COMPOSITION OF HANDLE UNDER COMMAND

专利摘要:
Handle Composition Under Command This disclosure relates to a system and method for controlling cement in an underground area. In some implementations, a cementation method in an underground formation includes positioning a cement sludge including a plurality of activating devices in a well drilling. Activation devices are configured to release an activator that increases the grout rate of the cement slurry. A signal is transmitted to at least a portion of the cement slurry to activate the activating devices. The activation device releases the activator in response to at least one signal.
公开号:BR112012004126B1
申请号:R112012004126-6
申请日:2010-08-20
公开日:2019-08-06
发明作者:Sam Lewis；Priscilla Reyes；Craig Roddy；Lynn Davis；Mark Roberson；Anthony Badalamenti
申请人:Halliburton Energy Services, Inc.；
IPC主号:

专利说明:

“PICK UP COMPOSITION UNDER COMMAND”
TECHNICAL FIELD [001] This invention relates to cementing operations and, more particularly, to activating cement compositions in underground areas.
BACKGROUND OF THE INVENTION [002] Natural resources such as gas, oil and water residing in an underground formation or zone are usually recovered by drilling the well in the underground formation while a drilling fluid circulates in the well drilling. After completing the drilling fluid circulation, a column of tubes (for example, casing) descends into the drilling of the well. The drilling fluid is then normally circulated down the inside of the pipe and up through the annular crown, which is located between the outside of the pipe and the well's drilling walls. Some well boreholes, for example, those of some oil and gas wells, are coated with a coating. The coating stabilizes the sides of the well bore. Then, primary cementation is typically performed, whereby a cement slurry is fixed in the annular crown and allowed to harden into a hard mass (ie sheath) to thereby attach the tube column to the well drilling walls and seal the annular crown. In a cementing operation, cement is introduced down into the well bore and into an annular space between the casing and the surrounding earth. The cement firmens the coating when drilling the well and prevents fluids from flowing vertically into the annulus between the coating and the surrounding earth. Different cement formulations are designed for a variety of well drilling conditions, which can be above ambient temperature and pressure. In designing a cement formulation, numerous potential mixtures can be evaluated to determine their mechanical properties under various conditions. Secondary cementing operations
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Subsequent 2/59 can also be performed. An example of a secondary cementation operation is compression cementation, by means of which a cement slurry is used to plug and seal undesirable flow passages in the cement sheath and / or the coating. Non-cementitious seals are also used in preparing a well bore. For example, polymer, resin, or latex-based sealants may be desirable for placement behind the coating.
[003] To increase the life of the well and minimize costs, sealing sludges are chosen based on calculated stresses and characteristics of the formation to be worked. Suitable seals are selected based on the conditions expected to be met during the life of the seal. Once a seal is chosen, it is desirable to monitor and / or evaluate the seal's health so that timely maintenance can be performed and the service life maximized. The integrity of the seal may be adversely affected by conditions in the well. For example, cracks in the cement can allow water to enter, while acidic conditions can degrade the cement. The initial strength and useful life of the cement can be significantly affected by its moisture content from the moment it is placed. Moisture and temperature are the primary drivers for the hydration of many cements and are critical factors in most prevalent deteriorating processes, including damage due to freezing and thawing, aggregate alkali reaction, sulphate attack and delayed ettringitis formation (hexacalcium trisulfate) aluminate). Thus, it is desirable to measure one or more seal parameters (for example, moisture content, temperature, pH and ionic concentration) in order to monitor the integrity of the seal.
[004] Active embedded sensors can involve inconveniences that make them undesirable for use in drilling the well drilling environment. For example, low-power electronic humidity sensors (for example, nanowatt), may have inherent limitations when
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3/59 embedded in cement. The highly alkaline environment can damage your electronic components, and they are sensitive to electromagnetic noise. Additionally, power has to be provided by an internal battery to activate the sensor and transmit data, which increases the size of the sensor and decreases the life of the sensor.
SUMMARY OF THE INVENTION [005] In accordance with an aspect of the present invention, a handle composition is provided under command, comprising: a handle composition and an activation device, wherein the activation device is used to increase the rate of grip of the handle composition in response to an activation signal. Preferably, the activation device is in a well bore.
[006] In another aspect, there is provided a grip cement composition under command, comprising; a cement composition including hydraulic cement, base fluid and setting retardant; and an activation device that releases an activator that increases the rate of pickup of the cement composition in response to a wireless signal.
[007] The present disclosure is concerned with a system and method for controlling cement in an underground area. In some implementations, a method of cementing in an underground formation includes placing a cement sludge including a plurality of activation devices in a well bore. Activation devices are configured to release an activator that increases the rate of cement sludge uptake. A signal is transmitted to at least a portion of the cement slurry to activate the activation devices. The activation device releases the activator in response to at least the signal.
[008] Furthermore, a method is disclosed here comprising placing a seal composition comprising one or more MEMS sensors in a well bore and letting the seal composition take hold.
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4/59 [009] Also disclosed here is a method of working a well bore comprising placing a MEMS interrogator tool in the borehole, starting with the placement of a seal composition comprising one or more MEMS sensors in the borehole, and ending the placement of the sealant composition when drilling the well when the interrogator tool is in close proximity to one or more MEMS sensors.
[0010] Additionally disclosed here is a method comprising placing a plurality of MEMS sensors in a well drilling service fluid.
[0011] Additionally disclosed here is a well drilling composition comprising one or more MEMS sensors, wherein the well drilling composition is a drilling fluid, a spacer fluid, a seal, or combinations thereof.
[0012] The above summarized in a very general way the resources and technical advantages of the present disclosure so that the following detailed description can be better understood. Additional features and advantages of the apparatus and method will be described below, which form the subject of the claims in this disclosure. Those skilled in the art should realize that the specific design and implementations revealed can be easily used as a basis for modifying or designing other structures to accomplish the same purposes as the present disclosure. Those skilled in the art must also realize that such equivalent constructions are not outside the scope of the apparatus and method presented in the attached claims.
[0013] Details of one or more implementations of the invention are presented in the accompanying drawings and in the following description. Other features, objectives and advantages of the invention will be apparent from the description and drawings, and from the claims.
DESCRIPTION OF THE DRAWINGS
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5/59 [0014] Figure 1 is an exemplary well system for producing fluids from a production area;
Figures 2A and 2B are exemplary cementation processes in the well system of figure 1;
Figure 3 illustrates an exemplary activation device for activating cement sludge when drilling the well;
Figures 4A-C illustrate exemplary processes for releasing activators in cement sludge;
Figure 5 is a flow chart illustrating an exemplary method for activating deposited cement sludge;
Figure 6 is a flow chart illustrating an exemplary method for making activation devices;
Figure 7 is an exemplary well system for transmitting activation signals for the cement sludge;
Figures 8A and 8B illustrate an exemplary power module for activation devices in a cement sludge;
Figure 9 is a flow chart illustrating an implementation of a method according to the present disclosure;
Figure 10 is a flow chart detailing a method for determining when a reverse cementation operation is completed and for subsequent optional activation of a subsurface tool; and
Figure 11 is a flow chart of a method for selecting from a group of seal compositions according to an implementation of the present disclosure.
[0015] Same reference symbols in the various drawings indicate the same elements.
DETAILED DESCRIPTION OF THE INVENTION [0016] Figure 1 is a cross-sectional view of an exemplary well system 100 for controlling cement in an underground area. Per
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6/59 example, system 100 may include a cement sludge with devices that perform one or more operations associated with the control of the cement sludge handle. Operations may include determining one or more parameters of cement and / or cement sludge (for example, moisture content, temperature, pH, ionic concentration), releasing an activator that initiates or accelerates the setting process and / or others. With respect to implementations including sensors, system 100 can periodically interrogate sensors in the cement to detect operational conditions over a period of time. For example, system 100 can detect cement properties to assess a state, for example, of a well drilling in operation. With regard to the activation of the cement sludge, the system 100 may have a cement delivery system under control that selectively controls the grip of a cement sludge. In these examples, system 100 may include a cement slurry with devices that release an activator in the cement sludge in response to at least one activation signal. An activator typically includes any chemical that activates and / or accelerates the setting process for a cement sludge in system 100. An activator can also delay or otherwise affect the setting or properties of the cement sludge. For example, system 100 may include one or more of the following activators: sodium hydroxide, sodium carbonate, calcium chloride, calcium nitride, calcium nitrate and / or others. Furthermore, system 100 may include devices with sensors and activators in such a way that the devices release the activators in response to at least detection of predefined criteria in the cement sludge, such as when the pH reaches a specified level. In some implementations, activation devices may include elements that substantially terminate one or more activators and that release the activator in response to at least one event. For example, the activation devices can receive a signal (for example, infrared signal) and, in response to the signal, the closure element can release one or more
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7/59 activators. To activate the closure element, system 100 can mechanically move the closure element, chemically remove at least a portion of the closure element, resistively heat the closure element to form an opening, and / or other processes to release one or more activators. For example, system 100 may include Micro-Electro-Mechanical System (MEMS) devices in the cement sludge that mechanically release activators. In general, system 100 includes a cement sludge in an annular crown formed between a liner and a well bore and, when the cement picks up, the cement secures the liner in place. By monitoring and / or selectively controlling the take-up of a cement slurry, system 100 can allow the cement properties to be adjusted once the cement sludge has been pumped down into the borehole. Furthermore, system 100 can monitor cement during normal operating conditions.
[0017] In some implementations, well system 100 includes a production zone 102, a non-production zone 104, a well bore 106, cement sludge 108 and devices 110. Production zone 102 can be a formation groundwater including resources (for example, oil, gas, water). Non-production zone 104 can be one or more formations that are isolated from drilling well 106 using cement sludge 108. For example, zone 104 may include contaminants that, if mixed with the resources, may result in the need for processing additional resources and / or make production economically unviable. Cement sludge 108 can be pumped or selectively positioned in the drilling of well 106. In some implementations, the properties of cement sludge 108 can be monitored using devices 110. Alternatively, or in combination, the grip of cement sludge 108 can be activated or accelerated using devices 110. For example, devices 110 can release an activator in response to an initiated signal,
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8/59 for example, by a user of system 100 and / or devices 110 that detect specified operating conditions. By monitoring and / or controlling the handle, a user can configure the system 100 without substantial interference from the cement slurry handle 108.
[0018] Back to a more detailed description of the elements of system 100, the drilling of well 106 extends from a surface 112 to the production area 102. The drilling of well 106 may include a platform 114 that is arranged close to the surface 112. Platform 114 can be coupled to a column of tubing 116 that extends a substantial portion of the length of the drilling of well 106 around surface 112 towards production zones 102 (e.g., hydrocarbon-containing reservoir). In some implementations, the column of pipe 116 may extend beyond production zone 102. The column of pipe 116 may extend as close to a termination 118 as the drilling of well 106. In some implementations, well 106 may be completed with the pipe column 116 extending to a predetermined depth close to the production zone 102. Briefly, the drilling of well 106 initially extends in a substantially vertical direction to the production zone 102. In some implementations, the drilling of well 106 may include other portions that are horizontal, inclined or otherwise offset from the vertical.
[0019] Platform 114 can be centered on an underground oil or gas formation 102 located below the surface of the earth 112. Platform 114 includes a working deck 124 that supports a crane 126. Crane 126 supports a lifting device 128 for raising and lowering pipe columns such as pipe column 116. Pump 130 is capable of pumping a variety of drilling compositions from the well (eg drilling fluid, cement) into the well and includes a measuring device pressure that provides a pressure reading on the
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9/59 pump discharge. The drilling of well 106 was drilled in several strata of the earth, including formation 102. At the end of the well drilling, the column of pipe 116 is usually placed in the drilling of well 106 to facilitate the production of oil and gas from the formation 102. The pipe column 116 is a pipe column that extends down through the drilling of well 106, through which oil and gas can be extracted. A cement shoe or liner 132 is typically attached to the end of the liner when the liner is lowered into the well bore. The casing shoe 132 guides the column of tubing 116 towards the center of the hole and can minimize or otherwise lessen problems associated with collision in rock protrusions or washes when drilling well 106 as the casing column is lowered in the well. The lining shoe 132 can be a guide shoe or a floating shoe, and typically comprises a tapered piece of equipment, usually of the projectile-shaped tip type found at the bottom of the lining column 116. The lining shoe 132 can be a floating shoe equipped with an open bottom and a valve that serves to prevent backflow, or U-pipe, of cement mud 108 from annular crown 122 to the column of pipe 116 as the column of pipe 116 runs through the drilling of well 106. The region between the tubing column 116 and the drilling wall of well 106 is known as the casing ring crown 122. To fill the casing ring crown 122 and fix the tubing column 116 in place, the tubing column 116 is normally cemented in the drilling of well 106, which is referred to as primary cementation. In some implementations, cement sludge 108 can be injected into the drilling of well 106 through one or more perforations 134. Cement sludge 108 can flow through a hose 136 into the column of pipe 116. In some cases,
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10/59 column of tubing 116 may rest or otherwise rest on a ferrule 138 of surface liner 120.
[0020] In some implementations, the system 100 can activate the cement sludge catch 108 using the activating devices 110 during, for example, conventional primary cementation operation. In conventional primary cementing implementations, devices 110 can be mixed into cement sludge 108 before entering the column of pipe 116, and cement sludge 108 can then be pumped down into the column of pipe 116. For example, devices 110 can be mixed in cement slurry 108 at a density in the range of 479 to 2876 kg / m ³ (4-24 pounds per gallon (ppg)). As the sludge 108 reaches the bottom of the column of pipe 116, it drains out of the column of pipe 116 and into the annular lining crown 122 between the column of pipe 116 and the drilling wall of well 106. The measurement as the cement sludge seeps up into the annular crown 122, it displaces all the fluid in drilling the well. To ensure that no cement remains inside the pipe column 116, devices called cleaners can be pumped by a service fluid from the well drilling (for example, drilling mud) through the pipe column 116 behind the cement mud 108. The cleaner makes contact with the inner surface of the pipe column 116 and pushes any remaining mud 108 out of the pipe column 116. When cement mud reaches the surface of the earth 112, and the annular crown 122 is filled with mud 108, the pumping ends. Regarding the pumping of the cement sludge 108 into the annular crown, a signal can be transmitted to the devices 110 before, during, and / or after the pumping is completed. The signal can request detected operating conditions, initiate the release of activators and / or other operations. For example, devices 110 can release activators that initiate and / or accelerate the setting of cement sludge 108 into annular crown 122 in response to
