CN105649603A - A method for real-time testing of fluid accumulation in wellbore of gas wells - Google Patents

Abstract

The invention belongs to the field of gas well testing, and particularly relates to a method for testing the liquid accumulation volume of a gas well shaft in real time. When the accumulated liquid amount needs to be tested, a test instruction is issued, and the liquid level depth in the casing, the casing wellhead pressure and the oil pipe wellhead pressure are measured simultaneously. And then the test data is substituted into the corresponding mathematical model, so that the liquid level depth of the oil pipe and the total liquid volume of the shaft can be deduced, the test interval time is shortened at lower cost, the in-time test of the liquid volume of the shaft is realized, and the defects in the prior art are overcome.

Description

A method for real-time testing of fluid accumulation in wellbore of gas wells

technical field

The invention belongs to the field of gas well testing, and in particular relates to a method for real-time testing of the liquid accumulation in the wellbore of a gas well, which is used for real-time testing and derivation of the liquid accumulation in the wellbore of the gas well.

Background technique

During the production process of the gas well, there will be fluid accumulation. When the amount of liquid accumulation is too high, the gas production rate will decrease, and even the gas well will be scrapped. In order to solve this problem in the gas field, it is necessary to take measures to drain the wellbore. However, the volume of effusion varies and the required drainage protocol varies. If the measures are not taken properly, it will lead to insufficient drainage or high cost. Therefore, it is very necessary to test the wellbore fluid volume before drainage.

At present, gas fields use down pressure gauges to test the pressure gradient curve in the tubing to identify the position of the tubing liquid level and calculate the volume of fluid accumulation in the tubing. This method has the following disadvantages

1. The cost of testing is high, and each test costs thousands of yuan; it requires a lot of manpower and material resources, and for large fields with many wells, manpower is insufficient;

2. The test interval is long, and the change of the fluid volume cannot be reflected in time;

3. It can only measure the liquid level depth of the oil pipe, but not the liquid level depth of the casing, which is insufficient for calculating the total liquid volume;

4. For some wells with limited inner diameter of tubing, the pressure gauge cannot pass through and cannot be tested.

Contents of the invention

The purpose of the present invention is to make up for the existing deficiencies in the test of liquid accumulation in gas fields, provide a method for real-time testing of the liquid accumulation in the wellbore of a gas well, shorten the test interval time at a lower cost, and realize the timely measurement of the liquid accumulation in the wellbore. test.

For this reason, the present invention provides a kind of method of real-time testing gas well borehole fluid volume, comprises the steps:

Step 1. Install instruments: Install a liquid level tester for measuring liquid level and a casing pressure transmitter for measuring casing pressure at the casing joint of the gas tree, and make the liquid level tester and casing pressure transmitter The test ports of the oil pressure transmitter are all connected to the casing; the oil pressure transmitter for measuring the pressure of the oil pipe is installed at the oil pipe joint of the gas tree, and the test port of the oil pressure transmitter is connected with the oil pipe; the liquid level tester, The casing pressure transmitter and the oil pressure transmitter are connected to the server of the control center through the GPRS wireless network;

Step 2. Through the control of the server, use the liquid level tester to measure the casing liquid level depth S ₁ at that time, use the casing pressure transmitter to measure the casing pressure P ₁ , and use the oil pressure transmitter to measure the tubing pressure P2 _;

Step 3: Find out the density ρ 1 of the gas in the casing according to the comparison table of casing pressure and gas density combined with the casing pressure value P ₁ , and find out the gas density ρ ₁ in the casing according to the comparison table of oil pipe pressure and gas density combined with the pressure value P ₂ of the oil pipe. The density ρ ₂ of the gas;

Step 4: According to ρ ₁ , ρ ₂ , S ₁ , combined with the known effusion density ρ ₃ , calculate the depth S ₂ of the tubing liquid level;

Step 5: According to the inner diameter of the casing D ₁ , the inner diameter of the tubing D ₂ , the depth of the liquid level in the casing S ₁ , the depth of the liquid level in the tubing S ₂ , and the total depth of the casing S ₃ , the amount of liquid accumulated in the wellbore Q is calculated.

The liquid level tester is a permanent echo method liquid level tester, which measures the depth of the casing liquid level by echolocation.

In the second step, the server periodically sends test instructions to control the liquid level tester, casing pressure transmitter and oil pressure transmitter for real-time testing.

In the step 4, the oil pipe liquid level depth S2 is calculated and obtained by the following _formula :

In the formula: ρ ₁ —— is the density of the gas in the casing, which can be determined according to P ₁ look-up table;

ρ ₂ —— is the density of the gas in the tubing, which can be determined according to P ₂ look-up table;

ρ ₃ —— is the density of effusion, which is a known quantity;

S ₁ —— is the depth of the liquid level in the casing, which is the measured value;

S ₂ —— is the liquid level depth in the oil pipe.

