bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximum Reservoir Contact (MRC) Water Injector Well Performance in ADNOC Onshore Carbonate Reservoir Equipped with Limited Entry Liner (LEL) Smart Completion
Authors: Al Shkeili Sara Abdulla , Javid Khalid , Benourkhou Noureddine , Al Sayari Saleh Ali , Al Dhuhoori Moza Saeed , Utama Indra , Rachapudi Venkata Subba Ramarao , Chang Ernisto Lenin , Jimenez Alvaro , Chaudhry Muhammad Zubair Tanvir , Mogensen Kristian , Hosani Fahad Mustafa 
Published: October 2022

Abstract
Developing mature reservoirs is associated with challenges and limitations both in surface and subsurface. In This paper we will tackle the area of developing reservoirs with Maximum Reservoir Contact (MRC) wells by introducing our experience in combining it with LEL completion and introduce initial results in unlocking the potential of our reservoir with reduced capital expenditure (CAPEX).
Conventional wells with 3000 ft open hole length become more challenging as development of the field progresses and especially with drilling new wells. Congestion and anti-collision at surface and subsurface limitations arise more often let alone the cost, manpower and environmental issues. We are going to introduce Maximum reservoir contact MRC wells with extended open hole length of around 10,000 ft. which allow to maximize gain from this well while optimizing other parameters (well spacing, cost…etc.). Measurement of rate and pressure, pre and post acid stimulation controlled by LEL completion as well as comparison with conventional water injectors in the vicinity were performed before to evaluate the performance of the MRC well.
It was confirmed that MRC well injectivity surpasses the conventional injectors with shorter open hole length in relatively tight areas of the reservoir which have low permeability especially if equipped with LEL completion. Initial results show Injectivity improvement compared with nearby water injectors plus additional gain in injectivity noticed after acid stimulation with the LEL completion. The MRC well performance after stimulation showed well head injection pressure decreased drastically after the acid stimulation with increased injected volumes of water. This shows that smart completion solutions well help to improve performance and optimize acid stimulation which highlights the importance of combining MRC with LEL to maximize gain and enhance performance to take the maximum benefit.
Through our success with MRC well with LEL completion the community of petroleum engineering will be able to take decisions regarding implementing this method and technology to optimize their drilling which will have positive impact in cost, planning and environment.
Say No to Carryovers
Authors: Yadav Sudhanshu Kumar , Al Muhairi Mohammad Ahmad , Obaid Ahmed , Hosani Rasha Al 
Published: October 2022

Abstract
Carryovers are infrequent incidents in process industry. Cause of these events is poorly understood. Carryover cannot be prevented using current configuration of instrumentation and control systems. Prior to the event operators are caught completely off-guard as the process parameters continue to stay in normal operating range. Realization of abnormal situation comes a bit late when carryover fluid reaches in downstream subsystems. Operators need help to stop these events from occurring by taking some informed decisions. This is achieved by introducing a new Operator Warning and Advisory Layer of protection.
Transformation in Well Delivery Commissioning Cycle Time Using Kaizen Methodology-Sultanate of Oman
Authors: Al-Azkawi Hafidh Said , Al-Naabi Omar Sulieman , Al-Hadhrami Abdullah Khalifa , Al-Musharafi Salim Mohamed 
Published: October 2022

