function for production prediction has good generalization ability in small sample cases and can handle nonlinear relationships in shale oil production prediction, the selection of kernel function and parameter optimization are quite difficult. The fundamental reason is that vertical wells and horizontal wells have fundamentally different principles and mechanisms. Compared with vertical wells, horizontal wells not only have differences in seepage mechanics principles, but also have the added influence of a series of engineering factors in the fracturing process, as well as the seepage mechanics mechanism of permeation and displacement in the reservoir matrix. Therefore, this technology suffers from low accuracy in predicting the production of fracturing reservoirs.

[0005] The technology disclosed in patent publication number CN110175412A involves a reservoir data fitting method. This method includes: acquiring pressure data and pressure-related data based on multiple sets of measured reservoir data; determining key data nodes in the pressure-related data based on the changing trends of the pressure-related data; dividing the first changing trend information formed by the pressure data and the second changing trend information formed by the pressure-related data into multiple data segments based on the key data nodes; matching corresponding target data segments to each target parameter to be determined in the target reservoir model to be fitted from the multiple data segments; using the target data segments corresponding to each target parameter as calibration data to fit each target parameter to determine, thereby determining the target reservoir model. This reservoir data fitting method uses multiple data segments from two different changing trend information sources as different target parameters for calibration, which can specifically fit the target parameters, thereby improving the convergence speed of the fitting and thus improving the fitting speed of the reservoir model. However, simulation methods rely on relatively reliable data systems, which pose significant challenges for fracturing systems with high uncertainty. Furthermore, numerical simulations struggle to characterize dynamically changing discharge volumes and flow channels. The core mechanism of this patented technology lies in using field-measured pressure as a dependent parameter. On one hand, pressure acquisition is influenced by wellbore flow and nozzles, making it a dynamic variable. On the other hand, the prediction of production, especially cumulative production, is a volumetric parameter. Therefore, the selection of dependent parameters on which this patented technology is based limits the reliability of its prediction results, resulting in low accuracy in predicting the production of fracturing-treated reservoirs.

[0006] In summary, existing technologies have the technical problem of being unable to accurately predict the production of fracturing reservoirs. Summary of the Invention

[0007] This invention provides a method for predicting the production of fractured reservoirs, which accurately predicts the production of fractured reservoirs based on a well flowback rate and oil pressure-cumulative production fitting prediction chart. The method includes:

[0008] The wellhead oil, gas, water, and sand produced by the fracturing reservoir wells are taken as the total solid and liquid volume produced; the underground equivalent volume of the wellhead oil, gas, water, and sand produced is determined based on the total solid and liquid volume produced.

[0009] The total volume of fracturing fluid and proppant injected into the ground is taken as the total volume injected into the ground. Based on the fracturing operation parameters, the total volume injected into the ground is determined by the underground equivalent volume or the total volume of solid and liquid produced, as well as the total volume injected into the ground.

[0010] Based on the flowback rate and production dynamics of the oil wells, a fitting prediction chart of flowback rate and cumulative oil production of fracturing reservoirs is established.

[0011] Based on the morphological characteristics of the fitting prediction chart of the flowback rate and cumulative oil production of fracturing reservoir wells, the production status of the wells is determined.

[0012] Based on the production status of the oil wells and the characteristics of the straight line segments on the prediction chart, the cumulative oil production of each oil well in the fracturing reservoir is determined.

[0013] This invention also provides an apparatus for predicting the production of fractured reservoirs, used to accurately predict the production of fractured reservoirs based on a well flowback rate and oil pressure-cumulative production fitting prediction chart. The apparatus includes:

[0014] The underground equivalent volume determination unit is used to take the wellhead oil, gas, water, and sand produced by the fracturing and induced oil reservoir as the total produced solid and liquid volume; and to determine the underground equivalent volume of the produced wellhead oil, gas, water, and sand based on the total produced solid and liquid volume.

[0015] The flowback rate determination unit is used to take the sum of the volumes of the fracturing fluid and proppant injected into the ground as the total volume injected into the ground; based on the fracturing construction parameters, according to the underground equivalent volume or the total solid-liquid volume produced, and the total volume injected into the ground, the flowback rate of the total volume injected into the ground is determined;

[0016] The chart establishment unit is used to establish a fitting prediction chart of the flowback rate and cumulative oil production of fracturing reservoirs based on the flowback rate and production dynamics of the wells.

[0017] The production status determination unit is used to determine the production status of oil wells based on the morphological characteristics of the fitting prediction chart of the flowback rate and cumulative oil production of fracturing reservoirs.

[0018] The cumulative oil production determination unit is used to determine the cumulative oil production of each well in the fracturing reservoir based on the production status of the oil well and the characteristics of the straight line segment of the prediction chart.

[0019] This invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the above-described method for predicting the production of fracturing reservoirs.

[0020] This invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the above-described method for predicting the production of fracturing reservoirs.

[0021] This invention also provides a computer program product, which includes a computer program that, when executed by a processor, implements the above-described method for predicting the production of fracturing reservoirs.

