U.S. patent application number 14/513163 was filed with the patent office on 2015-04-23 for method for determining a filtration velocity of reservoir fluids.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Vyacheslav Pavlovich Pimenov, Valery Vasilievich Shako, Maria Viktorovna Sidorova, Bertrand Theuveny.
Application Number | 20150107827 14/513163 |
Document ID | / |
Family ID | 52825152 |
Filed Date | 2015-04-23 |
United States Patent
Application |
20150107827 |
Kind Code |
A1 |
Shako; Valery Vasilievich ;
et al. |
April 23, 2015 |
Method for Determining A Filtration Velocity of Reservoir
Fluids
Abstract
Temperature is measured in a shut-in wellbore and rates of
temperature change in depth intervals within productive layers and
in depth intervals adjacent to the productive layers are
determined. Areas are selected in the depth intervals within the
productive layers wherein the rate of temperature change is
significantly higher than the rate of change in the depth intervals
adjacent to the productive layers. A numerical model of temperature
change in the shut-in wellbore is created taking into account a
filtration effect of a reservoir fluid on the rate of the
temperature change in the shut-in wellbore. The measurement results
are compared with the numerical modeling results, and their best
match is used for determining a fluid filtration velocity in the
selected areas in the depth intervals within the productive
layers.
Inventors: |
Shako; Valery Vasilievich;
(Domodedovo, RU) ; Pimenov; Vyacheslav Pavlovich;
(Moscow, RU) ; Theuveny; Bertrand; (Moscow,
RU) ; Sidorova; Maria Viktorovna; (Moscow,
RU) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar land |
TX |
US |
|
|
Family ID: |
52825152 |
Appl. No.: |
14/513163 |
Filed: |
October 13, 2014 |
Current U.S.
Class: |
166/250.01 |
Current CPC
Class: |
E21B 47/103
20200501 |
Class at
Publication: |
166/250.01 |
International
Class: |
E21B 49/08 20060101
E21B049/08; E21B 47/06 20060101 E21B047/06 |
Foreign Application Data
Date |
Code |
Application Number |
Oct 18, 2013 |
RU |
2013146561 |
Claims
1. A method for determining a reservoir fluid filtration velocity,
comprising: measuring temperature in a shut-in wellbore;
determining a rate of temperature change at depth intervals within
productive layers and a rate of temperature change at depth
intervals adjacent to the productive layers; selecting areas at the
depth intervals within the productive layers wherein the rate of
temperature change is significantly higher than the rate of change
at depth intervals adjacent to the productive layers; creating a
numerical model of temperature change in the shut-in wellbore
taking into account a filtration effect of a reservoir fluid on the
rate of the temperature change in the shut-in wellbore; comparing
the measurement results with the numerical modeling results; and
determining the filtration velocity of the reservoir fluids in the
selected areas at the depth intervals within the productive layers
by matching the measurement results with the numerical simulation
results.
2. The method of claim 1, wherein the temperature in the shut-in
well is measured with a fiber-optic gauge.
3. The method of claim 1, wherein the temperature in the shut-in
well is measured by means of at least three temperature loggings of
the well.
4. The method of claim 1, wherein the areas where the rate of
temperature change is significantly higher than the rate of change
in the depth intervals adjacent to the productive layers are
selected after 10 to 30 hours of the wellbore shut-in.
5. The method of claim 1, wherein the temperature measurements in
the shut-in wellbore are performed after cementation.
6. The method of claim 1, wherein the temperature measurements in
the shut-in wellbore are performed after production.
7. The method of claim 1, wherein the temperature measurements in
the shut-in wellbore are performed after fluid injection.
8. The method of claim 1, wherein the temperature measurements in
the shut-in wellbore are performed after fluid circulation.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority to Russian Application No.
2013146561 filed Oct. 18, 2013, which is incorporated herein by
reference in its entirety.
TECHNICAL FIELD
[0002] This invention relates to geophysical well logging and is
intended for determination of reservoir fluid velocities in oil
wells.
BACKGROUND
[0003] The optimization of the pattern and behavior of producing
and injecting wells requires information on directions and flow
rates of reservoir fluids in oil reservoirs with dozens or hundreds
of wells drilled. This information allows specifying the
hydrodynamic model of an oil reservoir. Reservoir fluid flow
information is particularly important for high-viscosity oil
production. Besides the heterogeneity of oil reservoir properties,
which can be obtained from geophysical studies, the production
process is characterized by heterogeneity of reservoir filtration
properties associated with reservoir fluid composition.
