Apparatus and methods for conducting well-related fluids

Apparatus and methods for conducting well-related fluids are disclosed. The apparatus and methods may be used to mitigate erosion of fluid handling equipment by fluids associated with hydrocarbon wells. An exemplary apparatus comprises: an upstream conduit including an upstream fluid passage for receiving and conducting well-related fluid; a choke member including a choke fluid passage; and a downstream conduit including a downstream fluid passage in fluid communication with the upstream fluid passage via the choke fluid passage. A cross-sectional area of the downstream passage may be greater than a cross-sectional area of the upstream passage to allow expansion of the fluids passing through the choke such that the average velocity of such fluids may not exceed a threshold velocity selected to mitigate erosion of the downstream conduit.

TECHNICAL FIELD

The disclosure relates generally to the handling of well-related fluids and more particularly to mitigating erosion of fluid handling equipment by well-related fluids.

BACKGROUND OF THE ART

Hydraulic fracturing operations are used to improve the flow of hydrocarbons from subterranean formations and into a wellbores. Fracturing involves pumping of a fracturing fluid into the wellbore under extremely high pressure in order to induce fracturing in the formation rock immediately surrounding the wellbore to improve the transmission of hydrocarbons through the formation and into the wellbore. Proppants are often included in the fracturing fluid to penetrate the fractures created in the formation by the fracturing fluid and effectively prop the fractures open after the pressure is removed.

During or after hydraulic fracturing, cleaning and other operations related to the preparation of the oil or gas wells for long term production can include pressurized fluid(s) (materials) flowing back from the wells. Such flow back fluids may include a mixture of water, gas, oil, sand, solid rocks or other solids, completion fluid and drilling mud for example. Such flow back fluids can be abrasive and can cause erosion of existing fluid equipment. Existing equipment for handling such fluids must be monitored closely to prevent potentially catastrophic failures of such equipment due to erosion.

Improvement is therefore desirable.

SUMMARY

The disclosure describes an apparatus for conducting well-related fluid, the apparatus comprising: an upstream conduit including an upstream fluid passage for receiving and conducting well-related fluid, the upstream fluid passage being defined by a fluid passage-defining upstream conduit surface material and having an upstream cross-sectional area at an upstream location; a choke member including a choke fluid passage in fluid communication with the upstream fluid passage, the choke fluid passage being defined by a fluid passage-defining choke member surface material, the choke fluid passage having a choke inlet, for receiving the well-related fluid from the upstream fluid passage, and a choke outlet, the choke fluid passage having a minimum choke cross-sectional area that is smaller than the upstream cross-sectional area; and a downstream conduit including a downstream fluid passage in fluid communication with the upstream fluid passage via the choke fluid passage and configured to receive the well-related fluid from the choke outlet and conduct the well-related fluid, the downstream fluid passage being defined by a fluid passage-defining downstream conduit surface material and having a downstream cross-sectional area at, or substantially at the choke outlet, or disposed within six (6) inches of the choke outlet, wherein the downstream cross-sectional area is larger than the upstream cross-sectional area; wherein the wear resistance of the fluid passage-defining choke member surface material is greater than the wear resistance of the fluid passage-defining downstream conduit surface material.

In another aspect, there is provided an assembly for conducting well-related fluid, the assembly comprising: an upstream conduit including an upstream fluid passage defined therein for receiving and conducting well-related fluid, the upstream fluid passage having an upstream cross-sectional area at an upstream location; a removably installed choke member including a choke fluid passage defined therein, the choke fluid passage having a choke inlet, for receiving the well-related fluid from the upstream fluid passage, and a choke outlet, the choke fluid passage having a minimum choke cross-sectional area that is smaller than the upstream cross-sectional area; and a downstream conduit including a downstream fluid passage defined therein in fluid communication with the upstream fluid passage via the choke fluid passage and configured to receive the well-related fluid from the choke outlet and conduct the well-related fluid, the downstream fluid passage having a downstream cross-sectional area at, or substantially at, the choke outlet, or disposed within six (6) inches of the choke outlet, that is larger than the upstream cross-sectional area.

In a further aspect, there is provided an apparatus for conducting well-related fluid, the apparatus comprising: a first choke member including a first choke fluid passage defined therein, the first choke fluid passage being configured to receive a pressurized well-related fluid and cause a first pressure drop in the well-related fluid; and a first conduit including a first fluid passage defined therein, the first fluid passage having a first introduction region configured to receive the well-related fluid from the first choke fluid passage and conduct well-related fluid toward a container, the first fluid passage having a first cross-sectional area at the first introduction region that is sized based on: a predetermined flow rate of well-related fluid through the first fluid passage; a predetermined pressure of the well-related fluid in the first fluid passage; a predetermined portion of the well-related fluid being compressible and a first threshold average fluid velocity through the first fluid passage selected to mitigate erosion.

