Patent Grant
9540914
Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of these expenses, added emphasis has been placed on efficiencies associated with well completions and maintenance over the life of the well. Further, ever increasing well depths and sophisticated architecture are also employed for the sake of maximizing the efficiency and total hydrocarbon recovery from a given hydrocarbon reservoir. For example, vertical well depth may exceed 10,000 feet in order to reach deep reservoirs as well as to help ensure maximum vertical contact with the reservoir.
Of course, even maximum vertical contact with the reservoir is limited given that the reservoir, as with most any other geologic formation, is found in a layered fashion. For example, it would not be uncommon to find a reservoir that occupies about 100 feet vertically, but tens of thousands of feet horizontally. As a result, well architecture often includes a cased vertical well section that extends into an open-hole horizontal or lateral leg section. In fact, the main bore of the well may vertically traverse the reservoir with several lateral legs emerging therefrom and going in different horizontal directions through the reservoir.
Not only does each horizontal leg add to the amount of contact with the reservoir, each leg may add dramatically to the amount of contact. For example, even in the noted circumstance where the well may afford 100 feet of vertical contact to the main bore, each lateral leg may extend to 10,000 feet or more horizontally through the reservoir. Thus, where perhaps five such horizontal legs emerge from the main bore in this fashion, 50,000 feet of added contact surface with the reservoir is provided by way of these legs. In a case where each of the legs is about the same diameter as the main vertical bore, this means that about 500 times the amount of interface with the reservoir has been provided by way of the legs as compared to the main bore.
Of course, with tens of thousands of feet of added well space provided by horizontal legs as described above, tens of thousands of feet of added well maintenance and management is required. For example, production from the reservoir may change over time and contaminants, often water, may begin to be produced. However, it is unlikely that water will suddenly be produced from all regions of the horizontal legs simultaneously. Rather, water production is likely to emerge inconsistently at isolated locations of one horizontal leg or another. Nevertheless, because each horizontal leg emerges from the same main bore, water production at a single location of a single horizontal leg may adversely affect all of production operations. Stated another way, the dramatic increase in reservoir contact area afforded by the horizontal legs has also dramatically increased the likelihood of water production with the potential to affect production operations.
In order to address the possibility of water production from a single location adversely affecting all production operations in a well of multilateral architecture as described, each leg is generally compartmentalized into zonally isolated regions. For example, the architecture of a 10,000 foot leg may be zonally isolated into five separate 2,000 foot sections. In this way, each section may be monitored throughout production operations for water production. Thus, once sufficient water production is detected at one of the sections, production therefrom may be closed off or reduced, for example, by closing a sliding sleeve or valve actuated by surface control or through an intervention if necessary.
The ability to detect water production and independently close off production, section by section as noted above, generally involves the placement of a dedicated capacitance measurement tool within each section. Each tool may be provided with the ability to communicate with equipment at the oilfield surface. So, for example, where water production is detected by the tool within the third section of the second lateral leg, the operator at the surface of the oilfield is provided with such information and may take appropriate corrective action (e.g. to direct closing of a sliding sleeve in the section to stop production therefrom). As a result, production from all other sections of the second leg and all other legs may proceed unaffected by any water production from the now closed off section.
Unfortunately, the ability to detect true water production or an accurate “water cut” by a conventional capacitance measurement tool is limited. Specifically, the amount of water that is being produced as compared to the totality of the produced fluid may not be ascertained with a great degree of accuracy, particularly where the water cut exceeds about 25-30%. That is, once the water being produced exceeds 25-30% of the produced fluid, the readings obtained from a capacitance measurement tool will continue to show only a 25-30% cut, even though the actual cut may be 35-80% or more.
Often, the inability to detect the true water cut is not of major concern. For example, it may be desirable to close off all production from a section whenever water production exceeds about 10%. Thus, the inability to accurately ascertain a 55% cut, for example, is of no significance. However, this is not always the case as many times it is desirable to know the true water cut even if well over 30%.
