SU1416681A1 - Method of determining effective porosity coefficient of producing formation - Google Patents

Abstract

The invention relates to the oil and gas industry, namely, to the determination of oil and gas reserves from the results of testing the prospects of formations during the drilling of wells with pipe testers. The goal is to improve the accuracy of determining the effective porosity coefficient of the reservoir by increasing the radius of the study. inflow with flow rate q. Then record the curve of the change of the regime of flow (CSRP) with the depth gauge in podpakornom space at the bottom of the well. Flow rates in the first and second inflow modes are determined (by means of a deep debitometer or by calculation), a closed test period is carried out, and the podspaker space is isolated from the internal cavity of the pipes. Record the pressure recovery curve (HPC) in the sub-packer space. The reservoir pressure and the hydraulic coefficient of the reservoir are determined from the data of the CSRP and ARC. The effective porosity ratio is calculated using a specific formula. 5 Il. i (L O) O) 00

Description

The invention relates to an oil and gas production industry, namely to determining the pore volume and fractures of a reservoir involved in the filtration of formation fluid, i.e. to the determination of oil and gas reserves based on the results of testing prospective formations in the process of drilling wells with pipe testers.

The aim of the invention is to improve the accuracy of determining the effective porosity coefficient of a productive formation by increasing the study radius.

FIG. Figure 1 shows a pressure chart of a depth gauge located below the formation tester in the sub-pakpernoy zone; in fig. 2 is a fragment A of the diagram in FIG. one; Fig. 3 is a pressure chart of a depth gauge located in the pipes above the formation tester; in fig. 4 is a graph of a pressure recovery curve (HPC) plotted in semi-logarithmic coordinates P depending on

/ 1 T + e. (Ig -);

in fig. 5 is a graph of the curve of the change in the mode of the pritor (PRS), plotted in the semilogarithmic coordinates PC, depending on

but&

Tl + lt

ut

Chg

1 it. Ig tg-).

one

The method is carried out as follows.

The well radius and the formation thickness are measured. During testing, the inflow from the reservoir is called in the first mode with a flow rate q., Then the flow regime changes with the flow rate q. 1) the mathematical expression describing this change in pressure is as follows:

P -P 0.183 qiM. 2.25 k Tt., S - 6 mfxB r |

+. Tr + It. JA 1 t, kh dt q, - T,

where PO «PC, respectively, is the reservoir pressure and the current pressure in the sub-packer space; q, qj- rates respectively

in the first and second flow modes;

. Q

five

0 5

0

five

0

five

0

k is the reservoir permeability coefficient; h is the formation thickness; Gr - well radius; ji, B — viscosity and coefficient

bulk elasticity of the reservoir fluid; T, L - respectively time

the first inflow mode and the current time after the transition from the first inflow mode to the second one. Flow rates are determined on the first and second flow modes (for example, using a depth flow meter or by calculation using a depth gauge recording). Test the closed period, isolating the sub-packer space from the interior of the tubes. ,

Record the pressure recovery curve (HPC) in the sub-packer space using a depth gauge (Fig. 1). The mathematical expression describing the pressure change in a closed test period is

R . q- .. T + g, fy. P (Ig -), (2)

where q is the average tsebit;

 V

PM tt fo5 (a where V is the volume of fluids obtained for

total inflow time; . T, b - the total inflow time and the current time of the closed period. Plot a plot of P with T + b

: f (lg) using a chart

9

pressure of the depth manometer (HPC), and it determines the reservoir pressure Pp, which is equal to the length of the segment, cut off on the ordinate axis, from the origin (Fig. 4) „

Determine the compressibility factor of the formation fluid and its viscosity under laboratory conditions (according to the analysis of the fluid sampled during the test), and then plot the PC f (lg

 t -1

five

4t

using the pressure gauge of the depth gauge (CSRP), it is used to determine the coefficient of hydroconductivity

kh of the stratum -yyy, which is inversely proportional to the angle of inclination M

 0.183-q-i (u

kh

plotted graph (Fig. 5). Then, the coefficient of reservoir permeability K is determined from the coefficient of hydraulic conductivity of the formation, using data from the measurement of the thickness of the formation h and viscosity of the formation fluid | t (.

