PETROLEUM SOCIETY OF CIM
PAPER NO. CIM 93-54
THIS IS A PREPRINT SUBJECT TO CORRECTION
RESERVOIR FLUID SAMPLING AND
RECOMBINATION TECHNIQUES
FOR LABORATORY EXPERIMENTS
BY
Jeff Strong,Hycal Energy ResearchLaboratoriesLtd.
F. Brent Thomas,Hycal EnergyResearchLaboratoriesLtd.
D. Brant Bennion,Hycal EnergyResearchLaboratoriesLtd.
PUBLICATION RIGHTS RESERVED
THIS PAPER IS TO BE PRESENTED AT THE CIM 1993 ANNUAL TECHNICAL CONFERENCE IN
CALGARY, MAY 9-12,1993. DISCUSSION OF THIS PAPER IS INVITED. SUCH DISCUSSION
MAY BE PRESENTED AT THE TECHNICAL MEETING AND WILL BE CONSIDERED FOR
PUBLICATION IN CIM JOURNALS IF FILED IN WRITING WITH THE TECHNICAL PROGRAM
CHAIRMAN PRIOR TO THE CONCLUSION OF THE MEETING.
ABSTRA~
The sampling of oil and gas condensate
reservoirs require that representative fluid samples
be removed by either surface or subsurface
sampling techniques. This paper briefly reviews both
of these techniques and discusses their relative
merits. Several practical examples are provided that
demonstrate the utility of an equation of state model
to verify the quality of separator samples to be useC;
in a recombination. In situations where free gas has
been entrained with the separator samples, the
equation of state model can frequently be used to
synthesize an appropriate gas to be used in a
recombination.
Introduction
Obtaining representative reservoir fluid samples
has become of increasing importance in the
development and exploitation of oil and gas
condensate reservoirs. This is especially true of
reservoirs where extensive computer simulations are
usedto scopeout developmental
strategiesor
where
,
enhanced
oil
recovery
options
are
investigated.
Often times these decisions are based
on properties measured on relatively small fluid
volumes produced from the reservoir at one point in
time. Therefore it is imperative that the fluid samples
used to make these decisions closely match the
characteristic properties of the reservoir fluids at
actual reservoir conditions.
Representative fluid samples can usually be
obtained from producing reservoirs at either surface
or subsurface locations. Surface samples are
removed at either the separator or at the wellhead,
with the associated gas and liquid subsequently
recombined in proportions to represent the actual
reservoir fluid. Subsurface samples are removed from
within the wellbore at actual reservoir conditions
using bottom hole sampling tools and techniques.
The suitability of the particular sampling technique will
depend on a large nun't>er of factors which may
include economic considerations such as the cost of
sampling and associated loss of production, the type
of surface facilities that are available, the fluid
volumes that will be required and the type of reservoir
and fluid to be sampled.
The sampling technique employed can be of
particular importance in saturated oil or gas
condensate reservoirs where the possibility of
entrainment of disassociated phases decreases the
likelihood of obtaining a truly representative fluid. In
some of these situations, various techniques can be
employed to compensate for entrainment of these
dissociated phases. The focus of this paper is
aimed at determining the techniques used to
recombine the separator samples to represent oil
and gas condensate systems along with many
situations where they have been depleted into the
two-phase region. A brief review of those situations
where bottom hole sampling will more likely provide
a representative sample will also be discussed.
Sampling Techniques
A thorough review of the equipment and
techniques used to obtain these different types of
fluid samples is outside the scope of this discussion
and individuals who are interested in more extensive
information on sampling procedures should refer to
the cited literature (1,2.3)
and information available
from equipment vendors and service companies that
specialize in sampling. However, a brief review of
the most common sampling techniques will be useful
to establish the fundamental principles that will
discussed later in this paper.
In general, surface samples obtained at the
separator require collection of high stage separator
gas and liquid which must be subsequently
reconDined in a ratio that corresponds to the
relative amounts of gas and liquid produced as the
reservoir fluid travels up through the wellbore and on
through the surface separation facilities. This type of
sample is the most frequently used for several
reasons:
or asphaltenes) or emulsion formation
Removing fluid samples from the wellhead itself is
possible, although the presence of multi-phase flow
will often result in heterogenous samples that will
require modification of the gas phase in order to
obtain representative reservoir fluid. Wellhead
samples are usually taken only In those instances
where chemicals are being added at the surface
separator and there is no other location available for
removing an uncontaminated fluid sample. In rare
instances, If the reservoir is highly undersaturated
with a bubble point pressure that is actually lower
than the wellhead pressure, wellhead samples may
provide fluids that are nearly equivalent to subsurface
samples. However, in general, wellhead samples will
not directly provide representative reservoir fluids
without altering the gas phase to achieve the correct
reservoir fluid.
