CN113189309A - Method for determining retrograde condensate oil saturation - Google Patents
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Abstract
The invention provides a method for determining the saturation of retrograde condensate oil, which comprises the following steps: 1) at T0And P0Injecting a condensate gas sample into the inlet end of the first core which is saturated by the bound water until the condensate gas sample of the first core is saturated; 2) standing the first core, then reducing the pressure at the outlet end of the first core, injecting dry gas into the inlet end of the first core, and collecting a first outflow sample at the outlet end of the first core; 3) obtaining the gas-phase permeability of the condensate oil under the average pressure; 4) and obtaining the retrograde condensate oil saturation of the condensate gas sample under the average pressure according to the corresponding relation among the gas phase permeability, the gas phase permeability of the condensate oil and the oil saturation. The method can determine the condensate oil saturation of condensate gas under different pressure conditions in the circulating gas injection process, and quantitatively evaluate the condensate oil loss and the gas phase flow energy thereofThe influence of force is of great significance.
Description
Technical Field
The invention discloses a method for determining the saturation of retrograde condensate oil, and belongs to the field of oil and gas field development engineering.
Background
Retrograde condensation is a common phenomenon in depleted exploitation of condensate gas reservoirs. In the development process of the condensate gas reservoir, along with the continuous reduction of the formation pressure, condensate oil can be separated out by reverse condensation in the formation to form a gas phase and a liquid phase, and the gas phase flow capacity is reduced, so that the recovery ratio is reduced. At present, most condensate gas fields adopt a dry gas reinjection mode to carry out gas injection development, the formation pressure is kept above the system dew point pressure, the precipitation of condensate oil is slowed down, and the recovery ratio is improved. However, as the gas field enters the later stage of development, the formation pressure is already significantly lower than the system dew point pressure, and due to the reverse condensation effect of the near wellbore zone, condensate in liquid phase is formed. When the precipitated condensate does not reach the critical flowable saturation degree, the condensate does not flow, but the flow of the gas phase is influenced, namely, additional resistance of the flow is formed, and further, the yield of the condensate gas reservoir gas well is influenced. The retrograde condensate oil saturation is an important parameter reflecting the flowing capacity of the condensate oil, and has great influence on the recovery ratio of the condensate oil, the productivity of a gas well and the stable production period, so the retrograde condensate oil saturation is a hot problem of domestic and foreign research.
At present, a high-temperature high-pressure experiment is a main method for determining the retrograde condensate saturation of a condensate gas reservoir, but most of the experiments are based on a gas reservoir depletion type development mode, so that the determination of the retrograde condensate saturation of the condensate gas reservoir under different pressure conditions in a circulating gas injection process has important significance for quantitative evaluation of condensate loss and influence of the retrograde condensate saturation on gas phase flow capacity.
Disclosure of Invention
The invention provides a method for determining the retrograde condensate oil saturation, which can determine the retrograde condensate oil saturation of condensate gas under different pressure conditions in a circulating gas injection process and has important significance for quantitatively evaluating the condensate oil loss and the influence of the condensate oil loss on the gas phase flow capacity.
The invention provides a method for determining the saturation of retrograde condensate oil, which comprises the following steps:
1) at T0And P0Injecting a condensate gas sample into the inlet end of the first core which is saturated by the bound water until the condensate gas sample of the first core is saturated;
2) standing the first core, and then reducing the pressure of the outlet end of the first core to P1And injecting dry gas into the inlet end of the first core so that the pressure of the inlet end of the first core is P2Collecting a first outflow sample at the outlet end of the first core;
3) according to P1、P2、t1The volume and viscosity of the gas in the first effluent sample and the length and cross-sectional area of the first core are used to obtain the average pressure P12Gas phase permeability K of lower condensate12；
4) According to K12And obtaining the corresponding relation between the gas phase permeability of the condensate oil and the oil saturation degree to obtain P12(ii) lowering the retrograde condensate saturation of the condensate sample;
wherein, T0Is the actual temperature of the formation, P0Is the actual pressure of the formation, t1The injection time of the dry gas.
