Well Logging Tools and Techniques
Magnetic Resonance Logs
INTRODUCTION
In this section, we’ll review NMR concepts, compare NMR tools to other logging tools, discuss current tool types, and briefly look at examples of NMR logs.
A
CKNOWLEDGEMENT
IHRDC wishes to express their gratitude to Numar, a Halliburton Company, for graciously contributing resources, technical input, and graphics pertaining to NMR theory, as well as
information on their MRIL logging tool and associated services. Further details on this subject can be found in NMR Logging Principles and Applications, (1999) by Coates, Xiao, and Prammer. (See the References section for a complete listing.) Additional information on Halliburton/Numar MRIL services can be found on-line. Look under the Logging and Perforating section at
www.halliburton.com .
IHRDC also thanks Schlumberger for graphics and information pertaining to their CMR tool. Additional information on the Schlumberger CMR tool can be found at www.connect.slb.com .
B
ACKGROUND
Since its discovery in 1946, nuclear magnetic resonance (NMR) has developed into a valuable tool for physics, chemistry, biology, and medicine. The potential for applying this technology to formation evaluation was identified during the 1950’s. Early logging tools had very limited application and the majority of the work was related to core analysis. With the invention of NMR logging tools that use permanent magnets and pulsed radio frequencies, sophisticated laboratory techniques were developed to enable in situ determination of formation properties. This capability opens a new era in formation evaluation and core analysis, just as the introduction of NMR has revolutionized the other scientific areas to which it has been applied.
C
ONCEPT
To understand the concept and applications for NMR in formation evaluation, it may be helpful to review and compare the use of magnetic resonance imaging (MRI) in the medical field.
MRI is one of the most valuable clinical diagnostic tools in health care today. With a patient placed in the whole-body compartment of an MRI system, magnetic resonance signals from hydrogen nuclei at specific locations in the body can be detected and used to construct an image of the interior structure of the body. These images may reveal physical abnormalities and thereby aid in the diagnosis of injury and disease.
The MRI of the human head in Figure 1 (Medical MRI presentation) demonstrates two important MRI characteristics.
Figure 1
First, the signals used to create each image come from a well-defined location, typically a thin slice or cross section of the target. Because of the physical principles underlying NMR technology, each image is sharp, containing only information from the imaged cross section, with material in front or behind being essentially invisible.
Second, only fluids (seen in blood vessels, body cavities, and soft tissues) are visible, while solids (such as bone) produce a signal that typically decays too fast to be recorded. By taking advantage of these two characteristics, physicians have been able to make valuable diagnostic use of MRI -without needing to understand complex NMR principles.These same NMR principles, instead of being used to diagnose anomalies in the human body, can be used to analyze the fluids held in the pore spaces of reservoir rocks. And, just as physicians do not need to be NMR experts to use MRI technology for effective medical diagnosis, neither do geologists, geophysicists, petroleum engineers, nor reservoir engineers need to be NMR experts to use MRI logging technology for reliable formation evaluation.
In an NMR Logging tool, a permanent magnet produces a magnetic field that excites formation materials. An antenna transmits into the formation precisely timed bursts of radio-frequency energy in the form of an oscillating magnetic field. Between these pulses, the antenna is used to listen for the decaying “echo” signal from those hydrogen protons that are in resonance with the field from the permanent magnet. Since this magnetic resonant frequency depends on the local strength of the magnetic field, the measurement zone of the tool is a function of the magnetic field generated, and the radio frequency used. These tool operations will be discussed in more detail in the sections to follow.
C
OMPARING
NMR
TOOLS
TO
OTHER
LOGGING
TOOLS
Because only fluids are visible to NMR, the porosity measured by an NMR tool contains no contribution from the matrix materials, and therefore does not need to be calibrated to formation
lithology. This response characteristic makes NMR tools fundamentally different from conventional logging tools.
The conventional neutron, bulk-density, and acoustic-travel-time porosity-logging tools are influenced by components of the reservoir rock. Because reservoir rocks typically have more rock framework than fluid-filled space, these conventional tools tend to be much more sensitive to the matrix materials than to the pore fluids.
Conventional resistivity-logging tools, while being extremely sensitive to the fluid-filled space and traditionally used to estimate the amount of water present in reservoir rocks, cannot be regarded as true fluid-logging devices. These tools are strongly influenced by the presence of conductive minerals and, for the responses of these tools to be properly interpreted, a detailed knowledge of the properties of both the formation and the water in the pore space is required.
Unique Formation Measurements
NMR tools can provide three types of information, each of which make these tools unique among logging devices:
information about the quantities of the fluids in the rock,
information about the properties of these fluids, and
information about the sizes of the pores that contain these fluids.Current Tool Types
Magnetic Resonance Imaging Logging (MRIL), introduced by NUMAR in 1991, takes the medical MRI or laboratory NMR equipment and turns it inside-out. So, rather than placing the subject to be analyzed at the center of the instrument, the instrument itself is placed, in a wellbore, at the center of the formation to be analyzed. This tool is used by Numar, a Halliburton company and by Baker Atlas, a Baker Hughes company.
The Schlumberger tool, the Combinable Magnetic Resonance tool (CMR), follows on from earlier Schlumberger NMR tools that date back to the 1970s. The CMR is a pad-type tool, which uses a directional antenna sandwiched between a pair of bar magnets to focus the CMR measurement on a 6-in. [15-cm] long zone inside the formation—the same rock volume scanned by other essential logging tools.
L
OG
E
XAMPLES
This first example, shown in Figure 2 (Example of CMR porosity log) demonstrates how NMR porosity (in this case from a Schlumberger CMR tool) is independent of lithology,
Figure 2
overlaying the density porosity plotted on a dolomite scale in the dolomite sections and overlaying the density porosity on a limestone scale in the limestone sections.
The second example, Figure 3 (Interpreting Numar MRIL Data), shows the breadth of information gained by interpreting NMR data in conjunction with conventional logs.
Figure 3
In this case, the NMR data is from a Numar MRIL tool interpreted using the MRIAN analysis program. MRIAN is a proprietary computer based analysis developed by NUMAR that uses MRIL measurements to augment the conventional resistivity and porosity logs within the Dual Water Model system of equations. The MRIL is especially effective in cation exchange capacity (CEC) models because the quantity of clay bound water (Swb) is easily obtained by direct measurement utilizing the MRIL C/TP. (For definitions of these terms, refer to the glossary. Other NMR terms are described in more detail in later sections of the module.)
Track 1 Gamma Ray, SP, and Caliper measurements (from conventional logs), and MRIL formation porosity, divided into eight T2 defined bins. The first bin represents the shortest T2 time group (typically 4 ms), in gray, and the last bin represents the longest T2 time group (typically 512 ms), shown in cyan.
Track 2 The Resistivity curves (deep, medium, and shallow) and core permeability are displayed along with the permeability that is derived from the MRIL measurements of porosity, irreducible fluid, and free fluid volumes.
