CN111257533A - Method for measuring content of water vapor in natural gas - Google Patents
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- CN111257533A CN111257533A CN202010090719.4A CN202010090719A CN111257533A CN 111257533 A CN111257533 A CN 111257533A CN 202010090719 A CN202010090719 A CN 202010090719A CN 111257533 A CN111257533 A CN 111257533A
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- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 title claims abstract description 152
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Chemical compound O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims abstract description 116
- 239000003345 natural gas Substances 0.000 title claims abstract description 76
- 238000000034 method Methods 0.000 title claims abstract description 33
- 239000007789 gas Substances 0.000 claims abstract description 52
- 238000002360 preparation method Methods 0.000 claims abstract description 46
- 239000007788 liquid Substances 0.000 claims abstract description 34
- 238000009833 condensation Methods 0.000 claims abstract description 24
- 230000005494 condensation Effects 0.000 claims abstract description 24
- 239000008398 formation water Substances 0.000 claims abstract description 13
- 238000002347 injection Methods 0.000 claims abstract description 13
- 239000007924 injection Substances 0.000 claims abstract description 13
- 239000012530 fluid Substances 0.000 claims abstract description 10
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 9
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 9
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 9
- 238000002474 experimental method Methods 0.000 claims abstract description 8
- 238000005303 weighing Methods 0.000 claims abstract description 4
- 229920006395 saturated elastomer Polymers 0.000 claims description 11
- 238000010438 heat treatment Methods 0.000 claims description 8
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 6
- 239000011521 glass Substances 0.000 claims description 4
- 238000011065 in-situ storage Methods 0.000 claims description 4
- 238000007599 discharging Methods 0.000 claims description 3
- 229910052757 nitrogen Inorganic materials 0.000 claims description 3
- 239000003507 refrigerant Substances 0.000 claims description 3
- 238000005057 refrigeration Methods 0.000 claims description 2
- 239000000126 substance Substances 0.000 claims description 2
- 238000012360 testing method Methods 0.000 abstract description 7
- 230000008569 process Effects 0.000 abstract description 5
- 239000003921 oil Substances 0.000 description 7
- 238000004458 analytical method Methods 0.000 description 4
- 239000000203 mixture Substances 0.000 description 4
- 230000009286 beneficial effect Effects 0.000 description 3
- 230000018044 dehydration Effects 0.000 description 3
- 238000006297 dehydration reaction Methods 0.000 description 3
- 238000011161 development Methods 0.000 description 3
- 230000004048 modification Effects 0.000 description 3
- 238000012986 modification Methods 0.000 description 3
- 238000003860 storage Methods 0.000 description 3
- 238000007796 conventional method Methods 0.000 description 2
- 238000005259 measurement Methods 0.000 description 2
- 238000000691 measurement method Methods 0.000 description 2
- 238000001556 precipitation Methods 0.000 description 2
- 230000009467 reduction Effects 0.000 description 2
- 230000015572 biosynthetic process Effects 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000010586 diagram Methods 0.000 description 1
- 238000004090 dissolution Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 229910052500 inorganic mineral Inorganic materials 0.000 description 1
- 239000011707 mineral Substances 0.000 description 1
- 238000002156 mixing Methods 0.000 description 1
- 238000005070 sampling Methods 0.000 description 1
- 238000002791 soaking Methods 0.000 description 1
- 238000003756 stirring Methods 0.000 description 1
- 238000012546 transfer Methods 0.000 description 1
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N33/00—Investigating or analysing materials by specific methods not covered by groups G01N1/00 - G01N31/00
- G01N33/22—Fuels; Explosives
- G01N33/225—Gaseous fuels, e.g. natural gas
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N5/00—Analysing materials by weighing, e.g. weighing small particles separated from a gas or liquid
- G01N5/04—Analysing materials by weighing, e.g. weighing small particles separated from a gas or liquid by removing a component, e.g. by evaporation, and weighing the remainder
- G01N5/045—Analysing materials by weighing, e.g. weighing small particles separated from a gas or liquid by removing a component, e.g. by evaporation, and weighing the remainder for determining moisture content
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Abstract
The invention relates to a method for measuring the content of water vapor in natural gas, which comprises the following steps: transferring the natural gas sample into a high-temperature high-pressure sample injector; injecting formation water into the sample proportioning device through a water injection port to establish a gas-water balance; standing the sample preparation device with the water injection port facing downwards, opening a valve of the water injection port, and draining liquid water in the sample preparation device; the fluid in the sample preparation device enters a condensing tube through a pressure reducing valve, water vapor and liquid hydrocarbon are condensed, and natural gas enters a gas flowmeter; putting the condenser pipe into hot water of 90-100 ℃, volatilizing liquid hydrocarbon, weighing and comparing the mass of the condenser pipe before and after the experiment, and combining the total amount of gas in the gas flowmeter to obtain the water vapor content in the unit volume of the natural gas or the liquid water amount generated by the natural gas at the corresponding condensation temperature. The method has the advantages of reliable principle and simple and convenient operation, can accurately test the content of the water vapor in the natural gas, provides reliable theoretical basis for the setting of the ground treatment process parameters of the natural gas, and has wide application prospect.
