Majed ABDULWAHAB’s Post

#Coiled_tubing_Stuck_Pipe #How to #Retrieve_the_coil:   1- Continue circulation if possible. 2-Work the coil in the opposite direction from the way you were going, when it was discovered, the coil was stuck. If a few feet of progress is made in that direction, begin working the coil back the other way. Try working the coil down a few feet, and then try the up direction again. Gradually increase the overpull or set down weight in each cycle rather than going to maximums all at once. 3-Often times coil circulation is lost to the surface due to the solids buildup. If circulation can be attained across the solids build‐up, consider pumping a high viscosity sweep to help string the solids out. The goal is to string out the solids to reduce the friction load so the coil can be moved. A “sand arch” around the coil has tremendous gripping power. 4- Avoid working the coil over the gooseneck with high coil pressure, as this drastically reduces the number of cycles that can be performed before suffering permanent coil fatigue (ballooned pipe). Check the coil history to get an idea how much the coil, which is currently across the gooseneck, has been worked on other jobs. Take careful note of any prior fishing jobs or stimulations where the coil has been reciprocated many times. 5-Try to increase the differential hydraulic pressure across the solid bridge by flowing the well harder, increasing gas lift or surging the well while continuing to work the coil. 6- If fluid can be injected, consider pumping in gas or nitrogen down the tubing‐coiled tubing annulus to form a gas cap. Then surge the well down the wing valve to apply a high upward differential pressure across the problem debris, again while working the coiled tubing. 7. If fluid can be injected down the coiled tubing‐tubing annulus, this can be used in conjunction with working the pipe. Avoid pumping at pressures close to the collapse rating of the coiled tubing. h. Always keep track of coiled tubing cycles over the gooseneck. Do not work the pipe excessively if no progress is being made. Work to change the down hole conditions to increase the chances of freeing the pipe. Then resume working the pipe again. 8-Once progress is made, always continue circulating while working the pipe back up the hole slowly. 9-Consideration can be given to spotting acid across the problem debris if you feel it is even partially acid soluble. 10- A minor “mechanical movement” can be achieved without the use of jars by removing one of the three pump suction valves from the triplex pump to induce hydraulic jacking through the coiled tubing. The pulses created can contribute to solving both mechanical or friction stuck coiled tubing. However, this option should be used with caution due to the inherent cycling effects imposed on the coiled tubing at surface. ... .. . Continue in Comments

#Coiled_tubing_Stuck_Pipe :- Recommends practices and contingency plans . ......................................................................................................................................................... When the pipe is unable to be moved freely with a force of 80% of the tensile yield, the pipe is stuck due to one of two reasons. #Friction sticking is due to tortuous wellbore or buckled production tubing. #Mechanical sticking can be the result of solids accumulation around the coiled tubing or downhole tools becoming lodged in the completion.   - Friction Stuck Coiled Tubing Preventing friction stuck coiled tubing begins in the job planning by identifying wellbore paths that have areas of dogleg severity (DLS) that can inhibit the free movement of the pipe. Normally a relatively high DLS (10 ‐15 deg/100’) can be tolerated if it exists in an isolated area. However, if they are widespread in the completion, even a moderate DLS can frictionally stick the coiled tubing. The drag weigh forces can be modeled to determine if there will be a problem. While performing the operation, frequent weight checks (each 500’) will help identify a problem before it becomes severe. This can also be a problem in dual or triple completions even if there is no obvious DLS problem.   1- Apply 80% of the tensile yield to the pipe and maintain that force for a minimum of 30 minutes. 2-If possible, continue to maintain circulation by pumping at low rate pressure to minimize the coiled tubing pressure. 3-Pump friction‐reducing additives such as polymer gel diesel or beads down the coiled tubing or down the coiled tubing‐production tubing annulus. If pumping down the CT/PT annulus, limit the pressure below the collapse rating of the coiled tubing. 4- Displace the well to heavier fluid to provide increased buoyancy. 5- Additional buoyancy can be achieved by displacing the coiled tubing to nitrogen. Note that collapse pressure conditions have increased when changing the fluid/gas displacement of the wellbore and coiled tubing. 6- Mechanical movement can be induced without the use of hydraulic jars in the tool string. - Mechanically Stuck  If the weight indicator load does not decrease after applying a tensile load of up to 80% of the pipe tensile yield rating, it is likely that the coiled tubing is mechanically stuck. Attempt to lower the coiled tubing into the well to determine if it is actually stuck at that point or if it is unable to pass through a restriction or upset in the completion pipe.  If the coiled tubing can be moved downward, then determine the following:   1-If the pipe (or tools) could have been bent or buckled by setting down excessive weight or running into an obstruction. 2-Review the well sketch for any obstructions or restrictions that may present problems for the movement of coiled tubing or downhole tools. 3-Mechanical movement can be induced without the use of hydraulic jars in the tool string. 

