A method for oil production in a high permeability edge and bottom water reservoir

Abstract

The present application relates to a kind of high permeability edge bottom water reservoir's oil production method, belong to oil and gas well mining technical field.The high permeability edge bottom water reservoir's oil production method of the present application, at the initial stage of reservoir development, by the single well of water-containing region is temporarily blocked, make the communication between water-containing region and transition region control in smaller range, form a sand control and water reduction "barrier" on the longitudinal and plane of reservoir, improve the oil layer recovery of main area, reduce the formation sand discharge, reduce the formation water breakthrough time, avoid formation water (edge bottom water) gushing into wellbore wax card, sand card and environmental pollution.Secondary oil recovery, when main oil production area formation energy is exhausted, use edge water energy water drive to carry out oil production, improve the overall recovery efficiency.

Description

TECHNICAL FIELD

[0001] The application relates to an oil production method for a high-infiltration edge-bottom water reservoir and belongs to the technical field of oil and gas well exploitation. BACKGROUND

[0002] The Chunguang oil region is a monocline reservoir with a south-deep north-shallow structure. The reservoir deposition type belongs to a shore-shallow lake deposition type. On the plane, due to the influence of multi-stage delta interlaced superposition and multi-stage lake transgression and regression, multiple stratigraphic traps and lithologic trap development zones are formed, but the traps are separated from each other and isolated into reservoirs; in the vertical direction, the stratigraphic traps and lithologic traps belong to the braided river delta deposition and shore-shallow lake deposition type, and are easy to form side edge updip pinch-out oil reservoirs. The sand body distribution in the pinch-out area is relatively broken, the sand body connection relationship is complex, and the pinch-out point position of the sand body is not consistent in the upper and lower sand layers. The Chunguang oil region is a set of shore-shallow lake sand and mud facies deposition strata as a whole, and the water power gradually decreases along the lake shoreline to the lake area, the argillaceous rock gradually increases, the sandstone grain size gradually becomes fine, the thickness becomes thin and decreases.

[0003] The oil layer in the updip pinch-out area is mainly developed in the beach bar deposition, and is affected by multi-stage lake transgression and regression. The oil layer has a set of coarse-fine-coarse sedimentary cycles, and the logging curve is funnel-shaped. The lithology is mainly sandy conglomerate, medium-fine sandstone, fine sand, green-gray silty mudstone and mudstone, the minimum sand grain size is 0.12-0.2 mm, and the argillaceous content is 4.04-34.2%. The core profile can clearly see the wavy bedding. In the oil layer, the particle size of the sand grains is not uniform in the plane and the vertical direction.

[0004] On the plane, with the exhaustion of the stratum energy in the reservoir central area in the late development stage, the edge water and the bottom water of the reservoir with high energy push to the reservoir central area with low energy, a large amount of stratum water flows in, which leads to the corrosion of the surface manifold, the increase of the surface reinjection cost. At the same time, the unevenly coarse and fine stratum sand flows into the wellbore with the underground water, the stratum sand blocks the fluid flow channel of the wellbore, and reduces the service life of the well pumping unit.

[0005] The Changcai area entered the decline stage from December 2014, and the current comprehensive water cut is 75.9%, and most units have entered the medium-high water cut stage. With the increase of the water cut, the sandstone strength decreases, which causes the dispersed migration and blockage of the underground argillaceous fine sand to the oil well. At the same time, the sand screen scaling and corrosion become more and more serious in the high salinity environment of the underground water, the stable production of the oil well becomes more and more difficult, and the effective period of the sand control decreases.

[0006] ①The sand grain size is small, and the sand production is serious

[0007] The sand grain size of the Chunguang oil region is in the range of 0.12-0.2 mm, and the sand grain size medium value of the 19 development units is less than 0.165 mm, which belongs to the fine sand stratum, and the sand production is serious. The mechanical sand control has poor adaptability to the fine sand stratum.

[0008] ②High shale content, serious plugging

[0009] Among 60 development units in Chunguang Oilfield, the shale content of 21 units is more than 10%. With the increase of water content, the clay swells in water, the strength of sandstone skeleton decreases, the stability of reservoir becomes poor, the dispersed migration of shale and fine silt intensifies, which results in serious plugging of near wellbore zone and sand screen pipe, and the effective period of sand control becomes shorter.

[0010] ③In the middle and high water cut stage, the water content increases rapidly, and the effective period of sand control is short after water breakthrough

[0011] Chunguang Oilfield has entered the middle and high water cut stage due to the advance of edge water and bottom water, and the comprehensive water content reaches 81.8%. The increase of water content leads to the decrease of sandstone strength, the poor stability of reservoir, the intensified dispersed migration of shale and fine silt, the plugging of sand screen pipe, and the decrease of oil production.

[0012] ④The sand is not completely removed before sand control, and the formation sand plugging is not completely removed. During the casing milling and fishing, the sand is discharged for many times, and the sand of 11 m and 17 m is discharged twice before the sand control pipe column is lowered (the pocket of the well is 2.95 m). The sand near the perforation is not removed before sand control, which leads to the rapid decrease of liquid volume. The liquid level is at the wellhead before sand control, and the casing pressure is 2.32 MPa. After sand control, the liquid level is 106 m, and it decreases to 493 m after one month, which indicates that the formation is plugged.

[0013] ⑤The casing below the oil layer is damaged, and the formation skeleton is damaged, which intensifies the sand production. During the casing milling, the formation sand, granular cement block, and gravel are discharged many times. A cement block with a diameter of about 11 cm is discharged from the casing milling cylinder, the lead printing diameter is reduced, the short axis is 112 mm, and there are cuts at the bottom. It is judged that the casing is damaged due to the reduction of diameter. After the sand control pipe is fished, it is found that the sand control pipe nipple is corroded and perforated at three places with a diameter of about 1-1.5 cm. The casing is damaged, the sand production leads to the further damage of sand control layer, and the small pocket of sand sink and the incomplete covering of oil layer by sand control screen pipe (1.43 m difference) intensify the plugging of formation sand in wellbore.

