Hydrates For Well Control

Abstract

Systems, apparatus, and methods for controlling a well blowout comprising: a flow control device such as a blowout preventer on a wellbore, the primary throughbore of the flow control device comprising internal dimensional irregularities creating a non-uniform flow path in the primary throughbore which as sufficient fluid rate may enhance pressure fluid pressure drop therein; a control fluid aperture fluidly connected with the wellbore for introducing a control fluid through a control fluid aperture and into the primary throughbore while wellbore fluid flows through the wellbore; a hydrate component introduction pump for introducing the hydrate inducing component into the control fluid; a hydrate inducing fluid aperture positioned in the wellbore conduit below the control fluid aperture for introducing the hydrate inducing fluid into the wellbore and for combining with the control fluid that includes the hydrate inducing fluid to form a saturated hydrate forming fluid mixture within the primary throughbore while control fluid is also being introduced into the wellbore through the control fluid aperture.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application 62/786,870 filed Dec. 31, 2018 entitled “Hydrates for Well Control,” the entirety of which is incorporated by reference herein.

FIELD OF THE DISCLOSURE

The present disclosure is directed generally to apparatus, systems, and methods for well control, such as may be useful in relation to a hydrocarbon well blowout event and more particularly to systems and methods pertaining to an interim intervention operation for an out of control well.

BACKGROUND OF THE DISCLOSURE

Safety and time are of the essence in regaining control of a well experiencing loss of wellbore pressure control. Loss of pressure control and confinement of a well is commonly referred to as a “blowout.” Well control pressure management or “intervention” is required to regain pressure control and confine wellbore fluids within the formation and wellbore. Well control intervention is an important concern not only to the oil and gas industry from a safety and operations standpoint, but also with regard to protecting commercial, environmental, and societal interests at large.

Well control intervention systems and methods are generally classified as either conventional or unconventional. Conventional intervention systems are generally used when the well can be shut-in or otherwise contained and controlled by the wellbore hydrostatic head and/or surface pressure control equipment. In contrast, unconventional well control intervention systems are generally used to attempt to regain control of flowing wells that cannot be controlled by the wellbore fluid and/or surface pressure control equipment. Such “blowout” situation may result from failure of downhole equipment, loss of wellbore hydrostatic control, and/or failure of surface pressure-control equipment. In both intervention classifications, the object of regaining well control is to halt the flow of fluids (liquid and gas) from the wellbore, generally referred to as “killing” or “isolating” the well. Unconventional methods are more complex and challenging than conventional methods and frequently require use of multiple attempts and/or methods, often requiring substantial time investment, including sometimes drilling relief wells. Improved methods and systems for unconventional well control intervention are needed.

Unconventional well control intervention methods include “direct” intervention, referring to intervention actions occurring within the wellbore and indirect intervention refers to actions occurring at least partially outside of the flowing wellbore, such as via a relief well. Two known unconventional direct intervention methods include a momentum weighted fluid methods and dynamic weighted fluid methods. Momentum weighted fluid methods rely upon introducing a relatively high density fluid at sufficient rate and velocity, directionally oriented in opposition to the adversely flowing well stream, so as to effect a fluid collision having sufficient momentum that the kill fluid overcomes the adverse momentum of the out of control fluid stream within the wellbore. Such process is commonly referred to as “out running the well.” This is often a very difficult process, especially when performed at or near the surface of the wellbore (e.g., “top-weighted fluid”).

Dynamic weighted fluid methods are similar to momentum weighted fluid methods except dynamic weighted fluid methods rely upon introduction of the weighted fluid stream into the wellbore at a depth such that hydrostatic and hydrodynamic pressure are combined within the wellbore at the point of introduction of the weighted fluids into the wellbore, thereby exceeding the flowing pressure of the blowout fluid in the wellbore and killing the well. Dynamic weighted fluid interventions are commonly used in relief well and underground blowout operations, but are also implemented directly in wellbores that contain or are provided with a conduit for introducing the weighted fluid into the wellbore relatively deep so as to utilize both hydrostatic and hydrodynamic forces against the flowing fluid.

However, each of the aforementioned well control procedures require significant time to plan, deploy resources, and enact. Need remains for yet an additional well control intervention that can be relatively quickly implemented as compared to the other intervention mechanisms. An efficient response system is desired to provide interim well control intervention that at least temporarily impedes or preferably halts the uncontrolled flow of fluids from an out of control wellbore and provides a time cushion until a more permanent solution can be developed and implemented.

SUMMARY OF THE DISCLOSURE

Systems, equipment, and methods are disclosed herein that may be useful for intervention in a wellbore operation that has experienced a loss of hydrostatic formation pressure control, such as a blowout. The disclosed information may enable regaining some control of the well, mitigating the flow rate of the blowout, and potentially even wholly halt the uncontrolled fluid flow. The disclosed technology includes creating a hydrate buildup within the wellbore that creates an impediment or plug that prevents or restricts the blowout fluid flow rate.

The disclosed control system may be relatively quickly implemented as an interim intervention mechanism to restrict or contain effluent from the wellbore so as to provide a time-cushion until a permanent well control solution can be implemented. Thereby, conventional and/or other unconventional well control operations for a permanent or final solution may (subsequently or concurrently) proceed in due course to stop or control the well effluent flowrate.

In one aspect, the methods disclosed herein may include systems, apparatus, and methods for controlling a well blowout comprising; a flow control device such as a blowout preventer on a wellbore; a control fluid aperture fluidly connected with the wellbore for introducing a control fluid through a control fluid aperture and into the wellbore while wellbore fluid flows from the subterranean formation through the wellbore; a hydrate inducing fluid aperture positioned in the wellbore conduit below the control fluid aperture for introducing a hydrate inducing fluid into the wellbore while control fluid is also being introduced into the wellbore through the control fluid aperture.

