RU2806536C1 - Method for measuring relative phase permeabilities in a porous medium - Google Patents

Abstract

FIELD: petrophysical research.

SUBSTANCE: invention can be used in various processes involving porous media and liquids with different physical properties. The method for determining relative phase permeabilities in a porous medium includes a laboratory study of fluid filtration in samples of a porous medium, while reproducing the natural physicochemical characteristics of the rock-formation fluid system, while maintaining pressure and temperature values corresponding to those of the formation, using formation fluids or their models, when measuring relative phase permeabilities in the process of filtering a two-phase fluid flow with a given phase ratio. Measurements of relative phase permeabilities in the process of filtration of a two-phase flow are carried out with varying saturation of the porous medium, until the flow becomes stationary, that is, in a non-stationary filtration mode.

EFFECT: measurement of relative phase permeabilities in a porous medium in the range from initial to critical saturation with a displacing fluid.

1 cl, 1 dwg, 1 tbl

Description

The invention relates to petrophysical research and can be used in various technological processes that involve porous media and liquids with different physical properties.

Phase permeability is a value characterizing the ability of a porous medium to pass liquids or gases (fluids) through itself in the presence of other fluids. The value characterizes the volumetric filtration rate of a fluid with a known dynamic viscosity through a porous medium of a known cross-section, perpendicular to the filtration direction, under the influence of a pressure gradient. A permeability of 1 µm ² means that a fluid with a viscosity of 1 mPa-s will move under the influence of a pressure gradient of 1 bar/cm, through a porous medium with a cross-section of 1 cm ² , at a speed of 1 cm/s. Phase permeability changes depending on the content of other fluids in the porous medium. To describe the ability of a porous medium to pass fluids through itself at different contents (saturations) of other fluids, the dependences of phase permeabilities on saturation are used, which are determined empirically. Since such dependencies are determined on specific rock samples that have a certain absolute permeability (the ability to pass fluids through them in the absence of other fluids), to extend these measurements to structurally similar rocks, relative phase permeability is used, which is the ratio of phase permeability to basic permeability . The basic permeability is usually the absolute permeability of the porous medium. To perform calculations of fluid flow through rocks, measurements of relative phase permeabilities are used on samples of similar structure, determining phase permeabilities by multiplying the relative phase permeabilities by the absolute permeability of the rock for which the calculations are performed.

The essence of the method for measuring this value is to determine the relative phase permeabilities according to Darcy's law (formula 1), with changing saturation of the porous medium by creating non-stationary filtration modes through a reservoir model corresponding to the conditions of occurrence, from natural core material. The unsteady filtration mode involves the formation of a two-phase fluid flow through the reservoir model, in which the flow of one of the fluids is intended to change the saturation of the reservoir model (process fluid), and the other fluid is used to determine phase permeabilities (measuring fluid). A change in the saturation of the reservoir model caused by the process fluid reduces the pore volume for filtration of the measuring fluid, therefore the permeability for the measuring fluid decreases and its share in the flow changes, which leads to an error in determining the rate of its filtration, therefore the share of the process fluid in the total flow should be negligible. Phase permeability is measured in accordance with Darcy's law (formula 1). During the research, fluid filtration rates (Q) are set, pressure drop (ΔP) is measured, and the parameters of model length (l), model cross-sectional area (F) and fluid viscosity (μ) are constant under measurement conditions. A physical model of the reservoir is created in laboratory conditions from natural core material, while reproducing reservoir thermobaric (pore and rock pressure, temperature, initial saturation) conditions, based on the Efros similarity criteria, the basic element of the physical model is presented in Figure 1.

where: k is the phase permeability of the fluid under study, µm ² ;

Q is the volumetric flow rate for the fluid under study, cm ³ /s (the parameter is measured using pumps that set the flow rates of fluids NS1 and NS2 in Fig. 1);

μ is the dynamic viscosity of the fluid under study, mPa⋅s (the parameter is a constant measured for the corresponding fluid before the experiment);

L is the length of the measuring section of the reservoir model, 10 ^-2 m (the parameter is a constant of the reservoir model, depending on the distance between the taps for measuring the pressure drop ΔP);

F is the cross-sectional area of the reservoir model, 10 ^-4 m ² (the parameter is a constant of the reservoir model, depending on the diameter of the core samples that make up this model);

ΔР - pressure drop at the measuring section of the core column, 10 ^-1 MPa (the parameter is measured using a differential pressure gauge DM Fig. 1 or pressure sensors on the taps to measure the pressure drop).

Relative phase permeability (k _r ) is determined by the ratio of the measured phase permeability (k) to the base permeability (k _base ), according to formula 2.

In the literature related to the gas and oil industry, the determination of relative phase permeabilities in laboratory conditions is carried out by non-stationary displacement and stationary filtration, which are discussed below.

The closest to the proposed technical solution is a method for determining phase permeabilities during joint stationary filtration. (Kovalev A.G., Kuznetsov A.M., Yurchak V.P., Ivanova L.B. Oil. Method for determining phase permeabilities in laboratory conditions with joint stationary filtration. - OST 39-235-89, 1989. - 36 p.)

