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A full-opening safety valve, also known as a full bore safety valve, is designed to allow unrestricted flow through the valve when it's fully open. This is crucial in oil field operations to ensure that there's no bottlenecking or restriction in the flow path during drilling or production, which can lead to increased pressure and potential safety hazards. These valves are an essential component of the well's safety system, providing a means to quickly shut off the well in case of an emergency, such as an uncontrolled release of oil or gas. Would you like more detailed information on this topic? Full-opening safety valves are critical for maintaining control over the well by providing a secure means of shutting in the wellbore if necessary. They are typically installed as part of the well's blowout preventer (BOP) system, which is a series of valves at the top of the well that can be closed if the drilling crew loses control of the well. The "full-opening" aspect refers to the valve's design, which allows for the same diameter as the casing or tubing, minimizing pressure drop and allowing tools and equipment to pass through easily. This is particularly important during operations such as wireline or coiled tubing interventions. These valves are designed to close rapidly in the event of a blowout, a sudden release of crude oil or natural gas from the well. They can be activated manually, remotely, or automatically by detecting abnormal pressure conditions. In summary, full-opening safety valves are a vital part of the safety equipment in oil field operations, ensuring that personnel and the environment are protected from potential blowouts by allowing for immediate and unrestricted closure of the well. A Full Opening Safety Valve (FOSV) typically consists of several key components: - Valve Body: The main structure that houses all other components and provides the flow path when open. - Actuator: The mechanism that operates the valve, which can be hydraulic, pneumatic, or electric. - Gate or Ball: The closure element that seals off the flow when the valve is closed. - Seat: The surface against which the gate or ball seals to prevent flow. - Stem: Connects the actuator to the gate or ball, transmitting the force needed to open or close the valve. - Seals and Packings: Ensure a tight seal around the stem and between the body and closure element to prevent leaks. - Bonnet: The top part of the valve that contains the stem and actuator mechanism. These components work together to ensure that the FOSV can quickly and effectively seal off a well in case of an emergency, such as a blowout. Is there a specific part of the FOSV you're interested in, or would you like information on another aspect of oil field operations?

𝗕𝗹𝗼𝘄𝗼𝘂𝘁 𝗽𝗿𝗲𝘃𝗲𝗻𝘁𝗶𝗼𝗻 (𝗕𝗢𝗣) A blowout occurs when formation pressure exceeds the hydrostatic pressure of the drilling mud, causing an uncontrolled flow of fluids to the surface. This can happen due to: Insufficient well control measures. Sudden pressure surges (kicks) during drilling. Failure of surface equipment or well barriers. Blowout Preventer (BOP) Overview A Blowout Preventer (BOP) is a high-pressure safety device installed on top of the wellhead. Its primary function is to seal the wellbore and control fluid flow during emergencies. Key Components of a BOP System: 1. Annular Preventer: A flexible, donut-shaped rubber seal that closes around various drill pipe sizes or completely seals the wellbore. 2. Ram Preventers: Pipe Rams: Seal around the drill pipe. Blind Rams: Seal the wellbore when no pipe is present. Shear Rams: Cut through the drill string and seal the wellbore in extreme emergencies. 3. Control Unit: Operates the BOP through hydraulic or pneumatic systems. 4. Accumulator: Stores hydraulic fluid to activate the BOP in case of power loss. 5. Kill and Choke Lines: Facilitate pressure control and fluid circulation. Types of Blowout Preventers 1. Annular BOP Versatile and seals around various pipe sizes. Commonly used for regular well control operations. 2. Ram BOP Provides a more robust seal using metal rams. Often stacked for redundancy in high-pressure wells. 3. Subsea BOP Used in offshore drilling. Installed on the seabed and remotely operated. Functions of a BOP 1. Well Control Prevents formation fluids from escaping to the surface. Manages kicks by isolating the wellbore. 2. Pressure Regulation Maintains well pressure within safe limits. Provides a controlled environment for pressure equalization. 3. Emergency Shutdown Activates during loss of well control to prevent blowouts. Essential in critical situations like equipment failure or human error. Operational Procedures 1. Pre-Drilling Checks BOP systems are pressure-tested before drilling operations. Maintenance and inspection ensure reliability. 2. Kick Detection and Response Early detection through monitoring systems triggers immediate action. BOP is engaged to isolate the wellbore. 3. Well Killing Operations Kill lines circulate heavy drilling mud to counteract formation pressure. BOP remains sealed until the well is stabilized. Challenges and Advances in BOP Technology 1. High-Pressure, High-Temperature (HPHT) Wells Require advanced BOP designs to withstand extreme conditions. 2. Automation and Remote Operation Enhanced control units and real-time monitoring improve safety and response times. 3. Subsea Innovations Development of autonomous subsea BOPs for deepwater drilling. Redundancy systems enhance reliability. 4. Regulatory Compliance Stricter standards and frequent inspections ensure operational integrity. Photo refrence, credit : https://lnkd.in/dFdWa_ja

