bluuebunny/crossref_metadata_2025_split huggingface dataset:
Doing Less with Less with Fit for Purpose FEA Solution in Asset Support
Authors: Chow Wan Han , Bolhassan Rosannah , Loh Khian Aik , Kota Ravi , Henry Zulkipli 
Published: November 2020

Abstract
Managing asset Integrity has been a long inconvenient issue to many ageing assets in Malaysian waters. As the Oil and Gas business grows and matured, so have the assets. Often time direct solutions are not available due to complexity of the problems. As asset operator, it is our responsibility to find life extension solution to keep the hubs full and remains competitive. With the advancement in technology and creative mindset, large system can be subdivided into smaller systems and solved one at a time before reintegrated into the larger system which forms the backbone of finite element analysis method.
This paper will illustrate some of the asset integrity issues faced by shallow and deep-water platforms. The three selected asset integrity examples include a topside beam with cut-out, well casing material loss and stress joint fatigue life extension. A step by step fit for purpose solution along with the challenges faced and mitigation measures taken was documented in this paper. For beam with cut-out, the 2D beam model is compared against the 3D model concentrating on the stress flow pattern and stress concentration factor. For well casing material loss, discussion evolved on how strengthening can be minimized by simply repositioning the bolt location. For stress joint fatigue life extension, the limitation of an axis-symmetry model in capturing bending moment and the conservatisms of applying an equivalent tension load to simulate the bending action was discussed. Simplified solutions are often associated with conservative result which is not necessarily true. Simplified solution in this context is a method to break the complex system into simpler system and solve using minimum resources, time and cost. The aim is to share knowledges with fellow operators on ways to maximize the niche manpower to do less with less.
In conclusion, by simplifying the complex system coupled with 3D advanced analysis tools, the integrity of the asset remained intact, reduces the need of periodic inspection/ parts replacement and opens-up opportunity for life extensions. The same concept can be replicated for other similar projects and be mindful that FEA do not solve all problem, but people do.
A Simplified Method to Predict the Shock Load on Crane Wire to Hang Hammer During Pile Running
Authors: Huang Zhiwei , Kurundwade Santosh , Kibby Landon , Chen Zongrui 
Published: November 2020

Abstract
Pile running, the uncontrolled fall of a pile due to the collapse of a hard soil layer over softer soils, is a major constructability risk during pile driving operations. This is especially the case for the long and large diameter piles driven with heavy hammer. Unexpected pile running may cause loss of the pile, damage to the jacket, damage to the crane due to overload or even hammer loss. This paper discusses about shock load on cranes due to pile running and its estimation using simplified method based on a real project record. The method can help to develop dedicated plans for pile driving if pile running is predicted in pile drivability analysis in future projects. At the same time some remedial measures to reduce shock load on crane wire are included and discussed.
Laser Drilling in Extremely Hard Formation
Authors: Batarseh Sameeh I. , Alharith Abdullah M. , Assiri Wisam , San Roman Alerigi Damian 
Published: November 2020

Abstract
The objective of this work is to demonstrate the success and the ability of high power lasers beam to drill in extremely hard formations. The result showed that the rate of penetration in these formations is much faster than conventional drilling methods. Formations with high compressive strength can prevent or slow drilling and rock penetration. A High power laser program was established to overcome the limitations of conventional drilling methods and provide an innovative non-damaging technology as alternatives to current practices. The technology is not only able to drill in extremely hard formations but also enhances rock properties without compromising wellbore integrity.
For the past two decades, researchers attempted to deploy high power laser technology for several downhole applications, with no success because the power needed to penetrate the rock was insufficient. Laser technology has evolved and advanced recently, creating compact efficient, higher power, and economically feasible systems.
An experimental setup was designed to evaluate the performance of a high power laser in different rock types and with different compressive strengths, ranging from 12,000 to 43,000 psi. These samples were exposed to a high power laser for several applications. The results demonstrated that a high power laser could penetrate extreme rock formation in seconds, for example, at the lab scale, it took 3 seconds to drill 3 inches of basalt (43,000 psi compressive strength). The flow properties were also enhanced regardless of the compressive strength and hardness of the rock.
Laser technology attracted the oil and gas industry due to its unique features, such as the precision in controlling and orienting the energy in any direction. Laser drilling is independent of the reservoir stress orientation and magnitude. The laser generation unit is mounted on the surface and the laser beam delivered downhole via fiber optics cable. The system has a minimal footprint, is an environmentally friendly technology, and can drill and case simultaneously.
High power lasers have the potential to be the next intelligent drilling and completion generation that will change current practice. State-of-the-art high power laser technology provides an innovative and safe non-explosive based technology. Precision, speed, small footprint, and reliability are some of the properties of the technology that make it attractive for downhole applications.
Synchronized Towing of Flexible Riser in Shallow Water and Varying Current
Authors: Shahaya Marshel Anbu , B. Karim Khairul Anuar , A. Latif Nur Atika , Badaruddin M. Fauzi , Ali Napiah M. Nazmi 
Published: November 2020

