Patent Application
20220082005
The present invention relates in general to fluid stimulation equipment for oil and gas wells and in particular to a fluid direction manifold subjected to severe operating conditions, such as the high pressures, high flow rates, and abrasive fluids commonly found in hydraulic fracturing operations and other oil and gas stimulation applications.
In one of the most severe service applications known today, hydraulic fracturing (“fracing”), very high pressure slurry is pumped at very high rates. In particular, fracing slurry is forced down a wellbore with enough pressure to fracture the hydrocarbon bearing rock formations and force particulates into the resulting cracks. When the pressure is released, the particles (“proppant”), which may be sand or other high compressive strength additives such as ceramic particles and bauxite, remain in the factures (cracks) and keep the fractures open. This “mechanism” then allows pathways for hydrocarbon to flow from the rock that was previously solid.
As the fracing industry becomes more efficient, multiple fracing stages are being pumped from a single “fracing factory”, consisting of many fracing pump trucks and accessory equipment to multiple wells, as first disclosed in U.S. Pat. No. 7,841,394, assigned to Halliburton. In order to make this process efficient, the concept of a distribution manifold was introduced as disclosed in U.S. Patent Application Publication No. 2010/0300672, assigned to FMC, which describes in detail the method of using such a manifold. This technique has become common practice, with this type of manifold commonly known as a zipper manifold in the hydraulic fracing industry.
When zipper manifolds started being used for fracing fluid distribution around 2009-2010, most wells were vertical and the number of stages being pumped per well was around 10 to 20. A stage is the process of pumping a mixture of proppant (typically sand), water and some chemicals down a wellbore under high pressure, usually in excess of 9000 psi, for fracturing a specific interval of the wellbore. Since then, the industry has been getting more and more aggressive and most wells being fraced today are doing so in long horizontal wellbore sections having 50 to 100 stages.
A modern fracing operation typically runs 24 hours per day for several days. In the Permian basin of Texas, 70 fracing stages per well are now common. Each stage can last 1 to 2 hours and results in a small portion of the total wellbore being fractured. Then the pumps are stopped, and wireline is run. These wireline operations do a variety of things depending on the completion system being used. For example, a wireline can used be to set a plug, perforate a new zone, or open or close a sliding sleeve. This prepares a new section (interval) of the wellbore for fracing.
Then a new stage is pumped, fracturing the newly exposed wellbore. This process continues until all the sections of the wellbore have been fraced. It is common to achieve 8 to 15 fracing stages in a day, rotating the activity continuously between typically 3 wells. With 70 stages per well, this means that the zipper manifold is operating continuously for 14 to 28 days (excluding rig-up and rig-down time).
The frac flow is routed from the main incoming factory line (missile) to the distribution (zipper) manifold that is tied in to multiple wells. This allows simultaneous operations, and for a 3 well pad with a 3-way zipper manifold it means that one well is having a frac stage being pumped, one is idle and one is having wireline operations. The number of fracing stages is increasing with up to 100 stages and more per well possible in the foreseeable future.
This means that the valves on the zipper manifold are being opened and closed over 100 times on a three well pad job resulting in many problems. One problem is the wear of valves and subsequent downtime as the conditions for valves are typically very harsh at the zipper manifold location. The particle size distribution in these fracing fluids is distributed so that the larger particles can prop open larger cracks and finer particles can prop open the very tips of the cracks, which are microscopic in nature. The particle sizes can vary from 0.004 inches to 0.01 inches (No. 140 Mesh to No. 8 Mesh). The pumping pressure can be up to 15,000 psi and the slurry velocity through a valve bore of 5.125 inches, as is typical of a 5⅛ inch, 15000 psi valve, is well above erosional velocity of about 50 to 70 feet per second. Moreover, the fracing is typically preceded and followed by an acid wash of 15% hydrochloric acid, which accelerates corrosion.
