U.S. patent application number 13/458569 was filed with the patent office on 2012-11-01 for methods of calculating a fluid composition n a wellbore.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to CHARLES S. OAKES, TERIZHANDUR S. RAMAKRISHNAN, SANDEEP VERMA.
Application Number | 20120273194 13/458569 |
Document ID | / |
Family ID | 47067009 |
Filed Date | 2012-11-01 |
United States Patent
Application |
20120273194 |
Kind Code |
A1 |
VERMA; SANDEEP ; et
al. |
November 1, 2012 |
METHODS OF CALCULATING A FLUID COMPOSITION N A WELLBORE
Abstract
The subject disclosure relates to methods for passively
measuring a composition of a wellbore.
Inventors: |
VERMA; SANDEEP; (ACTON,
MA) ; OAKES; CHARLES S.; (CAMBRIDGE, MA) ;
RAMAKRISHNAN; TERIZHANDUR S.; (BOXBOROUGH, MA) |
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
47067009 |
Appl. No.: |
13/458569 |
Filed: |
April 27, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61480642 |
Apr 29, 2011 |
|
|
|
Current U.S.
Class: |
166/250.01 |
Current CPC
Class: |
Y02P 90/70 20151101;
G01N 2291/02872 20130101; E21B 43/164 20130101; G01N 2291/02809
20130101; E21B 49/08 20130101 |
Class at
Publication: |
166/250.01 |
International
Class: |
E21B 47/06 20120101
E21B047/06 |
Claims
1. A method for obtaining a composition estimate of a fluid in a
wellbore traversing a subterranean formation, comprising: measuring
a temperature and a pressure of a fluid in the wellbore; obtaining
a density by differentiating the pressure with respect to vertical
height; and calculating the composition of the fluid using an
equation of state.
2. The method of claim 1, further comprising introducing carbon
dioxide to the formation.
3. The method of claim 1, further comprising measuring brine
displacement.
4. The method of claim 1, further comprising using an observation
wellbore and an injection wellbore.
5. The method of claim 1, further comprising identifying
interventions.
6. The method of claim 1, further comprising determining the
injected carbon dioxide composition.
7. The method of claim 1, wherein the equation of state is European
Gas Research Group--2004.
8. The method of claim 1, wherein the equation of state is European
Gas Research Group--2008.
9. The method of claim 1, wherein the equation of state is
virial.
10. The method of claim 1, wherein the equation of state is
cubic.
11. The method of claim 1, wherein the measuring comprises using a
device selected from the group consisting of a gradiomanometer,
vibrating tube, and vibrating wire.
12. The method of claim 1, further comprising comparing the
obtained and observed density measurements.
13. The method of claim 12, further comprising repeating the
obtaining the density measurement.
14. A method for obtaining a composition estimate of a fluid in a
wellbore traversing a subterranean formation, comprising: measuring
density, temperature, and a pressure of a fluid in the wellbore;
and calculating the composition of the fluid using an equation of
state.
15. The method of claim 14, further comprising introducing carbon
dioxide to the formation.
16. The method of claim 14, further comprising measuring brine
displacement.
17. The method of claim 14, further comprising using an observation
wellbore and an injection wellbore.
18. The method of claim 14, further comprising identifying
interventions.
19. The method of claim 14, further comprising determining the
injected carbon dioxide composition.
20. The method of claim 14, wherein the equation of state is
European Gas Research Group--2004.
21. The method of claim 14, wherein the equation of state is
European Gas Research Group--2008.
22. The method of claim 14, wherein the equation of state is
virial.
23. The method of claim 14, wherein the equation of state is
cubic.
24. The method of claim 14, further comprising comparing the
obtained and observed density measurements and repeating the
obtaining the density measurement.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims benefit of U. S. Provisional Patent
Application Ser. No. 61/480,642 filed on Apr. 29, 2011, which is
incorporated herein by reference.
FIELD
[0002] The subject disclosure generally relates to wellbore fluid
characterization. More particularly, the subject disclosure relates
to passive methods for determining a wellbore fluid
composition.
