A method for establishing a "medicine field concept" of a heavy oil development wellbore

Abstract

The present application relates to a kind of methods for establishing heavy oil development wellbore " medicine field concept ", comprising the following steps: S1: oil well production or pump inspection operation is measured to determine oil well dynamic liquid level H1 first day pumping;S2: from oil jacket annulus, oil well wax removal viscosity reducer is added, by adjusting the addition amount of oil well wax removal viscosity reducer, so that heavy oil development wellbore " medicine field " is established;The principle of the present application is that when oil well is put into production or pump inspection operation pumping, its dynamic liquid level is real-time change and in dynamic balance, when a certain amount of wax removal viscosity reducer is added from oil jacket annulus, the dynamic balance of dynamic liquid level is broken, wax removal viscosity reducer and the fluid in oil well will produce " Brown movement " and " similar solubility " and / or " water film emulsification " and / or " polyhedral emulsification " and other fusions, in this way, a new dynamic balance of dynamic liquid level is established, so that wax removal viscosity reducer continuously plays a role in an addition period.

Description

Technical Field

[0001] This invention belongs to the field of oil production engineering technology, and in particular relates to a method for establishing a "pharmacy concept" for heavy oil development wellbore. Background Technology

[0002] Wellbore viscosity reduction and lifting is one of the key technologies for the successful cold production of heavy oil. It is basically carried out by chemical viscosity reduction. However, the key technical point for success is: after the new well is put into production or the pump is inspected in the old well, after the well water is drained, check whether the well can operate normally for 1-7 days after the oil starts to produce oil.

[0003] The paper "Indoor Tests and Field Applications of Chemical Viscosity Reduction Technology in Heavy Oil Wellbores," published by Wu Guobin et al. in *Henan Petroleum* in May 2004, records that the high-salinity, extra-heavy oil fault-block reservoirs Xin 73 and Xin 100 in the Dongxin Oilfield experienced unsatisfactory extraction results with electric heating or electric heating combined with surface water mixing. Based on laboratory research and considering the field conditions, a wellbore chemical viscosity reduction process using an aqueous solution of an active agent was tested. The results showed that this technology not only solves the problem of lifting heavy oil in wellbores but also addresses the difficulty of surface transportation, and also results in low extraction costs.

[0004] In her 2019 Master's thesis at China University of Petroleum (Beijing), "Optimization and Evaluation of Viscosity-Reducing Agents for Tarim River Heavy Oil," Manisha described how, to clarify the high viscosity principle of Tarim River heavy oil and address its high viscosity and poor flowability during extraction and transportation, this paper first systematically studied the rheological properties, viscosity-temperature characteristics, acid value, and component content of Tarim TH10138, TK677, and TH123101 heavy oils through indoor experiments. The relationship between the four components and the viscosity of the heavy oil was analyzed, and the reasons for the high viscosity of the heavy oil were explored using a control group of unrefined oil (Unit 1). Secondly, the solubility, compatibility, interfacial tension reduction ability, salt resistance, and flocculation ability of ten selected viscosity-reducing agents were evaluated. A seven-factor, two-level orthogonal experiment was used to screen the viscosity-reducing agents, and the optimal ratio was selected by evaluating the viscosity-reducing effect of compound viscosity-reducing agents. Finally, the effects of oil-water ratio, temperature, viscosity reducer concentration, salinity, and pH on the viscosity-reducing effect of the viscosity reducer were studied. The compatibility of the viscosity reducer was evaluated by analyzing the natural dehydration ability and secondary viscosity-reducing ability of the oil-water emulsion. At 50℃, the optimal viscosity reducer formulation at an oil-water ratio of 1:1 was found to be 1000 mg / L of 21# viscosity reducer + 500 mg / L of 7# viscosity reducer + 0.4% Na2CO3, achieving a viscosity reduction rate of 98.3% for heavy oil and a dehydration rate of over 80% for the oil-water emulsion. A lower oil-water ratio resulted in lower emulsion viscosity, which was mainly related to the viscosity of the dispersed phase. This viscosity reducer system exhibited stable viscosity-reducing effects within the temperature range of 40℃ to 80℃, with a viscosity reduction rate of approximately 98%. Higher viscosity reducer concentrations resulted in lower emulsion viscosity, but the emulsion viscosity remained essentially unchanged after the viscosity reducer concentration exceeded 1500 mg / L. 2+ When the concentration exceeds 10000 mg / L, the viscosity reducer becomes less effective at reducing the viscosity of heavy oil, and the stability of the oil-water emulsion is poor. The viscosity reducer is less effective in strong acid environments (pH≤4), but has good viscosity reduction effect in weak acid and alkaline environments.