[0014] Based on the above production problems, the plugging mechanism is analyzed, and the results are as follows:

[0015] (1) The reason for the plugging of near wellbore zone is that the plugging material of high shale loose sandstone reservoir is the clay mineral after the water-sensitive swelling of illite-montmorillonite mixed layer rock mineral, which plugs the pores of near wellbore zone and causes the decrease of permeability.

[0016] When the oil well is exploited, the underground rock and mineral are first deformed in different forms, then micro-cracks and fractures are produced, and the cracks expand to a certain stage, and the rock is damaged. The basic forms of rock damage are brittle fracture (tensile fracture, shear fracture) and plastic flow. Generally, the rock and mineral are linear elastic bodies, but because the rock is a combination of multiple minerals, and some rocks have internal cracks and loose crystal particle arrangement, the rock exhibits complex characteristics. Under the action of load, the rock deformation may appear elastic deformation, plastic deformation, and flow deformation. The deformation properties of the rock are related to the stress state and the environment. The same rock may have different deformation characteristics under different stress states.

[0017] (2) The reason for causing the plugging in the wellbore is that the metal sand filter pipe is mainly physically adsorbed and bridged. The mechanism of the physically adsorbed plugging is as follows: after the metal sand filter pipe is lowered into the well, static electricity is easily generated, the colloid system in the oil layer pore has negative charge, and is easily adsorbed with the metal sand filter pipe to cause plugging. The mechanism of the bridged plugging is as follows: when a part of small particle sand enters the wellbore and cannot pass through, the small particle sand forms a bridge in the filter hole. When the bridging phenomenon occurs, smaller particles cannot pass through the filter hole, and plugging occurs and becomes more and more serious.

[0018] (3) The reason for causing a large amount of edge and bottom water to gush into the wellbore is as follows: through indoor experiments, it is found that the formation water is injected into the pore space from the inlet end of the rock model under constant pressure, the gas first occupies the large throat and the pore controlled by the large throat, then the gas gradually fills the small throat and the pore controlled by the small throat, and with the passage of time, the experimental results gradually approach to the steady state. Because of the micro-heterogeneity of the radius of the pore and the throat, different pore and throat radii have different capillary pressures, the gas displacement has different capillary resistances, the displacement front velocity is different, and there is obvious micro-fingering phenomenon. The so-called fingering phenomenon is that the gas is injected into the model from the inlet end, when the displacement pressure is greater than the capillary resistance of the throat, the gas first passes through the throat; when the displacement pressure is less than the capillary resistance, the gas stops moving forward for a period of time, and then jumps; the displacement front moves forward along the connection path with smaller capillary resistance and first reaches the outlet to form a dominant channel. When the gas reaches the outlet end, the injected gas flows along the dominant channel. The smaller the pore and throat radius, the greater the capillary resistance, the displacement resistance in the gas flow channel is reduced, the injected gas basically moves forward along the dominant channel, the swept range no longer expands, the water displacement efficiency basically no longer increases, and the fingering phenomenon is more obvious.

[0019] Based on the above analysis results, through the investigation of the current oil and gas well sand production related technology, the results are as follows: Chinese patent document CN 106126866B discloses an oil and gas well sand control method and device based on geomechanical model. The oil and gas well sand control method provided by the invention comprises: establishing a calculation model of the bottom hole flowing pressure of the oil and gas well according to the surrounding rock stress analysis model of the oil and gas well and the rock failure criterion; calculating geomechanical parameters according to logging data; the geomechanical parameters include: horizontal maximum principal stress, horizontal minimum principal stress, tensile strength of well wall rock and reservoir pore pressure; calculating the bottom hole flowing pressure according to the geomechanical parameters and the calculation model of the bottom hole flowing pressure; determining the critical production pressure difference of the oil and gas well according to the reservoir pore pressure and the bottom hole flowing pressure; determining the relationship between the reservoir pore pressure and the critical production pressure difference during the production of the oil and gas well according to the logging data, and adjusting the actual production pressure difference of the oil and gas well according to the relationship.

[0020] Chinese patent document CN 108949132A discloses a solid sand and plugging removal treatment fluid for fine powder sand oil reservoir oil well sand control, a sand control treatment fluid system and a sand control method using the same. The solid sand and plugging removal treatment fluid contains the following components in mass content: 8-12% solid sand and plugging removal agent, 0.5-1.5% cleanup agent, 0.5-1.5% corrosion inhibitor, 1-2% iron ion stabilizer, 1-2% mutual solvent, 1-2% ammonium chloride, and the balance is water. The sand control treatment fluid system consists of pretreatment fluid, front liquid, treatment fluid and displacement fluid, and the volume ratio is 4-6:1-2:2-3:1-2 in turn. The components of the sand control treatment fluid system synergistically form a cohesive coating on the surface of fine powder sandstone and clay particles, and cement solid sand. After the implementation of this measure, the sand control and production increasing effect is remarkable.

[0021] Chinese patent document CN 106368675B discloses an oil and gas well sand production monitor and sand production monitoring data processing method. The oil and gas well sand production monitor is composed of a sand production monitoring channel, a noise monitoring channel and a data acquisition and processing system. The oil and gas well sand production monitoring data processing method synchronously collects the output signals of the sand production monitoring channel and the noise monitoring channel after filtering, and compares the two to eliminate noise and obtain pure sand production signal rsp(i), and get the sand production rate Mt and the cumulative sand production M in unit time. The invention mainly solves the problem that the existing technology cannot specially measure and distinguish the noise characteristics during sand production monitoring. Through the calculation of sand production, it realizes the guidance of timely adjustment of parameters for oil or gas production, ensures moderate sand production, achieves the purpose of improving the production capacity of oil and gas wells and prolonging the production life of oil and gas wells.

