U.S. patent application number 11/388274 was filed with the patent office on 2006-10-12 for methods and apparatus for the downhole characterization of formation fluids.
This patent application is currently assigned to Schlumberger Technology Corporation. Invention is credited to Soraya S. Betancourt, Hani Elshahawi, Go Fujisawa, Anthony Goodwin, Li Jiang, Oliver C. Mullins, Julian Pop, Terizhandur S. Ramakrishnan.
Application Number | 20060226699 11/388274 |
Document ID | / |
Family ID | 30000300 |
Filed Date | 2006-10-12 |
United States Patent
Application |
20060226699 |
Kind Code |
A1 |
Betancourt; Soraya S. ; et
al. |
October 12, 2006 |
Methods and apparatus for the downhole characterization of
formation fluids
Abstract
Methods and apparatus for investigating a hydrocarbon bearing
geological formation traversed by a borehole are disclosed. A
borehole tool is used to acquire a sample of fluid in the
formation. Compositional analysis of the fluid sample is conducted
to provide a determination of the composition of the sample. The
sample composition is then related to a model of the thermodynamic
behavior of the fluid; i.e., the mass fractions of the fluid
components are used as inputs to an equation of state (EOS) to
predict the phase behavior of the fluid.
Inventors: |
Betancourt; Soraya S.;
(Ridgefield, CT) ; Goodwin; Anthony; (Sugar Land,
TX) ; Fujisawa; Go; (Sagamihara-shi, JP) ;
Mullins; Oliver C.; (Ridgefield, CT) ; Elshahawi;
Hani; (Houston, TX) ; Pop; Julian; (Houston,
TX) ; Ramakrishnan; Terizhandur S.; (Bethel, CT)
; Jiang; Li; (Ridgefield, CT) |
Correspondence
Address: |
GORDON & JACOBSON, P.C.
60 LONG RIDGE ROAD
SUITE 407
STAMFORD
CT
06902
US
|
Assignee: |
Schlumberger Technology
Corporation
|
Family ID: |
30000300 |
Appl. No.: |
11/388274 |
Filed: |
March 24, 2006 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
10309849 |
Dec 3, 2002 |
7081615 |
|
|
11388274 |
Mar 24, 2006 |
|
|
|
Current U.S.
Class: |
303/113.2 ;
250/255 |
Current CPC
Class: |
E21B 47/10 20130101;
G01N 7/00 20130101; G01N 9/36 20130101; G01N 33/2823 20130101; G01N
25/04 20130101; G01N 1/12 20130101 |
Class at
Publication: |
303/113.2 ;
250/255 |
International
Class: |
B60T 8/34 20060101
B60T008/34; G01V 5/00 20060101 G01V005/00 |
Claims
1-29. (canceled)
30. A method of investigating a hydrocarbon bearing geological
formation traversed by a borehole, comprising: a) acquiring a
sample of fluid in the formation with a formation fluid sampling
tool located in the borehole; b) conducting a compositional
analysis of the fluid sample located in the sampling tool while
said sampling tool is in the borehole, wherein said compositional
analysis includes an identification of methane, and an
identification of at least one additional hydrocarbon or group of
hydrocarbons; c) relating the compositional analysis to a model of
the thermodynamic behavior of the fluid.
31. A method according to claim 30, further comprising: d) based on
said relating, predicting a phase behavior of fluid remaining in
the formation.
32. A method according to claim 30, further comprising: d) based on
said relating, generating a pressure-temperature plot of at least
one of said sample and fluid remaining in the formation.
33. A method according to claim 32, wherein: said
pressure-temperature plot includes an indication of a critical
point.
34. A method according to claim 32, wherein: said
pressure-temperature plot includes an indication of at least one of
a bubble line and a dew line.
35. A method according to claim 32, wherein: said
pressure-temperature plot includes an indication of a critical
point, an indication of a bubble line, and indication of a dew
line, and an indication of an ambient condition of the
formation.
36. A method according to claim 31, further comprising: e)
determining whether said fluid in the formation is either
condensate or volatile oil.
37. A method according to claim 36, further comprising: if said
fluid in the formation is determined to be condensate, finding an
indication of a dew pressure for said fluid at an ambient
temperature in said formation; comparing said dew pressure to an
ambient reservoir pressure; and using results of said comparing,
indicating a desired maximum drawdown pressure for said acquiring a
sample.
38. A method according to claim 37, further comprising: adjusting a
drawdown pressure for said acquiring step based on said desired
maximum drawdown pressure.
39. A method according to claim 36, further comprising: if said
fluid in the formation is determined to be a volatile oil, finding
an indication of a saturation pressure for said fluid at an ambient
temperature in said formation; comparing said saturation pressure
to an ambient reservoir pressure; and using results of said
comparing, indicating a desired maximum drawdown pressure for said
acquiring a sample.
40. A method according to claim 36, further comprising: if said
fluid is determined to be a volatile oil, acquiring multiple
samples at different drawdown pressures in order to find a bubble
point for the fluid in the formation.
41. A method according to claim 30, wherein: said conducting a
compositional analysis comprises measuring an optical absorption
spectrum of said fluid and conducting a pseudo-compositional
analysis by translating said absorption spectrum into
concentrations or mass fractions of said methane and at least one
said compositional group of hydrocarbons.
42. A method according to claim 41, wherein: said at least one said
group of hydrocarbons includes a first group containing ethane,
propane, butane, and pentane fractions, and a second group
containing hexane and heavier components (C.sub.6H.sub.14+).
43. A method according to claim 31, further comprising: repeating
steps a) and b) for multiple fluid samples, wherein step d)
comprises predicting phase behavior with a level of certainty.
44. A method according to claim 31, further comprising: repeating
steps a) through d) at multiple locations in the borehole.
