Method for predicting and controlling water injection pressure rise of water injection well

Abstract

The invention provides a method for predicting and controlling water injection pressure rise of a water injection well, which comprises the following steps of: 1, collecting data of the water injection well according to different characteristics of each stage of water injection development of an oil reservoir; 2, according to the water injection well data, water injection well dynamic analysis is conducted; 3, establishing a water injection well water injection pressure rise prediction model according to oil reservoir factors by taking the water injection pressure as response and the factors influencing the water injection pressure rise as variables; and 4, according to the water injection well water injection pressure rise prediction model, a water injection well pressure rise control method is formulated. According to the water injection well water injection pressure rise prediction and control method, the prediction model is established, the water injection well pressure rise trend is predicted according to the model, a targeted control method is formulated, advanced early warning is achieved, effective water injection is guaranteed, and the purposes of more water injection and good water injection are achieved.

Description

Technical Field

[0001] The present invention relates to the technical field of oilfield water injection engineering, and particularly to a method for predicting and controlling the rising of water injection pressure in injection wells. Background Technique

[0002] The development of oilfield injection water is one of the most commonly used production methods. Most oilfield water injections adopt the method of reinjecting sewage. According to statistics, about 75% of the oilfield water injections in China are reinjecting purified oilfield water. Most of the oil reservoir developments in oilfields have entered the water injection development stage. At the initial stage of the injection well startup or transfer injection, the water injection pressure is relatively low. As the water injection time extends, the water injection pressure gradually rises. Injection wells can be classified into stable water injection wells and unstable water injection wells according to the allocated injection volume and water injection hourly rate.

[0003] For most of the unstable water injection wells in low-permeability reservoirs, the rising of water injection pressure caused by reservoir problems in the reservoir leads to unstable water injection. According to investigations, among the geological reserves of waterflooded reservoirs, the geological reserves of low-permeability reservoirs account for about 40%, and the recovery factor is about 15%. Water injection is currently the most effective way to supplement formation energy in low-permeability oilfields. Due to the deep burial of the reservoir, poor physical properties of the reservoir, and large seepage resistance in low-permeability reservoirs, the under-injection of water wells is serious, and it is difficult to form an effective drive between injection and production wells. The water injection pressure in injection wells of low-permeability reservoirs rises rapidly and to a high level, the daily injection volume is low, and the main reasons for the low utilization rate of injection wells are the large injection-production well spacing, which makes it difficult to form an effective displacement. The injection pressure of some water wells increases year by year, and finally they stop absorbing water and are shut down. To solve the problems of under-injection and non-injection of water in injection wells of low-permeability reservoirs, a variety of water injection enhancement measures have been taken, but most of the measure wells have deficiencies such as post-control, short effective period, low success rate, and large investment, and the treatment effect is not ideal.

[0004] For most of the water injection unstable wells in medium and high permeability reservoirs, the unstable water injection is caused by the increase in water injection pressure due to problems in the wellbore, surface process, and reinjected water. The wellbore of an injection well includes the well wall and casing, and the water injection string. Due to long-term high-pressure water injection, problems such as well wall collapse and fragmentation, near-wellbore zone pollution and blockage will occur in the well wall, problems such as casing damage and leakage, perforation blockage will occur in the casing, and there will be oil layer backflow, oil sludge, mud, gravel, formation sand, rust and dirt, aging polymers, etc. in the casing, all of which will cause the water injection pressure to rise; the water injection string is mainly composed of components such as a cross-over hanger and nipple, tubing, water distributor, packer, and bottom washing valve, and problems such as scaling, leakage, breakage, corrosion, blockage, and seal failure will occur in its various components. In particular, scaling corrosion and sedimentation of oil sludge and sand inside it will cause the water injection pressure to rise. The surface process and reinjected water include the injection wellhead, check valve, control valve, injection pipeline, high-pressure flow controller, and reinjected water. Due to long-term high-pressure water injection, problems such as scaling and corrosion, sedimentation of oil sludge and sand, debris blockage, valve failure, and unqualified water quality will occur in each part, all of which will cause the water injection pressure to rise. To control the increase in water injection pressure caused by the wellbore, surface process, and reinjected water, control methods such as sand control and burial prevention, trial squeezing and plugging removal, oil production and well washing, testing and reaming, workover, tubing inspection, testing and adjustment, acidizing and pickling, pipeline flushing, and process equipment replacement are usually adopted to make the injection well resume stable water injection, but there are deficiencies such as after-the-fact control, lack of prediction of measure timing, low success rate, short effective period, and high cost.

[0005] In the Chinese patent application with the patent number CN111101925A, the invention provides a method for evaluating the scaling trend of an injection well, which includes the following steps: S1, establishing a formation pressure field model by calculating the formation pressure at any point between multiple wells; S2, establishing a formation temperature field model through the heat exchange process between the fluid and the rock and the heat exchange process inside the unit body;

[0006] S3, establishing a random normal distribution of initial formation porosity and a permeability model; S4, establishing a scaling prediction model: predicting the scaling distribution range, scaling amount, scaling distribution, and change in porosity through the scaling prediction model. The invention predicts the scaling trend by establishing a scaling prediction model, enabling the scaling trend of the injection well to be predicted, thereby achieving precise scale prevention and ensuring the long-term stable production of oil and gas wells.

[0007] This prior art fully considers the scaling trend in the reservoir, but does not consider the change in the water injection pressure of the injection well over time, and does not propose the relationship between the scaling trend of the injection well and the increase in water injection pressure and control measures.

[0008] In the Chinese patent application with patent number CN201410769794.8, the present invention relates to a method for predicting water injection pressure of a dense low permeability oil reservoir, comprising the following steps: (1) using core, logging and test analysis data to determine the occurrence of cracks, the direction and size of ground stress in the test area; (2) determining the underground opening pressure of cracks in different directions; (3) predicting the critical value of water injection pressure based on the opening pressure size and opening sequence. The method can determine the opening sequence of cracks in different directions of the water injection well and the formation around the oil well during the water injection development of the dense low permeability oil reservoir, determine the critical value or upper limit of the reasonable water injection pressure, effectively control the fracture water breakthrough and violent flooding of the oil well, improve the water injection development effect of the dense low permeability oil reservoir, and can be widely used in the water injection development of dense low permeability oil fields in my country, providing a geological basis for the efficient and reasonable development of dense low permeability oil fields in my country.

[0009] This prior art fully considers the critical value or upper limit of the fracture direction of the dense low permeability oil reservoir formation and the injection pressure, but does not consider the change trend of the injection pressure of the injection wells in the medium and low permeability oil reservoirs over time, and proposes treatment measures for increasing the injection volume of the formation and wellbore of the ultra-low permeability injection well by preventing scale.

[0010] In the Chinese patent application with patent number CN202110777410.7, the field of oil recovery technology is involved, and in particular, a method for water injection under micro-fracture pressure in low / ultra-low permeability reservoirs for oil recovery. In view of the characteristics of low / ultra-low permeability reservoirs, intelligent software is used to dynamically monitor and automatically control the water injection pressure, water injection volume and temperature online in real time, so that a large number of micro-cracks are formed in the formation. Water is injected under micro-fracture pressure to fill the formation with micro-cracks. If some micro-cracks are connected in series with natural cracks to form a high-permeability channel, plugging agents are immediately injected for plugging. The final result is that the formation is full of micro-cracks, and the injected water can be easily injected without rushing along the high-permeability channel, thereby maximizing the sweep coefficient of the injected water and improving the recovery rate.

[0011] This prior art fully considers water injection under micro-cracks and micro-fracture pressure and the formation of high-permeability channels, but does not consider the change trend of water injection pressure of water injection wells in medium-permeability oil reservoirs over time, and proposes control measures such as scale and sand prevention, acidification and blockage removal, and pressure drive to increase water injection volume.

