Patent Grant
10865608
This application relates generally to offshore oil and gas wells and other subterranean exploration and production activities and more specifically to floating production systems built or made by converting mobile offshore drilling units (MODUs) to include a movable wellbay structure and a multi-well dry-tree production system that enables drilling, evaluation, completion, and maintenance of offshore wells.
U.S. Pat. No. 5,150,987, issued to White et al., describes a heave-restrained platform and drilling system (HRP/DS) for drilling and producing through oil wells in deep water that included a floating structure having a central buoyancy means, at least three out-rigger columns, and a hybrid mooring system in which a spread (lateral) mooring system functions with an array of tensioned production risers (serving as a vertical tension leg) to keep the structure generally over a specified seabed location. Risers are connected to hydrocarbon wells on the floor of a body of water upon which the floating structure floats within a horizontal locus generally beneath the floating structure and being connected to the floating structure under sufficient tension such as to also function as tendons to restrain heave of the floating structure in addition to functioning as conduits for hydrocarbon production. At least three lateral anchor lines were attached to the floating structure and to the floor of the body of water at loci lateral of the locus of attachment of the risers and under sufficient tension and in an array such as to maintain the floating structure substantially on horizontal location.
Many of the new discoveries in the Gulf of Mexico (GoM) combine extreme water depths with high pressure, high temperature (HPHT) reservoir conditions where mudline shut in pressures can approach or even exceed 15 ksi. These wells are much deeper than what has been typical of past developments. Instead of 20,000 foot total measured depths (TMD), HPHT wells tend to be greater than 30,000 feet TMD. Drilling and completion costs become a more dominant factor in the selection of the development concept, where savings between a dry tree well versus a wet tree subsea completed well can be over $150,000,000 per well. For a 5-10 well development of such challenging reservoirs, it is likely to require 5-8 years just to drill and complete the initial production wellbores. Another key advantage of dry trees is the significantly increased capability for well surveillance, wire line logging, interventions etc. as enhanced by simpler completion technology. Also, the ability to run and more easily service downhole electric pumps, can significantly increase well rate and reserve recovery when compared to subsea wells which have their well tieback and control trees sitting at the seafloor. The combination of all these factors puts greater emphasis on dry tree technology as an enabler for economic development of HPHT reservoirs in deep waters.
The current GoM deep water commercial environment has much greater reservoir uncertainty compared to the first wave of deep water developments by industry. Many reservoirs (for example, those in the Lower Tertiary Paleogene Wilcox play) lie beneath a layer of subterranean salt (labelled as “subsalt”) with poor seismic resolution and the inability to clearly define reservoir extent, fault blocks, and continuity. Exploration wells on these prospects have cost over 500 million dollars and have taken over 1 year to fully drill and evaluate. The extreme costs and timelines associated with drilling and evaluation reduces the number of appraisal wells that are feasible, resulting in unusually long appraisal timelines to gather information intended to support complex decisions regarding costly field development schemes. The end result is that Operators are being forced to make much bigger and riskier financial bets on these developments without critical information to resolve a number of key reservoir performance and reserve recovery factors.
Drilling and completion costs on wells into the Paleogene are likely to ultimately be 60% to 75% of the total project cost. This unusual cost structure imbalance is very different from the cost allocations for historic deep water development in the GoM, in which facility costs dominated field development concept selection. Paleogene development concepts are optimized by focusing on reducing drilling and completion costs, increasing reservoir surveillance, improving workover, and recompletion, intervention and maintenance capability all leading to increased reserve recovery. This is a paradigm shift for project teams that are dominated by facility expertise and tend to remain focused on the type of floater to select with lesser regard for how this might impact drilling and completion costs. Facility costs are expected to be less than 40% of the overall Paleogene project cost, and the disproportionate effort to reduce facility and topside costs rather than drilling and completion costs cannot significantly improve project economics. The key, then, is to focus on adaptive development strategies that significantly reduce drilling costs and provide production and reservoir dynamic data that changes the game from having to guess right to a strategy that provides the operator with truly robust capability to appraise the reservoir, while retaining the flexibility for future redeployment and reuse, if required.
The application of dry tree development to GoM Paleogene reserves is strongly aligned with fundamentals of reducing complexity and risk. Dual barrier fully pressure rated top tension risers provide direct access to the reservoir with simpler and more reliable surface trees and BOP's that can be easily monitored and maintained in a high state of reliability. Typically, dry tree drilling and completion equipment is an order of magnitude simpler with fewer moving parts compared to equivalent wet tree technology. In ultra-deep waters, the adoption of a dry tree tieback solution can eliminate the use of highly expensive and relatively unproven 20 ksi subsea trees and high integrity pipeline protection systems (HIPPS).
The use of a permanent taut-leg spread mooring system instead of a dynamic positioning (DP) system to hold a vessel on site eliminates the need for emergency disconnection of the drilling riser, and the risers do not have to be retrieved for hurricane abandonment. A study conducted as part of the Norwegian Deepwater Research Program (Reliability Study, Phase 2 Report No: A3314/C/NDE/RBB, February 1999) indicated that position excursions which are likely to lead to physical damage are approximately two orders of magnitude less likely for a moored floater versus one depending on DP.
Well surveillance (also called “monitoring”) and interventions are extremely important in evaluating well performance and maximizing recovery from new geologic horizons like the Paleogene. According to Norwegian Petroleum Directorate's Director General, Gunnar Berge, at the Subsea Conference in Bergen, Mar. 17, 2004, a study performed by Statoil and the Norwegian Petroleum Directorate showed that the recovery factor from subsea wells is 15-20 percent lower than from wells with direct vertical access. The accessibility to subsea completed wells is more difficult and represents larger costs than wells drilled from a dry tree installation. Even for minor jobs a mobile rig is often required. The study went on to conclude that performance from dry tree wells is 25% better than subsea wells drilled in the same geologic environment (Well Intervention, Offshore Magazine Jun. 1, 2001). The main difference being that ready access for light intervention and wireline work on dry tree wells compared to the much more expensive and fewer options on the subsea analog. Surveillance in the form of compaction logging, production inflow and multi-rate production logging of individual reservoir layers has significantly contributed to better production performance of dry tree wells (SPE Paper 115365).
Another key factor particularly for GoM economics is the differential drilling and completion times as the result of the impact of hurricanes and loop currents. Drilling riser deployment and retrieval times can have a significant impact on subsea well costs. Dynamically-Positioned mobile offshore drilling units (DP MODUs) capable of drilling and completing high pressure/high temperature (HPHT) Paleogene wells can be expected to carry fully burdened or “loaded” dayrates greater than $1 million/day. In 5,000 ft. of water, deploying a subsea BOP and drilling riser can take 2-3 days, with even more time required to retrieve the riser in the event of well abandonment for hurricanes. The total time required to prepare for abandonment, abandon the site, return and restart well operations in ultra-deep water Gulf of Mexico can mean 2 to 3 weeks of lost work whenever a hurricane threatens. Further, each floating drilling rig experiences on average 2 to 3 temporary abandonments caused by hurricanes in the Gulf every year, forcing operators to plan on about 6 weeks of expensive hurricane-induced downtime.