Track 3 The T2 distribution, also presented in Track 1 in a bin format, is illustrated in this track in a variable density format. T2 time is logarithmically spaced across the track from 0.2 ms on the left edge to 2048 ms on the right edge of the track. The amount of porosity that is represented by each T2 value (partial porosity) is illustrated by color; blue represents zero partial porosity and red represents the highest partial porosity. Since the bound (clay or capillary) fluids are represented by the short T2 times, they will be seen on the left portion of the track, while increasing volumes are represented by the colors shown. The free fluids are represented by longer T2 times and are seen in the middle and the right portions of the track.
Track 4 The results of the Differential Spectrum Method (DSM) are displayed in this VDL format. The difference between two T2 spectra, each taken at a different wait time (Tw), yields the
hydrocarbon signal. Relative position indicates hydrocarbon type, and color is proportional to volume.
Track 5 Time Domain Analysis (TDA) computes an MRIL only result yielding all the major fluid volumes. In addition to these MRIL volumes, fluid typing indicates, independently, gas (red), oil (green), and water (blue), and where fluid contacts may exist.
Track 6 This track contains a playback of the conventional neutron and density porosity curves along with the MRIL. These porosities are further divided into four volumes: the irreducible fluid volume (light gray), the hydrocarbon filled portion (red), moveable water (blue), and clay bound water (dark gray). The Dual Water Model is used to compute both the total and effective volumes of water, using only conventional log data, then the effective water volume is compared with the irreducible volume from the MRIL. When the computed effective volume of water is greater than the MRIL irreducible volume of water, water production is inferred.
PRINCIPLES OF OPERATION
This section provides an overview of NMR Fundamentals, Logging Basics, Relaxation mechanisms, and Pore Fluid Effects
NMR FUNDAMENTALS
Nuclear magnetic resonance refers to the way in which nuclei respond to a magnetic field. Many nuclei have a magnetic moment -they behave like spinning bar magnets. These spinning magnets can interact with externally applied magnetic fields, producing measurable signals. For most elements the detected signals are small. However, hydrogen, which makes up a significant component of both water and hydrocarbons in the pore spaces of rock, has a relatively large magnetic moment.
NMR L
OGGING
B
ASICS
Before a formation is logged by an NMR logging tool, the protons in the formation fluids are randomly oriented. When the tool passes through the formation, the tool generates magnetic fields that activate those protons.
First, the tool's permanent magnetic field aligns, or polarizes, the spin axes of the protons in a particular direction. This process, called polarization, increases exponentially in time with a time constant, designated as T1.
Next, the tool's oscillating field is applied to tip these protons away from their new equilibrium position in the same way a child’s spinning top precesses in the Earth’s gravitational field.
Precession occurs as a body rotating about one axis slowly rotates around a second axis. In the
NMR case, this second axis is the static magnetic field. This is shown in Figure 1 (Spin
Figure 1
When the oscillating field is subsequently removed, the protons begin tipping back toward the original direction in which the static magnetic field aligned them. In NMR terminology, this tipping-back motion is called relaxing, and measurement of the ‘relaxation time’ is the fundamental measurement of NMR logging tools.
Relaxation mechanisms
The primary NMR relaxation mechanism is grain surface relaxation, in which a molecule in the fluid hits the grain surface due to Brownian motion and transfers nuclear spin energy to the grain surface (Figure 2: Relaxation mechanisms).
Figure 2
The effectiveness of the process depends on the surface: sandstones are about 3 times as efficient at relaxing pore water as carbonates.
Bulk fluid relaxation occurs in the absence of pore surface interaction. It is significant in large pore spaces such as vuggy carbonates, and also when hydrocarbons are present. Bulk fluid relaxation is seen in hydrocarbons because the non-wetting phase does not contact the pore surface, so it cannot be relaxed by the surface relaxation method.
Specified pulse sequences are used to generate a series of so-called spin echoes, which are measured by the NMR logging tool and are displayed on logs as echo trains. These spin-echo trains constitute the raw NMR data.
To generate a spin-echo train, the NMR tool measures the amplitude of the spin echoes as a function of time (Figure 3 : Spin-echo train display).
Figure 3
Because the spin echoes are measured over a short time, the NMR tool travels no more than a few inches in the well while recording the spin-echo train. The recorded spin-echo trains can be displayed on a log as a function of depth.
The initial amplitude of the spin-echo train is proportional to the number of hydrogen nuclei associated with the fluids in the pores within the sensitive volume. Thus, this amplitude can be calibrated to provide porosity.
The observed echo train can be linked both to data-acquisition parameters and to properties of the pore fluids located in the measurement volumes. Data acquisition parameters include inter-echo spacing (TE) and polarization time (TW). TE represents the time between the individual echoes in an echo train. TW represents the time between the cessation of measurement of one echo train and the beginning of measurement of the next echo train. Both TE and TW can be adjusted to change the information content of the acquired data.
Pore Fluid Effects
Properties of the pore fluids that affect the echo trains are the:
Hydrogen Index (HI): a measure of the density of hydrogen atoms in the fluid
Longitudinal Relaxation Time (T1): an indication of how fast the tipped protons in the fluids relax longitudinally (relative to the axis of the static magnetic field)
Transverse Relaxation Time (T2): an indication of how fast the tipped protons in the fluids relax transversely (again, relative to the axis of the static magnetic field)
Diffusivity (D): a measure of the extent to which molecules move at random in the fluid.TOOL DESCRIPTION
This section describes NMR logging tools developed by Numar and by Schlumberger.
NUMAR’S MRIL TOOL
Magnetic Resonance Imaging Logging (MRIL), introduced by NUMAR in 1991, takes the medical MRI or laboratory NMR equipment, and turns it inside-out. Rather than placing the subject to be analyzed at the center of the instrument, the instrument itself is placed in the wellbore, at the center of the formation to be analyzed. MRIL services are provided by Numar, a Halliburton company and by Baker Atlas, a Baker Hughes company.
At the center of the MRIL tool, a permanent magnet produces a magnetic field that excites formation materials. An antenna surrounding this magnet transmits into the formation precisely timed bursts of radio-frequency energy in the form of an oscillating magnetic field. Between these pulses, the antenna is used to listen for the decaying “echo” signal from those hydrogen protons that are in resonance with the field created by the permanent magnet.
Because a linear relationship exists between the proton resonance frequency and the strength of the permanent magnetic field, the frequency of the transmitted and received energy can be tuned to investigate cylindrical regions at different diameters around the MRIL tool. This tuning of the MRI probe to be sensitive to a specific frequency allows MRI instruments to image narrow slices of the rock formation.
Figure 1 (Cylinders of investigation) illustrates the measurement concept behind Numar’s MRIL-Prime tool, which was introduced in 1998.