[0012] The above existing technologies are all significantly different from the present invention and fail to solve the technical problem we want to solve. For this reason, we have invented a new method for predicting and controlling the increase in injection pressure of injection wells. Summary of the invention

[0013] The purpose of the present invention is to provide a method for controlling the increase of water injection pressure by predicting the changing trend of factors affecting the increase of water injection pressure in water injection wells, so as to achieve advance control.

[0014] The object of the present invention can be achieved by the following technical measures: A method for predicting and controlling the increase in injection pressure of an injection well, which includes:

[0015] Step 1: Collect data of the injection well according to the different characteristics of each stage of the waterflood development reservoir.

[0016] Step 2: Conduct dynamic analysis of the injection well based on the injection well data.

[0017] Step 3: Establish a prediction model for the increase in injection pressure of the injection well by dividing the reservoir and factors, taking the injection pressure as the response and the factors affecting the increase in injection pressure as variables.

[0018] Step 4: Develop a control method for the increase in injection well pressure according to the prediction model for the increase in injection pressure of the injection well.

[0019] The object of the present invention can also be achieved by the following technical measures:

[0020] In Step 1, based on reservoir classification, fine reservoir description, and understanding of injection-production connectivity, collect historical reservoir static data, dynamic data, well history of operation wells and anatomical descriptions, experimental data, monitoring data, water quality indicators, injection-production big data, and injection index, which are the injection well data.

[0021] In Step 2, during overall or long-term injection dynamic analysis, sample by reservoir and use its big data to identify and determine the probability distribution of injection pressure with time and injection volume.

[0022] In Step 2, in the laboratory, conduct experiments on the filtration rate of different types of liquids in the formation, analyze on-site scale samples, and predict the scaling trend when water from different sources is mixed. According to the test results, judge the change trend of injection pressure.

[0023] In Step 3, through big data collection, collation, and cleaning, apply prediction methods such as injection indicator curves, statistics, and experimental analysis. Taking the injection pressure as the response and the factors affecting the increase in injection pressure as variables, establish a prediction model for the increase in injection pressure of the injection well by dividing the reservoir and factors.

[0024] In Step 3, the injection pressure refers to the pressure at the outlet of the flowmeter in the water distribution room. The factors affecting it include low permeability of the reservoir, injection volume, increase in injection pressure due to reservoir blockage, scaling in the reservoir wellbore, and non-compliance of the water quality along the way.

[0025] In Step 3, the injection indicator curve is the relationship curve between the injection pressure and the corresponding injection volume; by analyzing the characteristics of the curve shape and the change of the curve slope, the water absorption capacity of the oil layer and its change can be understood.

[0026] In step 3, a prediction model for the increase in the injection pressure of injection wells is established by factors, including the relationship model between the low-permeability injection pressure and the injection volume, the prediction model for the injection pressure of injection wells with reservoir plugging, and the prediction model for the scaling trend of calcium carbonate salts; the prediction model for the scaling trend of calcium carbonate salts is used to predict the scaling trends of the reservoir and the wellbore.

[0027] In step 4, according to the prediction model for the increase in the injection pressure of injection wells, the change trends of the injection pressure and various influencing factors are predicted. If it is judged that the injection process is abnormal, control methods are formulated and their implementation effects are evaluated.

[0028] In step 4, the evaluation of the implementation effect includes: evaluating the pressure-driven injection energy, the flowing fluid level of the corresponding oil well, the injection pressure, the scaling prediction position and the scaling amount, and the source and along-the-way water quality; through the evaluation, the change of the water absorption index of the injection well, the anti-scaling effect of the injection well, the water quality treatment effect, and the block development effect are verified.

[0029] In step 4, according to the relationship model between the low-permeability injection pressure and the injection volume, the pressure-driven injection technology is implemented to increase the injection pressure and injection volume of the low-permeability reservoir; micro-fractures are formed by large displacement and high pressure, and the displacement agent is quickly sent to the remaining oil enrichment area through the fractures. While fracturing and creating fractures, the displacement agent filters out along the way up and down, and the displacement agent is quickly filled into the pores, reducing the contact time and contact distance between the chemical agent and the formation, and improving the displacement efficiency; at the same time, by injecting a large amount of displacement fluid, the formation energy can be supplemented in a short time, achieving the effect of energy storage before pressing, increasing and maintaining the formation pressure, and extending the stable production period.

[0030] In step 4, the implementation of the pressure-driven injection technology includes optimizing the construction parameters and optimizing the pressure-driven pipe string method; among them, optimizing the construction parameters includes injection parameters, matrix permeability, and injection methods.

[0031] In step 4, according to the prediction model for the injection pressure of injection wells with reservoir plugging, if it is judged that the injection pressure deviates from the exponential distribution, it is considered that the reservoir is plugged or the formation pressure has risen.

[0032] In step 4, for reservoir plugging, pressure boosting and injection increase are implemented. The skid-mounted injection device is applied to implement pressure boosting and injection increase projects for low-permeability blocks; mobile pressure boosting injection is implemented, and the mobile pressure boosting injection skid is applied to implement high-pressure and small-displacement injection at the well points where the injection pressure exceeds the design pressure of the pump station.

[0033] In step 4, if the injection pressure rises due to the rise of the formation pressure, the rise of the injection pressure is controlled by adjusting the injection volume and injection pressure of the injection well.

[0034] In step 4, according to the calcium carbonate scale formation trend prediction model, physical and chemical scale prevention and removal technologies and acidizing and pickling plugging removal technologies are applied to control the water quality along the injection process. The control of the water quality along the injection process includes softening treatment of produced water, physical cleaning of pipelines, rapid water quality detection, and matching tungsten-plated and infiltrated anti-corrosion tubing.

[0035] The object of the present invention can also be achieved by the following technical measures: an injection well injection pressure rise prediction and control system, which uses the injection well injection pressure rise prediction and control method to establish an injection well injection pressure rise prediction model, and formulates a control method for the injection well pressure rise according to the model prediction.

[0036] In the injection well injection pressure rise prediction and control method of the present invention, by establishing a prediction model, predicting the injection well pressure rise trend according to the model, and formulating a targeted control method, early warning is realized, effective water injection is ensured, and the purpose of injecting more water and injecting good water is achieved. Compared with the prior art, the present invention has the following beneficial effects:

[0037] 1. The present invention collects data systematically and uses the under-injected well early warning system, applies methods such as statistics, experiments, and dynamic simulation to establish a prediction model, predicts the injection well pressure rise trend according to the model, formulates a targeted control method, realizes early warning, ensures effective water injection, and achieves the purpose of injecting more water and injecting good water.

[0038] 2. The present invention comprehensively predicts and analyzes the factors leading to the injection well pressure rise, finds the crux of the problem, and establishes a complete control method system to ensure the development of water injection benefits.

[0039] 3. The present invention provides a technical support for formulating a scale control method by establishing a scale prediction model prediction scale trend method system, which can effectively predict the scale formation trend of the injection well reservoir, wellbore, and surface process, for early prevention and precise scale prevention.

[0040] 4. The present invention applies the pressure-driven water injection technology to supplement the formation energy of low-permeability reservoirs in a short time, achieving the effect of energy storage before pressure, increasing and maintaining the formation pressure, extending the stable production period, effectively solving the difficulties in water injection development of low-permeability oil reservoirs, and having a large application space in low-permeability oil reservoirs.