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11/59 at least the signal. Part or all of the column of pipe 116 can be fixed to the material of the adjacent soil with a cement jacket, illustrated in figures 2A and 2B. In some implementations, the pipe column 116 comprises a metal.
[0021] After the handle, the pipe column 116 can be configured to carry a fluid, such as air, water, natural gas, or to load an electric cable, pipe column or other elements.
[0022] After positioning the column of the pipe 116, a cement sludge 108 including devices 110 can be pumped into the annular crown 122 by a pump platform wagon (not shown). Exemplary cement sludges 110 are discussed in more detail below. With respect to the deposition or otherwise positioning of the cement sludge 108 in the annular crown 122, the devices 110 may release activators to activate or otherwise increase the rate of cement sludge 108 in response to at least one signal. In other words, devices 110 can activate cement sludge 108 to promote the setting of cement in the annular crown 122. Alternatively, or in combination, devices 110 can detect one or more attributes of cement sludge 108 such as moisture content , temperature, pH, ionic concentration and / or other parameters. In some implementations, substantially all of the cement has grip on the annular crown 122, and only a limited portion, if any, of the cement enters the column of tubing 116. In some implementations, all of the cement hardens on the annular crown 122, and no portion of the cement. cement sludge 108 enters the pipe column 116.
[0023] With respect to devices 110 including activators, activation devices 110 can release an activator that initiates or accelerates the handling of cement sludge 108. For example, cement sludge 108 can remain in a substantially sludge state. a specified period of time, and the activation devices 110 can activate the sludge
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12/59 cement in response to at least one signal. Activation devices 110 can receive a signal and, in response to the signal, release activators. In some cases, activation devices 110 terminate activations, for example, with a membrane. In some implementations, the membrane can be metal, a polymer and / or another element. Suitable polymers to create such a membrane include polystyrene, ethylene / vinyl acetate copolymer, polymethylmethacrylate polyurethanes, polylactic acid, polyglycolic acid, polyvinyl alcohol, polyvinylacetate, ethylene / hydrolyzed vinyl acetate, silicones, and combinations of each or each copolymer. In response to the signal, the activation device 110 may form an opening in the membrane. The activation device 110 can form an opening by mechanically moving a portion of the membrane and / or releasing a chemical component that removes a portion of the membrane. In some implementations, the activation signal can directly activate the membrane. For example, the activation signal can be an ultrasonic signal that vibrates the membrane to form an opening. Activation device 110 may include a polymer membrane that degrades ultrasonically to release enclosed activators. In some instances, an ultrasonic signal can structurally change the membrane to release the activators such as, for example, opening the membrane like a flap. In some implementations, the signal includes at least one of an electromagnetic signal, a pressure signal, a magnetic signal, an electrical signal, an acoustic signal, an ultrasonic signal, or a radiation signal, and in which the radiation signal comprises at least one of neutrons, alpha particles, or beta particles. In some implementations, the cement composition can be caught in a range of one hour to a day after reacting with the activator. The activation device can include at least one dimension in a range from about 1 pm to about 10,000 pm.
[0024] The release activator may include sodium hydroxide, sodium carbonate, amine compounds, salts comprising calcium, sodium,
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13/59 magnesium, aluminum and / or a mixture of these. Activation device 110 can release a calcium salt such as calcium chloride. In some implementations, the activation device 110 can release a sodium salt such as sodium chloride, sodium aluminate and / or sodium silicate. Activation device 110 can release a magnesium salt such as magnesium chloride. In some examples, activation device 110 can release amine compounds such as triethanol amine, tripropanol amine, triisopropanol amine and / or diethanol amine. In some implementations, the activation device 110 can release the activator in an amount sufficient to promote the setting of the cement sludge 108 in about 1 minute to about 2 hours. Alternatively, the activator may be present in an amount sufficient to promote catching of the mud in about an hour to about a day. In implementations including sodium chloride as the released activator, the concentration can be in the range of about 3% to about 15% by weight of cement in cement slurry 108. In implementations including calcium chloride as the released activator, the concentration it can be in the range of about 0.5% to about 5% by weight of the cement in the cement sludge 108.
[0025] In some implementations, the activation device 110 can promote the lightning grip of the cement mud 108. In the form referred to here, the expression lightning grip should mean the initiation of the grip of the cement mud 108 in about 1 minute at about 5 minutes after contact with the released activator. In some implementations, the previously identified activators can promote the lightning of cement sludge 108. Lightning activators can include sodium hydroxide, sodium carbonate, potassium carbonate, sodium or potassium bicarbonate salts, sodium silicate salts , sodium aluminate salts, ferrous and ferric salts (for example, ferric chloride and ferric sulphate), salts of polyacrylic acid and / or others. In some implementations, the following activators
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14/59 can promote the catching of cement sludge 108 based on these activators that exceed a specified concentration: calcium nitrate, calcium acetate, calcium chloride and / or calcium nitride. In some implementations, activation device 110 may release a solid activator.
[0026] In some implementations, devices 110 comprise MEMS devices containing an array of micro-reservoirs coated with an ultrasound sensitive polymer membrane (e.g., polyanidides, polyglycolides, polylactides, ethylene vinyl acetate copolymers, silicones). The micro-reservoirs can be loaded with one or multiple cement additives (eg accelerator, retardant). Upon exposure to acoustic waves (for example, ultrasonic waves), the polymer membrane can start to degrade / break and cause the release of the desired additives. Release rate of the additives can be controlled by the intensity of the ultrasound and its duration. A MEMS device can not only be manufactured to have micro-reservoirs, but it can also include micro pumps. The desired additive can be dispersed in the pumps. Upon exposure, the MEMS 110 device can have a sensor / transducer / acoustic / ultrasonic detector that, with ultrasound, the additive can be pumped via cavitation. In addition, the MEMS trigger can cause a cascade of events (for example, increase in temperature and / or pressure) resulting in the release of additives.
[0027] With respect to devices 110 including one or more sensors, the sensors can be positioned within the well drilling 106. For example, the sensors 110 can extend over all or part of the well drilling length 106 adjacent to the pipe column 116. Sealing sludge 108 can be placed on the subsurface as part of a primary cementation, secondary cementation, or other sealing operation described in more detail here. In some implementations,
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15/59 a data interrogator tool can be positioned in an operable location to collect data from sensors 110, for example, lowered into the drilling of well 106 next to sensors 110. The data interrogator tool can interrogate data sensors 110 (for example, example, sending an RF signal) while the data interrogator tool crosses all or part of the well drilling 106 containing sensors 110. Data sensors 110 can be activated to record and / or transmit data signal from the data interrogator tool. The data interrogator tool can communicate the data to one or more computer components (for example, memory and / or microprocessor) that can be located on the tool, on surface 112, or both. The data can be used locally or remotely with respect to the tool to calculate the location of each data sensor and correlate the measured parameters with those locations to assess the performance of the seal.
[0028] In some implementations, sensors 110 include MEMS sensors that, for example, detect conditions during drilling (for example, drilling fluid comprising MEMS sensors) or during cementation (for example, cement slurry 108 comprising MEMS sensors), as described in more detail below. Additionally, or alternatively, data collection can be performed at one or more times subsequent to the initial placement in composition 108 comprising MEMS 110 sensors. For example, data collection may be performed at the time of initial placement in the composition 108 well comprising MEMS 110 sensors or immediately thereafter to provide a base nail data set. As the well is operated to recover natural resources over a period of time, data collection can be performed at additional times, for example, at regular maintenance intervals such as every 1 year, 5 years, or 10 years. The data retrieved during subsequent monitoring intervals can be
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16/59 compared with baseline data, as well as with any other data obtained from previous monitoring intervals, and such comparisons may indicate the general condition of drilling well 106. For example, changes in one or more detected parameters may indicate one or more problems in drilling the well. Alternatively, consistency or uniformity in the detected parameters may indicate that there is no substantial problem in drilling well 106. In some implementations, data (for example, seal parameters) from a plurality of monitoring intervals are plotted over a period of time, and a resulting graph can be provided showing an operational or trend line for the detected parameters. Atypical changes in the graph indicated, for example, by a sharp change in the slope or a staggered change in the graph, can provide an indication of one or more present problems or the potential for a future problem. In this way, corrective and / or preventive treatments or services can be applied when drilling well 106 to address current or potential problems.
[0029] In some implementations, the MEMS 110 sensors can be contained in a seal composition 108 placed substantially in the annular space 122 between a pipe column and the well drilling wall. That is, substantially all MEMS 110 sensors can be located in the annular space 122, or in close proximity to it. In some implementations, the well drilling service fluid comprising the MEMS 110 sensors (and thus similarly the MEMS 110 sensors) may not penetrate, migrate, or substantially shift into the formation from the well 106 drilling. alternatively, substantially all MEMS 110 sensors are located inside, adjacent to, or in immediate proximity to the drilling of well 106, for example, at a distance less than or equal to about 1 foot (0.3048
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m), 3 feet (0.9144 m), 5 feet (1.524 m), or 10 feet (3.048 m) from drilling well 106. Such a positioning adjacent to or in immediate proximity to MEMS 110 sensors with respect to drilling well 106 may be unlike the placement of MEMS 110 sensors in a fluid that is pumped into formation 102 in large volumes and substantially penetrates, migrates or displaces into or through formation 102, for example, as with a fracturing fluid or a flood fluid. Thus, in modalities, MEMS 110 sensors can be placed close to or adjacent to the drilling of well 106 (as opposed to the general formation), and provide relevant information for the well drilling itself and compositions (for example, seals 108) used in it ( again, unlike training or a general production zone).
[0030] In some implementations, the data sensors 110 added to the sealing mud 108 may be passive sensors that do not require continuous power from a battery or an external source in order to transmit data in real time. In some implementations, data sensors 110 are microelectromechanical systems (MEMS) comprising one or more MEMS devices (and typically a plurality of them), referred to here as MEMS 110 sensors. MEMS 110 devices are well known, for example, a semiconductor device with mechanical resources of micrometric scale. MEMS incorporate the integration of mechanical elements, sensors, actuators and electronic components in a common substrate. In implementations, the substrate comprises silicon. MEMS elements include mechanical elements that are movable by an input energy (electrical or other energy). Using MEMS, a sensor 110 can be designed to emit a detectable signal based on numerous physical phenomena, including thermal, biological, optical, chemical and magnetic effects or stimuli. MEMS 110 devices are small in size, have low
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18/59 energy requirements, are relatively inexpensive and robust, and thus are well suited for use in well drilling work operations. [0031] In some implementations, data sensors 110 comprise an active material connected (for example, internally mounted or surface mounted) in a closure, the active material being prone to respond to a well drilling parameter, and the material active being operationally connected (for example, in physical contact, wrapping or coating) with a capacitive MEMS element. In several implementations, MEMS 110 sensors detect one or more parameters when drilling well 106. In some implementations, the parameter may include temperature, pH, moisture content, ionic concentration (eg chlorine, sodium and / or potassium ions ) and / or others. MEMS 110 sensors can also detect characteristic data of well cement such as stress, strain or combinations thereof. In some implementations, the MEMS 110 sensors of the present disclosure may comprise active materials that respond to two or more measurements. In this way, two or more parameters can be monitored.
[0032] Suitable active materials, such as dielectric materials, that respond in a predictable and stable manner to changes in parameters over a long period can be identified according to methods well known in the art, for example, see, for example, Ong, Zeng and Grimes. The Wireless, Passive Carbon Nanotube-based Gas Sensor IEEE Sensors Joumal, 2, 2, (2002) 82-88; Ong, Grimes, Robbins and Singl, Design and application of a wireless, passive, resonant-circuit environmental monitoring sensor Sensors and Actuators A, 93 (2001) 33-43, each of which is incorporated by reference in its entirety. MEMS 110 sensors suitable for the methods of the present disclosure that respond to various parameters of well drilling are disclosed in US patent 7,038,470 BI which is incorporated herein by the reference in its entirety.
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19/59 [0033] In some implementations, MEMS 110 sensors can be coupled with radio frequency identification devices (RFIDs) and can detect and transmit parameters and / or data on well cement characteristics to monitor the cement during its life useful. RFIDs combine a microchip with an antenna (the RFID chip and the antenna are collectively referred to as the transponder or tag). The antenna provides the RFID chip with power when exposed to a narrowband, high frequency electromagnetic field from a transceiver. A bipolar antenna or a coil, depending on the operating frequency, connected to the RFID chip, activates the transponder when current is induced in the antenna by an RF signal from the transceiver antenna. A device like this can retrieve a unique ID identification number by modulating and re-radiating the radio frequency (RF) wave. Passive RF RF tags are gaining widespread use because of their low cost, long life, simplicity, efficiency, ability to identify parts at a contactless distance (ability to transmit information without a physical connection). These robust and miniature labels are attractive from an environmental point of view as they do not require a battery. The MEMS sensor and RFID tag are preferably integrated into a single component 110 (e.g., chip or substrate), or may alternatively be separate components 110 operationally coupled together. In some implementations, an integrated and passive MEMS / RFID sensor 110 may contain a data detection component, an optional memory and an RFID antenna, whereby the excitation energy is received and drives the sensor, thus detecting a present condition and / or accessing one or more detected conditions stored in memory and transmitting the same via the RFID antenna.
[0034] In the United States, operational bands normally used for RFID systems center on one of the three frequencies assigned by the government: 125 kHz, 13.56 MHz or 2.45 GHz. A fourth frequency, 27.125
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20/59
