MXPA00008491A - Inflow detection apparatus and system for its use - Google Patents

Abstract

There is provided a method for monitoring fluid flow within a region to be measured of a subterranean formation, said method comprising placing at least one source within said subterranean formation;placing at least one sensor within said region to be measured, wherein each said at least one sensor is adjacent to at least one source such that said sensor measures changes to said fluid caused by said source;and providing at least one means for transmitting data from each said at least one sensor to at least one data collection device, said at least one data collection device capable of communicating with an operator.

Description

APPARATUS FOR THE DETECTION OF THE AFFLUENCE AND A SYSTEM FOR ITS USE Field of the Invention This invention relates to a method for quantifying the flow of a fluid into a subterranean formation, particularly the quantifications of the flow rate of liquids, gases, and mixed fluids in subterranean formations.

Background of the Invention Recent advances in the oil well drilling industry for well drilling construction techniques, such as horizontal wells and multilateral wells, present new challenges for the completion and deposit engineering disciplines. The high-speed horizontal wells in deep water conditions further boost the high-tech tools that the oil engineer has at his disposal for REF .: 122666 to produce in a prudent and safe way the petroleum deposits.

Classical methods for monitoring the oil deposits that assume the permeability (* K ") and height (* H") of the area are known, which contributes to the well production. This * KH "is probably confirmed with production records on a periodic basis, and is typically considered as constants.The KH of a well is of superior importance for most calculations in oil deposits. horizontal well or a multilateral well, the H of the drill that penetrates the oil reservoir is known from electric methods for recording data, and more recently by techniques for recording data while going drilling. However, the interval in which the oil deposit data is recorded may not be the same as the H, which currently contributes to the production of the well and, in fact, the H may change over time. j - ^^^^^^^^^^^^^^^^^^^^^^^^ '^^^ ^^ faith to faith ^^^^ ^^^^^^^^^^^ J ^^^^ I ^^^^^^ the industry has adopted a carefree attitude to the assumption on the performance of the flow in the horizontal and multilateral wells. The large assumptions regarding the performance of the inflow into the well are made based on the surface data (ie flow velocity, pressure, water interruption, etc.), of possible manometers at the bottom of the well. hole, and general rules. The reality is that these assumptions can lead to poor performance of the well, poor handling of the oil deposit, failure to finish the equipment, and in the worst case, a catastrophic failure of the well.

The only method that is currently available to the production engineer or to the engineer in oil deposits, to observe the changes or losses in the H, is to operate a production record transmitted by a wire line or deployed through tubes during the interventions in the wells. These records are difficult to interpret, particularly in horizontal wells ^ &^^^^^^ AÍ ^^^^^^^^ f ^ with a high angle. This is due to the inability that has the current meter to quantify, in three phases, the flow rates, commonly referred to in the literature as water retention or gas dissipation. This procedure, to record the production data of those known from European Patent Applications Nos. 0442188 and 0508894 require a mobilization of rigging, which results in a loss of production during the mobilization of the rigs upwards. and the mobilization of the rigs down the registration equipment, and presents the risk of losing the equipment in the well. The annotation of the production records is not always possible (for example, due to some completions below the sea or the wells where an electric submersible pump (ESP) is installed.) Moreover, since the data for the production record are subject to interpretation, the decision to carry out a series of production data records is usually avoided, and the end result is that production is maintained by increasing the size of the surface seal. more damage, . *. ^^ ... * - ^ > ..- > -..- .-- »_ - -. ^ Á? ^^^^^^^., ^^^^^^ .. - ^ | ffl r - Ultimately in well drilling failures and detection of high production of hydrates and explosions.

The method according to the preamble of claim 1 is known from European Patent Application 0442188. The known method is a Doppler flow counter that is lowered temporarily on a wire line along a well borehole. . It is known from the European Patent Application No. 0508894, another probe for data recording which is equipped with a means of detection and generation of signals through optical fiber.

Brief Description of the Invention The method of the invention is characterized in that a source and a sensor are permanently mounted within an underground well bore and / or surrounding formation.

Detailed description of the invention The method of the invention provides a means to monitor the flow of a fluid, where a fluid is liquids or gases or mixtures of liquids and gases, from underground formations. The quantification takes place directly in the region where quantification is desired. In the case of a rising well, the quantifications can be taken while the well is producing. The thermal and / or acoustic sources are placed in the path of the fluid flow and sensors capable of detecting the temperature or acoustic changes are placed near the sources that detect the changes in the fluid caused by the sources.