In another aspect, there is provided a method for conducting compressible well-related fluid toward a container, the method comprising: receiving a flow of pressurized compressible well-related fluid; reducing a pressure of the compressible well-related fluid; allowing the compressible well-related fluid to expand immediately after the reduction in pressure of the compressible well-related fluid, the expansion of the compressible well-related fluid being based on: a predetermined flow rate of the compressible well-related fluid; a predetermined pressure of the expanded compressible well-related fluid; a predetermined portion of the compressible well-related fluid being compressible and a threshold average fluid velocity selected to mitigate erosion of the fluid handling equipment; and conducting the expanded compressible well-related fluid toward a container at an average velocity that is below the predetermined threshold average fluid velocity.

In another aspect, there is provided a method for conducting compressible well-related fluid, the method comprising: receiving a flow of pressurized compressible well-related fluid within a choke, the choke including a choke fluid passage having a minimum choke cross-sectional area; reducing a pressure of the compressible well-related fluid within the choke fluid passage sufficiently to effect expansion of the compressible well-related fluid, such that the effected reduction in pressure is at least a twenty (20) percent pressure reduction; discharging the depressurized compressible well-related fluid from an outlet of the choke into a downstream conduit including a downstream fluid passage in fluid communication with the choke fluid passage and configured to receive the well-related fluid from the choke outlet and conduct the well-related fluid, the downstream fluid passage having a downstream cross-sectional area at, or substantially at, the choke outlet, or disposed within six (6) inches of the choke outlet, wherein the downstream cross-sectional area is larger than a cross-sectional area of an upstream fluid passage through which the pressurized compressible well-related fluid is flowed at an upstream location, upstream of the choke.

In another aspect, there is provided an assembly for conducting well-related fluid, the assembly comprising: an upstream conduit including an upstream fluid passage defined therein for receiving and conducting well-related fluid, the upstream fluid passage having an upstream cross-sectional area at an upstream location; a choke member including a choke fluid passage defined therein, the choke fluid passage having a choke inlet, for receiving the well-related fluid from the upstream fluid passage, and a choke outlet, the choke fluid passage having a minimum choke cross-sectional area that is smaller than the upstream cross-sectional area, the choke member characterized by a friction loss coefficient (Kf) of at least 15; and a downstream conduit including a downstream fluid passage defined therein in fluid communication with the upstream fluid passage via the choke fluid passage and configured to receive the well-related fluid from the choke outlet and conduct the well-related fluid, the downstream fluid passage having a downstream cross-sectional area at, or substantially at, the choke outlet, or disposed within six (6) inches of the choke outlet, that is larger than the upstream cross-sectional area.

In a further aspect, there is provided an assembly for conducting well-related fluid, the assembly comprising: a choke member including a choke fluid passage defined therein, the choke fluid passage having a choke inlet, for receiving the well-related fluid from the upstream fluid passage, and a choke outlet, the choke fluid passage having a minimum choke cross-sectional area; an upstream pipe connected to the choke member, upstream of the choke member, the upstream pipe including an upstream fluid passage defined therein for receiving and conducting well-related fluid, the upstream fluid passage having an upstream cross-sectional area at an upstream location; and a downstream pipe connected to the choke member, downstream of the choke member, the downstream pipe including a downstream fluid passage defined therein in fluid communication with the upstream fluid passage via the choke fluid passage, the downstream fluid passage being configured to receive the well-related fluid from the choke outlet and conduct the well-related fluid, the downstream fluid passage having a downstream cross-sectional area at a downstream location that is larger than the upstream cross-sectional area.

In a further aspect, there is provided an assembly for conducting well-related fluid, the assembly comprising: a choke member including a choke fluid passage defined therein, the choke fluid passage having a choke inlet, for receiving the well-related fluid from the upstream fluid passage, and a choke outlet, the choke fluid passage having a minimum choke cross-sectional area; an upstream pipe connected to the choke member, upstream of the choke member, the upstream pipe including an upstream fluid passage defined therein for receiving and conducting well-related fluid, the upstream fluid passage having an upstream cross-sectional area at an upstream location; an expander connected to the choke member, downstream of the choke member; and a downstream pipe connected to the choke member, downstream of the choke member, via the expander, the downstream pipe including a downstream fluid passage defined therein in fluid communication with the upstream fluid passage via the choke fluid passage, the downstream fluid passage being configured to receive the well-related fluid from the choke outlet and conduct the well-related fluid, the downstream fluid passage having a downstream cross-sectional area at a downstream location that is larger than the upstream cross-sectional area.

Further details of these and other aspects of the subject matter of this application will be apparent from the detailed description and drawings included below.

DETAILED DESCRIPTION

Aspects of various embodiments are described through reference to the drawings.

FIG. 1shows a fluid conducting apparatus, generally shown at10, according to the prior art. Fluid conducting apparatus10comprises a conduit having upstream portion12and downstream portion14. Upstream portion12and downstream portion14have substantially equal cross-sectional areas, respectively shown at12and14. Fluid conducting apparatus10also comprises choke16defining choke fluid passage17. Upstream portion12and downstream portion14are in fluid communication via choke fluid passage17. The use of chokes for restricting fluid flow is known. The flow-restricting function of chokes can cause an associated pressure (i.e., head) loss in a fluid flowing through choke fluid passage17. For example, as a fluid flows from upstream portion12, through choke fluid passage17along arrow18, and into downstream portion14, choke16causes a pressure drop in the fluid. Accordingly, fluid pressure P14in downstream portion14is lower than fluid pressure P12in upstream portion12.

