1. A method for determining the moving speed of a fluid interface of a condensate gas cap oil reservoir is characterized by comprising the following steps:

acquiring the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area;

obtaining the current formation pressure of the condensate gas cap reservoir according to the original gas cap region pore volume, the current gas cap region pore volume, the original oil ring region pore volume, the current oil ring region pore volume, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap reservoir material balance equation; wherein the condensate gas cap reservoir material balance equation is preset;

and obtaining the oil-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtaining the gas-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the gas cap and the current formation pressure.

2. The method of claim 1, wherein the condensate gas cap reservoir material balance equation is:

V_Gi+V_Oi＝V_G+V_O+ΔV_Tf

wherein, V_GiIs the pore volume, V, of the original gas cap region_OiIs the pore volume, V, of the original oil ring region_GIs the current gas cap zone pore volume, V_OΔ V for the current oil ring zone pore volume_TfIs the total expansion volume of rock in the reservoir calculated according to the following formula:

wherein, C_fIs the rock compression coefficient, p_iIs the average pressure of the condensate gas cap oil deposit under the original condition, p is the current formation pressure of the condensate gas cap oil deposit, m is the ratio of the oil ring pore volume to the gas cap pore volume under the original condition, G is the original natural gas reserve of the condensate gas cap oil deposit, B_giIs the volume coefficient of the gas head gas under the original condition, y_wiIs the water vapor content in the gas phase under the original conditions, S_wcGIs the irreducible water saturation within the gas cap volume.

3. The method of claim 1, wherein said deriving an oil-water interface movement velocity of the condensate gas cap reservoir from the volume of barrier injected water intruding an oil ring and the current formation pressure comprises:

calculating and obtaining the volume of the barrier injected water intrusion oil ring according to the current formation pressure and a first preset formula;

and calculating to obtain the oil-water interface moving speed according to the volume of the barrier injected water invading the oil ring and a second preset formula.

4. The method of any of claims 1 to 3, wherein the deriving a gas-water interface travel velocity for the condensate gas cap reservoir from the volume of barrier injected water intrusion gas cap and the current formation pressure comprises:

calculating and obtaining the volume of the barrier injected water invading gas cap according to the current formation pressure and a third preset formula;

and calculating to obtain the moving speed of the gas-water interface according to the volume of the barrier injected water invading into the gas cap and a fourth preset formula.

5. A device for determining a rate of fluid interface movement in a condensate gas cap reservoir, comprising:

the acquiring unit is used for acquiring the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area;

a first obtaining unit, configured to obtain a current formation pressure of the gas condensate cap reservoir according to the original gas cap region pore volume, the current gas cap region pore volume, the original oil ring region pore volume, the current oil ring region pore volume, a total expansion volume of rocks in the oil and gas reservoir, and a gas condensate cap reservoir material balance equation; wherein the condensate gas cap reservoir material balance equation is preset;

and the second obtaining unit is used for obtaining the oil-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtaining the gas-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the oil ring and the current formation pressure.

6. The apparatus of claim 5, wherein the condensate gas cap reservoir material balance equation is:

V_Gi+V_Oi＝V_G+V_O+ΔV_Tf

wherein, V_GiIs the pore volume, V, of the original gas cap region_OiIs the pore volume, V, of the original oil ring region_GIs the current gas cap zone pore volume, V_OΔ V for the current oil ring zone pore volume_TfIs the total expansion volume of rock in the reservoirThe product is calculated according to the following formula:

wherein, C_fIs the rock compression coefficient, p_iIs the average pressure of the condensate gas cap oil deposit under the original condition, p is the current formation pressure of the condensate gas cap oil deposit, m is the ratio of the oil ring pore volume to the gas cap pore volume under the original condition, G is the original natural gas reserve of the condensate gas cap oil deposit, B_giIs the volume coefficient of the gas head gas under the original condition, y_wiIs the water vapor content in the gas phase under the original conditions, S_wcGIs the irreducible water saturation within the gas cap volume.

7. The apparatus of claim 5, wherein the second obtaining unit comprises:

the first calculating subunit is used for calculating and obtaining the volume of the barrier injection water intrusion oil ring according to the current formation pressure and a first preset formula;

and the second calculating subunit is used for calculating and obtaining the oil-water interface moving speed according to the volume of the barrier injected water invading the oil ring and a second preset formula.

8. The apparatus according to any one of claims 5 to 7, wherein the second obtaining unit comprises:

the third calculation subunit is used for calculating and obtaining the volume of the barrier injected water intrusion gas cap according to the current formation pressure and a third preset formula;

and the fourth calculating subunit is used for calculating and obtaining the moving speed of the gas-water interface according to the volume of the barrier injected water invading the gas cap and a fourth preset formula.

9. An electronic device comprising a memory, a processor and a computer program stored on the memory and executable on the processor, characterized in that the steps of the method of any of claims 1 to 4 are implemented when the computer program is executed by the processor.

10. A computer-readable storage medium, on which a computer program is stored, which, when being executed by a processor, carries out the steps of the method of any one of claims 1 to 4.

Background

Condensate gas cap reservoirs are a special type of oil and gas reservoir, which are formed in a specific geological environment. The condensate gas presents gaseous state characteristics under the original oil deposit condition, and the condensate gas can generate reverse condensation effect to generate condensate oil along with the reduction of the formation pressure to the dew point pressure. In addition, the formation pressure is reduced, so that the crude oil in the oil ring is degassed, the viscosity of the crude oil is increased, and the development difficulty of an oil area is increased.