In an aspect, the primary throughbore of the flow control device comprising internal dimensional irregularities creating increased friction through a hydro-dynamically tortuous or non-uniform flow path in the primary throughbore, or such as drill pipe or other tools positioned therein.

In another aspect, the processes disclosed herein may include a method of performing a wellbore intervention operation to reduce an uncontrolled flow of wellbore fluids from a subterranean wellbore, the method comprising: providing a flow control device, the flow control device engaged with a top end of a wellbore conduit that includes a wellbore throughbore, the flow control device including a primary throughbore that comprises at least a portion of the wellbore throughbore, the primary throughbore being coaxially aligned with the wellbore throughbore; providing a control fluid aperture in at least one of (i) the top end of the wellbore conduit, (ii) the flow control device, and (iii) a location intermediate (i) and (ii), the control fluid aperture being fluidly connected with the wellbore throughbore; providing a hydrate inducing fluid aperture into the wellbore throughbore at an upstream location in the wellbore throughbore with respect to flow of wellbore blowout fluid flowing through the wellbore throughbore (that is, below the control fluid aperture); introducing a control fluid through the control fluid aperture and into the wellbore throughbore while a wellbore blowout fluid flows from the subterranean formation through the wellbore throughbore at a wellbore blowout fluid flow rate, whereby the control fluid is introduced into the wellbore throughbore at a control fluid introduction rate that is at least 25% (by volume) of the previously estimated or determined wellbore blowout fluid flow rate from the wellbore throughbore prior to introducing the control fluid into the wellbore throughbore; and introducing a hydrate inducing fluid through the hydrate inducing fluid aperture and into the wellbore throughbore while pumping the control fluid through the control fluid aperture.

In yet another aspect, the advantages disclosed herein may include an apparatus for performing a wellbore intervention operation to reduce an uncontrolled flow rate of wellbore blowout fluids from a subterranean wellbore, the apparatus comprising: a flow control device, the flow control device engaged with a top end of a wellbore conduit that includes a wellbore throughbore at a surface location of the wellbore conduit, the flow control device including a primary throughbore that includes the wellbore throughbore, the primary throughbore coaxially aligned with the wellbore throughbore; a control fluid aperture in at least one of (i) the top end of the wellbore conduit, (ii) the flow control device, and (iii) a location intermediate (i) and (ii), the control fluid aperture being fluidly connected with the wellbore throughbore, the control fluid aperture for introducing a control fluid into the wellbore throughbore while a wellbore blowout fluid flows from the subterranean formation through the wellbore throughbore at a wellbore blowout fluid flow rate, whereby the control fluid is introduced at a control fluid introduction rate of at least 25% (by volume) of the wellbore blowout fluid flow rate from the wellbore throughbore prior to introducing the control fluid into the wellbore throughbore; a hydrate inducing fluid aperture in the wellbore throughbore positioned at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to direction of flow of wellbore fluid flowing through the wellbore throughbore, the hydrate inducing fluid aperture capable to introduce a hydrate inducing fluid into the wellbore throughbore while the control fluid is introduced into the wellbore throughbore through the control fluid aperture.

One collective objective of the presently disclosed technology is creating a pressure drop in the flowing blowout fluid within the primary throughbore by creating hydrodynamic conditions therein that approach the maximum fluid conducting capacity of the primary throughbore, by introducing control fluid therein. The prior art teaches momentum controls and dynamic controls that also utilize introducing fluid into the wellbore conduit 10. However, the prior art types of intervention mechanisms typically rely upon introducing the fluid into the wellbore conduit as close to bottom hole source of the blowout energy as possible in order to provide an increase hydrostatic column on the formation. That is, they require introducing a separate conduit such as coil tubing or drill pipe relatively deep into the wellbore to realize a hydrostatic benefit and/or use momentum in the control fluid by vigorously directing the control fluid directionally opposing the flow direction of the blowout fluid in effort to overwhelm the blowout fluid with momentum forces and eventual hydrostatic forces. Such technique is known in using weighted drilling mud through a nozzle against a flowing gas stream. In contrast to those prior art methods, according to the presently claimed technology a pressure drop is created within surface-accessible equipment such as near or in the wellhead or related equipment, by overwhelming the flow conduit therethrough with more fluid that the available pressure wellbore flowing pressure therein can move through the opening, thus creating an increase in pressure drop through the wellhead equipment. Successful implementation of the presently disclosed technology affords an additional method (in addition to the previously known prior art methods) to achieve some measure of control over the blowout fluid in the most readily accessible points possible—within the wellhead or proximity thereto—while using readily portable equipment and without requiring introduction of a separate conduit or work string deep into the wellbore or requiring removal of an obstruction or string from therein. Such successful implementation of the presently disclose technology may thus supplement the blowout intervention process, providing readily responsive action plan that provides a temporary constriction on the blowout until other methods such as momentum or dynamic kills or addition of a capping stack can be subsequently implemented.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is an exemplary schematic representation of a well control operation according to the present disclosure.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

Relatively rapid access to processes and apparatus for controlling and killing a well blowout may further benefit the energy industry. The presently disclosed technology is believed to provide functional improvements and/or improved range of methodology options over previously available technology. Methods and equipment are disclosed that may provide effective interim control of blowout fluid flow from a wellbore such that a more permanent well killing operation may be performed subsequently or concurrently therewith. In many embodiments the presently disclosed well control operation methods may be applied in conjunction with performance of the long-term or “highly dependable” (permanent) kill operation. In some instances, the presently disclosed interim technology may morph seamlessly from a “control” intervention operation into a permanent well killing operation.