The method for determining the saturation of the retrograde condensate oil comprises the following steps of, before the step 4), obtaining the corresponding relation between the gas phase permeability and the oil saturation of the condensate oil according to the following method:
a) injecting condensate oil into the inlet end of the water-saturated second core until the condensate oil of the second core is saturated;
b) at T0And P0Standing the second core downwards, and then reducing the pressure of the outlet end of the second core to P3And injecting dry gas into the inlet end of the second core so that the pressure of the inlet end of the second core is P4Collecting a second outflow sample at the outlet end of the second core;
c) acquiring the oil saturation of the second core according to the volume of the liquid in the second effluent sample and the volume of the condensate oil in the second core during standing;
d) according to P3、P4、t2Obtaining the gas-phase permeability K, t of the condensate oil of the second core under the oil saturation degree by using the volume and viscosity of the gas in the second effluent sample and the length and cross-sectional area of the second core2The injection time of the dry gas;
e) adjusting P3、P4And the steps b) -d) are circulated for N times, and the oil saturation of N different second cores and the gas phase permeability of condensate oil of the N different second cores under the oil saturation are obtained; n is more than or equal to 6;
f) and establishing a corresponding relation between the gas-phase permeability of the condensate oil and the oil saturation according to the oil saturation of the N different second cores and the gas-phase permeability of the condensate oil under the oil saturation of the N different second cores.
The method for determining the retrograde condensate saturation as described above, wherein in step 3), the method is based on P1、P2、t1The above-mentionedThe volume and viscosity of the gas in the first effluent sample and the length and cross-sectional area of the first core are used for obtaining the average pressure P12Gas phase permeability K of lower condensate12Comprising calculating said mean pressure P according to equation 112Gas phase permeability K of lower condensate12，
In the formula 1, Vg1Is the volume of gas in the first effluent sample, μ is the viscosity of the gas in the first effluent sample, L is the length of the first core, and a is the cross-sectional area of the first core.
The method for determining the retrograde condensate saturation degree as described above, wherein in the step c), the obtaining the oil saturation degree S of the second core according to the liquid volume in the second outflow sample and the condensate volume in the second core at the time of standing comprises calculating the oil saturation degree S of the second core according to equation 2,
in formula 2, S is the oil saturation of the second core, Vo2Is the volume of liquid in the second effluent sample, VoIs the condensate volume in the second core at rest.
The method for determining the retrograde condensate saturation as described above, wherein in step d), the method is based on P3、P4、t2Obtaining the gas phase permeability K of the condensate oil of the second core under the oil saturation degree according to the volume and the viscosity of the gas in the second effluent sample and the length and the cross-sectional area of the second core, wherein the gas phase permeability K of the condensate oil is calculated according to a formula 3,
in the formula 3, Vg2Is the volume of gas in the second effluent sample, μ is the viscosity of the gas in the second effluent sample, L is the length of the second core, and a is the cross-sectional area of the second core.
The method for determining the retrograde condensate saturation degree as described above, wherein the first effluent sample is subjected to gas-liquid separation to obtain a gas volume in the first effluent sample;
and carrying out gas-liquid separation on the second effluent sample to obtain the gas volume and the liquid volume in the second effluent sample.
The method for determining the retrograde condensate saturation degree, wherein in the step 1), injecting the condensate sample into the inlet end of the first core, which is saturated by the bound water, until the condensate sample of the first core is saturated, includes:
and injecting the condensate gas sample into the inlet end of the first core establishing bound water saturation until the gasoline ratio of the effluent at the outlet end of the first core is equal to that of the condensate gas sample.
The method for determining retrograde condensate saturation as described above, wherein the first core and the second core are taken from an actual reservoir.
The method for determining the retrograde condensate saturation degree is characterized in that before the condensate sample is injected into the inlet end of the first core which establishes the bound water saturation, the radial pressure of the first core is controlled to be greater than the pore pressure of the first core.
The method for determining the retrograde condensate saturation degree includes, in step b), controlling the radial pressure of the second core to be greater than the pore pressure of the second core.
The method for determining the retrograde condensate oil saturation is based on a conventional core failure experiment and a phase permeability curve testing method, is reliable, simple and applicable in principle, comprehensively considers the influences of a porous medium, water saturation and condensate oil flow, can accurately and objectively determine the retrograde condensate oil saturation of condensate gas under different pressure conditions in the circulating gas injection process, has important significance for quantitatively evaluating the condensate oil loss and the influence of the retrograde condensate oil saturation on the gas phase flow capacity, and has very wide market prospect.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings needed to be used in the description of the embodiments or the prior art will be briefly introduced below, and it is obvious that the drawings in the following description are some embodiments of the present invention, and for those skilled in the art, other drawings can be obtained according to these drawings without creative efforts.
FIG. 1 is a graph of gas phase permeability versus oil saturation for condensate from well No. 1 of an example of the present invention;
FIG. 2 is a graph of pressure versus gas phase permeability for well number 1 of an embodiment of the present invention;
FIG. 3 is a graph of pressure versus retrograde condensate saturation for well number 1 in accordance with an embodiment of the present invention;
FIG. 4 is a graph of pressure versus retrograde condensate saturation for a gas reservoir in accordance with an embodiment of the present invention.