Figure 1
The diameter and thickness of each thin cylindrical region are selected by simply specifying the central frequency and bandwidth to which the MRIL transmitter and receiver are tuned. The diameter of the cylinder is temperature dependent, but typically ranges from approximately 14 to 16 inches.
SCHLUMBERGER’S CMR TOOL
The Schlumberger Combinable Magnetic Resonance tool (designated as the CMR tool) follows on from earlier Schlumberger NMR tools that date back to the 1970s. It uses a directional antenna sandwiched between a pair of bar magnets to focus the CMR measurement on a 6-in. [15-cm] zone inside the formation—the same rock volume scanned by other essential logging
measurements. As shown in Figure 2 (CMR tool), it is a compact skid-mounted tool that was designed to be combinable with many other standard logging tools.
Figure 2
The vertical resolution of the CMR measurement makes it sensitive to rapid porosity variations, as often seen in laminated shale and sand sequences.
The first pulsed-echo NMR logging tools introduced in the early 1990s, were unable to detect the fast components of resonance decay. The shortest T2 was limited to the 3 to 5 msec range, which
allowed measurement of capillary-bound water and free fluids together, to derive effective
porosity.However, clay-bound water, being more tightly bound, is believed to decay at a much faster rate than was measurable with these tools. The latest improvements in these tools measure decay rates at a much higher speed -by a factor of ten. Now, measuring T2 decay components in
the 0.1 to 0.5-msec range is possible. These improvements include electronic upgrades, more efficient data acquisition, and new signal-processing techniques that take advantage of the early-time information. The CMR tool is run in an eccentered configuration.
Figure 3
This region is approximately 0.5” x 0.5” by 6” long, and is located about 1.1 inches inside the formation.
NMR INTERPRETATION
OVERVIEW
All NMR measurements made by current tools are summarized by the T2 distribution. The
petrophysical applications of this distribution can be summarized as follows:
The area under the distribution curve equals NMR porosity
T2 distribution mimics pore size distribution in water-saturated rocks
Permeability is estimated from logarithmic-mean T2 and NMR porosity
Empirically derived cutoffs separate the T2 distribution into areas equal to free-fluidporosity and irreducible water porosity
Multiple T2 data sets acquired with different acquisition parameters can differentiateProperly defined, the area under the T2 distribution curve is equal to the initial amplitude of the
spin-echo train. Hence, the T2 distribution can be directly calibrated in terms of water-filled
porosity. In essence, a key function of the NMR tool and its associated data-acquisition software is to provide an accurate description of the T2 distribution at every depth in the wellbore.
The basic physics behind NMR interpretation is common to all the data, however, each of the current NMR logging service companies - Baker Atlas, Numar, and Schlumberger have their own proprietary interpretation methods. In addition, there are now several companies that specialize in the interpretation of NMR data, including NuTech and NMR+.
P
OROSITY
The initial amplitude of the raw decay curve is directly proportional to the number of polarized hydrogen nuclei within the pore fluid.
The raw reported porosity is provided by the ratio of the initial amplitude of the raw decay to the tool response in a water tank (which provides a medium having 100% porosity). This porosity is independent of the lithology of the rock matrix, and can be validated by comparing laboratory NMR measurements on cores with conventional laboratory porosity measurements.
The accuracy of the raw reported porosity depends primarily on three factors:
a sufficiently long TW, to achieve complete polarization of the hydrogen nuclei in the fluids
a sufficiently short TE, to record the decays for fluids associated with clay pores and other pores of similar size
the number of hydrogen nuclei in the fluid being equal to the number in an equivalent volume of water, that is, HI = 1.Provided the preceding conditions are satisfied, the NMR porosity is the most accurate porosity reading available in the logging industry.
The first and third factors are only important for gas or light hydrocarbons. In these cases, special activations can be run to provide information to correct the porosity. The second factor was a problem in earlier generations of tools, because they could not, in general, see most of the fluids associated with clay minerals.
Terminology
Through this text we have used generic terminology where it makes sense, and used tool-specific terminology as applicable. The following table summarizes the main terms used with reference to NMR logging measurements:
Generic Term Description Numar Schlumberger
nmr Total Porosity MSIG CMRP
effr Effective Porosity MPHI-FFI
nmr Free Fluid Index MFFI CMFFCBV
nmr Clay Bound Volume MCBW or BVI BFVNMR
Evaluation
Automated Computer
A glossary of many terms used in NMR logging and interpretation is included under a separate heading within this subtopic.
Because in shaly sand analysis, the non-clay porosity is referred to as effective porosity, the historical NMR porosity was also called effective porosity (eff). Current NMR tools now capture a total porosity(nmr). The difference between total and effective porosity is taken as the clay-bound volume (CBVnmr). This division of porosity is useful in analysis, and often corresponds to other measures of effective porosity and clay-bound volume. The division of porosity into clay-bound porosity and effective porosity depends to some extent on the method used; thus, other methods may break out clay-bound porosity and effective porosity differently, or may assign different weights to each, and therefore may provide different values than that measured by NMR.
NMR T
2Distribution
In water-saturated rocks, it can be proven mathematically that the decay curve associated with a single pore will be a single exponential with a decay constant proportional to pore size, such that small pores have small T2 values, and large pores have large T2 values.
At any depth in the wellbore, the rock samples probed by the NMR tool will have a distribution of pore sizes. Each pore size generates a corresponding T2 value. As seen previously, the total of all the T2 signals in the measurement volume creates a decay train, as shown in Figure 1 (T2
Spin-echo decay train)
The amplitude of the spin-echo-train decay can be fit very well by a sum of decaying exponentials, each with a different decay constant. The set of all the decay constants forms the decay spectrum or transverse-relaxation-time (T2) distribution.
Hence, the multi-exponential decay represents the distribution of pore sizes at that depth, with each T2 value corresponding to a different pore size. Figure 2 (T2 distribution) was derived from
the previous figure’s spin-echo train.
Figure 2
The NMR T2 distribution can be displayed in several different ways: Each visualization represents
the distribution of the porosity over T2 values and, hence, over the pore sizes.
Figure 3
On the MRIL log, T2 distributions are displayed in three ways: A plot of the cumulative amplitudes from the binned T2-distribution is shown in Track 1, a color image of the binned T2-distribution is in Track 3, and a waveform presentation of the same information is in Track 4. The T2-distribution typically displayed for MRIL data corresponds to binned amplitudes for exponential decays at 0.5, 1, 2, 4, 8, 16, 32, 64, 128, 256, 512, and 1024 ms when MSIG is shown, and from 4 ms to 1024 ms when MPHI is shown. The 8-ms bin, for example, corresponds to measurements made between 6 and 12 ms. Because logging data are much noisier than laboratory data, only a comparatively coarse T2-distribution can be created from NMR log data.