When the fluid passing through choke16is compressible, such drop in pressure can result in expansion of the fluid. For a gaseous (e.g., compressible) portion of such fluid, the magnitude expansion of the fluid can be a function of the drop in pressure of the fluid. For example, the expansion of a gaseous portion of a fluid may be proportional to the drop in pressure and may be estimated using Boyle's law; P1*V1=P2*V2, where P1and V1are a first pressure and corresponding first volume respectively of a gas and P2and V2are a second pressure and corresponding second volume respectively of the gas. Hence, since the pressure drop across choke16causes an expansion of compressible phase(s) in fluid in downstream portion14and the cross-sectional area14of downstream portion14is equal to the cross-sectional area12of upstream portion12, the expansion of the fluid will cause a corresponding increase in velocity of the fluid. Accordingly, the velocity of the fluid will be higher in downstream portion14than in upstream portion12in the event where the pressure drop caused by choke16results in an expansion of the fluid.

During well-related applications involving flow back of well-related fluids, the flow back fluids can be pressurized to high pressures such as 10 ksi (kilopounds per square inch) and these pressures must be reduced before the fluids can be sent to the container(s) at atmospheric pressures. Some well-related fluids such as flow back fluids can be multi-phase fluids that may, for example contain gaseous phases (e.g., natural gas), liquid phases (e.g., water), drilling mud, sand and/or proppant used in hydraulic fracturing processes. Accordingly, such well-related fluids can be abrasive and can cause erosion of fluid handling equipment. Pipe erosion, when started can be considered by most as being similar to tooth decay. Once a path of erosion has started it can tend to continue vigorously.

If fluid conducting apparatus10is used to cause a decrease in pressure of well-related fluids during a flow back operation, the pressure drop can cause the fluids to expand and thereby cause the velocity of the fluid to increase in downstream portion14and consequently increase the risk of erosion in downstream portion14in relation to upstream portion12. Depending on the magnitude of the pressure drop, the flow rate of fluid(s) and also the portion of the fluid being compressible, the increase in velocity and corresponding risk of erosion of downstream portion14and any downstream fluid handling equipment can be significant.

Solid particles such as those that may be found in well-related fluids in combination with high velocity, friction and turbulence can increase the risk of erosion in fluid handling equipment. It has been determined that in oilfield applications where solids in the form of drilling mud, sand (e.g., propant) or any produced or drilled solids will erode fluid handling equipment such as piping. For example, erosion can be more severe when fluid velocities exceed 120 ft/s. It can be difficult some cases to reduce the velocity of well-related fluids using standard oilfield practices and equipment and keep velocities at safe levels where erosion is mitigated. This is especially true when compressible gas is a part of the multi-phase fluid stream because of the expansion of compressible phase(s) when the pressure of the fluid(s) is decreased such as in downstream portion14for example.

When a choke16(e.g. flow restriction) is utilized there can be a pluming effect as the fluid(s) exit the choke16and enter outlet14from the rapid-transition of upstream pressure P12to the downstream pressure P14. This effect can be compounded by the extreme turbulence of the sheering effect of the fluid(s) going through the choke16. The pluming effect can encounter the internal walls outlet14on the downstream side of choke16and result in erosion starting immediately downstream of the choke16. Most failures due to erosion (e.g., wash outs and loss of containment) can occur directly downstream of choke16.

FIG. 2shows an axial cross-sectional view of an exemplary fluid conducting apparatus20in accordance with the present disclosure. Apparatus20may be used in well-related applications for conducting multi-phase, well-related fluids such as flow back fluids that may be at least partially compressible. For example, apparatus20may be used in operations associated with hydraulic fracturing of hydrocarbon wells. During hydraulic fracturing operations, a well undergoing hydraulic fracturing can become plugged with sand (proppant) that is injected into the well to prop the fractures open when the pressure of the fracturing fluid is released following a hydraulic fracturing operation. In such occurrances, a clear-out operation must be conducted on the well to unplug the well. Such clear-out operations can result in high pressure fluid(s) and relatively large amounts of sand flowing back from the well. The fluids including the sand are collected in one or more flow back tanks open to the atmosphere. However, the pressure of the flow back fluid(s) must be reduced prior to collection in the flow back tank(s).

Fluid conducting apparatus20may be used to mitigate erosion of fluid conducting equipments during operations. For example fluid conducting apparatus20may be used to control the velocity of such fluids in fluid handling equipment such that the average velocity of such fluids may not exceed a threshold velocity selected to mitigate erosion. The term “average velocity” through a conduit is used herein as representing the volumetric flowrate divided by the cross-sectional area of the conduit.