Detailed Description
In order to make the objects, technical solutions and advantages of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the embodiments of the present invention. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
The invention provides a method for determining the saturation of retrograde condensate oil, which comprises the following steps:
s101: at T0And P0And injecting a condensate gas sample into the inlet end of the first core which is used for establishing bound water saturation until the condensate gas sample of the first core is saturated.
In order to improve the accuracy of the retrograde condensate saturation determination method, the first core adopted by the invention is from an actual reservoir. Before S101, the first core needs to be pretreated (e.g., washed and dried), and its diameter, length, permeability and porosity are measured, wherein the measurement method is the same as the measurement method in the prior art.
It is noted that if the first core needs to be spliced, splicing may be performed according to a czochralski arrangement.
Firstly, bound water saturation needs to be established on the pretreated first core, specifically, the operation of establishing bound water saturation comprises injecting formation water of an actual reservoir into the dried and vacuumized first core to enable the first core to be saturated with water, and then injecting formation water of an actual reservoir into the first core at an actual temperature T of the formation0And the actual formation pressure P0And injecting nitrogen into the first core through the inlet end of the first core until the outlet end of the first core does not produce water, thereby completing the establishment of the bound saturated water of the first core. And the formation water volume of the formation water for injecting the actual reservoir into the first core is the pore volume of the first core, and the pore volume of the first core is calculated according to the formula 4.
In formula 4, V is the pore volume (ml) of the first core, L is the length (cm) of the first core, D is the diameter (cm) of the first core,
porosity (%) of the first core.
After the first core bound saturated water is established, the actual temperature T of the stratum0And the actual formation pressure P0And injecting a condensate gas sample into the inlet end of the first core until the condensate gas sample of the first core is saturated.
Specifically, the condensate gas sample is continuously injected from the inlet end of the first core until the gas-oil ratio of the effluent collected at the outlet end of the first core is equal to the gas-oil ratio of the injected condensate gas sample, and the condensate gas sample is proved to be full of the first core at the moment, so that the injection of the condensate gas sample is stopped. The condensate gas sample is prepared by taking natural gas, condensate oil and formation water produced by a wellhead of an actual condensate gas reservoir as raw materials and referring to dew point pressure and gasoline ratio GOR in a gas reservoir original formation fluid property analysis report (PVT analysis report).
In addition, before the condensate gas sample is injected into the inlet end of the first core which is used for establishing bound water saturation, the radial pressure of the first core can be controlled to be larger than the pore pressure of the first core.
In the invention, the difference between the radial pressure of the first core and the pore pressure of the first core is controlled to be about 3 MPa.
S102: standing the first core, and then reducing the pressure of the outlet end of the first core to P1And injecting dry gas into the inlet end of the first core so that the pressure at the inlet end of the first core is P2And collecting a first outflow sample at the outlet end of the first core.
Standing the first rock core to enable a condensate gas sample in the first rock core to be at T0And P0After fully balancing, reducing the pressure at the outlet end of the first rock core to P1Thereby achieving a reduction in pore pressure in the first core. Meanwhile, according to a cyclic gas injection development mode and a design injection-production ratio, dry gas (dry gas in the actual production process) is injected into the inlet end of the first core so that the pressure at the inlet end of the first core is P2And collecting a first effluent sample from the exit end of the first core.
In S102, the radial pressure of the first core is maintained to be controlled, so that the radial pressure of the first core is greater than the pore pressure of the first core.
P is above1、P2Is an experimental pressure which can be determined according to specific experimental conditions; t is t1The pressure of the inlet end of the first core from the time of injecting dry gas to P2The time used is the time for injecting the dry gas.
S103: according to P1、P2、t1The volume and viscosity of the gas in the first effluent sample and the length and cross-sectional area of the first core are used to obtain the average pressure P12Gas phase permeability K of lower condensate12。
Wherein the pressure P is evaluated12Is referred to as P1、P2The cross-sectional area of the first core was calculated according to equation 5,
A＝0.25πD2formula 5
In formula 5, A is the cross-sectional area (cm) of the first core2) And D is the diameter (cm) of the first core.
After the first effluent sample flowing out of the first core outlet end is collected in S102 (at normal temperature and normal pressure), the gas-liquid separation device is required to perform gas-liquid separation on the first effluent sample, and the gas volume V obtained after the gas-liquid separation is recordedg1And detecting the viscosity mu of the gas obtained after gas-liquid separation.