Water-filled (low viscosity) channels may occur between injection
and producing wells, through which the injected water enters the
producing wells providing no oil displacement and no heating of
oil-containing areas of the reservoir. In this respect, development
of methods for controlling reservoir fluid flows in oil reservoirs
with a great number of production and injection wells is of great
interest.
[0004] At present, reservoir fluid flows in oil reservoirs are
controlled indirectly by monitoring hydraulic relation between
wells through an interference test. See, for example, Amanat U.
Chaudhry, Oil Well Testing Handbook, Elsevier Science, 2004, p.
429-462. This method is based on observing pressure change in
non-operating wells when the behavior of active wells is
changed.
[0005] A more direct method consists in tracing filtration flows
with tracer materials. See, for example, G. Michael Shook, Shannon
L. Ansley, Allan Wylie, Tracers and Tracer Testing: Design,
Implementation, and Interpretation Methods, 2004, INEEL. The method
involves adding a tracer into a fluid injected into a well and
registering a moment of appearance of the tracer and its
concentration in a fluid flowing out of producing wells. Various
chemical and radioactive substances are used as tracers. They
should be water-soluble, have no precipitation, no rock sorbing, be
registrable within a wide range of concentrations, etc. Filtration
flow tracing is quite an expensive and laborious method not very
often used. Besides, tracing allows estimating only an average
fluid filtration velocity between an injection well and a
production well. The fluid filtration velocity at the producing
well location (as if it was shut down) remains unknown.
SUMMARY
[0006] The disclosure provides a method for identifying depth
intervals (layers), where the fluid flow occurs, and estimating
their filtration velocity at the observation well location.
[0007] The method comprises measuring temperature in a shut-in
wellbore and determining a rate of temperature change in depth
intervals within productive layers and a rate of temperature change
in depth intervals adjacent to the productive layers. Areas are
selected in the depth intervals within the productive layers
wherein the rate of temperature change is significantly higher than
the rate of change in the depth intervals adjacent to the
productive layers. A numerical model of temperature change in the
shut-in wellbore is created taking into account a filtration effect
of a reservoir fluid on the rate of the temperature change in the
shut-in wellbore. The measurement results are compared with the
numerical modeling results, and their best match is used for
determining a fluid filtration velocity in the selected areas in
the depth intervals within the productive layers.
[0008] According to one of the embodiments of the disclosure, the
temperature in the shut-in well is measured with a fiber-optic
gauge.
[0009] According to another embodiment of the disclosure, the
temperature in the shut-in well is measured by means of at least
three temperature loggings of the well.
[0010] The temperature measurements are performed in the shut-in
well upon completing cementation, production, fluid injection, or
circulation.
[0011] The areas wherein the rate of temperature change is
significantly higher than the rate of change in the depth intervals
adjacent to the productive layers could be selected after 10 to 30
hours of the wellbore shut-in.
BRIEF DESCRIPTION OF DRAWINGS
[0012] Those skilled in the art should more fully appreciate
advantages of various embodiments of the present disclosure from
the following drawings:
[0013] FIG. 1 shows examples of disturbing a reservoir thermal
field prior to temperature measurements in a shut-in well;
[0014] FIG. 2 shows a simulated temperature in the reservoir at the
end of 30 days production;
[0015] FIG. 3 shows a simulated temperature field in the reservoir
at the end of 3 days of shut-in;
[0016] FIG. 4 shows simulated well temperatures normalized to an
initial deviation of the well temperature from the reservoir
temperature;
[0017] FIG. 5 shows normalized temperature change rates for two
filtration velocities;
[0018] FIG. 6 shows a relation between the normalized temperature
change rate to the filtration velocity at shut-in time 20 hours;
and
[0019] FIG. 7 shows a chart of the estimation domain used for
estimation of the filtration velocity using numerical modeling.
DETAILED DESCRIPTION
[0020] The suggested method is based on a dependence of the rate of
temperature change, measured in an observation well, on the
presence and velocity of fluid filtration in a reservoir
intersected by a wellbore.
[0021] This method is implemented in the following way. A
temperature profile is measured with temperature logging devices or
a fiber temperature gauge along a shut-in wellbore after cementing
(FIG. 1a), production (FIG. 1b), fluid injection (FIG. 1c), or
circulation (FIG. 1d). In case of logging, at least 3-5 temperature
measurements are performed. In many cases, an initial temperature
in the wellbore and in a near-wellbore zone differs from
temperature of the rocks distant (a few meters) from the
wellbore.
[0022] The rate of temperature change measured in the wellbore at
various depths is calculated in depth intervals within productive
layers, in depth intervals adjacent to the productive layers, and
in those adjoining the reservoirs (at a distance of not more than a
few dozen meters).
