Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/01—Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
  • E21B17/20—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/06—Measuring temperature or pressure

Definitions

• the present invention relates to an apparatus for, and a method of, gathering parameters from a well flow. More particularly, it relates to an apparatus and a method for gathering parameters along a petroleum well path in order thus to be able to evaluate the flow, fluid phases and productivity or injectivity of the well.
• a familiar method is to install required sensors permanently along predetermined locations in the well path.
• the sensors communicate to the surface, for example to a rig, through one of, or a combination of, two or more of an electrical cable or a fibre cable.
• Data can also be communicated to the surface by means of wireless communication, or by means of so-called memory cards temporarily storing the gathered data in the well.
• Electricity for electronic sensors is provided by means of batteries, or by means of cable to an energy source at the surface .
• downhole monitoring is considered to represent a high degree of difficulty. This particularly applies to wells having well path angles between 65° and 95°.
• sensors may be inserted into the well after having been established.
• Coiled tubing has a tendency to "buckle”, i.e. it coils up and assumes the shape of a helical spring so as to stop, or it winds (becomes "helical"), i.e. the tubing assumes the shape of a helical spring so as not to stop.
• Buckle i.e. it coils up and assumes the shape of a helical spring so as to stop, or it winds (becomes "helical”
• the tubing assumes the shape of a helical spring so as not to stop.
• This is particularly a problem experienced upon repeated use of the coiled tubing.
• well tractors for coiled tubing have been developed.
• coiled tubing in the well will cause the effective pipe diameter to become reduced, and the production of the fluid to become slowed down due to increased friction between the production tubing and the coiled tubing. This friction results in the well not behaving in an optimum manner, and in some cases the result of the logging does not represent
• coiled tubing has a limited reach, insofar as there is a limit to how much coiled tubing may be reeled onto a drum to be used, for example, from a rig or a ship.
• Wireline requires a well tractor to push the logging tool in front of itself.
• a well tractor may also function as a throttle unit (choke) . In some cases, it has been produced out of a horizontal well as a consequence of the production rate being too high.
• Logging with a fibre cable is limited to the ability to measure temperature along the cable.
• flow can be measured only in permanently installed solutions in which fibre cables are used (and simultaneously are installed along the well path above the reservoir section) , and both pressure and flow must be measured to evaluate the productivity or injectivity of the well.
• the object of the invention is to remedy or reduce at least one of the disadvantages of the prior art.
• a measuring device is run into a desired portion of a well by means of a thin, rigid cable, hereinafter referred to as a semi-rigid rod.
• the well path may be both vertical and horizontal.
• the measuring devices are arranged for providing data for allowing estimation of the fluid phases oil, gas and water in the well flow, and to be able to provide data for allowing estimation of the productivity index, PI, or injectivity index, II, of the well.
• productivity index PI, or injectivity index II represents flow rate per day per unit of pressure, for example BBL/d/psi.
• the corresponding term for the injectivity index II will be injection rate per day per unit of pressure, for example BBL/D/psi.
• the sensors may include chemicals or so-called “tracers”, which are arranged for allowing detection and quantification of fluids downhole, and also other sensor types of a type known per se.
• the semirigid rod forms the logging unit for the temperature profile along the well.
• the flow rate of the well may be estimated.
• PCT application WO 2006/00347 describes a rod which has proven suitable for measuring DTS .
• pressure sensors are preferably integrated along the cable and are also placed at an end portion of a rigid fibre cable or a semi-rigid rod.
• the sensors DTS, pressure and fluid identification method are combined in order to replace conventional logging methods wherein physical sensors for temperature, pressure and flow are connected as a tool string at the end of a cable.
• the apparatus and method according to the present invention represent particularly great advantages in horizontal wells which otherwise cannot be logged with conventional logging tools .
• the cable is kept stationary during logging of a well under production/injection, or during logging of a shut-in well.
• a depth correlation tool may be used in connection with checking whether a rigid fibre cable or semi-rigid rod "buckles" or has become “helical” .
• an apparatus for use when gathering parameters from a well flow in a petroleum well for allowing evaluation of the flow and productivity or injectivity of the well including:
