By KATHY SHIRLEY
NMR (first) 'Rocked' in the '60s
The potential of NMR measurements
to provide information on formation pore fluids and pore structure
was first identified in the 1950s. The first NMR log was run in
1960, measuring the signal from protons precessing in Earth's magnetic
These early NMR logging tools required
doping the drilling mud with magnetite to kill the borehole signal.
Advances in NMR interpretation occurred
in the 1960s, including a relationship between relaxation time and
permeability in sandstones, the concept of free fluid index and
the relationship between pore size, fluid and matrix properties.
A new version of the tool was developed
in the late 1970s and remained the only widely available NMR tool
until the advent of the pulsed NMR tools in the late 1980s. This
new generation tool had a T2 (the amount of time it takes for the
magnetization component to deteriorate) sensitivity limit of about
30 milliseconds and measured only the bulk or movable fluid in the
It did not measure the T2 distribution
of the pore fluid.
The first commercial pulse-echo logging
tool was introduced in 1990, and Schlumberger introduced its first
commercial tool in 1994. Schlumberger's Combinable Magnetic Resonance,
or CMR, tool was first proposed in the late 1980s and a prototype
was field tested in 1992.
In 1994 the commercial CMR tool had
a T2 sensitivity limit of three milliseconds. It couldn't routinely
measure T2 signals below three milliseconds, such as those from
clay-bound water or water trapped in small pores.
Schlumberger improved the technology
with its CMR-200 and Total CMR (TCMR) porosity processing -- enhancing
the T2 sensitivity limit by an order of magnitude to 0.3 milliseconds.
The TCMR porosity processing software was optimized to make full
use of the hardware improvements in the determination of total porosity.
TCMR logs demonstrated that in most formations the tool is capable
of measuring total porosity.
NMR data can be used directly to
infer formation properties -- and comparing NMR with other measurements
can expand on this information. For example, comparisons with density
porosity can be used to quantify gas or light hydrocarbons in shaly
sand and other difficult environments.
For years nuclear magnetic resonance logging
technology has been touted as the best new tool for downhole geology,
providing geologists with a wealth of information that's simply
not attainable with any other tool. And, in fact, commercial NMR
logging tools today usually deliver on all those promises.
Unfortunately, geologists sometimes are not equipped
to unravel the complicated data derived from the method -- and often
must enlist the help of the nearest physicist.
James Kovats, NMR product champion for Schlumberger,
acknowledges that service companies must continue to educate clients
on the value of NMR and exactly how the technology works.
"There is a growing number of people in the industry
who understand this new technology, but we still have quite a lot
of education to do," he said.
"Many people think NMR measurements are extremely
complicated, but it's a very rich dataset with a great deal of valuable
information -- and it's up to us to help clients understand how
to best leverage all that information to better understand the reservoir."
Speed has always been the major stumbling block for
NMR technology, Kovats said, but Schlumberger's newest generation
NMR logging tool, called CMR Plus (for Combinable Magnetic Resonance),
has increased the logging speed to match that of other tools in
the logging suite.
"Now, when a petrophysicist says he's interested
in getting NMR data he doesn't have to put his career on the block
and convince management to spend extra rig time to acquire NMR data,"
Kovats said the tool is three to five times faster
than earlier tools.
"The previous generation tools logged on the order
of 100 to 200 feet per hour in a slow environment, and 600 feet
an hour in optimum conditions," he said. "The new tool can log 700
to 800 feet per hour at an absolute minimum and can go as high as
3,600 feet per hour, depending on the downhole environment.
"This increase in logging speed makes the tool more
cost effective," he continued. "Also, with the speed increases...
we can log larger intervals and gather significantly more data on
zones that might otherwise not have been tested."
That, he concluded, can translate to finding additional
productive reservoirs that might not have looked promising on other
types of data.
A User-Friendly Approach
Scientists recently have turned their attention to
another important stumbling block to the widespread use of NMR technology:
Making the method more user friendly for oil company personnel.
"NMR technology has advanced to the point where we
are coming full circle and can get back to simple outputs," Kovats
said. "Saturation, viscosity, porosity. That's what people are interested
in ... They want to know how much oil there is, how much storage
capacity there is and will the oil flow."
