Advanced Fluid
Characterization
Hydrocarbon
identification and
analysis using NMR
Applications
■
Determination of fluid storage
volume based on lithologyindependent total porosity
■
Quantification of pay based on
oil, gas and water saturation
■
Oil mobility determination
based on in-situ oil viscosity
■
Producibility calculation
using hydrocarbon-corrected
bound-water volume and
permeability
■
Oil viscosity versus depth
mapping for perforation and
completion design
■
Direct hydrocarbon detection
●
Fresh, unknown or varying
formation water resistivities
●
Low-resistivity, low-contrast
pay and thin beds
■
Residual oil saturation in
water-based muds
■
Residual water saturation
in oil-based muds
■
Mobility calibration for
MDT* Modular Formation
Dynamics Tester
What is the MRF method?
When is an MRF analysis needed?
The MRF* Magnetic Resonance Fluid
characterization method is a patented
technique for direct identification and
analysis of hydrocarbons. The station
log measurement can be made using
any CMR tool; special tools or modifications are not necessary. A modified
CMR-Plus* tool is required for the fast
3-min data acquisition.
The MRF technique integrates downhole data acquisition and wellsite inversion with a multifluid response model
to determine fluid saturations, fluid
volumes and oil viscosities. Lithologyindependent formation porosity and
separate T2 distributions for brine and
oil are also extracted. Hydrocarboncorrected bound-water volume and
permeability are computed from the
T2 distributions. This real-time analysis
improves prediction of the well’s producing capability and is vital for completion decisions.
Viscosity, like permeability, greatly
influences a well’s producing capability. Viscosity can vary by orders of magnitude, and in many parts of the world
it determines zonal production rates
to a much greater extent than formation permeability. When hydrocarbon
viscosity is varying or unknown, the
MRF method can provide the answers
you need.
MRF technology can also provide
solutions in fresh or varying formation
waters, where Archie resistivity analysis is difficult. Using direct hydrocarbon characterization, pay intervals can
be identified even in zones with low
resistivity. The MRF method can overcome problems associated with Archie
analysis, such as varying cementation
exponent; dipping, thin or laminated
beds that affect resistivity tools and
unknown or varying water resistivity.
This method also overcomes incorrect
permeability calculations caused by
hydrocarbon effects.
Figure 1. Example of real-time MRF analysis performed at the wellsite. The direct, user-friendly analysis provides
a comprehensive formation evaluation of the near-wellbore region and includes quality control indicators.
Benefits
■
Improved reserves estimates
and increased reserves from
location of bypassed pay
■
Optimized well completions
■
Worldwide availability
using any standard CMR*
Combinable Magnetic
Resonance tool
■
Real-time answers from
automated wellsite inversion
■
Independent analysis without need for resistivity measurements, Rw or Archie
parameters
Features
■
■
■
Automated 3-min acquisition
integrated with wellsite
inversion
Constituent Viscosity Model
(CVM) based on fundamental
physics
Measurement without
radioactive source
Water porosity (%): 17.0
Water saturation (%): 54.3
Water T2LM (ms): 48.8
Free water φ (%): 14.9
Temperature (°C): 24.6
Oil porosity (%): 14.3
Oil saturation (%): 45.7
Oil T2LM (ms): 180
Bound water φ (%): 2.1
Gas porosity (%): 0.0
Gas saturation (%): 0.0
Oil viscosity (cp): 6.6
T1/T2 ratio: 1.243
OBMF porosity (%): 0.0
OBMF saturation (%): 0.0
TCMR porosity (%): 31.3
Permeability (mD): 1652.4
0.09
Water T2 log mean
0.08
Oil T2 log mean
0.07
0.06
Signal
amplitude
Water T2 distribution
0.05
0.04
Oil T2 distribution
0.03
0.02
0.01
0
0.1
1.0
10
100
T2 relaxation time (ms)
1,000
10,000
How does the MRF analysis work?
Small or light-end hydrocarbon molecules move at rapid rotational and
translational velocities as a result of
thermally induced Brownian motion.
Figure 2 shows this concept at the
microscopic level. At the macroscopic
level, the long distances small molecules can travel in a given time are
observed as a high molecular diffusion
coefficient. Fast molecular motions
result in low fluid viscosity. As a result
of the low viscosity, small molecules
have long T2 decay times.