[0022] Chinese patent document CN 114776264A discloses a solid phase control method in natural gas hydrate exploitation process, comprising the following steps: obtaining reservoir data, calculating the particle size median of hydrate and silt in different reservoir solid phases, and taking the volume proportion of hydrate and the volume proportion of silt in each layer of reservoir solid phase as the weight of the particle size median, respectively, to determine the comprehensive particle size of each layer of reservoir solid phase; determining the accuracy range of the solid phase control strategy corresponding to different exploitation methods according to the comprehensive particle size; determining the control flow rate range of the wellbore according to the hydrate secondary generation temperature, pressure range and sand-carrying critical velocity range; according to the relationship between the sand production and the production capacity, the optimal solid phase control accuracy range and the optimal control flow rate range are selected through experiments.

[0023] However, the current patent technology has the following problems:

[0024] (1) The stripping and migration of the cement of the formation rock cause intensified sand production, and the formation sand flows into the wellbore with the underground water. The sand blocking capacity of the mechanical screen pipe placed in the wellbore is limited, which causes the formation sand to bury the oil layer, frequent operation to clean the formation sand, easy pollution of the formation, and increased production cost.

[0025] (2) The formation water returns to the surface manifold, causing large-area corrosion of the manifold, increasing the environmental protection risk, and increasing the cost of treating and re-injecting the formation water.

[0026] (3) During the surface well extraction process, the larger the production pressure differential is, the higher the seepage velocity is, the larger the pressure gradient in the fracture is, the larger the fluid scouring force on the proppant is, and the larger the tensile force that the rock bears is. When the force exceeds the tensile strength of the rock, the rock will be damaged by tension, causing sand production in the oil and gas well.

[0027] (4) As the exploitation proceeds, the pressure of the oil and gas reservoir gradually decreases, and the pressure applied on the rock framework becomes larger and larger. When the force exceeds the shear stress resistance of the rock, the rock will be sheared and damaged.

[0028] For high-permeability edge-bottom water reservoirs, due to the difference in the distribution of edge water pressure on the oil-water boundary line of the reservoir, the edge water in some areas advances quickly, the oil layer sees water quickly, and is accompanied by sand production, plugging of the wellbore, reduction of oil production, and increase of the burden of surface sewage treatment. In some areas, the edge water does not advance, and the energy cannot be supplemented, resulting in low overall recovery of the reservoir. Therefore, it is urgent to develop an oil extraction method suitable for high-permeability edge-bottom water reservoirs to improve the recovery of the reservoir. SUMMARY

[0029] The purpose of the present application is to provide an oil extraction method for high-permeability edge-bottom water reservoirs, which can solve the problem of low recovery rate in the current oil extraction method for high-permeability edge-bottom water reservoirs.

[0030] In order to achieve the above-mentioned purpose, the technical scheme adopted by the oil extraction method for high-permeability edge-bottom water reservoirs of the present application is:

[0031] A method for oil production in a high-permeability edge-bottom water reservoir, comprising the following steps:

[0032] (1) determining the position of edge-bottom water in the high-permeability edge-bottom water reservoir, dividing the high-permeability edge-bottom water reservoir into an oil-bearing area, a transition area and a water-bearing area, all the sand bodies drilled by single wells in the oil-bearing area being oil-bearing sand bodies, all the sand bodies drilled by single wells in the transition area including oil-bearing sand bodies and water-bearing sand bodies, and all the sand bodies drilled by single wells in the water-bearing area being water-bearing sand bodies;

[0033] (2) determining whether to temporarily block the single wells in the water-bearing area according to the connection between the water-bearing area and the transition area; then carrying out primary oil production on the single wells in the transition area and the oil-bearing area, and determining the end point of the primary oil production according to the change of production pressure; after the primary oil production is completed, secondary oil production is started;

[0034] When all the single wells in the transition area reach the end point of the primary oil production, deblocking operation is started on all the single wells in the water-bearing area;

[0035] During the secondary oil production, the ratio of the formation fluid pressures of any two single wells in the transition area is controlled to be less than 1.25, and the ratio of the formation fluid pressures of any two single wells in the oil-bearing area is controlled to be not greater than 1.5.

[0036] The method for oil production in the high-permeability edge-bottom water reservoir can control the connection between the water-bearing area and the transition area in a small range at the initial stage of reservoir development by temporarily blocking the single wells in the water-bearing area, and form a "barrier" for sand control and water reduction in the vertical and horizontal directions of the reservoir, thereby improving the oil layer recovery rate of the main area, reducing the discharge of formation sand, reducing the water breakthrough time of the formation, and avoiding the wax and sand sticking in the wellbore and environmental pollution caused by the influx of formation water (edge-bottom water) into the wellbore. During the secondary oil production, the edge water energy is used for water flooding when the formation energy of the main oil production area is exhausted, thereby improving the overall recovery rate.

[0037] In the present application, the high-permeability edge-bottom water reservoir refers to an edge-bottom water reservoir with a permeability of not less than 100 md. The determination method of the edge-bottom water reservoir is as follows: if a set of sedimentary sand bodies is water outside and oil inside in the plane according to the formation fluid properties corresponding to the well site, it is an edge water reservoir; if the same set of sedimentary sand bodies is water in the deep part and oil in the high part, it is a bottom water reservoir.