MHz, has also been assigned. When the 2.45 GHz carrier frequency is used, the range of an RFID chip can be many meters. Although this is usable for remote sensing, there may be multiple transponders in the RF field. In order to prevent these devices from interacting and tampering with data, anti-collision schemes are used, as they are known in the art. In implementations, data sensors are integrated with local tracking hardware to transmit their position as they flow into a sealing mud. Data sensors 110 can form a network using wireless connections on neighboring data sensors and are capable of location and positioning, for example, by means of local positioning algorithms as are known in the art. Sensors 110 can organize themselves in a network, listening to each other, therefore allowing communication of signals from sensors more distant towards the sensors closest to the interrogator to allow transmission and uninterrupted data capture. In these implementations, the interrogator tool may not need to cross the entire drilling section of the well containing MEMS sensors in order to read data collected by such sensors. For example, the interrogator tool may only need to be lowered about half along the vertical length of the well drilling containing MEMS sensors. Alternatively, or in combination, the interrogator tool can be lowered vertically when drilling the well to a location adjacent to a horizontal arm of a well 106, whereby the MEMS 110 sensors can be located on the horizontal arm and can be set without the need for the interrogator tool to cross the horizontal arm. Alternatively, or in combination, the interrogator tool can be used on or near the surface and read the data collected by the sensors distributed throughout all or part of the well drilling. For example, sensors 110 can be located distal from the interrogator and can communicate via a network formed by the sensors, as previously described.
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21/59 [0035] In some implementations, MEMS 110 sensors are ultra-small, for example, 1 mm2, so that they can be pumped into a sealing mud. In some implementations, the MEMS 110 device can be approximately 1 pm2 to 1 mm2, 1 mm2 to 3 mm2, 3 mm2 to 5 mm2, 5 mm2 to 100 mm2 and / or other dimensions. In some implementations, data sensors 110 may be able to provide data throughout the life of the cement. In implementations, data sensors 110 can provide data for up to 100 years. In some implementations, the drilling composition of well 108 may comprise an amount of MEMS effective to measure one or more desired parameters. In various implementations, the composition of the drilling of well 108 can comprise an effective amount of MEMS in such a way that detected readings can be obtained at intervals of about 1 foot (0.3048 m), 6 inches (152.4 mm), 1 inch (25.4 mm) and / or other gap along the drilling portion of well 106 containing MEMS 110. MEMS may be present in the drilling composition of well 108 in an amount of about 0.01 to about 50 percent by weight.
[0036] In some implementations, MEMS 110 sensors can comprise passive sensors (remain de-energized when not being interrogated) energized by the energy radiated by a data interrogator tool. The data interrogator tool may comprise an energy transceiver that sends energy (for example, radio waves) and receives signals from the MEMS 110 sensors and a processor that processes the received signals. The data interrogator tool may additionally comprise a memory component, a communications component, or both. The memory component can store raw and / or processed data received from MEMS 110 sensors, and the communications component can transmit raw data to the processor and / or transmit
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22/59 processed data to another receiver, for example, located on the surface. The components of the tool (for example, transceiver, processor, memory component and communications component) are coupled together and in signal communication with each other.
[0037] In some implementations, one or more of the components of the data interrogator (not shown) can be integrated into a tool or unit that is temporarily or permanently placed on the subsurface (for example, a subsurface module). In some implementations, a removable subsurface module comprises a transceiver and a memory component, and the subsurface module is placed in the well bore, reads data from the MEMS sensors, stores the data in the memory component, is removed from the well bore , and raw data is accessed. Alternatively, or in combination, the removable subsurface module may have a processor to process and store data in the memory component, which is subsequently accessed on the surface when the tool is removed from the well bore. Alternatively, or in combination, the removable subsurface module may have a communications component for transmitting raw data to a processor and / or transmitting processed data to another receiver, for example, located on the surface. The communications component can communicate via wired or wireless communications. For example, the subsurface component can communicate with a component or other node on the surface via a cable or other communications / telemetry device such as a radio frequency, electromagnetic telemetry device or an acoustic telemetry device. The removable subsurface component can be intermittently positioned on the subsurface via any suitable transfer, for example, communication cable, coiled tubing, direct tubing,
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23/59 gravity, pumping, etc., to monitor conditions at various times during the life of the well.
[0038] In some implementations, the data interrogator tool comprises a permanent or semi-permanent subsurface component that remains on the subsurface for extended periods of time. For example, a semi-permanent subsurface module can be retrieved and data downloaded once every few years. Alternatively, or in combination, a permanent subsurface module can remain in the well for the life of the well. In an implementation, a permanent or semi-permanent subsurface module comprises a transceiver and a memory component, and the subsurface module is placed inside the well bore, reads data from the MEMS sensors, optionally stores the data in the memory component, and transmits the data read and optionally stored to the surface. Alternatively, or in combination, the permanent or semi-permanent subsurface module may have a processor that processes and transmits raw data, which can be stored in memory and / or transmitted to the surface. The permanent or semi-permanent subsurface module may have a communications component for transmitting raw data to a processor and / or transmitting processed data to another receiver, for example, located on the surface. The communications component can communicate via wired or wireless communications. For example, the subsurface component can communicate with a component or other node on the surface via a cable or other communication / telemetry device such as a radio frequency, electromagnetic telemetry device or an acoustic telemetry device.
[0039] In some implementations, the data interrogator tool comprises an RF energy source incorporated in its internal circuit system and the data sensors are passively energized using
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24/59 an RF antenna, which captures energy from the RF energy source. The data interrogator tool can be integrated with an RF transceiver. In implementations, MEMS sensors (eg MEMS / RFID sensors) are energized and interrogated by the RF transceiver from a distance, for example, a distance greater than 10 m or, alternatively, from the surface or from an adjacent displaced well. In some implementations, the data interrogator tool passes through a casing in the well and reads MEMS sensors located in a sealing sheath (for example, cement) surrounding the casing and located in the annular space between the casing and the well's drilling wall. In some implementations, the interrogator detects MEMS sensors when in close proximity to the sensors, typically via a removable subsurface component across a length of the well bore comprising the MEMS sensors. In some implementations, immediate proximity comprises a radial distance from a point within the casing to a planar point in an annular space between the casing and the drilling of the well. In some implementations, immediate proximity comprises a distance of 0.1 m to 1 m, 1 m to 5 m, 5 m to 10 m, or other ranges. In implementations, the transceiver interrogates the sensor with RF energy at 125 kHz and immediate proximity comprises 0.1 m to 0.25 m. Alternatively, or in combination, the transceiver interrogates the sensor with RF energy at 13.5 MHz and immediate proximity comprises 0.25 m to 0.5 m. Alternatively, or in combination, the transceiver interrogates the sensor with RF energy at 915 MHz and immediate proximity comprises 0.5 m to 1 m. Alternatively, or in combination, the transceiver interrogates the sensor with RF energy at 2.4 GHz and immediate proximity comprises 1 m to 2 m.
[0040] Although mud 108 is referred to as cement mud, mud 108 can include cementitious and / or non-cementitious sealants without departing from the scope of this disclosure. In some implementations, seals do not
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25/59 cementitious systems comprise resin-based systems, latex-based systems, or combinations thereof. In implementations, the seal comprises a cement sludge with styrene-butadiene latex (for example, as disclosed in U.S. Patent 5,588,488 incorporated herein by the reference in its entirety). Seals can be used on the expandable coating handle, which is further described below. In some implementations, the seal may be a cement used for cementing operations for drilling the primary or secondary well, as further discussed below.
[0041] In some implementations, seal 108 can be cementitious and comprises a hydraulic cement that picks up and hardens by reaction with water. Examples of hydraulic cement include, but are not limited to, Portland cements (for example, Portland cements class A, B, C, G and H), pozzolan cements, plaster cements, phosphate cements, high alumina cements, silica, high alkalinity cements, shale cements, acid / basic cements, magnesia cements, fly ash cement, zeolite cement systems, cement kiln cement systems, slag cements, microfine cement , metacaolin and combinations of these. Examples of seals are disclosed in U.S. patents 6,457,524, 7,077,203 and 7,174,962, each of which is incorporated herein by reference in its entirety. In some implementations, seal 108 may comprise a sorel cement composition, which typically comprises magnesium oxide and a chloride or phosphate salt which together form, for example, magnesium oxychloride. Examples of magnesium oxychloride sealants are disclosed in U.S. patents 6,664,215 and 7,044,222, each of which is incorporated herein by reference in its entirety.
[0042] The drilling composition of well 108 (for example, sealant) may include a sufficient amount of water to form a sludge
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26/59 pumpable. The water can be fresh water or salt water (for example, an unsaturated aqueous salt solution or a saturated aqueous salt solution such as brine or sea water). In some implementations, cement sludge 108 may be a lightweight cement sludge containing foam (e.g., expanded cement) and / or hollow beads / microspheres. In some implementations, MEMS 110 sensors can be incorporated or attached to all or part of the hollow microspheres. Thus, the MEMS 110 sensors can be dispersed in the cement together with the microspheres. Examples of seals containing microspheres are disclosed in U.S. Patents 4,234,344, 6,457,524 and 7,174,962, each of which is incorporated herein by reference in its entirety. In some implementations, MEMS 110 sensors are incorporated into an expanded cement such as those described in more detail in US patents 6,063,738, 6,367,550, 6,547,871 and 7,174,962, each of which is incorporated herein by reference in its full.
[0043] In some implementations, additives can be included in the cement composition to improve or change its properties. Examples of such additives include, but are not limited to, accelerators, setting retardants, defoamers, fluid loss agents, weight materials, dispersants, density reducing agents, formation conditioning agents, lost circulation materials, thixotropic agents, auxiliaries suspension or combinations thereof. Other mechanical properties modifying additives, for example, fibers, polymers, resins, latexes and the like, can be added to further modify the mechanical properties. These additives can be included individually or in combination. Methods for introducing these additives and their effective amounts are known to those skilled in the art.
[0044] With regard to activator implementations, cement sludge 108 may comprise a drying cement composition
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27/59 delayed that remains in a muddy state (for example, resistant to gelling) for an extended period of time. In such implementations, a delayed setting cement sludge 108 may include a cement, a base fluid and a setting retardant. In these and other implementations, activation can change the state of the cement sludge from delayed to neutral, accelerated, or less delayed. Cement sludge 108 may include other additives. The delayed-set cement sludge 108 typically remains in a sludge state for a range of about 6 hours to about 7 days in subsurface conditions or other conditions. That is, cement sludge 108 may include components that result in a sludge state for a greater or lesser amount of time. For example, cement sludge 108 can be mixed or otherwise made well in front of the positioning of sludge 108 in annular crown 122. Delayed grip cement sludge 108 may, in some implementations, include a cement, a base fluid and a setting retardant. The delayed-grip cement sludge 108 can be subjected to a handle at a desired time, such as after laying, by activating the activation devices 110 to release one or more activators.
[0045] With regard to cements included in cement sludge
108, any cement suitable for use in underground applications may be suitable for use in the present invention. For example, delayed-set cement sludge 108 may include hydraulic cement. In general, hydraulic cements typically include calcium, aluminum, silicon, oxygen and / or sulfur and can catch or harden by reacting with water. Hydraulic cements include, but are not limited to, Portland cements, pozzolanic cements, high aluminate cements, plaster cements, silica cements and high alkalinity cements. Furthermore, delayed-set cement sludge 108 may include shale-based cements or loudspeak slag. In such cases, shale may include glazed shale, raw shale (for example,
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28/59 (example, unburned shale) and / or a mixture of raw and glazed shale.
[0046] With respect to base fluids included in the cement slurry 108, the delayed-setting cement sludge 108 may include one or more base fluids such as, for example, an aqueous base fluid, a base base fluid non-aqueous, or mixtures of these. Water-based can include water from any source that does not contain an excess of compounds (for example, dissolved organic compounds, such as tannins) that can adversely affect other compounds in cement slurry 108. For example, cement sludge with delayed setting 108 it may include fresh water, salt water (for example, water containing one or more salts), brine (for example, saturated salt water) and / or sea water. The non-aqueous base can include one or more organic liquids such as, for example, mineral oils, synthetic oils, esters and / or others. In general, any organic liquid in which a salt water solution that can be emulsified may be suitable for use as a base fluid in the delayed-set cement sludge 108. In some implementations, the base fluid exceeds the concentration enough to form pumpable mud. For example, the base fluid can be water in an amount in the range of about 25% to about 150% by weight of cement (bwoc) such as one or more of the following ranges: about 30% to about 75% bwoc , about 35% to about 50% bwoc, about 38% to about 46% bwoc and / or others.
[0047] With regard to retardants of setting in the cement sludge
108, cement sludge 108 may include one or more different types of setting retardants such as, for example, phosphoric acid, phosphonic acid derivatives, lignosulfonates, salts, organic acids, hydroxyethylated carboxymethylated celluloses, co- or synthetic terpolymers comprising groups sulfonate and carboxylic acid and / or borate compounds. In some implementations, the holding retardants used in the present invention are
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29/59 phosphonic acid derivatives. Examples of setting retardants may include commercially available phosphonic acid derivatives, for example, from Solutia Corporation of St. Louis, Mo. under the trade name DEQUEST. Another exemplary setting retardant may include a phosphonic acid derivative commercially available from Halliburton Energy Services, Inc., under the trade name MICRO MATRIX CEMENT RETARDER. Example borate compounds can include sodium tetraborate, potassium pentaborate and / or others. A commercially available example of a suitable setting retarder comprising potassium pentaborate is available from Halliburton Energy Services, Inc. under the trade name Component R. Exemplary organic acids may include gluconic acid, tartaric acid and / or others. An example of a suitable organic acid may be commercially available from Halliburton Energy Services, Inc. under the trade name HR.RTM. 25. Other examples of setting retardants may be commercially available from Halliburton Energy Services, Inc. under the trade names SCR-100 and SCR-500. In general, the setting retardant in the delayed setting cement sludge 108 may be in an amount sufficient to delay the setting in an underground formation for a specified time. The amount of the setting retardant included in the cement sludge 108 can be in one or more of the following ranges: about 0.1% to about 10% bwoc, about 0.5% to about 4% bwoc and / or others.
[0048] In some implementations, cement sludge 108 may not include a setting retardant. For example, the sludge from system 108 may include high aluminate cements and / or phosphate cements independent of a setting retardant. In such cases, the activators can initiate the catching of mud 108. For example, these activators can include alkali metal phosphate salts. High aluminate cement may comprise calcium aluminate in an amount in the range of about 15% to about 45% by weight of high aluminate cement, fly ash class F in an amount in the range
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30/59 about 25% to about 45% by weight of high aluminate cement and sodium polyphosphate in an amount in the range of about 5% to about 15% by weight of high aluminate cement. In certain implementations of the present invention in which a cement composition comprising a phosphate cement is used, a reactive component of the cement composition (for example, the alkali metal phosphate salt) can be used as an activator.