• At least one pressure sensor arranged in a manner allowing it to sense pressure in the well, whereby also the amounts of water, oil and gas from one or more formation sections may be quantified.
• water, oil and gas from more than two formation sections or zones may be quantified.
• the at least two mutually spaced- apart measuring devices and/or fluid phase indicators include one of, or a combination of, two or more of a sensor, a chemical or a trace element.
• the semi-rigid rod includes a fibre cable.
• the semi-rigid rod is of the type described in WO 2006/003477.
• the semi-rigid rod includes a plurality of spaced-apart pressure sensors.
• the apparatus includes an additional pressure sensor for compression-measuring of the end portion of the apparatus in the well .
• the additional pressure sensor is placed between the semi-rigid rod and a so-called "bull nose" placed at the end of the apparatus in the well.
• the main purpose of the bull nose is to guide the semi-rigid rod past sharp edges that may be present in a well, thereby functioning as a steering device for said rod.
• the apparatus is arranged in a manner allowing it to communicate measuring data through the fibre and out of the well while measuring is in progress.
• a method of gathering parameters from a well flow in a petroleum well for allowing evaluation of the flow and productivity or injectivity of the well includes the steps of: - inserting an apparatus to a desired portion of the well, the apparatus including:
• At least one pressure sensor arranged in a manner allowing it to sense pressure in the well; and - keeping the apparatus substantially stationary within the well during gathering of parameters from one or more formation sections in the well.
• the measuring results from the measuring devices and the semi-rigid rod are communicated to the surface for further processing.
• Elements liberated from a chemical or a trace element may be communicated to the surface in the same manner.
• Figure 1 shows a principle drawing of a well, in which 5 measuring devices have been inserted into the well by means of a semi-rigid rod, and in which the measuring devices are comprised of the semi-rigid rod and eight sensors;
• Figure 2a shows a graph illustrating the relationship betweeno flow, pressure and time in a fluid-producing well.
• Figure 2b shows a graph illustrating the relationship between flow, pressure and time in a fluid-injecting well.
• figure 1 is greatly distorted, and that the relative scales of thes different elements shown are incorrect.
• Figure 1 shows a principle drawing of a well 1, in which an apparatus 3 according to the present invention has been inserted into the well 1.
• the apparatus 3 includes a semi-rigid rod 5 ending up, at oneo end portion thereof, on a reel 7 outside the well 1, and ending up, at the other end portion thereof, at a bottom portion of the well 1.
• the semi-rigid rod 5 is of a self-straightening type. That is to say, when the semi-rigid rod 5 is inserted5 into the well, the rod 5 has substantially no curvature remaining from the reel 7.
• the chemical devices 9 are comprised of receptacles holding trace elements or so-called "tracers" of a type known per se. In a manner known per se, the trace elements are released into the fluid flow within which the chemical devices 9 are disposed. Preferably, the trace elements released into the fluid flow from each of the chemical devices 9 are arranged in a manner allowing them to be separated from each other.
• the chemical devices 9 of figure 1 are attached around the semi-rigid rod 5.
• the chemical devices in alternative embodiments, also may be arranged in a manner allowing them to be attached to, or merely be connected to, portions of the semi-rigid rod 5.
• bull nose 13 Disposed at the end of the semi-rigid rod 5 there is a so-called "bull nose" 13.
• the main purpose of a bull nose 13 is to guide the semi-rigid rod 5 past sharp edges that may be present in a well.
• the well 1 is provided with casings/liners 15 and production tubing 17. At the end portion of the horizontal portion of the well 1, the well 1 is comprised of a so-called open hole.
• the measuring device 3 illustrated in figure 1 may provide the following information directly or indirectly.
• Pressure within the well 1 may be measured directly by means of the pressure sensor 11, and possibly by means of pressure sensors (not shown) disposed along the rod 5.
• Temperature distribution or -profile, DTS, along the semirigid rod 5 may be measured along the entire length thereof. Upon knowing the temperature profile, it is possible to derive a total fluid flow. From the total fluid flow, it is possible to estimate a flow profile in the well. Particular calculation models have been developed for this purpose. Preferably, the calculations are carried out by means of a computer program.
• the chemical devices 9 or tracers disposed along the semi-rigid rod 5 it is possible to estimate water and gas inflow points. For example, consumption of a tracers or trace elements may be determined by measuring the amount of trace elements originally installed in the chemical device 9 versus the amount remaining upon retrieving the chemical device 9 to surface after a logging operation. The consumption is a function of fluid flow rate (water, for example) past the chemical device 9 holding the trace element. Moreover, surface equipment for detecting concentrations of the different trace elements or tracers in the producing well flow may be provided.
