bluuebunny/crossref_metadata_2025_split huggingface dataset:
PDO's First Advanced Process Control Technology Optimizing Condensate & LPG Production
Authors: Al Humeid Mohammed Mustafa Ali , Al Musalhi Abdullah Khalfan Salim , Al Mawali Salim Hamed Thunaiyan , Sharma Vinay Kumar , Al Jahdhami Khalid Mohammed Sulaiman , Al Hamer Ahmed Abdullah Nasib 
Published: October 2022

Abstract
Condensate production needs to be stabilized before exporting it. True Vapor Pressure (TVP) is the standard measure for condensate volatility and is used for Condensate product specification.
Petroleum Development Oman (PDO) exports condensate with a TVP limit below 100 kPa. Whenever the limit is violated, Condensate production is automatically diverted to an off-spec tank for re-processing to bring the TVP below the limit before exporting it. Liquified Petroleum Gas (LPG) is also produced from the volatile condensate with C3 mol% and C5+ mole% specification limits below 18% and 2% respectively. Optimum operation is a point where condensate production is maximized up to the TVP specification limit at the expense of LPG production, and LPG production is maximized up to the specification limits at the expense of flash gas production. The higher the TVP the higher the condensate production, and the higher the C3% the higher the LPG production. However, due to complex process dynamics (excessive time delays between causes and effects) and limitations of the base-layer control systems (the standard setup used in PDO) in dealing with such dynamics, it is practically impossible to continuously perform corrective setpoint changes by the operator. Therefore, the margin between the TVP maximum operating limit and the actual operating point was maintained conservatively at 80 kPa to absorb the variations in TVP without violating the limit and initiating offspec mode.
Advanced Process Control (APC) is an established digital technology that has been deployed successfully in the process industry for decades to handle such scenarios and maximize the output of similar processes without violating any limits. The technology employs a predictive model of the process dynamics to anticipate changes before they happen and apply corrective actions proactively to maintain a steady and optimal operation.
The feasibility study to implement APC for the condensate Stabilization System was concluded in December 2020 and showed that APC will yield an economic value. The APC application was then designed and commissioned in October 2021 with 100% in-house capabilities and have resulted in benefits in line with the estimations of the feasibility study. The success of APC implementation in PDO opens up the door to upstream specific applications to solve optimization challenges that were not possible to solve using existing standard control system (DCS). Figure 1 demonstrates the benefits gained from deploying APC for the Condensate Stabilization System.
Figure 1 Demonstration of APC Benefits
Unlocking the Potential of Slug Control Deployment Using a Newly Developed Foam Chemical
Authors: Sagar Siti Fatimah Sarah , Hendraningrat Luky , Halim Nor Hadhirah , Rodzali Azmeer , Chai Ching Hsia Ivy , Riyanto Latief , Baharuddin Salina 
Published: October 2022

