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Collaborating Authors
Operational safety
ABSTRACT: Mining, natural and technological hazards can occur in a former mining site. The multi-hazard analysis becomes critical. This paper aims to establish the methodological basis for assessing the interactions between the main hazards identified in abandoned mines. The interactions between 57 hazards are analysed based on: theoretical aspects, feedback analysis and expert opinions. Interaction matrices and loops are used, helping to study the interactions between hazards. INTRODUCTION, OBJECTIVE AND METHODOLOGY The number of abandoned mines is continuously increasing in the world. Several hazards can affect former mining sites (ISRM, 2007). Generally, several square kilometres of a mine site may be vulnerable to various types of hazards, including mining hazards, which may interact with each other. Multi-hazard assessment is mandatory in this case. Multi-hazard is frequently used to describe such a situation (Gill & Malamud, 2016). This paper aims to present a first reflection to develop a methodology for abandoned mines which allows, in the long term, the identification and evaluation of the potential interactions between hazards. First, the methodology identifies residual mining, natural, and technological hazards. Then, three types of interactions were sought: mining hazards versus mining hazards, mining hazards versus natural hazards and mining hazards versus technological hazards. Interaction matrices and loops have made it possible to facilitate the analysis and visualisation of potential interactions. The potential retained interactions are the result of the following: โข the theoretical basis of phenomena, โข back analysis of the real-life case studies and, โข the feedback of the experts. Three levels of interaction have been considered: no interaction or zero interaction potential; unlikely interaction(s) or low interaction potential and likely interaction(s) or high interaction potential. DESCRIPTION AND ASSESSMENT OF HAZARDS The hazards that may occur in a former mining site are grouped into three main categories: 19 mining hazards, 21 natural hazards and 17 technological hazards; see Table 3. For mining hazards, hazard qualification relies on predisposing factors. However, natural and technological hazard qualifications are based on the probability of occurrence or the severity of a hazardous event, meaning that a qualitative, semi-quantitative, or purely quantitative approach is sufficient for their qualification.
Successful Velocity String Deployment Pilot to Improve Productivity and Sustainable Gas Recovery for Three Sub-Optimal Completion Wells in Oman Block-61
Al Darai, A. (bp) | Al Fadhli, K. (bp Oman) | Al Harrasi, S. (bp) | Najwani, M. A. (bp) | Raji, A. (Halliburton) | Qamar, O. (Halliburton) | Villarroel, P. (Halliburton) | Daoud, S. (Halliburton) | van der Ven, B. (Halliburton)
Abstract Block 61 is a gas field, located in Oman, characterized by tight reservoirs. Majority of the vertical wells in the field are completed with 4ยฝโณ to 5ยฝโณ production tubing. As wells continued to produce over time, a decline in the production was observed due to liquid loading. A Sustainable option to enhance production recovery was introduced. This involved reducing the current production tubing internal diameter (ID) and area. To accomplish this without compromising the reservoir, a velocity string (VS), using a snubbing unit, was installed for three wells in effort to determine if it's fit for purpose for full field development. (VS) wells were chosen based on specific selection criteria, mainly focusing on wells with reservoir pressure around 4,500 psi and different performance levels, to evaluate VS completion design and capabilities under various well conditions. Three pilot candidate wells were completed with smaller sized velocity string completion tubing in Block 61. The installation was executed through a Snubbing unit with wellhead pressure control configuration in snubbing mode, resulting in the deployment of the VS under pressure. The benefits of this well intervention method is that it eliminates the potential for hydrate formation and reservoir damage since no kill fluid is pumped in the wellbore. The VS completion design consists of jointed chrome pipes, completion components (Sliding Sleeve Door (SSD) & Wireline Entry Guide (WEG)) and a hang-off packer. From an operational perspective, the wells were delivered safely with minimal non-productive time (NPT) and 31% ahead of schedule. This resulted from the continuous and proactive implementation of lessons learned, which were captured during the VS installation operations. This paper will cover the valuable lesson learned to help drive efficiency and optimization of future planned campaigns. Moreover, post VS installation, the 3 pilot candidate wells were brought back to production. The production rates from the candidate wells showed initial positive results flowing through the VS completion as predicted during the project design and planning. The application of the snubbing unit for bp Oman was the first successful VS installation in Block 61. This effective deployment presents an opportunity to extend the production life for over two hundred wells in Block 61 with high efficiency when intervening on these wells. The objective of this paper is to summarize the journey of installation of velocity strings in Block 61, aiming to cover aspects such as planning, design, wellbore preparation, operational execution and well performance results post installationBody text 1 paragraph.
