Reasonable production allocation determination method for gas well with high water breakthrough risk

Abstract

The invention provides a reasonable production allocation determination method for a gas well with high water breakthrough risk, which comprises the following steps: step 1, formation water invades along a large fracture to cause rapid water breakthrough of the gas well, and the water-invaded gas recovery well is closed until formation water in a shaft and formation water in a reservoir around the well return to a gas-water interface for well opening; 2, the initial daily gas production rate of the gas recovery well test scheme is set; 3, collecting the data of the gas recovery well within a set time period, and judging whether the operation of the gas recovery well is abnormal or not according to the collected data; 4, the daily gas production rate is adjusted according to the judgment result, and the data of the gas production well continues to be observed; 5, the step 3 and the step 4 are repeated until the reasonable production allocation of the gas recovery well is determined; according to the method, coupling balance between the wellbore and the fault and formation water can be achieved, and then the corresponding gas well opening reasonable production allocation is obtained.

Description

Technical Field

[0001] The present invention belongs to the field of gas well exploitation, and in particular relates to a method for determining reasonable production allocation for a gas well with a high water exposure risk. Background Art

[0002] The water invasion problem of gas reservoirs is one of the main problems that plague gas reservoir development, especially for abnormally high-pressure water-containing gas reservoirs. Water invasion of gas reservoirs not only reduces the gas well productivity and shortens the life of gas wells, but also reduces the gas reservoir exploitation degree and final recovery rate. A large number of domestic and foreign literatures have studied the types and causes of water invasion in various types of gas reservoirs. It is particularly important to formulate technical policies for the development of gas reservoirs and gas wells after water breakthrough. One of the more important points is to determine the reasonable production allocation of gas reservoirs and gas wells after water breakthrough, so as to slow down the water invasion speed, protect the pure gas area, extend the life cycle of gas wells and gas reservoirs, and improve the final recovery rate of gas reservoirs.

[0003] At present, the common water invasion mechanisms of fractured water-bearing gas reservoirs are edge water invasion and bottom water invasion, among which: edge water flows along fractures and faults to production wells; bottom water flows along fractures and faults to production wells. When gas-water two-phase flow occurs in gas reservoirs, it manifests itself in three macroscopic phenomena: water sealing, isolation and water flooding of gas, i.e., water invasion. The common point is that formation water blocks the seepage channels of some gas, resulting in a low final recovery rate of the gas reservoir. Summary of the invention

[0004] The purpose of the present invention is to provide a method for determining reasonable production allocation for gas wells with high water risk, which solves the problem of low recovery rate in water-bearing production gas wells due to the fact that bottom water invades the bottom of the well horizontally and vertically along the faults and the actual gas-water interface is located in the lower part of the production layer.

[0005] The present invention provides the best or optimum production allocation for the water-producing gas well, so as to slow down the water invasion speed, protect the pure gas area, extend the life cycle of the gas well and gas reservoir, and improve the final recovery rate of the gas reservoir.

[0006] In order to achieve the above object, the technical solution adopted by the present invention is:

[0007] The present invention provides a method for determining reasonable production allocation of a gas well with a high water breakthrough risk, comprising the following steps:

[0008] Step 1: The formation water invades along the large fault, causing the gas well to see water quickly. The water-invaded gas well is closed until the formation water in the wellbore and the reservoir around the well retreats below the gas-water interface and then the well is opened;

[0009] Step 2, setting the initial daily gas production of the gas production well test plan;

[0010] Step 3, collecting data of the gas well within a set time period, and judging whether the operation of the gas well is abnormal based on the collected data;

[0011] Step 4: adjust the daily gas production according to the judgment result, and continue to observe the data of the gas well;

[0012] Step 5, repeat steps 3 and 4 until a reasonable production allocation of the gas well is determined.

[0013] Preferably, in step 2, the initial daily gas production is the minimum daily gas production process standard of the gas production well.

[0014] Preferably, in step 3, judging whether the operation of the gas well is abnormal based on the collected data, the specific method is:

[0015] If the wellhead oil pressure, temperature, gas production, water production and water-gas ratio in the collected data do not exceed the preset fluctuation range, the gas well is operating normally;

[0016] If any of the wellhead oil pressure, temperature, gas production, water production or water-gas ratio in the collected data exceeds the preset fluctuation range, the gas well is operating abnormally.

