US 12,693,249 B2 · Method for quantitative evaluation on sensitivity of shale oil and gas reservoir to injected fluids

Abstract

The present disclosure provides a method for quantitative evaluation on a sensitivity of a shale oil and gas reservoir to injected fluids. The method includes the following steps: (I) preparation of rock samples; (II) quantitative evaluation on sensitivities of a shale porosity and a bedding fracture permeability to an injected fluid; and (III) quantitative evaluation on a sensitivity of a shale matrix permeability to an injected fluid. A method for comprehensive evaluation on a sensitivity of a shale oil and gas reservoir to injected fluids is innovatively provided based on the nuclear magnetic resonance testing technology with two basic physical property parameters: porosity and permeability. The method realizes quantitative evaluation on sensitivities of pores of different sizes and matrix of shale and a bedding fracture permeability to injected fluids, and realizes quantitative and accurate evaluation on a sensitivity of a shale oil and gas reservoir to injected fluids.

A method for quantitative evaluation on a sensitivity of a shale oil and gas reservoir to injected fluids, comprising:

(I) preparation of shale rock samples selecting three shale rock samples from a same coring interval and marking the three shale rock samples as 1 #, 2 # and 3 #, wherein the shale rock samples 1 # and 2 # are used for determining a target drying temperature and time, and the shale rock sample 3 # is used for completing an evaluation experiment on sensitivities of a shale porosity and a permeability to an injected fluid;
requirements for the shale rock sample 3 # are as follows:
the shale rock sample is a standard plunger sample having a diameter of 2.5 cm and a length of greater than or equal to 5 cm;
the shale rock sample 3 # is subjected to pretreatment before the evaluation experiment, and is cut into three small shale rock samples numbered as 4 #, 5 # and 6 #;
the shale rock sample 4 # is used for a high pressure mercury injection test;
the shale rock sample 5 # is used for evaluating sensitivities of the shale porosity and the bedding fracture permeability to the injected fluid;
and the shale rock sample 6 # is ground into 10/20-mesh particles for evaluating a sensitivity of a shale matrix permeability;
(II) quantitative evaluation on the sensitivities of the shale porosity and the bedding fracture permeability to the injected fluid
wherein a process of quantitative evaluation on the sensitivities of the shale porosity and the bedding fracture permeability to the injected fluid comprises three steps:
A, determination of the target drying temperature and time of the shale shock sample 1 # and the shale rock sample 2 #
before conducting the evaluation experiment on the sensitivities of the shale porosity and the bedding fracture permeability to the injected fluid, removing mobile fluids comprising hydrocarbons and water existing in the shale rock samples to guarantee that the shale rock samples are clean;
(1) selecting two shale rock samples from a same coring interval and marking the shale rock samples as 1 # and 2 #;
(2) setting 10 different drying temperatures Tt1, Tt2, Tt3, Tt4, Tt5, Tt6, Tt7, Tt8, Tt9 and Tt10, which progressively increase in sequence by 20° C.;
(3) drying the shale rock sample 1 # at a set temperature condition for time to hours (h}, measuring corresponding rock sample masses m1, m2, m3, m4, m5, m6, m7, m8, m9 and m10 of the shale rock sample 1 #under different drying temperature conditions and carrying out a two-dimensional nuclear magnetic resonance test of the dried shale rock sample 1 # to obtain a two-dimensional nuclear magnetic resonance spectrum T1;
(4) plotting a changing curve of the mass of the shale rock sample 1 # with the drying temperature, wherein the changing curve of the mass of the shale rock sample 1 # with the drying temperature has an inflection point when the mobile fluids in the shale rock sample 1 # are removed completely, and a temperature corresponding to the inflection point is the target drying temperature T0;
