A method and system for controlling casing pressure in wells with packers and tubing blockage

Abstract

This invention provides a method and system for controlling casing pressure in wells with packers and tubing blockage. It simulates the pressure profile inside the tubing after throttling due to blockage at different nozzle openings. The simulation results are then incorporated into tubing strength verification calculations. Referring to specified safety factor requirements, the maximum allowable casing pressure value under different oil pressures is calculated. Based on this maximum allowable casing pressure value, casing pressure control is performed on the well, forming a calculation method for casing pressure control in wells with packers and tubing blockage. This method guides casing pressure control during well opening and production processes in wells with tubing blockage, preventing tubing string damage, ensuring the wellbore integrity of high-pressure gas wells, and guaranteeing safe operation of gas wells.

Description

Technical Field

[0001] This invention relates to the fields of fluid dynamics and tubing mechanics analysis, specifically to a method and system for controlling casing pressure in wells with packers and tubing blockage. Background Technology

[0002] High-pressure gas wells in the Kuqa foreland of the Tarim Oilfield commonly suffer from tubing blockage. Once a blockage occurs within the wellbore, it triggers downhole throttling and pressure drop. The pressure difference between the tubing pressure above the blockage and the pressure column formed by the annular protective fluid will be greater than normal, increasing the risk of the tubing being crushed by the annular protective fluid. This is especially true during the well restart process after shut-in, when drastic pressure changes can easily cause tubing damage. Currently, the industry's oil-casing pressure management methods only apply to wells without blockages and lack a scientific solution to this problem. Summary of the Invention

[0003] To address the problems existing in the prior art, this invention provides a method for controlling casing pressure in wells with packers that are blocked by tubing. The method simulates the pressure profile inside the tubing after throttling due to tubing blockage, and uses the simulation results to calculate the tubing strength. By referring to the specified safety factor requirements, the maximum allowable casing pressure value under different oil pressures is calculated.

[0004] This invention is achieved through the following technical solution:

[0005] A method for controlling casing pressure in a well with packer-equipped tubing blockage includes the following steps:

[0006] Step 1: Construct the associated formation model, tubing flow channel model, and fluid model;

[0007] Step 2: Change the parameters of the flow channel model in the tubing and conduct pressure and temperature profile simulations in the tubing to obtain pressure and temperature profiles in the tubing under different nozzle openings.

[0008] Step 3: Construct a tubing mechanical model and combine it with the tubing pressure and temperature profiles under different nozzle openings to obtain the maximum allowable casing pressure value under different nozzle sizes. Then, control the casing pressure based on the maximum allowable casing pressure value.

[0009] Preferably, the formation model, the tubing flow channel model, and the fluid model are constructed sequentially using OLGA software.

[0010] Preferably, the formation model includes formation temperature, pressure, and (IPR) inflow dynamics curves.

[0011] Preferably, the tubing flow channel model includes tubing dimensions, tubing insertion depth, packer setting depth, tubing inner wall roughness, clogging location depth, flow channel dimensions at the clogging location, and nozzle dimensions.

[0012] Preferably, the proportion of different hydrocarbon components in the fluid model is determined based on the results of fluid experiment tests.

[0013] Preferably, the tubing mechanical model includes tubing dimensions, tubing steel grade, tubing insertion depth, packer setting depth, annular protection fluid density, and tubing safety factor requirements.

[0014] Preferably, in step 2, the pressure and temperature profiles inside the oil pipe under different nozzle openings are obtained by changing the nozzle size parameters of the flow channel model inside the oil pipe.

[0015] A system for controlling casing pressure in a well with packer-equipped tubing blockage includes:

[0016] The model building module is used to build associated formation models, tubing flow channel models, and fluid models;

[0017] The simulation module is used to simulate the pressure and temperature profile inside the tubing, and obtain the pressure and temperature profile inside the tubing under different nozzle openings.

[0018] The pressure control module is used to construct a tubing mechanical model and, in conjunction with the tubing pressure and temperature profiles under different nozzle openings, obtain the maximum allowable casing pressure value under different nozzle sizes. Based on the maximum allowable casing pressure value, casing pressure control is performed in tubing-clogged wells.

