Patent Grant
7565834
1. Field of Invention
The present invention relates generally to downhole oilfield tools and methods of use, and more specifically to downhole oilfield tools having two or more fluid injection ports for logging pressure, temperature, and/or fluid flow.
2. Related Art
It may be appreciated that well stimulation processes and systems have been in use for years. Typically, stimulation diversion processes and systems are comprised of downhole production logging tools (PLT), radioactive tracers with gamma ray detection tools and fiber optic strings measuring distributed temperature. These measurements in the PLT usually have single pressure, single flow meter, gamma ray and temperature. The data from these downhole tools are realtime when an electric cable and/or fiber optic fiber is connected inside the coiled tubing string, or in memory mode when the data is collected after the job.
Acidizing stimulation with coiled tubing may be effective if the acid can be placed in the correct targeted zones in the formation. The first step in accomplishing this is to determine the zone that would normally take the acid. Unfortunately, there is no current method of calculating this a priori or measuring placement during the job, and it is not possible to carry out production logging to measure the injectivity while pumping acid as the reactive fluid will continuously alter the injection conditions and profile. Other methods such as differential temperature sensing (DTS) to determine the well profile while pumping cold fluid are possible but have their own drawbacks.
From the above it is evident that there is a need in the art for improvement in monitoring oilfield fluid diversion systems and methods. In particular, it would be an advance in the art if downhole methods and systems could be devised wherein the tools and/or coiled tubing and DTS sensors are kept stationary the fluid injection point is changed to obtain two or more distinct logs. Alternatively, it would be advantageous if the fluid injection point is moved while point pressure is detected. With the help of these multiple logs, determination of the location of a thief zone would be feasible.
In accordance with the present invention, systems (also referred to herein as tools or downhole tools) and methods are described that reduce or overcome problems in previously known methods and systems for investigating and/or logging downhole conditions.
A first aspect of the invention is a method, one method of the invention comprising:
Methods within the invention include those wherein fluid flow through the upper and lower injection ports may be hydraulically selected and actuated by simply varying the flow rate of injected fluid in the coiled tubing above or below a certain threshold value. In these methods the hydraulic selection could be performed at the surface by an operator. In certain methods of the invention, in order to increase the depth resolution of the temperature profile, the non-thermally insulated optical fiber cable section running outside the tool may be helically wound on the outside surface of the tubular. In yet other methods within the invention, in order to increase the temperature resolution of the temperature profile the non-thermally-insulated optical fiber section may be used in a double ended manner. The thermally insulated optical fiber section may be thermally insulated from the fluid in the tubular using a double wall flow path within the tube or by using other thermal insulators. In certain methods of the invention the differential temperature profiles may be obtained in real time, although the invention is not so limited. The first differential temperature profile may indicate a sharp temperature gradient at the top of a thief zone, while the second differential temperature profile may indicate a sharp temperature gradient at the bottom of a thief zone. Optionally, point pressure may be measured near or at the terminus of the tubular. Also, some embodiments of the invention may be used to obtain time-lapsed injectivity profiles useful for acting upon during treatment, or even for evaluation so the method may provide injectivity variation on a zone while treating with acid.
Another set of methods of the invention comprises:
Methods within this set of methods include flowing a fluid through the tubular and through the lower fluid injection port, and detecting a sudden pressure increase at the end of the tubular. A fixed packer or cup packer may be employed for restricting flow through the annulus. This sudden increase in point pressure at the end of the tubular would indicate that the packer had just passed a thief zone. Similar logging runs may provide additional useful information, for example: flowing a fluid through the tubular and through the upper fluid injection port, and sensing point pressure near the upper fluid injection port; flowing a fluid through the tubular and through the upper fluid injection port while sensing point pressure near the bottom of the tubular; flowing a fluid through the tubular and through the lower fluid injection port while sensing point pressure near the upper fluid injection port; and flowing a fluid through either or both fluid injection ports while sensing point pressure at both the upper and the lower fluid injection ports.
In optional embodiments, the fiber optic cable may be positioned through the internal cross section of the tubular, or though a tool attached to the end of the tubular. In these embodiments, flow would initially be injected through the upper fluid injection port and the temperature distribution along the tool would be measured in a standard DTS mode. In this way at least the initial flow of the injected fluid could be monitored.
