Method of Using a Perforator Device for the Transfer of Tracer Additives into a Formation

This disclosure generally relates to the use of an innovative type of nanoparticle additive known as a ‘tracer’ in a wellbore or other comparable subterranean formation. The tracer may be disposed into or otherwise associated with a perforator device, which together may then be transferred into the wellbore. Once a shaped charge of the perforator device is detonated, the explosion jet may disperse the tracer into contact with the formation at the perforation level.

The tracer may be flown out from the targeted structure with a resultant produced fluid, then tested in a manner that facilitates determination of flow performance from each individual perforation, or a model of one or more production parameters associated with the wellbore. The disclosure relates to using ultrahigh-resolution inert nano particle tracer technology in oil, gas and geothermal wells that need not necessarily be hydraulically fractured.

A hydrocarbon-based economy continues to be dominant force in the modern world. As such, locating and producing hydrocarbons, along with understanding the flow performance of subsurface formations, continues to demand attention from the oil and gas (O&G) industry. A well or wellbore is generally drilled in order to recover valuable hydrocarbons and other desirable materials trapped in geological formations in the Earth, which are later refined into commercial products, such as gasoline or natural gas. The wellbore may be cemented, cased, etc. as well understood in the art.

In some instances (such as an unconventional wellbore), the rock formation may require fracturing in order to stimulate the flow. Typically, this is achieved by a two-step process commonly referred to as ‘plug-and-perf’, where the ‘perf’ refers to a perforation step that requires firing a series of perforation charges (sometimes shaped charges) resulting in perforations through the casing and cement that extend into the formation.

The wellbore may be perforated in a series of sections, with a respective target section or stage isolated by a zone isolation tool. Once perforation is complete, the ‘plug’ step occurs whereby the isolated section may be subject to injection of high-pressure fluid sufficient enough to cause hydraulic fracturing in the rock.

An example of a known shaped charge design is shown in. The shaped chargehas a charge housing or casehaving an openingat the charge housing end, while generally closed off at a second charge housing end (e.g., in a cylindrical shape). There is then a linerto maintain and hold a charge explosive material(of the type normally to create a high-velocity jet and a shock wave) within the housing.

An initiator such as detonator (cord)may be coupled with the charge housing end. The chargeis oriented in a (radially) outward direction when in use. In operation, the detonatoris operable to detonate the explosive material, resulting in a high velocity jet of liner material. The jet breaches the wall of the perforator device (gun), the casing, then the cement, and finally the formation rock, resulting in a hole (or perforation tunnel) that creates a path for either fluid injection or for oil/gas extraction.

shows an example of a perforator devicehaving multiple charges, and in most instances multiple devicesare used, corresponding to desired perforation zones, all associated with gun string. The perforator deviceincludes a detonator and control circuitry. Once detonated the shaped chargewill eject a jet of material to form the aforementioned perforation tunnel into the formation.

Once perforating operations are complete, it is desirous to commence production. In conventional wells, this may occur with better frequency. Just the same, no matter the well type, common today to increase or enhance production in the tight or unconventional reservoirs is the use of hydraulic fracturing (i.e., “fracing”) in the surrounding formations.

Fracing entails the pumping of fracturing fluids with sand into a formation in an open-hole or via perforations in a cased wellbore or other openings in the casing to form a fracture(s) in the formation. Fracing routinely requires very high fluid pressure and pumping rate and can occur in a multi-stage fracing manner.

The modern design of shale well with multi-stage hydraulic fracturing operations involve pumping from 20 to 100 fracing stages and from 1 to 10 or more perforation clusters per stage with a cumulative volume of 5 to 20 million gallons of water and from 5 to 20 million pounds of sand per well. This represents a total cost ranging from 4.0 million to 9.5 million U.S. dollars per well. Fracing operations are expensive, increasingly environmentally challenging and emissions intensive, and can represent up to 70% of the total cost for each well.

With such extensive costs, there may be situations where a wellbore is not subjected to hydraulic fracturing, but yet it still might be desirous to have some amount of diagnostic information about the well. For example, producers may desire to know when production occurs from a target formation. For the sake of flow assurance, it might be desirous to have diagnostic information that may be decoupled from fracturing. It follows that it might be desirous to have diagnostic information about (a part of) the wellbore, but not necessarily a fractured area.

Production diagnostic tools may be used in order to predict well performance, improve well design, or aid in future well development. Typically, diagnostic or surveillance tools include PLT (production logging), fiber-optic, and liquid chemical tracers.