The original pressure balance of a condensate gas cap oil reservoir can be broken through oil and gas exploitation, and an oil and gas interface is caused to move. When the top pressure of the condensate gas is higher than the pressure of the oil ring, the condensate gas in the gas top easily invades into the oil ring downwards, so that the gas channeling of an oil well close to an oil-gas interface is caused, and the oil production capacity of the oil well is reduced; when the pressure of the oil ring is higher than the pressure of the gas cap, the crude oil in the oil ring can intrude upwards into the gas cap, and the intruded crude oil is in a dispersed state and is not easy to be produced to the ground, so that part of crude oil resources are lost. Therefore, the interaction and the mutual influence between the gas cap and the oil ring are well treated in the condensate gas cap oil reservoir development process, the oil-gas channeling is prevented, the oil-gas interface is kept stable or moves slowly, and the condensate gas cap oil reservoir development method is a key factor for realizing reasonable development of the oil-gas reservoirs.

When the content of the condensate oil in the gas cap is very high, water can be injected into an oil-gas interface to form a water barrier, so that the oil area and the gas area can be divided and reasonably developed, and the method is a so-called barrier water injection development mode. The condensate gas cap oil is stored in the barrier water injection process, and the injected water respectively supplements formation energy to the gas cap and the oil ring so as to prevent gas cap gas reverse condensation and oil ring crude oil degassing. Meanwhile, water is injected to form a stable water barrier between the gas cap and the oil ring, so that the gas cap gas is prevented from entering the oil well in the oil ring and crude oil in the oil ring enters the gas cap. The moving speed of a gas-water interface and an oil-water interface is determined in the barrier water injection process, and development and adjustment of a condensate gas cap oil reservoir are facilitated.

Disclosure of Invention

In view of the problems in the prior art, embodiments of the present invention provide a method and an apparatus for determining a moving speed of a fluid interface of a condensate gas cap reservoir, which can at least partially solve the problems in the prior art.

On one hand, the invention provides a method for determining the moving speed of a fluid interface of a condensate gas cap oil reservoir, which comprises the following steps:

acquiring the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area;

obtaining the current formation pressure of the condensate gas cap reservoir according to the original gas cap region pore volume, the current gas cap region pore volume, the original oil ring region pore volume, the current oil ring region pore volume, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap reservoir material balance equation; wherein the condensate gas cap reservoir material balance equation is preset;

and obtaining the oil-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtaining the gas-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the gas cap and the current formation pressure.

In another aspect, the present invention provides a device for determining a moving speed of a fluid interface of a condensate gas cap reservoir, including:

the acquiring unit is used for acquiring the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area;

a first obtaining unit, configured to obtain a current formation pressure of the gas condensate cap reservoir according to the original gas cap region pore volume, the current gas cap region pore volume, the original oil ring region pore volume, the current oil ring region pore volume, a total expansion volume of rocks in the oil and gas reservoir, and a gas condensate cap reservoir material balance equation; wherein the condensate gas cap reservoir material balance equation is preset;

and the second obtaining unit is used for obtaining the oil-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtaining the gas-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the oil ring and the current formation pressure.

In yet another aspect, the present invention provides an electronic device, comprising a memory, a processor and a computer program stored on the memory and executable on the processor, wherein the processor executes the program to implement the steps of the method for determining a fluid interface movement speed of a condensate gas cap reservoir according to any of the embodiments described above.

In yet another aspect, the present invention provides a computer readable storage medium having stored thereon a computer program which, when being executed by a processor, carries out the steps of the method for determining a fluid interface movement velocity for a condensate gas cap reservoir according to any of the embodiments described above.

The method and the device for determining the movement speed of the fluid interface of the condensate gas cap oil reservoir can obtain the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area, obtaining the current formation pressure of the condensate gas cap oil reservoir according to the pore volume of the original gas cap region, the pore volume of the current gas cap region, the pore volume of the original oil ring region, the pore volume of the current oil ring region, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap oil reservoir substance balance equation, obtaining the oil-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and the gas-water interface moving speed of the condensate gas cap oil reservoir is obtained according to the volume of the barrier injected water invading the gas cap and the current formation pressure, so that the calculation efficiency of the fluid interface moving speed in the condensate gas cap oil reservoir barrier water injection development process is improved.

Drawings

In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings used in the description of the embodiments or the prior art will be briefly described below, it is obvious that the drawings in the following description are only some embodiments of the present invention, and for those skilled in the art, other drawings can be obtained according to the drawings without creative efforts. In the drawings:

FIG. 1a is a schematic diagram of a fluid distribution prior to development of a condensate gas cap reservoir provided by an embodiment of the present invention;

FIG. 1b is a schematic illustration of the fluid distribution after development of a condensate gas cap reservoir provided by an embodiment of the present invention;

fig. 2 is a schematic flow chart of a method for determining a moving speed of a fluid interface of a condensate gas cap reservoir according to an embodiment of the present invention.

Fig. 3 is a schematic flow chart of a method for determining a moving speed of a fluid interface of a condensate gas cap reservoir according to another embodiment of the present invention.

Fig. 4 is a schematic flow chart of a method for determining a moving speed of a fluid interface of a condensate gas cap reservoir according to another embodiment of the present invention.

Fig. 5 is a schematic diagram of injection water distribution under a condensate gas cap reservoir barrier waterflood development mode according to an embodiment of the present invention.

Fig. 6 is a schematic diagram illustrating a relationship between an oil production speed, a gas production speed, and an oil-water interface movement speed in a barrier water injection development mode according to an embodiment of the present invention.

Fig. 7 is a schematic diagram illustrating a relationship between an oil production speed, a gas production speed, and a gas-water interface movement speed in a barrier water injection development mode according to an embodiment of the present invention.

Fig. 8 is a schematic structural diagram of a device for determining a moving speed of a fluid interface of a condensate gas cap reservoir according to an embodiment of the present invention.

Fig. 9 is a schematic structural diagram of a fluid interface movement speed determination apparatus for a condensate gas cap reservoir according to another embodiment of the present invention.

Fig. 10 is a schematic structural diagram of a fluid interface movement speed determination apparatus for a condensate gas cap reservoir according to still another embodiment of the present invention.

