Patent Grant
10738567
The invention relates to methods, systems and devices for plug and abandonment operations to shut down a well or a portion thereof.
The decision to plug and abandon (P&A) a well or field is an economic decision. Once production value drops below operating expenses, it is time to consider abandonment, even if considerable reserves remain. Thus, well abandonment is an inevitable stage in the lifespan of a well.
It is also possible to abandon only part of a well. One cost effective way to enhance production is to permanently abandon the bottom of the well, but use the existing slot to sidetrack the well to reach new pay-zones. The cost can often be cut in half when sidetracking an existing well instead of drilling a new horizontal well. This process is known as “slot recovery.”
Plugging can also be temporary, e.g., to allow for work-over, a long shut-in, or for converting an exploratory well to a production well. Norwegian standards state that the integrity of materials used for temporary abandonment should be ensured for the planned abandonment period times two.
In oilfield jargon “plug and abandon” or “P&A” refers to preparing a well to be closed permanently (or at least until prices or technology developments warrant reentry). The earliest oil wells were abandoned without any plugging, but the first plugging requirements were enacted by Pennsylvania in the 1890s. However, prior to modern regulations set in the '50s, many wells were abandoned with plugs consisting of brush, wood, paper sacks, linen or any other material that could be pushed into a well to form a basis for the dumping of one or two sacks of cement to “plug” the well. Current procedures are significantly more disciplined however.
Plugging and abandonment (P&A) regulations vary among states and between countries, but all regulations prescribe the depth intervals that must be cemented, as well as the materials that are allowed in plugging practices. Most states require that cement plugs be placed and tested across any open hydrocarbon-bearing formations, across all casing shoes, across freshwater aquifers, and perhaps several other areas near the surface, including the top 20 to 50 ft [6 to 15 m] of the wellbore. Many countries and states require that a “rock-to-rock” cement plug be set that is contact with wellbore outside the casing if the casing is not adequately isolated with cement.
In recognition of its strength, low permeability and low cost, cement typically is used to create a seal between formations or to seal off the surface of the wellbore. Other materials that do not offer the same strength or durability as cement, including drilling mud, gel, and clay, are used to fill in the spaces between cement plugs. Additionally, many states allow the use of mechanical bridge plugs in lieu of a large cement plug since the bridge plug is extremely strong and nearly completely impermeable. However, mechanical plugs are susceptible to corrosion, and therefore the regulations typically require the bridge plugs to be capped by a specified amount of cement.
The basics of P&A operations vary little, whether the well is on land or offshore. Operators remove the completion hardware, set plugs and squeeze cement into the annuli at specified depths across producing and water-bearing zones to act as permanent barriers to pressure from above and below, in addition to protecting the formation against which the cement is set. Operators remove the wellhead last. Some basic plugs are shown in
Balanced plug technique is the most common placement method used in abandonment operations today. A tubing or a drill string is lowered to the desired depth for the plug base and the cement slurry is pumped until the cement slurry level is the same inside and outside of the string. When the cement height is the same on the inside of the tubing as in the annulus, the pipe is slowly pulled out. The pipe will be pulled out with a speed so that the fluid level is balanced at all times. When the pipe reaches the cement-spacer interface, little or no mixing between the spacer and the cement will occur if the interfaces between the fluids are the same both inside and outside the pipe.
One of the main problems in any cementing procedure is contamination of the cement. Poor mud-removal in the area where the cement is to be set can give rise to channels through the plug caused by the drilling fluid. To avoid this, a spacer is often pumped before and after the cement slurry to wash the hole and to segregate the drilling fluid and the cement from each other.
Another cause for channeling is eccentricity of the tubing, indicating the importance of adequate use of centralizers, which hold the tubing in the center of the bore. The cement will have more difficultly moving on the narrow side of the tubing, tending to allow channeling in the narrow space, and even where channeling does not occur, the cement will be thinner on that side, and thus be weaker and more easily damaged. Cement shrinkage can also cause gaps between the plug and casing and between the plug and reservoir wall. (
Because cement is susceptible to channeling, shrinkage and other problems, most regulations require that a substantial length of well be filled with cement, ranging from 30 to 50 meters. Thus, the response to cements shortcomings is to simply use more cement, in the hopes that eventually a reliable barrier will be formed. However, a 50-meter length of cement plug can require 2 tons of cement, which is expensive and time consuming to deploy, and takes a long time to cure. Area preparation and tubular removal, which might require milling of casing strings, is also very time consuming. Where every day on an offshore rig costs as much as a half to a million dollars a day, there is a strong drive to reduce time and costs.
