CN116084906B - Small-scale sand oil reservoir energy increasing extraction process - Google Patents
Small-scale sand oil reservoir energy increasing extraction process Download PDFInfo
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Abstract
The invention discloses an energy-increasing extraction process of a small-scale sand oil reservoir, which comprises the steps of firstly obtaining the dosage, viscosity and well-soaking time of a low-viscosity linear gel fracturing fluid system by a numerical simulation method, and then pumping the low-viscosity linear gel fracturing fluid system and simultaneously adding 40/70 meshes of quartz sand in a matched manner; pump filling 1450-2000 m 3 Is an oil displacement agent; pumping a medium viscosity fracturing fluid system, and simultaneously adding 30/50 mesh quartz sand in a matched manner; the pumping quantity is 70m 3 A high-viscosity gel fracturing fluid system with the viscosity of 150-200 mPa.s is added with 20/40 meshes of ceramsite in a matching way; and (5) performing well soaking energy storage after the fracturing fluid pump injection is completed, and performing flowback production after well soaking is completed. According to the process, the height of the crack is effectively controlled in the fracturing construction, the fluid loss of the fracturing fluid and the energizing working fluid is reduced, the efficient flow of the energizing working fluid in the artificial crack is ensured, and then the end part of the crack is plugged, so that the energy storage at the far well end and the reverse displacement after well opening are realized.
Description
Technical Field
The invention relates to an energy-increasing extraction process for a small-scale sand oil reservoir, and belongs to the technical field of drilling equipment such as petroleum, natural gas, mine engineering and the like.
Background
The small-scale sand reservoir has the geological characteristics of limited single well control reserves, unclear sand spreading rule, wide interlayer development distribution range and poor interlayer connectivity, so that the reservoir has low reserves, high exploitation difficulty, low exploitation degree and poor overall exploitation effect. At present, in the development scheme aiming at small-scale sand oil reservoirs, development modes of vertical well failure type exploitation, horizontal well failure type exploitation and single well water injection huff and puff exploitation are mainly adopted. Although water flooding and artificial energy supplement are considered in the water flooding throughput exploitation mode, the recovery ratio cannot meet the requirement of economic return. The injection and production relation is forcedly formed in the small-scale sand body densely distributed wells, the production cost cannot be effectively controlled, and for a small-scale sand body oil reservoir, the lateral heterogeneity is strong, the effective injection and production relation is difficult to establish between single wells, and the energy supplementing efficiency is poor. In summary, in the current development schemes for small-scale sand reservoirs, a set of process schemes suitable for efficient development thereof has not been formed.
Disclosure of Invention
In order to overcome the defects in the prior art, the invention discloses a small-scale sand oil reservoir energy increasing extraction process.
The technical scheme provided by the invention for solving the technical problems is as follows: an energy-increasing extraction process for a small-scale sand oil reservoir comprises the following steps:
s10, adopting a low-viscosity linear adhesive fracturing liquid system as an energizing liquid, and setting the construction discharge capacity to be 2m 3 And/min, and adopting a numerical simulation method to respectively select the dosage of the energizing liquid to be 50m 3 、100m 3 、150m 3 、200m 3 、250m 3 、300m 3 And the optimal parameters of the viscosity of the energizing liquid of 5 mPas, 15 mPas, 20 mPas, 25 mPas, 30 mPas and the stewing time of 0.5d, 1d, 3d, 5d and 7d are used for construction;
s20, adding 40/70 mesh quartz sand, 3% floating agent and 4% sinking agent in a matched manner while pumping the low-viscosity linear adhesive fracturing fluid system; the sand ratio of the 40/70 mesh quartz sand is 6-8%, and the construction discharge capacity is 1m 3 /min；
Step S30, further using 10m 3 Displacement pump filling 600-800 m per minute 3 To improve the oil displacement effect;
step S40, pumping dosage is 135m 3 The medium viscosity fracturing fluid system with the viscosity of 30-60 mPa.s is added with 30/50 meshes of quartz sand, the sand ratio of the 30/50 meshes of quartz sand is 10-20%, and the construction discharge capacity is 3.5-4 m 3 /min；
Step S50, at 12m 3 Displacement pump with a/min filling of 850-1200 m 3 The oil displacement agent improves the oil displacement effect;
step S60, pumping dosage is 130-170 m 3 The high-viscosity gel fracturing fluid system with the viscosity of 150-200 mPa.s is matched with 20/40 mesh ceramsite when 50% of liquid is pumped, the filtrate reducer and temporary plugging agent are added, the sand ratio of the 20/40 mesh ceramsite is 20-25%, and the construction discharge capacity is 4-5 m 3 Adding 20/40 mesh ceramsite with the sand ratio of 25-32% and the construction discharge capacity of 4-5 m into 50% liquid after pumping per minute 3 /min；
And step S70, performing well-soaking energy storage after the fracturing fluid is pumped, and performing flowback production after well-soaking is finished.
Further technical proposal is that the low-viscosity linear glue fracturing fluid system comprises 0.10 percent of HPG, 1.0 percent of anti-swelling agent, 0.05 percent of bactericide, 0.3 percent of foaming discharge assisting agent and 0.2 percent of Na 2 CO 3 。
According to the further technical scheme, in the numerical simulation method of the step S10, a hydraulic fracturing model is used for carrying out numerical operation to obtain an artificial fracture half-length, an artificial fracture width distribution, an artificial fracture fluid pressure distribution, an artificial fracture internal fracturing fluid filtration loss, a matrix oil phase pressure distribution and a matrix water phase saturation distribution in the fracturing construction process, the parameters are substituted into relevant parameters obtained by calculation in a stewing model as initial parameters, and then the parameters are brought into a flowback-production model to obtain the accumulated oil well yield of the oil well; and finally, determining the optimal dosage of the energizing liquid, the viscosity of the energizing liquid and the time for soaking the well according to the accumulated yield of the oil well.
