bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparative analysis of post-procedural symptom patterns after intragastric balloon and endoscopic sleeve gastroplasty
Authors: Castagneto-Gissey Lidia , Russo Maria Francesca , Ernesti Ilaria , Gualtieri Loredana , Genco Martina , Casella Giovanni , Di Lorenzo Nicola 
Published: October 2024

Aim: Endoscopic bariatric and metabolic therapies (EBMTs) offer minimally invasive approaches for obesity management, with intragastric balloon (IGB) and endoscopic sleeve gastroplasty (ESG) being amongst the most prominent interventions. While both are effective, their comparative impact on post-procedural gastric symptoms remains underexplored.
Methods: Single-center retrospective study was designed to evaluate the incidence of post-procedure symptoms in patients undergoing IGB and ESG. Incidence and severity of gastric symptoms were assessed using visual analog scales at various time points. Weight outcomes and medication usage were also recorded. Changes at different time points (baseline, one and four months) were compared by means of Mann-Whitney U Test. Bivariate correlations were carried out through Pearson correlation.
Results: Thirty patients undergoing IGB placement and 13 patients undergoing ESG were included in the analysis. ESG group showed a significant reduction in BMI at four months compared to IGB (32.2 ± 4.2 vs . 34.4 ± 5.3, P = 0.05). ESG demonstrated significantly lower rates of post-procedural gastric symptoms compared to IGB, including nausea, regurgitation, vomiting, and abdominal cramps and greater satiety (P < 0.001) in the early postoperative period. Medication usage differed between groups, with higher usage of antispasmodics and antiemetics among IGB patients during the first week (P < 0.001). Symptom severity correlated with the need for antiemetics and antispasmodics.
Conclusion: This study provides insights into the management of gastric symptoms following two prominent EBMTs. While both endoscopic interventions offer viable options for obesity management, ESG emerges as a favorable choice due to its significantly lower incidence of early post-procedural gastric symptoms. Further research is warranted to refine symptom management strategies and elucidate differences in symptom profiles between IGB and ESG procedures, ultimately aiming to optimize treatment efficacy and patient satisfaction in the field of endoscopic obesity interventions.
Subsea Application of Viscosity Reducers Improves Operational Efficiencies and Increases Oil Production
Authors: Braakhuis G. , Caird S. , Kopowicz M. 
Published: October 2024

Abstract
Crude oil emulsions can be challenging to produce due to high fluid viscosities causing increased frictional forces in the tubing and flowlines, resulting in slug flow, production deferment and poor oil / water separation. Through the application of an Emulsion Viscosity Reducer (EVR) chemical some of these challenges can be overcome, while additional benefits can be achieved. This paper will present examples of EVR applications offshore in the North Sea that enabled increased oil production. The Emulsion Viscosity Reducer was injected via subsea umbilical to a flowline or through the gas lift system into the production tubing downhole. Various parameters such as produced fluid viscosity, bottom hole pressure, well and flowline slugging, and oil production were monitored. The chemical injection rate was optimised based on the monitored parameters. Trials were performed with the chemical injection stopped and re-started so that the effect of the emulsion viscosity reducer is confirmed against numerous baseline data sets. In one of the examples, the performance of a newly developed combination EVR-wax inhibitor product is detailed. Injection of EVR resulted in reduced viscosity fluids being produced and as such various positive effects were observed including reduced bottom hole pressure, mitigation of slugging, choke opening being enabled, increased oil production, improved oil / water separation in the process and reduced flaring. Significant increases in oil production were observed. In the example where the combination EVR wax inhibitor was injected, evidence of improved wax inhibition efficiency compared to the wax inhibitor chemistry alone was observed. The combination of a slight increase in fluids temperature due to shorter transit time as a result of increased and more consistent flow, and the surface-active nature of the EVR chemistry led to the observed improvement. Through this work production parameters which indicate if a well or flowline may be suitable for an EVR application were identified and the benefits of such an application may be quantified. We also introduce the concept of a tool which can estimate the potential uplift in oil production given specific well and production parameters, resulting in methods for other oil and gas production facilities to re-produce similar operations and increase production efficiency.
Early Stuck Pipe Detection Based on Time Series Analysis
Authors: SHI Xiaoyan , Ji Yong , Cui Meng , Wu Dong , Guo Weihong , Jing Lingzhi , Tian Yumeng , Yang Xinyi 
Published: October 2024