[0038] Preferably, the determination method of whether to temporarily block the single well in the water-bearing region is as follows: injecting a tracer into a single well in the water-bearing region, measuring the mass of the tracer appearing in each single well in the transition region, and calculating the ratio of the mass of the tracer appearing in all single wells in the transition region to the mass of the tracer injected into the single well in the water-bearing region; defining the ratio of the mass of the tracer appearing in all single wells in the transition region to the mass of the tracer injected into the single well in the water-bearing region as the flow-through value of the single well in the water-bearing region, and if the flow-through values of all single wells in the water-bearing region are greater than 0.3, the single well in the water-bearing region is temporarily blocked.

[0039] Preferably, the determination method of the end point of primary oil recovery is as follows: for the single well in the transition region, primary oil recovery ends when the production pressure decays to 50%-70% of the original formation pressure; for the single well in the oil-bearing region, primary oil recovery ends when the production pressure decays to 20%-40% of the original formation pressure.

[0040] Preferably, during secondary oil recovery, the ratio of the formation fluid pressures of any two single wells in the transition region is controlled to be less than 1.25 by performing squeeze packer sand control construction on the single well with a larger formation fluid pressure and / or injecting nitrogen into the single well with a smaller formation fluid pressure; and the ratio of the formation fluid pressures of any two single wells in the oil-bearing region is controlled to be no greater than 1.5 by performing squeeze packer sand control construction on the single well with a larger formation fluid pressure and / or injecting nitrogen into the single well with a smaller formation fluid pressure. BRIEF DESCRIPTION OF DRAWINGS

[0041] Figure 1 A sand body subzone plan view of a certain high-permeability edge-bottom water reservoir in an embodiment of the present application;

[0042] Figure 2 A sand body sedimentary facies map of a certain high-permeability edge-bottom water reservoir in an embodiment of the present application. DETAILED DESCRIPTION

[0043] The technical solutions of the present application are further described below in combination with specific embodiments.

[0044] EMBODIMENT

[0045] Taking a certain high-permeability edge-bottom water reservoir as an example, the oil recovery method of the high-permeability edge-bottom water reservoir in the embodiment specifically includes the following steps:

[0046] (1) determining the position of the edge-bottom water of the reservoir and dividing the reservoir into regions

[0047] S1, all single wells drilled in the plane of the mining area are interpreted by lithologic well logging, and the physical property data of each single well are obtained, including oil reservoir permeability, porosity, sand thickness, oil / water content of oil reservoir, and shale content. The physical property data of wells 2-18, 2 and 2-20, and the corresponding well sections and well section types (production layer, sealed layer, to be shot layer, etc.) are summarized in Table 1.

[0048] Table 1 Physical property data of wells 2-18, 2 and 2-20

[0049]

[0050] S2, according to the lithologic well logging interpretation results, the distribution of all single wells drilled in a certain rock layer (N1S2V2 formation) in the plane of the unit 2 is drawn, and the sand body sublayer plane map is drawn, as shown in Figure 1 , the overall area range of a certain rock layer in the plane is determined, Δ in the figure represents the reservoir pinch-out, and the black solid line formed by connecting Δ represents the reservoir pinch-out line (the range line of the reservoir); / / / (blue solid line) represents the position of the reservoir edge and bottom water advance; the red solid line represents the dividing line of the two exploitation wellblocks in a certain high-permeability edge and bottom water reservoir, one side of the dividing line is the wellblock with well number starting with 206, and the other side of the dividing line is the wellblock with well number starting with 2; the black dot represents the position of the single well (vertical well) on the sublayer plane map, and the numerical symbol near the black dot represents the well number; the line segment between the two black dots represents the position of the single well (horizontal well) on the sublayer plane map, and the numerical symbol near the line segment between the two black dots represents the well number;

[0051] S3, according to the well logging interpretation results, the distribution of all single wells drilled in a certain rock layer (N1S2V2 formation) in the vertical direction is drawn, and the thickness of the sand body drilled by each single well and the oil content of the drilled sand body are marked near the position of each single well on the sand body sublayer plane map, and the oil content is quantitatively represented by oil thickness, if it is not oil, it is water; for example, Figure 1 in the figure, the single well with well number P206-16 drilled a sand body with thickness of 4.2m, and the oil content of the drilled sand body was 0; Figure 1 in the figure, the single well with well number P206-3 drilled a sand body with thickness of 3.6m, and the oil thickness of the drilled sand body was 2.8m;

[0052] According to the marked plane map, the reservoir can be divided into three areas: oil-bearing area, transition area and water-bearing area, all the sand bodies drilled by the single wells in the oil-bearing area are oil-bearing sand bodies, all the sand bodies drilled by the single wells in the transition area include oil-bearing sand bodies and water-bearing sand bodies, and all the sand bodies drilled by the single wells in the water-bearing area are water-bearing sand bodies;

[0053] Meanwhile, based on the previously obtained sand body sedimentary facies diagram of Unit 2 ( Figure 2 As can be seen from the sand body sedimentary facies of the high-permeability edge-bottom water reservoir in this embodiment, the sand body sedimentary facies is the littoral-shallow lacustrine facies, which includes mudflat facies and beach-bar facies. As can be seen from the sand body sedimentary facies diagram, the sedimentary facies corresponding to the transition zone include mudflat facies and beach-bar facies, and the sedimentary facies corresponding to the water-bearing zone include mudflat facies.

[0054] (2) Determine the formation pressure, sand particle size, and formation water flow direction of a single well in different regions.

[0055] S1. Electronic pressure gauges are inserted into the water-bearing sand layers of single wells (well numbers P2-15, P2-19, P2-6, P2-20) in the water-bearing area, the sand layers of single wells (well numbers P2-12, P2-8, P2-2) in the transition area, and the oil-bearing sand layers of single wells in the oil-bearing area to test the formation pressure. The formation pressure reflects the energy level at the edge and bottom of the reservoir, and the measured formation pressure is converted into a formation pressure gradient, with the unit being MP / m.

