CN111878073A - Method and device for evaluating fracturing effect of tight reservoir - Google Patents
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Abstract
The embodiment of the specification provides a method and a device for evaluating fracturing effect of a tight reservoir. The method comprises the following steps: acquiring total flowback data after reservoir fracturing; determining flowback data of the cracks of each fracturing section according to the total flowback data; the flowback data comprise the flowback volume of fracturing fluid in flowback fluid, the flowback volume of formation water, the mineralization degree of the flowback fluid and the flowback time; and determining the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section, greatly improve the evaluation accuracy of the fracturing effect of the reservoir and provide reliable data for later-stage history fitting and yield prediction.
Description
Technical Field
The embodiment of the specification relates to the technical field of compact oil and gas exploration and development, in particular to a method and a device for evaluating the fracturing effect of a compact reservoir.
Background
Along with the development of unconventional oil and gas, the development difficulty of oil and gas reservoirs is gradually increased, in order to more fully exploit the oil and gas, the yield increasing transformation of a reservoir (usually referred to as an oil layer or a gas layer) is required, and the staged fracturing of a horizontal well is a key technology of the unconventional oil and gas development in the United states. In the field of petroleum, fracturing refers to a method of forming fractures in oil and gas reservoirs by utilizing the action of water power in the process of oil extraction or gas production, and is also called hydraulic fracturing. Fracturing is to artificially crack a stratum, improve the flowing environment of oil gas in the underground and increase the yield of an oil-gas well, and fracturing modification plays an important role in improving the flowing condition of the bottom of the oil-gas well, reducing the flow resistance between layers and improving the using condition of the oil-gas layer. Therefore, the method for evaluating the fracturing effect of the reservoir has very important functions on capacity prediction and development decision of the reservoir.
The currently common post-fracture evaluation tools are microseisms and potentiometric monitoring, and many fracture mapping techniques are used to infer fracture geometry, such as radioactive tracers, surface and downhole inclinometers, and various electromagnetic measurement techniques. The micro-seismic and potential monitoring method has the problems of high construction difficulty, high cost and the like. Complex microseismic measurements have been developed to infer the geometric dimensions of the fracture, their extended use is limited by the limitations of their field of view and expensive instrumentation, and microseismic monitoring signals are noisy, the size of the fracture being analyzed is inaccurate, and cannot accurately provide the fracture volume and conductivity of the support. When the crack width is monitored by the tracer, sampling points are few, the time-space distribution of the tracer cannot be accurately obtained, the data provided by a fracturing graphic representation technology is limited (namely the crack direction or the shaft height), and the whole fracturing construction can be used only after finishing.
Post-fracturing fracture evaluation according to well testing can be realized by producing for a certain time after fracturing and then closing the well pressure recovery, and the timeliness is lacked. Generally, the average parameters of fractures and reservoirs are obtained by adopting a long-term pressure instability analysis method or a yield instability analysis method, the yield is analyzed, the time consumption is long, the fluid property is simplified, and the fracture results are relatively general. Especially for unconventional reservoirs, the matrix-to-fracture flow time is long, influenced by the fracture properties, and fracture characteristics need to be characterized early in the well life.
Disclosure of Invention
The embodiment of the specification aims to provide a method and a device for evaluating the fracturing effect of a compact reservoir so as to improve the accuracy of evaluating the fracturing effect of the reservoir.
In order to solve the above problems, embodiments of the present specification provide a method and an apparatus for evaluating a fracturing effect of a tight reservoir.
A method for evaluating fracturing effects of tight reservoirs, the method comprising: acquiring total flowback data after reservoir fracturing; determining flowback data of the cracks of each fracturing section according to the total flowback data; the flowback data comprise the flowback volume of fracturing fluid in flowback fluid, the flowback volume of formation water, the mineralization degree of the flowback fluid and the flowback time; and determining the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section.
A tight reservoir fracturing effectiveness evaluation device, the device comprising: the acquisition module is used for acquiring total flowback data after the reservoir fracturing; the determining module is used for determining the flowback data of the cracks of each fracturing section according to the total flowback data; the flowback data comprise the flowback volume of fracturing fluid in flowback fluid, the flowback volume of formation water, the mineralization degree of the flowback fluid and the flowback time; and the evaluation module is used for determining the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section.
According to the technical scheme provided by the embodiment of the specification, the embodiment of the specification can acquire total flowback data after the reservoir fracturing; determining flowback data of the cracks of each fracturing section according to the total flowback data; the flowback data comprise the flowback volume of fracturing fluid in flowback fluid, the flowback volume of formation water, the mineralization degree of the flowback fluid and the flowback time; and determining the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section. The method for evaluating the fracturing effect of the compact reservoir provided by the embodiment of the specification can evaluate a single-stage crack or a multi-stage crack, specifically analyze the characteristics of each stage of crack, determine the complexity of the crack and solve the crack parameters through single-stage crack analysis and calculation, thereby comprehensively evaluating the fracturing effect of the reservoir and greatly improving the accuracy of evaluating the fracturing effect of the reservoir.
Drawings
In order to more clearly illustrate the embodiments of the present specification or the technical solutions in the prior art, the drawings used in the description of the embodiments or the prior art will be briefly described below, it is obvious that the drawings in the following description are only some embodiments described in the specification, and other drawings can be obtained by those skilled in the art without creative efforts.