45. An apparatus for investigating a hydrocarbon bearing geological
formation traversed by a borehole, comprising: a) a borehole tool
including means for acquiring a sample of fluid in the formation
and means for conducting a compositional analysis of the sample of
fluid, wherein said compositional analysis includes an
identification of methane, and an identification of at least one
additional hydrocarbon or group of hydrocarbons; and b) means for
relating the compositional analysis to a model of the thermodynamic
behavior of the fluid.
46. An apparatus according to claim 45, wherein: said means for
conducting a compositional analysis includes optical means for
analyzing the sample.
47. An apparatus according to claim 45, wherein: said means for
relating includes means for predicting a phase behavior of fluid
remaining in the formation.
48. An apparatus according to claim 47, further comprising: c)
means for generating a pressure-temperature plot of at least one of
the sample and fluid remaining in the formation.
49. An apparatus according to claim 48, wherein: said
pressure-temperature plot includes an indication of a critical
point.
50. An apparatus according to claim 47, wherein: said
pressure-temperature plot includes an indication of at least one of
a bubble line and a dew line.
51. An apparatus according to claim 48, wherein: said
pressure-temperature plot includes an indication of a critical
point, an indication of a bubble line, and indication of a dew
line, and an indication of an ambient condition of the
formation.
52. An apparatus according to claim 45, wherein: said means for
acquiring a sample of fluid includes means for adjusting a drawdown
pressure of said apparatus and means for monitoring acquired
samples in order to find a bubble point for the fluid in the
formation.
53. An apparatus according to claim 45, wherein: said means for
conducting a compositional analysis comprises means for measuring
an optical absorption spectrum of said fluid and for conducting a
pseudo-compositional analysis by translating said absorption
spectrum into concentrations or mass fractions of said methane and
at least one said group of hydrocarbons.
54. An apparatus according to claim 53, wherein: said at least one
said group of hydrocarbons includes a first group containing
ethane, propane, butane, and pentane fractions, and a second group
containing hexane and heavier components (C.sub.6H.sub.14+).
Description
[0001] This application is related to co-owned U.S. Pat. No.
5,859,430 to O. Mullins et al., entitled "Method and Apparatus for
the Downhole Compositional Analysis of Formation Gases", which is
hereby incorporated by reference herein in its entirety.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to methods and apparatus for
making in situ determinations regarding hydrocarbon bearing
geological formations. The present invention more particularly
relates to methods and apparatus for conducting phase calculations
on samples of downhole fluids. The phase calculations may then be
used in order to determine the proximity of the parameters of the
formation to one or more of a vapor pressure line, a bubble point
curve, a dew point curve, and a critical point for the fluid. The
invention has application to downhole testing procedures and to
production parameters and procedures, although it is not limited
thereto.
[0004] 2. State of the Art
[0005] Characterizing commercially viable accumulations of
hydrocarbons is the main objective of well logging. Downhole
sampling and testing tools such as the Modular Dynamic Formation
Tester (MDT) (MDT being a trademark of Schlumberger Ltd.) are used
during the logging phase to gain a more direct assessment of the
production characteristics of the accumulation. The
[0006] There have been described and illustrated herein embodiments
of methods and apparatus for characterizing formation fluids. While
particular embodiments of the invention have been described, it is
not intended that the invention be limited thereto, as it is
intended that the invention be as broad in scope as the art will
allow and that the specification be read likewise. Thus, while the
invention was described with reference to generating P-T diagrams,
it will be appreciated that the actual diagrams need not get
generated, and that useful determinations can be made by finding
specific points of interest such as the critical point and/or the
bubble point or dew point for a particular in situ temperature.
Further, while certain particular tools and modules such as the MDT
and CGA were described as preferred, it will be appreciated that
other tools capable of making determinations of fluid constituents
may be utilized. Also, while the preferred embodiment of the
invention utilizes optical analysis, those skilled in the art will
appreciate that other compositional analysis mechanism, e.g., mass
spectroscopy, gas chromatography, etc., may be employed. It will
therefore be appreciated by those skilled in the art that yet other
modifications could be made to the provided invention without
deviating from its spirit and scope as claimed. objective of the
MDT tool is to provide a controlled channel of hydraulic
communication between the reservoir fluid and the wellbore. The
tool allows withdrawal of small amounts of formation fluid through
a probe that contacts the reservoir rock (formation). In addition
to obtaining a more direct measurement of the flow characteristics
of the reservoir and the formation pressure, high quality samples
of fluid can be obtained for analysis. Historically, the fluid
samples were brought to the surface for analysis in the laboratory,
but recent developments in the MDT tool have made possible the
direct measurement of fluid properties downhole during the pump-out
or sampling sequence. Details of the MDT tool and the Optical Fluid
Analyzer (OFA) module of the MDT tool may be obtained with
reference to commonly owned U.S. Pat. No. 3,859,851 to Urbanosky,
U.S. Pat. No. 4,994,671 to Safinya et al., U.S. Pat. No. 5,167,149
to Mullins et al., U.S. Pat. No. 5,201,220 to Mullins et al., U.S.
Pat. No. 5,266,800 to Mullins et al., and U.S. Pat. No. 5,331,156
to Hines et al., all of which are hereby incorporated by reference
in their entireties herein.
[0007] The main advantage of downhole analysis is that the fluid is
relatively pristine. If the sampling pressure is above the
saturation pressure, the fluid will be in a single phase ensuring
that the original composition is being analyzed. For pressures
below the saturation pressure a measurement of the properties of
the liquid phase in the oil zone and the associated gas above it
will yield a more accurate sampling than a sample recombined in
surface. Indeed, it may be difficult to retain the sample in the
state in which it existed downhole when it is retrieved to
surface.