Fig. 11 is a schematic physical structure diagram of an electronic device according to an embodiment of the present invention.

Detailed Description

In order to make the objects, technical solutions and advantages of the embodiments of the present invention more apparent, the embodiments of the present invention are further described in detail below with reference to the accompanying drawings. The exemplary embodiments and descriptions of the present invention are provided to explain the present invention, but not to limit the present invention. It should be noted that the embodiments and features of the embodiments in the present application may be arbitrarily combined with each other without conflict.

In order to facilitate understanding of the technical solutions provided in the present application, the following first describes relevant contents of the technical solutions in the present application. In the embodiment of the invention, the condensate gas cap and the bottom oil ring in the condensate gas cap oil reservoir are assumed to be in the same pressure system, and the oil-gas interface is uniformly pushed; the original formation pressure is higher than the dew point pressure of the condensate gas; bound water exists on both the condensate gas cap and the oil ring; neglecting the dissolution of the condensate gas cap gas in the oil ring and the blow-by of the oil ring escaping dissolved gas into the condensate gas cap; neglecting the adsorption phenomenon of gas in the stratum. The implementation subject of the method for determining the moving speed of the fluid interface of the condensate gas cap reservoir provided by the embodiment of the invention comprises but is not limited to a computer.

Fig. 1a is a schematic diagram of fluid distribution before development of a gas condensate cap oil reservoir according to an embodiment of the present invention, and as shown in fig. 1a, three phases of oil, gas, and water exist before development of the gas condensate cap oil reservoir, which are well-defined. Fig. 1b is a schematic diagram of fluid distribution after development of a condensate gas cap oil reservoir according to an embodiment of the present invention, as shown in fig. 1b, after a certain period of development, when the condensate gas cap pressure is higher than the oil ring pressure, a reverse condensation phenomenon occurs in the condensate gas cap, and condensate oil is formed; when the oil ring pressure is higher than the gas cap pressure, the crude oil degassing phenomenon occurs in the oil ring, and the solution gas escapes.

Fig. 2 is a schematic flow chart of a method for determining a fluid interface movement speed of a condensate gas cap reservoir according to an embodiment of the present invention, and as shown in fig. 2, the method for determining a fluid interface movement speed of a condensate gas cap reservoir according to an embodiment of the present invention includes:

s201, acquiring the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area;

specifically, considering the effect of water vapor in the formation, the original gas cap zone pore volume may be expressed as:

wherein, V_GiFor the pore volume of the original gas cap region, the unit can be m³G is the original natural gas reserve of the stratum of the condensate gas cap oil reservoir, and the unit can adopt m³，B_giThe unit of the volume coefficient of the gas cap gas under the original condition can adopt m³/m³，y_wiThe water vapor content in the gas phase under the original condition can be expressed by a decimal number, S_wcGIs the irreducible water saturation within the gas cap volume. The pore volume of the original gas cap region can be calculated by formula (1).

In the development process of the condensate gas cap oil reservoir, condensate oil can be continuously separated out after the local layer pressure is lower than the dew point pressure of condensate gas; meanwhile, as the formation pressure is continuously reduced, the formation connate water also begins to be continuously evaporated. Considering the effects of the above factors, the current pore volume of the gas cap zone when the formation pressure drops to the current formation pressure is:

wherein, V_GFor the current gas cap zone pore volume, the unit can be m³G is the original natural gas reserve of the stratum of the condensate gas cap oil reservoir, and the unit can adopt m³，G_pFor the accumulated natural gas output in the gas cap area, the unit can adopt m³，B_gFor the volume coefficient of the current gas cap gas, the unit can adopt m³/m³，y_wIs the percentage of water vapor in the condensate gas phase at the current formation pressure, S_coIs the saturation of the condensate in the gas cap volume, S_wcGFor confinement in the gas cap volumeThe water saturation.

Saturation S of condensate in gas cap volume_coThe method can be measured by an indoor isochoric failure experiment, and can also be obtained by calculating a material conservation relation on the basis of phase equilibrium calculation; percentage of water vapor in condensate gas phase y at current formation pressure_wThe relation between the water vapor content and the pressure can be measured through a formation condensate gas saturated water content experiment, and the relation is obtained by establishing a fitting formula of the water vapor content according to a multiple regression method.

The pore volume of the original oil ring zone can be calculated by the following formula:

wherein, V_OiFor the original oil ring zone pore volume, the unit can adopt m³M is the ratio of the oil ring pore volume to the gas cap pore volume under the original condition, V_GiThe pore volume of the original gas cap area, G the original natural gas reserve of the formation of the condensate gas cap reservoir, B_giIs the volume coefficient of the gas head gas under the original condition, y_wiIs the water vapor content in the gas phase under the original conditions, S_wcGIs the irreducible water saturation within the gas cap volume. The original conditions refer to formation conditions (including pressure, temperature and the like) when the condensate gas cap reservoir is not put into development.

When the formation pressure drops below the bubble point pressure of the oil in the oil ring, the solution gas in the oil ring begins to escape, and a part of the escaping gas is produced to the surface along with the crude oil in the oil ring. Thus, considering the solution gas evolution, the current oil ring zone pore volume when the formation pressure drops to the current formation pressure is:

wherein, V_OFor the pore volume of the current oil ring area, the unit can adopt m³，V_OiFor the original oil ring zone pore volume, the unit can be adoptedm³，S_wcOSaturation of irreducible water in the volume of the oil ring, N_pFor the ground volume of oil extracted from the oil ring, the unit can be m³，B_oiFor the volume coefficient of the oil under the original pressure, the unit can adopt m³/m³，B_oFor the volume coefficient of the oil ring oil under the current formation pressure, the unit can adopt m³/m³，ΔS_wFor the increase in saturation of water in the oil ring region, S_gOThe current gas saturation in the oil ring area, m is the ratio of the oil ring pore volume to the gas cap pore volume under the original condition, G is the original natural gas reserve of the stratum of the condensate gas cap oil deposit, B_giIs the volume coefficient of the gas head gas under the original condition, y_wiIs the water vapor content in the gas phase under the original conditions, S_wcGIs the irreducible water saturation within the gas cap volume.