(5) setting 10 different drying times t1, t2, t3, t4, t5, t6, t7, t8, t9 and t10, which progressively increase in sequence by 2 h, wherein t5 or t6 is set to be identical to t0 to reduce a testing workload under a condition of guaranteeing experimental accuracy;
(6) drying the shale rock sample 2 # according to a set time at the target drying temperature T0, measuring corresponding rock sample masses m′1, m′2, m′3, m′4, m′5, m′6, m′7, m′8, m′9 and m′10 of the shale rock sample 2 # under different drying time conditions and carrying out the two-dimensional nuclear magnetic resonance test of the dried shale rock sample 2 # to obtain a two-dimensional nuclear magnetic resonance spectrum T2;
(7) plotting a changing curve of the mass of the shale rock sample 2 # with the drying time, wherein the mass of the shale rock sample 2 # does not change with the drying time when the mobile fluids in the shale rock sample 2 # are removed completely, and at this time, the corresponding time is the target drying time t0;
and
(8) analyzing the two-dimensional nuclear magnetic resonance spectrum T1 and the two-dimensional nuclear magnetic resonance spectrum T2 after the target drying time t0, and determining a final target drying temperature T0 and drying time t0 of the shale rock sample 1 # and the shale rock sample 2 # if the number of nuclear magnetic signals in minipores, mesopores and macropores does not change;
and
if a number of nuclear magnetic signals in minipores, mesopores and macropores in the two-dimensional nuclear magnetic resonance spectra T1 and T2 changes, reselecting the shale rock samples and carrying out the evaluation experiment according to steps (1) to (7), and
redetermining the target drying temperature To and time to of the shale rock sample 1 # and the shale rock sample 2 #;
B, a high pressure mercury injection+injected fluid soaking+nuclear magnetic resonance test combined experiment
(1) the high pressure mercury injection test of the shale rock sample 4 # drying the prepared shale rock sample 4 # according to the determined final target drying temperature T0 and time t0, performing the high pressure mercury injection test on the dried shale rock sample 4 #, plotting a changing curve of a pore distribution frequency with a pore radius under a condition of semilogarithmic coordinates and determining a pore distribution characteristic of the shale rock sample 4 #;
and
(2) an injected fluid soaking+nuclear magnetic resonance test combined experiment of the shale rock sample 5 #;
C, processing and analysis of experimental data
1) quantitative evaluation on the sensitivity of the bedding fracture permeability of the shale rock sample 5 # to the injected fluid
(1) introducing a quantitative evaluation indicator for the sensitivity of the bedding fracture permeability to the injected fluid, as shown in formula (1):
R
K
=
K
a
-
K
b
K
b
×
100
⁢
%
(
1
)
wherein Rk represents a change rate of the bedding fracture permeability in units of percentage (%};
Kb represents the bedding fracture permeability of a dry shale rock sample in units of mD;
and Ka represents the bedding fracture permeability of the shale after being soaked in the injected fluid in units of mD;
(2) calculating the change rate of the bedding fracture permeability before and after the shale is soaked in the injected fluid according to the formula (1);
and
(3) quantitatively evaluating the sensitivity of the bedding fracture permeability of the shale rock sample 5 # to the injected fluid;
2) quantitative evaluation on a sensitivity of a total porosity of the shale to the injected fluid (1) introducing a quantitative evaluation indicator for the sensitivity of the total porosity of the shale to the injected fluid, as shown in formula (2):
R
t
=
f
a
-
f
b
f
b
·
100
⁢
%
(
2
)
wherein Rt represents a change rate of the total porosity measured by a burden-pressure porosity and permeability meter in units percentage (%);
fb represents a porosity of the dry shale rock sample in units of percentage (%);