As one skilled in the art of mechanical engineering can ascertain, the fracing “mechanism” will inject proppant particles into any crack, orifice or possible leak path in the valve assembly. The injected particles remain in the valve assembly when the pressure is released. Small particles as large as 0.004 inches are within machining tolerances of steel parts and therefore will find their way into metal sealing surfaces. With the high velocity of abrasive fracing fluid, any weakness or point of turbulence can very quickly lead to a washout of a seal area or any interface. With ever increasing numbers of stages, the valve life limit can be reached during an operation resulting in repair/maintenance downtime. This is a safety problem as the repair person is exposed to an increased safety risk as all the equipment is interconnected.
With the zipper manifold always having one high pressure fracing operation concurrent with a residual pressure wireline operation, and possibly other preparation work on the idle well, there is a lot of room for errors. Even with procedures and strict protocols, accidents are common. A typical example occurs when there has been repair/maintenance work on a frac pump, after which the pump is started for testing. If this series of events was not properly regulated, high pressure can be applied accidentally via the zipper manifold to an undesired location.
The pressure pumping industry has become more automated with the use of hydraulic valves, which allow for automated operations from a safe remote location. As a result of this automation, human error has become more prevalent as it is very easy to simply “flip a switch” to open and close pressure barriers (i.e., valves). These pressure barriers are crucial for safety, since wells and pump trucks are potentially fatal pressure sources and the operation of an incorrect pressure barrier may result in a fatal incident.
In a typical operation occurring for a three well pad scenario, Well #1 is idle and the zipper valves are closed, which isolates pump pressure to the wellbore. Well #2 is pumping and the zipper valves are open, such that pressure from the pumps is applied to the wellbore. Well #3 is undergoing wireline operations and the zipper valves are closed, isolating the pump pressure from the wellbore and the wellbore pressure back to the pumps.
Once Well #2 finishes pumping and the zipper manifold valves are shut, Well #2 becomes idle. However, Well #2 is still under pressure from the last frac stage, such that if the zipper manifold operator is instructed to open Well #1 to begin pumping, but instead accidently opens Well #2, the pumps are exposed to wellbore pressure. In this scenario, it is highly probable that the high pressure piping connected to the pumps is disconnected, as the pumps also require frequent maintenance during operations. The workers repairing the pumps are then subject to injury.
When using a zipper manifold, the in-line flowline valves (“ground valves”) between the zipper manifold and the pumps are typically left open because the zipper manifold valves are used to provide the primary pressure barrier, with two valves being used in series for double isolation. These valves are operated as isolation or flow pairs, being opened and closed one after another. The valves closest to the pumps on the manifold are exposed to every frac stage of all the wells being fraced. So, on a three well pad, these valves are subjected to up to 200 to 300 stages of frac slurry. Because of this, the zipper manifold valves are the most likely to malfunction, which causes the non-productive time and safety hazards.
There is a need to further reduce the activity of personnel in the dangerous area between the pump trucks and the wells. The introduction of zipper manifolds with hydraulic valve actuators has not fully solved this issue, as personnel are required more and more frequently to repair valves on the zipper manifold with ever increasing numbers of fracing stages. With these stages creating more demand on the pumps, these valves are also being repaired with ever increasing frequency on jobs. Both types of repairs require opening of components that are directly connected to pressure sources, either the well or the pumps. The easy actuation of valves via hydraulics has increased the number of safety incidents and this will continue to increase as maintenance activity increases with more stages.
The fracing industry in its desire to ever increase efficiency is now looking at 6 to 10 well pads, as horizontal placement of wellbores allows for design efficiency. This will mean one fracing factory of multiple pumps being interfaced with 6 or more wells using two or more three-way zipper manifolds or other efficient configurations with many more valves leading to further safety issues.
There is a more reliable manifold solution that: eliminates down time due to valve repair; provides a safer method of operation; and can be easily expanded to more well pads. Such a manifold solution termed “jumper manifold” is presented in U.S. patent application Ser. No. 16/696,487, which is incorporated by reference herein in its entirety. Advantageously such a jumper manifold requires a very reliable high-pressure connector that needs to be connected and disconnected many times during these types of continuous fracing operations without requiring maintenance.
U.S. Pat. No. 9,932,800 assigned to Cameron discloses the concept of using a monobore manifold that runs along all of the wells in a wellpad, essentially a continuous Zipper Manifold. This is time consuming to rig up with the large bore lines requiring very careful adjustment to be able to line up several wells simultaneously.