[0022] In this embodiment of the invention, the method for predicting the production of fracturing-treated reservoirs, compared with existing technologies that cannot accurately predict the production of fracturing-treated reservoirs, involves: taking the wellhead oil, gas, water, and sand produced by the fracturing-treated reservoir well as the total produced solid-liquid volume; determining the underground equivalent volume of the produced wellhead oil, gas, water, and sand based on the total produced solid-liquid volume; taking the sum of the volumes of fracturing fluid and proppant injected into the ground as the total injected volume; and determining the total injected volume based on the fracturing operation parameters, according to the underground equivalent volume or the total produced solid-liquid volume, and the total injected volume. Based on the flowback rate and production dynamics of oil wells, a fitting prediction chart of the flowback rate and cumulative oil production of fracturing reservoirs is established. The production status of oil wells is determined based on the morphological characteristics of this chart. Based on the production status and the linear segment characteristics of the prediction chart, the cumulative oil production of each well in the fracturing reservoir is determined. This allows for accurate prediction of fracturing reservoir production based on the flowback rate and cumulative oil production fitting prediction chart, improving the accuracy of production prediction for fracturing reservoirs. Attached Figure Description

[0023] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort. In the drawings:

[0024] Figure 1 This is a flowchart illustrating the method for predicting reservoir production through fracturing in an embodiment of the present invention.

[0025] Figure 2 This is a schematic diagram illustrating the relationship between oil pressure and backflow rate in an embodiment of the present invention;

[0026] Figure 3 This is a schematic diagram illustrating the relationship between cumulative oil production and return rate in an embodiment of the present invention;

[0027] Figure 4 This is a schematic diagram of fracturing flow in a fracturing oil well, as shown in an embodiment of the present invention.

[0028] Figure 5 This is a schematic diagram of repeated fracturing of a fracturing oil well in an embodiment of the present invention;

[0029] Figure 6 This is a schematic diagram illustrating the stable change of oil pressure with the backflow rate in an embodiment of the present invention;

[0030] Figure 7 This is a schematic diagram of the pressure in a fracturing oil well with crossflow in an embodiment of the present invention;

[0031] Figure 8 This is a schematic diagram of the pressure in a repeatedly fractured oil well in an embodiment of the present invention;

[0032] Figure 9 This is a schematic diagram of oil well pressure changes during production regimes in an embodiment of the present invention;

[0033] Figure 10 This is a schematic diagram of low-pressure operation in an embodiment of the present invention;

[0034] Figures 11A to 11C This is a graph showing the cumulative oil production fitting prediction of fracturing wells in this embodiment of the invention;

[0035] Figure 12 This is a schematic diagram of the device for predicting reservoir production through fracturing in an embodiment of the present invention. Detailed Implementation

[0036] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings. Here, the illustrative embodiments of the present invention and their descriptions are used to explain the present invention, but are not intended to limit the present invention.

[0037] The acquisition, storage, use, and processing of data in this application comply with relevant laws and regulations.

[0038] Considering the technical problems existing in the current technology, how to establish a relatively stable and reliable mathematical model to find the pattern of production changes when the pressure or fracturing field changes is a practical problem that needs to be solved. Therefore, this invention proposes a scheme for predicting the production of fracturing reservoirs. The following is a detailed description of this scheme for predicting the production of fracturing reservoirs.

[0039] Figure 1 This is a flowchart illustrating the method for predicting reservoir production through fracturing in an embodiment of the present invention. Figure 1 As shown, the method includes the following steps:

[0040] Step 101: Take the wellhead oil, gas, water, and sand produced by the fracturing reservoir well as the total solid-liquid volume produced; determine the underground equivalent volume of the wellhead oil, gas, water, and sand produced based on the total solid-liquid volume produced.

[0041] Step 102: Take the sum of the volumes of the fracturing fluid and proppant injected into the ground as the total volume injected into the ground; based on the fracturing operation parameters, determine the total volume injected into the ground flowback rate according to the underground equivalent volume or the total volume of solid and liquid produced, and the total volume injected into the ground.

[0042] Step 103: Based on the flowback rate and production dynamics of the oil wells, establish a fitting prediction chart of flowback rate and cumulative oil production of fracturing reservoirs;

[0043] Step 104: Determine the production status of the oil well based on the morphological characteristics of the fitting prediction chart of the flowback rate and cumulative oil production of the fracturing reservoir.

[0044] Step 105: Based on the production status of the oil wells and the characteristics of the straight line segments on the prediction chart, determine the cumulative oil production of each oil well in the fracturing reservoir.

[0045] The method for predicting oil production in fracturing reservoirs provided in this invention involves the following steps: The wellhead oil, gas, water, and sand produced by the fracturing reservoir wells are taken as the total produced solid-liquid volume; based on the total produced solid-liquid volume, the underground equivalent volume of the produced wellhead oil, gas, water, and sand is determined; the volume of the fracturing fluid and proppant injected into the ground is taken as the total injected volume; based on fracturing parameters, the underground equivalent volume or the total produced solid-liquid volume, and the total injected volume, the total injected volume flowback rate is determined; based on the flowback rate and well data on production dynamics, a fitting prediction chart of well flowback rate versus cumulative oil production in the fracturing reservoir is established; based on the morphological characteristics of the fitting prediction chart, the well production status is determined; based on the well production status and the linear segment characteristics of the prediction chart, the cumulative oil production of each well in the fracturing reservoir is determined.

[0046] Compared with existing technologies that cannot accurately predict the production of fractured reservoirs, the method for predicting the production of fractured reservoirs provided in this invention can accurately predict the production of fractured reservoirs based on a fitting prediction chart of well flowback rate and cumulative oil production, thus improving the accuracy of production prediction. The method for predicting the production of fractured reservoirs is described in detail below.

[0047] To address the problems of existing technologies, this invention provides a dynamic understanding of reservoirs and single wells that closely reflects production practice. Referring to the curve characteristics of some cumulative value charts in water drive characteristic curves, and through various trials, a linear chart completely different from the water drive characteristic curves was established. First, the total volume of fracturing fluid and proppant injected into the formation is considered the total volume injected into the formation, and the oil, gas, water, and sand discharged from the wellhead are considered the total volume discharged. The ratio between these two is hereinafter referred to as the total volume injected backflow rate, or simply the flowback rate. Through statistical analysis, it was found that in the later stages of fracturing production wells, the flowback rate chart often forms a pressure linear segment and a cumulative production linear segment. Combining the characteristics of these two linear segments, a method for predicting fracturing reservoir production was established. The specific technical solution process is as follows:

[0048] (1) Taking into account the production of oil, water and gas, calculate the underground equivalent volume of the cumulative fluid produced at the wellhead, i.e., step 101 above.