The flow rate, volume, and temperature of injected fluid may vary over wide margins. Those skilled in the art will easily be able to determine the flow rates and temperatures required of the injected fluid to accomplish the intended purpose or purposes. Suggested ranges of these parameters are provided herein.
Another aspect of the invention are systems, one system comprising:
Systems within the invention may comprise one or more point pressure sensors, and may comprise other sensors for measuring other parameters, and means for using the measured parameters in realtime to monitor, control, or both monitor and control diversion of a fluid. Systems of the invention may include those wherein the sensors may be selected from flow meter spinners, electromagnetic flow meters, thermally active temperature sensors, thermally passive temperature sensors, pH sensors, resistivity sensors, optical fluid sensors and radioactive and/or non-radioactive tracer sensors, such as DNA or dye sensors. Systems of the invention may include means for using this information in realtime to evaluate and change, if necessary, one or more parameters of the fluid diversion. Means for using the information sensed may comprise command and control sub-systems located at the surface, at the tool, or both. Systems of the invention may include downhole flow control devices and/or means for changing injection hydraulics in both the annulus and tubing injection ports at the surface. Systems of the invention may comprise a plurality of sensors capable of detecting thief zones and/or pay zones, fluid flow out of the tubular, fluid flow below the tubular and up or down the annulus between the tubular and the wellbore in realtime mode that may have programmable action both downhole and at the surface. This may be accomplished using one or more algorithms allow quick realtime interpretation of the downhole data, allowing changes to be made at surface or downhole for effective treatment. Systems of the invention may comprise a controller for controlling fluid direction and/or shut off of flow from the surface. Exemplary systems of the invention may include fluid handling sub-systems able to improve fluid diversion through command and control mechanisms. These sub-systems may allow controlled fluid mixing, or controlled changing of fluid properties. Systems of the invention may comprise one or more downhole fluid flow control devices that may be employed to place a fluid in a prescribed location in the wellbore, change injection hydraulics in the annulus and/or tubular from the surface, and/or isolate a portion of the wellbore.
The inventive systems may further include different combinations of sensors/measurements above and below, (and may also be at) the injection port in the tubular to determine/verify diversion of the fluid, and location of thief zones and/or pay zones.
Systems and methods of the invention may include surface/tool communication through one or more communication links, including but not limited to hard wire, optical fiber, radio, or microwave transmission. In exemplary embodiments, the sensor measurements, realtime data acquisition, interpretation software and command/control algorithms may be employed to detect thief zones and/or pay zones, for example, command and control may be performed via preprogrammed algorithms with just a signal sent to the surface that the command and control has taken place, the control performed via controlling placement of the injection fluid into the reservoir and wellbore. In other exemplary embodiments, the ability to make qualitative measurements that may be interpreted realtime during a pumping service on coiled tubing or jointed pipe is an advantage. Systems and methods of the invention may include realtime indication of fluid movement (diversion) out one or more fluid injection ports, or out the downhole end of the tubular, which may include down the completion, up the annulus, and in the reservoir. Two or more flow meters, for example electromagnetic flow meters, or thermally active sensors that are spaced apart from the point of injection at the end of the tubular may be employed. Other inventive methods and systems may comprise two identical diversion measurements spaced apart from each other and enough distance above the fluid injection port at the end or above the measurement devices, to measure the difference in the flow each sensor measures as compared to the known flow through the inside of the tubular (as measured at the surface).
The inventive methods and systems may employ multiple sensors that are strategically positioned and take multiple measurements, and may be adapted for flow measurement in coiled tubing, drill pipe, or any other oilfield tubular. Systems of the invention may be either moving or stationary while the operation is ongoing. Treatment fluids, which may be liquid or gaseous, or combination thereof, and/or combinations of fluids and solids (for example slurries) may be used in stimulation methods, methods to provide conformance, methods to isolate a reservoir for enhanced production or isolation (non-production), or combination of these methods. Data gathered may either be used in a “program” mode downhole; alternatively, or in addition, surface data acquisition may be used to make real time “action” decisions for the operator to act on by means of surface and downhole parameter control. Fiber optic telemetry may be used to relay information such as, but not limited to, pressure, temperature, casing collar location (CCL), and other information uphole.