Active Pressure Management Maintained the Primary Well Control and Enabled to Strengthen and Drill through Naturally Fractured Carbonates Formation with Extremely Narrow Drilling Margins and Resulting in One of the Vital Hydrocarbons Discovery in Northern Pakistan โ A Successful Approach of Managing Wellbore Pressure Profiles by Managed Pressure Drilling (MPD)
Ashraf, Qasim (Weatherford, Pakistan) | Chisti, Uzma (Weatherford, Pakistan) | Tashfeen, Muhammad (MPCL, Pakistan) | Farooq, Muhammad Umar (MPCL, Pakistan) | Rehman, Muhammad Abdul (MPCL, Pakistan)
Abstract Drilling through narrow drilling margins in wildcat wells always proves to be a challenging task where uncertainties regarding drilling windows make operators decide bottom hole equivalent circulating densities (ECDs) based on unclear data, resulting in a loss/gain scenario during drilling. This paper describes the effective use of the constant bottom hole pressure (CBHP) variant of Managed Pressure Drilling (MPD) in the wildcat well of X-1 to explain the successful drilling of the reservoir section, providing an incredibly narrow window of 0.08 SG across Lockhart & underlying formations by actively controlling the wellbore ECDs. While drilling 8 3/8" section at X -1 utilizing MW of 1.47 SG across carbonates of Lockhart formation, drilling proved to be challenging as complete losses occurred which resulted in complex well control scenario. Therefore, avoiding losses and sustaining primary control seemed to be a nearly impossible task after performing various attempts to cure losses by spotting heavy LCMs, which added to the risk by clogging the string. Hence a narrow drilling window coupled with loss/gain scenario and a plugged drilling string altogether made the operator rethink the drilling strategy. Active bottom hole pressure management techniques, such as Managed Pressure Drilling enables to walk between the lines of pore and fracture limits with the best efficiency and integrity. Managed pressure drilling's ability to dynamically control the well enabled the operator to dynamically maintain the primary barrier and to drill through the naturally fractured loss/gain prone formation of Lockhart by utilizing underbalanced mud weight of 1.35 SG MW while maintaining ECDs ranging 1.47-1.55 SG across critical interval of Lockhart formation. Additionally, determining drilling margins through the use of dynamic pore pressure tests (DPPT) and dynamic formation integrity tests (DFIT) made the operator to make crucial choice of drilling through the Lockhart formation (Primary Reservoir) along with underlying Hangu, Kawagarh, Lumshiwal, and Chichali formations. Effective management of annular pressure profiles resulted in successful drilling of 8 3/8" hole section without any further complications. Using low mud weight & managing ECD while drilling Lockhart formation reduced losses and thus avoided reservoir damage, which contributed to the large reservoir discovery. The discovery of a new field in Northern Pakistan using an unconventional way to control, drill, and ascertain well behavior has opened up new frontiers. This study discusses the effectiveness of MPD's CBHP technique in critical well control situations along with the design of active pressure control hydraulics, suitable for narrow margins along with all operational details, providing crucial results for comparable applications in the future.
- Geology > Geological Subdiscipline > Geomechanics (0.56)
- Geology > Rock Type > Sedimentary Rock (0.47)
- Asia > Pakistan > Khyber Pakhtunkhwa > Kohat District > Kohat Basin > Wali Exploration Licence > Kawagarh Formation (0.99)
- Asia > Pakistan > Khyber Pakhtunkhwa > Karak District > Lockhart Formation (0.99)
Offshore Underwater Fixed Structure Integrity Assessment Using LRUT, PEC & ACFM Advanced Technologies with Minimal Marine Growth Removal
Krishnamoorthy, Paramasivam (Chief Technical Officer โ NDT โ Bureau Veritas Middle East Region, Abu Dhabi, UAE) | Tremblay, Charles (Product Manager for PEC and ACFM, Eddyfi Technologies - Canada) | Jackson, Paul (Director of LRUT and MFL Centre of Excellence, Eddyfi Technologies, UK)
Abstract Offshore underwater structures degrade over time due to the harsh environment and operating conditions of the structure leading to potential problems such as fatigue cracking or corrosion. This necessitates the need for regular inspection, monitoring, and possibly repair to ensure that the structurescontinue to operate safely. However, conventional inspection techniques face significant challenges when inspecting subsea structures, particularly related to the access of the area of interest. Removal of marine growth in these areas and the safe use of remotely operated vehicles (ROVs) can be time consuming and problematic. To address these challenges, a unique approach was developed that combines different advanced non-destructive testing (NDT) techniques to maximize productivity and minimize intrusions while ensuring the data collected is the high quality needed for integrity assessment, allowing for the safe operation of critical assets. This approach involves a combination of long-range ultrasonic testing (LRUT) technology with marinized transducer tooling, underwater Pulsed Eddy Current (PEC) testing, and underwater Alternating Current Field Measurement (ACFM) to inspect subsea structures. The LRUT technology is initially used to screen piles for overall condition with marine growth only needing to be removed at the tool location. PEC is used to verify critical findings without removing any marine growth. ACFM is used to inspect underwater welds for fatigue cracks, all with minimal removal of marine growth. This approach has successfully implemented in the field, including the use of underwater marinized LRUT collars, to inspect approximately 1000+ piles of circular piles (LRUT for 700+ circular piles and ACFM & PEC for 1000+ piles which includes circular and hexagonal piles) with different diameters and wall thicknesses. This technical paper provides details about the challenges encountered during implementation and how they were overcome. Furthermore, it shares real site experience and results of this innovative inspection program. The results were validated by cross-checking with other techniques such as underwater ultrasonic thickness gauging (UTG) and close visual inspection (CVI) by qualified divers to ensure accuracy and reliability of the results.
