bluuebunny/crossref_metadata_2025_split huggingface dataset:
Revolutionizing Liquid Unloading in Gas Wells: Maximizing Production with Self-Agitating Chemical Sticks
Authors: Wazir N. Ahmad , Rodzali M , Riyanto L. , Zainal S. , Hendraningrat L. 
Published: November 2024

Abstract
During a well's initial operation, high gas pressure and velocity lift water naturally. As the well ages, reduced pressure, and velocity cause water to accumulate, creating hydrostatic pressure that eventually blocks gas production. To resume gas flow, removing the accumulated water is essential. Many removal methods are costly and energy intensive. This paper presents a detailed analysis and evaluation of the technical performance of self-agitating chemical sticks, specifically designed for liquid unloading in gas wells. The operation of self-agitating chemical sticks is based on a reaction between a foam stick and an acid stick. This stoichiometric reaction generates N2 gas, leading to foam formation that lowers the hydrostatic pressure within the gas wellbore. Laboratory evaluations of these chemical sticks, including their unloading efficiency, solubility and the impact of condensate presence were conducted under various simulated conditions at different temperatures and salinity levels. Laboratory evaluation confirmed the superior performance of the self-agitating sticks. The unloading efficiency under various temperatures and salinity levels indicated that the chemical sticks were more efficient at high temperatures above 85°C, where the reaction between the foam stick and acid stick became more vigorous, unloading more than 50% of water under simulated conditions. However, salinity did not significantly affect the performance of the chemical sticks, indicating that they can be applied at any salinity level in the well. The presence of condensate was also tested at various levels, and the results indicated that the performance of the sticks is not significantly affected if the condensate level does not exceed 50% of the well. Solubility tests showed that the chemical sticks can dissolve completely without debris, even at low temperatures. This broadens the potential application of the sticks under any conditions in a gas well. The Self-agitating chemical stick presents a unique character as the gas produced from the reaction between foam sticks and acid sticks is N2 gas compared to typical gas produced by other foam sticks and gas sticks, which is CO2 gas. CO2 gas can alter the pH of the liquid in the wellbore to acidic, increasing the risk of corrosion in the casing and production tubing. Hence, the liquid unloading through the foam formation from the self-N2 gas-generating stick will reduce the risk due to the inert nature of the N2 gas.
Responsible & Sustainable Approach Towards Minimizing Incidental Flaring Events
Authors: Rajpurohit Surendra Singh , Osama Abdalla , Katheeri Mohamed Al , Anilkumar Ravishankar , Almarzooqi Iman , Rashedi Mohamed Al 
Published: November 2024

Abstract
As part of Company's continuous efforts to foster Sustainability, Decarbonizations and GHG emissions reductions, we have introduced a new systematic approach to reduce the frequency and the magnitude of unplanned flaring events across Company fields. This paper examines these cycled phases starting with data collection & initial assessment stage, followed by identification of the bad actors, then classifying them based on their severity and impact. This is further proceeded with utilizing root cause analysis mechanisms where recommended action is implemented accordingly. To ensure the effectiveness of executing the solutions, action and implementation plans will be developed in the final stage. Additionally, this paper explores opportunities and the value added in terms of flaring avoidance, Equipment Availability and Reliability without jeopardizing HSE and Asset Integrity. To ensure a cohesive and efficient response to the flaring event, a centralized task force team has been formed to address the issue comprehensively and implement necessary solutions.
Breaking the Mold with an Innovative, High Performance Retrievable Bridge Plug for Wellbore Isolation Applications
Authors: Fry Oliver , Friesen Jeremy , Aboelnaga Sharif , McGowan Robin , Khokhar Sajid Hussain , Sorensen Alla , Al-Kashgari Ahmed 
Published: November 2024

