RU2476670C1 - Method for determining filtration properties of jointly operating formations (versions) - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: method involves determination of integral hydrodynamic characteristics as per drill hole hydrodynamic research (DHR) results, measurement of flow rate and calculation of filtration properties of each formation, and then, depending on well operating conditions, the following actions are taken: according to Version 1, as per DHR curves in an open shaft there evaluated are ratios of porosities

and effective thicknesses of formations; based on integral skin factor value determined as per DHR and value α, skin factors and permeability of each formation are calculated. According to Version 2, records of acoustic logging and thermometry are fixed in the well, as per which height and width of formation hydraulic fracturing (FHF) is evaluated and skin factors of each formation are calculated. According to Version 3, when performing DHR, time variation curves of flow rate of each formation and difference of flow rates are recorded; average rate of change of flow rate difference is determined, as per which skin factor and permeability of formations is evaluated.

EFFECT: improving evaluation reliability of individual filtration properties of each of the jointly operated oil formations considering mutual influence of formations on each other, as well as considering differences of skin factors of formations.

3 cl, 4 dwg

Description

The invention relates to oil production technologies, and in particular to methods for monitoring production and development of jointly exploited oil reservoirs.

In the joint development of oil reservoirs in the fields, production wells are equipped with simultaneous-separate operation systems (ORE), for setting which, by controlling the opening of valves or mandrels in the on-line mode, information is obtained on the hydrodynamic and geophysical parameters of each of the exploited reservoirs (for example, the invention according to the patent of the Russian Federation No. 2211311, 01/15/2001).

In the case of joint operation of reservoirs in wells equipped with an ORE system with packing of each reservoir without the possibility of hydraulically adjusting the diameter of the outlet (inlet) mandrel or in the absence of such equipment, traditional methods for determining the filtration properties and perfection characteristics of opening each reservoir based on the results of hydrodynamic studies of wells (well test) unsuitable, due to the fact that the mutual influence of the layers is not taken into account.

As the closest analogue, “The method of differentially determining the filtration parameters of jointly exploited productive formations” was taken (RF patent No. 2172404, 05/13/1999).

и скин-фактора

, измерении дебита каждого из пластов Q⁽ⁱ⁾ методом механической расходометрии и расчета фильтрационных свойств каждого пласта на основе уравнений нестационарной фильтрации с использованием данных об измеренном дебите.This method is based on the determination of the integral (common for all reservoirs) indicators: conductivity

and skin factor

, measuring the flow rate of each of the Q ⁽ⁱ⁾ layers by the method of mechanical flow metering and calculating the filtration properties of each formation based on non-stationary filtration equations using data on the measured flow rate.

The disadvantage of this method is the low accuracy of determining the filtration properties of the formations, since in the calculations it is assumed that the formations do not exert mutual influence on each other. In addition, according to this method, the skin factors of all layers are taken equal, while in fact the skin factors of the layers can have significant individual differences.

The objective of the invention is to increase the reliability of the assessment of individual filtration properties of each of the jointly exploited oil reservoirs, taking into account the mutual influence of the reservoirs on each other, and also taking into account differences in skin factors of the reservoirs.

To solve this problem, the inventive method includes the following steps (for different conditions of operation of the wells):

Option 1. If the strata belong to the same lithofacies (characterized by a representative porosity-permeability relationship): porosity ratios are estimated using well logs in an open borehole (methods: spontaneous polarization, electrometry, neutron, acoustic)

and effective thicknesses of the layers, then, based on the well test, the integrated skin factor determined by the calculation method determines the skin factor and permeability of each of the layers using the formulas.

The calculation formulas for the two-layer system are:

Where

r _kn - the radius of the power circuit;

r _c is the radius of the well;

h ₁ , h ₂ - effective power of the upper and lower reservoir;

s ₁ , s ₂ - skin factors of formations;

k ₁ , k ₂ - permeability of formations;

Q ₁ , Q ₂ - production rates.

Option 2. If there are hydraulic fractures (hydraulic fracturing) in two or more jointly developed formations: during overhaul in the well, additional recordings of wave acoustic logging and non-stationary thermometry are carried out, which evaluate the height and width of the hydraulic fracture, which together with the data on hydraulic fracturing the volume of proppant injected into the fracture allows us to estimate the fracture length L _i for each formation, then based on the data on the fracture lengths L ₁ and L _{2, the} difference of the skin factors of the formations Δs is estimated by the formula:

then, based on the value determined by the well test, the integral skin factor and Δs value, the skin factor of each of the layers is calculated.

The formulas for calculating the skin factor for a two-layer system are:

Next, permeability of formations is calculated. For a two-layer system, the calculation is performed according to formulas (3) and (4).

Option 3. If there are hydraulic fracturing fractures (Fracturing) in two or more jointly developed formations and there is no information on hydraulic fracturing design: during the well test (start or stop cycle of a well), change curves in the flow rate of each formation are recorded, then the change curve in the time difference of the flow rates ΔQ = Q ₂ -Q ₁ , after which the average rate of change of the difference of flow rates ΔQ in the logarithmic time scale Int: β = ∂ [ΔQ] / ∂ [lnt] (in the time range at which the dependence ΔQ (t) is close to exponential), by which The Δs value is determined for the rum and the skin factor and permeability of each layer are calculated. For a two-layer system, the calculation is performed according to formulas (3), (4), (6) and (7).