Assuming that the oil ring zone does not contain the gas condensate head gas invaded due to expansion, the gas saturation S in the oil ring zone is present_gOThe calculation of (c) takes into account only the escaping solution gas, then:

wherein R is_siFor the oil ring dissolved gas-oil ratio at virgin formation pressure, the unit can be m³/m³，R_sFor the dissolved gas-oil ratio at the current formation pressure, the unit can be m³/m³，R_pFor the current production gas-oil ratio of the oil ring, the unit can adopt m³/m³，B_gIs the volume coefficient of the current gas cap gas.

Considering the influence of water invasion outside the oil reservoir and oil reservoir water injection, the water saturation increment delta S in the oil ring area_wCan be obtained by the following formula:

wherein, W_eThe water invasion amount of the edge bottom water is shown,the unit can adopt m³，W_iBFor barrier injection of water, the unit can adopt m³，W_pFor the current cumulative water production, the unit can adopt m³，B_wIs the volume factor of water.

And bottom water invasion W of oil reservoir_eIt can be determined by the Fetkovitch method. The Fetkovitch water cut calculation formula is as follows:

wherein the content of the first and second substances,

W_ei＝V_w(C_w+C_f)p_i (8)

wherein, W_eiThe unit can adopt m for the maximum water invasion potential of the water body³，p_wiThe unit of the original formation pressure of the water body can adopt MPa, p is the current formation pressure of the condensate gas cap oil deposit, the unit can adopt MPa, J is the water invasion index, and the unit can adopt m³V (d.MPa), t is development time, and the unit can adopt day, V_wThe unit of the volume of the water body can adopt m³，C_wAs formation water compressibility factor, C_fThe compression coefficient of rock can be in MPa^-1，p_iIs the average pressure of the condensate gas cap reservoir under the original conditions,is the circumferential coefficient of the oil reservoir,theta is the water invasion angle of the oil reservoir, the unit can adopt the degree, k is the permeability of the reservoir layer, and the unit can adopt the mu m²H is the thickness of the water layer, m can be adopted as the unit, a is the conversion coefficient, and a can be 86.4 mu_wIs formation waterThe viscosity of (b) can be expressed in units of mPa.s, r_eThe radius of the water body can be m, r_oFor the radius of the reservoir, the unit can be m.

S202, obtaining the current formation pressure of the condensate gas cap oil reservoir according to the original gas cap area pore volume, the current gas cap area pore volume, the original oil ring area pore volume, the current oil ring area pore volume, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap oil reservoir substance balance equation; wherein the condensate gas cap reservoir material balance equation is preset;

specifically, after obtaining the original gas cap zone pore volume, the current gas cap zone pore volume, the original oil ring zone pore volume, and the current oil ring zone pore volume, a current formation pressure of a gas condensate cap reservoir may be obtained from the original gas cap zone pore volume, the current gas cap zone pore volume, the original oil ring zone pore volume, the current oil ring zone pore volume, a total expansion volume of rocks within the hydrocarbon reservoir, and a gas condensate cap reservoir material balance equation, i.e., the original gas cap zone pore volume, the current gas cap zone pore volume, the original oil ring zone pore volume, and the current oil ring zone pore volume are substituted into the gas condensate cap reservoir material balance equation, and the total expansion volume of rocks within the hydrocarbon reservoir is expressed by a current formation pressure of the gas condensate cap reservoir, an equation for the current formation pressure of the gas condensate cap reservoir may be obtained, and solving the equation to obtain the current formation pressure of the condensate gas cap oil reservoir. Wherein the condensate gas cap reservoir material balance equation is preset.

S203, obtaining the oil-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtaining the gas-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the gas cap and the current formation pressure.

Specifically, after the current formation pressure of the gas top condensate reservoir is obtained, the oil-water interface moving speed of the gas top condensate reservoir is obtained according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and the gas-water interface moving speed of the gas top condensate reservoir is obtained according to the volume of the barrier injected water invading the gas top and the current formation pressure.

For example, the volume of the barrier injected water invading the oil ring is calculated and obtained according to the current formation pressure and a first preset formula, and then the oil-water interface moving speed is calculated and obtained according to the volume of the barrier injected water invading the oil ring and a second preset formula. And calculating to obtain the volume of the barrier injected water invading gas cap according to the current formation pressure and a third preset formula, and then calculating to obtain the gas-water interface moving speed according to the volume of the barrier injected water invading gas cap and a fourth preset formula. Wherein the first preset formula, the second preset formula, the third preset formula and the fourth preset formula are preset.

The method for determining the movement speed of the fluid interface of the condensate gas cap oil reservoir can obtain the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area, obtaining the current formation pressure of the condensate gas cap oil reservoir according to the pore volume of the original gas cap region, the pore volume of the current gas cap region, the pore volume of the original oil ring region, the pore volume of the current oil ring region, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap oil reservoir substance balance equation, obtaining the oil-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and the gas-water interface moving speed of the condensate gas cap oil reservoir is obtained according to the volume of the barrier injected water invading the gas cap and the current formation pressure, so that the calculation efficiency of the fluid interface moving speed in the condensate gas cap oil reservoir barrier water injection development process is improved.