[0008] Petroleum oil and gas are essentially a mixture of several
hydrocarbon components whose variation dictates the characteristics
of the fluid. Different types of reservoir fluids include black
oils, volatile oils, retrograde condensates, wet gases, and dry
gases, and the fluid types require different considerations for
their exploitation, and different properties are used for their
description. For example, it is generally agreed that black oils
and dry gases can be described satisfactorily using averaged
properties of the oil and gas phases, such as the volumetric
factors and gas solubility ratios. Volatile oils, retrograde
condensates and wet gases require a more detailed knowledge of the
fluid composition since the ultimate recovery will be dictated by
the control of the production conditions (mostly pressure).
[0009] A downhole fluid analysis provides information in real time
in contrast to a laboratory analysis that may last for several
days, or surface wellsite analysis, which may result in undesirable
phase transitions as well as the loss of key constituents. One
component that can be analyzed downhole is hydrogen sulfide
(H.sub.2S). Although this component does not significantly affect
the phase behavior of the reservoir fluids it is significant for
metallurgy of the production string.
[0010] A detailed description of the fluid properties is desirable
for an accurate modeling of the fluids in the reservoir. Indeed,
decisions such as the type of well completion, production
procedures and the design of the surface handling and processing
facilities are affected by the characteristics of the produced
fluids. For example, if fluid in the reservoir is a retrograde
condensate, the saturation (dew) pressure, combined with the
formation pressure and permeability will dictate the maximum
pressure drawdown for production of the fluids, or whether an
injection scheme for pressure maintenance or liquid vaporization
should be implemented.
SUMMARY OF THE INVENTION
[0011] It is therefore an object of the invention to provide
apparatus and methods for modeling in situ certain properties of
fluids in a reservoir.
[0012] It is another object of the invention to provide apparatus
and methods for analyzing reservoir fluids in relation to the
thermodynamic behavior of the fluids in the formation.
[0013] It is a further object of the invention to provide downhole
apparatus and methods for using a compositional analysis of fluid
obtained from a formation and the thermodynamic behavior of the
fluid in the formation in order to make determinations regarding
fluid sampling, well completion, or production procedures.
[0014] In accord with the objects of the invention, in situ
determinations regarding hydrocarbon bearing geological formations
are made via the use of a sampling tool such as the Schlumberger
Modular Dynamic Formation Tester (MDT). Downhole data acquired with
the sampling tool are used to conduct a compositional analysis of
the reservoir fluid and the compositional analysis of the reservoir
fluid is related to a model of the thermodynamic behavior of the
fluid; i.e., the mass fractions of the fluid components are used as
inputs to an equation of state (EOS) to predict the phase behavior
of the fluid. With the reservoir fluid characterized with respect
to its thermodynamic behavior, fluid production parameters,
transport properties, and commercially useful indicators of the
reservoir are computed. For example, the thermodynamic model can
provide the phase envelope that can be used to interactively vary
the rate at which samples are collected in order to avoid entering
the two-phase region. Other properties that may also be useful in
assessing the methods required to produce the particular reserve
can be estimated from the chosen equation of state. As examples,
the density, viscosity, and volume of gas formed from a liquid
after expansion to a specified temperature and pressure may be
obtained directly from the EOS or from correlations between EOS
calculated properties and composition.
[0015] According to another aspect of the invention, the
characterization of the fluid sample with respect to its
thermodynamic model can be used as a benchmark to determine the
validity of the obtained sample, whether to retain the sample,
and/or whether to obtain another sample at the location of
interest. More particularly, based on the thermodynamic model and
information regarding formation pressures, sampling pressures, and
formation temperatures, if it determined that the fluid sample was
obtained near or below the bubble line of the sample, a decision
may be made to jettison the sample and/or to obtain sample at a
slower rate (i.e., a smaller pressure drop) so that gas will not
evolve out of the sample. Alternatively, because knowledge of the
exact dew point of a retrograde gas condensate in a formation is
desirable, a decision may be made, when conditions allow to vary
the pressure drawdown in an attempt to observe the liquid
condensation and thus establish the actual saturation pressure.
[0016] In order to generate a relatively accurate thermodynamic
model of the reservoir fluid it is desirable to obtain an accurate
determination of the reservoir fluid composition. Thus, in accord
with a presently preferred embodiment of the invention, the
reservoir fluid composition is estimated by the Condensate and Gas
Analyzer (CGA) module of the MDT tool. The CGA module measures
absorption spectra and translates them into concentrations of
several molecular groups in the fluids of interest. In particular,
determinations of the concentrations of methane (CH.sub.4), a group
containing ethane, propane, butane, and pentane fractions
(C.sub.2H.sub.6, C.sub.3Hs, i-C.sub.4H.sub.10, n-C.sub.4H.sub.10,
i-C.sub.5H.sub.12, n-C.sub.5H.sub.12), a lump of hexane and heavier
components (C.sub.6H.sub.14+), and carbon dioxide (CO.sub.2), can
be calculated. However, the present invention is generalized to any
given partitioning of the fluid composition. Thus, if desired, each
component of the fluid may be considered separately in order to
provide more accuracy in the modeling.
[0017] Additional objects and advantages of the invention will
become apparent to those skilled in the art upon reference to the
detailed description taken in conjunction with the provided
figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] FIG. 1 is a pressure-temperature diagram for a pure
component.
[0019] FIG. 2 is a pressure-temperature diagram for a hydrocarbon
mixture which shows a bubble line, dew line and critical point for
the mixture.
[0020] FIG. 3 is a pressure-temperature diagram for a
pseudo-composition of hydrocarbons.
[0021] FIG. 4 is a diagram of an apparatus of the invention.
[0022] FIG. 5 is a pressure-temperature diagram for a
pseudo-composition of hydrocarbons as determined by the CGA module
of an MDT tool.
[0023] FIG. 6 is a pressure-temperature diagram for the actual
composition of hydrocarbons utilized in generating FIG. 5.
[0024] FIGS. 7a-7f are pressure-temperature diagrams for the actual
composition of hydrocarbons utilized in generating FIG. 5 but with
varying mole fractions of mud filtrate contaminating the
sample.
