CN109960896B - Method for quantitatively evaluating flowing difficulty degree of plugging agent in complex crack - Google Patents
Method for quantitatively evaluating flowing difficulty degree of plugging agent in complex crack Download PDFInfo
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Abstract
The invention provides a method for quantitatively evaluating the flowing difficulty degree of a plugging agent in a complex fracture, which comprises the steps of predicting the width of the fracture according to fracture parameters of a target stratum, manufacturing simulated fractures with different widths according to the fracture width, injecting the plugging agent into the simulated fractures with different widths at different injection rates, carrying out flowing test, fitting a flowing characteristic formula according to measured data, calculating the flowing resistance difference numerical value of the plugging agent in the simulated fractures with different widths according to the flowing characteristic formula, and quantitatively evaluating the flowing difficulty degree of the plugging agent in the complex fracture by using the flowing resistance difference numerical value. The flowing difficulty of the plugging agent in the fracture is expressed by numerical values, so that the injection difficulty of the plugging agent in the complex fracture leakage stratum can be conveniently judged, and basic support is provided for a method for controlling the flowing behavior of the plugging agent in the complex fracture leakage stratum of the system.
Description
Technical Field
The invention relates to the field of drilling fluid plugging, in particular to a method for quantitatively evaluating the flowing difficulty of a plugging agent in a complex fracture.
Background
The well leakage is one of the most common underground complex problems in the current drilling process, directly reduces the drilling speed and increases the drilling cost, and is one of the main technical bottlenecks for restricting the exploration and development speeds of oil gas, natural gas hydrate, geothermal heat and other reservoirs. The well leakage can occur in different types of stratums, wherein the leakage degree of the stratums developed by cracks and karst caves is the most serious and difficult to solve.
The adoption of chemical plugging agents to block lost formations is one of the current commonly used well leakage countermeasures. Common chemical plugging agents comprise bridging plugging agents, high-water-loss plugging agents, temporary plugging material plugging agents, chemical plugging agents, composite (soft and hard plugging) plugging agents and the like, and a treatment method for plugging different leaking positions by using different plugging agents is preliminarily formed in a mine field. However, at present, research on the plugging agent at home and abroad mainly focuses on improving the strength, toughness, temperature resistance and the like of the plugging agent, but the research on the matching degree of the plugging agent and a leakage passage, particularly a complex crack leakage passage, is less, a method for evaluating the flowing behavior of the plugging agent in a complex crack leakage stratum is not established, and a method for controlling the injection and flowing behavior of the plugging agent in the complex crack leakage stratum forming a system is not established, so that the injection of the plugging agent in a mine site has blindness, and the plugging effect is easy to cause poor.
Disclosure of Invention
Aiming at the technical problems that the injection of the plugging agent in the prior art is blind and the plugging effect is poor, the invention provides a method for quantitatively evaluating the flowing difficulty degree of the plugging agent in the complex fracture.
In order to achieve the purpose, the method for quantitatively evaluating the flowing difficulty degree of the plugging agent in the complex fracture comprises the following steps: step 1) predicting the fracture width of a natural fracture of a target stratum according to the logging parameters of the target stratum; step 2) manufacturing core models with simulated fractures according to the fracture width of the natural fractures, wherein the simulated fractures of each core model have different fracture widths; step 3) injecting a plugging agent into the simulated fracture according to different injection rates; step 4) calculating the flowing pressure gradient of the plugging agent in simulated fractures with different widths at different injection rates according to the injection pressure corresponding to the different injection rates; step 5) determining a flow characteristic formula of the plugging agent in the simulated fracture according to the injection rate, the fracture width and the flow pressure gradient; and 6) calculating the flow resistance difference numerical value of the plugging agent in simulated fractures with different fracture widths according to the flow characteristic formula, and quantitatively evaluating the flow difficulty of the plugging agent in the complex fractures by adopting the flow resistance difference numerical value.