Fluid conducting apparatus20may comprise upstream conduit(s)22defining upstream fluid passage(s)24for receiving and conducting well-related fluid(s); choke(s)26including choke member(s)27defining choke fluid passage(s)28; and downstream conduit(s)30defining downstream fluid passage(s)32. Upstream fluid passage24may have an upstream cross-sectional area taken, for example, at location34along upstream fluid passage24and transverse to upstream fluid passage24. Upstream conduit22may comprise a pipe of uniform diameter and internal cross-sectional area along its length. Upstream fluid passage24may have a substantially uniform cross-sectional area. The upstream cross-sectional area may be a maximum cross-sectional area, and the maximum cross-sectional area may be disposed at one or more locations along its length. The upstream cross-sectional area may also be taken at, or substantially at, the choke inlet (such as at location34). The upstream cross-sectional area may also be taken within an operative distance of six (6) inches of the choke inlet, measured along the axis of the flow passage. For example, the operative distance is three (3) inches. As a further example, the operative distance is one (1) inch. Upstream fluid passage24may be defined by interior wall(s)36of upstream conduit22. Upstream conduit22may be configured for fluid connection to a hydrocarbon well and accordingly may receive well-related fluid(s) (e.g., flow back fluids) during well-related operations. For example, upstream conduit22may comprise flange(s)37for removably coupling upstream conduit22to other fluid handling equipment.

Choke member27may include a conventional or other type of flow bean. Alternatively, choke26my be of other suitable type of choke (e.g., choke plate) suitable for use in conjunction with well-related fluid(s). Choke fluid passage28may have choke inlet(s)38for receiving well-related fluid(s) from upstream fluid passage24and choke outlet(s)40. Choke fluid passage24may be defined by interior wall(s)42of choke member26.

Choke fluid passage28may have a minimum choke cross-sectional area that is smaller than the upstream cross-sectional area. Accordingly, choke fluid passage28may serve as a flow restriction and cause a pressure drop in the well-related fluid(s) flowing therethrough. Since the average flow velocity of well-related fluid(s) through choke fluid passage28may be higher than the average flow velocity of well-related fluid(s) through upstream fluid passage24, choke member27may be made of a material having a wear resistance that is higher than upstream conduit22and/or downstream24. Accordingly, interior wall(s)42of choke member27may comprise a material having a higher wear resistance than a material comprised in interior wall(s)36of upstream conduit22. The comparison of wear resistance may be done in accordance with standard testing procedures such as defined by applicable standards from ASTM International. For example, the difference in wear resistance may be defined by an amount of material removal during a specified time period under well-defined testing conditions. Choke member27may be a distinct and replaceable component made of a different material than upstream conduit22and/or downstream conduit30. For example, choke member27may comprise a material having a hardness higher than the material of upstream conduit22and/or downstream conduit30. For example choke member27may comprise tungsten carbide or ceramic, and conduits24and30may comprise carbon steel, A105B carbon steel (sour service), A333 carbon steel (sour service), 4130 pipe or 4140 pipe.

Choke26may comprise choke body(ies)44to which choke member27may be removably installed to establish fluid communication between upstream fluid passage24and downstream fluid passage32. For example, choke member27may be threadably secured to choke body44via threads46. Accordingly, choke member27may be removably secured to choke body44and may be replaceable. For example, choke member27may be replaced in case of wear (e.g., due to erosion) or if another choke member27having a different minimum choke cross-sectional area is desired instead (e.g., if the flow resistance offered by choke member27is to be changed). Choke26may also comprise flange(s)48removably coupling choke26to other fluid handling equipment. For example, flanges48may be used to removably couple choke26to upstream conduit22and also to removably couple choke26to downstream conduit30.

Downstream conduit30may comprise adaptor(s)50and downstream pipe(s)52. Downstream pipe52may have a substantially uniform diameter and internal cross-sectional area along its length. Together, adaptor50and downstream pipe52may define downstream fluid passage32. Downstream fluid passage32may be in fluid communication with upstream fluid passage24via choke fluid passage28and configured to receive well-related fluid(s) from choke outlet40and conduct the well-related fluid. Downstream pipe52may conduct well-related fluid(s) to a container described further below in relation toFIGS. 3,4and5). Adaptor50may comprise flanges54that may be used to removably couple adaptor50to other fluid handling equipment. For example, flanges may be used to removably couple adaptor50to choke26and/or to downstream pipe52. Similarly, downstream pipe52may comprise flanges56that may be used to removably couple downstream pipe52to other fluid handling equipment such as adaptor50.

Downstream fluid passage32may have an introduction region at or near position50A within which well-related fluid(s) may be introduced into downstream fluid passage32. For example, choke member27may partially extend into downstream conduit30up to position50A. Potentially varying with the position at which the cross-sectional area is taken, the cross-sectional area within the downstream fluid passage32is larger than the minimum choke cross-sectional area by a factor of at least two (2). For example, the factor is at least three (3).

