bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Implementation of Low-Pressure Operations LPO Projects: Delivering Low UTC Incremental Oil in Low Oil Price Market
Authors: Narwal Tushar , Kumar Kamlesh , Alias Zaal , Agrawal Pankaj , Busaidi Asaad , Al-Hajri Hamood , Kindi Maryam , Muthalaly Mathen , Mohammed Rabab , Abri Zahir , Al Hadhrami Abdullah 
Published: December 2021

Abstract
Southern Oman has several high pressure (500-1000 bar), deep (3-5 km) and critically sour oil fields (H2S/CO2 up to ~10%/25%). Most of these reservoirs are carbonate stringers encapsulated in salt lacking any natural aquifer support. Field Development strategy for most of the reservoirs in the cluster is primary depletion followed by miscible gas injection. No artificial lift mechanism is installed in these fields, as gas flood is expected to provide the necessary energy later. Many of these fields are depleted and reached lift-die out conditions due to high backpressure from the station. To extend the depletion production life, the team came with Low-Pressure Operation (LPO) project for these fields. This concept was successfully implemented in various fields across the 3 production stations in the cluster. LPO concept is a novel, pragmatic and cost-effective solution to continue production from previous lift die-out wells which is first of its kind in the company. This approach helped to utilize the existing infrastructure and ullage available in the facilities and eliminate the need for installing expensive and complex artificial lifts (e.g. ESP) or depletion compressor systems. This resulted in incremental production at very low UTC and low CAPEX requirements during the low oil price period.
An Integrated and Automated Workflow to Enhance Production Efficiency and Compliance in a Giant Offshore Field
Authors: Zhao Wenyang , Al Qubaisi Salama Darwish , Al Kindi Salem Ali , Al-Feky Mohamed Helmy , Al Shehhi Omar Yousef , Sugawara Yuki 
Published: December 2021

Abstract
Daily production compliance is fundamental to sustain reservoir management excellence and ultimately achieve an optimum oil recovery. The production activities execution is critical to adhere to the reservoir management guidelines and best practices. It is a more challenging task in brownfields due to the limitation of controlling system and limited access especially in offshore fields. A timely and efficient approach is undoubtedly necessary to enhance production efficiency and compliance. An integrated and automated tool has been innovated to analyze and report well production status against the guidelines and requirements in a mature offshore field with more than 50 years history. This systematic approach has been developed through integrating the planned rate, daily actual production rate, latest flow tests, and current well performance. Noncompliance is reported automatically on a user defined time scale, including daily, weekly, monthly or any customized time range within the month time. Daily violation report is generated automatically and sent to production operation for prompt adjustments and other requested actions.
The automated workflow enables both daily production reporting and production compliance reporting. Daily production reporting is a routine work, which usually takes a lot of time every day. The workflow is capable of reducing 90% of the time comparing to the manual way. Production compliance reporting is currently mainly focusing on the comparison of actual production to planned rate and guideline rate. Any exception will be reported as violation. The violation dashboard summarizes the details based on the user selected time range. On daily basis, an email containing the violation details could be generated and sent to the corresponding teams for corrective actions. In this giant brown field, production GOR is a primary controlling parameter. The latest flow tests have been taken into account to evaluate the gas production compliance. Any violation to the GOR guidelines will be reported in the same communication email for timely correction. With the innovated tool, the violation ratio of the giant offshore field has been successfully reduced and controlled. The usual responding time for corrections has been dramatically reduced from months to days.
Stimulation Workflow Applied on LAPA Pre-Salt Carbonate Field Deep-Water Brazil
Authors: Pedrosa Hélio Alves , Colbert Felipe Costa , Garcia Fernando Marques , Gachet Raphael Fernandes , Boldrini Alberto Carlos , De Souza Jose Marcio , Carrara Marcelo Oliveira , Okullo Ruhhiyyih Audi , Belisario Joan Hernandez , Lacerda Ly Amaury , Goyallon David 
Published: December 2021