Figure 4
Effective porosity
Early NMR tools were unable to measure the short relaxation times associated with bound water, and thus the reported porosity was based on the porosity above a T2 cutoff (typically 4ms). This
reported porosity was referred to as effective porosity or FFI For current tools, this has now been superceded by measurements of bulk volume irreducible and free fluid index which together comprise total porosity.
Free Fluid & Clay Bound Volume
The porosity and pore-size information from NMR measurements can be used to estimate both the permeability and the potentially producible porosity (that is, the movable fluids).
The NMR estimate of producible porosity is called the free-fluid index (FFInmr ). The estimate of
FFInmr is based on the assumption that the producible fluids reside in large pores, whereas the bound fluids reside in small pores. Because T2 values can be related to pore sizes, a T2 value can
be selected below which the corresponding fluids are expected to reside in small pores, and above which the corresponding fluids are expected to reside in larger pores. This T2 value is called
the T2 cutoff (T2cutoff).
Through partitioning of the T2 distribution, T2cutoff divides nmr into free-fluid index and bound-fluid porosity, or bulk volume irreducible or clay bound volume (CBVnmr), shown in Figure 5 (T2
Figure 5
The T2cutoff can be determined with NMR measurements on water-saturated core samples.
Specifically, a comparison is made between the T2 distribution of a sample in a fully
water-saturated state, and the same sample in a partially water-saturated state, the latter typically being attained by centrifuging the core at a specified air-brine capillary pressure.
Although capillary pressure, lithology, and pore characteristics all affect T2cutoff values, common
practice establishes local field values for T2cutoff. For example, in the Gulf of Mexico, T2cutoff values of
33 and 92 ms are generally appropriate for sandstones and carbonates, respectively. Generally though, the best values can be obtained by measuring core samples corresponding to the actual interval logged by an NMR tool.
P
ERMEABILITY
NMR relaxation properties of rock samples are dependent on porosity, pore size, pore-fluid properties and mineralogy. The NMR estimate of permeability is based on theoretical models, which show that permeability increases with both increasing porosity and increasing pore size. Two related kinds of permeability models have been developed.
The Free-fluid or Coates model can be applied in formations containing water and/or hydrocarbons.
The average-T2 model Schlumberger-Doll-Research model (SDR) -can be applied to poresystems containing only water.
Measurements on core samples are necessary to refine these models and produce a model customized for local use. Figure 6 (Decay of spin echo train) shows information related to
formation permeability.
Figure 6
Two echo trains were obtained from formations having different permeabilities. Both formations have the same porosity, but also have different pore sizes. This difference leads to shifted T2 distributions, and therefore to different values of the ratio of MFFI to BVI. Also indicated in the Figure are the permeabilities computed from the Coates model
k = [(MPHI / C)2 (MFFI / BVI)]2,
where
k is formation permeability and
C is a constant that depends on the formation
Figure 7
(Core permeability crossplot) shows how laboratory core data can be calibrated to determine the constant C in the Coates permeability model. Track 2 of the log in Figure 8 (MRIL permeability
Figure 8
NMR
PROPERTIES
OF
RESERVOIR
FLUIDS
Clay-bound water, capillary-bound water, and movable water occupy different pore sizes and locations. Hydrocarbon fluids differ from brine in their locations in the pore space, usually occupying the larger pores. They also differ from each other and brine in viscosity and diffusivity. NMR logging uses these differences to characterize the fluids in the pore space.
Figure 9
T2, and D for different fluid types and rock pore sizes demonstrate the variability and complexity of
the T1 and T2 relaxation measurements.) qualitatively indicates the NMR properties of different
fluids found in rock pores. In general, bound fluids have very short T1 and T2 times, along with slow
diffusion (small D) that is due to the restriction of molecular movement in small pores. Free water commonly exhibits medium T1, T2, and D values. Hydrocarbons, such as natural gas, light oil,
medium-viscosity oil, and heavy oil, also have very different NMR characteristics. Natural gas exhibits very long T1 times but short T2 times and a single-exponential type of relaxation decay.
NMR characteristics of oils are quite variable and are largely dependent on oil viscosities. Lighter oils are highly diffusive, have long T1 and T2 times, and often exhibit a single-exponential decay. As
viscosity increases and the hydrocarbon mix becomes more complex, diffusion decreases, as do the T1 and T2 times, and events are accompanied by increasingly complex multi-exponential
decays. Based on the unique NMR characteristics of the signals from the pore fluids, applications have been developed to identify and, in some cases, quantify the type of hydrocarbon present.
NMR Hydrocarbon Typing
Despite variabilities in the NMR properties of fluids, the locations of signals from different types of fluids in the T2 distribution can often be predicted or, if measured data are available, identified.
This capability provides important information for NMR data interpretation and makes many applications practical.
Figure 10
shows two methods for differentiating fluids. In Part a of this figure, different TW values are used with a T1-weighted mechanism to differentiate light hydrocarbons (light oil or gas, or both) from
water. In Part b of this figure, different TE values are used with a diffusivity-weighted mechanism in a well-defined gradient magnetic field to differentiate viscous oil from water, or to differentiate gas from liquid.
By varying water saturation, it is also possible to produce different T2 distributions, as shown in
Figure 11
C
ORE
A
NALYSIS
NMR measurements on rock cores are routinely performed in the laboratory. The porosity can be measured with sufficiently short TE and sufficiently long TW to capture all the NMR-visible porosity.
Thousands of lab measurements on cores verify that agreement between the NMR porosity and a Helium Boyles Law porosity is better than 1 porosity unit. Figure 12
Figure 12 (NMR-core porosity plot) illustrates such an agreement.
As exemplified in this figure, with a set of clean sandstones, good agreement is typically observed between porosity derived from laboratory NMR measurements and porosity derived from
conventional core analysis. NMR-porosity values typically fall within 1 p.u. of the measured core-porosity values. The Figure shows NMR laboratory data measured at two different TE values, namely, 0.5 and 1.2 ms. A comparison of core data to NMR data provides an indication as to whether micro-porosity is present. (Fluid in micro-pores exhibits a fast T2 that can be observed
when TE = 0.5 ms, but not when TE = 1.2 ms.) In this case, because no evidence exists for micro-porosity, the NMR “effective porosity”
eff
and total porositynmr
would be the same.Laboratory NMR Measurements
The most important aspect of laboratory NMR measurements is that they duplicate the downhole NMR measurement, providing an opportunity to link laboratory measured properties directly to the downhole tool response.
NMR measurements are nondestructive. This means that they can be incorporated into any laboratory process used to acquire petrophysical parameters such as capillary bound water, permeability and porosity.
Following the acquisition of petrophysical data, models can then be developed and used to directly interpret the downhole measurements. NMR laboratory measurements have several objectives:
Refining Capillary Bound Water Determination
The nominal cutoff T2 value used to separate free fluid from bound water can be refined in the
laboratory by first performing NMR analysis on a fully brine-saturated core sample. The sample is then processed using standard core analysis techniques to reduce the water saturation to a point where only the capillary bound water remains. The NMR measurement is then repeated, and the
difference between the T2 distributions can be used to refine the appropriate T2 cutoff. This is
shown in Figure 13
Figure 13
(Capillary based water saturation).The complete process can identify the relaxation time cutoff required to determine CBVnmr.