A cross-sectional area of downstream fluid passage32at position50A (e.g., at the introduction region), where choke outlet40is positioned, may be larger than the upstream cross-sectional area of upstream fluid passage24taken at position34, which may be near or at choke inlet38. Position50A may, in some embodiments, be at, or substantially at, the choke outlet40. A cross-sectional area of downstream fluid passage32, taken within an operative distance of six (6) inches of the choke outlet40, measured along the axis of the downstream fluid passage32, is also larger than the upstream cross-sectional area of upstream fluid passage24, taken at, or near, the choke inlet38. In some embodiments, for example, the operative distance is three (3) inches. In some embodiments, for example, the operative distance is one (1) inch. For example, a cross-sectional area of downstream fluid passage32at position50may also be larger than the upstream cross-sectional area of upstream fluid passage24taken at, or near, the choke inlet38. As a further example, a cross-sectional area of downstream fluid passage32at position52A (e.g., at downstream pipe52) may also be larger than the upstream cross-sectional area of upstream fluid passage24taken at, or near, the choke inlet. Potentially varying with the positions at which the upstream and downstream cross-sectional areas are taken, the cross-sectional area of the downstream fluid passage is larger than the cross-sectional area of the upstream fluid passage by a factor of at least 1.1. For example, the factor is at least 1.2. As a further example, the factor is at least 1.25. As yet a further example, the factor is at least 1.5 As a further example, the factor is at least two (2).

For example, choke26may be adapted to be coupled to an upstream pipe having an outside diameter of 2 inches and to a downstream pipe having an outside diameter of 3 inches. Choke26may be adapted to be coupled to an upstream pipe having an outside diameter of 2 inches and to a downstream pipe having an outside diameter of 3 inches. Alternatively, choke26may be adapted to be coupled to an upstream pipe having an outside diameter of 2 inches and to a downstream pipe having an outside diameter of 6 inches. In light of the present disclosure, one skilled in the relevant arts will understand that the choke26could also be configured to be coupled to pipes of other sizes.

Downstream pipe52may have a substantially uniform cross-sectional area along a length of downstream pipe52. Accordingly, downstream passage32may have a substantially uniform cross-sectional area along the length of downstream pipe52. Downstream pipe52conduct de-pressurized well-related fluid(s) to a container which may be at atmospheric pressure.

Choke26may be configured to be removably coupled to (e.g. installed between) upstream and downstream conduits of the same or similar sizes so adaptor50may be used to adapt a downstream interface of choke26to downstream pipe52, which may be of a larger size (e.g., diameter) than upstream conduit22. Alternatively, if the downstream interface of choke26is configured to be coupled directly to downstream pipe52, then adaptor50may not be required. In any event, choke26may be removably coupled to upstream conduit22using flanges37and48and bolts58or other suitable fastener(s). Similarly, choke26may be removably coupled to downstream conduit30using flanges48and54and bolts58or other suitable fastener(s). Accordingly, choke26may be removably installed in fluid conducting apparatus20and thereby permit replacement of choke member27(e.g., choke bean or insert). Also adaptor50may be removably coupled to downstream pipe52using flanges54and56and bolts58or other suitable fastener(s). A plurality of bolts58may be circumferentially distributed about flanges37,48,54and56. Suitable sealing means (not shown) may be provided to substantially prevent leakage of well-related fluid(s) between the fluid handling components. For example sealing members (e.g., compressible seal, gasket) (not shown) may be provided between flanges37and48; between flanges48and54; and, between flanges54and56to substantially prevent leakage.

In light of the present disclosure, one skilled in the relevant arts will understand that other means of removably installing choke26and establishing fluid communication between upstream passage24, choke26and downstream passage32could be used instead or in addition to flanges37,48,54,56and bolts58. For example, suitable threaded pipe fittings61as illustrated inFIG. 3could be used for removably coupling various components of fluid conducting apparatus20and manifold60also illustrated inFIG. 3.

Adaptor50may provide a gradual expansion of downstream fluid passage32between choke body44and downstream pipe52. Accordingly, cross-sectional area of downstream fluid passage32at the introduction region (e.g., position50A) may be smaller than cross-sectional area of downstream fluid passage32at downstream pipe52(e.g., position52A). The cross-sectional area at the introduction region may be smaller because of the “plume effect” (see reference numeral59inFIG. 2) that is manifested as the fluid exits the choke outlet and becomes rapidly expanded due to the reduction in pressure effected by the choke26. In any case, the cross-sectional area of downstream fluid passage32at the introduction region (e.g., position50A) may be larger than the cross-sectional area of upstream fluid passage24(e.g., position34). The sizing of the cross-sectional areas at the in introduction region (e.g., position50A) and at downstream pipe52(e.g., position52A) will be explained in detail below.

FIG. 3is a top plan view of a plurality of chokes26installed in exemplary manifold60. Manifold60may be used for conducting well-related fluid(s) in container (tank)62during one or more well operations associated with hydraulic fracturing. For example, manifold60may receive pressurized fluid(s) via one or more inlets64from a hydrocarbon well (not shown). Manifold inlet64may split the flow of fluid(s) into a plurality of branches60A,60B of manifold60for delivery into container62. Each of branches60A,60B may comprise one or more chokes26for reducing the pressure of fluid(s) prior to delivering the fluid(s) to container62, which may be at atmospheric pressure.