[0056] Test results show that the average formation pressure of a single well in the water-bearing area is 18 MPa, the average formation pressure of a single well in the transition area is 16 MPa, and the average formation pressure of a single well in the oil-bearing area is 14 MPa.

[0057] Therefore, the formation pressure of water-bearing sand bodies in water-bearing areas is higher than that of sand bodies in oil-bearing areas. Under the action of pressure, edge water and bottom water advance from high-energy locations to low-energy locations. Reasonable measures are needed to control the rate of water flooding of oil reservoirs.

[0058] Meanwhile, the fluid pressure of the formation in a single well (the flow pressure of the liquid flowing out from the sand body in the well) is tested once a month, and a pressure recovery curve is measured once. The pressure recovery curve is a curve obtained by plotting the pressure change (Y-axis) of the formation pressure after shutting in the well to recover to the original formation pressure and the time taken (x-axis). The purpose of the pressure recovery curve is to monitor the changes in formation energy. The longer it takes for the formation pressure to recover to the original formation pressure after shutting in the well, the more lacking the formation energy is. The shorter the pressure recovery time, the more abundant the formation energy is.

[0059] S2, determine the median particle size of sand produced from single wells (well numbers P2-15, P2-19, P2-6, P2-20) in the water-bearing area, the sand layer (well numbers P2-12, P2-8, P2-2) in the transition area, and the oil-bearing sand layer in single wells in the oil-bearing area. Based on the size of the sand produced from the formation, determine the particle size of the proppant selected in the sand control design, and then determine the particle size of the coated sand (coated sand is formed by coating resin on the surface of proppant particles);

[0060] The method for determining the median particle size of the discharged sand is as follows:

[0061] The screens of different mesh sizes are stacked on the vibrating screen in the order of decreasing mesh size. After the vibrating screen is hit for 10 min, the formation sand is sieved by the hitting force. When the cumulative mass percentage of the formation sand on the screens of different mesh sizes reaches 50%, the median sand grain size can be determined. Taking Well Pai 2-12 and Well Pai 2 as examples, the test results of the median sand grain size of Well Pai 2-12 and Well Pai 2 are shown in Table 2-3. The median sand grain size d50 of Well Pai 2-12 is 0.30 mm, and the uniformity coefficient d40 / d90 is 2.62. The median sand grain size d50 of Well Pai 2 is 0.205 mm.

[0062] Table 2 Test results of the median sand grain size of Well Pai 2-12

[0063] Mesh Particle size (mm) Mass (g) Mass percentage (%) Cumulative mass percentage (%) 30 ＞0.50 17.05 18.75 18.75 40 0.42-0.50 20.51 22.56 41.32 50 0.27-0.42 15.39 16.93 58.24 60 0.25-0.27 18.36 20.20 78.44 70 0.212-0.25 5.98 6.58 85.02 80 0.18-0.212 0.38 0.42 85.44 90 0.16-0.18 5.47 6.02 91.45 100 0.15-0.16 5.55 6.10 97.56 110 0.125-0.15 0.01 0.01 97.57 120 0.12-0.125 0.16 0.18 97.75 140 0.109-0.12 0.57 0.63 98.37 180 0.08-0.109 0.88 0.97 99.34 Remaining 〈0.08 0.6 0.66 100.00

[0064] Table 3 Test results of the median sand grain size of Well Pai 2

[0065] Mesh Particle size (mm) Mass (g) Mass percentage (%) Cumulative mass percentage (%) 20 ＞0.83 0 0.00 0.00 30 0.55-0.83 2.18 0.78 0.78 40 0.42-0.55 13.69 4.92 5.70 50 0.27-0.42 17.27 6.20 11.91 60 0.25-0.27 5.2 1.87 13.77 70 0.212-0.25 96.16 34.55 48.32 80 0.18-0.212 7.59 2.73 51.05 90 0.16-0.18 84.69 30.43 81.48 100 0.15-0.16 36.67 13.17 94.65 110 0.125-0.15 0 0.00 94.65 120 0.12-0.125 0.45 0.16 94.81 140 0.109-0.12 3 1.08 95.89 180 0.08-0.109 6.89 2.48 98.37 Remaining 〈0.08 4.55 1.63 100.00

[0066] The test results show that the median sand grain size of Well Pai 2-12 is 0.27-0.42 mm, and the median sand grain size of Well Pai 2 is 0.205 mm. Therefore, when sand control is performed on Well Pai 2-12, the particle size of the proppant selected is 0.55-0.27 mm, and when sand control is performed on Well Pai 2, the particle size of the proppant selected is 0.38-0.212 mm.

[0067] S3, since the content of clay minerals in the formation affects the type and amount of anti-swelling agent, in order to determine the type and amount of anti-swelling agent, the rock mineral composition of the water-bearing sand layer of the single well (well number P2-15, P2-19, P2-6, P2-20) in the water-bearing area, the sand layer of the single well (well number P2-12, P2-8, P2-2) in the transition area and the oil-bearing sand layer of the single well in the oil-bearing area are determined, wherein the test results of the rock mineral composition in Well Pai 2-15, Well Pai 2-12 and Well Pai 2-3 are shown in Table 4.

[0068] Table 4 Test results of the rock mineral composition in Well Pai 2-15, Well Pai 2-12 and Well Pai 2-3

[0069]

[0070] According to the rock mineral composition, the type and amount of anti-swelling agent can be determined through laboratory experiments. Specifically, in the experiments, the rock mineral samples in each single well are mixed with a certain amount of anti-swelling agent, and the anti-swelling effect is tested under the corresponding single well conditions to determine the type and amount of anti-swelling agent. The amount of anti-swelling agent can also be determined according to the content of clay minerals in the rock minerals. Generally, the higher the content of clay minerals, the greater the amount of anti-swelling agent.