FIG. 1 is a flow chart of a method for evaluating fracturing effect of a tight reservoir according to an embodiment of the present disclosure;
FIG. 2 is a diagram illustrating the relationship between the degree of mineralization of a flow-back fluid and the variation of the cumulative flow-back volume in an embodiment of the present disclosure;
FIG. 3 is a schematic diagram of the crack width distribution range and frequency in an embodiment of the present disclosure;
FIG. 4 is a graph of the log-log relationship between MBT and RNP in an example of the present disclosure;
fig. 5 is a functional module schematic diagram of a tight reservoir fracturing effect evaluation device in an embodiment of the present disclosure.
Detailed Description
The technical solutions in the embodiments of the present disclosure will be clearly and completely described below with reference to the drawings in the embodiments of the present disclosure, and it is obvious that the described embodiments are only a part of the embodiments of the present disclosure, and not all of the embodiments. All other embodiments obtained by a person of ordinary skill in the art based on the embodiments in the present specification without any creative effort shall fall within the protection scope of the present specification.
In the embodiment of the present specification, the fracturing fluid injected into the formation after the reservoir fracturing is finished is returned to the ground, which is called fracturing fluid flowback, and the returned fracturing fluid after the fracturing fluid has acted on the formation is called flowback fluid. The flowback fluid may include formation water and fracturing fluid. The fracturing fluid is a heterogeneous unstable chemical system formed by a plurality of additives according to a certain proportion, is a working fluid used for fracturing modification of an oil-gas reservoir, and has the main function of transmitting high pressure formed by ground equipment into a stratum so as to crack the stratum to form a crack and convey a propping agent along the crack. The flow-back data after the fracturing of the reservoir can be obtained, the flow-back data is early time-pressure-yield data after well completion, well and reservoir information can be reflected, the flow-back rate is calculated by monitoring fluid components, the long-term production capacity and potential problems of the well can be predicted, and the production dynamic analysis can be carried out.
However, flowback data analysis is difficult, mainly due to fast environmental changes of the fracture network and the wellbore, multiphase flow in the fracture, completion heterogeneity, and the like. In the conventional method, after fracturing is completed, single-well multi-fracture integral flowback is analyzed, obtained fracture parameters only represent the average level of the integral, but actually, due to the fact that fracturing construction parameters such as fracturing sequence and cluster spacing of each section are different, parameters such as the length, the width and the flow conductivity of each section of fracture are different, contribution of each section of fracture to the total oil and gas yield is different, fracture parameters obtained through analysis of flowback data of the single-well multi-fracture integral generally assume single-phase flow, results are possibly inaccurate, and in a commonly used flowback data analysis method, flowback quantity of flowback liquid is generally analyzed, composition components of the flowback liquid are ignored, and accordingly, evaluation parameters after fracturing are inaccurate. Considering that communication exists between sections and wells in the flowback process, and the fractures are more complex for unconventional reservoirs, if flowback data of fracturing of each section are collected in a segmented mode and flowback amount of fracturing fluid of each section is distinguished, accuracy of fracturing effect evaluation of compact reservoirs is expected to be improved.
Based on the thought, the embodiment of the specification provides a method for evaluating the fracturing effect of a compact reservoir. In the embodiment of the present specification, a main body for executing the tight reservoir fracturing effect evaluation method may be an electronic device having a logical operation function, and the electronic device may be a server or a client. The client can be a desktop computer, a tablet computer, a notebook computer, a workstation and the like. Of course, the client is not limited to the electronic device with certain entities, and may also be software running in the electronic device, or may also be program software formed by program development. The program software may be run in the electronic device described above.
Specifically, refer to fig. 1, which is a processing flow chart of a method for evaluating fracturing effect of a tight reservoir according to an embodiment of the present disclosure. The method for evaluating the fracturing effect of the tight reservoir provided by the embodiment of the specification can be implemented specifically by the following steps.
S110: and acquiring total flowback data after fracturing of the reservoir.
In some embodiments, the return of the fracturing fluid injected into the formation to the surface after fracturing the reservoir is called a fracturing fluid flowback, and the returned fracturing fluid after interacting with the formation is called a flowback fluid. Flowback is performed after fracturing the reservoir, and total flowback data after fracturing can be obtained. The total flowback data may include data such as initial reservoir pressure, bottom hole pressure, mineralization degree of flowback fluid, surface flowback fluid flow, accumulated flowback volume, total compression coefficient, and viscosity of produced fluid.
In some embodiments, the server may obtain total flowback data after a reservoir fracture in any manner. For example, a user may directly send total flowback data after reservoir fracturing to a server, and the server may receive the total flowback data; in another example, in an embodiment of the present specification, there is no limitation on how the server obtains the total flowback data after the reservoir fracturing by using any method, for example, other electronic devices except the server may send the total flowback data after the reservoir fracturing to the server, and the server may receive the total flowback data.
S120: determining flowback data of the cracks of each fracturing section according to the total flowback data; and the flowback data comprises the flowback volume of the fracturing fluid in the flowback fluid and the flowback volume and the flowback time of the formation water.
