CN107067093B - Method for measuring hydrate blockage risk of wellhead of salt cavern underground gas storage - Google Patents
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Abstract
The invention relates to a method for measuring the risk of blocking a wellhead hydrate of a salt cavern underground gas storage, which comprises the following steps of: step 1, determining the cooling degree required by hydrate generation in the gas production process of a salt cavern gas storage; step 2, determining the duration when the environment change temperature is equal to the cooling degree, namely the time when the hydrate generation condition exists; step 3, calculating the maximum mass of the hydrate generated by the natural gas and the water generated every day; step 4, calculating the quality of hydrate blocked by the hydrate with the length of 1 meter formed by the shaft or the well mouth according to the sectional area of the shaft or the well mouth; step 5, calculating the days for forming the hydrate blockage with the length of 1 meter according to the results of the steps 3 and 4; step 6, calculating the blocking probability of the hydrate at the wellhead of the salt cavern underground gas storage according to the time of the hydrate generation condition and the time of forming the hydrate with the length of 1 meter; and 7, taking the blocking probability of the salt cavern underground gas storage wellhead hydrate as an index, wherein the higher the probability is, the higher the blocking risk of the salt cavern underground gas storage wellhead hydrate is.
Description
Technical Field
The invention relates to risk control of a salt cavern underground gas storage, in particular to a method for measuring the risk of hydrate blockage of a wellhead of the salt cavern underground gas storage.
Background
The generation of hydrate is one of the harmful factors which influence the safe and stable operation of the gas storage and cause the risk of the reduction of the injection and production capacity of the gas storage. The hydrate is an ice-crystal solid substance and is formed by hydrating components in natural gas and a liquid state. As gas is produced from the reservoir, the temperature and pressure of the gas flowing up the wellbore will drop as the gas expands. This joule-thomson cooling effect will create favorable conditions for gas well hydrate formation. Generally, whether the hydrate is generated or not is judged by comparing the pressure and the temperature of the wellhead with the pressure and the temperature change curve of the hydrate stable region (figure 1), and if the hydrate is generated, the operation design parameters of the underground gas storage of the salt cavern are adjusted. Depending on the field practice, hydrates may be generated occasionally even if the gas storage utility well is operating within the gas hydrate stability curve (the estimates of wellhead operating pressure and temperature are below the hydrate stability curve). This phenomenon is more likely to occur closer to the wellhead, especially when cold air in winter and extremely low ground temperatures increase the gas cooling. When the cooling degree lasts for a long time, a large amount of hydrate can be generated, and even a shaft or a wellhead facility is blocked, so that the normal production operation of the gas storage is seriously influenced. Therefore, the method for predicting the probability of the blockage of the hydrate at the wellhead of the underground gas storage has important significance for controlling the risk of the reduction of the injection and production capacity of the gas storage. For the problem of calculating the blocking probability of the hydrate at the wellhead of the underground gas storage, no relevant report exists at home and abroad at present.
Disclosure of Invention
Aiming at the problems in the prior art, the invention provides a method for measuring the hydrate blockage risk of a wellhead of a salt cavern underground gas storage, which realizes the prediction of the hydrate blockage risk caused by the combined action of the Joule-Thomson cooling effect and the environment temperature in the gas production process of the salt cavern underground gas storage, can be used for the risk evaluation of the salt cavern underground gas storage, and provides technical support and scientific basis for controlling the risk of the reduction of the injection and production capacity of the gas storage.
The invention is realized by the following technical scheme:
a method for measuring the risk of hydrate blockage of a wellhead of a salt cavern underground gas storage comprises the following steps:
step 2, determining the duration T when the environment change temperature is equal to the cooling degree delta TassumedI.e. the time at which hydrate formation conditions exist;
step 3, calculating the maximum mass M of the hydrate generated by the natural gas and the water generated every dayh；
Step 4, calculating the mass M of the hydrate blocked by the hydrate with the length of 1 meter formed in the shaft or the well mouth according to the sectional area of the shaft or the well mouth1m；
Step 5, calculating the days t for forming the hydrate blockage with the length of 1 meter according to the results of the steps 3 and 41m；
Step 6, according to the existing time t of the hydrate generating conditionassumedAnd calculating the wellhead hydrate blockage probability of the salt cavern underground gas storage according to the time for forming the hydrate with the length of 1 meter, wherein the probability is equal to the quotient of the time for forming the hydrate under the condition that the hydrate is formed and the time for forming the hydrate blockage length;
and 7, taking the blocking probability of the salt cavern underground gas storage wellhead hydrate as an index, wherein the higher the probability is, the higher the blocking risk of the salt cavern underground gas storage wellhead hydrate is.