The further technical scheme is that the numerical simulation method comprises the following specific steps:
(1) Carrying out numerical solution on a reservoir fluid loss fracturing model with coupled fracturing fluid flow to obtain the width W (x) of any position of the artificial fracture at any time and the fluid of any position of the artificial fracturePressure P f (x) Fluid loss rate v of fracturing fluid in the seam v The method comprises the steps of carrying out a first treatment on the surface of the From this, the width W of each crack unit at the fracturing construction time t L,t Fluid pressure P of each fracture unit FL,t Fluid loss Q of each crack unit mfL,t And fluid pressure within the tip fracture unit at fracture construction time t
Fluid pressure P of each fracture unit FL,t Substituting the stress intensity factor K into the fracture tip stress at the fracturing construction time t Ii,t ；
Wherein: k (K) Ii,t To fracture tip stress intensity factor at fracturing construction time t, MPa.m 1/2 ；
The calculated crack tip stress intensity factor K Ii,t Fracture toughness K with reservoir rock IC ＝2MPa·m 1/2 Comparing;
when K is Ii,t ≤K IC When the artificial crack is in the fracturing construction time t, crack expansion does not occur, and the crack length is unchanged; when K is Ii,t ＞K IC When the artificial cracks are expanded, the crack length is increased, and the total number of artificial crack units is n L ＝n L +1, the width of the new crack unit is 0m, and the fluid loss of the new crack unit is 0m 3 /s；
Substituting the fluid loss at each fracture unit under the t time obtained by calculation into a reservoir seepage model to obtain seepage conditions of fracturing fluid after the fluid loss enters the reservoir; and circularly calculating until the simulation time reaches the fracturing construction time t=t a,end Entering step (2);
(5) And (3) performing well-logging simulation calculation: calculating matrix oil phase pressure distribution and matrix water phase saturation distribution in the well soaking process; width of each crack unit after fracturing obtained in the step (1)Substituting the fluid pressure of each fracture unit, the matrix grid pressure distribution and the water saturation distribution as initial parameters into the step (1) for cyclic calculation while setting the pumping flow rate to 0m 3 S; calculating t=t until completion of the braising b,end Ending, at which time t=t is available b,end Fluid pressure at each fracture cell of the artificial fracture at the timeOil phase pressure per matrix lattice +.>And water phase saturation of each matrix grid +.>
(6) Performing flowback production after well completion, and simulating parameters such as fluid pressure of the artificial fracture unit, pressure distribution of matrix grids, water phase saturation distribution of matrix grids and the like calculated by the method as initial parameters in a flowback-production model; obtaining the artificial fracture fluid pressure P at different time by numerical solution F And matrix oil phase pressure P mu Artificial crack water phase saturation S at different times Fv Saturation of matrix aqueous phase S mv The method comprises the steps of carrying out a first treatment on the surface of the From this, a time t can be obtained c Lower matrix grid water phase saturation S mv (i,j,t c ) Oil phase pressure P of matrix lattice mu (i,j,t c ) Water phase saturation S of artificial crack unit Fv (L,t c ) Oil phase pressure P of artificial fracture unit F (L,t c )；
(7) Time t c =0 and time t c The saturation of the oil phase and the water phase of the lower matrix grid and the saturation of the oil phase and the water phase of the artificial fracture unit are substituted into the following formula, and the time t from the production to the production of the well can be calculated c Accumulated oil well yield Q;
wherein: q is the time t from the production of open well 2 Cumulative oil well production at time, m 3 ；n i ,n j The total number of grids in the x-direction and the y-direction in the matrix and microcrack grids; n is n L The total number of the artificial crack units; zeta type toy L M is the length of each artificial crack unit; x is x i,j 、y i,j The length and width of the matrix and the microcrack grid at the i, j position, m; s is S mv (i, j, 0) is the initial water phase saturation of the matrix grid at i, j position at the beginning of well flowback-production; s is S Fv (L, 0) is the initial water phase saturation of the artificial crack unit of the L-th section at the beginning of flowback-production of the well; s is S mv (i,j,t c ) To time t for open production 2 The water phase saturation of the matrix grid at the j position at time i; s is S Fv (L,t c ) To time t for open production 2 And (5) water phase saturation of the artificial crack unit at the L-th stage.
The further technical scheme is that in the step S10, the consumption of each energizing liquid, the viscosity of the energizing liquid and the accumulated yield when the well is opened for 200 days in the well-closing time are finally determined, and the accumulated yield increase coefficient R when the well is opened for 200 days in the well-closing production with different consumption of the energizing liquid, the accumulated yield increase coefficient J when the well is opened for 200 days in the well-closing production with different viscosity of the energizing liquid and the accumulated yield increase coefficient K when the well is opened for 200 days in the well-closing time are calculated; selecting the optimal energy increasing liquid dosage corresponding to the minimum energy increasing liquid dosage in the range of 0.10-0.45, selecting the optimal energy increasing liquid viscosity corresponding to the minimum energy increasing liquid viscosity in the range of 0.11-0.23, and selecting the optimal well soaking time corresponding to the minimum well soaking time in the range of 0.10-0.30;
wherein the consumption of the energy-increasing liquid corresponding to the accumulated yield increase coefficient R when the well is opened for 200 days under each of the different consumption of the energy-increasing liquid is the maximum consumption of the two energy-increasing liquid; the viscosity of the energizing liquid corresponding to the accumulated yield increase coefficient J when the well is opened and produced for 200 days under each of the different viscosity of the energizing liquid is the maximum viscosity of the two viscosity of the energizing liquid; wherein the dead time corresponding to the accumulated yield increase coefficient K when the well is opened for 200 days under each different dead time is the dead time with the maximum two dead times.
The further technical scheme is that the calculation formulas of the accumulated yield increase coefficient R when the well is opened for 200 days under different dosage of the energizing liquid, the accumulated yield increase coefficient J when the well is opened for 200 days under different viscosity of the energizing liquid and the accumulated yield increase coefficient K when the well is opened for 200 days under different time of well soaking are respectively as follows:
wherein:for different pump liquid volumes q m 、q n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the R is the accumulated yield increase coefficient when the well is opened for 200 days under different energy increasing liquid consumption; />For different energized liquid viscosity mu m 、μ n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the J is the yield increase coefficient of the accumulated yield when different energy-increasing liquids are stuck to the bottom-hole production for 200 days; />For different time t of well soaking m 、t n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the K, the yield increase coefficient of the accumulated yield when the well is opened for 200 days under different well-stewed time.
According to a further technical scheme, the reservoir fluid loss fracturing model for coupling fracturing fluid flow comprises:
fracture width model considering fluid loss:
wherein: w (x) is crack width, m; h is the crack height, m; v is poisson's ratio, dimensionless; e is Young's modulus, MPa; sigma (sigma) n Is the horizontal minimum principal stress, MPa; p (P) f (x) Is the fluid pressure in the seam, MPa;
wherein: q (x) is the flow rate at any position in the seam, m 3 S; mu is the viscosity of fluid in the seam, mPa.s;
wherein: v v Is the fluid loss speed, m/s; t is the fracturing construction time, min;
fluid loss model:
Q mf (x)＝T mf (x)[P f (x)-P m (x)]
wherein:
wherein T is mf For the flow coefficient, m, between the fracture and the matrix 3 /(MPa·s)；Q mf Is the fluid loss between the crack and the matrix in unit time, m 3 /s；A mf The contact area of the crack and the matrix is m; k (k) mf Is the average permeability of the fracture and matrix, mD;for crack-to-crackThe characteristic distance m of the matrix grid;
according to the fluid loss model, the fluid loss degree can be obtained by solving:
the crack extension boundary conditions are:
wherein: g is the bulk modulus of the reservoir rock sample and MPa; n is n L The total number of the artificial crack units under the fracturing construction time t; zeta type toy L And m is the length of the artificial crack unit.