[0019] Compared with the prior art, the present invention has the following beneficial technical effects:

[0020] This invention provides a method for controlling casing pressure in wells with packers that are clogged with tubing. The method simulates the pressure profile inside the tubing after throttling due to different nozzle openings. The simulation results are then incorporated into the tubing strength verification calculation. Referring to specified safety factor requirements, the maximum allowable casing pressure value under different oil pressures is calculated. Based on this maximum allowable casing pressure value, the casing pressure of the well is controlled, forming a calculation method for casing pressure control in wells with packers that are clogged with tubing. This method guides the casing pressure control during well opening and production processes in wells with clogged tubing, avoiding tubing string damage, ensuring the wellbore integrity of high-pressure gas wells, and guaranteeing the safe operation of gas wells. Attached Figure Description

[0021] Figure 1 The temperature and pressure curves inside the oil pipe under the 5mm nozzle in Embodiment 1 of the present invention are shown.

[0022] Figure 2 This is a diagram showing the triaxial stress strength check of the tubing string in Embodiment 1 of the present invention. Detailed Implementation

[0023] The present invention will now be described in further detail with reference to the accompanying drawings. These descriptions are intended to explain the invention and not to limit it.

[0024] A method for controlling casing pressure in wells with packers that experience tubing blockage involves simulating the pressure profile inside the tubing after throttling due to blockage at different nozzle openings. The simulation results are then used in tubing strength verification calculations, and the maximum allowable casing pressure under different oil pressures is calculated by referring to specified safety factor requirements. The specific steps are as follows:

[0025] Step 1: Construct a stratigraphic model.

[0026] In this embodiment, a formation model is constructed in OLGA software, which includes the formation's temperature, pressure, and (IPR) inflow dynamic curves.

[0027] OLGA multiphase flow software is an unsteady-state multiphase flow simulation program that can simulate the movement of oil, gas, and water in oil wells, pipelines, and oil and gas processing equipment. With the increasing emphasis on "flow assurance" in the petroleum industry, OLGA has been widely used in feasibility studies, engineering design, and operational simulation. OLGA is also used to simulate problematic oil wells and pipelines to find solutions, identify optimal operating procedures, and select appropriate control systems. OLGA can also be used for real-time simulation control of normal production processes and as a training simulator for engineers.

[0028] Step 2: Construct a flow channel model inside the tubing.

[0029] A flow path model of the tubing is constructed in OLGA software, which includes tubing size, tubing insertion depth, packer setting depth, tubing inner wall roughness, clogging location depth, flow channel size at the clogging location, and nozzle size.

[0030] Step 3: Construct an in-pipe fluid model in OLGA software based on the in-pipe flow channel model, and determine the proportion of different hydrocarbon components in the fluid based on the fluid experimental test results.

[0031] Step 4: By linking the formation model, the tubing flow channel model, and the fluid model, and changing the nozzle size, simulate the pressure and temperature profiles inside the tubing in OLGA software to obtain the pressure and temperature profiles inside the tubing under different nozzle openings.

[0032] Step 5: Construct a mechanical model of the tubing.

[0033] A tubing mechanics model was constructed in WELLCAT software, which included tubing dimensions, tubing steel grade, tubing insertion depth, packer setting depth, annular protection fluid density, and tubing safety factor requirements.

[0034] Step 6: Perform tubing strength verification in WELLCAT software.

[0035] By substituting the pressure and temperature profiles inside the tubing under different nozzle sizes obtained in step 4 into the model in step 5, the maximum allowable sleeve pressure value under different nozzle sizes can be obtained.

[0036] This invention also provides a system for controlling casing pressure in wells with packers and tubing blockage, comprising,

[0037] The model building module is used to build associated formation models, tubing flow channel models, and fluid models;

[0038] The simulation module is used to simulate the pressure and temperature profile inside the tubing, and obtain the pressure and temperature profile inside the tubing under different nozzle openings.

[0039] The pressure control module is used to construct a tubing mechanical model and, in conjunction with the tubing pressure and temperature profiles under different nozzle openings, obtain the maximum allowable casing pressure value under different nozzle sizes. Based on the maximum allowable casing pressure value, casing pressure control is performed in tubing-clogged wells.

[0040] Example 1

[0041] Take the Keshen XX well in Tarim Oilfield as an example.

[0042] Step 1: Construct the formation model. The formation pressure of this well is 95 MPa, the formation temperature is 120℃, and the gas production index PI is 150,000 m³. 3 / (d·MPa).

