Patent Application
20100059220
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.
In the oil and gas production industry, there is a need for being able to evaluate petroleum wells producing oil and/or gas and/or water in order to measure the inflow of oil, gas and water along well paths above the reservoir section from which oil, gas and water are produced. This is particularly challenging in horizontal wells, including both a horizontal branch and so-called multiple branches or multilaterals.
Several apparatuses and methods for gathering data from a well are known for allowing evaluation of pressure and flow, and for allowing estimation of the fluid phases of the well flow, and the 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.
In order to be able to gather data from a well, it is also known to insert required sensors into the well, for example by means of a cable or so-called wireline, or by means of coiled tubing.
There are several disadvantages related to the above-mentioned prior art.
When using permanently installed sensors, the placement thereof must be planned and installed before being inserted into the well. The additional rig time required to install the sensors depends on the number of cables to be fitted, the number of sensor units to be fitted/installed, and on the length of the well. Experience goes to show that it is very costly to install sensors on a permanent basis in a well.
Among other things, electronic units have proven very vulnerable to the high temperatures that might exist in a well, and also to impacts and shocks. Electronic sensors therefore have a limited operating time. Replacement of failed electronic sensors is both time-consuming and difficult.
With respect to space in the well between a production tubing and a casing, passages for cables onward to the surface, and the clamping of a cable to the production tubing, permanently installed systems represent a challenge to the completion of wells.
Within the industry, downhole monitoring is considered to represent a high degree of difficulty. This particularly applies to wells having well path angles between 65° and 95°.
In order to reduce the above-mentioned disadvantages represented by the permanently installed monitoring- or logging systems, sensors may be inserted into the well after having been established.
In order to insert logging systems into wells having high well path angles, i.e. well paths having an angle between 65° and 95°, coiled tubing or wireline with a well tractor is required.
Coiled tubing, however, has a tendency to “buckle”, i.e. it is 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. This is particularly a problem experienced upon repeated use of the coiled tubing. To remedy this problem, among other things, well tractors for coiled tubing have been developed. However, 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 a correct image of the flow conditions within the well.
Additionally, 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.
In some cases, this has resulted in the cable, which connects the well tractor to the surface, to become twisted. Such a situation has resulted in equipment being lost in the well in response to the cable being ruptured during attempts of retrieving the equipment from the well.
It is also possible for a well tractor to get stuck in, for example, grooves in the well. This may result in not being able to retrieve the well tractor and the logging tool, instead being left in the well. Getting stuck with the well tractor has proven especially problematic in wells having valves or so-called “sleeves”, and in well paths without any casing, so-called “open-hole solutions”. Purpose-built well tractors for use in open-hole solutions have been developed, but they involve the same type of throttling problem as mentioned above.
All types of logging involving insertion of the logging tools into the well by means of coiled tubing or wireline, require movement into and out of the well during production, and under so-called shut-in well conditions. During such movements, the sensors may stop functioning in the intended manner.
High temperatures in the well, for example above 140° C., oftentimes lead to problems related to reduced strength or loss of electrical signal in the transitional portion between the cable and the logging tool. Experience goes to show that pressure—and temperature data generally experience a lot of noise under such conditions, which may result in unreliable data from the well.
Logging with a fibre cable is limited to the ability to measure temperature along the cable. As of today, 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. As of today, there are no logging sensors available for rigid fibre cable or semi-rigid rod capable of measuring the fluid phases of the well flow or capable of differentiating oil, water and gas in a well flow.
The object of the invention is to remedy or reduce at least one of the disadvantages of the prior art.
The object is achieved through features disclosed in the description below and in the subsequent claims.
In the method according to the present invention, 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. A person skilled in the art will know that the well's 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.
According to the invention, temperature, so-called DTS (distributed temperature sensing), is measured along a cable or a semi-rigid rod by means of an optical-fibre cable arranged in said cable or semi-rigid rod. Thus, the semi-rigid rod forms the logging unit for the temperature profile along the well. When the temperature profile is known, the flow rate of the well may be estimated.
PCT application WO 2006/00347 describes a rod which has proven suitable for measuring DTS.
In addition to the semi-rigid rod being enable to sense temperature, 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.
Thus, and according to the present invention, 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.
According to the invention the cable is kept stationary during logging of a well under production/injection, or during logging of a shut-in well.
A person skilled in the art will appreciate that the apparatus and method according to the invention imply that there is no need for physical depth correlation tools for allowing evaluation of the log. However, 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”.
According to a first aspect of the present invention, 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 is provided, the apparatus including:
In a preferred embodiment, 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, chemical or a trace element.
In a preferred embodiment, the semi-rigid rod includes a fibre cable. In one embodiment, the semi-rigid rod is of the type described in WO 2006/003477.
In one embodiment, the semi-rigid rod includes a plurality of spaced-apart pressure sensors.
In one embodiment, the apparatus includes an additional pressure sensor for compression-measuring of the end portion of the apparatus in the well. Preferably, 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.
In a preferred embodiment, 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.
In a second aspect of the invention, 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 is provided, wherein the method includes the steps of:
In one embodiment, 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.
An example of a preferred embodiment is described in the following and is depicted in the accompanying drawings, in which:
a shows a graph illustrating the relationship between flow, pressure and time in a fluid-producing well.
b shows a graph illustrating the relationship between flow, pressure and time in a fluid-injecting well.
A person skilled in the art will appreciate that
The apparatus 3 includes a semi-rigid rod 5 ending up, at one 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.
Preferably, the semi-rigid rod 5 is of a self-straightening type. That is to say, when the semi-rigid rod 5 is inserted into the well, the rod 5 has substantially no curvature remaining from the reel 7.
Disposed on the semi-rigid rod 5 are seven measuring devices in the form of six chemical devices 9 and one pressure sensor 11.
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
Disposed at the end of the semi-rigid rod 5 there is a so-called “bull nose” 13. As mentioned above, the main purpose is 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 arrows in the figure illustrate the flow of fluids in through perforations 18 in the liner 15 and flow of produced fluids. A person skilled in the art will appreciate that the arrows would have pointed in the opposite direction for a fluid-injection well. The straight, broken lines illustrate the division of the formation into different zones.
Upon having placed the measuring device 3 illustrated in
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 semi-rigid 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.
By means of 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.
Upon knowing the pressure and flow of the well 1, the productivity, or the so-called productivity index PI, of the well 1 may be estimated.
When the above-mentioned information has been provided, a person skilled in the art will be able to estimate the flow contribution from each single zone or formation section in the well, so as to render possible to quantify the amounts of water, oil and gas.
A person skilled in the art will appreciate that the measuring device 3 must be kept stationary relative to the well 1 while measuring is in progress.
In the following, the main features of performing a logging operation by means of the measuring device 3 according to the present invention are described. For simplicity, some of the required features obvious to a person skilled in the art have been left out completely or partially. Similarly, the processing of the measuring results undertaken during and after the logging operation is not included either.
b shows the same procedure for a fluid-injecting well 1.
Thus, the present invention provides an apparatus which 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.
As compared with prior art coiled tubing units, the invention will result in simpler logistics with respect to heavy lifting from, for example, a ship to a platform.
Also with respect to safety, 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” 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 cable 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.
| Number | Date | Country | Kind |
|---|---|---|---|
| 20065913 | Dec 2006 | NO | national |
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/NO2007/000446 | 12/17/2007 | WO | 00 | 11/12/2009 |
