Patent Application
20250075596
This patent application claims priority under 35 U.S.C. Section 119 to Mexican Patent Application No. MX/a/2023/010204, filed Aug. 31, 2023, the entire disclosure of which is incorporated herein by reference.
Production tubing (TP) or casing (TR) anomalies, which include holes, drillings or splits, can occur during design, drilling, completion, production and throughout the productive life of a hydrocarbon producing well; such anomalies can have diverse origins ranging from inappropriate design due to lack of knowledge of future operating conditions to erosion and corrosion damage; they are also done intentionally, for example, to increase production or are caused by changes in the producing interval.
The set of techniques developed in the present invention is oriented to the conclusion of an integral technology to restore the mechanical integrity of either, casing or production pipes of reduced diameter. Thus, this invention is inscribed within the technologies used for repair and maintenance operations of wells in hydrocarbon reservoirs.
This section discloses the various disclosed aspects of the art which may be associated with practices of the present invention, and its goal is to provide a framework to a better understanding of the particular aspects; accordingly, this section should be interpreted in this sense and not necessarily as acceptance of the prior art.
It should be noted that, in the description of this patent application, English system units are also used because all the infrastructure for drilling, completion, production and transportation of hydrocarbons is designed and manufactured in the aforementioned units, including pipes, accessories, components and tools.
Exploration, development and production processes in oil and gas wells include activities that involve different risks to the environment, personnel and facilities; in particular, casing and production pipelines are exposed to failures due to the events described in Table 1 (Short, 1981; U.S. Pat. No. 9,587,460 B32; Ho Yin Yap Ft al., 2021; Carballo et al., 2014; CNH, 2014, De la Torre et al, 2017; Karev Ft al., 2020; ALS, N/D).
In general terms, anomalies due to the events outlined above can be grouped as: a) intentionally made alterations and b) pipe damage. These two groups are listed below in Table 2 and illustrated in
Anomaly and leak detection technologies. Nowadays, there are both, indirect and direct ways to detect anomalies and leaks in tubing (TP) and casing (TR). The former include irregular monitoring and logging during completion and/or production, e.g. temperature monitoring, thermal decay logging and acoustic signals for fluid flow and leakage events, including a derived form technology of the latter phenomenon which is called “Distributed Acoustic Sensing” (DAS) (Noble Et al., 2021), and direct forms including the use of tools such as ultrasound (USIT), Corrosion Evaluation Tool (CET), Multifinger Caliper (MFCT), Electromagnetic Imaging Tool (EMIT) and use of video cameras; on the other hand, pipeline detection devices (PIG), magnetic flux leak detection tools and other resources such as pressure tests are used for pipelines. New materials, equipment and techniques have also contributed to the development of new TP and TR repair technologies, which are described below.
Flexible patching. Technologies used in the industry for repairing damaged or perforated pipes include the placement of flexible patches or other materials that are placed over high-strength inflatable elastomeric pneumatic elastomeric devices similar to packers (Toshikasu Igi, U.S. Pat. No. 9,481,156 B2; Bailey et al. U.S. Pat. No. 9,481,156 B2; Bailey Et al., 2000; Japanese patent No. JP200120653A; Styler Et al, 2001).
Alternative to the previously described patches, a section of pipe is trimmed longitudinally forming two additional faces from end to end, as indicated in
Observations relevant to these technologies include: a) the requirement that the pneumatic device must be kept expanded against the patch and the inner wall of the pipe as long as necessary for the resin to cure, harden and rigidly adhere to the pipe, b) The total length of each patch is limited by the length of the pneumatic device, typically no more than two meters, so only one patch of limited length can be applied at a time, wait for it to be installed, then remove the pneumatic device and start placing another patch, this, in cases of large lengths of pipe to be repaired, increases downtime, delays production and increases operating costs; c) a detailed analysis is necessary to evaluate the resistance of these patches since the positive pressure differentials inside the pipe can detach and/or damage the patch; Another relevant aspect to consider is the use of materials whose corrosion potential is different from that of the pipe, this can induce accelerated corrosion in the contact zone between the patch and the pipe, d) these devices, due to their installation principle, are not available for pipe diameters smaller than 88.90 mm (3.50 inches), e) finally, when the walls of the patch are significantly small, they are more susceptible to impacts; Hill et al., (2009) have reported that after a physical impact, patches made of composite materials, when exposed to environmental humidity combined with cathodic currents, can induce a type of corrosion where both, adhesion between the material substrates and cathodic protection are lost.
