Electricity: measuring and testing – Of geophysical surface or subsurface in situ – With radiant energy or nonconductive-type transmitter
Reexamination Certificate
2002-09-09
2004-11-23
Patidar, Jay (Department: 2862)
Electricity: measuring and testing
Of geophysical surface or subsurface in situ
With radiant energy or nonconductive-type transmitter
Reexamination Certificate
active
06822455
ABSTRACT:
BACKGROUND OF THE INVENTION
This invention relates to the field of well logging. More specifically, the invention relates to a novel apparatus and technique for measuring the resistivity of geologic formations surrounding a borehole during well logging and logging while drilling operations.
Formation resistivity is commonly used to evaluate geologic formations surrounding a borehole. Formation resistivity indicates the presence of hydrocarbons in the geologic formations. Porous formations having high resistivity generally indicate that they are predominantly saturated with hydrocarbons, while porous formations with low resistivity indicate that such formations are predominantly saturated with water. “Borehole rugosity” refers to borehole irregularities created by washouts, caves or other borehole wall features which deviate from a smooth borehole wall surface.
Devices have been previously developed for measuring formation resistivity. Many of these devices measure formation resistivity by measuring the properties of propagating electromagnetic waves. For example,
FIG. 1
shows an early generation, uncompensated propagation wave resistivity tool comprising one transmitter and two receivers for measuring the properties of an electromagnetic wave over two propagation paths. Property P
11
represents an electromagnetic propagation property for the propagation path from transmitter (Tx) to a first receiver (Rx1), and P
12
represents the same electromagnetic propagation property as used for P
11
but for the propagation path from the transmitter to a second receiver (Rx2). Typically the propagation properties measured are attenuation and phase. A differential measurement (M) is formed by taking the difference between P
12
and P
11
. This difference allows any errors related to the transmitter elements of the system to be removed from the final measurement (M). The measurement (M) is then converted to formation resistivity (R) via function (ƒ) which provides the relationship between the differential propagation property (M) and the resistivity of the surrounding formation.
FIG. 2
illustrates another propagation wave resistivity tool described in U.S. Pat. No. 4,949,045 to Clark et al. (1990) and in U.S. Pat. No. 4,968,940 to Clark et al. (1990). This tool provided improved measurement accuracy and reduced sensitivity to the effects of borehole irregularities when compared to the “uncompensated” tool shown in FIG.
1
. Such tool comprised two transmitters and a receiver pair located between the two transmitters and is known as a borehole compensated tool. M
U
represents the differential measurement for the upward propagating electromagnetic wave from transmitter (Tx1) and M
D
represents the differential measurement for the downward propagating electromagnetic wave from transmitter (Tx2). A borehole compensated measurement M
BHC
can be calculated by averaging the upward propagating measurement, M
U
, and the downward propagating measurement, M
D
. The formation resistivity is determined in a fashion similar to the uncompensated tool by converting propagation property (M
BHC
) to resistivity with function (ƒ). By averaging the measurements from the upward and downward propagating electromagnetic waves, the effects of borehole rugosity on the measured formation resistivity can be reduced. This average also removes errors corresponding to the two receiver elements of the system, Rx1 and Rx2. Like the uncompensated device, the borehole compensated device also eliminates the errors related to the transmitting elements of the system by using differential receiver measurements, M
U
and M
D
.
Although borehole compensated tools provide a more accurate measurement of formation resistivity than conventional uncompensated tools, such technique requires a tool approximately twice as long as an uncompensated tool. Tool length for an uncompensated tool with a single radial depth of investigation is directly related to the spacing between the transmitter and receiver pair. Longer spacings between the transmitter and receiver pair provide greater depth of investigation than shorter spacings and require a longer tool body accordingly. The tool length for a borehole compensated tool as described in patents '045 and '940 with an equivalent radial depth of investigation as an uncompensated tool will be approximately twice as long because of the requirement of both upper and lower transmitter elements.
Another compensated tool was described in U.S. Pat. No. 5,594,343 to Clark et al. (1997) wherein the transmitters were asymmetrically located on both sides of a receiver pair. Similar to the '045 and '940 patents previously described, such tool also required placement of at least one transmitter on each side of the receiver pair and also required a long tool body.
The compensated tools described above require a long tool body in the borehole to correctly position the transmitters and receivers. Long well tools not only require additional material and greater manufacturing cost but are more likely to bind or stick in narrow or deviated boreholes. This problem is particularly acute in multilateral wellbores having a reduced entry radius and in highly deviated wellbores. Accordingly, a need exists for an improved system capable of facilitating tool movement within a wellbore while gathering useful information regarding geologic formation characteristics such as resistivity and other geologic formation indicators.
SUMMARY OF THE INVENTION
The invention provides a system for evaluating a geologic formation property proximate to a borehole through such formation. The system comprises a tool body moveable through the borehole, a first transmitter engaged with the tool body for generating a signal into the geologic formation, a second transmitter engaged with the tool body proximate to the first transmitter for generating a signal into the geologic formation, a first receiver engaged with the tool body for receiving signals generated by the first and second transmitters, and a second receiver engaged with the tool body proximate to the first receiver for receiving signals generated by the first and second transmitters.
Another embodiment of the invention provides an apparatus comprising a tool body moveable through the borehole, a first transmitter engaged with the tool body for generating an electromagnetic wave into the geologic formation, a second transmitter engaged with the tool body proximate to the first transmitter for generating an electromagnetic wave into the geologic formation, a first receiver engaged with the tool body for receiving electromagnetic wave energy generated by the first and second transmitters and for generating electrical signals representing the electromagnetic wave energy, a second receiver engaged with the tool body proximate to the first receiver for receiving electromagnetic wave energy generated by the first and second transmitters and for generating electrical signals representing the electromagnetic wave energy, and a controller for processing the electrical signals generated by the first and second receivers.
The method of the invention comprises the steps of deploying a tool body in the borehole, of generating electromagnetic wave energy from the first transmitter at a selected location in the borehole, of generating electromagnetic wave energy from the second transmitter at a selected location in the borehole, of operating the first and second receivers in response to the electromagnetic waver energy generated by the first and second transmitters to generate electrical signals representing the electromagnetic waveenergy, and of transmitting said electrical signals to the controller.
REFERENCES:
patent: 4451789 (1984-05-01), Meador
patent: 4609873 (1986-09-01), Cox et al.
patent: 4949045 (1990-08-01), Clark et al.
patent: 4968940 (1990-11-01), Clark et al.
patent: 5594343 (1997-01-01), Clark et al.
patent: 6184685 (2001-02-01), Paulk et al.
patent: 6304086 (2001-10-01), Minerbo et al.
patent: 6353321 (2002-03-01), Bittar
patent: 6476609 (
Domingue & Waddell PLC
Patidar Jay
Ultima Labs, Inc.
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