Patent Application
20150075796
The present disclosure relates generally to methods and systems for performing wellsite operations. More particularly, this disclosure is directed to methods and systems for handling wellsite materials, such as treatment fluid, stimulation fluid, drilling muds, etc.
Wellsite operations may be performed to locate and capture valuable subsurface fluids, such as hydrocarbons. Wellbores may be drilled by advancing drilling tools into the earth to reach the subsurface fluids. Production equipment may be deployed into the wellbore to transport the hydrocarbons to the surface. In some cases, formations surrounding the wellbore may be treated to facilitate the flow of fluids to the surface. Treatment may involve injecting fluid into the wellbore to fracture the subsurface formations and provide pathways for fluid flow into the wellbore.
Various fluids may be delivered to the wellsite to perform wellsite operations. For example, during drilling, drilling fluids (e.g., muds) may be pumped into the wellbore to facilitate drilling and/or to line the wellbore. In another example, during production, treatment/stimulation fluid may be injected into the formation to fracture the formations. Such injected treatment/stimulation fluid may include, for example, acids to enhance the fractures, proppants to prop open the fractures, and the like. Various techniques may be used to deliver the treatment/stimulation fluid to the wellsite. Examples of treatment/stimulation fluid used at a wellsite are provided in Patent/Application Nos. US2012/0285695, U.S. Pat. No. 7,049,272, and PCT/RU/2011/000969.
In at least one aspect, the present disclosure relates to a system for handling wellsite packets for a wellsite. The wellsite packets include soluble packaging with wellsite materials therein. The wellsite has surface equipment and downhole equipment positioned about a wellbore penetrating a subterranean formation. The handling system includes at least one feeder to move the wellsite packets directly or indirectly into at least one mixer, wherein the at least one mixer is capable of stimulating dissolution of the soluble packaging so as to mix the wellsite materials with a fluid to form a wellsite mixture. A metering device is provided to selectively control a number of wellsite packets moving to the at least one mixer, and a pump is operatively coupled to the mixer to pump the wellsite mixture at the wellsite.
In another aspect, the present disclosure relates to a system for handling wellsite packets for a wellsite. The wellsite packets include packaging with wellsite materials therein. The wellsite has surface equipment and downhole equipment positioned about a wellbore penetrating a subterranean formation. The handling system includes at least one feeder having a reel rotationally mounted on a reel support. The feeder also includes a chain of the wellsite packets releasably wound about the reel so that the chain of wellsite packets is unwindable from the reel and into at least one receptacle. The system also includes at least one mixer operatively coupled to the receptacle. The mixer functions to mix the wellsite packets with a fluid to form a wellsite mixture. The system further includes a pump operatively coupled to the mixer to pump the wellsite mixture to the wellsite.
In another aspect, the present disclosure relates to a method of handling wellsite packets for a wellsite. The wellsite packets include packaging with wellsite materials therein. The wellsite has surface equipment and downhole equipment positioned about a wellbore penetrating a subterranean formation. The method includes moving the wellsite packets directly or indirectly into at least one mixer via at least one feeder. The method also includes selectively controlling a number of wellsite packets moving into the at least one mixer using a metering device. The method further includes forming a wellsite mixture by mixing the wellsite packets with a fluid using the at least one mixer, and pumping the wellsite mixture to the wellsite with a pump.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
Embodiments of the wellsite handling system and method are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components.
FIGS. 2.1-2.3, 3 and 4 are schematic illustrations of various configurations of a delivery portion of a wellsite handling system in accordance with an embodiment of the present disclosure;
FIGS. 5.1-5.4 are schematic illustrations of various metering devices in accordance with an embodiment of the present disclosure;
The description that follows includes exemplary apparatuses, methods, techniques, and instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.
Unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by anyone of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).
In addition, use of the “a” or “an” are employed to describe elements and components of the embodiments herein. This is done merely for convenience and to give a general sense of the inventive concept. This description should be read to include one or at least one and the singular also includes the plural unless otherwise stated.