Further technical scheme is, the reservoir seepage model includes:
P mc ＝P mu -P mv
wherein: phi (phi) m Is the porosity of the reservoir matrix, dimensionless; k (K) m Is the matrix permeability, mD; k (K) mrv Is the relative permeability of the aqueous phase in the matrix, dimensionless; k (K) mru Is the relative permeability of the oil phase in the matrix, dimensionless; s is S mv Is the water phase saturation in the matrix, dimensionless; v (V) b For the volume of matrix units, m 3 ；μ v mPa.s, the viscosity of the aqueous phase in the matrix; mu (mu) u mPa.s, the viscosity of the oil phase in the matrix; b (B) v Is the volume coefficient of the water phase in the matrix, and has no factor; b (B) u Is the volume coefficient of the oil phase in the matrix, and has no factor; p (P) mv 、P mu The pressure of the water phase and the oil phase in the matrix is MPa; p (P) mc Capillary pressure in the matrix, MPa;
initial conditions of reservoir seepage:
P mu (i,j,t) t＝0 ＝P e
wherein: p (P) e The pressure is the original stratum pressure of the oil reservoir and MPa; i, j is the position coordinate of the grid;
the boundary conditions of the seepage of the oil reservoir matrix are as follows:
wherein: l (L) x 、L y To represent reservoir length and reservoir width, m, respectively.
The further technical scheme is that the oil well flowback-production model comprises:
oil-water two-phase seepage differential equation in oil reservoir:
P mc ＝P mu -P mv
wherein: k (K) F The permeability of the artificial crack is D; v (V) F Is the volume of the artificial crack unit，m 3 ；K Frv The relative permeability of the water phase and the oil phase of the artificial fracture is dimensionless; k (K) mrv 、K mru The relative permeability of the matrix water phase and the oil phase is dimensionless; k (K) m D, the permeability of the matrix; v (V) m For the volume of the matrix network, m 3 ；q Fv 、q Fu Is the source and sink item of water phase and oil phase in the artificial crack, m 3 /s；S Fv 、S mv The water phase saturation degree of the artificial cracks and the matrix is dimensionless; phi (phi) F 、φ m The porosity of the artificial crack and the matrix is dimensionless; p (P) mv 、P mu The water phase pressure and the oil phase pressure of the matrix are MPa; q (Q) mFv 、Q mFu Water phase and oil phase channeling of main crack, m 3 /s；δ m Judging parameters of whether the matrix grid contains artificial cracks or not, wherein delta=1 when the matrix grid passes through the cracks; delta=0 when the matrix mesh passes without a crack; t is the time of flowback-production of the oil well, s; beta is a unit conversion coefficient, and beta=0.001 is taken;
the initial conditions include the distribution of initial pressure and initial saturation, i.e.:
wherein:the fluid pressure of each crack unit at the end of the construction of the dead well, namely the initial pressure distribution of the artificial crack in the flowback-production simulation of the oil well, is MPa; />The oil phase pressure of each matrix grid at the end of the construction of the well is equal to the initial oil phase pressure distribution of the matrix in the flowback-production simulation of the oil well, namely the pressure distribution of the oil phase is equal to the pressure distribution of the oil phase;
wherein:the water phase saturation of each matrix grid at the end of the construction of the braised well, namely the initial water phase saturation of the matrix in the flowback-production simulation of the oil well, is dimensionless;
the internal boundary conditions are:
P F (x w ,y w ,t c )＝P wf (t c )
wherein: x is x w 、y w The horizontal coordinate value and the vertical coordinate value m of the grid unit where the oil well is positioned; p is p wf Is the bottom hole flow pressure, MPa;
the outer boundary conditions are:
wherein: p (P) mv 、P mu The water phase pressure and the oil phase pressure of the matrix are MPa.
Further technical proposal is that the high viscosity gel fracturing fluid system comprises 0.42 percent HPG, 1.0 percent of anti-swelling agent, 0.05 percent of bactericide, 0.3 percent of foaming discharge assisting agent and 0.2 percent of Na 2 CO 3 The method comprises the steps of carrying out a first treatment on the surface of the The medium viscosity fracturing fluid system comprises 0.30 percent of HPG, 1.0 percent of anti-swelling agent, 0.05 percent of bactericide, 0.3 percent of foaming cleanup additive and 0.2 percent of Na 2 CO 3 。
The invention has the following beneficial effects: according to the process, the height of the crack is effectively controlled in the fracturing construction, the fluid loss of the fracturing fluid and the energizing working fluid is reduced, the efficient flow of the energizing working fluid in the artificial crack is ensured, and then the end part of the crack is plugged, so that the energy storage at the far well end and the reverse displacement after well opening are realized. The numerical simulation method is combined with the embedded discrete fracture model and the reservoir dual-medium model to simulate and optimize relevant parameters of the fracture expansion, the fracturing fluid filtration and the flowback production process, has higher calculation efficiency, can guide site construction in time, and promotes efficient development of small-scale sand oil reservoir resources.
Drawings
FIG. 1 shows daily oil production from an X-well under different pump fluid injection conditions;
FIG. 2 shows cumulative oil production for an X-well over 200 days under different pump fluid injection conditions;
FIG. 3 is daily oil production for an X-well at different viscosity conditions;
FIG. 4 is a graph of cumulative oil production for an X-well producing for 200 days at different viscosity conditions;
FIG. 5 shows daily oil production for various soak times for an X well;
FIG. 6 shows the cumulative oil production for 200 days after the X-well has been opened for various soak times.
Description of the embodiments
The following description of the embodiments of the present invention will be made apparent and fully in view of the accompanying drawings, in which some, but not all embodiments of the invention are shown. All other embodiments, which can be made by those skilled in the art based on the embodiments of the invention without making any inventive effort, are intended to be within the scope of the invention.
The invention discloses a small-scale sand oil reservoir energy increasing extraction process, which comprises the following steps of:
step 1, adopting a low-viscosity linear adhesive fracturing fluid system (0.10 percent of HPG+1.0 percent of anti-swelling agent+0.05 percent of bactericide+0.3 percent of foaming discharge assisting agent+0.2 percent of Na) 2 CO 3 ) As energizing liquid, the construction discharge capacity is 2m 3 Low-displacement injection of low-viscosity linear glue to generate lower net pressure to control crack height;
because different small-scale sand reservoirs have different pore permeation conditions, the consumption and viscosity of the energizing liquid need to be determined by a numerical simulation method in the invention; respectively selecting the dosage of the energizing liquid to be 50m 3 、100m 3 、150m 3 、200m 3 、250m 3 、300m 3 And the viscosity of the energizing liquid is 5 mPas, 15 mPas, 20 mPas, 25 mPas, 30 mPas and the time of soaking well is 0.5d,1d,3d,5d and 7d for simulation analysis, and the optimal use amount of the energizing liquid, the viscosity of the energizing liquid and the time of soaking well are selected for construction;
And in the simulation method, a hydraulic fracturing model is used for carrying out numerical operation, so that the artificial fracture half-length, the artificial fracture width distribution, the internal fluid pressure distribution in the artificial fracture, the fluid loss of the fracturing fluid in the artificial fracture, the matrix oil phase pressure distribution and the matrix water phase saturation distribution in the fracturing construction process can be obtained. Substituting the parameters into a dead well simulation calculation as initial parameters, and then bringing the obtained related parameters into a flowback-production model to finally obtain the productivity of the oil well.