Other materials have been investigated for use as plugging material. Resins offer superior adhesion, resistance to many caustic and corrosive chemicals, excellent mechanical properties such as low yield point and low viscosity in the unset state, and flexibility and toughness after setting, but historically they have been difficult to deploy without premature setting and or reactivity with downhole fluids. Additionally, if resin is placed in same volume as cement, it would make resin use very expensive, probably prohibitively costly.
Today's resin materials have improved however, and include ThermaSet by Wellcem AS, CannSeal by AGR, and the WellLock® resin system by Halliburton®. M&D Industries also makes resin plugging materials, including LIQUID BRIDGE PLUG®S with a range of hardeners and accelerators. The WellLock® resin, for example, uses cross-linking between an amine hardener and epoxides, resulting in a cured three-dimensional infinite polymer network, and can be deployed without negative impact from exothermic reactions triggered by water.
New types of cement slurries consisting of geopolymeric materials have also been developed as alternative to the conventional lightweight cement slurry. Geopolymers are made of aluminum and silicon and they exhibit superior mechanical and chemical properties compared to the Class G cement. Geopolymers can provide a material with specific properties from a range of cement/fly-ash/aluminiosilicate component ratios. This gives a lightweight slurry with high compressive and flexural strength thought to replace the conventional lightweight cements containing silica fume.
Sandaband is another cement alternative. It is a sand-slurry consisting of about three quarters sand particles and one quarter water and other additives, developed in Norway to meet the increasing demands of an long lasting plugging material. Sandaband possesses the properties as a Bingham fluid and acts as a deformable solid when it's stationary, but as a liquid when in motion. This ductile behavior means that the sand slurry will never fracture or create micro annuli. The sand slurry is also incompressible and gas tight, and does not shrink, fracture or segregate. It does however require a solid foundation, as it will sink if placed on another fluid.
Today, regulators are increasingly demanding that operators remove sections of casing so that a plug may be set that is continuous across the entire borehole in a configuration often referred to as “rock-to-rock,” and located in the cap rock above the reservoir. Because cement or other plugging material must go all the way to the formation wall, the typical procedure was to pull the tubing, mill the casing, and remove swarf before spotting the cement. See
One response to these challenges has been the introduction of a system known as perforate, wash and cement or “PWC” in a single run. The PWC operation is designed to access the formation through perforations in the casing to place a rock-to-rock cement barrier without removing the casing, thus saving valuable rig time and eliminating the swarf problem. To use this system, the well must be secured, Christmas tree removed, tubing pulled, and then PWC job can be done.
The PWC method uses a special tool by Archer, described in US20150053405. The tool is made of pipe conveyed perforating guns attached below a wash tool, which is below a cement stinger. Using PWC, ConocoPhillips completed 20 PWC plug installations in the North Sea, reducing the time required to set a permanent plug to 2.6 days from 10.5 days using section milling. As a result, the company calculated a savings of 124 rig days over the course of the 20 PWC wells. Given that rig time can easily be upwards of half a million dollars per day for an offshore rig, even a few days less time required for P&A can mean significant cost savings.
Although an improvement, the PWC method has limitations. To date, the PWC method has not been successfully applied through multiple casings. Furthermore, it is difficult to implement this method if the pipe has deformed such that the lengthy tool can no longer enter through the deviated section.
Thus, what is needed in the art are better methods, devices and systems for P&A that are safe, create a reliable barrier, that are cost effective, and both faster and easier to perform than current methods. Ideally, the new method would not require rig time, and would be performed “through tubing,” and could provide a “rock-to-rock” plug. An ideal system would not require securing the well, allow the Christmas tree to remain in place during operations acting as a barrier, avoid expensive modular offshore drilling unit or “MODU” use, and also avoid the rigging up of large BOP' s and well control equipment.
The present disclosure provides systems, methods and devices for P&A operations, wherein the production tubing is left in place, as is the Christmas tree, until the P&A is complete, and a two-material binary plug made of a resin and cement is placed in the well. The methods are also useful for other plugging operations, such as slot recovery, temporary abandonment, and the like. We have called this two material plug a “bi-plug” herein.
