CN111878073A - Method and device for evaluating fracturing effect of tight reservoir - Google Patents

Abstract

The embodiments of this specification provide a method and device for evaluating the fracturing effect of tight reservoirs. The method includes: acquiring the total flowback data of the reservoir after fracturing; determining the flowback data of the fractures in each fracturing section according to the total flowback data; the flowback data includes the flowback of the fracturing fluid in the flowback fluid. Displacement and formation water flowback, salinity of flowback fluid and flowback time; according to the flowback data, determine the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section, so as to facilitate The complexity of the fractures in each fracturing stage and the fracture parameters of the fractures in each fracturing stage can greatly improve the accuracy of the evaluation of the reservoir fracturing effect and provide reliable data for later history matching and production prediction. .

Description

A method and device for evaluating fracturing effect of tight reservoirs

technical field

The embodiments of this specification relate to the technical field of tight oil and gas exploration and development, and in particular, to a method and device for evaluating the fracturing effect of tight reservoirs.

Background technique

With the development of unconventional oil and gas, the development of oil and gas reservoirs has become more difficult. In order to fully exploit oil and gas, it is necessary to stimulate and reform the reservoir (usually oil or gas layers). Horizontal well staged fracturing is a Key technologies for unconventional oil and gas development in the United States. In the field of petroleum, fracturing refers to a method of forming cracks in oil and gas reservoirs by hydraulic action during the process of oil or gas production, also known as hydraulic fracturing. Fracturing is to artificially create cracks in the formation, improve the flow environment of oil and gas in the ground, and increase the production of oil and gas wells. to an important role. Therefore, evaluating the fracturing effect of the reservoir plays a very important role in the reservoir productivity prediction and development decision-making.

The commonly used post-frac assessment methods are microseismic and potential monitoring, and many fractographic visualization techniques are used to infer fracture geometry, such as radiotracers, surface and bottom-hole inclinometers, and various electromagnetic measurement techniques. Micro-seismic and potential monitoring methods have the problems of difficult construction and high cost. Sophisticated microseismic measurements have been developed and applied to infer the geometric dimensions of fractures. Due to the limited observation range and expensive instruments, their expanded applications are limited. In addition, the microseismic monitoring signals are noisy, and the analyzed fracture sizes are inaccurate and inaccurate. Provides propped fracture volume and conductivity. When the tracer monitors the fracture width, there are few sampling points, and the time-space distribution of the tracer cannot be accurately obtained. The fracturing graphic technology often provides limited data (ie fracture orientation or wellbore height), and the whole fracturing operation is completed.

The post-fracturing fracture evaluation based on well testing can be achieved by shut-in pressure recovery after a certain period of production after fracturing, which lacks timeliness. Generally, long-term pressure instability analysis or production instability analysis methods are used to obtain the average parameters of fractures and reservoirs to analyze production, but it takes a long time, the fluid properties are simplified, and the fracture results are relatively general. Especially for unconventional reservoirs, the flow time of matrix to fractures is very long, which is affected by the nature of fractures, so it is necessary to characterize fractures in the early stage of well life.

SUMMARY OF THE INVENTION

The purpose of the embodiments of this specification is to provide a method and device for evaluating the fracturing effect of a tight reservoir, so as to improve the accuracy of evaluating the fracturing effect of the reservoir.

In order to solve the above problems, the embodiments of the present specification provide a method and device for evaluating the fracturing effect of tight reservoirs, which are achieved in this way.

A method for evaluating the fracturing effect of a tight reservoir, the method comprising: acquiring total flowback data after reservoir fracturing; determining flowback data of fractures in each fracturing stage according to the total flowback data; The data includes the flowback amount of fracturing fluid and the flowback amount of formation water in the flowback fluid, the salinity and flowback time of the flowback fluid; The fracture parameters of the fractures in the fracturing section are used to evaluate the fracturing effect of the reservoir according to the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section.

A device for evaluating the fracturing effect of a tight reservoir, the device comprising: an acquisition module for acquiring total flowback data after reservoir fracturing; a determination module for determining each fracturing section according to the total flowback data The flowback data of the fracture; the flowback data includes the flowback amount of the fracturing fluid and the flowback amount of the formation water in the flowback fluid, the salinity of the flowback fluid and the flowback time; the evaluation module is used to The flowback data is used to determine the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section, so as to evaluate the reservoir fracturing effect according to the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section.

