Patent Application
20170342976
Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. As a result, oilfield efforts are often largely focused on techniques for maximizing recovery from each and every well. Whether the focus is on drilling, unique architecture, or step by step interventions directed at well fracturing, the techniques have become quite developed over the years. One such operation at the well site directed at enhancing hydrocarbon recovery from the well is referred to as a stimulation application. Generally, in conjunction with fracturing, a stimulation application is one in which a large amount of proppant, often a type of sand, is directed downhole at high pressure along with large volumes of water. So, for example, downhole well perforations into a formation adjacent the well which have been formed by fracturing may be further opened and/or reinforced for sake of recovery therefrom.
For effectiveness, the slurry of proppant and water that is utilized during stimulation is often supplied downhole at considerable rates and pressures. For example, it would not be uncommon for the slurry to be pumped at more than 60-100 barrels per minute (BPM) at pressures exceeding 10,000 PSI. Thus, in order to ensure that a sufficient volume, rate and pressure of the slurry is delivered during the stimulation application, a host of positive displacement pumps are often positioned at the oilfield for sake of driving the stimulation application. Specifically, each one of several pumps may be fluidly linked to a manifold which coordinates the overall delivery of the slurry fluid downhole.
Each of the noted positive displacement pumps may include a plunger driven by a crankshaft toward and away from a chamber in order to dramatically effect a high or low pressure on the chamber. This makes it a good choice for high pressure applications. Indeed, even outside of stimulation operations, where fluid pressure exceeding a few thousand pounds per square inch (PSI) is to be generated, a positive displacement pump is generally employed. In the case of stimulation operations specifically though, this manner of operation is used to effectively direct an abrasive containing fluid through a well to release oil and gas from rock pores for extraction.
As is often the case with large systems and industrial equipment, regular monitoring and maintenance of positive displacement pumps may be sought to help ensure uptime and increase efficiency. In the case of hydraulic fracturing applications, a pump may be employed at a well and operated for an extended period of time, such as six to twelve hours per day for more than a week. Over this time, the pump may be susceptible to wearing components such as the development of internal valve leaks. This is particularly of concern at conformable valve inserts used at the interface of the valve and valve seat. These “inserts” are elastomeric seals that are located in relatively challenging internal pump locations and must be manually inspected. Generally, due to the minimal costs involved, regardless of whether the inspection reveals defects, the seals will be replaced once the scheduled inspection has begun.
However, given that seal replacement will be required several times over the course of standard operations which generally last for a week or two at any given wellsite, there remains a significant cost involved. Specifically, added labor and manpower dedicated to repeatedly rotating pumps from use to inspection and back into operation is required at all times. Additionally, since pumps are constantly being rotated on and off-line for sake of inspection and seal replacement, there are several additional pumps sitting at each wellsite waiting to be called into service. Thus, the cost of ownership at each wellsite is dramatically increased. By way of specific example, it would not be uncommon to employ about 10 pumps at a wellsite for stimulation with an extra two or three pumps not in use but waiting to be rotated in as needed. Given that each pump is generally in excess of about 1 million dollars in today's numbers, this means that at any given point in time, an extra 3 million dollars or more in equipment expenses are being dedicated to equipment that is not being used. This is a considerable amount of expense being added to an already very costly endeavor.
Of course, while these measures are expensive, they are far less than the cost of failing to take such precautions. For example, the conformable nature of the seal means that it is susceptible to bulging related damage and abrasive cracking from the pumped fluid. Thus, if not regularly replaced, the seal may fail to seal, leading to pump failure which can have a cascading effect due to strain on other pumps of the system. Ultimately, this may result in the catastrophic shutdown of all wellsite operations and the need to repair ten or more pumps simultaneously.
Efforts have been undertaken to acoustically, or otherwise, monitor valve performance in real time in an effort to reduce the number of seal replacements required during ongoing operations. However, as a practical matter, there remains no high performing seal capable of reliably withstanding standard ongoing wellsite operations of a week or more. Thus, at present the need to maintain added technical labor and high dollar pumps in reserve remains even with such monitoring in place.
Valve embodiments for positive displacement pumps are detailed herein. A valve may include a stationary valve seat adjacent a chamber for pumping fluid therethrough, A reciprocating valve head opposite the chamber may be provided for intermittently engaging the seat with a metal strike face thereof as well as with an elastomeric seal on the head for engaging the seat, the seal engaging the seat to seal the fluid in the chamber. In an embodiment, a horizontal flange of the valve head may be provided to partially retain the seal at a lower surface thereof. A vertical flange of the strike face of the valve head is also provided to retain the seal at an outer diameter thereof. In another embodiment, the seal and the seat are configured to physically interface in a non-linear manner while engaging. Additionally, in another embodiment, the valve seat may be equipped with multiple axes different from one another such that multiple striking regions are provided between the seat and the valve and/or seal.