Refining the Permeability Model
Permeability is directly proportional to the interconnected pore sizes. Downhole NMR tools measure pore size distribution, but the model relating this to permeability requires an area-specific calibration coefficient. This can be directly determined from a combination of laboratory NMR measurements and standard core analysis permeability measurements on the same samples. This is shown in Figure 14 (Core permeability modeling).
Figure 14
Having estimated the relaxation time cutoff for an enhanced CBVnmr determination, the directly
measured core sample permeability can be compared to the NMR permeability model. Using this refined model, a more accurate representation for the downhole measurements can be provided.
Characterize Bulk Fluid Effects to Improve NMR Log Interpretation
Selecting the correct data acquisition parameters is vital for accurate, efficient NMR logging. If insufficient recovery time (TW ) is allowed, the resulting porosity will be too low. However wait timesthat are too long can slow down the downhole logging speeds. Laboratory measurements using different acquisition parameters can be compared with standard core porosity measurements to determine the optimum wait time (TW). An example of this is shown in Figure 15 (Core recovery
Figure 15
Here, we see that if the recovery time is too short, the resulting NMR porosities will be too low. This analysis indicates that a recovery time between 6 and 8 seconds is required to recover all the hydrogen protons for an accurate NMR porosity.
Refine Parameters Needed to Identify and Type Hydrocarbons
NMR logging can be used to identify and type hydrocarbons based on bulk relaxation times and diffusion rates. Oil can exhibit a wide range of relaxation times and diffusion constants, most of which are less than bulk water. Hydrocarbon gas has a diffusion mechanism that is significantly greater than water. Laboratory NMR measurements on bulk formation samples can be used to determine the NMR properties of formation hydrocarbons and thus significantly enhance NMR log interpretation.
Figure 16 (Core diffusion effects) shown in both the time domain (top) and the T2 spectrum
(bottom),the effects of diffusion can be investigated by changing the spacing of the echoes, which helps determine a fluid’s diffusion constant.
Figure 16
JOB PLANNING AND
LOG QUALITY CONTROL
In this section, we will discuss important issues pertaining to both the CMR and the MRIL logging jobs. We will start with a discussion of planning the job, then move on to quality control, both during and after the log run.
JOB PLANNING
Reliable and accurate NMR measurements of reservoir properties require careful, early job planning. Such planning is critical for the success of the logging run. Specific formation and fluid properties can be utilized to design an acquisition scheme that provides access to yet unknown reservoir characteristics, and which optimizes the acquisition process and thus improves the answers derived from the data. If acquisition parameters are not selected properly, answer products may provide properties that differ significantly from the actual reservoir properties, as is demonstrated in Figure 1 (Acquisition parameter effects).
Figure 1
This example shows a significant difference in T2 spectra, caused by changes in acquisition
parameters. In this figure, the red curve represents results obtained using inadequate acquisition parameters. The results graphed by the blue curve were obtained using optimized acquisition parameters.
In the final analysis of any logging job, it is often the planning that takes place before the log run which determines the success of the job. The Service Company Representative is usually in the best position to suggest which suite of logging tools will provide the best answers to the Operator’s problems. During the pre-job planning phase, it is in the Operator’s best interest to anticipate where ambiguities may develop, and to show the Representative examples where previous logs provided only vague answers. In this way, the Operator and Representative can work together to formulate logging strategies that will provide the best answers in the shortest time possible.
MRIL J
OB
P
LANNING
A clear definition of the logging objectives is essential in MRIL job planning and preparation. Limited objectives for porosity and permeability measurement can be met using standard data acquisition (activations), which allow easy and relatively fast logging. Supplemental objectives for hydrocarbon typing, however, call for advanced activations, which need to be run at reduced logging speed. Estimates of in-situ conditions are required to judge the applicability of the preferred type of activation, and to optimize the acquisition parameters and enhance the value of the outcome.
MRIL job planning can be executed in three basic steps:
1. Determine NMR fluid properties (T1, bulk, T2, bulk, D0, and HI). This step is straightforward if
samples of formation fluid are available. Alternatively, these properties can be estimated from global correlations based on estimated formation conditions.
2. Assess expected NMR responses (decay spectrum, polarization, apparent porosity) over the intervals to be logged. Again these may be estimated from available information on formation and fluid properties. In many cases, only a crude idea of the rock properties is necessary for job planning.
3. Select activation sets and determine appropriate activation parameters for TW, TE, and NE. (This step is covered in greater detail below.)
Selection of the Activation Set
Based on the current understanding of NMR physics and the behavior of fluids contained in porous media at elevated pressures and temperatures, three “families” of activations have been developed to cover the full range of major logging objectives, as illustrated in Figure 2 : Selection
of acquisition parameters.
Figure 2
Standard T2 activations provide data to determine porosity, permeability, and productivity(mobile fluids).
Dual-TW activations provide data to determine porosity, permeability, and productivity (mobile fluids) and to perform some direct hydrocarbon typing and quantification.
Dual-TE activations require slower logging speeds and provide data to determine porosity, permeability, and productivity (mobile fluids,) and to perform direct hydrocarbon typing, including viscous oil.For CMR logging, the following issues should be addressed prior to running the tool in the hole:
What is the objective of running the NMR tool?
What are the accuracy, precision and vertical resolution requirements?
What are the expected properties of the mud and formation fluids?
Mud type,
Hydrocarbon viscosity,
Formation pressure and
Temperature
What is the lithology?
Mineralogy
Texture, pore size and grain sizeThe answers (or best estimates) to these questions will aid in selecting the best logging parameter values.
LOG QUALITY CONTROL
This section describes quality control measures for the Numar and the Schlumberger magnetic resonance logging tools.
N
UMAR
MRIL L
OG
Q
UALITY
C
ONTROL
Quality control is essential to obtaining accurate information from the MRIL log. A system of tool-integrity and log-quality indicators is used to assure the highest level of data quality. The MRIL quality-control procedures include calibration before and after the survey, operational set-up, log recording, display of quality indicators, and a final quality check.
MRIL Quality Control During Logging
Logging Speed and Running Average
The logging speed of MRIL is affected by many factors. Speed charts, which determine the logging speed, are based on
gain
activation
polarization time
tool type
tool size
desired vertical resolution
operating frequencyInformation from the speed chart is essential for selecting the correct (minimum) running average, based on tool gain.
MRIL Log Quality Display
All of the quality indicators are recorded in the raw data file, and are available for playback whenever needed. MRIL log quality can be displayed in a variety of formats. All quality indicators
should be checked. This is easily achieved, because indicators have certain shadings if their values are outside of their allowable ranges.