The method is a “through tubing” P&A because the tubing is left in place for the operation. Typically, in P&A the tubing is pulled and the well is secured with barriers, plugs, fluid, or other methods and the Christmas tree is replaced with a well control equipment called a blowout preventer or “BOP.” The Christmas tree would of course already be equipped with a BOP, but that device typically has a maximum size of 7 1/16″ and it is typically replaced with a much larger BOP of 13⅝″ or larger, which typically requires a MODU to install for offshore wells.
“Through tubing” P&A, in contrast, means that the larger BOP will not have to be used because the well will be fully secured by permanent plugs in the wellbore before removing the Christmas tree. Because MODU use is avoided, the cost is $100,000 per day, compared to $500,000 or more per day for MODU use. Additionally, on some installations, two wells could be plugged at the same time if there was sufficient room for two or more P&A operations, further saving on costs and time.
Although the method is described as a “through tubing” method, the tubing is in fact actually removed (wholly or partially) at a small section to be plugged, however, the bulk of tubing remains in place. Thus, although removed, it is a much smaller section (1 to 5 m) than the 50-100 meters currently used in mill and plug techniques using cement plugs. Nevertheless, it is appropriately designated through tubing because the entirety of the tubing need not be pulled out of the well prior to the P&A operation. This disclosure describes a variety of ways to remove a short region of tubing and/or casing and access the plugging interval, but one preferred way is rupture and expansion.
A base plug or other blocking device is deployed to at or near the plugging zone. This blocking device can be set before casing and tubing removal, if set somewhat below the plugging zone, or can be placed after rupture and expansion at the base of the rupture and expansion zone, as desired. The base plug or blocking device should prevent at least 90% of the resin for falling downhole, at least 95%, preferably at least 99% or it may even provide a complete seal, although that is not a requirement.
A resin is then used to set a first plug, according to regulations and well dictates. If desired, the resin can be squeezed and or logged before the next step, but this is not a strict requirement.
In a second step, a cement cap is set on top of the resin plug, thus providing a two material plug, or a bi-plug (a binary plug having two sections of different materials adjacent each other). If desired, the cement can be squeezed and/or the bi-plug logged, depending on regulations and well dictates.
To the extent that the well at the section to be plugged is not cemented or is only poorly cemented, the method must first provide access to the annular space between the tubing and casing and between the outermost casing and reservoir so that the bi-plug can reach the reservoir. This can be done by rupture and expansion, perforation, cutting, milling, and other methods of either removing these tubulars, or rupturing them sufficiently for access. A preferred method uses directional charges, thus, the tubing and casing are left in place, but are ruptured and expanded, as is any poor quality cement outside the casing.
To the extent that the well at the section to be plugged is adequately cemented, the rupture and expansion is replaced by another method that leaves the exterior casing and annular cement intact. Thus, milling, cutting or other methods are used to remove a short (about 1 to 5 meters) section of the nested tubulars. The method then proceeds as above, setting a bi-plug.
If required, the bi-plug quality can be accessed by drilling a small hole out for logging tool access. Once bi-plug integrity is confirmed, the small hole can be plugged with either resin or cement, as described herein, or with an expandable alloy, such as described in co-pending COP 42399, U.S. Ser. No. 62/402,796, filed Sep. 30, 2016). This filled bi-plug thus provides a primary barrier, or a secondary barrier, or both, and once the barriers are in place, the Christmas tree can be removed, and the well closed for P&A.
In more detail, the invention includes any one or more of the flowing embodiment(s) in any one or more combination(s) thereof:
As used herein, a “P&A” refers to plug and abandon. Regulations require that the plugs be of sufficient quality to be “permanent,” never allowing formation fluids to leak. However, it is recognized that even a permanently plugged and abandoned well may be reopened at a later time for various reasons. Therefore, “permanent” does not imply that the well will not be reopened, but instead refers to the quality of the plug—it needing the potential to last for decades or more.