[0049] Figures 2A and 2B illustrate a cross-sectional view of the well system 100 including cement subjected to handle 202 in at least a portion of the annular crown 122. In particular, the activation devices 110 have released activators in at least a portion of the cement sludge 108 to form the cement subjected to handle 202. In figure 2A, the cement sludge 108 flowed to the annular crown 122 through the column of the pipe 116 and, in response to at least one signal, the activation devices 110 in mud 108 they released an activator. In the illustrated example, substantially all of the devices 110 in the annular crown 122 have released activators to form the gripped cement 202 substantially over the entire length of the annular crown 122. Referring to figure 2B, the cement sludge 108 flowed into the annular crown 122 through the column of pipeline 116 and, in response to at least one signal, activation devices 110 in mud 108 released activators at a specified location 204. In the illustrated example, region or location 204 is located close to zone 102. In in other words, activation devices 110 near zone 102 can release activators and form the cement subjected to handle 202 located in region 204. The activation signal can be located in the region identified by 204 and, in response to at least the signal located , the cement is formed subjected to handle 204. In some implementations, an initial amount of the cement sludge 108 can be exposed to an activation signal in a different way. such that the catching period can be substantially equal to a period of time for
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31/59 the cement sludge 108 flows to location 204. In these examples, cement sludge 108 can be exposed to the activation signal as sludge 108 including devices 110 enters the column of pipe 116. The measurement As the leading edge of the cement slurry 108 begins to pick up, the flow of fluid through the annular crown 122 may become more restricted and may eventually cease. Thus, cement sludge 108 can be substantially prevented from flowing to surface 112 through annular crown 122. The remainder of cement sludge 108 can catch annular crown 122 behind the leading edge, as shown in figure 2A, or the cement sludge 108 can pick up in a moment, as illustrated in figure 2B. Thereafter, the remaining cement sludge 108 can be exposed to activation signals at a later time to initiate or accelerate the gripping processes.
[0050] Figure 3 illustrates an exemplary activator device 110 of figure 1 according to some implementations of the present disclosure. In these implementations, the activator device 110 releases one or more stored activators in response to at least one wireless signal. The illustrated device 110 is, for example, only useful, and the device 110 may include some, none, or all of the elements illustrated without departing from the scope of this disclosure.
[0051] As illustrated, the activator device 110 includes a substrate
302 and a passivation layer 304 formed on the substrate 302. Passivation layer 304 includes or is otherwise adjacent to an activator module 306 to release activators, a transducer 308 to receive wireless signals, logic 310 to control the activator module 306 , and a power module 312 to supply power to device 110. Substrate 302 can provide a mechanical structure to support elements of the device and / or a surface for routing electrical and / or fluidic signals. The substrate 302 can be silicon, quartz, glass, organic compound (for example, kapton tape
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32/59 or other flexible material), FR-4, dura and / or other materials. In some implementations, the passivation layer 304 can protect one or more modules from the cement sludge around 108 and / or can provide direct access to the cement sludge 108, for example, to release the activators.
[0052] The activator module 306 can release one or more activators to initiate or accelerate the grouting of the cement sludge 108. In some implementations, the activator module 306 can receive one or more signals from logic 310 and perform a process to initiate a reaction , for example, with cement sludge 108. The activator module 306 may include a membrane or other element that encloses the activators. In these examples, the activator module 306 can move, remove or otherwise open the element to release the activators in the cement sludge 108. The activator module 306 can include a heating element in the closure element that encloses a unitary chemical compound, a binary chemical compound fixed with a rupture membrane, unitary chemical compound with a rupture membrane and / or other configurations that release closed activators. Transducer 308 can convert external stimuli into one or more transduction signals that are processed by logic 310. For example, transducer 308 can detect signals such as ultrasonic, pressure, magnetic, electrical, electromagnetic (eg, RF, infrared, X-rays) ), acoustic, optical, VCF, nuclear (e.g., gamma, alpha, beta, neutron) and / or other signals.
[0053] Logic 310 can generate voltages to operate the activator module
306 using power module 312 and in response to at least the signal from the transducer. For example, logic 310 can dynamically switch between a go and a go state in response to at least the transducer signals. In some implementations, logic 310 can perform one or more of the following: receiving power from power module 312; receiving one or more transducer signals from transducer 308; generate one or more signals for the module
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33/59 activator 306 using the received energy; transmitting one or more signals to the activator module 306 to activate the release of one or more activators and / or other processes. The 310 logic can be complementary metal-oxide semiconductor (CMOS), Transistor-transistor (TTL), bipolar, Radio Frequency (RF) and / or other type of device. The power module 312 supplies power to device 110. For example, power module 312 can be a voltage generator that supplies sufficient current to operate logic 310. Power module 312 can be a thin film battery and / or thick, battery components, one or more capacitors, one or more induction collecting coils and / or other elements that store energy.
[0054] Figures 4A-C illustrate exemplary implementations of activator devices 110 releasing one or more activators. In these implementations, device 110 may comprise an acoustic trigger MEMS for controlled delivery of additives under command in a cement slurry. Devices 110 may allow the properties of the cement to be adjusted once the cement sludge has been pumped into the subsurface (e.g., retarded, accelerated in situ). Devices 110 can release activators by moving one or more elements, resistively heating one or more elements to form at least one opening, by chemically attacking one or more elements, and / or other processes. In some implementations, each device 110 can relay the activation signals to other devices 110. The following implementations are for illustration purposes only, and devices 110 can release activators using some, all, or none of these processes.
[0055] Referring to figure 4A, the activating device 110 mechanically moves element 402 to release activators 404. In some implementations, device 110 may include a MEM device that terminates 404 activators when element 402 is in a first
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34/59 position. In response to at least one signal, element 402 can rotate around an axis to a second position that releases activators 404 in cement slurry 108. In some implementations, the activation signal can directly move element 402. For example , the activation signal can structurally change the shape of element 402, for example, via an ultrasonic signal. In some implementations, device 110 may switch element 402 between the two positions at a specified frequency to assist or otherwise increase the dispersion rate of activators 404 in cement sludge 108. Referring to figure 4B, the activator device 110 resistively heats element 402 to form an opening that releases activators 404. For example, element 402 may be a gold membrane including a tungsten filament that generates heat by an applied current. In such cases, the heat generated may melt or otherwise deform the membrane to form an opening that releases the activators 404. In addition to the metal membranes, the element 402 may be other materials such as a polymer. Referring to Figure 4C, device 110 includes activators 404 and release chemical 406 that removes at least a portion of element 402 to release activators. In the illustrated example, device 110 includes a first reservoir 412 enclosing activators 404 and a second reservoir 414 enclosing release chemical 406 using a retaining element 410. The first reservoir 412 and second reservoir 414 can be configured to communicate fluidly through valve system 408. In a first position, valve system 408 can be substantially prevented from flowing from release chemical 406 to the first reservoir 412. In the second position, release chemical 406 can flow from the second reservoir 414 for the first reservoir 412 through valve system 408. In the illustrated implementation, release chemical 406 reacts with element 402 to
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35/59 form an opening that releases activators 404 in cement sludge 108. For example, release chemical 406 can attack or otherwise dissolve element 402.
[0056] Figures 5 and 6 are flowcharts illustrating exemplary methods 500 and 600 for implementing and manufacturing devices including one or more activators. The methods illustrated are described with respect to the well system 100 of Figure 1, but these methods could be used by any other system. In addition, well system 100 can use any other technique to perform these tasks. Thus, many of the steps in these flowcharts can occur simultaneously and / or in a different order than shown. The well system 100 can also use methods with additional steps, fewer steps and / or different steps, as long as the methods remain appropriate.
[0057] Referring to figure 5, method 500 starts at step 502 where activation devices are selected based, at least in part, on one or more parameters. For example, activation devices 110 and enclosed activators may be based, at least in part, on components of cement sludge 108. In some implementations, activation devices 110 may be selected based on subsurface conditions (for example , temperature). In step 504, the selected activation devices are mixed with a cement sludge. In some examples, activation devices 110 can be mixed with cement slurry 108 as the platform car 130 pumps the sludge into annular crown 122. In some examples, activation devices 110 can be mixed with cement dried before generating the cement sludge 108. Then, in step 506, the cement sludge including the activation devices is pumped to the subsurface. In some cases, cement sludge 108 including activation devices 110 can be pumped into annular crown 122 at a specified rate. One or more signs
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36/59 of activation are transmitted to at least a portion of the subsurface cement sludge in step 508. Again, in the example, the transmitter can be lowered into the coating to transmit signals to a portion of the cement sludge 108. In this example, the transmitted signals can activate the devices 110 next to the shoe 140 to take up that portion of the cement sludge 108, as illustrated in figure 2B. In some cases, the column of tubing 116 may move (for example, up / down) to assist in distributing the activators in the desired manner.
[0058] Referring to figure 6, method 600 starts at step 602 where a substrate with a passivation layer is identified. For example, substrate 302 including passivation layer 304 of figure 3 can be identified. In step 604 and 606, the power, transducer and logic modules and at least a portion of the activation module are manufactured. A reservoir in the activation module is also manufactured. In the example, transducer 308, logic 310, power module 312 and at least a portion of the activation module 306 are manufactured. In this example, a reservoir for enclosing at least a portion of the activators such as the reservoirs illustrated in figures 4A-C. In step 608, activators are deposited in the reservoir. As for the example, activators 404 can be deposited in the reservoirs illustrated in figures 4A-C. Then, in step 610, a membrane is fabricated over the reservoir to substantially enclose the activators. Again, in the example, element 402 can be manufactured to enclose activators 404 in the reservoir.
[0059] Figure 7 illustrates an exemplary well system 100 with respect to transmitting activation signals to cement sludge 122. For example, system 100 can wirelessly transmit electromagnetic signals to cement sludge 108 including a request for release activators in the cement sludge 108. In the illustrated example, system 100 includes an inner medium 702 and a signal source 706 connected to the inner medium 702 and the
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37/59 column of pipe 116 through connections 708a and 708b, respectively. The 708 connections can be ohmic contacts, capacitively coupled, and / or others. In some implementations, the pipe column 116 can be a hot path for signals. For example, the pipe column 116 may be a continuous metal path or a metal path with a finite number of discontinuities. In this case, each portion may result in a modest step attenuation. Furthermore, the inner medium 702 can be at least partially enclosed in one or more hulls or inner tube 704.
[0060] In some implementation, system 100 may allow signal transduction below into a long tube using cable feeding principles (LP-LF). In such cases, system 100 may transduce a signal using one or more of the following: the column of tubing 116; surface coating 124; and / or one or more inner tubes 704. The surface pipe column 116 may be 100 m or more in length. Inner tube 704 can be 100 m or less in length. The inner medium 702 can be metal, air and / or a liquid. In some implementations, the surface pipe column 116 and / or the inner pipe 704 can be used as an additional hot path that is out of phase with the coating signal and / or a different signal waveform. The 706 signal source can be any hardware, software and / or firmware that generates an electrical signal. A connection between the signal source 706 and the pipe column 116 may include return paths through one or more of the following: cement slurry 108; surface coating 120; the non-production zone 104; the inner medium 702; shells of tube 704 and / or others. Cement sludge 108 can be very basic (e.g., pH 13) and a loss medium that attenuates the return signal. The signal source 706 can produce varying voltages in time that are propagated down the conduits such as the pipe column 116. The signal source 706 can propagate in one or more
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38/59 more of the following frequencies: Ultra Low Frequency (ULF) such as 0.1 Hz to 10 Hz; very low frequency (VLF) such as 10 Hz to 30 kHz; low frequency (LF) such as 30 kHz to 30 MHz; high frequency (HF) such as 3 MHz to 30 MHz; Very High Frequency (VHF) such as 30 MHz to 300 MHz; and / or ultra-high frequency (UHF) such as greater than 300 MHz. In some implementations, the 706 signal source can produce 12-bit switching code (OOK) with a baud rate of 4,800 and fcentro = 13 , 5 MHz. In these implementations, the signal source 706 can directly drive the column of pipe 116 and drive the surface coating 120 180 ° out of phase. Furthermore, inner tube 704 may not be activated and connections 706 may be capacitively coupled.
[0061] Figures 8 A and 8B illustrate an exemplary power module
312 of figure 3 according to some implementations of the present disclosure. In the illustrated implementation, power module 312 can use an alkaline or acid environment generated, for example, by cement sludge 108. In these cases, power module 312 can generate a voltage difference using cement sludge 108 and regardless of store energy using, for example, a battery or capacitor. In some implementations, the 312 power module can be manufactured using thin and / or thick film photolithographic techniques to create sub-millimeter (submm) scale batteries. The exemplary power module 312 is for illustration purposes only, and module 312 may include some, all or none of the elements illustrated without departing from the scope of this disclosure.
[0062] The illustrated power module 312 includes a first metal element 802 and a second metal element 804 that form the terminals of the power module 312. In this case, the first metal element 802 and the second metal element 804 react with the sludge. cement around 108 to generate a different tension between the two terminals. The first metallic element 802 and the second metallic element 804 are
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39/59 at least partially enclosed by the passivation layer 304 and substrate 302. As previously discussed, substrate 302 may comprise silicon, glass, sapphire, organic flexible material and / or other materials. The passivation layer 304 includes a first opening 806a that exposes at least one surface or portion of the first metal element 802 and a second opening 806b that exposes at least one surface or portion of the second metal element 804. The first metal element 802 is exposed and the second metallic element 804, a voltage difference is generated between these terminals. Furthermore, this voltage difference supplies energy to load 808 as well as logic 310. The terminals are connected at load 808 via conductors 810a and 810b. The openings 806a and 806b can be formed, for example, by photolithography or a thick film printing process.
[0063] In some implementations, substrate 302 may be silicon and about 1 mm by 1 mm per 100 pm and cement sludge 108 may be in a pre-cured wet state. In such implementations, the first metallic element 802 may be a metal such as zinc, and the second metallic element 804 may be a metallic salt such as manganese dioxide. The 802 and 804 elements can be deposited using thick film screen printing and can each be about 150 pm by 150 pm by 50 pm. Again in these implementations, openings 806a and 806b can be 100 pm by 100 pm, and layer 304 can be photolithographable BCB. The conductors or connections 810a and 810b can be thin film plating.