It can be seen from the technical solutions provided by the above embodiments of this specification that the total flowback data after reservoir fracturing can be obtained in the embodiments of this specification; The drainage data includes the flowback volume of the fracturing fluid in the flowback fluid and the flowback volume of the formation water, the salinity of the flowback fluid and the flowback time; The fracture parameters of the fractures in each fracturing section are used to evaluate the effect of reservoir fracturing according to the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section. The method for evaluating the fracturing effect of tight reservoirs provided in the embodiments of this specification can evaluate single-level fractures or multi-level fractures, and can analyze and calculate the characteristics of each level of fractures through single-level fracture analysis and calculation to determine the complexity of the fractures. , and obtain the fracture parameters to comprehensively evaluate the reservoir fracturing effect, which can greatly improve the accuracy of the evaluation of the reservoir fracturing effect.

Description of drawings

In order to more clearly illustrate the technical solutions in the embodiments of the present specification or the prior art, the following briefly introduces the accompanying drawings required in the description of the embodiments or the prior art. Obviously, the accompanying drawings in the following description are only These are some embodiments described in this specification. For those of ordinary skill in the art, other drawings can also be obtained based on these drawings without any creative effort.

Fig. 1 is a flow chart of a method for evaluating the fracturing effect of a tight reservoir according to an embodiment of the present specification;

2 is a schematic diagram of the relationship between the salinity of the flowback liquid and the cumulative flowback amount in the embodiment of the present specification;

Fig. 3 is a schematic diagram of crack width distribution range and frequency according to the embodiment of this specification;

4 is a schematic diagram of a double logarithmic relationship curve between MBT and RNP in the embodiment of the present specification;

FIG. 5 is a schematic diagram of functional modules of a device for evaluating the fracturing effect of a tight reservoir according to an embodiment of the present specification.

Detailed ways

The technical solutions in the embodiments of the present specification will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present specification. Obviously, the described embodiments are only a part of the embodiments of the present specification, rather than all the embodiments. Based on the embodiments in this specification, all other embodiments obtained by persons of ordinary skill in the art without creative efforts shall fall within the protection scope of this specification.

In the embodiments of the present specification, the return of the fracturing fluid injected into the formation to the surface after the completion of the fracturing of the reservoir is called fracturing fluid flowback, and the returned fracturing fluid after interacting with the formation is called flowback fluid. The flowback fluid may include formation water and fracturing fluid. Among them, the fracturing fluid refers to a heterogeneous and unstable chemical system formed by a variety of additives according to a certain ratio. It is a working fluid used in fracturing and reforming oil and gas layers. The resulting high pressure is transmitted into the formation, fracturing the formation to form fractures and transporting proppant along the fractures. After fracturing the reservoir, the flowback data can be obtained. The flowback data is the early time-pressure-production data after the completion of the well, which can reflect the well and reservoir information, and calculate the flowback by monitoring the fluid composition. The rate can be used to predict the long-term production capacity of the well and potential problems, and conduct production performance analysis.

However, the analysis of flowback data is difficult, mainly because of rapid changes in fracture pattern and wellbore environment, multiphase flow in fractures, and completion heterogeneity. The conventional method is to analyze the overall flowback of multiple fractures in a single well after the completion of fracturing, and the obtained fracture parameters can only represent the average level of the whole. As a result, the parameters such as fracture length, fracture width and conductivity of each fracture are different, and the contribution of each fracture to the total oil and gas production is also different. Through the analysis of the overall flowback data of a single well and multiple fractures, the fracture parameters generally assume single-phase flow. It may lead to inaccurate results, and in the commonly used flowback data analysis methods, the flowback volume of the flowback fluid is usually analyzed, while the composition of the flowback fluid is ignored, resulting in inaccurate post-pressure evaluation parameters. Considering that there will be communication between each stage and each well in the flowback process, and for unconventional reservoirs, the fractures are more complex, if the flowback data of each stage of fracturing is collected in stages, and the fracturing fluid of each stage is distinguished. It is expected to improve the accuracy of the evaluation of the fracturing effect of tight reservoirs.

Based on the above thinking, the embodiments of this specification provide a method for evaluating the fracturing effect of tight reservoirs. In the embodiment of the present specification, the main body that executes the method for evaluating the fracturing effect of a tight reservoir may be an electronic device with a logic 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 above-mentioned electronic device with a certain entity, and it can also be software running in the above-mentioned electronic device, or can also be a program software formed through program development. The program software can run in the above electronic equipment.

For details, please refer to the processing flow chart of a method for evaluating the fracturing effect of a tight reservoir provided according to an embodiment of the present specification shown in FIG. 1 . The method for evaluating the fracturing effect of a tight reservoir provided in the embodiments of this specification may include the following steps during specific implementation.

S110: Acquire total flowback data after reservoir fracturing.