Use of fiber optic systems that include distributed acoustic sensing (DAS) and distributed temperature surveys (DTS) is known to provide high-end diagnostic results. However, fiber is known to be excessive in cost and deployment complexities, and the time to obtain useful data may be in the realm of weeks or longer. Depending on the complexity, the installation of fiber optic DAS and DTS systems can add as much as $1 million/well to the completed total costs.

PLT also has its favored uses and is a historically well accepted approach, but while perhaps slightly lower in cost, it is known to provide a short snapshot view and information compared to fiber and requires well shut-in and costly wireline intervention.

Conventional chemical liquid tracers have enjoyed success but are also known to have limitations. These tracers are dissolvable in oil and water phases, and typically have fluorescent properties, DNA and ionic, organic materials, or radioactive diagnostic isotopes. Such tracers are used to evaluate fracturing performance, ostensibly to control the effectiveness of multi-stage hydraulic fracturing stimulation. Owing to obvious environmental deficiencies, tracers incorporating radioactive isotopes have largely fallen out of favor. Given their soluble characteristics, conventional chemical tracers must be tailored for individual fluid types, thereby requiring more, and often exotic, formulations for a single stage, increasing the chemical tracer costs appreciably.

Each of the aforementioned techniques: fiber, PLT, and liquid chemical tracer tools also have temperature limitations (i.e., for use in <500° F.) that make their use problematic at best in unconventional or igneous geothermal reservoirs, where temperatures may be as high as 1,000° F. Moreover, these techniques are routinely coupled with the frac operation, and usually used for stages.

The industry needs a simplistic, low-cost diagnostic method that can be used for assessing reservoir quality, completion design, and other wellbore performance parameters, especially for target areas of the formation (such as the wellbore bottom or toc) that need not be related to a particular perforation cluster and ‘stage’. This is especially the case for the instance when the diagnostic can be decoupled from a fracturing operation, as such operations require additional steps, equipment, interventions, etc.

The need for an ultrahigh resolution nanoparticle tracer that is versatile, affordable, highly accurate, non-radioactive, non-intrusive and quick to test is increasing as never before for all applications. What is needed is a new and improved way of forming and using a fast, cost-favorable, effective, and reliable way of evaluating a wellbore.

Embodiments of the disclosure may pertain to a shaped charge having a tracer additive, the shaped charge may further include: a first charge housing end; a second housing end; and an inner cavity. There may be an explosive material disposed within the inner cavity. In aspects, the shaped charge may be configured to detonate upon activation of a signal and form or cause a resultant explosive material jet stream. The tracer additive may be associated or otherwise disposed in a manner with the shaped charge housing in a way whereby the explosive material jet stream comes into contact with at least some of the tracer additive.

The shaped charge may include a substrate body or insert. The substrate body/insert may be positioned as desired, such as in proximity to the first charge housing end. The tracer additive may be mixed with a substrate. The substrate body may be a ring or donut shape, such that it has a hollow therein. The substrate may include or be made of any suitable material, such as metal, plastic, and so forth. The substrate may be molded, printed, machined, combinations thereof, etc.

The tracer additive may have a first tracer composition, which may be unique as compared to any other tracer additives. When added to the shaped charge or to a component of the shaped charged, the tracer additive may be in a solid powder form. The tracer additive may have an average particle diameter of at least 0.01 μm to no more than 10 μm. The tracer additive may have an average bulk specific gravity of at least 0.6 g/cmto no more than 1.6 g/cm3.

If the shaped charge or another shaped charge includes another tracer additive (such as a second tracer additive), that additive may be unique and have its respective tracer composition. The second tracer may have a solid powder having an average particle diameter of at least 0.01 μm to no more than 10 μm. The second tracer additive may have an average bulk specific gravity of at least 0.6 g/cmto no more than 1.6 g/cm3.

Yet other embodiments of the disclosure pertain to a method of using a tracer additive such as in a wellbore. The method may include using a perforator device configured with an at least one shaped charge disposed thereon. There may be a tracer additive associated with (such as disposed in or on) the at least one shaped charge.

The method may include sending the perforator device into the wellbore in manner whereby the perforator device arrives at a target formation in communication with the wellbore. Then, detonating the at least one shaped charge so that the tracer additive via an explosive jet stream discharged from the shaped charge is carried into contact with the target formation. Upon contacting the target formation with the tracer additive for an amount of time, returning a remnant fluid that includes at least a portion of the tracer additive to a surface.