- Energy > Oil & Gas > Upstream (1.00)
- Electrical Industrial Apparatus (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (0.89)
- Health, Safety, Environment & Sustainability > Safety > Operational safety (0.68)
Metal Expandable Packer Secures the Integrity of a Cemented Casing Shoe and Protects the Caprock from Potential High Injection Pressures
Hazel, Paul (Welltec, Aberdeen, Uk) | Jacobsen, Brian (Aker Bp, Oslo, Norway) | Huse, Arve (Aker Bp, Oslo, Norway) | Rygh, Synnรธve Lind (Aker Bp, Oslo, Norway) | Jรธrgensen, Paal Ludvik (Aker Bp, Oslo, Norway) | Lรธnning, Petter (Welltec, Stavanger, Norway) | Strรธmsvik, Frode (Welltec, Stavanger, Norway)
Abstract The Edvard Grieg platform and Solveig subsea field developments have four horizontal wells with a novel cap rock protection technology in place for water injection service. The 9 5/8" casing shoe is positioned within the cap rock providing the primary well barrier. However, the cap rock requires protection from potential out-of-zone fracturing during high pressure water injection. Options to protect and seal across the cap rock were cemented 7" liner, expandable cemented liner, or Metal Expandable Packers (MEP). With the MEP having the benefit of qualification to ISO 14310 and API 11D1. The 9 5/8" shoe was landed and cemented at the bottom of the cap rock, the mud weight lightened and the 8 ยฝ" hole was drilled to Total Depth (TD). A single trip liner was deployed consisting of a liner hanger, a 7" casing with MEP and with contingency swell packers, positioned at the top of the injection reservoir, and 6 5/8" and/or 5 ยฝ" sand screens with annulus flow prevention. The MEPs were expanded with 345 bar pressure after setting the liner hanger. On the Solveig wells, filter cake breaker fluid was reverse circulated across the reservoir and up the screen and landing string through an electric toe valve, before a ball valve was closed mechanically with an Radio Frequency Identification (RFID) tag operation as back-up. The MEP created a fracture propagation safety barrier between the top injection point and the casing shoe (bottom of the cap rock). This subsequently lowered the risk of out-of-zone cold water injection in a weaker zone between the cap rock and the injection reservoir. The solution also protected the formations behind the 9 5/8" casing up to the production packer location. Substituting the alternative cemented liner options with the MEP annulus barrier and anchoring system saved considerable rig time and cost with reduced operational risk. Maintaining the 8 ยฝ" hole to TD avoided slim-hole related risk and maintained a standard casing program, while enabling 6 5/8" ร 5 ยฝ" screens for a considerably longer reach with respect to torque and drag. The overall injection capacity was increased due to the larger bore and lower pressure losses. The MEP can facilitate short "bursts" of water injection at pressures above the minimum horizontal stress of the reservoir rock, which can create new flow paths. This provides a contingency in the event of the Solveig "no flow back" filter cake breaker solution was not successful, or the Edvard Grieg production clean-up was not successful, or injection was not sustainable over time due to formation plugging. Many wells are challenged with depleted zones above, across or below the cap rock which often challenges the positioning of the production or injection casing shoe. The ability to achieve a competent well barrier and protect against out-of-zone injection and undesired fracture propagation is a valuable solution addition. This solution addressed the challenge, securing a more robust and long term well integrity situation at substantially reduced cost and risk. The operator is considering wireless pressure gauges above the MEP in future applications to consistently confirm the MEPs as working barriers against high injection pressures.