and fa represents a porosity of the shale after being soaked in the injected fluid in units of percentage (%);
(2) calculating the change rate of the porosity before and after the shale is soaked in the injected fluid according to the formula (2);
and
(3) quantitatively evaluating the sensitivity of the total porosity of the shale to the injected fluid;
3) quantitative evaluation on a sensitivity of pores of different sizes of the shale to the injected fluid
(1) calculation of a time-space conversion coefficient for a value of relaxation time of two-dimensional nuclear magnetic resonance spectrum T2 and a pore size;
(2) establishment of a calibration relationship of the number of signals of the two-dimensional nuclear magnetic resonance spectrum T2 to a saturated water porosity of the shale
1, calculating the saturated water porosity of the shale rock sample 5 # by a gravimetric method by the following calculation formula:
f
w
=
(
m
w
-
m
0
r
w
)
/
(
p
⁢
d
2
⁢
L
4
)
·
100
⁢
%
=
4
⁢
(
m
w
-
m
0
)
r
w
⁢
pd
2
⁢
L
·
100
⁢
%
(
3
)
wherein fw represents the saturated water porosity in units of percentage (%);
mw represents a weight of the shale rock sample 5 # after being saturated with water in units of g;
m0 represents a weight of the dried shale rock sample 5 # in units of g;
rw represents water density in units of g/cm3;
d represents a diameter of the shale rock sample 5 # in units of cm;
and L represents a length of the shale rock sample 5 # in units of cm;
2, testing a T2 spectrum signal component based on nuclear magnetic resonance, and converting the nuclear magnetic T2 spectrum signal component of the shale after being saturated with water into a first porosity component according to formula (4):
f
NMR
,
w
|
T
2
=
S
w
⁢
f
w
S
a
⁢
c
,
w
-
S
a
⁢
c
,
d
(
4
)
wherein fNMR, w|T2 represents the first porosity component after saturation with water in units of percentage (%);
Sw represents a nuclear magnetic T2 spectrum signal component after saturation with water in units of PU;
Sac,w represents a cumulative value of nuclear magnetic T2 spectrum signals after saturation with water in units of PU;
and Sac,d represents a cumulative value of nuclear magnetic signals corresponding to the first peak of the T2 spectrum of saturated water in units of PU;
3, based on a conversion principle of the nuclear magnetic T2 spectrum signal component to the porosity component after saturation with water in step 2, converting the nuclear magnetic T2 spectrum signal component after the shale is soaked in the injected fluid into a second porosity component according to formula (5):
f
NMR
,
s
|
T
2
=
S
s
⁢
f
w
S
a
⁢
c
,
w
-
S
a
⁢
c
,
d
(
5
)
wherein fNMR,s|T2 represents the second porosity component after soaking in the injected fluid in units of percentage (%;
and Ss represents a nuclear magnetic T2 spectrum signal component after soaking in the injected fluid in units of PU;
and
4, based on the first porosity component obtained in step 2 and the second porosity component obtained in step 3, plotting a relationship curve of the porosity component and a cumulative value of porosity components changing with the relaxation time T2 after the shale is saturated with water and soaked in the injected fluid, wherein the cumulative value of nuclear magnetic signals corresponding to the first peak in the T2 spectrum needs to be removed from the curve;
(3) quantitative evaluation on the sensitivity of pores of different sizes to the injected fluid 1, based on the relationship curve of the cumulative value of porosity components changing with the relaxation time T2, introducing quantitative evaluation indicators for the sensitivities of the total porosity of the shale and the porosities of different sizes, as shown in formulas (6), (7), (8), (9) and (10):
R
NMR
t
=
f
NMR
,
s
t
-
f
NMR
,
w
t
f
NMR
,
w
t
·
100
⁢
%
(
6
)
R
NMR
m
⁢
i
⁢
c
=
F
NMR
,
s
mic
-
f
NMR
,
w
m
⁢
i
⁢
c
f
NMR
,
w
m
⁢
i
⁢
c
·
100
⁢
%
(
7
)
R
NMR
min
=
F
NMR
,
s
min
-
f
NMR
,
w
min
f
NMR
,
w
min
·
100
⁢
%
(
8
)
R
NMR
mes
=
F
NMR
,
s
mes
-
f
NMR
,
w
mes
f
NMR
,
w
mes