The inventive methods and systems may be employed in any type of geologic formation, for example, but not limited to, reservoirs in carbonate and sandstone formations, and may be used to optimize the placement of treatment fluids, for example, to maximize wellbore coverage and diversion from high perm and water/gas zones, to maximize their injection rate (such as to optimize Damkohler numbers and fluid residence times in each layer), and their compatibility (such as ensuring correct sequence and optimal composition of fluids in each layer).
Methods and systems of the invention will become more apparent upon review of the brief description of the drawings, the detailed description of the invention, and the claims that follow.
The manner in which the objectives of the invention and other desirable characteristics may be obtained is explained in the following description and attached drawings in which:
It is to be noted, however, that the appended drawings are not to scale and illustrate only typical embodiments of this invention, and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. In this respect, before explaining at least one embodiment of the invention in detail, it is to be understood that the invention is not limited in its application to the details of construction and to the arrangements of the components set forth in the following description or illustrated in the drawings. The invention is capable of other embodiments and of being practiced and carried out in various ways. Also, it is to be understood that the phraseology and terminology employed herein are for the purpose of the description and should not be regarded as limiting.
As used herein “oilfield” is a generic term including any hydrocarbon-bearing geologic formation, or formation thought to include hydrocarbons, including onshore and offshore. As used herein when discussing fluid flow, the terms “divert”, “diverting”, and “diversion” mean changing the direction, the location, the magnitude or all of these of all or a portion of a flowing fluid. A “wellbore” may be any type of well, including, but not limited to, a producing well, a non-producing well, an experimental well, and exploratory well, and the like. Wellbores may be vertical, horizontal, some angle between vertical and horizontal, and combinations thereof, for example a vertical well with a non-vertical component.
As mentioned previously, acidizing stimulation with coiled tubing and other tubulars may be effective if the acid can be placed in the correct targeted zones in the formation. The first step in accomplishing this is to determine the zone that would normally take the acid. Unfortunately, there is no current method of calculating this a priori or measuring placement during the job, and it is not possible to carry out production logging to measure the injectivity while pumping acid as the reactive fluid will continuously alter the injection conditions and profile. Other methods such as differential temperature sensing (DTS) to determine the well profile while pumping cold fluid are possible but have their own drawbacks.
The present invention describes methods and systems for more accurately evaluating such regions in an underground geologic formation. One embodiment is illustrated schematically in cross-section in
In one method embodiment, tubular section 6 and its accompanying fiber optic cable is positioned in the formation so that tubular section 6 having upper 8 and lower 10 fluid injection ports is near a suspected thief or pay zone section of a formation. A fluid having a temperature different than that of the formation is then injected through upper fluid injection port 8. A first differential temperature profile along the tubular section 6 between the upper 8 and lower 10 fluid injection ports is determined using non-insulated fiber optic cable 14. Subsequently, a fluid having a temperature different than that of the formation is injected through lower fluid injection port 10, and a second differential temperature profile along the tubular at least between upper 8 and lower 10 fluid injection ports is determined using non-insulated fiber optic cable 14.
In reference to
One or more point pressure measurement sensors 18 may be present in certain embodiments. In the embodiment illustrated in
An optional packer or flow diverter 16 may be added between the upper and lower fluid injection ports 8, 10, the purpose being to simply cause a pressure drop in the annulus to allow for the detection of a thief or pay zone.
In operation of one method of the invention, the idea is to pump a fluid first through the upper fluid injection port 3, log the temperature data, and optionally other data such as point pressure, flow rate, and the like, and then pump the same or different fluid through the bottom port 10 and again log the data. Cross analysis of the two temperature plots should yield information about the location of a thief or pay zone.