In some embodiments, the return of the fracturing fluid injected into the formation to the surface after the completion of the fracturing of the reservoir is called fracturing fluid flowback, and the returned fracturing fluid after interacting with the formation is called flowback fluid. After fracturing the reservoir with flowback, total flowback data after fracturing can be obtained. The total flowback data may include data such as initial reservoir pressure, bottom hole pressure, salinity of flowback fluid, surface flowback fluid flow, cumulative flowback volume, total compressibility, and viscosity of produced fluid.

In some embodiments, the server may obtain the total flowback data after reservoir fracturing in any manner. For example, the user can directly send the total flowback data after the reservoir fracturing to the server, and the server can receive it; another example is that other electronic devices other than the server can send the total flowback data after the reservoir fracturing to the server, The server may receive, and in the embodiment of this specification, the method used by the server to obtain the total flowback data after reservoir fracturing is not limited.

S120: Determine the flowback data of the fractures in each fracturing section according to the total flowback data; the flowback data includes the flowback amount of the fracturing fluid in the flowback fluid and the flowback amount and flowback time of the formation water.

In some embodiments, the flowback amount of fracturing fluid and the flowback amount of formation water in the flowback fluid, the salinity of the flowback fluid and the flowback time may specifically include in the flowback fluid at each flowback time. The real-time flowback and cumulative flowback of fracturing fluid, the real-time flowback and cumulative flowback of formation water, the real-time salinity and cumulative salinity of flowback fluid, and the Real-time flowback and cumulative flowback of medium fracturing fluid, real-time flowback and cumulative flowback of formation water, real-time salinity and cumulative salinity of flowback fluid.

In some embodiments, due to the different fracturing construction parameters such as the fracturing sequence and cluster spacing in each fracturing section, the fracture shape, fracture width and conductivity of the fractures in each fracturing section are different, and the fractures in each fracturing section have different effects on oil and gas. The contribution to total production also varies. In order to clarify the specific conditions of the fractures in each fracturing section, different types of chemical tracers can be added to the fracturing fluid in each fracturing section to monitor the flowback fluid at the wellhead used for fracturing in different fracturing sections at each flowback time The tracer concentration was used to determine the flowback data of each fracturing section.

假设所用示踪剂在各压裂段无漏失，且不吸附在地层岩石上，压裂后化学示踪剂均匀分布在该压裂段井筒、裂缝和基质孔隙的压裂液和地层水中，此时存在于压裂液和地层水中的示踪剂浓度为C′_t,j，对于第i个返排时刻，地面收集的总返排液体积为V_i ^m，地面收集的总返排液中测得第j压裂段压裂使用的化学示踪剂浓度为C_t,j,i；设第j压裂段压裂返排液中的压裂液体积为

地层水体积为

进入地层中第j压裂段的示踪剂的量可以表示为

第i个返排时刻地面返排的第j压裂段中示踪剂的量

假设时间足够长，进入地层中的示踪剂最终全部返排出来，进入地层中第j压裂段中示踪剂的量等于所有返排时刻返排出第j压裂段中示踪剂量，则有：Specifically, different types of chemical tracers can be added to the fracturing fluid in each fracturing section. After the fracturing is completed, the changes in the concentration of different types of chemical tracers in the flowback fluid can be monitored, and the material balance method can be used to distinguish The flowback amount of fracturing fluid in each fracturing section. Assuming that in the whole fracturing construction process, the designed concentration of tracer added to the fracturing fluid in the jth fracturing stage before fracturing is C _t,j , and for the jth fracturing stage, the volume of the fracturing fluid used is

Assuming that the tracer used has no leakage in each fracturing section and is not adsorbed on the formation rock, the chemical tracer is evenly distributed in the fracturing fluid and formation water in the wellbore, fractures and matrix pores of the fracturing section after fracturing. The concentration of the tracer present in the fracturing fluid and formation water is C′ _t,j . For the i-th flowback time, the volume of the total flowback fluid collected on the ground is V _i ^m , and the total flowback fluid collected on the ground is in the The concentration of chemical tracer used for fracturing in the jth fracturing stage is measured as C _t,j,i ; the volume of the fracturing fluid in the fracturing flowback fluid of the jth fracturing stage is

The volume of formation water is

The amount of tracer entering the jth fracturing section in the formation can be expressed as

The amount of tracer in the jth fracturing section of the surface flowback at the ith flowback moment

Assuming that the time is long enough, all tracers entering the formation are finally flowed back out, and the amount of tracer entering the jth fracturing section of the formation is equal to the amount of tracers flowing back out of the jth fracturing section at all flowback times, then Have:

和地层水体积

According to formula (1), the volume of fracturing fluid in the flowback fluid of the j fracturing section at the time of i flowback can be obtained

and formation water volume

In some embodiments, for the ith flowback time, the salinity of the flowback fluid of the jth fracturing stage is provided by two parts of the flowback fluid and the formation water in the flowback fluid of the jth fracturing stage. There is the following relationship:

The salt content in the flowback fluid of the jth fracturing stage = the salt content of the fracturing fluid in the flowback fluid of the jth fracturing stage + the salt content of the formation water in the flowback fluid of the jth fracturing stage, namely:

和

分别为第j段返排液中压裂液和地层水中的矿化度，可以通过监测得到。

and

are the salinity of fracturing fluid and formation water in the flowback fluid of the j-th section, which can be obtained by monitoring.