Preferably, the method includes the following assumptions,
(1) formation of 1 meter long hydrates will cause plugging of the facility;
(2) the ambient changing temperature occurs in the wellbore due to the ambient temperature cooling the wellhead and upper portion of the wellbore;
(3) assuming that water is saturated in the produced gas and that no free water is produced with the natural gas;
(4) molecular formula of hydrate is CH4(H2O)34Molecular weight is 628 g.
Preferably, in the step 1, the cooling degree Δ T is a temperature difference between the wellhead gas temperature and the hydrate stability region boundary, and is obtained through the following steps;
1.1, the pressure and temperature change curves of the natural gas hydrate stable region are expressed by the following formula (1) and formula (2),
Pk＝9.79634×10-5T4-0.10809T3+44.746T2-8236.3T+568737.4(T＞273.16K) (1)；
Pk＝0.075×T-17.887(T≤273.16K) (2)；
wherein: pkIs the gas pressure; t is the gas temperature;
1.2, adjusting the wellhead gas temperature TwellheadAnd corresponding wellhead gas pressure PwellheadSubstituting the formula (1) and the formula (2), and calculating to obtain the critical temperature T for generating the hydratec；
1.3, calculating the cooling degree required by the generation of the hydrate according to the formula (3);
ΔT＝Twellhead-TC(3)。
preferably, in step 2, the duration T during which the ambient temperature change is equal to the degree of cooling Δ T is determinedassumed(ii) a The number of days that the gas temperature is decreased by Δ T according to the local ambient temperature per year is counted as the time T when the hydrate formation condition is presentassumed。
Preferably, in step 3, the maximum mass M of hydrate formed by natural gas and water generated every day is calculated according to the following formula (4)h；
Wherein: mwIs the mass of water available to generate hydrates per day; wmol(h)Mass per mole hydrate; wmol(w)Is the mass per mole of water.
Further, the mass M of water available daily for hydrate formationwCan be estimated according to equation (5);
Mw＝ASwQg(5)；
wherein A is the proportion of water produced along with natural gas in each day for generating hydrate, and the unit percent is 1 percent; swIs the saturation coefficient of water in each cubic meter of natural gas and has the unit of Kg/m3；QgIs the maximum gas production rate in m3/d。
Preferably, in step 4, the amount of hydrate material forming a hydrate plug with a length of 1 meter in the wellbore or wellhead is calculated according to the formula (6):
M1m＝1×Awellhead×ρhydrate(6)；
wherein M is1mThe hydrate mass of the 1 meter long hydrate plug is formed for the shaft or the well head; a. thewellheadIs the area of the wellbore or wellhead; rhohydrateIs hydrate CH4(H2O)34The density of (c).
Preferably, in step 5, the number of days to form a 1 meter long hydrate plug is calculated according to equation (7):
compared with the prior art, the invention has the following beneficial technical effects:
the method provides a new technical means for predicting the hydrate blockage of the wellhead of the underground gas storage, can provide basis for an operation manager of the gas storage to take preventive measures in time by predicting the probability of the hydrate blockage of the wellhead caused by the environmental temperature according to the actual working conditions of the gas storage, and has important significance for controlling the occurrence of the risk of the reduction of the injection and production capacity of the gas storage.
Drawings
FIG. 1 is a flow chart of calculation of the wellhead hydrate blockage probability of the salt cavern underground gas storage according to the embodiment of the invention.
FIG. 2 is a schematic illustration of the degree of cooling required for hydrate formation during gas production in a salt cavern gas storage as described in the examples of the invention.
FIG. 3 is a graph comparing operating pressure versus temperature versus hydrate formation for certain gas storage emergency and normal operating conditions as described in the examples of the invention.
Detailed Description
The present invention will now be described in further detail with reference to specific examples, which are intended to be illustrative, but not limiting, of the invention.
The invention relates to a method for measuring the risk of hydrate blockage of a wellhead of a salt cavern underground gas storage, which aims to solve two key problems of time existing in the hydrate forming condition and the critical condition of forming blockage and makes the following assumptions:
(1) formation of 1 meter long hydrates will cause plugging of the facility;
(2) the additional gas cooling that occurs in the wellbore is due to the ambient temperature cooling of the wellhead and the upper half of the wellbore;
(3) assuming that water is saturated in the produced gas and that no free water is produced with the natural gas;
(4) the hydrate blockage probability is equal to the quotient of the time during which hydrate formation conditions exist and the time during which 1 meter long hydrate is formed;
(5) molecular formula of hydrate is CH4(H2O)34Molecular weight is 628 g.
