CN113266333A

CN113266333A - By extrusion of saturated CO2Method for improving permeability of oil sand reservoir by using brine

Info

Publication number: CN113266333A
Application number: CN202110724704.3A
Authority: CN
Inventors: 高彦芳; 任战利; 崔军平
Original assignee: Northwestern University
Current assignee: Northwestern University
Priority date: 2021-06-29
Filing date: 2021-06-29
Publication date: 2021-08-17
Anticipated expiration: 2041-06-29
Also published as: CN113266333B

Abstract

A method for improving the permeability of oil sand reservoirs by squeezing saturated _CO2 brine, calculating the overall permeability variation coefficient of the permeability profile, and reasonably choosing conventional water injection, _CO2 saturated brine injection at normal temperature, and _CO2 saturated brine injection at high temperature ; Calculate the permeability improvement coefficient, and draw the relationship between the initial permeability and the permeability improvement coefficient; reasonably control the wellhead pressure to gradually and slowly squeeze the saturated CO ₂ brine into the reservoir; recalculate the overall permeability variation coefficient, and the overall variation coefficient of the local formation decreases If it is less than 0.5, the transformation is successful; if the overall permeability variation coefficient of the formation is still greater than 0.5, inject _CO2 brine again at high temperature for 24 hours or extend the injection time by 2 days. Under the premise of not affecting the capacity expansion effect of traditional squeezing, the _CO2 solution selectively dissolves the shale components, while increasing the overall permeability of the reservoir, while weakening the permeability heterogeneity along the wellbore direction, thereby ensuring that along the wellbore direction. The steam chamber expands evenly in the direction of the wellbore, which increases crude oil production and improves crude oil recovery.

Description

By extrusion of saturated CO2Method for improving permeability of oil sand reservoir by using brine

Technical Field

The invention belongs to the technical field of unconventional oil and gas reservoir transformation and oil and gas development, and particularly relates to a method for improving oil and gas reservoirs by squeezing saturated CO₂A method for improving permeability of oil sand reservoirs with brine.

Background

The oil sand reservoir liquid squeezing and capacity expanding technology is applied to marine oil sand in the Alberta Canada region for the first time, and a sand grain contact structure of the oil sand reservoir liquid squeezing and capacity expanding technology forms an interlocking structure similar to a super-consolidation soil state under the action of glaciers. The land-phase heavy oil reservoir in the oilfield of the Xinjiang Fengcheng is not compacted by glaciers, the reservoir layer structure is loose, the physical interlayer develops, and the capacity expansion mechanism of the reservoir layer structure is different from that of Canada marine-phase oil sand. The key of the technology lies in whether a reservoir layer can be circularly preheated in a short time to form a uniform steam cavity, and the porosity, permeability and water saturation of the reservoir layer are improved and the preheating period is shortened by adopting a mode of squeezing water into a high-pressure stratum between a horizontal well pair before preheating.

China has abundant super heavy oil sand resources, but reservoir expansion potential is low, crude oil viscosity is high, heterogeneity is strong, oil sand mud content is high, the SAGD startup stage preheating period is long, and steam consumption is large. At present, based on the quick and uniform starting of SAGD of oil sand micro-fracturing water injection, the oil field of the northwest wind city of the Xinjiang Quadrature basin is subjected to pilot exploration and development. After water injection and capacity expansion are carried out on the well group FHW302, the communication degree of the horizontal section reaches 73% when the steam circulation is switched for 25 days, compared with the preheating time of other 13 pairs of conventional starting well groups which are developed in the same period in the same block, the preheating time is shortened by 46%, and the steam consumption is reduced by 55%. In addition, the average preheating period of the windward oil field after the well group expansion construction of the heavy 1 well zone 2 and the heavy 18 well zone 9 is respectively shortened by 80% and 71%. However, most wells in Xinjiang oil fields for micro fracturing are affected by heterogeneous reservoirs, and the actual production effect is poorer than that of the conventional preheating effect.

Due to the influence of the heterogeneity of the oil reservoir, the consolidation compactness of the reservoir stratum in the actual horizontal shaft direction is different, so that the fracture pressure at different positions in the shaft direction is different, the expansion of the loose section is obvious, the expansion of the compact section is not obvious, and the heterogeneity of the reservoir stratum is further expanded, so that dozens of wells actually implemented in the Xinjiang oil field are only effective for one third of the wells, and the actual production effect of most wells influenced by the heterogeneity is worse than the conventional preheating effect.