On the basis of the above embodiments, further, the condensate gas cap reservoir material balance equation is:

V_Gi+V_Oi＝V_G+V_O+ΔV_Tf

wherein, V_GiIs the pore volume, V, of the original gas cap region_OiIs a stand forPore volume, V, of the original oil ring region_GIs the current gas cap zone pore volume, V_OΔ V for the current oil ring zone pore volume_TfIs the total expansion volume of rock in the reservoir calculated according to the following formula:

wherein, C_fIs the rock compression coefficient, p_iIs the average pressure of the condensate gas cap oil deposit under the original condition, p is the current formation pressure of the condensate gas cap oil deposit, m is the ratio of the oil ring pore volume to the gas cap pore volume under the original condition, G is the original natural gas reserve of the condensate gas cap oil deposit, B_giIs the volume coefficient of the gas head gas under the original condition, y_wiIs the water vapor content in the gas phase under the original conditions, S_wcGIs the irreducible water saturation within the gas cap volume.

Specifically, considering the expansion of the rock in the gas cap area and the oil ring area simultaneously, when the formation pressure is reduced to the current formation pressure, the total expansion volume of the rock in the oil and gas reservoir is as follows:

wherein, is Δ V_TfFor the total expansion volume of the rock in the reservoir, the unit can be m³，ΔV_GfIs the total expansion volume, Δ V, of the rock in the gas cap_OfIs the total swell volume, C, of rock in the oil ring_fAnd the compression coefficient of the rock of the condensate gas cap oil reservoir.

According to the volume conservation principle in the development process of the oil and gas reservoir, namely, the pore volume of the original oil and gas reservoir is equal to the sum of the pore volume of the current oil and gas reservoir and the expansion volume of stratum rocks, the condensate gas cap reservoir substance balance equation can be obtained as follows:

V_Gi+V_Oi＝V_G+V_O+ΔV_Tf (11)

and substituting the formula (10) into the formula (11) to obtain an equation about the current formation pressure of the condensate gas cap oil reservoir, and solving to obtain the current formation pressure of the condensate gas cap oil reservoir through an iterative calculation method. The specific process is that the current reservoir pressure is assumed to be relative to p_iDecrease Δ P, i.e. the current formation pressure P ═ P_i- Δ p, calculating the expansion volume of the rock in the oil and gas reservoir at the moment through the formula (10), calculating the original gas cap zone pore volume, the current gas cap zone pore volume, the original oil ring zone pore volume and the current oil ring zone pore volume at the moment, and substituting the calculated expansion volume, the current gas cap zone pore volume, the original oil ring zone pore volume and the current oil ring zone pore volume into the condensate gas cap reservoir material balance equation (11), comparing whether the left side and the right side of the equation (11) are equal, and if the two sides are equal, the current formation pressure p ═ p_i- Δ p, if not equal, re-assuming a formation pressure variation Δ p and repeating the above calculation process until a current formation pressure p is obtained that meets the calculation accuracy requirements. The calculation accuracy requirement is set according to actual needs, and the embodiment of the invention is not limited.

Fig. 3 is a schematic flow chart of a method for determining a moving speed of a fluid interface of a gas cap reservoir according to another embodiment of the present invention, and as shown in fig. 3, based on the above embodiments, further, the obtaining a moving speed of an oil-water interface of the gas cap reservoir according to a volume of barrier injected water invading an oil ring and the current formation pressure includes:

s301, calculating to obtain the volume of the barrier injected water invading oil ring according to the current formation pressure and a first preset formula;

specifically, after obtaining the current formation pressure, the volume of the barrier injection water intrusion oil ring may be calculated by substituting the current formation pressure into a first preset formula.

S302, calculating and obtaining the oil-water interface moving speed according to the volume of the barrier injected water invading the oil ring and a second preset formula.

Specifically, after the volume of the barrier injected water intruding into the oil ring is obtained, the volume of the barrier injected water intruding into the oil ring may be substituted into a second preset formula, and the oil-water interface movement speed of the condensate gas cap reservoir may be calculated.

Fig. 4 is a schematic flow chart of a method for determining a moving speed of a fluid interface of a condensate gas cap reservoir according to yet another embodiment of the present invention, and as shown in fig. 4, based on the foregoing embodiments, further, the obtaining a moving speed of a gas-water interface of the condensate gas cap reservoir according to a volume of a barrier injected water invading the gas cap and the current formation pressure includes:

s401, calculating and obtaining the volume of the barrier injected water invading gas cap according to the current formation pressure and a third preset formula;

specifically, after obtaining the current formation pressure, the current formation pressure may be substituted into a third preset formula to calculate a volume of the barrier injected water invaded gas cap.

S402, calculating and obtaining the moving speed of the gas-water interface according to the volume of the barrier injected water invading the gas cap and a fourth preset formula.

Specifically, after the volume of the barrier injected water invading gas cap is obtained, the volume of the barrier injected water invading gas cap can be substituted into a fourth preset formula, and the gas-water interface moving speed can be obtained through calculation.

Fig. 5 is a schematic diagram of injection water distribution under a barrier water injection development mode of a condensate gas cap reservoir according to an embodiment of the present invention, as shown in fig. 5, when the barrier water injection development is performed, after the barrier is formed, the injected water flows to an oil ring and a gas cap respectively, and separates the gas cap reservoir into a large gas cap small oil ring reservoir and a small gas cap large oil ring reservoir. The barrier injected water is used as an energy supply source of the two oil and gas reservoirs to respectively supplement the deficit volumes to the two oil and gas reservoirs. Therefore, in the barrier water injection development process, the problem of movement of two interfaces of gas water and oil water exists in the condensate gas cap oil reservoir.

The volume of barrier injection water intrusion into the oil ring can be expressed as:

wherein, V_bOFor shielding the volume of the injected water intruding the oil ring, the unit can be m³，V_OiFor the original oil ring zone pore volume, the unit can adopt m³，V_OFor the pore volume of the current oil ring area, the unit can adopt m³，ΔV_OfIs the total expansion volume of rock in the oil ring. The formula (13) may be the first preset formula.