[0005] The paper "Analysis and Evaluation of Two Main Heavy Oil Wellbore Viscosity Reduction Technologies in Tarim Oilfield," published by Zhang Bin et al. in *Advances in Fine Petrochemicals* in November 2008, records the following: Adaptability analysis of different heavy oil viscosity reduction and lifting processes in the Tarim Oilfield shows that both thinning and chemical viscosity reduction technologies are suitable for heavy oil wells in Block 6 of the Tarim Oilfield. The paper briefly introduces the principles of the two viscosity reduction technologies. Laboratory and well application results show that the thinning technology is suitable for flowing wells with heavy oil viscosity greater than 50,000 mPa·s and water content less than 20%. At a thin-to-heavy oil volume ratio of 1:2 to 1:1, the viscosity reduction rate reaches over 90%. The chemical viscosity reduction technology uses emulsified viscosity reducer XS-2, which has strong salt resistance and a wide operating temperature range. Under conditions of an oil-to-water volume ratio of 7:3, a temperature of 60℃, and an XS-2 dosage of 1.0 kg / t crude oil, the viscosity of heavy oil in well T433 decreased from 3,156 mPa·s to 345 mPa·s.

[0006] Chinese patent CN106971082A discloses a method for optimizing viscosity reduction parameters in heavy oil wells, including: a flowability parameter determination step, comprising: obtaining the relationship between the viscosity and temperature of the target heavy oil to determine the sensitive temperature at which the target heavy oil can flow smoothly and be lifted to the surface; sequentially adding oilfield water to the target heavy oil from low to high and mixing and stirring to uniformly emulsify the heavy oil and oilfield water, thereby obtaining and plotting a curve showing the relationship between the viscosity and water cut of the target heavy oil, and using this to determine the inverse phase point of the crude oil when free water is removed; a wellbore thermal viscosity reduction parameter determination step, comprising: measuring the temperature change of the target heavy oil during its flow from the bottom of the well to the surface to determine the curve showing the change between the wellbore depth and temperature; and determining the wellbore depth for viscosity reduction based on the sensitive temperature; and a wellbore chemical viscosity reduction parameter determination step, comprising: determining the relationship between the concentration of surfactants, light hydrocarbons, and heavy oil viscosity through sampling experiments to determine the chemical viscosity reduction parameters required to ensure smooth flow of heavy oil.

[0007] Chinese Patent CN 110686164 B discloses a method for reducing crude oil viscosity. This invention relates to the field of crude oil transportation. To address the problem of increased crude oil viscosity at low temperatures leading to transportation difficulties, and to overcome the shortcomings of existing physical and chemical viscosity-reducing technologies, particularly improving the problem of increased viscosity and weakened viscosity-reducing effect of existing chemical viscosity reducers at low temperatures, this invention proposes a method for reducing crude oil viscosity: mixing crude oil with a cyclosiloxane containing diethylsiloxane linkages or a polymer containing diethylsiloxane linkages using conventional methods. This significantly reduces the viscosity of the crude oil, thereby reducing energy consumption during heating and insulation in crude oil transportation, lowering pump power, reducing crude oil resistance in pipelines, and reducing energy consumption during crude oil transportation. The synthesis method of this invention is simple, the reaction conditions are mild, the product is easy to separate and recover, equipment investment is low, equipment utilization is high, and it is easy to industrialize.