Subsurface samples are collected by lowering a
special sampling tool through the wellhead into the
bottom of the well near the perforations where live
reservoir fluid can be captured and brought back to
the surface. Prior to collecting subsurface samples
the well Is typically conditioned by restricting the
flowrate in order to level out pressure imbalances In
the near wellbore region and then shutting In the well
for a period of time (usually 24 to 72 hours) to allow
fluids to collect and equilibrate in the well bore.
The advantagesto subsurfacesampling of fluid
reservoirsare:
- in situations where nothing is known about the
reservoir fluid, subsurface samples may
provide a good indication of overall fluid
properties such as composition, GOR and
saturation pressure. These results can be
useful in assessing the quality of any
subsequent surface samples.
- accessto the surface fluid samples is readily
available
- relatively large fluid volumes can be collected
- the cost of collecting surface sa~les is
-
usually much lower than collecting bottom
hole samples
there is virtually no interruption of production
during the sampling period (although
conditioning of the well prior to sampling may
require some alteration of the oroduction rate).
Surfacesamples will typically yield representative
samples from the well provided that the well is
producing at a stable gas/oil ratio (GOR),
disassociated phases are not entrained in the
produced fluids and there is no solid {such as waxes
2
- the fluid when brought to surface represents
the In situ fluid, and as such, does not needto
be recombinedto a target saturationpressure
or target GOR
fluids that have cloud points greater than
surface temperature, those with a propensity to
precipitate solids (such as asphaltenes) with
reduction in pressure or temperature or those
with tendencies to form emulsions will be more
representative from a subsurface sample than
those fluids collected at the surface separator
-
entrainmentof disassociated
phasescan be
less severe depending on the effectiveness of
the well conditioning.
While many believe subsurface samples provide
the best opportunity of achieving a representative
reservoir fluid, these samples can be subject to
relatively low capture rates and have a limited
collection volume. Moreover, considerable disparities
have been observed on some oils where multiple
bottom hole samples have been taken.
Consideration of which method to use for
sampling will depend on the aforementioned
variablesand particularlyon the type of well to be
sampled. For the sake of clarity, the issue of
sampling oil wells and condensate wells will bs
treated separately although many of the sams
principleswill apply to both.
Sampling of 011Wells
For undersaturated reservoirs, the recombination
of surface separator samples will usually result in a
representative reservoir fluid provided that the well
is producing at a stabilized gas-oil ratio (GOR). For
undersaturated reservoirs where the producing GOR
is not stable then the possibility exists that the
bottom hole flowing pressure (BHFP) may actuaJly
be lower than the saturation pressure of the fluid. In
this situation, solution gas may be liberated in the
near wellbore area which then must first achieve a
critical gas saturation before it will flow Into the
wellbore and on to the separator. However, once a
steady state equilibrium is established in the near
wellbore region then the producing GOR will usually
stabilize and the surface separator should yield
fluids suitable for recombination.
Sampling saturated oil reservoirs provide a
special challenge since the production of any gas
cap or previously liberated solution gas will usually
result in a non-representative recombination.
Reducing the flow rate of a well and observing if
there is a corresponding drop in the measured
separator GOR may reveal if gas coning or gas
liberation effects are being observed in the well.
Figure 1 shows the standard relationship between
GOR and flow rate which one might expect for such
a well.
For the best opportunity to obtain
representative samples, the surface separator
should be operated at a condition below the
threshold flowrate that will induce entrainment of
disassociated gas phase. If operated above, then
the likelihood of having excess gas (over and above
the solution GOR) along with a leaner gas phase is
much increased.