In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it will be understood by those skilled in the art that the embodiments described may be practiced without these particular details. Further, numerous variations or modifications may be employed which remain contemplated by the embodiments as specifically described.
Embodiments are described with reference to certain embodiments of oilfield operations. Specifically, stimulation operations involving fracturing of a well are detailed herein. However, other types of oilfield operations may benefit from the valve and seal embodiments detailed herein. For example, any number of pump applications may be run where valve life and effectiveness are extended and enhanced by use of such valve and/or seal embodiments. This may include cementing and a host of other operations in which pumps are utilized to perform applications in a well. Indeed, so long as a seal and/or valve architecture embodiment is employed in such operations as detailed herein, appreciable benefit may be realized. Additionally, the term “seal” is employed herein for elastomeric seals that are utilized with reciprocating valve heads for repeatedly striking valve seats over the course of pumping operations. This term is meant to encompass related terminology that is sometimes interchangeably utilized, such as “valve insert”, “element” or other variations.
Referring specifically now to
As alluded to above, regular use of a pump 110 in oilfield operations means the repeated reciprocation of valves 100, 100′ against a seat 180, 185 for an extended duration, perhaps weeks at a time. This takes place as a plunger 190 reciprocates within a housing 107 toward and away from a chamber 135. In this manner, the plunger 190 effects high and low pressures on the chamber 135. For example, as the plunger 190 is thrust toward the chamber 135, the pressure within the chamber 135 is increased. At some point, the pressure increase will be enough to effect an opening of the upper discharge valve 100 to allow release of fluid and pressure from within the chamber 135. The amount of pressure required to open the valve 100 as described may be determined by a discharge mechanism 170 such as a spring which keeps the discharge valve 100 in a closed position (as shown) until the requisite pressure is achieved in the chamber 135. In an embodiment where the pump 110 is employed with others for stimulation at an oilfield, 601, pressures in excess of 2,000-10,000 PSI may be achieved in this manner (see
Continuing with reference to
The repeated striking of the valves 100, 100′ and seals 101, 101′ against the metal seats 180, 185, subjects, particularly the elastomeric seals 101, 101′, to a significant amount of potentially wearing conditions. However, as alluded to above, the unique valve 100, 100′ and seal 101, 101′ architectures employed herein may be utilized to substantially delay or eliminate the need for seal replacement during typical oilfield pumping operations.
Referring now to
The valve 100 includes a leg portion 225 for un-obstructingly reaching into the chamber 135 of
Referring now to
However, in the embodiment depicted, the seal 101 includes an axial tail portion 275 that, during reciprocation of the valve 100, is configured to extend into and seal off the chamber 135 a moment prior to the striking of the seal face 277 with the face 290 of the seat 180. As a result, the striking of the seal face 277 against the seat face 290 occurs at a time when a substantial amount of slurry abrasive is unlikely to be located at this striking interface. That is, the flow of fluid slurry from within the chamber 135 and across this interface is momentarily disrupted by the sealing off of the chamber 135 in advance of the noted striking. As the chamber 135 is sealed by the axial tail 275, the inertia of the fluid that has already escaped the chamber 135 may continue to take it away from the seat 180 and out of the pump 110 for downstream use (see
As a practical matter, use of a seal 101 and valve 100 as described above, would not notably impede flow of the pumped fluid. For example, the axial tail portion 275 of the seal 101 may extend no more than about 0.25 inches. Thus, considering the typical rate of reciprocation for the plunger 190 and valve 100 components, this may translate into a delay between chamber sealing and striking of the valve 100 at the seat 180 of less than about 0.3 seconds. Therefore, the introduction of a brief sealing-based interruption by the axial tail 275 just prior to the seal 277 and head face 279 striking the seat face 290 is of no significant impact to the effectiveness of the pumping application.
Continuing with reference to
Further, and perhaps more notably, the head 280 is also equipped with a shielding sidewall 220 which terminates at the head face 279 which ultimately strikes the seat face 290 as noted above. However, this feature also serves to shield the seal 101 from the comparatively higher pressures at the opposite side of the valve 100 from the chamber 135. That is, over the course of operations, the pump 110 is generally utilized to acquire and drive up pressures of an application fluid such as a fracturing slurry as alluded to above. This means that as a general rule, the fluid within the chamber 135 will be below that of the much higher pressures that are generated, for example, by multiple pumps and found in common lines outside of the depicted discharge valve 100. Nevertheless, the elastomeric seal 101, which may otherwise be susceptible to a degree of wear upon regular exposure to several thousand PSI of differential pressures, is shielded from such repeated exposures by the noted sidewall 220. Indeed, given the elastomeric nature of the seal 101, the entirety is shielded from the effects of such exposures, and not just the seal surface in contact with the sidewall 220. In other words, unlike in a conventional arrangement where the effects of such high pressure exposure may fluidly migrate across the body of the seal 101, the entire seal 101 of the depicted embodiments is shielded by the sidewall 220, particularly at the moment of striking.