Abstract
This paper describes a method of overcoming fundamental limitations in conventional retrievable bridge plug (RBP) design to significantly improve oil and gas wellbore isolation operations. By eliminating both elastomer deformation to reach the seal bore and the reliance on elastomer memory to recover to gauge, we can address the industry's need for retrievability combined with the increased performance requirements of higher pressure, higher temperatures, and gas-tight barriers. This approach eliminates significant risks in NPT, well loss and well control and also enables the placement of high-performance retrievable plugs in previously inaccessible completions.
To fundamentally change the trade-off between access, retrievability and performance in elastomer design a novel method of slicing a volume into constituent segments was developed. These segments can be re-arranged, without mechanical deformation, to fit into a smaller annular volume. This allows the construction of sealing elements and extrusion barriers that do not need to be deformed to reach the sealing bore, and do not rely on elastomer relaxation or memory to return to gauge diameter. This makes the retrievability of the plug independent of the material degradation issues that typically occur to the elastomer element downhole, particularly in high performance applications.
This Segmented-Ring Technology forms the basis of a novel sealing system that has been developed offering higher performance (&gt; 10,000 psi) at higher expansion ratios (20%) than any available wireline retrievable bridge plug on the market, thereby allowing High-Pressure, High Temperature (HPHT) gas-tight performance in restricted access completions. The elimination of elastomer memory as a recovery method greatly reduces recovery risks due to compression set, material degradation and Rapid Gas Decompression (RGD). The unique method of reconstructing the seal at the sealing diameter, paired with a modular plug architecture, also allows for new sizes of seal to be rapidly designed and deployed for specific applications.
The new Segmented Ring sealing system has been successfully implemented on multiple plug sizes ranging from 3-1/2"to 7" sizes, and successfully deployed worldwide to address recovery issues and high performance through tight restriction requirements.
Cultivating a Pervasive Data Culture - Establishing the Upstream Data Culture Program in PETRONAS
Authors: Saroji H. N. , Idris N. Md 
Published: November 2024

Abstract
PETRONAS Upstream is on the journey towards becoming a data enabled and driven organization. To ensure that Upstream is data-driven, it must first be data-enabled where data must be available, accessible, actionable and most importantly trusted for it to be consumed to make accurate decisions. However, simply having data that is democratized (available and accessible) and trusted simply does not guarantee success unless it is accompanied by the right attitudes and behaviors. Another significant challenge observed was the lack of data literacy and inconsistent data governance practices among both data creators and consumers. Additionally, the absence of standardized data management processes has been a major obstacle to establishing a trusted data source, which is essential for making accurate and informed decisions. Therefore, the Upstream Data Culture Program was established to address these challenges and most importantly to cultivate a pervasive data culture within PETRONAS Upstream.
The Upstream Data Culture Program was established to shift Upstreams’ mindset from the status quo to a data-driven approach, drawing on the renowned 8-step Change Model by John P. Kotter, a leading expert in business, leadership, and change management. The primary objective of this program is to foster a pervasive data culture by focusing on four key components commonly associated with data-driven organizations: Data Practices, Data Literacy, Data-Driven Leadership, and Data-Driven Decision Making.
Repurposing the Pipeline for CO2 Transportation in the Carbon Capture and Sequestration (CCS) Project
Authors: Amirrudin F. , Hashim W. Wan , Ali Z. , Sam M. Rahmat 
Published: November 2024

Abstract
Field D has been in production for over 40 years, and its output is now decreasing to the point of nearing abandonment conditions. This makes the field an appealing candidate for CO2 sequestration, aiding in the achievement of net zero carbon emission target while generating revenue through CO2 storage services. The processing, transportation, and sequestration of CO2 should be implemented at the minimum life cycle cost to ensure that the tariff imposed on emitters is more attractive than paying carbon tax. The tariff rate can be significantly reduced by converting the existing 205km-long natural gas pipeline from Field D facility to shore as the CO2 injection pipeline for sequestration.
This work highlights several key studies conducted during the feasibility stage to evaluate the viability of repurposing existing hydrocarbon pipelines for CO2 transportation. The feasibility study covered the flow assurance aspects elaborated in this paper, focusing on selecting dense or supercritical fluid versus gas-phase transport and flow assurance issues encountered in pipelines and injection wells. Effects on pipeline design and operating philosophies were also evaluated. Worst-case operating scenarios were thoroughly examined to establish the range of acceptable moisture content, impurity composition, and corrosion concerns, taking account of the use of corrosion inhibitors. A risk assessment was also conducted to identify mitigation plans, which included, among other things, material testing to be included in the action plan.
Evaluating an existing pipeline for suitability to convert to CO2 transportation service is challenging due to the need to access historical operating data and mechanical integrity data. According to the pipeline fitness for service (FFS) study, the flow assurance analysis determines the optimal design and safe operating envelope for the pipeline with CO2 service. Corrosion assessment was performed in enhanced-Multicorp software using inputs from flow assurance analysis to identify potential corrosion rates (CR) for CO2 service with presence of moisture and free water in the pipeline. The study also identified suitable corrosion inhibitors with expected dosages to suppress high corrosion rates in CO2 service when free water is present. Despite the data limitations, the feasibility of conversion was successfully demonstrated. To fully mitigate the risk, material testing on the existing pipeline will need to be conducted as a further precaution. This study offers valuable insights into the challenges and methodologies for converting existing natural gas pipeline to CO2 service in the early stage of CCS development.
Amalgamating Biosteering and Productivity Index Trend Analysis on the First Underbalanced Coiled Tubing Drilling (UBCTD) Injector Well in the Middle East to Improve Well Performance in Real-Time
Authors: Saradva H. , Mortimer E. , Robert M. , Jain S. , Rennox J. , Rivadeneira E. 
Published: November 2024