Abstract
Petroleum Development Oman LLC (PDO) is the leading exploration and production company in the Sultanate of Oman. The company drills around 650 wells a year most of the well are in the South asset where the highest oil production. Currently, the South directorate drills an average of 400 wells a year varying from sweet, thermal, and critical sour/high-pressure free flow wells. In addition, 200 wells undergo conversion process. Commissioning of these big numbers of wells has imposed a great challenge to the team due to the high number of stakeholders involved to commission one well. Based on the records of 2018, in average, the critical sour high-pressure wells took 300 days to commission from well pad release. While sweet conventional wells took 22 days from rig release and high-pressure free flow wells took 80 days from rig off to commissioning. Because of these long durations, the new oil production was impacted and therefore impacted the overall production targets.
The objective of this paper is to illustrate the improvement on the well delivery process in the south directorate. The team has followed a kaizen methodology for the root cause analysis and has come up with key improvements to minimize the Hook-up and commissioning of all types of wells drilled, followed by PDCA process.
After applying the improvements revealed from the different kaizens for each type of wells, the team managed to reduce the duration for the critical sour high-pressure wells from 300 days to 45 days in 2020 until reached to 17 days in 2021. For the sweet conventional wells, the duration was reduced from 22 days to 10 days in 2019 until it reached to an average of 3 days in 2022. On the high-pressure free flow wells, the duration was reduced from 80 days to currently averaging at 17 days. As a result, the Oil South Directorate realized a benefit from acceleration of the new oil production hence it increased the company revenues ahead of the plan.
The successful implementation of well hookup process of all the mentioned types can be replicated in other fields in Oman and worldwide. The improvement was already recognized internally within PDO by winning two awards which are oil south directory silver award and PDO CI award for the best kaizen in 2021. The methodology has been cascaded to other directorates within PDO for their replication.
Electroless Nickel Plating Applications to Enhance Corrosion Protection, Equipment Reliability and Cost Effectiveness in Centrifugal Compressors
Authors: Pranzetti Alice , Bellacci Michelangelo , Cappuccini Filippo , Rizzo Emanuele 
Published: October 2022

Abstract
Coating technology is an efficient and cost-effective solution to protect equipment from aggressive environments. Corrosion and particles erosion are the most important material degradation phenomena in process centrifugal compressors leading to loss of performances, increase of vibrations and potentially safety concerns, especially for compressors operating with toxic gases. Among the today available coatings, Electroless Nickel High-Phosphorous plating (ENP) is one of the most robust and reliable solution. In this paper, the ENP corrosion resistance in continuous wet harsh environments was investigated through customized autoclave tests. The campaign assessed the corrosion resistance of both proprietary standard ENP (10-13%P) and proprietary modified-ENP, respectively with PTFE and SiC particles, ("doped-ENP"), in a single (SL) and double-layers (DL) fashion. All DL-ENP samples (standard and doped), showed an excellent corrosion resistance in harsh environment up to 10 bar H2S, 150 bar CO2 and 100000 ppm of chlorides. Among the SL samples, standard ENP showed the best results compared to the doped options. The samples characterization highlighted that the standard ENP is an effective barrier against the ingress of the corrosive gas mixture. On the other hand, the "doped" SL samples showed a reduced corrosion resistance. This reduction seems to be caused by the disruption of the ENP dense and amorphous film, resultant from the dopant particles inclusion. In this same study, the electroless in situ repair of locally damaged ENP was also investigated. As a result of the restoration process fine-tuning, a seamless ENP patch repair was obtained, thus ensuring the complete refurbishment of the original coating.
Working the Agile Way to Fast Track the Hydrocarbon Maturation Process
Authors: Singh Jasbindra , Borbajo Renato , Bashokooh Behrooz , Sariri Aisha , Riyami Said , Haddad Bahjat , Al Breiki Al Anood , Radwan Mohamed , Rajhi Mohammed , Sulaimani Al Zaina , Hillgartner Heiko , Khusaibi Mohammed , Mahruqi Issa , Azri Nasser 
Published: October 2022