As shown in fig. 1, it includes the following steps.
The difference between the wellhead gas temperature and the hydrate stability zone boundary temperature is the degree of cooling required for hydrate formation, as shown in figure 2. The pressure and temperature change curves of the natural gas hydrate stability region are represented by formula (1) and formula (2):
Pk＝9.79634×10-5T4-0.10809T3+44.746T2-8236.3T+568737.4(T＞273.16K) (1)；
Pk＝0.075×T-17.887(T≤273.16K) (2)；
wherein: pkIs gas pressure, kPa; t is the gas temperature, K
Determining the existence time of hydrate formation condition by first determining the wellhead gas temperature TwellheadAnd corresponding wellhead gasPressure PwellheadSubstituting the formula (1) and the formula (2), and calculating to obtain the critical temperature T for generating the hydratecThen, the cooling degree required for hydrate formation can be determined according to the formula (3).
ΔT＝Twellhead-TC(3)。
Step 2, determining the duration T when the ambient temperature is delta Tassumed。
The cooling capacity of the natural gas by the ambient temperature of the wellhead of the underground gas storage is difficult to calculate, the magnitude of the cooling capacity can be represented by the number of days of gas temperature reduction caused by the local ambient temperature every year, and local meteorological data can be checked. Namely, the number of days in which the gas temperature is decreased by Delta T due to the local environmental temperature every year is recorded as the time T when the hydrate formation condition existsassumed。
Step 3, calculating the maximum mass M of the hydrate generated by the natural gas and the water generated every dayh。
Calculating the maximum mass of the hydrate generated by the gas and the water according to the formula (4):
wherein: mwIs the mass of water available to generate hydrates per day in kg; wmol(h)Is the mass per mole of hydrate, in g; wmol(w)Is the mass per mole of water, in g;
mass M of water available daily for hydrate formationwCan be estimated according to equation (5);
Mw＝ASwQg(5)
wherein A is the proportion of water produced along with natural gas in each day for generating hydrate, and the unit percent is 1 percent; swIs the saturation coefficient of water in each cubic meter of natural gas and has the unit of Kg/m3；QgIs the maximum gas production rate in m3/d。
And 4, calculating the mass of the hydrate forming the hydrate plug with the length of 1 meter on the shaft or the wellhead. Calculating according to the formula (6):
M1m＝1×Awellhead×ρhydrate(6)
wherein M is1mForming the mass of the hydrate blocked by the hydrate with the length of 1 meter for a shaft or a well mouth, wherein the unit Kg is the mass of the hydrate; a. thewellheadIs the cross-sectional area of the shaft or well head in m2；ρhydrateIs hydrate (CH)4(H2O)34) Density of (1) in Kg/m3。
And 5, calculating the days for forming the hydrate blockage with the length of 1 meter according to the results of the step 3 and the step 4. Calculated according to equation (7):
and 6, calculating the blocking probability of the wellhead hydrate according to the results of the step 2 and the step 5. The hydrate blockage probability can be calculated according to formula (8):
when PfplugAnd when the calculated value is more than 1, taking 1.
The risk prediction of the hydrate blockage of the wellhead of the underground gas storage of the salt cavern under the combined action of the Joule-Thomson cooling effect and the environment temperature in the gas production process of the gas storage is realized.
In use, specific examples are incorporated as follows.
The salt cavern volume of a salt cavern well of a certain salt cavern underground gas storage 01 is 25 × 104m3The storage medium is natural gas, the relative density of the natural gas is 0.575, and the gas production rate is 110000m under the emergency operation condition3The salt cavern pressure is 6MPa to 17MPa, and the salt cavern pressure is 30000m under the normal operation condition3H) the salt cavern pressure is 7MPa to 17MPa, the specification of an injection-production pipe is 177.8mm, the internal flow diameter of a well head is 159.4mm, and the water content of the gas reservoir in 2010 million cubic meters is 7.4 × 10-4kg/m3. The simulation results of multiple injection and production cycle operation of the gas reservoir are shown in table 1. Judging the maximum wellhead pressure and the minimum well under the emergency operation condition and the normal operation condition according to the pressure and temperature curve of the hydrateThe port pressures correspond to well head temperatures that are all below the curve (as shown in fig. 3). The probability of the ambient temperature causing wellhead hydrate plugging in these four cases is calculated according to the present invention as follows.