[0043] Step 2: Construct the flow channel model inside the tubing. The tubing uses a combination of 4 1 / 2" and 3 1 / 2" tubing. The depth of the 4 1 / 2" tubing is 0-2400m, and the depth of the 3 1 / 2" tubing is 2400-6800m. The packer setting depth is 6500m, the inner wall roughness of the tubing is 0.05mm, the depth of the blockage location is 6510m, the flow channel size at the blockage location is 10mm, and the nozzle size is 10mm when fully open.

[0044] Step 3: Construct an in-pipe fluid model. This well is located in a dry gas reservoir, and the fluid composition is mainly methane.

[0045] Step 4: Conduct a pressure profile simulation inside the tubing. Adjust the nozzle opening to obtain the pressure and temperature profiles inside the tubing under different nozzle openings. Here, only a 5mm nozzle is used as an example. Figure 1 (As shown).

[0046] Step 5: Construct a mechanical model for the tubing. The tubing uses a combination of 4 1 / 2" and 3 1 / 2" tubing. The 4 1 / 2" tubing is used at depths of 0–2400 m, and the 3 1 / 2" tubing at depths of 2400–6800 m. The tubing steel grade is 110. The packer setting depth is 6500 m, and the annulus protection fluid density is 1.4 g / cm³. 3 The safety factor for triaxial stress in the tubing is taken as 1.5.

[0047] Step Six: Conduct tubing strength verification. Substitute the tubing pressure profiles obtained in Step Four for different nozzle sizes into the model from Step Five to obtain the maximum allowable casing pressure for different nozzle sizes. Here, we take a 5mm nozzle as an example; the calculated casing pressure is 1MPa, and the triaxial stress safety factor of the tubing is exactly 1.5. Figure 2 (As shown).

[0048] The above content is only for illustrating the technical concept of the present invention and should not be construed as limiting the scope of protection of the present invention. Any modifications made to the technical solution based on the technical concept proposed in this invention shall fall within the scope of protection of the claims of this invention.

Claims

1. A method for controlling casing pressure in a well with packer-equipped tubing blockage, characterized in that, Includes the following steps: Step 1: Construct the associated formation model, tubing flow channel model, and fluid model; The tubing internal flow channel model includes tubing dimensions, tubing insertion depth, packer setting depth, tubing inner wall roughness, clogging location depth, flow channel dimensions at the clogging location, and nozzle dimensions. Step 2: Change the parameters of the flow channel model in the tubing and conduct pressure and temperature profile simulations in the tubing to obtain pressure and temperature profiles in the tubing under different nozzle openings. Step 3: Construct a tubing mechanical model and combine it with the tubing pressure and temperature profiles under different nozzle openings to obtain the maximum allowable casing pressure value under different nozzle sizes. Then, control the casing pressure based on the maximum allowable casing pressure value.

2. The method for controlling casing pressure in a well with packer-equipped tubing as described in claim 1, characterized in that, The formation model, the tubing flow channel model, and the fluid model were constructed sequentially using OLGA software.

3. The method for controlling casing pressure in a well with a packer as described in claim 1, characterized in that, The formation model includes dynamic curves of formation temperature, pressure, and IPR inflow.

4. The method for controlling casing pressure in a tubing-clogged well with a packer according to claim 1, characterized in that, Based on the results of fluid experiments, the proportion of different hydrocarbon components in the fluid model was determined.

5. The method for controlling casing pressure in a well with packer-equipped tubing as described in claim 1, characterized in that, The tubing mechanical model includes tubing dimensions, tubing steel grade, tubing insertion depth, packer setting depth, annular protection fluid density, and tubing safety factor requirements.

6. The method for controlling casing pressure in a tubing-clogged well with a packer according to claim 1, characterized in that, In step 2, by changing the nozzle size parameters of the flow channel model inside the oil pipe, the pressure and temperature profiles inside the oil pipe under different nozzle openings are obtained.

7. A system for controlling casing pressure in a tubing-clogged well with a packer according to any one of claims 1-6, characterized in that, include: The model building module is used to build associated formation models, tubing flow channel models, and fluid models; The simulation module is used to simulate the pressure and temperature profile inside the tubing, and obtain the pressure and temperature profile inside the tubing under different nozzle openings. The pressure control module is used to construct a tubing mechanical model and, in conjunction with the tubing pressure and temperature profiles under different nozzle openings, obtain the maximum allowable casing pressure value under different nozzle sizes. Based on the maximum allowable casing pressure value, casing pressure control is performed in tubing-clogged wells.

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