Laboratory or field experiments prove that CO₂After the sandstone reservoir is injected, mud is formed within 2 to 3 daysThe cement undergoes erosion in an acidic environment and the permeability is significantly increased. Thus, the use of CO is contemplated₂The acidic solution erodes the cement in the oil sand. On one hand, along the direction of a shaft, the part with high argillaceous content has low permeability, high pore pressure and CO₂The solution has high acidity and strong corrosion action; low permeability, low pore pressure, and CO at low argillaceous sites₂The acidity of the solution is low, and the corrosion effect is weak, and the selective corrosion characteristic reduces the heterogeneity of permeability along the direction of a shaft; on the other hand, perpendicular to the direction of the wellbore, CO₂The solution can chemically react with the argillaceous components within the micro-fracturing construction time to generate erosion pores, so that the permeability of a remote stratum and the overall permeability of a reservoir are increased.

Disclosure of Invention

In order to overcome the above-mentioned drawbacks of the prior art, it is an object of the present invention to provide a method for the impregnation of saturated CO by extrusion₂The method for improving the permeability of the oil sand reservoir by using brine solves the problem of intensified permeability heterogeneity along the well hole direction in the existing oil sand liquid squeezing technology, and realizes the purpose of CO passing through the oil sand reservoir on the premise of not influencing the traditional liquid squeezing capacity expansion effect₂The solution selectively erodes the argillaceous components, and the permeability heterogeneity along the well bore direction is weakened while the whole permeability of the reservoir is increased, so that the steam cavity is ensured to be uniformly expanded along the well bore direction, the crude oil yield is increased, and the crude oil recovery rate is improved.

In order to achieve the purpose, the invention adopts the technical scheme that:

by extrusion of saturated CO₂The method for improving the permeability of the oil sand reservoir by using brine is characterized by comprising the following steps:

step 1): acquiring a permeability section of a reservoir layer near the SAGD well through well logging interpretation, wherein the permeability section is a section of a well bore axis passing through an I well and a P well (the I well and the P well are respectively a steam injection well and a production well in the SAGD well); researching the range from 5m above a well I to the bottom of a reservoir, layering every 1m in the vertical direction, wherein the number of layering is N, and dividing grids every 1m in each layer in the horizontal direction;

step 2): reading permeability values of grids in each layer, and measuringCalculating the permeability coefficient of variation V of each layer_m(ii) a According to the distance between each layer and the shaft, different weight coefficients are given to different layers, the sum of the weight coefficients of permeability variation coefficients of each layer is 1, and the whole permeability variation coefficient V in the research range is calculated_t；

Permeability coefficient of variation V of mth layer_mThe formula for calculating (a) is as follows,

in the formula, m is 1-H; h is the total number of stratification in the study area; n is the number of grids of each layer; k_iPermeability values corresponding to each hierarchical mesh;

the average value of the permeability corresponding to each layered grid;

the overall permeability coefficient of variation Vt is calculated as:

V_t＝λ₁V₁+λ₂V₂+…λ_mV_m+…+λ_HV_H

in the formula, λ_mA weight coefficient which is a permeability coefficient of variation of the mth layer;

step 3): if the integral permeability variation coefficient is less than 0.5, adopting conventional water injection for expansion; if the integral permeability variation coefficient is more than 0.5 and less than 0.7, injecting saturated CO at normal temperature₂Expanding the volume of saline water; if the integral permeability variation coefficient is more than 0.7, injecting CO at high temperature₂Expanding the volume of saturated saline;

the conventional water injection and expansion in the step 3) refers to a method for injecting underground produced fluid into the stratum according to the step 7) and the step 8); injecting saturated CO at normal temperature₂The brine expansion refers to the configuration of saturated CO according to the temperature and pressure of the stratum where the reservoir is located₂Brine and injected into the formation according to step 7), step 8); CO injection at high temperature₂The saturated saline water expansion refers to the expansion according to the formation pressure and the steps5) The obtained optimal temperature T is configured with saturated CO₂Brine and injected into the formation according to step 7), step 8);