The oil-water interface moving speed of the condensate gas cap oil reservoir can be obtained according to a volume method, and is as follows:

wherein v is_owThe unit of the oil-water interface moving speed can adopt meter/year, V_bOFor shielding the volume of the injected water intruding the oil ring, the unit can be m³T is development time, the unit can be years, L is the width between the inner and outer boundaries of the oil-gas interface, m and W are reservoir widths, m and phi are formation porosity, and S_wcOSaturation of irreducible water in oil ring volume, S_orFor residual oil saturation, α is the formation dip, and the units may be degrees. The formula (14) may be the second preset formula.

The volume of barrier injected water intrusion into the gas cap can be expressed as:

wherein, V_bGFor the volume of the barrier against the intrusion of water into the gas cap, the unit can be m³，V_GiFor the pore volume of the original gas cap region, the unit can be m³，V_GFor the current gas cap zone pore volume, the unit can be m³，ΔV_GfIs the total expansion volume of the rock in the gas cap. The formula (15) may be the third preset formula.

The gas-water interface moving speed of the condensate gas cap oil reservoir can be obtained according to a volume method, and is as follows:

wherein v is_gwThe unit of the moving speed of the gas-water interface can adopt meter/year, V_bGFor the volume of the barrier against the intrusion of water into the gas cap, the unit can be m³T is development time, the unit can be years, L is the width between the inner and outer boundaries of the oil-gas interface, m and W are reservoir widths, m and phi are formation porosity, and S_wcGSaturation of irreducible water in gas cap volume, S_grFor residual gas saturation, α is the formation dip, and the units may be degrees. Equation (16) may be the fourth preset equation.

The method comprises the steps of taking a North Gamma condensation gas cap oil reservoir of a Nafel oil-gas field as a research object, and establishing a relation between the oil extraction speed, the gas production speed and the oil-water interface moving speed (shown in figure 6) and a relation between the oil extraction speed, the gas production speed and the gas-water interface moving speed (shown in figure 7) in a barrier water injection development mode respectively by utilizing an oil reservoir engineering evaluation model, so that the oil extraction speed, the gas production speed and the injection-production ratio are main control factors influencing the stability of a fluid interface. Wherein the gas production speed is set to be 0%, 1%, 2%, 4% and 6%, the oil production speed is set to be 0%, 0.3%, 0.6%, 0.9% and 1.2%, and the injection-production ratio is 0.5.

It can be seen from the relationship between the oil production speed, the gas production speed and the gas-water interface moving speed in the barrier water injection development mode shown in fig. 6 that:

(1) when the injection-production ratio is constant, the moving direction of the oil-water interface is different due to different gas production speeds and oil production speed combination forms. Wherein the abscissa represents the oil ring direction above the abscissa and the gas cap direction below the abscissa.

(2) Under the condition of the same injection-production ratio, when the gas production speed is lower and the oil production speed is higher, the oil-water interface moves towards the direction of the oil ring. The larger the oil extraction speed of the oil ring is, the higher the oil ring vacancy speed is, and the moving speed of an oil-water interface to an oil area is gradually increased; and the larger the gas-cap gas production speed is, the smaller the pressure difference between gas-cap oil rings is, and the moving speed of the oil-water interface to the oil area is gradually reduced.

(3) When the oil extraction speed is low and the gas extraction speed is too high, the gas cap depletion is easily intensified, and the oil-water interface gradually moves towards the gas cap direction, namely, the part of the graph, in which the gas-water interface moving speed is a negative value, is corresponded. At the moment, the oil extraction speed of the oil ring is higher, and the moving speed of the oil-water interface to the gas area is gradually reduced; the greater the gas production speed of the gas cap, the greater the moving speed of the oil-water interface to the gas area.

It can be seen from the relationship between the oil production speed, the gas production speed and the gas-water interface moving speed in the barrier water injection development mode shown in fig. 7 that:

(1) when the injection-production ratio is constant, the moving direction of the gas-water interface is different due to different gas-production speed and oil-production speed combination forms. Wherein the abscissa represents the gas cap direction above the abscissa and the oil ring direction below the abscissa.

(2) Under the condition of the same injection-production ratio, when the gas production speed is higher and the oil production speed is lower, the gas-water interface moves towards the gas cap direction. The greater the gas production speed of the gas cap is, the gradually increased moving speed of the gas-water interface to the gas cap is; and the oil extraction speed of the oil ring is higher, the moving speed of the gas-water interface to the gas cap is gradually reduced.

(3) When the oil production speed is high and the gas production speed is low, the gas-water interface gradually moves towards the direction of the oil ring, namely the part of the graph, in which the gas-water interface moving speed is negative, is corresponded. At the moment, the oil extraction speed of the oil ring is higher, and the moving speed of the gas-water interface to the oil ring is gradually increased; the greater the gas production speed of the gas cap, the lower the moving speed of the gas-water interface to the oil ring.

Under the barrier water injection development mode, as can be seen from fig. 6 and 7, the gas-cap oil extraction speed and the oil-ring oil extraction speed both have great influence on the gas-water interface moving speed and the oil-water interface moving speed.

Fig. 8 is a schematic structural diagram of a device for determining a fluid interface movement speed of a condensate gas cap reservoir according to an embodiment of the present invention, and as shown in fig. 8, the device for determining a fluid interface movement speed of a condensate gas cap reservoir according to an embodiment of the present invention includes an obtaining unit 801, a first obtaining unit 802, and a second obtaining unit 803, where:

the obtaining unit 801 is configured to obtain an original gas cap area pore volume, a current gas cap area pore volume, an original oil ring area pore volume, and a current oil ring area pore volume; the first obtaining unit 802 is configured to obtain a current formation pressure of the gas condensate cap reservoir according to the original gas cap region pore volume, the current gas cap region pore volume, the original oil ring region pore volume, the current oil ring region pore volume, a total expansion volume of rocks in the oil and gas reservoir, and a gas condensate cap reservoir material balance equation; wherein the condensate gas cap reservoir material balance equation is preset; the second obtaining unit 803 is configured to obtain the oil-water interface moving speed of the gas condensate cap reservoir according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtain the gas-water interface moving speed of the gas condensate cap reservoir according to the volume of the barrier injected water invading the gas cap and the current formation pressure.