Further, the step 2) of manufacturing a core model with simulated fractures according to the fracture width of the natural fractures, wherein the simulated fractures of each core model have different fracture widths, includes: determining a basic core of the core model according to the lithology and the matrix permeability of the target stratum; sandwiching salt cakes of different thicknesses in the base core according to fracture widths of the natural fractures; and dissolving the salt cake in the basic rock core to form the rock core model with the simulated fractures, wherein the simulated fractures of each rock core model have different fracture widths.
Further, the step 4) calculates the flowing pressure gradient of the plugging agent in the simulated fracture with different fracture widths at different injection rates according to the injection pressure corresponding to the different injection rates, and comprises the following steps: calculating the flowing pressure of the plugging agent in simulated fractures with different widths at different injection rates according to the injection pressure and the pipeline friction resistance; determining the flow pressure gradient from a ratio of the flow pressure to a length of the simulated fracture.
Further, step 5) determining a flow characteristic formula of the plugging agent in the simulated fracture according to the injection rate, the fracture width and the flow pressure gradient, wherein the flow characteristic formula comprises the following steps: determining a first relation between the injection rate and the flow pressure gradient under different seam widths respectively; determining a common parameter corresponding to the seam width through the first relational expression; determining a second relational expression according to the first relational expression and the common parameters; determining a common parameter relation between the common parameter and the seam width; and substituting the common parameter relational expression into the second relational expression to determine the flow characteristic formula.
Further, the determining a first relationship between injection rate and the flow pressure gradient comprises: respectively drawing first relation curves between the injection rate and the flow pressure gradient under different seam widths; and fitting the first relation curve to determine the first relation.
Further, the determining a common parameter relation between the common parameter and the slit width includes: drawing a second relation curve between the common parameter and the seam width; and fitting the second relation curve to determine the common parameter relation.
Further, step 6) calculating the flow resistance difference value of the plugging agent in simulated fractures with different fracture widths according to the flow characteristic formula, wherein the flow resistance difference value comprises the following steps: selecting a typical slit width from the slit widths; determining a representative flow pressure gradient corresponding to the representative slit width; and determining the ratio of the flowing pressure gradient of the plugging agent at different seam widths to the typical flowing pressure gradient, and taking the ratio as the flow resistance difference value.
Further, the method further comprises: and 7) drawing a relation curve between the flow resistance difference value of the plugging agent flowing in the simulated fracture under different fracture widths and the fracture width at different injection rates, and quantitatively evaluating the flow difficulty of the plugging agent in the complex fracture by using the relation curve.
Through the technical scheme provided by the invention, the invention at least has the following technical effects:
the method for quantitatively evaluating the flowing difficulty of the plugging agent in the complex fracture comprises the steps of predicting the width of the fracture according to fracture parameters of a target stratum, manufacturing simulated fractures with different widths according to the width of the fracture, injecting the plugging agent into the simulated fractures with different widths at different injection rates, carrying out flowing test, fitting a flowing characteristic formula according to measured data, calculating the flowing resistance difference numerical value of the plugging agent in the simulated fractures with different widths according to the flowing characteristic formula, and quantitatively evaluating the flowing difficulty of the plugging agent in the complex fracture by adopting the flowing resistance difference numerical value. The flowing difficulty of the plugging agent in the fracture is expressed by numerical values, so that the injection difficulty of the plugging agent in the complex fracture leakage stratum can be conveniently judged, and basic support is provided for a method for controlling the flowing behavior of the plugging agent in the complex fracture leakage stratum of the system.
Additional features and advantages of the invention will be set forth in the detailed description which follows.