In some embodiments, the return displacement amount of the fracturing fluid in the return fluid and the return displacement amount of the formation water, and the mineralization degree and the return time of the return fluid may specifically include a real-time return displacement amount and an accumulated return displacement amount of the fracturing fluid in the return fluid, a real-time return displacement amount and an accumulated return displacement amount of the formation water, a real-time mineralization degree and an accumulated mineralization degree of the return fluid at each return moment, and after the return displacement is finished, a real-time return displacement amount and an accumulated return displacement amount of the fracturing fluid in the return fluid, a real-time return displacement amount and an accumulated return displacement amount of the formation water, and a real-time mineralization degree and an accumulated mineralization degree of the return fluid.
In some embodiments, due to the difference of fracturing construction parameters such as the fracturing sequence and the cluster spacing of each section, the fracture morphology, the fracture width, the flow conductivity and other parameters of each fracturing section are different, and the contribution of each fracturing section fracture to the total oil and gas yield is also different. In order to find out the specific condition of the fractures of each fracturing section, different types of chemical tracers can be added into the fracturing fluid of each fracturing section, and the concentration of the tracers used for fracturing of different fracturing sections in the wellhead flowback fluid at each flowback moment is monitored to determine the flowback data of each fracturing section.
Specifically, different types of chemical tracers can be added into the fracturing fluid of each fracturing section, after fracturing is completed, the concentration changes of the different types of chemical tracers in the flowback fluid are monitored, and the flowback volume of the fracturing fluid of each fracturing section is distinguished through a substance balance method. Supposing that the concentration of a tracer agent which is designed and added into the jth fracturing section fracturing fluid before fracturing is C in the whole fracturing construction processt,jFor the jth fracturing stage, the volume of fracturing fluid used is
Assuming the tracer used is at each fractureThe section has no leakage and is not adsorbed on stratum rock, and the chemical tracer after fracturing is uniformly distributed in the fracturing fluid and stratum water of a shaft, a crack and a matrix pore of the fracturing section, and the concentration of the tracer existing in the fracturing fluid and the stratum water is C't,jFor the ith backflow time, the total backflow liquid volume collected on the ground is Vi mAnd the concentration of the chemical tracer used for fracturing the jth fracturing section in the total flowback fluid collected on the ground is measured to be Ct,j,i(ii) a The volume of the fracturing fluid in the fracturing flowback fluid of the jth fracturing section is set as
Volume of formation water
The amount of tracer entering the jth fracture zone in the formation may be expressed as
Amount of tracer in jth fracturing section of ground flowback at ith flowback time
Assuming that the time is long enough, the tracer entering the stratum is finally and completely discharged back, and the amount of the tracer entering the jth fracturing section in the stratum is equal to the amount of the tracer returned and discharged from the jth fracturing section at all the back-discharge moments, then:
the volume of the fracturing fluid which is returned by the fracturing of the j fracturing section in the i returning moment returning fluid can be obtained according to the formula (1)
And volume of formation water
In some embodiments, for the ith flowback time, the mineralization degree of the jth fracturing section flowback fluid is provided by the two parts of the flowback fracturing fluid and formation water in the jth fracturing section flowback fluid, and the relationship is as follows:
the salt content in the jth fracturing section flowback fluid is equal to the salt content in the fracturing fluid in the jth fracturing section flowback fluid and the salt content in the stratum water in the jth fracturing section flowback fluid, namely:
The volume of the fracturing fluid which is returned by the fracturing of the jth fracturing section in the ith returning moment returning fluid is obtained according to the calculation
And volume of formation water
The mineralization degree of the return fluid of the jth fracturing section at the ith return moment can be obtained
Comprises the following steps:
Ctrepresents the concentration of the tracer; csRepresents the degree of mineralization; j represents a fracture zone; i represents the discharge return time; superscript f denotes fracturing fluid; superscript w represents formation water; the superscript m denotes the flowback fluid.
S130: and determining the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section.
In a fracturing process, a complex fracture network is possibly generated, for example, in an unconventional oil and gas development process of shale gas, shale oil and the like, the fracturing can generate the complex fracture network due to high rock brittleness and existence of natural fractures. The fracturing effect of the tight reservoir can be qualitatively evaluated by determining the complexity of the fracture. Wherein, the more complicated the crack, the bigger the contact area of fracturing fluid and rock, the higher the imbibition rate, lead to high filtration, low flowback. In complex fractures, the tortuosity of secondary fractures can cause water lock, and fracturing fluid retained in the fractures enters a matrix through imbibition due to capillary force, chemical osmotic pressure, clay adsorption and the like, so that more oil gas is replaced.
In some embodiments, the complexity of each fracture section fracture may be determined according to the following method.
The method comprises the following steps: and judging the complexity of the crack according to the change relation of the mineralization degree of the backflow liquid along with the accumulated backflow amount.