Optional to the previously described patches, Tao Li Et al. (2013) propose a hydraulic and a mechanical device to expand a metal patch in a damaged section of casing (TR) below an expanded tubular patch in the TR, relevant weight and dimension considerations of the expansion systems include the need to place these patches with repair equipment; the reduction of the space between the PT and the TR, and the size of the devices expansion prevent applying this technology to small diameter production pipes; Additionally, there is an important consideration is the use of metal patches whose corrosion potential is different from that of the pipe, since this can induce accelerated corrosion in the contact zone between the patch and the pipe. Alternative to the previous technology, Neely (1985) presents a technology to install metal patches, up to five feet in length, expandable in areas where there are leaks; here a hydraulic piston expands the lower wall of the patch against the wall of the casing causing both, the contact and anchoring, and initiates the sealing; The piston slides upward, expands and causes the metal patch to expand until it covers the damaged area or the five feet length; The reference indicates that the installation time is thirty minutes for a ten foot patch, finally the piston is removed and the metal patch is tested for tightness. As indicated in the document, repair equipment is required to install this type of patch. Furthermore, the contact between the expanded metal patch and TR does not guarantee airtightness. Additionally, due to the nature of the technology, it can only be applied to large diameters of pipe, potentially larger than 4.5 inches. Similar technologies (Forbes, 1998) have been used extensively for restrictive 4.0-inch diameters in North Sea wells using coiled tubing.
Hydro-expandable patches. With the development of new materials, their applications have also multiplied in the petroleum industry. Among these materials are elastomers, which have been used intensively in seals, gaskets and as main elements of some packers. A particular type of those are the so-called hydro-expandable elastomers (Quamar Et at., 2021); These polymers swell by absorption when exposed to an appropriate oil- or water-based agent, in particular, when installed on steel pipe, they have been used as patches to repair casing pipes (Durongwattana et al., 2011) in the LKU-A01 well, in the central plain of Thailand;
The description of this system considers that the maximum design expansion time is greater than 10 days, considering that the rapid expansion agent is water; Additionally, we must wait for the patch to expand before placing another one; With respect to the diameters, pipes of 139.700 mm (5.50″) in devices up to 4.267 m (14 feet) in length may be used, additionally a 10% KCl brine is used so that the patch makes proper adhesive contact with the TR in a minimum of 5 to 27 days to prevents premature swelling, finally repair equipment is used for the patch installation.
Permanent patches. Another type of expansion patches, (Gammill, C., 2017, U.S. Pat. No. 9,587,460 B2; Gammill, C., US patent U.S. Pat. No. 10,612,349 B2; Julian et al., 2006; Weatherford, 2016), sometimes called soft patches, are made of low carbon steel or 300 series stainless steel, which may include a molded polymer on the outside or inside, they have been used successfully in pipes larger than 4.50 inches, these patches, when expanding within the area of interest, provide metal-to-metal contact “adapting” to the surface of the damaged pipe, where the polymer provides support for the insulation, Julian (Op. Cit., Weatherford, 2016) notes that they are less expensive than retrievable patches. Binggui Xu et al. (2020) have developed a sealing system with presumably polymeric cones expanded by means of hydraulic cylinders combined with an assembly of cones that expand to achieve anchoring. The double mechanical-hydraulic system involved requires precise control of the location and it is anticipated that its operation and weight will require repair equipment. It is considered too heavy for a steel line, nor are the diameter ranges indicated to apply this tool, but considering the double system, it is anticipated to be applicable to large diameter pipes, typically greater than 114.30 mm (4.50 inches).