Each branch60A,60B may be configured similarly. The plurality of chokes26A,26B may be used to cause stepwise pressure reductions in well-related fluid(s) prior to delivery to tank62. Accordingly, two or more chokes26A,26B may be coupled in serial flow communication. For example, branch60A may comprise first conduit66for receiving well-related fluid from manifold inlet64and conduct the well-related fluid(s) to first choke26A. Second conduit68may receive the well-related fluid from first choke26A and conduct the well-related fluid(s) to second choke26A. Second conduit68may comprise adaptor68A for interfacing with first choke26A. Third conduit70may receive the well related fluid(s) from second choke26B and conduct the well-related fluid(s) to tank62. Third conduit70may comprise adaptor70A for interfacing with second choke26B. Third conduit70may have a cross-sectional area that is larger than a cross-sectional area of second conduit68to permit expansion of well-related fluid(s) following the pressure reduction caused by second choke26B. Similarly, the cross-sectional area of second conduit68may be larger than the cross-sectional area of first conduit66to permit expansion of well-related fluid(s) following the pressure reduction caused by second choke26B. As will be explained further below, the progressively larger cross-sectional areas of conduits68and70may be sized to prevent the average velocity of the well-related fluid(s) from exceeding a threshold average fluid velocity selected to mitigate erosion of conduits68and70.

Third conduits70of each branch60A and60B of manifolds60may each lead to one or more diffusers72disposed inside tank62. Diffusers72may serve to diffuse the well-related fluid(s) as it/they is/are delivered to tank62. Diffusers72may comprise an elongated conduit extending inside tank62and comprising a plurality of openings through which the well-related fluid(s) may exit. Manifold60may also comprise pressure gauges74that may be used to monitor fluid pressures in second conduit68and/or third conduit70(i.e., downstream from first choke26A and/or downstream from second choke26B).

FIG. 4is a schematic front elevation view of the manifold ofFIG. 3. It is noted that adaptors68A and70A shown inFIG. 3are omitted inFIG. 4and that chokes26A,26B are shown schematically as plate-type chokes for illustration purposes only. One skilled in the relevant arts will understand that other types of chokes, including bean-type chokes, could also be suitable for use in manifold60.

FIG. 5is an axonometric view of an exemplary container (tank)62for storing well-related fluid(s). Container62may comprise container inlets76to which each branch60A,60B of manifold60may be coupled for delivery of well-related fluid(s) from third conduits70into diffusers72located in container62. Accordingly, manifold60may be installed for fluid communication with container62during flow back operations. For example, manifold may remain installed on container62even during transport of container62so that it does not have to be uninstalled and re-installed between operations.

Container62may have rear axle78which may allow container62to be moved by a fifth wheel tractor truck. Container62may have platform80to support operators and that may facilitate the coupling of manifold60to container62and also the monitoring of pressure gauges74during operation. Container62may also have splash guards82disposed above diffusers72to substantially prevent well-related fluid(s) from being directed upward from diffusers72and out of container62during operation.

As mentioned above, the well-related fluids that are handled during some well applications may be highly pressurized (e.g., 10 ksi) and may comprise multiple phases including a gases, liquids and solid particles (e.g. sand, proppants) that may be abrasive. Accordingly, such fluids may be at least partially compressible at least due to the presence of a gaseous phase. During some operations where the multi-phase, pressurized well-related fluid(s) flow(s) back from the well and must be stored in container42that is at atmospheric pressure, the pressure of the well-related fluid(s) must be reduced significantly before it/they are delivered to container62. The reduction in pressure and the delivery of such well-related fluids may be achieved using apparatus and devices described herein.

For example, through the appropriate sizing of chokes26A and26B and also the appropriate sizing of second conduits68and third conduits70, the average velocity of well-related fluid(s) flowing through manifold60may be kept to levels that do not result in excessive erosion. For example, the proper sizing of the above fluid handling components may be used to keep the average velocity of the well-related fluid(s) below a threshold average velocity selected to mitigate erosion.

In some applications, fluid composition and fluid handling equipment (e.g., piping, valves . . . etc.) the threshold average velocity selected may be about 120 feet/second. Accordingly the threshold average velocity may be determined experimentally based on the specific application, operating conditions and acceptable rates or erosion.

The sizing of fluid handling components will be explained in relation toFIG. 2but it is understood that the teachings presented below could also relate to chokes26A and26B shown inFIG. 3. The sizing of components in fluid conducting apparatus20may be done to strategically decrease the pressure of the well-related fluid(s) and also increase the flow area for the well-related fluid(s) to occupy. Because gas expands when its pressure is reduced, the gas must occupy a larger volume a static state. In the case of a gas is flowing down a conduit of a constant cross-sectional area, a drop in pressure at particular point along the conduit will cause the gas to expand and consequently the velocity of the gas will increase downstream from the point of pressure drop (if no larger cross-sectional area is provided). The expansion of an ideal gas may be linear in accordance with the ideal gas law (e.g. Boyle's law) referred above, so that, for example, a gas at 10 ksi (absolute pressure) occupying a volume V1will require double the volume V1if the pressure of the gas is reduced to 5 ksi (absolute pressure). In the case of the gas flowing inside the conduit of constant cross-sectional area, this pressure drop will cause the average velocity of the gas in the conduit to double downstream of the pressure drop.