Drawings
FIG. 1 is a flow chart of a method for quantitatively evaluating the flowing difficulty of a plugging agent in a complex fracture provided by the invention;
FIG. 2 is a graph showing the relationship between the flow pressure gradient and the injection rate of the plugging agent in a simulated fracture when the matrix permeability is 100mD and the fracture width is 1mm in the method for quantitatively evaluating the flow difficulty of the plugging agent in a complex fracture provided by the invention;
FIG. 3 is a graph showing the relationship between the flow pressure gradient and the injection rate of the plugging agent in a simulated fracture when the matrix permeability is 100mD and the fracture width is 2mm in the method for quantitatively evaluating the flow difficulty of the plugging agent in a complex fracture provided by the invention;
FIG. 4 is a graph showing the relationship between the flow pressure gradient and the injection rate of the plugging agent in a simulated fracture when the matrix permeability is 100mD and the fracture width is 5mm in the method for quantitatively evaluating the flow difficulty of the plugging agent in a complex fracture provided by the invention;
FIG. 5 is a graph showing the relationship between the flow pressure gradient and the injection rate of the plugging agent in a simulated fracture when the matrix permeability is 10mD and the fracture width is 1mm in the method for quantitatively evaluating the flow difficulty of the plugging agent in a complex fracture provided by the invention;
FIG. 6 is a graph showing the relationship between the flow pressure gradient and the injection rate of the plugging agent in the simulated fracture when the matrix permeability is 10mD and the fracture width is 2mm in the method for quantitatively evaluating the flow difficulty of the plugging agent in the complex fracture provided by the invention;
FIG. 7 is a graph showing the relationship between the flow pressure gradient and the injection rate of the plugging agent in the simulated fracture when the matrix permeability is 10mD and the fracture width is 5mm in the method for quantitatively evaluating the flow difficulty of the plugging agent in the complex fracture provided by the invention;
FIG. 8 is a fitting curve diagram of a common parameter a in the method for quantitatively evaluating the flowing difficulty of the plugging agent in the complex fracture provided by the invention;
FIG. 9 is a fitting curve diagram of a common parameter b in the method for quantitatively evaluating the flowing difficulty of the plugging agent in the complex fracture provided by the invention;
fig. 10 is a graph showing a relationship between a flow resistance difference value of the plugging agent flowing in simulated fractures with different widths and the width of the fracture at different injection rates in the method for quantitatively evaluating the flow difficulty of the plugging agent in the complex fracture provided by the invention.
Detailed Description
The following detailed description of embodiments of the invention refers to the accompanying drawings. It should be understood that the detailed description and specific examples, while indicating embodiments of the invention, are given by way of illustration and explanation only, not limitation.
It should be noted that the embodiments and features of the embodiments may be combined with each other without conflict.
The plugging agent used in the following examples is a polymer gel plugging agent, and consists of 8 wt% of polymer composite monomer, 1.0 wt% of solid-phase organic macromolecular cross-linking agent, 0.30 wt% of initiator, 4 wt% of rheology control agent, 1.2 wt% of toughening agent and clear water. The polymer composite monomer is acrylamide and 2-acrylamide-2-methylpropanesulfonic acid, the mass ratio of the acrylamide to the 2-acrylamide-2-methylpropanesulfonic acid is 5:1, the initiator is ammonium persulfate, the rheology regulator is lithium magnesium metal hydroxide, and the toughening agent is polypropylene fiber.
The present invention will be described in detail below with reference to the embodiments with reference to the attached drawings.
Referring to fig. 1, an embodiment of the present invention provides a method for quantitatively evaluating the flowing difficulty of a plugging agent in a complex fracture, including the following steps: step 1) predicting the fracture width of a natural fracture of a target stratum according to the logging parameters of the target stratum; step 2) manufacturing core models with simulated fractures according to the fracture width of the natural fractures, wherein the simulated fractures of each core model have different fracture widths; step 3) injecting a plugging agent into the simulated fracture according to different injection rates; step 4) calculating the flowing pressure gradient of the plugging agent in simulated fractures with different widths at different injection rates according to the injection pressure corresponding to the different injection rates; step 5) determining a flow characteristic formula of the plugging agent in the simulated fracture according to the injection rate, the fracture width and the flow pressure gradient; and 6) calculating the flow resistance difference numerical value of the plugging agent in simulated fractures with different fracture widths according to the flow characteristic formula, and quantitatively evaluating the flow difficulty of the plugging agent in the complex fractures by adopting the flow resistance difference numerical value.