step 4): at bottom hole pressure P_{max bottom hole}Preparing saturated CO at different temperatures₂Brine solution, testing pH, analyzing temperature versus CO₂Law of influence of the pH value of saline solutions, P_{max bottom hole}The maximum bottom hole pressure of the liquid squeezing construction is a value which is 0.5MPa lower than the fracture pressure of the stratum;

step 5): drawing a temperature-pH curve, and determining that the temperature T is the optimal temperature when the temperature is increased from T to T +10 ℃ and the pH reduction value is less than 0.2;

step 6): taking a core column from an on-site underground coring bit, and taking an underground core into a standard core column indoors; testing of initial permeability K of different core legs₀Then, standard core string is placed in saturated CO₂In saline water at pressure P_{max bottom hole}Soaking for 2.5 days, simulating the actual pore pressure of the underground reservoir to fully saturate the core with fluid, testing the permeability of the soaked core column, and calculating the permeability improvement coefficient I of each core; plotting the initial permeability K₀-permeability improvement factor I relation;

step 7): calculating the formation fracture pressure at the vertical depth of the P well as P_bThe hydrostatic column pressure in the vertical depth of the P well is P_w(ii) a The maximum bottom hole pressure of the liquid squeezing construction is calculated to be 0.5MPa less than the formation fracture pressure, namely P_{max bottom hole}＝P_b-0.5; calculating the difference between the maximum bottom hole pressure and the hydrostatic column pressure, namely P_{max well head}＝P_{max bottom hole}-P_w；

Step 8): cleaning the SAGD well, simultaneously controlling the well head pressure of the P well and the I well, and keeping the well head pressure of the two wells consistent; the pressure is increased step by step in four stages until the maximum wellhead pressure is reached, and the pressure increasing amplitude of each stage is P_{max well head}The pressure increase completion time of each stage is 30-60 min; after the pressure is increased in the first three stages, the constant pressure is maintained for 12h, and after the pressure is increased in the fourth stage, the constant pressure is maintained for 24h, namely the transformation is finished;

step 9): push buttonInitial permeability K₀-a permeability improvement factor I relationship, multiplying the permeability of all meshes in the initial permeability profile within the investigation region by the corresponding factor I; recalculating the overall permeability coefficient of variation in the research area, and successfully modifying when the overall coefficient of variation of the stratum is reduced to be less than 0.5;

step 10): if the integral permeability variation coefficient of the stratum is still larger than 0.5, adopting saturated CO injection₂Well of brine, high temperature CO injection again₂Brine for 24 hours; for the adopted high-temperature injection of saturated CO₂Brine wells, the injection time was extended by 2 days.

In each stratified layer in the step 1), grids are divided every 1m from the root to the toe of the horizontal well, and when the width of the last grid is greater than or equal to 0.5m, the grid is separated into one grid; when the width of the last grid is less than 0.5m, the last grid and the last grid are combined into a grid; the area range of the grid is divided into 5m from the bottom of the reservoir to the upper part of the I well in the vertical direction and from the root of the horizontal well to the toe of the horizontal well in the horizontal direction.

The weighting coefficient influencing the permeability coefficient of variation of each layer in the step 2) depends on the distance between each layer and the well bore.

The solute composition and content of the brine in the step 3) are matched with those of the produced water of the stratum.

The solute in the saline solution in the step 3) mainly comprises Na⁺、K⁺、Ca⁺、Mg⁺Isocation and Cl^-、SO₄ ^2-、HCO₃ ^-、CO₃ ^2-And (4) plasma.

In the step 3), the saline solution can be formed by directly using the formation water after crude oil treatment, or can be formed by using the saline solution prepared by a laboratory experiment.

The step 3) is to inject saturated CO at normal temperature₂By expansion of brine or by injection of CO at high temperature₂During the expansion of saturated brine, to prevent CO₂The solution corrodes the bottom layer of the mudstone, two types of sieve pipes are designed and produced, wherein the common sieve pipe is used for the well I, and a special sieve pipe is used for the well PThe sieve tube, I well sieve tube all slot, P well sieve tube only upper portion slot, the lower part does not slot.

The step 4) is to prepare saturated CO₂The temperature range of the saline solution is that the temperature of the stratum where the reservoir is located is 80 ℃.

The step 6) of indoor coring to obtain the standard core means that the core taken by the coring bit is processed into a standard cylinder with the diameter of 25mm and the length of 50mm by a manual or mechanical method, and the standard cylinder needs to be sealed by a sealing bag and stored in a refrigerator at the temperature of 20 ℃ below zero.