The parameter A is calculated for any fixed time 4tj and the corresponding downhole pressure PCI, taken from the plot of the CSRP.

The effective porosity coefficient of the reservoir is determined by the formula

k b / g

2.25 kt tt mey

ten

o, “HiH

(3)

h de k - coefficient of permeability of the reservoir, m; , formation thickness, m; well radius, m; viscosity and coefficient of bulk elasticity of formation fluid, MPa-s, 1 / M11a; flow rate in the second flow mode, m / s;

time of the first inflow mode, s;

,AT

1 T,

. (P „-P.;) Cl

0.183 qiju kh

Ig

T, + / 3 t

4tj

(four)

+ Yag Ig ti qi TI

The parameters are calculated for any fixed time Jt taken from the plot of the PSRP; Pp, Pj.j- initial reservoir pressure and bottomhole pressure at the moment of fixed time, taken from the CSRP schedule, MPa.

The method was tested in the well. Baseline data for the well and the test object: the bottom of the well is 2,770 m, the test interval is 2,750 - 2,770 m.

The method was carried out in the following order. The borehole diameter was measured to be 20 cm (Г (, 10 cm) and the reservoir thickness was h 1000 cm. Zatzma was equipped with a set of reservoir testers and pipes, which included a device for changing the flow regimes at the bottomhole. After the packer from the annulus) was caused by the inflow from the reservoir in the first mode after 20 mm fitting for T, 8.8 min (528s)

Then the inflow mode at the bottom was changed ({amen

with a diameter of 20 mm per fitting with a diameter of 10 mm), with which the inflow lasted for T 6.5 min (390 s). Then, a second change of inflow mode at the bottom of the well was carried out (replaced by a nozzle with a diameter of 10 mm with a nozzle with a diameter of 5 mm), at which the flow continued for T s 7.6 minutes (456 seconds).

A depth gauge was used to record the change throughout the open test period.

pressures in the sub-packer space (Fig. 1). The PA diagram (Fig. 1) shows the CSRD and CSRP2, respectively, the curves of the change in flow regimes during the transition from the first flow regime to

second and second to third, as well as characteristic pressure points P, P and PZ, corresponding to the initial pressures of the first, second and third inflows.

A pressure gauge installed in the tubes of the above reservoir tester also recorded a pressure chart (Fig. 3). This chart reflects the increase in pressure.

liquid column when filling drill pipes in periods of inflow. Debi-Tbiq ,, each inflow mode were calculated using x- and design points from the pressure diagram

in fig. 3 according to the formula

n - FTP Prp; (t), ..

W) - p g -t. .

where q is the flow rate in the i-th flow regime (first, second, third)

 lP "j (t) is the increase in pressure in drill pipes for the i-ro flow regime (for the first 4P, P" 2 - P, for the second Р Rg PZ - Plj, for the third - 4Pr P. - P c

 - area of internal section

drill pipe;

P density of formation fluid5 g - acceleration of free fall;

T) is the inflow time on the i-th inflow mode (first, second, third inflow modes).

The calculated flow rates using the formula (5) using the pressure chart in FIG. 3 are given in table. one.

Table 1

To interpret the curve of the regime of inflow mode (CSRP), an EN section was chosen — the transition from the first inflow mode to the second CSRP (Fig. 1 and 2).

Data required for building 15

no graph of PC pressure change in

Vat.q2ig 4t

depending on Ig

At

 t,

were taken with pressure charts

tab. 3,

Table 3

At the end of the third open period, a closed test period was carried out for Q 15 minutes. At the same time, the depth gauge recorded a pressure recovery curve (HPC) with starting and ending points, respectively, P4 and Pj (Fig. 1). Pressure 2o FIG. 1 and 2. For them the necessary calculations were made in the pipes with a closed period; the tested calculations given in the cable do not change and therefore the pressure gauge (Fig. 3) records the horizontal line at the same level, respectively. the characteristic point of P. 25

To plot the ARC graph in semi-logarithmic coordinates R. in the prefix, l.

hanging from Ig-g-, KVD in figure 1

about

It was divided into elementary areas. JQ For the corresponding values, -, taken from the ARCS (Fig. 1), were calculated

1 / T + HF

values of Ig (-g -) j are given in Table. 2

which are 35

ordinate segment OR, equal agreement | {on the equation of the ARC P 30.2 MPa.