As used herein, a “blocking device” is any device used to prevent cement or alloy from falling downhole, e.g., it provides a stable base on which to set the cast-in-place abandonment plug. This can be a mechanical device, such as basket, inflatable basket, plug, packer, or a metal alloy plug formed by melting Bismuth alloy, and the like. The blocking device could also be non-mechanical device such as a cement plug, barite plug, sand plug, a bolus of extra heavy mud, combinations thereof, or any other non-mechanical blocking device. Since this only acts as a base for a permanent plug, it is not required to act as a permanent plug by itself, and the requirements are less stringent. The blocking device can even be the bottom of the well if near enough to the plug zone. The use of a non-mechanical plug may be beneficial to fill an irregular space left by, e.g., a rupture and expansion tool, and block the annular space of tubulars left in the well, but a mechanical device can be set somewhat below the plugging zone with efficacy too.
“Tubular” or “tubing” can be used generically to refer any type of oilfield pipe, such as drill pipe, drill collars, pup joints, casing, production tubing and pipeline. However, generally we have referred to the inner tubing, such as injection tubing or production tubing as tubulars herein. The outer one or more tubing sets, we have referred to as “casing” herein.
As used herein, a “joint” is a length of pipe, usually referring to drillpipe, casing or tubing. While there are different standard lengths, the most common drillpipe joint length is around 30 ft [9 m]. For casing, the most common length of a joint is 40 ft [12 m].
As used herein, a “tubular string” or “tubing string” refers to a number of joints, connected end to end (one at a time) so as to reach down into a well, e.g., a tubing string lowers a sucker rod pump to the fluid level. These can also be called just “string.”
As used herein, a “Christmas tree” provides primary and back-up control facilities for normal production and wellbore shut-in. Christmas trees are found in a wide range of sizes and configurations, depending on the type and production characteristics of the well. The Christmas tree also incorporates facilities to enable safe access for well intervention operations, such as slickline, electric wireline or coiled tubing.
As used herein the “wellhead” refers to the surface termination of a wellbore that incorporates facilities for installing casing hangers during the well construction phase. The wellhead also incorporates a means of hanging the production tubing and installing the Christmas tree and surface flow-control facilities in preparation for the production phase of the well.
As used herein, a “blow out preventer” or “BOP” is a large device with a plurality of valves and fail-safes at the top of a well that may be closed if the drilling crew loses control of formation fluids. By closing the BOP (usually operated remotely via hydraulic actuators), the drilling crew usually regains control of the reservoir, and procedures can then be initiated to increase the mud density until it is possible to open the BOP and retain pressure control of the formation. BOPs come in a variety of styles, sizes and pressure ratings.
As used herein a “lubricator” is a long, high-pressure pipe fitted to the top of a wellhead or Christmas tree so that tools may be put into a high-pressure well. The top of the lubricator assembly includes a high-pressure grease-injection section and sealing elements. The lubricator is installed on top of the tree and tested, the tools placed in the lubricator and the lubricator pressurized to wellbore pressure. Then the top valves of the tree are opened to enable the tools to fall or be pumped into the wellbore under pressure. To remove the tools, the reverse process is used: the tools are pulled up into the lubricator under wellbore pressure, the tree valves are closed, the lubricator pressure is bled off, and then the lubricator may be opened to remove the tools.
As used herein “swarf” are the fine chips or coils of metal produced by milling the casing or tubing.
As used herein, a “cutter” is any downhole tube that can be used to cut casing or tubing, which is typically done when a tool is stuck, in order to retrieve the tubing string and send down fishing tools. There are a number of different types of such tools, some of which are named herein.
An “external cutter” is a type of cutter. The external cutter slips over the fish or tubing to be cut. Special hardened metal-cutters on the inside of the tool engage on the external surfaces of the fish. External cutters are generally used to remove the topmost, possibly damaged, portion of a fish to enable an overshot, or similar fishing tools, to engage on an undamaged surface.
As used herein, a “chemical cutter” is a type of cutter run on wireline to sever tubing at a predetermined point when the tubing string becomes stuck. When activated, the chemical cutter uses a small explosive charge to forcefully direct high-pressure jets of highly corrosive material in a circumferential pattern against the tubular wall. The nearly instantaneous massive corrosion of the surrounding tubing wall creates a relatively even cut with minimal distortion of the tubing, aiding subsequent fishing operations.
As used herein, a “jet cutter” is a type of cutter, generally run on wireline or coiled tubing, that uses the detonation of a shaped explosive charge to cut the surrounding tubing or casing wall. The cutting action leaves a relatively clean cut surface, although the explosive action tends to flare the cut ends.