·
100
⁢
%
(
9
)
R
NMR
mac
=
f
NMR
,
s
mac
-
f
NMR
,
w
mac
f
NMR
,
w
mac
·
100
⁢
%
(
10
)
wherein RtNMR represents a change rate of the total porosity calculated by a nuclear magnetic resonance method in units of (%);
ftNMR, s represents a cumulative value of total porosity components after soaking in the injected fluid in units of percentage (%);
ftNMR, w represents a cumulative value of total porosity components after saturation with water in units of percentage (%);
RmicNMR represents a change rate of a porosity of micropores in units of percentage (%);
fmicNMR, s represents a cumulative value of porosity components of micropores after soaking in the injected fluid in units of percentage (%);
fmicNMR, w represents a cumulative value of porosity components of micropores after saturation with water in units of percentage (%);
RminNMR represents a change rate of a porosity of minipores in units of percentage (%);
fminNMR, s represents a cumulative value of porosity components of minipores after soaking in the injected fluid in units of percentage (%);
fminNMR, w represents a cumulative value of porosity components of minipores after saturation with water in units of percentage (%);
RmesNMR represents a change rate of a porosity of mesopores in units of percentage (%);
fmesNMR, s represents a cumulative value of porosity components of mesopores after soaking in the injected fluid in units of percentage (%);
fmesNMR, w represents a cumulative value of porosity components of mesopores after saturation with water in units of percentage (%);
RmacNMR represents a change rate of a porosity of macropores in units of percentage (%);
fmacNMR, s represents a cumulative value of porosity components of macropores after soaking in the injected fluid in units of percentage (%);
fmacNMR, w represents a cumulative value of porosity components of macropores after saturation with water in units of percentage (%);
recommended classification criteria for pores of different sizes in a shale reservoir are as follows:
pores having a radius of <0.01 μm are micropores, and 0.01 μm to 0.1 μm as minipores, 0.1 μm to 1.0 μm as mesopores, and >1.0 μm as macropores;
2, based on the time-space conversion coefficient k, calculating values of the relaxation time T2 corresponding to divided radii of the micropores, minipores, mesopores and macropores, namely the values T2, 10 nm, T2, 100 nm and T2, 1000 nm of the relaxation time T2 corresponding to 10 nm, 100 nm and 1000 nm;
3, based on the values T.sub.2.10 nm, T.sub.2,100 nm and T.sub.2, 1000 nm, calculating the porosities fmicNMR, w, fminNMR, w, fmesNMR, w and fmacNMR, w of the micropores, minipores, mesopores and macropores after saturation with water and the porosities fmicNMR, s, fminNMR, s, fmesNMR, s and fmacNMR, s of the micropores, minipores, mesopores and macropores after soaking in the injected fluid by formulas (11) to (18):
f
NMR
,
w
m
⁢
i
⁢
c
=
(
S
w
|
T
2
,
10
⁢
nm
-
S
ac
,
d
)
·
f
w
S
ac
,
w
-
S
ac
,
d
(
11
)
f
NMR
,
w
min
=
(
S
w
|
T
2
,
100
⁢
nm
-
S
w
|
T
2
,
10
⁢
nm
)
·
f
w
S
ac
,
w
-
S
ac
,
d
(
12
)
f
NMR
,
w
mes
=
(
S
w
|
T
2
,
1000
⁢
nm
-
S
w
|
T
2
,
10
⁢
0
⁢
nm
)
·
f
w
S
ac
,
w
-
S
ac
,
d
(
13
)
f
NMR
,
w
mac
=
(
S
ac
,
w
-
S
w
|
T
2
,
1000
⁢
nm
)
·
f
w
S
ac
,
w
-
S
ac
,
d
(
14
)
f
NMR
,
s
mic
=
(
S
s
|
T
2
,
10
⁢
nm
-
S
ac
,
sd
)
·
f
w
S
ac
,
w
-
S
ac
,
d
(
15
)
f
NMR
,
s
min
=
(
S
s
|
T
2
,
100
⁢
nm
-
S
s
|
T
2
,
10
⁢
nm
)
·
f
w
S
ac
,
w
-
S
ac
,
d
(
16
)
f
NMR
,
s
mes
=
(
S
s
|
T
2
,
1000
⁢
nm
-
S
s
|
T
2
,
100
⁢
nm
)
·
f
w
S
ac
,
w
-
S
ac
,
d
(
17
)
f
NMR
,
s
mac
=
(
S
ac
,
s
-
S
s
|
T
2
,
1000
⁢
nm
)
·
f
w
S
ac
,
w
-
S
ac
,
d
(
18
)
where in Sw|T2, 10 nm represents a cumulative value of nuclear magnetic T2 spectrum signals of the micropores after saturation with water in units of PU;
Sw|T2, 100 nm represents a cumulative value of nuclear magnetic T2 spectrum signals of the minipores after saturation with water in units of PU;
Sw|T2, 1000 nm represents a cumulative value of nuclear magnetic T2 spectrum signals of the mesopores after saturation with water in units of PU;