Abstract
Towing of offshore pipelines can be heard during the mid-nineties, and it has been continuously improved with the advent of 2nd and third generation vessels. The operation poses a great challenge due to the dynamics and the instantaneous tension which the pipelines need to face. There is a high risk of flow line / pipeline getting damaged with potential increase in tension loads. It could also happen that the pipeline can get buckled with unexpected environmental loads. There can be a situation wherein the flow line gets damaged due to difference in tow speeds. In such situations the pipeline most likely touches the seabed for a shallow water depth. If a pipeline is in high tension in which greater than the allowable axial load, then there is likely pipeline can get damaged. If the pipeline is a flexible type, then there is a high chance for the outer sheath to get damaged. It is one of a most delicate operation which requires a focused interaction from different parties, viz. the Tow master, captain of the forward and trailing vessel and the monitoring vessel which have to move in a synchronized speed along with the Tow speed. There are in all three (3) major phases for a typical Towing Operation: a) Initiation and setup for Towing; b) start of Towing operation; and c) Tie-in or relocating the Pipeline / Riser to a new location.
The seabed route selection and the bathymetry features are decided and firmed upfront. It should be as much as possible select the shortest route with minimum changes in the Vessel azimuth and bearing direction. The bathymetry should be free of any elevated obstruction, subsea anchor, mooring buoys and any mooring anchor chain from the nearby floating facility. This paper will be discussing flexible dynamic riser with near seabed tow at shallow water depth and high current. The flexible dynamic riser is an existing production line, which was required to be detached from a floating facility and then to be towed away to a safe distance. The facilities were temporarily shut down and during that time flexible riser was planned to be towed to a safe location and wet stored. The flexible riser was then again towed back to the same field after changes were made in the infrastructure facilities. The additional challenges faced were on manipulating the tensions around the bend stiffener and maintaining allowable Minimum Bend Radius (MBR) near the bend stiffener portion. It discusses about the sequence of operation, the initial planning preparation work, the simulated engineering activity, the offshore marine spread and its associated activities, and the monitoring systems in place.
A New Solution for Well Abandonment: Bismuth and Thermite
Authors: Fulks Jeff M. , Carragher Paul 
Published: November 2020

Abstract
Well abandonment is as much a part of the oil and gas industry as drilling and production yet is seems to receive the least amount of consideration. Operators spend months and even years planning how they will drill and complete a well but often don't think about how they will abandon it until production has ceased. As such, they tend to rely on traditional methods and materials, doing it the same way it has always been done and yielding the same results which are often not desirable. Recently, more operators have chosen to spend more time planning well abandonments than ever before. Perhaps this is because the requirements for well abandonment have increased or because, unlike drilling and production, any money spent on well abandonment comes straight off the bottom line without the opportunity to recuperate during production. Either way, this increase in visibility has led to a search to abanon wells more efficiently and cost effectively.
One of the ways to achieve this is by looking at alternative sealing materials, such as bismuth. Since 2015, bismuth alloy tools have been delployed over 80 times to seal wells at various stages of the well's life with 60% of the tools run for well abandonment. Bismuth alloys are also being considered as possible alternative barriers to cement by multiple regulatory agencies.
Evaluation of Data Driven Versus Multiphase Transient Flow Simulator for Virtual Flow Meter Application
Authors: Ishak Mohd Azmin , Al-qutami Hasan Tareq Aziz , Ellingsen Halvard , Ruden Torgeir , Khaledi Hatef 
Published: November 2020