3
The recombination of surface separator samples
is achieved by either recombining the gas and fluid to
match the measured separator GOR or to match a
specified saturation pressure at the reservoir
temperature. Ideally, matching the recombination to
one of these characteristics will result in a fluid that
corresponds well in the other, although this is not
always the case. Whether the saturation pressure or
the gas-oil ratio is selected as the fluid characteristic
to be matched will usually be determined by whether
the separator is producing at a stable GOR and
whether an accurate estimate of the saturation
pressure is actually known. In cases where the
reservoir fluid is known to be highly undersaturated,
the target saturation pressure may be significantly
lower than the actual reservoir pressure and therefore
the separator GOR may be a better reservoir fluid
characteristic to attempt to match. For saturated oil
reservoirs where an existing gas cap is known to be
in contact with the oil, the saturation pressure of the
oil will generally be equal to the current reservoir
pressure and therefore, the saturation pressure may
be the better fluid characteristic to match.
Sampling of Gas Condensate Wells
Similarly, gas condensate systems may also
exhibit extreme sensitivity with respect to pressure
and temperature conditions and it is difficult to get
representative samples from the surface separator
unless one has access to a large separator, where
large fluid volumes have been averaged, and where
stable flow rates are observed. In the case of
subsurface samples, these are also sometimes
subject to temperature and pressure sensitivities and
their results need to be quantified and scrutinized
closely. Consequently, for gas condensate systems
there is no guarantee that a bottom hole sample will
be superior to surface samples and therefore all
results need to be closely examined. Indeed, for gas
condensate systems the most important factor may
be when the sample was taken once production had
been initiated. Simulation studies conducted by
McCain and Alexander3) on gas condensate wells
have suggested that gas samples should be obtained
early during the first 30 days of production in order to
obtain a representative reservoir sample. After that
point the gradual buildup of a condensate ring around
the wellbore will prevent the collection of
representative samples regardless of the amount of
well conditioning that is performed.
Equation of State Modelling
Equation of State modelling can be particularly
usefulto evaluatethe qualityof the surfacesamples
and provide a method of recombiningphases in
orderto predictoverallphasebehaviourat reservoir
conditions. In instances where the entrainmentof
disassociatedphasesis suspected,the Equationof
State can be a valuable tool to determine if the
separator gas collected is representativeof the
evolved reservoir solution gas. This can be
illustratedwith the followingexample.
EOS we can detennine whether the separator
samples can be recombined to represent the present
in situ reservoir liquid. The results of this comparison
are provided in Table 2.
Table
.-
2 . Comperi80n
Component
Example 1. A saturated oil reservoir had an original
pressure of 15,168 kPag (2200 psi) at 65°C (14eoF).
Since that time the reservoir has been depleted to a
current reservoir pressure of 11,032 kPag (1600
psig). In order to perform laboratory tests on the
field It was desired to recombine separator oil and
gas samples to represent the present in situ liquid
phase. An original compositional analysis was
available from a bottom hole sample taken in 1960
and co~ositional analyses of the current separator
gas and liquid were also available.These are
summarized in Table 1. Figure 2 shows a general
schematic of a depleted reservoir as used in this
exa~le.
N.
co.
HaS
c,
c.
c.
I-c.
n.c.
.,c.
n.c.
~
of ~.tor
-
EOS
G.s
0.0$1
0.0271
0.1231
0.6808
0.0840
0.0277
0.0025
O.~
0.0013
0.0011
0.0013
~
Measured
Gas
0.0056
0 .0264
0.1295
0.6790
0.0812
0.0351
0 .0034
0.0084
0.0016
0.0013
0.0008
This comparison shows that the methane content
of the EOS-generated separator gas was slightly
higher than that of the sampled gas. This suggested
that there was no gas cap gas entrained in the
separator gas since the EOS predicted a gas cap gas
containing approximately 76% methane which would
have contributed to a higher methane content in the
separator gas.
A subsequent recombination of the separator gas
and liquid samples according to the measured
separator GOR provided a recombined oil sample
with a saturation pressure that was within 100 kPa of
the present reservoir pressure. The compositional
analysis of the final recombined oil is provided in
Table 3 which shows relatively good agreement with
the composition predicted by the EOS. Therefore, by
using the EOS, the quality of the recombination has
been evaluated and the confidence level is improved.
In order to determine whether the separator gas
and liquid could be used to recombine a
representative sample of the in situ liquid an
equation of state was used simulate the reservoir
fluid. Based on the original compositional analysis of
the bottom hole sample an EOS model was tuned to
fit the original bubblepoint pressure of 15 168 kPag
at 65°C. Once the EOS had been tuned to match
the original reservoir conditions, the oil was then
partially depleted to current reservoir conditions and
then flashed to the present separator conditions.