Subsequently, using P1、P2、t1The volume and viscosity of the gas in the first effluent sample and the length and cross-sectional area of the first core to obtain the average pressure P12Gas phase permeability K of gas condensate in lower first core12。
In one embodiment, P is utilized1、P2、t1The volume and viscosity of the gas in the first effluent sample and the length and cross-sectional area of the first core to obtain the average pressure P12Gas phase permeability K of gas condensate in lower first core12The method comprises the following steps: calculating the mean pressure P according to equation 112Gas phase permeability K of lower condensate12，
In the formula 1, Vg1Is the volume (ml) of gas in the first effluent sample, μ is the viscosity (mpa.s) of gas in the first effluent sample, L is the length (cm) of the first core, a is the cross-sectional area (cm) of the first core2)。
S104: according to K12And obtaining the corresponding relation between the gas phase permeability of the condensate oil and the oil saturation degree to obtain P12The retrograde condensate saturation of the condensate sample is as follows.
The corresponding relation between the gas-phase permeability and the oil saturation of the condensate oil refers to a functional relation between the gas-phase permeability and the oil saturation of the condensate oil, namely, the known gas-phase permeability of the condensate oil is substituted into the corresponding relation on the basis of the corresponding relation, so that the oil saturation corresponding to the gas-phase permeability can be obtained; by substituting the known oil saturation into the correspondence relationship, the gas-phase permeability of the condensate corresponding to the oil saturation can be obtained.
Due to gas phase permeability K of the condensate oil in the first core12With the mean pressure P12Correlation, therefore, the gas phase permeability K of the condensate oil in the first core12By substituting into the correspondence, the average pressure P can be obtained12Retrograde condensate saturation of the gas condensate sample below.
The technical scheme provided by the invention comprehensively considers the influences of a porous medium, water saturation and condensate flow, so that the condensate saturation can be correctly and objectively determined under different pressure conditions in the circulating gas injection process, and the method has important significance for quantitatively evaluating the condensate loss and the influence of the condensate loss on the gas phase flow capacity.
In one embodiment, the gas phase permeability versus oil saturation of the condensate can be obtained by the following steps.
S201: and injecting condensate oil into the inlet end of the water-saturated second core until the condensate oil of the second core is saturated.
In order to improve the accuracy of the retrograde condensate saturation determination method, the second core adopted by the invention is from an actual reservoir. Before S201, the second core needs to be pretreated (e.g., washed and dried), and its diameter, length, permeability and porosity are measured, wherein the measurement method is the same as the existing measurement method in the art.
It is noted that if the second core needs to be spliced, splicing can be performed according to a czochralski arrangement.
Firstly, establishing water saturation for the pretreated second core, specifically, the operation of establishing water saturation comprises injecting formation water of an actual reservoir into the dried and vacuumized second core, and the injection volume of the formation water of the actual reservoir is equal to the pore volume of the second core, so that the second core is saturated with water. Wherein the pore volume of the second core is calculated according to equation 6.
In formula 6, V is the pore volume (ml) of the second core, L is the length (cm) of the second core, D is the diameter (cm) of the second core,
porosity (%) of the second core.
Then at the actual formation temperature T0And the actual formation pressure P0Then, the condensate oil is injected into the end of the second core through the inlet end of the second core until the outlet end of the second core does not produce water, thereby completing the condensate oil saturation of the second core, and recording the volume V of the injected condensate oilo。
S202: at T0And P0The second core is stood downwards, and then the pressure of the outlet end of the second core is reduced to P3And injecting dry gas into the inlet end of the second core so that the pressure at the inlet end of the second core is P4And collecting a second outflow sample at the outlet end of the second core.
Standing the second rock core for about 0.5 hour to make the volume in the second rock core be VoThe condensate of (A) is at T0And P0After fully balancing, reducing the pressure at the outlet end of the second rock core to P3Thereby achieving a reduction in pore pressure in the second core. Meanwhile, according to a cyclic gas injection development mode and a design injection-production ratio, dry gas (dry gas in the actual production process) is injected into the inlet end of the second core so that the pressure at the inlet end of the second core is P4And collecting a second effluent sample at an outlet end of the second core.
In S202, the radial pressure of the second core may be controlled such that the radial pressure of the second core is greater than the pore pressure of the second core.
In the invention, the difference between the radial pressure of the second core and the pore pressure of the second core is controlled to be about 3 MPa. P is above3、P4Is an experimental pressure which can be determined according to specific experimental conditions; t is t2The inlet end of the second core is from the pressure when the dry gas is injected to P4The time used is the time for injecting the dry gas.
S203: and acquiring the oil saturation of the second core according to the liquid volume in the second effluent sample and the condensate oil volume in the second core when the second effluent sample is static.