With dry trees, the drilling and production risers and facility are designed to remain connected throughout any hurricane no riser retrieval is required. Lost time is greatly reduced, and in some cases can be eliminated, due to the ability to wait longer and monitor the path of the hurricane and determine that the path will remain well away from the facility.
There can also be knock-on downtime associated with the effects of loop currents in suspending DP operations sooner or delaying riser connection post abandonment. MODU drilling risers cannot be run and retrieved in currents exceeding 1.5-2.0 knots. Retrieval and running operations during hurricane season must be carefully managed to ensure that successful hurricane abandonment can be accomplished in front of an approaching storm. Loop current events can last for weeks and can be a significant issue especially as operations move further out past 5,000 foot water depth contours. Rigs may have to wait additional time to allow loop currents to move away from the well location in order to re-run and re-connect the drilling riser.
Yet another significant issue is tripping a subsea BOP for repair versus a surface BOP. The additional time to abandon the well and retrieve the riser and BOP can result in a significant cost impact in terms of several weeks of downtime for each repair. A surface BOP in many cases can be repaired “hands-on” without well abandonment and without removing the BOP. A surface BOP with direct hydraulic controls is much more reliable than a complicated subsea BOP with electro-hydraulic multi-plex controls. Recent regulatory changes by the United States have introduced even more strict repair and maintenance requirements which force Operators to retrieve the BOP to surface for repair of any problem that cannot be repaired subsea. Surface BOP direct hydraulic control systems have been shown to be an order of magnitude more reliable than subsea multi-plex controls.
In recent years, there has been a substantial number of discoveries of HPHT oil-bearing formations in ultra-deep waters in the US Gulf of Mexico. The US government requires that these discoveries be developed and produced in a timely fashion or the offshore leases encompassing these potentially world-class assets must be relinquished. Today's predictions that relatively low oil prices will be sustained for many years make it imprudent for the lease holders to sanction extremely costly developments for these discoveries without having adequate understanding of the reservoirs productive capacities and requirements. As a result, even though the discoveries appear to be massive, their complexity and the high cost of complying with the requirements for holding onto the leases are creating financial pressures that can force the leaseholders to allow their leases and all the information and drilling results their efforts to date have generated to be relinquished back to the US people. In such cases, the relevant offshore blocks can be put up for auction again at a future date.
Those leaseholders are pushed to this decision when their fully risked economic analyses indicate that the uncertainties regarding the productivity of the reservoir, the cost of development and operation, and the value of the produced fluids cannot be expected to be economically resolved with existing technologies.
Introducing a system that allows the use of dry tree wells will avoid the financial penalties that HPHT subsea drilling operations and subsea tree well tieback systems impose on the economics of the recently discovered Lower Tertiary resource in the ultra-deep waters of the Gulf of Mexico.
A movable wellbay assembly for use in a facility for oil and gas well drilling, evaluation, completion, improvement, maintenance, intervention and/or production, the movable wellbay assembly comprising:
A method for constructing a new, or retrofitting and/or repurposing an existing drilling unit for service as a production facility capable of drilling, evaluating, completing, maintaining, improving, and/or producing from wells penetrated into a subsurface (subterranean) oil and gas reservoir located beneath a body of water, the drilling unit comprising a drilling derrick and an opening in a deck of the facility that allows vertical access to and passage of components therethrough, the drilling derrick secured to a drilling deck over the opening at a single location, the method comprising:
A facility for oil and gas well drilling, evaluation, completion, improvement, maintenance, intervention and/or production, comprising:
A method of using a movable wellbay assembly for oil and gas well drilling, evaluation, completion, improvement, maintenance, intervention and/or production, the method comprising:
A better understanding of the invention can be obtained when the detailed description of exemplary embodiments set forth below is considered in conjunction with the attached drawings in which:
Industry has advanced the use of dry trees on floating platforms by using mooring systems that hold the facility in a tight watch circle above a cluster of subsea wells and by designing hulls that minimize heave and, hence, riser stroke. All platform design solutions currently in practice employ the same drilling and completion technology using a wellbay structurally fixed into the platform sub-structure with a drilling rig standing on a skidding system on the top deck such that the rotary table and draw works can be moved and secured over any one of the slots for vertical access tieback risers in the fixed wellbay.
Dry tree tieback systems have been installed on many tension-leg platforms (TLPs) and deep-draft spar platforms. Many engineering firms have proposed designs for deep draft semisubmersibles over the past few decades (ref. “State of the art for dry tree semi technologies”, by Yu Hao et al, Engineering Science, 2013) but none have been built for deep water field development. In the same way as practiced for spars and TLPs, the deep-draft semisubmersible designs all employ wellbays supporting the top-tensioned dry tree tieback risers and their riser tensioning systems that have a fixed horizontal position within the floating production facility. Some of the designs do allow for the wellbay structure to move vertically while being permanently constrained to a preferred horizontal position within the moonpool.
Although many mobile offshore drilling units (MODUs) have been converted to service as floating production facilities producing from remotely distributed subsea completed wet tree tieback systems, the typical practice is to remove all of the drilling systems and well operations capabilities to make deck space and payload available for the installation of production equipment.
The idea of converting an existing semisubmersible MODU into floating production facility with dry trees is not generally considered feasible by industry today due to the inability to move the drilling derrick on the top deck and because of the large heave of these units during extreme storms. In 1980, a semisubmersible was converted to support production from three subsea completed wells that were tied back to its moonpool with a unique split tree design that placed wet trees at the seabed with 4.5″ tubing vertically tied back to dry trees supported on pairs of tensioning guideline wires at the surface (ref. “Dorada Field Production System: A solution to permanent vertical access to several wells from a semi-submersible”, Montoya and Lopez-Fanjul, OTC 4041). The Dorada field was located in shallow waters (93 m deep) of the relatively mild Mediterranean Sea offshore Spain. In this case, when well access was required, any one of the 3 surface trees could be tugged individually from a position at the edge of the moonpool to be held beneath the derrick for well operations in a solution similar to concepts for moving surface wellheads into position from stalls at the side of a moonpool described by White et al of U.S. Pat. No. 5,150,987, Springett et al of WO2016054610A1, and Jordan et al U.S. Pat. No. 9,238,943.
It is readily observed that moving a drilling derrick, all of its associated systems, and suspended loads about on the top deck affects the center of gravity and stability of the unit. Such a modification to an existing semisubmersible MODU is complex and costly. It also means that more of the deck area of the unit will be required for drilling operations—meaning that less space is available for oil and gas production equipment. The innovation of the present invention eliminates the need to modify an existing MODUs drilling derrick and support systems in a way intended to allow it to be moved around the deck. Instead, a new movable wellbay structure is retrofitted into the moonpool beneath the fixed derrick with elements that move the entire structural frame to position each slot and its wellhead as needed for direct well access for downhole activities, like drilling or work-over.