Specifically, in the embodiment of the present invention, a target formation is explored, the extracted target formation actual core is analyzed, and the fracture width of the natural fracture of the target formation is predicted by combining the completed well logging data (such as imaging well logging, acoustic well logging, etc.). And manufacturing a plurality of core models with simulated fractures according to the predicted fracture width, wherein the fracture width of the simulated fractures of each core model is different. And then injecting the plugging agent into the simulated fractures of the core model according to different injection rates, detecting the injection pressure of the simulated fractures with different fracture widths corresponding to the injection rate, and calculating the flowing pressure gradient of the plugging agent in the corresponding simulated fractures according to the injection rate and the injection pressure. And determining a flow characteristic formula of the plugging agent in the simulated fracture according to the injection rate, the fracture width and the flow pressure gradient, wherein the formula is a relational expression among the flow pressure gradient, the injection rate and the fracture width. And calculating the flow resistance difference numerical value of the plugging agent in simulated fractures with different widths according to a flow characteristic formula, and quantitatively evaluating the flow difficulty of the plugging agent in the complex fractures by adopting the flow resistance difference numerical value.
According to the method provided by the embodiment of the invention, the flowing difficulty degree of the plugging agent in the fracture is converted into a numerical value, the injection difficulty degree of the plugging agent in the complex fracture leakage stratum can be conveniently judged, and a basic support is provided for the method for controlling the flowing behavior of the plugging agent in the complex fracture leakage stratum for establishing the system.
Further, the step 2) of manufacturing a core model with simulated fractures according to the fracture width of the natural fractures, wherein the simulated fractures of each core model have different fracture widths, includes: determining a basic core of the core model according to the lithology and the matrix permeability of the target stratum; sandwiching salt cakes of different thicknesses in the base core according to fracture widths of the natural fractures; and dissolving the salt cake in the basic rock core to form the rock core model with the simulated fractures, wherein the simulated fractures of each rock core model have different fracture widths.
Specifically, in the embodiment of the present invention, taking the predicted seam width of the simulated fracture as an example of 0.05-5mm, two simulated cores with matrix permeability of 10 and 100 mracy are manufactured, and the manufacturing steps specifically include: (1) an artificial cemented columnar rock core with matrix permeability of 10 and 100 millidarcy is used as a basic rock core, and the apparent dimension of the basic rock core is 3.8cm in diameter and 8cm in length; (2) cutting the basic rock core along the central axis by using a rock core cutter; (3) placing the cut basic core blocks into a mold, placing coarse salt grains between the planes of the two basic core blocks, clamping the two basic core blocks by using a high-pressure clamp, compacting the salt grains, and measuring the thickness of a compacted salt cake by using a vernier caliper, wherein the thickness of the salt cake is 1mm, 2mm and 5mm respectively; (4) cementing the two basic rock core blocks along two sides of the salt cake (namely the axial direction of the columnar basic rock core) by using an epoxy resin cementing agent to obtain a crack rock core clamped with the salt cake; (5) placing the fracture core with the salt cake in a core holder, adding ring pressure of 2MPa, injecting deionized water into the fracture core at a constant speed, and after injecting deionized water with 50 fracture volumes, completely dissolving the salt cake to form simulated fractures with widths of 1mm, 2mm and 5mm respectively; (6) and (4) removing the ring pressure, taking out the basic rock core from the rock core holder, and drying to obtain the rock core models with the seam widths of 1mm, 2mm and 5mm respectively required by the experiment.
According to the method provided by the invention, the core model with parameters similar to the actual reservoir rock type, permeability, porosity and the like is prepared, and meanwhile, a plurality of core models with simulated fractures with different fracture widths can be prepared, so that the contrast and reliability of the experiment are improved.