After the second effluent sample flowing out of the second core outlet end is collected in S202 (at normal temperature and normal pressure), the gas-liquid separation device is required to perform gas-liquid separation on the second effluent sample, and the gas volume V obtained after the gas-liquid separation is recordedg2And the resulting liquid volume Vo2And the volume obtained after gas-liquid separation is Vg2The viscosity μ of the gas (c) is measured.
Subsequently, the volume V of the liquid in the second effluent sample is usedo2And the condensate volume V in the second core at restoAnd acquiring the oil saturation S of the current second core.
In one embodiment, the oil saturation S of the second core may be calculated using equation 2,
in the formula 2, S is the oil saturation (%) of the second core, and Vo2Volume of liquid in the second effluent sample (ml), VoVolume of condensate (ml) in the second core at rest.
S204: according to P3、P4、t2And the gas volume and viscosity of the second effluent sample and the length and cross-sectional area of the second core are used for obtaining the gas phase permeability K of the condensate oil of the second core under the oil saturation degree.
Wherein the saturation is the oil saturation S in S203, the cross section of the second core is calculated according to the formula 7,
A＝0.25πD2formula 7
In formula 7, A is the cross-sectional area (cm) of the second core2) And D is the diameter (cm) of the second core.
Subsequently, using P3、P4、t2Volume of gas in the second effluent sample Vg2And the viscosity mu, the length and the cross-sectional area of the first core, and the gas-phase permeability K of the condensate oil of the second core under the oil saturation degree.
In one embodiment, P is utilized3、P4、t2Volume of gas in the second effluent sample Vg2And the viscosity mu and the length and the cross-sectional area of the second core, and the gas phase permeability K of the condensate oil of the second core under the oil saturation is obtained, wherein the gas phase permeability K comprises: calculating the gas phase permeability K of the condensate oil according to the formula 3,
in the formula 3, Vg2Is the volume of gas in the second effluent sample, μ is the viscosity of the gas in the second effluent sample, L is the length of the second core, and a is the cross-sectional area of the second core.
S205: adjusting P3、P4Circulating the steps S202-S204N times to obtain the oil saturation of the N different second cores and the gas phase permeability of condensate oil of the N different second cores under the oil saturation; n is more than or equal to 6.
In the above-mentioned S202-204, it is found that3、P4The oil saturation S of the lower second core and the gas phase permeability K of the second core for condensate oil at the saturation S. In S205, the second core may be rested to have a volume (V) in the second coreo-Vo2) The condensate is fully balanced in the second core, and then the pressure at the outlet end of the second core is reduced to P5(P5And P3Different) to effect a reduction in pore pressure in the second core. Meanwhile, according to the mode of cyclic gas injection development and according to design, injection and productionIn comparison, dry gas (dry gas in the actual exploitation process) is injected into the inlet end of the second core so that the pressure at the inlet end of the second core is P6(P6And P4Different), and a second effluent sample was collected at the exit end of the second core.
After a second effluent sample flowing out of the second core outlet end is collected, gas-liquid separation needs to be performed on the second effluent sample by using a gas-liquid separation device, the gas volume obtained after the gas-liquid separation and the liquid volume obtained after the gas-liquid separation are recorded, and the viscosity of the gas with the volume obtained after the gas-liquid separation is detected.
Subsequently, the liquid volume in the second effluent sample and the condensate volume (V) in the second core at rest are usedo-Vo2) Then (P) is obtained according to equation 25、P6) Oil saturation S of the second core.
And then (P) is obtained according to equation 35、P6) And under the oil saturation S of the second core, the gas-phase permeability K of the condensate oil.
After N times of circulation, the oil saturation of N different second cores and the gas phase permeability of N different condensate oils can be obtained.
S206: and establishing a corresponding relation between the gas-phase permeability of the condensate oil and the oil saturation according to the oil saturation of the N different second cores and the gas-phase permeability of the condensate oil under the oil saturation of the N different second cores.
Specifically, taking points on a coordinate axis by taking gas phase permeability of N different condensate oils as an abscissa and taking oil saturation of N different second cores as an ordinate, and obtaining N coordinates; and fitting the N coordinates to obtain a curve and an equation S ═ f (K) thereof, wherein the equation is the corresponding relation between the gas-phase permeability and the oil saturation of the condensate oil. The correlation coefficient of the equation can be made larger than 0.9 by increasing the number of N in the present invention.
The method for determining the retrograde condensate saturation level of the present invention will be described in detail below with reference to specific examples.
