Gas reservoir production oil pipe and underground throttling design simulator

Abstract

The invention discloses a gas reservoir production oil pipe and underground throttling design simulator. The invention belongs to the technical field of shaft blockage prevention. The process for simulating the design parameters by using the gas reservoir production comprehensive model tubechoke.xlsx comprises the following steps: (1) predicting production parameters under different oil pipe diameters and different flow pressures; (2) calculating minimum critical liquid-carrying distribution and minimum erosion flow distribution of a shaft according to the pressure and temperature distribution of the shaft and a well structure, thereby determining the optimal diameter of an oil pipe and the flow pressure and yield at the bottom of the well; (3) determining the dosage and injection position of a hydrate inhibitor according to the yield, shaft pressure and temperature distribution and hydrate formation conditions; and (4) according to the yield, the shaft pressure and temperature distribution and the hydrate forming condition, the lowest tripping-in depth and the throttle nozzle diameter of the underground throttle are determined. The method and the simulator can guide the design for preventing shaft hydrate blockage and the design for preventing shaft accumulated liquid blockage, and the safe production of an oil and gas well is ensured.

Description

Technical Field

[0001] The invention belongs to the technical field of gas reservoir wellbore blockage prevention. Background Art

[0002] Hydrate blockage is a common phenomenon in gas field exploitation. Under certain pressure and temperature conditions, the fluid in the oil and gas reservoir forms solid crystals with water, thereby blocking the oil and gas production wellbore or pipeline and causing a production stoppage accident. Production stoppage not only delays oil and gas production, but also generates high processing costs. Therefore, prevention and treatment measures for hydrate blockage need to be considered in the production design stage of oil and gas reservoirs. At present, the industry adopts the addition of thermodynamic inhibitors [Yousif, OTC8234, 1996], or kinetic inhibitors, or pressure reduction, or insulation, or heating, or dehydration, or downhole throttling [Wang Faqing et al., Drilling and Production Technology, Vol. 40, No. 4, 2017], or a combination of the above methods to prevent hydrate blockage.

[0003] Thermodynamic inhibitors commonly used in industry are methanol or ethylene glycol to inhibit hydrate formation. If 10 cubic meters of water are produced per day, 0.2 cubic meters of methanol needs to be added to each cubic meter of water to inhibit hydrate formation. The cost of each ton of methanol is 3,000 yuan. Therefore, the daily cost of methanol required to inhibit hydrate formation in the well is about 5,000 yuan, and the annual cost of methanol per well is about 1.8 million yuan. The annual cost of methanol to inhibit hydrate formation in 11 wells on the offshore platform is 20 million yuan.

[0004] The downhole throttling technology of gas wells places the downhole throttling device at a certain position of the oil pipe to achieve wellbore throttling and pressure reduction, and makes full use of geothermal heating to make the gas flow temperature after throttling higher than the hydrate formation temperature, thereby reducing the wellhead pressure and ground pipeline pressure, eliminating the ground heating and insulation device, throttling the investment in alcohol injection pipelines and alcohol injection equipment and the cost of hydrate inhibitors, and reducing the cost of gas well production and management. This process has been widely used in oil and gas fields. In order to effectively prevent the formation of hydrates, the prediction of downhole throttling temperature drop and the prediction of hydrate formation conditions are crucial to the reasonable setting of downhole throttling process parameters. The throttling device insertion depth and throttling nozzle diameter are the key factors for the success of downhole throttling [Zhou Xingfu, Drilling and Production Technology, Vol. 30, No. 1, 2007]. The design of downhole throttling parameters of gas wells generally adopts the natural gas single-phase or quasi-single-phase throttling nozzle flow model. The Fortunati model, Perkins model, Wang Jinghang model, Xue Jianqiang model, etc. consider the influence of liquid production on nozzle flow.