Description
Technical Field
The invention relates to a method for measuring the content of water vapor in natural gas, which belongs to the field of oil and gas development.
Background
At present, gas reservoirs found at home and abroad are increasingly high in temperature, for example, condensate gas reservoirs with the temperature as high as 230 ℃ have been found at abroad, under the condition of such a high-temperature reservoir layer, water is very easy to exist in condensate gas in a steam state, and becomes a part of a formation condensate gas fluid system, namely, the gas phase in an actual natural gas reservoir layer is generally saturated with water steam. After the natural gas is exploited to the ground from the reservoir, the temperature and the pressure are generally reduced, the water vapor solubility in the natural gas is generally reduced due to the temperature reduction, the water dissolution in the natural gas is promoted due to the pressure reduction, and the effect of the natural gas and the water vapor solubility in the natural gas are difficult to accurately compare. In conclusion, the water vapor content in the natural gas sample obtained from the field is difficult to represent the actual situation, which affects the subsequent phase experiment results of the natural gas, and no method for preparing the natural gas sample saturated with water vapor indoors is reported at present.
The natural gas can be transported out only after being dehydrated, and meanwhile, in low-temperature seasons, the phenomena of liquid water precipitation and pipeline blockage caused by hydrate generation easily occur in the extracted natural gas, so that the control of the content of water vapor in the natural gas under different temperature and pressure conditions is very important. The existing natural gas steam content testing method comprises a chart look-up method, a phase state analysis method, an empirical formula method and a direct measurement method. The chart checking method, the phase state analysis method and the empirical formula method can obtain data without experiments, and have the characteristics of simplicity, convenience and wide application range, but have problems in the aspect of accuracy because no experiment foundation exists. The conventional direct measurement method generally adopts SY/T7507-2016 'determination of water content in natural gas'. However, the conventional method is directed to the content test of water vapor in gas in a natural gas pipeline, and is only suitable for the content test of water vapor in gas entering an external pipeline after dehydration, and the sampling condition is generally normal temperature and low pressure. And the conventional method has insufficient condensation, which often results in lower measured water vapor content. Meanwhile, in the aspect of determining the water vapor content in a gas-water balance system, the existing method only statically determines the water vapor content under a single condition, and a set of complete dynamic unified analysis method under the condition of changing pressure is not formed.
In conclusion, how to obtain a representative natural gas sample saturated with water vapor indoors and further establish a method for measuring the water vapor content in the natural gas under different temperature and pressure conditions has very important significance for the development, storage and transportation of natural gas reservoirs.
Disclosure of Invention
The invention aims to provide a method for measuring the content of water vapor in natural gas, which has reliable principle and simple and convenient operation, can accurately and quantitatively test the content of the water vapor in the natural gas, is beneficial to more accurately obtaining the phase state property of reservoir natural gas fluid, provides reliable theoretical basis for the setting of natural gas ground treatment process parameters (particularly low-temperature dehydration devices), and has wide application prospect.
In order to achieve the technical purpose, the invention adopts the following technical scheme.
The invention is divided into two steps: firstly, preparing a representative natural gas sample saturated with water vapor indoors, mixing the obtained natural gas (condensate gas is prepared from associated gas and degassed crude oil according to gas-oil ratio) and formation water under the actual working conditions (temperature and pressure) on site, and then removing redundant liquid water; secondly, measuring the content of water vapor in the natural gas, enabling the prepared natural gas sample saturated with water vapor under different conditions to pass through a set of low-temperature condensation system (patent publication No. CN108254468A), and then separating condensed light hydrocarbon from liquid water to accurately obtain the content of water vapor in the natural gas or the liquid water produced by the natural gas.