The terminology and phraseology used herein is for descriptive purposes and should not be construed as limiting in scope. Language such as “including,” “comprising,” “having,” “containing,” or “involving,” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited.
Finally, as used herein any references to “one embodiment” or “an embodiment” means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment. The appearances of the phrase “in one embodiment” in various places in the specification are not necessarily referring to the same embodiment.
The disclosure relates to a handling system for providing wellsite materials to a wellsite for use in drilling, treatment, injection, fracturing, and/or other wellsite operations. Part or all of the wellsite materials may be pre-packaged in wellsite packets. The wellsite packets may have soluble (e.g., water soluble) packaging for releasing the wellsite materials for mixing with fluids to form wellsite mixtures that may be pumped to surface and/or downhole locations at a wellsite. The handling system includes a packaging portion, transportation portion, storage portion, delivery, mixing and/or pumping portion for providing the wellsite packets to the wellsite.
“Wellsite materials” as used herein refers to wellsite fluids and/or solids, such as chemicals, proppants, fibers, and/or drilling muds. By way of example, the wellsite materials may include solid proppant added to fracturing fluid, solid and/or liquid chemical additives added to fracturing slurry (e.g., fibers, particulates, crosslinkers, breakers, corrosion inhibitors), fibers and particulates (and other lost circulation materials) added to treatment pills (preventative or remedial), solid hydrofluoric (HF) acid precursor added to acid solution (e.g., hydrofluoric, NH4HF2) for sandstone acidizing, solid cement additives added during cementing operations, and/or other solid and/or liquid wellsite components.
“Wellsite packets” refer to discrete packages of wellsite materials. The wellsite packages include specified solid and/or liquid components packaged in specified amounts into packaging, such as containers, coatings, plastics, shrink wrap, and/or the like, that may be soluble. The packaging may be used to prevent exposure of the wellsite materials to air or other potentially detrimental materials. The packaging may also include components that act as part of the materials used in treatment, and optionally may be reusable. The wellsite packets may be individual wellsite packets, a long tubular wellsite packet or multiple individual wellsite packets joined together in chains or sheets. The wellsite packets may be mixed with fluid(s) to form “wellsite mixtures.” Examples of wellsite mixtures may include: stimulation fluid, such as acid; fracturing fluid for hydraulic fracturing, such as proppant laden fluid (gas or liquid, e.g., water), and various additives; drilling mud; cement slurry; treatment fluid, such as surface water treatment; or other wellsite fluids that may or may not include particle(s), fiber(s) or other solids.
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The wellsite packets 117 may be sized and shaped for convenient transportation by transportation portion 118, storage by storage portion 120, delivery by delivery portion 122, mixing by mixing portion 125, and pumped by pumping portion 124 for use at the wellsite 104. The delivery portion 122 may deliver the wellsite packets 117 to the mixing portion 125 where the wellsite packets 117 may be mixed with other materials to form a wellsite mixture. The pumping portion 124 may be used for pumping the wellsite mixture to surface and/or downhole locations at the wellsite as indicated by the arrows.
One or more of the wellsite packets 117 may be placed in a carrier 126 for storage and/or transport. Examples of carriers as depicted may include containers 126.1, reels 126.2, and pallets 126.3. The container 126.1 may be, for example, a hard container, such as a plastic bin, or soft sided container, such as a sack or super sack, for receiving the wellsite packets 117. The container 126.1 may optionally be provided with handles 128 to facilitate lifting and/or transport. The containers 126.1 may be configured to receive the wellsite packets 117, 117.1, 117.2.
The reels 126.2 may be spools that carry the chain 117.1 of wellsite packets 117 wound about the reel 126.2. In this version, multiple wellsite packets 117 may be wound around the reel 126.2 for storage and transport, and unwound from the reel 126.2 for use.