Ss|T2, 10 nm represents a cumulative value of nuclear magnetic T2 spectrum signals of the micropores after soaking in the injected fluid in units of PU;
Ss|T2, 100 nm represents a cumulative value of nuclear magnetic T2 spectrum signals of the minipores after soaking in the injected fluid in units of PU;
Ss|T2, 1000 nm represents a cumulative value of nuclear magnetic T2 spectrum signals of the mesopores after soaking in the injected fluid in units of PU;
Sac,sd represents a cumulative value of nuclear magnetic signals corresponding to the first peak of the T2 spectrum after soaking in the injected fluid in units of PU;
and Sac,s represents a cumulative value of nuclear magnetic signals of the T2 spectrum after soaking in the injected fluid in units of PU;
and
4, calculating the change rates of the total porosity and the porosities of different sizes before and after the shale rock sample is soaked in the injected fluid based on formulas (6), (7), (8), (9) and (10), and giving results of quantitative evaluation on the sensitivities of the total porosity and the pores of different sizes of the shale reservoir to the injected fluid;
(III) quantitative evaluation on the sensitivity of the shale matrix permeability to the injected fluid
wherein the quantitative evaluation on the sensitivity of the shale matrix permeability to the injected fluid comprises the following steps:
1, sample preparation:
selecting the shale rock sample 6 # from the same coring interval with the evaluation on the sensitivities of the porosity and the bedding fracture permeability to the injected fluid, and grinding the shale rock sample 6 #into a 10/20-mesh particles with a mass of greater than 30 g;
2, drying the particle under the conditions of the target drying temperature T0 and time t0;
3, based on a pressure pulse decay principle, measuring a matrix permeability Kmb of particles of the ground sample 6 # by using a shale matrix permeameter;
4, placing the particle into a piston container, vacuumizing the piston container by using a vacuumizing pretreatment system for 48 h, and placing a sieve mesh on an upper portion of the piston container to protect the piston container;
5, placing the injected fluid into another piston container, injecting the injected fluid into the piston container holding the particle by using a pump to soak the particle sample for 48 h with a soaking pressure being identical to a formation pressure;
6, taking out the particle and drying the particle sample under the conditions of the target drying temperature T0 and time t0;
7, measuring the matrix permeability Kma of the particle after being soaked in the injected fluid by using the shale matrix permeameter;
8, calculating the change rate of the matrix permeability before and after the particle is soaked in the injected fluid based on formula (19):
R
m
⁢
K
=
K
m
⁢
a
-
K
m
⁢
b
K
m
⁢
b
×
100
⁢
%
(
19
)
wherein RmK represents the change rate of the matrix permeability of the particle in units of percentage (%);
Kmb represents the matrix permeability of the particle after being soaked in the injected fluid (after drying) in units of mD;
and Kma represents the matrix permeability of the particle after being soaked in the injected fluid in units of mD;
and
9, giving a result of the quantitative evaluation on the sensitivity of the shale matrix permeability to the injected fluid;
and
giving a result of the quantitative evaluation on the sensitivity of the shale oil and gas reservoir to the injected fluid by comprehensive analysis based on changing laws of the total porosity, the porosities of different sizes, the bedding fracture permeability and the matrix permeability before and after the shale is soaked in the injected fluid.

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Method for quantitative evaluation on sensitivity of shale oil and gas reservoir to injected fluids

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Method for quantitative evaluation on sensitivity of shale oil and gas reservoir to injected fluids

Life of this patent

Abstract

Claims3