Abstract
Sharjah National Oil Corporation (SNOC) undertook an Underbalanced Coiled Tubing Drilling (UBCTD) drilling project to improve three wells’ performance in its gas-storage reservoir. The project's success was crucial towards ensuring energy security in Sharjah and increasing the operational capacity of the gas-storage reservoir. A unique combination of biostratigraphy, production data and bottomhole drilling parameters was applied to maximize lateral length in the high productivity reservoir zones to support this vision.
The three-well UBCTD pilot campaign involved setting a whipstock in a 7″ liner, milling a casing exit for sidetracking, and drilling 3-5/8″ lateral wells. The laterals utilized UBCTD technology and methods to eliminate formation damage, enhance production, and improve drilling performance.
An integrated real-time biosteering, productivity index (PI), trend analysis and sub-surface geological monitoring methodology was adopted to achieve the project objectives. Biosteering was performed by preparing thin sections from cuttings samples and petrographic analysis conducted to identify indicative microfacies and microfossils. The analysis was integrated with gamma ray (GR), logs to identify the reservoir layer and stratigraphic position of the drill-bit relative to the target reservoirs.
The integration of biosteering, PI trend analysis, and sub-surface geological monitoring aimed to optimize drilling and production efficiency. The well's measured productivity was transient during drilling, leading to a "pseudo-PI" calculation. While this was not a reliable predictor under steady-state conditions, it effectively indicated productivity when the drill bit intersected the reservoir. Flow rate changes signaled the impact of drilling zones, with increased rates indicating enhanced productivity. Concurrently, the formation's biostratigraphy was assessed, recording trends across multiple laterals to identify productive biozones. Geosteering then optimized lateral trajectories within these zones to maximize productivity. This holistic approach allowed for real-time adjustment, ensuring drilling and production activities were aligned with reservoir characteristics, ultimately enhancing overall efficiency and output.
This paper underscores the benefits of integrating data from diverse sources to enhance reservoir and well performance analysis. It also highlights the pitfalls of information silos hindering data sharing among teams striving for a common goal. As a comprehensive guide, this paper provides an in-depth discussion of a workflow that integrates drilling, formation, and reservoir data to optimize productivity enhancement strategies.
Using Data-Driven Tubing Head Pressure Proxy for Integrated Production Network Coupled with Subsurface Models: A Way to Improve Computational Speed While Keeping Real Field Limits and Prediction Accuracy
Authors: Limsukhon P. , Sarbas Z. , Kabdenov S. , Abubakirov Y. , Iskakov E. 
Published: November 2024

Abstract
The coupling of surface and sub-surface modeling approach has been deployed in managing short- and long-term forecasts in the industry over the decades. Computation time for the fully coupling model poses a real challenge for long term forecast. The compromise solution was proposed for long term reservoir management studies, where surface networks are removed from the fully coupling model. The key challenge to this approach is the assignment of the wellhead pressure constraints, which are retrieved from surface network in fully coupled model.
Multiple assumptions of constant wellhead pressures were tested with random success of replication to fully coupled model results. The field level forecasts were reasonably reproduced; however, the reproduction was not achieved at gathering stations which are several kilometers away from each other. This poses a potential divergence of regional depletion rate of reservoirs from fully coupled model forecasts, which could impact reservoir management studies. The advancement of native functionality of reservoir simulator allows parameters to be calculated dynamically. Thus, "Tubing Head Pressure (THP) Proxy" was proposed to dynamically calculate values of wellhead pressure constraints over forecasting periods, where the pressure values calculated from subsurface models are close to solutions derived from fully coupled model.
The production forecasts with coupled subsurface models and THP proxy show excellent representation of fully coupled model at a significantly shorter turnaround time. The usage of THP proxy resulted in 4.5-fold decrease in computational run time compared to fully coupled model with the 0.3% error in cumulative oil produced at the end of concession production forecast date. For end of field life forecasts, the run time optimization achieved nearly 3.3 times reduction compared to surface and subsurface coupled model with the reasonable match for total volumes produced for the given period. The robustness of the solution over the wide ranges of reservoir management options and subsurface model ranges (P10, P50, P90) was observed. The possibility of evaluating surface system debottlenecking options using THP proxy was also explored and tested.
This paper describes the workflow which is aided by data science/analytics that generates THP proxy functions and integrate them into coupled subsurface modeling. This method helps enterprises to greatly improve the speed of long-term forecast deliverables from business planning & reserves booking processes, and governmental regulation documents that support the field development plan while maintaining the actual field constraints and prediction accuracy.
Optimization of the North Kuwait Jurassic Gas Integrated Production System - Modelling, Optimization, Impact
Authors: Alarouj M. , Akbar Y. , Al-Shuaib M. , Al-Saleh A. , Al-Salali Y. , Moes E. , Kosuke N. , Matvinko A. , Marketz F. , Saxena A. 
Published: November 2024