[0041] 5. The present invention prolongs the stable water injection time at a lower injection pressure by implementing early treatment of injection wells, ensures the coordination and balance of injection and production, supplements the formation energy, controls the water cut rise of oil wells, and realizes the stable production of water injection development benefits. BRIEF DESCRIPTION OF THE DRAWINGS

[0042] Figure 1 For a specific embodiment of the present invention, k = 1.0×10 -3 μm 2Injection indication curve graph;

[0043] Figure 2 In a specific embodiment of the present invention, k = 2.5×10 -3 μm 2 Injection indication curve graph;

[0044] Figure 3 In a specific embodiment of the present invention, k = 4.0×10 -3 μm 2 Injection indication curve graph;

[0045] Figure 4 In a specific embodiment of the present invention, k = 5.5×10 -3 μm 2 Injection indication curve graph;

[0046] Figure 5 Schematic diagram of the pressure distribution between conventional injection wells in a specific embodiment of the present invention;

[0047] Figure 6 Schematic diagram of the pressure distribution between pressure-driven injection wells in a specific embodiment of the present invention;

[0048] Figure 7 Schematic diagram of the injection pressure at different flow rates of a low-permeability core (permeability 15 md, porosity 16%) in a specific embodiment of the present invention;

[0049] Figure 8 Schematic diagram of the permeability at different flow rates of a low-permeability core (permeability 15 md, porosity 16%) in a specific embodiment of the present invention;

[0050] Figure 9 Schematic diagram of the pore pressure increase broadband in a specific embodiment of the present invention;

[0051] Figure 10 Schematic diagram of pressure-driven simulation at different displacements (permeability 16 md) in a specific embodiment of the present invention;

[0052] Figure 11 Schematic diagram of pressure-driven simulation at different displacements (permeability 30 md) in a specific embodiment of the present invention;

[0053] Figure 12 Schematic diagram of pressure-driven simulation under different injection methods in a specific embodiment of the present invention;

[0054] Figure 13 Schematic diagram of the pressure-driven injection pipe structure in a specific embodiment of the present invention;

[0055] Figure 14 Relationship curve graph between ionic strength μ and correction coefficient K at the same temperature in a specific embodiment of the present invention;

[0056] Figure 15 It is a block diagram for predicting and calculating the maximum scale deposition amount and scale deposition position in a specific embodiment of the present invention;

[0057] Figure 16 It is a graph showing the change of SI value with temperature for four water wells in a specific embodiment of the present invention;

[0058] Figure 17 It is a graph showing the change of the maximum scale deposition amount of Well Z64 - 12 with temperature and well depth in a specific embodiment of the present invention;

[0059] Figure 18 It is a graph showing the change of the maximum scale deposition amount of Well Z112 - 2 with temperature and well depth in a specific embodiment of the present invention;

[0060] Figure 19 It is a graph showing the change of the maximum scale deposition amount of Well Z136 - 5 with temperature and well depth in a specific embodiment of the present invention;

[0061] Figure 20 It is a graph showing the change of the maximum scale deposition amount of Well Z148 - X1 with temperature and well depth in a specific embodiment of the present invention;

[0062] Figure 21 It is a flowchart of a specific embodiment of the method for predicting and controlling the increase of injection pressure of an injection well in the present invention. Specific Embodiments

[0063] It should be noted that the following detailed description is exemplary and is intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those of ordinary skill in the technical field to which the present invention belongs.

[0064] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular forms are also intended to include the plural forms. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, and / or combinations thereof.

[0065] As Figure 21 shown, Figure 21 It is a flowchart of the method for predicting and controlling the increase of injection pressure of an injection well in the present invention. The method for predicting and controlling the increase of injection pressure of an injection well includes:

[0066] Based on the different characteristics of each stage of waterflooding development reservoir, on the basis of reservoir classification, fine reservoir description and understanding of injection-production connection, according to historical reservoir static data, dynamic data, operation well history and anatomical description, experimental data, monitoring data, water quality indicators, injection-production big data, injection index, etc., dynamic analysis of injection wells is carried out. And through the collection, collation and cleaning of big data, using prediction methods such as injection indicator curve, statistics, experimental analysis, etc., with injection pressure as the response and the factors affecting the rise of injection pressure as variables, a prediction model for the rise of injection well injection pressure is established by reservoir and by factor. According to the model prediction, a control method for the rise of injection well pressure is formulated.

[0067] Taking the injection pressure as the response and the influencing factors as variables, its characteristics are that the injection pressure refers to the pressure at the outlet of the flowmeter in the water distribution station, and the influencing factors include low permeability of the reservoir, injection volume, rise of formation pressure, scaling in the reservoir wellbore, unsuitability of injected water quality, etc.

[0068] Using prediction methods such as injection indicator curve, statistics, experimental analysis, etc., its characteristics are that the injection indicator curve is the relationship curve between injection pressure and corresponding injection volume. By analyzing the characteristics of the curve shape and the change of the curve slope, the water absorption capacity of the oil layer and its change can be understood. When conducting overall or long-term injection dynamic analysis, samples are taken by reservoir, and using its big data, the probability distribution of injection pressure, time and injection volume is identified and determined. In the laboratory, experiments on the filtration rate of different types of liquids in the formation, on-site scale sample analysis, prediction of scaling trend when water from different sources is mixed, etc. are carried out, and according to the test results, the change trend of injection pressure is judged.

[0069] When establishing a prediction model for the rise of injection well injection pressure, its characteristics are that on the premise of using injection indicator curve, probability distribution and injection pressure prediction, a prediction model for the rise of injection well injection pressure is established by factor. According to the change trend of injection pressure and each influencing factor predicted by the model, if it is judged that there is an abnormality in the injection process, a control method is formulated and its implementation effect is evaluated.

[0070] The prediction model for the rise of injection well injection pressure established by factor includes the relationship model between low-permeability injection pressure and injection volume, the prediction model for injection pressure of injection wells with reservoir plugging, and the prediction model for calcium carbonate scaling trend. The calcium carbonate scaling trend model is used to predict the scaling trend of the reservoir and wellbore.

[0071] The described control method is characterized in that, according to the model, it is judged whether the injection pressure rises abnormally, otherwise corresponding control methods are adopted for the influencing factors. This method includes implementing pressure drive technology, adjusting the injection volume and injection pressure, applying physical and chemical scale prevention and removal technology, applying acidizing and pickling plugging removal technology, controlling the water quality along the injection process, etc. The implementation of the pressure drive technology includes activities such as boosting injection pressure and gently injecting with a skid-mounted pressure drive pump. Controlling the water quality along the injection process includes softening treatment of produced water, physically cleaning the pipeline, quickly detecting the water quality, and supporting the use of tungsten-plated and infiltrated anti-corrosion oil pipes, etc.

[0072] The evaluation of its implementation effect is characterized in that it evaluates items such as pressure drive injection energy, the dynamic liquid level of the corresponding oil well, injection pressure, scale formation prediction location and scale formation amount, and the source and water quality along the process. Through evaluation, the changes in the water absorption index of the injection well, the scale prevention effect of the injection well, the water quality treatment effect, the block development effect, etc. are verified.

[0073] The following are several specific embodiments of applying the present invention.

[0074] Embodiment 1: The establishment and control method of the relationship model between injection pressure and injection volume in a low-permeability reservoir are as follows:

[0075] When the flowing pressure of the production well is constant, in order to maintain the stability of the formation pressure, the injection well must inject water under a certain pressure. When the water absorption capacity of the injection well decreases, in order to maintain the injection-production balance, the pressure should also be increased for injection. Under normal circumstances, the injection pressure that satisfies the injection-production balance and pressure balance does not exceed the fracture pressure of the oil layer. If the increase in injection pressure is restricted by the fracture pressure of the oil layer, it can be solved by adjusting the injection-production system to increase the injection-production well number ratio. The fracture pressure of the oil layer is another important factor affecting the injection pressure. In order to enable the injection well to inject water under normal conditions, it is usually not allowed for the injection pressure to exceed the fracture pressure of the oil layer. If the injection pressure exceeds the fracture pressure of the oil layer, it is very easy to form long fractures that penetrate the injection and production well bottoms, causing the water cut in the oilfield to rise rapidly or violent water flooding to occur.

[0076] By gradually increasing the injection pressure, the change of the injection indicator curve is studied. The injection indicator curve is the relationship curve between the injection pressure and the corresponding injection volume. By analyzing the characteristics of the curve shape and the change of the curve slope, the water absorption capacity of the oil layer and its change can be understood. As shown in Table 1, Table 2, Table 3, Table 4, Figure 1 , Figure 2 , Figure 3 , Figure 4 .