Specifically, the obtaining unit 801 may calculate the original headspace area pore volume according to equation (1) in consideration of the influence of water vapor in the formation. In the development process of the condensate gas cap oil reservoir, condensate oil can be continuously separated out after the local layer pressure is lower than the dew point pressure of condensate gas; meanwhile, as the formation pressure is continuously reduced, the formation connate water also begins to be continuously evaporated. In consideration of the above factors, the obtaining unit 801 may calculate and obtain the current pore volume of the gas cap region according to formula (2) when the formation pressure decreases to the current formation pressure. The obtaining unit 801 may obtain the pore volume of the original oil ring region according to the formula (3). When the formation pressure drops below the bubble point pressure of the oil in the oil ring, the solution gas in the oil ring begins to escape, and a part of the escaping gas is produced to the surface along with the crude oil in the oil ring. Therefore, the obtaining unit 801 may calculate and obtain the current pore volume of the oil ring region according to the formula (4) when the formation pressure is reduced to the current formation pressure in consideration of the escape of the solution gas.

After obtaining the original gas cap zone pore volume, the current gas cap zone pore volume, the original oil ring zone pore volume, and the current oil ring zone pore volume, the first obtaining unit 802 may obtain a current formation pressure of the gas condensate cap reservoir according to the original gas cap zone pore volume, the current gas cap zone pore volume, the original oil ring zone pore volume, the current oil ring zone pore volume, a total expansion volume of rocks in the hydrocarbon reservoir, and a gas condensate cap reservoir material balance equation, that is, the original gas cap zone pore volume, the current gas cap zone pore volume, the original oil ring zone pore volume, and the current oil ring zone pore volume are substituted into the gas condensate cap reservoir material balance equation, and the total expansion volume of rocks in the hydrocarbon reservoir is expressed by a current formation pressure of the gas condensate cap reservoir, to obtain an equation about the current formation pressure of the gas condensate cap reservoir, and solving the equation to obtain the current formation pressure of the condensate gas cap oil reservoir. Wherein the condensate gas cap reservoir material balance equation is preset.

After obtaining the current formation pressure of the gas top condensate reservoir, the second obtaining unit 803 obtains the oil-water interface movement speed of the gas top condensate reservoir according to the volume of the barrier injected water invading oil ring and the current formation pressure, and obtains the gas-water interface movement speed of the gas top condensate reservoir according to the volume of the barrier injected water invading gas top and the current formation pressure.

The device for determining the movement speed of the fluid interface of the condensate gas cap oil reservoir provided by the embodiment of the invention can obtain the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area, obtaining the current formation pressure of the condensate gas cap oil reservoir according to the pore volume of the original gas cap region, the pore volume of the current gas cap region, the pore volume of the original oil ring region, the pore volume of the current oil ring region, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap oil reservoir substance balance equation, obtaining the oil-water interface moving speed of the condensate gas cap oil deposit according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and the gas-water interface moving speed of the condensate gas cap oil reservoir is obtained according to the volume of the barrier injected water invading the gas cap and the current formation pressure, so that the calculation efficiency of the fluid interface moving speed in the condensate gas cap oil reservoir barrier water injection development process is improved.

On the basis of the above embodiments, further, the condensate gas cap reservoir material balance equation is:

V_Gi+V_Oi＝V_G+V_O+ΔV_Tf

wherein, V_GiIs the pore volume, V, of the original gas cap region_OiIs the pore volume, V, of the original oil ring region_GIs the current gas cap zone pore volume, V_OΔ V for the current oil ring zone pore volume_TfIs the total expansion volume of rock in the reservoir calculated according to the following formula:

wherein, C_fIs the rock compression coefficient, p_iIs the average pressure of the condensate gas cap oil deposit under the original condition, p is the current formation pressure of the condensate gas cap oil deposit, m is the ratio of the oil ring pore volume to the gas cap pore volume under the original condition, G is the original natural gas reserve of the condensate gas cap oil deposit, B_giIs the volume coefficient of the gas head gas under the original condition, y_wiIs the water vapor content in the gas phase under the original conditions, S_wcGIs the irreducible water saturation within the gas cap volume.

Fig. 9 is a schematic structural diagram of a device for determining a moving speed of a fluid interface of a condensate gas cap reservoir according to another embodiment of the present invention, as shown in fig. 9, based on the foregoing embodiments, further, the second obtaining unit 803 includes a first calculating subunit 8031 and a second calculating subunit 8032, where:

the first calculating subunit 8031 is configured to calculate and obtain a volume of the barrier injection water intrusion oil ring according to the current formation pressure and a first preset formula; the second calculating subunit 8032 is configured to calculate and obtain the oil-water interface movement speed according to the volume of the barrier injected water intruding into the oil ring and a second preset formula.

Specifically, after obtaining the current formation pressure, the first calculation subunit 8031 may substitute the current formation pressure into a first preset formula to calculate the volume of the barrier injection water intrusion oil ring.

After obtaining the volume of the barrier injected water intruding into the oil ring, the second calculating subunit 8032 may substitute the volume of the barrier injected water intruding into the oil ring into a second preset formula to calculate and obtain the oil-water interface moving speed of the gas condensate cap reservoir.