Certain key elements, components, and/or features of the disclosed technology are discussed herein with reference to FIG. 1, which is merely a general technical illustration of some aspects of the technology. Not all of the elements illustrated may be present in all embodiments or aspects of the disclosed technology and other embodiments may include varying component arrangements, omitted components, and/or additional equipment, without departing from the scope of the present disclosure. FIG. 1 merely provides a simplified illustration of some of the basic components used in drilling or servicing subterranean wells, particularly offshore wells, in accordance with the presently disclosed well control technology.

Generally, the presently disclosed technology involves creating a temporary blockage or impedance of the wellbore blowout fluid flow at the wellhead by introducing additional fluid into the flow stream at such rate as to create an increased backpressure in the wellhead throughbore that creates sufficient additional pressure drop in the flow control device throughbore that overcomes the flowing wellbore pressure of the blowout fluid flow through the wellhead. In many embodiments, the control fluid is introduced in proximity of an upper or top end of the wellbore, such as into the wellhead, drilling spool, or in a lower portion of the blowout preventer, or in adjacent equipment such as well control devices (e.g., blowout preventers, master valves, etc.) that have an internal arrangement of components exposed to the wellbore that creates a relatively restrictive turbulence of control fluid and formation fluid therein. In many aspects, the control fluid introduction rate is sufficiently high so as to create a flowing wellhead pressure drop within the wellhead primary throughbore and/or related equipment due to the fluid mixing and turbulent flow patterns therein, that exceeds the formation fluid flowing pressure at that point of control fluid introduction into the wellbore. It may be desired that the back pressure created by the increased fluid flow-rate through the well control equipment substantially inhibits, reduces, or even halts flow of the wellbore blowout fluid from the wellbore. This hydrodynamic well control operation may be subsequently continued while other operations to finally and permanently control the well are performed, such as pumping a weighted mud, cement, or another control fluid into the well. In many aspects, the weighted fluid comprises at least one of a seawater, saturated brine, drilling mud, and cement.

Another advantage offered by the present technology is use of readily available and environmentally compatible water or seawater as the introduced well control fluid. For offshore wells or wells positioned on lakes or inland waterways, this creates essentially a limitless source of control fluid, as the control fluid is merely circulated through the system. For land-based wells, a water source such as a bank of large tanks may be provided to facilitate circulating water from the tanks, into the primary throughbore, and back to the tanks or to another contained facility where the water may could be processed and reused. As an additional benefit, introducing seawater as the control fluid brings the added benefit of fire suppression and thermal reduction in event the effluent is on fire or has possibility of ignition.

Flow of the wellbore blowout fluid may be sufficiently arrested or halted (controlled) when sufficient rate of control fluid (e.g., water) is pumped into the well bore through a control fluid aperture(s) in or below the well control device as to increase fluid pressure in the well control device throughbore greater than the flowing pressure of the hydrocarbon flow at the point where the control fluid enters the wellbore. When wellbore blowout fluid is thereby controlled, blowout flow velocity or rate may be sufficiently halted or have such reduced upward velocity or rate such that a heavier weighted fluid can then be introduced into the wellbore through a weighted fluid aperture. The weighted fluid aperture is positioned below the control fluid aperture. The weighted fluid can then fall by gravity through the wellbore blowout fluid in the wellbore and/or displace the blowout fluid as the weighted fluid moves down the wellbore and begins permanently killing the well blowout. The well controlling step of introducing the control fluid into the wellbore may continue while the well killing operation of introducing the weighted fluid into the wellbore may be progressed until the blowout fluid no longer has the ability to flow at the surface when the well controlling operation of introducing the control fluid through the control fluid aperture is suspended. Introducing the weighted fluid in parallel with introducing the control fluid can continue until the wellbore is fully hydraulically stabilized and no longer has the ability to flow uncontrolled. A sufficiently reduced blowout fluid velocity may permit the weighted fluid to flow into the well bore without being ejected out of the well control device.

The presently disclosed methods and systems also have the advantage of being remotely operable from the rig, vessel or platform experiencing the blowout, as all operations may be performed from a workboat or other vessel that is safely distant from the blowout. By operating remotely from the drilling rig, the well-control system or operation will not be impacted by failure of the drilling rig. Further, pumping seawater into the well control device as the control fluid, not only provides an infinite source of control fluid, but also brings the advantage of adding firefighting water into the fuel in the event that the hydrocarbons are ignited after escaping onto the drilling rig. This system could both save the rig, control the well, and if desired provide means for introducing environmental-cleanup-aiding chemicals directly into the blowout effluent stream.