Even though the well-related fluid(s) conducted by fluid conducting apparatus20may not be entirely gaseous and may not be entirely compressible, the sizing of fluid conducting downstream conduit30may be determined based on a conservative estimation of the portion of well-related fluid(s) that may be compressible. Alternatively, it may be appropriate to assume, for the purpose of sizing downstream conduit30, that the entirety of the well-related fluid(s) is compressible in accordance with Boyle's law. This assumption may provide a conservative representation of the potential fluid expansion that may occur based on a given flow rate of multi-phase well-related fluid(s) in downstream conduit30. For example, using such assumption, if a portion of the well-related fluid is incompressible, then the expansion of the well-related fluid(s) will be less than the expansion capacity provided by downstream conduit30and hence the average velocity of the well-related fluid(s) downstream of choke26will still be below the threshold average fluid velocity selected to mitigate erosion.

Table 1 below illustrates exemplary numerical values of fluid velocities and pressures associated with reference toFIG. 2.

TABLE 1ParameterNumerical ValuePressure in upstream passage 243000psiVolumetric flow rate through upstream passage 242.2ft3/secInternal diameter of upstream passage 24 (circular0.167 ft (2 inches)pipe)Cross-sectional area of upstream passage 240.022ft2Average fluid velocity through upstream passage 24100ft/secPressure drop across choke 261500psiPressure in downstream passage 321500psiVolumetric flow rate through downstream passage4.4ft3/sec32 (calculated using Boyle's law assuming thatthe entirety of the fluid is compressible andbehaves as an ideal gas)Threshold average velocity to mitigate erosion of120ft/secdownstream passage 32Minimum cross-sectional area of downstream0.0367ft2passage 32 required to not exceed thresholdaverage velocityMinimum diameter of downstream passage 320.216 ft (2.6 inches)required to not exceed threshold average velocity(circular pipe)

While the minimum cross-sectional area calculated above may be required to keep the average velocity of the expanded well-related fluid(s) below the threshold average velocity selected to mitigate erosion, it may not be necessary that the fully enlarged cross-sectional area be located immediately downstream of choke outlet40(e.g., at position50A) due to entrance effects of the fluid(s) flowing out of choke26. For example, it may be desirable to have the fully expanded cross-sectional area of downstream passage32disposed at choke outlet40, but due to pluming of the fluid(s) as the fluid(s) exit(s) choke passage28, there may be an allowable distance between the fully expanded cross-sectional area and choke outlet40. As the well-related fluid(s) exit(s) choke outlet40, it/they may substantially continue to flow relatively along the longitudinal direction of choke passage28for some distance after choke outlet40before significant expansion and diffusion of the fluids. This distance may vary depending on the operation conditions but may be less than one (1) inch, for example, during some well-related flow back operations. For example, due at least partly to choke outlet40being positioned relatively centrally to downstream passage32, the velocity of the fluid(s) through downstream passage32near choke outlet40may be relative higher in a central region of downstream passage32and may not pose significant risk of erosion of the internal walls of downstream conduit30. Accordingly, some distance from choke outlet40may be required for the velocity profile of well-related fluid(s) through downstream passage32to become more uniform.

Nevertheless, it may be desirable to provide at least a partially expanded cross-sectional area of downstream passage32. Accordingly, cross-sectional area of downstream passage32taken at position50A may be greater than cross-sectional area of upstream passage24taken at position34. For example, it may be acceptable in some cases to use adaptor50to transition to the fully expanded cross-sectional area of downstream passage32taken at position52A at have choke outlet40positioned at a point along adaptor50. The fully expanded cross-sectional area of downstream passage32may be disposed immediately downstream of (e.g., at) choke outlet40or, alternatively, due to the entrance effects (e.g., pluming) of the well-related fluids into downstream passage32, it may be acceptable to have the fully expanded cross-sectional area of downstream passage32disposed substantially at (i.e., at some allowable downstream distance from) choke outlet40. In other words, the fully expanded cross-section area of downstream passage32may be disposed at some allowable distance that takes into consideration of the entrance effects of the well-related fluid(s) and does not pose an increased risk of erosion of downstream conduit30.

As mentioned above, a plurality of chokes26may be coupled in serial flow communication to achieve stepwise pressure drops of well-related fluid(s) during flow back operations prior to delivering the well-related fluid(s) to container62, which may be at atmospheric pressure. The sizing of fluid handling components for achieving stepwise pressure drops is illustrated through the numerical examples included in Table 2 below and in relation toFIG. 3. The stepwise pressure reductions may be done to limit the average velocity of well-related fluid(s) through individual chokes26and therefore reduce the risk of erosion of choke members27. Since choke members27may be made of materials having a greater wear resistance and/or hardness than that of conduits22and30, a different (e.g., higher) threshold average velocity may be selected for chokes26. Accordingly, methods presented herein may also be used to select choke sizes to mitigate erosion of chokes26A and26B.