[0008] Chinese patent CN107247816B discloses a method for determining the furthest construction radius for cold production chemical viscosity reduction in heavy oil reservoirs, comprising the following steps: First, establishing that the oil well requires and is worthwhile for construction, and obtaining relevant construction parameters; then, analyzing and calculating the flow resistance caused by the "start-up pressure gradient" of the heavy oil reservoir and the displacement pressure established by the pressure drop during reservoir production; finally, determining the range of the reservoir's non-movable oil radius under the current well production conditions by calculating (displacement pressure minus flow resistance is less than zero), and ultimately determining the furthest construction radius of the viscosity reducer. This invention determines the construction range through on-site chemical viscosity reduction, making the construction method more reasonable and greatly reducing construction risks.

[0009] Chinese Patent CN 106121605 A discloses a method comprising the following steps: Step (1): determining whether the oil well requires construction and has construction value; Step (2): after determining that the oil well requires construction and has construction value, collecting relevant calculation parameters; Step (3): based on the pressure drop formula formed by oil well production, obtaining the pressure drop curve, and determining the driving effect of formation pressure on underground crude oil under different radius conditions; Step (4): the radius calculated under critical conditions after the crude oil is degassed below the saturation pressure is the effective construction radius for chemical viscosity reduction in gas-bearing heavy oil reservoirs. The technical purpose of this invention is to enrich the construction methods for chemical cold production viscosity reduction in heavy oil reservoirs, and to provide a method for quickly determining the effective construction radius for chemical viscosity reduction of a single well in gas-bearing heavy oil reservoirs, providing a fast and convenient guide for on-site chemical viscosity reduction construction operations.

[0010] Chinese Patent CN 106194133 A discloses a method for determining the construction range of chemical viscosity reduction, which includes the following steps: Step (1): well selection; Step (2): collection of relevant parameters; Step (3): determination of production pressure drop during oil well production; Step (4): determination of the upper limit of the construction range; Step (5): determination of the lower limit of the construction range. This invention adopts cold production chemical viscosity reduction technology, and the injection radius range of the viscosity reducing agent is determined by fully considering the viscosity change process and existence state of the formation crude oil, which can effectively guide the on-site construction.

[0011] In fact, during oil testing or pump inspection operations in heavy oil wells, water-soluble chemical viscosity reducers are often injected into the formation to lower the oil layer viscosity. The formation crude oil forms an O / W (oil-in-water) emulsion, which flows smoothly into the wellbore. Wellbore viscosity reduction and lifting involves adding chemical viscosity reducers through the casing at the wellhead, allowing the agent to settle to the pump inlet via the annulus, thus reducing viscosity in heavy oil wells. However, in the field, some oil wells, after new wells are put into production (after oil testing) or after pump inspection operations in older wells, cannot operate normally after the kill fluid is drained. This has become a bottleneck technology restricting the lifting of heavy oil cold-production wells. Summary of the Invention

[0012] The technical problem solved by this invention is achieved through the following technical solution:

[0013] A method for establishing a "pharmacy concept" for heavy oil development wellbore includes the following steps:

[0014] S1: Measure the dynamic fluid level H1 of the oil well on the first day of oil well commissioning or pump testing;

[0015] S2: Add oil well dewaxing and viscosity reducing agent from the annulus of the oil casing. By adjusting the amount of oil well dewaxing and viscosity reducing agent added, a "chemical tank" is established in the wellbore of heavy oil development.