FIG. 1 illustrates an exemplary equipment arrangement for a well control operation according to the present disclosure, whereby wellbore 50 is experiencing a well control event and an operation according to the present disclosure is employed to intervene and kill the flow of effluent from wellbore 50. In the exemplary aspect illustrated in FIG. 1, a service vessel 72 is positioned safely apart from or remote offset from the rig 62 or well centerline 11. Exemplary vessel 72 may be loaded with equipment, pumps, tanks, lines, drilling mud, cement, and/or other additives as may be useful in the well control operation. Exemplary vessel 72 also provides pumps 32, 42 for introducing fluids into the wellbore 50 via pump lines 34 and 44. A wellbore 50 is located within a subterranean formation 60, whereby the wellbore is in fluid communication with a reservoir or formation containing sufficient formation fluid pressure to create a well control situation such as a blowout. Top side well control or operation-related equipment is positioned at several points along the wellbore 50 above the surface location (such as mudline 48 or water surface 74) including at water surface 74. Wellbore 50 is discharging the wellbore fluid 16 in an uncontrolled flow, from substantially any location downstream (above) of the wellhead pressure control devices 20. Wellbore fluid 16 may be escaping or discharged at substantially any location downstream from at least a portion of the well control surface equipment 20 or from the wellbore throughbore 12, such as near the mudline 48, on a rig or surface vessel 62 or therebetween. FIG. 1 illustrates the presence of a plurality of well control devices 20, such as a blowout preventer 26 (BOP), a lower marine riser package 52 (LMRP), and a marine riser 24. Well control device(s) 20 is(are) engaged with the top end 18 of wellbore 50. Wellbore 50 includes a wellbore conduit 10 defining a wellbore throughbore 12 therein, such as a well casing string(s). The collective components comprising the well control device 20 each include a primary throughbore 70 substantially coaxially aligned along a wellbore centerline 11 with the wellbore throughbore 12, but not necessarily having the same primary throughbore internal radial dimensions 28 as the wellbore conduit 10. The primary throughbore 70 is irregular with respect to internal radial dimensions 28 between various components therein, such as pipe rams 88, wipers, master valves on a christmas tree, plug profiles, and will possess varying internal surface roughness and dimensional variations so as to contribute to creation of turbulent fluid flow therein that under conditions of sufficiently high flow rate may create a substantial pressure drop therein that may impede the combined flow rate of formation blowout fluid and control fluid through the primary throughbore 70, thus aiding in creating enhance backpressure on the wellbore 50, and reducing or halting effluent 16 flow.

In one general aspect, the disclosed technology includes a method of performing a well control intervention operation to reduce an uncontrolled flow of wellbore fluids 16 such as a blowout from a subterranean wellbore 50. The term “blowout” is used broadly herein to include substantially any loss of well control ability from the surface, including catastrophic events as well as less-notorious occurrences, related to the inability of using surface pressure control equipment 20 to contain and control the flow of effluent fluid 16 from within a wellbore conduit 10 into the environment outside the well 50.

The disclosed method comprises providing at least one flow control device 20, such as a BOP 26, LMRP 52, Christmas tree valve arrangement, and snubbing equipment. The term “BOP” is used broadly herein to generally refer to the totality of surface or subsea well pressure or fluid controlling equipment present on the wellbore that comprises at least a portion of the wellbore throughbore 12 and which is typically appended to the top end 18 of the wellbore conduit 10 during an operation of, on, or within the well 50. The main internal well control device 20 throughbore 70 within the flow control devices may be referred to broadly herein as the primary throughbore 70. The wellbore throughbore 12 includes the primary throughbore 70. The well control device 20 is typically engaged with a top end 18 of the wellbore conduit 10 at a surface location of the wellbore conduit, such as at the seafloor mudline 48 (or land surface or platform or vessel surface). The primary throughbore 70 is coaxially aligned with the wellbore throughbore 12 and the primary throughbore 70 comprises internal dimensional irregularities such as constrictions and discontinuities, along the primary throughbore conduit 70 inner wall surface. These irregularities may be due to varying positions and dimensions related to internal components such as pipe rams, plug seats, master valves, or other internal features that may create a substantially discontinuous or irregular conduit path along the axial length of the primary conduit 70.

A control fluid aperture 30 is provided in proximity to the fluid control device 20, preferably located either in a lower half of the fluid control device 20 or at a point in the wellbore conduit 10 below (upstream with respect to the direction of blowout fluid flow) the fluid control device 20, such as in a drilling spool, a drilling choke-kill cross. The control fluid aperture 30 may include multiple of such apertures. The control fluid aperture 30 serves as a port(s) to introduce the control fluid into the wellbore at sufficient rate, volume, and pressure to, in combination with the formation fluid 16 or wholly alone, increase the total fluid flow rate through the primary throughbore 70 so as to impede or halt flow of formation fluid 16 through the wellbore conduit below the control fluid aperture 30. The control fluid aperture 30 may be provided in the top end 18 of the wellbore conduit 10, meaning substantially anywhere along the wellbore throughbore 12 above (uphole from) the bradenhead flange or mudline, wherein the control fluid aperture is also fluidly connected with the wellbore throughbore, or combinations thereof. The ports may be generally provided substantially perpendicular to the axis of the throughbore. In other aspects, the control fluid aperture 30 may be provided in at least one of (i) the top end of the wellbore conduit, (ii) the flow control device, and (iii) a location intermediate (i) and (ii), the control fluid aperture being fluidly connected with the wellbore throughbore, or combinations thereof. Introduction of the control fluid is introduced through the control fluid aperture 30, whereby the introduced control fluid may fluidly overwhelm the fluid flow through the wellbore throughbore 12 and may thereby provide temporary suspension or sufficient reduction in flow of wellbore blowout fluid 16 as to render the well at least temporarily controlled or killed. Thereafter more permanent and conventional killing operations may proceed, such as via introduction of a hydrate inducing fluid to provide hydrostatic control and containment of the wellbore 50.

In addition to the control fluid aperture 30, the disclosed technology provides a hydrate inducing fluid aperture 40 for introducing a weighted fluid into the wellbore below the control fluid aperture 30 to provide the hydrostatic control and containment of well effluent 16 from the wellbore 50. In some aspects it may be preferred to locate the hydrate inducing fluid aperture 40 in the wellbore throughbore 12 in proximity to the mudline 48, such as near the top end 18 of the wellbore conduit 10, or in a lower portion of the fluid control device 20 that is below the control fluid aperture. The term “below” means an upstream location in the wellbore throughbore with respect to direction of flow of wellbore blowout fluid 16 flowing through the throughbore 12. In some embodiments, the control fluid aperture may be located within a BOP body, between BOP rams, or in a drilling spool (choke-kill spool), or combinations thereof. In some aspects, it may be useful to provide the control fluid aperture 30 in the well control device 20 and providing the hydrate inducing fluid aperture in another wellbore component below (upstream with respect to the direction of flow of wellbore fluid flowing through the wellbore throughbore) from the well control device 20, or in both locations to have sufficient control fluid introduction capacity.