By recognizing and advantageously using the inherent elasticity of a top-tensioned metallic tie-back riser as a large and long spring, it is possible to maintain the well systems in a safe and reliable state even during the most extreme storms. In locations where metocean conditions are mild, it is possible to use the elasticity of a long tensioned riser string to completely accommodate the offsets and motions of the hull supporting the risers without attaching any dynamic tensioning devices. In locations subject to severe metocean conditions, it is possible to limit the stroke of the riser tensioning system by allowing the dynamic tensioners to “bottom out” while riser stretch accommodates and actually constrains further displacement of the hull.
Allowing the tensioners to bottom out and the risers to stretch can significantly reduce the relative movement of the dry trees within the moonpool and overall heave of the vessel. Restricting the range of allowed relative vertical movement of the wellheads attached to the innovative wellbay structure described in this patent application means that the dry trees and BOPs affixed atop the wellheads will remain above the sea surface in all operating conditions. By adopting an operating philosophy for implementation of this innovation that allows the risers to stretch and go slack, there is no need to build a low heave vessel like a deep draft semisubmersible, TLP, or spar. By incorporating this innovation, existing modern, ultra-deep water semisubmersible MODUs can be economically converted to serve as floating production facilities with dry trees.
This disclosure relates to an innovative top tension riser support and tensioning system that can be retrofitted in the moonpool of an existing MODU or incorporated into a newly-built MODU. Many of the latest generation MODU's have massive BOP and subsea tree transporter cart systems to move the equipment into and out of the moonpool area for deployment or retrieval as required. The present invention provides a new top tension riser support system comprising a movable wellbay structure that houses the top tension riser tensioners and is able to be preferentially displaced laterally in the moonpool on adjustable tensioners, skid rails, geared tracks or wheels. For the purposes of implementing this riser top tensioning system, the subsea BOP, and subsea BOP handling system are removed from the moonpool, and the moonpool is modified to accept and carry the loads induced by retro-fitting with a movable wellbay structure supporting top-tensioned risers and their tensioners, which forms a movable wellbay system.
The movable wellbay structure is designed to provide the structural interface between the top tension risers, which are fixed to the earth at the seabed to a subsea wellhead and the MODU. The tensioners provide top tension to the top tension risers and also feature an ability to extend and retract in a dynamic stroking function to manage the top tension during the operational and survival metocean design conditions. The movable wellbay structure can move laterally along guides in the moonpool to position any one of the top tension risers under the rig floor and rotary table so that the converted MODU's drilling and completion systems can be connected to the top tension riser at the top of the riser so as to provide direct vertical access to top tension riser with various well drilling, control, evaluation, completion, production, monitoring and intervention elements, including, for example, a surface BOP, a surface production tree and/or a low pressure telescopic joint connected to the rotary table. The movable wellbay structure is moved laterally in the moonpool and is locked into position below the rotary table using multiple and redundant passive locking devices similar to what is in use today on offshore platform rig skidding systems. The movable wellbay structure will remain in the locked position for the duration of the drilling and completion activities on the well, unless the operations are interrupted temporarily by a storm-induced rig abandonment. If such a temporary interruption is required, the well will be secured and the movable wellbay structure may be relocated to and locked into a centralized position most suitable for survival in extreme weather event.
The movable wellbay structure is the key technology required to convert an existing semisubmersible MODU to a production system with top tensioned risers and, if desired, dry tree tieback systems. Alternatively, this movable wellbay structure may be recognized as the key technology required to convert an existing semisubmersible MODU to a production system providing direct vertical access to multiple subsea wells located beneath the facility via top tensioned tieback and workover intervention risers. The scope of the conversion may include, but not be limited to, removing the existing marine drilling riser and tensioner system, the subsea BOP and its transport cart system, the marine drilling riser storage/handling equipment, and the DP thrusters, power management and control and positioning systems from the MODU. In addition to being modified by retro-fitting the movable wellbay structure into the facility's moonpool, the MODU is modified to accept connection to a pre-set polyester or steel wire rope taut-leg mooring system, production equipment and control systems, and export systems and risers as service requirements and space and weight constraints dictate.
In this embodiment, a structural frame that can both support top-tensioned tie-back risers for multiple wells and be preferentially re-positioned horizontally so that any one of the wellheads attached to the top of each well tie-back riser can be situated directly beneath the rotary table of the drilling derrick centrally positioned on the deck of a semisubmersible is designed so that it can be retro-fitted into the moonpool of an existing floating semisubmersible drilling unit. This movable wellbay structure sits on a flat beam, rail or track that allows the wellbay structure and the wellheads and risers it supports to be pushed, pulled, skidded or driven to each preferred position and securely locked into position for well operations and/or survival situations.
The movable wellbay structure described above may be designed and fabricated as a single structural frame comprising all the intended well slots or as separate structural frames for each or a pair of well slots that can be mechanically linked to act as a unified wellbay structure.
Once the length of each well tie-back riser is built up to a calculated target length by inserting “spacing out” pup joints (as typically used in offshore well tie-back practice) on top of a length comprised of standard length joints, top tensioning devices are connected and an engineered target top tension is applied to bring and hold the riser at a preferred suspended configuration. At this point, depending upon the operating and environmental conditions to which the total system may be exposed, the water depth in which the semisubmersible facility is installed, and upon the expected extreme horizontal offsets and motion characteristics of the semisubmersible facility once it has been installed, the top ends of the risers and their respective wellheads may be locked to the movable wellbay structure or attached to it by individual tensioning devices.
A key to making this innovation work is to ensure that the semisubmersible facility is held tightly on position over the wellheads located at the seafloor. Most of the high capability semisubmersible drilling units suitable for conversion to the service envisioned for this innovation have modern dynamic-positioning systems provided as part of the design package when leaving the shipyard. A dynamic positioning system can maintain a tight watch circle above the wellheads on the seabed in most sea states when functioning properly but may not have the positioning capability or reliability to keep the semisubmersible on station in all conditions. Therefore, it is anticipated that conversion of an existing semisubmersible to service for this innovation will require it be modified to allow it to be secured on site by a pre-installed taut-leg mooring system as typically used to hold floating production facilities on station in very deep waters. To limit the influence of offset on the tension variation in risers locked to the movable wellbay structure and/or the range of stroke required in the top tensioning devices, it is expected that the station-keeping system adopted will limit the most extreme offset in any condition to less than about 5 percent of water depth.
The possibility for locking down the top ends of top tensioned risers comprised of steel, aluminum, titanium and/or fiber composite tubulars is enhanced when the wells are located in deep waters or in relatively mild ocean environments, or a combination of both. It is also possible to modify the submerged portions of the semisubmersible hull to enhance its hydrodynamic performance to limit motions in a way that allows the riser top ends to be locked to the movable wellbay structure, thus avoiding the need for dynamic tensioning devices.
If the movable wellbay structure is itself supported by motion-compensating stroking devices that can accommodate some or all of the horizontal offset effects and motions of the semisubmersible in the deep water ocean environment, then the opportunity for locking the riser top ends to it is enhanced such that the need for individual dynamically adjusting top tensioning devices can be avoided.