[0017] Preferably, in step 4, the daily gas production is adjusted according to the judgment result, and the specific method is:

[0018] If the gas well is operating abnormally, the chloride ions in the water sample of the gas well are obtained, and whether the gas well produces water is determined based on the chloride ions. If the gas well produces water, the daily gas production is reduced, otherwise the daily gas production is increased;

[0019] If the gas well is operating normally, the chloride ions in the water sample of the gas well are obtained, and whether the gas well produces water is determined based on the chloride ions. If the gas well produces water, the daily gas production is reduced, otherwise the daily gas production is increased.

[0020] Preferably, the reduced daily gas production is less than or equal to 20% of the current production.

[0021] A method for determining reasonable production allocation of a gas well with high water breakthrough risk comprises the following steps:

[0022] Step 1, obtaining the static pressure gradient in the pure water section of the wellbore of the water-flooded wellbore and the deep formation pressure in the production layer of the gas production well to be tested in the shut-in state;

[0023] Step 2, calculating the open flow rate of the gas production well to be tested;

[0024] Step 3, obtaining the top elevation depth of the production well section of the gas production well to be tested, the bottom elevation depth of the production well section, and the water source elevation depth that penetrates into the bottom of the well along the fault of the gas production well to be tested;

[0025] Step 4, calculating the production pressure difference required for the gas well to flow the water body at the water source interface into the bottom of the well;

[0026] Step 5, calculate the maximum daily wellhead gas production of the gas production well to be tested without formation water flowing into the bottom of the well, and determine the reasonable production allocation of the gas production well to be tested based on the maximum daily wellhead gas production.

[0027] Preferably, in step 2, the open-flow rate of the gas production well to be tested is calculated using the Great North Point Method empirical formula.

[0028] Preferably, in step 4, the production pressure difference required for the gas production well to flow the water body at the water source interface into the bottom of the well is calculated according to the following formula:

[0029] ΔP=(h2-h3)×G DS-W

[0030] Among them, ΔP is the production pressure difference; h2 is the bottom elevation depth of the production well section; h3 is the water source elevation depth; G DS-W It is the static pressure gradient in the pure water section of the wellbore.

[0031] Preferably, in step 5, the maximum daily gas production at the wellhead without formation water entering the bottom of the well is calculated according to the following formula:

[0032]

[0033] Among them, P R is the formation pressure; q g is the maximum daily gas production at the wellhead; ΔP is the production pressure difference; Q AOF Unimpeded flow.

[0034] Preferably, in step 5, the reasonable production allocation of the gas production well to be tested is determined according to the maximum wellhead daily gas production, and the specific method is:

[0035] The reasonable production allocation for the gas well to be tested is based on a daily gas production rate that is less than or equal to the maximum wellhead gas production rate.

[0036] Compared with the prior art, the present invention has the following beneficial effects:

[0037] The present invention provides a method for determining reasonable production allocation of gas wells with high water-seeping risk. The method is based on the critical water-yielding production pressure difference and aims at water-carrying production wells where edge and bottom water invade horizontally and vertically along faults and enter the well bottom. Since the actual gas-water interface is located in the lower part of the production layer, firstly, it is considered to control the daily gas production and production pressure difference by carrying out a small pressure difference test program to ensure that formation water does not enter the well bottom; secondly, according to the actual water source depth, the longitudinal production pressure difference required for edge and bottom water to invade horizontally and vertically along faults and enter the well bottom is calculated, so as to control the water column invasion height, realize the coupling balance between the wellbore to the fault and the formation water, and then obtain the corresponding reasonable production allocation for gas well opening. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] Figure 1 It is a plan view of a certain water-gas reservoir;

[0039] Figure 2This is a schematic diagram of the north-south gas reservoir section of the S gas reservoir. DETAILED DESCRIPTION

[0040] In the following description, specific details such as specific system structures, technologies, etc. are provided for the purpose of illustration rather than limitation, so as to provide a thorough understanding of the embodiments of the present application. However, it should be clear to those skilled in the art that the present application may also be implemented in other embodiments without these specific details. In other cases, detailed descriptions of well-known systems, devices, circuits, and methods are omitted to prevent unnecessary details from obstructing the description of the present application.