Abstract
Production System Optimization (PSO), an established Industry best practice for well, reservoir and facility management (WRFM) has been implemented for the North Kuwait Jurassic Gas (NKJG) asset with the objective to review, model and optimize the integrated production system (IPS). The focus of this paper is to describe the IPS, the modelling strategy, model results and the impact of PSO in NKJG.
The NKJG IPS consists of eleven fractured carbonate HPHT sour gas fields, with the majority of production coming from Middle Marat reservoir layers, approximately 270 producer wells, an extensive flowline network and six production facilities. The IPS was reviewed and modelled following a field-by-field approach starting with the relatively smaller Dhabi (DA) and Abdali (AD) fields, followed by upscaling and refining the reviews and models to the larger North-West Raudhatain (NWRA), Raudhatain (RA), Sabriyah (SA) and Umm Niqqa (UN) fields. Integrated production system modeling (IPSM) was conducted to quantify constraints in the IPS, construct limit diagrams and to estimate PSO gains from removing well, flowline network and facility constraints. Well modelling was conducted to assess well flow stability at larger choke sizes. Reservoir modelling was conducted to assess the long-term sustainability of optimization gains. Based on PSO gain estimates, opportunities were ranked, prioritized and executed. Incremental gains were measured and compared with estimates.
IPSM modelling demonstrated that the key opportunities to optimize the NKJG IPS are choke optimizations, flowline de-commingling and reducing facility inlet pressure, the largest PSO potential is in the largest field and that the flowline network is the dominating constraint only one medium-size field. Well modelling confirmed flow stability at larger choke sizes for the majority of identified bean-up opportunities. Only a limited number of choke optimization opportunities exist in fields with water production where gas well deliquification is required to restore and optimize well performance. Field-level reservoir modelling showed that PSO gains are sustainable in the long term. Realizing priority opportunities has contributed to achieving an asset gas production record. It was concluded that the integrated use of IPSM, well and reservoir models for PSO has generated an improved understanding of the NKJG IPS and, combined with effective opportunity management has a substantial impact on asset performance.
Maximizing Reservoir Potential: Coiled Tubing Multilateral Extended Reach Intervention for Acid Stimulation
Authors: Chishti S. S. , Correa P. , Alabdullah M. , Ahsan M. 
Published: November 2024

Abstract
Multilateral well designs have been gaining demand, aiming to expand the recovery of hydrocarbon or injection of recovered fluids, depending on application. The primary challenge in such well completion is accessing the unnatural laterals, followed by extending the coiled tubing (CT) depth reach at which the stimulation treatment can be delivered, which is normally restricted by the friction lock limit. This paper presents a solution for multilateral extended reach CT stimulation.
The producing multilateral well was completed as dual open hole laterals, from completion to open hole, increasing the friction coefficient and reducing the maximum reach. The application of a reliable hydraulic multilateral entry tool (MLT) and an extended reach tool (ERT) was proposed, which provided a reliable option to access the un-natural lateral and extend the reachability of coiled tubing for stimulation. The BHA included a real time integrated sensor tool and casing collar locator (CCL), powered by a reliable single conductor system for telemetry. The use of real time data provided confirmation on accessing the correct lateral.
The use of an MLT is mandatory to enable CT entry into the lateral leg. During intervention, the access depth to the lateral window was located with the use of CCL for depth accuracy, followed by pressurizing the MLT to a predetermined pressure for the tool to begin the search mode, indexing the wand section of the tool and enabling it to complete a mapping cycle by continuously rotating 360° in less than 2 minutes. A pressure drop signal will indicate that the window has been located and rotation will then stop with full kickoff achieved. If there is no pressure drop, the tool will complete full rotation and is reset to straight position by increasing pressure to a predetermined value. CT is then moved to next mapping depth and new cycle is started. Upon locating the window, the indexed wand section is run in hole (RIH) into the lateral past the access window and CT is stopped to reset the tool to extended position and allowing fluid to be continuously pumped through the ERT and the MLT. At this point, the ERT is activated, and it helps CT RIH past the default friction lock limit to perform stimulation at a deeper depth.
The combination of these technologies, prove to be an effective option to increase the working envelope of smaller OD CT in multilateral extended reach interventions, challenged by the offshore work environment. This application translates to an increased footage of direct stimulation in the open hole section and maximizing the reservoir potential.