In some embodiments, the fluid in the wellbore and wider hydraulic fractures is first drained when flowback is initiated, which is primarily a fracturing fluid raffinate. As flowback time increases, fluid in the secondary fractures begins to drain, resulting in increased flowback fluid mineralization due to ion exchange of the fracturing fluid in the secondary fractures with formation water and prolonged contact with rock minerals. The mineralization degree of the return fluid of different fracturing sections changes along with the change of the accumulated return discharge amount, the mineralization degree of the return fluid of some fracturing sections is always increased, and the mineralization degree of the return fluid of some fracturing sections is leveled after being increased to a certain degree, so that the complexity degree of the fracture can be qualitatively described through the change of the mineralization degree of the return fluid along with the change of the accumulated return discharge amount.
For large-section multi-cluster fracturing, a plurality of fractures may exist in each cluster, and based on Fick's first law, the relationship between the fracture width and the mineralization of the nth fracture in the jth fracturing section is established:
According to the formula (4), the mineralization of the crack is inversely proportional to the width of the crack, and the higher the mineralization of the crack is, the smaller the width of the crack is. However, in the formula (4), the mineralization degree of the nth crack in the j fracturing section is difficult to directly measure, and the crack width cannot be directly calculated, but the mineralization degree of the return fluid can be monitored on the ground, and the relationship between the amount of the return fluid on the ground and the mineralization degree of the crack can be established. For the ith flowback time, the salt content in the jth fracturing section fracturing flowback fluid is provided by n cracks, the amount of the flowback fluid is approximately equal to the volume of the n cracks participating in the flowback, and the method comprises the following steps:
Aj,i,nthe fracture cross-sectional area is indicated. The mineralization degree of the jth fracturing section flowback fluid at the ith flowback moment can be obtained by the formula (3)
And calculating the variation trend of the mineralization degree of the flowback liquid of the j fracturing section, and judging the variation trend of the mineralization degree of the fracture in the j fracturing section according to the variation of the mineralization degree of the flowback liquid along with the accumulated flowback volume, thereby describing the complexity of the fracture.
As shown in fig. 2, comparing the fracturing section a with the fracturing section B, the mineralization degree of the fracturing section a is increased along with the increase of the accumulated flowback volume, and after the liquid in the hydraulic fracture flows back, the mineralization degree in the later period of flowback is increased due to the high-salt fluid in the secondary fracture; and the mineralization degree of the fracturing section B is firstly increased along with the increase of the accumulated return displacement and gradually tends to be unchanged, and the mineralization degree is shown as a gentle section on the graph. The width distribution range of the cracks in the fracturing section A is larger than that of the cracks in the fracturing section B, which indicates that the shape of the cracks in the fracturing section A is more complex.
The second method comprises the following steps: and determining the complexity of the fracture of each fracturing section according to the probability density relation between the mineralization of the flowback fluid and the width of the fracture.
Because the width of the crack cannot be directly calculated in the formula (4), the probability density function of the width of the crack can be obtained through formula transformation, the distribution range of the width of the crack and the occupation ratio of the cracks with different widths are obtained, the probability density of the width of the crack is related to the mineralization degree of the return fluid, specifically, the probability density of the width of the crack can be calculated according to the mineralization degree of the return fluid, and therefore the complexity of each section of crack is determined:
wherein, f (w)j) A probability density distribution function representing the fracture width of the j fracture section;
representing the mineralization degree of the fracture flowback fluid of the jth fracturing section; n is a radical ofjRepresenting the normalized return displacement, i.e. the ratio of the accumulated return displacement to the real-time return displacement,
QC，jindicating the accumulated amount of flow back, at indicating the flow back time,
the calculation can be carried out by derivation of a relation curve of the normalized return discharge capacity and the degree of mineralization of the return discharge liquid.
Specifically, the distribution range of the crack width can be obtained according to the probability density curve of the crack width, so that the complexity of the crack can be judged according to the formula (6). As shown in fig. 3, the fracture width distribution range of the fracture section a is wider than that of the fracture section B, is between 0.11 mm and 0.23mm, and is bimodal, at this time, the fracture in the fracture section a is mainly formed by two fractures with aperture ranges, the frequency of occurrence of the fracture with the fracture width of 0.14mm is the highest, and the frequency of occurrence of the fracture with the fracture width of 0.22mm is the second order; the fracture width distribution range of the fracturing section B is narrow and is between 0.1 and 0.2mm, the fracture width distribution range is unimodal, at the moment, the fracture in the fracturing section B mainly consists of the fracture with a single fracture width range, and the fracture with the fracture width of 0.14mm is taken as the main fracture. The fracture morphology in the fracturing section a is therefore more complex.
The third method comprises the following steps: and evaluating the complexity of the cracks of each fracturing section according to the actual flowback rate of the fracturing fluid.
The flowback rate of the simple plane cracks is relatively high, the secondary cracks in the complex cracks are not filled or filled with a small amount of propping agent, the fracturing fluid entering the secondary cracks is almost immovable, and simultaneously, due to the action of gravity, the phenomenon of oil-gas-water separation occurs in the cracks, so that the relative permeability of the fracturing fluid is low, the fracturing fluid is difficult to flow out, and the flowback rate of the fracturing fluid of the complex cracks is low.
Specifically, the actual flow rate of the fracturing fluid of each fracturing section can be determined according to the flow rate of the fracturing fluid flowing back from the jth fracturing section and the total injected fracturing fluid flow rate of the jth fracturing section. The higher the flowback rate, the lower the fracture complexity.