- Geology > Petroleum Play Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.75)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.96)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 410 > Block 16/5 > Solveig Field > Skagerrak Formation (0.92)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 410 > Block 16/5 > Solveig Field > Hegre Formation (0.92)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 410 > Block 16/4 > Solveig Field > Skagerrak Formation (0.92)
- (10 more...)
A Next-Generation, Fully Controllable Alloy Wellbore Sealing Technology
Lucas, Alex (TotalEnergies Upstream Danmark A/S, Copenhagen, Denmark) | McWilliam, Gary (TotalEnergies Norge AS, Stavanger, Norway) | Eden, Robert (Rawwater Engineering Company Limited, Warrington, United Kingdom) | Rege, Gert (Wellstrรธm AS, Stavanger, Norway) | Osnes, Kay Even (Wellstrรธm AS, Stavanger, Norway) | Worthington, Sam (Wellstrรธm AS, Stavanger, Norway) | Gudmestad, Kristian (Wellstrรธm AS, Stavanger, Norway)
Abstract Sealing wellbores via the use of alloy sealing technology presents a number of challenges. The typical approach involves the use of exothermic chemical reactions delivering high temperatures to ensure sufficient heat is generated to ensure the alloys remain molten for long enough to reach their intended radial extent. One challenge of such an approach are the high temperatures generated and their potential effect on the external well barrier elements (casing, cement, formation). Furthermore, chemical methods are a โone shotโ approach that do not permit close control or repeat of the heating the process after initiation. A next-generation alloy placement system has been developed using an electrical heater, cable and deployment system with sufficient capacity to deploy a fully controllable and verifiable heating solution, capable of operating at lower temperatures for extended durations. This allows close control of heating cycle to prevent damage and optimise the process, resulting in a superior barrier envelope. Furthermore, rigorous design and testing ensures the minimum amount of expensive alloy is used to achieve the desired seal. This paper details the extensive design and testing programme that was undertaken to devise an optimal alloy plug and mature a complete barrier system that challenges both conventional approaches involving cement, and first-generation alloy plugging technologies. The project culminated in a full-scale pilot in a test well that replicated the challenging wellbore environment of the intended application as closely as possible. The testing demonstrated that the technology is capable of setting a competent alloy barrier to deliver at least a 3,000 psi / 207 bar differential pressure โbig boreโ seal, even when set in drilling fluid and flowing gas.
- Europe > Norway (0.69)
- North America > United States > Texas (0.68)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Casing and Cementing (1.00)
- Well Completion > Well Integrity (1.00)
- (6 more...)
Curing Packer Leak Riglessly Using Bismuth Alloy: Results of the Field Pilot
Ahmad, Bilal (ADNOC Onshore) | Yugay, Andrey (ADNOC Onshore) | Akhtar, Mohamed Masud (ADNOC Onshore) | Hijjawi, Mohammad Rajai Baker (ADNOC Onshore) | Vorozhikhin, Sergei (ADNOC Onshore) | Almuharrami, Abdulla (ADNOC Onshore) | Nadeem, Amir (ADNOC Onshore) | Varshney, Mayank (ADNOC Onshore) | Arif, Ehsan (ADNOC Onshore) | Al Harmoodi, Eisa (ADNOC Onshore)
Abstract Wells with positive pressure at surface must comply with double barrier policy. Packer is part of primary barrier envelope, its failure causes well non-compliance to the policy, leaving it with single barrier only. Standard practice is to perform a rig intervention to replace the packer. This paper describes the outcome of the 2nd phase (5 wells) field testing of the new technology available on the market that is designed to cure packer leak riglessly. Packer is the element of the primary barrier envelope that seals off the annulus between the tubing and the casing ("A" annulus). The new technology consists of dropping of bismuth alloy beads from the wellhead into the tubing casing annulus aimed to descending by gravity and settling on top of the leaking packer. Once beads were in place in the annulus "A", a thermite heater was run inside the tubing on electric line and placed on depth across the beads. Upon activation the thermite heater produced an exothermic reaction melting the beads resulting in molten bismuth alloy but keeping the tubing integral. As the alloys cool and solidify, they expand to provide a seamless gas tight seal. Pilot project was divided into two phases. The 1st phase of the pilot (3 wells) completed in 2021 (Yugay et al, 2022). The 2nd phase (5 wells) execution completed in Mar-2023. The wells are under monitoring for evaluation at the time of Abstract submission, 2 wells are showing success. Already some interesting findings and lessons learned have been obtained, that would add value for those who might think of implementing the same in their fields. Step by step execution process including verification and validation will guide you through the whole exercise and will help to design the program in a most effective and efficient way. Positive business impact of this technology consists not only from the direct cost savings due to cancelled rig intervention (around USD2.5MM plus additional "hidden" costs associated with the well and location preparation for the rig entry), but also saved rig slot that can be utilized for the acceleration of other projects. Avoidance of the several months of the deferred production also makes this technology very attractive.