Further, the step 4) calculates the flowing pressure gradient of the plugging agent in the simulated fracture with different fracture widths at different injection rates according to the injection pressure corresponding to the different injection rates, and comprises the following steps: calculating the flowing pressure of the plugging agent in simulated fractures with different widths at different injection rates according to the injection pressure and the pipeline friction resistance; determining the flow pressure gradient from a ratio of the flow pressure to a length of the simulated fracture.
Specifically, in the embodiment of the invention, after the injection pressure of the plugging agent flowing in the simulated fractures with different fracture widths at different injection rates is determined, the pipeline friction resistance is subtracted from the injection pressure, the flowing pressure of the plugging agent in the simulated fractures with different fracture widths at different flow rates is determined, and the ratio of the flowing pressure to the length of the corresponding simulated fracture is used as the flowing pressure gradient.
Further, step 5) determining a flow characteristic formula of the plugging agent in the simulated fracture according to the injection rate, the fracture width and the flow pressure gradient, wherein the flow characteristic formula comprises the following steps: determining a first relation between the injection rate and the flow pressure gradient under different seam widths respectively; determining a common parameter corresponding to the seam width through the first relational expression; determining a second relational expression according to the first relational expression and the common parameters; determining a common parameter relation between the common parameter and the seam width; and substituting the common parameter relational expression into the second relational expression to determine the flow characteristic formula.
Specifically, in the embodiment of the present invention, a first relational expression between the injection rate and the flow pressure gradient of each simulated fracture is determined, the plurality of first relational expressions are compared to determine a common parameter in the first relational expression, the common parameter is subjected to data processing to obtain a common parameter relational expression between the common parameter and the fracture width, a second relational expression is determined by comprehensively considering the first relational expression and the common parameter of each simulated fracture, and the common parameter relational expression is substituted into the second relational expression to obtain a flow characteristic formula, wherein the flow characteristic formula is a relational expression between the fracture width, the injection rate, and the flow pressure gradient.
According to the method provided by the invention, a relational expression among the seam width, the injection rate and the flow pressure gradient can be obtained, the seam width in the formula is not limited to the seam width used in experiments, and the flow pressure gradient and the flow resistance difference value of the plugging agent in the fracture with any seam width can be calculated by utilizing the formula, so that the method is used for quantitatively representing the flow difficulty degree of the plugging agent in the fractures with different seam widths from micro-fractures to macro-wide fractures.
Further, the determining a first relationship between injection rate and the flow pressure gradient comprises: respectively drawing first relation curves between the injection rate and the flow pressure gradient under different seam widths; and fitting the first relation curve to determine the first relation.
Specifically, in the embodiment of the present invention, during the flow test, the flow rates of the plugging agent in the simulated fractures of different widths and the flow pressure gradient at the flow rates are recorded, a first relation curve of the injection rate and the flow pressure gradient at the same fracture width is drawn by using the injection rate as an abscissa and the flow pressure gradient as an ordinate, and the first relation curve is subjected to fitting processing to determine a first relation between the injection rate and the flow pressure gradient.
Further, the determining a common parameter relation between the common parameter and the slit width includes: drawing a second relation curve between the common parameter and the seam width; and fitting the second relation curve to determine the common parameter relation.
Specifically, in the embodiment of the present invention, the first relational expressions under a plurality of different slit widths are compared to determine the common parameter in the first relational expression, the slit width is taken as an abscissa and the common parameter is taken as an ordinate, a second relational curve between the common parameter and the slit width is drawn, and then the fitting process is performed on the second relational curve to determine the common parameter relational expression between the common parameter and the slit width.
Further, step 6) calculating the flow resistance difference value of the plugging agent in simulated fractures with different fracture widths according to the flow characteristic formula, wherein the flow resistance difference value comprises the following steps: selecting a typical slit width from the slit widths; determining a representative flow pressure gradient corresponding to the representative slit width; and determining the ratio of the flowing pressure gradient of the plugging agent at different seam widths to the typical flowing pressure gradient, and taking the ratio as the flow resistance difference value.