In the step 5, the liquid accumulation Q in the wellbore is calculated and obtained by the following formula:

In the formula: D ₁ —— is the inner diameter of casing, which is a known quantity;

D ₂ —— is the inner diameter of oil pipe, which is a known quantity;

S ₁ —— is the depth of the liquid level in the casing, which is the measured value;

S ₂ —— is the liquid level depth in the oil pipe;

S ₃ —— is the total depth of the casing, which is a known quantity;

Q——is the amount of liquid accumulation in the wellbore.

Beneficial effects of the present invention: the method for real-time testing of fluid accumulation in the wellbore of gas wells of the present invention shortens the test interval at a relatively low cost and realizes timely testing of the fluid accumulation in the wellbore to make up for the shortcomings of the prior art.

Description of drawings

The present invention will be described in further detail below in conjunction with the accompanying drawings.

Fig. 1 is a schematic diagram of instrument installation of the present invention.

Fig. 2 is a schematic diagram of the testing principle of the present invention.

Explanation of reference signs: 1. Liquid level tester; 2. Gas tree; 3. Casing pressure transmitter; 4. Oil pressure transmitter.

detailed description

Example 1:

This embodiment provides a method for real-time testing of the liquid accumulation in the wellbore of a gas well, including the following steps:

Step 1. Install the instrument: As shown in Figure 1, install the liquid level tester 1 for measuring the liquid level and the casing pressure transmitter 3 for measuring the casing pressure at the casing joint of the gas tree 2, and make the liquid level The test ports of tester 1 and casing pressure transmitter 3 are connected to the casing; oil pressure transmitter 4 for measuring tubing pressure is installed at the oil pipe joint of gas tree 2, and the oil pressure transmitter The test port of 4 is communicated with the oil pipe; connect the liquid level tester 1, casing pressure transmitter 3 and oil pressure transmitter 4 with the server of the control center through the GPRS wireless network;

Step 2. Through the control of the server, use the liquid level tester 1 to measure the depth S ₁ of the casing liquid level at that time. The liquid level tester 1 here is a permanent echo method liquid level tester, and the casing is measured by echolocation Depth of the liquid level, the casing pressure P ₁ is measured by the casing pressure transmitter 3, and the oil pipe pressure P ₂ is measured by the oil pressure transmitter 4;

Step 3: Find out the density ρ 1 of the gas in the casing according to the comparison table of casing pressure and gas density combined with the casing pressure value P ₁ , and find out the gas density ρ ₁ in the casing according to the comparison table of oil pipe pressure and gas density combined with the pressure value P ₂ of the oil pipe. The density ρ ₂ of the gas;

Step 4: According to ρ ₁ , ρ ₂ , S ₁ , combined with the known effusion density ρ ₃ , calculate the depth S ₂ of the tubing liquid level;

In step 4, the oil pipe liquid level depth S2 is calculated by the following formula, combined with Figure ₂ :

In the formula: ρ ₁ —— is the density of the gas in the casing, which can be determined according to P ₁ look-up table;

ρ ₂ —— is the density of the gas in the tubing, which can be determined according to P ₂ look-up table;

ρ ₃ —— is the density of effusion, which is a known quantity;

S ₁ —— is the depth of the liquid level in the casing, which is the measured value;

S ₂ —— is the liquid level depth in the oil pipe.

Step 5: According to the inner diameter of the casing D ₁ , the inner diameter of the tubing D ₂ , the depth of the liquid level in the casing S ₁ , the depth of the liquid level in the tubing S ₂ , and the total depth of the casing S ₃ , the amount of liquid accumulated in the wellbore Q is calculated.

In Step 5, the amount of liquid accumulated in the wellbore Q is calculated by the following formula, combined with Figure 2:

In the formula: D ₁ —— is the inner diameter of casing, which is a known quantity;

D ₂ —— is the internal diameter of oil pipe, which is a known quantity;

S ₁ —— is the depth of the liquid level in the casing, which is the measured value;

S ₂ —— is the liquid level depth in the oil pipe;

S ₃ —— is the total depth of the casing, which is a known quantity;

Q——is the amount of liquid accumulation in the wellbore.

In the above step 2, the server periodically sends test instructions to control the liquid level tester 1, the casing pressure transmitter 3 and the oil pressure transmitter 4 to perform real-time testing.

After adopting the method for real-time testing of the fluid volume in the wellbore, the fluid volume test can be performed at any time by issuing an instruction from the server, or can be automatically tested according to a predetermined time. The initial installation cost of the invention is approximately equal to the original process interval test cost in the life cycle, and the later test cost is close to zero. The test accuracy of effusion volume can reach 10%, which meets the needs of work. Real-time data testing of batch wells is realized without increasing cost.

