Nuclear magnetic resonance (NMR) imaging
technology for well logging rather quickly morphed from a kind of
esoteric novelty to a mainstream oil patch application. Indeed,
since its debut in the early 1990s, this innovative approach to
logging and reservoir evaluation has come to be de rigueur
for operators both large and small.
"The cost is about proportional to what a triple
combo would be, so this is not just for the major operating companies,"
said Ron Cherry, product manager NMR services at Halliburton Energy
"We do a lot of jobs for the smaller companies, and
East Texas is a particularly busy area right now," he noted, "and
the technology is used a lot offshore where the cost relationship
to the triple combo measurment suite is the same."
Although not the lone wolf in the NMR logging applications
arena — industry veteran Schlumberger also has a dedicated focus
on the technology (see related story, page 18) — Halliburton has
a lengthy track record of tool development and application of the
technology. This comes via its ownership of NUMAR, which pioneered
the use of NMR in the oil patch with its Magnetic Resonance Imaging
Logging (MRIL®) tool.
For those operators unfamiliar with what NMR technology
brings to the table, it's designed to provide some vital information:
- Identify bound vs. moveable fluid.
- Obtain effective porosity.
- Determine permeability.
- Obtain accurate measurement and quantification of reservoir
fluids — oil, gas, and water — via Direct Hydrocarbon Typing
Perhaps the best approach for an operator debating
the pros and cons of a magnetic resonance imaging (MRI) application
would be to review a check-list of questions that the technology
can help answer:
- Is the rock porous and, if so, how porous?
- Does it contain moveable/producible fluids?
- In what fractions will the gas, oil and water produce?
- How are the fluid columns separated, what is the height of
each column, and where are the transition zones?
- Are there any specific obstacles to production, such as pore-clogging
clays, tar layers and such?
- What are the properties of each producible fluid, and what
is the gas/oil ratio in the hydrocarbon phase? How viscous is
Solving the Mystery
A quick look at the basics — a kind of NMR 101 —
might help to remove some of the mystique surrounding the technology,
making it appear less daunting to someone contemplating its usage.
Magnetic resonance imaging technology initially was
used for chemical analysis and is now employed routinely for medical
evaluations, where the equipment uses large magnets to surround
the subject being examined. In the quest to render MRI suitable
for use in the oil and gas industry, NUMAR miniaturized the magnets,
shrinking and redefining them to fit into a small diameter borehole
to allow NMR measurements of material surrounding the MRIL tool.
In stark contrast to conventional logging, NMR measurements
are mineralogy-independent. The MRIL tool responds only to the hydrogen
protons in the fluid of the rock's pore spaces, receiving no signal
from the rocks per se.
The hydrogen protons align with the permanent magnetic
field created by the MRIL magnet probe. The tool then emits a radio
frequency (RF) pulse that "tips" the protons at a 90-degree angle,
and subsequent 180-degree pulses are applied.
The magnitude of the ensuing NMR signal, which is
created by the RF pulse, is directly proportional to the amount
of hydrogen present in the volume probed by the tool and provides
a measure of liquid-filled porosity.
The hydrogen protons associated with the hydrated
clays and clay-bound water relax, or realign quickly. Clay porosity
is directly measured by the MRIL tool.
Both pore texture and size impact the decay rate
of the NMR signal. Measurement of this signal provides an estimate
of the rock's internal surface-to-volume ratio, which is closely
related to bulk-volume-irreducible water, and in turn provides an
estimate of grain size distribution. The difference between the
MRIL-derived porosity and irreducible water is the moveable fluid
Relaxation data and porosity data are used to compute
permeability straight from the MRIL tool.
Because the MRIL tool responds to matrix fluid, NMR
technology is not applicable to hard rock reservoirs with fracture
One of the NMR applications that captured the fancy
of operators early on is the now-commonplace DHT. It allows the
accurate measurement and quantification of water, light oil and
gas in the near-wellbore region investigated by the tool.
"Direct Hydrocarbon Typing has become so fundamental,
it's now like bread and butter," Cherry said. "Almost every log
we run is a hydrocarbon typing log."
New Tools Continue
As one tool becomes "old hat", others invariably
come along to keep the cutting-edge sharpened, such as the new Magnetic
Resonance Imaging Logging-While Drilling (MRIL® -WD™) system, which
was introduced last summer.
It is now being used commercially in the Gulf of
Mexico and the North Sea.
"It's like the MRIL logging tool in that it provides
information about fluid, irreducibles, permeability and other applications
you get from the logging tool," Cherry noted, "but you can do it
in real-time while drilling."
Another tool now being field-tested is a magnetic
resonance module called MRILab® that goes with Halliburton's Reservoir
Description Tool (RDT®) — a formation tester-type tool.
The MRILab downhole fluids analyzer module takes
MRI measurements of fluids as they flow directly from the reservoir
into the RDT tool through the RDT pads, allowing the evaluation
team to measure parameters that give indications of the viscosity
of the fluid, according to Cherry. It addresses the difficult problem
of differentiating oil base mud filtrate from connate hydrocarbons.
"When you start sampling a formation, you want to
know what's the native fluid, not the filtrate," said Charles Siess,
global MRIL product manager at Halliburton. "With an oil-based mud
instead of a water-based mud in an oil zone, trying to figure if
you went from oil-based filtrate to native crude is tough.
"In measuring the magnetic resonance parameters of
reservoir fluids as they flow through the MRILab, what we see is
there is a difference in signature between the filtrate and the
The MRILab module provides in-situ fluid characteristics
at reservoir PVT conditions. By taking measurements downhole, the
samples are not altered as they are when sent to a lab for analysis,
where the lab must try to reconstruct reservoir conditions.
"We think it's important to get these measurements
in-situ," Cherry said. "By measuring fluids directly you get the
raw fluid measurement and get the exact parameters you need for
use in log interpretation of either the LWD or the wireline tool.
"In other words, if you have fluid measurement from
MRILab, you know exactly what the fluid properties are," he said,
"and this enhances interpretation accuracy of the well log."