Abstract
The "Agile Development" process utilises fast track evaluation of discovered hydrocarbon reservoirs and fields using the analogue based evaluation, capitalizing on existing organizational know-how in development of existing assets. It provides flexibility in the process to be able to adapt any changes happening during the span of the evaluation. The scope of the process covers the technical evaluation and the assurance events leading to a decision-based roadmap forming the basis of final investment decisions.
The fast-tracking "Agile Development" process has been designed to evaluate opportunities from appraisal to development phase based on the analogue data and the concepts. The process is utilised to characterize several different steps, starting from framing the opportunity to the delivery of the field development plan. Analogue assessment typically involves identifying the analogue[s], understanding the development concepts and utilising them for the estimating the production from the project development and the associated costs to evaluate the economic attractiveness. The assurance of the evaluation process has also been adapted to specific needs in project evaluation process. There are different tools - all developed in-house within the organisation - available for screening the analogues and then finally, selecting the analogue suitable for the evaluation of the project development planning. The outcome is also benchmarked on several parameters to ensure the project robustness.
The process has been implemented in several projects involving depletion and waterflood flood recovery mechanisms. The approach has resulted in reducing the time saving by over 50% as compared to normal process of opportunity evaluation. The quality of the product is similar to the FDPs delivered using the standard processes. The process may bring in additional value as it accelerates the delivery of the FDP in a much shorter time while providing flexibility to adapt to any changes experienced during the evaluation process.
This is a fast-tracking approach of evaluating the attractiveness of the discovered opportunities by implementing the experience and learnings from the development of similar reservoirs.
The process is still maturing and has the potential to reduce the evaluation time further by additional 50% for the projects using similar recovery mechanisms. The approach can further be extended for testing and/or implementing in EOR process specifically polymer flooding methods.
OPEX Optimisation for Un-Piggable Vent Line/Low Flow Pipeline Inspection via Self-Propelling Robotic ILI Tool
Authors: Abdullah Mohamed Ali , Supian Aishah Mastura , Ahmad M Nazri , M Ali Napiah M Nazmi , Mat Tuselim Ahmad Sirwan , Zakaria Muzdalifah , Hassan Hendra Luthfi , Mohamed Abd Salam Mohamed Ridzuan , Denis Gurin , Mikhail Lebedev , Elena Fertikova , Vitaly Romanovich 
Published: October 2022

Abstract
This paper is to share the development of Self-Propelling Robotic In-Line Inspection technology that PETRONAS embark as OPEX optimization for un-piggable pipeline. Lack of conventional inspection methods to inspect un-piggable pipelines such as vent pipelines without pig traps facility and low flow pipelines, has prompted PETRONAS to embark on technology development journey for Self-Propelling Robotic ILI.
The development of the Self-Propelling Robotic In-Line technology consists enhancement of robotic tethered crawler tool to a wireless robotic tool, testing and validation using actual full scale fabrication test loop. Fabricated test loop includes horizontal and vertical section with bends of 1.5D to simulate the inspection tool travel as per actual site condition representing vent line.
The enhancement consists of wireless connection range, optimum speed and distance, movement of slippery surface which grease was applied on the vertical section and emergency extraction of inspection robot.
Robotic ILI qualification test which was successfully met PETRONAS requirement based on full scale factory acceptance test. The test was focused and able to meet below success criteria: -
Robotic ILI tool able to self-propel on vertical test spool. Robotic ILI tool able to move with wireless connection for the intended travel length. Emergency retrieval tool procedure and mechanism in the event of faulty robotic ILI or loss of connection. Sensor detection capability at POD 90% and POI 80%.
Based on the evaluated technology, Robotic ILI solution is feasible in ascertaining the un-piggable pipeline integrity and recommended solution to tackle high operational costs that upstream operators face when inspecting their pipelines using current available methods. Deployment of this technology is estimated to provide up to 30% OPEX optimization. The technology has been evaluated to be technically ready and tested which currently in the stage of pilot testing.
Current approach to inspect un-piggable vent or low flow pipeline is Crawler ILI type technology which propelled by umbilical cable whereby the pipeline requires to be in shutdown mode. While inspection using Self-Propelling Robotic ILI can be applied for un-piggable pipeline i.e. low flow pipeline and vent line with short duration or no requirement of shutdown.
Driving Operational Excellence and Energy Reduction via End-To-End Production & Energy Loss Accounting at an Oil&Gas Client
Authors: Fien Gert-Jan A. F. , Semaan Samar M. 
Published: October 2022