The pallets 126.3 may be horizontal platforms capable of supporting the chain 117.1 of wellsite packets 117 thereon. Containers 126.1 and/or reels 126.2 may be positioned onto the pallets 126.3 to be lifted, for example, by forklifts. In another example, the pallets 126.3 may have a cover (or wrapping) 130 to contain the wellsite packets 117 therein. The cover 130 may be a plastic, such as a water insoluble film. The pallets 126.3 may optionally be provided with framing to permit the pallets 126.3 to be stacked and/or protected.
Transportation portion 118 is depicted as including one or more transporters 132 that may be used to transport the wellsite packets 117. Transporter 132 may be any equipment capable of carrying the carriers 126 and/or the wellsite packets 117 to a desired location. As shown, the transporter may be, for example, a pneumatic transport 132.1, a belly dump transport 132.2, a flatbed trailer (or freight hauler) 132.3, or other means (e.g., rails) for transporting loads. The transporter 132 may be configured to carry the wellsite packets 117 and/or other materials (e.g., solids, fluids, containers, etc.) used with the wellsite packets 117 or used for wellsite operations.
The storage portion 120 is depicted as a housing 134 for containing the wellsite packets 117. The storage equipment 134 may be any equipment capable of storing a desired number of wellsite packets 117, carriers 126 and/or transporter 134. For example, the housing 134 may be silos 134.1 for receiving the wellsite packets 117.
In one example configuration, the silos 134.1 may be configured such that the wellsite packets 117 may be dropped into an upper portion of the silo 134.1 and selectively discharged at a lower portion of the silo 134.1 for delivery by the delivery portion 122. As depicted, a container 126.1 of individual wellsite packets 117 may be poured into the upper portion of the silos 134.1 for storage. Optionally, a bucket elevator (or lifter) 135.1 or other type of vertical conveyor may be provided to receive and lift one or more wellsite packets 117 into the upper portion of the silo 134.1 as indicated by the arrows. Examples of bucket elevators 135.1 and silos 134.1 are provided in U.S. application Ser. Nos. 13/838,872, 13/839,088, and 13/839,368, each of which is incorporated herein by reference in their entirety. In another example, a pneumatic conveyor 135.2 may optionally be provided to move wellsite packets 117 into the silos 134.1.
As also depicted, a warehouse (or shed or other building) 134.2 may be provided to house the wellsite packets 117. Transporter 132.3 may act as a storage vessel 134.3 for housing wellsite packets 117 and/or carriers 126.2, 126.3. In some cases, as also shown, the carriers 126 and/or transporters 132 may themselves act as housing 134 for storing wellsite packets 117 at a desired location. In at least one of the examples shown, wellsite packet 117 is passed into silo 134.1, carrier 126.1 is placed in warehouse 134.2, and pallet 126.3 and reel 126.2 is positioned on transporter 132.3/134.3.
To facilitate transport and/or storage of the wellsite packets 117 and prevent potential deterioration that may occur over time due to, for example, moisture. Various means may be provided to protect the wellsite packets 117. For example, a desiccant or detackifier may be provided to prevent the packaging from deteriorating and/or adjacent wellsite packets from sticking together. For example, a powder may be used as a detackifier, such as a proppant, talc, magnesium stearate, and the like may be used to prevent sticking. The detackifier or other material used to prevent deterioration may also be a component that serves a function, such as solid lubrication, at wellsite operations.
The delivery portion 122 is depicted as including various delivery devices, such as a feeder 144, a metering device 152, and a breaking device 138. The feeder 144 may be coupled to storage portion 120 and/or the various housings 134, for moving the wellsite packets 117 from the storage portion 120 and on to the mixing portion 125. For example, the wellsite packets 117 may dump directly from the silos 134.1 into the feeder 144, or be passed in the carriers 126 and/or transporters 132 to the feeder 144.
As shown, the feeder 144 may be provided at various locations along the handling system 100 to move the wellsite packets 117 from any location between transport 118 and pumping 124 to any location between transport 118 and pumping 124. The feeder 144 may be configured to manually or automatically receive and pass the wellsite packets 117 to the mixing portion 125. For example, as shown, the feeder 144 may be an operator 144.1 for manually feeding the wellsite packets 117; the feeder 144 may be direct feeding 144.3 by way of gravity; or, the feeder 144 may be automated feeding, such as, a belt-type conveyor 144.2, an auger (metering screw) 144.4, a pneumatic conveyor 135.2/144.5, a bucket elevator 135.1/144.6, a reel injector 144.7, and/or any combination thereof for moving the wellsite packets 117 within the handling system 100.