[0049] The production of oil, gas, and water from wellheads in oil reservoirs varies in volume underground due to the influence of high temperature and high pressure. This invention patent mainly considers the underground fluid flow, so it is necessary to combine reservoir engineering to convert the wellhead oil, gas, water, and sand production to the underground volume in order to carry out the calculation of the deep absorption effect of fracturing fluid replacing crude oil.

[0050] In practice, the groundwater volume produced is calculated using the formation water volume coefficient B. w The calculation (Formula 1-2), that is, in one embodiment, determines the underground equivalent volume of the produced wellhead oil, gas, water and sand based on the total produced solid and liquid volume, which may include: the underground equivalent volume of produced water, calculated using the formation water volume factor.

[0051] In practice, the underground volume of produced oil is determined using the underground crude oil volume coefficient B. o The calculation (Formula 3-4) in one embodiment is to determine the underground equivalent volume of the produced wellhead oil, gas, water and sand based on the total produced solid and liquid volume. This may include: the underground equivalent volume of the produced oil, calculated using the underground crude oil volume coefficient.

[0052] In specific implementation, if the underground oil reservoir is saturated, the produced gas is calculated using the produced gas state equation combined with the dissolved gas-oil ratio (Formula 5-9). If the underground oil reservoir is unsaturated, the produced gas exists underground in the form of dissolved gas and is included in the calculation of the underground volume factor of crude oil, requiring no additional calculation. That is, in one embodiment, the underground equivalent volume of produced wellhead oil, gas, water, and sand is determined based on the total produced solid and liquid volume. This can include: if the underground oil reservoir is saturated, the underground equivalent volume of produced gas is calculated using the produced gas state equation combined with the dissolved gas-oil ratio; if the underground oil reservoir is unsaturated, the underground equivalent volume of produced gas exists underground in the form of dissolved gas and is included in the calculation of the underground volume factor of crude oil, requiring no additional calculation.

[0053] In specific implementation, if the producing well produces sand (proppant quartz sand, etc.), the additional underground discharge volume is calculated by converting the mass and density of the produced sand or by converting the sand volume and the sand pore volume. That is, in one embodiment, the underground equivalent volume of the produced wellhead oil, gas, water and sand is determined based on the total produced solid and liquid volume. This may include: if the producing well produces sand, the underground equivalent volume of the sand is calculated by converting the mass and density of the produced sand or by converting the sand volume and the sand pore volume.

[0054] (1)

[0055] (2)

[0056] (3)

[0057] (4)

[0058] (5)

[0059] (6)

[0060] (7)

[0061] (8)

[0062] (9)

[0063] (10)

[0064] —The volume of crude oil in a container at pressure P and temperature T, m 3 ;

[0065] —Volume of crude oil after degassing under ground conditions (20℃, 0.1MPa), in m³ 3 ;

[0066] —The volume factor of formation water, a decimal;

[0067] —The volume of formation water, in m, under specific formation conditions. 3 ;

[0068] —The volume of water in this formation under surface conditions, in meters. 3 ;

[0069] —Natural gas volume factor, m 3 / m 3 ;

[0070] —The volume of natural gas under standard conditions, in meters. 3 ;

[0071] —Quantitative volume of natural gas under reservoir conditions, in m³ 3 ;

[0072] —Density of gas reservoir at temperature and pressure, kg / m³ 3 ;

[0073] —Density under standard ground conditions, kg / m³ 3 ;

[0074] —The pressure of natural gas under standard conditions;

[0075] —Volume of natural gas under standard conditions;

[0076] —The temperature of natural gas under standard conditions;

[0077] t — reservoir temperature, °C;

[0078] —The original dissolved gas-oil ratio of the formation oil, m 3 / m 3 ;

[0079] —The dissolved gas-oil ratio at pressure P, m 3 / m 3 ;

[0080] —Volume of crude oil after degassing on the ground, in m 3 ;

[0081] —Volume under ground conditions, m 3 ;

[0082] —Volume under stratigraphic conditions, m 3 ;

[0083] — This is the compressibility factor, usually expressed in Pa. -1 ;

[0084] — Coefficient of volumetric thermal expansion, 1 / ℃;

[0085] —The change in pressure from the surface to the formation, in MPa;

[0086] —The temperature change from the ground to the strata, in °C.

[0087] The above parameters constitute the total volume of formation material discharged during the entire production chain after oil well fracturing.

[0088] (2) Calculate the solid volume return rate of the in-well flow based on the fracturing construction parameters, i.e., step 102 above.