[0071] S4, in order to further verify whether the formation water (edge and bottom water) can flow from the water-bearing area to the transition area and the oil-bearing area, tracer is injected into the single well (well number P2-15, P2-19, P2-6, P2-20) of the water-bearing area, and it is observed whether the tracer can be monitored in the single well of the transition area (well number P2-12, P2-8, P2-2) and the single well of the oil-bearing area, so as to determine the flow direction of the formation water (whether the formation water can flow from the water-bearing area to the transition area and the oil-bearing area); in the embodiment, the tracer can be monitored in all the single wells (well number P2-12, P2-8, P2-2) of the transition area and all the single wells of the oil-bearing area, which indicates that the formation water can flow from the water-bearing area to the transition area and the oil-bearing area;

[0072] (3) primary oil recovery and secondary oil recovery

[0073] S1, before primary oil recovery, tracer is injected into each single well (well number P2-15, P2-19, P2-6, P2-20) of the water-bearing area in turn, the time when the tracer appears in each single well (well number P2-12, P2-8, P2-2) of the transition area is observed, the mass of the appearing tracer is measured, and the ratio of the mass of the appearing tracer in all the single wells of the transition area to the mass of the tracer injected into a single well of the water-bearing area is calculated; in specific implementation, the tracer can be first injected into a single well of the water-bearing area, the time when the tracer appears in all the single wells (well number P2-12, P2-8, P2-2) of the transition area is observed, the mass of the appearing tracer is measured, and the ratio of the mass of the appearing tracer in all the single wells of the transition area to the mass of the tracer injected into the single well of the water-bearing area is calculated, then the tracer is injected into another single well of the water-bearing area, and the operation is repeated;

[0074] The ratio of the mass of the tracer appearing in all single wells in the transition zone to the mass of the tracer injected into a single well in the water-bearing zone is defined as the flow-through value of the single well in the water-bearing zone. If the flow-through values of all single wells in the water-bearing zone are greater than 0.3, measures need to be taken for the single wells (wells P2-15, P2-19, P2-6, P2-20) in the water-bearing zone, i.e. measures for plugging the edge water are taken to prevent the edge water from flowing into the main zone, so as to improve the exploitation degree of the main zone. Specifically, temporary plugging slurry is pumped into the single wells in the water-bearing zone to plug the water-bearing sand layer and prevent the formation water from rapidly water-flooding the oil layer (the temporary plugging slurry can form an artificial fracture in the sand layer, the temporary plugging slurry carries temporary plugging agents, the temporary plugging agents are transported from the ground to the far-end of the artificial fracture, and the temporary plugging agents can plug the fractures in the formation to prevent the formation water from flowing from the high-pressure area to the low-pressure area. Meanwhile, the temporary plugging agents will naturally dissolve after a period of time in the formation water with a certain salinity).

[0075] The test results show that in the embodiment, the flow-through values of all single wells in the water-bearing zone are greater than 0.3, and therefore, temporary plugging measures need to be taken for all single wells (wells P2-15, P2-19, P2-6, P2-20) in the water-bearing zone. The specific method of the temporary plugging measures is as follows: first, a preflush is injected into the single well, the amount of the preflush is 20 m 3 , and the preflush is used to form an artificial fracture; then, temporary plugging slurry is injected into the single well, the amount of the temporary plugging slurry is 270 m 3 , and the temporary plugging slurry is used to plug the high-permeability sand layer; then, foam liquid composed of base fluid and nitrogen is injected into the single well, the amount of the base fluid is 50 m 3 , the amount of the nitrogen is 27600 Nm 3 (Nm 3 is the gas volume at 0℃ and 1 standard atmosphere, and the volume unit is m 3 ), and the foam liquid is used to push the temporary plugging agents into the deep formation; finally, displacement fluid is injected into the single well, the amount of the displacement fluid is 20 m 3 , and the displacement fluid is used to fill the wellbore with liquid to ensure that the temporary plugging agents are completely pumped into the formation. The preflush is composed of base fluid and foaming agent (the foaming agent is a commercially available product), and the mass fraction of the foaming agent in the preflush is 1%. The temporary plugging slurry is composed of base fluid and temporary plugging agent (the temporary plugging agent is a water-soluble fracture diverting temporary plugging agent produced by Beijing Baofengchun Petroleum Technology Co., Ltd.), and the mass fraction of the temporary plugging agent in the temporary plugging slurry is 3%. The displacement fluid is base fluid, and the base fluid is composed of the following components with the following mass fractions: guanidine gum powder 0.3%, potassium chloride 2%, and the rest is formation sewage.

[0076] In order to further verify the temporary plugging effect of the single well in the water-bearing area, the injection tracer is injected into the single well in the water-bearing area again, and the flow-through values of all single wells in the water-bearing area are calculated. The results show that the flow-through values of all single wells in the water-bearing area are less than 0.3, indicating that the temporary plugging effect of the single well in the water-bearing area is good after the temporary plugging construction.