(1) The artificial cracks in the hydraulic fracturing model are single-phase flow. The reservoir fluid loss fracturing model coupled with the fracturing fluid flow is as follows:
a) Fracture width model considering fluid loss:
wherein: w (x) is crack width, m; h is the crack height, m; v is poisson's ratio, dimensionless; e is Young's modulus, MPa; sigma (sigma) n Is the horizontal minimum principal stress, MPa; p (P) f (x) Is the fluid pressure in the seam and MPa.
Wherein: q (x) is the flow rate at any position in the seam, m 3 S; mu is the viscosity of the fluid in the slit and mPa.s.
Wherein: v v Is the fluid loss speed, m/s; t is the fracturing construction time, min.
Fluid loss model:
in the process of extending the cracks, fluid in the cracks continuously leaks to the reservoir, and the fluid can be intuitively understood as that channeling exists between the cracks and the matrix reservoir, and a flow exchange model between the cracks and the matrix is directly established to simulate the fluid loss.
Q mf (x)＝T mf (x)[P f (x)-P m (x)] (4)
Wherein:
wherein: t (T) mf For the flow coefficient, m, between the fracture and the matrix 3 /(MPa·s)；Q mf Is the fluid loss between the crack and the matrix in unit time, m 3 /s；A mf The contact area of the crack and the matrix is m; k (k) mf Is the average permeability of the fracture and matrix, mD;and m is the characteristic distance from the crack to the matrix grid where the crack is located.
According to the fluid loss model, the fluid loss degree can be obtained by solving:
the crack extension boundary conditions are:
wherein: g is the bulk modulus of the reservoir rock sample and MPa; n is n L The total number of the artificial crack units under the fracturing construction time t; zeta type toy L And m is the length of the artificial crack unit.
Carrying out numerical solution on a reservoir fluid loss fracturing model with coupled fracturing fluid flow to obtain the width W (x) of any position of the artificial fracture at any time and the fluid pressure P of any position of the artificial fracture f (x) Fluid loss rate v of fracturing fluid in the seam v . From this, the width W of each crack unit at the fracturing construction time t L,t Fluid pressure P of each fracture unit FL,t Fluid loss Q of each crack unit mfL,t And pressFluid pressure in tip fracture unit at fracture construction time t
To be calculated to obtainSubstituting the stress intensity factor K into the fracture tip stress at the fracturing construction time t Ii,t 。
Wherein: k (K) Ii,t To fracture tip stress intensity factor at fracturing construction time t, MPa.m 1/2 。
b) The calculated crack tip stress intensity factor K Ii,t Fracture toughness K with reservoir rock IC ＝2MPa·m 1/2 A comparison is made. When K is Ii,t ≤K IC When the artificial crack is in the fracturing construction time t, crack expansion does not occur, and the crack length is unchanged; when K is Ii,t ＞K IC When the artificial cracks are expanded, the crack length is increased, and the total number of artificial crack units is n L ＝n L +1, the width of the new crack unit is 0m, and the fluid loss of the new crack unit is 0m 3 /s。
Substituting the fluid loss at each fracture unit under the t time obtained by calculation into a reservoir seepage model to obtain the seepage condition of the fracturing fluid after the fluid loss enters the reservoir.
c) Reservoir seepage model in fracturing process:
P mc ＝P mu -P mv (10)
wherein: phi (phi) m Is the porosity of the reservoir matrix, dimensionless; k (K) m Is the matrix permeability, mD; k (K) mrv Is the relative permeability of the aqueous phase in the matrix, dimensionless; k (K) mru Is the relative permeability of the oil phase in the matrix, dimensionless; s is S mv Is the water phase saturation in the matrix, dimensionless; v (V) b For the volume of matrix units, m 3 ；μ v mPa.s, the viscosity of the aqueous phase in the matrix; mu (mu) u mPa.s, the viscosity of the oil phase in the matrix; b (B) v Is the volume coefficient of the water phase in the matrix, and has no factor; b (B) u Is the volume coefficient of the oil phase in the matrix, and has no factor; p (P) mv 、P mu The pressure of the water phase and the oil phase in the matrix is MPa; p (P) mc Capillary pressure in the matrix, MPa;
initial conditions of reservoir seepage:
P mu (i,j,t)| t＝0 ＝P e (11)
wherein: p (P) e The pressure is the original stratum pressure of the oil reservoir and MPa; i, j are the position coordinates of the grid.
The boundary conditions of the seepage of the oil reservoir matrix are as follows:
wherein: l (L) x ,L y M for representing reservoir length and reservoir width, respectively;
the matrix oil phase pressure P at any position of the artificial fracture at any time can be obtained by carrying out numerical solution on the fracturing model mu Saturation of matrix aqueous phase S mv . Thereby, the oil phase pressure P of each matrix grid at the fracturing construction time t can be obtained mui,j,t And the water phase saturation S of each matrix grid mli,j,t . Repeating the step (1) to calculate the width W of each crack unit at the time t+1 L,t+1 Fluid pressure P of each fracture unit FL,t+1 Fluid loss Q of each crack unit mfL,t+1 . And circularly calculating until the simulation time reaches the fracturing construction time t=t a,end Step (2) is entered.
(2) And (3) performing well-logging simulation calculation: and calculating the pressure distribution of the matrix oil phase and the saturation distribution of the matrix water phase in the well stewing process. Substituting the width of each crack unit, the fluid pressure of each crack unit, the matrix grid pressure distribution and the water saturation distribution obtained in the step (1) after the fracturing is finished as initial parameters into the step (1) to carry out cyclic calculation, and setting the pumping flow to 0m 3 And/s. Calculating t=t until completion of the braising b,end Ending, at which time t=t is available b,end Fluid pressure at each fracture cell of the artificial fracture at the timeOil phase pressure per matrix lattice +.>And water phase saturation of each matrix grid +.>
(3) And (3) after the completion of the well logging, performing flowback production, and simulating parameters such as the fluid pressure of the artificial fracture unit, the pressure distribution of the matrix grid, the water phase saturation distribution of the matrix grid and the like obtained by calculation through the method as initial parameters in the flowback-production process of the oil well.
a) Oil-water two-phase seepage differential equation in oil reservoir:
P mc ＝P mu -P mv (19)
wherein: k (K) F The permeability of the artificial crack is D; v (V) F Is the volume, m of the artificial crack unit 3 ；K Frv The relative permeability of the water phase and the oil phase of the artificial fracture is dimensionless; k (K) mrv 、K mru The relative permeability of the matrix water phase and the oil phase is dimensionless; k (K) m D, the permeability of the matrix; v (V) m For the volume of the matrix network, m 3 ；q Fv 、q Fu Is the source and sink item of water phase and oil phase in the artificial crack, m 3 /s；S Fv 、S mv The water phase saturation degree of the artificial cracks and the matrix is dimensionless; phi (phi) F 、φ m The porosity of the artificial crack and the matrix is dimensionless; p (P) mv 、P mu The water phase pressure and the oil phase pressure of the matrix are MPa; q (Q) mFv 、Q mFu Water phase and oil phase channeling of main crack, m 3 /s；δ m Judging parameters of whether the matrix grid contains artificial cracks or not, wherein delta=1 when the matrix grid passes through the cracks; delta=0 when the matrix mesh passes without a crack; t is the time of flowback-production of the oil well, s; beta is a unit conversion coefficient, and beta=0.001 is taken;
b) The initial conditions include the distribution of initial pressure and initial saturation, i.e.:
wherein:the fluid pressure of each crack unit at the end of the construction of the dead well, namely the initial pressure distribution of the artificial crack in the flowback-production simulation of the oil well, is MPa; />The oil phase pressure of each matrix grid at the end of the well-logging construction, namely the initial oil phase pressure distribution of the matrix in the oil well flowback-production simulation, is MPa.