Another way of working without a zipper manifold is to use a movable flowline, as disclosed in U.S. Pat. No. 8,590,556 assigned to Halliburton. Here the valves on the truck are used as isolation valves and the fracing line is disconnected and swung over to the next well to be fraced. The well that is being wirelined and the well that is idle are both isolated as they are disconnected completely from the main fracing line that is connected to the pumps. This method eliminates the possibility of exposing the pumps to wellbore pressure of the wells not being fraced. However, this method requires workers to be in the “red zone” (i.e., the “widow maker area”) a distance of 75-100′ from an area around the flowline between the wellhead and pumps. The Halliburton design requires an operator to control the movable flowline from the truck within this “red zone”.
This Halliburton articulated line concept has limitations in the ever more efficient eco-system of fracing rig-ups. On older design 2 or 3 well pads it was possible to place the truck (vehicle) efficiently between the fracing pumps and the wellheads so that each wellhead could be serviced in turn without moving the vehicle or platform as described in the claims of '556. With the drive for efficiency resulting in wellpads with 6 or more wellheads it is not possible to reach all 6 well heads from one position. That means the vehicle or platform has to be moved during the operations which is absolutely not efficient as this requires breaking some connections from the main pump line, adding extensions to enable the vehicle to move further along, requiring renewed pressure testing. Adding another vehicle with such an articulated line is possible, also requiring an additional manifold to split the main incoming pump line. This is cost prohibitive.
What is needed is an efficient and cost-effective solution that enables the advantages of the articulated line concept without adding significant cost or complexity. This is the scope of the present invention which proposes a system that enables safe extension for the furthest wellheads thus enabling the vehicle or platform with an articulated line to stay in one place.
To remove the need to have additional articulated platforms or to move the vehicle with an articulated system during operations, a “Modular Fracing Wellhead Extension” (MFWE) is introduced. These MFWEs are used to create connection points within the range of the articulated line from the vehicle or platform so that the integrity of main line from the pumps to the vehicle/platform is preserved throughout the whole operation and that the articulated line can reach four or more connection points leading to all of the wellheads at the wellpad being fraced.
These MFWEs can be rigged up at the same time as the connections for the wellheads within reach of the articulated line are prepared, which is done before the fracing operations commence so as not to interfere in the fracing process once the operations have started.
The MFWE modules use the same connection interface as deployed on the wellheads in reach of the articulated connection platform.
In one aspect, a modular wellhead extension manifold is disclosed for providing a fluid connection from a wellhead line supplying a source of fluid for delivery to a wellhead that is disposed beyond the reach of the wellhead line, to a wellhead extension line connected to the wellhead. The modular wellhead extension manifold comprises an outlet block having a top-facing fluid inlet and a side-facing fluid outlet operably connectable to a wellhead extension line that is connected to a wellhead for delivering a fluid to the wellhead. A first hydraulically actuated isolation valve having a bottom-facing fluid outlet is operably connected to the fluid inlet of the outlet block, a top-facing fluid inlet, and a first valve mechanism is connected between the fluid outlet and fluid inlet of the first isolation valve. A second hydraulically actuated isolation valve having a bottom-facing fluid outlet is operably connected to the fluid inlet of the first isolation valve, a top-facing fluid inlet, and a second valve mechanism is connected between the fluid outlet and fluid inlet of the second isolation valve. Each respective valve mechanism of the respective isolation valve is selectively hydraulically movable between an open position allowing fluid flow through the respective isolation valve and a closed position blocking fluid flow through the respective isolation valve. A connector assembly having a lower portion including a bottom-facing fluid outlet is operably connected to the fluid inlet of the second isolation valve and an upper portion including a fluid inlet is connectable to a wellhead line for receiving the fluid from the wellhead line. The upper and lower portions of the connector assembly can be selectively engaged to, and disengaged from, one another without the use of bolted fasteners. When engaged to one another, the upper and lower portions of the connector assembly form a fluid-tight path from the fluid inlet of the connector to the fluid outlet of the connector and the upper and lower portions cannot be moved apart from one another. When disengaged from one another, the upper and lower portions of the connector assembly can be repositioned apart from one another. When the upper and lower portions of the connector assembly are engaged to one another and the respective valve mechanisms of the first and second isolation valves are in the open positions, the fluid from the wellhead line can flow through the modular wellhead extension manifold into the wellhead extension line for delivery to the wellhead.