[0077] Table 1 k = 1×10 -3 μm 2 Table of the relationship between the injection bottom hole pressure and the injection volume

[0078] Injection pressure (MPa) 30 40 45 50 60 70 <![CDATA[Injection volume (m 3 / d)]]> 2.21 3.60 4.40 5.35 7.06 9.24

[0079] Table 2 k=2.5×10 -3 μm 2 Relationship between injection well bottom pressure and injection volume

[0080] Injection pressure (MPa) 30 40 45 50 60 70 <![CDATA[Injection volume (m 3 / d)]]> 2.7 5.6 7.20 8.87 12.0 15.34

[0081] Table 3 k=4.0×10 -3 μm 2 Relationship between injection well bottom pressure and injection volume

[0082] Injection pressure (MPa) 30 40 45 50 60 70 <![CDATA[Injection volume (m 3 / d)]]> 5.14 7.68 9.50 11.26 15.0 20.4

[0083] Table 4 k=5.5×10 -3 μm 2 Relationship between injection well bottom pressure and injection volume

[0084] Injection pressure (MPa) 30 40 45 50 60 70 <![CDATA[Injection volume (m 3 / d)]]> 6.4 10.0 11.6 13.4 17.6 22

[0085] The above chart calculates the ideal injection volume corresponding to different injection pressures under different formation permeabilities. The effective permeability of the XX block studied is about 1.5×10 -3 μm 2 The injection pressure can be determined according to the above table and the injection requirements. 3 / d, the injection pressure is required to reach 20MPa. Assuming the well depth is 3500m, considering the effects of friction and hole loss, assuming that the string friction and hole loss are about (1~2)MPa, the wellhead pressure must reach above 18MPa.

[0086] According to the relationship model between water injection pressure and injection volume, pressure-driven water injection technology is implemented to increase the water injection pressure and injection volume of low permeability oil reservoirs. Micro-cracks are formed by large displacement and high pressure, and the oil displacement agent is quickly sent to the remaining oil-rich area through the cracks. The oil displacement agent is quickly filled into the pores while fracturing and creating cracks, reducing the contact time and contact distance between the chemical agent and the formation, thereby improving the oil displacement efficiency. At the same time, by injecting a large amount of oil displacement fluid, the formation energy can be replenished in a short time, achieving the effect of pre-pressure energy storage, increasing and maintaining the formation pressure, and extending the stable production period. The mechanism is as follows: first, pressure drive increases the pore throat radius; second, pressure drive increases the filtration distance; third, large pressure difference asymmetric coupling water injection redistributes the remaining oil, thereby improving the oil washing efficiency. Figure 5 , Figure 6 shown.

[0087] Before the rock breaks, high-pressure water injection can improve the rock's seepage capacity. Under high-speed seepage conditions, the seepage velocity and driving pressure of low-permeability cores are linearly related. As the flow rate increases, the permeability increases first and then tends to stabilize. High-pressure water injection has a certain effect on improving the rock's seepage capacity. Figure 7 , Figure 8as shown

[0088] The injected water has a low viscosity and a large filtration loss, which can increase the pore pressure of the rock. During the pressure-driven process, under the action of the net pressure, the liquid seeps into the matrix. Different types of liquids show different seepage velocities in the formation. The lower the viscosity of the liquid, the faster the filtration rate. As shown in Table 5

[0089] Table 5 Test results of seepage velocities of different types of liquids in the formation

[0090]

[0091] After fracturing the rock by large-volume water injection, the filtration continuously increases the pore pressure, and the fracture morphology is complex. During the process of fracturing the rock by large-volume water injection, the large filtration of water significantly increases the matrix pore pressure. As the pore pressure increases, the difference between the principal stresses decreases, which is conducive to the formation of a complex fracture network. The size of the rock sample is selected as 300mm×300mm×300mm, and the three-dimensional stresses are 15MPa, 10MPa, and 5MPa respectively. As Figure 9 as shown

[0092] The on-site implementation of the pressure-driven technology includes optimizing construction parameters and optimizing the pressure-driven pipe string method

[0093] 1. Optimize construction parameters

[0094] (1) Injection parameters

[0095] Taking the injection volume of 30000m 3 per single well as an example, the fracture morphologies under three injection rates and stepwise decreasing injection rates are respectively simulated to study the fracture propagation law, and the injection time and wellhead construction pressure are calculated. As Figure 10 (a), (b), (c) shown

[0096] (2) Matrix permeability

[0097] Based on geological modeling, the permeability is adjusted to 30md and the simulation is carried out again. Taking the injection volume of 3000m 3 as an example, the fracture morphologies at the injection rates of 0.5m 3 / min, 1.0m 3 / min, and 2.0m 3 / min are respectively simulated to study the fracture propagation law. As Figure 11 (a), (b), (c) shown

[0098] (3) Injection method

[0099] Taking 10000m 3Taking the injection volume as an example, the fracture patterns during injection with increasing and decreasing displacement rates were respectively simulated. The simulation results show that stepwise decreasing displacement rate injection is more conducive to forming short and wide fractures, with a small fracture volume, which is beneficial for balanced displacement. As shown in Figure 12 (a), (b), (c), and Table 6.

[0100] Table 6 Numerical simulation results of pressure displacement under different injection methods

[0101]

[0102]

[0103] 2. Optimize the pressure displacement string

[0104] Optimize the pressure displacement injection process string to achieve longitudinal balanced displacement. Taking an injection volume of 3000 m3 as an example, the bottom hole pressure changes were respectively simulated when the injection displacement rate was (0.5 - 2.0) m 3 / min, and it was found that the more obvious the rock fracture was with the increase of displacement rate. As shown in Table 7, Figure 13 .

[0105] Design of the pressure displacement string:

[0106] P 井口 = P 井底 - P 液柱 + P 摩阻

[0107] P 液柱 = ρ·g·H

[0108] P 摩阻 = 1.385×10 6 ×D -4.8 ·Q 1.8 ·H

[0109] where: D is the inner diameter of the fracturing string, in mm

[0110] H is the length of the fracturing string, in m

[0111] Q is the displacement rate, in m 3 / min

[0112] Table 7 Friction resistance table of the string under different displacement rates

[0113]

[0114] The structure of the pressure-driven water injection string: safety joint + reverse circulation valve + hydraulic anchor + Y221 packer + bell mouth. After the string is in place, lift up, rotate forward, and press down the string to seal the Y221 packer. After the seal is qualified, water injection can be started. After the water injection is completed, if the well needs to be repaired later, if there is overflow in the oil pipe, the well can be washed and killed by reverse circulation. If there is an abnormal situation when lifting the string, the ball can be dropped from the safety joint.

[0115] Advantages of optimized pressure-driven water injection string:

[0116] ① The upper part of the packer can be properly pressurized to reduce the actual pressure of the packer;

[0117] ②The diameter of the pipe column is large and there is no throttling;

[0118] ③ The sealing force when setting the packer can compensate for the shrinkage of the pipe string during water injection, avoiding the creep of the pipe string causing the packer sealing failure.

[0119] ④ Pressure difference 70MPa, temperature resistance 150℃;

[0120] ⑤The sealing operation is simple and the unsealing is easy;

[0121] ⑥High reliability and low cost.

[0122] 3. Pressure drive effect: From 2020 to 2023, the oil production plant mainly implemented pressure drive well groups in ultra-low permeability reservoirs, covering geological reserves of 14.6 million tons, cumulative water injection of 1.05 million cubic meters, peak daily oil increase of 125 tons, and cumulative oil increase of 55,600 tons. The pressure drive water injection energy supplement increased the well opening rate and dynamic liquid level of the pressure drive well group by 13.5% and 114m respectively.

[0123] At the same time, for unstable water injection wells and unstable water injection wells with ineffective or poor acidization due to poor reservoir properties, high starting pressure and other reasons in low permeability reservoirs, the relationship between water injection pressure and water injection volume is optimized to provide a decision-making basis for the implementation of injection measures. For water wells in low permeability reservoirs where acidization is ineffective or poor, low-displacement, low-stage cumulative injection activities are independently carried out to reduce injection costs. Active boosting water injection will be carried out for 3 wells in 2023. In view of the large difference in vertical heterogeneity and the development needs of injection and production regulation, research on stratified pressure drive technology is carried out to ensure long-term stratified pressure drive injection.