Specifically, in the embodiment of the present invention, a typical slit width is selected from slit widths of different widths. Recording the flow resistance of the plugging agent in a typical seam width as 1, calculating a typical flow pressure gradient of the plugging agent flowing in the typical seam width at different injection rates, selecting the typical flow pressure gradient as a reference, respectively calculating the ratio of the flow pressure gradient of the plugging agent flowing in different seam widths and the typical flow pressure gradient at the same injection rate, taking the ratio as a flow resistance difference numerical value, and quantitatively evaluating the flow difficulty of the plugging agent in a complex fracture through the flow resistance difference numerical value. In the present invention, a slit width of any width may be selected as a typical slit width, and preferably, the widest slit width is selected as a typical slit width in the present invention.
Further, the method further comprises: and 7) drawing a relation curve between the flow resistance difference value of the plugging agent flowing in the simulated fracture under different fracture widths and the fracture width at different injection rates, and quantitatively evaluating the flow difficulty of the plugging agent in the complex fracture by using the relation curve.
Specifically, in the embodiment of the invention, the seam width is used as an abscissa, the flow resistance difference value is used as an ordinate, a relation curve between the flow resistance difference value of the plugging agent flowing in the simulated fracture at different injection rates and the seam width is respectively drawn, and the difficulty degree of the flow of the plugging agent in the complex fracture is quantitatively evaluated by using the relation curve.
By the method provided by the invention, the difficulty degree of the flowing of the plugging agent in different seam-width cracks from micro cracks to macro wide cracks can be represented more intuitively and quantitatively.
Example 1
The drilling fluid loss is serious when the drilling fluid encounters a crack development stratum in the drilling process of an oil field. And (4) analyzing by combining the logging data of the completed well drilling of the block with the actual core of the target stratum taken out by the exploratory well, and predicting that the width of the natural fracture of the target stratum is 0.05-5 mm.
By adopting the core model manufacturing method provided by the invention, the artificial cemented columnar core with the matrix permeability of 10 and 100 millidarcy is used as the basic core to manufacture the core model with the simulated cracks, the appearance size of the core model is 3.8cm in diameter and 8cm in length, the simulated cracks are respectively 1mm, 2mm and 5mm in width, and the parameters of the core model are shown in table 1:
TABLE 1 core model parameters
By adopting the method provided by the invention, plugging agent solution is injected into simulated cracks with different widths at the injection rates of 0.2mL/min, 0.5mL/min, 1.0mL/min, 2.0mL/min and 5.0mL/min respectively, the injection pressure is collected, the friction of a pipeline is removed, the flow pressure of the plugging agent in the simulated cracks at different injection rates is obtained, and the test results are shown in tables 2 and 3.