[0089] Due to the complex subsurface characteristics of unconventional reservoirs, and the uncertainty of fracturing stimulation leading to a complex subsurface fracture network structure, this dual complexity significantly increases the uncertainty of reservoir modeling after fracturing. Consequently, methods such as natural decline and numerical simulation adapted to conventional reservoirs lose their foundation. However, during fracturing, factors such as proppant dosage, pump speed, pressure, fracturing fluid composition, number of segments, number of clusters, segment spacing, and cluster spacing all affect the flowback of fracturing fluid and the flowback ratio of the total volume of material injected into the formation. This effect is relatively easy to predict. In one embodiment, the fracturing operation parameters may include one or any combination of proppant dosage, pump speed, pressure, fracturing fluid composition, number of segments, number of clusters, segment spacing, or cluster spacing. These parameters are used to distinguish the classification morphological characteristics of typical curves and to predict the selection of segment intervals. Therefore, considering the fracturing operation, if the fracturing is a single fracturing operation, the total volume of the fracturing fluid injected into the formation and the volume of proppant injected are used as the total volume injected into the formation, and the underground equivalent volume of produced oil, gas, water, and sand is used as the numerator to calculate the flowback rate R of the fracturing fluid injected into the formation over time (Formula 11). If repeated fracturing occurs, the total volume injected into the formation during the two fracturing operations is used as the denominator, and the total volume of produced solids and liquids is used as the numerator to calculate the flowback rate (Formula 12). In this case, the flowback rate often reverses at the fracturing time point, thus affecting the morphological characteristics of the pressure chart and the cumulative production chart. In this embodiment of the invention, the flowback rate is calculated with the underground volume as the target, that is, how much is injected underground and how much is returned underground, to see the production situation when the flowback rate is 100%. At the same time, it helps to observe the occurrence of underground seepage.

[0090] As can be seen from the above, in one embodiment, determining the total underground volume return rate based on the underground equivalent volume or the total produced solid-liquid volume, and the total underground volume, may include:

[0091] Based on the fracturing operation, if the fracturing is a single fracturing operation, the total volume of the fracturing operation entering the ground is used as the denominator and the equivalent underground volume is used as the numerator to calculate the return rate of the total volume of the fracturing operation entering the ground as a function of time.

[0092] If repeated fracturing occurs Figure 5 This is a schematic diagram of repeated fracturing of a fracturing oil well in an embodiment of the present invention. The total volume of the fracturing that has entered the ground is used as the denominator, and the total volume of solid and liquid produced is used as the numerator to determine the flowback rate of the total volume of the fracturing that has entered the ground.

[0093] (11)

[0094] (12)

[0095] R — Return rate;

[0096] V out —Cumulative production volume, m3 ;

[0097] V in —Total volume underground, m 3 ;

[0098] V wd —Volume of liquid entering the ground, m 3 ;

[0099] V sd —Volume of proppant inserted into the ground, m 3 ;

[0100] V oR —The cumulative underground volume of oil production, in meters 3 ;

[0101] V gR —The cumulative underground volume of gas produced, in meters 3 ;

[0102] V wR —The cumulative underground volume of water production, in meters 3 ;

[0103] V sR —The underground volume of sand produced, in meters 3 .

[0104] (3) Combining dynamic data and monitoring data, establish a single-well flowback rate-wellhead oil pressure / cumulative oil production chart (e.g. Figures 11A-11C As shown in the figure, that is, step 103 above.

[0105] Figure 2 This is a schematic diagram of the relationship between oil pressure and flowback rate in an embodiment of the present invention, namely, a wellhead oil pressure chart for flowback rate; Figure 3 This is a schematic diagram illustrating the relationship between cumulative oil production and backflow rate in an embodiment of the present invention, specifically a graph showing the cumulative oil production based on the backflow rate. Figure 2 and Figure 3 , construct as Figures 11A to 11C The oil pressure cumulative oil production fitting prediction chart shown can be used as a chart to illustrate the linear trend between cumulative oil production and oil pressure. Figures 11A to 11C This is a fitted prediction chart of cumulative oil production from fracturing wells in this embodiment of the invention, specifically a fitted prediction chart of flowback rate and cumulative oil production from fracturing reservoirs. Figures 11A to 11C In the formula, X represents the return rate; in the formula for the increasing trend line, Y represents the cumulative oil production; in the formula for the decreasing trend line, Y represents the oil pressure.

[0106] In step 103 above, in one embodiment, based on the flowback rate and production dynamics of oil wells, a fitting prediction chart of flowback rate and cumulative oil production of fracturing reservoirs is established, which may include: using the flowback rate as the horizontal axis to construct the prediction chart.

[0107] In practical implementation, the flowback rate is used as the horizontal axis to construct the chart because fracturing wells generally have low permeability, and formation pressure transmission is highly dependent on the fracture network system. Therefore, the wellhead pressure and production are often high in the early stages, followed by a rapid pressure drop and subsequent rapid production decline. Using a flowback rate chart can reduce the production fluctuations caused by changes in wellhead pressure in the early and later stages, which are difficult to predict. Furthermore, since fracturing often results in problems such as sand blockage and salt blockage, shutting in the well can also disrupt wellhead pressure changes or production continuity, thus affecting the stability of calculations such as natural decline and numerical simulations. Using this chart, it can be seen that... Figure 2 , Figure 4 The pressure and the volume of material extruded into the formation can form a good linear relationship, and actual data have verified the stability of this data trend.

[0108] In specific implementation, in this embodiment of the invention, dynamic data can refer to dynamic changes in oil and fluid production in oil wells, and the monitoring data is mainly pressure, and may also include production profiles and production intensity monitoring along the process (profile data is very rare).

[0109] In a specific implementation, in one embodiment, the above-mentioned method for predicting the production of fracturing reservoirs may also include: after a major event, such as desalting and unblocking, repeated fracturing, etc., it is necessary to update the prediction chart of flowback rate and cumulative oil production based on oil pressure, recreate the equations corresponding to the straight line segments of oil pressure-flowback rate and cumulative oil production-flowback rate, and establish a new prediction template.

[0110] (4) Determine the production status of the oil well based on the comprehensive pressure chart morphology characteristics, i.e., step 104 above.