Oil leaks, catastrophic and high potential consequences in terms of cost, risk, process and personnel safety, environment, and reputation would come from cost reduction in inspection & lack of knowledge for selecting the best NDT method! An effective Inspection strategy and the right techniques are able to provide a trusted report which is essential for an effective asset integrity and repair plan. Oil & Gas assets inspection guide for ensuring process safety through steps forming from identifying hazards running to the best practices. Inspection is essential for: ✪ Safety: Identifying hazards to prevent accidents & injuries. ✪ Reliability: Ensuring equipment efficiency, and decreasing downtime. ✪ Maintenance: Planned shutdown and earlier detection of issues allow timely repairs, boosting equipment life. Types of Inspections: ◉ Regular Inspection: A basic assessment to identify obvious signs of wear, leaks, or damage. ◉ Functional Inspection: Testing equipment under normal operating conditions to ensure performance. ◉ Non-Destructive Testing (NDT): To evaluate material integrity without causing damage. ◉ Predictive Maintenance Inspections: Using data and analytics (e.g., vibration analysis, thermal imaging) to predict equipment failures before they occur. Inspection Procedures: 🖍️ Preparation of Documentation: Equipment manuals, previous inspection reports, and maintenance history. 🖍️ Inspection Checklist: Create a checklist that includes specific items to inspect based on equipment components. Conducting the Inspection: ➤ Safety First: Ensure all safety protocols are applied, including lockout/tagout procedures. ➤ Visual Assessment: Look for signs of wear, corrosion, leaks, and loose connections, Check for proper labeling and signage. ➤ NDT Methods: If applicable, conduct NDT to assess material integrity. ➤ Record Findings: Document all observations and measurements. Post-Inspection: ✹ Analyze Data: Review inspection results to identify trends or recurring issues. ✹ Report: A detailed inspection report includes findings, recommendations, and action items. ✹ Follow-up: Schedule necessary repairs or further investigations based on inspection results. Best Practices for Equipment Inspection: ・ Training: Ensure inspectors are trained and familiar with equipment and inspection techniques. ・ Regular Scheduling: Establish a regular inspection schedule based on equipment criticality and usage. ・ Use Technology: Consider using software for tracking inspections, findings, and maintenance activities. ・ Cross-Disciplinary Teams: Involve experts from different disciplines (engineering, safety, operations) in inspections for comprehensive assessments. ・ Continuous Improvement: Regularly review and update inspection processes. Read and Download the high-resolution PDF file of NDT SCOOP 𝐌𝐀𝐆𝐀𝐙𝐈𝐍𝐄 at ndtcorner.com #ndtx #oilandgas #ndt #ndtinspection #API653 #ndttraining #ndtjobs #ndttesting #ndttesting

Hello.. 🙋♂️ ! Let's talk about the BOP (BlowOut Preventer). The blowout preventer stack is ready to spring into action over the drilling rig at a moment’s notice. This towering structure is a last line of defense against catastrophic blowouts. Against such a task, it’s no wonder there are so many essential components that are needed. What Are a BOP Stack’s Main Components? The blowout preventer stack consists of blind ram preventers, pipe ram preventers, and shear ram preventers. Annular preventers are an essential component of BOP stacks. The kill line, choke flowline, and fill lines are used to regulate the fluid flow. Finally, the bell nipple serves as a connection for the injection of fluids. Blind Ram Preventer Pipe Ram Preventer Annular Preventer Shear Ram Preventer Drilling Spool Kill Line Choke Flowline Bell Nipple Fill Line 1) Blind Ram Preventer A blind ram preventer is a heavy-duty component that seals off a wellbore in emergencies. This preventer contains large rams that close tightly around drill pipes or casings. They prevent the uncontrolled release of oil or gas. 2) Pipe Ram Preventer A pipe ram preventer is designed to seal off the wellbore by clamping down on the drill pipe or tubing. This action prevents the escape of oil or gas during emergencies. 3) Annular Preventer An annular blowout preventer is a crucial safety device used in oil drilling. It forms a seal around the drill pipe or casing by inflating a rubber element, called a packer, in a circular shape. The annular preventer is versatile and can accommodate variations in pipe sizes. 4) Shear Ram Preventer Shear ram preventers are specialized rams within a BOP stack designed to seal off the drill pipe. 5) Drilling Spool A drilling spool is a metal structure that connects the BOP and the wellhead. It provides a platform for mounting various components, such as valves and chokes. 6) Kill Line A kill line is a high-pressure pipe that connects the rig’s pumps to the blowout preventer. During kicks (unexpected influx of fluids into the well), heavy fluids are pumped through the kill line into the wellbore. 7) Choke Flowline A choke flowline is a pipe connected to the wellhead through which fluids from the well flow. The choke valve, located on the flowline, regulates the rate of fluid flow. 8) Bell Nipple A bell nipple guides and controls the flow of drilling fluids during well operations. It’s a short, cylindrical extension located at the top of the casing string or BOP stack. The bell nipple provides a connection point. 9) Fill Line A fill line is a pipe used to inject fluids, like drilling mud or cement, into the wellbore during drilling. It connects to pumps on the drilling rig and directs the fluid downhole through the casing or tubing. This process controls pressure, lubricates the drill bit, and supports other drilling operations. (credit for BOP team) want to know more..? pls contact us www.tycjmd.com.ar info@tycjmd.com.ar whatsapp +54 9 11 2290 0778