Post-MRIL Logging Quality Checks
The MRIL responses should be checked against other logs when available. Two equations are essential for understanding MRIL tool responses and their relationships to petrophysical parameters:
]
1
[
(T1 ) TWe
HI
MPHI
e
CBW
MPHI
MSIG
whereMPHI = effective porosity measured by the MRIL tool
e = effective porosity of the formation
HI = hydrogen index of the fluid in the effective porosity system
TW = polarization time used during logging
T1 = longitudinal relaxation time of the fluid in the effective porosity system
MSIG = total porosity measured by MRIL total-porosity logging
CBW = clay-bound water measured by the MRIL tool with TE = 0.6 ms and partial-polarization activation
Agreement of MPHI with XPHI in Clean, Water-Bearing Formations
In clean, water-filled formations, MPHI should be approximately equal to XPHI (the density-neutron cross-plot porosity). In shaly sands, MPHI should approximately equal density porosity calculated with the correct grain density.Knowing the mud type is also essential for analyzing the response of an MRIL tool. Because of the tool’s relatively shallow depth of investigation, the tool investigates primarily the flushed zone.
Effects of Hydrogen Index and Polarization Time on MPHI
MPHI may not equal effective porosity because of the effects of both hydrogen index and long T1
components. The MRIL Prime measurement process usually eliminates the porosity
underestimation that results from T1 effects. The measurements are still affected by the hydrogen
index (HI). In clean gas zones, MPHI values obtained from stationary measurements should be close to neutron porosity values calculated with the correct matrix.
MPHI Relation to MSIG on Total-Porosity Logs
MRIL effective porosity (MPHI) is always less than MRIL total porosity (MSIG), except in very clean formations. In the latter case, clay-bound-water porosity (CBW) is zero, thus MPHI equals
MSIG. In general, MPHI MSIG.
MPHI
TESRelation to MPHI
TELon Dual-TW logs
Porosity measured with a short polarization time (MPHITwS) is usually underestimated, and thus will
be less than porosity measured with a longer polarization time (MPHITwL). Such is the case even if
TWL is not long enough for full polarization. This underestimation is especially prevalent in
hydrocarbon-bearing zones. So, in general, MPHITwS MPHITwL.
Because of diffusion effects, a T2 distribution obtained with a long TE will appear to be shifted to
the left of a distribution obtained with a shorter TE. Because some of the T2 components may be
shifted out of the very early bins, some porosity in the early bins will not be recorded with a long
TE. Therefore, in general, MPHITEL MPHITES.
S
CHLUMBERGER
CMR L
OG
Q
UALITY
C
ONTROL
Quality control is essential for obtaining accurate information from the CMR log. Since skid contact with the formation is essential, the CMR tool must be run eccentered.
CMR Quality Control During Logging
Logging Speed and Running Average
Maximum logging speeds are automatically calculated by the MAXIS computer, based on the tool’s pulse sequence and sample rate. This maximum logging speed ensures that a new measurement is properly acquired during each sample interval.
CMR Log Quality Display
All of the quality indicators are recorded in the raw data file, and are available for playback whenever needed. Field CMR logs include the following log quality controls related to logging conditions:
Bad-hole flag
Insufficient wait time flagPost-CMR Logging Quality Checks
The CMR porosity logs should be checked for correct response in the following environments:
Clean, water-saturated formations or formations where the fluid hydrogen index = 1. The CMR porosity is comparable to neutron and density porosities in clean sandstonesand carbonates.
Shaly Formations: Free fluid porosity is much lower than CMR porosity in shalyformations
Shales: In shales the CMR free fluid porosity reads low (close to 0 p.u.)
Gas Zones: In clean gas zones, the CMR porosity is much lower than the densityporosity and is typically comparable to neutron porosity. The CMR response in gas zones depends on invasion, wait time and the hydrogen index of the gas.
Heavy Oil Zones: CMR porosity does not include the volume of heavy oil (or bitumen).The CMR is lower than neutron and density porosities where heavy oil is present.
NMR APPLICATIONS
The broad range of data available from the current generation of NMR logging tools enables the tool to be utilized in a variety of applications. The most fundamental of these is the measurement of total porosity, independent of formation type. Directly leading on from this are applications based on analysis of the porosity distribution to provide permeability information and the
quantification of producible fluid versus bound fluid. A further range of applications is based on the evaluation of fluid type, differentiating between water, light or viscous oil and gas. These
applications are shown in the following sections, using examples obtained by Numar’s MRIL tool and Schlumberger’s CMR tool.
POROSITY AND PERMEABILITY
P
OROSITY
E
XAMPLE
FROM
N
UMAR
MRIL L
OG
Figure 1 (MRIL log) presents data from a well that was drilled through a shaly sand in Egypt.
Figure 1
Track 1 contains MRIL permeability (green curve) and core permeability (red asterisks). Track 2 contains MRIL porosity (blue curve), neutron and density porosity (green curves), and core porosity (red asterisks).
In this reservoir, the highly variable grain sizes resulted in considerable variation in rock permeability. Capillary-pressure measurements on rock samples yielded a good correlation between pore bodies and the pore throat structures. This correlation indicates that the NMR T2
distribution provides a good representation of the pore-size distribution when pores are 100% water saturated.
P
ERMEABILITY
E
XAMPLE
FROM
N
UMAR
MRIL L
OG
Figure 2 (Australian MRIL log presentation) shows MRIL log data acquired through a massive sandstone reservoir in Australia’s Cooper basin.
Figure 2
This reservoir exhibits low-porosity (approximately 10 p.u.) and low-permeability (approximately 1 to 100 md).
Track 1 displays gamma ray and caliper curves. Track 2 shows deep-and shallow-reading resistivity logs. Track 3 presents the MRIL calculated permeability and shows core permeability measurements for easy comparison between the two methods. Track 4 shows the MRIL porosity response, neutron and density porosity readings (based on a sandstone matrix), as well as core porosity.
This well was drilled with a potassium chloride (KCl) polymer mud [48-kppm sodium chloride (NaCl) equivalent] and 8.5-in. bit. MRIL data were acquired with TW = 12 seconds and TE = 1.2 ms.
Over the interval depicted, the log shows a clean sandstone formation at the top, a shaly sandstone at the bottom, and an intervening shale between the two sandstones. Agreement between MPHI and the core porosity is good. The slight underestimation of MPHI relative to core porosity is attributed to residual gas within the flushed zone. The MRIL permeability curve was computed using a model customized to this area. The agreement between MRIL permeability and core permeability is very good.
HYDROCARBON TYPING
Figure 3 (CMR tar zone) shows how tar zones presented on the CMR log.