[0111] In step 104 above, in one embodiment, determining the well production status based on the morphological characteristics of the fitting prediction chart of the flowback rate and cumulative oil production of the fracturing reservoir can include: determining the well production status based on the following morphological characteristics of the fitting prediction chart of the flowback rate and cumulative oil production of the fracturing reservoir:

[0112] The pressure characteristics exhibited in the later stage of fracturing wells when the oil pressure changes within a preset range as the flowback rate increases; the characteristics of straight segments that are interrupted during production, exhibiting new straight segments with different slopes; the characteristics of flowback rate and pressure data when the flowback rate returns and the pressure rises above the preset amplitude value; the characteristics of changes in the slope of straight segments or other pressure fluctuations when the nozzle size is changed; and the characteristics of a continuous increase in flowback rate but low oil pressure when switching to pumping as the oil pressure drops below zero, with the actual converted formation pressure falling above the preset amplitude value.

[0113] In practice, the pressure chart may exhibit the following five or more morphological characteristics: First, the pressure changes steadily with the increase of the flowback rate, which is a pressure characteristic exhibited in the later stages of fracturing wells. Figure 6 Secondly, the straight segment was interrupted during production, exhibiting new straight segment characteristics with different slopes. This is because fracturing of other wells in the surrounding area has entered the fracture system of this well, causing a significant increase in oil pressure. Figure 7 Thirdly, the flowback rate rebounds, and the flowback rate and pressure data characteristics when the pressure exceeds the preset amplitude value are affected by repeated fracturing in this well. Figure 8 Fourth, change the size of the nozzle to alter the slope of the straight section or cause other pressure fluctuations. Figure 9 Fifth, as the oil pressure drops below zero and pumping resumes, the flowback rate continues to increase, but the oil pressure remains low, resulting in a significant decrease in the actual calculated formation pressure. Figure 10 Based on these five morphological characteristics, the straight segment, the extrapolated material return rate, and the extrapolated cumulative oil production are determined respectively.

[0114] (5) Based on the characteristics of the straight line segment on the oil pressure and cumulative production chart, determine the straight line segment, extrapolate the material return rate into the well, and extrapolate the cumulative oil production, i.e., step 105 above.

[0115] In step 105 above, in one embodiment, determining the cumulative oil production of each well in the fracturing reservoir based on the well production status and the straight line segment characteristics of the prediction chart may include:

[0116] Based on the production status of oil wells and the fitting prediction chart of flowback rate and cumulative oil production of fracturing reservoirs, the preferred linear segment characteristics are determined.

[0117] Based on the preferred straight line segment characteristics, establish the straight line equations for the oil pressure straight line segment and the cumulative oil production straight line segment;

[0118] Based on the linear equations of the oil pressure line segment and the cumulative oil production line segment, predict the limit value of the natural backflow rate when the oil pressure is zero.

[0119] Substituting the limit value of the natural flowback rate of the oil well into the linear equation, the cumulative oil production from natural flowback of each oil well in the fracturing reservoir is determined.

[0120] In specific implementation, a comprehensive chart of single-well oil pressure and cumulative production (such as...) is used. Figures 11A to 11C As shown in the figure, using the fitting prediction chart of flowback rate and cumulative production of oil pressure in fracturing reservoirs as a reference, and combining the production status, a suitable straight line stage is selected to fit and establish the linear equations for the pressure and cumulative production straight line segments. A linear trend line is drawn for the straight line segments, and this trend line equation is used as the equation for the straight line segments. Based on the straight line equations, the limit value of the natural flowback rate when the oil pressure is zero is predicted. Substituting the limit value of the natural flowback rate of the oil well into the straight line equation, the cumulative production of oil produced by natural flowback of each oil well in the fracturing reservoir is determined (e.g., ...). Figures 11A to 11C (As shown).

[0121] In practical implementation, a suitable linear phase is selected based on the production status. To more accurately predict the flowback multiple of oil wells under zero oil pressure conditions, this embodiment of the invention can determine the dimensionless oil pressure range of 0.02 to 0.2 as the key production period for well fitting. Given that the production conditions of each well are not entirely the same, a smaller production period is selected for each well within this range to improve the accuracy of the prediction.

[0122] In practice, based on the characteristics of the straight line segment on the oil pressure and cumulative production chart, the straight line segment is determined, and the material flowback rate and cumulative oil production are extrapolated. For example, Figures 11A to 11C As shown, after determining the straight line segment, a linear fit is performed on the straight line segment, and the trend line is extended to predict the flowback rate when the oil well is finally abandoned and the cumulative oil production at this flowback rate.

[0123] (6) Statistically analyze the flowback rate and predicted cumulative oil production of each well, and analyze the factors affecting the production of oil wells, which is a further preferred scheme of the present invention.

[0124] In one embodiment, the method for predicting the production of a fracturing reservoir may further include: determining the cumulative oil production of all wells in a pre-defined study area of ​​the fracturing reservoir based on the cumulative oil production of each well in the fracturing reservoir.

[0125] In practice, the flowback rate and cumulative oil production of all oil wells are statistically analyzed, and the proportional relationship of different types of oil wells is statistically analyzed to form an understanding of the overall oil well production status of the block. Specifically, the proportional relationship can be formed by statistically analyzing the number of different types of oil wells. This proportional relationship can include: stable changes in oil pressure with flowback rate, fracturing channeling, repeated fracturing, changes in production system, and low oil pressure operation.

[0126] In this embodiment of the invention, data from oil companies in multiple regions were collected and a map was established. In actual oilfield applications in multiple oilfields, it was confirmed that this pattern is universally present and can be used to predict production and for production applications in fracturing reservoirs, such as fracturing assessment.

[0127] This invention also provides an apparatus for predicting the production of fracturing reservoirs, as described in the following embodiments. Since the principle by which this apparatus solves the problem is similar to the method for predicting the production of fracturing reservoirs, the implementation of this apparatus can refer to the implementation of the method for predicting the production of fracturing reservoirs; repeated details will not be elaborated further.