Introducing a control fluid through the control fluid aperture 30 into the wellbore throughbore 12 while wellbore blowout fluid 16 flows from the subterranean formation 60 through the wellbore throughbore 12 may in some instances provide sufficient backpressure to both temporarily control and permanently control the well. In the case of a relatively low-pressure wellbore (e.g., one having a BHP gradient of less than a seawater, kill mud, or freshwater gradient) the control fluid alone may perform to both temporarily control the well and with continued pumping also serve as the weighted fluid to fill the wellbore with control fluid and permanently kill the well. It may be advantageous to introduce at least a portion or as much as possible of the control fluid into the primary throughbore 20 as far upstream (low) as possible, such as in the lower half of the BOP 26, such as below BOP mid-line 15, without hydraulically interfering with introduction of the hydrate inducing fluid into the hydrate inducing fluid aperture 40.

The presently disclosed technology also includes an apparatus and system for performing a wellbore intervention operation to reduce an uncontrolled flow rate of wellbore fluids from a subterranean wellbore. In one embodiment, as illustrated in exemplary FIG. 1, the apparatus or system may comprise a flow control device 20 mechanically and fluidly engaged (directly or including other components engaged therewith) with a top end of a wellbore conduit (generally the wellhead at the surface or mudline, but in proximity thereto such as in a conductor casing or other conduit in proximity to the mudline or surface) that includes a wellbore throughbore 12 at a surface location 48 of the wellbore conduit, the flow control device 20 including a primary throughbore 70 that is included within the wellbore throughbore 12, the primary throughbore 70 coaxially aligned with the wellbore throughbore 12 and the primary throughbore 70 comprising internal dimensional irregularities. “Internal dimensional irregularities” and like terms refers to the primary throughbore 70 having a non-uniform effective internal conduit-forming surfaces or internal cross-sectional area or internal diameter dimensions, along the axial length of the primary throughbore 70 as compared with the substantially uniform internal diameter of the wellbore conduit 10. The internal dimensions of the primary throughbore may be less than, greater than, or in some instances substantially the same as the internal diameter of the wellbore conduit 10. “Internal dimensional irregularities” variations include the internal component positional and size variations within the various apparatus, valves, BOP's, etc., that comprise the primary throughbore 70 downstream from (above) the hydrate inducing fluid introduction aperture. Such varying internal diameter variations provide internal fluid flow-disrupting edges and shape inconsistencies along the axial length of the primary throughbore 70 that collectively may facilitate substantial turbulent flow and enhanced rate restriction, resulting in increased hydraulic pressure drop along the primary throughbore 70.

The control fluid is introduced into the wellbore throughbore in sufficient rate to create a substantial hydrodynamic pressure drop within the primary throughbore 70, such as a pressure drop of at least 10%, or at least 25%, or at least 50%, or at least 75%, or at least 100% from the previously estimated or determined flowing hydraulic pressure of the wellbore blowout fluid within the primary throughbore 70 before introduction of the control fluid therein. It is anticipated that the control fluid may commonly need to be introduced into the primary throughbore 12 at a control fluid introduction rate that is at least 25%, or at least 50%, or at least 100%, or at least 200% of the previously estimated or determined wellbore blowout fluid 16 flow rate from the wellbore throughbore 12 prior to introducing the control fluid into the wellbore throughbore 12. In another aspect, it may be desired that when substantially only, or at least a majority by volume, or at least 25% by volume of the total fluid flowing (formation effluent plus control fluid) through the downstream, outlet end of the primary throughbore 70 is control fluid, then a weighted fluid such as weighted mud, cement, weighted kill fluid, or heavy brine may be introduced preferably through the weighted fluid aperture 40 and into the wellbore throughbore 12 while pumping the control fluid through the control fluid aperture 30.

There may be applications where it is desired to begin pumping weighted fluid through the control fluid aperture, either solely or in combination with introducing weighted fluid into the weighted fluid aperture. In such instances such instances, the weighted fluid may be substantially the same fluid as the control fluid, or another weighted fluid.

When the well is killed (exhibiting either reduced flow rate or halted flow rate of formation fluids from the reservoir or formation 60) due to introduction of control fluid into the primary throughbore 70, the well will still be flowing the control fluid from the primary throughbore 70 exit. In many instances it is preferred that the well is killed with respect to flow of formation effluent through the primary throughbore, and substantially all of the fluid discharging from the primary throughbore 70 is control fluid. Thereby, wellbore blowout fluid 16 is effectively replaced with control fluid such as seawater 80.

Introducing “neat” control fluid (without additives) into the wellbore throughbore 12 may or may not fully contain or halt formation fluid flow from the well 50 as desired. Some aspects of the disclosed technology may include tailoring the control fluid. In other aspects, it may be desirable to provide additives 86 through additive lines 84, 85 to the control fluid (or the weighted fluid) by adding fluid-enhancing components therein, such as salts, alcohols, surfactants, biocides, and polymers. In some embodiments, the control fluid may comprise at least one of carbon dioxide, nitrogen, air, methanol, another alcohol, NaCl, KCl, MgCl, another salt, and combinations thereof.