Correct Installation and Inspection of Gaskets: 1. **Clean Surfaces**: Ensure that the flange surfaces are clean, free from debris, and properly prepared before installing the gasket. 2. **Proper Alignment**: Align the gasket and flange bolt holes accurately to ensure a proper fit. 3. **Correct Torque**: Use the manufacturer's recommended torque specifications to tighten the bolts evenly and avoid over-tightening, which can damage the gasket. 4. **Visual Inspection**: Inspect the gasket for any visible signs of damage, such as cracks, tears, or deformation, before installation. 5. **Compression Check**: Verify that the gasket is evenly compressed and seals the flange properly. Check for gaps or leaks. 6. **Regular Maintenance**: Periodically inspect gaskets for wear, damage, or leaks. Replace them as needed to prevent failures. 7. **Consider Operating Conditions**: Take into account the temperature, pressure, and chemical compatibility when selecting and installing gaskets. 8. **Follow Manufacturer Guidelines**: Adhere to the manufacturer's instructions and guidelines specific to the gasket type and application for proper installation and inspection procedures. 9. **Record Keeping**: Maintain records of gasket installation dates, inspections, and replacements for tracking and maintenance purposes. 10. **Training and Expertise**: Ensure that personnel involved in gasket installation and inspection are properly trained and have the necessary expertise to perform the tasks correctly. Remember, proper installation and regular inspection are crucial for gasket performance and to prevent leaks, equipment damage, and safety hazards.

Connecting the Adaptor and Casing of an Center Back Mount Oil-Filled Pressure Gauge with Specialized Equipment for Tightening the Adaptor: Connecting the adaptor and casing of an center back mount oil-filled pressure gauge requires ensuring a secure and reliable fastening, typically accomplished using specialized equipment for tightening. Below are the detailed steps for the connection process: **1. Preparation:** Ensure the surfaces of the adaptor and casing are clean, and inspect the threads for any damage. Additionally, check for foreign objects or debris at the connection site to ensure sealing integrity. **2. Adaptor Installation:** Insert the adaptor into the casing interface, and if necessary, use appropriate sealing components such as washers or O-rings to ensure sealing at the connection point. **3. Tool Selection:** Select the appropriate specialized equipment for tightening based on the specifications of the center back mount oil-filled pressure gauge and the connecting components. This may include torque wrenches, torque wrench sockets, and other tools. **4. Torque Setting:** Set the torque value of the torque wrench according to the specifications provided by the manufacturer or the operation manual. This value is typically determined based on the requirements of the connecting components and the application. **5. Commence Tightening:** Use the specialized equipment to begin tightening the adaptor. Ensure even application of force and operate according to the specified torque value to prevent over-tightening or loosening at the connection point. **6. Connection Verification:** After completion, inspect and verify the connection. Pressure testing may be performed to confirm sealing integrity and stability. **7. Data Recording:** Record the torque value, connection date, and other relevant data for maintenance and tracking purposes. **8. Final Inspection:** Conduct a comprehensive check to ensure there are no loose connections or oil leaks, ensuring the safe operation of the equipment. Following these steps ensures a secure and reliable connection between the adaptor and casing of an center back mount oil-filled pressure gauge, guaranteeing the normal operation and safety of the equipment.