The permeability testing method in the step 6) can adopt a steady state method or a transient state method, and can adopt gas measurement or liquid measurement.

The invention has the beneficial effects that:

by cyclically injecting CO into the injection-production double horizontal well₂The saturated saline water is subjected to micro-fracturing, so that the development of the near-well reservoir micro-fractures can be effectively promoted, the porosity, permeability and water saturation of the reservoir are improved, and the hydraulic and thermal communication between wells is quickly established. In addition, the argillaceous and calcite minerals are rich in CO₂The corrosion in the saline acid solution is beneficial to the initiation of new pores and microcracks, the porosity and pore connectivity are improved, and the permeability is increased. CO 2₂During brine-rock interaction, the degree of mudstone erosion increases with increasing temperature. Oil sand is mostly argillaceous cementation, the argillaceous content is high, and CO₂Water-rock reactions offer natural advantages. From the viewpoint of aging, the room test is rich in CO₂The saline water is injected for about 50 hours, so that the permeability of the argillaceous cemented sandstone reservoir can be increased by about 10-100 times. This means that if the oil sand formation is cyclically injected with saturated CO₂The salt water is 3-4 days or so, and the permeability of a near-well reservoir can be effectively improved. The traditional strong acid acidification method has strong destructiveness on the stratum and the cover layer, poor controllability and saturated CO₂Saline solutions can make up for the above deficiencies.

The construction sequence related by the invention is before various thermal oil extraction methods, and can be smoothly completed only by utilizing the existing well type, ground and underground pipe columns. The method can obviously improve the permeability of the oil sand reservoir, thereby improving the heat convection capacity of the reservoir, has low cost and quick response, and is suitable for various thermal oil extraction technologies.

Drawings

FIG. 1 is a drawing of a process for the preparation of a polymer by the extrusion of saturated CO₂Technical flow diagram of a process for brine to improve permeability of oil sands reservoirs.

FIG. 2 is a schematic of a slotted zone of a specially designed screen for a P-well in a SAGD well.

FIG. 3 is a schematic diagram of the slot positions and sizes of a parallel staggered slotted screen for a SAGD well.

FIG. 4 is a schematic view perpendicular to the direction of borehole extension of the downhole location and angle of the I-well and P-well screens in a SAGD well.

FIG. 5 is a schematic representation of the downhole location and angle of the I-well and P-well screens in a SAGD well along the borehole extension.

FIG. 6 is a schematic diagram of a specially designed I-well and P-well screens that control the direction of the produced water flow.

Fig. 7 is a schematic diagram of the hydraulic-acid etching composite expansion zone of the near well region and the hydraulic expansion zone of the far well region perpendicular to the extension direction of the well hole.

Fig. 8 is a schematic diagram of the hydraulic-acid etching composite expansion zone of the near well region and the hydraulic expansion zone of the far well region parallel to the well bore extending direction.

Detailed Description

The invention is further described with reference to the following figures and examples.

As shown in FIG. 1, a method of saturating CO by extrusion₂The method for improving the permeability of the oil sand reservoir by using brine is characterized by comprising the following steps:

step 2): reading the permeability value of the grid in each layer, and calculating the permeability variation coefficient V of each layer_m(ii) a According to each layered distance wellThe distance of the cylinder is given to different layers with different weight coefficients, the sum of the weight coefficients of the permeability variation coefficients of all layers is 1, and the integral permeability variation coefficient V in the research range is calculated_t；

the average value of the permeability corresponding to each layered grid;

the overall permeability coefficient of variation Vt is calculated as:

V_t＝λ₁V₁+λ₂V₂+…λ_mV_m+…+λ_HV_H

the conventional water injection and expansion in the step 3) refers to a method for injecting underground produced fluid into the stratum according to the step 7) and the step 8); injecting saturated CO at normal temperature₂The brine expansion refers to the configuration of saturated CO according to the temperature and pressure of the stratum where the reservoir is located₂Brine and injected into the formation according to step 7), step 8); CO injection at high temperature₂The saturated saline water expansion means that saturated CO is configured according to the formation pressure and the optimal temperature T obtained in the step 5)₂Brine and according to step 7),Step 8) a method of injecting into a formation;

step 9): according to initial permeability K₀The permeability improvement factor I, the area to be investigatedMultiplying the permeability of all grids in the initial permeability profile by a corresponding coefficient I; recalculating the overall permeability coefficient of variation in the research area, and successfully modifying when the overall coefficient of variation of the stratum is reduced to be less than 0.5;