[0077] S2, then the normal pumping of underground crude oil in the single well (well No. P2-12, P2-8, P2-2) in the transition area and the single well (P2, P2-3, P2-5, P2-23, P2-10) in the oil-bearing area is started, and the process of oil extraction is primary oil extraction;

[0078] The end point of the primary oil extraction is determined according to the following method: for the single well (well No. P2-12, P2-8, P2-2) in the transition area, when the production pressure is depleted to 50%-70% of the original formation pressure, the primary oil extraction ends and the secondary oil extraction is started; for the single well (P2, P2-3, P2-5, P2-23, P2-10) in the oil-bearing area, when the production pressure is depleted to 20%-40% of the original formation pressure, the primary oil extraction ends and the secondary oil extraction is started;

[0079] In order to supplement the energy of the oil reservoir in the transition area and the oil-bearing area by using the energy of the formation water conduction, when all single wells in the transition area reach the end point of the primary oil extraction (i.e. the production pressure of all single wells in the transition area is depleted to 50%-70% of the original formation pressure), the deblocking operation is started for all single wells (well No. P2-15, P2-19, P2-6, P2-20) in the water-bearing area. During the deblocking, the natural dissolution of the temporary plugging agent can be used, or the forced deblocking by using chemical agents can be used. In order to determine the deblocking effect, the injection tracer is injected into the single well in the water-bearing area again, and the flow-through values of all single wells in the water-bearing area are calculated. The results show that the flow-through values of all single wells in the water-bearing area are greater than 0.3, indicating that the deblocking effect is good, and the edge water energy in the water-bearing area can enter the transition area and the oil-bearing area;

[0080] S3, in the secondary oil recovery, in the development of high permeability reservoir, in order to avoid the fluid pressure in a region of the underground sand layer and the fluid pressure in the adjacent region of the underground sand layer is relatively large, thereby causing the regional recovery is lower, need to ensure that the fluid pressure in the same depth range of the underground sand layer is similar; In the secondary oil recovery, observe the formation fluid pressure of the oil-bearing sand layer in each single well (well number P2-12, P2-8, P2-2) in the transition zone, if the ratio of the formation fluid pressure of the oil-bearing sand layer of two single wells is 1.25-1.5, it indicates that the formation fluid pressure of the oil-bearing sand layer of the two single wells is relatively large, the single well with larger formation fluid pressure needs to be squeezed and packed to create artificial fractures, thereby connecting the high pressure area and the low pressure area, or pumping nitrogen into the single well with smaller formation fluid pressure to supplement the formation energy of the low pressure area, thereby achieving pressure balance in the region, so that oil recovery is carried out under the condition of uniform reservoir pressure, thereby improving the recovery efficiency; After the single well with larger formation fluid pressure in the above two single wells is squeezed and packed and / or nitrogen is pumped into the single well with smaller formation fluid pressure, the ratio of the formation fluid pressure of the oil-bearing sand layer of the two single wells is less than 1.25;

[0081] At the same time, in the secondary oil recovery, observe the formation fluid pressure of the oil-bearing sand layer in each single well (well number P2, P2-3, P2-5, P2-23, P2-10) in the oil-bearing region, if the ratio of the formation fluid pressure of the oil-bearing sand layer of two single wells is greater than 1.5, it indicates that the formation fluid pressure of the oil-bearing sand layer of the two single wells is relatively large, the single well with larger formation fluid pressure needs to be squeezed and packed to create artificial fractures, thereby connecting the high pressure area and the low pressure area, or pumping nitrogen into the single well with smaller formation fluid pressure to supplement the formation energy of the low pressure area, thereby achieving pressure balance in the region, so that oil recovery is carried out under the condition of uniform reservoir pressure, thereby improving the recovery efficiency; After the single well with larger formation fluid pressure in the above two single wells is squeezed and packed and / or nitrogen is pumped into the single well with smaller formation fluid pressure, the ratio of the formation fluid pressure of the oil-bearing sand layer of the two single wells is less than or equal to 1.5;

[0082] In the secondary oil recovery, the method for squeezing and packing the single well in the transition zone and the single well in the oil-bearing region, specifically comprising the following steps: first, injecting a mixture of liquid nitrogen and anti-swelling agent into the single well at a displacement of 1m 3 / min, the role is to remove the sand plug in the wellbore and the near wellbore zone (1-3m range) of the formation, and to pretreat the single well against swelling, then injecting a preflush into the single well, the displacement is 1m 3 / min, the injection amount is 3m 3 , then injecting a mixture composed of preflush and temporary plugging agent into the single well, the displacement is 1m 3 / min, the injection amount is 6m 3Then, the sand-carrying fluid is injected into the single well, the sand-carrying fluid carries the sand-coated sand to prevent sand formation, and the sand is added according to the step sand fluid ratio of 8%-12%-15%-20%-25%, and the discharge capacity is 2m 3 / min, when the sand fluid ratio (sand fluid ratio = volume of sand / volume of sand-carrying fluid) is 8%, the injection amount of the sand-carrying fluid is 6m 3 , when the sand fluid ratio is 12%, the injection amount of the sand-carrying fluid is 10m 3 , when the sand fluid ratio is 15%, the injection amount of the sand-carrying fluid is 10m 3 , when the sand fluid ratio is 20%, the injection amount of the sand-carrying fluid is 12m 3 , when the sand fluid ratio is 25%, the injection amount of the sand-carrying fluid is 12m 3 ; finally, the displacement fluid is injected into the single well, the discharge capacity is 2m 3 / min, and the injection amount is 3m 3 ;

[0083] In the method of squeeze packing sand control construction, the injection amount of nitrogen is calculated and determined according to the following formula:

[0084]

[0085] In the formula, V is the volume of nitrogen, a is the short axis radius, equal to 1 / 2 of the oil layer thickness, b is the long axis radius, c is the sand control perforation length, is the average porosity of the oil layer, E swp is the sweep efficiency, Q a is the additional amount;