和地层水体积

可以得到第i个返排时刻第j压裂段返排液的矿化度

为：According to the above calculation, the volume of fracturing fluid in the flowback fluid of the jth fracturing stage in the flowback fluid at the i-th flowback time

and formation water volume

The salinity of the flowback fluid of the jth fracturing section at the ith flowback time can be obtained.

for:

C _t represents tracer concentration; C _s represents salinity; j represents fracturing stage; i represents flowback time; superscript f represents fracturing fluid; superscript w represents formation water; superscript m represents flowback fluid.

S130: Determine the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section according to the flowback data, so as to evaluate the reservoir according to the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section Fracturing effect.

In the fracturing process, complex fracture networks may be generated. For example, in the process of unconventional oil and gas development such as shale gas and shale oil, fracturing can generate complex fracture networks due to the high rock brittleness and the existence of natural fractures. By determining the complexity of fractures, the fracturing effect of tight reservoirs can be qualitatively evaluated. Among them, the more complex the fracture, the larger the contact area between the fracturing fluid and the rock, and the higher the imbibition rate, resulting in high filtration loss and low flowback. In complex fractures, the tortuosity of secondary fractures may lead to water lock, and the fracturing fluid retained in the fractures, due to capillary force, chemical osmotic pressure, and clay adsorption, penetrates into the matrix through imbibition, thereby displacing more oil and gas.

In some embodiments, the fracture complexity of each fracturing segment can be determined according to the following method.

Method 1: Judging the complexity of the fractures according to the relationship between the salinity of the flowback fluid and the cumulative flowback amount.

In some embodiments, fluids in the wellbore and wider hydraulic fractures are drained first, primarily as fracturing fluid raffinate, when flowback begins. With the increase of the flowback time, the liquid in the secondary fracture begins to be discharged. Due to the ion exchange between the fracturing fluid in the secondary fracture and the formation water, and the long contact time with the rock minerals, the salinity of the flowback fluid increases. The salinity of the flowback fluid in different fracturing sections varies with the cumulative flowback amount. The salinity in the flowback fluid in some fracturing sections has been rising, and the salinity in the flowback fluid in some fracturing sections has increased. After reaching a certain level, it will level off, so the complexity of the fracture can be qualitatively described by the change of the salinity of the flowback fluid with the cumulative flowback amount.

For large-stage multi-cluster fracturing, there may be multiple fractures in each cluster. Based on Fick's first law, the relationship between the fracture width of the nth fracture in the jth fracturing section and the salinity is established:

表示第j压裂段中第n条裂缝的矿化度，n表示压裂段内的第n条裂缝；D表示扩散系数；L表示基质到裂缝的距离；w_j,i,n表示裂缝宽度；Δt表示第i-1时刻到第i时刻的间隔时间，上标F表示裂缝。

represents the salinity of the nth fracture in the jth fracturing section, n represents the nth fracture in the fracturing section; D represents the diffusion coefficient; L represents the distance from the matrix to the fracture; w _j,i,n represents the fracture width ; Δt represents the interval from the i-1th time to the i-th time, and the superscript F represents the crack.

From formula (4), it can be known that the fracture salinity and fracture width are inversely proportional, and the higher the fracture salinity, the smaller the fracture width. However, in formula (4), since it is difficult to directly measure the salinity of the nth fracture in the j fracturing section, the fracture width cannot be directly calculated, but the salinity of the flowback fluid can be monitored on the ground, and the surface flowback fluid volume and The relationship between fracture salinity. For the ith flowback moment, the salt content in the fracturing flowback fluid of the jth fracturing section is provided by n fractures, and the flowback fluid volume is approximately equal to the volume of the n fractures participating in the flowback, then:

计算j压裂段返排液的矿化度变化趋势，再根据返排液矿化度随累计返排量的变化可以判断j压裂段中裂缝矿化度的变化趋势，从而描述裂缝的复杂程度。A _j,i,n represents the fracture cross-sectional area. The salinity of the flowback fluid of the jth fracturing section at the ith flowback time can be obtained by formula (3)

Calculate the change trend of the salinity of the flowback fluid in the j fracturing section, and then judge the change trend of the fracture salinity in the j fracturing section according to the change of the salinity of the flowback fluid with the cumulative flowback, thereby describing the complexity of the fracture. degree.