[0064] Referring to figures 9-11, methods for detecting and / or monitoring the position and / or condition of well drilling compositions are illustrated, such as, for example, seal conditions (for example, cement) using data sensors based on MEMS 110, previously discussed with reference to figure 1. Even more particularly, this
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40/59 disclosure describes methods of monitoring the integrity and performance of well drilling compositions over the life of the well using MEMS-based data sensors. Performance can be indicated by changes, for example, in various parameters, including, but not limited to, moisture content, temperature, pH and various ionic concentrations (eg sodium, chloride and potassium ions) of cement. In implementations, the methods comprise the use of embedded data sensors 110 capable of detecting parameters in a drilling composition of well 108, for example, a seal such as cement. In some implementations, the methods allow evaluation of seal 108 during mixing, placement and / or curing of seal 108 within the drilling of well 106. In some implementations, the method can be used to assess the seal of this placement and cure throughout its useful life and, where applied, to a period of deterioration and repair. In implementations, the methods of this disclosure can be used to extend the life of the seal, reduce costs and / or intensify the creation of improved remediation methods. In addition, methods can be used to determine the seal site 108 within a borehole well 106, such as to determine the location of a cement slurry 108 during primary cementation of a borehole well 106, as further discussed below.
[0065] The methods disclosed herein comprise the use of various well drilling compositions 108, including seals and other service fluids for well drilling. In the form used herein, well drilling composition includes any composition that can be prepared or otherwise provided on the surface and placed below in the drilling of well 106, typically by pumping. In the form used herein, a seal refers to a fluid used to fix components within a well bore or to cap or seal an empty space within well bore 106. Seals 108 and, in particular, cement slurries and non-compositions
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41/59 cement are used as well drilling compositions in several implementations described here, and it should be understood that the methods described here are applicable for use with other well drilling compositions. In the form used here, service fluid refers to a fluid used to drill, complete, intervene, fracture, repair, treat or otherwise prepare or perform maintenance on a well bore 106 for the recovery of materials residing in a formation underground 102 penetrated by drilling well 106. Examples of service fluids include, but are not limited to, cement sludge, non-cementitious sealants, drilling fluids or sludges, spacer fluids, fracturing fluids or completion fluids, all of which are well known in the art. The service fluid is for use in drilling a well 106 that penetrates an underground formation 102. It should be understood that underground formation encompasses both areas below exposed land and areas below ground covered by water, such as ocean water or sweet. The well drilling 106 can be a substantially vertical well drilling and / or it can contain one or more lateral well drilling, for example, produced via directional drilling. In the form used herein, components are referred to as integrated if they are formed on a common support structure placed in the packaging of relatively small size, or otherwise assembled in close proximity to each other.
[0066] Referring to figure 9, method 900 is an exemplary method of placing MEMS sensors in a well bore and collecting data. In block 902, data sensors are selected based on the parameter (s) or other conditions to be determined or detected within the well drilling. In block 904, a number of data sensors are mixed with a well drilling composition, for example, a sealing mud. In some implementations, data sensors are added to a seal by any method known to those skilled in the art. For example,
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42/59 sensors can be mixed with a dry material, mixed with a more liquid component (for example, water or a non-aqueous fluid), or combinations of these. Mixing can take place in place, for example, adding the sensors in a large volume mixer such as a cement slurry mixer. The sensors can be added directly to the mixer, can be added to one or more component streams and subsequently fed into the mixer, can be added downstream from the mixer, or combinations thereof. In some implementations, data sensors can then be added after a mixing unit and mud pump, for example, through a side bypass. The sensors can be dosed and mixed at the well site, or they can be pre-mixed into the composition (or one or more components thereof) and subsequently transported to the well site. For example, the sensors can be mixed dry with dry cement and transported to the pit location where a cement slurry is formed comprising the sensors. Alternatively, or in addition, the sensors can be premixed with one or more liquid components (for example, mixed water) and transported to the pit location where a cement slurry is formed comprising the sensors. The properties of the drilling composition of the well or its components can be such that the sensors distributed or dispersed in it do not substantially settle during transportation or placement.
[0067] The sealing sludge is then pumped into the subsurface in the block
906, whereby the sensors are positioned inside the well bore. For example, the sensors can extend over all or part of the length of the well drilling adjacent to the casing. The sealing sludge can be placed on the subsurface as part of a primary cementation, secondary cementation, or other sealing operation described in more detail here. In block 908, a data interrogation tool is
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43/59 positioned in an operable location to collect data from the sensors, for example, lowered into the well drilling near the sensors. In block 910, the data interrogator tool interrogates the data sensors (for example, sending an RF signal) while the data interrogator tool travels all or part of the well drilling containing the sensors. The data sensors are activated to record and / or transmit data in block 912 via the signal from the data interrogator tool. In block 914, the data interrogator tool communicates data to one or more computer components (for example, memory and / or microprocessor) that can be located on the tool, on the surface, or both. The data can be used locally or remotely from the tool to calculate the location of each data sensor and correlate the measured parameter (s) with such locations to assess the performance of the seal.
[0068] Referring back to figure 1, during cementation, or subsequent to the cement pick, a data interrogating tool can be positioned in the drilling of well 106, as in block 908 of figure 9. For example, the cleaner can be equipped with a data interrogator tool and can read data from MEMS while being pumped on the subsurface and transmit it to the surface. Alternatively, or in combination, an interrogation tool can be run in drilling the well after the completion of cementation of a coating segment, for example, as part of the drill string during resumed drilling operations. Alternatively, or in combination, the interrogating tool can be run on the subsurface via a communication cable or other transfer mechanism. The data interrogator tool can then be signaled to interrogate the sensors (block 910 of figure 9) whereby the sensors are activated to record and / or transmit data, block 912 of figure 9. The data interrogator tool communicates the data to a 914 processor through the
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44/59 that the position of the data sensor (and similarly cement sludge) and the integrity of the cement can be determined by analyzing detected parameters with respect to changes, trends, expected values, etc. For example, such data can reveal conditions that can be adverse for the curing of the cement. The sensors can provide a temperature profile the length of the cement sheath, with a uniform temperature profile similarly indicating a uniform cure (for example, produced by the heat of hydration of the cement during curing) or a cooler zone can indicate the presence of water that can degrade the cement during the transition from mud to cement subjected to handle. Alternatively, or in combination, such data may indicate a zone of reduced, minimal or absent sensors, which would indicate a loss of cement corresponding to the area (for example, a loss / void or water / wash in zone). Such methods can be available with various cement techniques described herein such as conventional or reverse primary cementation.
[0069] Because of the high pressure at which cement is pumped during conventional primary cementation (pumping down into the liner and up into the annular crown), cement sludge fluid can leak into existing low pressure zones crossed by drilling the well. This can adversely affect the cement, and incur undesirable expenses for corrective cementing operations (eg, compression cementation, discussed below) to position the cement in the annular crown. Such a leak can be detected via the present disclosure, as previously described. In addition, conventional circulation cementation can be time-consuming and therefore relatively expensive, as the cement is always pumped down the pipe column 116 and back to the annular crown 122.
[0070] One method of avoiding problems associated with conventional primary cementation is to employ reverse circulation primary cementation. Reverse circulation cementation is a technique term used to describe
Petition 870190002342, of 1/8/2019, p. 47/189 / 59 a method where a cement slurry is pumped down into the coating annular crown 122 instead of into the column of pipe 116. The cement slurry displaces any fluid as it is pumped down into the annular crown 122. Fluid in the annular crown it is forced down into the annular crown 122, into the column of pipe 116 (along with any fluid in the liner), and then back to the surface of the earth 112. During reverse circulation cementation, liner shoe 132 comprises a valve that is adjusted to allow flow into the pipe column 116 and then sealed after the cementing operation is completed. Once sludge is pumped to the bottom of the pipe column 116 and fills the annular crown 122, the pumping is finished and the cement can naturally pick up on the annular crown 122. Examples of reverse cementing applications are disclosed in US patents 6,920,929 and 6,244,342, each of which is incorporated herein by reference in its entirety.
[0071] In some implementations of the present disclosure, sealing sludge comprising MEMS data sensors are pumped down into the annular crown in reverse circulation applications, a data interrogator is located inside the well bore (for example, integrated into the casing shoe) and the performance of the seal is monitored as described with respect to the conventional primary seal method disclosed above. In addition, the data sensors of the present disclosure can also be used to determine the termination of a reverse circulation operation, as further discussed below.
[0072] Secondary cementation within a well drilling can be performed subsequent to primary cementation operations. A common example of secondary cementation is compression cementation in which a seal such as a cement composition is forced under pressure into one or more permeable zones when drilling the well to
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46/59 seal such areas. Examples of such permeable zones include cracks, cracks, fractures, shafts, flow channels, voids, high permeability shafts, annular voids, or combinations thereof. The permeable zones can be present in the cement column residing in the annular crown, a duct wall in the well drilling, an annular micro crown between the cement column and the underground formation and / or an annular micro crown between the cement column and the conduit . The sealant (for example, secondary cement composition) picks up within the permeable zones, thus forming a hard mass to cover these zones and prevent fluid from passing through them, that is, substantially prevents fluid communication between the well drilling and the formation via the permeable zone. Various procedures that can be followed to use a seal composition in a well bore are described in U.S. Patent 5,346,012, which is incorporated herein by reference in its entirety. In various implementations, a seal composition comprising MEMS sensors is used to repair holes, channels, voids and annular micro-crowns in the liner, cement sheath, gravel packaging and the like, as described in US patents 5,121,795, 5,123,487 and 5,127 .473, each of which is incorporated herein by reference in its entirety.
[0073] In some implementations, the method of the present disclosure can be employed in a secondary cementation operation. In these implementations, data sensors are mixed with a sealant composition (for example, a secondary cement sludge) in block 904 of figure 9 and subsequent or during positioning and hardening of the cement, the sensors are interrogated to monitor the performance of the secondary cement in a manner analogous to the incorporation and monitoring of data sensors in primary cementation methods previously revealed. For example, MEMS sensors can be used to
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47/59 verify that the secondary seal is functioning properly and / or monitor its long-term integrity.
[0074] In implementations, the methods of the present disclosure are used to monitor cementitious (for example, hydraulic cement), non-cementitious (for example, polymer, latex or resin systems), or combinations of these, which can be used in applications primary, secondary or other sealing applications. For example, expandable tubular components, such as tube, tube column, liner, inner tube, or the like, are generally sealed in an underground formation. The expandable tubular component (e.g., casing) is placed in the well borehole, a sealing composition is placed in the well borehole, the expandable tubular component is expanded, and the sealing composition is subjected to natural handle in the wellbore. For example, after the expandable coating is placed on the subsurface, a mandrel can be run through the coating to expand the coating diametrically, with expansions of up to 25% possible. The expandable tubular component can be placed in the well bore before or after the sealing composition is placed in the well bore. The expandable tubular component can be expanded before, during, or after taking up the sealing composition. When the tubular component is expanded during or after the grip of the sealing composition, resilient compositions will remain competent because of their elasticity and compressibility. Additional tubular components can be used to extend the drilling of the well into the underground formation below the first tubular component, as is known to those skilled in the art. Sealing compositions and methods of using compositions with expandable tubular components are disclosed in U.S. patents 6,722,433 and 7,040,404 and U.S. patent publication No. 2004/0167248, each of which is incorporated herein by reference in its entirety. In
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48/59 implementations of expandable tubular component, the seals may comprise compressible hydraulic cement compositions and / or non-cementitious compositions.
[0075] Compressible hydraulic cement compositions have been developed that remain competent (continue to support and seal the tube) when compressed, and such compositions may comprise MEMS sensors. The sealant composition is placed in the annulus between the well bore and the tube or tube column, the sealant is naturally hardened into an impermeable grease and then the expandable tube or tube column is expanded, whereby the hardened sealant composition is compressed. In implementations, the compressible expanded seal composition comprises a hydraulic cement, a rubber latex, a rubber latex stabilizer, a gas and a mixture of foaming surfactants and foam stabilization. Suitable hydraulic cements include, but are not limited to, Portland cement and calcium aluminate cement. In some implementations, the sticky composition may include a polymeric additive. The polymer additive can be a monomer, a prepolymer, an oligomer, or a short-chair polymer that pohmerizes in response to the sonic signal. In these examples, activators may include a free radical dopant that releases autocatalytic free radicals in response to the sonic signal in such a way that the released autocatalytic free radicals initiate the polymerization of at least a portion of the handle composition.
[0076] Generally, resilient non-cementitious sealants with resistance comparable to cement, but greater elasticity and compressibility, are required for cementation of expandable lining. In some implementations, these seals comprise polymeric seal compositions, and such compositions can comprise MEMS sensors. In some implementations, the composition of seals comprises
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49/59 a polymer and a compound containing metal. In some implementations, the polymer comprises copolymers, terpolymers and interpolymers. The metal-containing compounds can comprise zinc, tin, iron, selenium, magnesium, chromium or cadmium. The compounds can be in the form of an oxide, carboxylic acid salt, a complex with a dithiocarbamate ligand, or a complex with a mercaptobenzothiazole ligand. In some implementations, the seal comprises a mixture of latex, dithiocarbamate, zinc oxide and sulfur.
[0077] In some implementations, the methods of the present disclosure comprise adding data sensors to a seal to be used behind the expandable liner to monitor the integrity of the seal by expanding the liner and during the life of the seal. In this implementation, the sensors can comprise MEMS sensors capable of measuring, for example, change in humidity and / or temperature. If the sealant develops cracks, water ingress can thus be detected via an indication of humidity and / or temperature.
