Electricity: measuring and testing – Particle precession resonance – Using well logging device
Reexamination Certificate
2001-06-05
2003-01-28
Arana, Louis (Department: 2862)
Electricity: measuring and testing
Particle precession resonance
Using well logging device
Reexamination Certificate
active
06512371
ABSTRACT:
BACKGROUND OF THE INVENTION
The present invention relates to nuclear magnetic resonance (NMR) logging and is directed more specifically to a system and method for detecting the presence and estimating the quantity of gaseous and liquid hydrocarbons in the near wellbore zone.
Petrophysical parameters of a geologic formation which are typically used to determine whether the formation will produce viable amounts of hydrocarbons include the formation porosity PHI, fluid saturation S, the volume of the formation, and its permeability K. Formation porosity is the pore volume per unit volume of formation; it is the fraction of the total volume of a sample that is occupied by pores or voids. The saturation S of a formation is the fraction of a its pore volume occupied by the fluid of interest. Thus, water saturation S
W
is the fraction of the pore volume which contains water. The water saturation of a formation can vary from 100% to a small value which cannot be displaced by oil, and is referred to as irreducible water saturation S
Wirr
. For practical purposes it can be assumed that the oil or hydrocarbon saturation of the formation S
O
is equal to S
O
=1−S
W
. Obviously, if the formation's pore space is completely filled with water, that is if S
W
=1, such a formation is of no interest for the purposes of an oil search. On the other hand, if the formation is at S
Wirr
it will produce all hydrocarbons and no water. Finally, the permeability K of a formation is a measure of the ease with which fluids can flow through the formation, i.e., its producibility.
Nuclear magnetic resonance (NMR) logging is among the most important methods which have been developed to determine these and other parameters of interest for a geologic formation and clearly has the potential to become the measurement of choice for determining formation porosity. At least in part this is due to the fact that unlike nuclear porosity logs, the NMR measurement is environmentally safe and is unaffected by variations in matrix mineralogy. The NMR logging method is based on the observation that when an assembly of magnetic moments, such as those of hydrogen nuclei, are exposed to a static magnetic field they tend to align along the direction of the magnetic field, resulting in bulk magnetization. The rate at which equilibrium is established in such bulk magnetization upon provision of a static magnetic field is characterized by the parameter T
1
, known as the spin-lattice relaxation time. Another related and frequently used NMR logging parameter is the so called spin-spin relaxation time constant T
2
(also known as transverse relaxation time) which is an expression of the relaxation due to non-homogeneities in the local magnetic field over the sensing volume of the logging tool.
Another measurement parameter used in NMR well logging is the formation diffusion D. Generally, diffusion refers to the motion of atoms in a gaseous or liquid state due to their thermal energy. The diffusion parameter D is dependent on the pore sizes of the formation and offers much promise as a separate permeability indicator. In an uniform magnetic field, diffusion has little effect on the decay rate of the measured NMR echoes. In a gradient magnetic field, however, diffusion causes atoms to move from their original positions to new ones, which moves also cause these atoms to acquire a different phase shifts compared to atoms that did not move, and will thus contribute to a faster rate of relaxation. Therefore, in a gradient magnetic field diffusion is a logging parameter which can provide independent information about the structure of the geologic formation of interest, the properties of the fluids in it, and their interaction.
It has been observed that the mechanisms which determine the values of T
1
, T
2
and D depend on the molecular dynamics of the sample being tested. In bulk volume liquids, typically found in large pores of the formation, molecular dynamics is a function of molecular size and inter-molecular interactions which are different for each fluid. Thus, water, gas and different types of oil each have different T
1
, T
2
and D values. On the other hand, molecular dynamics in a heterogeneous media, such as a porous solid which contains liquid in its pores, differs significantly from the dynamics of the bulk liquid and generally depends on the mechanism of interaction between the liquid and the pores of the solid media. It will thus be appreciated that a correct interpretation of the measurement parameters T
1
, T
2
and D can provide valuable information relating to the types of fluids involved, the structure of the formation and other well logging parameters of interest.
On the basis of the T
2
spectra, two specific methods for gas measurements are known in the prior art and will be considered briefly next to provide relevant background information. The first method is entitled “differential spectrum method” (DSM). The DSM is based on the observation that often light oil and natural gas exhibit distinctly separated T
2
measurements in the presence of a magnetic field gradient, even though they may have overlapping T
1
measurement values. Also, it has been observed that brine and water have distinctly different T
1
measurements, even though their D
0
values may overlap. The DSM makes use of these observations and is illustrated in
FIG. 1
in a specific example for a sandstone reservoir containing brine, light oil and gas.
A second method known in the art is called “shifted spectrum method” (SSM). The SSM is illustrated in
FIGS. 2A-B
. Specifically,
FIG. 2A
shows synthetic T
2
decay curves in a gas bearing zone. The solid curve is for the short interecho time (≈0.6 msec) and the dashed curve corresponds to a longer interecho time of about 2.4 msec.
FIG. 2B
illustrates the T
2
spectra obtained from the inversion of the synthetic echo trains in FIG.
2
A. The solid spectrum corresponds to the shorter interecho time, while the dashed spectrum line corresponds to the longer interecho time. In
FIG. 2B
the solid spectrum line corresponds to both brine and gas. The signal from gas is shifted out of the detectability range, so that the single spectrum peak is due to brine.
While prior art DSM and SSM methods provide a possible working approach to detection of gas using solely NMR data, the methods also have serious disadvantages which diminish their utility in practical applications. Specifically, typically two separate logging passes are required and therefore the methods show relatively poor depth matching properties on repeat runs. Furthermore, subtraction of signals from different logging passes is done in the T
2
spectrum domain which may result in losing valuable information in the transformation process, especially when the received signals have low signal-to-noise ratios (SNRs). In fact, for a typical logging pass, low hydrocarbon index (HI) of the gases in the formation, and relatively long T
1
times generally lead to low SNR of the received signals. After transformation into the T
2
spectrum domain even more information can be lost, thus reducing the accuracy of the desired parameter estimates.
In the parent application Ser. No. 08/822,567 filed Mar. 19, 1997, which is incorporated herein by reference for all purposes, a well logging system and method are disclosed for detecting the presence and estimating the quantity of gaseous and liquid hydrocarbons in the near wellbore zone. The approach presented in this application effectively addresses some of the concerns associated with prior art DSM and SSM methods. In particular, the proposed system uses a gradient-based, multiple-frequency NMR logging tool to extract signal components characteristic for each type of hydrocarbons. To this end, a data acquisition method is proposed in which measurements at different frequencies are interleaved to obtain, in a single logging pass, multiple data streams corresponding to different recovery times and/or diffusivity for the same spot in the formation. The resultant data streams are proce
Arana Louis
Bennie & Edmonds LLP
Halliburton Energy Service,s Inc.
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