[0041] It should be understood that when used in the present specification and the appended claims, the term "comprising" indicates the presence of described features, wholes, steps, operations, elements and / or components, but does not exclude the presence or addition of one or more other features, wholes, steps, operations, elements, components and / or combinations thereof.

[0042] It should also be understood that the term “and / or” used in the specification and appended claims refers to any and all possible combinations of one or more of the associated listed items, and includes these combinations.

[0043] As used in the specification and appended claims of this application, the term "if" can be interpreted as "when" or "uponce" or "in response to determining" or "in response to detecting", depending on the context. Similarly, the phrase "if it is determined" or "if [described condition or event] is detected" can be interpreted as meaning "uponce it is determined" or "in response to determining" or "uponce [described condition or event] is detected" or "in response to detecting [described condition or event]", depending on the context.

[0044] In addition, in the description of the present application specification and the appended claims, the terms "first", "second", "third", etc. are only used to distinguish the descriptions and cannot be understood as indicating or implying relative importance.

[0045] References to "one embodiment" or "some embodiments" etc. described in the specification of this application mean that one or more embodiments of the present application include specific features, structures or characteristics described in conjunction with the embodiment. Therefore, the statements "in one embodiment", "in some embodiments", "in some other embodiments", "in some other embodiments", etc. that appear in different places in this specification do not necessarily refer to the same embodiment, but mean "one or more but not all embodiments", unless otherwise specifically emphasized in other ways. The terms "including", "comprising", "having" and their variations all mean "including but not limited to", unless otherwise specifically emphasized in other ways.

[0046] Example 1

[0047] This embodiment provides a method for determining reasonable production allocation of a gas well with a high water breakthrough risk. The method carries out a small pressure difference test scheme for a water-bearing production well to determine the maximum production pressure difference and gas production without formation water entering the bottom of the well, specifically comprising the following steps:

[0048] Step 1: Formation water intrusion along large faults causes rapid water seepage in gas wells. First, a long-term well shut-in observation can be carried out. After the well is shut down, the water quickly retreats along the large faults.

[0049] Step 2, when the formation water in the wellbore and the reservoir around the well has retreated below the gas-water interface, the well is opened and the initial daily gas production of the well is set to the minimum daily gas production process standard of the gas well. In this embodiment, the initial daily gas production is set to 50,000-100,000 cubic meters to ensure that formation water does not penetrate into the bottom of the well.

[0050] Step 3, collecting the wellhead oil pressure, temperature, gas production, water production and water-gas ratio of the gas production well within a set time period, and respectively judging whether the wellhead oil pressure, temperature, gas production, water production and water-gas ratio exceed the corresponding preset fluctuation ranges, wherein if the wellhead oil pressure, temperature, gas production, water production and water-gas ratio in the collected data do not exceed the preset fluctuation ranges, the gas production well is operating normally;

[0051] If any of the wellhead oil pressure, temperature, gas production, water production or water-gas ratio in the collected data exceeds the preset fluctuation range, the gas well operation is abnormal;

[0052] In this embodiment, the fluctuation range of the wellhead oil pressure is 0-±5%, and the fluctuation range of the gas production and the water production is -5% to 5%.

[0053] The preset fluctuation ranges of temperature and water-gas ratio are determined by experience and the gas wells to be tested.

[0054] Set the time period to 2 hours interval.

[0055] The wellhead oil pressure and temperature, gas production, water production and water-gas ratio are observed every 2 hours. Without adjusting the production system, the wellhead oil pressure fluctuation range is between 0-±5%, and the gas production and water production fluctuation range is between -5% and 5%.

[0056] Step 4, collect water samples every 3 days, send the water samples to the laboratory to measure chloride ions as soon as possible, and judge whether the wellhead of the gas well to be produced produces water based on the measured chloride ions. If water is produced, proceed to step 6, otherwise proceed to step 5.

[0057] Step 5: If under the current system, the wellhead does not produce water and the pressure is stable, increase the production appropriately (the recommended single increase is less than the preset threshold, which is 50,000 cubic meters), and continue to observe the wellhead oil pressure and temperature, gas production, water production and water-gas ratio.

[0058] Step 6: If under the current system, if the wellhead oil pressure exceeds the fluctuation range of 0-±5% or the gas production and water production exceed the fluctuation range of -5% to 5%, the wellhead has produced water, then the daily gas production should be appropriately reduced, that is, the daily gas production should be reduced to less than or equal to 20% of the current production, and the wellhead oil pressure and temperature, gas production, water production and water-gas ratio should continue to be observed.