[0016] Furthermore, the method for establishing a "chemical field" in the heavy oil development wellbore by adding oil well wax remover and viscosity reducer from the annulus and adjusting the amount of oil well wax remover and viscosity reducer added is as follows:

[0017] S2-1: Add 1000 kg of oil well dewaxing and viscosity reducing agent. After adding the agent for 2-4 hours, measure the dynamic fluid level H2 of the oil well and test the maximum current A of the oil well motor. i Or, test the maximum current (A) of the oil well motor. i and the maximum suspension point load F of the pumping unit i Simultaneously, obtain the theoretical height H3 of the fluid level rise in the annulus of the oil casing after adding the oil well dewaxing and viscosity reducing agent;

[0018] S2-2: Compare the changes in the dynamic fluid level of the oil well and obtain the comparison value α. i :

[0019]

[0020] S2-3: When α is obtained i If the value is between 1.0 and 1.2, repeat step S2-1 on the second day;

[0021] S2-4: When α is obtained i If the value is between 0.5 and 1.0, repeat operation step S2-1 and adjust the amount of oil well dewaxing and viscosity reducing agent added to 500 kg; at this time, compare the rate of change of the maximum current of the oil well motor and the maximum suspension point load of the pumping unit.

[0022] S2-5: When the change rate of the maximum current of the oil well motor and the maximum suspension point load of the pumping unit are both within ±20%, the heavy oil development wellbore "pharmacy" is established; or when the change rate of the maximum current of the oil well motor and / or the maximum suspension point load of the pumping unit both exceed ±20%, then repeat step S2-1 the next day.

[0023] Furthermore, it also includes step S3: After the heavy oil development wellbore "chemical farm" is established and the oil well is in normal production, the amount and cycle of adding the wax-removing and viscosity-reducing agent are determined according to the method for determining the addition time of the wax-removing agent in oil wells disclosed in CN 107724999 B, the method for determining the wax-removing and viscosity-reducing effect of oil wells with a water content of more than 50% disclosed in CN108169068 B and the evaluation method and device for the viscosity-reducing effect of the viscosity-reducing agent in oil wells disclosed in CN 104265282 B.

[0024] Furthermore, in step S2-1, the theoretical height H3 of the fluid level rise in the annulus of the oil well after adding the oil well dewaxing and viscosity reducing agent is:

[0025]

[0026] In the formula: Vi is the volume of oil well dewaxing and viscosity reducing agent added; D is the inner diameter of the oil well casing; d is the outer diameter of the oil well tubing body, mm; L is the casing length; i refers to the 1st, 2nd, 3rd, ... nth day;

[0027] Furthermore, the aforementioned It refers to the volume (m3) of the annular space of the oil jacket with a height of 1m;

[0028] Furthermore, the annular space between the oil well casing and the oil well tubing refers to the space between the inner diameter of the oil well casing and the outer diameter of the oil well tubing body. The annular space between the oil well casing and the oil well tubing is described in detail in the article "Analysis of Influencing Factors and Countermeasures for Echo Method Monitoring of Dynamic Fluid Level in Oil Wells" published by Huangfu Wanghuan et al. in 2017 in the journal "Technical Supervision of Petroleum Industry" Volume 33, Issue 7.

[0029] Furthermore, the theoretical height H3 of the fluid level rise in the annulus is essentially the volume of the added oil well dewaxing and viscosity-reducing agent occupying the annulus. A multiple of; that is, the height to which the oil well fluid level rises.

[0030] Furthermore, in this field, the dynamic fluid level of oil wells is often characterized by m; the dynamic fluid level refers to the fluid level depth, which is described in detail in Ren Chuanxiao's article "Research on Optimization Method of Inter-well Pumping System" published in Petroleum & Petrochemical Energy Conservation, Vol. 12, No. 4, 2022.

[0031] Furthermore, in step S2-1, for surface-driven screw pump oil wells, the maximum current A of the oil well motor is tested. i .

[0032] Furthermore, in step S2-1, for the pumping unit well, the maximum current A of the well motor is tested. i and the maximum suspension point load F of the pumping unit i .

[0033] Furthermore, the oil well dewaxing and viscosity reducing agent in step S2 may be, but is not limited to, FV-1, HQAD-1, and HQ-2.