A Blowout Preventer (BOP) is a crucial safety device in the oil and gas industry used to prevent uncontrolled blowouts of oil or gas wells. The BOP plays a vital role in protecting equipment, personnel, and the environment. It is specifically used in drilling oil and gas wells both offshore and onshore. Types of BOP: 1. Ram BOP: This type of BOP includes components called “rams” that can stop the flow of fluids. There are different types of rams designed to stop drill pipes or even seal off the well completely. 2. Annular BOP: This type of BOP can enclose the well around the drill pipe and prevent blowouts. Its operation is more flexible, allowing it to work with various types of drill pipes or tools. BOP Operation: During oil or gas well drilling, underground fluid pressure may rise to the point of causing a blowout. In such cases, the BOP is activated either automatically or manually to prevent the blowout. The device consists of a series of valves and mechanical parts that control pressure and safely manage drilling fluids. Importance of BOP in the Oil Industry: 1. Safety of Equipment and Personnel: Prevents severe damage to drilling equipment and protects the workforce. 2. Environmental Protection: Prevents well blowouts and oil or gas leaks into the environment, which could lead to catastrophic consequences. 3. Maintaining Production and Operations: Preventing blowouts ensures continuous, uninterrupted operations, avoiding financial losses.

🚨 Understanding Safety-Critical Equipment in Oil and Gas Plants🚨 Safety-Critical Equipment (SCE) is essential for accident prevention and safe operations in oil and gas facilities. Here’s a streamlined guide to key equipment, their roles, and best practices. ⛽ 1. Blowout Preventer (BOP) -Definition: Hydraulic device that seals and controls wellheads. - Function: Prevents blowouts during drilling. -When to Use: Drilling and well-control operations. -Best Practices & Pitfalls: Maintain per API RP 53; neglecting tests risks catastrophic blowouts. 🚨 2. Emergency Shutdown System (ESD) -Definition: Automated systems that halt operations in emergencies. -Function: shut down or isolate process to protect personnel and assets. -When to Use: During leaks, fires, or system failures. - Best Practices & Pitfalls: Integrate with IEC 61511; untrained operators can delay activations. 🔥 3. Detection Systems -Definition: Detect fires or gas leaks and trigger alarms. -Function: Provide timely alerts to prevent incidents. - When to Use: High-risk areas prone to fires or gas leaks. -Best Practices and Pitfalls: Follow NFPA 72 and OSHA 1910.120, calibrate sensors, and ensure proper placement. Faulty sensors or incorrect positioning can delay responses. 💨 4. Pressure Relief Devices and Flare Systems -Definition: Relieve pressure and safely burn hydrocarbons. - Function: Prevent explosions during system upsets. -When to Use: During pressure surges or thermal events. -Best Practices & Pitfalls: Adhere to ASME BPVC VIII; clogged or undersized valves risk overpressure. 🔒 5. Remotely Operated Shut-Off Valves (ROSOV) -Definition: Valves isolating processes remotely. -Function: Limits hydrocarbons during emergencies. -When to Use: In pipelines and critical systems. -Best Practices & Pitfalls: Test per IOGP 476; actuator failures hinder isolation. ⚙️ 6. High Integrity Pressure Protection System (HIPPS) -Definition: Valves preventing over-pressurization. -Function: Protects sensitive equipment. -When to Use: Heat exchangers and compressors. -Best Practices & Pitfalls: Validate per IEC 61508; miscalibration , improper design causes failures. 🧯 7. Fire Suppression Systems -Definition: Systems extinguishing fires with water, foam, or gas. -Function: Controls fires in critical areas. -When to Use: Electrical units, pump rooms, or process zones. -Best Practices & Pitfalls: Test per NFPA 15; malfunctioning and wrong placement reduce effectiveness. 🛢️ 8. Vessel Pressure Control Systems -Definition: Systems managing pressure in vessels ( e.g. heat , temprature , pressure , level) senors ,meters and alarms . -Function: Prevents overpressure and overflow incidents. -When to Use: Storage tanks and separators. -Best Practices & Pitfalls: Inspect per API RP 750; corroded components lead to failures. ✅ Conclusion Well-managed SCE, regular inspections, and compliance with standards ensure safety in oil and gas operations. Proactive risk management saves lives and assets.