Abstract
Lapa is a pre-salt deep-water field located around 270km off the coast of São Paulo, Brazil at Santos basin. This carbonate reservoir lies in water depths of around 2,100m and can produce good quality light 26° API oil. The stimulation in large carbonate reservoirs is very challenging, and techniques used for Lapa were based on chemical divergence. The development in offshore environments requires proper planning, execution, and monitoring to achieve the desired results and, of course, profitability.
The matrix acidizing method was chosen to stimulate all wells of this campaign (2 producers and 2 injectors). This method consists of bypassing formation damage and stimulating the reservoir by creating wormholes via chemical pumping. In the design phase, stimulation operations previously performed at this field were reviewed, analyzed, and optimized. The main changes were regarding the completion strategy without the use of coiled tubing and placement during the completion phase as it could optimize the time and the cost for the project. The volumetric rate (gal/ft) was also reduced and the selection of the main fluid changed after several laboratory analysis and software simulations.
The Lapa field requires high fluid volumes due to the length of the intended treatment interval. The assembly of a stimulation plant on a supply vessel from operator fleet (multi-purpose FSV – field support vessel) was the most cost-efficient approach to address the high volumes required as there was no Well Stimulation Vessel (WSV) available "on call" in the Brazilian offshore market at that time. This solution could also optimize the vessel fleet while the vessel was not required for pumping as FSV was also equipped with ROV and was mean to carry subsea planned task. The fluid test strategy was also a key point for this successful project as many tests were performed to make sure that the correct fluid system was selected. During this process, several fluid systems and different formulations were submitted for core flow tests and dual core flow tests to evaluate worm holing efficiency of retarded fluids and diversion performance of Chemical diverters. Compatibility tests were also performed, and a mud cake breaker was developed locally, especially for this project.
This paper will bring an overview of all aspects regarding Lapa stimulation project since the conception, fluid system selection, laboratory tests, lessons learned and the potentially future strategy for this field.
Smart Crude Desalter Monitoring System Using Capacitance Based Technology
Authors: White Ramsey James , Al-Hamoud Abdullah Abdulrahman , Lopez Miguel Angel 
Published: December 2021

Abstract
Saudi Aramco operates several electrostatic coalescers for bulk emulsion separation and crude desalting. One of the major challenges in operating electrostatic coalescers is the potential buildup of tight emulsions and a rag layer at the interface layer, which causes short-circuiting of the electrostatic grids which increases the risk excessive carryover of water with the crude. Conventional liquid level instrumentation cannot measure the thickness of emulsion layers since the level taps are at the clean oil and water layers. Consequently, the buildup of emulsions is normally not detected by operators.
A capacitance-based emulsion detection system was installed at one of the electrostatic coalescers of a Saudi Aramco facility. The system is comprised of multiple probes installed at various elevations in the vessel. Each probe measures the capacitance of the liquid in which it is immersed in. The data is then transmitted to the DCS, where an algorithm computes the oil/water content. Saudi Aramco developed an enhanced predictive alarm logic and advisory tool using the measured capacitance data so that operations may take preemptive measures to prevent upsets from occurring.
The alarm system was tested over an extended period of time and it has shown that it can accurately detect the buildup of emulsions prior to an upset in the electrostatic coalescer. What is unique about the system is that it utilizes a combination of absolute capacitance measurements and capacitance variations in the algorithm. Emulsion buildups are detected by the alarm system hours before a potential upset, providing operators ample time to take preemptive measures such as increasing the demulsifier injection rate, desludging the vessel or lowering the interface level. The system significantly reduced the number of electrostatic coalescer upsets at the facility and crude quality was enhanced. Upon inspection of the probes during shutdowns, no buildup of deposits, which impacts capacitance readings, were found on the probes since a flushing system was installed. The alarm system has been utilized for four years with no major issues.
Utilizing the capacitance probes to develop an algorithm for an alarm system is a novel technique to detect emulsion layer buildup hours prior to a potential electrostatic grid upset. Large-scale deployment is more economical as it is more cost-effective than radioactive profilers and is logistically easier to manage.
Remote Internet Coverage through Satellite Broadband
Authors: Palit Sujoy , Alteneiji Sherooq Saleh 
Published: December 2021