In one embodiment, selective operation of the respective hydraulically actuated isolation valves is remotely controllable from a predetermined distance away from the modular wellhead extension manifold.
In another embodiment, the upper portion of the connector assembly has a side-facing fluid inlet that can rotate relative to the lower portion of the connector assembly to change the angle of the side-facing fluid inlet of the connector relative to the side-facing fluid outlet of the outlet block.
In yet another embodiment, the lower portion of the connector assembly further comprises a spool, wherein the spool comprises a flanged bottom end for bolted connection to the fluid inlet of the second isolation valve. The lower portion further comprises a top configured with a profile for the upper portion of the connection assembly to latch on.
In still another embodiment, a height of the fluid inlet of the connector above the outlet block can be selected by changing a length between the flanged bottom end of the spool and the profile of the spool.
In a further embodiment, the connector assembly further comprises a plurality of dogs arrayed annularly around a junction between the upper and lower portions of the connector assembly, each dog having a plurality of inward-facing teeth. The lower portion of the connector assembly includes a grooved upper end adjacent the junction and a flanged bottom end for bolted connection to the fluid inlet of the second isolation valve. The upper portion of the connector assembly includes a grooved lower end adjacent the junction and an interface for the fluid inlet. The connector assembly further comprises at least one ring encircling the upper and lower portions and operably connected to the plurality of dogs. Rotation of the ring in a first direction relative to upper and lower portions causes the plurality of dogs to move inwards until the teeth engage the grooves on the upper and lower portions to engage the upper and lower portions, and rotation of the ring in a second direction relative to the upper and lower portions causes the plurality of dogs to move outward until the teeth disengage the grooves on the upper and lower portions to disengage the upper and lower portions.
In as still further embodiment, one of the upper and lower portions defines an axial socket, and the other of the upper and lower portions defines a projection configured to interfit with the axial socket to maintain axial alignment of the upper and lower portions when engaged.
In a yet further embodiment, the modular wellhead extension manifold further comprises a skid having a skid frame operably connected to the outlet block. The skid supports the modular wellhead extension manifold on a ground surface.
In another embodiment, the skid frame further comprises a skid base plate disposed below the skid frame, and a plurality of jacks attached between the skid frame and the skid base plate to allow changing the height of the outlet block or connector assembly relative to the ground surface by selectively changing the lengths of the plurality of jacks.
In yet another embodiment, the skid frame further comprises a skid base plate disposed below the skid frame, and a plurality of jacks attached between the skid frame and the skid base plate to allow changing the angle of the outlet block relative to the ground surface by selectively changing the lengths of the plurality of jacks.
In another aspect, a system is disclosed for supplying fracing or stimulation fluid to a plurality of wellheads that enables extension of a connection point for the plurality of wellheads to be extended from an original specified radius of operation to a new specified new radius of operation, the new radius being greater than the original radius. The system comprises a respective extension line connected to each of the respective wellheads disposed outside of the original radius of operation and extending into the original radius of operations. The system further comprises a respective device attached to each respective extension line within the original radius of operations that is configured to enable the same connection interface as the wellheads inside the original radius of operation.
In one embodiment, each respective device has the same connection interface as the wellheads within the original operating radius.
In another embodiment, each interface includes a remotely operated connector that can selectively connect to a fluid supply line.
In still another embodiment, the remotely operated connector is actuated by hydraulics.
In yet another embodiment, the original radius of operation is determined by a dimension of a crane affixed on a stationary platform or vehicle.
In a further embodiment, the original radius of operation is determined by a fluid supply line attached to a swivel point.
In a still further embodiment, the connector is a remotely operated connector.
In a yet further embodiment, the remotely operated connector is actuated by hydraulics.