Table 1 simulation results were run under multiple injection and production cycles of the gas reservoir.
1) Time t at which hydrate formation conditions existassumed。
Firstly, the wellhead pressure in the table 1 is substituted into the formula 1 or the formula 2 to calculate the corresponding hydrate generation critical temperature, the cooling degree required by hydrate generation is calculated according to the formulas (1), (2) and (3), then the number of days of the gas temperature drop caused by the local environment temperature every year is the cooling degree, the number of days of the temperature interval in which the cooling degree is located is counted in the preferred embodiment, the division of the temperature interval is shown in the table 2, the existence time of the hydrate generation condition is determined, and the result is shown in the table 3.
Table 2 days for which the local ambient temperature caused the gas temperature to decrease to the cooling degree.
Table 3 calculation of the time at which hydrate formation conditions exist.
2) Time t for formation of 1 m long hydrate1m。
The emergency operating conditions are calculated as follows:
firstly, S isw＝7.4×10-4kg/m3，Qg＝2.64×106m3The formula (5) is substituted by/d, and the daily availability is calculatedMass M of water in which hydrate is formedw＝22.44kg/d；
Then M is addedwSubstituting formula (4) to calculate the maximum mass M of hydrate generated by natural gas and saturated waterh＝24.4Kg。
And calculating the mass of the hydrate forming the hydrate plug with the length of 1 meter by the shaft or the wellhead according to the formula (6), wherein the mass of the hydrate forming the hydrate plug with the length of 1 meter by the shaft is 55.02Kg, and the mass of the hydrate forming the hydrate plug with the length of 1 meter by the wellhead is 18 Kg.
Will MhAnd M1mSubstituting the formula (7), and calculating the number of days t for forming 1 meter long hydrate blockage on the shaft or the wellhead1m2.25d and 0.73d, respectively.
The normal operating conditions are calculated as follows:
firstly, S isw＝7.4×10-4kg/m3，Qg＝7.2×105m3D is substituted by formula (5), calculating the mass M of water available to form hydrates per dayw＝5.328kg/d。
Then M is addedwSubstituting formula (4) to calculate the maximum mass M of hydrate generated by natural gas and saturated waterh＝5.809Kg。
And calculating the mass of the hydrate forming the hydrate plug with the length of 1 meter by the shaft or the wellhead according to the formula (6), wherein the mass of the hydrate forming the hydrate plug with the length of 1 meter by the shaft is 55.02Kg, and the mass of the hydrate forming the hydrate plug with the length of 1 meter by the wellhead is 18 Kg.
Will MhAnd M1mSubstituting the formula (7), and calculating the number of days t for forming 1 meter long hydrate blockage on the shaft or the wellhead1m9.47d and 3.09d, respectively.
3) And (4) calculating the plugging probability of the wellhead hydrate.
The emergency operating conditions are calculated as follows, for example:
will t1mThe time of existence t of hydrate formation condition corresponding to the maximum wellhead pressure under the emergency operation condition in Table 3assumedSubstituting into formula (8), namely obtaining the probability of the shaft or the wellhead pipe plugging of 1.46 × 10-1And 1.
Will t1mAnd table 3 best under emergency operating conditionsExistence time t of hydrate generation condition corresponding to small wellhead pressureassumedAnd (4) substituting the formula (8), namely obtaining the probability of shaft or well mouth pipe plugging as 1 and 1 respectively.
The normal operating conditions are calculated as follows:
will t1mThe time of existence t of hydrate formation condition corresponding to the maximum wellhead pressure under the emergency operation condition in Table 3assumedSubstituting into formula (8), namely obtaining the probability of plugging the well shaft or the well mouth respectively to be 3.48 × 10-2And 1.07 × 10-1。
Will t1mThe time of existence t of hydrate formation condition corresponding to the minimum wellhead pressure under the emergency operation condition in Table 3assumedSubstituting into formula (8), namely obtaining the probability of plugging the well shaft or the well mouth respectively as 3.17 × 10-1And 9.7 × 10-1。
From the calculation results, it can be known that: the probability of blockage of the generated hydrate under the emergency operation condition is higher than the probability of pipe blockage under the normal operation condition, so the blockage risk of the generated hydrate under the emergency operation condition is higher.
