Measuring and testing – Borehole or drilling – Fluid flow measuring or fluid analysis
Reexamination Certificate
2000-11-02
2002-11-05
Williams, Hezron (Department: 2856)
Measuring and testing
Borehole or drilling
Fluid flow measuring or fluid analysis
C073S152270, C073S152520, C073S152180, C175S041000, C175S050000, C166S250010, C250S255000
Reexamination Certificate
active
06474152
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to the analysis of downhole borehole fluids. More particularly, the present invention relates to apparatus and methods for the in situ determination of compressibility of hydrocarbon fluids in a geological formation.
2. State of the Art
Naturally occurring hydrocarbon fluids include a wide range of fluids including dry natural gas, wet gas, condensate, light oil, black oil, heavy oil, and heavy viscous tar. The physical properties of these various hydrocarbon fluids, such as density, viscosity, and compressibility vary considerably. In addition, the separation of each of the hydrocarbon fluid compositions into distinctly separate gas, liquid and solid phases, each with its own physical properties, occur at certain contours of pressure and temperature. This is referred to generally as the “phase behavior” of the hydrocarbon.
The economic value of a hydrocarbon reserve, the method of production, the efficiency of recovery, the design of production hardware systems, etc., all depend upon the physical properties and phase behavior of the reservoir hydrocarbon fluid. Hence, it is important that the fluid properties and phase behavior of the hydrocarbon be determined accurately following the discovery of the hydrocarbon reservoir, so that a decision of whether it is economically viable to develop the reservoir can be made; and if viable, an appropriate design and plan for the development of the reservoir can be adopted. With that in mind, those skilled in the art will appreciate that the ability to conduct an analysis of formation fluids downhole (in situ) is extremely desirable.
The assignee of this application has provided a commercially successful borehole tool, the MDT (a trademark of Schlumberger) which analyzes formation fluids in situ. The MDT extracts and analyzes a flow stream of fluid from a formation in a manner substantially as set forth in co-owned U.S. Pat. Nos. 3,859,851 and 3,780,575 to Urbanosky, as well as U.S. Pat. Nos. 4,860,581 and 4,936,139 to Zimmerman et al., which are hereby incorporated by reference herein in their entireties. The OFA (a trademark of Schlumberger), which is a module of the MDT, determines the identity of the fluids in the MDT flow stream and quantifies the oil and water content based on the previously incorporated related patents. In particular, previously incorporated U.S. Pat. No. 4,994,671 to Safinya et al. provides a borehole apparatus which includes a testing chamber, means for directing a sample of fluid into the chamber, a light source preferably emitting near infrared rays and visible light, a spectral detector, a data base means, and a processing means. Fluids drawn from the formation into the testing chamber are analyzed by directing the light at the fluids, detecting the spectrum of the transmitted and/or backscattered light, and processing the information accordingly in order to quantify the amount of water and oil in the fluid. As set forth in previously incorporated U.S. Pat. No. 5,266,800 to Mullins, by monitoring optical absorption spectrum of the fluid samples obtained over time, a determination can be made as to when a formation oil is being obtained as opposed to a mud filtrate. Thus, the formation oil can be properly analyzed and quantified by type. Further, as set forth in the previously incorporated U.S. Pat. No. 5,331,156 to Hines et al., by making optical density measurements of the fluid stream at certain predetermined energies, oil and water fractions of a two-phase fluid stream may be quantified.
The Safinya et al., Mullins, and Hines et al. patents represent great advances in downhole fluid analysis, and are particularly useful in the analysis of oils and water present in the formation. The issues of in situ gas quantification and analysis are addressed in the previously incorporated U.S. Pat. Nos. 5,167,149 to Mullins et al., 5,201,220 to Mullins et al., 5,859,430 to Mullins et al., 5,939,717 to Mullins, and in O.C. Mullins et al., “Effects of high pressure on the optical detection of gas by index-of-refraction methods”,
Applied Optics
, Vol. 33, No. 34, pp. 7963-7970 (Dec. 1, 1994). In particular, U.S. Pat. No. 5,859,430 to Mullins et al. discloses a method and apparatus for the downhole compositional analysis of formation gases which utilizes a flow diverter and spectrographic analysis. More particularly, the apparatus includes diverter means for diverting formation gas into a separate stream, and a separate gas analysis module for analyzing the formation gas in that stream. The methods and apparatus of the '647 application are useful in determining what types of gas are present in the formation fluid. U.S. Pat. No. 5,939,717 to Mullins, on the other hand, is directed to methods and apparatus for determining in situ gas-oil ratios (GOR) which are necessary for establishing the size and type of production facilities required for processing newly discovered oil.
Despite the large advances set forth above made in the downhole analysis and quantification of oil, gas, and water, and gas-oil ratios, additional information regarding physical properties of the hydrocarbons such as the hydrocarbon compressibility are desired. A determination of hydrocarbon compressibility is desirable for at least two reasons. First, as a result of production, the pressure of the reservoir fluid will be reduced. The extent of this reservoir pressure reduction is a function of compressibility, as fluids of large compressibility will maintain their pressure with modest production, whereas very incompressible fluids will suffer a significant pressure drop with modest production. The reduction in pressure results in a reduction in the rate of production, and possibly undesired phase transitions. It is important to be able to predict in advance of production the expected pressure behavior of the reservoir, and therefore, one must know the fluid compressibility.
Second, the compressibility can also be used to help determine the volume of the reservoir. In particular, a 3D seismic technique is often used to image the subsurface structure, and identify the compartment sizes and shapes in the formation. Then an amplitude versus offset (AVO) technique such as described in W. J. Ostrander, Geophysics, 49,1637 (1984) may be used within the 3D seismic technique to identify variations in the compressibility of fluid which is saturating the subsurface formations. A direct determination of compressibility, therefore, may be used to re-process the seismic data, and in this way, obtain (in other words, “back out”) an improved estimate of the size and shape of the hydrocarbon reservoir compartment.
Fluid compressibility is defined as the fractional change in volume that is associated with a change in pressure. Mathematically, compressibility &bgr; is defined according to:
β
=
-
1
V
(
∂
V
∂
P
)
T
(
1
)
where ∂V is a change of volume, V is an initial volume, ∂P is a change in pressure, and T is a constant and known temperature.
Various methods are presently known for determining the compressibility of formation fluids in situ. A sonic logging tool can measure the velocity of compressional and shear waves within the formation, and if the elastic properties of the rock matrix are known via other means, it may be possible to determine the compressibility of the saturating fluid from the measured velocities. See, for example, J. E. White, “Underground Sound”, Elsevier Publishing Co., New York (1983). However, the compressibility measurement obtained in this manner is “dynamic” and does not always yield reliable results. Also, borehole fluid testing tools such as the previously described MDT tool can be used to measure fluid compressibility by using a pressure gauge in conjunction with a known volumetric compression capacity. However, precise measurements of small volumetric changes are extremely difficult to obtain; especially downhole. In addition, the measurement of an extrinsic property such as volume requires certainty that all
Distefano Thomas
Kurkjian Andrew
McGowan Robin
Mullins Oliver C.
Traboulay Ian
Ryberg John
Salazar J.L. Jennie
Schlumberger Technology Corporation
Wiggins David J.
Williams Hezron
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