[0078] In one implementation, the MEMS sensor is added to one or more well drilling service compositions used or placed on the subsurface in drilling or completing a single diameter well drilling, as disclosed in US patent 7,066,284 and publication of US patent No. 2005/0241855, each of which is incorporated herein by reference in its entirety. In one implementation, MEMS sensors are included in a chemical coating composition used in drilling a single-diameter well. In another implementation, MEMS sensors are included in compositions (for example, seals) used to place the expandable liner or tubular components in a single-diameter well bore. Examples of chemical coatings are disclosed in U.S. patents 6,702,044, 6,823,940 and 6,848,519, each of which is incorporated herein by reference in its entirety.
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50/59 [0079] In some implementations, MEMS sensors are used to collect seal data and monitor the long-term integrity of the seal composition placed in a well bore, for example, a well bore for resource recovery such as water or hydrocarbons or an injection well for disposal or storage. In an implementation, data / information collected and / or derived from MEMS sensors when drilling a subsurface well, the seal comprises at least a portion of the input and / or output of one or more calculators, simulations, or models used to predict, select and / or monitor the performance of well drilling seal compositions over the life of a well. Such models and simulators can be used to select a seal composition comprising MEMS for use in drilling the well. After placement in the well drilling, MEMS sensors can provide data that can be used to refine, recalibrate or correct models and simulators. In addition, MEMS sensors can be used to monitor and record the subsurface conditions to which the seal is subjected, and the seal's performance can be correlated to such data over the long term to provide an indication of problems or the potential for problems in the same well drilling, or different drilling. In various implementations, data collected by the MEMS sensors is used to select a seal composition or otherwise evaluate or monitor such sealants, as disclosed in US patents 6,697,738, 6,922,637 and 7,133,778, each of which is here incorporated by the reference in its entirety.
[0080] Referring to figure 11, a method 1100 for selecting a sealant (for example, a cementation composition) to seal an underground area penetrated by a well bore in accordance with the present implementation basically comprises determining a group of
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51/59 effective compositions from a group of compositions given estimated conditions observed during the life of the well, and estimate the risk parameters for each of the group of effective compositions. In an alternative implementation, actual measured conditions observed during the life of the well, in addition to or replacing the estimated conditions, can be used. Such actual measured conditions can be obtained, for example, via seal compositions comprising MEMS sensors described herein. Effectiveness considerations include problems that the seal composition is stable under subsurface conditions of pressure and temperature, resists subsurface chemicals, and has mechanical properties to withstand stresses from various subsurface operations to provide zonal insulation throughout the life of the well .
[0081] In step 1102, input data from the well to a particular well are determined. Well input data includes routinely measurable or calculable parameters inherent in a well, including vertical well depth, overload gradient, pore pressure, maximum and minimum horizontal stresses, hole size, outer casing diameter, inner casing diameter, drilling fluid density, desired pumping mud density, completion fluid density, and seal top. As will be discussed in more detail with reference to step 1104, the well can be modeled by computer. In modeling, the state of stress in the well at the end of drilling, and before the sealing mud is pumped into the annular space, affects the state of stress for the boundary of the interface between the rock and the seal composition. Thus, the stress state in the rock with the drilling fluid is evaluated, and properties of the rock such as Young's modulus, Poisson's ratio and yield parameters are used to analyze the stress state of the rock. Such terms and their methods of determination are well known to those skilled in the art. It is understood that input data
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52/59 of the well will vary between individual wells. In an alternative implementation, well input data includes data that is obtained via seal compositions comprising MEMS sensors, as described herein.
[0082] In step 1104, well events applicable to the well are determined. For example, cement hydration (handle) is a well event. Other well events include pressure testing, well completion, hydraulic fracturing, hydrocarbon production, fluid injection, drilling, subsequent drilling, formation movement due to high-rate hydrocarbon production from unconsolidated formation, and movement tectonic after the sealant composition has been pumped into place. Well events include those events that are certain to occur during the life of the well, such as cement hydration, and those events that are easily predictable to occur during the life of the well, given a particular well location, rock type and others factors well known in the art. In one implementation, well events and data associated with them can be obtained via seal compositions comprising MEMS sensors, as described herein.
[0083] Each well event is associated with a certain type of stress, for example, cement hydration is associated with contraction, pressure testing is associated with pressure, well completions, hydraulic fracturing and hydrocarbon production are associated with pressure and temperature, fluid injection is associated with temperature, formation movement is associated with the load, and drilling and subsequent drilling are associated with dynamic loading. As can be seen, each type of stress can be characterized by an equation for the stress state (collectively well stress states event), described in more detail in US patent 7,133,778, which is incorporated by reference in its full.
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53/59 [0084] In step 1106, well input data, well event stress states, and seal data are used to determine the effect of well events on the integrity of the seal sheath over life of the well for each of the seal compositions. The sealant compositions that would be effective for sealing the underground zone and its capacity for its elastic limit are determined. In an alternative implementation, the estimated effects over the life of the well are compared and / or corrected in comparison to corresponding actual data collected during the life of the well via seal compositions comprising MEMS sensors, as described herein.
[0085] Step 1106 ends by determining which sealant compositions would be effective in maintaining the integrity of the resulting cement sheath during the life of the well.
[0086] In step 1108, parameters for risk of seal failure for effective seal compositions are determined. For example, even if a seal composition is considered to be effective, a seal composition may be more effective than another. In an implementation, the risk parameters are calculated as percentages of sealant competence when determining efficiency in step 1106. In an alternative implementation, the risk parameters are compared and / or corrected against actual data collected over the life of the well via seal compositions comprising MEMS sensors, as described herein.
[0087] Step 1108 provides data that allows a user to perform a cost and benefit analysis. Because of the high cost of corrective operations, it is important that an effective seal composition is selected for the conditions expected to be observed during the life of the well. It is understood that each of the seal compositions has an easily calculable monetary cost. Under certain conditions, several compositions
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54/59 sealant can be equally effective, and it can also have the added virtue of being less expensive. Thus, it should be used to minimize costs. Most commonly, a sealant composition will be more effective, but also more expensive. Thus, in step 1110, an effective sealant composition with acceptable risk parameters is selected given the desired cost. In addition, the general results of steps 1102-1110 can be compared with actual data that is obtained via seal compositions comprising MEMS sensors, as described herein, and such data can be used to modify and / or correct inputs and / or outputs multi-step 1102-1110 to improve their accuracy.
[0088] As previously discussed and, with reference to figure 1, cleaners are generally used during conventional primary cementation to force the cement sludge out of the coating. The wiper plug also serves another purpose: typically, the end of a cementing operation is signaled when the wiper cap makes contact with a constraint (eg lining shoe) within the column of tubing 116 at the bottom of the column . When the plug makes contact with the restriction, a sudden pressure increase at pump 130 is recorded. In this way, it can be determined when the cement has been displaced from the pipe column 116 and the flow of fluid that resumes to the surface via the annular coating crown 122 stops.
[0089] In reverse circulation cementation, it may also be necessary to correctly determine when the cement sludge completely fills the annular crown 122. Continue to pump cement into the annular crown 122 after the cement has reached the far end of the annular crown 122 forces cement to the distant end of the pipe column 116, which could incur a loss of time if cement has to be removed to continue drilling operations.
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55/59 [0090] The methods disclosed here can be used to determine when the cement sludge has been properly positioned on the subsurface. In addition, as discussed below, the methods of the present disclosure may additionally comprise using a MEMS sensor to actuate a valve or other mechanical device to close and prevent cement from entering the coating upon determining the end of a cementing operation.
[0091] The way in which the method of the present disclosure can be used to signal when the cement is properly positioned within the annular crown 122 will now be described within the context of a reverse circulation cementation operation. Figure 10 is a flow chart of a method for determining the end of a cementing operation and optionally acting additionally a subsurface tool at the end (or starting completion) of the cementing operation. This description will refer to the flow chart in figure 10, as well as the representation of the well drilling in figure 1.
[0092] In block 1002, a data interrogator tool described below is positioned at the far end of the pipe column 116. In one implementation, the data interrogator tool is incorporated in or adjacent to a casing shoe positioned at the bottom end of the coating and in communication with operators on the surface. In block 1004, MEMS sensors are added to a fluid (for example, cement slurry, spacer fluid, displacement fluid, etc.) to be pumped into annular crown 122. In block 1006, cement slurry is pumped into inside annular crown 122. In one implementation, MEMS sensors can be placed substantially across the cement slurry pumped into the well bore. In some implementations, MEMS sensors can be placed on a lead plug or otherwise placed on an initial portion of the
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56/59 cement to indicate a leading edge of the cement sludge. In one implementation, MEMS sensors are placed in forward and escape plugs to signal the start and end of the cement sludge. While cement is continuously pumped into annular crown 122, in decision 1008, the data interrogator tool (DIT) is trying to detect whether the data sensors are in close proximity to communication with the data interrogator tool. As long as no data sensor is detected, pumping additional cement into the annulus continues. When the data interrogator tool detects the sensors in block 1010 indicating that the leading edge of the cement has reached the bottom of the liner, the interrogator sends a signal to end the pumping. The cement in the annular crown is allowed to pick up naturally and form a substantially impermeable mass that supports and positions the coating on the well bore and bonds the coating on the walls of the 1020 block well bore.
[0093] If the block fluid 1004 is the cement sludge, MEMS-based data sensors are incorporated into the bonded cement, and cement parameters (eg temperature, pressure, ionic concentration, stress, strain, etc.) ) can be monitored during laying and during the life of the cement according to previously revealed methods. Alternatively, or in combination, data sensors can be added to an interface fluid (for example, spacer fluid or other fluid plug) introduced into the annulus before and / or after the introduction of cement sludge into the annulus.
[0094] The aforementioned method for determining the completion of a primary well drilling cementation operation may additionally comprise the activation of a subsurface tool. For example, in block 1002, a valve or other tool can be operationally associated with a data interrogator tool at the end
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57/59 away from the coating. This valve can be contained in the floating shoe 132, for example, as previously disclosed. Again, the floating shoe 132 may contain an integral data interrogator tool, or may otherwise be coupled to a data interrogator tool. For example, the data interrogator tool can be positioned between the pipe column 116 and the floating shoe 132. Following the previously described method and blocks 1004 to 1008, pumping continues as the data interrogator tool detects the presence or absence of data sensors in close proximity to the interrogator tool (depending on the specific cementation method being employed, for example, reverse circulation, and the positioning of the sensors in the cement flow). Upon detection of a presence or determinative absence of sensors in immediate proximity indicating the end of the cement sludge, the data interrogator tool sends a signal to actuate the tool (for example, valve) in block 1012. In block 1014, the valve is closed, sealing the lining and preventing cement from entering the lining column portion above the valve in a reverse cementation operation. In block 1016, closing the valve in 1016 causes an increase in counter pressure that is detected in hydraulic pump 130. In block 1018, pumping is stopped, and cement can naturally pick up on the annular crown in block 1020. In implementations where sensors of data have been incorporated through the cement, cement parameters (and thus cement integrity) can additionally be monitored during placement and during the life of the cement according to methods disclosed here.
[0095] Improved methods of monitoring well drilling seal condition, placement during seal life, as revealed here, provide numerous advantages. Such methods are capable of detecting changes in parameters in well drilling
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58/59 such as moisture content, temperature, pH and ion concentration (for example, chloride, sodium and potassium ions). Such methods provide this data to monitor the condition of the seal, the period of initial quality control during mixing and / or placement, during the life of the seal, and in its period of deterioration and / or repair. Such methods are cost-effective and allow real-time data determination using sensors capable of operating without the need for a direct power supply (ie, passive, not active sensors), in such a way that the size of the sensor be minimal to maintain seal strength and pumpability of seal mud. The use of MEMS sensors to determine well drilling characteristics or parameters can also be applied to methods of budgeting a well service treatment, selecting a treatment for the well service operation and / or monitoring a well service treatment in time during its performance, for example, as described in US patent publication No. 2006/0047527 A1, which is incorporated herein by reference in its entirety.
[0096] Although preferred implementations of the methods have been shown and described, their modifications can be made by those skilled in the art without departing from the spirit and precepts of the present revelation. The implementations described here are exemplary only, and should not be limiting. Many variations and modifications of the methods disclosed herein are possible and are within the scope of this disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be considered to include interactive ranges or limitations of the same magnitude that fall within the ranges or limitations expressly stated (for example, from about 1 to about 10 includes , 2, 3, 4, etc .; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). The use of the term optionally with respect to any element of a claim must mean that the object element is required, or alternatively, is not required. Both
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59/59 alternatives must be within the scope of the claim. The use of broader terms such as understand, include, have, etc. it should be understood to provide support for more restricted terms, such as consisting of, consisting essentially of, substantially comprised of, etc.
[0097] Thus, the scope of protection is not limited by the description presented here, but is only limited by the following claims, this scope including all equivalents of the subject matter of the claims. Any and all claims are incorporated into the specification as an implementation of the present disclosure. Thus, the claims are an additional description and are an addition to the preferred implementations of the present disclosure. The discussion of a reference here is not an admission that it is technology prior to the present disclosure, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications and publication cited herein are thus incorporated by reference, to the extent that they do not provide exemplary and procedural details or other details supplementary to those presented here.
[0098] Numerous implementations of the invention have been described. However, it is understood that various modifications can be made without departing from the scope of the invention. Accordingly, other implementations are within the scope of the following claims.