🔲 API 571, titled "Damage Mechanisms Affecting Fixed Equipment in the Refining Industry," provides guidelines and recommendations for the identification and assessment of damage mechanisms in process equipment such as pressure vessels, piping, and tanks in the refining industry. It is a practical guide that helps engineers and inspectors understand and manage the various damage mechanisms that can occur in these assets. 🔲 The API 571 standard covers a wide range of damage mechanisms, including corrosion, cracking, fatigue, embrittlement, erosion, and others. It provides information on the causes, characteristics, and inspection methods for each damage mechanism, as well as guidance on how to assess the severity and remaining life of equipment affected by these mechanisms. 🔲 Here are some key points and topics covered in API 571: 1️⃣ Damage Mechanism Categories: The standard categorizes damage mechanisms into various categories such as general, localized, high-temperature, and environmentally assisted cracking, as well as other types of damage. 2️⃣ Damage Mechanism Descriptions: API 571 provides detailed descriptions of each damage mechanism, including its causes, contributing factors, typical locations, and inspection methods. 3️⃣ Inspection and Monitoring: The standard offers guidance on inspection techniques and monitoring strategies to detect and assess damage mechanisms effectively. It covers non-destructive testing (NDT) methods, visual inspection, thickness monitoring, and other relevant techniques. 4️⃣ Damage Mechanism Evaluation: API 571 provides information on evaluating the severity of damage mechanisms based on factors such as cracking length, corrosion rate, remaining wall thickness, and other relevant parameters. 5️⃣ Mitigation and Control: The standard offers recommendations for mitigating and controlling damage mechanisms, including material selection, corrosion inhibitors, protective coatings, maintenance strategies, and inspection intervals. 6️⃣ Fitness-for-Service (FFS) Assessment: API 571 outlines the principles of performing a fitness-for-service assessment, which involves evaluating the structural integrity and remaining life of damaged equipment, considering factors such as the damage mechanism, operating conditions, and inspection results. 🔲 It's important to note that API 571 is a reference document and should be used in conjunction with other industry standards and practices, such as API 570 (Piping Inspection Code) and API 510 (Pressure Vessel Inspection Code), to ensure comprehensive assessment and management of equipment integrity. 🔲 The API 571 standard is regularly updated, so it is advisable to consult the latest version of the document for the most up-to-date information and guidelines on damage mechanisms in the refining industry.

#Packer_Selection_Specification-PART#3                                   Packer selection must take into account: 1-type of hole: open, cased, liner completed; 2-type of well: producing, appraisal, injection; 3-well content: oil, gas (sweet, sour), water, steam, abrasive material; 4-natural well pressure: high, low, flowing, shut-in - in the tubing; 5-imposed well pressure: high, low - in the annulus - especially during completion pressure testing; 6-well temperature: flowing, shut-in - range of temperature changes; 7-vertical: straight, deviated - small angle, large angle. 8-production method: natural flow, gas lift, pump; 9-drawdown rate: high, low; 10-completion method: tubing latched in tension, setdown in compression, multiple straddle pack, tailpipe, extension required below packer; 11-tubing hanger design: suitable for packer setting/releasing method; minimum bore: ability to pass tools and equipment required further downhole; 12-packer function: annulus/tubing isolation, zone isolation, damage straddling, cement squeezing; also to be taken into consideration are the pressure and temperature changes, especially during stimulation operations ,casing damage caused by the slips; 13-hang-off requirements (tailpipe assembly). #Packer_Classification 1-Retrievable: The packer is run as an integral part of the tubing. Except for the retrievable bridge plug, the tubing cannot be pulled without pulling the packer. The packer is set mechanically, hydraulically or a combination of both. It is released by manipulation of the tubing, either rotating or pulling (shearing lock pins). 1-The following aspects need to be considered when running retrievable packers: 2-pulling the packer out of the well may swab the well in 3-equalization of pressure across the packer before pulling may be difficult 4-straight pull release packers may prematurely shear and release due to tubing contraction; 5-deposits above the packer may render it non-retrievable. Permanent: The packer is set within the casing and the setting mechanism (tubing/wireline) can be released from the packer. Except for the case of a permanent bridge plug the tubing can be run and resealed in the packer. The packer may be set mechanically (by tubing), hydraulically or electrically (by wireline). 2-Permanent/Retrievable: This class of packer combines the advantages of the permanent packer (i.e. large bore, withstands higher pressure differentials etc.) but when required can be released and recovered, entire, from the well. In general, a permanent packer will be selected if: 1-the predicted maximum differential pressure across the packer exceeds 5000 psi; 2-the temperature at setting depth exceeds 225°F; 3-H2S is present and the temperature at the packer is less than 160°F; 4-infrequent workovers are envisaged. Otherwise a retrievable packer may be recommended. #Source# -SPE -PetroDoc -SLB Packers Setting/Operation. -Baker Hughes Packers Operation