[0059] Step 7, and so on, until a reasonable production system is found in which the wellhead does not produce water.

[0060] Example 2

[0061] This embodiment provides a method for determining reasonable production allocation for a gas well with a high water risk. According to the actual water source, the vertical production pressure difference required for the edge bottom water to invade horizontally and vertically into the well bottom along the fault is calculated, so as to control the water column invasion height and achieve coupling balance between the wellbore to the fault and the water. Specifically, the following steps are included:

[0062] Step 1: Obtain the static pressure gradient G in the pure water section of the wellbore of the flooded well in the block where well A is located through the wireline well test operation. DS-W and the deep formation pressure P R .

[0063] Step 2: Based on the wellhead data of the day before the well was shut in, including the wellhead oil pressure, daily oil, gas and water production at the wellhead, the open flow rate Q of Well A is calculated using the Great North Point Method empirical formula. AOF .

[0064] The empirical formula of the Great North Point Method is:

[0065]

[0066] Among them, P wf is the bottom hole flowing pressure; P R is the formation pressure; q g The daily gas production.

[0067] Step 3, draw a gas reservoir profile of the block where well A is located, mark the top elevation depth h1 and the bottom elevation depth h2 of the production well section of well A in the figure, and mark the water source elevation depth h3 that enters the bottom of well A along the fault horizontally and vertically, which is calculated and verified according to multiple methods.

[0068] Step 4: Water flows into the bottom of the well along the faults and cracks, and needs to overcome the gravity effect of the water avoidance height. From the perspective of gas reservoir engineering research, a certain production pressure difference is required to flow the water from the water source interface into the bottom of the well. According to the production well section top elevation depth h1, the production well section bottom elevation depth h2, the water source elevation depth h3, and the static pressure gradient G in the pure water section wellbore of Well A, DS-W, you can get the production pressure difference ΔP:

[0069] ΔP=(h2-h3)×G DS-W

[0070] Step 5: Based on the known P R , Q AOF , ΔP calculates the daily gas production q at the wellhead corresponding to the production pressure difference ΔP g , with ≤q g As the A well is opened, the production is reasonably allocated.

[0071]

[0072] Among them, P R is the formation pressure, MPa; P wf is the bottom hole flowing pressure, MPa; G DS-W is the static pressure gradient in the pure water section of the wellbore, MPa / m; q g is the daily gas production, 10 4 m 3 / d;Q AOF is unimpeded flow, 10 4 m 3 / d; h1, h2, h3 are the depths above sea level, m; ΔP is the production pressure difference, MPa.

[0073] Example 3

[0074] An ultra-deep and ultra-high pressure edge water gas reservoir S in a basin in western China has an east-west short axis anticline structure. Four wells have been drilled along the long axis of the structure, and wells A, B, C, and D have completed oil testing and put into production. Among them, well A saw water during the oil testing and was already in the water zone, so it was designed as a drainage well; well C is located in a high part of the structure, with a large water avoidance height, and suddenly produces water, with fast water, large water volume, and strong energy, showing a violent flooding feature; the two gas production wells B and D on the east and west wings of well C are in normal production and no signs of water production are seen. Through multi-method phase inference and verification, it is determined that the water source of well C is the formation water on the south wing of the structure, which is connected along the fault and the water source depth is -3519.3m.

[0075] Using method 1 of the invention, a small pressure difference test scheme was carried out in Well C to determine the maximum production pressure difference and gas production without formation water entering the bottom of the well:

[0076] (1) Scheme design: The preliminary design is to shut down Well C for 3 months and then start the well to control the daily gas production within 50,000-100,000 cubic meters per day.

[0077] (2) Actual operation:

[0078] ① Well C was actually shut in for 137 days;

[0079] ② Well C was first opened with a daily gas production of 50,000 cubic meters per day, and a dedicated person was assigned to track and observe the changes in wellhead oil pressure and temperature, gas production, water production and water-gas ratio. After 10 days of continuous opening and production, no water was produced at the wellhead and the oil pressure was stable.

[0080] ③ Adjust to the system of 80,000 cubic meters of gas per day per day, and arrange special personnel to track and observe the changes in wellhead oil pressure and temperature, gas production, water production and water-gas ratio, and open the well for continuous production for 10 days.