In another embodiment, the flow path of the fracturing or stimulation fluid extends through a port in the connector, then extends down to a bottom of the device and then extends to out of the device to the wellhead being fraced.
In yet another embodiment, the device is adjustable in a vertical axis, horizontal axis and angular axis, thereby enabling easier connection.
For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
The principles of the present invention and their advantages are best understood by referring to the illustrated embodiment depicted in
This mixture is fed into the blending unit's hydration device and the now near fully hydrated fluid stream is blended in the mixer 1107 with proppant (typically sand) from the proppant storage system 1109 to create the final fracturing fluid. This process can be accomplished continuously at downhole pump rates. The final fluid is directed to a pumping grid 1111, which commonly consists of several pumping units that pressurize the frac fluid, which is subsequently directed to a central manifold 1107. The central manifold 1107 connects and directs the fluid via connections 1109 to multiple wells 1110 simultaneously or sequentially. The manifold 1107 is typically known in the industry as a zipper manifold. One advantage of the principles of the present invention is the replacement of this manifold.
In use, the high pressure frac vessel 202 is connected to the inlet cross 214 and each outlet cross 206 (e.g., 206a-d) is connected to a corresponding frac tree 216 (e.g., 216a-d), which has been installed on a respective wellhead 203. In particular, a number of high-pressure lines 207a-207b connect the high pressure frac vessel 202 to corresponding inlet connection adapters on the inlet cross 214. Also, each outlet connection adapter on a particular outlet cross 206 is connected to a high-pressure line 207 which in turn is connected to a corresponding inlet connection on the frac tree 216. Thus, while the inlet cross 214 is connected to multiple pumps lines, each frac tree 216 is connected to a single outlet cross 206. However, since each outlet cross 206 comprises multiple outlet passages, a single frac tree 216 may be connected to several high-pressure lines 207. Moreover, since flow from the flow bore 220 into each outlet cross 206 is controlled by a corresponding valve 205 (e.g., 205a-d), each of these high-pressure lines 207 can be controlled with a single valve, or as in the case with a modern zipper manifold, dual valves with hydraulic actuators that are remotely controlled.
The block member 204 and the valves 205 are preferably supported on a single skid and connected to the skid by suitable means, such as mounting brackets (not shown). This arrangement allows the zipper manifold 201 to be transported and positioned on site as a unified assembly. Different versions of this type of arrangement, which provide more outlets such as four or six are in common use.
As discussed above, one problem faced with these prior art manifolds, particularly in view of the ever-increasing number of frac stages, is the reliability of the valves. The need for valve repairs leads to downtime, as well as increased risk to personnel who have to work in the danger zone. Furthermore, remote operation can lead to operational disconnects in communication and incorrect routing of high-pressure slurry, which is a main cause of accidents on fracing operations. A system is therefore required that eliminates the use of valves and replaces them with an advantageous arrangement, which will be referred to as a jumper manifold to distinguish it from a conventional zipper manifold.
The function of the jumper manifold 300 is generally the same as in the prior art discussed in connection with
In the embodiment of
Similarly, the inlet line 303 is shown as a monobore, which can be replaced by multiple lines coming into spool 305d. Spools 305 can have 3 to 6 inlets or outlets each and are connected to blocks 314a to 314d. In alternate embodiments, spools 305a to 305d may be connected though a single block containing parts 305, 306 and 314. The blocks 314a to 314d have mechanical connectors 307a to 307d connected on top that can be remotely actuated to open and close and effect a connection. Preferably, the entire jumper manifold 300 assembly is mounted on a single skid 304.
Assuming, for discussion purposes, that it is desired to frac well 301a. Then a jumper 308, which is a pipe or other conduit with two end connectors, is installed between blocks 314a and 314d. Specifically, the jumper 308 is mechanically latched with connectors 307a and 307d respectively to affect a pressure tight connection.
Connectors 307b and 307c preferably have solid plugs installed (not detailed) so that the lines 302b and 302c are isolated from possible pressure sources 301b and 301c respectively. As a result, there is a direct connection from inlet line 303 to well 301a, such that well 301a is completely isolated from wells 301b and 301c, with no valves in the configuration that can leak, fail or be inadvertently operated. The mechanical connectors (latches) 307a to 307d preferably include pressure interlocks preventing their unlatching under pressure.