Figure 3
In water, gas or oil, the CMR tool has a clear tar signature as seen in Zone C—a suppression of the long T2 components (track 5) and a reduction in total porosity (track 4). In this well, the CMR tool is able to confirm—by the presence of large T2 contributions from oil and no reduction in total CMR porosity—that the lower oil zone (Zone E) is not tar, but mobile oil, which may have been trapped by a local stratigraphic closure.
NMR ENHANCED WATER SATURATION WITH
RESISTIVITY DATA
N
UMAR
MRIL
LOG
EXAMPLE
Because resistivity tools have a large depth of investigation, a resistivity-based water-saturation model is preferred for determining water saturation in the virgin zone of a formation. However, resistivity measurements cannot distinguish between capillary-bound water and movable water. This lack of contrast makes it difficult to recognize hydrocarbon-productive low-resistivity and/or low-contrast pay zones from data provided by traditional logging suites.
The unique information, such as CBVnmr and FFInmr, provided by NMR logging can significantly
enhance the estimation of resistivity-based water-saturation, and can greatly assist in the recognition of pay zones that will produce water-free.
Through an MRI analysis process known as MRIAN, the NMR data are integrated with the deep-resistivity data to determine whether producible water is in the virgin zone, or whether an interval showing high water saturation may actually produce water-free hydrocarbons. The log shown in
Figure 4 (MRIAN log presentation) shows how the combination of conventional deep-resistivity data with NMR-derived MCBW, BVI,
Figure 4
MFFI, and MPHI can greatly enhance petrophysical estimations of effective pore volume, water
cut, and permeability. The MRIAN analysis results displayed in Track 5 show that the whole interval from XX160 to XX255 has a BVI almost identical to the water saturation interpreted from the resistivity log. This zone will likely produce water-free because of this high BVI.
TEST ZONE IDENTIFICATION
S
CHLUMBERGER
CMR E
XAMPLE
A combination of the Combinable Magnetic Resonance (CMR) and Modular Formation Dynamics Tester (MDT) tools provides independent complementary information on reservoir producibility. These answers--permeability, fluid identification and fluid contacts--optimize decisions on well tests and reservoir exploitation. Savings can be realized when both tools are run together on a single wireline-or pipe-conveyed descent.
CMR permeability data give a continuous interpretation of reservoir permeability and determine the best location to set the MDT tool. Subsequent MDT data confirm and refine the initial CMR interpretation. The combination of data from these two independent sources gives an enhanced permeability evaluation over the entire reservoir section. Figure 5 (CMR / MDT combination) shows how the CMR high-resolution permeability indicator is used to identify permeability streaks in a laminated sand-shale sequence, this information is used for positioning of the MDT tool.
Figure 5
Fluid identification Data from CMR, resistivity, density and neutron logs, combined with MDT pressure measurements and fluid samples, yield positive identification of formation fluids. Real-time optical fluid analysis from the MDT tool provides in-situ crude oil typing for estimates of gas-oil ratio, API gravity and coloration. There is minimal contamination before sampling because the OFA Optical Fluid Analyzer module allows uninterrupted monitoring of the flowline fluids and therefore optimal filtrate cleanup. Fluid contact changes in the CMR log reflect the tool’s response to different formation fluids, and the MDT tool provides pressure gradients. These two independent measurements of fluid type confirm gas, oil and water contacts. The CMR bound-and free-fluid answers can be used to determine the best points for obtaining MDT formation pressure measurements and samples.
S
INGLE
LOGGING
RUN
One run is eliminated and efficiency is improved when the MDT and CMR tools are combined in one trip, even though they are operated sequentially, rather than simultaneously. Time savings are significant and greatly improve the efficiency of sampling operations. Less time spent in sampling lowers the probability of deteriorating well conditions and stuck tools.
CASE HISTORIES
In this section, we will see how NMR logs were able to differentiate between productive and non-productive zones in cases where conventional logging suites were unable to properly discern the difference.
LOW-RESISTIVITY-RESERVOIR EVALUATION USING
NUMAR’S MRIL TOOL
In this example, we see how Numar’s MRIL data were used to provide a better understanding of reservoir lithology to improve production in a zone that would have otherwise been considered non-productive.
S
ETTING
The reservoir penetrated by this well consists of a massive, medium-to fine-grained sandstone formation, developed from marine shelf sediments that were subjected to intense bioturbation. Air permeability typically ranges between 1 and 200 md, with core porosity varying between 20 and 30 p.u.
The upper portion of the reservoir (Zone A) has higher resistivity (approximately 1 ohmm) than that of the lower reservoir (Zone B, approximately 0.5 ohmm). Produced hydrocarbons consist of light oil with viscosity from 1 to 2 cp.
The Operator’s Dilemma
The well was drilled with water-based mud. Conventional logs are shown in Figure 1: SP,
Figure 1
These logs suggest that the upper part of the sand (XX160 to XX185) would possibly produce with a high water cut, but that the lower part of the sand (XX185 to XX257) is probably wet.
The operator was concerned by the decrease in resistivity seen within the lower portion of the reservoir. The operator needed to know whether the decrease was due to
textural changes (smaller grain sizes, in which case the well might produce free of water) or
an increase in the volume of movable water.The ability to reliably answer this question would make a significant impact on reserve calculations, well-completion options, and future field-development decisions.
An additional piece of important information for this reservoir is that actual cumulative production often far exceeds the initial calculated recoverable reserves, based on a water-saturation cutoff of 60%. If the entire zone in question were actually at irreducible water saturation, then the total net productive interval could be increased from 25 to 70 ft. This gain would result in increased net hydrocarbon pore volume by more than 200%, accompanied by significant increases in expected recoverable reserves.
MRIL logs were incorporated into the logging suite for two principle reasons:
to distinguish zones of likely hydrocarbon production from zones of likely water production by establishing the bulk volume of irreducible water (bvi) and the volume of free fluids (mffi)MRIL Solution
The MRIL data acquired in this well included total porosity to determine clay-bound water, capillary-bound water, and free fluids. MRIL results from both TDA and MRIAN are illustrated in
Figure 2: MRIL log presentation.
Figure 2
Dual-TW logging was to be used to distinguish and quantify hydrocarbons. The MRIL data interpretation provided the basis for revising details in the reservoir’s depositional model, and resulted in an improved understanding of this reservoir’s lithology.