BACKGROUND
[0003] Gas injection may be used for enhanced oil, or enhanced
natural gas recovery, and in sequestration of carbon dioxide. In
certain circumstances it may be useful to know the injected gas
composition introduced via an injection well into a reservoir. In
the reservoir, the injected gas contacts and displaces the
reservoir fluid. This changes the previously established
thermodynamic equilibrium between the existing vapor, liquid and
solid phases in the reservoir. The injected gas mixes first with
the vapor phase and then diffuses into the liquid phase. Local
drive to equilibrium may cause repartitioning of components into
phases, e.g., injection of CO.sub.2 into a methane saturated brine
stream leads to preferential release of methane into the vapor
phase and dissolution of CO.sub.2 into the brine or the liquid
phase. Subsequently, the change in liquid and/or vapor composition
may lead to additional mass transfer with the solid phase, e.g.,
addition of CO.sub.2 in the vapor and liquid phases leads to
preferential release of methane adsorbed on solid mineral surfaces.
Additionally, it may lead to dissolution/precipitation reactions
with reservoir minerals. Consequently, the reservoir fluid and the
injected fluid composition change due to mass transfer.
[0004] Observation wells are drilled away from injection wells to
provide real-time measurements of the fluid composition at
bottom-hole conditions. These measurements include sampling,
well-well pressure interference, EM or seismic/acoustics, and well
logs. The observation wells are usually perforated to allow fluid
to enter the well if sampling is desired.
SUMMARY
[0005] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, or as an aid in
limiting the scope of the claimed subject matter.
[0006] According to some embodiments, a method for obtaining a
passive measurement of a composition is described. The method
includes measuring a temperature and a pressure of a fluid in a
wellbore; obtaining a density by differentiating the pressure with
respect to vertical height and using an equation of state to infer
the composition of the fluid.
[0007] According to some embodiments, a second method for obtaining
a passive measurement of a composition is described. The method
includes measuring a temperature, pressure and density of a fluid
in a wellbore and using an equation of state to infer the
composition of the fluid.
[0008] Further features and advantages of the subject disclosure
will become more readily apparent from the following detailed
description when taken in conjunction with the accompanying
drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The patent or application file contains at least one drawing
executed in color. Copies of this patent or patent application
publication with color drawings will be provided by the Office upon
request and payment of the necessary fee. The subject disclosure is
further described in the detailed description which follows, in
reference to the noted plurality of drawings by way of non-limiting
examples of embodiments of the subject disclosure, in which like
reference numerals represent similar parts throughout the several
views of the drawings, and wherein:
[0010] FIG. 1 depicts a cross-section of a reservoir between the
injection well and the first and second observation wells;
[0011] FIG. 2 depicts brine displacement as a function of time in
an observation well;
[0012] FIG. 3 is a graph of pressure versus depth for an injection
well and a first and a second observation well;
[0013] FIG. 4 is a graph of temperature versus depth for an
injection well and a first and a second observation well;
[0014] FIG. 5 is a graph of density versus depth for the injection
well;
[0015] FIG. 6 is a graph of density versus depth for the injection
well;
[0016] FIG. 7 is a graph of density versus depth for the injection
well;
[0017] FIG. 8 is a graph of density versus depth for a first
observation well;
[0018] FIG. 9 is a graph of density versus depth for a second
observation well; and
[0019] FIG. 10 is a flow chart of the method steps of one
embodiment of the subject disclosure;
[0020] FIG. 11 is a graph of density versus depth for a second
observation well;
[0021] FIG. 12A is a graph of the concentration profile as a
function of depth for a first observation well and FIG. 12B is a
graph depicting the bottom-hole composition in a first observation
well, as measured in samples;
[0022] FIG. 13 is a graph depicting the change in surface pressure
at the injection well and a first and a second observation
well;
[0023] FIG. 14 is a graph depicting the number of days for brine
displacement;
[0024] FIG. 15 is a graph depicting the number of days a first
observation well is being filled with the CO.sub.2 rich fluid;
and
[0025] FIG. 16A is a graph of the concentration profile as a
function of depth for a first observation well and FIG. 16B is a
graph depicting the bottom-hole composition in a first observation
well, as measured in samples.