In an embodiment, the valve 100 and seal 101 may be of a different architecture such that the tail 275 is located at the upper end of the seal 101 and of a larger diameter, commensurate with the head 280. In this embodiment, a vertical sealing may take place at this higher, discharge, side of the valve 100 with slurry constituents largely trapped therebelow, at the chamber side of the valve 100 during striking.
Referring now to
In the embodiment of
By way of contrast, the clearance 230 of
Again, the valve 300 includes a head 280 with an architecture for shielding the seal 301 from the pressurized slurry that is being pumped. Specifically, in addition to being supported by a flange 385 that traverses almost the entirety of the underside of the seal 301, the shielding sidewall 320 of the head 280 isolates the seal 301 from the high pressure, discharge, side of the valve 300. Further, as alluded to above, in the embodiment shown, the valve head's strike face 379 is on a different axis than that of the seal 377. For example, the horizontal metal to metal contact between this face 379 and that of the seat 390 may provide a greater degree of isolation to the seal 301 at the moment the valve 300 strikes closed as shown.
Referring now to
The reversal of orientation for the strike faces 477 (478) and 479, means that during valve reciprocation, the metal base 485 will be the first to contact the seat 180 (with 479 striking 495). As a result, this means that similar to other embodiments above, the slurry being pumped through the chamber 135 is substantially cut off from exposure to the seal 401 just prior to the completed strike of the valve 400 at the seat 180. Once more, the substantial base 485 provides increased metal to metal contact during strike. Further, the substantial character of the base 485, combined with the occluded chamber 135 at the moment the seal 401 reaches the valve seat 180, provides substantial reinforcement to the seal 401 at the moment the seal 401 might otherwise be susceptible to differential pressures at the discharge side of the valve 400 as detailed above.
Continuing with reference to
Referring now to
Again, the seal 501 is located at the more unique discharge side of the valve 500. However, the metal to metal interfacing of the head 280 with the seat 180 at its face 595 begins to take place before the seal 501 strikes fully closed at the surface 597. Thus, once again, a degree of protection from slurry constituents is provided to the seal 501 just prior to the strike face 577 of the seal reaching the seat surface 597. However, in this embodiment, the seal 501 is of an architecture that sealing begins to take place at a substantially vertical side 509 of the seal 501 before the impact of the strike is completed. That is, actual sealing by the seal 501 begins in a vertical location (509) that is not subjected to the full impact of the seal 501 striking the surface 597. As a result, any proppant or other abrasive at vertical side 509 is never subjected to being forcibly driven into or damaging the seal 501 to the extent possible if the abrasive were located at the substantially horizontal surface 597. However, as indicated, the likelihood of the abrasive being located 597 at this surface 597 is minimized given that sealing off of the slurry flow has already begun at the vertical side 509 of the seal 501.
As with the embodiment of
Referring now to
Referring now to
In addition to pumps 110, 600, other equipment may be directly or indirectly coupled to the well head 650 for the operation. This may include a manifold 675 for fluid communication between the pumps 110, 600. A blender 690 and other equipment may also be present. In total, for such a hydraulic fracturing operation, each pump 110, 600 may generate between about 2,000 and about 10,000 PSI or more. Thus, as valves 100, 100′, 300, 400, 500 strike seats 180, 185 within each pump 110, 600, an extreme amount of stress is concentrated at each valve-seat interface as described hereinabove. Nevertheless, with added reference to
Embodiments detailed hereinabove provide valve configurations and seals that allow for substantial cost reductions during multi-pump operations. Specifically, depending on the period of ongoing operations, use of such valve and seal arrangements may reduce if not eliminate the need to periodically take pumps offline during use for sake of seal replacement. As a result, manpower requirements may be reduced as well as the substantial cost of having several spare million dollar pumps sitting around unused for the majority of operations. Furthermore, this is achieved in a reliable manner that does not require the use of other sophisticated seal monitoring equipment and associated expenses. Through the valve and seal configurations detailed herein, pumps may remain reliably online for greater periods, potentially even for the duration of a standard stimulation job, without the requirement of such added costly measures.
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. 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.