Caccialupi Et al., 2018, in U.S. Pat. No. 10,132,141 B2, has developed a variant of permanent patches that considers the existence of geometric restrictions such as nipples, unions or other types of similar elements in the leaking area; in this case, patches have been developed with sealing components with jaws above and below the area affected by leaks or other perforations; These jaws are designed not to exceed, when expanded, the inner diameter of the pipe that includes the indicated geometric restrictions, in such a way that a seal is created with an elastomeric ring or a protrusion, similar to that of packers, but only in specific points above and below the affected area. The expansion is carried out with a main expansion element that slides on a longitudinal axis with hydraulic pressure by means of pistons. Although this device may include a mechanical anchor, there is the possibility that it does not include one, and the seal is made by means of the elastomeric elements, in such a way that a redundant docking system is foreseen. An advantage of this system is that it can be installed with steel line. This type of device does not consider the potential cyclic compression and expansion deformations in the conduction line due to changes in the flow regime, since once the mechanical anchors are installed there is no possibility of longitudinal movement. Another important consideration is that this device and patch are designed for pipe of casing as indicated in the summary, typically with diameters greater than 114.30 mm (4.50 inches). Due to the weight of the necessary equipment and the dimensions of the patch itself, repair equipment is used; On the other hand, the dimensions of the equipment make them available for pipes diameter of 4.50 inches or larger; additionally, the selection of the low carbon or stainless-steel metal patch must consider the minimization of galvanic pairs between these materials and the damaged pipe in order to avoid accelerated corrosion of the patch-pipe system. Finally, the effectiveness of metal-metal contact for sealing must be carefully evaluated. Julian et al., (2006) in a study of 263 permanent and recoverable patches installed in fields in Prudhoe Bay, Alaska, indicates that soft patches had an effectiveness less than 70%, with the main failures being immediately after installation and leaks after the patch has been installed, presumably at the patch-pipe contact. Other authors (Tao Li, 2014) point out that expandable pipes (SET) have a low success rate in thermal recovery wells under high temperature conditions or high-pressure injection wells.
Recoverable patches. Generally speaking, these patches can be classified by the number and characteristics of the fixing elements of the patch, by the number and properties of the insulation elements and the specific properties of the installation/removal system, as well as by the number of trips necessary for their installation, are also characterized by the materials used and the range of diameters where they are applied. Typically, they are made of carbon steel or stainless steel, new coatings based on titanium or aluminum nitrates or tungsten carbide (Li Tao, 2015) improve their resistance properties to high temperatures and pressures; Their diameters (ID) are typically larger or equal to 108.610 mm (4.276 inches) (TTS) and are installed in one, two or up to three trips, depending on their design; those installed in one trip include packers that are fixed with a spacer tube that connects them and inside the spacer tube is another tubular element that provides the necessary force to adjust the lower gasket and extrude it to the pipe wall intended to be isolated, all in one trip. Two-trip systems typically include two packers at each end of the retrievable patch and an inner tubular member that connects both packers, and whose length is designed to isolate the damaged area of the pipe to be isolated. In each trip, a docking element is fixed between the patch and the damaged pipe, together with the sealing element and the insulating jackets in the damaged section. The literature investigated shows that there are different approaches in the design and operation of docking elements (
Mullins (2016) describes a device in the U.S. Pat. No. 9,453,393 B2 whose objective is to install a jacket in a well that has a casing, The device for installation includes the use of Viton type packers and anchors installed alternately along the device, the anchors are installed with a mandrel system that activates them when a rotational moment is applied; Although the objective of this device is to install a sleeve at the bottom of a well, the diameters in which it is manufactured are not clearly established; however, the use of repair equipment or at least a mast with equipment to apply torsion in the installation line of their
The hermeticity of the patches is mainly achieved by three mechanisms, a) that which involves metal to metal contact, b) that which includes devices made of rubber compounds or elastomers type ring-seals or chevron type and c) combinations of the previous ones. Special consideration is required during the design of these sealing mechanisms; In an analysis of failure mechanisms of recoverable and permanent patches, in Prudhoe Bay fields, from 1985 to 2006, Julian Et Al., (2006) points out that 26% of the wells analyzed were due to a second leak, 28% were due to leaks in the patch, 19% of the failures were due to unsuccessful installation operations, 8% were due to sticking during traveling (lowering or raising), 4% to imprecise placement and the remaining 15% to unknown causes.