TABLE 2 flow pressure of lost circulation additive in fractured rock core with matrix permeability of 100 millidarcy
TABLE 3 flow pressure of the plugging agent in a fractured core with a matrix permeability of 10 millidarcy
Determining a flowing pressure gradient according to the ratio of the flowing pressure to the length of the simulated fracture, and drawing a relationship graph of the flowing pressure gradient and the injection rate of the plugging agent in the core model with different seam widths and different matrix permeabilities, as shown in fig. 2 to 7, so as to obtain a first relationship between the injection rate and the flowing pressure gradient under different seam widths:
the first relation between the flowing pressure gradient and the injection rate of the plugging agent in the simulated fracture when the matrix permeability is 100mD and the fracture width is 1mm is as follows: dp/dl-52.303 v +62.732
The first relation between the flowing pressure gradient and the injection rate of the plugging agent in the simulated fracture when the matrix permeability is 100mD and the fracture width is 2mm is as follows: dp/dl-42.494 v +57.46
The first relation between the flowing pressure gradient and the injection rate of the plugging agent in the simulated fracture when the matrix permeability is 100mD and the fracture width is 5mm is as follows: dp/dl-34.665 v +45.41
When the matrix permeability is 10mD and the fracture width is 1mm, the first relation between the flowing pressure gradient and the injection rate of the plugging agent in the simulated fracture is as follows: dp/dl-50.439 v +63.901
The first relation between the flowing pressure gradient and the injection rate of the plugging agent in the simulated fracture when the matrix permeability is 10mD and the fracture width is 2mm is as follows: dp/dl 43.96 v +55.697
The first relation between the flowing pressure gradient and the injection rate of the plugging agent in the simulated fracture when the matrix permeability is 10mD and the fracture width is 5mm is as follows: dp/dl-34.254 v +47.605
Comparing the plurality of first relational expressions to determine common parameters a and b in the first relational expressions, and performing data processing on the common parameters to obtain common parameters a and b under different seam widths, as shown in table 4:
TABLE 4 common parameters at different slit widths
As can be seen from comparative analysis, when the permeability of the matrix is the same, the values of a and b both decrease with the increase of the slit width; when the slot widths are the same, the values of a and b are insensitive to changes in matrix permeability. Therefore, only the influence of the slit width is considered in fitting a and b, and the fitting results are shown in fig. 8 and 9.
As can be seen from fig. 8 and 9, the common parameters a and b are exponentially related to the slit width, and the numerical value decreases with the increase of the slit width, and the decreasing amplitude gradually decreases, so as to obtain the common parameter relation between the common parameters and the slit width:
and comprehensively considering the first relational expression of the simulated cracks with different widths and the common parameters to determine a second relational expression:
dp/dl＝a·v+b
and substituting the common parameter relation into the second relation to obtain a flow characteristic formula:
selecting the widest seam (5.0mm) of the experiment from the seam width as a typical seam width, recording the flow resistance of the plugging agent in the typical seam width as 1, calculating the typical flow pressure gradient of the plugging agent flowing in the typical seam width at different injection rates, selecting the typical flow pressure gradient as a reference, respectively calculating the ratio of the flow pressure gradient of the plugging agent flowing in different seam widths at the same injection rate to the typical flow pressure gradient, taking the ratio as a flow resistance difference value, and quantitatively evaluating the flow difficulty of the plugging agent in a complex fracture through the flow resistance difference value.
In this embodiment, the flow pressure gradient and the flow resistance difference of the plugging agent in the simulated fracture with the fracture width ranging from 10 μm to 5mm were calculated by taking the injection rate of the plugging agent as 0.5mL/min, 2.0mL/min and 5.0mL/min as examples, and the calculation data is shown in table 5.
TABLE 5 flow pressure gradient and flow resistance difference between fractures of plugging agent in simulated fracture
As shown in fig. 10, in the embodiment of the present invention, the seam width is taken as an abscissa, the flow resistance difference value is taken as an ordinate, a relationship curve between the flow resistance difference value of the plugging agent flowing in the simulated fracture with different seam widths and the seam width at different injection rates is respectively drawn, and the relationship curve is used to quantitatively evaluate the flow difficulty of the plugging agent in the complex fracture.
As can be seen from FIG. 10, the flow resistance difference value of the plugging agent is sensitive to the change of the seam width, and the resistance difference value is continuously reduced along with the increase of the seam width, which indicates that the plugging agent is more difficult to enter when the seam width is smaller.
The preferred embodiments of the present invention have been described in detail with reference to the accompanying drawings, however, the present invention is not limited to the specific details of the above embodiments, and various simple modifications can be made to the technical solution of the present invention within the technical idea of the present invention, and these simple modifications are within the protective scope of the present invention.
It should be noted that the various technical features described in the above embodiments can be combined in any suitable manner without contradiction, and the invention is not described in any way for the possible combinations in order to avoid unnecessary repetition.
In addition, any combination of the various embodiments of the present invention is also possible, and the same should be considered as the disclosure of the present invention as long as it does not depart from the spirit of the present invention.