He said that NMR can provide all that data with a
new magnetic resonance fluid characterization method currently being
"We can provide that information without having to
educate the client about the technical intricacies of NMR logging,"
The advent of this magnetic resonance fluid characterization
method is enhancing NMR as a tool for multi-disciplines.
"Previously it was geared primarily to petrophysicists
who knew how to glean the information," Kovats said. "Now geologists
as well as reservoir engineers can benefit greatly from the information
-- without requiring a degree in physics."
The magnetic resonance fluid (MRF) characterization
method -- currently undergoing worldwide experimental field testing
and expected to be available commerically by next year -- provides
a detailed formation evaluation of the near- wellbore region investigated
by modern NMR logging tools.
It gives quantitatively accurate estimates of formation
properties, including total porosities, fluid saturations and oil
These are obtained by inversion of suites of NMR
data using a new multifluid relaxation model, according to a paper
presented at the recent Society of Petroleum Engineers annual meeting
by R. Freedman with Schlumberger.
NMR's value for providing formation evaluation information
is well documented -- and foremost among the many physical properties
probed by NMR is molecular diffusion. Since water molecules typically
diffuse much faster than oil molecules and much slower than gas
molecules, NMR diffusion measurements provide a means for detection
and differentiation of reservoir fluids.
This capability has generated much excitement in
the oil industry since the introduction of modern pulsed NMR logging
tools. However, despite the considerable efforts of service companies
and oil companies, the development of an accurate and reliable NMR
fluid-typing method has been limited by the lack of a detailed understanding
of molecular diffusion and NMR relaxation in hydrocarbon mixtures.
That's where the MRF method comes in -- it uses suites
of spin-echo measurements acquired from NMR logging tools, and the
data suites consist of spin-echo measurements with different echo
spacings, polarization times, applied magnetic field gradients and
numbers of echoes.
These measurements, sensitive to the viscosities
and molecular diffusion coefficients of the fluids, provide information
needed for fluid characterization. The MRF method is based on the
inversion of a general multifluid relaxation model that describes
the decay of the transverse magnetization in porous rocks containing
What does that mean to oil companies?
"It is well known ... that oil-bearing reservoirs
can be misinterpreted or even missed altogether by conventional
resistivity-based interpretation," Freedman wrote. "One difficulty
is the fact that many oil-bearing reservoirs exhibit anomalously
low values of resistivity, which results in spuriously high water
Other difficulties in the interpretation of resistivity
logs, according to his paper, can be traced to fresh formation waters
or waters with unknown or variable salinity. Problems also occur
in formations with complex lithologies that can result in totally
erroneous water saturation estimates.
The MRF characterization method, centered around
a new multifluid relaxational mode, overcomes problems inherent
in resistivity interpretation by providing formation evaluation
information that is not possible with other well logging techniques.
"Hydrocarbon detection and viscosity estimates using
NMR logging tools have been tried via various methods in the past,"
Kovats said, "but those methods were based on assumptions that were
not always true, so they weren't very reliable or robust."
The Multi-Disciplinary Tool
The MRF method provides a wide range of information.
It gives scientists:
- Flushed-zone fluid saturations and volumes.
- Total NMR porosities.
- Bulk volumes of irreducible water.
- Crude oil viscosities.
- Brine T2 distributions and T1/T2 ratios.
- Crude oil T2 and diffusion coefficient distributions.
- Hydrocarbon-corrected permeabilities.
All of these outputs are computed by simultaneous inversion of
a simple suite of NMR data using the MRF multifluid relaxation method.
The most important capabilities of the MRF method,
according to Kovats, is its ability to accurately determine flushed
zone water saturations and oil viscosities.
"So many techniques concentrate on permeability,
but viscosity can be equally important," Kovats said. "We have a
lot of customers with reservoirs where producibility of hydrocarbons
is largely controlled not by permeability but by the viscosity of
the oil. They have to be able to differentiate between lighter oils
that will flow from heavier, more viscous oils that won't produce.
This technology allows us to provide that information."
The addition of the MRF method to NMR logging will
expand the use of NMR data, Kovats said.
"If the reservoir engineer has a clear picture of
the oil's viscosity, he can make better decisions about optimum
completion techniques, artificial lift needs and the necessary surface
facilities," he said. "This makes NMR logging a truly multi-disciplinary