[0025] FIG. 8 is a flow chart illustrating the use of phase
calculations in determining whether or not to continue
sampling.
[0026] FIG. 9 is a flow chart illustrating the use of phase
calculations made over time in a decision regarding whether or not
to continue sampling.
[0027] FIG. 10 is a flow chart illustrating the use of phase
calculations in helping define drawdown pressures for retrograde
condensates.
[0028] FIG. 11 is a flow chart illustrating the use of phase
calculations in helping define drawdown pressures for volatile
oils.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0029] Matter can exist in three basic phases, namely: gas, liquid
and solid. The phase behavior of a substance refers to all possible
states or phases in which this substance is present under certain
conditions of pressure and temperature. A "substance" is formed by
one or more identifiable "components" or "chemical entities". The
term "system" will also be used in this context as a synonym of
"substance".
[0030] Gibbs phase rule states that the degrees of freedom of a
system (NF), is equal to the number of components (N.sub.C) minus
the number of phases (N.sub.P) plus 2, assuming that there are no
chemical reactions among components. The number 2 refers to the
intensive properties: pressure and temperature. The degrees of
freedom of a system establish the number of independent intensive
properties that must be specified to obtain the thermodynamic state
of all the properties of the system.
[0031] FIG. 1 depicts a pressure-temperature (P-T) diagram for a
pure component (N.sub.C=1). When two phases coexist NF equals 1 and
the two phases are present along any of the lines depicted in FIG.
1. For three phases N.sub.F=0, and the three phases can only exist
under a certain pressure and temperature specified by the Triple
point. A critical point exists at the end of the gas/liquid phase
boundary line and this vapor pressure curve has high relevance for
the petroleum industry. At the critical point the gas and liquid
properties are identical and beyond it the phase transitions occur
without discontinuous changes in the fluid properties. In the
region with pressure and temperature higher than the critical
point, the fluid is called supercritical.
[0032] Petroleum fluids (oil and gas) are mixtures of multiple
hydrocarbon components (N.sub.C>2) with a complicated phase
behavior. When two phases are present, N.sub.F>2, and the
pressure and temperature conditions under which the two phases
exist is represented by an area enclosed by an envelope in a P-T
diagram. FIG. 2 shows the P-T phase diagram for a hydrocarbon fluid
with composition listed in Table 1. TABLE-US-00001 TABLE 1
Component Mole Fraction C1 0.7102 C2 0.1574 C3 0.0751 i-C4 0.0089
n-C4 0.0194 i-C5 0.0034 n-C5 0.0027 C6 0.0027 C7 + (.gamma. = 0.7,
M = 103) 0.0003 CO2 0.0167 N2 0.0032
[0033] In FIG. 1, the bubble and dew curves of the pure component
coincide. In the case of a mixture, such as the one presented in
FIG. 2, the two curves enclose the two-phase region and meet at the
critical point. The lines within the envelope correspond to
different mole fractions of vapor (V), and subsequently the bubble
line corresponds to V=0 and the dew curve has V=1. It is important
to note that the fluid composition is constant in FIG. 2.
[0034] As is seen in FIG. 2, the left-most line represents the
bubble curve of the mixture. For pressure and temperature
conditions above the bubble curve, the fluid is in the liquid
phase. If pressure is decreased at a constant temperature below the
critical temperature (Tc) (i.e., the temperature at the critical
point which marks the delineation between the bubble line and the
dew line), the "first" gas bubble will form at the bubble point
pressure. In FIG. 2, the right-most line is called the dew curve.
Pressure and temperature conditions beyond the dew curve correspond
to a single gaseous phase.
[0035] The phase envelope is characterized by three properties: the
cricondenbar, the cricondentherm and the critical point. The
cricondenbar is the point of highest pressure at which the two
phases exist (in FIG. 2 this is approximately 98 bar); the
cricondentherm is the point of highest temperature at which the two
phases are present (in FIG. 2 this is approximately 298.degree. K);
and the critical point is the point where the dew line and the
bubble line meet and the fluid phases coalesce. In the vicinity of
the critical point the classical equations of state (EOS) cannot
provide accurate (within a few degrees K of critical temperature)
predictions of the thermodynamic properties of a fluid without
recourse to a cross-over model. The critical point of this mixture
is shown in FIG. 2 at 96 bar and 260.degree. K.
[0036] Equations of state describe mathematically the phase
behavior of a fluid by relating three intensive properties of
matter: pressure, temperature, and molar volume. In its most basic
form the EOS is the ideal gas equation: P = RT V M ( 1 ) ##EQU1##
Most EOS used in the oil industry are derivatives of van der Waals
equation. These cubic equations were developed to deal with phase
equilibria of complex multicomponent mixtures. Their general form
is:
P=RT/[V.sub.M-b.sub.1(T)]-a(T)/[(V.sub.M+b.sub.2(T))(V.sub.M+b.sub.3(T))]
(2) where V.sub.M is the molar volume, T is the temperature, and R
is the gas constant. The first term in the right side of Equation 2
represents the correction to the molar volume due to the volume
occupied by the molecules. The second term represents the
contribution to the pressure due to the attraction of the molecules
as a function of temperature.
[0037] The major failing of the cubic equations of state is that
the equations provide only rough predictions of liquid density
(i.e., the predictions may be in error by at least 10%). However, a
simple empirical correction, known as the volume translation, has
been devised that improves this without affecting the phase
equilibria predictions. This correction is usually determined by
adjusting a coefficient to measured densities. There are other,
more complex, equations of state such as the well-known
Benedict-Webb-Rubin equations. These equations can require
significant processing power depending on the complexity of the
fluid and flow-sheet problem. Thus in most oilfield applications
the cubic EOS are used. For purposes of the present invention,
either the cubic EOS or the more complex EOS may be utilized.