1. Obtaining the corresponding relation between the gas phase permeability and the oil saturation of the condensate oil
1) The full diameter core of the actual reservoir was obtained, washed, dried, and the diameter D (9.987cm), length L (9.21cm), and permeability K were measured0(13.255mD), porosity
(12.5%), core splicing is carried out according to a pulling method base arrangement mode;
2) obtaining natural gas, condensate oil and formation water produced by a wellhead of an actual condensate gas reservoir, and obtaining a dry gas sample injected by the actual condensate gas reservoir, wherein the pressure of the gas reservoir is 45.37MPa, and the temperature of the gas reservoir is 134.5 ℃;
3) calculating core pore volume
Vacuumizing the dried rock sample, and injecting formation water with the volume of 90.138(ml) into the rock core to saturate the rock core;
4) injecting condensate oil into the rock core from the rock core inlet end until no water is discharged from the rock core outlet end, and measuring the accumulated water discharge volume Vw(65ml), the volume V of condensate injected is recordedoCalculating irreducible water saturation SwsDetermining the initial oil saturation S in the core (90.138-65)/90.138 × 100% ═ 26.78%o＝(1－0.2678)×100％＝73.22％；
5) Standing a saturated sample core under a stratum condition to ensure that fluid in the core is fully balanced;
6) after the fluid in the core is fully balanced, releasing a formation fluid sample at the outlet end of the core so as to reduce the pore pressure in the core, simultaneously, according to a circulating gas injection development mode, according to a design injection-production ratio of 1:1, performing gas injection back pressure at the inlet end of the core (the injected gas is a dry gas sample), condensing and separating the released sample at the outlet end, and always maintaining the radial pressure P of the core in the processdSlightly above pore pressure PfRecording the test time t2Pressure at core inlet end P4Pressure at outlet end P3And the outlet volume of the outlet end of the rock core obtained by condensation separation is Vg2Oil phase volume of Voi；
7) According to the formula (V)o-Voi)/VoCalculating the oil saturation S in the rock core by multiplying 100%;
8) calculating the gas phase permeability K of the rock core under the oil saturation S according to the following formula:
in the formula:
μ -gas viscosity, mPa · s; l is the length of the core, cm; a-core Cross-sectional area, cm2
9) First stage pressure (inlet end pressure P)4Pressure at outlet end P3) After the test is finished, the outlet end valve needs to be closed, after the fluid in the rock core is fully balanced, the oil saturation and the gas phase permeability in the rock core of the next pressure point are tested, and the specific result is shown in table 1;
taking the gas phase permeability of the condensate oil in the table 1 as an abscissa and the oil saturation corresponding to the gas phase permeability as an ordinate to take points on a coordinate axis to obtain 9 coordinates; fitting the 9 coordinates to obtain a curve and an equation thereof;
fig. 1 is a plot of gas phase permeability versus oil saturation for condensate from well No. 1 of an example of the present invention, with the equation for S-5.842 lnK + 9.0528.
TABLE 1
2. Determination of retrograde condensate saturation
1) The full diameter core of the actual reservoir was obtained, washed, dried, and the diameter D (9.987cm), length L (9.21cm), and permeability K were measured0(13.255mD), porosity
(12.5%), core splicing is carried out according to a pulling method base arrangement mode;
2) obtaining natural gas, condensate oil and formation water produced by a wellhead of an actual condensate gas reservoir, and obtaining a dry gas sample injected by the actual condensate gas reservoir, wherein the pressure of the gas reservoir is 45.37MPa, and the temperature of the gas reservoir is 134.5 ℃;
3) reference to dew point pressure P in gas reservoir virgin formation fluid property analysis report (PVT analysis report)b(47.47MPa), GOR with single degassing-oil ratio1(3135m3/m3) Preparing a formation fluid sample, namely a condensate gas sample, and putting the prepared formation condensate gas sample into an intermediate container for later use;
4) calculating core pore volume
Vacuumizing the dried rock sample, and injecting formation water with the volume of 90.138(ml) into the rock core to saturate the rock core;
5) pumping nitrogen into an intermediate container by using a booster pump, boosting the pressure to the experimental pressure temperature condition (original formation pressure and temperature), displacing formation water in the rock core by using the nitrogen until the outlet end of the rock core does not produce water, enabling the water in the rock core to be in a bound state, and measuring the volume V of accumulated waterwCalculating irreducible water saturation Sws＝(V－Vw)/V×100％；