[0081] The outlet does not produce water and the oil pressure is stable;

[0082] ④ Adjust to the system of 100,000 cubic meters of gas production per day for 3 days, and arrange special personnel to track and observe the changes in wellhead oil pressure and temperature, gas production, water production and water-gas ratio, and open the well for continuous production for 10 days

[0083] The wellhead does not produce water and the oil pressure is stable;

[0084] ⑤ Adjust to the system of 120,000 cubic meters of gas per day on the 4th day, and arrange special personnel to track and observe the changes in wellhead oil pressure and temperature, gas production, water production and water-gas ratio. At this time, adjust the production system

[0085] On the second day, water was found at the wellhead, with a daily water production of about 0.3t / d;

[0086] ⑥ Adjust to the system of 110,000 cubic meters of gas per day on the 5th day, and arrange special personnel to track and observe the changes in wellhead oil pressure and temperature, gas production, water production and water-gas ratio. At this time, adjust the production system

[0087] On the third day, water was found at the wellhead, with a daily water production of about 0.1t / d;

[0088] ⑦ Adjust to the system of 100,000 cubic meters of gas production per day for 3 days, and arrange special personnel to track and observe the changes in wellhead oil pressure and temperature, gas production, water production and water-gas ratio. Continuous well opening and production will ensure that no water is produced at the wellhead and the oil pressure is stable.

[0089] (3) Actual results: Well C was successfully opened with a small pressure difference test, and the daily gas production was 100,000 cubic meters per day. The wellhead did not produce water during continuous opening, and the oil pressure was stable. That is, the daily gas production of 100,000 cubic meters per day was the maximum gas production of Well C without formation water entering the bottom of the well.

[0090] Based on the results of method 1, the maximum production pressure difference △P and gas production q without formation water entering the bottom of the well are calculated according to method 2. g , in order to verify the practicality and applicability of method 2:

[0091] (1) Known data:

[0092] ① The production well section and bottom elevation depths of Well C, h1 and h2, are -3071.31m and -3169.31m respectively;

[0093] ②The depth of the water source rising along the fault is -3539.3m;

[0094] ③Measurement of the static pressure gradient in the pure water section of the wellbore of Well A in the water-flooded well under the shut-in state of the S gas reservoir

[0095] GDS-W = 0.011 MPa / m;

[0096] ④ The measured deep formation pressure P of the producing layer during the shut-in period of Well C R 74.48MPa;

[0097] ⑤ Before the C well was shut in, the wellhead oil pressure was 33.44MPa and the daily gas production was 24.27×10 4 m 3 / d, daily water production 134.21t / d.

[0098] (2) Based on known data, the open flow rate Q of Well C is evaluated using the Great North Point Method empirical formula AOF :

[0099]

[0100] (3) Based on the production well section of Well C, the bottom elevation depth h1, h2, the water source elevation depth h3, and the static pressure gradient G in the pure water section wellbore DS-W , you can get the production pressure difference △P.

[0101] ΔP=(h2-h3)×G DS-W =[(-3169.13)-(-3539.3)]*

[0102] 0.011=4.07MPa

[0103] (4) According to the known P R , Q AOF , △P calculates the daily gas production q at the wellhead corresponding to the production pressure difference △P g =9.9×10 4 m 3 / d, with q g ≤9.9×10 4 m 3 / d as a reasonable production allocation for the opening of C well.

[0104]

[0105] in conclusion:

[0106] 1. The two methods are combined and verified. Both method 1 and method 2 determine the maximum production pressure difference and gas production without formation water entering the bottom of the well;

[0107] The maximum production pressure difference of Well C without formation water entering the bottom of the well is 4.07MPa and the daily gas production is 9.9×10 4 m 3 / d.

[0108] The embodiments described above are only used to illustrate the technical solutions of the present application, rather than to limit them. Although the present application has been described in detail with reference to the aforementioned embodiments, a person skilled in the art should understand that the technical solutions described in the aforementioned embodiments may still be modified, or some of the technical features may be replaced by equivalents. Such modifications or replacements do not deviate the essence of the corresponding technical solutions from the spirit and scope of the technical solutions of the embodiments of the present application, and should all be included in the protection scope of the present application.