[0038] Methods of determining the dew and bubble curves with
equations of state are well documented; See, e.g., Michelsen, M.
L., "Calculation of Phase Envelopes and Critical Points for
Multicomponent Mixtures", Fluid Phase Equilibria, 4, 1980 (pp.
1-10) which is hereby incorporated by reference herein in its
entirety. Use of the cubic equation of state to determine the dew
and bubble curves requires knowledge of the critical temperature,
critical pressure, and acentric factor (.omega.) for each of the
components, along with the binary interaction parameters (b.sub.ij)
(which may be set to zero if unknown and may result in a reduction
in accuracy of the prediction). The algorithm required to determine
the bubble point (which is essentially identical with that required
for the dew point) with an equation of state for both phases has
been documented in the literature; See, e.g., Michelsen, M. L. id.
Essentially, this requires that the composition of the liquid and
either the pressure or temperature be fixed and then for an assumed
temperature and gas mole fraction the fugacity is calculated with
the EOS model. These values are then used to calculate the
equilibrium ratio. The process is iterated until the sum of the
gaseous mole fractions is equal to unity.
[0039] For the case when some fluid components are grouped, schemes
can be used to split a grouped composition into individual
components at a mole fraction. These procedures, which have been
documented in the literature, may increase the accuracy of the
predictions from a particular equation of state.
[0040] Certain parameters of the selected EOS also may be tuned to
additional physical measurements or prior knowledge to obtain a
more representative model. If for example, a measurement of the
bubble point pressure of a sample is available, the information is
incorporated to fit the selected equation of state at this point.
Model parameters that can be tuned are the critical pressure,
critical temperature, and acentric factor (.omega.) of each
component, the binary interaction coefficients (b.sub.ij), or the
molar composition of the mixture. For cubic EOS, which poorly
represents the density of liquids, a measurement of density is
desirable to determine the volume correction factor, and thus
permit prediction densities with an uncertainty of better than
10%.
[0041] Uncertainty in phase calculations is associated with the
error involved by the use of an EOS to model the fluid behavior,
the uncertainty in the composition of the fluid measured with the
downhole tool, and the use of pseudo-components to represent groups
of hydrocarbon fractions. Therefore, according to the preferred
embodiment of the invention, the calculations are made in a
probabilistic framework and an estimate of the uncertainty in the
calculated phase behavior is preferably reported with the result.
As a result, process decisions may be made in real-time by
computerized systems or operators.
[0042] In the special case that the composition and other physical
property measurements obtained with the MDT tool correspond to
conditions near to critical, the uncertainty in the fluid
properties calculated with a cubic equation of state are
necessarily higher. However, the information that the fluid is near
critical is already of great value. In particular, determining
which side of the critical point (that is whether the fluid is a
near critical liquid or near critical gas) is extremely useful data
for exploration and production decisions. For example, a near
critical gas may show retrograde behavior in the production
tubulars while a near critical liquid will have a bubble
pressure.
[0043] In order to demonstrate the performance of the proposed
analysis scheme, the composition listed in Table 1 for which the
phase boundary is shown in FIG. 2 was taken as a starting point.
The components of Table 1 were then grouped according to the groups
that are available from the MDT CGA analysis. Thus two groups were
formed to represent the fractions C2 to C5 and C6+; i.e., the mole
fractions of the components C2 through C5 were combined, and the
mole fractions of C6 and larger carbon chains were combined. The
phase equilibrium calculations were repeated with this CGA
pseudo-composition and the P-T section that resulted is shown in
FIG. 3.
[0044] For the new pseudo-composition it is seen in FIG. 3 that the
cricondenbar is at approximately 87 bar, the cricondentherm is at
approximately 282.degree. K and the critical point is at
approximately 86 bar and approximately 258.degree. K. These
calculated values are, in general, a little lower than those shown
in FIG. 2 for the extended composition listed in table 1. When
comparing the values obtained with the pseudo-component analysis
with the values determined for the extended composition, the
pseudo-component cricondenbar is about 12% lower, the
cricondentherm about 5% lower and the critical pressure about 11%
lower, while the critical temperature is essentially invariant
(i.e., within about 1%). Although this comparison has been
performed for only one, albeit typical, fluid the results indicate
that the maximum pressure and temperature of the phase diagram
estimated with the pseudo-composition can be useful in defining
(along with an estimated error) the maximum pressure and
temperature drops that the fluid can withstand and still be single
phase. Perhaps more notable is the very small variation in
predicted critical temperature. This implies that the CGA
pseudo-component analysis can be used to distinguish the fluid type
of either liquid or gas solely on the basis of a comparison of the
calculated critical temperature and the actual reservoir
temperature.
[0045] Once the model of the fluid is defined, the following
properties can be computed: surface tension between phases,
viscosity of each phase, Condensate-Gas ratio (CGR) or Gas-Oil
ratio (GOR), density of each phase, volumetric factors and
compressibility, heat capacity, and saturation pressure (bubble or
dew point). Thus, the EOS can be solved to obtain the saturation
pressure at a given temperature. The density, gas-liquid ratios,
and volumetric factors are byproducts of the EOS. Other properties
such as heat capacity or viscosity are derived from the other
properties in conjunction with information regarding the fluid
composition.
[0046] When any of these properties is measured directly or
indirectly by the MDT tool or any other logging technique, or is
available from prior knowledge, it validates the EOS models as well
as fits the EOS adjustable parameters. The latter is at the user's
discretion but may be useful in estimating the uncertainty arising
from the method used to calculate the phase envelope.
[0047] Furthermore, the properties measured and computed with this
invention can be used in conjunction with other reservoir
evaluation techniques for a compositional numerical simulation of
the flow and production behavior of the reservoir.