Wherein the content of the first and second substances,
denotes the volume of fracturing fluid used in the jth fracture zone, KjAnd (4) representing the actual flowback rate of the fracturing fluid of the j-th fracturing section.
In some embodiments, the complexity of each section of the fracture may be determined according to method one, method two, and method three.
In some embodiments, fracture parameters for each fracture stage fracture may be determined from the flowback data by the following steps.
S131: and calculating the flow normalized pressure and the material balance time according to the relation between the flow and the pressure data in the flow returning process.
In some embodiments, bottom hole pressure, surface flow and accumulated flowback volume of the frac well initial flowback may be collected, and the flow normalized pressure RNP and the material balance time MBT calculated:
wherein p isinitialRepresenting reservoir initial pressure, pwfRepresenting the bottom hole pressure, qsRepresenting ground flow, Qc,jIndicating the cumulative return displacement, RNP the normalized pressure, and MBT the mass-balance time.
S132: and (3) deriving the flow normalized pressure, determining the flow state of the fluid in the fracture of each fracturing section according to the derivative of the flow normalized pressure, and dividing the flow stages according to the flow state of the fluid.
Specifically, the flowback data may be substituted into equations (8) - (10) to obtain a plurality of sets of RNP and MBT, and as shown in fig. 4, a relation curve between MBT and RNP may be plotted in a log-log coordinate system, and the flow normalized pressure is derived to obtain equation (11):
where RNP' represents the derivative of RNP.
In some embodiments, the flow state of the fluid in the fractures of each fracture section can be determined according to the flowback data and the relationship between the flow normalized pressure RNP' and the material balance time MBT, and the flow stages can be divided according to the flow state of the fluid.
Specifically, the flow phase may be divided according to the slope of the relationship between MBT and RNP 'by substituting the flowback data into equation (11) to draw a relationship between MBT and RNP'. In a specific example, the relationship between MBT and RNP and the relationship between MBT and RNP 'are shown in fig. 4, where the part with the slope 1/4 of the relationship between MBT and RNP' is shown by a solid black line, and the flow state of the fluid in this stage is a bilinear flow stage; the part with the slope 1/2 of the curve of MBT versus RNP' is shown by the black dashed line, and the flow state of the fluid in the phase is a linear flow phase; and the boundary effect appears at the later stage, the part of the curve of the relation between MBT and RNP' with the slope of 1 is shown by a black chain line, the boundary effect appears at the stage, and the flow state of the fluid at the stage is a boundary flow stage.
S133: and fitting the functional relation between the flow normalized pressure and the material balance time of different flow stages.
In some embodiments, after the flow phases are divided, the slope and intercept of the RNP and MBT relationships can be determined by fitting the RNP and MBT relationships of the different flow phases to their functional relationships.
In some embodiments, a linear function fit is made to the RNP and MBT relationship curves for the flow phase of the flow back liquid, determining the slope and intercept of the curves.
RNP＝aMBT+b (12)
Wherein, a represents the slope of the RNP and MBT relation curve of the flow stage of the return liquid, and b represents the intercept of the RNP and MBT relation curve of the flow stage of the return liquid.
S134: fracture parameters are determined based on a functional relationship between flow normalized pressure and material equilibrium time for different flow stages.
In some embodiments, the fracture parameters may include fracture half-length, fracture conductivity, and fracture permeability.
In some embodiments, the conductivity of the fracture is the ability of the proppant-filled fracture to pass fluids under the influence of reservoir effects. Permeability (K) of the tape is generally supported by means of a slitf) And support gap width (w)f) Product of (K)fwf) To indicate. In the fracturing optimization design, the concept of dimensionless conductivity can also be used, namely (K)fwf)/(KLf) Is shown in which LfDenotes the crack length, K denotes reservoirLayer permeability. The dimensionless conductivity represents the matching relation between the fracture conductivity and the reservoir liquid supply capacity, and too small dimensionless conductivity means that the flow capacity in the fracture is smaller than the formation liquid supply capacity, and the yield is reduced; too large dimensionless conductivity means that the fracture has sufficient flow capacity, but the formation cannot supply liquid to follow up, which causes unnecessary waste, and the appropriate dimensionless conductivity is important for evaluating the economic benefit of the fracturing. After fracturing construction, the yield increasing effect and the validity period have a great relationship with the flow conductivity of the crack. The main factors affecting fracture conductivity may include the physical properties of the proppant, the placement concentration of the proppant in the fracture, fracture closure pressure, the mechanical properties of the reservoir rock, and the damage of the fracturing fluid to the support zone, among others.
In some embodiments, for the fracturing fluid flowback stage, the overall storage coefficient and permeability of the fracture may be estimated from the slope and intercept of the functional relationship of the MBT to RNP in the flowback stage. Specifically, the total storage coefficient is calculated using the following equation:
Cst＝B/a (13)
wherein, CstRepresenting the total storage coefficient and B the formation volume factor.
After obtaining the total storage coefficient, the permeability of the fracture can be obtained by the following formula:
wherein k isfDenotes the permeability of the crack, phifDenotes the crack porosity, CtDenotes the total compression factor, mu fluid viscosity, A is the displacement area, reDenotes the displacement radius, rwRepresents the wellbore radius and γ represents the euler constant.