Fig. 10 is a schematic structural diagram of a fluid interface moving speed determination apparatus for a condensate gas cap reservoir according to yet another embodiment of the present invention, as shown in fig. 10, on the basis of the foregoing embodiments, further, the second obtaining unit 803 includes a third calculating subunit 8033 and a fourth calculating subunit 8034, where:

the third calculation subunit 8033 is configured to calculate, according to the current formation pressure and a third preset formula, a volume of the barrier injected water invading gas cap; the fourth calculating subunit 8034 is configured to calculate and obtain the gas-water interface moving speed according to the volume of the gas cap invaded by the barrier injected water and a fourth preset formula.

Specifically, after obtaining the current formation pressure, the third calculation subunit 8033 may substitute the current formation pressure into a third preset formula to calculate the volume of the barrier injected water intrusion gas cap.

After obtaining the volume of the barrier injected water intrusion gas cap, the fourth calculating subunit 8034 may substitute the volume of the barrier injected water intrusion gas cap into a fourth preset formula to calculate and obtain the gas-water interface moving speed.

The embodiment of the apparatus provided in the embodiment of the present invention may be specifically configured to execute the processing flows of the above method embodiments, and the functions of the apparatus are not described herein again, and refer to the detailed description of the above method embodiments.

Fig. 11 is a schematic physical structure diagram of an electronic device according to an embodiment of the present invention, and as shown in fig. 11, the electronic device may include: a processor (processor)1101, a communication Interface (Communications Interface)1102, a memory (memory)1103 and a communication bus 1104, wherein the processor 1101, the communication Interface 1102 and the memory 1103 are communicated with each other via the communication bus 1104. The processor 1101 may call logic instructions in the memory 1103 to perform the following method: acquiring the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area; obtaining the current formation pressure of the condensate gas cap reservoir according to the original gas cap region pore volume, the current gas cap region pore volume, the original oil ring region pore volume, the current oil ring region pore volume, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap reservoir material balance equation; wherein the condensate gas cap reservoir material balance equation is preset; and obtaining the oil-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtaining the gas-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the gas cap and the current formation pressure.

In addition, the logic instructions in the memory 1103 can be implemented in the form of software functional units and stored in a computer readable storage medium when the logic instructions are sold or used as independent products. Based on such understanding, the technical solution of the present invention may be embodied in the form of a software product, which is stored in a storage medium and includes instructions for causing a computer device (which may be a personal computer, a server, or a network device) to execute all or part of the steps of the method according to the embodiments of the present invention. And the aforementioned storage medium includes: a U-disk, a removable hard disk, a Read-Only Memory (ROM), a Random Access Memory (RAM), a magnetic disk or an optical disk, and other various media capable of storing program codes.

The present embodiment discloses a computer program product comprising a computer program stored on a non-transitory computer readable storage medium, the computer program comprising program instructions which, when executed by a computer, enable the computer to perform the method provided by the above-mentioned method embodiments, for example, comprising: acquiring the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area; obtaining the current formation pressure of the condensate gas cap reservoir according to the original gas cap region pore volume, the current gas cap region pore volume, the original oil ring region pore volume, the current oil ring region pore volume, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap reservoir material balance equation; wherein the condensate gas cap reservoir material balance equation is preset; and obtaining the oil-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtaining the gas-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the gas cap and the current formation pressure.

The present embodiment provides a computer-readable storage medium, which stores a computer program, where the computer program causes the computer to execute the method provided by the above method embodiments, for example, the method includes: acquiring the pore volume of an original gas cap area, the pore volume of a current gas cap area, the pore volume of an original oil ring area and the pore volume of a current oil ring area; obtaining the current formation pressure of the condensate gas cap reservoir according to the original gas cap region pore volume, the current gas cap region pore volume, the original oil ring region pore volume, the current oil ring region pore volume, the total expansion volume of rocks in the oil and gas reservoir and a condensate gas cap reservoir material balance equation; wherein the condensate gas cap reservoir material balance equation is preset; and obtaining the oil-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the oil ring and the current formation pressure, and obtaining the gas-water interface moving speed of the condensate gas cap oil reservoir according to the volume of the barrier injected water invading the gas cap and the current formation pressure.

As will be appreciated by one skilled in the art, embodiments of the present invention may be provided as a method, system, or computer program product. Accordingly, the present invention may take the form of an entirely hardware embodiment, an entirely software embodiment or an embodiment combining software and hardware aspects. Furthermore, the present invention may take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, and the like) having computer-usable program code embodied therein.

The present invention is described with reference to flowchart illustrations and/or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each flow and/or block of the flow diagrams and/or block diagrams, and combinations of flows and/or blocks in the flow diagrams and/or block diagrams, can be implemented by computer program instructions. These computer program instructions may be provided to a processor of a general purpose computer, special purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, create means for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.

These computer program instructions may also be stored in a computer-readable memory that can direct a computer or other programmable data processing apparatus to function in a particular manner, such that the instructions stored in the computer-readable memory produce an article of manufacture including instruction means which implement the function specified in the flowchart flow or flows and/or block diagram block or blocks.

These computer program instructions may also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer implemented process such that the instructions which execute on the computer or other programmable apparatus provide steps for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.

In the description herein, reference to the description of the terms "one embodiment," "a particular embodiment," "some embodiments," "for example," "an example," "a particular example," or "some examples," etc., means that a particular feature, structure, material, or characteristic described in connection with the embodiment or example is included in at least one embodiment or example of the invention. In this specification, the schematic representations of the terms used above do not necessarily refer to the same embodiment or example. Furthermore, the particular features, structures, materials, or characteristics described may be combined in any suitable manner in any one or more embodiments or examples.

The above-mentioned embodiments are intended to illustrate the objects, technical solutions and advantages of the present invention in further detail, and it should be understood that the above-mentioned embodiments are only exemplary embodiments of the present invention, and are not intended to limit the scope of the present invention, and any modifications, equivalent substitutions, improvements and the like made within the spirit and principle of the present invention should be included in the scope of the present invention.