DETAILED DESCRIPTION
[0026] The particulars shown herein are by way of example and for
purposes of illustrative discussion of the embodiments of the
subject disclosure only and are presented in the cause of providing
what is believed to be the most useful and readily understood
description of the principles and conceptual aspects of the subject
disclosure. In this regard, no attempt is made to show structural
details in more detail than is necessary for the fundamental
understanding of the subject disclosure, the description taken with
the drawings making apparent to those skilled in the art how the
several forms of the subject disclosure may be embodied in
practice. Furthermore, like reference numbers and designations in
the various drawings indicate like elements.
[0027] Methods of obtaining a composition of a wellbore fluid
without the use of a sampling device are disclosed. Further,
methods for determining the injected fluid composition in an
injection well are disclosed. Finally, methods for obtaining a
passive measurement of a gas composition in an observation well are
disclosed. In a first embodiment the method comprises measuring a
temperature and a pressure of a fluid in the observation well
during or after the displacement of brine. The observation well is
initially filled with brine and is subsequently displaced by the
gas flowing past the perforations. The method further comprises
obtaining a density by differentiating the pressure with respect to
the vertical height, and using an appropriate equation of state,
and the measured properties, to accurately calculate the
composition of a binary mixture. This analysis could be expanded to
multi-component mixtures if additional information is available. In
a second embodiment, a second method for obtaining a passive
measurement of a composition is described. The method includes
measuring a temperature and a pressure of a fluid in a wellbore,
and independently a density and using an equation of state to infer
the composition of the fluid. A non-limiting example of an equation
of state is GERG-2004 GERG-2008 (hereinafter "GERG") (Groupe
Europeen de Recherches Gazieres or European Gas Research Group) but
other equations of state may be used without departing from the
scope of the subject disclosure. See Kunz, O., Klimeck, R., Wagner,
W., Jaeschke, M., "The GERG-2004 Wide-Range Equation of State for
Natural Gases and Other Mixtures," GERG Technical Monograph 15.
Fortschr.-Ber. VDI, VDI-Verlag, Dusseldorf, 2007 and "The
Properties of Gases and Liquids," Robert C. Reid, John M. Prausnitz
and Bruce E. Poling, the contents of which are herein incorporated
by reference. Using an equation of state, the compositional profile
is obtained as a function of well depth. The composition may be
calculated at any depth and at any intervals of depth in the
wellbore. The method may be used to confirm a wellbore fluid
composition in injection wells or as a bottomhole fluid composition
measurement tool in static observation wells.
[0028] Wellbore pressures and temperatures may be measured using
Schlumberger's Platform Basic Measurement Sonde.TM. (PBMS). PBMS is
merely one example and other examples may be used. The fluid
density can be measured using known devices, such as Schlumberger's
gradiomanometer sonde.TM. which measure the hydrostatic pressure of
a column of fluid. A gradiomanometer sonde is merely one example
and other examples may be used such as a vibrating tube, vibrating
wire etc.
[0029] Referring generally to FIG. 1, one embodiment of a well
system is illustrated. In the example illustrated, the injection
well and a first and a second observation well are lined with a
casing. The casing typically is perforated in a manner that places
the perforations in the same reservoir or stratigraphic interval
for all wells. The perforations enable flow of fluids into (or out
of) a wellbore at each well zone. Referring generally to FIG. 1,
one example of an injection well and a first and a second
observation well is illustrated, according to embodiments of the
subject disclosure. The CO.sub.2 flows into the reservoir though
the perforations in the injection well. The injected fluid migrates
in the reservoir towards the first and the second observations
wells. At the first observation well, some of the injected fluid
enters the well through the perforations and bubbles up the brine
column in the tubing thereby displacing the brine from the tubing
because the density of the injected fluid is less than brine
density at the same temperature and pressure. In time, all of the
brine is displaced from the observation wells. The extent of the
brine displacement is representative of the time that the injected
fluid has been in the vicinity of the first or second observation
wells. Once the brine is completely displaced from the well, there
is no phase replacement in the observation well.