Claims

1. A method for determining reasonable production allocation for gas wells with high water breakthrough risk, characterized in that: The following steps are involved: Step 1: The formation water invades along the large fault, causing the gas well to see water quickly. The water-invaded gas well is closed until the formation water in the wellbore and the reservoir around the well retreats below the gas-water interface and then the well is opened; Step 2, setting the initial daily gas production of the gas production well test plan; Step 3, collecting data of the gas well within a set time period, and judging whether the operation of the gas well is abnormal based on the collected data; Step 4: adjust the daily gas production according to the judgment result, and continue to observe the data of the gas well; Step 5, repeat steps 3 and 4 until a reasonable production allocation of the gas well is determined.

2. A method for determining reasonable production allocation for a high water risk gas well according to claim 1, characterized in that: In step 2, the initial daily gas production is the minimum daily gas production process standard of the gas production well.

3. The method for determining reasonable production allocation of a high water risk gas well according to claim 1, characterized in that: In step 3, it is determined whether the gas well operation is abnormal based on the collected data. The specific method is: If the wellhead oil pressure, temperature, gas production, water production and water-gas ratio in the collected data do not exceed the preset fluctuation range, the gas well is operating normally; If any of the wellhead oil pressure, temperature, gas production, water production or water-gas ratio in the collected data exceeds the preset fluctuation range, the gas well is operating abnormally.

4. The method for determining reasonable production allocation of a high water risk gas well according to claim 1, characterized in that: In step 4, the daily gas production is adjusted according to the judgment result. The specific method is: If the gas well is operating abnormally, the chloride ions in the water sample of the gas well are obtained, and whether the gas well produces water is determined based on the chloride ions. If the gas well produces water, the daily gas production is reduced, otherwise the daily gas production is increased; If the gas well is operating normally, the chloride ions in the water sample of the gas well are obtained, and whether the gas well produces water is determined based on the chloride ions. If the gas well produces water, the daily gas production is reduced, otherwise the daily gas production is increased.

5. A method for determining reasonable production allocation for gas wells with high water breakthrough risk according to claim 4, characterized in that: The reduced daily gas production is less than or equal to 20% of the current production.

6. A method for determining reasonable production allocation for gas wells with high water breakthrough risk, characterized in that: The following steps are involved: Step 1, obtaining the static pressure gradient in the pure water section of the wellbore of the water-flooded wellbore and the deep formation pressure in the production layer of the gas production well to be tested in the shut-in state; Step 2, calculating the open flow rate of the gas production well to be tested; Step 3, obtaining the top elevation depth of the production well section of the gas production well to be tested, the bottom elevation depth of the production well section, and the water source elevation depth that penetrates into the bottom of the well along the fault of the gas production well to be tested; Step 4, calculating the production pressure difference required for the gas well to flow the water body at the water source interface into the bottom of the well; Step 5, calculate the maximum daily wellhead gas production of the gas production well to be tested without formation water flowing into the bottom of the well, and determine the reasonable production allocation of the gas production well to be tested based on the maximum daily wellhead gas production.

7. A method for determining reasonable production allocation for a high water risk gas well according to claim 6, characterized in that: In step 2, the open-flow rate of the gas well to be tested is calculated using the Great North Point Method empirical formula.

8. A method for determining reasonable production allocation for a high water risk gas well according to claim 6, characterized in that: In step 4, the production pressure difference required for the gas well to flow the water body at the water source interface into the bottom of the well is calculated according to the following formula: ΔP=(h2-h3)×G DS-W Among them, ΔP is the production pressure difference; h2 is the bottom elevation depth of the production well section; h3 is the water source elevation depth; G DS-W It is the static pressure gradient in the pure water section of the wellbore.

9. A method for determining reasonable production allocation for a high water risk gas well according to claim 6, characterized in that: In step 5, the maximum daily gas production at the wellhead without formation water entering the well bottom is calculated according to the following formula: Among them, P R is the formation pressure; q g is the maximum daily gas production at the wellhead; ΔP is the production pressure difference; Q AOF Unimpeded flow.

10. A method for determining reasonable production allocation for a high water risk gas well according to claim 6, characterized in that: In step 5, the reasonable production allocation of the gas production well to be tested is determined according to the maximum wellhead daily gas production. The specific method is: The reasonable production allocation for the gas well to be tested is based on a daily gas production rate that is less than or equal to the maximum wellhead gas production rate.

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