Abstract
Present day industries worldwide, including oil and gas sector, are going through a transition from the traditional concept of isolated operation to a more cohesive and interconnected digital transformation. The driving forces behind the transformation can be summarized as follows: -A collaborative workplace spanning multiple locations, where the processes can be synchronized through an integrated work management system-Reduced deployment of manpower to remote and hazardous locations through implementation of remote monitoring and control from a central location-Providing intelligent guidance to operation and maintenance through implementation of training, real-time troubleshooting etc.-Informed decision making through historical data, real-time video, lessons learnt etc.-Storage and mobility of data, efficient computing and distributed workload-Machine substitution of human performance (artificial intelligence, drones, robots etc.)
From all these drivers, evolves the concept of Internet of Things (IoT). On the field side, the idea of IoT means to deploy web-enabled devices having unique addressable identity. A plethora of such field instruments, devices, machines, processes and people then need to be interconnected over internet through a robust and reliable telecom infrastructure to make such integrated platform happen. Therefore, on the backbone side, this complex mesh of interconnectivity largely depends on the availability of a feasible and practical communication media. Providing a viable communication media becomes more challenging with the constraints of locations involved – their remoteness, difficult terrains, prevalent hazardous atmosphere, to name a few.
The objective of this paper is to present one such communication scheme through VSAT, which is easy to deploy, economically viable, scalable with growing demand and based on emerging technology of private satellite communication. For the sake of objectivity, this paper discusses most of the scenarios with an offshore oil and gas field, although the idea can be generalized to apply on other sectors and industries.
AR Gauge Scanner Mobile Application
Authors: Althobaiti Abdulrahman , Abdellatif Fadl , Alrasheed Ali , Trigui Hassane , Alsaadi Ahmed , Patel Sahejad 
Published: December 2021

Abstract
This paper showcases an innovative mobile application powered by IR4.0 technologies including augmented reality (AR) and artificial intelligence (AI). The purpose of this application is to enable digital transformation of analog gauges, digitize their measurements, automate historical data storage, visualize trends, and provide useful information about the gauge to the operator. Utilizing this application will replace the current practice of manual recording of readings in order to reduce human errors as well as promote operational efficiency.
With this application, the operator simply points the mobile device's camera towards the gauge and the image is converted to a digital measurement using computer vision algorithms. The digitized readings are sent to a remote database for recordkeeping and data analytics. In order to identify which gauge is being scanned, which is necessary for proper recordkeeping, the application detects a unique QR-code tag attached to the gauge. Additionally, the application utilizes AR technology to overlay gauge specific information (such as gauge type, safe operating range, fluid type, etc.) along with the digitized reading. Visualization of historical readings is another feature in the application that assists the operator in trend monitoring and decision making.
Preliminary tests for the prototype application were carried out in a laboratory environment to demonstrate the working principle of this application. Although the technology is in its early stages of development, it shows promising results in terms of accuracy and speed of the computer vision algorithms to detect and digitize the analog gauges. The historical data recorded by the application can also be accessed via the control room using a web interface, where information from various gauges can be retrieved and visualized for analysis and monitoring. Overall, the presented application integrates computer vision and augmented reality to provide an effective solution for digitizing analog gauges while promoting digital transformation efforts within the industry.
Innovative Use of Wireline Tools Enables Successful Re-Entry on Subsea Wells
Authors: Ragaglia Simone , Napoleone Luca Luigi , Carotenuto Antonio , De Dominicis Guerino , Luppina Salvatore , Mangione Alessandro , Faraoun Abderrahmane , Mourani Houssam , Allegretti Gianluca 
Published: December 2021