[0030] Fluid samples may be collected at the bottom of the
observation wells using a U-tube sampling system or with a
cased-hole formation tester. Initially the first and the second
observation wells are filled with brine. As the CO.sub.2-rich fluid
phase arrives at the first and second observation wells, the
CO.sub.2 will bubble up through the perforations and displace the
brine gradually from these wells. In the examples shown here, the
brine is completely replaced by a CO.sub.2-rich fluid phase in the
first and second observation wells in approximately six days. The
rate of uptake of fluid by the observation well can be controlled
by total inlet area of perforations. Use of valves that may be
remotely opened or closed (from the surface) may provide additional
flexibility in sampling the temporal concentration profile of the
fluid close to the wellbore.
[0031] FIG. 2 depicts brine displacement as a function of time in a
first and a second observation well. FIG. 2 is only for
illustration and is not intended to restrict the scope of the
subject disclosure. The number of observation wells may increase or
decrease depending on the field location. As can be seen in FIG. 2
the brine within the tubing of the observation well is gradually
replaced by the fluid from the reservoir. In one non-limiting
example, the injection well and the first and second observation
wells are collinear. The first observation well is approximately
227 feet from the injection well and the second observation well is
140 feet farther. The distances are only for illustration and are
not intended to restrict the scope of the subject disclosure. The
first and second observation wells are initially filled with brine
but have perforations that allow for fluid communication with the
reservoir. As the CO.sub.2 plume migrates to the first and second
observation wells, bubbles of the CO.sub.2-rich phase rise within
the wellbore and displace brine until nearly the entire wellbore is
filled with the CO.sub.2-rich phase. The wellbore in this instance
is approximately 10,000 feet deep so the process of filling the
entire wellbore with the CO.sub.2-rich phase takes several days.
During this time, the plume continues to migrate past the first and
second observation wells and the fluid composition in the
CO.sub.2-rich plume may change with time due to (i) changes in
injected fluid composition and (ii) mass transfer with the
reservoir brine including desorption of gases from solids. The
compositional variation of the CO.sub.2-rich fluid as a function of
depth in the wellbore reflects this change in the plume
concentration at different points in time as the fluid flows past
the wells. The fluid displacement in the wellbore is stable only
when progressively heavier fluid intrudes into the wellbore. If
not, convective motion is induced, which asymptotically establishes
a thermodynamically consistent profile, in which gravity adjusted
chemical potential is the same throughout the wellbore. For stable
displacement, the effect of evolving composition will be captured
in the compositional profile of the gas in the wellbore.
[0032] FIG. 3 is a graph of pressure versus depth for an injection
well and a first and a second observation well. In the injection
well the bottom-hole pressure is higher than in the first and
second observation wells, which are at reservoir pressure, as fluid
is being injected into the reservoir at a set flow rate. The
vertical pressure gradient in the first and the second observation
wells is however different because the fluid composition in the two
wellbores is different.
[0033] FIG. 4 is a graph of temperature versus depth for an
injection well and a first and a second observation well. As can be
seen in FIG. 4 the temperature in the injector well increases as a
function of depth. This increase is expected due to heat transfer
from the formation and due to increase in pressure, and the
concomitant temperature increase due to near adiabatic compression.
The static temperature profiles in the first and second observation
well are identical and thus are reflective of the local geothermal
gradient.
[0034] FIG. 5 is a graph of density versus depth for the injection
well. The dotted line is the density calculated at wellbore
pressure and temperature conditions, assuming pure CO.sub.2. The
solid lines connecting the data points are the measured density
profile in the wellbore using the PGMS sonde. The discrepancy
between the measured density profile and the calculated density
profile for pure CO.sub.2 is evident.
