Measuring and testing – Volume or rate of flow – Of selected fluid mixture component
Reexamination Certificate
1998-08-28
2001-05-22
Fuller, Benjamin H. (Department: 2855)
Measuring and testing
Volume or rate of flow
Of selected fluid mixture component
C073S195000, C073S200000, C073S061440
Reexamination Certificate
active
06234030
ABSTRACT:
BACKGROUND AND SUMMARY OF THE INVENTION
The present invention relates generally to multiphase metering and multiphase flow, and more particularly, to a method for handling oil, gas and water flow during petroleum production.
The word Petroleum means “rock oil” or “oil from rocks”. Oil and gas begins to form as part of a biogenic decay process which happens under a variety of geologic circumstances that usually involve anaerobic conditions. Plankton, or other higher forms of life die and are deposited in marine basins, to be covered by the soft muds that are formed there. These are subsequently overlain with other types of deposits, sequentially building up, much in the manner observed today near the outlets of the Texas rivers where they meet the waters of the Gulf.
As these source beds compact over geologic time, the ancient sea water along with the oil and gas move into overlaying formations that are more porous, such as sandstones. If hard limestones have formed, and subsequently have fractured, these fluids can also find their way into these fissures and cracks and into the vugular cavities that may be present. Eventually these fluids collect and redistribute themselves within these porous formations, with water tending to collect near the base and the gas moving upward toward the cap. Natural seals formed by the base rock and cap rocks (dense limestones or shales usually, sometimes salt plugs), serve to trap these fluids, and may allow pressures to build up as more gas forms, or as the reservoir rocks themselves compress from additional weight of the overmass. (See
FIG. 1.1
)
Petroleum production starts when man drills into one of these porous sections and encounters sufficient oil and or gas under conditions that will permit commercial exploitation. Tests are performed on the exploratory wells that encounter the formation, and logs are run to help evaluate the find.
“Development” wells are next. These wells are drilled from land sites or from platforms and usually are started with a large diameter hole, into which 20 inch or 16 inch casing is run and cemented. The cementing process is used to bond the casing to the rock and to form a seal. During drilling the blow out preventors (BOPs) are bolted and sealed to the top assembly of this casing system, known as the wellhead. The wellhead together with the surface string forms the support for the subsequent casing strings that will be set in the well as it is drilled to greater depths.
Each intermediate casing string (e.g.; 13 ⅜ths, 9 ⅝ths) is hung from the wellhead (according to the drilling program of the well), where it is sealed, and then cemented through the shoe joint on the bottom to seal off the string. (Refer to
FIG. 1.2
.) A smaller bit is then used to drill out through the shoe into deeper zones, and is followed by the next casing string, etc. The driller logs (and may take samples) in the open hole of each new sequence before setting casing, using a logging service. Mud logs (a continuous report on drilling progress based on examination of the mud and cuttings circulating out of the hole during drilling) are often kept. The production string of casing is the final string run, and when it is in place and cemented, the well is ready for completion.
The term “completion” encompasses a number of methods that determine how the well will communicate with the producing intervals is penetrated. This can range from “barefoot” or open hole completions, to hung liners, to perforated casing, and nowadays may include drilling one or more laterals into the formation for horizontal completions. The basic idea is to maximize the capability of the well to produce hydrocarbons without the side effects of producing water and sand, and to minimize the production of the gas cap (gas already present in the reservoir).
Included in the completion scheme is the tubing string and any downhole pumping or gas injection methods. Tubing is run into the well through the production string of casing, and generally a packoff is set above the producing interval. If the well has enough pressure, it can produce by flowing through the tubing. The annulus between the tubing and the casing is usually dry or may be filled with a fluid, such as water. If it cannot flow, then some form of down hole pumping or gas injection can be used to assist production.
The tubing string is suspended from the tubing hanger (or tubing head) located above the wellhead and bolted and sealed to it. The BOP is removed and replaced by the Christmas tree, which is the combination of valves assembled together to provide surface shut off control to the tubing, to the casing annulus, and to the flow line connected to the tree. Gages are included in this assembly to indicate the pressure and temperature conditions of the flow coming through the tree and to monitor the casing annulus pressure. (Refer to
FIG. 1.3
.)
The production from the tree is sent through a choke into a flow line, which is connected to a gathering manifold, often called the production manifold, well battery, trap farm, etc. (local jargon may prevail here). It enters this manifold through a shut off valve, and has an alternate flow line connected through another valve to a test manifold. This means the flow from the well can either go directly into the production processing equipment, or flow to this equipment via a testing device. See
FIG. 1.4
that depicts a well testing schematic at a gathering center.
The most common testing device is the test separator, a device that is operated to more or less mimic the pressure and temperature conditions of the production separator. Its purpose is to provide information about the productivity of an individual well and to record the amount of oil, gas, and water that well is extracting from the reservoir. Other testing schemes include strapping tanks (calibrated tanks) and sampling systems for water cut draw offs. The newest type of well tester is the multiphase flow meter.
This test data (after allocation as explained below) is maintained and accumulated for each well over the life of the well. It is also reported (usually a legal requirement) on a monthly basis to a governmental agency. The production quantities and overall trends are used by reservoir engineers and production geologists to identify new prospects for development or to design enhanced recovery programs (such as waterflooding). They are also interested in short term, daily or hourly test data to evaluate the productivity of the formation at the well bore interface. This production data may be augmented from time to time with pressure data taken from the well. Of particular interest is a pressure build-up vs time survey taken by shutting in the well with a pressure “bomb” (i.e., recorder) hung in the well. It is a very unpopular practice from the viewpoint of production people as it reduces production income and has the risk that the well may not come back fully to its pre-test productivity. With the advent of multiphase metering is offered a new approach where a flowing well is sequentially reduced in its production (choked back) in four steps. The key is to know when the production has stabilized after each step has been made (which is provided by the minute to minute data of the multiphase meter). In this way, without shutting in the well, the same type of data needed for the reservoir engineer to calculate permeability, well bore damage (the “skin effect”), boundary proximity's, and other information important to reservoir management and workover planning can be obtained.
The production engineers are also interested in the well's production data, but more from the standpoint of evaluating the mechanical condition of the well, and the efficiency of the operation of the equipment used for production (the type of pump, the condition of the packoffs, size of tubing, monitoring for paraffin deposits and build up, tubing leaks, surging, etc.). The overall production data will determine if the well is economic (i.e., paying for itself) whereas the trending data (day-by-day from se
Fuller Benjamin H.
Patel Jagdish
Rosewood Equipment Company
Standley & Gilcrest LLP
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