X-ray or gamma ray systems or devices – Specific application – Fluorescence
Reexamination Certificate
2000-10-04
2002-01-01
Kim, Robert H. (Department: 2882)
X-ray or gamma ray systems or devices
Specific application
Fluorescence
C250S356100, C073S061440, C378S047000, C378S050000
Reexamination Certificate
active
06335959
ABSTRACT:
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
Not applicable.
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention generally relates to an apparatus and method for characterizing multiphase oil well effluents, typically comprising water, crude oil and gas, using measurements associated with the fluid mixture. More particularly, the present invention relates to an apparatus for measuring multiple energy gamma ray attenuations through the effluent mixture and a method for determining the effluent phase volume fractions of water, oil and gas from these measurements. Still more particularly, a preferred embodiment of the present invention relates to an apparatus and method for determining effluent phase volume fractions for an inhomogeneous flow condition using the gamma ray attenuation measurements.
2. Background of the Invention
Advances in petroleum drilling and production technology make it possible to economically explore and produce oil and gas in areas that were previously inaccessible, such as deepwater offshore fields. New technologies also provide opportunities to maximize oil and gas recoveries from existing offshore and onshore reservoirs. Producing these fields economically requires optimized production methods, improved production allocations, enhanced reservoir management, and accurate pipeline measurement. To accomplish these objectives, producers and pipeline operators must determine, as accurately as possible, oil well effluent characteristics.
Oil well effluents are multiphase fluids typically comprising water, oil and gas phases. Total mixture flow rate, component phase flow rates, and effluent composition (i.e. the phase volume fractions of water, oil and gas) are all important to producers and pipeline operators. By evaluating these characteristics, a producer can take corrective action when necessary to optimize production operations over the life of the field and thereby enhance reservoir management. Once an oil well effluent is produced, it is typically transported through pipelines to treating facilities. Knowledge of oil well characteristics is also critical in pipeline measurement applications for leak detection and custody transfer measurement purposes.
In practice, developing a method for accurately determining oil well effluent characteristics has been challenging due to the multiphase nature of the fluid and its varying flow conditions. As effluent is produced or transported, it is exposed to changing pressures, temperatures and pipe configurations that create inhomogeneous, unstable, and unpredictable flow patterns in the multiphase fluid. An especially problematic flow condition is the slug flow regime where phase stratification occurs causing the gas to come out of solution and form pockets apart from the liquid phase. As the effluent moves in the slug flow regime, gas and liquid sections alternate at varying frequencies, thereby affecting the accuracy of standard liquid flow meters designed to perform in single-phase liquids. The industry refers to the gas and liquid sections as either gas “slugs” and liquid “plugs” or gas “films” and liquid “slugs.” The former “slug and plug” industry nomenclature will be used herein.
The traditional oil industry practice for determining effluent characteristics has been to periodically divert the well output to a test separator to split the effluent into its component phases. Once the phases are separated, they are then measured independently using conventional orifice, positive displacement, or turbine meter devices as appropriate for the phase being measured. This operation has several inherent limitations. Separators are physically large, costly, and particularly ill-suited for use offshore where platform space is scarce and enlarging the platform can significantly increase capital costs. From a measurement standpoint, it is often impractical for each well to have a dedicated separator so several wells typically share a common separator making continuous well effluent monitoring impossible. Additionally, stabilized well flow is necessary for accurate measurement, and testing the effluent from just one well can take up to a whole day.
Over the past twenty years, various devices and techniques have been proposed for on-line multiphase fluid measurements that eliminate the need for separators. Most suggest a combination of measurement sensors for separately determining total flow rate and volume fractions of one or more of the phases.
U.S. Pat. No. 4,144,754, incorporated by reference herein for all purposes, describes one of the first multiphase meters. The apparatus comprises a flow loop and a gamma ray densitometer. The flow loop exerts centrifugal force on the fluid mixture that generates differential pressure on the fluid between the inner and outer walls of the loop. The densitometer measures the fluid mixture density. By correlating the differential pressure and density the total mixture flow rate can be determined. Wile this meter is applicable for fluids of unknown or varying density, it does not seem to accurately account for the “slip” phenomenon that occurs when the gas phase flow rate differs from the mixture flow rate. To resolve this problem, mixing devices may be added upstream of the flow meter to homogenize the flow and equalize flow velocities; however this solution adds to the capital costs and increases the required space for the measurement equipment.
U.S. Pat. No. 4,282,760, incorporated herein for all purposes, describes a method for improved measurement accuracy that accounts for the slip phenomenon and determines liquid (oil and water) and gas mass flow rates. The method makes use of multiple densitometers to measure mixture, liquid and gas densities and correlate those measurements with differential pressure to determine total, liquid and gas phase mass flow rates. Although improving measurement accuracy, more equipment is required, thereby adding to the complexity and cost.
Since the early days of multiphase measurement, numerous methods for accomplishing accurate measurement have been proposed, including capacitance techniques, reflection or scatter techniques, and transmission techniques based on measurements of neutrons, infrared, ultrasonics, microwaves, or gamma rays. U.S. Pat. No. 5,591,922, incorporated herein for all purposes, describes a method and apparatus for determining multiphase effluent phase proportions and mass flow rates for the mixture and for each component phase. The apparatus comprises a Venturi and a device for measuring gamma ray or X-ray attenuation at three different energy levels correlating with and proportional to each effluent phase to be measured. A low absorption window may be incorporated into the Venturi section of the pipeline to increase the transmission of radiation through the crude oil, and a gas-charged, proportional counter tube detector is used to measure gamma ray attenuation.
Several advances and improvements have been made over the basic Venturi and gamma ray source/detector apparatus and method. PCT Application EP94/01320, the contents of which are incorporated by reference for all purposes, discloses an improvement to the apparatus gamma ray window by employing a lining of carbon fiber reinforced resin (CFRE) within the meter conduit. The lining forms a window with the advantages of low radiation absorption while allowing relatively high internal pressures to be applied.
European Patent Specification EP 0,696,354 B1, the contents of which are incorporated by reference for all purposes, discloses an improvement to the gamma ray detector design by employing a dual area solid-state semiconductor diode detector for improved measurement accuracy in detecting both low and high-energy emission lines. Since detector efficiency is significantly lower at high-energy emission lines, the efficiency of the detector is improved by providing a solid state detector configuration with at least two radiation detecting surfaces. A filter is located between the radiation source and the first detecting surface to p
Lynch Frank Joseph
Miller Gary John
Conley & Rose & Tayon P.C.
Daniel Industries Inc.
Hobden Pamela R.
Kim Robert H.
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