[0035] FIG. 6 is a graph of density versus depth for the injection
well. Data consistency for the measured densities was confirmed by
cross-checking against the calculated density form the differential
of pressure with depth, shown as the yellow dashed lines connecting
the derived density points. Although there the inferred density
calculated from the differential of pressure with depth is noisy,
the mean density overlays well with the density measured using the
PGMS sonde. The least square error between the measured and
calculated densities was minimized by adjusting methane mole
fraction, a likely contaminant, using the GERG equation of state
for the mixture. The resulting amount of methane, calculated as
above, was calculated to be about 8% (mol) (see FIG. 7).
Subsequently, it was confirmed that the injected gas included a
fraction of recycled CO.sub.2 from an enhanced oil recovery (EOR)
site that contained significant quantities of methane.
[0036] FIGS. 8 and 9 are graphs of density versus depth for the
first and second observation wells, respectively. The solid red
line is the measured density profile in the wellbore. The yellow
lines are the calculated density from the differentiated pressure,
and are therefore noisy. The dotted red line is the density for
pure CO.sub.2 calculated at wellbore pressure and temperature
conditions. The dotted blue curve is the curve best-fitted to the
measured density profile for an optimized CO.sub.2-CH.sub.4 mixture
fraction. The density profiles measured in the first observation
well and the second observation wells indicate non-uniformity in
composition. Moreover, the estimated pure CO.sub.2 density using
the measured pressure-temperature profiles and the GERG equation of
state was not close to the measured density profiles in the first
and second observation wells. Therefore, a least-square analysis
was carried out on both the first and the second observation wells
for the mixture composition based on the measured density profile.
The best fit curve in FIG. 8 indicates that the first observation
well contains greater than 18 mol % CH.sub.4 near the surface
decreasing to significantly less than 18 mol % at the well bottom.
The solid red curve with a lower density than the best fit
indicates that the methane concentration is higher nearer the top
of the wellbore and that the CO.sub.2 concentration is higher
deeper in the wellbore. FIG. 9 points to the second observation
well containing approximately 8 mol % CH.sub.4 in the top
two-thirds of the well with almost pure CO.sub.2 near the bottom.
The remarkable change in density at about 60% of the depth of the
wellbore is difficult to explain based on the temperature or
pressure profile and our analysis indicates that this density jump
is a result of a steep change in the relative concentration of the
CO.sub.2 methane mixture. In this well, apparently some of the
wellbore fluid was vented for an indeterminate period of time
although that time must be less than the time necessary to have
completely purged the well of CO.sub.2-rich gas. The surface
venting caused additional fluid, notably of a different composition
than that which existed in the wellbore prior to venting, to be
drawn into the wellbore. The composition of this fluid, drawn into
the bottom of the wellbore, is different due to the fact that the
CO.sub.2 plume is continuously migrating past the wellbore with the
composition changing in the near wellbore region. Thus, an
additional use for the method proposed in this disclosure is a
diagnostic method for identifying intended and unintended
interventions.
[0037] FIG. 10 is a flow chart of the calculation sequence for one
embodiment of the subject disclosure. To calculate the composition
that best fits the wellbore density profile, a contaminant is
judiciously selected based on whether the measured density profile
is greater or less than the calculated density profile for pure
carbon dioxide. The choice of contaminant is also constrained by
likelihood of occurrence within the wells. Iteration begins with a
starting guess for the contaminant mole fraction. The second step
comprises using the measured wellbore pressure, temperature profile
and the guessed composition to calculate the density using the GERG
equation of state, as a function of depth. The third step comprises
calculating a sum of the least square errors between the calculated
and measured density. The fourth step involves reviewing the sum of
the errors. If the sum of the errors is less than the tolerance,
then the converged density profile is accepted. If the sum of the
errors is not less than tolerance, then the mole fraction of the
contaminate is calculated using an appropriate convergence scheme,
for example, Newton-Raphson algorithm or the Van
Wijngaarden-Dekker-Brent method, which is documented in W. Press et
al., Numerical Recipes: The Art of Scientific Computing, Cambridge
University Press, New York (1992), and is herein incorporated by
reference. The steps are then repeated until the sum of the errors
between the calculated and measured densities is less than a
previously specified tolerance. Note that any other error
specification, for example, sum of absolute differences, may be
used for minimization.