A method for measuring the content of water vapor in natural gas sequentially comprises the following steps:
(1) transferring a natural gas sample obtained on site into a high-temperature and high-pressure sample preparation device, and keeping the temperature and the pressure in the sample preparation device consistent with the actual working condition on site;
(2) injecting a certain amount of formation water into the sample preparation device through the water injection port, then closing a valve of the water injection port, rotating the sample preparation device for a long time enough to fully perform substance exchange between gas and water, and establishing a gas-water balance;
(3) rotating the sample preparation device to enable the water injection port to stand downwards for a long enough time, slowly opening a valve of the water injection port, detecting whether liquid water flows out, if the liquid water flows out, indicating that the gas phase in the sample preparation device is completely saturated with water vapor, and if the liquid water does not flow out, repeating the step (2), and continuously injecting formation water until the gas phase is completely saturated with water vapor;
(4) downwards arranging a water injection port of the sample preparation device, and completely discharging residual liquid water in the sample preparation device;
(5) passing the fluid in the sample preparation device through an ultralow-temperature glass condensation system, wherein the condensation system consists of a pressure reducing valve, a condensation pipe, a low-temperature box, a gas flowmeter and a connecting pipeline, the condensation pipe is transparent, and the lowest working temperature is lower than-200 ℃; the top of the condensing pipe is provided with an air inlet and an air outlet, the sample matching device is connected with the air inlet of the condensing pipe through a pressure reducing valve, the air outlet of the condensing pipe is connected with a gas flowmeter, the condensing pipe is positioned in a low-temperature box, and the low-temperature box is filled with a refrigerant; the fluid in the sample preparation device enters a condensation pipe through a pressure reducing valve, water vapor and liquid hydrocarbon are condensed, and natural gas enters a gas flowmeter;
(6) and closing the sample preparation device, taking down the condenser pipe, putting the condenser pipe into hot water at 90-100 ℃ to volatilize liquid hydrocarbon in the condenser pipe, taking out the condenser pipe from the hot water, wiping the outer surface, weighing and comparing the mass of the condenser pipe before and after the experiment, and combining the total gas amount in the gas flowmeter to obtain the water vapor content in the unit volume of the natural gas or the liquid water amount generated by the natural gas at the corresponding condensation temperature.
In the step (1), if the gas condensate is gas condensate, preparing a gas condensate sample in a sample preparation device according to the existing standard, namely preparing the gas condensate sample by adopting field associated gas and deaerated oil according to the gas-oil ratio.
In the step (2), the water injected into the sample preparation device may be directly obtained in situ or prepared in a laboratory, and preferably, the actual formation water is obtained in situ.
In the step (2), the gas-water balance time in the sample preparation device is 3-5 h.
In the step (5), the sample preparation device is connected with the high-pressure pump, the pressure in the sample preparation device is kept unchanged through the high-pressure pump, a heating sleeve is arranged outside the sample preparation device, and the temperature of the sample preparation device is controlled to be kept unchanged through the heating sleeve.
In the step (6), the temperature of hot water for heating the condensation pipe is 90-100 ℃, preferably 90-95 ℃, and the heating time of the condensation pipe is 0.5-1 h.
And (6) controlling the temperature of the low-temperature box of the condensing system to obtain the liquid water amount generated by the natural gas at different temperatures.
In the step (6), when the condensing system adopts liquid nitrogen for refrigeration, the total water vapor content in the natural gas can be obtained.
The invention can reestablish the gas-water balance relationship by changing the temperature and pressure conditions in the sample preparation device, discharge redundant liquid water and carry out the next group of experiments.
Compared with the prior art, the invention has the following beneficial effects:
(1) the method for preparing the representative natural gas sample saturated with the water vapor indoors is provided for the first time, and the method is beneficial to more accurately obtaining the phase property of the reservoir natural gas fluid;
(2) the method for measuring the water vapor content in the natural gas is provided, the test process is simple, the test result is accurate and reliable, the design of a natural gas dehydration scheme and the parameter setting of the natural gas storage and transportation process are facilitated, and important basic parameters and theoretical bases are provided for the development of natural gas reservoirs and the storage and transportation of the natural gas;
(3) the method can be used for different oil fields, different gas reservoirs and different water types, and has wide application range and strong universality of analysis data.
Drawings
FIG. 1 is a schematic flow diagram of a method of determining the water vapor content of natural gas according to the present invention.