[0124] Example 2: The establishment and control method of the prediction model for the increase of injection pressure of the injection well due to reservoir blockage are as follows:

[0125] 1. Establish a prediction model for water injection pressure rise in water injection wells

[0126] Using probability distribution, the deviation trend of injection pressure is detected. Through big data analysis and individual distribution identification, the injection pressure conforms to the exponential distribution. When the injection well starts to inject water, the pressure will gradually increase until it reaches an equilibrium state. Suppose the injection pressure P(t) of the injection well is a function of time, where t represents time. The following exponential function can be used to describe the change of injection pressure:

[0127] P(t) = Po * (1 - e^(-kt))

[0128] Where Po is the initial injection pressure, k is a positive constant, and e is the base of the natural logarithm.

[0129] The characteristic of this model is that the initial injection pressure Po will gradually increase until it reaches an equilibrium state. As time goes by, e^(-kt) in the exponential function will gradually approach 0, making the injection pressure P(t) approach Po.

[0130] By judgment, if the injection pressure deviates from the exponential distribution, it is considered that the reservoir is blocked or the formation pressure has risen.

[0131] 2. Control method

[0132] For reservoir blockage, implement pressure boosting and injection enhancement. Apply skid-mounted injection devices and implement pressure-boosted injection projects for low-permeability blocks to enhance injection. Implement mobile pressure-boosted injection. Apply mobile pressure-boosted injection skids. At the well points where the injection pressure exceeds the design pressure of the pump station, implement high-pressure and small-displacement injection. Implement 1 well, with a daily injection allocation of 300 cubic meters, an injection pressure of 39.5 MPa, a cumulative injection of 19,500 cubic meters in the stage, and a cumulative oil increment of 4.64 tons. Implement large-displacement injection to depolymerize. For wells severely blocked by polymers, adopt large-displacement pressure-boosted injection technology to quickly replenish formation energy, and later adopt pressure-boosted pumps for pressure-boosted injection to improve the effect of water injection development. Implement 2 well-times in Block 106, with a cumulative injection of 43,000 cubic meters in the stage, a daily oil increment of 2.2 tons, and a cumulative oil increment of 600 tons. For injection wells blocked by water shutoff and polymer injection, adopt sandblasting perforation + depolymerizing agent and cycle large-displacement injection. For injection wells blocked by near-bottom zone pollution, deep pollution, and high clay content and water sensitivity, adopt acidification and composite injection enhancement.

[0133] If the injection pressure rises due to the increase in formation pressure, then control the rise of the injection pressure by adjusting the injection volume and injection pressure of the injection well.

[0134] Example 3: The establishment and control method of the calcium carbonate scale formation trend prediction model are as follows:

[0135] 1. Establish a method system for predicting the calcium carbonate scale formation trend.

[0136] According to SY / T 0600 "Prediction of Scale Formation Tendency in Oilfield Water", the scale samples on site were analyzed. The main scale type in injection wells is carbonate scale, with the calcium carbonate content above 80% in all cases. A small amount of iron scale was also found, indicating that corrosion also occurs in the wells, and organic scale and silica scale are relatively less. The specific prediction method system is as follows:

[0137] The general rule for judging the scale formation tendency of water quality is that when water from a single source or water from different sources is mixed, the scale formation tendency is predicted based on the concentration of scale-forming ions in the water and the magnitude of the theoretical solubility product constant, by predicting the maximum concentration of scale-forming ions or the minimum theoretical solubility product constant. There are two prediction methods: the saturation index method and the stability index method.

[0138] ⑴ Stability index method

[0139] The stability index is calculated according to the following formula:

[0140] SAI = 2(K + pCa + pAlK) - pH

[0141]

[0142]

[0143] In the formula: SAI - stability index

[0144] K - correction coefficient, obtained from the relationship curve between ionic strength and water temperature Figure 14 Look up

[0145] pCa - negative logarithm of the calcium ion (Ca2+) concentration (mol / L)

[0146] pAlK - negative logarithm of the total alkalinity (mol / L)

[0147] μ - ionic strength

[0148] Ci - ion concentration, mol / L

[0149] Zi - ion valence

[0150] The judgment method is:

[0151] ① When SAI is greater than or equal to 6, it indicates that calcium carbonate is unsaturated and there is no tendency to scale

[0152] ② When SAI is less than 6, it indicates that calcium carbonate is supersaturated and there is a tendency to scale

[0153] ③ When SAI is less than 5, it indicates that calcium carbonate is supersaturated and the scaling is severe

[0154] ⑵ Saturation index method:

[0155] The saturation index method is calculated according to the following formula:

[0156] SI = PH - K - pCa - pAlK

[0157]

[0158]

[0159] The judgment method is as follows:

[0160] In the formula: SI—saturation index

[0161] PH—pH value of the water sample

[0162] K—correction coefficient, which can be found from the relationship curve between ionic strength and water temperature Figure 14 by query

[0163] pCa—negative logarithm of the concentration of calcium ions (Ca 2+ ) (mol / L)

[0164] pAlK—negative logarithm of the total alkalinity (mol / L)

[0165] μ—ionic strength

[0166] C i —ionic concentration, mol / L

[0167] Z i —ionic valence

[0168] The judgment method is as follows:

[0169] ① When SI is less than 0, it indicates that calcium carbonate is unsaturated and there is no tendency to scale

[0170] ② When SI is equal to 0, it indicates that calcium carbonate is in a stable state, that is, the critical state

[0171] ③ When SI is greater than 0, it indicates that calcium carbonate is in a supersaturated state and there is a tendency to scale

[0172] The direct cause of scale formation in the system is the precipitation of a sparingly soluble salt in a supersaturated solution, and the liquid supersaturation is due to the mixing of immiscible liquids, temperature, pressure, and pH changes. Scale formation is caused by thermodynamic instability and chemical incompatibility within the system. The saturation index SI is a measure of supersaturation. Therefore, the possibility of calcium carbonate precipitation in the solution can be indicated according to the "saturation index".

[0173] According to the magnitude of the stability index or saturation index, combined with the operation dissection description, predict and judge the scale formation degree of the injection well reservoir and wellbore

[0174] 2. The control methods for scale blockage of injection well reservoirs are as follows:

[0175] As the injected water flows into the formation, the temperature and pressure rise, and scale is likely to form in the wellbore. The formation of scale has an important impact on the normal production of injection wells and wellbore corrosion.

[0176] Step 1: Establishment of the prediction model. For the prediction of oilfield water scaling, the prediction models are basically established based on the CaCO3 dissolution equilibrium theory. The models mainly consider the influence of the changes in pressure, temperature, and pH value in the wellbore on scaling. To facilitate the study of the scaling law in the injection wellbore, the following assumptions are made: The wellbore temperature changes linearly; the temperature, pressure, pH value, and ion concentration of the fluid at the same depth in the wellbore are the same; the water mainly exists in the liquid state.

[0177] Step 2: Selection of the scaling trend prediction model.

[0178] Analyze the scaling trend and maximum scaling amount of each well in injection wells at different temperatures, and obtain the scaling situation and scaling amount at different well depths based on the law of wellbore temperature change.

[0179] The CO2 content in the purified oilfield water injected is very small, and the influence of pressure on the scaling amount is not significant. Since the reaction of forming CaC03 is an endothermic reaction, the influence of temperature and pressure on the scaling amount is quite large. Therefore, mainly analyze the influence of temperature on scaling. As the temperature increases, the SI value increases and the scaling trend increases. It can be seen that temperature is one of the main factors affecting the SI value and scaling trend, and the higher the temperature, the more serious the scaling.

[0180] Step 3: Establishment of the maximum scaling amount prediction model. Since the scale formed by the sewage in the injection well is mainly CaC03 scale, use the CaC03 scaling model to predict the scaling in the injection wellbore.