Typically, buoyancy elements are attached and distributed along the body of the risers to limit the amount of top tension required to keep the riser in a suspended string configuration that suitably manages stress in all the tie-back riser components in all operating and survival conditions.
Dynamically adjusting devices providing top tensions to the individual top tensioned risers can be of any form already in application for floating production systems in deep waters. These top-end tensioners maintain a reasonable range of top tension variation for each riser while stroking in or out to accommodate the horizontal displacements and motions of the semisubmersible hull floating in a deep offshore environment. The tensioning devices are typically attached to a load bearing structural element in or attached to an upper section of the top-tensioned riser string that is called a “tensioning ring”. The attachment point for this tensioning ring should account for the stroke being provided by the tensioning devices.
The riser tensioning devices, called tensioners, can be direct acting of push-up/down or pull-up/down hydraulic rod and barrel type or wireline type or some combination of both. The attachment of the tensioners to the load bearing tensioning ring can be such that the risers are freely suspended from the movable wellbay structure or are housed within a guiding structure that is a rigid part of its frame and extends along the entire length of the vertical stroking movement to provide lateral restraint. In mild environments, it may also be possible to employ simple or compound springs as dynamic tensioners, as seen in industry and used on at least one TLP in southeast Asian waters.
The means and surface equipment needed for drilling and completing production wells and producing, processing, and exporting oil and gas production wells through these tie-back risers and surface wellheads that place the most critical valve and control systems in a dry surface environment are already well known and proven to those practiced in the art.
As an alternative to or in addition to the movable wellbay structure supporting a well drilling riser and/or production risers that provide direct access through surface mounted wellheads and production trees or a BOP into subsea wells located beneath the converted semisubmersible facility, one or more of the wellbay slots may be dedicated to supporting a tie-back riser that delivers production from and direct wellbore access into a subsea well located beneath the converted semisubmersible facility that is completed and produced through a subsea production tree.
As an alternative to or in addition to the movable wellbay structure supporting top tension well drilling or production risers that provide direct access through surface mounted wellheads and well control components into subsea wells located beneath the converted semisubmersible facility, one or more of the wellbay slots may be dedicated to supporting a tie-back riser that delivers production from one or more local or remote subsea wells completed with subsea trees. This top-tensioned riser can provide direct access to subsea separation and/or lifting equipment located on the seabed beneath the converted semisubmersible facility as well as providing flow paths for separated oil and gas flow streams. This top-tensioned riser can be designed for direct access to and recovery of key components of the separation and/or lifting equipment (such as electric submersible lift pumps or other downhole equipment) at the seabed. Having these capabilities comprised in the total system of the semisubmersible converted (or newly built) for the drilling, completion, production, intervention, maintenance, processing and exporting service described above enables field operators to gain valuable data and insights regarding productive performance characteristics of the reservoirs, the locations and configurations of the well bores, and the completion systems installed in the directly accessible and remote subsea wells.
The first preferred embodiment provides a method that converts an existing mobile offshore drilling unit (MODU) such that it will have the capacity for drilling, completion and maintenance of oil and/or gas wells, and production, processing and export of hydrocarbon fluids when riser top tensioning systems are attached to a movable wellbay structure supporting top tensioned tie-back risers from multiple subsea wells or other subsea production elements and allowing individual riser top ends to be located directly beneath a fixed or movable drilling derrick/rotary table or other operating devices located within or above the moonpool when the movable wellbay structure and appurtenances are retro-fitted into its moonpool. The movable wellbay structure of this embodiment includes upper structural elements as part of its overall frame structure, which are intended to transfer by contact the loads imposed by the weight of the movable wellbay structure and by the risers and well control or production equipment supported by the structure to rails or tracks on a mid-level deck (or multiple decks) of the converted MODU. The interface between the load transferring elements and the rails or tracks is designed with low friction surfaces, bearings, wheels or gearing that will allow translation of the movable wellbay structure in the desired direction, and when desired, be mechanically locked into a fixed position. The movable wellbay structure of this embodiment with riser tensioners and all supporting structures providing enough tensioning stroke and load bearing capacity to accommodate the normal operating and survival weather-induced motions when said movable wellbay structure is retro-fitted into the moonpool on the rig to convert it to serve as a floating production facility. The movable wellbay of this embodiment in which any of the wellbay slots designed to support top-tensioned production risers is also designed to allow the installation and use of a drilling riser string and well control devices affixed to the top of the top-tensioned drilling riser string. The movable wellbay of this embodiment that is made as a single structural frame comprising all the intended well slots or as separate structural frames for each or a pair of well slots that can be mechanically linked to act as a unified wellbay structure.
The movable wellbay structure of the first embodiment in which a structural element, commonly called a “tensioning ring” which incorporates features to avoid stress concentrations and may incorporate extensive framing elements, affixed to or part of a riser joint at the top of each of the top-tensioned riser strings supported by said movable wellbay structure is securely guided by a geared track or sliding contact with a rigid beam or rail built in as part of the movable wellbay structure frame structure extending vertically the entire range of stroke of the tensioning devices affixed between said movable wellbay structure and the tensioning ring and/or other guide devices attached to the riser, wherein the friction between the tensioner ring and other devices and the rigid beam or rail of the sliding contact is reduced by treating the contact surface of the tensioner ring's interfacing elements with a low friction coating or by affixing a pad or pads of low friction material to the contact faces of said ring and or the rigid beam or rail.
The facility described in the first embodiment can be used to appraise oil and gas reservoirs and to dynamically test by producing hydrocarbon fluids the suitability of various well completion technologies and schemes for the commercial production of hydrocarbon fluids contained in such subterranean reservoirs.
The movable wellbay structure of the first embodiment can support surface wellheads that allow direct vertical access to wells into reservoirs or to seabed pumps for lift of remotely tied back subsea (wet tree) wells from low pressure reservoirs.
The first embodiment can be designed to balance stretch and slack capacity of very long risers and the amount of distributed buoyancy affixed along the risers with the design stroke of the tensioners to manage stresses in the tieback risers supported on the movable wellbay structure of the first embodiment during normal operating and survival weather events and including shock absorbers and damping devices at the up and down-stroke stops to limit dynamic stress variations when stroke limits are reached.
The movable wellbay structure in the first embodiment can have the surface wellheads fixed to it without providing any dynamic tensioner stroke, and all motions and offsets can be accommodated by riser stretching and slacking.
Instead of having the movable wellbay structure supported on rails, a tensioner stroking interface can be provided between the movable structure of the first embodiment and the floating drilling rig into which it has been retrofitted. In this alternative embodiment, a preferentially adjustable feature to the stroking of the tensioners allows the movable wellbay structure in the first embodiment to be positioned horizontally as needed for direct access into any one of the risers.
The movable wellbay structure of the first embodiment can be fixed into a secure position or guided and constrained by mechanical and/or structural means to survive extreme storm conditions.
Another aspect of the first embodiment is modification of the motions' response of the floating facility supporting the movable wellbay structure of the first embodiment in extreme conditions with tension variation (stretch) in a centrally located set of risers (as well as the stretching and slackening of the lines of a mooring system that is added in place of or in addition to the DP system of the ultra-deep water MODU).