Abstract
The slug flow regime typically forms during multiphase flow in subsurface and surface facilities, which can result in severe flow capacity losses. The foam injection is a proposed method to control and remove slugging in the wellbore and nowadays, the foam application has been extended to controlling the slugging in the pipeline transportation. Prior to a pilot deployment in an offshore Field "S", this study describes a technological assessment review of a newly designed internal foam chemical to control slugging.
This application for controlling foam slugs aims to eliminate hydrodynamic slugs that constantly form at Field "S" due to wave instability at gas-liquid flow rates. Based on liquid level trending at surface facilities platform of Field "S", a slug flow regime was observed from severe fluctuation trending. Technology assessment was conducted using inhouse guidelines that aim to shorten overall pilot deployment to initiate testing as early as possible. The laboratory experiment was performed including compatibility tests. The foam stability and interfacial tension (IFT) were carried out using Teclis Foamscan and Grace spinning drop tensiometer, respectively. Meanwhile, the rheology characterization of foam was conducted using a Foam rheometer for the viscosity test.
A slug flow regime was discovered based on severe fluctuation trending at surface facilities platform of Field "S" for liquid level trending. Utilizing internal guideline designed to hasten the entire pilot deployment and start testing as soon as possible, technology assessment was done. A pressurized foam Rheometer was used to measure the foam dynamic viscosity, and it measured about 5.2 cP at a shear rate of 1000 s-1. The IFT measured lower than with water and other commercial foamer. When the foam chemical, defoamer, and demulsifier were tested for compatibility with production chemicals such scale inhibitor, corrosion inhibitor, and biocide, neither precipitation nor separation was seen. The recently developed foam chemical may help to further reduce corrosion from 0.17 mm/y to 0.05 mm/y. The technical, operational, health and safety, and environmental major unknown elements of this newly designed technology have all been evaluated and identified. Foam created by foam injection is a main challenge with this method, but it has been overcome by finding the right demulsifier and defoamer.
Based on this study, a newly developed foam chemical has been identified as a potential to be deployed in reducing liquid slugging in the pipeline. If slugging can be effectively controlled, value creation will result from an increase in gas and liquid production as well as the avoidance of pipeline maintenance and repair.
A Multi-Layered Strategy to Manage Foaming in Ultra-Sour Gas Sweetening Units
Authors: Al Ali Eman , Srinivas Ravi , Kaleem Jawwad , Srivastava Ganank , Shehata Mostafa 
Published: October 2022

Abstract
Foaming is a major operational occurrence seen in gas sweetening units; causing production losses, off-spec product, solvent losses, equipment corrosion and excessive consumption of anti- foam chemicals. Foaming can therefore shutdown an entire unit if mismanaged.
This paper details a multi-layered bulletproof strategy to manage foaming while operating and designing ultra-sour gas sweetening units. Process simulation models of an operational amine unit at ADNOC Sour Gas (ASG) were built to showcase the positive impacts of each of these recommendations on the performance of the unit. This multi-pronged guideline that adds a safety-net around the upstream separation equipment, sour feed gas, lean amine, and absorber include: (1) Internal modifications to the upstream feed gas separator; (2) Fail-safe design practice around feed separator; (3) Recalculation & modification to the conventional 5 degC temperature approach rule for the lean solvent & (4) Robust differential pressure measurement across absorber.
The above recommendations demonstrated a CAPEX and OPEX saving of US$ 25 MM and US$ 0.6 MMPA respectively to ASG. In addition, reduction in process upsets and pressure drops in the gas circuit generated production related revenues of &gt; US$ 2 million/yr.
Ultrahigh H2S Well-Testing Operations Using Automated Surface Solutions
Authors: Alkhuwayr Asim , Karunakaran Prasad , Malik Mazhar , Youssef Mostafa 
Published: October 2022

Abstract
Automation of surface well-testing solutions has enabled the oil and gas industry to safely explore and produce high-risk wells and formations with unprecedentedly high levels of process assurance and quality.
Surface well-testing operations are regularly performed throughout the lifecycle of oil and gas wells to evaluate potential reserves in exploration wells initially, and later to monitor changes in well or reservoir parameters in producing wells. The collected information is critical to optimizing hydrocarbon asset management.
Such surface well-testing operations present risk associated with control, evaluation, and disposal of produced hydrocarbon at the rig/wellsite. Additionally, these operations can be demanding in terms of manpower because considerably large crews are necessary to operate equipment safely and efficiently.
Furthermore, risks are elevated when high levels of hydrogen sulfide (H2S) gas are present in well effluent because it can present imminent and elevated hazards to personnel health and equipment integrity.
To help address risks associated with high H2S concentrations in an exploration well located in a remote desert location, A new automated surface well-testing technologies for automated control and operation of critical surface well-testing equipment was recently deployed. Incorporated as part of this automated process was a zero-emission gas sampling and analysis technology. Additionally, new criteria for equipment selection and acceptance were adopted to help reduce risks to as low as reasonable when flowing hydrocarbon at the surface with such ultrahigh concentrations of H2S.
Using automated well-testing, sampling, and analysis technologies enabled the safe and efficient completion of three well tests with observed H2S concentrations up to 40% while reducing crew size and removing them from the red-zone area; there were also zero emissions in the working area.
Hydrogen Stress Cracking Resistance of Seamless Pipes for Hydrogen Storage and Transport Applications
Authors: Thebault Florian , Designolle Vincent 
Published: October 2022