[0128] Figure 12 This is a schematic diagram of the device for predicting reservoir production through fracturing in an embodiment of the present invention, as shown below. Figure 12 As shown, the device includes:

[0129] The underground equivalent volume determination unit 01 is used to take the wellhead oil, gas, water and sand produced by the fracturing oil well as the total solid and liquid volume produced; and to determine the underground equivalent volume of the wellhead oil, gas, water and sand produced based on the total solid and liquid volume produced.

[0130] The flowback rate determination unit 02 is used to take the sum of the volumes of the fracturing fluid and proppant injected into the ground as the total volume injected into the ground; based on the fracturing construction parameters, according to the underground equivalent volume or the total solid-liquid volume produced, and the total volume injected into the ground, the flowback rate of the total volume injected into the ground is determined;

[0131] Chart establishment unit 03 is used to establish a fitting prediction chart of oil well flowback rate and oil pressure cumulative oil production in fracturing reservoirs based on the flowback rate and production dynamic oil well data.

[0132] Production status determination unit 04 is used to determine the production status of oil wells based on the morphological characteristics of the fitting prediction chart of oil well flowback rate and oil pressure cumulative production in fracturing reservoirs.

[0133] The cumulative oil production determination unit 05 is used to determine the cumulative oil production of each well in the fracturing reservoir based on the production status of the oil well and the characteristics of the straight line segment of the prediction chart.

[0134] In one embodiment, the aforementioned cumulative oil production determination unit is specifically used for:

[0135] Based on the production status of oil wells and the fitting prediction chart of flowback rate and cumulative oil production of fracturing reservoirs, the preferred linear segment characteristics are determined.

[0136] Based on the preferred straight line segment characteristics, establish the straight line equations for the oil pressure straight line segment and the cumulative oil production straight line segment;

[0137] Based on the linear equations of the oil pressure line segment and the cumulative oil production line segment, predict the limit value of the natural backflow rate when the oil pressure is zero.

[0138] Substituting the limit value of the natural flowback rate of the oil well into the linear equation, the cumulative oil production from natural flowback of each oil well in the fracturing reservoir is determined.

[0139] In one embodiment, the aforementioned production status determination unit is specifically used to: determine the production status of the oil well based on the following morphological characteristics of the fitted prediction chart of the flowback rate and cumulative oil production of the fracturing reservoir:

[0140] The pressure characteristics exhibited in the later stage of fracturing wells when the oil pressure changes within a preset range as the flowback rate increases; the characteristics of straight segments that are interrupted during production, exhibiting new straight segments with different slopes; the characteristics of flowback rate and pressure data when the flowback rate returns and the pressure rises above the preset amplitude value; the characteristics of changes in the slope of straight segments or other pressure fluctuations when the nozzle size is changed; and the characteristics of a continuous increase in flowback rate but low oil pressure when switching to pumping as the oil pressure drops below zero, with the actual converted formation pressure falling above the preset amplitude value.

[0141] In one embodiment, the return rate determination unit is specifically used for:

[0142] Based on the fracturing operation, if the fracturing is a single fracturing operation, the total volume of the fracturing operation entering the ground is used as the denominator and the equivalent underground volume is used as the numerator to calculate the return rate of the total volume of the fracturing operation entering the ground as a function of time.

[0143] If repeated fracturing occurs, the total volume of the material entering the ground from at least two fracturing operations is used as the denominator, and the total volume of solid and liquid produced is used as the numerator to determine the return rate of the total volume of the material entering the ground.

[0144] In one embodiment, the chart building unit is specifically used to: construct the prediction chart using the return rate as the horizontal axis.

[0145] In one embodiment, the underground equivalent volume determination unit is specifically used for: if the underground oil reservoir is saturated, the underground equivalent volume of produced gas is calculated using the produced gas state equation combined with the dissolved gas-oil ratio; if the underground oil reservoir is unsaturated, the underground equivalent volume of produced gas exists underground in the form of dissolved gas and is included in the calculation of the crude oil underground volume coefficient, without the need for additional calculation.

[0146] In one embodiment, the underground equivalent volume determination unit is specifically used to: calculate the underground equivalent volume of produced water using the formation water volume factor.

[0147] In one embodiment, the underground equivalent volume determination unit is specifically used to: calculate the underground equivalent volume of produced oil using the underground crude oil volume coefficient.

[0148] In one embodiment, the underground equivalent volume determination unit is specifically used to: if the producing well produces sand, calculate the underground equivalent volume of the produced sand based on the relationship between the mass and density of the produced sand or based on the volume of the produced sand and the volume of the produced sand pores.

[0149] In one embodiment, the fracturing operation parameters include: sand addition rate, pump speed, pressure, fracturing fluid composition, number of segments, number of clusters, segment spacing, or cluster spacing, or any combination thereof.

[0150] In one embodiment, the apparatus for predicting the production of a fracturing reservoir may further include an overall condition determination unit, used to: determine the cumulative oil production of all wells in a predetermined study area of ​​the fracturing reservoir based on the cumulative oil production of each well in the fracturing reservoir.

[0151] This invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the above-described method for predicting the production of fracturing reservoirs.

[0152] This invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the above-described method for predicting the production of fracturing reservoirs.

[0153] This invention also provides a computer program product, which includes a computer program that, when executed by a processor, implements the above-described method for predicting the production of fracturing reservoirs.