The hydrodynamic characteristics of the hull of the existing semisubmersible of the first embodiment can be modified to reduce its motions in waves and, thus, required stroke of the tensioners or stretch of the risers when such reduction of vertical response will not result in unacceptable increase in wave impact effects on the deck or well systems structures or equipment. There are many proven and practiced techniques for changing semisubmersible motions in waves, such as changing the ratio of surface-piercing column area to the volume of the submerged pontoon hulls by increasing their volume and planform area or by adding structurally reinforced plate extensions from the pontoons (usually inward or outward from the bottom plate or from an internal flat near the baseline) that significantly increase the added mass and damping hydrodynamic characteristics.
Another aspect of the first embodiment of the invention is replacing and/or modifying equipment on an existing semisubmersible MODU to incorporate the movable wellbay structure of the first embodiment to support and provide direct access to wells tied back to the converted facility by top-tensioned risers and to enable well completion, reservoir fluid production, processing, and exporting operations in addition to drilling operations.
A second embodiment of the present invention is a method for incorporating the movable wellbay structure of the first embodiment into the design and construction of a new-build semisubmersible floating facility designed for extended operations at a deep water site with capabilities and systems for drilling, completing, and maintaining wells and producing, processing, and exporting hydrocarbons from a subterranean reservoir. Such a new-build facility may also incorporate the capacity and systems for temporarily storing produced hydrocarbon fluids.
A third embodiment of the present invention is a method for incorporating the movable wellbay structure of the first embodiment into the design and construction of a new-build monohull floating facility designed for extended operations at a deep water site with capabilities and systems for drilling, completing, and maintaining wells and producing, processing, and exporting hydrocarbons from a subterranean reservoir. Such a new-build facility may also incorporate the capacity and systems for temporarily storing produced hydrocarbon fluids.
Turning now to the drawings, with reference to
With hidden lines eliminated for clarity,
Ideally, the tensioning devices (60a and 60b), such as hydraulically actuated cylinder and rod sets, provide nearly constant tension to the tensioning ring (70) while stroking in and out to accommodate relative motions between the movable wellbay structure (10) and the tensioning ring (70) as the semisubmersible unit to which the movable wellbay structure is affixed moves under the influences of the environment in which it is operating.
The range of stroke of the tensioning devices (60a and 60b) can be designed to ensure that the up stroke and down stroke limits are never exceeded during any expected conditions. However, to save money on the cost of the tensioning devices, the inherent elasticity of the long top-tensioned riser strings (90a-90c) can be used to advantage by balancing the stretch of said riser strings to be safely within the elastic range of stress while limiting the design stroke range of the tensioning devices (60a and 60b). In other words, as long as allowable stress limits within the risers, tensioning devices, and associated components are not exceeded when extreme relative movements of the tensioning ring (70) cause the tensioning devices to bottom out or top out, it is reasonable to limit the stroke range of the tensioning device allowing occasional bottoming out or topping out. When the downward stroke range limit is reached by relative movement of the tensioning ring (70), the top tension on the risers will increase rapidly as the riser stretches. A shock absorbing and damping system can be installed at the top and/or bottom of the tensioner stroke range to minimize the shock and vibration involved with the transition from freely stroking to topping or bottoming out. Operational or accidental changes in draft of the semisubmersible hull (comprised of submerged pontoons 100a-100b and partially submerged columns 105a-105b) should be avoided or limited to minimize the design stroke requirements for the tensioning devices (60).
When desired, a specific slot of the movable wellbay structure can be positioned with its wellhead situated under the rotary table such that, after the well has been stabilized, the surface production tree (20) can be removed, and a surface BOP and low pressure telescopic joint can be attached to the wellhead and attached to the diverter housing or mud return system under the rotary table. In this configuration, the converted MODU's rig has full functionality on the well, albeit with a surface BOP and top tensioned riser system rather than a subsea BOP and marine drilling riser system.
Oil and gas production from individual wells is transferred to production equipment installed on the converted semisubmersible unit via flexible pipe jumpers or other transfer means similar to what is used on spars and TLP's. Such fluids transfer is proven practice with jumpers tied back to a production manifold which in turn is connected to onboard process facilities and flare and/or vent systems.
With reference to
An alternative to having the top ends of the tensioned risers fixed rigidly into the structural tension-bearing deck rigidly fixed into the five slots in the movable wellbay structure in
An alternative to having the top ends of the tensioned risers fixed rigidly into the structural deck of the wellbay slot in the movable wellbay in
By retrofitting this movable wellbay structure innovation in any of the embodiments described above as the core feature in the conversion of existing semisubmersible drilling units into facilities capable of drilling, completing, intervening, improving, and maintaining wells and producing hydrocarbon fluids from subterranean reservoirs through top tension production risers, it is possible to greatly reduce the cost and lead time for achieving first production as compared to building a new facility of similar capabilities from scratch. Further, the existing semisubmersible converted by including this innovation will also provide a much more timely and cost effective means for producing and gathering critical insights into reservoir characteristics and well completion system performance than either a new or converted floating facility designed to produce from remote subsea wells due to the high cost of drilling, completing, and maintaining such wells when producing from high pressure, high temperature reservoirs located in deep waters.
This innovation has advantages over all prior art by disclosing a means to have multiple top-tensioned drilling and/or production risers connected between the converted MODU and wellheads located at the sea floor while providing the ability to move the surface wellhead atop of any one of these risers to a position directly beneath the rotary table and/or beneath other operating devices located in or above the moonpool of the converted MODU. In order to deploy and support an array of risers, it is preferred to convert the MODU for connection into a fixed taut leg mooring system where the rig maintains an essentially constant mean position and heading over the life of the facility. This is not possible with dynamically-positioned MODUs as they are designed to “weathervane” to minimize the forces imposed by wind, waves and currents. Dynamically-positioned MODU's also must have the ability to perform an emergency disconnect, should well control or station keeping limits be exceeded. Successfully managing an emergency disconnect with multiple risers and subsea BOPs and subsequently and simultaneously retrieving the risers after disconnect is not considered operationally feasible and poses dangerous and unnecessary risk to the facility and crew.
Others (White et al of U.S. Pat. No. 5,150,987, Springett et al of WO2016054610A1, and Jordan et al U.S. Pat. No. 9,238,943) have described a way to move an individual well riser from one location in a moonpool to a position beneath the rotary table of a fixed drilling derrick. Further, Finn et al in U.S. Pat. No. 6,431,284 B1 and U.S. Pat. No. 6,648,074 B2 and Vanvik in U.S. Pat. No. 6,691,784 describe mechanisms that allow moving wellbays vertically. However, no one has contemplated the concept or addressed the challenges of moving an entire wellbay structure to position the individual wellheads as needed beneath the fixed derrick and/or beneath other operating devices located in or above the moonpool. This variation and the inclusion of dynamic riser tensioning devices presents significant design challenges but also enables the effective conversion of an existing MODU into a valuable well drilling, completion, maintenance, improvement, and production facility offering direct vertical access with surface wellheads and BOPs to groups of subsea wells in deep waters.