In relation to casing, Al-Dossary Et Al. (2017) has reviewed the types of leaks existing in these pipes in five different oil fields, in the same geographical region, presumably in Arabia, which adds particular regional geological characteristics that allow him to classify the observed leaks into the following three types, a) the first scenario includes leaks crossing superficial aquifers, therefore located at a shallow depth that carry corrosive waters with CO2 and H2S gases, and is considered a thief zone and difficult to seal; b) the second type occurs when the leak occurs in formations with highly pressurized formation water, without cementation around the casing, these waters are corrosive and contain H2S, which corrode the pipe quickly; and, c) the third type of leaks, according to the authors, is due to different factors including metal losses, damaged couplings, leaks in the diverter valve, coupled with low quality cementation, cement aging, inappropriate cementitious mixture or poor cementing practices and their consequences. Al-Dossary concluding remarks highlights the circumstances in which the leaks are presented and proposes, what he considers, the best practices and tools of the above scenarios for the best treatment of the leaks in its Table 1, and the corresponding procedures for the repair of the leaks in diagrams 1 to 3 of their paper. It is important to note that these solutions require repair equipment and are available for TRs greater than 114.3 mm (4.5 inches).
Patches with packer and cementation. Ansari et al. (2016) have proposed the use of a technology called HidraWell, designed to restore the integrity of casing pipes. The authors emphasize the need to conduct extensive investigations prior to the mobilization of workover teams, to accurately determine the integrity condition of a hydrocarbon well when the second safety barrier in the annular region or barrier B has failed; This remediation technology is proposed as an alternative to grinding and replacing the damaged section and re-cementing of 244.475 mm and 339.725 mm pipes (9⅝″ and 13⅜″); This technology includes a tool that has a packer and its guard and a clamping piece to control a grinding section at the front; Prior to the installation of the grinding section, the packer is installed and the section to be isolated is cemented, then the grinding section is installed and the cemented area is penetrated to allow the flow of fluids through it, as indicated in
Other limitations are related to the fact that these tools are not designed for diameters smaller than 114.3 mm (4.5 inches), those that include front cementation rely on good adhesion between cement and pipe, and the efficiency relies on one or two packers and/or the impermeable contact between the metal patch and the TR or TP.
Inflatable packers. These technologies have been important for cases of uninterruptible operations such as work under high pressures during the drilling of wells. These packers easily pass through restrictions, are very resistant and withstand high pressure demands, however, their use is risky in wells where pressures and temperatures are at the maximum limit of these devices (Rodenboog, 2001), additionally since these inflatable packers are subject to high pressures in high temperature environments, when deflated, they tend to include a plastic deformation component, in addition to elastic deformations; Mackenzie et al. (2022) points out that these plastic deformations are not recoverable, which may require additional tension at the time of extraction and therefore brushing or erosion and even damage to the packers surface.