In some operations it may be desirable to introduce fluid streams comprising or consisting of polymerizable formulations (broadly referred to herein as polymers, including actual polymers or other chemically activated or reactive mass-forming combinations of components), including polymerizable formulations that activate or polymerize within the primary throughbore 70 to create a polymer accumulation within the primary throughbore 70. Such polymerizable formulations may be a multi-component chemical or polymer formulations wherein each of the reactant components are separately introduced into the primary throughbore 70 for mixing and (quickly) reacting or (quickly) polymerizing therein. Such polymers may also include chemical or polymer formulations that are water or hydrocarbon activated compositions. The activated polymers may accumulate or otherwise volumetrically build up within the primary throughbore, creating a flowpath restriction, constriction, or full blockage of the fluid flow rate through the primary throughbore 70. Fibrous and/or granular solids such as nylons, kevlars, durable materials, or fiberglass materials may also be concurrently introduced for enhancing the toughness or shear strength of the polymer accumulation within the primary throughbore 70.

In some applications, it may be useful to introduce the control fluid into the wellbore throughbore 12 at a control fluid introduction rate that indirectly provides other associated desired effects, such as creating hydrates within the wellbore throughbore 12 such as by the introduction of carbon dioxide into the control fluid. Creation of hydrates within the primary throughbore 70 may assist with increasing the pressure drop through the primary throughbore as hydrate formation progresses, by reducing the flow cross-sectional area and internal surface roughness within the primary throughbore. Conversely, at some ambient temperatures or conditions it may be desirable to inhibit hydrate formation within the control fluid apertures 30 or lines 34 in order to sustain maximum flow rate therein and it may be useful to introduce a hydrate inhibition component such as an alcohol into the control fluid.

In some applications, it may be desirable to introduce control fluid into the wellbore throughbore 12 at a control fluid introduction rate sufficient to reduce the wellbore fluid flow rate by determined amount, such as achieving a reduction of at least 10%, or 25%, or 50%, 75%, or 90%, or at least 100%, (by volume) with respect to the wellbore blowout fluid 16 flow rate through the wellbore throughbore 12 or primary throughbore 70, prior to introduction of the control fluid into the primary throughbore 70.

The disclosed apparatus or system includes a control fluid aperture 30 in at least one of (i) the top end of the wellbore conduit, (ii) the flow control device, and (iii) a location intermediate (i) and (ii), the control fluid aperture being fluidly connected with the wellbore throughbore. The control fluid aperture 30 facilitates introducing (such as by pumping or by gravitational flow) a control fluid into the wellbore throughbore 12 while a wellbore fluid flows from the subterranean formation 60 through the wellbore throughbore 12 at a wellbore fluid flow rate, whereby the control fluid is introduced at a control fluid introduction rate of at least 25% (by volume) of the estimated or determined wellbore fluid flow rate was from the wellbore throughbore prior to introducing the control fluid into the wellbore throughbore.

A hydrate inducing fluid aperture 40 is also provided for introducing hydrate inducing fluid into the wellbore throughbore 12. The aperture 40 is positioned at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to direction of flow of wellbore fluid flowing through the wellbore throughbore (e.g., the hydrate inducing fluid aperture 40 is generally positioned below the control fluid aperture 30 and in some embodiments the hydrate inducing fluid aperture 40 may be positioned below the fluid control device 20 or near a lower end of the fluid control device 20. The hydrate inducing fluid aperture 40 is sized and/or provided by sufficient number of apertures 40 to be capable to introduce a hydrate inducing fluid into the wellbore throughbore 12 while the control fluid is introduced into the wellbore primary throughbore 70 through the control fluid aperture 30, from a control fluid conduit line 34 and a control fluid pump 32.

“Flow control device” 20 is a broad term intended to refer generally to the any of the pressure and/or flow control regulating devices associated with the top end 18 of the well 50, including equipment near a mudline 48, an earthen surface, or other water surface, that may be used in conjunction with controlling wellbore pressure and/or fluid flow during a well operation. The collection of such devices may generally define the “primary throughbore” portion of the wellbore throughbore 12. Exemplary well operations using a flow control device include substantially any operation that may encounter wellbore pressure or flow, such as drilling, workover, well servicing, production, abandonment operation, and/or a well capping operation, and exemplary equipment includes at least one of a BOP 28, LMRP 52, at least a portion of a riser assembly, a production tree, choke/kill spool, and combinations thereof.

The present apparatus or system also includes a control fluid conduit 34 and a control fluid pump 32 in fluid communication with the control fluid aperture 30. In some aspects, suction for the pump may be drawn from a suction line 82 in fluid connection with the adjacent water source 80, such as the ocean, a freshwater source, large water tanks, etc. Using seawater or other readily available fluid as the control fluid whereby the blowout effluent is discharging into the ocean provides a substantially limitless source of environmentally compatible control fluid. Thereby, the limitations on control fluid introduction rate and duration are merely mechanical issues that may be addressed or enhanced separately (e.g., control fluid aperture size and number of apertures available, pressure ratings, pump capacity, etc.). Multiple apertures fluid connected with the wellbore throughbore 12 may be utilized as the control fluid apertures 30. The multiple apertures may be located substantially anywhere within and/or upstream of (below) the primary throughbore 70. It is preferred that the most downstream (highest) hydrate inducing fluid aperture 40 is upstream of (below) all of the control fluid apertures 30, with preferably at least 3 but more preferably at least 5 and even more preferably at least 7 wellbore conduit effective internal diameters of the wellbore blowout fluid 16 flow stream separating the most upstream (lowest) control fluid aperture 30 from the most downstream (highest) hydrate inducing fluid aperture 40. Stated differently, the hydrate inducing fluid aperture 40 is upstream of (below) the nearest control fluid aperture 30, by at least 3, 5, or 7 internal diameters of the wellbore conduit throughbore 12.

Thereby, the hydrate inducing fluid does not encounter the majority of the mixing and turbulent hydraulic energy imposed into the wellbore throughbore 12. It may also be preferred in some aspects that the hydrate inducing fluid aperture is positioned upstream (below) of the primary throughbore 70.