Abstract
With an increasing number of projects involving production and use of low-carbon hydrogen, the compatibility with hydrogen gas of assets for storage and transport shall be guaranteed. Indeed, hydrogen is a threat for steel equipment integrity as it promotes subcritical crack growth. In this paper the fracture toughness resistance of a selection of seamless pipes and girth weld for pipeline, OCTG and pressure vessel in pure H2 is investigated. It covers a large variability of materials in terms of microstructures (ferrite-pearlite, bainite, martensite) and yield strengths (from 400 MPa to 700 MPa). Recommendations and requirements provided by ASME B31.12 standard have been followed for this qualification program. Fracture toughness evaluations were performed via fatigue pre-cracked bolt-load specimens exposed to 100 bar hydrogen gas during 1000 h at room temperature. All materials presented hydrogen stress intensity factor thresholds KIH largely above 55 MPa.m1/2, compliant with the ASME B31.12 option B requirement that defines materials requirements for hydrogen service. Data provided can be used for building Failure Assessment Diagram, decisive tool for predicting the safe domain of usage of structures.
Investigating Integrated Chemical Treatments for Iron Oxide Removal in Water Injection Operations
Authors: Al-Ibrahim Hussain Abdullah , Alhamad Luai Abdullah , Alnjaidi Mohammed Ahmed , Alsalem Ali Hussain 
Published: October 2022

Abstract
Quality of water used for injection is a very essential factor in preventing/minimizing formation damage potential due to scale precipitation. Various components in produced water such as H2S, suspended solids, bacteria and other metal ions such as iron are the primary cause of permeability impairment. Injected water should be compatible with both rock and formation fluids, thus the need to find chemical solutions to minimize the impact of injection water on formation rock arises. Potassium Permanganate (KMnO4), and Citric Acid based treatments are experimentally investigated to effectively improve water injection quality and minimize formation damage.
Extensive experimental methods were conducted to determine the optimum treatmentpercentage required to reach optimum water quality, with least amount of scale precipitants. Water samples with high salinity, iron content, sulfates and bicarbonates were used in this study. Additional experimental methods including HT/HP compatibility tests and coreflooding experiments were conducted to evaluate the impact of adding KMnO4 and Citric Acid onformation water and formation rock permeability. Compatibility and coreflooding tests were conducted on different water mixtures to optimize a water mixture having less damage on formation permeability. Experiments were conducted at temperatures up to 250°F and pressure 3,000 psi. Post treatment damage mechanisms were also investigated using XRD and ESEM methods on formed scale due to fluid/fluid and rock/fluid interactions.
The experimental investigation yielded that KMnO4 would reduce the iron content, therefore, eliminating possibility of formation damage. Oxygen scavenger was also added to some water mixtures to halt iron precipitation. HT/HP compatibility test results indicated that no iron oxide precipitation occurred in examined water mixtures after KMnO4 and oxygen scavenger were added. Coreflood experiments showed no permeability reduction in the core plugs although with white solid precipitation noticed on the face of the plugs which was attributed to the precipitation of the insignificant amount of CaCO3 as indicated by ESEM and XRD analysis. Citric acid-based recipe, on the other hand, yielded varying results with different water samples. Some cases showed somehow good water quality improvements with low iron content and others did not with high iron content.
This paper presents an experimental approach to treating and optimizing the quality of water intended for injection using KMnO4, or Citric Acid. XRD, ESEM analysis and compatibility and coreflooding experiments were conducted to assess impact of interaction of different water/water mixtures on clastic and carbonate core plugs permeabilities. It also investigates different formation damage mechanisms associated with water injection.
Low-Cost Multi-Phase Flow Metering and Assays Technology Using Online Magnetic Resonance
Authors: Deng Feng , Liu Huabing , Chen Shiwen , Chen Guanhong , Wang Mengying , Liu Chao , Shi Junfeng , Jiang Weidong 
Published: October 2022