[0048] Turning now to FIG. 4, the preferred apparatus of the
invention is seen. A borehole tool 10 is suspended in the borehole
12 from the lower end of a typical multiconductor cable 15 that is
spooled in a usual fashion on a suitable winch (not shown) on the
formation surface. The cable 15 is electrically coupled to an
electrical control system 18 on the formation surface. The tool 10
includes an elongated body 19 which encloses the downhole portion
of the tool control system 16. The elongated body 19 also carries a
selectively extendable fluid admitting assembly 20 and a
selectively extendable tool anchoring member 21 which are
respectively arranged on opposite sides of the tool body. The fluid
admitting assembly 20 is equipped for selectively sealing off or
isolating selected portions of the wall of the borehole 12 such
that pressure or fluid communication with the adjacent earth
formation 14 is established. Also included with tool 10 are means
for determining the downhole pressure and temperature (not shown)
and a fluid analysis (optical) module 25 through which the obtained
fluid flows. The fluid may thereafter be expelled through a port
(not shown) or it may be sent to one or more fluid collecting
chambers 22 and 23 which may receive and retain the fluids obtained
from the formation. Control of the fluid admitting assembly, the
fluid analysis section, and the flow path to the collecting
chambers is maintained by the electrical control systems 16 and 18.
As will be appreciated by those skilled in the art, the electrical
control systems may include one or more (micro)processors,
associated memory, and other hardware and/or software to implement
the invention.
[0049] Using the apparatus of FIG. 4, a sample of formation fluid
was obtained at a measured reservoir pressure (and temperature),
and the information was processed with the CGA module/algorithm.
The CGA module measures absorption spectra and translates them into
concentrations of several molecular groups in the fluids of
interest. In its present state the CGA module of the MDT tool
provides measurements of the concentrations of methane (CH.sub.4),
a group containing ethane, propane, butane, and pentane fractions
(C.sub.2H.sub.6, C.sub.3H.sub.8, i-C.sub.4H.sub.10,
n-C.sub.4H.sub.10, i-C.sub.5H.sub.12, n-C.sub.5H.sub.12), a lump of
hexane and heavier components (C.sub.6H.sub.14+), and carbon
dioxide (CO.sub.2), from which molar or weight fractions can be
calculated. The (pseudo-) composition determined from the CGA is
set forth in Table 2. TABLE-US-00002 TABLE 2 Mass Fraction (%) CO2
3.5 C1 41.1 C2-5 22.0 C6 33.4
From this composition the phase diagram of FIG. 5 was obtained. The
reservoir pressure and the actual saturation pressure measured in
the laboratory are also plotted in FIG. 5. It can be observed from
FIG. 5 that the type of fluid in the reservoir (which was measured
to be at approximately 550 bar and 156.degree. C.) is a retrograde
condensate since that pressure/temperature combination is to the
right side of the critical point and above the dew curve. As will
be discussed hereinafter, this information is valuable since it
dictates the considerations to be taken while sampling.
[0050] With the fluid characterized as above, the saturation
pressure value calculated with the cubic EOS at 156.degree. C. is
372 bar. Using a confidence interval of .+-.10% represented by the
dark circles, the person in charge of the sampling would be advised
not to lower the pressure below 410 bar.
[0051] For the particular fluid sampled by the apparatus of the
invention, a laboratory compositional analysis was available and is
shown in Table 3: TABLE-US-00003 TABLE 3 Component Mole Fraction
(%) N2 0.51 CO2 4.25 C1 72.94 C2 8.28 C3 4.21 iC4 0.70 nC4 1.43 iC5
0.51 nC5 0.61 C6 0.74 C7 1.11 C8 1.14 C9 0.69 C10 2.88
With the components of Table 3 as detailed, a phase diagram was
generated and is shown in FIG. 6. As may seen from FIG. 6, at
156.degree. C., the actual saturation pressure of the obtained
fluid is 389.5 bar. This point is shown on the plot of FIG. 5 and
falls within the confidence interval shown.
[0052] According to one aspect of the present invention, the
generation of phase plots can be used to help determine the effect
of borehole mud contamination on the obtained fluid sample. In
particular, a tool such as shown in FIG. 4 is introduced into the
borehole and stationed at a desired borehole depth which is
typically selected based on an evaluation of the reservoir with
open-hole logs in zones where it is expected to find a single-phase
fluid (oil or gas). The tool probe enables hydraulic communication
with the reservoir, and fluids are pumped out through the tool and
analyzed in the optical module of the borehole tool. The first
composition measurements are obtained, and usually correspond to a
highly contaminated fluid from the near wellbore region where
drilling fluid (e.g., an oil-based mud) filtrated into the
reservoir and mixed with the native fluids (including, e.g.,
hydrocarbons). Quantitative estimates of contamination (i.e., the
fraction of contamination) can be determined using algorithms which
utilize near infrared optical analysis of samples obtained by the
MDT such as disclosed in U.S. Pat. No. 6,350,986 to Mullins et al.,
and U.S. Pat. No. 6,274,865 to Schroer et al., both of which are
hereby incorporated by reference herein in their entireties. The
contamination estimate is equivalent to the mass fraction of
contaminant in the oil-based-mud-filtrate/formation-fluid
mixture.
[0053] The initial composition measurement of the contaminated
sample is used to generate a phase diagram based on calculations
performed with an equation of state. Knowing the fraction of
contaminant in the mixture, the measured contaminated composition
is inverted to obtain an estimate of the uncontaminated fluid. For
example, if the compositional measurement determines the fraction
of liquid in the sample along with some compositional analysis of
gaseous components, then all of the contamination is assigned to
the liquid composition, and the fraction of contamination may be
subtracted from the liquid to give an estimate of the composition
of the virgin fluid. The virgin fluid composition estimation can
then be used to predict the phase diagram of the pure phase.
[0054] As fluids are pumped through the optical module of the MDT,
the composition of the fluids is constantly being determined.
Typically, as sampling progresses, progressively cleaner (less
contaminated) samples are obtained. The phase diagrams can be
generated continuously and the compositions inverted to estimate
the uncontaminated sample based on the fraction of contaminant.