This innovation does not require a low heave vessel like a deep draft semisubmersible, tension leg platform or spar in any of its embodiments. Industry has advanced the use of dry trees on floating platforms by designing the hull to minimize heave and, hence, riser stroke. All platform design solutions currently in practice employ the same drilling and completion technology using a fixed and stationary wellbay built structurally into the platform sub-structure with a drilling rig built on the top deck on a skidding system where it can be moved and positioned over any one of the fixed wellbay slots. The use of an existing semisubmersible MODU as a dry tree unit has not been considered feasible by industry due to the inability to move the drilling derrick on the top deck, as well as the large heave associated with these units during extreme storms. The innovation of the present invention eliminates the need for the rig to skid on existing purpose-built MODUs, where instead the entire wellbay frame is moved to position the desired wellhead as needed for direct well access for downhole activities, like drilling or work-over by the rig. Further, by advantageously using the inherent elasticity of a top-tensioned metallic tie-back riser as a large and long spring, it is possible to maintain the well systems in a safe and reliable state even during the most extreme storms. In locations subject to severe metocean conditions, it is possible to limit the stroke of the riser tensioning system by allowing the tensioners to “bottom out” where the tensioner stroke reaches a dynamic limit and is arrested by the use of structural restraints and shock absorbing systems to prevent further relative displacement while riser stretch accommodates part of the overall stroke requirement. Allowing the tensioners to bottom out and the risers to stretch can significantly reduce the overall heave of the vessel, enabling the movable wellbay structure and the top tension risers and well control or production equipment it supports to fit practically within the moonpool.
1. An offshore floating oil & gas well drilling, evaluation, completion, improvement, maintenance and production facility that includes: (1) a semisubmersible vessel or a monohull vessel having a vertical opening referred to as a moonpool, where the vessel has bulkhead and deck structures, including an upper deck called the drilling deck, surrounding the moonpool; (2) a drilling derrick with a primary operating device that may be positioned and/or secured to the drilling deck in a central position over the moonpool, where the drilling derrick may be fixed or movable; (3) mooring lines attached to the vessel for anchoring the vessel; (4) a wellbay assembly located at least partially in the moonpool, where the wellbay assembly is movable, where the wellbay assembly has at least two sets of riser tensioners in an array of structurally distinct positions or slots, where each riser tensioner set is designed and built to hold a riser in tension; and means for moving the wellbay assembly for aligning the top ends of first one of the at least two risers and then a different riser below the drilling derrick.
2. The offshore facility of embodiment 1, where the multiple top tensioned risers enable operations on and production from and vertical access to subsea completed wells with wet trees or surface completed wells with dry trees that have subsea wellheads located on a tight array on the seafloor essentially beneath the floating production facility, possibly where the wellheads are within about 50 feet of each other.
3. The offshore facility of embodiment 1 or 2, where each riser holder further includes a dynamic top tensioning system for holding a riser in tension.
4. The offshore facility of embodiment 1, 2 or 3, where the structural assembly is supported by a dynamic tensioning system which uniformly holds all of the more than two top-tensioned risers uniformly in tension when the risers are rigidly connected to the structural assembly.
5. The offshore facility of any one of embodiments 1-4, where the riser holders for each of the top tensioned risers are arranged such that while one of the riser top ends is located beneath the primary operating device one or more of the top ends of the other risers supported by the structural assembly are positioned beneath one or more other operating devices located in or above the moonpool near the primary operating device such that multiple operations can be performed on, in, or through the risers and their slots in the structural assembly simultaneously. Other operating devices include a secondary derrick and riser running or equipment lowering devices, which can set or pull plugs, run testing protocols on wells, be used to install and remove BOPs and trees. Other operating devices include, but are not limited to: elevators and transport devices for installation of BOP or trees on wellheads; testing kits; robotic devices interfacing with and making connections (e.g., jumper hose or control umbilical stabbing) between trees and production manifolds and hard piping; and a slick-line lubricator tower.
6. The offshore facility of any one of embodiments 1-5, where some or all of the multiple top tensioned risers convey production from remote subsea completed wells with wet trees to production facilities on the floating production system.
7. The offshore facility of any one of embodiments 1-6, where some or all of the multiple top tensioned risers can provide direct vertical access to hydraulic lifting or pumping equipment located beneath the floating production facility at the seabed or within producing wells.
8. The offshore facility of any one of embodiments 1-7, where the floating production facility is a permanently moored vessel that has a monohull or a semisubmersible hull form designed to support all relevant loads in all required metocean conditions.
9. The offshore facility of any one of embodiments 1-8, where the operating devices may each be either fixed in position on the vessel or be capable of being relocated and secured in ways that are advantageous for performing their operating functions individually or simultaneously.
10. A method for retrofitting and repurposing an existing mobile offshore drilling unit (MODU) for service as a floating production facility capable of drilling, evaluating, completing, maintaining, improving, and/or producing from wells penetrated into subsurface (subterranean) oil & gas reservoirs located beneath a body of water, including: (1) obtaining a right to modify and use the existing MODU, where the existing MODU has a moonpool, a marine drilling riser and tensioner system, a subsea blowout preventer (BOP) and cart transport system, marine drilling riser storage and handling equipment, and a non-permanent type spread mooring system suitable for speedy relocation of the MODU and/or a dynamic positioning system comprising thrusters, a power generation and management system, and a positioning control system; (2) removing the marine drilling riser and tensioner system, the subsea BOP and cart transport system, the marine drilling riser storage and handling equipment, and, if deemed advantageous, various components of the dynamic positioning systems from the MODU; (3) building and/or installing a structural assembly that is located at least partially in the moonpool, wherein the structural assembly is movable, wherein each riser holder is designed and built to hold a top-tensioned riser that is stretched between the riser holder and components at or near the seabed which allow for production of hydrocarbons from subterranean reservoirs; and (4) building and/or installing means for moving the structural assembly for aligning the top ends of first one of the at least two risers and then a different riser below the drilling derrick. However, an existing moored platform, which does not have a dynamic positioning system and related equipment, can also be converted to a floating oil and gas facility with a movable wellbay assembly.
11. The method of embodiment 10, where either the up stroke or down stroke or the range of both the up and the down stroke of the dynamic tensioners supporting the top tensioned risers is limited by placing mechanical stops and shock absorbing systems at desired positions such that the range of movement of the tension rings attached to the top tensioned risers is constrained while any further dynamic displacement of the hull is accommodated by stretching or compressing the risers.
12. The method of embodiment 10, where either the up stroke or down stroke or the range of both the up and the down stroke of the dynamic tensioners supporting the top tensioned risers is limited by splitting allocation of the targeted stroke range between the tensioners on the wellbay and those on the individual risers.