If it is desired to fracture the next stage for well 301b, then line 302b will be isolated by two valves on the frac stack (not shown) on well 301b, and depressurized by a bleed line (not shown). Then the connector 307b can be opened and the plug (not shown) removed. Thereafter line 302a from well 301a can be similarly isolated and depressurized as previously done for line 302b.
The upstream inlet line 303 from the frac pumps can be isolated by the dual isolation valves present in the main frac line (not shown, off skid) and bled off. Now the jumper 308 can be unlatched between connectors 307a and 307d, lifted and pivoted to enable latching with connector 307b, where previously the plug has been removed. The jumper 308 is lowered and then latched with connectors 307b and 307d. A blind plug is installed in latch 307a. Now well 301b can be worked with fracturing pressure, leaving well 301a and well 301c completely isolated for other activities like wirelining.
In
As the connection between the jumper and the plugs to the blocks is a vertical one, alignment can be carefully controlled and multiple seals or metal seals may be used, as there are no tolerance requirements, such as those required for moving a valve member. Consequently, the sealing system will be much more reliable than a valve and removes failure points.
In
To minimize the number of connections, the manifold interface 3150 may comprise a single docking station line 320 capable of accessing one or more wellheads from a single platform position, and the well interface 3100 may comprise a single wellhead line 330. The single lines may be capable of delivering fluid at similar rates and pressures that would have previously required multiple lines.
The well interface 3100 and the manifold interface 3150 may each include any components of a surface pipe string, including straight discharge joints, connections, couplings, elbows, swivel joints, valves, plugs, detectors and measurement equipment, etc.
A crane 345 may be mounted on the platform 3050 or on the vehicle chassis near the platform 3050. The crane 345 provide lifting, positioning, or support of components of the plug and pump system 3000 during rig-up/down. The crane 345 also may be utilized to provide additional stability during pumping operations. The crane 345 may be similar in many respects to conventional industrial cranes. The platform 3050 may be fixed, or it may be mounted on a mobile vehicle 355, such as a truck as illustrated in
As shown in
In some embodiments, one or more quick connectors 350 may be utilized to connect the plug and pump system 3000 to the docking station 335 or the wellhead 340. The quick connectors 350 may be locally or remotely operated. In many respects, quick connectors 350 may be similar to conventional quick connects. For example, a quick connector 350 may be of a large, conical shape to allow for a tolerance of several inches when positioning the quick connector 350 above the wellhead 340 (
For the following
Each one of these rig-ups has its advantages and disadvantages and are used based on customers preferences.
The prior art plug and pump system of
Resolving this inefficiency is the object of this invention. Referring now to
Such a schematic plan view of the prior art plug and pump system rigged up for six wells and with the aid of the current invention able to service all six wells is shown in
Referring now to
Continuing with
Some embodiments, the MFWEs 400 can be adjustable in a similar fashion as disclosed in
Although the invention has been described with reference to specific embodiments, these descriptions are not meant to be construed in a limiting sense. Various modifications of the disclosed embodiments, as well as alternative embodiments of the invention, will become apparent to persons skilled in the art upon reference to the description of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiment disclosed might be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
It is therefore contemplated that the claims will cover any such modifications or embodiments that fall within the true scope of the invention.
This application claims benefit of U.S. Provisional Application No. 63/079,269, filed Sep. 16, 2020, entitled MODULAR FRACING WELLHEAD EXTENSION (Atty. Dkt. No. QUAR02-34999), which is incorporated by reference herein in its entirety. This application is related to U.S. patent application Ser. No. 16/696,487, entitled HIGH PRESSURE JUMPER MANIFOLD, and to U.S. patent application Ser. No. 16/696,563, entitled HIGH PRESSURE AND HIGH FREQUENCY CONNECTOR AND ACTUATOR SYSTEM THEREFORE, each of which is incorporated by reference herein in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 63079269 | Sep 2020 | US |