In wells such as those described hereinabove where an extensive amount of interface with the reservoir takes place in through horizontal legs, the true cut value over 30% is likely to be of significance. In multilaterals such as these, water cut may exceed 30% but only in an intermittent fashion. That is, the horizontal architecture may serve to promote a phase separation between water and hydrocarbons such that surges of water emerge periodically. Thus, the detection of water may not actually be an indication that the entire section being monitored has transitioned to an overall state of high water production. Instead, it may merely be that a temporary surge of water is detected as a result of the well architecture. Of course, the significance of such a temporary surge is unknown if the operator is never made aware of whether the water cut from the surge is 30%, 100%, or some other value in between. As a result, the operator may be left to assume a 100% water cut whenever the cut detection is over 30%. This may in turn lead to prematurely and unnecessarily closing off the leg section. In fact, given that the well is multilateral in nature, this natural phase separation problem is likely to be repeated at several different sections of the well. Therefore, a dramatic reduction in the overall productivity and efficiency of the well may take place as a multitude of well sections are prematurely closed off due to the unavailability of true water cut data in excess of about 30%.
A method of estimating water cut in a region of a well during well operations is provided. The method may include establishing a production index for the region and computing an initial flow rate in the region from the production index. A measured flow rate may then be monitored with a Venturi device. Comparison of the initial and measured flow rates may be tracked on an on-going basis to provide a dynamic read of fluid density. Thus, water cut between 0 and 100% may be estimated for the region over the course of operations.
Embodiments are described with reference to certain downhole hardware and architecture. Specifically, the embodiments depict a multilateral well with a variety of horizontal legs divided into multiple isolated production regions. However, any number of different types of downhole architecture may benefit from embodiments of a system and/or technique of monitoring water cut as detailed herein. For example, even operations at a strictly a vertical well may benefit from the enhanced monitoring and optimization afforded by the water cut monitoring system and techniques described herein. Indeed, so long as water cut estimates across an entire range of 0-100% are available for sake of optimizing production, appreciable benefit may be realized.
Referring now to
As alluded to above, the depicted hardware is outfitted with an embodiment of a water cut monitoring system. That is, in order to ensure that the percentage of water in the production fluid 135 from the area 190 and region are not over a predetermined acceptable level, the depicted hardware of the region includes a system for monitoring the fluid 135 in this regard. Specifically, the system for the isolated region includes a capacitance tool 110 that interfaces with the fluid 135 in order to provide a fairly accurate measure of water cut or water fraction. In the embodiment shown, the tool 110 is shown adjacent to a Venturi device 100 for communication with fluid therein. However, in other embodiments, the tool 110 may actually be disposed within the device 100 itself. Further, in yet another embodiment, a water cut measurement sensor other than an installed capacitance tool may be utilized to obtain the initial water cut. For example, a more temporary sensor introduced to the region via wireline intervention may be utilized to obtain initial water cut measurements.
Regardless, so long as the percentage of water in the fluid 135 is below about 25-30%, a conventional tool such as the depicted capacitance tool 110 may reliably provide such water cut information. Once more, at the outset of production operations, the water cut is unlikely to be significant enough to render the tool 110 ineffective. Nevertheless, given the possibility of water cut increasing over the life of the well 180 or perhaps in surges or “slugs” as a result of the well architecture, the system is also outfitted with additional features to allow continued reliable monitoring of water cut even at levels above 30%.
Continuing with reference to
In
It is of note that the system of
Referring now to
For embodiments herein, as an initial measure, the PI may be established by the device 100 at a time when the water cut is of a known value of below about 30% (e.g. as reliably verified by the capacitance tool 110). Thus, the equation above properly notes a PI at 0-30%. By way of real world example for sake of illustration only, there may be a known flow rate of 1,000 barrels per day and a 1,500 PSI flowing pressure detected by the device 100 in a well that is known to have a reservoir pressure of 2,000 PSI. In such a circumstance, the PI would be 2 (i.e. 1,000/(2,000−1,500)).
Given that the PI was determined at a time when the water cut was of a known level, a reliable value for the PI may continue to be used to ultimately determine the density of the flowing fluid 135 at any given point in time. That is, as the density of the fluid 135 changes, due to water cut increasing up to and beyond 30%, the PI value may be presumed to remain substantially constant. Thus, as described further below, the unknown variable of density may ultimately be solved with reference to a presumed PI in combination with detections from the device 100.