Identify SCEs in the plant and ensure implementing an adequate inspection, test and preventive maintenance plan

What is Shutdown/Shutdown Activities for Oil and Gas Plants? --Close down-- A shutdown project's implementation phase typically lasts 5 to 14 days. Initially, after the zero date has passed, all operations are halted, manholes are opened, and the equipment is centrally cleaned. Preliminary infrastructure is examined both internally and externally, and afterward, some adjustments are done. Supervisory personnel in charge of facility maintenance are in charge of carrying out shutdown operations. To finish the task within the allotted time, we combine the shutdown scheduler with shutdown planner job packets. Close down operations 1. A toolbox Discuss work ranges, hazards, and safety officer and supervisory controls. 2. Acquiring licenses, Equipment for entry into the workplace, fire and hole watches, and equipment for neutralization and decontamination 3. Blind installation, Manway open, Get a certificate of gas testing and install air movers for ventilation. Cooling down apparatus 4. A confined space to monitor the time of arrival and departure. Putting on temporary lighting 5. A metal box should be placed over all of the bottom nozzles to prevent the entry of foreign objects. 6. Conduct a preliminary examination for QC and obtain guidance. 7. Set up scaffolding inside. 8. Finish all the tasks based on the scope and QC advice. Hydrostatic, X-ray, and other tests 9. Make a proposal for the last examination and internal scaffolding removal. 10. Get a box-up certificate from the maintenance, operation, process, and quality control departments. 11. QC and maintenance torque witness 12. Housekeeping and general cleanup Depending on the requirements of the scope of the task, you can add more. Note: In order to make the work materials conveniently available during the S-D , they are isolated prior to S-D .

Case Study: Accuracy of the Pressure Gauges A drill ship holding position offshore was due to carry out the annual servicing of its two auxiliary boilers. The boilers were used only for well test operations and had not been operated since the last annual service, except for maintenance operations. The duty engineers brought the boilers up to temperature and pressure specifications in preparation for the annual checks. As this was underway, the pressure safety valves opened. They appeared to open at 5.9 bar for boiler; well below the boilers’ working pressure of 7 bar. Over the course of the next four hours, the boiler were stopped and restarted a further three times. They still appeared to be opening below the boilers’ working pressure.  It was decided to shut down the boilers and allow them to cool so the technicians could then overhaul the pressure safety valves. Once cool, the pressure safety valves of boiler were adjusted in situ by the service engineers so they would open at a higher pressure. This explains why the ‘non-tamper’ seals were found missing from the safety valves of boiler after the accident. The next day, the service technicians resumed the work, together with one of the ship’s engineering personnel. The boiler was started and almost immediately triggered alarms on the machinery monitoring panel. Then, boiler catastrophically failed from overpressure, filling the boiler compartment with steam. The two service technicians and ship’s second assistant engineer who were in the boiler room suffered lethal injuries. The investigation found, among other things, that the pressure sensors of boiler was not operating as required and were giving false pressure readings. Yet the accuracy of the pressure sensors was never questioned as everyone believed they knew the problem; that the safety valves were opening below their set pressure. It is possible that this led to confirmation bias that then set the stage for the unsafe act of adjusting the safety valves to open under higher pressure. Further, the service technicians’ lack of experience may have contributed to both the confirmation bias and the subsequent unsafe act. Lessons learned 1- In systems that are dependent on several inputs, careful analysis is needed to determine where the real source of the problem lies. In this case the problem was ‘upstream’ of the safety valves, at the pressure sensors. 2-Boilers are inherently very dangerous due to high operating temperatures and pressures. Strict and competent supervision of operation and maintenance should be the norm. 3-Safety valve operating parameters should only be set by expert guidance and under test bench conditions, never ‘on the fly’. Once adjusted, the valves are then fitted with a non-tamper seal identifying the set pressure, facility that performed the work and the date of adjustment. These seals should not be removed. Source: https://lnkd.in/d5Jr_F4W. #safety #process #safetyvalve #inspection #maintenance #processsafety