AbstractOn-line, in-situ, and simultaneous detection of wellhead multiphase flow metering and assays is considered to be the best solution to obtain the above-mentioned complete information. However, due to technical limitations, currently wellhead measurement and testing are two different procedures, using different detection methods and even assigning them to different technicians. Online Magnetic Resonance (MR) is considered to be a technology that can effectively achieve molecular-level detection accuracy of oil & gas production measurement and assay after gamma ray technology, and is more environmentally friendly than the former. This work breaks through the flow measurement and testing methods of MR technology, innovates the MR magnet and antenna structure, develops a highly integrated intelligent spectrometer system, and realizes a miniaturized MR multiphase flowmeter (MRMF Smart). The low-cost portable MR tester (MRI Egg) highly integrates MR magnets, imaging coils, and spectrometers to realize multiphase flow in-situ sampling and rapid testing. The realization of this technology not only "moves" the fluid laboratory to the wellhead, but also enables MRI Technology is no longer synonymous with "expensive". MRMF Smart has carried out various tests in 100+ wells in China, the application objects cover conventional and unconventional oil and gas wells, and the application scenarios cover metering rooms, single wells, platforms, and oil and gas testing. The liquid phase measurement error is less than 5%, and the gas phase measurement error is less than 10%. MRI Egg has carried out various tests in 80+ wells in China, application scenarios include water content analysis, fluid composition analysis, viscosity detection, imaging analysis, solid oil content analysis, etc. The realization of the technology has combined the oil & gas metering and assays procedures into one, and jointly develops in the direction of high efficiency, accuracy, green low carbon and low cost.
IMGESA (Integrated Meteorological and Geohazard System Advisory) as Predictive Analytics Tool for Managing Geohazard Impacts to Pipeline
Authors: Rohani Muhammad Joehan Bin , A. Rahman Azam Bin , Abdullah M Syazwan Kamil Bin , Ali M Nazmi Bin , Putra I Wayan Eka , Hidzir Hazwani Binti , Amirian Ehsan 
Published: October 2022

Abstract
There is an industry need to have a fit for purpose whilst accurate method of predicting geohazard impact to pipelines. Geohazard events are influenced by rain occurrences. The effect of rain intensity and duration has been much researched in the context of understanding slope failures in Malaysia's context, however timely prediction of slope failures triggered by rain events that can cause pipeline damage remains challenging.
The major challenge arises from the fact that numerous variables influence the prediction of the target parameters called PR (Risk Index for geohazard impact to pipeline) and pipeline strain predictions. Uncertainties that makes prediction challenging includes but are not limited to soil strength parameters, subterrain geological conditions, occurrences of external disturbances that are outside zone of concerns and also numerous pipeline related parameters that renders understanding influences complex.
To further enhance timely and improved accuracy of predicting geohazard impact to pipeline, new Machine Learning capabilities were used to develop a tool called IMGESA (Integrated Meteorological and Geohazard System Advisory) leveraging on probabilities method to study the features of terrain degradation that are impacted by rain intensity and its duration. New probabilistic algorithms can be used to manage uncertainties. Machine Learning methods can provide the basis for continuous improvement to predictions.
Two main parts in establishing the impact of geohazards to terrain degradation are discussed in this paper: the first is associated with availability of data, namely which data can be considered as main influencer to terrain degradation; the second is associated with development of methodology in establishing the predictive model of PR (Risk Index) and Strain Prediction that can be acceptable by industry.
This paper will explore the issues from these two important parts and will present salient Machine Learning related experiences to provide the much-needed technology enhancement to push the needle in predicting terrain degradation and its impact to onshore assets.
Developing Comprehensive Predictive and Prescriptive Management System for Flexible Pipeline Survivability
Authors: Jaafar Azam Syah Bin , Hussien Hayati Binti , Ali Noor Razak Siti Aishah Binti 
Published: October 2022