Figure 3 provides a schematic description of this
EOS procedure. By co~ring
the composition of
the actual separator gas to that generated by the
4
As previously mentioned, the presence of a gas
cap in a saturated oil reservoir can frequently result
in the entrainment of the disassociated gas phase
into the separator fluids thereby making a direct
recombination of fluids invalid. However, based upon
preliminary EOS analysis a suitable separator gas
can be synthesized in the laboratory in order tc
obtain a representative recombined oil sample.
appropriateGOR. In order to reduce the saturation
pressure to the target reservoir pressure, the GOR
had to be decreased by almost 20% thereby altering
the transport properties and composition of the oil.
However, when a second recombination was
performed using a blended synthetic separator gas
based on the composition predicted by the EOS, the
GOR obtained was 82.5 m3/m3 with a saturation
pressure within 100 kPa of the current reservoir
pressure. A comparison of the recombined oils is
providedin Table 5.
Example 2. This second example shows a situation
where the separator oil and gas as sampled cannot
be used in a direct recombination due to the
entrainment of gas cap gas. As in the first example,
an initial reservoir fluid composition was available
from very early in the productive life of the reservoir
which was used to input into the EOS model. The
model was tuned to give an oil with a bubblepoint
pressure of about 15 860 kPa (2300 psig) at 75°C
(16~F). The schematic of Figure 4 shows the EOS
process used for this situation. However, unlike the
first example a comparison of the sampled separator
gas and the EOS-generated separator gas showed
considerable differences. Table 4 shows the
comparison of these two gas compositions.
Table 4
. Comparisonof SeparatorGases
Component
EOS
N.
co.
0.0059
0.0512
H.s
0.0064
Ct
0.6387
0.1362
0.0907
0.0554
0.0155
Example 3. The next example considers a situation
where separator oil is not available and the
recombination must be performed with dead stock
tank oil. This can occur when an emulsion has
formed in the separator and the oil must first be
degassed and then centrifuged in order to remove
the water. However in this example the oil actually
came from an overseas well which was accidentally
degassed during transport. A compositional analysis
of the reservoir fluid was available along with the
saturation pressure and single stage flash GOR
which were used to tune the equation of state model.
Tuning of the EOS was performed by adjusting the
temperature and pressure of the EOS flash until the
composition of the liquid from the EOS closely
matched the actual analysis of the present separator
liquid. Once the model had been tuned, the
necessary gas was synthesized in the laboratory and
then recombined with the remaining dead oil. Table
6 provides the properties of the resulting recombined
oil sample compared with the original properties of
the bottom hole sample.
I
c.
c.
c.
~
0.7309
O.~
0.0641
0.0392
0.0080
c.
There is a significantamountof excessmethanein
the sampled gas which is most likely the result of
gas cap gas entrainment into the separator. Using
the actual separator fluids in a recombination
resulted in a fluid with a saturation pressure much
higher than the maximum reservoir pressure for the
5
from a free liquid leg. The producing GOR was in
the range of 1500 m3/m3and the liquid had a gravity
of 43 API.
An equation of state model was
developed to detennine if the liquid could have
possibly resulted from a gas-condensate system.
This was perfonned by using the equation of state to
model the gas and liquid phases produced through
the separator and then recombining these two phases
with the EOS in varying amounts to detennine the
GOR that would be required to achieve a single
phase at reservoir conditions. The results indicated
that a GOR in excess of 100000 m3/m3 would be
required at 63°C in order to achieve a saturation
pressure of 15 MPa. Since this GOR is far in excess
of what was observed in the field, this would appear
to suggest that the production from this well was a
combination of gas and entrained free liquid rather
than resulting solely from a gas condensate system.
The sampling of gas condensate wells has
already been discussed in terms of the relative
merits of subsurface versus surface sampling. One
particular problem that is sometimes encountered is
determining whether a sample collected at surface
represents a gas condensate, a free liquid leg in the
reservoir or a combination of both. The distinction
between oils and condensates is usually evident
from a compositional standpoint and as a general
rule it has been suggested by Moses(4)that reservoir
fluids which are less than 12.5 mole% heptanes plus
are usually in the gas phase in the reservoir. This
can also be confirmed with an equation of state
model performed on separator samples taken early
in the life of the reservoir. The key question to
answer is if the separator gas at the reservoir
temperature and pressure can vaporize the liquid
corresponding to the measured separator GOR. If
not, then the GOR needs to be increased until the
liquid is vaporized. If the saturationpressure of that
fluid Is within the realistic limits of the reservoir then
the produced liquid may be derived from the vapour
phase in situ.