In some embodiments, the fracture half-length may be the distance the fracture extends from the wellbore along the radial reservoir after a fracture modification of the reservoir, generally referred to as the fracture length of a horizontal fracture. The half-length of the crack is one of the crack size factors. Fracture size elements may also include the width and height of the fracture, which may characterize the effectiveness of the reservoir being fracture engineered.
In some embodiments, for the case of boundary flow, the fracture half-length may be estimated according to the functional relationship between the boundary flow phase MBT and the RNP, and the fracture conductivity may be calculated according to the functional relationship between the bilinear flow phase MBT and the RNP. Specifically, if a boundary flow phase occurs, the fracture half-length is calculated using the following equation:
if the bilinear flow occurs, the fracture conductivity can be obtained by the following formula:
in the formula, OGIP represents the original gas volume and is obtained by calculation according to the slope of the relation function of RNP and MBT in the boundary flow phase, SwiRepresenting initial water saturation, T representing reservoir temperature, keffDenotes effective permeability,. mu.denotes viscosity, ctDenotes the total compression factor, xfDenotes the half-length of the crack, BgiRepresenting the original gas volume coefficient, xeRepresents the perforation spacing, h represents the reservoir thickness, phi represents the porosity, nfDenotes the number of fracture clusters, FCDDenotes the dimensionless conductivity of the fracture, S3Representing the slope of the bilinear flow phase RNP versus MBT function.
In some embodiments, the fracturing effect of the reservoir can be evaluated according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section. Specifically, the difference coefficient of the fracture parameters can be calculated according to the fracture parameters of the fractures of each fracturing section, and the difference degree of the fractures of each fracturing section is judged; evaluating the reservoir fracturing effect according to the difference degree of the fractures of each fracturing section and the complexity degree of the fractures of each fracturing section; the difference degree of the fractures corresponds to the complexity degree of the fractures to a certain degree, for a compact reservoir, the smaller the difference of the fractures of each fracturing section is, the more uniform the fractures are, the higher the complexity degree is, and the better the fracturing effect of the reservoir is; the larger the difference of the fractures of each fracturing section is, the more one or more main fractures exist, the lower the complexity of the fractures is, and the worse the fracturing effect of the reservoir is.
The difference coefficient is the percentage of the standard deviation of a group of data and the mean value thereof, is a relative index for measuring and calculating the data discrete degree, and is a relative difference number. Since there is no measurement unit for the relative difference amount, it is suitable for comparison of data variation cases where the measurement units are different or where the measurement units are the same but the concentration amounts are different greatly. The larger the difference coefficient of the fracture parameters of the fractures of each fracturing section is, the larger the difference degree of the fractures of each fracturing section is.
By quantitatively analyzing multiphase flowback data of a multi-section fractured horizontal well (MFHW), the complexity of fractures can be described, whether a complex fracture network is formed or not can be preliminarily judged, and an effective oil-gas seepage channel can be provided for a low-permeability and unconventional reservoir stratum and the oil-gas yield can be ensured; and the volume is effectively reconstructed according to the crack, so that oil and gas yield prediction and economic evaluation are performed, and a basis is provided for development decision-making. Compared with the traditional well testing method for acquiring the parameters of the fractures and the reservoir layers, the fracturing effect evaluation based on the flowback data of the fracturing fluid can truly reflect the fracturing effect during the fracturing. The time from the fracturing end to the flowback end is short, the flow of the fracturing fluid to the stratum is limited for the low-permeability stratum, and compared with pressure recovery data and production data, the flowback data interpretation result can reflect the fracturing effect of the stratum during fracturing.
The method for evaluating the fracturing effect of the compact reservoir provided by the embodiment of the specification can be used for acquiring total flowback data after the reservoir is fractured; determining flowback data of the cracks of each fracturing section according to the total flowback data; the flowback data comprise the flowback volume of fracturing fluid in flowback fluid, the flowback volume of formation water, the mineralization degree of the flowback fluid and the flowback time; and determining the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section. The method for evaluating the fracturing effect of the compact reservoir provided by the embodiment of the specification can evaluate a single-stage crack or a multi-stage crack, specifically analyze the characteristics of each stage of crack, determine the complexity of the crack and solve the crack parameters through single-stage crack analysis and calculation, thereby comprehensively evaluating the fracturing effect of the reservoir and greatly improving the accuracy of evaluating the fracturing effect of the reservoir.
Referring to fig. 5, an embodiment of the present specification further provides a device for evaluating a fracturing effect of a tight reservoir, and the device may specifically include the following structural modules.
An obtaining module 510, configured to obtain total flowback data after reservoir fracturing;
a determining module 520, configured to determine flowback data of fractures of each fracturing segment according to the total flowback data; the flowback data comprise the flowback volume of fracturing fluid in flowback fluid, the flowback volume of formation water, the mineralization degree of the flowback fluid and the flowback time;
and the evaluation module 530 is configured to determine the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data, so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section.
In some embodiments, the determining flowback data for each fracture section fracture from the total flowback data comprises: adding different chemical tracers into the fracturing fluid of each fracturing section, and determining flowback data of the fractures of each fracturing section according to the change relation of the concentration of the chemical tracers used for fracturing of different fracturing sections in the wellhead flowback fluid along with flowback time.