6) After bound water is built, the nitrogen gas inlet valve is closed, then the temperature is gradually increased and pressurized until the pore pressure and temperature of the rock core are consistent with the original formation pressure and temperature of the gas reservoir, and the radial pressure P applied to the rock coredSlightly above pore pressure Pf(3 MPa), injecting the prepared formation fluid sample into the rock core, and testing the gas-oil ratio GOR of the outlet end of the rock core every 0.5 hour2Up to and with GOR1The consistency is achieved;
7) standing the saturated sample core under the stratum condition to ensure that the fluid in the long core is fully balanced;
8) after the fluid in the rock core is fully balanced, releasing a formation fluid sample at the outlet end of the rock core, thereby realizing rock reductionIn the pressure of the central pore space, simultaneously, according to the mode of circulating gas injection development and the design injection-production ratio of 1:1, gas injection back pressure is carried out at the inlet end of the core (the injected gas is a dry gas sample), the outlet end is used for discharging the sample for condensation and separation, and the radial pressure P of the core is always kept in the processdSlightly above pore pressure PfRecording the test time t1Pressure at core inlet end P2Pressure at outlet end P1And the outlet volume of the outlet end of the rock core obtained by condensation separation is Vg1；
9) The mean pressure P during the experiment was calculated according to the following formula12Gas phase permeability K under the conditions12，
In the formula:
μ -gas viscosity, mPa · s; l is the length of the core, cm; a-core Cross-sectional area
10) First stage pressure (core inlet pressure P)2Pressure at outlet end P1) After the test is finished, the gas outlet valve needs to be closed, the gas phase permeability of the next pressure point is tested after the fluid in the rock core is fully balanced, and the specific result is shown in a table 2;
taking the average pressure in the table 2 as an abscissa and the gas permeability corresponding to the average pressure as an ordinate to take points on a coordinate axis to obtain 9 coordinates; fitting the 9 coordinates to obtain a curve and an equation thereof;
FIG. 2 is a graph of pressure versus gas permeability for well number 1 of an embodiment of the present invention having the equation K-0.5121 e0.0478P；
11) Substituting K corresponding to each average pressure into S ═ 5.842lnK +9.0528, and calculating the oil saturation value (reverse condensate saturation) at each average pressure, wherein the specific results are shown in table 2;
taking the average pressure in the table 2 as an abscissa and the oil saturation values respectively corresponding to the average pressure as an ordinate, and taking points on a coordinate axis to obtain 9 coordinates; fitting the 9 coordinates to obtain a curve and an equation thereof;
FIG. 3 is a graph of pressure versus retrograde condensate saturation for well number 1 in accordance with an embodiment of the present invention, with the equation S-19.961 e-0.059P；
TABLE 2
| Inlet end pressure (MPa) | Outlet end pressure (MPa) | Mean pressure (MPa) | Gas phase permeability (%) | Oil saturation (%) | |
| 1 | 6 | 4 | 5.0 | 0.66 | 11.5 |
| 2 | 11 | 9 | 10.0 | 0.85 | 10.0 |
| 3 | 16 | 14 | 15.0 | 0.90 | 9.7 |
| 4 | 21 | 19 | 20.0 | 1.43 | 7.0 |
| 5 | 26 | 24 | 25.0 | 1.46 | 6.8 |
| 6 | 31 | 29 | 30.0 | 2.36 | 4.0 |
| 7 | 36 | 34 | 35.0 | 3.42 | 1.9 |
| 8 | 41 | 39 | 40.0 | 3.53 | 1.7 |
| 9 | 45.37 | 44.63 | 45.0 | 3.71 | 1.4 |
12) And selecting the rock cores and fluid samples of other 5 wells of the gas field to repeat the operation to obtain the relation between the pressure and the retrograde condensate saturation degree suitable for the whole gas reservoir, wherein fig. 4 is a graph of the pressure and the retrograde condensate saturation degree of the gas reservoir in the embodiment of the invention. And 4, the retrograde condensate saturation change trend of the remaining wells without experiments can be calculated, and basic data are provided for efficient development of the gas reservoir.
Finally, it should be noted that: the above embodiments are only used to illustrate the technical solution of the present invention, and not to limit the same; while the invention has been described in detail and with reference to the foregoing embodiments, it will be understood by those skilled in the art that: the technical solutions described in the foregoing embodiments may still be modified, or some or all of the technical features may be equivalently replaced; and the modifications or the substitutions do not make the essence of the corresponding technical solutions depart from the scope of the technical solutions of the embodiments of the present invention.