[0038] FIG. 11 is a graph of density versus depth for a first
observation well. This figure shows an additional black curve
fitted to the measured density profile in the wellbore. This curve
was generated by subdividing the wellbore and then repeating the
analysis for each section using a different composition. Each
fitted section represents a different composition, with the higher
methane content present at lower depths (see FIGS. 12A and
12B).
[0039] FIG. 12A is a graph of the concentration profile as a
function of depth for a first observation well, as calculated using
GERG. FIG. 12B is a graph depicting the bottomhole composition in a
first observation well, as measured in samples collected using
U-tube sampling technology. The correlation in CH.sub.4
concentration between the two curves is obvious with the shallow
depths corresponding to earlier times.
[0040] FIG. 13 is a graph of surface pressure at the injection well
and the first and the second observation wells. As expected,
pressure at the injection well is relatively stable. The onset of
bubble entry into a first observation well is measured by an
increase in the surface pressure for both the first and second
observation wells. It appears that it takes approximately six days
for both the first and second observation wells to be filled with
the fluid moving past the perforations. This is shown in greater
detail in FIG. 14.
[0041] It is also interesting to note that the final pressure in
the first observation well is higher than the final pressure
achieved in the second observation well and that they are both
higher than the surface pressure for the injection well. Between
the static first and second observation wells, the comparison is
straightforward. A higher pressure for the first observation well
indicates that the overall average density of the fluid that has
filled the wellbore is of a lower density than the fluid in the
second observation well. An easy way to look at this is--initially,
the wellbore was filled with brine with a density higher than the
fluid that displaced it. At this time, the surface gauge pressure
was zero as the column of dense brine compensated for the
bottomhole pressure. In comparison to the injection well, even
though the bottomhole pressure in the injection well is
significantly higher than the first or second observation well, the
injection well is filled with a denser fluid than either the first
or second observation well fluids. The pressure head of the denser
fluid column offsets the higher bottomhole pressure so that surface
pressure is lower.
[0042] FIG. 14 shows that in both the first and second observation
wells it takes about six days for the brine to get completely
displaced by the CO.sub.2-rich fluid flowing past the perforations,
as shown by the blue and green rectangles that overlay the pressure
profiles. Note that this time to displace the brine can be
controlled by modifying the total perforation area.
[0043] In FIG. 15, where U-tube sampled fluid composition versus
time is shown, the blue shaded rectangle represents the temporal
interval within which the first observation well brine is replaced
by the CO.sub.2-rich fluid flowing past the perforations. This
interval is relevant for comparison with the concentration profile
that we calculate using the equation of state.
[0044] FIG. 16A is a graph of the concentration profile as a
function of depth for a first observation well, as calculated using
GERG. FIG. 16B is a graph of the bottomhole composition in a first
observation well obtained from the U-tube sampling over six days,
the exact time interval over which the wellbore was being filled
with the CO.sub.2-rich fluid. Both curves show that the methane
concentration in the fluid flowing past the perforations declines
with time. Some embodiments may benefit from an equation of state
that is any cubic or virial equation of state that allows mixing
rules.
[0045] There are many applications for the subject disclosure.
Non-limiting examples include determining the injected CO.sub.2
composition in a carbon sequestration project. Methods of the
subject disclosure will determine what compositions are injected at
the wellhead and also will determine the purity of the CO.sub.2
injected. Furthermore, methods of the subject disclosure determine
if chemical or physical processes are occurring within the
reservoir and thus changing the compositions in the observation
wellbores. The compositional profile may be indicative of
interactions with the injected CO.sub.2.
[0046] While the subject disclosure is described through the above
embodiments, it will be understood by those of ordinary skill in
the art that modification to and variation of the illustrated
embodiments may be made without departing from the inventive
concepts herein disclosed. Moreover, while the preferred
embodiments are described in connection with various illustrative
structures, one skilled in the art will recognize that the system
may be embodied using a variety of specific structures.
Accordingly, the subject disclosure should not be viewed as limited
except by the scope and spirit of the appended claims.
* * * * *