In some embodiments, the evaluation module may include: the fracture complexity determining module is used for comprehensively determining the complexity of the fracture of each fracturing section according to at least two of the following modes: judging the complexity of the cracks of each fracturing section according to the change relation of the mineralization degree of the flowback fluid along with the accumulated flowback volume; determining the complexity of the fracture of each fracturing section according to the probability density relation between the mineralization degree of the flowback fluid and the width of the fracture; and evaluating the complexity of the cracks of each fracturing section according to the actual flowback rate of the fracturing fluid.
In some embodiments, the evaluation module may further include: the fracture parameter determination module is used for calculating flow normalized pressure and material balance time according to the relationship between the fracture and reservoir properties and flow and pressure data in the flowback process; the flow normalized pressure is derived, the flow state of the fluid in the fracture of each fracturing section is determined according to the derivative of the flow normalized pressure, and the flow stages are divided according to the flow state of the fluid; fitting a functional relation between the flow normalized pressure and the material balance time in different flow stages; and determining fracture parameters of each fracturing section based on the functional relation between the flow normalized pressure and the material balance time of different flowing stages.
It should be noted that, in the present specification, each embodiment is described in a progressive manner, and the same or similar parts in each embodiment may be referred to each other, and each embodiment focuses on differences from other embodiments. In particular, as for the apparatus embodiment and the apparatus embodiment, since they are substantially similar to the method embodiment, the description is relatively simple, and reference may be made to some descriptions of the method embodiment for relevant points.
After reading this specification, persons skilled in the art will appreciate that any combination of some or all of the embodiments set forth herein, without inventive faculty, is within the scope of the disclosure and protection of this specification.
In the 90 s of the 20 th century, improvements in a technology could clearly distinguish between improvements in hardware (e.g., improvements in circuit structures such as diodes, transistors, switches, etc.) and improvements in software (improvements in process flow). However, as technology advances, many of today's process flow improvements have been seen as direct improvements in hardware circuit architecture. Designers almost always obtain the corresponding hardware circuit structure by programming an improved method flow into the hardware circuit. Thus, it cannot be said that an improvement in the process flow cannot be realized by hardware physical modules. For example, a Programmable Logic Device (PLD), such as a Field Programmable Gate Array (FPGA), is an integrated circuit whose Logic functions are determined by programming the Device by a user. A digital system is "integrated" on a PLD by the designer's own programming without requiring the chip manufacturer to design and fabricate application-specific integrated circuit chips. Furthermore, nowadays, instead of manually making an integrated Circuit chip, such Programming is often implemented by "logic compiler" software, which is similar to a software compiler used in program development and writing, but the original code before compiling is also written by a specific Programming Language, which is called Hardware Description Language (HDL), and HDL is not only one but many, such as abel (advanced Boolean Expression Language), ahdl (alternate Language Description Language), traffic, pl (core unified Programming Language), HDCal, JHDL (Java Hardware Description Language), langue, Lola, HDL, laspam, hardward Description Language (vhr Description Language), vhjhdul, vhr Description Language, and vhr-Language, which are currently used in most common. It will also be apparent to those skilled in the art that hardware circuitry that implements the logical method flows can be readily obtained by merely slightly programming the method flows into an integrated circuit using the hardware description languages described above.
The systems, devices, modules or units illustrated in the above embodiments may be implemented by a computer chip or an entity, or by a product with certain functions. One typical implementation device is a computer. In particular, the computer may be, for example, a personal computer, a laptop computer, a cellular telephone, a camera phone, a smartphone, a personal digital assistant, a media player, a navigation device, an email device, a game console, a tablet computer, a wearable device, or a combination of any of these devices.
From the above description of the embodiments, it is clear to those skilled in the art that the present specification can be implemented by software plus a necessary general hardware platform. Based on such understanding, the technical solutions of the present specification may be essentially or partially implemented in the form of software products, which may be stored in a storage medium, such as ROM/RAM, magnetic disk, optical disk, etc., and include instructions for causing a computer device (which may be a personal computer, a server, or a network device, etc.) to execute the methods described in the embodiments or some parts of the embodiments of the present specification.
The embodiments in the present specification are described in a progressive manner, and the same and similar parts among the embodiments are referred to each other, and each embodiment focuses on the differences from the other embodiments. In particular, for the system embodiment, since it is substantially similar to the method embodiment, the description is simple, and for the relevant points, reference may be made to the partial description of the method embodiment.
The description is operational with numerous general purpose or special purpose computing system environments or configurations. For example: personal computers, server computers, hand-held or portable devices, tablet-type devices, multiprocessor systems, microprocessor-based systems, set top boxes, programmable consumer electronics, network PCs, minicomputers, mainframe computers, distributed computing environments that include any of the above systems or devices, and the like.
This description may be described in the general context of computer-executable instructions, such as program modules, being executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc. that perform particular tasks or implement particular abstract data types. The specification may also be practiced in distributed computing environments where tasks are performed by remote processing devices that are linked through a communications network. In a distributed computing environment, program modules may be located in both local and remote computer storage media including memory storage devices.