Methods with pressure-activated sealing materials. This technology includes the use of sealing materials that polymerize (solidify) only where the leak remains active and a pressure differential exists, otherwise they remain fluid (Johns Et Al., 2007). The authors point out that a great advantage of this technology is that unused material is removed by mechanical methods and does not present difficulties for future maintenance operations. The following aspects are highlighted as relevant when designing a solution based on these technologies: the accurate detection of fluid leaks is very important and conventional recording methods are not the most appropriate, on the other hand, the electromagnetic tool (EMIT) to obtain images is designed to quantify the loss of metal along the TR, but it does not distinguish whether the leak is into or out of the pipe; in addition, some tools such as those dedicated to temperature measurement, noise registers and/or caliper could mask leaks. The authors point out that the best method are ultrasound based methods. However, it is necessary to consider that the effectiveness of its sealing depends on the size of the leak; the larger it is, the more complications there are in using this technology, since it requires specific periods of time, that include: the time necessary for the sealing agent to reach the area of the leak, plus the curing time that requires 18 or more hours, plus the time required to perform sealing and tightness tests, additionally the sealed area of the leak becomes a sensitive area when piping or tools are lowered through it.
Use of epoxy resins. A variant of the previous method is the use of epoxy resins (Yufei Sun Et Al., 2019) that are injected over a plug, along the area where leaks occur, premixed with both, a catalyst for hardening and a reaction accelerator. The authors point out that this technology is ideal for conditions where the use of particles can cause bridging in channels or very closed fractures, gravel packing, small and microannular fractures; They also point out that once it penetrates the microspaces that form the leaks, a three-dimensional network is created that seals the system. Once cured, it is drilled through to open the production column again. Although its compression properties are good, its tension properties are not better, this limits its use to small to very small pore and channel sizes, larger Leak cavities can produce this type of stress making their use risky, particularly if differential pressures exist due to leaks.
Use of laser rays. Another type of hydrocarbon pipes that require repair are those that conduct hydrocarbons on the ocean floor, in extreme cold and heat, in places that are difficult to access and those exposed to microbiological corrosion; Asher et al. (2012) discuss this topic and in particular the potential for remote repair using laser beam cleaning/welding of hydrocarbon pipelines.
Production methods with water control. In some hydrocarbon wells, excessive water production becomes a big issue (Nasser H. Al-Azmi Et Al., 2017); in them, appropriate knowledge of the water production mechanism is particularly relevant to develop and apply efficient technologies, Nasser presents relatively simple solutions that include placing packers in the producing area, in such a way that the production of hydrocarbons trough the annular and canceled at the center, then, using one or more pumps the water is extracted through the surface.
Sealing fluids based on nanoparticles. These fluids have been designed (Todd Et Al., 2018) to cover the market for old wells or wells that have been decommissioned, but with high pressures in the annular space and with very small leaking holes in the TR less than 150.0 micrometers; The sealing effect is achieved when these fluids meet brines or cementation material in the porous areas. The authors present results from three wells where this technology has been successfully applied. Of course, these sealing fluids are limited to microporosities on large surfaces and do not consider larger porosities such as holes in the range of millimeters or even centimeters caused by corrosion and other agents.
Current exploration techniques allows us to know and precisely verify the areas where anomalies are found in production or casing pipes. This has also allowed the development of new production and casing pipe repair technologies that include composite patches, resins based sealing systems and other thermoactivated, hydro activated materials, or materials activated with pressure differentials; sealing methods have also been developed with preformed materials, and with the use of soft metals that can expand inside the TR or TP in full or partial contact with the interior wall. Other types of mechanical devices include those installed with anchors in the pipe being repaired, sealing the contact with devices inspired by packer technology. Each of these systems offers generalized or specific solutions to particular scenarios and presents advantages and limitations specific to its objectives and scope, which are reflected in their designs. Their limitations are related to repair equipment requirements, deployment systems, installation times, longevity of the technology, scope of the solution, since almost all of them are developed for pipe diameters greater than 114.3 mm (4.5 inches), efficiency and flexibility of the solution.
The present invention has overcome the limitations of the technologies described and provides the following advantages:
It is, therefore, an object of the present invention provides a system for restoring the mechanical integrity of production or casing pipes with diameters less than 114.3 mm (4.5 inches).
Another object of the present invention is to provide the petroleum industry with a novel device and methods that resolve quickly the sealing of leaks or punctures in tubing or casing at any length and can accommodate protrusions such as joint defects and similar geometric restrictions in the area to be isolated.