[0005] Wellbore blockage due to liquid accumulation is also a common phenomenon in gas field exploitation. Liquid accumulation can sometimes completely kill the gas well. Therefore, the liquid carrying capacity of the gas well must be considered when designing the gas well to prevent hydrates. The minimum liquid carrying flow rate of the gas well is an important parameter in the preparation of the gas reservoir development plan. The accurate prediction of the minimum critical liquid carrying flow rate is of great significance to the optimization of the gas well working system and the design to prevent wellbore blockage. The minimum critical liquid carrying flow rate depends on the main factors such as the tubing diameter, bottom hole flow pressure, well type, and downhole throttling. Downhole throttling causes the throttle outlet pressure to drop and increases the upper wellbore liquid carrying capacity. Domestic and foreign scholars have proposed many critical liquid carrying models for the problem of gas well liquid accumulation. Among them, the critical liquid carrying velocity model proposed by Turner in 1969 based on the droplet force analysis is currently the most widely used gas well critical liquid carrying model. Because the prediction results of the Turner model are too large, domestic and foreign scholars Coleman, Nosseir, Sutton, Li Min [Fault Block Oil and Gas Field, Vol. 9, No. 6, 2002] and others have revised the Turner model. With the widespread application of complex wells such as horizontal wells in oil and gas fields, Belfroid, Jiang Jian [Natural Gas and Oil, Vol. 30, No. 3, 2012], Zhou Jian, Huang Quanhua, etc. proposed a calculation model for the minimum liquid carrying capacity of inclined wells and horizontal wells.

[0006] The gas reservoir development and production system can be divided into three subsystems: reservoir-wellbore-surface pipeline. These three subsystems are interconnected, and the state design of the system is subject to the constraints of each subsystem, including water cone, sand production, liquid carrying, hydrate, wax accumulation, corrosion, erosion, etc. The node system analysis method is a powerful tool for optimizing single well production. It has been widely used in production optimization design, dynamic analysis and other fields, and has gradually become an indispensable analytical method for optimizing production. Using experimental equipment to study the formation conditions of fluid hydrates is the basis for preventing hydrate blockage [Chen Weidong et al., JNOC, 1998; Chemical Engineering, Vol. 58, No. 21, 2007]. When there is no measured data, it is necessary to use correlation formulas or models to predict the formation conditions of hydrates [Guo Ping et al., Science, Technology and Engineering, Vol. 18, No. 29, 2018]. Summary of the invention

[0007] The present invention uses the node analysis method to couple various models to form a comprehensive gas reservoir production model to solve the problems of wellbore liquid accumulation and wellbore hydrate blockage during gas reservoir production. To solve the problem of liquid accumulation blockage, the present invention optimizes the oil pipe diameter, bottom hole flow pressure and horizontal well deflection angle. To solve the hydrate blockage problem, the present invention uses the injection of thermodynamic inhibitors to inhibit hydrate formation or uses downhole chokes to prevent hydrate formation. Figure 1 , Figure 1It shows that: (1) With the increase of methanol inhibitor content in water, the hydrate formation curve moves to the left, so that the non-hydrate formation area on the right increases; (2) When the wellhead operating pressure is 15Mpa and the operating temperature is 290K, 4% methanol needs to be added to make the wellhead fluid in the non-hydrate formation area; (3) When a downhole throttle is installed at a certain position in the wellbore to reduce the pressure above the throttle, and the wellhead pressure is reduced from 15Mpa before throttling to 8Mpa or lower wellhead pressure after throttling, the wellhead operating conditions are below the hydrate formation curve and hydrates are not formed. The present invention is based on Figure 1 The principle of the gas reservoir production tubing and downhole throttling design simulator tubechoke.xlsx was developed to analyze the influence of tubing diameter, bottom hole flow pressure, horizontal well deflection angle and downhole throttling on wellbore liquid carrying, and then analyze the influence of chemical inhibitor dosage and downhole throttling on hydrate formation. The process steps of designing parameters using the comprehensive gas reservoir production model tubechoke.xlsx simulator are as follows: (1) predicting production parameters under different tubing diameters and different flow pressures; (2) calculating the minimum critical liquid carrying distribution and minimum erosion flow distribution of the wellbore according to the wellbore pressure and temperature distribution and well structure, thereby determining the optimal tubing diameter, bottom hole flow pressure and production; (3) determining the dosage and injection position of hydrate inhibitor according to the production, wellbore pressure and temperature distribution and hydrate formation conditions; (4) determining the minimum depth of the downhole throttle and the throttle mouth diameter according to the production, wellbore pressure and temperature distribution and hydrate formation conditions. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] The accompanying drawings can clearly illustrate the principles of the present invention and the effects of the embodiments of the present technical solution, but they do not limit the claims of the present invention. In the accompanying drawings:

[0009] Figure 1 .Effects of methanol content and downhole throttling on wellhead hydrate formation,

[0010] Figure 2 Example 1 Production and minimum liquid carrying capacity of different tubing diameters at different bottom hole pressures,

[0011] Figure 3 Example 1: The amount of methanol used to suppress hydrate changes with ambient temperature during steady-state production at a bottom hole pressure of 35 MPa.

[0012] Figure 4 Example 1: The temperature of the wellbore fluid and the temperature of the wellbore hydrate before and after throttling vary with the depth of the well.

[0013] Figure 5 Example 2 Effect of tubing diameter and deflection angle on liquid carrying capacity under different bottom hole pressures,

[0014] Figure 6Example 2 Effect of horizontal well length on wellhead hydrate formation when bottom hole pressure is 49 MPa and inclination is 45 degrees.

[0015] Figure 7 Example 2: The minimum liquid carrying capacity before and after throttling varies with the well depth.

[0016] Figure 8 Example 3 Effect of tubing diameter and deflection angle on liquid carrying capacity under different bottom hole pressures,

[0017] Fig. 9 Example 3 Effect of branch length on wellhead hydrate formation. DETAILED DESCRIPTION

[0018] The process steps of the present invention using the comprehensive gas reservoir production model tubechoke.xlsx to simulate the design parameters are as follows: (1) predicting production parameters under different tubing diameters and different flow pressures; (2) calculating the minimum critical liquid carrying distribution and the minimum erosion flow distribution of the wellbore based on the wellbore pressure and temperature distribution and the well structure, thereby determining the optimal tubing diameter and the bottom hole flow pressure and production; (3) determining the amount and injection position of the hydrate inhibitor based on the production, wellbore pressure and temperature distribution and hydrate formation conditions; (4) determining the minimum insertion depth and choke mouth diameter of the downhole choke based on the production, wellbore pressure and temperature distribution and hydrate formation conditions. To further illustrate the content, features and efficacy of the present invention, the following examples are listed to illustrate the tubechoke.xlsx simulator:

[0019] Example 1 (vertical well): A natural gas reservoir is 2557m deep, with a bottom hole pressure of 44.61Mpa, a gas reservoir temperature of 116.15 degrees, a natural gas specific gravity of 0.65, a gas layer thickness of 14m, a gas layer permeability of 0.4md, a skin factor of 0, and a vertical well gas reservoir drainage radius of 274m. The calculation results of using the tubechokecal.xlsx simulator to design the diameter of the vertical well production tubing and the downhole choke are as follows Figures 2 to 4 .

[0020] Figure 2 The results are as follows: (1) The influence of tubing diameter on the minimum liquid carrying flow rate is greater than that of bottom hole flow pressure; (2) The smaller the tubing diameter, the smaller the minimum liquid carrying flow rate; (3) When the tubing diameter is 0.062m and the bottom hole flow pressure is greater than 32Mpa, the calculated well production capacity is less than the required minimum liquid carrying flow rate, so it is decided to select a tubing diameter of 0.0507m; (4) The well production capacity is far less than the minimum erosion flow rate of 282461m 3 / d, so no erosion damage occurs to the wellbore.

[0021] Figure 3The results are as follows: (1) When the bottom hole flowing pressure is 35 MPa and the production is steady, the amount of methanol required to inhibit the formation of wellbore hydrates during the production process increases with the decrease of ambient temperature and with the increase of water production; (2) The effect of water production on methanol consumption is more obvious than the effect of ambient temperature on methanol consumption.