The feeder 144 may optionally be provided with a receptacle 146 to receive one or more wellsite packets 117 from any location between transport 118 and mixing 125. The feeder 144 may also include the metering device 152 to meter and/or distribute the wellsite packets 117 as they pass therethrough. The metering device 152 may be used to provide a certain number of wellsite packets 117 for use. The metering device 152 may also be used to pass a certain amount of the wellsite materials (e.g., fibers) that may be prone to clogging or plugging of equipment. As shown in
Optionally, the breaking device 138, such as a dissolver 138.1 and/or a breaker 138.2, may be provided to open the wellsite packets 117 to release the wellsite materials. The dissolver 138 may be, for example, mechanical (e.g., a shredder), chemical (e.g., a solvent), or physical (e.g., temperature, pressure). The breaking device 138 may be positioned about the handling system 100, for example, before or after the delivery portion 122 as shown.
As shown, the dissolver 138.1 may be a chemical device, such as a steamer or a chemical (e.g., a solvent), to facilitate the breaking down of the wellsite packets 117. The dissolver 138 may also be used to begin breaking down the packaging and/or the wellsite materials of the wellsite packets 117 to facilitate mixing. The breaker 138.2 may be, for example, a knife, shredder, steamer or other device capable of opening the packaging to release the wellsite materials.
The wellsite packets 117 and/or wellsite materials from the feeder 144 are passed to the mixing portion 125 for mixing. The mixing portion 125 includes a mixers 160, and fluid sources 156. The mixing portion 126 may be provided to mix the wellsite packets 117 and/or fluids from fluid sources 156 to form the wellsite mixture. The fluid sources 156 may include fluids 156.1 and/or additives 156.2. The fluids 156.1 may be, for example, water, or other aqueous fluids capable of dissolving and/or mixing with the wellsite packets 117 to form wellsite mixtures usable at the wellsite. The additives 156.2 may be, for example, oxidizers, acids and/or reactive chemicals that may be added along the handling system 100 and/or at the wellsite 104 for altering the wellsite mixture as desired.
The mixing portion 125 may be provided with one or more mixers 160 to form the wellsite mixture. For example, the mixers 160 may include a batch mixer 160.1 to provide batch mixing and/or one or more continuous mixers 160.2 to provide continuous (or on the fly) mixers. The various mixers may be provided to mix the wellsite packets 117, fluids 156.1, and/or additives 156.2 to generate the wellsite mixture. By way of example, a first mixer may be a high energy mixer capable of dispersing solids in the wellsite packets 117 into a concentrated wellsite mixture, and a second mixer may be provided to dilute the concentrated wellsite mixture into a fluid mixture. Various examples of mixers are shown and described in US Patent Publication Nos. US2011/0155373 or US2010/0243252 and U.S. Pat. Nos. 4,453,829 or 4,808,004, each of which is incorporated herein by reference in their entirety.
A control unit 142 may be operatively connected to one or more portions of the handling system 100 to monitor various parameters of the equipment and/or wellsite materials. Sensors may be provided for measuring one or more parameters (e.g., quantity of wellsite packets 117 and/or wellsite materials passing through portions of the handling system 100) as desired. The control unit 142 may also control the operation of various aspects of the handling system 100. The control unit 142 may include various components, such as processors, computers, or other devices for monitoring and/or controlling the handling system 100.
FIGS. 2.1-2.3 shows examples of feeders 144.1, 144.2, 144.3 and 144.7 for receiving the wellsite packets 117 (either individually or in multiples).