[0034] The advantages and positive effects of this invention are:

[0035] The method of this invention has been applied to more than 100 oil wells in the past 5 years, and the wells have been able to produce normally after being put into production or after pumping is started. Detailed Implementation

[0036] First, it should be noted that the specific structure, features, and advantages of the present invention will be described in detail below by way of examples. However, all descriptions are for illustrative purposes only and should not be construed as limiting the present invention in any way. Furthermore, any single technical feature described or implied in the various embodiments mentioned herein can still be arbitrarily combined or deleted among these technical features (or their equivalents) to obtain more other embodiments of the present invention that may not be directly mentioned herein.

[0037] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other.

[0038] Example 1

[0039] A method for establishing a "pharmacy concept" for heavy oil development wellbore includes the following steps:

[0040] S1: Measure the dynamic fluid level H1 of the oil well on the first day of oil well commissioning or pump testing;

[0041] S2: Add oil well dewaxing and viscosity reducing agent from the annulus of the oil casing. By adjusting the amount of oil well dewaxing and viscosity reducing agent added, a "chemical tank" is established in the wellbore of heavy oil development.

[0042] Furthermore, the method for establishing a "chemical field" in the heavy oil development wellbore by adding oil well wax remover and viscosity reducer from the annulus and adjusting the amount of oil well wax remover and viscosity reducer added is as follows:

[0043] S2-1: Add 1000 kg of oil well dewaxing and viscosity reducing agent. After adding the agent for 2-4 hours, measure the dynamic fluid level H2 of the oil well and test the maximum current A of the oil well motor. i Or, test the maximum current (A) of the oil well motor. i and the maximum suspension point load F of the pumping unit i Simultaneously, obtain the theoretical height H3 of the fluid level rise in the annulus of the oil casing after adding the oil well dewaxing and viscosity reducing agent;

[0044] S2-2: Compare the changes in the dynamic fluid level of the oil well and obtain the comparison value α. i :

[0045]

[0046] S2-3: When α is obtained i If the value is between 1.0 and 1.2, repeat step S2-1 on the second day;

[0047] S2-4: When α is obtained iIf the value is between 0.5 and 1.0, repeat operation step S2-1 and adjust the amount of oil well dewaxing and viscosity reducing agent added to 500 kg; at this time, compare the rate of change of the maximum current of the oil well motor and the maximum suspension point load of the pumping unit.

[0048] S2-5: When the change rate of the maximum current of the oil well motor and the maximum suspension point load of the pumping unit are both within ±20%, the heavy oil development wellbore "pharmacy" is established; or when the change rate of the maximum current of the oil well motor and / or the maximum suspension point load of the pumping unit both exceed ±20%, then repeat step S2-1 the next day.

[0049] Specifically, it also includes step S3: After the heavy oil development wellbore "chemical farm" is established and the oil well is in normal production, the amount and cycle of adding the wax-removing and viscosity-reducing agent are determined according to the method for determining the addition time of the wax-removing agent in oil wells disclosed in CN 107724999 B, the method for determining the wax-removing and viscosity-reducing effect of oil wells with a water content of more than 50% disclosed in CN108169068 B and the evaluation method and device for the viscosity-reducing effect of the viscosity-reducing agent in oil wells disclosed in CN 104265282 B.