As used herein, a “perforation tool” cuts small holes or slots in the tubulars. These are typically used to convert a designated region of casing to production use, the holes allowing ingress of oil. Such tools can also be used herein in the P&A process.
As used herein, an “expansion tool” is a downhole tool used to expand the diameter of a tubular. This is done either hydraulically, by applying mud pressure, or mechanically, by pulling the conical/tapered expansion tool, or by a rotating axial force.
As used herein a “rupture and expansion tool” is distinguished from an expansion tool, which leaves the casing intact, albeit bigger. Instead, this tool both ruptures and expands casing and tubing. Exemplary tools are being developed, and herein we have used prototypes that uses an energetic material (typically directional charges) that when ignited creates heat and large volume of gas in a short period of time. The material is designed to expand, rupture, and give annulus access in a controlled manner. Each device is designed for the particular tubular and casing in each well. The device can also be defined as “Tubular Expansion Rupture and Annular Access (TERAA).”
Yet another tool that could be used is a “laser cutter”, such as the one developed by FORO Energy. They have developed a high-energy laser with low loss fiber optic cable that can be deployed down hole extremely rapidly and with millimeter accuracy.
As used herein a “cement bond log” or “CBL” is a representation of the integrity of the cement, especially whether the cement is adhering solidly to the outside of the casing. The log is typically obtained from one of a variety of sonic-type tools. The newer versions, called cement evaluation logs, along with their processing software, can give detailed, 360-degree representations of the integrity of the cement, whereas older versions may display a single line representing the integrated integrity around the casing. In this case, the CBL is used to determine that a good connection between the abandonment plug and the formation walls, and it can be used to check the quality of the resin plug as well.
A CBL can be generated with a “cement bond tool.” Cement bond tools infer the quality of the bond between casing and the cement (or resin) placed in the annulus between the casing and the wellbore. The measurement is made by using acoustic (sonic and ultrasonic) tools.
The use of the word “a” or “an” when used in conjunction with the term “comprising” in the claims or the specification means one or more than one, unless the context dictates otherwise.
The term “about” means the stated value plus or minus the margin of error of measurement or plus or minus 10% if no method of measurement is indicated.
The use of the term “or” in the claims is used to mean “and/or” unless explicitly indicated to refer to alternatives only or if the alternatives are mutually exclusive.
The terms “comprise”, “have”, “include” and “contain” (and their variants) are open-ended linking verbs and allow the addition of other elements when used in a claim.
The phrase “consisting of” is closed, and excludes all additional elements.
The phrase “consisting essentially of” excludes additional material elements, but allows the inclusions of non-material elements that do not substantially change the nature of the invention.
The following abbreviations are used herein:
Developed herein is a method of plug and abandonment, which is shown schematically in various embodiments in
A wireline lubricator is placed on top the Christmas tree (not shown). The lubricator contains a tool with an energetic device 421 having charges 422, suspended from the wireline 423, designed to rupture and expand the tubing and casing (
The above energetic tool is only one method of gaining access to the reservoir wall, and other methods that can be used. These other methods include using: i) a milling tool run on wireline or coiled tubing, although this is less preferred as the swarf must be removed; ii) upward milling and allowing swarf to fall downhole, iii) a jetting tool that uses water and abrasives; iv) a plasma melting tool; v) a laser cutter, energetic cutters, propellant cutters, and the like. Note that although milling can be used, it still differs from prior art milling techniques, which mill 50-100 meters of tubing, whereas the method described herein mills only a tenth of that amount (1 foot-5 meters).
The expanded cavity can be washed using a tool (e.g., jet washer) on coil tubing, but this is optional. Access to the annular space between the casing and formation can be assessed, by e.g., camera or sonic log, and if insufficiently ruptured, the casing can also be perforated to give better access to the annulus cavity. A perforated cavity is shown in
The cavity (before and/or after perforation) can also be mapped using a sonic tool or camera 424 to determine the size of the cavity and access to the reservoir. This and similar verification steps are important when establishing the validity of the method, but may be omitted once sufficient experience has been gained, or the verification and/or washing steps may be performed in different order.