It may be desirable in some aspects that control fluid pump 32 and control fluid conduit 34 are capable of pumping control fluid through the control fluid aperture(s) 30 and into the wellbore throughbore 12 at a control fluid introduction rate of at least 25%, or at least 50%, or at least 100%, or at least 200% (by volume) of the wellbore fluid flow rate through the wellbore throughbore 12 that was estimated or determined prior to introduction of the control fluid into the wellbore throughbore 12. The larger the total fluid flow rate through the primary throughbore 70, the greater the hydraulic pressure drop created therein by the combined fluid streams, and the larger the volumetric fraction of control fluid introduced therein that comprises the total fluid stream, the lower the volumetric fraction of wellbore effluent 16 escaping into the environment from the wellbore 50. It may be desirable in other aspects to introduce sufficient control fluid into the wellbore such that the fractional rate of wellbore effluent from the reservoir is substantially nothing or incidental. In another aspect, it may be desirable that an estimated or determined at least 25% by volume, or at least 50% or at least 75% or at least 100% by volume of the total fluid (control fluid plus formation effluent wellbore blowout fluid) flowing through the primary throughbore during introduction of the control fluid into the primary throughbore is control fluid. The hydrate inducing fluid may be introduced through the hydrate inducing fluid aperture and into the wellbore throughbore while pumping the control fluid through the control fluid aperture.

The hydrate inducing fluid aperture 40 is positioned preferably below the control fluid aperture 30 and the hydrate inducing fluid aperture(s) is dimensioned to provide flow rate capacity to introduce hydrate inducing fluid into the wellbore throughbore at a rate whereby the weighted fluid falls through the stagnant or reduced velocity wellbore fluid effluent flow rate through the wellbore throughbore 12. In some applications such as when it may be desirable introduce a high rate of hydrate inducing fluid into the wellhead 18, it may be desirable to switch from introducing the control fluid into the control fluid aperture to introducing hydrate inducing fluid into the control fluid aperture, such as while also introducing hydrate inducing fluid into the hydrate inducing fluid aperture.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

The phrase “etc.” is not limiting and is used herein merely for convenience to illustrate to the reader that the listed examples are not exhaustive and other members not listed may be included. However, absence of the phrase “etc.” in a list of items or components does not mean that the provided list is exhaustive, such that the provided list still may include other members therein.

In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

As used herein, the phrase, “for example,” the phrase, “as an example,” and/or simply the term “example,” when used with reference to one or more components, features, details, structures, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, embodiment, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, embodiments, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, embodiments, and/or methods, are also within the scope of the present disclosure.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil and gas industries.

It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.

Claims

1. A method of performing a wellbore intervention operation to reduce an uncontrolled flow of wellbore fluids from a subterranean wellbore, the method comprising:

providing a flow control device, the flow control device engaged proximate a top end of a wellbore conduit that includes a wellbore throughbore, the flow control device including a primary throughbore coaxially aligned with and included within the wellbore throughbore;

providing a control fluid aperture proximate the top end of the wellbore conduit, the control fluid aperture being fluidly connected with the primary throughbore;

providing a hydrate inducing fluid aperture in the wellbore throughbore at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to the direction of wellbore blowout fluid flow through the wellbore throughbore;

introducing a control fluid through the control fluid aperture and into the wellbore throughbore while the wellbore blowout fluid flows at an uncontrolled rate from the subterranean formation and through the wellbore throughbore at a wellbore blowout fluid flow rate, whereby the control fluid is introduced into the wellbore throughbore at a control fluid introduction rate that is at least 25% of the wellbore blowout fluid flow rate from the wellbore throughbore prior to introducing the control fluid into the wellbore throughbore; and

introducing a hydrate inducing fluid through the hydrate inducing fluid aperture and into the wellbore throughbore while simultaneously introducing the control fluid through the control fluid aperture at the control fluid introduction rate to induce the formation and deposition of hydrates within the wellbore and affect the flow rate of the wellbore blowout fluid flow rate from the wellbore throughbore.

2. The method of claim 1, wherein the flow control device comprises at least one of a drilling spool, a blowout preventer, a lower marine riser package, and a riser assembly.

3. The method of claim 1, comprising providing the control fluid aperture in or upstream of the well control device and providing the hydrate inducing fluid aperture in another wellbore component upstream from the well control device with respect to the direction of flow of wellbore blowout fluid flowing through the wellbore throughbore.

4. The method of claim 1, further comprising introducing the control fluid into the primary throughbore at a control fluid introduction rate of at least 50% of the wellbore blowout fluid flow rate prior to introduction of the control fluid into the wellbore throughbore.

5. The method of claim 1, further comprising introducing the control fluid into the primary throughbore at a control fluid introduction rate of at least 100% of the wellbore blowout fluid flow rate prior to introduction of the control fluid into the wellbore throughbore.

6. The method of claim 1, further comprising introducing the control fluid into the primary throughbore at a control fluid introduction rate of at least 200% of the wellbore blowout fluid flow rate prior to introduction of the control fluid into the wellbore throughbore.

7. The method of claim 1, further comprising using seawater for control fluid.

8. The method of claim 1, further comprising introducing the hydrate inducing fluid through the hydrate inducing fluid aperture and into the wellbore throughbore when an estimated or determined at least 25% by volume of total fluid flowing through the primary throughbore during introduction of the control fluid into the primary throughbore is control fluid.

9. The method of claim 1, further comprising creating hydrate formation within the wellbore throughbore with the control fluid.

10. The method of claim 9, wherein the hydrate inducing fluid comprises at least one of an alkane and water further comprising introducing carbon dioxide into the control fluid to create hydrates within the wellbore throughbore.