• Consumption of trace elements may also provide an indication on the direction and extent of any cross-flow in the well 1.
• the productivity, or the so-called productivity index PI, of the well 1 may be estimated.
• a portion of the measuring device 3 is inserted into the so-called injection head 21.
• the injection head 21 is then placed on top of said X-mas tree, and pressure control testing is carried out.
• a depth control unit (not shown) .
• a depth control unit may be comprised of a device for measuring the length of the semi-rigid rod 5 being inserted into the well 1, but it may also be comprised of a depth-measuring device (not shown) . Measuring results from said depth-measuring device are compared with the measured length of the rod 5 inserted into the well 1. This makes possible to establish whether the semi-rigid rod 5 is rigid, “buckles” or is "helical”.
• the semi-rigid rod 5 is inserted into the well 1 at a controlled speed, for example 20 metres/min, until reaching the desired position.
• a controlled speed for example 20 metres/min
• the desired position is reached at the end of the well 1. Due to the inherent properties of the semi-rigid rod 5, it will straighten out, but still adapt to the well path.
• the measuring tool 3 is kept at rest, and logging is started while the well 1 is shut in.
• the well 1 is opened to a first flow denoted "flow 1" in figure 2, the flow of which is assumed to be 50 % of maximum flow capacity.
• the well 1 is flowed towards a test separator (not shown) until the well flow has stabilized.
• a test separator not shown
• this may take between six and twelve hours, however differing from well to well.
• the well 1 is flowed for twelve hours, for example, after which logging is performed until achieving satisfactory data quality. Any surface sampling for analysis of trace elements being released from the chemical devices 9 is carried out regularly, for example every hour.
• the well 1 is opened to a second flow depicted "flow 2" in figure 2, the flow of which is 100 % of maximum flow capacity, and the well is allowed to flow for another twelve hours, after which logging is performed until achieving satisfactory data quality.
• Any surface sampling for analysis of trace elements being released from the chemical devices 9 is carried out regularly, for example every hour.
• the well is shut in by closing one or more pressure control valves 19 and, if desired, pressure build-up after production is measured. Such measuring of pressure build-up may be carried out substantially continuously over, for example, twelve hours.
• the apparatus 3 Upon finishing the logging, the apparatus 3 is retrieved from the well 1.
• Figure 2b shows the same procedure for a fluid-injecting well 1.
• the present invention provides an apparatus which 5 surprisingly may allow for quantification of more than one fluid phase in a well flow, simultaneously allowing measuring of the productivity or injectivity of the well.
• the invention will result in simpler logistics with respect to heavyo lifting from, for example, a ship to a platform.
• the present invention exhibits considerable advantages relative to the prior art. Upon having run a rigid cable or semi-rigid rod in a controlled manner into the well when shut in, it will remain "parked"s until the job is finished. Thus, no activity is carried out in order to move the apparatus during the operation. Any risk to personnel in the area around the logging unit is greatly reduced owing to the fact that the operation is limited only to monitoring that the signals from the fibres in the cableo are of good quality. All other work takes place in an approved area, the equipment used being a PC and an interface for converting raw signals into readable data lines providing pressure, temperature, fluid phase and time indication.

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• Engineering & Computer Science (AREA)
• Geology (AREA)
• Life Sciences & Earth Sciences (AREA)
• Mining & Mineral Resources (AREA)
• Physics & Mathematics (AREA)
• Environmental & Geological Engineering (AREA)
• Fluid Mechanics (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
• Geophysics (AREA)
• Mechanical Engineering (AREA)
• Measuring Volume Flow (AREA)
• Testing Or Calibration Of Command Recording Devices (AREA)

Priority Applications (2)

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Publications (1)

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Cited By (4)

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Citations (4)

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• 2006
  • 2006-12-19 NO NO20065913A patent/NO333962B1/no not_active IP Right Cessation
• 2007
  • 2007-12-17 EP EP07860914.6A patent/EP2102451B1/en not_active Not-in-force
  • 2007-12-17 US US12/520,457 patent/US20100059220A1/en not_active Abandoned
  • 2007-12-17 WO PCT/NO2007/000446 patent/WO2008091155A1/en active Application Filing

Patent Citations (4)

Non-Patent Citations (1)

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