The test error of the echo method liquid level tester is far smaller than the data derivation error. If it is necessary to further improve the test accuracy, or to conduct tests in gas wells where the pressure gauge cannot pass, it is only necessary to replace the mathematical model (calculation formula) without increasing hardware costs.

To sum up, in the method for real-time testing of gas well wellbore liquid volume of the present invention, a permanent echo method liquid level tester and a pressure transmitter are installed at the casing joint of the gas well X-mas tree, and at the same time, the gas well X-mas tree A pressure transmitter is installed at the oil pipe joint. When it is necessary to test the amount of liquid accumulation, a test command is issued, and the liquid level depth in the casing, the wellhead pressure of the casing and the wellhead pressure of the tubing are measured at the same time. Substituting the test data into the corresponding mathematical model, the depth of the tubing liquid level and the total fluid accumulation in the wellbore can be deduced, the test interval can be shortened at a lower cost, and the timely testing of the fluid accumulation in the wellbore can be realized to make up for the existing technology. lack of.

The above examples are only illustrations of the present invention, and do not constitute a limitation to the protection scope of the present invention. All designs that are the same as or similar to the present invention fall within the protection scope of the present invention.

Claims (5)

1. A method for real-time testing of gas well wellbore fluid volume, characterized in that: comprise the steps: Step 1. Install instruments: install the liquid level tester (1) for measuring the liquid level and the casing pressure transmitter (3) for measuring the casing pressure at the casing joint of the gas tree (2), and make the liquid level The test ports of the tester (1) and the casing pressure transmitter (3) are connected to the casing; the oil pressure transmitter (4) for measuring the pressure of the tubing is installed at the tubing joint of the gas tree (2), And connect the test port of the oil pressure transmitter (4) to the oil pipe; connect the liquid level tester (1), casing pressure transmitter (3) and oil pressure transmitter (4) through the GPRS wireless network Both communicate with the server in the control center; Step 2. Through the control of the server, use the liquid level tester (1) to measure the casing liquid level depth S ₁ at that time, use the casing pressure transmitter (3) to measure the casing pressure P ₁ , and use the oil pressure variable The oil pipe pressure P ₂ is measured by the transmitter (4); Step 3: Find out the density ρ 1 of the gas in the casing according to the comparison table of casing pressure and gas density combined with the casing pressure value P ₁ , and find out the gas density ρ ₁ in the casing according to the comparison table of oil pipe pressure and gas density combined with the pressure value P ₂ of the oil pipe. The density ρ ₂ of the gas; Step 4: According to ρ ₁ , ρ ₂ , S ₁ , combined with the known effusion density ρ ₃ , calculate the depth S ₂ of the tubing liquid level; Step 5: According to the inner diameter of the casing D ₁ , the inner diameter of the tubing D ₂ , the depth of the liquid level in the casing S ₁ , the depth of the liquid level in the tubing S ₂ , and the total depth of the casing S ₃ , the amount of liquid accumulated in the wellbore Q is calculated. 2. The method for real-time testing of fluid volume in a gas well wellbore according to claim 1, characterized in that: the liquid level tester (1) is a permanent echo method liquid level tester, and the casing is measured by echolocation liquid depth. 3. The method for real-time testing of gas well wellbore liquid volume according to claim 1 or 2, characterized in that: in the second step, the server periodically sends test instructions to control the liquid level tester (1), casing pressure The transmitter (3) and the oil pressure transmitter (4) are tested in real time. 4. the method for real-time testing gas well shaft fluid volume as claimed in claim 3, is characterized in that: in described step 4, tubing liquid level depth S2 calculates and obtains by following _formula : In the formula: ρ ₁ —— is the density of the gas in the casing, which can be determined according to P ₁ look-up table; ρ ₂ —— is the density of the gas in the tubing, which can be determined according to P ₂ look-up table; ρ ₃ —— is the density of effusion, which is a known quantity; S ₁ —— is the depth of the liquid level in the casing, which is the measured value; S ₂ —— is the liquid level depth in the oil pipe. 5. the method for real-time testing gas well shaft fluid volume as claimed in claim 3, is characterized in that: in described step 5, the fluid volume Q in the wellbore is calculated and obtained by the following formula: In the formula: D ₁ —— is the inner diameter of casing, which is a known quantity; D ₂ —— is the inner diameter of oil pipe, which is a known quantity; S ₁ —— is the depth of the liquid level in the casing, which is the measured value; S ₂ —— is the liquid level depth in the oil pipe; S ₃ —— is the total depth of the casing, which is a known quantity; Q——is the amount of liquid accumulation in the wellbore.