The step 3) is to inject saturated CO at normal temperature₂By expansion of brine or by injection of CO at high temperature₂During the expansion of saturated brine, to prevent CO₂The solution corrodes the mudstone bottom layer, two types of sieve pipes are designed and produced, wherein a common sieve pipe is used for the I well, a special sieve pipe is adopted for the P well, the sieve pipe of the I well is completely slotted, and as shown in figure 2, the sieve pipe of the P well is only slotted at the upper part and is only slotted at the lower partNo slit is formed.

The embodiment is a certain SAGD well in a Xinjiang Fengcheng oil field, the vertical depth of an I well is 372m, the vertical depth of a P well is 377m, the distance between the P well and a mudstone bottom layer is 2m, the length of a horizontal section is 500m, and the fracture pressure gradient of a reservoir stratum is 0.016 MPa/m. According to the parameters, the research area can be divided into 12 layers, and each layer is divided into 500 grids. The permeability coefficient of variation of the 12 layers from top to bottom was calculated to be 0.33, 0.42, 0.65, 0.76, 0.36, 0.54, 0.78, 0.89, 0.32, 0.56, 0.87, 0.33, respectively. The permeability coefficient of variation of the 12 layers from top to bottom are respectively 1/45, 2/45, 1/15, 4/45, 1/9, 1/9, 4/45, 1/15, 4/45, 1/9, 1/9 and 4/45. The overall permeability coefficient of variation was calculated to be 0.5822.

Because the integral permeability variation coefficient is more than 0.5 and less than 0.7, the injection of saturated CO at normal temperature is adopted₂And (5) expanding the volume by using saline water.

Drilling underground rock cores of a reservoir section on site in an oil field, obtaining 5 standard rock core columns indoors, testing the initial permeability of the standard rock cores, and respectively recording the initial permeability as k₁、k₂…k₅(ii) a Respectively placing 5 standard core columns in CO₂Soaking in saturated saline for 2.5 days; setting fluid pressure P by a pressure intensifier_{max bottom hole}The permeability of the soaked core column was tested at 5.5MPa and was reported as k'₁、k'₂…k'₅(ii) a Calculating the saturated CO adopted by each core column₂The permeability improvement factor I after brine soaking, i.e. the ratio of the core soaked to the initial permeability, is recorded as I₁、I₂…I₂₀。

Initial permeability K of 5 standard cores₀0.01mD, 0.2mD, 0.8mD, 1.2mD and 2.9mD in sequence, and the permeability improvement coefficients I are 19.5, 8.6, 5.6, 3.7 and 1.3 in sequence. Fitting the relationship between the initial permeability and the permeability improvement coefficient, I ═ 3.193lnK can be obtained₀+4.426。

In this example, saturated CO₂The base fluid of the brine adopts a brine solution matched with the produced liquid of the stratum, wherein the solute composition is as follows: HCO₃ ^-Concentration 1496.15mg/L, Cl^-The concentration is 1950.53mg/L, Ca⁺The concentration is 7.33mg/L, Na⁺And K⁺The concentration is 2003.16mg/L, and the total mineralization is 4970.24 mg/L.

In this example, well I used a conventional sand screen; as shown in FIG. 2, the P-well is made of a special screen, 1/2 area is slotted and 1/2 area is non-slotted. As shown in FIG. 3, the slit part is a staggered slit with a width of 0.2-0.5 mm. The production screen is run in with the slotted zone facing up as shown in figures 4-5. As shown in FIG. 6, this particular screen allows only CO₂The saturated saline water extrudes liquid upwards, can avoid the mudstone bottom layer to be corroded.

In this example, the maximum wellhead pressure P for squeeze construction is calculated_{max outlet}1.8 MPa. The I well and the P well are squeezed in four stages: loading the wellhead pressure of the three wells from 0 to 0.45MPa in 60min at the first stage, and maintaining the pressure of 0.45MPa for 12 hours; loading the wellhead pressure of the three wells from 0.45MPa to 0.9MPa in the second stage, and maintaining the pressure of 0.9MPa for 12 hours; loading the wellhead pressure of the three wells in the third stage from 0.9MPa to 1.35MPa, and maintaining the pressure of 1.35MPa for 12 hours; the wellhead pressure of the three wells in the fourth stage is loaded from 1.35MPa to 1.8MPa, and the pressure of 1.8MPa is maintained for 24 hours.