Abstract
Production Well Testing is one of the major routines in the upstream oil and gas operations. It is an important oil & gas operation as it will be used to track the performance of individual well productivity, production planning, projection for future investment or divestment i.e. drill new wells, shut non-productive wells or execute well intervention. Historically, production well testing is executed using a single-phase meter after the hydrocarbon is separated in a test separator. Alternatively, physical Multiphase Flow Meter (MPFM) could be used either over a test header or at individual well flowline. MPFMs combine several measurement principles such as Gamma ray spectroscopy, capacitance tomography, microwave, and ultrasound to infer phase flow rates. From PETRONAS experience, there are many instances where the MPFM, especially in subsea installation, failed either prematurely or later part of the field life. Virtual Flow Meter (VFM) can be used as a back-up in this case. Traditionally, a virtual flow meter uses a steady state or transient flow simulator that exploit various measurements within the wells and facility such as downhole pressure & temperature gauges, tubing head flowing pressure, differential pressure across the choke, choke position and fluid characteristic to derive the flow rates of oil, water and gas. In this paper, we will compare and evaluate a VFM that uses transient flow simulator against data-driven VFM which uses machine learning technique. Both data-driven and transient flow simulator VFM are evaluated using the same well test data from real producing oil fields. From this work, the team realized there is a potential that both data-driven and transient flow simulator can be combined to provide a complementary benefit as an optimal Virtual Flow Meter and to reduce the overall system uncertainty.
Optimization of Online Pipeline Repair Method Using Welded Sleeve
Authors: Md Zin Ghazali , Badaruddin M. Fauzi , M. Zabidi M. Zazli , Ibrahim Kamal Azam 
Published: November 2020

Abstract
The objective of this paper is to demonstrate the optimization of online pipeline repair method using welded sleeve for onshore pipelines. There are several online repair methods available however the use of sleeve is preferred due to higher strain capacity and ease of installation.
In managing prone leak pipelines due to geographical terrain requires higher strain resistance over stress based design. Inline Inspection (ILI) program using geopig has recorded more than 0.5% strain on various location along the pipelines. From the original WPS, most of the girth welds are able to withstand only 0.2% strain. In order to ensure continuous production, any location that recorded more than 0.2% strain has to be strengthened. A relatively simple and ease of installation repair method is required. Any girth welds experiencing more than 0.2% strain may be cut out and reweld however requires extensive repair welding activities. This method also is not favorable due to loss of production.
The proposed welded sleeve welding procedure qualification (WPS) for online repair has to be qualified as per API 1104 prior to welding. The WPS were tested in accordance to API 1104 Annex B to simulate the in service welding requirement. All the mechanical tests were successfully tested as per the requirements. In addition to mechanical test, the sleeve also is required to pass the Full Scale Bend Test (FSBT) testing. The FSBT is intended to simulate the actual pipe condition with sleeve to withstand strain as per calculation. A 12m pipes with actual pressure of 96 bars were bended vertically downward to measure the maximum strain results. As per Finite Element Analysis (FEA), the maximum calculated strain for the sleeve to withstand is 0.9%. The results were compared with FEA analysis to check the amount of strain allowed on the weld.
This repair method eliminate the cut out repair method that require extensive repair works. The cut out and replace certainly will cost more and time consuming. Using this sleeve online repair method, loss of production is eliminated. The repair works is minimal hence the repair schedule is faster compared to cut out. The estimated cost savings is around RM20M per repair using welded sleeve method.
Improved Recovery Through Optimum Well Design Using Autonomous Inflow Control Device in Complex Brown Field Reservoir
Authors: Mohammad Zin Zulkifli , Khairuddin M. Shahnizam , A. Manaf Maziah , Mohammad Suria Melanie , Yap Bee Ching , Ahmad Mior Yusni , Shafie Shaiful Helmi , Dang Lola Le 
Published: November 2020

Abstract
Challenges associated with horizontal wells production in a barefoot or only standalone screen are well documented in the industry. Inflow control devices have been around for years and have been the answer to mitigate the challenges typically associated with heterogeneity in horizontal wells, as was applied in an offshore brown field in East Malaysia, Field S. However, as the field gets more mature, increasing production challenges posed by the reservoir leads to conventional passive inflow control device solution becoming less effective. Over time, as water production from the reservoir increases due to the rise of aquifer column, new infill wells have to be completed shallower and closer to gas oil contact to maximise recovery leading to risk of high gas production. The risk is further compounded by uncertainty in the fluid contacts in a complex dipping reservoir.
In order to mitigate these challenges, Autonomous Inflow Control Device (AICD) was selected for Field S infill wells to control excessive gas production anticipated due to the wells placement. AICD's ability to choke production based on the fluid properties allows for improved flow control together with influx balancing from segmentation into compartments by swellable packers. In total, seven (7) horizontal wells were completed in an infill drilling campaign in Field S, with the wells placed at around 5 m from prognosed gas oil contact. AICD was installed with premium sand screen and swellable packers in the wells’ lower completion and has managed to control excessive gas production while enabling production at the targeted oil rate.
This paper describes the implementation of AICD in Field S infill drilling campaign with challenges of complex dipping reservoir and fluid contact uncertainty. The workflow to investigate the feasibility of the candidate and the completion design process will be discussed. Well modelling (nodal analysis) using production data was performed to characterise the well performance and to understand the impact of AICD in controlling gas and inflow of producing fluid into the producing horizontal section.
Risk Management and Control for CO2 Waterless Fracturing
Authors: Meng Siwei , Yang Qinghai , Duan Yongwei , Tao Jiaping , Chen Shi 
Published: November 2020