Abstract
Re-entry of subsea wells can always hide unforeseen difficulties. Contingency mobilization of coiled tubing (CT) usually gives a wide spread of solutions to overcome most of the possible events.
However, when operating on a winterized semisubmersible rig in the remote fields of the Barents Sea, rig-up of CT spread can be costly and complicated. Furthermore, lighter and easily deployable wireline powered mechanical tools have proven to be effective in tackling most of the possible challenges. Possible tubing obstruction issues can be resolved via clean-out/suction, pumping, or milling methods. In this instance, all three were used with different tools to clear the obstruction from the tubing and to clean with precision inside an internal fishing profile of a well head barrier plug to allow for well access.
The first challenge encountered when re-entering the tubing in Well-1 was the presence of a 151m long hydrate plug. It was easily removed by an e-line tool capable of applying 10 bar of dynamic underbalance, while maintaining a continuous flow circulation. Such an application is a novel development in the use of existing tools.
After removing the hydrate plug, it was discovered that the tubing was plugged by 246m of wax deposits, which were preventing communication with the reservoir. To overcome this problem, a jetting tool was utilized to continuously pump fresh wax solvent inside the landing string. Pumping continuously fresh wax dissolvent provided a unique and effective means to mechanically and chemically remove a significant obstruction.
Once the communication with the reservoir was re-established, an additional obstruction of almost 129m (resistant to the wax dissolvent) was encountered. To overcome this challenge an e-line milling tool was utilized, and the resulting debris was bullheaded down into the reservoir.
Similarly, when re-entering Well-2 a challenge was encountered to pull a barrier plug due to debris deposits inside the internal fishing profile. Both e-line milling and suction tools were sequentially used to resolve the problem and prepare the plug for retrieval.
The tools used were already available on the market for different applications. In this case the tools were used in an alternative way, using their features to solve issues beyond conventional expectations. The result fosters confidence to plan future re-entry without the need for mobilizing a CT spread.
Carbonate Karstified Oil Fields Geological Prediction and Dynamic Simulation Through Equivalent Relative Permeability Curves
Authors: Tarantini Vincenzo , Albertini Cristian , Tfaili Hana , Pirondelli Andrea , Bigoni Francesco 
Published: December 2021

Abstract
Karst systems heterogeneity may become a nightmare for reservoir modelers in predicting presence, spatial distribution, impact on formation petrophysical characteristics, and particularly in dynamic behaviour prediction. Moreover, the very high resolution required to describe in detail the phenomena does not reconcile with the geo-cellular model resolution typically used for reservoir simulation. The scope of the work is to present an effective approach to predict karst presence and model it dynamically.
Karst presence recognition started from the analysis of anomalous well behaviour and potential sources of precursors (logs, drilling evidence, etc.) to derive concepts for karst reservoir model. This first demanding step implies then characterizing each cell classified as karstified in terms of petrophysical parameters. In a two-phase flow, karst brings to fast travelling of water which leaves the matrix almost unswept. This feature was characterized through dedicated fine simulations, leading to an upscaling of relative permeability curves for a single porosity formulation.
The workflow was applied to a carbonate giant field with a long production history under waterflood development. Firstly, a machine learning algorithm was trained to recognize karst features based on log response, seismic attributes, and well dynamic evidence, then a karst probability volume was generated and utilized to predict the karst presence in the field. Karst characterization just in terms of porosity and permeability is sufficient to model the reservoir when still in single phase, however it fails to reproduce observed water production. Karst provides a high permeability path for water transport: classical history match approaches, such as the introduction of permeability multipliers, proved to be ineffective in reproducing the water breakthrough timing and growth rate. In fact, the reservoir consists of two systems, matrix, and karst: however, the karst is less known and laboratory analysis shows relative permeability only for the matrix medium. The introduction of equivalent or pseudo-relative permeability curves, accounting for both the media, was crucial for correct modelling of the reservoir underlying dynamics, allowing a proper reproduction of water breakthrough timing and water cut (WCT) trends.
The implementation of a dedicated pseudo relative permeability curve dedicated to karstified cells allowed to replicate early water arrival, thus bringing to a correct prediction of oil and water rates, also highlighting the presence of bypassed oil associated with water circuiting, particularly in presence of highly karstified cells.
Novel Data-Driven Methodology for Production Allocation Calculation Utilizing Physics-Based Models Coupled and Integrated Within a Digital Framework
Authors: Alsaeedi Ayesha Ahmed Abdulla Salem , Elabrashy Manar Maher Mohamed , Alzeyoudi Mohamed Ali , Albadi Mohamed Mubarak , Soni Sandeep , Isambertt Jose , Tripathi Deepak 
Published: December 2021