An additional object is to provide a device that is easily installed in few hours with steel line, using standard Fishing tool type connectors.
Another additional object is to provide a device that, due to its design and selection of manufacturing materials, provides continuous service for long periods of time.
These and other objects of the device of the present invention will be discussed later in greater detail.
Aimed to provide clarity in the description of the system for the restoration of the mechanical integrity of casing or production pipes of reduced diameter, object of the present invention, reference will be made to the accompanying drawings, without limiting the scope of the present invention:
The present invention relates to a technology whose objective is to restore the mechanical integrity of casing or production pipes in hydrocarbon producing wells that have anomalies in their wall, these include holes, perforations or divisions; This technology includes a Device (D) that is installed in a conventional operation with a slickline unit, avoiding the use of repair equipment and minimizing the impact on the components of the integral hydrocarbon production system, and is placed inside a well to isolate areas of tubing or casing having abnormalities; simultaneously allows the flow of hydrocarbons or other fluids along its longitudinal axis, at pressures of up to 34.474 MPa (˜5,000.00 psi); It also includes a method for diagnosis, design and potential effectiveness of the Device in a well, a method for the device (D) installation in the well, a method for verifying its effectiveness already installed, and a method for its recovery to the surface.
This assembled Device has a cylindrical shape, made up of seven longitudinally hollow cylindrical sections, assembled one on top of another along its longitudinal axis (
First section (I). This section includes a lower mechanical anchor, which has expandable wedges, hereinafter called wedges [number (3) of
Second section (II). This section (
The fixation of the lower Packer is carried out as follows: Both, the Wedge holder sleeve (6) and the Sealing cylinder (9) are fixed; then, by striking the upper part of the Captive Sleeve (12), a downward linear movement is generated that is transferred to the Core of the lower packer (13), to the Nose (11) and to the Seal (10), causing the tool to reduce in length and expand the Seal (10). To prevent the tool from returning to its initial length, the Ratchet (8) prevents the Packer from expanding after being compressed.
The recovery of the First and Second sections is carried out in the following way: Using a Fishing tool, preferably GS type, the Captive Sleeve (12) is hit upwards, this generates a shear force in the Bolt (14) in such a way that it breaks, which allows the upward linear movement of the Nose (11), as well as the contraction of the Seal (10); due to the forces to which they will be subjected, the Wedge holder Sleeve (6), the Ratchet (8), the Sealing cylinder (9), the Nose (11), the Captive sleeve (12) and the Lower packer core (13) are made of materials that withstand stresses of 655.002 MPa (˜95,000.0 psi), preferably AISI 4140T steel, the Bolt (14) preferably made of SAE 64 bronze, and the Ring (7) and the Seal (10) made of materials resistant to oils, acids, abrasion, water vapor and heat, preferably Viton™ Fluoroelastomers. The Second section (II), in its upper part, is joined to the Third section (III) by means of a seal type union with the Upper Connector, where the seal generating elements are chevrons, as indicated next.
Third section (III). This section includes a mechanical system called Upper Connector (
Fourth section (IV). This section (
Fifth section (V). This section (
Sixth section (VI). This section (
Seventh section (VII). This section (
The anchoring is carried out in the following way: The Wedge holder Sleeve-S (28) and the Tightness Cylinder-S (31) are fixed; by striking the upper part of the Captive Sleeve-S (34), a downward linear movement is generated that is transferred simultaneously to the Upper packer Core-S (35), to the Nose-S (33) and to the Seal-S (32), causing the Device (D) to reduce in length and expand the Seal-S (32). To prevent this section from recovering its initial length, the Ratchet-S (30) prevents the Upper Packer from expanding after being compressed.