If you are a coil tubing supervisor, at some point you will end up stuck in the hole. I don’t recommend using this calculation on a horizontal well because around 30 to 60 deg you will start pulling enough drag in the curb to compromise this formula. In a vertical well, you will have a good idea about where you are stuck at. If the bottom of your coil is around 30 to 60 deg you will be ok using this formula. First thing you need to find your area which is the cross-sectional area of the CT pipe wall.  Coil tubing OD = 1.5 Coil tubing ID = 1.282 Area of cross sections steal = 1.5 sq – 1.282 sq times .7854 equals area. I would recommend circulating pipe on pipe around and back to the surface but you may not be able to circulate. Then I would work the pipe up and down a few times to free the pipe up a little bit to reduce pipe-on-pipe friction behind the coil tubing. Stretch = inches, from the over-pull force Force =applied weight overweight of pipe in the air to stretch the CT Pull pipe weight. Call that pipe weight zero. Mark the pipe and pull over the hanging pipe weight. Pull 8000 lbs to 15000 lbs and Stop pulling up. Mark the pipe again. Measure the distance between the marks in inches and write that number down. The max weight you pulled to measure your stretch minus the weight it took to pull pipe weight. Write down that number. Now you have all the numbers needed to calculate a free point for your stuck coil tubing. I walked you thru the process so you can understand the formula and how to get those numbers along with where they came from. EXAMPLE The actual free point formula:  L = Stretch in inches*(30000000*Area)/Force/12 CT OD    = 1.5 CT ID      = 1.282 Stretch     = 120 inches Force =    15000 lbs (Weight Indicator) 120 * 30,000,000 * 0.476 / 15000 /12 = 9520 feet. If anyone has any questions, DM me and I'll answer any questions you might have. When people talk about doing a free point it sounds complicated but it's actually an easy process. That 30,000,000 number is just a constant number used in the formula. That 12 number is also a constant number used in the formula. Good luck and try not to get stuck in the hole. If you do, you know everyone is going to give you a hard time about it.

We’ve updated the PPC Installation, Operation, and Maintenance (IOM) Manual with an all-new look and improved ease of use, with more detail and step-by-step instructions. The manual continues to focus on giving installers a simple, yet safe and effective way to correctly install and maintain a tank system. Utilize these key tips when installing your chemical storage tank to minimize potential cracks and leaks that could lead to tank failure. https://hubs.la/Q02s6mWJ0

4 most important mechanical isolation methods Spool removal or air gapping isolation Spool removal or air gapping is a line-breaking method that involves removing a spool section from the piping and installing a blind flange to block the flow from the source. This method is highly reliable and secure as it achieves actual, physical separation of the source from the equipment. The downside of this method is that if the pipeline has a large nominal size, the spool can be very bulky to disconnect, remove, and replace after the maintenance work. Lifting equipment and additional manpower are required to achieve isolation. Furthermore, maintenance workers may have to deal with rusted bolts and misaligned gaskets extending the downtime as flange surfaces are cleaned and a new gasket is inserted. This isolation method is very time-consuming and is not suitable for routine maintenance work and emergency situations.

Our Learn About Steam pages cover a variety of information about steam and steam systems. This tutorial include important installation advice for safety valves, along with handling, plant conditions, pipework configuration and much more. https://lnkd.in/dmAi3Swc #Engineering #SafetyValves #Maintenance #MaintenanceMonday #SpiraxSarcoVietnam