[0023] After a shut-in time 10-30 hours, areas are selected in the
depth intervals within the productive layers wherein the rate of
temperature change is significantly higher than the rate of change
in depth intervals adjacent to the productive layers.
[0024] A numerical model of temperature change in the shut-in
wellbore is created taking into account an influence of the
reservoir fluid filtration on the temperature change rate in the
shut-in well. The measurement results are compared with the
numerical modeling results, and the best match of the measurement
and modeling results is used for determining a fluid filtration
velocity in the selected areas in the depth intervals within the
productive layers.
[0025] The possibility of selecting depth intervals and estimating
the reservoir fluid filtration velocity was demonstrated on
synthetic cases generated by commercial simulator COMSOL
Multiphysics 3.5.RTM..
[0026] 2D modeling of a stationary field of pressure (and
filtration velocity) and of a nonstationary field of temperatures
was performed in a horizontal homogeneous estimation domain
including the wellbore.
[0027] The pressure and temperature equations are:
.DELTA. P = 0 ##EQU00001## .delta. .rho. f c f .differential. T
.differential. t + ( - .lamda. T ) = - .rho. f c f V T where
##EQU00001.2## V _ = - k .mu. . ##EQU00001.3##
.gradient.P is a fluid filtration velocity,
.delta. = .phi. + ( 1 - .phi. ) .rho. m c m .rho. f c f ,
##EQU00002##
k is reservoir permeability, .mu. is viscosity of a filtered fluid,
.lamda. is thermal conductivity of the fluid-saturated reservoir,
.rho..sub.mc.sub.m is bulk thermal capacity of reservoir crystal
matrix, .rho..sub.fc.sub.f is fluid bulk thermal capacity, and
.phi. is reservoir porosity.
[0028] Equation boundary conditions for the pressure calculations
include (FIG. 7) (i) impermeable upper and lower boundaries of the
estimation domain the wellbore surface and (ii) specified pressures
P.sub.1 and P.sub.2 on a left boundary and on a right boundary of
the estimation domain. The pressure difference of P.sub.1-P.sub.2
was selected in a way to provide the required fluid filtration
velocity at the specified reservoir permeability.
[0029] Boundary conditions for the energy equation (FIG. 7) include
(i) heat-insulated upper and lower boundaries of the estimation
domain, (ii) temperature T.sub.0 (equal to the reservoir
temperature) on the left boundary, and (iii) the free outflow
condition on the right boundary of the estimation domain.
[0030] The calculation was performed in two stages.
[0031] At a first stage, a constant temperature was specified for
wellbore boundaries, the temperature corresponds to the temperature
of the fluid flowing in the wellbore during production or
circulation. A temperature field at the end of circulation was
calculated and used as an initial condition for a second stage. At
the second stage, temperature field evolution after the wellbore
shut-in was calculated. The calculation covered the entire
estimation domain including the wellbore.
[0032] As an example, let us consider a reservoir with two
productive layers, producing from a lower layer (FIG. b). FIG. 2
shows a simulated temperature field in an upper layer (at a fixed
depth) after 30 day production at the filtration velocity in this
layer of 0.25 m/day.
[0033] The simulated temperature field in the layer after 3 days
shut-in is shown in FIG. 3. The wellbore is shown with a black
circle. Since a size of an area where the temperature substantially
differs from the reservoir temperature exceeds the wellbore radius
notably, the area of the fluid with a higher temperature moves with
the filtered fluid. As a result, the temperature measured in the
wellbore changes faster than with no flow.
[0034] The simulated temperatures in the wellbore normalized to an
initial deviation of the wellbore temperature from the reservoir
temperature at the filtration velocities of 0.12 and 0.25 m/day are
shown in FIG. 4 (curve 1--V=0, curve 2--V=0.12 m/day, and curve
3--V=0.25 m/day). FIG. 5 shows the temperature change rate at the
filtration velocities of 0.12 and 0.25 m/day normalized to the
temperature change rate with no filtration in the reservoir (curve
1--V=0.25 m/day and curve 2--V=0.12 m/day).
[0035] According to the calculations, a temperature relaxation rate
normalized in this way is highest within the time interval of 10-30
hours after wellbore shut-in. FIG. 6 shows the relation of this
value to the fluid filtration velocity at 20 hours shut-in. The
specific expression of the normalized temperature relaxation rate
depends on wellbore configuration and rock thermal properties, and
should be calculated in each particular case (e.g., using the
commercial simulator COMSOL Multiphysics 3.5.RTM.). According to
FIG. 6, the suggested method allows obtaining information on
filtration flows having velocity of more than 0.03-0.95 m/day.
* * * * *