[0022] Figure 4 The results are as follows: (1) When there is no downhole throttle, the wellbore fluid temperature curve and the wellbore hydrate formation curve intersect at a depth of 200 meters. Therefore, the wellbore hydrate formation area is from the wellhead to 200 meters downhole, and chemical inhibitors need to be injected to ensure that the wellbore is not blocked by hydrates; (2) After the downhole throttle is installed, the wellbore fluid temperature curve is higher than the wellbore hydrate formation curve, so the wellbore will not be blocked by hydrates; (3) According to the hydrate formation conditions and production capacity, the downhole throttle installation depth is determined to be below 1600 meters, and the nozzle diameter is 2.62 mm.

[0023] Embodiment 2 (horizontal well): A condensate gas reservoir has a depth of 3600m, a bottom hole pressure of 55Mpa, a gas reservoir temperature of 100 degrees, a gas layer thickness of 10m, a gas layer permeability of 0.75md, a skin factor of 0, a gas reservoir discharge radius of 600m, a vertical length of the horizontal well deflection section of 100 meters, a deflection angle of 45 degrees, and a condensate gas composition of 0.0026N2+0.0206CO2+0.8279C1+0.0719C2+0.0229C3+0.0058IC4+0.0084C4+0.0015IC5+0.0014C5+0.0007C6+0.0373C7P, a C7P molecular weight of 140, a C7P density of 0.78, and a minimum ground temperature of minus 30 degrees. The calculation results of using tubechokecal.xlsx simulator to design the diameter of horizontal well production tubing and downhole throttling are as follows Figures 5 to 7 . Figure 5 The results are as follows: (1) The effect of the inclination angle on the minimum liquid carrying flow rate is greater than that of the bottom hole flow pressure on the minimum liquid carrying flow rate; (2) When the bottom hole flow pressure is less than 49 MPa, the gas reservoir production capacity can meet the minimum liquid carrying requirements under different tubing diameters and different inclinations, so the tubing diameter is selected as 0.0507 m; (3) When the bottom hole flow pressure is 49 MPa, the tubing diameter is 0.0507 m, and the horizontal well length is 100 m, the calculated well production capacity is 40300 m 3 / d is much smaller than the minimum erosion flow rate of 268180m / d calculated under this condition. 3 / d, so no erosion damage will occur to the wellbore.

[0024] Figure 6The results are as follows: (1) As the length of the horizontal well increases, the wellhead fluid temperature increases; (2) When the horizontal well length is less than 250 m, the wellhead fluid temperature is less than the wellhead hydrate formation temperature, so hydrates will form at the wellhead; (3) When the horizontal well length is greater than 250 m, the wellhead fluid temperature is greater than the wellhead hydrate formation temperature, so hydrates will not form at the wellhead. Figure 7 The results are as follows: (1) When the horizontal well length is 500m, the inclination angle is 45 degrees, the wellbore diameter is 0.0507m, and the bottom hole flow pressure is 48Mpa, the calculated production capacity is 67939m 3 / d, minimum liquid carrying capacity is 48014m 3 / d, wellhead flow pressure 36.38Mpa, wellhead flow temperature 311.32K, wellhead hydrate formation temperature 306K, so the horizontal well production capacity is greater than the minimum liquid carrying flow rate without liquid accumulation blockage, wellbore fluid temperature is greater than the hydrate formation temperature without hydrate blockage; (2) After the downhole choke is installed at the horizontal well position, the minimum liquid carrying flow rate is 48014m 3 / d reduced to 26478m 3 / d and helps in liquid carrying production.