Abstract
This paper will cover the recent implementation of a new end-to-end Production & Energy Loss Accounting (PELA) system at three separate sites of a major refining and petrochemicals company in the Middle East. It describes the development of practical tools, governance structure, training of relevant staff, embedding and evolving of the associated Management Operating System (MOS) and some of the early benefits achieved.
The new system includes customized software tools providing shift operators in each process with real-time information about production and energy losses in the main value drivers: asset utilization, product quality, reprocessing, equipment efficiencies, flaring, etc. The tools allow immediate assignment of standardized "cause categories" for later aggregation and analysis. A separate data compilation and visualization tool was also developed, along with work processes to support deviation analysis and decision making. More than a hundred technical staff across the three sites received training and a weekly meeting cadence was established for maximum leverage from this initiative.
This PELA system successfully covers 21 separate process areas. It led to confirmed savings of 7.9 MMUS$ in the first year alone, by wiring the organization for continuous improvement and providing greater transparency for staff and management alike.
PELA serves as a vehicle for change by driving awareness of the front-line staff and ensuring better cooperation between them, process engineers, maintenance, and production planning. The success of such a program relies on lean skills, analytical capabilities, expertise in change management, and strong leadership within the line.
Technology for Assuring Integrity of Uninspectable Small Diameter Pipeline Systems
Authors: Phipps James Alexander 
Published: October 2022

Abstract
The inspection of large diameter pipelines using intelligent pigs is commonplace and subject to continuous development.
Increasingly onerous is the inspection and thus integrity void associated with ‘unpiggable’ pipelines, caused by a variety of factors including diameter, geometry, access and economics.
The traditional inspection of pipework is onerous, expensive and can expose the operator and contractor to increased levels of risk, typically associated with access and logistics challenges.
The development and deployment of small and ultra small intelligent pigs can increasingly enable the inspection of pipeline and pipework inventory which could not previously be exploited.
The increasing momentum to embrace alternative energy sources involves new and often smaller diameter systems, as well as the opportunity to re-purpose part of the existing energy network.
The ability to deploy such technologies can significantly increase the speed of inspection survey, offer full coverage, whilst lowering the risk associated with complex and extensive access arrangements.
Enhancing Plant Reliability Through Risk Management of Single Point of Failures (SPoF) in Sour Gas Facility
Authors: Jain Nitish Kumar , Narsapur Sameer Surendra 
Published: October 2022

Abstract
ADNOC Sour Gas has experienced plant trips in the past, production loss as a result of avoidable actions resulting from component failures. These trips, in many instances were a result of a single point of failure. Single point of failures (SPoF) are specific common sections of piping and equipment which if failed or leaked in service can immediately shutdown the entire operating unit or the production facility as a direct impact or cascaded effect without giving the operator adequate time to respond and control the situation.
Large size gas processing plants such as ADNOC Sour Gas Facility with two gas trains operating simultaneously are designed to run uninterrupted for 4 to 5 years between 2 planned major turnaround cycles. By design and per specification, there are number of sections in the plant that have no stand by or any redundancy available in design. Due to this design of common sections or often defined as single components, it is not feasible to repair equipment, piping or instrumentation due to integrity issues while they are in operation. Any rectification work on these common systems (mechanical, electrical, instrumentation or structural) can lead to shutting down the entire gas plant & facilities. This planned or unplanned shutdown can lead to enormous production loss. To alleviate or minimize the consequences from these single common plant section events and improve the reliability and availability of the overall facility, management of these common sections is paramount for the business. ADNOC Sour Gas has successfully utilized the lesson learnt and identified all potential SPoF in the facility and developed SPoF management plan.
In order to ensure higher reliability of Operations, it is important that SPoFs are minimized or managed to avoid downtime. The concept of SPoF is very effectively utilized in IT industries, Networking and supply chain. Sour gas has successfully applied the concept for Oil & Gas Operations.
ESP Run Life Increased by 230% Using a Small, Customized Device: The Next Step in Flow Assurance and Chemical Injection for ESP-Lifted Wells
Authors: Andagoya Carrillo Kevin Ismael , Villalobos Jorge Luis , Sierra Osiris , Correal Alvaro , Quinzo María Elena , Orozco Andrés , Enriquez Luis , Reyes Carlos , Leon Fernando 
Published: October 2022