Abstract
Determining the production from each well is crucial for financial and technical purposes. Moreover, this production can be anticipated using several different techniques. This paper describes the procedures to calculate the production allocated to each well in a giant gas-producing field by utilizing physics-based models that are orchestrated in a dynamic digital platform to provide a robust and efficient solution.
The cases for this study of allocating gas rates to individual wells were performed using a digital platform as the primary tool utilized to account for the main productional location factors such as well tests and events that are used to estimate actual production volumes. Subsequently, relevant data is extracted, filtered, and loaded into the system in a dynamic interaction with fewer human interventions. The methodology for calculating the production allocated followed these main steps: a) Determine production per well under existing possible measures, b) Determine well contribution factors, c) Distribute actual rates and production according to allocation factors.
By using polynomial equations where the inflow performance of the gas wells was verified, the allocation rates were calculated at every desired point of the network. Having an integrated platform proved to be advantageous since it provided a seamless link between different relevant manual and real-time databases and well / network models bringing unique capabilities and benefits. While comparing this integrated and holistic approach versus the previously established one, it was highlighted that production allocation using mainly choke sizes and well test as a sole source for well production can bring significant variations. This creates production mismatches at the well level; therefore, it portrays a misrepresentation of the actual field conditions. Numerous challenges, which are usually faced while calculating the production allocation process, were overcome during the development of this study, such as frequent surface network changes, lack of databases communication, and daily variations on the on/off wells’ status. Furthermore, the data management capabilities of the framework allowed data to be quickly accessible by the users whenever needed allowing them to visualize across the different teams and departments, taking actions when and where required.
This standardized methodology provided consistency, reliability, and accuracy, which can be replicated on oil-producing fields and networks; it can be enhanced and scaled in order to incorporate other business processes such as well allowable calculation and voidage monitoring.
Evaluating Small vs. Large Power Blocks for Pipeline Compression Stations
Authors: Chhibber Gautam , Dave Mayank Kumar 
Published: December 2021

Abstract
This paper discusses how the application of large, gas turbine-based power blocks (&gt;50,000-hp) in pipeline compression stations can contribute to lower capital costs, improved lifecycle performance, and reduced carbon emissions. For illustrative purposes, two compression facility power block configurations (nine 30,0000-hp trains vs. five 55,000-hp trains) are compared on the basis of capital expenditures (CapEx), operating expenditures (OpEx), availability, efficiency, and operating flexibility. A summary of the study's results are as follows:
– Net present value (NPV) analyses show that 5x55,000-hp ISO trains can result in up to $50 million reduction in CAPEX vs 9x30,000-hp ISO trains – By having fewer trains, operations & maintenance (O&M) costs can be reduced by as much as 20% – Lifetime fuel savings with a 5x55,000-hp train configuration vs. 9x30,000-hp trains are estimated at $40 million, owing to the increased operating flexibility of modern gas turbines, even at partial loads.
The paper will also present considerations for digitalization, modular construction, and package integration – with a particular focus on how these measures can be leveraged to lower execution risk and enhance the lifecycle performance of gas turbine-driven compression trains.