In aspects, the tracer additive may have a first tracer composition. The tracer additive may be in a solid powder form having an average particle diameter of at least 0.01 μm to no more than 10 μm. The tracer additive may have an average bulk specific gravity of at least 0.6 g/cmto no more than 1.6 g/cm3.

In aspects, the testing a sample may include using a fluorescence response-based analysis. For example, the fluorescence response-based analysis may include use of EDXRF.

These and other embodiments, features and advantages will be apparent in the following detailed description and drawings.

Regardless of whether presently claimed herein or in another application related to or from this application, herein disclosed are novel apparatuses, units, systems, and methods that pertain to use of solid inert tracer additives, details of which are described herein. Embodiments of the disclosure may refer to “in-wellbore tracer deployment”—where the tracer is already in the wellbore (associated with a shaped charge of perforator device) before deployment of the tracer into the wellbore occurs (akin to “in-charge tracer deployment” or “in-gun tracer deployment”).

Embodiments of the present disclosure are described in detail with reference to the accompanying Figures. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, such as to mean, for example, “including, but not limited to . . . ”. While the disclosure may be described with reference to relevant apparatuses, systems, and methods, it should be understood that the disclosure is not limited to the specific embodiments shown or described. Rather, one skilled in the art will appreciate that a variety of configurations may be implemented in accordance with embodiments herein.

Although not necessary, like elements in the various figures may be denoted by like reference numerals for consistency and ease of understanding. Numerous specific details are set forth in order to provide a more thorough understanding of the disclosure; however, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Directional terms, such as “above,” “below,” “upper,” “lower,” “front,” “back,” etc., are used for convenience and to refer to general direction and/or orientation, and are only intended for illustrative purposes only, and not to limit the disclosure.

Connection(s), couplings, or other forms of contact between parts, components, and so forth may include conventional items, such as lubricant, additional scaling materials, such as a gasket between flanges, PTFE between threads, and the like. The make and manufacture of any particular component, subcomponent, etc., may be as would be apparent to one of skill in the art, such as molding, forming, press extrusion, machining, or additive manufacturing. Embodiments of the disclosure provide for one or more components to be new, used, and/or retrofitted to existing machines and systems.

Various equipment may be in fluid communication directly or indirectly with other equipment. Fluid communication may occur via one or more transfer lines and respective connectors, couplings, valving, piping, and so forth. Fluid movers, such as pumps, may be utilized as would be apparent to one of skill in the art.

Numerical ranges in this disclosure may be approximate, and thus may include values outside of the range unless otherwise indicated. Numerical ranges include all values from and including the expressed lower and the upper values, in increments of smaller units. As an example, if a compositional, physical or other property, such as, for example, molecular weight, viscosity, melt index, etc., is from 100 to 1,000. it is intended that all individual values, such as 100, 101, 102, etc., and sub ranges, such as 100 to 144, 155 to 170, 197 to 200, etc., are expressly enumerated. It is intended that decimals or fractions thereof be included. For ranges containing values which are less than one or containing fractional numbers greater than one (e.g., 1.1, 1.5, etc.), smaller units may be considered to be 0.0001, 0.001, 0.01, 0.1, etc. as appropriate. These are only examples of what is specifically intended, and all possible combinations of numerical values between the lowest value and the highest value enumerated, are to be considered to be expressly stated in this disclosure. Numerical ranges are provided within this disclosure for, among other things, the relative amount of reactants, surfactants, catalysts, etc. by itself or in a mixture or mass, and various temperature and other process parameters.

The term “connected” as used herein may refer to a connection between a respective component (or subcomponent) and another component (or another subcomponent), which can be fixed, movable, direct, indirect, and analogous to engaged, coupled, disposed, etc., and can be by screw, nut/bolt, weld, and so forth. Any use of any form of the terms “connect”, “engage”, “couple”, “attach”, “mount”, etc. or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.

The term “fluid” as used herein may refer to a liquid, gas, slurry, single phase, multi-phase, pure, impure, etc. and is not limited to any particular type of fluid such as hydrocarbons.

The term “utility fluid” as used herein may refer to a fluid used in connection with any fluid disposed into a wellbore (akin to an injection fluid). The utility fluid may be pressurized, and may be used to carry an additive into the wellbore. ‘Utility fluid’ may also be referred to and interchangeable with ‘service fluid’ or comparable.