As shown in Fig. 2, comparing the fracturing section A and the fracturing section B, the salinity of the fracturing section A has been increasing with the increase of the cumulative flowback amount. After the liquid flowback in the hydraulic fracture, the secondary fracture The high salinity fluid in the middle causes the increase of salinity in the later stage of flowback; while the salinity of fracturing section B first increases with the increase of cumulative flowback, and gradually tends to remain unchanged, which is shown as a gentle section on the figure. It shows that the distribution range of fracture width in fracturing section A is larger than that in fracturing section B, indicating that the fracture shape in fracturing section A is more complex.

Method 2: Determine the complexity of the fractures in each fracturing section according to the probability density relationship between the salinity of the flowback fluid and the fracture width.

Since the width of the fracture cannot be directly calculated in formula (4), the probability density function of the fracture width can be obtained by transforming the formula, and the distribution range of the fracture width and the proportion of fractures with different widths can be obtained. Specifically, the probability density of the fracture width can be calculated according to the salinity of the flowback fluid, so as to determine the complexity of each section of the fracture:

表示第j压裂段裂缝返排液的矿化度；N_j表示归一化返排量，即累计返排量与实时返排量的比值，

Q_C，j表示累计返排量，Δt表示返排时间，

可通过对归一化返排量与返排液矿化度的关系曲线求导计算。Among them, f(w _j ) represents the probability density distribution function of the fracture width of the jth fracturing section;

represents the salinity of the fracture flowback fluid in the jth fracturing stage; _Nj represents the normalized flowback amount, that is, the ratio of the cumulative flowback amount to the real-time flowback amount,

Q _{C, j} is the cumulative flowback amount, Δt is the flowback time,

It can be calculated by derivation of the relationship between the normalized flowback volume and the salinity of the flowback 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 formula (6). As shown in Figure 3, the fracture width distribution range of fracturing section A is wider than that of fracturing section B, ranging from 0.11 to 0.23 mm, which is bimodal. At this time, the fractures in fracturing section A are mainly two apertures. The frequency of fractures in the fracturing section B is narrow, ranging from 0.1 to 0.2 mm, and the frequency of fractures with a fracture width of 0.14 mm is the highest, followed by the frequency of fractures of 0.22 mm. The fractures in the fracturing section B are mainly composed of fractures with a single fracture width, and the fractures with a fracture width of 0.14 mm are the main ones. Therefore, the fracture morphology in fracturing section A is complex.

Method 3: Evaluate the complexity of the fractures in each fracturing section according to the actual flowback rate of the fracturing fluid.

The flowback rate of simple plane fractures is relatively high, while for complex fractures, since the secondary fractures in the fractures are not filled with proppant or are filled with a small amount of proppant, the fracturing fluid entering the secondary fractures is almost immobile. The phenomenon of oil-gas-water separation occurs, resulting in low relative permeability of fracturing fluid, difficult to flow out, and low fracturing fluid flowback rate in complex fractures.

Specifically, the actual flowback rate of the fracturing fluid in each fracturing section may be determined according to the amount of fracturing fluid flow back in the jth fracturing section and the total amount of fracturing fluid injected in this section. The higher the flowback rate, the lower the fracture complexity.

表示第j压裂段使用的压裂液体积，K_j表示第j压裂段的压裂液实际返排率。in,

represents the volume of fracturing fluid used in the _jth fracturing section, and Kj represents the actual flowback rate of the fracturing fluid in the jth fracturing section.

In some embodiments, the complexity of each section of the fracture can be determined comprehensively according to the first method, the second method and the third method.

In some embodiments, the fracture parameters of the fractures in each fracturing section can be determined according to the flowback data through the following steps.

S131: Calculate the flow-normalized pressure and the material balance time according to the relationship between the flow and pressure data in the flow-back process.

In some embodiments, the bottom hole pressure, surface flow rate and accumulated flowback amount of the initial flowback of the fracturing well can be collected, and the flow normalized pressure RNP and material balance time MBT can be calculated:

Among them, p _initial is the initial reservoir pressure, p _wf is the bottom hole pressure, q _s is the surface flow rate, Q _c,j is the cumulative flowback, RNP is the normalized pressure, and MBT is the material balance time.

S132: Differentiate the flow normalized pressure, determine the flow state of the fluid in the fractures in each fracturing section according to the derivative of the flow normalized pressure, and divide the flow stage according to the flow state of the fluid.