However, if the corresponding
saturation pressure is much higher than the
maximum pressure of the reservoir then there is
good evidence that a free liquid leg exists in situ.
This technique should be only employed early in the
life of a suspected condensate well since the loss of
liquids in the near wellbore region will distort the
phase behaviour of the recombined fluids and give
erroneous results.
Example 4. An example of this previous situation is
where a gas well at 15 MPa and 63°C was
producing significant quantities of liquid at the
surface separator although it was not known whether
the liquidswerethe resultof a gas condensate
or
6
When separator samples are recombined to
represent very lean gas condensate systems with
GOR's in excess of 5000 m3/m3, the resulting
mixtures are very difficult to use in the laboratory tc
measure volumetric properties due to the small
volume of liquid. Constant volume depletion (CVD)
tests require that exact dewpoint pressures and
phase volumes be determined experimentally using
relatively small volumes of overall sample. The
resulting experimental error associated with these
measurements can result in inaccurate estimates of
the two phase formation volume factors.
An
alternative methodology that can be e~loyed when
dealing with reconmined gas condensate systems is
to recombine the samples to a GOR that is low
enough to be able to accurately measure the phase
behaviour of the mixture. Once this has been
accomplished then an EOS model can be tuned with
the experimental data and then subsequently used to
predict phase behaviour at the actual field GOR.
Recommendations
The collection of representative samples from a
reservoir can be accomplished through the use of
surface separator samples or subsurface samples but
results should be scrutinized carefully to ensure that
the final reservoir fluid Is consistent with the
properties of the reservoir. Equation of state models
can be employed to great advantage to assist in the
evaluation and synthesis of separator samples to be
used in recombinations. As with all computer
simulations, the quality of the input data should be
evaluated before it is used to model prospective
recombination fluids.
Conclusions
References
1. The selection of an appropriate sampling
technique will generally be made based on
factorssuch as overallsamplecosts,the surface
facilitiesthat are available, the fluid volumesthat
are required and the type of reservoir to be
sampled. Regardlessof the methodemployedto
collect the sample, the resulting reservoirfluid
should be scrutinizedcarefully to ensure that It
accuratelyrepresentsthe in situ fluid before It is
used in any laboratorystudy.
1. Reudelhuber,F.O.,Sampling Proceduresfor Oil
Reservoirs; Journal of Petroleum Technoloav.
Dec. 1957.00. 15-18.
2. An equationof state model can be used to
evaluatethe qualityof surfacesamplesespecially
those where the entrainment of disassociated
phases is suspected.
3. In situationswhere separator gas phases have
been contaminated or are not available, an
equation of state model can be used to
synthesizethe appropriateseparatorgas to be
used in the reco~ination. The accuracyof the
recombinationwill depend on the quality of the
originalfluid compositionused in the model.
4. For suspectedgas condensatesystems,an EOS
modelcan be used to determineif the produced
liquid is a condensate resulting from the
productionof gas or a free liquid resultingfrom
entrainmentwith the produced gas. The EOS
model should only be based on samples
producedearly in the life of the well since later
samplesmay be nonrepresentative.
Acknowledgments
The authors would like to acknowledge the
supportof Hycal EnergyResearchLaboratoriesLtd.
in providingresearchfacilitiesand sampledata used
to preparethis presentation.
7
2. API RP 44. API Recommended Practice for
SamDlina Petroleum Reservoir Fluids; 1st addition,
Jan. 1966
3. McCain, W.D. and Alexander, A.A., SalT1>lingGas
Condensate Wells; SocietY of Petroleum
Enaineers Reservoir Enaineerina. Aua. 1992 . DD.
358-362.,
4. Moses, P.L., EngineeringApplicationsof Phase
Behaviourof CrudeOil and CondensateSystems;
Journal of PetroleumTechnoloay.July 1986. DD.
715-723.
GAS ENTRAINMENT
FIGURE 1
AS A FUNCTION OF FLOWRATE
/
,/
0
~
~
~
Well Flowrate
FIGURE 2
GENERAL SCHEMATIC OF DEPLETED RESERVOIR
Separator Gas
Separator Oil
Gas Cap
Saturated
Oil System
Depleted Oil
FIGURE 3
EXAMPLE 1 - EOS SCHEMATIC
FIGURE 4
EXAMPLE 2 - EOS SCHEMATIC