One embodiment of the invention provides a method for monitoring the flow of a fluid in a region to be quantified within an underground formation. At least one source is placed inside the formation. The placement is relatively permanent, which means that the source is placed and then left in the area to be quantified. At least one ^ gfé? Sensor is also placed within the region to be quantified. Each sensor must be adjacent to one or more sources, in a proximity close enough to quantify changes in fluid 5 caused by the sources. It is also necessary to provide at least one means for transmitting the data from the sensors to at least one data collection device. The data collection device may be underground, on the surface, or 10 in the air but must be able to communicate with an operator. As used herein, an operator can be an object, such as an operating station, or a human being.

The sources can be optical sources, thermoelectric sources, acoustic sources, or combinations of these. Examples include thermistors, optical heaters, continuous heating elements, electric cables, sonar generators, and power generators. vibrations. Since it is optimal to limit the constraints in the formation, the preferred sensors are the optical fibers, which are small enough so that ^^^^^ g ^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^ ^^^^ be non-intrusive. Optical fibers can also act as a means of data transmission, therefore they serve two purposes. The sources and preferably sensors are oriented perpendicular to the fluid flow.

When the underground formation is a well, the region of the fluid flow to be quantified is typically within the well borehole, whether vertical, horizontal, or offset. A means for deploying the sensors and data links in a fairly non-intrusive manner is by means of hollow tubular components.

It is expected that the system of the invention performs well by using the technology applied to wells, known as Microoptical Perception Technology ('MOST') .MOST allows the miniaturization of the perception equipment in the submersible equipment. Oil and gas well environments have a restricted geometry and hostile conditions of temperature and pressure. operate in these environments due to its ability to use small data links (optical fibers) and to use sensors that can withstand temperatures above 200 ° C.

Since the sources, sensors and data links are permanently installed in the desired region within the formation, there is no need for interventions in the wells, such as production records. The method can provide a continuous profile of the inflow performance of the formation, based on real time and multiple nodes can be monitored for flow detection throughout the formation.

The use of thermal sensors and sources are used as an example. A series of thermal, electric or optically driven sources can be placed along the axis of the well bore in parallel to a series of thermal sensors. Thermal sources can be of various forms, including, but not limited to, heating elements. a single tip such as thermistors, optical heaters, or a continuous heating element such as an electric cable.

Preferably, the thermal sensors are multiple or isolated optical fibers. The fibers can be deployed within the well by various means, and in a varied geometry. An example of the deployment that protects fibers from exposure to hydrogen is to configure thermal sensors and data links in small hollow components, such as tubes. The system for the detection of the flow is taken when placing the optical fibers in the stream of the flow before the heaters, after the heaters, or both. Other embodiments use the optical fibers and heaters that are deployed in parallel to one another, and surrounding each other in spiral configurations, and other configurations. The preferred embodiment places the thermal source and the thermal sensors perpendicular to the flow of the fluid in the well bore, such that the thermal source heats the fluid while the thermal sensors quantify the thermal change of the flowing fluid stream. about the thermal source. Then, this system forms a classical series of thermal flow counters according to the following simplified equation 5 for the thermal flow: Q = Wcp (Tz-T where: 10 Q = heat transferred (BTU / Hr); W = flow velocity of the mass of a fluid (lbm / Hr); and cp = specific heat of the fluid (BTU / lbm ° C) 15 The accuracy of the flow meter is dependent on the accuracy of the specific heat data for flowing fluids. The specific heat of the fluids in the well changes with time, by the pressures of the tributary, and the conditions of the petroleum deposit (for example the conicity). wfeag'sa - »- 'v * & > Vmxv * *? T jb * »> * r, > The optimum production of the wells requires that the thermal sources and the devices for the quantification of the temperature be small and not intrusive to the internal diameter of the well perforation. The non-intrusive deployment allows the well to be fully open and therefore allows the techniques of stimulation, constriction, or data recording to be carried out through the completion with the sources, sensors and data links permanently installed.

The preferred sensors and / or data links of the invention are the optical fibers. Optical fibers are exotic glass fibers that are available with a variety of different coatings and by several different manufacturing methods that affect their optical characteristics. Optical fibers have a rapid decrease in their functionality when exposed to hydrogen, and certainly groundwater is a readily available carrier for hydrogen. Therefore, the fibers must be placed in a ^^ ¡^ gg ^ ¡g ^ g ^^^^ ¡^^ d ^ §¿ ^ ¡^ transporter. But other characteristics of the optical fibers allow a fiber to record the multiple changes along the length of the fiber, this is an obvious advantage.