- Europe > United Kingdom > North Sea > Central North Sea (0.41)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Well Integrity > Design for well integrity (1.00)
- Management (1.00)
- Health, Safety, Environment & Sustainability > Safety > Operational safety (1.00)
Abstract Hand and finger injuries are prevalent in the oil and gas industry, resulting in significant human and economic costs. Understanding the underlying causes and contributing factors of these injuries is crucial for their prevention and mitigation. This paper explores the use of human factors analysis and classification systems in comprehending hand and finger injuries in the oil and gas industry. It highlights the key elements of a comprehensive human factors approach, examines the major factors contributing to hand and finger injuries, and presents a classification system for analyzing and categorizing these injuries. By integrating human factors principles into safety management systems, Company can effectively identify and address the root causes of hand and finger injuries, leading to improved safety performance and reduced occupational hazards.
Abstract Several "ad-hoc" safety assessments are routinely performed in Major Hazard Facilities such as Operational Risk Assessments (ORA), Management of Change (MOC) HAZOPs, Pre Startup Safety Reviews (PSSR), maintainability reviews and Root Cause Analyses (RCA). Recurrent safety assessments include HAZOP revalidations (re-HAZOPs), Safety Case / Safety Reports, BowTie reviews, etc. Undertaking these assessment in a coherent and systematic manner is problematic, not to mention keeping all the safety related information updated and in the same place. This paper describes how Artificial Intelligence (AI) can be used to build and maintain a "live" functional twin of any industrial facility where Process Safety (PS) information is continuously updated and accessible to support standard risk management processes, which is the basic feature underpinning the concept of "Process Safety Management (PSM) evergreening". Employing Multilevel Flow Modelling (MFM), a functional twin of the facility is created by the HAZOP Assistant software application. With its reasoning capability, the model creates a map of all possible causal-effect relationships, linking causes with end consequences and safeguards alike a HAZOP study or a bowtie. This "live" map of causal-effect relationships can be accessed and displayed at any time in the form of an event tree or bowtie. The functional twin is not a database of words but an actual physical model which includes qualitative mass and energy balances. As PS knowledge improves, the model can be easily updated with the new information. When changes are made to the facility, the model can be updated to reflect the "as-is" status, so that safety assessments are updated and relevant. The paper highlights how the HAZOP Assistant software application builds and maintains a functional twin of the facility to support the above processes consistently and efficiently, in one platform and reducing errors and costs.
- Health, Safety, Environment & Sustainability > Safety > Safety risk management (1.00)
- Health, Safety, Environment & Sustainability > Safety > Operational safety (1.00)
- Health, Safety, Environment & Sustainability > HSSE & Social Responsibility Management > HSSE management systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Optimization of the Well Diagnostics Investigation
Yugay, A. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Zhukin, A. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Vorozhikhin, S. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Girgis, F. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Alkarbi, M. A. (ADNOC Onshore, Abu Dhabi, United Arab Emirates)
Abstract Well Integrity discipline is all about barriers. Double barrier envelope policy is a well integrity requirement well-known worldwide. This can be found in international standards: API RP90 (1 & 2), Norsok D10, ISO 16530 (1 & 2). This policy applies to wells with positive pressure at surface capable to flow naturally. Primary barrier envelope consists of well equipment which is in direct contact with produced or injected media. Secondary barrier envelope will be exposed to well media in case of primary barrier element failure. This paper focuses on such kind of wells that have a positive pressure at surface and fall under double barrier policy. Any failure in primary barrier envelope (means - completion) is easily repairable during workover by simply re-completing the well with new completion. This can be done almost unlimited number of times, as long as there is a place to set the packer. Failure in secondary barrier envelope (means - casing) can be done as well, but not that easy and limited amount of time. In some cases, especially for onshore wells it might be economically more reasonable to drill the new well rather than to deal with complicated workover. Depending on the Company policy, casing integrity can be restored in sections using casing patches or the entire length can renewed by running and cementing casings of smaller diameter. Obviously, in both cases it impacts the size of the completion and cannot be done multiple times.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Well Integrity > Design for well integrity (1.00)
- Health, Safety, Environment & Sustainability > Safety > Operational safety (1.00)