[0025] Example 3 (branch well): The permeability of a gas reservoir is 3md, the gas layer thickness is 5m, and the drainage area is 600m 2 , the gas reservoir pressure and temperature are 18Mpa and 360K respectively, and the well depth is 1800m. The vertical distance of the horizontal well deflection section is 100m, the deflection angle is 45 degrees, and the horizontal well trunk length is 500m. Four equally spaced branches are drilled by the horizontal well, the distance between the branches in the same direction is 200m, the angle between the branch and the trunk is 30 degrees, and the absolute roughness of the wellbore is 0.00036m. The specific gravity of natural gas is 0.588. The ambient ground temperature is 4 degrees. The calculation results of using the tubechokecal.xlsx simulator to design the branch well production tubing diameter and downhole throttling are as follows Figures 8 to 9 . Figure 8 The results are as follows: (1) The effect of the inclination angle on the minimum liquid carrying flow rate is greater than that of the bottom hole flow pressure; (2) When the bottom hole flow pressure is 16 MPa, the gas reservoir production capacity can meet the minimum liquid carrying requirement when the tubing diameter is 0.0507 m, but the gas reservoir production capacity cannot meet the minimum liquid carrying requirement when the tubing diameter is 0.062 m, so the tubing diameter is 0.0507 m; (3) However, when the bottom hole flow pressure is 16 MPa, the tubing diameter is 0.0507 m, and the branch length is 100 m, the branch well production capacity is 49053 m 3 / d is much smaller than the minimum erosion flow rate of 332178m / d calculated under this condition. 3 / d, so no erosion damage will occur to the wellbore.

[0026] Fig. 9The results are as follows: (1) As the branch length increases, the wellhead fluid temperature increases; (2) When the bottomhole flow pressure is 16 MPa, when the branch length increases to the maximum value of 600 m, the wellhead fluid temperature is still lower than the wellhead hydrate formation temperature, so hydrates will form at the wellhead; (3) When the bottomhole flow pressure is 14 MPa, no matter how long the branch length is, the wellhead fluid temperature is always higher than the wellhead hydrate formation temperature, so hydrates will not form at the wellhead.

Claims

1. Gas reservoir production tubing and downhole throttling design simulator, which is characterized by The comprehensive gas reservoir production model tubechoke.xlsx is used to analyze the effects of factors such as tubing diameter, bottom hole flow pressure, horizontal well deflection angle and downhole throttling on wellbore liquid carrying, analyze the effects of chemical inhibitor dosage and downhole throttling on hydrate formation, and analyze the effects of other factors on production optimization design. The process steps for designing parameters using the tubechoke.xlsx simulator are as follows: (1) predicting production parameters under different tubing diameters and different flow pressures; (2) calculating the minimum critical wellbore liquid carrying distribution and minimum erosion flow distribution based on the wellbore pressure and temperature distribution and well structure, thereby determining the optimal tubing diameter, bottom hole flow pressure and production; (3) determining the amount of hydrate inhibitor and injection position based on production, wellbore pressure and temperature distribution and hydrate formation conditions; (4) determining the minimum depth of the downhole throttle and the throttle mouth diameter based on production, wellbore pressure and temperature distribution and hydrate formation conditions.

2. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: The comprehensive gas reservoir production model is an integrated model that couples various models such as gas reservoir-wellbore-choke, etc. It can consider the restrictions on production optimization design caused by factors such as water cone, sand production, liquid carrying, hydrate, wax accumulation, corrosion, and erosion.

3. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: Well structures include vertical wells, inclined wells, horizontal wells, and multi-branch wells.

4. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: Use gas reservoir data to calculate the theoretical production capacity of various well structures or use well test production capacity formula to calculate production capacity or other production capacity prediction methods.

5. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: The node analysis method and the comprehensive gas reservoir production model are used to analyze the pressure and temperature distribution at each node of the wellbore, including the bottom of the well, the bottom of the choke, the top of the choke, the wellhead, etc.

6. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: The minimum liquid carrying flow rate model such as Li Min model or Jiang Jian model or other models is used to calculate the minimum liquid carrying flow rate of the gas well.

7. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: Use the Joule-Thomson coefficient method or other methods to calculate the downhole throttling temperature drop.

8. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: Various downhole choke flow models are used to calculate the choke size under production allocation conditions.

9. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: The experimental data fitting formula and empirical formula are used to predict the hydrate formation conditions with an error of less than 2 degrees, which exceeds the existing empirical method. The effects of various inhibitor dosages such as methanol, ethylene glycol, ethanol, and triethylene glycol on the hydrate formation of gas reservoir fluids are analyzed.

10. The gas reservoir production tubing and downhole throttling design simulator according to claim 1 is characterized by: Use a computer and EXCEL office software to run the tubechoke.xlsx simulator to analyze wellbore clogging by fluid accumulation and wellbore hydrate clogging.

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