Claims (6)
1. A method for measuring the risk of hydrate blockage of a wellhead of a salt cavern underground gas storage is characterized by comprising the following steps:
step 1, determining the cooling degree delta T required by hydrate generation in the gas production process of a salt cavern gas storage; the cooling degree delta T is the temperature difference between the wellhead gas temperature and the hydrate stable region boundary, and is obtained through the following steps;
1.1, the pressure and temperature change curves of the natural gas hydrate stable region are expressed by the following formula (1) and formula (2),
Pk＝9.79634×10-5T4-0.10809T3+44.746T2-8236.3T+568737.4(T＞273.16K) (1)；
Pk＝0.075×T-17.887(T≤273.16K) (2)；
wherein: pkIs the gas pressure; t is the gas temperature;
1.2, adjusting the wellhead gas temperature TwellheadAnd corresponding wellhead gas pressure PwellheadSubstituted type(1) And (2) calculating to obtain the critical temperature T for generating the hydratec；
1.3, calculating the cooling degree required by the generation of the hydrate according to the formula (3);
ΔT＝Twellhead-TC(3)；
step 2, determining the duration T when the environment change temperature is equal to the cooling degree delta TassumedI.e. the time at which hydrate formation conditions exist;
step 3, calculating the maximum mass M of the hydrate generated by the natural gas and the water generated every dayh(ii) a The maximum mass M of the hydrate formed by the natural gas and the water generated every day is calculated according to the following formula (4)h；
Wherein: mwIs the mass of water available to generate hydrates per day; wmol(h)Mass per mole hydrate; wmol(w)Mass per mole of water;
step 4, calculating the mass M of the hydrate blocked by the hydrate with the length of 1 meter formed in the shaft or the well mouth according to the sectional area of the shaft or the well mouth1m；
Step 5, calculating the days t for forming the hydrate blockage with the length of 1 meter according to the results of the steps 3 and 41m；
Step 6, according to the existing time t of the hydrate generating conditionassumedAnd calculating the wellhead hydrate blockage probability of the salt cavern underground gas storage according to the time for forming the hydrate with the length of 1 meter, wherein the probability is equal to the quotient of the time for forming the hydrate under the condition that the hydrate is formed and the time for forming the hydrate blockage length;
and 7, taking the blocking probability of the salt cavern underground gas storage wellhead hydrate as an index, wherein the higher the probability is, the higher the blocking risk of the salt cavern underground gas storage wellhead hydrate is.
2. The method for determining the risk of hydrate blockage of the wellhead of the salt cavern underground gas storage according to claim 1, characterized by comprising the following assumptions,
(1) formation of 1 meter long hydrates will cause plugging of the facility;
(2) the ambient changing temperature occurs in the wellbore due to the ambient temperature cooling the wellhead and upper portion of the wellbore;
(3) assuming that water is saturated in the produced gas and that no free water is produced with the natural gas;
(4) molecular formula of hydrate is CH4(H2O)34Molecular weight is 628 g.
3. The method for determining the risk of hydrate blockage at a wellhead of a salt cavern underground gas storage according to claim 1, wherein in the step 2, the duration T when the environment change temperature is equal to the cooling degree delta T is determinedassumed(ii) a The number of days that the gas temperature is decreased by Δ T according to the local ambient temperature per year is counted as the time T when the hydrate formation condition is presentassumed。
4. The method for determining the risk of hydrate blockage at a wellhead of a salt cavern underground gas storage according to claim 1, wherein the mass M of water available for hydrate formation per daywCan be estimated according to equation (5);
Mw＝ASwQg(5)；
wherein A is the proportion of water produced along with natural gas in each day for generating hydrate, and the unit percent is 1 percent; swIs the saturation coefficient of water in each cubic meter of natural gas and has the unit of Kg/m3；QgIs the maximum gas production rate in m3/d。
5. The method for measuring the hydrate blockage risk of the wellhead of the salt cavern underground gas storage according to claim 1, wherein in the step 4, the amount of hydrate substances forming the hydrate blockage with the length of 1 meter on the shaft or the wellhead is calculated according to the formula (6):
M1m＝1×Awellhead×ρhydrate(6)；
wherein M is1mFormation of 1 meter long hydrate for wellbore or wellheadThe amount of hydrate material that plugs; a. thewellheadIs the area of the wellbore or wellhead; rhohydrateIs hydrate CH4(H2O)34The density of (c).
6. The method for measuring the hydrate blockage risk of the wellhead of the salt cavern underground gas storage according to claim 1, wherein in the step 5, the number of days for forming the hydrate blockage with the length of 1 meter is calculated according to the formula (7):
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