As shown in FIGS. 7-8, in this embodiment, saturated CO is squeezed into the reservoir₂After the saline solution, a hydraulic and acid-etching composite expansion area is generated in a near well area, and a hydraulic expansion area is generated in a far well area, so that the porosity and the permeability of a reservoir stratum are effectively increased.

The permeability coefficient of variation of each layer was recalculated to have permeability coefficients of 0.23, 0.32, 0.45, 0.56, 0.24, 0.45, 0.74, 0.61, 0.22, 0.36, 0.65, and 0.25 for 12 layers from top to bottom, respectively. And according to the weight coefficient of the permeability coefficient of each layer, calculating to obtain an integral permeability coefficient of 0.4362, which indicates that the effect is better after modification and the modification is finished.

Example two:

by extrusion of saturated CO according to the invention₂The modification steps, the working principle, the beneficial effects and the like of the other embodiment of the method for improving the permeability of the oil sand reservoir by using the brine are the same as those of the first embodiment, except that the permeability variation coefficients of 12 layers are as follows: the permeability coefficient of variation of the 12 layers from top to bottom are 0.35, 0.22, 0.35, 0.46, 0.34, 0.24, 0.58, 0.49, 0.38, 0.56, 0.77 and 0.43 respectively. The permeability coefficient of variation of the 12 layers from top to bottom are respectively 1/45, 2/45, 1/15, 4/45, 1/9, 1/9, 4/45, 1/15, 4/45, 1/9, 1/9 and 4/45. The overall permeability coefficient of variation was calculated to be 0.4502.

Because the integral permeability variation coefficient is less than 0.5, the conventional water injection expansion is adopted. In this example, conventional sand screens were used for wells I and P.

Example three:

by extrusion of saturated CO according to the invention₂The modification steps, the working principle, the beneficial effects and the like of the other embodiment of the method for improving the permeability of the oil sand reservoir by using the brine are the same as those of the first embodiment, except that the permeability variation coefficients of 12 layers are as follows: the permeability coefficient of variation of the 12 layers from top to bottom are 0.75, 0.82, 0.65, 0.86, 0.64, 0.84, 0.58, 0.79, 0.68, 0.86, 0.77 and 0.69 respectively. The permeability coefficient of variation of the 12 layers from top to bottom are respectively 1/45, 2/45, 1/15, 4/45, 1/9, 1/9, 4/45, 1/15, 4/45, 1/9, 1/9 and 4/45. The overall permeability coefficient of variation was calculated to be 0.7444.

Because the coefficient of variation of the overall permeability is greater than 0.7, CO injection at high temperature is used₂And (5) expanding the volume by saturated saline water.

The reduction in pH when the temperature increased from 55 to 65 ℃ was equal to 0.21; when the temperature increased from 65 to 75 ℃, the pH decreased by 0.18, thus determining that the temperature of 65 ℃ was the optimum temperature.

The permeability coefficient of variation of each layer was recalculated to have permeability coefficients of 0.33, 0.42, 0.54, 0.56, 0.44, 0.45, 0.34, 0.61, 0.22, 0.36, 0.65, and 0.55 for 12 layers from top to bottom, respectively. And according to the weight coefficient of the permeability coefficient of each layer, calculating to obtain an integral permeability coefficient of 0.4622, which indicates that the effect is better after modification and the modification is finished.

Example four:

by extrusion of saturated CO according to the invention₂The other embodiment of the method for improving the permeability of the oil sand reservoir by using the brine has the same modification steps, working principles, beneficial effects and the like as those of the first embodiment, except for the matching relationship of all parameters in the modification steps:

the embodiment is a certain SAGD well in a Xinjiang Fengcheng oil field, the vertical depth of an I well is 372m, the vertical depth of a P well is 377m, and the fracture pressure gradient of a reservoir stratum is 0.017 MPa/m. Calculating to obtain the maximum wellhead pressure P of the squeeze construction_{max outlet}2.2 MPa. The I well and the P well are squeezed in four stages: loading the wellhead pressure of the two wells from 0 to 0.55MPa within 50min at the first stage, and maintaining the pressure of 0.55MPa for 12 hours; loading the wellhead pressure of the two wells from 0.55MPa to 1.1MPa in the second stage, and maintaining the pressure of 1.1MPa for 12 hours; loading the wellhead pressure of the two wells in the third stage from 1.1MPa to 1.65MPa, and maintaining the pressure of 1.65MPa for 12 hours; and loading the wellhead pressure of the two wells in the fourth stage from 1.65MPa to 2.2MPa, and maintaining the pressure of 2.2MPa for 24 hours, namely finishing the transformation.