While the specification has been described with examples, those skilled in the art will appreciate that there are numerous variations and permutations of the specification that do not depart from the spirit of the specification, and it is intended that the appended claims include such variations and modifications that do not depart from the spirit of the specification.
Claims (10)
1. A method for evaluating fracturing effect of a tight reservoir is characterized by comprising the following steps:
acquiring total flowback data after reservoir fracturing;
determining flowback data of the cracks of each fracturing section according to the total flowback data; the flowback data comprise the flowback volume of fracturing fluid in flowback fluid, the flowback volume of formation water, the mineralization degree of the flowback fluid and the flowback time;
and determining the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section.
2. The method of claim 1, wherein determining flowback data for each fracture section fracture from the total flowback data comprises:
adding different chemical tracers into the fracturing fluid of each fracturing section, and determining flowback data of the fractures of each fracturing section according to the change relation of the concentration of the chemical tracers used for fracturing of different fracturing sections in the wellhead flowback fluid along with flowback time.
3. The method of claim 1, wherein determining the complexity of each fracture section fracture from the flowback data comprises: the complexity of the fracture of each fracture section is determined according to at least two of the following modes:
judging the complexity of the cracks of each fracturing section according to the change relation of the mineralization degree of the flowback fluid along with the accumulated flowback volume;
determining the complexity of the fracture of each fracturing section according to the probability density relation between the mineralization degree of the flowback fluid and the width of the fracture;
and evaluating the complexity of the cracks of each fracturing section according to the actual flowback rate of the fracturing fluid.
4. The method of claim 1, wherein the fracture parameters comprise fracture half-length and fracture conductivity and fracture permeability.
5. The method of claim 1, wherein determining fracture parameters for each fracture stage fracture from the flowback data comprises:
calculating flow normalized pressure and material balance time according to the relationship between the properties of the fractures and the reservoir and flow and pressure data in the flowback process;
the flow normalized pressure is derived, the flow state of the fluid in the fracture of each fracturing section is determined according to the derivative of the flow normalized pressure, and the flow stages are divided according to the flow state of the fluid;
fitting a functional relation between the flow normalized pressure and the material balance time in different flow stages;
and determining fracture parameters of each fracturing section based on the functional relation between the flow normalized pressure and the material balance time of different flowing stages.
6. The method of claim 1, wherein the evaluating the effect of the reservoir fracturing as a function of the complexity of the fractures of each fracturing stage and fracture parameters of the fractures of each fracturing stage comprises:
calculating the difference coefficient of the fracture parameters according to the fracture parameters of the fractures of each fracturing section, and judging the difference degree of the fractures of each fracturing section;
evaluating the reservoir fracturing effect according to the difference degree of the fractures of each fracturing section and the complexity degree of the fractures of each fracturing section; the difference degree of the fractures corresponds to the complexity degree of the fractures to a certain degree, for a compact reservoir, the smaller the difference of the fractures of each fracturing section is, the more uniform the fractures are, the higher the complexity degree is, and the better the fracturing effect of the reservoir is; the larger the difference of the fractures of each fracturing section is, the more one or more main fractures exist, the lower the complexity of the fractures is, and the worse the fracturing effect of the reservoir is.
7. A tight reservoir fracturing effect evaluation device is characterized by comprising:
the acquisition module is used for acquiring total flowback data after the reservoir fracturing;
the determining module is used for determining the flowback data of the cracks of each fracturing section according to the total flowback data; the flowback data comprise the flowback volume of fracturing fluid in flowback fluid, the flowback volume of formation water, the mineralization degree of the flowback fluid and the flowback time;
and the evaluation module is used for determining the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section according to the flowback data so as to evaluate the fracturing effect of the reservoir according to the complexity of the fractures of each fracturing section and the fracture parameters of the fractures of each fracturing section.
8. The apparatus of claim 7, wherein the determining flowback data for each fracture section fracture from the total flowback data comprises:
adding different chemical tracers into the fracturing fluid of each fracturing section, and determining flowback data of the fractures of each fracturing section according to the change relation of the concentration of the chemical tracers used for fracturing of different fracturing sections in the wellhead flowback fluid along with flowback time.
9. The apparatus of claim 7, wherein the evaluation module comprises:
the fracture complexity determining module is used for comprehensively determining the complexity of the fracture of each fracturing section according to at least two of the following modes: judging the complexity of the cracks of each fracturing section according to the change relation of the mineralization degree of the flowback fluid along with the accumulated flowback volume; determining the complexity of the fracture of each fracturing section according to the probability density relation between the mineralization degree of the flowback fluid and the width of the fracture; and evaluating the complexity of the cracks of each fracturing section according to the actual flowback rate of the fracturing fluid.
10. The apparatus of claim 7, wherein the evaluation module further comprises:
the fracture parameter determination module is used for calculating flow normalized pressure and material balance time according to the relationship between the fracture and reservoir properties and flow and pressure data in the flowback process; the flow normalized pressure is derived, the flow state of the fluid in the fracture of each fracturing section is determined according to the derivative of the flow normalized pressure, and the flow stages are divided according to the flow state of the fluid; fitting a functional relation between the flow normalized pressure and the material balance time in different flow stages; and determining fracture parameters of each fracturing section based on the functional relation between the flow normalized pressure and the material balance time of different flowing stages.
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