The term “fluid connection”, “fluid communication,” “fluidly communicable,” and the like, as used herein may refer to two or more components, systems, etc. being coupled whereby fluid from one may flow or otherwise be transferrable to the other. The coupling may be direct, indirect, selective, alternative, and so forth. For example, valves, flow meters, pumps, mixing tanks, holding tanks, tubulars, separation systems, and the like may be disposed between two or more components that are in fluid communication.

The term “pipe”, “conduit”, “line”, “tubular”, or the like as used herein may refer to any fluid transmission means, and may be tubular in nature.

The term “tubestring” or the like (such as ‘workstring’) as used herein may refer to a tubular (or other shape) that may be run into a wellbore. The tubestring may be casing, a liner, production tubing, combinations, and so forth. The tubestring may be multiple pipes (and the like) coupled together. The tubestring may be used for transfer of fluids, or used with some other kind of action, such as drilling, running a tool, or any other kind of downhole action, and combinations thereof. The tubestring may be or include a gun string, which may be one or more perforating gun devices coupled together.

The term “composition” or “composition of matter” as used herein may refer to one or more ingredients, components, constituents, etc. that make up a material (or material of construction). Composition may refer to a flow stream of one or more chemical components.

The term “chemical” as used herein may analogously mean or be interchangeable to material, chemical material, ingredient, component, chemical component, element, substance, compound, chemical compound, molecule(s), constituent, and so forth and vice versa. Any ‘chemical’ discussed in the present disclosure need not refer to a 100% pure chemical. For example, although ‘water’ may be thought of as H2O, one of skill would appreciate various ions, salts, minerals, impurities, and other substances (including at the ppb level) may be present in ‘water’. A chemical may include all isomeric forms and vice versa (for example, “hexane”, includes all isomers of hexane individually or collectively).

The term “explosive material” as used herein may refer a material with a composition of matter having properties and/or characteristics that, upon an igniting or detonation, results in an explosion that creates a jet of material. The direction of the jet of material may be controlled or otherwise predicted.

The term “liner” as used herein may refer to a solid object formed from pressed powder (under high pressure). Tracer additives may be mixed with a liner powder forming a liner mixture powder. This may be before the mixture is pressed (e.g., using a liner punch into a liner diebody to make a liner).

The term “water” as used herein may refer to a pure, substantially pure, and impure water-based stream, and may include wastewater, process water, fresh water, seawater, produced water, slop water, treated variations thereof, mixes thereof, etc., and may further include impurities, dissolved solids, ions, salts, minerals, and so forth. Water for a frac fluid can also be referred to as ‘frac water’.

The term “impurity” as used herein may refer to an undesired component, contaminant, etc. of a composition. For example, a mineral or an organic compound may be an impurity of a water stream.

The term “frac fluid” as used herein may refer to a fluid injected into a well as part of a frac operation. Frac fluid is often characterized as being largely water, but with other constituents such as proppant, friction reducers, and other additives or compounds.

The term “produced fluid”, “production fluid”, and the like as used herein may refer to water, gas, mixtures, and the like recovered from a subterranean formation or other area near the wellbore. Produced fluid may include hydrocarbons or aqueous, such as flowback water, brine, salt water, or formation water. Produced water may include water having dissolved and/or free organic materials. Produced fluid may be akin to ‘wellbore fluid’, in that the fluid may be returned from the wellbore. Produced fluid may include utility fluids and formation fluids.

The term “frac operation” as used herein may refer to fractionation of a downhole well that has already been drilled. ‘Frac operation’ can also be referred to and interchangeable with the terms fractionation, hydraulic fracturing, well stimulation, production enhancement, hydrofracturing, hydrofracking, fracking, fracing, and frac. A frac operation can be land or water based. Generally, the term ‘fracing’ or ‘frac’ is used herein, but meant to be inclusive to other related terms of industry art.

The phrase “processing a fluid” as used herein may refer to some kind of active step or action, such as man-made or by machine, imparted on the fluid (or fluids). For example, a fluid may be received into a device (such as a mixer) and upon processing, may leave as a ‘processed fluid’. ‘Processed’ is not meant be limited, as this may include reference to transferred, treated, tested, measured, mixed, sensed, separated, combinations, etc. in whatever manner may be desired or applicable for embodiments herein. It is noted that while various steps or operations of any embodiment herein may be described in a sequential manner, such steps or operations may be operated in batch or continuous fashion.