A blocking device 410 can then be run and set in the bottom of the cavity to provide a base or bottom for the abandonment plug 434 (
Exemplary devices include the SlikPak™ Plus system, by TAM International, Inc. This is a battery operated, computerized, inflatable, retrievable bridge plug setting system designed to be run on slickline or electric line. Other suitable devices include the ACE Thru Tubing Umbrella Plug, which firmly anchors into place a “metal petal” umbrella that functions as a cement basket to be utilized as a base for subsequent placement (dumping) of bridging material, cement, or resin. Hole Products also offers a complete line of inflatable wireline packers, as does Barracuda Oil Tools. BiSN has Bismuth Alloy plugs that could be used.
The blocking device does not need to be perfect, as resin will fill in any imperfections, solidify, and then prevent further leakage. Further, if the casing is cemented, even with poor quality cement, the rupture and expansion tool will cause the cement behind the rupture zone to crumble and fall downhole, also providing blockage to resin falling downhole. Where an expandable base plug is used and the casing is not cemented, it should be set close to where the expanded tubing meets the wall, to ensure minimal loss of resin downhole. However, this is only one option for setting a blocking device. If desired, the tubing at the bottom of the plug zone can be cut, e.g., with a jet cutter or mill, and the plug set where the tubing is removed, and tubing above the plug ruptured and expanded, etc. There are other ways of setting a reasonably leak-proof base plug that can be used, and the operator can use the most cost effective or convenient method.
Next (
After the resin is cured, the next step is to fill the remaining cavity with cement 437 or to cap the resin plug with cement (
If desired or required by regulations, a bore can be made in the plug and a logging tool run to confirm the placement and quality of the bi-plug once fully cured and set. In the future, it may be practical to log the plug without drilling a bore, in which case the bore can be omitted, but current regulations requires the central portion of the bi-plug be drilled out to allow entry of the 360° cement bond tool (
Once a solid connection between the resin/cement and expanded casing and formation is confirmed, another base plug 411 is set and cement 451 or other material refills hole and typically overcaps the two material bi-plug 499 (
Final tests to confirm bi-plug integrity include sonic or ultrasonic logging, positive pressure tests and negative pressure tests, inflow tests, and the like.
To verify the position of a bi-plug, top of cement (TOC) can be tagged. To tag TOC, the work string or toolstring is slowly lowered until a reduction in weight is noticed as the string lands on the cement plug. Plug location and top of cement is then confirmed. To test integrity of a bi-plug, a load test can be performed. A load test is performed by lowering the toolstring onto the TOC, similar to the tagging operation. Then the driller applies weight onto the string and observes the outcome. If the weight on bit (WOB) readings increase as more weight is applied, and the position of the bit is constant, the plug is solid. The tag TOC and load test are often performed at the same time. Pressure tests are also often conducted—both positive and negative pressure tests.
If the annular space outside the exterior casing was adequately cemented, this method could be modified, to mill or cut a small section of tubing and then the two material resin-cement plug used. However, if not cemented, or if the cement bond quality is poor, rupture and expansion or rupture and expansion with optional perforation is preferred. Rupture and expansion is typically sufficient to crumble any poor cement, which will typically fall further downhole, leaving a clean annular. The crumbled cement will also block the annulus at the bottom of the plugging zone, as the crumble will fill with resin and begin hardening, preventing further leakage.
If there are multiple tubular strings, greater than two, the same process can be done, although expansion and rupture will require greater energy. Two casing strings can also be done this way using the same process.
The following documents are incorporated by reference in their entirety:
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US20150345248, US20150368542, US20160145962, Apparatus for use in well abandonment
US20150368542 Heat sources and alloys for us in down-hole applications
U.S. Pat. No. 6,474,414 Plug for tubulars
U.S. Pat. No. 6,664,522 Method and apparatus for sealing multiple casings for oil and gas wells
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U.S. Pat. No. 7,152,657 In-situ casting of well equipment
U.S. Pat. No. 7,290,609, Subterranean well secondary plugging tool for repair of a first plug
US20150053405 One trip perforating and washing tool for plugging and abandoning wells
COP 42399 at U.S. Ser. No. 62/402,796, filed Sep. 30, 2016.
COP 42423, U.S. Ser. No. 62/402,802, filed Sep. 30, 2016.
COP 42425, U.S. Ser. No. 62/62/402,810, filed Sep. 30, 2016.
U.S. Pat. No. 6,679,328—Reverse section milling method and apparatus
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This application claims priority to U.S. App. No. 62/402,821, filed Sep. 30, 2016, and incorporated by reference herein in its entirety for all purposes.
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