Recovery of this section is carried out in the following way: using a Fishing tool, preferably GS type, the Captive Sleeve-S (34) is hit upwards, this generates a shear force in the Bolt-S (36) in such a way that it breaks, which simultaneously allows the upward linear movement of the Nose-S (33), as well as the contraction of the Seal-S (32); because of the stresses to which they will be subjected, the Wedge holder sleeve-S (28), the Ratchet-S (30), the Tightness Cylinder-S (31), the Nose-S (33), the Captive Sleeve-S (34) and the Upper packer core-S (35) are made of materials that withstand stresses of 655.002 MPa (˜95,000.0 psi), preferably AISI 4140T, Bolt-S (36) preferably made of SAE 64 bronze, and both, the Ring-S (29) and the Seal-S (32) are manufactured from materials resistant to oils, acids, abrasion, water vapor and heat, preferably Viton™ Fluoroelastomers. The Seventh section (VII), in its upper part, has a Fishing tool housing, preferably GS type, for its placement and extraction, and is joined to the Sixth section (VI) by means of a truncated thread.
Method for the diagnosis, design and potential effectiveness of the Device in a well. The evaluation of the applicability of the Device (D) in a well requires the analysis of information that establishes the feasibility of being installed, as well as the way to perform it.
In the case of the feasibility of being installed, the mechanical state information allows identifying the distribution of those accessories in the production rig, their location and characteristics (model, inside diameter, clearance between the device and the TP or TR), as well as the completion of the well which includes the casing diameter, its location and length, conditions where the accessories present an inside diameter smaller than the production tubing, its proximity to the zone to be repaired, presence of telescoped production tubing inverted and other circunstances that prevent the installation of the Device (D), must be considered. Those cases in which the access to the well present physical and/or administrative inconveniences, and/or the platform, cellar and christmas tree are not in adequate conditions may be reasons for the Device (D) not to be installed. Also the way it will be installed, type of slickline unit, surface equipment, slickline string, number of trips, trip speed, force of attachment impacts on Sections (1) and (II), and (VI) and (VII) depends on the information obtained through the geophysical logging unit (length of zone to be repaired), production logs (type of fluids, percentages, viscosity, presence of solids), gyroscopic (well deviation), intervention history (presence of obstructions) and others.
Device (D) installation method. The Device (D) installation considers two phases, a pre-installation phase and an installation operation phase. In the pre-installation phase, information is acquired to determine the operational requirements in equipment and slickline accessories to install the Device (D), as part of this information the mechanical condition, production history and interventions, electrical logs, gyroscopic and any other relevant operational record available are obtained; additionally, the site of the well to be intervened is visited to evaluate the conditions of its accesses, platform, cellar, christmas tree, and others available. In the operational phase of installation, the Device (D) is installed considering at least three trips with slickline unit in the following order:
Lowering and fixing of the Sixth (VI) and Seventh (VII) sections inside the production/casing pipeline. Depending on the damage length of the production/casing pipeline, it will be the number of trips of the sleeves (20) and connectors indicated above, the more extended longitudinally the damage is, the greater the number of sleeves (20) required to isolate the altered zone.
It is important to mention that the length of the sleeves (20) to be placed in each descent is conditioned by the capacity of the slick line unit (SLU) as well as its accessories (lubricators).
It is important to keep in mind that, as part of the operating procedures in operations with slick line units, prior to lowering any tool, it is mandatory to calibrate the production/casing pipe to a diameter at least equal to the outside diameter of the Device (D), in order to guarantee its free descent and avoid jamming. This operation is performed only once before starting the fastening of the components that make up the Device (D).
Method of verifying the effectiveness of Device (D) installation. Verification of the effectiveness of the Device (D) installation is accomplished by measuring physical variables including pressure, flow rate, percentage of fluid production, and other physical variables and/or by taking logs including closed and open bottom pressure, electrical and other, either with a slick line unit or electrical logs. The criteria for defining the type of measurement is determined by the mechanical condition of the well and the type of leak detected, for clarity the following example is presented: in the case of a well with an annular space between the casing and production tubing, that has a packer at its lower end and has a leak detected in the production tubing, the effectiveness of the placement of the Device (D) will be verified by comparing the pressures between the annular space and the production tubing, which must be different; another scenario is the case of a well with production/casing pipe where a closed and flowing bottomhole pressure log can be run in the repaired zones in order to detect pressure and/or temperature variations, as well as production logging to detect changes in fluid input.