Claims (7)
1. A method for quantitatively evaluating the flowing difficulty of a plugging agent in a complex fracture, which is characterized by comprising the following steps:
step 1) predicting the fracture width of a natural fracture of a target stratum according to the logging parameters of the target stratum;
step 2) manufacturing core models with simulated fractures according to the fracture width of the natural fractures, wherein the simulated fractures of each core model have different fracture widths;
step 3) injecting a plugging agent into the simulated fracture according to different injection rates;
step 4) calculating the flowing pressure gradient of the plugging agent in simulated fractures with different widths at different injection rates according to the injection pressure corresponding to the different injection rates;
step 5) determining a flow characteristic formula of the plugging agent in the simulated fracture according to the injection rate, the fracture width and the flow pressure gradient, wherein the flow characteristic formula comprises the following steps: determining a first relation between the injection rate and the flow pressure gradient under different seam widths respectively; determining a common parameter corresponding to the seam width through the first relational expression; determining a second relational expression according to the first relational expression and the common parameters; determining a common parameter relation between the common parameter and the seam width; substituting the common parameter relational expression into the second relational expression to determine the flow characteristic formula;
and 6) calculating the flow resistance difference numerical value of the plugging agent in simulated fractures with different fracture widths according to the flow characteristic formula, and quantitatively evaluating the flow difficulty of the plugging agent in the complex fractures by adopting the flow resistance difference numerical value.
2. The method of claim 1, wherein step 2) of creating core models with simulated fractures according to fracture widths of the natural fractures, wherein the simulated fractures of each core model have different fracture widths, comprises:
determining a basic core of the core model according to the lithology and the matrix permeability of the target stratum;
sandwiching salt cakes of different thicknesses in the base core according to fracture widths of the natural fractures;
and dissolving the salt cake in the basic rock core to form the rock core model with the simulated fractures, wherein the simulated fractures of each rock core model have different fracture widths.
3. The method as claimed in claim 1, wherein the step 4) of calculating the flowing pressure gradient of the plugging agent in the simulated fracture with different fracture widths at different injection rates according to the injection pressure corresponding to the different injection rates comprises:
calculating the flowing pressure of the plugging agent in simulated fractures with different widths at different injection rates according to the injection pressure and the pipeline friction resistance;
determining the flow pressure gradient from a ratio of the flow pressure to a length of the simulated fracture.
4. The method of claim 1, wherein determining a first relationship between an injection rate and the flow pressure gradient comprises:
respectively drawing first relation curves between the injection rate and the flow pressure gradient under different seam widths;
and fitting the first relation curve to determine the first relation.
5. The method of claim 1, wherein determining the common parameter relationship between the common parameter and the slot width comprises:
drawing a second relation curve between the common parameter and the seam width;
and fitting the second relation curve to determine the common parameter relation.
6. The method as claimed in claim 1, wherein the step 6) of calculating the flow resistance difference value of the plugging agent in the simulated fracture with different fracture widths according to the flow characteristic formula comprises:
selecting a typical slit width from the slit widths;
determining a representative flow pressure gradient corresponding to the representative slit width;
and determining the ratio of the flowing pressure gradient of the plugging agent at different seam widths to the typical flowing pressure gradient, and taking the ratio as the flow resistance difference value.
7. The method of claim 1, further comprising:
and 7) drawing a relation curve between the flow resistance difference value of the plugging agent flowing in the simulated fracture under different fracture widths and the fracture width at different injection rates, and quantitatively evaluating the flow difficulty of the plugging agent in the complex fracture by using the relation curve.
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| CN101089116A (en) * | 2007-07-11 | 2007-12-19 | 中国石油大学(华东) | Adaptive leak preventing and stopping agent for drilling fluid |
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| CN103396774A (en) * | 2013-08-09 | 2013-11-20 | 西南石油大学 | Plugging agent and preparation method thereof |
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