Large molecules have small rotational and translational velocities and
therefore move shorter distances
through the fluid. This slow molecular
motion results in a low diffusion coefficient for the fluid and a high viscosity
value. As a result of the high viscosity,
large molecules have short T2 times.
A pure fluid composed of a single
molecular species has a single diffusion
coefficient value, a single viscosity
value and a single value for its T2
decay. The fluid can be represented
as a narrow peak in the T2 and
diffusion spectra.
A mixture containing both smalland large-molecule fluids exhibits
one T2 value for the small molecules
and another for the large molecules.
However, individual T2 values in the
mixture differ from those of the constituent pure fluids. The same result
occurs with the diffusion rates. Components in the mixture retain their
separate identities while their individual properties are modified. Crude oils
are a complex mixture of many different hydrocarbon species with a broad
range of molecular sizes. The CVM
relates the T2 and diffusion properties
of mixtures to molecular composition.
Based on fundamental physics, the
CVM properly accounts for the broad
diffusivity and T2 spectra of bulk crude
oils. The CVM has been empirically
validated for both live and dead
crude oils.
Constituent viscosity is a phenomenological link between the T2 relaxation and the diffusion coefficient
of each molecular species in a hydrocarbon mixture. The bulk viscosity
observed with a viscometer reflects
the broad distribution of microscopic
or constituent viscosities.
Figure 2. Small or light-end member molecules move quickly; heavier long-chain molecules move
more slowly. Hydrocarbon molecule relaxation rates and diffusion coefficients are related to the
molecule size. With their wide range of molecular sizes, crude oils have a broad distribution of
nuclear magnetic resonance (NMR) relaxation times and molecular diffusion coefficients. The
Constituent Viscosity Model (CVM) relates molecular diffusivity and T2 relaxation of the individual
components to bulk viscosity.
Small hydrocarbon
molecule fast rotation
leads to fast diffusion
Large hydrocarbon
molecule slow rotation
leads to slow diffusion
Mixture of C6
and C30
Pure C30
Pure C6
Amplitude
10 –6
10–5
Diffusivity (cm /s)
2
10 –4
The CVM predicts an inverse relationship between the geometric mean
of the bulk oil T2 distribution and the
bulk oil viscosity. This relationship
has long been observed in laboratory
data (Fig. 3).
Pore size information is available
from T2 distributions measured in water
zones. Brine T2 distributions are broad
as a result of the range of pore sizes
found in reservoir rocks. In an oil
zone, the brine distribution typically
overlaps with the broad T2 distribution
of the oil to form the total T2 distribution seen on a standard log (right side
of Fig. 4). This overlap often makes
standard T2 interpretation difficult
because the contributions of water
and hydrocarbon are indistinguishable.
Pore size information is mixed with
hydrocarbon viscosity information.
Largely because of this overlap of oil
and water T2 distributions, previous
hydrocarbon detection techniques
have not been reliable.
Figure 3. For bulk crude oils, an inverse relationship exists between the
geometric mean of the T2 distribution and the viscosity.
10
Light oil
API: 45–60
Density ~ 0.65–0.75 g/cc
1
Medium oil
API: 25–40
Density ~ 0.75–0.85 g/cc
0.1
Heavy oil
API: 10–20
Density ~ 0.85–0.95 g/cc
T2 (s)
0.01
0.001
0.0001
0.1
1.0
10
100
1,000
10,000
100,000
Viscosity (cp)
Figure 4. In a formation with no hydrocarbons, brine-filled porosity produces T2 distributions representative of pore-size distributions
with associated bound and free fluids (left). The broad T2 distribution of a typical bulk crude is shown in the center. Because the rock
is not present, the bulk crude oil T2 distribution is a function of molecular composition only. In a typical T2 log, the addition of the two
distributions results in a mixed response that can be difficult to interpret (right).
Brine T2 Distributions
Oil T2 Distributions
Constituent viscosity
Pore size
+
Clay-bound water
Capillary-bound water
Free water
Total Distribution
=
Tar
Heavy oil
Intermediate oil
Light oil
Tar plus clay-bound water
Heavy oil plus capillary bound water
Intermediate oil plus free water
Light oil plus free water
The MRF method incorporates the
fundamental physical principles of the
CVM and a multifluid inversion algorithm to reliably extract oil and water
signals from NMR data. To achieve this
separation, the MRF method exploits
molecular diffusion in the field gradient generated by the tool magnet. This
process leads to an additional NMR
decay proportional to the square of
the echo spacing and to the diffusion
constant of each fluid component governed by the simple equation shown
in Fig. 5.