13. A floating oil and gas production platform installed in deep water that includes: a permanent spread mooring supporting a large centrally located drilling derrick with a primary operating device and a moonpool opening through the deck; a movable structural assembly located at least partially in the moonpool; at least two riser holders designed and built to hold a top-tensioned riser that is stretched between its riser holder and components at or near the seabed that allow for production of hydrocarbons from subterranean reservoirs; and structure and equipment for moving the structural assembly for aligning the top ends of first one of the at least two risers and then a different riser below the drilling derrick and primary operating device or below other operating devices mounted within or above the moonpool, where the operating devices perform functions related to drilling, evaluating, completing, maintaining, improving, and/or producing from wells penetrated into subsurface (subterranean) oil & gas reservoirs located beneath a body of water.
14. The offshore facility or method of any one of embodiments 1-13, where the means for moving the structural assembly is selected from among adjustable tensioners, skids, tracks, geared tracks, pads of low friction material, wheels, rolling, sliding, rails, guide rails, monorail, rack and pinion gears, electric motors, internal combustion engines, pistons, hydraulic pistons, hydraulic systems, crane systems, and push and pull systems.
15. An offshore drilling, completion and production facility that includes: a semisubmersible vessel or a monohull vessel having an opening therethrough referred to as a moonpool, where the vessel has upper and lower decks surrounding the moonpool; a drilling derrick fixed to the upper deck over the moonpool or fixed to a movable structure that is fixed to the upper deck over the moonpool; mooring lines attached to the vessel for anchoring the vessel; a movable structural assembly located at least partially in the moonpool that includes at least two riser holders that are designed and built to hold a riser; and structure and equipment (preferably including a rail system mounted directly or indirectly to the lower deck) for moving the structural assembly for aligning first one riser and then a different riser below the drilling derrick, preferably where each riser holder includes a riser tensioning system for holding a riser in tension
16. The offshore facility of embodiment 15, further including at least two subsea oil and/or gas wells; a riser extending between each well and one of the riser holders; and an assembly of valves, spools, and fittings referred to as a dry tree or a blowout preventer attached directly or indirectly to and in fluid communication with each riser, where the dry tree or the blowout preventer is located above the surface of the water during normal operation.
17. A method for appraising a formation below a seabed that is under water that includes: obtaining a right to modify and use an existing mobile offshore drilling unit (MODU), where the MODU is preferably a floating semisubmersible vessel or a floating monohull vessel, where the existing MODU has a deck, an opening through the deck known as a moonpool, a fixed or movable drilling derrick located above the moonpool that is mounted directly or indirectly to the deck; building and/or installing a movable structural assembly within the MODU that is located at least partially in the moonpool, where the structural assembly has at least two riser holders, and where each riser holder is designed and built to hold a riser; building and/or installing means for moving the structural assembly for aligning first one riser and then a different riser below the drilling derrick; drilling and completing at least two subsea oil and/or gas wells using the drilling derrick and pressure-competent drilling risers; placing a riser between each well and one of the riser holders; attaching an assembly of valves, spools, and fittings referred to as a dry tree or a blowout preventer directly or indirectly to each riser, where the dry tree or the blowout preventer is located above the surface of the water during normal operation; and producing oil and/or gas from the oil and/or gas wells, where the method preferably includes connecting a dry tree tie-back assembly of valves and controls to the wellhead at the top of the riser.
18. The method of embodiment 17, further including either: (1) attaching an assembly of valves, spools, and fittings referred to as a dry tree or a blowout preventer directly or indirectly to each riser, where the dry tree or the blowout preventer is located above the surface of the water during normal operation, where each riser is designed for full well operating pressure or (2) attaching an assembly of valves, spools, and fittings referred to as a riser base, a wet tree and a subsea choke directly or indirectly to each well below the surface of the water, preferably at the seabed, where the riser base, the wet tree and/or the subsea choke is designed to reduce the pressure of produced oil and/or gas so that each riser can be designed for less than full well operating pressure
19. The method of embodiment 17-, further including installing one or more mudline oil and gas separation systems; placing a riser between each mudline separation system and one of the riser holders; completing the oil and/or gas wells; connecting a surface tie-back assembly of valves and controls to the wellhead at the top of the riser; and producing oil and/or gas from the oil and/or gas wells through the mudline separation system.
20. The method of any one of embodiments 17-19, further including adding production facilities and export systems for producing oil and/or gas from the oil and/or gas wells drilled into said reservoir; and producing from said reservoir to gather data and generate insights about the productivity of the reservoir and the means for implementing effective well completions.
21. The method of any one of embodiments 17-20, where the structural assembly is made movable using one or a combination of adjustable tensioners, skids, tracks, geared tracks, wheels, rolling, sliding, rails, guide rails, monorail, rack and pinion gears, pads of low friction material, electric motors, internal combustion engines, pistons, hydraulic pistons, hydraulic systems, crane systems, and push and pull systems.
22. An offshore floating platform for oil and gas well drilling, evaluation, completion, improvement, maintenance and/or production, which includes: a semisubmersible vessel or a monohull vessel having a vertical opening referred to as a moonpool, where the vessel has bulkhead and deck structures, and where the vessel has an upper drilling deck that surrounds the moonpool; a drilling derrick with a primary operating device that may be positioned and/or secured to the drilling deck over the moonpool; mooring lines attached to the vessel for anchoring the vessel; a wellbay assembly located at least partially in the moonpool, where the wellbay assembly is movable, where the wellbay assembly has at least two sets of riser tensioners in an array of structurally distinct slots, and where each riser tensioner set is designed and built to hold a riser in tension; and means for moving the wellbay assembly for aligning an upper end of first one riser and then a different riser below the drilling derrick.
23. The offshore floating platform of embodiment 22, where the wellbay assembly comprises a structural frame to support a set of individual riser tensioners for each well and a tensioning ring to which the tensioners are attached, where the wellbay assembly comprises guide rails, and wherein the tensioning ring is guided by the guide rails while stroking up and down.
24. The offshore floating platform of embodiment 23, where the wellbay assembly comprises a grid that has at least two or from 2 to 8 slots and a frame, where the grid is supported by the frame, and where the grid is movable with respect to the frame along one axis.
25. The offshore floating platform of embodiment 24, wherein the frame has opposing parallel edge members, wherein the vessel has a pair of supports, wherein the opposing edge members rest on the pair of supports and are movable back and forth on the pair of supports, and where the movement of the grid on the frame is orthogonal to the movement of the frame on the pair of supports.
26. The offshore floating platform of embodiment 22, where the wellbay assembly comprises a grid that has from 2 to 8 slots, where the vessel has a pair of supports, where the grid rests on the pair of supports and is movable back and forth on the pair of supports along a first axis, where the vessel has a pair of beams or rails that traverse the moonpool, where the derrick is received on the pair of beams or rails and is movable on the pair of beams and rails along a second axis, and where the second axis is orthogonal to the first axis.