[0181] The maximum scaling amount of CaC03 is predicted using the maximum amount prediction formula for the formation of CaCO3 scale proposed by Valone and Skillern to predict the maximum scaling amount of CaC03. The calculation formula is shown in the formula:

[0182] PTB = 17500×[C - (X2 + 4×10K - pH)0.5]

[0183] In the formula:

[0184] PTB - Predicted value of the maximum scaling amount of CaCO3, dimensionless, 1PTB = 0.35mg / L

[0185] C, X - Ion concentration, C = CO3 2- + HCO3 － ; X = CO3 2- - HCO3 － , mol / L

[0186] pH - pH value, pH = pH 地面+△pH,

[0187] △pH = (4150×10 -3 △T) + [4185×10 -7 ×(T d 2 -T s 2 )]-107×10 -5 △p

[0188] △p = p d -p s

[0189] Where: p d —— bottom-hole pressure, MPa;

[0190] p s —— surface pressure, MPa;

[0191] △T = T d -T s

[0192] Where: T d —— bottom-hole temperature, °C;

[0193] T s —— surface temperature, °C;

[0194] Prediction and judgment criteria for the scaling amount of CaC03: When PTB < 0, no scaling occurs; when 0 < PTB < 100, there is a small amount of scaling; when 100 < PTB < 250, the scaling is much and hard; when PTB > 250, the scaling is extremely serious.

[0195] Step 4: Solving method of the prediction model. For an injection well, first, a fixed calculation step size is taken. According to parameters such as the average daily injection volume and wellbore structure, the wellbore temperature, wellbore fluid pressure, and pH value are calculated. Then, starting from the bottom hole, considering the change in the mass concentration of scaling ions, the saturation index SI and the precipitation amount of CaC03 scale for each section in the wellbore are calculated. It is a program block diagram for calculating the distribution of CaC03 precipitation along the well depth by the iterative method. As Figure 15 shown.

[0196] Step 5: Analysis of prediction results. From the prediction of the entire scaling part of the injection water and the size of the scaling amount, the part with the largest scaling amount in the wellbore is within the range of less than 2000 m below the well depth and close to 500 m from the bottom hole. The reason is that the bottom-hole temperature is high.

[0197] Step 6: According to the prediction, control methods are taken.

[0198] 1. Physical scale prevention technology. Physical scale prevention technology prevents inorganic salts from depositing on the system wall through a certain effect, while allowing inorganic salts to form crystal nuclei or even crystallize in the solution. However, it is required that this crystallization suspends in the solution without adhering to the wall of the system. Its technologies include seeding technology, ultrasonic technology, and magnetic scale prevention technology.

[0199] 2. Chemical scale prevention technology. One is to add acid or inject carbon dioxide to prevent alkaline scale. The other is to use scale inhibitors to carry out complexation reactions with cations such as Ca 2+ , Mg 2+ etc., shielding them and minimizing their reaction with CO3 2- and preventing the aggregation of the formed CaCO3 lattice, so that the precipitate exists in the solution in a suspended state, preventing or reducing the blockage of the injection-production system.

[0200] For different types of oil reservoirs, multiple formulation systems such as sandstone acid and composite retarded acid have been established, mainly using retarded and low-damage acid fluid systems to meet the needs of different blockage types and different reservoir stimulations. In 2023, a total of 35 injection augmentation well-times were implemented, with a cumulative increase in injection volume of 420,000 cubic meters.

[0201] 3. The control methods for the scaling and blockage of the injection wellbore are as follows:

[0202] Step 1: Implement the petroleum industry standard. The injected water quality in the low-permeability oilfield formation meets the requirements of "Recommended Indexes and Analysis Methods for Injected Water Quality in Clastic Rock Reservoirs". At the same time, it is required that the water quality is stable, and no obvious scaling occurs when the injected water itself or is mixed with the formation water.

[0203] Step 2: Study the scaling law. Injection wells in low-permeability blocks generally scale, and the scale is hard, seriously affecting the service life of the injection string, resulting in a short effective period for injection augmentation, between 6 months and 9 months, leading to a large amount of work in operations and a short maintenance-free period. Scaling law: As the injection volume increases, the scaling of injection wells gradually worsens. Distribution law: As the well depth increases and the formation temperature rises, the scaling gradually worsens. There is less scaling above 2000m. Scale crystals begin to form at 2000m, and the scaling thickness increases gradually from 1mm to 30mm from 2000m to 4000m. The following surface measures are taken:

[0204] Step 3: Verify the scaling mechanism. During the reinjection process of produced water, the original stable system balance is changed to produce certain precipitates, which eventually deposit on the surface of the tubing or the pore surface of reservoir rocks to form scale. That is, Ca 2+ , Mg 2+ and CO3 2- , HCO 3- combine to form carbonate scale. The higher the temperature, the smaller the solubility of the precipitate.

[0205] Step 4: Confirmation of the scale composition. Generally, CaCO3 accounts for more than about 70% of the total scale sample, followed by BaSO4, MgCO3, etc.

[0206] Step 5: Softening and modification. According to the water quality of the produced water in the produced water softening treatment station and combined with the scale formation mechanism, caustic soda is added for softening and modification treatment to remove Ca 2+ and HCO 3- .

[0207] Step 6: Conduct an experiment on the calcium removal effect of NaOH. An experiment on adding sodium hydroxide is carried out in the produced water softening treatment station. The concentrations of calcium and magnesium ions decrease. It is obtained that at the inflection point of the sodium hydroxide concentration, the greater the dosage, the better the calcium removal effect. When the dosage reaches a certain value, the calcium removal effect tends to be flat and the calcium ion concentration drops to the lowest, indicating that the calcium removal effect is very obvious.

[0208] Step 7: Conduct an indoor evaluation experiment on the high-temperature scale formation degree. Simulate the high-temperature conditions of the formation indoors and carry out a scale formation experiment on softened water to initially determine the dosage, providing guidance for on-site implementation.

[0209] Step 8: Test method: Use the high-temperature resistant glass test tube method instead of the high-temperature reaction kettle method, and use the constant temperature oven instead of the high-temperature heating method, greatly improving the test efficiency.

[0210] Step 7: Test results: The concentrations of calcium and magnesium ions in the produced water of the produced water softening treatment station do not scale under high-temperature conditions, and the concentrations of calcium and magnesium ions in the produced water softening treatment station are determined.

[0211] Step 9: Indoor optimization experiment on the hydrochloric acid dosing concentration. Add hydrochloric acid to the produced water after calcium removal by sodium hydroxide indoors until the pH value reaches the designed value to determine the hydrochloric acid dosing concentration.

[0212] Step 10: On-site implementation. In the softening water treatment system of the produced water softening treatment station, the concentrations of calcium and magnesium ions after softening meet the requirements and the water quality meets the standards.

[0213] Step 11: Effect evaluation, which includes water quality treatment effect, high-temperature scale prevention effect of softened and purified water, change in the water injection well water absorption index, water well scale prevention effect, block development effect, etc. By injecting softened and purified water, the scaling of the water injection well reservoir, wellbore and surface flow is reduced.

[0214] 4. Example analysis of the prediction of the scaling position and scaling amount in the water injection wellbore is as follows:

[0215] (1) Well type parameters

[0216] The positions of water injection wells are different, and the main factors affecting wellbore scaling are also different. Therefore, four representative water injection wells, namely Well Z64-12, Well Z112-2, Well Z136-5, and Well Z148-X1 in Oilfield G, are selected for predicting the scaling positions and scaling amounts. The relevant parameters of these wells are shown in Table 8.

[0217] Table 8 Parameters of Typical Wells

[0218]

[0219]

[0220] (2) Selection of Scaling Trend Prediction Model

[0221] Analyze the scaling trends and maximum scaling amounts of each well in water injection wells at different temperatures, and obtain the scaling conditions and scaling amounts at different well depths based on the variation law of wellbore temperature.