11. The method of claim 1, further comprising introducing control fluid into the wellbore throughbore at a control fluid introduction rate sufficient to reduce the wellbore blowout fluid flow rate by 25% with respect to the wellbore blowout fluid flow rate through the wellbore throughbore prior to introduction of the control fluid into the wellbore throughbore.

12. The method of claim 1, further comprising introducing control fluid into the wellbore throughbore at a control fluid introduction rate sufficient to reduce the wellbore blowout fluid flow rate by at least 50% with respect to the wellbore blowout fluid flow rate through the wellbore throughbore prior to introduction of the control fluid into the wellbore throughbore.

13. The method of claim 1, further comprising introducing control fluid into the wellbore throughbore at a control fluid introduction rate sufficient to reduce the wellbore blowout fluid flow rate by at least 75% with respect to the wellbore blowout fluid flow rate through the wellbore throughbore prior to introduction of the control fluid into the wellbore throughbore.

14. The method of claim 1, further comprising introducing control fluid into the wellbore throughbore at a control fluid introduction rate sufficient to reduce the wellbore blowout fluid flow rate by at least 90% with respect to the wellbore blowout fluid flow rate through the wellbore throughbore prior to introduction of the control fluid into the wellbore throughbore.

15. The method of claim 1, further comprising providing the control fluid aperture in at least one of (i) the flow control device, and (ii) a location intermediate the flow control device and the wellbore conduit.

16. The method of claim 1, further comprising thereafter introducing hydrate inducing fluid through the control fluid aperture.

17. An apparatus for performing a wellbore intervention operation to reduce an uncontrolled flow rate of wellbore fluids from a subterranean wellbore, the apparatus comprising:

a flow control device, the flow control device engaged proximate a top end of a wellbore conduit that includes a wellbore throughbore at a surface location of the wellbore conduit, the flow control device including a primary throughbore that includes the wellbore throughbore, the primary throughbore coaxially aligned with the wellbore throughbore;

a control fluid aperture proximate the top end of the wellbore conduit, the control fluid aperture being fluidly connected with the wellbore throughbore, the control fluid aperture positioned to introduce a control fluid into the primary throughbore concurrent with wellbore blowout fluid flowing from the subterranean formation at an uncontrolled rate through the wellbore throughbore at a wellbore fluid flow rate;

a hydrate inducing fluid aperture in the wellbore throughbore positioned at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to direction of flow of wellbore blowout fluid flowing through the wellbore throughbore, the hydrate inducing fluid aperture capable to introduce a hydrate inducing fluid into the wellbore throughbore while the control fluid is introduced into the wellbore throughbore through the control fluid aperture at the control fluid introduction rate.

18. The apparatus of claim 17, wherein the flow control apparatus comprises at least one of a blowout preventer, lower marine riser package, at least a portion of a riser assembly, production tree, drilling spool, and combinations thereof.

19. The apparatus of claim 17, wherein the control fluid aperture is fluidly connected with a control fluid conduit and a control fluid pump.

20. The apparatus of claim 17, further comprising sizing the control fluid aperture to introduce a control fluid into the wellbore throughbore at a control fluid introduction rate of at least 25% of an estimated or determined wellbore blowout fluid flow rate through the wellbore throughbore that was estimated or determined prior to introduction of the control fluid into the wellbore throughbore.

21. The apparatus of claim 19, wherein the control fluid pump and control fluid conduit are capable of introducing control fluid through the control fluid aperture and into the wellbore throughbore at a control fluid introduction rate of at least 50% of the wellbore blowout fluid flow rate through the wellbore throughbore prior to introduction of the control fluid into the wellbore throughbore.

22. The apparatus of claim 19, wherein the control fluid pump and control fluid conduit are capable of introducing control fluid through the control fluid aperture and into the wellbore throughbore at a control fluid introduction rate of at least 100% of the wellbore blowout fluid flow rate through the wellbore throughbore prior to introduction of the control fluid into the wellbore throughbore.

23. The apparatus of claim 19, wherein the control fluid pump and control fluid conduit are capable of introducing control fluid through the control fluid aperture and into the wellbore throughbore at a control fluid introduction rate of at least 200% of the wellbore blowout fluid flow rate through the wellbore throughbore prior to introduction of the control fluid into the wellbore throughbore.

24. The apparatus of claim 17, wherein the weighted fluid aperture is dimensioned to introduce weighted fluid into the wellbore throughbore at a rate whereby the weighted fluid falls through the wellbore fluid.

25. The apparatus of claim 17, wherein the hydrate inducing fluid aperture is upstream of the nearest control fluid aperture, by at least three internal diameters of the wellbore conduit throughbore.

26. The apparatus of claim 17, wherein the hydrate inducing fluid aperture is upstream of the nearest control fluid aperture, by at least five internal diameters of the wellbore conduit throughbore.

27. The apparatus of claim 17, wherein the control fluid comprises at least one of seawater, freshwater, saturated brine, and a drilling mud.

28. The apparatus of claim 27, wherein the control fluid further comprises at least one of carbon dioxide, nitrogen, air and combinations thereof.

29. The apparatus of claim 17, wherein the hydrate inducing fluid comprises at least one of a seawater, saturated brine, drilling mud, and cement.

30. The apparatus of claim 17, wherein the control fluid aperture is located in at least one of a blowout preventer and a drilling spool.

31. The apparatus of claim 17, further comprising a vessel remotely located with respect to wellbore centerline, the vessel having at least one of the control fluid pump and the hydrate inducing fluid pump.

32. The apparatus of claim 17, wherein the hydrate inducing fluid aperture in the wellbore throughbore is provided at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to the direction wellbore blowout fluid flow through the wellbore throughbore.