权利要求:
Claims (19)
[1]
1. Handle composition under command, characterized by the fact that it comprises:
a handle composition;
an activation device (110), wherein the activation device (110) is used to increase a catch rate of the handle composition by releasing an activator (404) in response to an activation signal; and, in which the activation device (110) is a device of the Micro-Electro-Mechanical System (MEMS).
[2]
2. Handle composition under command according to claim 1, characterized in that the handle composition comprises a cement composition including a hydraulic cement, a base fluid, and a handle retardant; and wherein the activator (404) increases the rate of pickup of the cement composition and the activation signal is a wireless signal.
[3]
Composition according to claim 1 or 2, characterized by the fact that the handle composition is subjected to the handle in a range of one hour to a day after reacting with the activator (404).
[4]
Composition according to any one of claims 1 to 3, characterized in that the activation device (110) includes at least one dimension in a range of about 1 micron (pm) to about 10,000 pm.
[5]
Composition according to any one of claims 1 to 4, characterized in that the activation signal or wireless signal comprises at least one of an electromagnetic signal, a pressure signal, a magnetic signal, an electrical signal, an acoustic signal, an ultrasonic signal, or a radiation signal, wherein the radiation signal comprises at least one of neutrons, alpha particles, or beta particles.
Petition 870190002342, of 1/8/2019, p. 63/189
2/4
[6]
Composition according to any one of claims 2 to 5, characterized by the fact that the cement sludge (108) is mixed at a density in a range of 479 to 2,876 kg / m ³ (about 4 to about 24 pounds per gallon (ppg)).
[7]
Composition according to any one of claims 1 to 6, characterized in that the activator (404) comprises at least one of sodium hydroxide, sodium carbonate, amine compounds, salts comprising calcium, sodium, magnesium, aluminum, or combinations thereof.
[8]
Composition according to any one of claims 1 to 7, characterized in that the activation device (110) includes a voltage generator (312) configured to generate a voltage in an alkaline or acid environment independent of a source internal power supply.
[9]
Composition according to claim 8, characterized in that the tension generator (312) includes a first element (802) including a metallic surface in contact with the cement composition and a second element (804) including a surface of metallic salt in contact with the cement composition, and where the first element (802) and the second element (804) generate a difference in tension in response to contact with the cement composition.
[10]
10. Composition according to claim 9, characterized in that the metallic surface comprises zinc and the metallic salt comprises manganese dioxide.
[11]
Composition according to any one of claims 1 to 10, characterized in that the activation device (110) includes a polymer membrane to enclose the activator (404) in a substrate, and in which the polymer membrane forms an opening to release the activator (404) in response to an acoustic signal.
Petition 870190002342, of 1/8/2019, p. 64/189
3/4
[12]
12. Composition according to claim 11, characterized by the fact that the polymer membrane is selected from the group consisting of a polystyrene, ethylene / vinyl acetate copolymer, polymethylmethacrylate polyurethanes, polylactic acid, polyglycolic acid, polyvinyl alcohol, polyvinylacetate , ethylene / hydrolyzed vinyl acetate, silicon, and combinations thereof.
[13]
13. Composition according to any one of claims 1 to 12, characterized in that the activation signal is a wireless signal comprising an ultrasonic signal.
[14]
14. Composition, according to claim 13, characterized by the fact that the ultrasonic signal comprises signal transmitted at a frequency in the range of about 20 kiloHertz (kHz) to about 500 kHz.
[15]
Composition according to any one of claims 1 to 14, characterized in that the activation signal is a wireless signal comprising an acoustic signal.
[16]
16. Composition, according to claim 15, characterized by the fact that the acoustic signal is transmitted at a frequency in the range of about 20 Hertz to about 20 kHz.
[17]
17. Composition according to any one of claims 1 to 16, characterized in that the activator (404) is partially enclosed by an element selected from the group consisting of a polystyrene, ethylene / vinyl acetate copolymer, polyurethane polyurethanes, polylactic acid, polyglycolic acid, polyvinyl alcohol, polyvinylacetate, hydrolyzed ethylene / vinyl acetate, and combinations thereof.
[18]
18. Composition according to any one of claims 2 to 17, characterized by the fact that the activator (404) is
Petition 870190002342, of 1/8/2019, p. 65/189
4/4 mixed with the cement composition at a concentration of about 0.5% to about 30% by weight of the cement composition.
[19]
19. Composition according to any one of claims 2 to 18, characterized by the fact that the cement composition is selected from the group consisting of Portland cement, pozzolanic cement, high aluminate cement, plaster cement, silica cement, cement high alkalinity and sorel cement.