[0222] The CO2 content in the produced water injected into these wells is very small, and the influence of pressure on the scaling amount is not significant. Since the reaction to generate CaC03 is an endothermic reaction, the influence of temperature and pressure on the scaling amount is quite large. Therefore, mainly analyze the influence of temperature on scaling.

[0223] Figure 16 -a~ Figure 16 -d Curves of SI values of the four water wells varying with temperature. From the curve analysis, the scaling trend predictions of each well are consistent and the differences are not significant. Therefore, the SI saturation index method prediction model can be used to predict the scaling trends of the wellbores of Well Z64-12, Well Z112-2, Well Z136-5, and Well Z148-X1. From Figure 16 -a~ Figure 16 -d Curves, it can be obtained that as the temperature increases, the SI value increases and the scaling trend increases. Thus, we can know that temperature is one of the main factors affecting the SI value and scaling trend, and the higher the temperature, the more serious the scaling.

[0224] Figure 17 -a~ Figure 20 -b Are respectively the curves of the maximum scaling amounts of Well Z64-12, Well Z112-2, Well Z136-5, and Well Z148-X1 varying with temperature and well depth.

[0225] From Figure 17From the SI curve in -a, the SI curve is a two-segment broken line. Scaling starts at 45°C. After the temperature is higher than 55°C, the SI value increases linearly. When the bottom-hole temperature is about 97°C, its value reaches as high as 2.4. Therefore, from the SI value, the scaling trend of Well Z64-12 is serious. From the analysis of the maximum scaling amount curve, starting from a temperature of 65°C, a relatively serious scaling condition appears, and the PTB value is between 100 and 215, belonging to the category of serious scaling. Therefore, comprehensively analyzing these two curves, the wellbore of Well Z64-12 is seriously scaled. This basically coincides with the operation description of this well.

[0226] From Figure 17 From the maximum scaling amount vs. well depth curve in -b, for Well Z64-12, scaling becomes serious at a well depth of 1800 m, and the scaling amount increases as the well depth increases. Therefore, for Well Z64-12, the main scaling part is between 1800 m below the wellhead and 3200 m at the bottom of the well.

[0227] From Figure 18 From the SI curve in -a, the SI value of the entire well section of this well is relatively low, and the maximum value does not exceed 0.2. Therefore, from the SI value, the scaling trend of Well Z112-2 is weak. From the change of the PTB value, its change range is within the category of slight scaling. Therefore, through comprehensive analysis, it is known that the wellbore of Well Z112-2 is slightly scaled.

[0228] From Figure 18 From the analysis in -b, the bottom-hole temperature of Well Z112-2 is relatively low, and the highest bottom-hole temperature is only 40°C, and the PTB value does not exceed 70. This is because this well is a sewage reinjection well, with a liquid volume of 400 m³ / d, and the sewage water temperature rises slightly. Therefore, the wellbore of Well Z112-2 is slightly scaled as a whole, but it is prone to bottom-hole blockage caused by substances such as emulsified oil and solid suspended matter.

[0229] From Figure 19 It can be seen from -a that the SI value and PTB value of Well Z136-5 have a linear relationship with the bottom-hole temperature. The highest SI value does not exceed 0.5, and there is a slight scaling trend. From the analysis of the maximum scaling amount PTB curve, the PTB value is below 100, indicating that the scaling amount of Well Z136-5 is not large. Therefore, comprehensively considering the relationship between these two curves, Well Z136-5 is slightly scaled, but more severely scaled than Well Z112-2.

[0230] From Figure 19 From the maximum scaling amount vs. well depth curve in -b, the maximum PTB value appears at a position below a well depth of 2000 m. Therefore, the most severely scaled part of this well is below a well depth of 2000 m, that is, within a range of 200 m near the bottom of the well.

[0231] The bottom-hole temperature of Well Z148-X1 is high, and the highest can reach 124°C. Figure 20Judging from the SI curve in -a, the highest SI value exceeds 2.0, indicating that the wellbore scaling trend is very serious during the production process of this well; Judging from Figure 20 the PTB curve in -a, after the downhole temperature exceeds 80 °C, the PTB value is between 100 and 240, belonging to the category of serious scaling. Therefore, through comprehensive analysis, Z 148-X1 has serious scaling under the current production state. This also basically coincides with the conclusion of on-site investigation.

[0232] Judging from Figure 20 the relationship between PTB and well depth in -b, for Well Z148-X1, when the well depth is about 2800 m, the scaling starts to be serious and the scaling amount will increase significantly. Therefore, for Well Z148-X1, the most serious scaling part is within the range of about 700 m close to the bottom of the well.

[0233] Judging from the above analysis, the wellbore scaling trend of Well Z112-2 and Well Z136-5 is weak and belongs to mild scaling. The wellbore scaling trend of Well Z64-12 and Well Z148-X1 is serious and belongs to serious scaling. This is indeed the case in on-site investigation.

[0234] It can be seen that the present invention can reflect the actual scaling situation of injection wells. Judging from the prediction of the entire scaling part and the scaling amount of several wells, the part with the largest wellbore scaling amount is within the range of 500 m close to the bottom of the well below a well depth of 2000 m. The reason is that the bottom hole temperature is high.

[0235] Example 4: The control method for unqualified water quality along the injection process is as follows:

[0236] Step 1: Define water quality control factors. The control factor is suspended solids, followed by emulsified oil. Injection water scaling is an important factor damaging the reservoir. Demulsifiers, water clarifiers, scale inhibitors, corrosion inhibitors, bactericides, and cleaning agents are preferably selected.

[0237] Step 2: Control the quality of chemicals. Through work such as reviewing chemical access, monitoring the process, and evaluating the quality. At the same time, an automatic chemical dosing device is equipped, which can accurately adjust the chemical dosage according to the change of water quality, realizing chemical dosing on demand.

[0238] Step 3: Control water quality nodes. Formulate a tank cleaning plan, and conduct daily management such as regular cleaning, maintenance, and filter media replacement of filter tanks. Use an infrared thermal imaging detector to detect the thickness of oil sludge and sand in the water storage tank.

[0239] Step 4: Clean physical pipelines in a timely manner. Clean the water supply pipeline and injection main pipeline. Implement the cleaning of 13 single-well pipelines annually, and the water quality along the corresponding wellhead reaches the standard.

[0240] Step 5: Detect the water quality at the outlet, promptly discover abnormal water quality and handle it. Innovate the rapid water quality detection method, adopt the image recognition method to quickly detect the water quality. The on-site detection time is reduced from 2 hours to 2 minutes, greatly improving the detection efficiency and shortening the water quality fluctuation handling time. The six-step rapid detection method: (1) Take 50 ml of water sample; (2) Add petroleum ether; (3) Slowly shake the water sample for 30 seconds; (4) Let the water sample stand still for 15 seconds; (5) Place it in the detection device; (6) Read the data by water quality imaging.

[0241] Step 5: Improve the water treatment standard. For low-permeability blocks, fine water of level 2 or above is provided. For medium and high-permeability oilfields and produced water reinjection blocks, water quality of level 4 is provided.

[0242] Step 6: Detect the water quality at the source and along the way. Conduct research and analysis on the factors causing water quality pollution along the way. For the problem of water quality pollution along the way, through the analysis of the scale and corrosion products in the injection pipe network, take targeted measures. Carry out water quality treatment along the way. For the pollution reasons, adopt technologies such as cavitation jet physical cleaning and chemical cleaning respectively to clean the scale and corrosion products in the injection pipe network, reducing the secondary pollution of the water quality along the way.

[0243] Step 7: Implement classified well flushing. In the well flushing process, introduce and install a well flushing parameter monitor to automatically collect and regularly upload the well flushing displacement and pressure data, realizing the whole-process quality control of well flushing, improving the timeliness rate and qualification rate of well flushing, and enhancing the overall effect of well flushing. Flush the well according to the three-section method, implement four requirements such as well flushing design and well flushing instruction manual, describe the well flushing process in detail, introduce a self-circulating well flushing vehicle to flush the well, ensure the well flushing quality, carry out 214 well flushing operations per year, and improve the efficiency of well flushing. Establish a data ledger for pressure, water volume, time, well flushing description, etc. during the well flushing process to ensure well flushing according to the specified cycle.