TABLE 2ParameterNumerical ValuePressure at inlet 643000psiVolumetric flow rate through first conduit 660.167ft3/secInternal diameter of first conduit 66 (circular0.133 ft (1.6 inches)pipe)Internal cross-sectional area of first conduit 660.0139ft2Average fluid velocity through first conduit 6612.04ft/secPressure drop across choke 26A1500psiPressure in second conduit 681500psiVolumetric flow rate through second conduit0.335ft3/sec68 (calculated using Boyle's law assuming thatthe entirety of the fluid is compressible andbehaves as an ideal gas)Average fluid velocity through second conduit 685.99ft/secInternal cross-sectional area of second conduit 680.056ft2Internal diameter of second conduit 68 (circular0.267 ft (3.2 inches)pipe)Pressure drop across choke 26B1475psiPressure in third conduit 7025psiVolumetric flow rate through third conduit12.83ft3/sec70 (calculated using Boyle's law assuming thatthe entirety of the fluid is compressible andbehaves as an ideal gas)Average fluid velocity through third conduit 70101.87ft/secInternal cross-sectional area of third conduit 700.126ft2Internal diameter of third conduit 70 (circular0.4 ft (4.8 inches)pipe)

Choke passage28may have a cross-sectional area that is smaller than the cross-sectional area of upstream passage24. Choke passage28may also have a cross-sectional area that is smaller than the cross-sectional area of downstream passage32. The cross-sectional area of choke passage28may be selected to provide a desired pressure drop in well-related fluid(s) being conducted through fluid conducting apparatus20. For example, the cross-sectional area of choke passage28may be selected to provide a friction loss coefficient (Kf) of at least fifteen (15). For example, the Kfis at least twenty (20). As a further example, the Kfis at least twenty (20). Typically, a larger pressure differential required results in a smaller the choke diameter being required for a specific fluid (e.g., gas) flow rate. The internal diameter of choke(s)26A,26B (e.g., the internal diameter of choke passage28) can be calculated and pressures (upstream and downstream) predicted for desired pressure drops.

FIG. 6shows a flow chart illustrating exemplary method100in accordance with one aspect of the present disclosure. For example, method100may comprise: receiving pressurized well-related fluid(s) (see block110); reducing the pressure of the well-related fluid(s) (see block120); Allowing the well-related fluid(s) to expand in a conduit while keeping the velocity of the expanded well-related fluid(s) below a threshold velocity selected to mitigate erosion of the conduit (see block130); and delivering the well-related fluid(s) to a container (see block140). As mentioned above, the pressure reduction may be done stepwise used a plurality of chokes26A and26B connected in serial flow communication. Accordingly, blocks110,120and130may be repeated as desired to achieve the desired overall pressure reduction in the desired number of steps (e.g., stages) as shown by arrow150.

As explained above, the expansion of the well-related fluid(s) may be done by providing downstream passage32of expanded cross-sectional area at or substantially at, choke outlet40for the purpose of limiting the average velocity of the well-related fluid(s) below at threshold selected to mitigate erosion. According to the numerical examples provided above, the downstream cross-sectional area may be sized based on: a predetermined flow rate of well-related fluid(s) through downstream fluid passage32; a predetermined pressure of the well-related fluid(s) in downstream fluid passage32; a predetermined portion of the well-related fluid(s) being compressible and a threshold average fluid velocity through downstream fluid passage(s) selected to mitigate erosion. The threshold average velocity may be selected so that fluid handling equipment will not be rapidly eroded and will provide an acceptable level of service for and acceptable period of time. For example, in well-related operations involving pressurized flow back fluid(s), such threshold average velocity may be around 120 ft/sec.

The above description is meant to be exemplary only, and one skilled in the relevant arts will recognize that changes may be made to the embodiments described without departing from the scope of the invention disclosed. For example, the blocks and/or operations in the flowcharts and drawings described herein are for purposes of example only. There may be many variations to these blocks and/or operations without departing from the teachings of the present disclosure. For instance, the blocks may be performed in a differing order, or blocks may be added, deleted, or modified. The present disclosure may be embodied in other specific forms without departing from the subject matter of the claims. Also, one skilled in the relevant arts will appreciate that while the systems, apparatus and assemblies disclosed and shown herein may comprise a specific number of elements/components, the systems, apparatus and assemblies could be modified to include additional or fewer of such elements/components. For example, while any of the elements/components disclosed may be referenced as being singular, it is understood that the embodiments disclosed herein could be modified to include a plurality of such elements/components. The present disclosure is also intended to cover and embrace all suitable changes in technology. Modifications which fall within the scope of the present invention will be apparent to those skilled in the art, in light of a review of this disclosure, and such modifications are intended to fall within the appended claims.