Specifically, the flyback data can be substituted into formulas (8)-(10) to obtain multiple sets of RNP and MBT, as shown in FIG. And derivation of the flow normalized pressure can get formula (11):

where RNP' represents the derivative of RNP.

In some embodiments, the flow state of the fluid in the fractures of each fracturing section may 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 state of the fluid may be determined according to the flow state of the fluid. Divide flow phases.

Specifically, the flowback data can be substituted into formula (11), the relationship curve between MBT and RNP' can be drawn, and the flow stage can be divided according to the slope of the relationship curve between MBT and RNP'. In a specific example, the relationship between MBT and RNP, and the relationship between MBT and RNP' are shown in Figure 4. The part of the relationship between MBT and RNP' whose slope is 1/4 is represented by a solid black line. The flow state of the fluid in this stage is a bilinear flow stage; the part of the relationship curve between MBT and RNP' whose slope is 1/2 is represented by a black dotted line, and the flow state of the fluid at this stage is a linear flow stage; the boundary effect occurs in the later stage, and MBT and RNP' The part of the relationship curve of RNP' with a slope of 1 is represented by a black dot-dash line, the boundary effect occurs at this stage, and the flow state of the fluid at this stage is the boundary flow stage.

S133: Fit the functional relationship between the flow normalized pressure and the material equilibrium time in different flow stages.

In some embodiments, after the flow stages are divided, the RNP and MBT relationship curves of different flow stages can be fitted according to the functional relationship of the relationship curves to determine the slope and intercept of the RNP and MBT relationship curves.

In some embodiments, a first-order function fitting is performed on the RNP and MBT relationship curve of the flow-back fluid to determine the slope and intercept of the curve.

RNP=aMBT+b (12)

Among them, a represents the slope of the relationship between RNP and MBT in the flow-back phase, and b represents the intercept of the relationship between RNP and MBT in the flow-back phase.

S134: Determine the fracture parameters based on the functional relationship between the flow normalized pressure and the material balance time in 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-packed fracture to pass fluid under the action of the effective stress of the reservoir. It is generally expressed by the product (K _f w _f ) of the permeability (K _f ) of the fracture support zone and the supported fracture width (w _f ). In the fracturing optimization design, the concept of dimensionless conductivity can also be used, which is expressed by (K _f w _f )/(KL _f ), where L _f is the fracture length and K is the reservoir permeability. The dimensionless conductivity represents the matching relationship between the fracture conductivity and the reservoir fluid supply capacity. Too small dimensionless conductivity means that the flow capacity in the fracture is less than the formation fluid supply capacity, and the production will be reduced; Too large flow capacity means that although the fracture has sufficient flow capacity, the formation fluid supply cannot keep up, resulting in unnecessary waste. Appropriate dimensionless conductivity is very important for the evaluation of fracturing economic benefits. After fracturing, the stimulation effect and validity period have a great relationship with the fracture conductivity. The main factors affecting fracture conductivity may include the physical properties of proppant, the placement concentration of proppant in the fracture, the fracture closure pressure, the mechanical properties of the reservoir rock, and the damage of the fracturing fluid to the propping zone.

In some embodiments, for the fracturing fluid flowback phase, the overall storage coefficient and fracture permeability may be estimated from the slope and intercept of the MBT as a function of RNP for the flowback phase. Specifically, the total storage factor is calculated using the following equation:

C _st =B/a (13)

where C _st represents the total storage factor, and B represents the formation volume factor.

After obtaining the total storage coefficient, the permeability of the fracture can be calculated by the following formula:

Among them, k _f is the permeability of the fracture, φ _f is the fracture porosity, C _t is the total compressibility, μ fluid viscosity, A is the displacement area, r _e is the displacement radius, r _w is the wellbore radius, and Υ is the European Pull constant.

In some embodiments, the half-length of the fracture may be the distance that the fracture extends from the wellbore along the radial reservoir after the reservoir fracturing, which generally refers to the fracture length of the horizontal fracture. The crack half-length is one of the crack size factors. Fracture size factors can also include fracture width and height, which can characterize the effect of the reservoir being stimulated by fracturing.