[0244] Step 8: Improve the well pipe string. By supporting tungsten-plated and infiltrated anti-corrosion oil pipes and high-quality downhole water distribution tools, the long service life of the injection pipe string is achieved. For deep reservoirs, an anchored and compensated stratified injection pipe string is used for separate injection. A total of 28 high-quality stratified injection pipe string operations have been implemented, laying a foundation for the efficient water injection development of shallow reservoirs.

[0245] Step 9: Effect evaluation: By taking measures such as pharmaceutical quality control, cleaning of storage tanks and pipelines, rapid water quality detection at process nodes, and well flushing according to standards, the comprehensive water quality compliance rate remains above 95%.

[0246] Finally, it should be noted that the above are only preferred embodiments of the present invention and are not intended to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or perform equivalent replacements for some of the technical features. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

[0247] Except for the technical features described in the specification, the rest are known technologies to those skilled in the art.

[0248] In the present invention, specific embodiments are used to elaborate on the principle and implementation manner of the present invention. The description of the above embodiments is only used to help understand the method and its core idea of the present invention; at the same time, for those of ordinary skill in the art, according to the idea of the present invention, there will be changes in the specific implementation manner and application scope. In summary, the content of this specification should not be construed as a limitation to the present invention.

Claims

1. A method for predicting and controlling the increase of injection pressure in an injection well, characterized in that, The method for predicting and controlling the rising injection pressure of an injection well includes: Step 1: Collect data of the injection well according to the different characteristics of each stage of the waterflood development reservoir. Step 2: Conduct dynamic analysis of the injection well based on the well data. Step 3: Take the injection pressure as the response and the factors affecting the rising injection pressure as variables, and establish a prediction model for the rising injection pressure of the injection well by reservoir and by factor. Step 4: Develop a control method for the rising pressure of the injection well according to the prediction model of the rising injection pressure of the injection well.

2. The prediction and control method for the increase of the water injection pressure of an injection well according to claim 1, wherein In Step 1, based on reservoir classification, fine reservoir description, and understanding of injection-production connectivity, collect historical reservoir static data, dynamic data, well history of operation wells and dissection description, experimental data, monitoring data, water quality indicators, injection-production big data, and injection index, which are the data of the injection well.

3. The method for predicting and controlling the increase in the water injection pressure of an injection well according to claim 1, wherein In Step 2, during overall or long-term injection dynamic analysis, sample by reservoir and use its big data to identify and determine the probability distribution of injection pressure, time, and injection volume.

4. The method for predicting and controlling the increase in injection pressure of an injection well according to claim 3, characterized in that, In Step 2, in the laboratory, conduct experiments on the filtration rate of different types of liquids in the formation, analyze on-site scale samples, and predict the scaling trend when water from different sources is mixed. According to the test results, judge the changing trend of the injection pressure.

5. The method for predicting and controlling the increase in water injection pressure of an injection well according to claim 1, characterized in that, In Step 3, through big data collection, sorting, and cleaning, apply prediction methods such as injection indicator curves, statistics, and experimental analysis. Take the injection pressure as the response and the factors affecting the rising injection pressure as variables, and establish a prediction model for the rising injection pressure of the injection well by reservoir and by factor.

6. The prediction and control method for the increase in water injection pressure of an injection well according to claim 5, characterized in that, In Step 3, the injection pressure refers to the pressure at the outlet of the flowmeter in the water distribution station. The factors affecting it include low permeability of the reservoir, injection volume, rising injection pressure due to reservoir plugging, scaling in the reservoir wellbore, and non-compliance of the water quality along the way.

7. The injection water pressure rise prediction and control method according to claim 5, characterized in that In Step 3, the injection indicator curve is the relationship curve between the injection pressure and the corresponding injection volume; by analyzing the characteristics of the curve shape and the change of the curve slope, the water absorption capacity of the oil layer and its change can be understood.

8. The injection pressure rise prediction and control method for an injection well according to claim 5, characterized in that In Step 3, establish a prediction model for the rising injection pressure of the injection well by factor, including the relationship model between the low-permeability injection pressure and the injection volume, the prediction model of the injection pressure of the injection well with reservoir plugging, and the prediction model of the calcium carbonate scaling trend; the prediction model of the calcium carbonate scaling trend is used to predict the scaling trend of the reservoir and the wellbore.

9. The method for predicting and controlling the increase in the water injection pressure of an injection well according to claim 8, characterized in that, In Step 4, according to the prediction model of the rising injection pressure of the injection well, predict the changing trends of the injection pressure and various influencing factors. If it is judged that the injection process is abnormal, develop a control method and evaluate its implementation effect.

10. The method for predicting and controlling the increase of injection pressure of an injection well according to claim 9, characterized in that, In Step 4, evaluating the implementation effect includes: evaluating the pressure drive injection energy, the dynamic liquid level of the corresponding oil well, the injection pressure, the scaling prediction position, the scaling amount, the source, and the water quality along the way; through evaluation, verify the change of the water absorption index of the injection well, the anti-scaling effect of the injection well, the water quality treatment effect, and the block development effect.

11. The method for predicting and controlling the increase of injection pressure of an injection well according to claim 9, characterized in that, In step 4, according to the relationship model between low-permeability water injection pressure and injection volume, the pressure-driven water injection technology is implemented to increase the water injection pressure and injection volume in the low-permeability reservoir; micro-fractures are formed by large displacement and high pressure, and the displacement agent is quickly sent to the remaining oil enrichment area through the fractures. While fracturing and creating fractures, the displacement agent filtrates up and down along the wellbore and is quickly filled into the pores, reducing the contact time and contact distance between the chemical agent and the formation, and improving the displacement efficiency; at the same time, by injecting a large amount of displacement fluid, the formation energy can be supplemented in a short time, achieving the effect of energy storage before pressing, increasing and maintaining the formation pressure, and extending the stable production period.

12. The injection water pressure rise prediction and control method according to claim 11, characterized in that, In step 4, the pressure-driven water injection technology is implemented, including optimizing construction parameters and the pressure-driven string method; among them, optimizing construction parameters includes injection parameters, matrix permeability, and injection method.

13. The injection pressure rise prediction and control method for an injection well according to claim 9, characterized in that In step 4, according to the water injection pressure prediction model for blocked injection wells in the reservoir, through judgment, if the water injection pressure deviates from the exponential distribution, it is considered that the reservoir is blocked or the formation pressure has risen.

14. The injection water pressure rise prediction and control method according to claim 13, wherein In step 4, for reservoir blockage, pressure boosting and injection increasing are implemented. The skid-mounted water injection device is applied to implement pressure boosting water injection project for low-permeability blocks; mobile pressure boosting water injection is implemented. The mobile pressure boosting water injection skid is applied to implement high-pressure and small-displacement injection at the well points where the injection pressure exceeds the design pressure of the pumping station.

15. The prediction and control method for the increase of the water injection pressure of an injection well according to claim 13, characterized in that, In step 4, if the water injection pressure rises due to the rise of the formation pressure, the rise of the water injection pressure is controlled by adjusting the water injection volume and water injection pressure of the injection well.

16. The injection pressure rise prediction and control method for an injection well according to claim 9, characterized in that, In step 4, according to the calcium carbonate scaling trend prediction model, physical and chemical scale prevention and removal technology and acid pickling and plugging removal technology are applied to control the water quality along the water injection process. The control of the water quality along the water injection process includes softening treatment of produced water, physical cleaning of pipelines, rapid water quality detection, and supporting tungsten-plated and infiltrated anti-corrosion oil pipes.

17. Prediction and control system for the rising injection pressure of injection wells, characterized in that, The water injection pressure rise prediction and control system for the injection well establishes a water injection pressure rise prediction model for the injection well by using the water injection pressure rise prediction and control method described in any one of claims 1-16, and formulates a control method for the pressure rise of the injection well according to the model prediction.

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