Claims

1. a method for improving oil sand reservoir permeability by squeezing into saturated _CO brine, is characterized in that, comprises the following steps:

Step 1): Obtain the permeability profile of the reservoir near Well SAGD through logging interpretation. The permeability profile is the axis of the wellbore passing through Well I and Well P (Well I and Well P respectively refer to the steam injection well and the production well in Well SAGD). The section of 5m above Well I to the bottom of the reservoir is studied, and the vertical layers are layered at intervals of 1m, the number of layers is N, and the grids are divided horizontally at intervals of 1m in each layer;

Step 2): read the permeability value of the grid in each layer, calculate the permeability variation coefficient V _m of each layer; according to the distance of each layer from the wellbore, give different layers with different weight coefficients , the sum of the weight coefficients of the permeability variation coefficients of each layer is 1, and the overall permeability variation coefficient V _t within the research range is calculated;

The formula for calculating the permeability variation coefficient V _m of the mth layer is,

In the formula, m takes 1～H; H is the total number of layers in the study area; n is the number of grids in each layer; K _i is the permeability value corresponding to the grid of each layer;

is the average value of the permeability corresponding to each layered grid;

The formula for calculating the overall permeability coefficient of variation Vt is:

V _t =λ ₁ V ₁ +λ ₂ V ₂ +…λ _m V _m +…+λ _H V _H

In the formula, λ _m is the weight coefficient of the permeability variation coefficient of the mth layer;

Step 3): If the overall permeability coefficient of variation is less than 0.5, use conventional water injection for capacity expansion; if the overall permeability coefficient of variation is greater than 0.5 and less than 0.7, use saturated CO ₂ brine injection at room temperature for capacity expansion; if the overall permeability coefficient of variation is greater than 0.7, Then use high temperature injection of CO ₂ saturated brine to expand capacity;

In the described step 3), the conventional water injection expansion refers to the method of injecting the underground produced fluid into the formation according to the steps 7) and 8); and the saturated _CO2 brine injection at normal temperature refers to the expansion according to the temperature of the formation where the reservoir is located and the formation. pressure, configure saturated _CO2 brine, and inject it into the formation according to steps 7) and 8); inject _CO2 saturated brine at high temperature to expand capacity means, according to the formation pressure and the optimal temperature T obtained in step 5), configure saturated CO2 ₂ brine, and the method of injecting into the formation according to step 7) and step 8);

Step 4): Under the bottom hole pressure P _max , the saturated CO ₂ brine solution at different temperatures is configured to test its pH value, and the law of the influence of temperature on the pH value of the CO ₂ brine solution is analyzed. The _{bottom hole of P max} is squeezed liquid The maximum bottom hole pressure for construction is a value that is 0.5MPa lower than the formation fracture pressure;

Step 5): draw a temperature-pH curve, when the temperature increases from T to T+10°C, if the pH reduction value is less than 0.2, determine the temperature T as the optimal temperature;

Step 6): take the core string from the downhole core bit on site, and take the downhole core into a standard core string indoors; test the initial permeability K ₀ of different core strings, and then put the standard core string in saturated CO ₂ Soak in brine for 2.5 days under the pressure P _max , simulate the actual pore pressure of the downhole reservoir, make the saturated CO ₂ brine fully saturate the core, test the permeability of the core column after soaking, and calculate the permeability of each core Improvement coefficient I; draw the relationship between initial permeability K ₀ - permeability improvement coefficient I;