In some embodiments, in the case of boundary flow, the fracture half-length can be estimated according to the functional relationship between MBT and RNP in the boundary flow stage, and the conductivity of the fracture can be calculated according to the functional relationship between MBT and RNP in the bilinear flow stage. Specifically, if a boundary flow phase occurs, the fracture half-length is calculated using the following equation:

If bilinear flow occurs, the fracture conductivity can be calculated by the following formula:

In the formula, OGIP represents the in-situ gas volume, which is calculated according to the slope of the relationship function between RNP and MBT in the boundary flow stage, S _wi represents the initial water saturation, T represents the reservoir temperature, k _eff represents the effective permeability, μ represents the viscosity, c _t represents the total compressibility coefficient, x _f represents the fracture half-length, B _gi represents the original gas volume coefficient, x _e represents the perforation spacing, h represents the reservoir thickness, φ represents the porosity, n _f represents the number of fracture clusters, and F _CD represents the fracture size. Dimensionless conductance, S3 represents the slope of the RNP _- MBT relationship function in the bilinear flow stage.

In some embodiments, the reservoir fracturing effect can be evaluated according to the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section. Specifically, the difference coefficient of the fracture parameters can be calculated according to the fracture parameters of the fractures in each fracturing section to judge the degree of difference of the fractures in each fracturing section. Reservoir fracturing effect; among them, the degree of difference of fractures corresponds to the complexity of fractures to a certain extent. For tight reservoirs, the smaller the difference of fractures in each fracturing section, the more uniform the fractures and the higher the degree of complexity. The better the fracturing effect; the greater the difference between the fractures in each fracturing section, it means that there are one or more main fractures, the lower the complexity of the fractures, the worse the reservoir fracturing effect.

The difference coefficient is the percentage of the standard deviation of a group of data and its mean value, is a relative index for measuring the degree of dispersion of the data, and is a relative difference quantity. Since the relative difference quantity has no measurement unit, it is suitable for the comparison of data variation with different measurement units or the same measurement unit but with a large difference in the concentration quantity. The greater the difference coefficient of the fracture parameters of the fractures in each fracturing section, the greater the degree of difference of the fractures in each fracturing section.

By quantitatively analyzing the multiphase flowback data of multi-stage fracturing horizontal wells (MFHW), the complexity of fractures can be described, and it can be preliminarily judged whether a complex fracture network is formed. For low permeability and unconventional reservoirs, complex fracture network can provide effective Oil and gas seepage channel to ensure oil and gas production; according to the effective fracture volume, oil and gas production prediction and economic evaluation can be carried out to provide a basis for development decisions. Compared with traditional well testing methods to obtain fracture and reservoir parameters, the fracturing effect evaluation based on fracturing fluid flowback data can truly reflect the fracturing effect during fracturing. The time from the end of fracturing to the end of flowback is short. For low-permeability formations, the flow of fracturing fluid to the formation is limited. Compared with pressure recovery data and production data, the interpretation results of flowback data can reflect the formation pressure during fracturing. cracking effect.

The method for evaluating the fracturing effect of tight reservoirs provided in the embodiments of this specification can obtain the total flowback data after the reservoir is fractured; The data includes the flowback amount of fracturing fluid and the flowback amount of formation water in the flowback fluid, the salinity and flowback time of the flowback fluid; The fracture parameters of the fractures in the fracturing section are used to evaluate the fracturing effect of the reservoir according to the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section. The method for evaluating the fracturing effect of tight reservoirs provided in the embodiments of this specification can evaluate single-level fractures or multi-level fractures, and can analyze and calculate the characteristics of each level of fractures through single-level fracture analysis and calculation to determine the complexity of the fractures. , and obtain the fracture parameters to comprehensively evaluate the reservoir fracturing effect, which can greatly improve the accuracy of the evaluation of the reservoir fracturing effect.

Referring to FIG. 5 , an embodiment of the present specification further provides a device for evaluating the fracturing effect of a tight reservoir, and the device may specifically include the following structural modules.

an acquisition module 510, configured to acquire total flowback data after reservoir fracturing;

The determination module 520 is configured to determine the flowback data of the fractures in each fracturing section according to the total flowback data; the flowback data includes the flowback amount of the fracturing fluid in the flowback fluid and the flowback amount of the formation water, the flowback The salinity and flowback time of the drainage;

The evaluation module 530 is configured to determine the complexity of the fractures in each fracturing section and the fracture parameters of the fractures in each fracturing section according to the flow-back data, so as to facilitate according to the complexity of the fractures in each fracturing section and the fractures of the fractures in each fracturing section Parameter to evaluate reservoir fracturing effect.

In some embodiments, the determining the flowback data of the fractures of each fracturing section according to the total flowback data includes: adding different chemical tracers to the fracturing fluid of each fracturing section, according to the wellhead flowback fluid The relationship between the concentration of chemical tracers used in different fracturing stages and the flowback time determines the flowback data of the fractures in each fracturing stage.