Because water molecules are typically smaller and more mobile than
the hydrocarbon molecules in crude
oils, the water signal decays faster
than the oil signal for long-echo spacings. By inverting a specially designed
suite of NMR measurements with different echo spacings, the MRF method
separates brine and oil signals even
when the T2 distributions completely
overlap. After separation, the individual T2 distributions are used to compute the volumes of water, gas and
oil. Oil viscosity and hydrocarboncorrected bound-fluid volume are
calculated. In addition to providing
direct and resistivity-independent
saturations and volumes, the T2 distribution of reservoir oil derived during
the MRF inversion helps in interpreting the CMR depth log.
Figure 5. Schematic of the MRF data suite and simultaneous inversion to extract brine and oil volumes,
oil viscosity, and T2 distributions. The equation describes the decay time of measured NMR signals
( T2D ) caused by molecular diffusion ( D) in the tool gradient ( G). The diffusion decay increases with
increasing echo spacing ( TE).
Molecular Diffusion in Field Gradient
Echo spacing = TE1
TE2
TE3
1
T2D
D (γ G ) TE 2
2
=
12
Brine and Oil T2 Distributions
45 cp
X655 m
Amplitude
0.3
X700 m
44 cp
X708 m
86 cp
10
100
1000
T2 (ms)
Water
Oil
In what range of viscosities will the
MRF method work?
The MRF method works in viscosities
from less than 1 cp to more than 200 cp
(Fig. 6). For viscosities below this
range, the DMR* Density-Magnetic
Resonance method should be used
because hydrocarbons that are very
light (such as gas and condensate)
result in porosity deficits. Above 200 cp
there is a lack of diffusion sensitivity.
The shape of the T2 distribution must
be analyzed using the CMR-Plus
enhanced precision mode (EPM).
Where is the MRF method available?
For the highest viscosities, hydrocarbons become invisible to NMR tools,
which measure fluid only. The DMR
method can be used to quantify tar
content.
Advanced fluid characterization using
the MRF method is available worldwide. Any CMR tool can be used for
data acquisition; specially equipped
tools or modifications are not necessary. To achieve the fast 3-min station
log measurement and perform the realtime wellsite inversion, a modified
CMR-Plus tool and special software
kit are required.
Has the method been tested?
Schlumberger has validated the MRF
method in the laboratory using a broad
range of live and dead crude oils and
rock types. Its reliability and range of
applications have been confirmed by
extensive worldwide field tests in
diverse environments.
Figure 6. The MRF method works within the range of approximately 1 to 200 cp. Outside this range, the indicated method should be used.
Low-MRF Sensitivity
Low-MRF
Sensitivity
MRF-Sensitive Regime
0.5 cp
2 cp
10 cp
100 cp
1000 cp
0.1
1
10
100
1,000
10,000
Transverse relaxation time T2 (ms)
DMR
100,000
EPM
10,000
DMR
MRF
1,000
100
Viscosity (cp)
10
1
0.1
CMR-Plus Tool Specifications
Physical specifications
Length
Weight
Measure point
Min hole size
Max hole size
Max tension limit
Max compression limit
Operational ratings
Max pressure
Max temperature
Mud type and salinity
Measurement specifications
Max logging speed
Long T1 environment
Short T1 environment
Bound fluid mode
Vertical resolution
Static
Dynamic (high-resolution mode)
Dynamic (standard mode))
Min echo spacing
Measurement range
Porosity
T2 distribution
Precision
Total CMR porosity
CMR free-fluid porosity
Depth of investigation
All hole sizes
15.6 ft
413 lbm
23 in. above bottom of tool
57⁄ 8 in.
No limit
50,000 lbf
50,000 lbf
20,000 psi (25,000 psi with modified tools)
350°F
Unlimited
800 ft/hr
2700 ft/hr
3600 ft/hr
6-in. measurement aperture
9 in., three-level averaging
24 in., three-level averaging
0.2 ms
0–100 p.u.
0.3 ms–3.0 s
1-p.u. standard deviation, three-level averaging at 75°F
0.5-p.u. standard deviation, three-level averaging at 75°F
0.5-in. blind zone
1.1-in. 50% point
1.5-in. 95% point
www.connect.slb.com
SMP-5905
©Schlumberger
September 2002
*Mark of Schlumberger