Under laboratory conditions, the compressibility coefficient of the reservoir

go fluid (B 10 T-TFT-) and viscosity

MPa

| U 0.45-10 MPa-s according to the analysis of the sample selected when testing a sample of fluid 0 VDa.

To interpret the curve of the inflow regime pattern (CSRD), an EN section was chosen - the transition from the first inflow mode to the second RSVD (Fig. 1 and 2).

Data Required for Build5

no graph of PC pressure change in

Vat.q2ig 4t

depending on Ig

At

 t,

were taken with pressure charts

o FIG. 1 and 2. The necessary calculations were made for them, given in. five

tab. 3,

 FIG. walkable

Table 3

he made untreated in

table 2

According to the table. 2, the ARC plot was plotted in semilogarithmic coordinates Рр depending on

T + 9. , h, cc conductivity of the reservoir Ig. , L: Y (Fig. 4). This chart has "

e

VIY inclined straight with tilt angle

  qi 0,1 / h Mj

M

0.183 q (q k-h.

clipped on the axis

According to the table. 3 plotted

dependencies (lg .V- TJT-)

Ls q i 1

which has the form of an inclined straight (Fig. 5). According to the equation describing the pressure change when changing the flow regime, the slope angle is

My graphics in FIG. 5 is 2 0 ,. 1.43 MPa / lts.

Hence, we determined the coefficient of hydraulic conductivity of the reservoir.

  qi 0.183-8.83- / H Mj1.43

1135 cm / (MPa s);

1135 1000

kh

1.13 cm2 / (MPa s); 1135

D7l83-qjju 0.183-56805

 l ° 9 w Calculated parameter A for a fixed time 4t. 60 s corresponding to the bottomhole pressure of 22.83 MPa:

A. (P, -P, - ° - fagI u

it.

inflow regime change (CSRP), sampling of formation fluid and e analysis, measurement of the well radius and seam thickness, which are characterized by the fact that, in order to increase precisely by increasing the formation radius of the formation, the period tests with recording the pressure recovery curve (HPC), according to the CSRP and HPC data, determine the surface pressure and the coefficient of hydro-formation pressure, and the coefficient

Я1 1 ALL - (9 79 0.183-8870 15 The effective porosity is calculated using igt / UU, - /, BJ; .1 formula ....

Ka

) rO, 387 6.82 MPa.

m

Determined the efficiency coefficient

2,25-kTi

oh reservoir porosity by the formula

KfiA

/ W W;

ten

o.rtJfVjf

2.25 kTi

2.25 1.13-528

10- yuo -

pBrJlO e.i "HiM

0.02.

Thus, the proposed method allows with sufficient accuracy to determine the effective porosity coefficient of the productive formation at the stage of its drilling and testing without a significant change in the test equipment and technology.

Claims (1)

Invention Formula The method for determining the effective porosity coefficient of a productive plasg, including the formation study in two modes of flow of fluid into the well with the determination of well flow rates and recording the flow pattern change curve (CSRD), sampling of formation fluid and its analysis, measurement of well radius and thickness formation, characterized in that, in order to increase accuracy by increasing the study radius of the formation, after the study in the second mode, a closed test period is carried out with recording the recovery curve (HPC), according to the DRNC and HPC determined gidropro- formation pressure and formation conductivity coefficient and coefficient efchisl .... Ka m 2,25.kT, Q 0, m, H, B-rt 0 five thirty 35 where m is the effective porosity coefficient of the reservoir; k - permeability coefficient reservoir h — formation thickness, m; g - well radius, m; | U, B — viscosity and coefficient of bulk elasticity of a reservoir fluid, MPa s, 1 / MPa; Yad-flow rate in the second inflow mode, m / s; I T is the time of the first flow regime, s; BUT . (Po-P "i) - f IS) i - eleven Pg - reservoir pressure, MPa; a fixed time from the beginning of the study and the corresponding downhole pressure, s, MPa. five  PI PI figure 1 T, 528 0122ti3611860728 96 Bpefffifu l fig g Time fft / ff. cpi / g bapt / w / y