Step 7): Calculate the formation fracture pressure at the vertical depth of Well P as P _b , and the hydrostatic column pressure at the vertical depth of Well P as P _w ; calculate the maximum bottom hole pressure of the liquid squeezing operation is 0.5MPa less than the formation fracture pressure, that is, _{Pmax bottom hole} =P _b -0.5; the maximum wellhead pressure for calculating the liquid squeezing operation is the difference between the maximum bottom hole pressure and the hydrostatic column pressure, that is, _{Pmax wellhead} = _{Pmax bottom hole} - _Pw ;

Step 8): clean the SAGD well, then simultaneously control the wellhead pressure of the P well and the I well, and keep the wellhead pressure of the two wells the same; step by step in four stages until the maximum wellhead pressure is reached, and the pressure boosting range of each stage is ΔP=P _{max wellhead} /4, the completion time of each stage of boosting is 30-60min; the constant pressure is maintained for 12h after the first three stages of boosting, and the constant pressure is maintained for 24h after the fourth stage of boosting, namely the end of the stimulation;

Step 9): According to the relationship between initial permeability K ₀ - permeability improvement coefficient I, multiply the permeability of all grids in the initial permeability profile in the study area by the corresponding coefficient I; recalculate the overall permeability in the study area Coefficient of variation, when the overall variation coefficient of the formation is reduced to less than 0.5, the reconstruction is successful;

Step 10): If the overall permeability variation coefficient of the formation is still greater than 0.5, for the wells that have been injected with saturated _CO2 brine, inject _CO2 brine at high temperature again for 24 hours; for wells that have adopted high temperature injection of saturated _CO2 brine, the injection time 2 days extension.

2. A method for improving the permeability of oil sand reservoirs by squeezing saturated CO ₂ brine according to claim 1, characterized in that, in each layer in the described step 1), according to the method from the root of the horizontal well To the toe, divide the grid every 1m. When the width of the last grid is greater than or equal to 0.5m, it is divided into a grid alone; when the width of the last grid is less than 0.5m, it is merged with the previous grid is a grid; the area of the grid is divided vertically from the bottom of the reservoir to the upper 5m of Well I, and horizontally from the root of the horizontal well to the toe of the horizontal well.

3. a kind of method for improving oil sand reservoir permeability by squeezing saturated CO ₂ brine according to claim 1, is characterized in that, in described step 2), the weight coefficient that affects the coefficient of variation of permeability of each layer depends on The distance of each layer from the wellbore.

4. a kind of method for improving oil sand reservoir permeability by squeezing saturated CO according to claim ₁ , it is characterized in that, in described step 3), the solute composition and content of brine should be consistent with formation output water to match.

5. a kind of method of improving oil sand reservoir permeability by squeezing saturated CO according to claim ₁ , it is characterized in that, in described step 3), the solute in brine solution mainly comprises Na ⁺ , K ⁺ , Ca ⁺ , Mg ⁺ and other cations and Cl ^- , SO ₄ ^2- , HCO ₃ ^- , CO ₃ ^2- and other anions.

6. a kind of method for improving oil sand reservoir permeability by squeezing saturated CO according to claim 1, it is characterized in that, in described step ₃ ), the brine solution can directly use the formation water after crude oil treatment , or saline in a laboratory laboratory configuration.

7. a kind of method for improving oil sand reservoir permeability by squeezing saturated _CO brine according to claim 1, it is characterized in that, in described step 3), when injecting saturated _CO at normal temperature brine expansion or high temperature In order to prevent the _CO2 solution from corroding the mudstone bottom layer, two types of screens should be designed and produced when the _CO2 saturated brine is injected to expand the capacity. The well screen pipes are all slits, and the P well screen pipes are only slit in the upper part and not in the lower part.

8. a kind of method for improving oil sand reservoir permeability by squeezing saturated _CO salt water according to claim 1, it is characterized in that, in described step 4), configure the temperature range of saturated _CO salt water solution for storage. The temperature of the layer where the layer is located is ~80°C.

9. a kind of method of improving oil sand reservoir permeability by squeezing saturated _CO according to claim 1, it is characterized in that, in described step 6), indoor coring into standard core refers to, using Manually or mechanically, the core from the coring bit is processed into a standard cylinder with a diameter of 25mm and a length of 50mm, which needs to be sealed with a sealed bag and stored in a refrigerator at -20°C.

10. A method for improving oil sand reservoir permeability by squeezing saturated _CO2 brine according to claim 1, characterized in that, in the described step 6), the permeability testing method can adopt steady state method or instantaneous method. The state method can be gas or liquid.