Abstract
In 2020, PETRONAS had lost a flexible pipeline due to an increase level of contaminants in the process stream, which carries into the flexible pipeline system. The incident had caused a major cost impact in which the pipeline needs to be replaced and the production had to be differed for at least 1-year. Detail investigation was conducted, and the finding indicates that amongst the root cause was the unavailability of proper predictive and prescriptive approach in managing flexible pipeline integrity system. Thus, this had triggered PETRONAS to embark an initiative to develop a Flexible Pipeline Management System, which then will be included and further developed alongside with PETRONAS digitalization journey.
PETRONAS Flexible Pipeline Management System will be developed by upgrading the existing PETRONAS Digital Management System for carbon steel pipeline. As an overview, scopes for the Flexible Pipeline Management System are comprises of guidelines development, risk parameters establishment, fitness for service (FFS) assessment method advancement, and flexible pipeline remaining life extension study (FLES). Its development started with leveraging on PETRONAS experience in carried out integrity assessment for the existing flexible pipeline with expired design life using analytical method.
The assessment was conducted in collaboration with flexible pipeline integrity experts which had been included as part of PETRONAS capability up skilling program. Progressively, the flexible pipeline integrity management guideline, risk assessment protocol, and predictive assessment method for FFS and PLES were developed and corelated within.
The above elements had been grouped and formed as Flexible Pipeline's integrity assessment manual. It has then been piloted to one of PETRONAS existing flexible pipeline and turned out very successful. The pilot had resulted in eliminating the need of pipeline replacement and generated cost avoidance of more than USD10 Mil - by assessing the remaining life of the pipeline, managing the risk failures through inspection and monitoring plan, as well as minor repair(s) whenever specified.
Iron Sulfide Chemical Dissolver Deployment in Water Wells
Authors: Al-Hajri Nasser M , Ureiga Sulaiman T , Javed Muhammad Imran , Marri Saleh J 
Published: October 2022

Abstract
This paper will introduce a pioneering Iron Sulfide (FeS) chemical dissolver. The novel chemical dissolver can be used for descaling applications in oil and gas wells. However, the particular scope of this paper would be to outline an operational well intervention workflow for a successful deployment of FeS dissolver in water wells.
Iron sulfide scale presence in the wellbore is challenging to oilfield operators. Unlike other common scale types, such as Calcium Carbonates, FeS scale does not dissolve easily in Hydrochloric Acid (HCl) and the FeS/HCl reaction produces the dangerous Hydrogen Sulfide as a reaction product. Accordingly, oilfield operators resort to mechanical descaling of the FeS in order to restore wellbore accessibility. Mechanical descaling has disadvantages that include high cost, the need to flowback downhole milling returns, and possible damage to downhole tubulars. Alternatively, the novel chemical described in this paper can be used to effectively descale the wellbore without exposing the oilfield operator to the setbacks that could encountered from mechanical descaling. This paper will outline operational steps to execute a flagship descaling operation. The operational steps include pre-job diagnostics, job design and contingencies, as well as expected results and outcomes.
The proposed FeS dissolving chemical has successfully met all laboratory and field criteria to descale iron sulfide scale and stimulated well injectivity. The deployment of the FeS dissolver can result in 67 % increase in overall well injection rate compared to pre-chemical descaling rate. Other tangible benefits to this chemical include avoidance of rig workover operations to pull and replace downhole tubing in cases where mechanical descaling was not successful in restoring wellbore access. The new chemical allows for conducting safer descaling operation by reducing risks associated with reproduction of hydrogen sulfide, formation damage from non-friendly chemicals, and downhole equipment damage by corrosion. The chemical also has the ability to dissolve carbonates for near wellbore cleanup. The dissolver has a 70 % enhanced dissolving ability comparing to 15% HCl.