27. A system that includes the offshore floating platform of embodiment 22; one or more subterranean oil and/or gas wells; and a riser between each riser tensioner set and a well, preferably further including production facilities on the offshore floating platform, preferably where at least one well is completed with a wet tree for production through the riser to the production facilities, and preferably where at least one well is completed with a dry tree for production through the riser to the production facilities. The system preferably further includes hydraulic lifting or pumping equipment located at the seabed or within a well, where a top end of the riser can be moved by moving the wellbay assembly for providing vertical access to the hydraulic lifting or pumping equipment through the riser. The system preferably also further includes a mudline oil and gas separation system; a riser between the mudline separation system and one of the riser holders; a dry tree on the riser; and a surface tie-back assembly of valves and controls connected to the dry tree for production through the mudline separation system. The means for moving the wellbay assembly in the system is selected from among adjustable tensioners, skids, tracks, pads of low friction material, geared tracks, wheels, rolling, sliding, rails, guide rails, monorail, rack and pinion gears, electric motors, internal combustion engines, pistons, hydraulic pistons, hydraulic systems, crane systems, and push and pull systems.
Having described the invention above, various modifications of the techniques, procedures, materials, and equipment will be apparent to those skilled in the art. It is intended that all such variations within the scope and spirit of the invention be included within the scope of the appended claims.
This application claims priority to and the benefit of U.S. Provisional Patent Application Ser. No. 62/384,626 filed on Sep. 7, 2016, and U.S. Nonprovisional patent application Ser. No. 15/482,064 filed on Apr. 7, 2017 (now U.S. Pat. No. 9,976,364, issued May 22, 2018) and U.S. Ser. No. 15/960,724 filed Apr. 24, 2018 (now U.S. Pat. No. 10,428,599, issued Oct. 1, 2019), all of which are incorporated by reference.
| Number | Name | Date | Kind |
|---|---|---|---|
| 4367796 | Bolding | Jan 1983 | A |
| 5147148 | White et al. | Sep 1992 | A |
| 5150987 | White et al. | Sep 1992 | A |
| 5427180 | dePaiva Leite | Jun 1995 | A |
| 5492436 | Suksumake | Feb 1996 | A |
| 6041865 | Knapp | Mar 2000 | A |
| 6431284 | Finn et al. | Aug 2002 | B1 |
| 6601531 | Baylot | Aug 2003 | B1 |
| 6648074 | Finn et al. | Nov 2003 | B2 |
| 6691784 | Wanvik | Feb 2004 | B1 |
| 6692193 | Beynet et al. | Feb 2004 | B2 |
| 6766860 | Archibald et al. | Jul 2004 | B2 |
| 7451821 | Rashid et al. | Nov 2008 | B2 |
| 7628225 | Petersson et al. | Dec 2009 | B2 |
| 8083440 | Curtiss, III | Dec 2011 | B2 |
| 8251003 | Vandenworm | Aug 2012 | B2 |
| 8522880 | Roodenburg | Sep 2013 | B2 |
| 9238943 | Jordan | Jan 2016 | B2 |
| 9341024 | Labrugere | May 2016 | B2 |
| 9458671 | Jordan et al. | Oct 2016 | B2 |
| 9677368 | Jordan et al. | Jun 2017 | B2 |
| 9976364 | Shilling, III | May 2018 | B2 |
| 10428599 | Shilling, III | Oct 2019 | B2 |
| 20020074125 | Fikes et al. | Jun 2002 | A1 |
| 20060231273 | Armstrong | Oct 2006 | A1 |
| 20100147528 | Baugh | Jun 2010 | A1 |
| 20120018166 | Croatto | Jan 2012 | A1 |
| 20130098627 | Jordan et al. | Apr 2013 | A1 |
| 20130189039 | Wanvik et al. | Jul 2013 | A1 |
| 20130195559 | Andresen | Aug 2013 | A1 |
| 20140305655 | Otten | Oct 2014 | A1 |
| 20150068726 | Vogt et al. | Mar 2015 | A1 |
| 20160145943 | Jordan et al. | May 2016 | A1 |
| 20160376862 | Jordan et al. | Dec 2016 | A1 |
| 20170298694 | Jordan et al. | Oct 2017 | A1 |
| 20180066481 | Shilling, III | Mar 2018 | A1 |
| 20190257160 | Shilling, III et al. | Aug 2019 | A1 |
| Number | Date | Country |
|---|---|---|
| 2383418 | Mar 2001 | CA |
| 2001016458 | Mar 2001 | WO |
| 2012104309 | Aug 2012 | WO |
| WO-2012104309 | Aug 2012 | WO |
| 2013062736 | May 2013 | WO |
| 2016054610 | Apr 2016 | WO |
| Entry |
|---|
| USPTO, Examiner Search Information, U.S. Appl. No. 15/482,064, dated Dec. 27, 2017, 2 pages, Alexandria, VA (USA). |
| USPTO, Examiner Search Strategy, U.S. Appl. No. 15/482,064, dated Dec. 27, 2017, 3 pages, Alexandria, VA (USA). |
| USPTO, Examiner (USPTO) Form 892, U.S. Appl. No. 15/482,064, dated Dec. 27, 2017, 2 pages, Alexandria, VA (USA). |
| USPTO, Examiner Office Action, U.S. Appl. No. 15/482,064, dated Dec. 27, 2017, 14 pages, Alexandria, VA (USA). |
| Jeffrey L. Wendt, Response to USPTO Examiner Office Action, U.S. Appl. No. 15/482,064, dated Jan. 23, 2018 14 pages, Alexandria, VA (USA). |
| USPTO, Examiner Search Strategy, U.S. Appl. No. 15/482,064, dated Mar. 15, 2018, 2 pages, Alexandria, VA (USA). |
| USPTO, Examiner Search Information, U.S. Appl. No. 15/482,064, dated Mar. 15, 2018, 2 pages, Alexandria, VA (USA). |
| USPTO, Notice of Allowance, U.S. Appl. No. 15/482,064, dated Mar. 15, 2018, 7 pages, Alexandria, VA (USA). |
| The International Bureau of WIPO, Notification Concerning Transmittal of International Preliminary Report on Patentability (Chapter I of the Patent Cooperation Committee, for PCT/US2017/048893, pp. 1, dated Mar. 21, 2019, Geneva, Switzerland. |
| The International Bureau of WIPO, International Preliminary Report on Patentability (Chapter I of the Patent Cooperation Treaty), for PCT/US2017/048893, pp. 1-6, dated Mar. 12, 2019, Geneva, Switzerland. |
| USPTO, Examiner Office Action, U.S. Appl. No. 15/960,724, dated Feb. 14, 2019, 23 pages, Alexandria, VA (USA). |
| Jeffrey L. Wendt, Response to USPTO Examiner Office Action, U.S. Appl. No. 15/960,724, dated May 9, 2019, 8 pages, Alexandria, VA (USA). |
| USPTO, Notice of Allowance, U.S. Appl. No. 15/960,724, dated Jul. 17, 2019, 15 pages, Alexandria, VA (USA). |
| Number | Date | Country | |
|---|---|---|---|
| 20200040671 A1 | Feb 2020 | US |
| Number | Date | Country | |
|---|---|---|---|
| 62384626 | Sep 2016 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 15960724 | Apr 2018 | US |
| Child | 16587609 | US | |
| Parent | 15482064 | Apr 2017 | US |
| Child | 15960724 | US |