Interpretation of MRIL Data
MRIL data were acquired in the well and were used in DSM, TDA, and MRIAN analyses. The MRIL data in Figure 2 (MRIL log presentation) helped the Operator to determine that the resistivity reduction was due to a change in grain size and not to the presence of movable water. The two potential types of irreducible water that can cause a reduction in measured resistivity are clay-bound water (whose volume is designated by MCBW) and capillary-clay-bound water (whose volume is indicated by BVI). The MRIL clay-bound-water measurement (Track 3) indicates that the entire reservoir has very low MCBW. The MRIL BVI curve (Track 7) indicates a coarsening-upward sequence (BVI increases with depth). The increase in BVI and the corresponding reduction in resistivity are thus attributed to the textural change. The TDA analysis (Track 6) determined oil saturation in the flushed zone to be in the 35-to-45% range. Results of the TDA (Track 6) and TDA/MRIAN (Track 7) combination analysis imply that the entire reservoir contains no significant amount of movable water and is at irreducible condition. The MRIAN results (Track 7) indicate that both the upper and lower intervals have high water saturation, but that the formation water is at
irreducible conditions. Thus, the zone should not produce any formation water. The entire zone has permeability in excess of 100 md (Track 2). Based on these results, the operator perforated the interval from XX163 to XX234. The initial production of 2,000 BOPD was water-free and thus confirmed the MRIL analysis.
Note the difference between the TDA and TDA/MRIAN results in the MRIL log presentation. The TDA shows that the free fluids include both light oil and water, whereas the TDA/MRIAN results show that all of the free fluids are hydrocarbons. This apparent discrepancy is simply due to the different depth of investigation of the various logging measurements. TDA saturation reflects the flushed-zone as seen by MRIL measurement. The TDA/MRIAN combination saturation reflects the virgin zone as seen by deep-resistivity measurements. Because water-based mud was used in this well, some of the movable hydrocarbons were displaced in the invaded zone by the filtrate from the water-based mud.
EVALUATION OF RESERVOIR PRODUCIBILITY USING
SCHLUMBERGER’S CMR TOOL
In this example, we see how Schlumberger’s CMR data were integrated with conventional logging and pressure data to differentiate between gas, oil, and tar within a complex reservoir.
S
ETTING
This well was drilled with oil-base mud in eastern Venezuela. In this reservoir, the Operator needed to identify gas, oil and tar zones. The Operator chose a suite of logs which included Schlumberger’s CMR tool in order to successfully determine the producibility of each zone within the reservoir.
CMR Answers
Figure 3
The CMR-MDT log helped to sharply define the fluid types inferred by the density-neutron data. The CMR and density-neutron data confirmed gas in Zones A and H. The other zones had no density-neutron crossover (interpreted as oil), but several zones had a CMR porosity deficit (identified by the blue shading on the log example). The CMR porosity deficit, as compared to the density-neutron porosity, was attributed to the presence of tar in Zones B, D, E, F and I. The resistivity log showed no contrast between the tar and hydrocarbon zones in this oil-base mud environment.
The MDT pressure points independently confirmed the presence of tar. All four pressure tests attempted within the tar zones produced dry test results. In contrast, all pressure points attempted in the gas or light-oil zones produced good pressure and mobility readings. The CMR-MDT data, together with the triple combo data provided a conclusive petrophysical analysis of this complex gas, oil and tar system.
I
MPROVED
T
ESTING
E
FFICIENCY
WITH
S
CHLUMBERGER
’
S
CMR
T
OOL
This example shows how Schlumberger’s CMR tool was used to identify zones for further testing.
Setting
The Operator was drilling a well in waters offshore of China. Previous logs within this reservoir showed an unconsolidated shaly sand formation with little variation in the resistivity and density-neutron porosity curves. Pressure testing had proven problematic in the past.
CMR Answers
The Operator chose to run a CMR tool in order to define permeable zones that would merit further testing (Figure 4: MDT Test zone identification).
Figure 4
The CMR bound and free-fluid porosity curves showed good definition, and easily identified the more permeable intervals. The MDT points were selected on the basis of the higher permeability areas (low bound-fluid volume), thereby avoiding the low-permeability zones and potential probe plugging.
Six successful pressure tests were obtained, and three samples were recovered in an environment where MDT testing had previously been quite troublesome.
GLOSSARY OF TERMS
Activation
Programmed command sequences that control how MRIL tools polarize formations and measure NMR properties of those formations. Activations may contain single or multiple CPMG sequences.
Activation, Dual-TE
An activation that enables the acquisition of two CPMG echo trains at different echo spacings (TE) but at identical re-polarization times (TW). Data acquired with dual-TE activations are used for hydrocarbon identification, and this activation has been successfully used in detecting and quantifying medium-viscosity oils.. The hydrocarbon identification technique takes advantage of
the different diffusivities of the various reservoir fluids. Because the MRIL tool produces a magnetic field gradient, the T2 of each fluid has a component that depends on its diffusivity T2D,
and on the TE used in the NMR measurements. Increases in TE will shift the T2 spectrum toward
smaller T2 values, and the shift will be different for each fluid type. Separation in T2 space follows
from 12 ) ( G TE 2 D
.Activation, Dual-TW
An activation that enables the acquisition of two CPMG echo trains at different wait times (TW) and identical echo spacings (TE). Data acquired with dual-TW activations are used to improve detection of gas and light oils. This detection is based on the fact that the T1 of gas and light oils is
much larger than the T1 of water in a formation.
Polarization p is proportional to TW, i.e., 1
TW
1
e
Tp
.The smaller TW is chosen such that the NMR signal from the formation water is completely polarized, but the oil and/or gas signals are not. The longer TW is chosen so that most of the hydrocarbon signals are also polarized. The signal left after the subtraction of the two echo trains or the two resulting T2 distributions contains only signal from the hydrocarbon. This method can be
used to quantify oil and gas volumes when the T1 values of oil and gas are known.
Activation, Standard-T
2An activation that enables the acquisition of a CPMG echo train with a TW with which formation fluids can be fully polarized, and with a TE with which the diffusion effects on T2 can be eliminated.
Typical values for this activation are TE = 1.2 ms, 3 s TW 6 s, and
NE = 300. This activation is mainly used for determining "effective" porosity and permeability.
Activation, Total-Porosity
An activation that enables the acquisition of two CPMG echo trains with different echo spacings (TE) and different wait times (TW). One echo train is acquired with TE = 0.6 ms and TW = 20 ms (only partial polarization is achieved) and is used for quantifying the small pores which are at least in part associated with clay-bound water. The other echo train is acquired with TE = 0.9 or 1.2 ms and with a TW that is sufficiently long so that full polarization is achieved. This echo train is used to determine effective porosity, and the summation of the two porosities (clay-bound and effective) provides total porosity information. The combination of TE and TW used to acquire the latter echo train constitutes a Standard T2 activation.
B
0Static magnetic field generated by the NMR tool. It may also be designated as Bz.
B
1Oscillating magnetic field generated by a radio-frequency (RF) resonant circuit. This field is applied in the plane perpendicular to B0 and is used to flip the magnetization by 90 and 180.
BFV
CMR Bound fluid volume
Bound Water
A somewhat loosely defined term that can refer either to water that is not producible or to water that is not displaceable by hydrocarbons. Bound water is defined in many references as water that has become adsorbed on the surface of solid particles or grains. Under natural conditions, this water is viscous-like and immobile, but might not have lost its electrolytic properties. Bound water consists of both capillary-bound water and clay-bound water.