类似技术:

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公开号 | 公开日 | 专利标题

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BR112012004126B1|2019-08-06|COMPOSITION OF HANDLE UNDER COMMAND

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CA2771626C|2014-02-25|Methods of activating compositions in subterranean zones

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同族专利:

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公开号 | 公开日

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AR077949A1|2011-10-05|

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GB2487856B|2016-04-27|

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GB201205236D0|2012-05-09|

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BR112012004126A2|2016-03-22|

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WO2011023938A9|2011-06-16|

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MX2012002396A|2012-04-11|

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US8083849B2|2011-12-27|

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CA2771698C|2014-04-08|

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US20100050905A1|2010-03-04|

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CA2771698A1|2011-03-03|

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NO345153B1|2020-10-19|

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MX339853B|2016-06-15|

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WO2011023938A1|2011-03-03|

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NO20120199A1|2012-05-25|

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GB2487856A|2012-08-08|

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法律状态:
2018-04-10| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

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2018-11-13| B06T| Formal requirements before examination [chapter 6.20 patent gazette]|Free format text: O DEPOSITANTE DEVE RESPONDER A EXIGENCIA FORMULADA NESTE PARECER POR MEIO DO SERVICO DE CODIGO 206 EM ATE 60 (SESSENTA) DIAS, A PARTIR DA DATA DE PUBLICACAO NA RPI, SOB PENA DO ARQUIVAMENTO DO PEDIDO, DE ACORDO COM O ART. 34 DA LPI. |

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2019-06-04| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

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2019-08-06| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 20/08/2010, OBSERVADAS AS CONDICOES LEGAIS. (CO) 20 (VINTE) ANOS CONTADOS A PARTIR DE 20/08/2010, OBSERVADAS AS CONDICOES LEGAIS |

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2021-06-22| B21F| Lapse acc. art. 78, item iv - on non-payment of the annual fees in time|Free format text: REFERENTE A 11A ANUIDADE. |

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2021-10-13| B24J| Lapse because of non-payment of annual fees (definitively: art 78 iv lpi, resolution 113/2013 art. 12)|Free format text: EM VIRTUDE DA EXTINCAO PUBLICADA NA RPI 2633 DE 22-06-2021 E CONSIDERANDO AUSENCIA DE MANIFESTACAO DENTRO DOS PRAZOS LEGAIS, INFORMO QUE CABE SER MANTIDA A EXTINCAO DA PATENTE E SEUS CERTIFICADOS, CONFORME O DISPOSTO NO ARTIGO 12, DA RESOLUCAO 113/2013. |

优先权:

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申请号 | 申请日 | 专利标题

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US12/547,275|US8083849B2|2007-04-02|2009-08-25|Activating compositions in subterranean zones|

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US12/547275|2009-08-25|

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PCT/GB2010/001580|WO2011023938A1|2009-08-25|2010-08-20|Activating compositions in subterranean zones|

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