These estimates should be in agreement with the initial estimate of
the virgin fluid composition. By continuously finding estimated
uncontaminated compositions and comparing to previous
determinations, the contamination measurement can be validated.
[0055] The impact of contamination on various measurements and
determinations made therefrom may be seen with reference to FIGS.
7a-7f. FIGS. 7a-7f show P-T diagrams for the sample set forth above
in Table 3 but contaminated with different amounts of a mud
filtrate composed of 50% nC16 and 50% nC18 (molar fractions). FIGS.
7a to 7e show the diagrams obtained for this mixture at different
proportions (molar fractions) of the contaminant. For a 20% mole
fraction of filtrate (FIG. 7a), the fluid at the (ambient)
reservoir conditions of approximately 550 bar and approximately
156.degree. C. is in the liquid phase, as the critical point for
the contaminated mixture is at approximately 172 bar and
approximately 390.degree. C. As the contamination decreases from
FIG. 7a to FIG. 7b (10% mole fraction of filtrate), FIG. 7c (5%
mole fraction of filtrate), FIG. 7d (4% mole fraction of filtrate),
and FIG. 7e (2.5% mole fraction of filtrate), the critical point
moves towards a lower temperature (e.g., from approximately
390.degree. C. to approximately 157.degree. C.). With 2.5% mole
fraction of filtrate, the critical point essentially coincides with
the reservoir temperature. At this contamination level it could be
erroneously concluded that the fluid in the reservoir is
supercritical. At a 1% mole fraction of filtrate (FIG. 7f), the
fluid is all in the gas phase at reservoir conditions (i.e., at 550
bar and 156.degree. C.) and the dew pressure at the reservoir
temperature is again 389 bar. Thus, it will be appreciated that if
correction is not made for contamination, an incorrect
determination can be made as to the state of the fluid in the
formation.
[0056] Those skilled in the art will appreciate that when a large
percentage of a formation fluid is constituted from longer carbon
chains (e.g., C6+), the mud filtrate composed of 50% nC16 and 50%
nC18 will have a smaller effect on the thermodynamic model of the
fluid; and when a large percentage of the formation fluid is
constituted from methane or short carbon chains, the typical
oil-based mud filtrate will have a larger effect on the fluid
model.
[0057] The provision of a downhole tool which can produce phase
diagrams of in-situ fluids and which can account for mud filtrate
contamination has numerous applications. For example, the
characterization of the fluid sample with respect to its
thermodynamic model can be used as a benchmark to determine the
validity of the obtained sample, whether to retain the sample,
and/or whether to obtain another sample at the location of
interest. More particularly, and turning to FIG. 8, after a fluid
sample is obtained by the borehole tool, a measurement of the
composition or pseudo-composition of the (contaminated) sample is
made at 102 and a measurement of the level of contamination is made
at 104. With both measurements, and given knowledge of the
constituents of the contaminants, determination of the constituents
of the virgin (uncontaminated) fluid is found at 106. Utilizing
equations of state, phase calculations of both the uncontaminated
and the contaminated fluids may be made and compared at 108. The
phase calculations may then be compared at 110 at the formation
temperature and pressure, in order to determine whether the
contamination significantly affects the PVT properties of the
fluid. In other words, if the pressure and temperature of the
formation are located on same portions of the P-T diagrams for the
contaminated fluid and uncontaminated fluid indicating that the
fluid is in the same phase in both cases, the contamination may not
be considered "significant", and the sampling at that depth in the
borehole may be completed at 112 with the storage (if desired) of
the obtained sample. On the other hand, if the contamination
significantly affects the PVT properties of the fluid, at 114, a
determination is made as to whether the sampling time at the depth
location in the formation has reached a maximum time. If so, at
116, the tool is preferably moved to a new location for sampling;
while, if not, at 118, additional fluid samples may be obtained in
the hope that fluid contamination will decrease to a level where it
is not significant.
[0058] Continuous or multiple sampling, and the processing of data
from the continuous or multiple sampling which results in multiple
contamination measurements, multiple uncontaminated composition
determinations, and multiple sets of phase calculations can be used
in several manners. First, as multiple determinations are made of
the contamination measurements and the uncontaminated composition,
the certainty level with respect to these values increases. The
certainty level can be provided along with the actual determination
as a "product". Second, as will be discussed hereinafter with
respect to FIGS. 10 and 11, in certain circumstances the initial
phase calculations can be used to adjust the drawdown pressure in
order to obtain a single phase fluid. Third, multiple
determinations can be used to predict a contamination clean-up rate
which in turn can be utilized in determining whether or not to
continue sampling at the sampling location.
[0059] Turning to FIG. 9, with a first phase calculation having
been previously conducted at 122 on a first fluid sample, a second
phase calculation is conducted at 124 on a second fluid sample. If
desired, third and subsequent phase calculations (not shown) can be
conducted on additional fluid samples. Based on the respective
phase calculations, a determination is made as to the rate of
contamination clean-up. If the rate of contamination clean-up
suggests at 126 that an acceptable contamination level will be
reached within a suitable timeframe, sampling continues at 128. If
not, sampling is terminated at 130. It should be noted that the
"acceptable contamination level" correlates to whether the level of
contamination will significantly affect the PVT properties of the
fluid as discussed above with reference to FIG. 8.
[0060] As previously suggested, the phase calculations of the
invention can also be used to adjust drawdown (sampling) pressures.