In the figure:
1-a natural gas vessel; 2. 6, 8, 9, 11, 12, 13-valves; 3-an air compressor; 4. 7-high pressure automatic pump; 5-a condensate gas container; 10-formation water container; 14-high temperature high pressure sample injector; 15-glass condenser tube; 16-a low temperature box; 17-water bath beaker; 18-an electronic balance; 19-gas flow meter.
Detailed Description
The invention is further illustrated below with reference to the figures and examples in order to facilitate the understanding of the invention by a person skilled in the art. It is to be understood that the invention is not limited in scope to the specific embodiments, but is intended to cover various modifications within the spirit and scope of the invention as defined and defined by the appended claims, as would be apparent to one of ordinary skill in the art.
Example 1
A method for measuring the content of water vapor in natural gas sequentially comprises the following steps:
(1) injecting a certain amount of natural gas or condensate gas (if the condensate gas is prepared by adopting field associated gas and degassed oil according to a gas-oil ratio) into the high-temperature high-pressure sampler 14 through the natural gas container 1 or the condensate gas container 5 and the air compressor 3;
(2) after the temperature and the pressure reach the actual conditions on site, injecting 20ml of in-situ obtained formation water into the sample preparation device at constant pressure through the high-pressure automatic pump 4 and the formation water container 10, and stirring the sample preparation device for 3 hours to ensure that the gas and the formation water are fully dissolved; standing for 3h to completely separate gas and water, inverting the sample preparation device, slowly opening the valve, and finding that liquid water flows out, thereby proving that the gas phase is saturated with water vapor; then slowly draining the redundant liquid water;
(3) according to the flow chart shown in the figure 1, a pipeline is connected from the top of a sample preparation device and connected with an air inlet of a glass condensation pipe 15 arranged in a low-temperature box 16, an air outlet of the condensation pipe is connected with a gas flowmeter 19 through a pipeline, a valve of the sample preparation device is slowly opened to allow fluid to enter the condensation pipe through a pressure reducing valve at a flow rate of about 100mL/min, water vapor and liquid hydrocarbon are condensed, natural gas enters the gas flowmeter 19, and the pressure of the sample preparation device is kept constant through a high-pressure automatic pump 7 in the experimental process;
(4) discharging a certain amount of fluid (11000mL), closing an outlet valve of the sample preparation device, taking out a condenser pipe, observing the liquid precipitation condition when the temperature of the condenser pipe rises to room temperature, soaking the body of the condenser pipe in a water bath beaker 17 at 95 ℃ for more than 30min, volatilizing condensed liquid hydrocarbon, wiping the outside of the condenser pipe, weighing the mass of the condenser pipe by using an electronic balance 18, comparing the mass change of the condenser pipe before and after an experiment, determining the amount of precipitated liquid water in the condenser pipe, and determining the water content in a gas sample at corresponding temperature and pressure by combining the gas discharge amount;
(5) and (4) adjusting the high-pressure automatic pump 7 to transfer the gas to the next pressure point to be measured, and repeating the steps (2) to (4).
Table 1 shows the raw natural gas composition in this example and table 2 shows the formation water composition. The actual temperature on site is 125 ℃, the pressure is 40MPa, and the refrigerant adopts liquid nitrogen. Table 3 shows the measurement results of the water vapor content in the natural gas at 125 ℃ and under different pressures (8 pressure points), and it can be seen that the water vapor content in the natural gas gradually increases with the decrease of the pressure, and 0.831m is reached under 5MPa3/104m3。
TABLE 1 Natural gas composition (mol%)
TABLE 2 mineral composition of formation water
TABLE 3 measurement of Water vapor content
| Pressure (MPa) | 40 | 35 | 30 | 25 | 20 | 15 | 10 | 5 |
| Water vapor content (m)3/104m3) | 0.349 | 0.367 | 0.383 | 0.403 | 0.440 | 0.485 | 0.622 | 0.831 |
The present invention is not limited to the above-described embodiments, and various modifications are possible for those skilled in the art. Any modification, equivalent replacement, or improvement made within the spirit and principle of the present invention should be included in the protection scope of the present invention.