In some embodiments, the evaluation module may include: a fracture complexity determination module, configured to comprehensively determine the fracture complexity of each fracturing section according to at least two of the following manners: according to the salinity of the flowback fluid The change relationship of the cumulative flowback amount determines the complexity of the fractures in each fracturing section; the complexity of the fractures in each fracturing section is determined according to the probability density relationship between the salinity of the flowback fluid and the fracture width; according to the actual flowback of the fracturing fluid rate to evaluate the complexity of the fractures in each fracturing section.

In some embodiments, the evaluation module may further include: a fracture parameter determination module for calculating flow normalized pressure and material balance time according to the relationship between fracture and reservoir properties and flow and pressure data during flowback; The flow normalized pressure is derived, the flow state of the fluid in the fractures 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; The functional relationship between the normalized pressure and the material equilibrium time; the fracture parameters of each fracturing section are determined based on the functional relationship between the flow normalized pressure and the material equilibrium time in different flow stages.

It should be noted that, each embodiment in this specification is described in a progressive manner, and the same or similar parts of each embodiment may be referred to each other, and each embodiment focuses on the differences from other embodiments. place. In particular, for the apparatus embodiments and the device embodiments, since they are basically similar to the method embodiments, the descriptions are relatively simple, and reference may be made to some descriptions of the method embodiments for related parts.

After reading this specification, those skilled in the art can think of any combination of some or all of the embodiments listed in this specification without creative effort, and these combinations are also within the scope of disclosure and protection of this specification.

In the 1990s, improvements in a technology could be clearly differentiated between improvements in hardware (eg, improvements to circuit structures such as diodes, transistors, switches, etc.) or improvements in software (improvements in method flow). However, with the development of technology, the improvement of many methods and processes today can be regarded as a direct improvement of the hardware circuit structure. Designers almost get the corresponding hardware circuit structure by programming the improved method flow into the hardware circuit. Therefore, it cannot be said that the improvement of a method flow cannot be realized by hardware entity modules. For example, a Programmable Logic Device (PLD) (eg, Field Programmable Gate Array (FPGA)) is an integrated circuit whose logic function is determined by user programming of the device. It is programmed by the designer to "integrate" a digital system on a PLD without having to ask the chip manufacturer to design and manufacture a dedicated integrated circuit chip. And, instead of making integrated circuit chips by hand, these days, most of this programming is done using "logic compiler" software, which is similar to the software compilers used in program development and writing, but before compiling The original code also has to be written in a specific programming language, which is called Hardware Description Language (HDL), and there is not only one HDL, but many kinds, such as ABEL (Advanced Boolean Expression Language) , AHDL(AlteraHardware DescriptionLanguage), Confluence, CUPL(Cornell University Programming Language), HDCal, JHDL(Java Hardware Description Language), Lava, Lola, MyHDL, PALASM, RHDL(RubyHardware Description Language), etc. VHDL is currently the most commonly used (Very-High-SpeedIntegrated Circuit Hardware Description Language) and Verilog2. It should also be clear to those skilled in the art that a hardware circuit for implementing the logic method process can be easily obtained by simply programming the method process in the above-mentioned several hardware description languages and programming it into the integrated circuit.

The systems, devices, modules or units described in the above embodiments may be specifically implemented by computer chips or entities, or by products with certain functions. A typical implementation device is a computer. Specifically, the computer can be, for example, a personal computer, a laptop computer, a cellular phone, a camera phone, a smart phone, 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 description of the above embodiments, those skilled in the art can clearly understand that this specification can be implemented by means of software plus a necessary general hardware platform. Based on this understanding, the technical solutions of this specification or the parts that make contributions to the prior art can be embodied in the form of software products, and the computer software products can be stored in storage media, such as ROM/RAM, magnetic disks, etc. , CD, etc., including several 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 various embodiments or some parts of the embodiments in this specification.

Each embodiment in this specification is described in a progressive manner, and the same and similar parts between the various embodiments may be referred to each other, and each embodiment focuses on the differences from other embodiments. In particular, as for the system embodiments, since they are basically similar to the method embodiments, the description is relatively simple, and for related parts, please refer to the partial descriptions of the method embodiments.

This specification can be used in numerous general purpose or special purpose computer system environments or configurations. For example: personal computers, server computers, handheld or portable devices, tablet devices, multiprocessor systems, microprocessor-based systems, set-top boxes, programmable consumer electronics, network PCs, minicomputers, mainframe computers, including A distributed computing environment for any of the above systems or devices, and the like.

This specification 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 can 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 storage devices.

Although this specification has been described by way of examples, those of ordinary skill in the art will recognize that there are many modifications and changes to this specification without departing from the spirit of the specification, and it is intended that the appended claims include such modifications and changes without departing 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.

Images