[0154] In this embodiment of the invention, the method for predicting the production of fracturing-treated reservoirs, compared with existing technologies that cannot accurately predict the production of fracturing-treated reservoirs, involves: taking the wellhead oil, gas, water, and sand produced by the fracturing-treated reservoir well as the total produced solid-liquid volume; determining the underground equivalent volume of the produced wellhead oil, gas, water, and sand based on the total produced solid-liquid volume; taking the sum of the volumes of fracturing fluid and proppant injected into the ground as the total injected volume; and determining the total injected volume based on the fracturing operation parameters, according to the underground equivalent volume or the total produced solid-liquid volume, and the total injected volume. Based on the flowback rate and production dynamics of oil wells, a fitting prediction chart of the flowback rate and cumulative oil production of fracturing reservoirs is established. The production status of oil wells is determined based on the morphological characteristics of this chart. Based on the production status and the linear segment characteristics of the prediction chart, the cumulative oil production of each well in the fracturing reservoir is determined. This allows for accurate prediction of fracturing reservoir production based on the flowback rate and cumulative oil production fitting prediction chart, improving the accuracy of production prediction for fracturing reservoirs.

[0155] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0156] This invention is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart illustrations and / or block diagrams. Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0157] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0158] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0159] The specific embodiments described above further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above descriptions are merely specific embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for predicting oil production in fracturing reservoirs, characterized in that, include: The wellhead oil, gas, water, and sand produced by the fracturing reservoir wells are taken as the total solid and liquid volume produced; the underground equivalent volume of the wellhead oil, gas, water, and sand produced is determined based on the total solid and liquid volume produced. The total volume of fracturing fluid and proppant injected into the ground is taken as the total volume injected into the ground. Based on the fracturing operation parameters, the total volume injected into the ground is determined by the underground equivalent volume or the total volume of solid and liquid produced, as well as the total volume injected into the ground. Based on the flowback rate and production dynamics of the oil wells, a fitting prediction chart of flowback rate and oil pressure / cumulative oil production for fracturing reservoirs is established; the horizontal axis of the prediction chart is the flowback rate, and the vertical axis is the oil pressure and cumulative oil production. Based on the various morphological characteristics of the fitting prediction chart of oil well flowback rate and oil pressure cumulative production in fracturing reservoirs, the production status of oil wells is determined. Based on the production status of the oil wells and the linear segment characteristics of the prediction chart, the cumulative oil production of each oil well in the fracturing reservoir is determined, which includes: determining the preferred linear segment characteristics based on the production status of the oil wells and the fitted prediction chart of the oil well flowback rate and cumulative oil production in the fracturing reservoir. Based on the preferred straight line segment characteristics, establish the linear equations for the oil pressure straight line segment and the cumulative oil production straight line segment; based on the linear equations for the oil pressure straight line segment and the cumulative oil production straight line segment, predict the limit value of the natural flowback rate when the oil pressure is zero; substitute the limit value of the natural flowback rate of the oil well into the linear equation to determine the cumulative oil production of each oil well in the fracturing reservoir.

2. The method as described in claim 1, characterized in that, The various morphological features include: The pressure characteristics exhibited in the later stage of fracturing wells when the oil pressure changes within a preset range as the flowback rate increases; the characteristics of straight segments that are interrupted during production, exhibiting new straight segments with different slopes; the characteristics of flowback rate and pressure data when the flowback rate returns and the pressure rises above the preset amplitude value; the characteristics of changes in the slope of straight segments or other pressure fluctuations when the nozzle size is changed; and the characteristics of a continuous increase in flowback rate but low oil pressure when switching to pumping as the oil pressure drops below zero, with the actual converted formation pressure falling above the preset amplitude value.

3. The method as described in claim 1, characterized in that, Based on the fracturing operation parameters, the total underground volume flowback rate is determined according to the subsurface equivalent volume or the total produced solid-liquid volume, and the total volume injected into the ground, including: Based on the fracturing operation, if the fracturing is a single fracturing operation, the total volume of the fracturing operation entering the ground is used as the denominator and the equivalent underground volume is used as the numerator to calculate the return rate of the total volume of the fracturing operation entering the ground as a function of time. If repeated fracturing occurs, the total volume of the material entering the ground from at least two fracturing operations is used as the denominator, and the total volume of solid and liquid produced is used as the numerator to determine the return rate of the total volume of the material entering the ground.

4. The method as described in claim 1, characterized in that, Based on the flowback rate and production dynamics of oil wells, a fitting prediction chart of flowback rate and cumulative oil production in fracturing reservoirs is established, including: using the flowback rate as the horizontal axis to construct the prediction chart.

5. The method as described in claim 1, characterized in that, Based on the total produced solid and liquid volumes, determine the underground equivalent volumes of produced wellhead oil, gas, water, and sand, including: if the underground reservoir is saturated, the underground equivalent volume of produced gas is calculated using the produced gas state equation combined with the dissolved gas-oil ratio; if the underground reservoir is unsaturated, the underground equivalent volume of produced gas exists underground in the form of dissolved gas and is included in the calculation of the crude oil underground volume factor, without the need for additional calculation.

6. The method as described in claim 1, characterized in that, Based on the total solid and liquid volume produced, determine the underground equivalent volume of the produced wellhead oil, gas, water, and sand, including the underground equivalent volume of produced water, calculated using the formation water volume factor.

7. The method as described in claim 1, characterized in that, Based on the total solid and liquid volume produced, determine the underground equivalent volume of the produced wellhead oil, gas, water, and sand, including the underground equivalent volume of the produced oil, calculated using the underground crude oil volume factor.

8. The method as described in claim 1, characterized in that, Based on the total solid and liquid volume produced, determine the underground equivalent volume of the produced wellhead oil, gas, water, and sand, including: if the producing well produces sand, calculate the underground equivalent volume of the sand produced based on the relationship between the mass and density of the produced sand or based on the volume of the produced sand and the volume of the sand pores.