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A metering device 152.5 in the form of a blade (or turnstile) is provided in the silo 134.1 to selectively permit the passage of wellsite packets 117 therethrough. The metering device 152.5 may rotate such that the wellsite packets 117 passing therethrough are broken down and selectively permit the wellsite materials to pass into the mixer 160. As indicated by the curved arrow, a vortex may be created as the wellsite materials are spun into the mixer 160.2 to rotationally mix the wellsite materials.
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Drums 262 may optionally be provided to pull the chain 117.2 of wellsite packets 117 from reel 126.2 and/or to separate a cover therefrom. As an example, the reels 126.2 may pull a plastic cover from the chain 117.2 of the wellsite packets onto the drums 262 and release the wellsite materials into the receptacle 246.3. A knife 264 may optionally be provided to cut the chain 117.2 of wellsite packets 117.
As shown, the hopper 344 may have an outlet 349 that merges the wellsite packets 117 with the inputs 347, and a metering device 351. The metering device 351 as shown is a gate assembly 351 with a passage 353 therethrough. As indicated by the two-way arrow, the gate assembly 351 includes a gate valve is movable between a closed position preventing the passage of materials from the hopper 344 and out outlet 349, and an open position aligning the passage 351 with the intakes 345.1 and/or 345.2 to permit the materials to pass therethrough. The hopper 344 may also be coupled to and/or be used as a receptacle 146.
FIGS. 5.1-5.3 depict various examples of metering devices 152.1-152.3 in use. The metering device is coupled between a feeder 544 and the mixer 160. The feeder 544 is depicted as a silo receiving the wellsite packets 117 and dropping the wellsite packets 117 to the metering device 152.1-152.3.
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Part or all of the handling system 100 may optionally be separate or integral. Part or all of the handling system 100 may also be optionally separate from or integral with surface equipment 106 and/or downhole equipment 108 (e.g., treatment systems 112).
The treatment system 112 includes a pump system (depicted as being operated by a field operator 672) for operating the system 112 in accordance with a prescribed plan/schedule. The treatment system 112 pumps fluid from the surface to the wellbore 115 during a fracture operation.
The treatment system 112 includes a plurality of water tanks 674, which feed water to a gel hydration unit 676. The gel hydration unit 676 combines water from the tanks 674 with a gelling agent to form a gel. The gel is then sent to a mixing unit, shown as a blender 678, where it is mixed with a proppant from a proppant transport 680 to form a fracturing fluid. The solid particles (e.g., guar) used to form the gel may be provided to the blender 678 in wellsite packets 117. The gelling agent may be used to increase the viscosity of the fracturing fluid, and to allow the proppant to be suspended in the fracturing fluid. It may also act as a friction reducing agent to allow higher pump rates with less frictional pressure.
The treatment fluid is then pumped from the blender 678 to the pumping trucks 682 with plunger pumps as shown by solid lines 684. Each treatment truck 678 receives the fracturing fluid at a low pressure and discharges it to a common manifold 685 (sometimes called a missile trailer or missile) at a high pressure as shown by dashed lines 686. The missile 685 then directs the fracturing fluid from the pumping trucks 682 to the wellbore 115 as shown by solid line 688. One or more pumping trucks 682 may be used to supply fracturing fluid at a desired rate.
Each pumping truck 682 may be normally operated at any rate, such as well under its maximum operating capacity. Operating the pumping trucks 682 under their operating capacity may allow for one to fail and the remaining to be run at a higher speed in order to make up for the absence of the failed pump. A computerized control system may be employed to direct the entire treatment system 112 during the fracturing operation.
The treatment fluids may include various fluids, such as conventional stimulation fluids with proppants, may be used to create fractures. Other fluids, such as viscous gels or “slick water” (which may have a friction reducer (polymer) and water), may also be used to hydraulically fracture shale gas wells. Such “slick water” may be in the form of a thin fluid (e.g., nearly the same viscosity as water) and may be used to create more complex fractures, such as multiple micro-seismic fractures detectable by monitoring. The wellsite mixture provided by the handling system may include part or all of the treatment fluids. Additional fluids may be added along the handling and/or treatment systems as desired.
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the system and method for performing wellbore stimulation operations. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6, for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