Wherein:the method is dimensionless for the water phase saturation of each matrix grid at the end of the construction of the dead well, namely the initial water phase saturation of the matrix in the flowback-production simulation of the oil well.
c) The internal boundary conditions are:
P F (x w ,y w ,t c )＝P wf (t c ) (22)
wherein: x is x w 、y w The horizontal coordinate value and the vertical coordinate value m of the grid unit where the oil well is positioned; p is p wf Is the bottom hole flow pressure and MPa.
d) The outer boundary conditions are:
taking the parameters calculated in the step (2) as initial conditions of the oil well flowback-production model, and obtaining the artificial fracture fluid pressure P at different times by numerical solution F And matrix oil phase pressure P mu The method comprises the steps of carrying out a first treatment on the surface of the Artificial crack water phase saturation S at different times Fv Saturation of matrix aqueous phase S mv . From this, a time t can be obtained c Lower matrix grid water phase saturation S mv (i,j,t c ) Oil phase pressure P of matrix lattice mu (i,j,t c ) Water phase saturation S of artificial crack unit Fv (L,t c ) Oil phase pressure P of artificial fracture unit F (L,t c )。
(4) And calculating the productivity of the oil well.
Time t c =0 and time t c The saturation of the oil phase and the water phase of the lower matrix grid and the saturation of the oil phase and the water phase of the artificial fracture unit are substituted into the following formula, and the time t from the production to the production of the well can be calculated c The cumulative production Q of the well.
Wherein: q is the time t from the production of open well 2 Cumulative oil well production at time, m 3 ；n i ,n j The total number of grids in the x-direction and the y-direction in the matrix and microcrack grids; n is n L The total number of the artificial crack units; zeta type toy L M is the length of each artificial crack unit; x is x i,j 、y i,j The length and width of the matrix and the microcrack grid at the i, j position, m; s is S mv (i, j, 0) is the initial water phase saturation of the matrix grid at i, j position at the beginning of well flowback-production; s is S Fv (L, 0) is the initial water phase saturation of the artificial crack unit of the L-th section at the beginning of flowback-production of the well; s is S mv (i,j,t c ) The water phase saturation of the matrix grid at the position i and j is the time t2 from the production of the open well; s is S Fv (L,t c ) To time t for open production 2 And (5) water phase saturation of the artificial crack unit at the L-th stage.
(5) By applying the simulation method, the daily output and accumulated output change of the oil well under different pump injection amounts, viscosities and well soaking time of the energizing liquid can be obtained through calculation.
Wherein:for different pump liquid volumes q m 、q n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the R is the cumulative yield increase coefficient when the well is opened for 200 days under different energy increasing liquid consumption, at the moment q m The energy-increasing liquid is used correspondingly;for different energized liquid viscosity mu m 、μ n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the J is the yield coefficient of the accumulated yield when different energy-increasing liquids are stuck and produced for 200 days in downhole production, and mu m The viscosity of the corresponding energizing liquid; />For different time t of well soaking m 、t n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the K yield coefficient of accumulated yield when the well is opened for 200 days under different well soaking time, at the moment t m The corresponding well soaking time is;
step 2, pumping a low-viscosity linear adhesive fracturing fluid system, and simultaneously adding low-density 40/70-mesh quartz sand in a matching way, wherein the sand ratio is 6% -8%, and the construction discharge capacity is 1m 3 3% floating agent and 4% sinking agent are added, and when the floating agent floats upwards and the sinking agent sinks to form a stable partition plate, the stress of the partition plate is increased, the flow of fracturing fluid in the longitudinal direction is blocked, the blocking strength of the partition plate is improved, and accordingly cracks are prevented from extending upwards and downwards in a transitional mode;
step 3, at 10m 3 The displacement pump is used for injecting the oil displacement agent 600-800 m per minute 3 The oil displacement effect is improved;
step 4, adopting a medium viscosity fracturing fluid system (0.30 percent HPG+1.0 percent of anti-swelling agent+0.05 percent of bactericide+0.3 percent of foaming cleanup additive+0.2 percent of Na) 2 CO 3 ) Fracturing fluid 135m 3 The viscosity is 30-60 mPa.s, low density 30/50 mesh quartz sand is added in a matched way, the sand ratio is 10-20%, and the construction discharge capacity is 3.5-4 m 3 And/min, making the seam and simultaneously further controlling the seam height.
Step 5, at 12m 3 Displacement pump for injecting oil displacement agent 850-1200 m per min 3 And the oil displacement effect is improved.
Step 6, adopting a high viscosity gel fracturing fluid system (0.42 percent HPG+1.0 percent of anti-swelling agent+0.05 percent of bactericide+0.3 percent of foaming discharge assisting agent+0.2 percent of Na) 2 CO 3 ) 70m3 of fracturing fluid with the viscosity of 150-200 mPa.s is added with 20/40 meshes of ceramsite in a matched way, the sand ratio is 25-32%, and the construction discharge capacity is 4-5 m 3 And/min, forming high-diversion cracks, increasing the volume of the produced cracks, improving the diversion capacity of the cracks, temporarily blocking part of pore channels by using a fluid loss additive during the period, reducing the fluid loss of working fluid, ensuring the extension and development of main cracks, and simultaneously pumping a large amount of liquid to the far ends of the cracks to store elastic energy so as to achieve the aim of supplementing the elastic energy to a reservoir. After the completion of the fracturing fluid pumping, in order to avoid the direct communication of the artificial fracture with the energy increasing area, the energy increasing working fluid is prevented from returning along the artificial fracture channel, the distal end diffusion of the fracture of the energy increasing working fluid is ensured, temporary plugging is carried out in the middle of the fracture, and therefore energy supplement of the deep part of the reservoir and reverse displacement after well opening are realized.
After the temporary plugging agent is pumped at this stage, a high-viscosity gel fracturing fluid system (0.42 percent HPG+1.0 percent of anti-swelling agent+0.05 percent of bactericide+0.3 percent of foaming discharge assisting agent+0.2 percent of Na) is adopted again to ensure that the temporary plugging agent enters the middle position of the crack as much as possible to form temporary plugging 2 CO 3 ) Fracturing fluid with the diameter of 50-100 m 3 The viscosity is 150-200 mPa.s, 20/40 mesh ceramsite is added in a matched way, the sand ratio is 25% -32%, the construction displacement is 4-5 m < 3 >/min, so that pumped liquid can be effectively accumulated in a matrix at the far end of a crack;
and 7, performing well-soaking energy storage after the fracturing fluid is pumped, so that the energy stored in the reservoir layer slowly diffuses into the matrix at the far well end, supplementing stratum energy to play a core role in energy increasing, and performing flowback production after well-soaking is finished.