[0050] In step S2-1, the theoretical height H3 of the fluid level rise in the annulus after adding the oil well dewaxing and viscosity reducing agent is:

[0051]

[0052] In the formula: Vi is the volume of oil well dewaxing and viscosity reducing agent added; D is the inner diameter of the oil well casing; d is the outer diameter of the oil well tubing body, mm; L is the casing length; i refers to the 1st, 2nd, 3rd, ... nth day;

[0053] The aforementioned This refers to the volume (m3) of the annular space at a height of 1m in the casing. The annular space, also known as the casing space, is the space between the inner diameter of the well casing and the outer diameter of the well tubing. This annular space is detailed in the article "Analysis and Countermeasures of Factors Affecting Dynamic Fluid Level Monitoring in Oil Wells using Echo Method" published by Huangfu Wanghuan et al. in 2017 in *Petroleum Industry Technical Supervision*, Vol. 33, No. 7. Theoretically, the height H3 of the fluid level rise in the annular space is essentially the volume of the added oil well dewaxing and viscosity-reducing agent within the annular space. The multiple of; that is, the height to which the oil well fluid level rises. In this field, the dynamic fluid level of oil wells is often represented by m; the dynamic fluid level refers to the fluid level depth, which is described in detail in the article "Research on Optimization Method of Inter-well Pumping System" published by Ren Chuanxiao in Volume 12, Issue 4 of "Petroleum and Petrochemical Energy Conservation" in 2022.

[0054] In addition, in step S2-1, for surface-driven screw pump oil wells, the maximum current A of the oil well motor is tested. iIn step S2-1, for the pumping unit well, the maximum current A of the well motor is tested. i and the maximum suspension point load F of the pumping unit i .

[0055] It is possible that the oil well dewaxing and viscosity reducing agent in step S2 may be, but is not limited to, FV-1, HQAD-1, or HQ-2.

[0056] The principle of this invention is that the dynamic fluid level of an oil well changes in real time and is in dynamic equilibrium when it is put into production or pumped for inspection. When a certain amount of wax remover and viscosity reducer is added from the annulus, the dynamic equilibrium of the dynamic fluid level is broken. The wax remover and viscosity reducer will undergo "Brownian motion" and "like dissolves like" and / or "water film emulsification" and / or "polyhedral emulsification" depending on the properties of the wax remover and viscosity reducer. In this way, a new dynamic equilibrium of the dynamic fluid level is established, so that the wax remover and viscosity reducer can continue to play a role within one addition cycle.

[0057] Example 2

[0058] In the application of well XX-24, the surface crude oil viscosity at 50℃ was 6207.93 mPa.s, the well casing inner diameter was 124 mm, the tubing body outer diameter was 89 mm, and the surface-driven screw pump was used for production.

[0059] Step 1: On the first day of oil well commissioning or pump start-up, the dynamic fluid level H1 of the oil well is measured to be 672m;

[0060] Step 2: Add oil well dewaxing and viscosity reducing agent through the annulus:

[0061] Step 2-1: On the first day, the amount of wax remover and viscosity reducer added to the oil well is 1000 kg. 2-4 hours after adding the wax remover and viscosity reducer, the dynamic fluid level H2 of the oil well is measured to be 681 m. The maximum current A of the oil well motor is tested. i It is 22A;

[0062] Meanwhile, the theoretical height H3 of the fluid level rise in the annulus after adding the oil well dewaxing and viscosity reducing agent is calculated to be 17.54m.

[0063]

[0064] In the formula: V i To determine the volume of oil well dewaxing and viscosity reducing agent to be added, m 3 The calculation method is the ratio of the mass of the oil well dewaxing and viscosity reducing agent to its density, with the density taken as 1; D is the inner diameter of the oil well casing, mm; d is the outer diameter of the oil well tubing, mm; L is the casing length, taken as 1m here; the inner diameter of the oil well casing D and the outer diameter of the oil well tubing d are converted to m in the calculation, and i refers to the 1st, 2nd, 3rd, ... nth day.

[0065] Step 2-2: Compare the changes in the dynamic fluid level of the oil well, comparing H2-H1 with H3. The ratio of H2-H1 to H3 is 1.9489.