The disadvantages of this method are the drainage of the core during joint filtration, which, due to permeability hysteresis, leads to errors in determining the relative phase permeability (Drainage of the core when determining its relative phase permeability by the method of joint stationary filtration / M.G. Lozhkin. - Exposure Oil Gas, September 2016. - pp. 38-39.) and the impossibility of determining phase permeabilities in the range when the permeability for one of the fluids is close to zero, which leads to the impossibility of determining phase permeabilities in the range describing the initial stage of reservoir development.

There is a known method for determining phase permeabilities using displacement method data. (Efros D.A. Modeling of linear displacement of oil by water / D.A. Efros, V.P. Onoprienko // Proceedings. VNII).

The disadvantage of this method is that, in laboratory conditions, on final models, a sharp change in the saturation of the porous medium occurs, as a result of which the filtration parameters (pressure drop, saturation) are difficult to correlate with each other, which leads to distortions in the experimental results. Reliable measurements can only be made near the point of residual saturation, which leads to the fact that the relative phase permeability can only be determined for the displacing fluid. If the system does not exhibit saturation hysteresis when changing the direction of filtration, then it is recommended to carry out a second process, the opposite of the original one. (For example, after replacing oil with water, replace water with oil). For low-permeability rocks, this approach is not applicable, since they have a significant hysteresis of permeability when changing the direction of change in saturation.

There is a known method for determining relative phase permeabilities in laboratory conditions with sequential pseudostationary filtration (Lozhkin M.G., Method for determining relative phase permeabilities in laboratory conditions with sequential pseudostationary filtration // Exposition Oil Gas, November, 2015. - P. 22-24).

The disadvantage of this method is the inability to implement sequential pseudo-stationary filtration on core with low permeability and high initial water saturation. Due to the fact that the porous medium, due to the high initial water saturation, has a reduced effective porosity, the sequential filtration proposed in the method leads to the rapid movement of a portion of water injected in the amount of 0.2 pore volume. This leads to sudden changes in saturation, which, together with the imperfection of the measuring equipment (the presence of elasticity in the elements of the devices and the medium), leads to errors in measurements.

There is a known method for determining relative phase permeabilities in a porous medium (RF patent No. 2442133, published 02/10/2012 Bulletin No. 4) which consists of displacing a resident agent from a sample of a porous medium with end and side surfaces by a displacing agent and determining the saturation of the porous medium after achieving a stationary flow and calculations of relative phase permeability. From this method it clearly follows that measurements are carried out after the flow has reached steady state. Since in order to determine the relative phase permeability it is necessary to determine both saturation and permeability simultaneously, the main feature of the claimed invention “with changing saturation of the porous medium, that is, with a non-stationary filtration mode” does not follow from the specified source of information. Also, a significant difference of the claimed invention is the condition of a negligible fraction of the flow of the second fluid responsible for the change in saturation.

The technical problem solved by applying the invention is the determination of phase permeabilities in the saturation region, which characterizes the initial period of development of hydrocarbon deposits.

The technical result of the proposed invention consists in measuring the relative phase permeabilities in a porous medium in the range from initial to critical saturation with the displacing fluid, which characterizes the initial stage of reservoir development, under non-stationary filtration mode.

Based on the stated essence of the method for determining relative phase permeabilities during joint filtration of resident and displacing fluids through the pore space of a porous medium, the following sequence of actions is implemented to obtain the specified technical result.

a) Formation of an array of initial data on the physical model of the reservoir, which includes:

- reservoir pressure;

- rock pressure;

- formation temperature;

- dynamic viscosity of fluids;

- residual water saturation of samples;

- length of the measuring section of the reservoir model;

- cross-sectional area of the samples;

- pore volume of samples.

b) Organization of movement through the physical model of the formation (Fig. 1) with 100% saturation of the displacing fluid of the displacing fluid flow with a given volumetric flow rate when measuring the pressure drop (ΔP, Fig. 1), to calculate the phase permeability according to formula 1, characterizing the permeability of the formation according to displacing fluid.

c) Creation of residual water saturation by known methods (capillary extraction, centrifugation) not related to the essence of the invention.

d) Organization of movement through the physical model of the reservoir (Fig. 1) with the residual water saturation of the resident fluid flow with a given volumetric flow rate when measuring the pressure drop (ΔP, Fig. 1), to calculate the phase permeability according to formula 1, characterizing the permeability of the reservoir for the resident fluid.

e) Organization of the movement through the physical model of the formation (Fig. 1) of a mixture of resident (measuring) and displacing (process) fluids with a proportion of the displacing fluid in the mixture, which allows, when calculating the phase permeability, to neglect the change in the flow rate of the resident fluid due to changes in the saturation of the core with the displacing fluid. Filtration is completed after reaching the maximum possible saturation with the displacing fluid, at the current proportion of the displacing fluid in the flow. Immediately from the beginning of filtration of the fluid mixture, the following measurements are carried out:

- pressure drop (ΔР, Fig. 1), for calculating phase permeabilities according to formula 1, characterizing the permeability of the formation to resident fluid, with increasing saturation with the displacing fluid;