As seen in FIG. 10, based on the phase calculations at 132, and
also with knowledge of the temperature and pressure of the
formation, a determination can be made as to whether the in situ
fluid is black oil 133, volatile oil 134, condensate 135, wet gas
136 or dry gas 137. In the case of condensate, if at 138 the fluid
being sampled from the formation is a gas (i.e., the condensate is
exhibiting "retrograde behavior"), as taught in co-owned
concurrently filed U.S. application Ser. No. 10/309,850 now issued
as U.S. Pat. No. 7,002,142 entitled "Detecting Downhole Dew
Precipitation in Oilfield Retrograde Condensate", which is hereby
incorporated by reference herein in its entirety, the gas may be
monitored for its fluorescence at 140, and its dew pressure
observed at 142. Also, at 144, from the phase calculations, the dew
pressure Pdew (i.e., the point on the dew curve corresponding to
the in situ temperature) can be calculated. If at 146 the in situ
pressure of the reservoir Preservoir is greater than the dew
pressure, a maximum drawdown pressure drop (i.e., Preservoir-Pdew)
is defined at 148 in order to maintain single phase flow into the
borehole tool. This maximum drawdown pressure drop may be used in
the sampling procedure to adjust the drawdown pressure utilized in
obtaining samples. However, if the calculation of Preservoir from
the phase calculations is not greater than Pdew, than retrograde
behavior should not be observed. Thus, the Pdew calculated at 146
does not equate to the Pdew observed from the monitoring of
fluorescence, and the fluid model should be accordingly adjusted at
150 by e.g., choosing different equations of state, adjusting
parameters in the EOS, or adjusting the determination of the
compositional components.
[0061] If the phase calculations at 132 suggest that the in situ
fluid is volatile oil 134, as seen in FIG. 11, a different set of
calculations may be conducted. With volatile oil, at 152 the
saturation pressure Psat and optionally the critical pressure are
calculated. If at 153 the reservoir pressure Preservoir is greater
than Psat, a maximum drawdown pressure drop (i.e., Preservoir-Psat)
is defined at 154 in order to maintain single phase flow (i.e.,
liquid) into the borehole tool. This maximum drawdown pressure drop
may be used in the sampling procedure to adjust the drawdown
pressure utilized in obtaining samples. In addition, if the
drawdown pressure is to be adjusted, other adjustments (such as the
contamination cleanup rate--FIG. 9) may be made to the system.
However, if Preservoir is not greater than Psat, then the obtained
sample should be a two phase sample 155. If desired, this
determination can be compared to a determination of phase of the
actual sample, and the fluid model accordingly adjusted if the
prediction differs from the actual situation. It should be noted
that the maximum drawdown pressure drop may also be used in making
decisions regarding production of hydrocarbons from the
formation.
[0062] According to another aspect of the invention, if it
determined that the fluid sample was obtained near the bubble line
of the sample, a decision may be made to find to conduct drawdown
at different pressure drops in order to find an exact (actual)
bubble point. The bubble point may then be used in making decisions
regarding production of hydrocarbons from the formation.
[0063] It will be appreciated by those skilled in the art that one
possible "output" of the apparatus of the invention is one or more
P-T diagrams for each obtained sample with or without indications
of certainty. In lieu of P-T diagrams, it is possible to provide
for each depth of interest a numerical indication of the bubble or
dew point at the temperature of the formation at that depth.
Likewise, it is possible to simply provide an indication of a
pressure under which two phase production would occur. Other
possible outputs include, inter alia, density, gas-liquid ratio,
and viscosity determinations, as well as evaluations of
contamination effects on sample quality and fluid behavior.
[0064] The versatility of fluid composition measurements at
different borehole depths opens the possibility of gaining a better
understanding of the reservoir structure. Knowing the estimated
compositional gradient, it is possible to compare the estimated
composition at a different depth with the actual measurement at
that depth to analyze variations. Abrupt changes in the composition
that may or may not be accompanied by changes in the pressure
gradient are an indication of vertical discontinuity in the
reservoir structure.
[0065] Composition measurements along with real time phase
calculation at different depths enables the computation and
verification of important fluid properties such as saturation
pressure, gas-liquid ratios, and liquid drop-out volumes on high
quality single-phase samples obtained at downhole conditions
without the risk of phase recombination on the formation surface.
The variations of these properties with depth can be used as the
basis for the construction of a fluid model for the whole
reservoir.
[0066] A specific situation where fluid composition and phase
behavior calculations are of great utility is the analysis of
reservoirs containing gas and liquid zones where it is of primary
interest to identify if the gas is associated to the liquid. In
this case the bubble point of the liquid hydrocarbon obtained from
phase calculations and the compositional gradient give an
indication of the communication between the two zones.
Specifically, if the oil zone is not near its saturation pressure,
then it is most likely not in communication with nearby gas zones.
Conversely, if an oil is at its saturation pressure and a gas
containing formation is nearby, it is likely that the two zones are
in communication.
[0067] Another application is the case of thick reservoirs where
compositional variations occur due to gravity and temperature
gradients. Prediction of gas-oil fluid contacts in these cases is
possible from the composition gradient. In reservoirs that span a
large range of depths the composition variations can be tested
following the previous procedure in selected wells.
[0068] There have been described and illustrated herein embodiments
of methods and apparatus for characterizing formation fluids. While
particular embodiments of the invention have been described, it is
not intended that the invention be limited thereto, as it is
intended that the invention be as broad in scope as the art will
allow and that the specification be read likewise. Thus, while the
invention was described with reference to generating P-T diagrams,
it will be appreciated that the actual diagrams need not get
generated, and that useful determinations can be made by finding
specific points of interest such as the critical point and/or the
bubble point or dew point for a particular in situ temperature.
Further, while certain particular tools and modules such as the MDT
and CGA were described as preferred, it will be appreciated that
other tools capable of making determinations of fluid constituents
may be utilized. Also, while the preferred embodiment of the
invention utilizes optical analysis, those skilled in the art will
appreciate that other compositional analysis mechanism, e.g., mass
spectroscopy, gas chromatography, etc., may be employed. It will
therefore be appreciated by those skilled in the art that yet other
modifications could be made to the provided invention without
deviating from its spirit and scope as claimed.
* * * * *