Claims (8)
1. A method for measuring the content of water vapor in natural gas sequentially comprises the following steps:
(1) transferring a natural gas sample obtained on site into a high-temperature and high-pressure sample preparation device, and keeping the temperature and the pressure in the sample preparation device consistent with the actual working condition on site;
(2) injecting a certain amount of formation water into the sample preparation device through the water injection port, then closing a valve of the water injection port, rotating the sample preparation device for a long time enough to fully perform substance exchange between gas and water, and establishing a gas-water balance;
(3) rotating the sample preparation device to enable the water injection port to stand downwards for a long enough time, slowly opening a valve of the water injection port, detecting whether liquid water flows out, if the liquid water flows out, indicating that the gas phase in the sample preparation device is completely saturated with water vapor, and if the liquid water does not flow out, repeating the step (2), and continuously injecting formation water until the gas phase is completely saturated with water vapor;
(4) downwards arranging a water injection port of the sample preparation device, and completely discharging residual liquid water in the sample preparation device;
(5) passing the fluid in the sample preparation device through an ultralow-temperature glass condensation system, wherein the condensation system consists of a pressure reducing valve, a condensation pipe, a low-temperature box, a gas flowmeter and a connecting pipeline, the condensation pipe is transparent, and the lowest working temperature is lower than-200 ℃; the top of the condensing pipe is provided with an air inlet and an air outlet, the sample matching device is connected with the air inlet of the condensing pipe through a pressure reducing valve, the air outlet of the condensing pipe is connected with a gas flowmeter, the condensing pipe is positioned in a low-temperature box, and the low-temperature box is filled with a refrigerant; the fluid in the sample preparation device enters a condensation pipe through a pressure reducing valve, water vapor and liquid hydrocarbon are condensed, and natural gas enters a gas flowmeter;
(6) and closing the sample preparation device, taking down the condenser pipe, putting the condenser pipe into hot water at the temperature of 90-100 ℃, volatilizing liquid hydrocarbon in the condenser pipe, taking out the condenser pipe from the hot water, wiping the outer surface, weighing and comparing the mass of the condenser pipe before and after the experiment, and combining the total mass of gas in the gas flowmeter to obtain the water vapor content in the unit volume of the natural gas or the liquid water amount generated by the natural gas at the corresponding condensation temperature.
2. The method for determining the water vapor content of natural gas according to claim 1, wherein in step (1), if the gas condensate is produced, the gas condensate is produced in a sample distributor according to the gas-oil ratio by using the associated gas and the deaerated oil on site.
3. The method for determining the water vapor content of natural gas according to claim 1, wherein in step (2), the water injected in the sample preparation device is directly obtained in situ or prepared in a laboratory.
4. The method for determining the water vapor content in natural gas according to claim 1, wherein in the step (2), the gas-water balance time in the sample preparation device is 3-5 h.
5. The method for determining the water vapor content in natural gas according to claim 1, wherein in the step (5), the sample preparation device is connected with a high-pressure pump, the pressure in the sample preparation device is kept constant by the high-pressure pump, a heating sleeve is arranged outside the sample preparation device, and the temperature of the sample preparation device is kept constant by controlling the heating sleeve.
6. The method for measuring the content of water vapor in natural gas according to claim 1, wherein in the step (6), the temperature of hot water for heating the condensation pipe is 90-95 ℃, and the heating time of the condensation pipe is 0.5-1 h.
7. The method for measuring the water vapor content in the natural gas as claimed in claim 1, wherein in the step (6), the liquid water content generated by the natural gas at different temperatures is obtained by controlling the temperature of a low-temperature box of a condensation system.
8. The method for determining the water vapor content in the natural gas as claimed in claim 1, wherein in the step (6), when the condensation system adopts liquid nitrogen for refrigeration, the total water vapor content in the natural gas can be obtained.
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Cited By (5)
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| CN111948106A (en) * | 2020-08-11 | 2020-11-17 | 陈海南 | City air networking check out test set |
| CN112505161A (en) * | 2020-12-01 | 2021-03-16 | 西南石油大学 | Device and method for measuring content and precipitation amount of aromatic hydrocarbon substances in natural gas |
| CN115539015A (en) * | 2022-09-19 | 2022-12-30 | 西南石油大学 | Method for judging gas condensate-crude oil coexistence in reservoir |
| CN117330727A (en) * | 2023-11-15 | 2024-01-02 | 成都蓝湖科技有限公司 | Moisture analysis pretreatment system of high-sulfur natural gas dehydration device |
| CN115539015B (en) * | 2022-09-19 | 2024-05-28 | 西南石油大学 | Method for judging coexistence of condensate gas and crude oil in reservoir |
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Application publication date: 20200609 |