Electricity: measuring and testing – Particle precession resonance – Using well logging device
Reexamination Certificate
2001-09-10
2003-03-04
Arana, Louis (Department: 2862)
Electricity: measuring and testing
Particle precession resonance
Using well logging device
C324S306000
Reexamination Certificate
active
06528995
ABSTRACT:
FIELD OF THE INVENTION
This invention relates to the field of well logging of earth wellbores and, more particularly, to methods for measuring flow velocity in an earth formation with nuclear magnetic resonance techniques and for using the measured flow velocity to determine various other important well logging parameters.
BACKGROUND OF THE INVENTION
Well logging provides various parameters that may be used to determine the “quality” of a formation from a given wellbore. These parameters include such factors as: formation pressure, resistivity, porosity, bound fluid volume and hydraulic permeability. These parameters, which are used to evaluate the quality of a given formation, may provide, for example, the amount of hydrocarbons present within the formation, as well as an indication as to the difficulty in extracting those hydrocarbons from the formation. Hydraulic permeability—how easily the hydrocarbons will flow through the pores of the formation—is therefore, an important factor in determining whether a specific well site is commercially viable.
There are various known techniques for determining hydraulic permeability, as well as other well logging parameters. For example, it is known how to derive permeability from nuclear magnetic resonance (NMR) measurements. NMR measurements, in general, are accomplished by causing the magnetic moments of nuclei in a formation to precess about an axis. The axis about which the nuclei precess may be established by applying a strong, polarizing, static magnetic field (BO) to the formation, such as through the use of permanent magnets (i.e., polarization). This field causes the proton spins to align in a direction parallel to the applied field (this step, which is sometimes referred to as longitudinal magnetization, results in the nuclei being “polarized”). Polarization does not occur immediately, but instead grows in accordance with a time constant T
1
, as described more fully below, and may take as long as several seconds to occur (even up to about eight seconds or longer). After sufficient time, a thermal equilibrium polarization parallel to B
0
has been established.
Next, a series of radio frequency (RF) pulses are produced so that an oscillating magnetic field B
1
, is applied. The first RF pulse (referred to as the 90° pulse) must be strong enough to rotate the magnetization from B
0
substantially into the transverse plane (i.e., transverse magnetization). The rotation angle is given by:
&agr;=
B
1
&ggr;t
p
(1)
and is adjusted, by methods known to those skilled in the art, to be 90° (where t
p
is the pulse length and &ggr; is the gyromagnetic ratio—a nuclear constant). Additional RF pulses (referred to as 180° pulses where &agr;=180°) are applied to create a series of spin echoes. The additional RF pulses typically are applied in accordance with a pulse sequence, such as the error-correcting CPMG (Carr-Purcell-Meiboom-Gill) NMR pulse sequence, to facilitate rapid and accurate data collection. The frequency of the RF pulses is chosen to excite specific nuclear spins in the particular region of the sample that is being investigated. The rotation angles of the RF pulses are adjusted to be 90° and 180° in the center of this region.
Two time constants are associated with the relaxation process of the longitudinal and transverse magnetization. These time constants characterize the rate of return to thermal equilibrium of the magnetization components following the application of each 90° pulse. The spin-lattice relaxation time (T
1
) is the time constant for the longitudinal magnetization component to return to its thermal equilibrium (after the application of the static magnetic field). The spin-spin relaxation time (T
2
) is the time constant for the transverse magnetization to return to its thermal equilibrium value which is zero. Typically, T
2
distributions are measured using a pulse sequence such as the CMPG pulse sequence described above. In addition, B
0
is typically inhomogeneous and the transverse magnetization decays with the shorter time constant T
2
*, where:
1
T
2
*
=
1
T
2
+
1
T
′
(
2
)
In the absence of motion and diffusion, the decay with characteristic time T′ is due to B
0
inhomogeneities alone. In this case, it is completely reversible and can be recovered in successive echoes. The amplitudes of successive echoes decay with T
2
. Upon obtaining the T
2
distributions, other formation characteristics, such as permeability, may be determined.
A potential problem with the T
2
distributions may occur if the echo decays faster than predicted, for example, if motion of the measuring probe occurs during measurements. Under these conditions, the resultant data may be degraded. Thus, for example, displacement of the measurement device due to fast logging speed, rough wellbore conditions or vibrations of the drill string during logging-while-drilling (LWD) may prevent accurate measurements from being obtained.
Moreover, it also is known that T
2
distributions do not always accurately represent pore size. For example, G.R. Coates et al., “A New Characterization of Bulk-Volume Irreducible Using Magnetic Resonance,” SPWLA 38th Annual Logging Symposium, Jun. 15-18, 1997, describes the measurement of bound fluid volume by relating each relaxation time to a specific fraction of capillary bound water. This method assumes that each pore size has an inherent irreducible water saturation (i.e., regardless of pore size, some water will always be trapped within the pores). In addition, the presence of hydrocarbons in water wet rocks changes the correlation between the T
2
distribution and pore size.
Hydraulic permeability of the formation is one of the most important characteristics of a hydrocarbon reservoir and one of the most difficult quantitative measurements to obtain. Often permeability is derived from T
2
distributions, created from NMR experiments, which represent pore size distributions. Finally, permeability is related to the T
2
data. This way to determine permeability has several drawbacks and is therefore sometimes inapplicable.
Typically T
2
distributions are measured using the error-correcting CPMG pulse sequence. In order to provide meaningful results, the length of the recorded echo train must be at least T
2
max
. During this time period, as well as during the preceding prepolarization period, the measurement is sensitive to displacements of the measuring device. Further, in some cases, the T
2
distributions do not represent pore size distributions, e.g., hydrocarbons in water wet rocks change the correlation between T
2
distribution and pore size distribution. Finally, the correlation between pore size distribution and permeability of the formation is achieved using several phenomenological formulae that are based on large measured data sets, displaying relatively weak correlation. In carbonates, these formulae breakdown because of the formations' complex pore shapes.
A more direct way to measure permeability is by measurements of induced flow rates using a packer or probe tool. Still, this measurement requires extensive modeling of the formation response which includes the geometry of the reservoir and of the tool, the mud cake, and the invasion zone. The effort required for modeling however, could be significantly reduced if flow velocity could be obtained. It would be advantageous to obtain flow velocity, which could be used to determine various parameters required for modeling so that the number of variables required for modeling is reduced.
For at least the foregoing reasons, it is an object of the present invention to provide apparatus and methods for determining flow velocity utilizing NMR techniques.
It is a still further object of the present invention to provide methods for determining permeability utilizing NMR measurements of flow velocity.
It is an even further object of the present invention to provide methods for determining the extent of drilling damage to the formation, formation pressure, mud filtration rate and changes in the invaded zone duri
Poitzsch Martin
Pop Julian
Speier Peter
Arana Louis
Jeffery Brigitte L.
McEnaney Kevin P.
Schlumberger Technology Corporation
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