- saturation of the reservoir model, by any of the known methods.

f) Organization of the movement through the physical model of the reservoir (Fig. 1) of a mixture of resident (process) and displacing (measuring) fluids with the share of the resident agent in the flow, ensuring limitation of the flow of the resident fluid, allowing, when calculating the phase permeability, to neglect the change in the flow rate of the displacing fluid due to changes in saturation core when measuring in the following mode. Immediately from the beginning of filtration of the fluid mixture, the following measurements are carried out:

- pressure drop (ΔР, Fig. 1), for calculating phase permeabilities according to formula 1, characterizing the permeability of the formation to resident fluid, with increasing saturation with the displacing fluid;

- saturation of the reservoir model, by any of the known methods.

g) Organization of water pumping at a given flow rate, in a volume of 10 pore volumes of the reservoir model, with measurement of permeability and corresponding water saturation, after achieving steady flow.

An example of a method for measuring relative phase permeabilities on a terrigenous core with a porosity of 0.273 units and a permeability of 32.45 * 10 ^-3 μm ² (point “a”) is presented below. Reservoir model constants: L=8*10 ^-2 m; F=7.25*10 ^{-4 m2} . Fluid constants: gas viscosity - μ _g =0.0215 mPa*s; water viscosity - μ _in =0573 mPa*s.

For an example of implementing the methods, Figure 1 shows the basic element of a device for measuring relative phase permeabilities. This basic element is an abbreviated representation of known devices, including those described in OST 39-235-89, mentioned above on page 4. In FIG. 1 the following abbreviations are used:

DM - differential pressure gauge,

R - core electrical resistance meter;

MP - reservoir model;

KD - core holder providing formation pressure, 1 - length of the measuring section of the formation model, EI - electrical insulators, TSV - dry air thermostat,

SSF is a fluid collection system with maintaining pore pressure, NS1, NS2 are pumping stations for fluid 1 and fluid 2, respectively.

First, water was pumped through a reservoir model with 100% water saturation to obtain phase permeability for water at 100% water saturation (point “b”). The electrical resistivity of a reservoir model with 100% water saturation was also obtained to determine water saturation by plotting its dependence on electrical resistivity. The resulting electrical resistance was 90 Ohms. Water permeability was 10.7 * 10 ^-3 µm ² or 0.599 units. relative to the basic permeability (17.92*10 ^-3 µm ² ). Then residual water saturation was created (point “c”), after which gas was pumped according to point “d” to determine the phase permeability for gas at residual water saturation, the permeability for gas was 17.92 * 10 ^-3 μm ² , and the water saturation was equal to 0.292 d .unit, for which the electrical resistance was 1016 Ohms. Based on the obtained values of electrical resistance, a saturation parameter was obtained (n = 1.97) according to which water saturations were obtained in subsequent modes of studying the permeability of the reservoir model, according to formula 3, where R _meas is the measured value of the electrical resistance of the reservoir model, and R _100% is the electrical resistance at 100% water saturation.

According to point “d”, the next mode was to determine the phase permeability of gas during joint filtration with water. To do this, a mixture of gas and water was pumped with a water fraction in the flow equal to 2% and the pressure drop and electrical resistance were recorded throughout the entire regime to calculate the phase permeabilities and saturation of the reservoir model. The range of studies of the permeability of the reservoir model was from 0.294 to 0.574 units of water saturation. Then, joint filtration of water and gas was carried out, with a gas share in the flow of 2% (according to point “e”), while recording the pressure drop and electrical resistance. The range of reservoir model studies was from 0.685 to 0.760 units. After that, the gas was displaced by pumping water (point “g”), in a volume of 10 pore volumes of the reservoir model; after reaching a steady flow, the pressure drop and water permeability of the reservoir model were recorded. The relative phase permeability of the reservoir model was 0.121 units. at saturation 0.76 units. This completed the permeability study.

The results of determining saturation and relative phase permeability are presented in Table 1.

Explanation of symbols:

Q ^g - volumetric gas flow rate, 10 ^-3 cm ³ /s;

Q ⁱⁿ - volumetric flow rate of water, 10 ^-3 cm ³ /s;

*AP - pressure drop, bar;

K ⁱⁿ _pr - phase permeability to water, 10 ^-3 µm ² ;

K ^g _pr - phase permeability to gas, 10 ^-3 µm ² ;

R - electrical resistance of the reservoir model, Ohm;

k _rw - relative phase permeability to water, fractions of unity;

k _rg - relative phase permeability for gas, fractions of unity;

S _w - water saturation of the reservoir model, fractions of unity.

Claims (1)

A method for determining relative phase permeabilities in a porous medium, including a laboratory study of the filtration of liquids in samples of a porous medium, while reproducing the natural physicochemical characteristics of the rock - formation fluids system, while maintaining pressure and temperature values corresponding to those of the formation, when using formation fluids or their models, when measuring relative phase permeabilities in the process of filtration of a two-phase fluid flow with a given phase ratio, characterized in that measurements of relative phase permeabilities in the process of filtration of a two-phase flow are carried out with changing saturation of the porous medium, until the flows become stationary, that is, with a non-stationary filtration mode.