As alluded to above, with a reliably known PI in hand, the flow rate for an entire time period, irrespective of actual water cut, may be determined by the following equation:
Q*(0-100%)=PI(0-30%)·ΔPw
That is, a flowrate across an entire range (i.e. Q*) may be computed with reference to the presumably constant PI and the pressure drop (ΔPw) as described above. Again, by way of specific example only, this means that where a pressure drop of 500 is again detected, the flowrate will remain 1,000. However, over the time period at issue, the pressure drop may fluctuate. Nevertheless, as opposed to guesswork along these lines, the determined flowrate over the period in question may be used to compute fluid density over the same period such that an actual water cut estimate may be made, again, irrespective of the level of water cut (i.e. even if over 30%). With reference to the initial productivity index (PI) variables introduced above, an equation for such determinations may be represented as follows:
In this case, the flowrate (Qv) for any given point in time is already established along the lines indicated above. However, with added reference to
Additionally, the discharge coefficient (C) is a constant that is based on the dimensions of the Venturi device 100, generally with a value of just under 1. For example, the discharge coefficient (C) may be between about 0.90 and 0.99. This means that only the density (ρ), a direct measure of water cut, need be computed for any given point in time. Specifically, an equation solving for the density at any given point in time may be presented as follows:
As indicated above the pressure drop (ΔPv) here may be obtained via ongoing dynamic readings available directly from sensors 200, 250 of the Venturi device 100. Further, the flowrate (Q*) is again presumed across an entire range of water cut. This means that the water cut, as indicated by computed density (ρ), may be plotted over a period of time, for example as depicted in the chart of
With specific reference to the device 100 of
Referring now to
In
This type of information of level of detail may substantially enhance the operator's ability to optimize production. That is, in absence of the system and techniques detailed herein, the operator may be deciding whether to allow a region to continue to produce based on the assumption that every surge of over 25-30% reaches 100% (and for the entirety of the surge). Of course, this is an unlikely circumstance. However, rather than leaving the operator to blindly optimize based on uncertain likelihoods, the present system and techniques allow the operator to estimate true water production for the period being monitored. Ultimately, with brief added reference to
Referring now to
Continuing with reference to
Referring now to
With the sliding sleeve 155 closed or not present readings may also be acquired by the system that do not support maximizing production from the region. For example, with reference to
It is notable that where the system 100 and techniques detailed hereinabove are utilized to close off or restrict production in the manner described above, the optimization has taken place with true water cut estimates available across a complete range of 0-100%. Additionally, while the above described manner of closing off production involved closing sliding sleeves, other well architecture may be utilized for independent closing off or restriction production on a region by region basis.
Referring now to
With the above computation of fluid density available over the period, actual water cut over an entire range of 0-100% may be estimated as indicated at 560. Accordingly, as noted at 580, well production may be optimized by controlling production from the region in question based on the actual water cut thereat.
Embodiments described hereinabove include embodiments of water cut or water fraction techniques and systems that allow for the monitoring of a true water cut value of over 30% in a flowing well. That is, in contrast to conventional systems and techniques, embodiments herein allow for the estimating of the water cut over a full 0-100% range. Thus, even in wells of complex architecture, including multiple horizontal legs which are prone to develop water surges or “slugs”, the true water cut may be monitored in real time. As a result, a more accurate read on water cut for each region of the well that is independently monitored may be obtained. Therefore, production for the overall well may be optimized with a greater degree of precision as production from each well region is independently controlled based on the enhanced read of water cut for the region.
The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. For example, applications outside of the oilfield environment may take advantage of water fraction techniques as detailed herein, wherever a conduit producing fluids of varying types is to be employed. Additionally, even within the oilfield environment, applications aside from hydrocarbon production may utilize such techniques, such as those involving intelligent completions in advance of production. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.
| Number | Date | Country | Kind |
|---|---|---|---|
| 13306299 | Sep 2013 | EP | regional |
| Number | Name | Date | Kind |
|---|---|---|---|
| 20140137643 | Henry | May 2014 | A1 |
| Number | Date | Country | |
|---|---|---|---|
| 20150083402 A1 | Mar 2015 | US |