The method for estimating the difference in skin factors proposed in option 3 is based on the experimentally established fact that in the time range t from 1 to 3 days from the start of the well test (start of the well for a stable mode of injection or injection with registration of the pressure stabilization curve, stop of the producing well with registration of the pressure recovery curve, shutdown of the injection well with registration of the pressure drop curve, etc.) the dependence of the difference in production rates ΔQ on time t is close to exponential. Therefore, ΔQ varies on a logarithmic time scale according to a linear law.

Thus, the proposed method allows for stationary hydrodynamic and field-geophysical monitoring of production pump wells with the joint operation of two or more reservoirs under different operating conditions of such wells.

An example of the practical implementation of the method at one of the production wells of JSC Gazprom Neft, consisting of two jointly working formations, is shown in Fig.1-4.

Figure 1 shows the dependence of the difference in flow rates of jointly working formations from the time elapsed since the start of the hydrodynamic study cycle. Dependence codes are the half-lengths of cracks in the upper and lower layers. Region I is highlighted on the graph — the time domain of values in which the ΔQ (lnt) dependence is close to linear.

Figure 2 shows the dependence of the rate of change in the difference in flow rates β = ∂ [ΔQ] / ∂ [lnt] on the difference in skin factors of the jointly exploited formations Δs.

Figure 3 shows the original well test curves for assessing the integrated parameters of jointly working formations obtained by the pressure sensor at the pump intake. The upper part shows the graphs of changes in time of the flow rate of the well and total production, the lower part shows the pressure graph (the results of interpretation by the matching method are indicated by lines, the measurement results by dots).

Figure 4 presents the results of the interpretation of well testing for a reservoir system on a LOG-LOG scale. The pressure increment curve is shown in the upper part, and the logarithmic derivative in the lower part (points are the measurement results, solid lines are calculated curves obtained by the registration method). The abscissa shows the relative time.

In accordance with the measurements, the permeability of the upper layer was 5 mD, of the lower layer - 2 mD.

=1.7 и скин-фактор

=-4.6.According to the results of well testing, the following were determined: integrated permeability of the formation system

= 1.7 and skin factor

= -4.6.

Based on the results of flow measurement, the flow rate of the upper and lower strata is estimated:

Q ₁ = 116.8 m ³ / day and Q ₂ = 27.3 m ³ / day.

In accordance with option 1 of the proposed method, the porosity ratio of the studied formations was estimated, which was α = k _P ⁽¹⁾ / k _P ⁽²⁾ = 4.62. This made it possible by formulas (1), (2), (3) and (4) to calculate the permeability and skin factors for each layer: k ₁ = 3.8 mD, k ₂ = 0.8 mD, s ₁ = -4.6, s ₂ = -4.3.

Further, according to options 2 and 3, the difference of skin factors for jointly working formations was estimated. For this, fracturing design data was used (option 3). According to the design, the effective thickness of the upper stratum is 6.4 m, the proppant volume in the stratum is 79 tons, the effective thickness of the lower stratum is 15.6 m, and the half-length is 150 tons. The difference in skin factors of the strata was 0.24.

As a result of calculating the parameters of the formations using formulas (3), (4), (6) and (7), the permeability of the formations was: k ₁ = 3.2 mD, k ₂ = 0.6 mD, skin factors were: s ₁ = -4.7, s ₂ = -4.4.

Thus, in accordance with the above example, the results of the evaluation of the properties of the reservoirs, obtained by various algorithms provided by the proposed method, were close to each other.

Claims (3)

1. A method for determining the filtration properties of working reservoirs, including determining the integrated (common for reservoirs) hydrodynamic characteristics from the well test results, measuring the flow rate of each of the reservoirs by mechanical flow metering and calculating the filtration properties of each reservoir based on non-stationary filtration equations using measured flow rate data, characterized in that the porosity ratio is estimated from the well logs in an open borehole

and effective formation thicknesses, then based on the well test, the integrated skin factor and α value are used to calculate the skin factor and permeability of each of the layers. 2. A method for determining the filtration properties of working reservoirs, including the determination of the integrated (common for reservoirs) hydrodynamic characteristics from the well test results, measuring the flow rate of each of the layers by mechanical flow metering and calculating the filtration properties of each reservoir based on non-stationary filtration equations using data on the measured flow rate, characterized in that in the well, recordings of wave acoustic logging and non-stationary thermometry are carried out, according to which they determine the height and width of the hydraulic fracture, which, together with the data on the volume of proppant injected into the fracture, makes it possible to estimate the hydraulic fracture length for each formation, then, based on the data on the fracture lengths, the difference of the skin factors of the formations Δs is estimated, and then based on the well test value integral skin factor and Δs values calculate the skin factor and permeability of each of the layers. 3. A method for determining the filtration properties of working reservoirs, including determining the hydrodynamic (integrated for reservoirs) integrated hydrodynamic characteristics from the well test results, measuring the flow rate of each of the reservoirs by mechanical flow metering and calculating the filtration properties of each reservoir based on non-stationary filtration equations using measured flow rate data, characterized in that during the course of the well test, the curves of changes in the flow rate of each formation are recorded, then the curve is calculated and Menenius time difference flow rates, after which the average rate of change of flow rates of the difference, which is determined by the difference of the skin layers factors and calculating skin factor and permeability of each of the layers.

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