Claims (10)
1. A method for determining the saturation of retrograde condensate oil is characterized by comprising the following steps:
1) at T0And P0Injecting a condensate gas sample into the inlet end of the first core which is saturated by the bound water until the condensate gas sample of the first core is saturated;
2) standing the first core, and then reducing the pressure of the outlet end of the first core to P1And injecting dry gas into the inlet end of the first core so that the pressure of the inlet end of the first core is P2Collecting a first outflow sample at the outlet end of the first core;
3) according to P1、P2、t1The volume and viscosity of the gas in the first effluent sample and the length and cross-sectional area of the first core are used to obtain the average pressure P12Gas phase permeability K of lower condensate12；
4) According to K12And obtaining the corresponding relation between the gas phase permeability of the condensate oil and the oil saturation degree to obtain P12(ii) lowering the retrograde condensate saturation of the condensate sample;
wherein, T0Is the actual temperature of the formation, P0Is the actual pressure of the formation, t1The injection time of the dry gas.
2. The method for determining the saturation degree of retrograde condensate according to claim 1, wherein before the step 4), the method further comprises obtaining the corresponding relation between the gas-phase permeability and the oil saturation degree of the condensate according to the following method:
a) injecting condensate oil into the inlet end of the water-saturated second core until the condensate oil of the second core is saturated;
b) at T0And P0Standing the second core downwards, and then reducing the pressure of the outlet end of the second core to P3And injecting dry gas into the inlet end of the second core so that the pressure of the inlet end of the second core is P4Collecting a second outflow sample at the outlet end of the second core;
c) acquiring the oil saturation of the second core according to the volume of the liquid in the second effluent sample and the volume of the condensate oil in the second core during standing;
d) according to P3、P4、t2Obtaining the gas-phase permeability K, t of the condensate oil of the second core under the oil saturation degree by using the volume and viscosity of the gas in the second effluent sample and the length and cross-sectional area of the second core2The injection time of the dry gas;
e) adjusting P3、P4And recycling steps b) -d) N times, acquiring the oil saturation of N different second cores and the gas phase permeability of condensate oil of the N different second cores under the oil saturation; n is more than or equal to 6;
f) and establishing a corresponding relation between the gas-phase permeability of the condensate oil and the oil saturation according to the oil saturation of the N different second cores and the gas-phase permeability of the condensate oil under the oil saturation of the N different second cores.
3. The method for determining retrograde condensate saturation according to claim 1, wherein in step 3), the method is based on P1、P2、t1The volume and viscosity of the gas in the first effluent sample and the length and cross-sectional area of the first core are used to obtain the average pressure P12Gas phase permeability K of lower condensate12Comprising calculating said mean pressure P according to equation 112Gas phase permeability K of lower condensate12，
In the formula 1, Vg1Is the volume of gas in the first effluent sample, μ is the viscosity of the gas in the first effluent sample, L is the length of the first core, and a is the cross-sectional area of the first core.
4. The method for determining retrograde condensate saturation according to claim 2, wherein the obtaining the oil saturation S of the second core according to the liquid volume in the second effluent sample and the condensate volume in the second core at rest in step c) comprises calculating the oil saturation of the second core according to equation 2,
in formula 2, S is the second coreOil saturation, Vo2Is the volume of liquid in the second effluent sample, VoIs the condensate volume in the second core at rest.
5. Method for determining the retrograde condensate saturation according to claim 2 or 4, wherein in step d) said method is based on P3、P4、t2Obtaining the gas phase permeability K of the condensate oil of the second core under the oil saturation degree according to the volume and the viscosity of the gas in the second effluent sample and the length and the cross-sectional area of the second core, wherein the gas phase permeability K of the condensate oil is calculated according to a formula 3,
in the formula 3, Vg2Is the volume of gas in the second effluent sample, μ is the viscosity of the gas in the second effluent sample, L is the length of the second core, and a is the cross-sectional area of the second core.
6. The method of determining the retrograde condensate saturation level of claim 2, wherein the first effluent sample is subjected to gas-liquid separation to obtain a gas volume in the first effluent sample;
and carrying out gas-liquid separation on the second effluent sample to obtain the gas volume and the liquid volume in the second effluent sample.
7. The method for determining retrograde condensate saturation according to claim 1, wherein the step 1) of injecting the condensate sample into the inlet end of the first core establishing bound water saturation until the first core condensate sample is saturated comprises:
and injecting the condensate gas sample into the inlet end of the first core establishing bound water saturation until the gasoline ratio of the effluent at the outlet end of the first core is equal to that of the condensate gas sample.
8. The method for determining retrograde condensate saturation according to any one of claims 1-2, wherein the first core and the second core are taken from an actual reservoir.
9. The method for determining retrograde condensate saturation according to claim 1, wherein the radial pressure of the first core is controlled to be greater than the pore pressure of the first core before injecting the condensate sample into the inlet end of the first core that establishes bound water saturation.
10. The method for determining retrograde condensate saturation according to claim 2, wherein in step b), the radial pressure of the second core is controlled to be greater than the pore pressure of the second core.
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