In another method embodiment, fluid is pumped alternately through both fluid injection ports 8, 10, as described in the previous paragraph, but while moving the tubular 4 and tubular section 6 up and down past the suspected location of a thief or pay zone. A sharp pressure contrast may be seen when the packer 16 passes the pay/thief zones. Methods within this embodiment include flowing a fluid through tubular 4, tubular section 6, and through the lower fluid injection port 10, and detecting a sudden pressure increase at the distal end of tubular section 6 using a point pressure sensor 18. A fixed packer or cup packer 16 may be employed for restricting flow through the annulus. This sudden increase in point pressure at the distal end of tubular section 6 would indicate that packer 16 had just passed a thief zone. Similar logging runs may provide additional useful information, for example: flowing a fluid through tubular 4 and through upper fluid injection port 8, and sensing point pressure near upper fluid injection port 8; flowing a fluid through tubular 4 and through upper fluid injection port 8 while sensing point pressure near the distal end of tubular section 6 using a point pressure sensor 18; flowing a fluid through tubular 4 and through lower fluid injection port 10 while sensing point pressure near upper fluid injection port 8; and flowing a fluid through either or both fluid injection ports 8, 10 while sensing point pressure at both the upper and the lower fluid injection ports 8, 10.
In optional embodiments, the fiber optic cable may be positioned through the internal cross section of the tubular, or though a tool attached to the end of the tubular. In these embodiments, flow would initially be injected through the upper fluid injection port and the temperature distribution along the tool would be measured in a standard DTS mode. In this way at least the initial flow of the injected fluid could be monitored.
As mentioned previously, the flow rate, volume, and temperature of injected fluid may vary over wide margins, and those skilled in the art will easily be able to determine the flow rates and temperatures required of the injected fluid to accomplish the intended purpose or purposes. In methods of the invention, the temperature difference between the fluid being injected and the local formation be at least 10° C., and may be at least 50° C. In certain embodiments, for example in arctic regions, the injected fluid may be warmer than the formation, while in other methods within the invention the injected fluids may be colder than the local formation. The flow rate of injected fluid may be tailored to the specific task at hand, and may range from about 100 bbls/day up to about 10,000 bbls/day [16 to 1600 m3/day].
Fiber optic tethers useful in the invention are now described.
Referring now to
The bare fiber optic bulkhead 116 is an important aspect of the cartridge design and may be utilized for a variety of purposes. A specially machined plug or mechanical part can be used to pass bare fiber through as a bulkhead and maintain pressure integrity. The plug or part allows the user to minimize fiber optic terminations by allowing the bare fiber to pass through the bulkhead rather than having to make a fiber optic termination to get the fiber through the bulkhead. The reduction in fiber optic terminations reduces the loss of the system and is very important when the fiber becomes very long. A bare fiber optic bulkhead may also be employed in a pressure bulkhead. A bare fiber optic bulkhead could be applied with any pressure application being a possibility both on surface and down hole. A generic pressure bulkhead is described in reference to embodiment 400 of
In a fiber optic-enabled coiled tubing string a fiber carrier protective tube 106 may carry any number of fibers, with the current standard being 4 fibers. The fibers may be color coded for easy identification on either end of the coiled tubing string, which can range from 2,000 to over 30,000 ft in length [610 to over 9100 meters]. In some embodiments each fiber may have a dedicated purpose, which makes it desirable to have the color coding to know where the fiber needs to be connected on the surface end and on the downhole end.
The communication system may be an electrical cable or a system of optical fibers inside a metal tube such as illustrated in
A communication device as described in reference to
Methods of the invention include those wherein the injecting of the fluid may, in the case of the lower fluid injection port, be through the tubular to a bottom hole assembly (BHA) attached to the distal end of the tubular. Optionally, methods of the invention may include determining differential flow, such as by monitoring, programming, modifying, and/or measuring one or more parameters selected from temperature, pressure, rotation of a spinner, measurement of the Hall effect, volume of fluids pumped, fluid flow rates, fluid paths (annulus, tubing or both), acidity (pH), fluid composition (acid, diverter, brine, solvent, abrasive, and the like), conductance, resistance, turbidity, color, viscosity, specific gravity, density, and combinations thereof. Yet other methods of the invention are those wherein one or more parameters are measured at a plurality of points upstream and downstream of a fluid injection point. One advantage of methods and systems of the invention is that fluid volumes and time spent on location performing the fluid treatment/stimulation may be optimized.
Although only a few exemplary embodiments of this invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims. In the claims, no clauses are intended to be in the means-plus-function format allowed by 35 U.S.C. § 112, paragraph 6 unless “means for” is explicitly recited together with an associated function. “Means for” clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.
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| Number | Date | Country | |
|---|---|---|---|
| 20080289408 A1 | Nov 2008 | US |