[0086] In this embodiment, the single well with well number P2-2 in the transition area is taken as an example, the oil layer thickness of the single well is 4.3m, the long axis radius is equal to 5m, the sand control perforation length is 4.3m, the average porosity of the oil layer is 35%, the sweep efficiency is 0.25, and the additional amount is 2000Nm 3 (Nm 3 refers to the gas volume at 0℃ and 1 standard atmosphere, and the volume unit is m 3 ), the calculated volume of nitrogen is equal to 9700Nm 3 (Nm 3 refers to the gas volume at 0℃ and 1 standard atmosphere, and the volume unit is m 3 );

[0087] The preflush fluid, sand-carrying fluid and displacement fluid used in the method of squeeze packing sand control construction are composed of the following components with mass fraction: guar gum 0.35-0.5%, potassium chloride 2%, and the balance is joint station deoiled sewage, the production factory of guar gum is Beijing Baofengchun Petroleum Technology Co., Ltd.;

[0088] The temporary plugging agent used in the method of the squeeze packing sand control construction is a water-soluble fracture diverting temporary plugging agent produced by Beijing Baofengchun Petroleum Technology Co., Ltd.; the coated sand is prepared according to the method in the patent document CN114181684A “Water-blocking oil-permeable coated sand and preparation method thereof and chemical sand control system”, and specifically the water-blocking oil-permeable coated sand prepared in Example 1 in the patent document CN114181684A can be used.

[0089] It is found through a large number of experiments that, for a high-permeability edge-bottom water reservoir, when oil production is performed according to the oil production method for a high-permeability edge-bottom water reservoir in the examples, under the condition that other conditions are consistent, the total amount of oil production is obviously reduced by changing the end point of the first oil production, specifically as follows: for a single well in the transition zone, when the production pressure is depleted to A% of the original formation pressure, the first oil production is ended; for a single well in the oil-bearing zone, when the production pressure is depleted to B% of the original formation pressure, the first oil production is ended, wherein A is less than 50 or greater than 70, and B is less than 20 or greater than 40; the experimental results show that, when the end point of the first oil production is changed, the total amount of oil production is obviously reduced, and compared with the oil production method without changing the end point of the first oil production (i.e., A is 50-70 and B is 20-40), the total amount of oil production corresponding to the oil production method with the changed end point of the first oil production is 30-50% of the total amount of oil production corresponding to the oil production method without changing the end point of the first oil production;

[0090] In addition, it is found through a large number of experiments that, for a high-permeability edge-bottom water reservoir, when oil production is performed according to the oil production method for a high-permeability edge-bottom water reservoir in the examples, under the condition that other conditions are consistent, the total amount of oil production is also obviously reduced when the ratio of the formation fluid pressures of any two single wells in the transition zone is controlled to be greater than 1.25 or the ratio of the formation fluid pressures of any two single wells in the oil-bearing zone is controlled to be greater than 1.5, and compared with the oil production method in which the ratio of the formation fluid pressures of any two single wells in the transition zone is controlled to be less than 1.25 and the ratio of the formation fluid pressures of any two single wells in the oil-bearing zone is controlled to be not greater than 1.5, the total amount of oil production corresponding to the oil production method in which the ratio of the formation fluid pressures of any two single wells in the transition zone is controlled to be greater than 1.25 or the ratio of the formation fluid pressures of any two single wells in the oil-bearing zone is controlled to be greater than 1.5 is reduced by 60-80%.

Claims

1. A method for producing oil from a high permeability edge and bottom water reservoir, characterized by, The method comprises the following steps: (1) determining the position of edge and bottom water in the high-permeability edge and bottom water reservoir, dividing the high-permeability edge and bottom water reservoir into an oil-bearing area, a transition area and a water-bearing area, all the sand bodies drilled by single wells in the oil-bearing area being oil-bearing sand bodies, all the sand bodies drilled by single wells in the transition area including oil-bearing sand bodies and water-bearing sand bodies, and all the sand bodies drilled by single wells in the water-bearing area being water-bearing sand bodies; (2) determining whether to temporarily block the single wells in the water-bearing area according to the connection between the water-bearing area and the transition area; then carrying out primary oil production on the single wells in the transition area and the oil-bearing area, and determining the end point of the primary oil production according to the production pressure change; after the primary oil production is completed, secondary oil production is started; when all the single wells in the transition area reach the end point of the primary oil production, deblocking operation is started on all the single wells in the water-bearing area; the determination method of the end point of the primary oil production is as follows: for the single wells in the transition area, the primary oil production is completed when the production pressure is depleted to 50%-70% of the original formation pressure; for the single wells in the oil-bearing area, the primary oil production is completed when the production pressure is depleted to 20%-40% of the original formation pressure; in the secondary oil production, the ratio of the formation fluid pressures of any two single wells in the transition area is controlled to be less than 1.25 by carrying out extrusion packing sand control construction on the single well with a larger formation fluid pressure and / or injecting nitrogen into the single well with a smaller formation fluid pressure, and the ratio of the formation fluid pressures of any two single wells in the oil-bearing area is controlled to be not greater than 1.5 by carrying out extrusion packing sand control construction on the single well with a larger formation fluid pressure and / or injecting nitrogen into the single well with a smaller formation fluid pressure.

2. The method of producing oil from a high permeability edge and bottom water reservoir as set forth in claim 1, wherein, The determination method of whether to temporarily block the single wells in the water-bearing area is as follows: injecting a tracer into a single well in the water-bearing area, measuring the mass of the tracer appearing in each single well in the transition area, and calculating the ratio of the mass of the tracer appearing in all the single wells in the transition area to the mass of the tracer injected into the single well in the water-bearing area; the ratio of the mass of the tracer appearing in all the single wells in the transition area to the mass of the tracer injected into the single well in the water-bearing area is defined as the flow-through value of the single well in the water-bearing area, and if the flow-through values of all the single wells in the water-bearing area are all greater than 0.3, the single wells in the water-bearing area are temporarily blocked.

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