Examples
Taking an oilfield X well as an example, the well Duan Sha has small size, poor reservoir physical properties, thicker and irregularly distributed interlayer, and has the geological characteristics of poor interlayer connectivity and thin and scattered impurities. In the early development practice of the well, a failure type development mode is adopted for a small-scale sand reservoir, but the recovery ratio is lower, and the economic return requirement cannot be met. Therefore, taking the characteristic of an X well as an example, the small-scale sand oil reservoir energy increasing and extraction process provided by the invention has a good development effect. Different fracturing fluid viscosities are adopted in the fracturing construction process, so that the high seam is controlled, and meanwhile, the full seam making and construction safety are realized. According to the invention, the dosage of the X-well energizing liquid is 50m 3 、100m 3 、150m 3 、200m 3 、250m 3 、300m 3 The viscosity of the energizing liquid is 5 mPas, 15 mPas, 20 mPas, 25 mPas, 30 mPas, and the stewing time is 0.5d,1d,3d,5d,7d, thus obtaining the influence of the fracturing construction process parameter change on the productivity of the oil well as shown in figures 1-6, the oil well production is firstly subjected to small-amplitude rise to reach 12m under the original pressure state of the stratum 3 After the maximum production of/d, the drop is made rapidly to 4m 3 /d, then gradually drop to 2m 3 /d, and maintain 2m 3 Production around/d, but overall daily oil production is lower; by using the energy increasing and extraction process at the production day 200, the oil well production firstly goes through a large-amplitude production increasing stage, and after the production reaches a peak value, the daily oil production of the oil well starts to decay, which is due to the fact that the energy supply near the oil well and the crack is deficient while the oil well productivity is rapidly increased in a short period, so that the productivity is rapidly reduced. After the energy-increasing production process is reduced to a certain extent, the daily oil production attenuation of the oil well begins to be slow, and the overall production capacity is higher than that of the formation in the original pressure state, which also shows that the energy-increasing production process plays a role in the production of the oil wellLifting effect.
As can be seen from FIG. 1, the daily output of the well will show about the same trend with different amounts of pump energized liquid, although 200m is pumped 3 And 250m 3 The daily output of the energizing liquid is slightly higher than that of pumping 150m 3 However, the differences between the daily yields of the three are small, and as can be seen from FIG. 2, the accumulated yield in the later period of the oil well shows a slow rising trend with the change of the pumping liquid amount, although the pumping is carried out for 200m 3 And 250m 3 The cumulative yield of the energizing solution is slightly higher than 150m 3 But the difference of the accumulated yields of the three materials is not large, and the trend of shrinkage is shown, and the pump is pumped for 150m 3 Since the R value of the energizing liquid is 0.25 in the reference range, 150m of the energizing liquid is preferably pumped 3 。
It can be seen from fig. 3 that the daily output of the oil well shows approximately the same trend with the difference in viscosity of the energizing liquid, the daily output is slightly higher than 20mpa·s when the viscosity of the energizing liquid is 25mpa·s and 30mpa·s, but the difference in daily output is small among them, and from fig. 4, it can be seen that the cumulative output of the oil well shows a trend of gradually rising with the change in viscosity of the energizing liquid, the cumulative output is slightly higher than 20mpa·s when the viscosity of the energizing liquid is 25mpa·s and 30mpa·s, but the difference in cumulative output among them is not large and shows a decreasing trend, and the J value when the viscosity of the energizing liquid is 20mpa·s is 0.25 in the reference range, so that the viscosity of the energizing liquid is preferably 20mpa·s.
It can be seen from fig. 5 that the trend of the post-production rate of the oil well is approximately the same with the change of the time of the dead well, although the production rates of the dead well for 5 days and 7 days are slightly higher than 3 days, the difference of the daily production rates of the three is small, and from fig. 6, the trend of the post-accumulation production rate of the oil well is increased with the change of the time of the dead well, although the difference of the accumulated production rates of the dead well for 5 days and 7 days is slightly higher than 3 days, the difference of the accumulated production rates of the three is not large, and a shrinking trend is shown, and the K value at the dead well time of 20 mpa.s is 0.20 in the reference range, so that the dead well is preferable for 3 days.
Comprehensively consider that the pumping liquid quantity of the energizing liquid is set to 150m 3 The viscosity was 20 mPas. The total liquid amount of the construction is 2300m 3 Ceramsite 45m 3 Floating agent 4.5m 3 Sinking agent 5.5m 3 . And (3) performing well soaking pressure accumulation on the well after pumping, and performing flowback production after well soaking is finished.
After development and construction are carried out, the stratum pressure is increased under the action of injection fluid, so that the elastic energy of the oil reservoir is improved. The elastic energy of the oil reservoir is improved, fluid in the pores can be effectively discharged and driven, and a good production effect is achieved for the oil well.
Therefore, the invention can effectively improve the single well yield of the small-scale sand oil reservoir, optimize the construction parameters of the energy-increasing extraction process, is favorable for the optimization and optimization of the construction scheme, and has a certain guiding significance for realizing the cost-reducing and efficiency-increasing development of the small-scale sand oil reservoir.
The present invention is not limited to the above-mentioned embodiments, but is not limited to the above-mentioned embodiments, and any person skilled in the art can make some changes or modifications to the equivalent embodiments without departing from the scope of the technical solution of the present invention, but any simple modification, equivalent changes and modifications to the above-mentioned embodiments according to the technical substance of the present invention are still within the scope of the technical solution of the present invention.