Fibers can be used in oil and gas wells in conjunction with COTDR Time Delay Reflectometry devices (commonly referred to as "intrinsic quantification"). The intrinsic perception along the fiber is carried out with the application of quantum electrodynamics (* QED "). The QED is related to the science of subatomic particles such as photons, electrons, etc. For this application, the interest is found in photons that travel through a very special subatomic glass matrix.The probability, or the probability amplitude, that the photon interacts with a subatomic structure of silicon dioxide is known for each specialized optical fiber. Retrodifraction of the light resulting from the function of the thermal effects in the glass subatomic structure has a well-known relation for the index refraction of the optical fiber. The knowledge about the power and frequency of the light that is moving from top to bottom, or that is pushed through the optical fiber, allows the predicted calculation of the light and of the emitted frequency or of the retrodifraction in a given length , along the optical fiber.

The process of the invention uses an OTDR and thermal and / or acoustic sources to quantify the flow in the wells. The changes of flow in each node can be monitored with all haste, which provides a qualitative quantification on a permanent basis in real time. By knowing the type of glass and the laser light used, you can quantify the return energy of a back-scattering of the light using an * OTDR "according to the following equation: Pbs (1) = ** P0? TvgCsNA2exp (/ -2adx) where: Pbs = energy of the backscattering returning from distance 1; P0 = launch energy; ? t = source time for the pulse width, in units of time 5; vg = group speed; Cs = diffraction constant; NA = numerical aperture of the fiber; and a = total loss of the attenuation coefficient. 10 The OTDR can quantify in a very successful and repeatable way the changes in the backscattering as a function of the temperature caused by a wave of light pulsed by a laser through an optical fiber, by relating Cs in, and a to.

Cs = (ar) co + (as) co + Pc / Pt (as) d where: < g ^. > . ' 'r? «s? S" < -V, -. tA.? i. , = tfte & ~ > , ar = Raman diffraction coefficient; as = Rayleigh diffraction coefficient; () co = parameter associated with the core of the fiber; () ci - parameter associated with the coating of the fiber; and Pci / Ptotai = proportion of the total power that exists in the coating due to the evanescent effects of the wave.

The OTDR equipment uses a laser source, an optical fiber, a directional coupler connected to the fiber, an opto-electronic receiver, a signal processor, and a data acquisition equipment.

The method of the invention allows simple actions to be carried out at the bottom of the hole without intervention on the surface, and allows the performance of the oil deposit at the bottom of the hole to be monitored when using a seismic 4D and other technologies. The present invention can also be applied to other flow processes (ie, in pipes, refining processes, etc.). ^ .. ^ ^,. ^. ^ ...... ^ Íto ^^ ..,! - - • E ^^ siÉa - ^ - a ^^ It is noted that in relation to this date, the best known method for the applicant to carry out the aforementioned invention, is the conventional one for the manufacture of objects or products. to which it refers.

Having described the invention as above, property is claimed as contained in the following: wí * VS _UJ £ ÍIII_L - ilfl MfflflfcWT-llir- -s - ^ "- - > • * • * •» + - - ^ ** - ^ * t-

Claims (11)

1. A method to monitor the flow of a fluid within an underground region to be quantified, where this method comprises: placing at least one source within this subterranean region; place at least one sensor within this region to be quantified, where at least, each of These sensors are adjacent to at least each of the sources in such a way that this sensor quantifies the changes in this fluid caused by this source; provide at least one means to transmit 15 data from at least one of these sensors towards at least one data collection device, at least, this data collection device is able to communicate with an operator, characterized in that the source and the sensor are mounted in a manner 20 permanent inside the drilling of the underground well and / or the surrounding formation.

2. A method according to claim 1, characterized in that this source is selected from an optical source, a thermoelectric source, an acoustic source, and combinations thereof.

3. A method according to claim 2, characterized in that this source is selected from a thermistor, an optical heater, a continuous heating element, an electric cable, a sonar generator, a vibration generator, and combinations thereof.

4. A method according to claim 1, characterized in that this sensor is one or several optical fibers.

5. A method according to claim 1, characterized in that one or more sensors and one or more sources are oriented perpendicular to the fluid flow. . »^ ¡To», ^^. ^^, ^. t ^^^^^ S i mliñlWmW? m ^^ iS mS

6. A method according to claim 4, characterized in that these sensors and data links are deployed in hollow tubular components.

7. A method according to claim 6, characterized in that this source is selected from an optical source, a thermoelectric source, an acoustic source, and combinations thereof. 10.

A method according to claim 7, characterized in that this thermal source is selected from a thermistor, an optical heater, a continuous heating element, an electric cable, 15 a sonar generator, a vibration generator, and combinations thereof.

9. A method according to claim 6, characterized in that this sensor is one or more fibers 20 optics.

10. A method according to claim 9, characterized in that these sensors or data links are deployed in hollow tubular components.

11. A method according to claim 6, characterized in that one or more sensors from one or more sources are oriented perpendicular to the fluid flow in this region, to be quantified within the wellbore.