Abstract
The fluid is seen with the high pressure and low temperature during the CO2 waterless fracturing operation, which is prone to accidents such as casualties and environmental pollution. In this paper, a complete operation safety management approach and a contingency plan are developed, with respect to the CO2 waterless fracturing.
For the fracturing equipment and support facility, high-pressure-resistant, low-temperature-tolerant specialized wellhead, valve and surface pipeline are required. The pipe wall thickness should exceed the N80 tubing criterion, and the relief line has to be anchor-fixed. In order to prevent suffocation caused by CO2, all vehicles and personnel must stay windward. All safety valve outputs should be arranged leeward, facing no personnel operation and equipment placement. Crews must appropriately wear protection that prevents suffocation and cold injury. While operating valves, they should stand beside the valve and operate steadily, so as to avoid object strike induced by the dry ice.
The contingency plan corresponding to the operation condition is developed. In the case of CO2 leakage, the operation should be stopped immediately, personnel will be evacuated to the open area on the windward side, and the air blower at the field should be turned on. As for the occurrence of gaseous CO2 in the surface process, one has to identify the gasification position in a timely fashion and adjust the vent valve of the blender and the surface pipeline and the wellhead valve correspondingly. If gaseous CO2 occurs inside the wellbore, the countermeasures of close surveillance, stabilizing pressures by injecting CO2 at a small rate, and pressure relieving after switching off pumps are implemented, depending on the severity of the case. Upon the arrival of the blender pressure at 2.4 MPa, the safety valve is open for venting. Synergistic pressure relief should be executed by opening the sand-input ball valve, gas valve and liquid valve, if the pressure continues to grow.
So far the CO2 waterless fracturing has been successfully operated for over 20 times, in the tight oil reservoir, shale oil reservoir, low-pressure sensitive gas reservoir, etc. No safety accident has been reported, which demonstrates the rationality and operability of the proposed risk management and control approaches for the CO2 waterless fracturing.
Effect of Two–Phase Flow on Gas Permeability in Marine Flexible Pipelines
Authors: Zhao Bingliang , Wang Kai , Li Yi , Yu Xichong , Chen Jinghua 
Published: November 2020

Abstract
The flexible composite pipes are quite suitable for the development of marine oil&gas reservoirs due to the excellent characteristics of design abilities, economics and dynamic behaviors. At present, the theories and methods of the gas permeations in the composite walls have not yet considered the influences of the multiphase flow in the inner pipes. Therefore, the prediction accuracies of the permeation rates are expected to improve for the marine flexible pipelines with significant differences of pressure and temperature drops. In this paper, a comprehensive gas permeation model including gas-liquid two-phase flow is proposed, and the effect of flow patterns on the gas permeation rate and vent period is investigated numerically. The results show that the flow patterns of multi-phase flow have significant impact on the permeation rate of gas due to different pressure drop and temperature drop for the same mass flow rate, and the permeation rate of CO2 is higher than that of CH4 under the same working condition.
Preventing Brittle Fracture of Metallic Materials in Oil and Gas Companies Through Mandatory Control Framework During Design, Engineering and Construction
Authors: Abdul Malik Noor Syamiza , Yusoff Suriani Binti , A Razak M Hasbi 
Published: November 2020

Abstract
The consequences of a catastrophic failure of equipment are very serious, both in terms of financial implications and the risk to human life. Essential requirements in the design and operation of pressure containing equipment such as pressure vessels, piping, and pipelines particularly those made from ferritic steel and operating at low temperatures shall be seriously considered in avoiding the possibility of brittle failure. Thus, preventing Brittle Fracture of Metallic Materials in Oil and Gas Companies through Mandatory Control Framework during Design, Engineering and Construction is implemented throughout PETRONAS facilities.
The specification of material requirements was developed to prevent process safety incident and mitigate the consequences resulting from the unintentional release of energy or hazardous by adopting lessons learned from major process safety incidents that have occurred in PETRONAS and in international hydrocarbon processing industries. Therefore, a governance document i.e. Mandatory Control Framework (MCF) was developed in PETRONAS by verifying the HSE management systems and practices in assuring the technical design integrity and quality during installation.
The establishment of MCF in most major oil and gas companies took place especially after the Texas refinery and Macondo incidents. The main intent of MCF is to ensure that all capital projects, plant modifications and the existing facilities with HIGH and VERY HIGH process HAZARDS complies with PETRONAS Technical Standard (PTS) requirements to safeguard the interest of all relevant parties.