Claims (8)
1. The energy-increasing extraction process for the small-scale sand oil reservoir is characterized by comprising the following steps of:
s10, adopting a low-viscosity linear adhesive fracturing liquid system as an energizing liquid, and setting the construction discharge capacity to be 2m 3 And/min, and adopting a numerical simulation method to respectively select the dosage of the energizing liquid to be 50m 3 、100m 3 、150m 3 、200m 3 、250m 3 、300m 3 And the optimal parameters of the viscosity of the energizing liquid of 5 mPas, 15 mPas, 20 mPas, 25 mPas, 30 mPas and the stewing time of 0.5d, 1d, 3d, 5d and 7d are used for construction;
step S20, adding 40/70 mesh quartz sand, 3% floating agent and 4% quartz sand in a matched manner while pumping the low-viscosity linear adhesive fracturing fluid system % sinking agent; the sand ratio of the 40/70 mesh quartz sand is 6-8%, and the construction discharge capacity is 1m 3 /min；
Step S30, further using 10m 3 Displacement pump filling 600-800 m per minute 3 To improve the oil displacement effect;
step S40, pumping dosage is 135m 3 The medium viscosity fracturing fluid system with the viscosity of 30-60 mPa.s is added with 30/50 meshes of quartz sand, the sand ratio of the 30/50 meshes of quartz sand is 10-20%, and the construction discharge capacity is 3.5-4 m 3 /min；
Step S50, at 12m 3 Displacement pump with a/min filling of 850-1200 m 3 The oil displacement agent improves the oil displacement effect;
step S60, pumping dosage is 130-170 m 3 The high-viscosity gel fracturing fluid system with the viscosity of 150-200 mPa.s is matched with 20/40 mesh ceramsite when 50% of liquid is pumped, the filtrate reducer and temporary plugging agent are added, the sand ratio of the 20/40 mesh ceramsite is 20-25%, and the construction discharge capacity is 4-5 m 3 Adding 20/40 mesh ceramsite with the sand ratio of 25-32% and the construction discharge capacity of 4-5 m into 50% liquid after pumping per minute 3 /min；
Step S70, performing well-soaking energy storage after the fracturing fluid is pumped, and performing flowback production after well-soaking is finished;
in the numerical simulation method of the step S10, a hydraulic fracturing model is used for carrying out numerical operation to obtain artificial fracture half-length, artificial fracture width distribution, artificial fracture fluid pressure distribution in the artificial fracture, fracturing fluid filtration loss in the artificial fracture, matrix oil phase pressure distribution and matrix water phase saturation distribution in the fracturing construction process, and the parameters are substituted into relevant parameters obtained by calculation in a dead well model as initial parameters and then are brought into a flowback-production model to obtain the accumulated oil well yield; finally, determining the optimal dosage of the energizing liquid, the viscosity of the energizing liquid and the time for soaking the well according to the accumulated output of the oil well;
The numerical simulation method comprises the following specific steps:
(1) Carrying out numerical solution on a reservoir fluid loss fracturing model with coupled fracturing fluid flow to obtain the width W (x) of any position of the artificial fracture at any time and any position of the artificial fractureFluid pressure P at f (x) Fluid loss rate v of fracturing fluid in the seam v The method comprises the steps of carrying out a first treatment on the surface of the From this, the width W of each crack unit at the fracturing construction time t L,t Fluid pressure P of each fracture unit FL,t Fluid loss Q of each crack unit mfL,t And fluid pressure within the tip fracture unit at fracture construction time t
Fluid pressure P of each fracture unit FL,t Substituting the stress intensity factor K into the fracture tip stress at the fracturing construction time t Ii,t ；
Wherein: k (K) Ii,t To fracture tip stress intensity factor at fracturing construction time t, MPa.m 1/2 ；
The calculated crack tip stress intensity factor K Ii,t Fracture toughness K with reservoir rock IC ＝2MPa·m 1/2 Comparing;
when K is Ii,t ≤K IC When the artificial crack is in the fracturing construction time t, crack expansion does not occur, and the crack length is unchanged; when K is Ii,t ＞K IC When the artificial cracks are expanded, the crack length is increased, and the total number of artificial crack units is n L ＝n L +1, the width of the new crack unit is 0m, and the fluid loss of the new crack unit is 0m 3 /s；
Substituting the fluid loss at each fracture unit under the t time obtained by calculation into a reservoir seepage model to obtain seepage conditions of fracturing fluid after the fluid loss enters the reservoir; and circularly calculating until the simulation time reaches the fracturing construction time t=t a,end Entering step (2);
(2) And (3) performing well-logging simulation calculation: calculating matrix oil phase pressure distribution and matrix water phase saturation distribution in the well soaking process; after the fracturing obtained in the step (1) is finishedThe width of each crack unit, the fluid pressure of each crack unit, and the matrix grid pressure distribution and the water saturation distribution are substituted as initial parameters into step (1) for cyclic calculation while the pumping flow rate is set to 0m 3 S; calculating t=t until completion of the braising b,end Ending, at which time t=t is available b,end Fluid pressure at each fracture cell of the artificial fracture at the timeOil phase pressure per matrix lattice +.>And water phase saturation of each matrix grid +.>
(3) Performing flowback production after well completion, and simulating parameters such as fluid pressure of the artificial fracture unit, pressure distribution of matrix grids, water phase saturation distribution of matrix grids and the like calculated by the method as initial parameters in a flowback-production model; obtaining the artificial fracture fluid pressure P at different time by numerical solution F And matrix oil phase pressure P mu Artificial crack water phase saturation S at different times Fv Saturation of matrix aqueous phase S mv The method comprises the steps of carrying out a first treatment on the surface of the From this, a time t can be obtained c Lower matrix grid water phase saturation S mv (i,j,t c ) Oil phase pressure P of matrix lattice mu (i,j,t c ) Water phase saturation S of artificial crack unit Fv (L,t c ) Oil phase pressure P of artificial fracture unit F (L,t c )；
(4) Time t c =0 and time t c The saturation of the oil phase and the water phase of the lower matrix grid and the saturation of the oil phase and the water phase of the artificial fracture unit are substituted into the following formula, and the time t from the production to the production of the well can be calculated c Accumulated oil well yield Q;
wherein: q is the time t from the production of open well 2 Cumulative oil well production at time, m 3 ；n i ,n j The total number of grids in the x-direction and the y-direction in the matrix and microcrack grids; n is n L The total number of the artificial crack units; zeta type toy L M is the length of each artificial crack unit; x is x i,j 、y i,j The length and width of the matrix and the microcrack grid at the i, j position, m; s is S mv (i, j, 0) is the initial water phase saturation of the matrix grid at i, j position at the beginning of well flowback-production; s is S Fv (L, 0) is the initial water phase saturation of the artificial crack unit of the L-th section at the beginning of flowback-production of the well; s is S mv (i,j,t c ) To time t for open production 2 The water phase saturation of the matrix grid at the j position at time i; s is S Fv (L,t c ) To time t for open production 2 And (5) water phase saturation of the artificial crack unit at the L-th stage.
2. The small-scale sand reservoir energy-increasing extraction process of claim 1, wherein the low-viscosity linear gel fracturing fluid system comprises 0.10% hpg, 1.0% anti-swelling agent, 0.05% bactericide, 0.3% foaming cleanup agent, 0.2% na 2 CO 3 。
3. The process of claim 1, wherein in step S10, the cumulative yield of each of the usage amount of the enhanced fluid, the viscosity of the enhanced fluid, and the production time of the well-open production for 200 days are finally determined, and the cumulative yield increase coefficient R of the production time of the well-open production for 200 days, the cumulative yield increase coefficient J of the production time of the well-open production for 200 days, and the cumulative yield increase coefficient K of the production time of the well-open production for 200 days are calculated; selecting the lowest energy-increasing liquid dosage which is equal to or more than 0.10 and less than or equal to 0.45, selecting the lowest energy-increasing liquid viscosity which is equal to or less than 0.11 and less than or equal to 0.23, and selecting the lowest well-soaking time which is equal to or less than 0.10 and less than or equal to 0.30 and is equal to or less than or equal to 0.11 and is optimal;
wherein the consumption of the energy-increasing liquid corresponding to the accumulated yield increase coefficient R when the well is opened for 200 days under each of the different consumption of the energy-increasing liquid is the maximum consumption of the two energy-increasing liquid; the viscosity of the energizing liquid corresponding to the accumulated yield increase coefficient J when the well is opened for 200 days under the different viscosities of the energizing liquids is the maximum one of the two energizing liquid viscosities; wherein the dead time corresponding to the accumulated yield increase coefficient K when the well is opened for 200 days under each different dead time is the largest dead time in the two dead times.