[0066]

[0067] In the formula: α i It is the ratio of H2-H1 to H3;

[0068] Step 2-3: When α in step 2-2 i If the value is between 1.0 and 3.0, repeat step 2-1 on the second day;

[0069] Step 2-4: When step 2-2 reaches the third day, α i The value is 0.7428. On the 4th day, the amount of dewaxing and viscosity reducing agent added to the oil well is 500 kg. The remaining operations are repeated, repeating step 2-1. At this time, the maximum current A of the oil well motor on the 4th day is... i It is 19.5A, compared to the maximum current (A) of the oil well motor. i The rate of change was -11.36%;

[0070] Steps 2-5: Maximum current A of oil well motor i The rate of change was -11.36%, and the "powder kiln" in the wellbore of well XX-24 has been established;

[0071] Step S3 can also be considered: During normal oil well production, the amount and cycle of adding the wax-removing and viscosity-reducing agent should be determined according to "A method for determining the addition time of wax-removing agent in oil wells disclosed in CN107724999 B", "A method for determining the wax-removing and viscosity-reducing effect of oil wells with water content of more than 50% and its application disclosed in CN 108169068 B", and "A method and apparatus for evaluating the viscosity-reducing effect of viscosity-reducing agent in oil wells disclosed in CN 104265282 B".

[0072] After the application of XX-24 well, the oil well can produce normally after being put into production or after pumping is started.

[0073] Example 3

[0074] In application to well YY-69, the surface crude oil viscosity at 50℃ was 719.05 mPa·s, the well casing inner diameter was 124 mm, the tubing body outer diameter was 73 mm, and the oil pump was used for production.

[0075] Step 1: On the first day of oil well commissioning or pump start-up, the dynamic fluid level H1 of the oil well is measured to be 518m;

[0076] Step 2: Add oil well dewaxing and viscosity reducing agent through the annulus:

[0077] Step 2-1: On the first day, the amount of wax remover and viscosity reducer added to the oil well is 1000 kg. 2-4 hours after adding the wax remover and viscosity reducer, the dynamic fluid level H2 of the oil well is measured to be 526 m. The maximum current A of the oil well motor is tested. i The maximum suspension point load F of the pumping unit is 48A. i It is 73.16 kN.

[0078] Meanwhile, the theoretical height H3 of the fluid level rise in the annulus after adding the oil well dewaxing and viscosity reducing agent is calculated to be 12.66m.

[0079]

[0080] In the formula: V i To determine the volume of oil well dewaxing and viscosity reducing agent to be added, m 3 The calculation method is the ratio of the mass of the oil well dewaxing and viscosity reducing agent to its density, with the density taken as 1; D is the inner diameter of the oil well casing, mm; d is the outer diameter of the oil well tubing, mm; L is the casing length, taken as 1m here; the inner diameter of the oil well casing D and the outer diameter of the oil well tubing d are converted to m in the calculation, and i refers to the 1st, 2nd, 3rd, ... nth day;

[0081] Step 2-2: Compare the changes in the dynamic fluid level of the oil well, comparing H2-H1 with H3. The ratio of H2-H1 to H3 is 1.5825.

[0082]

[0083] Step 2-3: When α in step 2-2 i If the value is between 1.0 and 3.0, repeat step 2-1 on the second day;

[0084] Step 2-4: When step 2-2 reaches the third day, α i The ratio was 0.8163. On the 4th day, the amount of dewaxing and viscosity-reducing agent added to the oil well was 500 kg. The remaining operations were repeated, repeating step 2-1. At this time, the maximum current A of the oil well motor on the 4th day was... i The current is 46A, compared to the maximum current (A) of the oil well motor. i The rate of change was -4.17%; the maximum suspension load F of the pumping unit i It is 74.09 kN, compared to the maximum suspension point load F of the oil well pumping unit. i The rate of change was +2.38%;

[0085] Steps 2-5: Maximum current A of oil well motor i The rate of change was -4.17%, and the maximum suspension load F of the oil well pumping unit. i The rate of change was +2.38%; the "pharmacy" in the wellbore of YY-69 has been established.