Method of recovery of the Device (D) to the surface. The recovery process of the Device (D) considers two stages, a so-called pre-recovery stage and an operational recovery stage. In the previous phase of recovery, information is acquired to determine the operational requirements in equipment and slick line accessories to recover the Device (D), as part of this information: detailed report of the Device (D) installation, updated well mechanical condition; production and intervention history; gyroscopic, and other available well information; additionally, the well to be intervened is visited to evaluate the conditions of its accesses, platform, cellar, christmas tree, and other relevant conditions for the operation. In the second operative stage the Device (D) is recovered to surface considering at least three trips with slick line unit and in the following order:
Depending on the length of the repaired casing/production pipeline damage, it was the same number of sleeves and connectors installed, which should be recovered to the surface.
It is important to mention that the installed sleeves have a length which must be considered when selecting the capacity of the slick line unit (SLU) and its accessories (length of the lubricators).
It is important to keep in mind that, as part of the operating procedures in operations with slick line units, prior to the recovery of any tool, it is mandatory to calibrate the production/casing pipe to a diameter at least equal to the outside diameter of the Device (D), to guarantee its free recovery to the surface and avoid jamming. This operation is performed only once before starting the surface recovery of the components that make up the Device (D).
To show the best mode of application known by the applicant, the following is an example related to the system for the restoration of the mechanical integrity of reduced diameter casing or production pipes, object of the present invention and described above, without this limiting its technical scope.
EXAMPLE. A Device (D) is available as illustrated in
Materials and equipment. The fluid to transmit the pressure to (D) is water at 24° C.; a WOMA model 330-Z Triplex high pressure pump was used to generate pressure for testing, reaching maximum pressure values of 68.948 MPa (˜10,000 psi) and maximum flow rate of 0.005317 m3/s (319.0 It/min); The pressure control was performed with a Hi-Force pneumatic console, model AHP275, which allowed the automatic application of a pressure gradient defined in pressure increments of Dp=3.447 MPa (˜500.0 psi), up to the test pressure of p=17.237 MPa (˜2,500.0 psi).
Test procedure. A test bench was set up as illustrated in
Device (D) in its original design is shown in
In order to clearly illustrate the tests being performed, simplified schematics of the device (D) similar to
In the second stage, the anchoring system was tested, and the following steps were carried out:
Results.
To perform the hermeticity test on Device (D), the following steps were carried out:
Results.
To perform the differential pressure test on Device (D) the following steps were carried out:
Results.
Anchor test. Regarding the anchorage test, it was performed satisfactorily since the anchors withstood the thrust corresponding to 20.684 MPa (˜3,000.0 psi) on the surface of the device (D), without any relative longitudinal displacement of D with respect to the PT. The above allows concluding that the installation and recovery system of Device (D) worked correctly, moreover, the anchor activation mechanism operated correctly.
Hermeticity test. This test is intended to show the containment of pressures outside the packer gap; the pressure records show that the intermediate pressure, corresponding to the space between the packers, remained at atmospheric pressure throughout the test while the pressures at the ends of D gradually increased to 20.684 MPa (˜3,000.0 psi), which was successfully accomplished. The above leads to the conclusion that the packer activation mechanism operated correctly.
Differential pressure test. This test is aimed at evaluating hydrostatic pressure containment in the space between packers. The pressure records show that the pressure gradually applied in the space between the packers remained confined in that space while outside the space the pressure remained equal to atmospheric pressure throughout the test, which evidenced the success of this test. This leads to the conclusion that the packer isolation mechanism operated correctly.
| Number | Date | Country | Kind |
|---|---|---|---|
| MX/A/2023/010204 | Aug 2023 | MX | national |