4. The process for enhancing the energy and extracting the oil deposit of the small-scale sand body according to claim 3, wherein the calculation formulas of the accumulated yield increase coefficient R when the oil deposit is opened for 200 days under the condition of different energy increasing liquid consumption, the accumulated yield increase coefficient J when the oil deposit is opened for 200 days under the condition of different energy increasing liquid viscosity and the accumulated yield increase coefficient K when the oil deposit is opened for 200 days under the condition of different dead time are respectively as follows:
wherein:for different pump liquid volumes q m 、q n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the R is the accumulated yield increase coefficient when the well is opened for 200 days under different energy increasing liquid consumption; />For different energized liquid viscosity mu m 、μ n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the J is the yield increase coefficient of the accumulated yield when different energy-increasing liquids are stuck to the bottom-hole production for 200 days; />For different time t of well soaking m 、t n Cumulative production at 200 days of open-hole production under conditions, m 3 The method comprises the steps of carrying out a first treatment on the surface of the K, the yield increase coefficient of the accumulated yield when the well is opened for 200 days under different well-stewed time.
5. The small-scale sand reservoir enhanced recovery process of claim 1, wherein the reservoir fluid loss fracturing model coupled with fracturing fluid flow comprises:
fracture width model considering fluid loss:
Wherein: w (x) is crack width, m; h is the crack height, m; v is poisson's ratio, dimensionless; e is Young's modulus, MPa; sigma (sigma) n Is the horizontal minimum principal stress, MPa; p (P) f (x) Is the fluid pressure in the seam, MPa;
wherein: q (x) is the flow rate at any position in the seam, m 3 S; mu is the viscosity of fluid in the seam, mPa.s;
wherein: v v Is the fluid loss speed, m/s; t is fracturingConstruction time, min;
fluid loss model:
Q mf (x)＝T mf (x)[P f (x)-P m (x)]
wherein:
wherein T is mf For the flow coefficient, m, between the fracture and the matrix 3 /(MPa·s)；Q mf Is the fluid loss between the crack and the matrix in unit time, m 3 /s；A mf The contact area of the crack and the matrix is m; k (k) mf Is the average permeability of the fracture and matrix, mD;the characteristic distance from the crack to the matrix grid where the crack is located is m;
according to the fluid loss model, the fluid loss degree can be obtained by solving:
the crack extension boundary conditions are:
wherein: g is the bulk modulus of the reservoir rock sample and MPa; n is n L The total number of the artificial crack units under the fracturing construction time t; zeta type toy L And m is the length of the artificial crack unit.
6. The small-scale sand reservoir enhanced oil recovery process of claim 1, wherein the reservoir seepage model comprises:
P mc ＝P mu -P mv
wherein: phi (phi) m Is the porosity of the reservoir matrix, dimensionless; k (K) m Is the matrix permeability, mD; k (K) mrv Is the relative permeability of the aqueous phase in the matrix, dimensionless; k (K) mru Is the relative permeability of the oil phase in the matrix, dimensionless; s is S mv Is the water phase saturation in the matrix, dimensionless; v (V) b For the volume of matrix units, m 3 ；μ v mPa.s, the viscosity of the aqueous phase in the matrix; mu (mu) u mPa.s, the viscosity of the oil phase in the matrix; b (B) v Is the volume coefficient of the water phase in the matrix, and has no factor; b (B) u Is the volume coefficient of the oil phase in the matrix, and has no factor; p (P) mv 、P mu The pressure of the water phase and the oil phase in the matrix is MPa; p (P) mc Capillary pressure in the matrix, MPa;
initial conditions of reservoir seepage:
P mu (i,j,t)| t＝0 ＝P e
wherein: p (P) e The pressure is the original stratum pressure of the oil reservoir and MPa; i, j is the position coordinate of the grid;
the boundary conditions of the seepage of the oil reservoir matrix are as follows:
wherein: l (L) x 、L y To represent reservoir length and reservoir width, m, respectively.
7. The small-scale sand reservoir enhanced oil recovery process of claim 1, wherein the well flowback-production model comprises:
oil-water two-phase seepage differential equation in oil reservoir:
P mc ＝P mu -P mv
wherein: k (K) F The permeability of the artificial crack is D; v (V) F Is the volume, m of the artificial crack unit 3 ；K Frv The relative permeability of the water phase and the oil phase of the artificial fracture is dimensionless; k (K) mrv 、K mru The relative permeability of the matrix water phase and the oil phase is dimensionless; k (K) m D, the permeability of the matrix; v (V) m For the volume of the matrix network, m 3 ；q Fv 、q Fu Is the source and sink item of water phase and oil phase in the artificial crack, m 3 /s；S Fv 、S mv The water phase saturation degree of the artificial cracks and the matrix is dimensionless; phi (phi) F 、φ m The porosity of the artificial crack and the matrix is dimensionless; p (P) mv 、P mu The water phase pressure and the oil phase pressure of the matrix are MPa; q (Q) mFv 、Q mFu Water phase and oil phase channeling of main crack, m 3 /s；δ m Is a matrixJudging parameters of whether the grids contain artificial cracks or not, wherein delta=1 when the matrix grids pass through the cracks; delta=0 when the matrix mesh passes without a crack; t is the time of flowback-production of the oil well, s; beta is a unit conversion coefficient, and beta=0.001 is taken;
the initial conditions include the distribution of initial pressure and initial saturation, i.e.:
wherein:the fluid pressure of each crack unit at the end of the construction of the dead well, namely the initial pressure distribution of the artificial crack in the flowback-production simulation of the oil well, is MPa; />The oil phase pressure of each matrix grid at the end of the construction of the well is equal to the initial oil phase pressure distribution of the matrix in the flowback-production simulation of the oil well, namely the pressure distribution of the oil phase is equal to the pressure distribution of the oil phase;
wherein:the water phase saturation of each matrix grid at the end of the construction of the braised well, namely the initial water phase saturation of the matrix in the flowback-production simulation of the oil well, is dimensionless;
The internal boundary conditions are:
P F (x w ,y w ,t c )＝P wf (t c )
wherein: x is x w 、y w The horizontal coordinate value and the vertical coordinate value m of the grid unit where the oil well is positioned; p is p wf Is the bottom hole flow pressure, MPa;
the outer boundary conditions are:
wherein: p (P) mv 、P mu The water phase pressure and the oil phase pressure of the matrix are MPa.
8. The process of claim 1, wherein the high viscosity gel fracturing fluid system comprises 0.42% HPG, 1.0% anti-swelling agent, 0.05% bactericide, 0.3% foaming and drainage aid, 0.2% Na 2 CO 3 The method comprises the steps of carrying out a first treatment on the surface of the The medium viscosity fracturing fluid system comprises 0.30 percent of HPG, 1.0 percent of anti-swelling agent, 0.05 percent of bactericide, 0.3 percent of foaming cleanup additive and 0.2 percent of Na 2 CO 3 。
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