[0086] Alternatively, step S3 can be considered: during normal oil well production, the amount and frequency of wax removal and viscosity reduction agent added should be determined according to "A method for determining the addition time of wax removal agent in oil wells disclosed in CN107724999 B", "A method for determining the wax removal and viscosity reduction effect of oil wells with water content of more than 50% and its application disclosed in CN 108169068 B", and "A method and apparatus for evaluating the viscosity reduction effect of viscosity reduction agent in oil wells disclosed in CN 104265282 B".

[0087] After the application of YY-69 well, the oil well can produce normally after being put into production or after pumping is started.

[0088] The method of expression of this invention is well known to those skilled in the art.

[0089] The above embodiments have provided a detailed description of the present invention, but the content described is only a preferred embodiment of the present invention and should not be considered as limiting the scope of the present invention. All equivalent variations and improvements made within the scope of the present invention should still fall within the patent coverage of the present invention.

Claims

1. A method for establishing a heavy oil wellbore chemical storage facility, characterized in that, Includes the following steps: S1: Measure the dynamic fluid level H1 of the oil well on the first day of oil well commissioning or pump testing; S2: Add oil well dewaxing and viscosity reducing agent from the annulus of the oil casing. By adjusting the amount of oil well dewaxing and viscosity reducing agent added, a "chemical tank" is established in the wellbore of heavy oil development. The method described above for adding oil well dewaxing and viscosity reducing agent from the annulus of the oil casing, and adjusting the amount of oil well dewaxing and viscosity reducing agent added to establish a "chemical field" in the heavy oil development wellbore, is as follows: S2-1: Add 1000 kg of oil well dewaxing and viscosity reducing agent. After adding the agent for 2-4 hours, measure the dynamic fluid level H2 of the oil well and test the maximum current A of the oil well motor. i Or, test the maximum current (A) of the oil well motor. i and the maximum suspension point load F of the pumping unit i Simultaneously, obtain the theoretical height H3 of the fluid level rise in the annulus of the oil casing after adding the oil well dewaxing and viscosity reducing agent; S2-2: Compare the changes in the dynamic fluid level of the oil well and obtain the comparison value. : ； S2-3: When obtained If the value is between 1.0 and 1.2, repeat step S2-1 on the second day; S2-4: When obtained If the value is between 0.5 and 1.0, repeat operation step S2-1 and adjust the amount of oil well dewaxing and viscosity reducing agent added to 500 kg; at this time, compare the rate of change of the maximum current of the oil well motor and the maximum suspension point load of the pumping unit. S2-5: When the maximum current of the oil well motor and the maximum suspension point load change rate of the pumping unit are both within ±20%, the heavy oil development wellbore "pharmacy" is established; or when the maximum current of the oil well motor and / or the maximum suspension point load change rate of the pumping unit both exceed ±20%, then repeat step S2-1 the next day.

2. The method for establishing a heavy oil wellbore chemical storage facility according to claim 1, characterized in that, In step S2-1, the theoretical height H3 of the fluid level rise in the annulus after adding the oil well dewaxing and viscosity reducing agent is: ； In the formula: V i The volume of the dewaxing and viscosity-reducing agent added to the oil well; D is the inner diameter of the oil well casing; d is the outer diameter of the oil well tubing; L is the casing length, which is 1 meter here; i is the 1st, 2nd, 3rd, ... nth day.

3. The method for establishing a heavy oil wellbore chemical storage facility according to claim 1, characterized in that, In step S2-1, for surface-driven screw pump oil wells, the maximum current A of the oil well motor is tested. i .

4. The method for establishing a heavy oil wellbore chemical storage facility according to claim 1, characterized in that, In step S2-1, for pumping unit wells, the maximum current A of the well motor is tested. i and the maximum suspension point load F of the pumping unit i .

5. The method for establishing a heavy oil wellbore chemical storage facility according to claim 1, characterized in that, The oil well dewaxing and viscosity reducing agent in step S2 includes at least one of FV-1, HQAD-1, and HQ-2.

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