Abstract
Carbonate scale is a mineral deposit transported by produced water, and its presence negatively affects well production and electrical submersible pump (ESP) performance. Instead of attempting to remediate it after it has already accumulated, a suitable and more-cost-effective process is to use a continuous inhibition treatment through an additional hardware installed in the ESP. An acid treatment can be suitable for certain types of scale, but acid treatments can cause damage to the tubing string and the ESP if not handled properly.
A new hardware was developed and used in ESP applications by looking for inhibition in fouling fluids as soon as the fluid comes out of the reservoir and before considerable pressure or heat changes occur by increasing the contact time with the treatment and by looking for a faster homogenization between the reservoir fluid and the inhibitor treatment with a 360° tool injection.
An analysis of historical data demonstrates a significant increase in ESP mean time between failure in wells dealing with fouling fluids where the tool, a tail pipe with a multipoint centralizer, was implemented. Additionally, a more-stable downhole parameter condition was reached.
It was also observed that, depending on where the tool was placed, production improved by postponing the buildup of deposits at the reservoir face and mitigating skin damage. This hardware, which improves flow assurance, has been continuously improved, and each step will be covered. Additional information was retrieved during the analysis performed during teardown of the ESPs, and it has been possible to identify wells dealing with similar problems. Some wells were newly categorized as problematic, and several data suggest that the increase in water cut related to a waterflooding process could have changed the fluid properties. By understanding the specific cause of the ESP failure let us understand that there was a direct relationship to a lack of an effective chemical treatment, not related to the formulation or dosage of the chemical treatment, but because of the challenging well trajectory due the mechanical configuration or for uncertainties in the producing fluid properties. It was necessary to create alternative tools as new solutions to improve flow assurance.
This project will provide an alternative solution that is cost effective and provides a tangible value to projects in which flow assurance and effective chemical treatment are effective when dealing with harsh fluid properties or the behavior of the fluid is unknown before ESP installation.
Emulsion Interface Model – From Science to Implementation
Authors: Vai Yee Hon , Deguillard Estelle , Mohd Saaid Ismail , Chin Hsia Ivy , Mohd Fauzi Noor Amira , Van Male Jan , Handgraaf Jan-Willem 
Published: October 2022

Abstract
Using computational chemistry solutions, a practical software tool is developed to simulate emulsion system, thereby gaining comprehensive information from atomistic level to manage oil field emulsion. The software tool is a revolutionary emulsion interface model, established based on physical chemistry of surface tension and torque concepts, coupled with solution of interface bending rigidity with relation to interface energy. With solid theoretical foundation, the tool is reliable and proven for field application. The emulsion interface model simulates emulsion behavior in molecular dynamics to predict emulsion type and stability in the presence of various surface-active agents. It comprises of two key mathematical approaches. The first approach is used to assess the surface mechanical coefficients (surface tension and torque) to infer the type of emulsion formation: water-in-oil emulsion, oil-in-water emulsion or microemulsion. The second approach is used to estimate the emulsion interface bending rigidity to deduce interface stability. Digital oil model with accurate representation of atomistic components of actual crude oil is constructed as input to the simulation. The emulsion interface model is verified with both published data on pure oil emulsion system and with actual data on oilfield emulsion system from offshore field in Malaysia. Good agreement between simulations and field results is achieved. This indicates that the main characteristics and physics of emulsion behavior are captured correctly in the emulsion interface model. The duration for selecting effective surface-active agents to manage oilfield emulsion can be reduced up to 90%. The main advantage of the tool lies in its dual-functionality applicable for both emulsifier selection for enhanced oil recovery and demulsifier selection for production flow assurance. Ultimately, the application of emulsion interface model has successfully enabled step-change in oilfield emulsion management via an efficient and reliable scientific based digital platform. It is a powerful tool with potential to exclusively use simulation to design molecular composition of surface-active agent for novel chemical production.