9. The method as described in claim 1, characterized in that, The fracturing operation parameters include: sand addition rate, pump speed, pressure, fracturing fluid composition, number of segments, number of clusters, segment spacing or cluster spacing, or any combination thereof.

10. The method as described in claim 1, characterized in that, Also includes: Based on the cumulative oil production of each well in the fracturing reservoir, the cumulative oil production of all wells in the pre-defined study area of ​​the fracturing reservoir is determined.

11. A device for predicting the production of fracturing reservoirs, characterized in that, include: The underground equivalent volume determination unit is used to take the wellhead oil, gas, water and sand produced by the fracturing oil well as the total solid and liquid volume produced. Based on the total solid and liquid volume produced, determine the underground equivalent volume of the wellhead oil, gas, water, and sand produced. The flowback rate determination unit is used to take the sum of the volumes of the fracturing fluid and proppant injected into the ground as the total volume injected into the ground; based on the fracturing construction parameters, according to the underground equivalent volume or the total solid-liquid volume produced, and the total volume injected into the ground, the flowback rate of the total volume injected into the ground is determined; The chart creation unit is used to create a fitting prediction chart of the flowback rate and cumulative oil production of wells in fracturing reservoirs based on the flowback rate and production dynamics data. The horizontal axis of the prediction chart is the flowback rate, and the vertical axis is the oil pressure and cumulative oil production. The production status determination unit is used to determine the production status of oil wells based on various morphological characteristics of the fitting prediction chart of oil well flowback rate and oil pressure cumulative production in fracturing reservoirs. The cumulative oil production determination unit is used to determine the cumulative oil production of each oil well in the fracturing reservoir based on the oil well production status and the straight line segment characteristics of the prediction chart. It includes: determining the preferred straight line segment characteristics based on the oil well production status and the oil well flowback rate and oil pressure cumulative oil production fitting prediction chart of the fracturing reservoir. Based on the preferred straight line segment characteristics, establish the linear equations for the oil pressure straight line segment and the cumulative oil production straight line segment; based on the linear equations for the oil pressure straight line segment and the cumulative oil production straight line segment, predict the limit value of the natural flowback rate when the oil pressure is zero; substitute the limit value of the natural flowback rate of the oil well into the linear equation to determine the cumulative oil production of each oil well in the fracturing reservoir.

12. The apparatus as claimed in claim 11, characterized in that, The various morphological features include: The pressure characteristics exhibited in the later stage of fracturing wells when the oil pressure changes within a preset range as the flowback rate increases; the characteristics of straight segments that are interrupted during production, exhibiting new straight segments with different slopes; the characteristics of flowback rate and pressure data when the flowback rate returns and the pressure rises above the preset amplitude value; the characteristics of changes in the slope of straight segments or other pressure fluctuations when the nozzle size is changed; and the characteristics of a continuous increase in flowback rate but low oil pressure when switching to pumping as the oil pressure drops below zero, with the actual converted formation pressure falling above the preset amplitude value.

13. The apparatus as claimed in claim 11, characterized in that, The return rate determination unit is specifically used for: Based on the fracturing operation, if the fracturing is a single fracturing operation, the total volume of the fracturing operation entering the ground is used as the denominator and the equivalent underground volume is used as the numerator to calculate the return rate of the total volume of the fracturing operation entering the ground as a function of time. If repeated fracturing occurs, the total volume of the material entering the ground from at least two fracturing operations is used as the denominator, and the total volume of solid and liquid produced is used as the numerator to determine the return rate of the total volume of the material entering the ground.

14. The apparatus as claimed in claim 11, characterized in that, The chart building unit is specifically used to construct the prediction chart using the return rate as the horizontal axis.

15. The apparatus as claimed in claim 11, characterized in that, The underground equivalent volume determination unit is specifically used for: if the underground oil reservoir is saturated, the underground equivalent volume of produced gas is calculated using the produced gas state equation combined with the dissolved gas-oil ratio; if the underground oil reservoir is unsaturated, the underground equivalent volume of produced gas exists underground in the form of dissolved gas and is included in the calculation of the crude oil underground volume coefficient, without the need for additional calculation.

16. The apparatus as claimed in claim 11, characterized in that, The underground equivalent volume determination unit is specifically used for: calculating the underground equivalent volume of produced water using the formation water volume coefficient.

17. The apparatus as claimed in claim 11, characterized in that, The underground equivalent volume determination unit is specifically used for: the underground equivalent volume of produced oil, calculated using the underground crude oil volume coefficient.

18. The apparatus as claimed in claim 11, characterized in that, The underground equivalent volume determination unit is specifically used to: if the producing well produces sand, calculate the underground equivalent volume of the produced sand based on the relationship between the mass and density of the produced sand or based on the volume of the produced sand and the volume of the produced sand pores.

19. The apparatus as claimed in claim 11, characterized in that, The fracturing operation parameters include: sand addition rate, pump speed, pressure, fracturing fluid composition, number of segments, number of clusters, segment spacing or cluster spacing, or any combination thereof.

20. The apparatus as claimed in claim 11, characterized in that, It also includes an overall condition determination unit, which is used to determine the cumulative oil production of all wells in the pre-set study area of ​​the fracturing reservoir based on the cumulative oil production of each well in the fracturing reservoir.

21. A computer device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the method of any one of claims 1 to 10.

22. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores a computer program that, when executed by a processor, implements the method of any one of claims 1 to 10.

23. A computer program product, characterized in that, The computer program product includes a computer program that, when executed by a processor, implements the method of any one of claims 1 to 10.

Images