Abstract
Recognizing stuck pipe signs in an earlier time and adopting appropriate action can greatly reduce non-productive time during drilling and improve drilling safety. The purpose of this paper is to propose a time series analysis approach and build a reliable and easy-to-use tool to automatically detect stuck pipe accurately and early. Based on the in-depth theoretical analysis and historical stuck pipe data analysis, main early stuck pipe indicators during different drill operations are identified. More than ten time series analysis algorithms and machine learning algorithms are utilized to capture subtle change trends and local change patterns in noisy real-time measured surface data during drilling, and a self-adaptive threshold value determination method is proposed to improve the detection accuracy under different data measurement quality. Moreover, correlation analyses are conducted on the multidimensional time series based on the studied rules and priori knowledge to reduce the false alarms caused by curtain drilling operations. An early stuck pipe detection software tool is built. The tool consumes both real-time and archived drilling data, and provides alarms when stuck pipe indicators are detected. 19 wells’ historical drill data are fed to the tool for algorithm verification, the results show that the tool can automatically detect all 22 stuck pipe incidents in the data set, among which, 5 incidents were detected 2 hours before the field recorded event time, 2 incidents were detected more than 1 hour before the field recorded time, 8 incidents were detected 3-42 minutes before, 4 incidents were detected about the same time as the field recorded time, and 3 incidents were detected less than 2 minutes later than the field recorded time. The average false alarm rate is about once per 48 hours operation time. The tool was also connected to the real-time drilling data in remote drilling operation support center. During the trail, two early stuck pipe signs are captured accurately. The computation time for each real-time data point is less than 0.5 second, which meets the real-time requirement. According to the demonstrated stuck pipe detection rate and false alarm rate, the tool is promising and beneficial for detecting stuck pipe in early time automatically, which improves the drilling safety and reduce non-productive time.
Increasing Natural Dump-Flood Rate from High Pressure Aquifer to Low-Pressure Reservoir to Boost Oil Production Through Economical Shockwave Stimulation Technique
Authors: Zamanuri A. , Chin H. V. , Tran T. V. , Mohamad A. S. Noor , Naziri A. F. Ahmad , Subari I. 
Published: October 2024

Abstract
In a natural dump-flood well that has been progressing for approximately six years, observations were made that only one of the two intended low-pressure oil reservoirs – B2 and B3 reservoirs – is receiving water from the high-pressure aquifer in the same source well. The B2 reservoir which has benefited from the natural dump-flood has seen increasing reservoir pressure over the years and the off-take well commenced production two years after the commencement of the dump-flood. On the other hand, the pressure in the B3 reservoir remained stagnant and the off-take well for this reservoir remained idle throughout the six years of dump-flooding, indicating that crossflow from the dump-flood did not go into the B3 reservoir. Due to these observations, well stimulation through wireline-conveyed shockwave pulsing was selected to stimulate the near wellbore area of the injecting and receiving reservoir to address the issue.
Identifying the root cause of the formation damage in the B3 reservoir is crucial in selecting the ideal method for well stimulation. Based on the available mineralogy test of the field, the formation damage was caused by fines migration due to the substantial amount of migrating fines including Plagioclase, Feldspars, Illites and Kaolinites which makes shockwave pulsing the optimal stimulation method to rectify the issue. During the execution, the shockwave pulsing tool was run inside the well with wireline and placed immediately across the perforation intervals of both the injecting and receiving reservoir. The stimulation was performed with an average pulse density of 60 pulses/foot throughout the entire perforations to remove the near wellbore formation damage.
Three years after the well stimulation was executed, the pressure in the B3 reservoir was observed to increase from 650 psi to approximately 930 psi – a positive indication of successful dump-flood into the B3 reservoir. A further increase of the reservoir pressure was observed to 1050 psi one year later and the off-take well was finally brought back to production with an initial production rate of 500 bopd after being idle for more than 10 years. Several months later, the oil production rate keeps on increasing up to 850 bopd likely attributed to increasing reservoir pressure in the B3 reservoir as a result of the ongoing dump-flood from the high-pressure aquifer.
This initiative has succeeded in re-activating an idle well through cost-effective well stimulation and secondary recovery technique as opposed to the more expensive option of acid stimulation and conventional water injection. This paper seeks to present the overall dump-flood mechanism, well stimulation technique selection criteria and detailed operation of the well intervention activity including lessons learnt and improvement plans which would be valuable for similar operations in the future.
The Geothermal Energy Potential of the West Onshore Canning Basin, Western Australia
Authors: Wilson K. , van Hattum J. L. 
Published: October 2024

Abstract
The energy transition and advances in geothermal energy exploitation have revitalized interest in geothermal power in Australia, evidenced by a rebound in geothermal energy exploration acreage releases by several states and subsequent industry uptake. The natural, regenerative heat of the earth is a practically limitless pool of energy without the intermittency of other sources of renewable energy. Advancements in geothermal technology are dismantling the geological barriers that have limited its adoption. These innovations, primarily derived from unconventional petroleum drilling and completion techniques, have directed geothermal investigation towards Enhanced Geothermal Systems (EGS) in hot dry rocks (HDR), particularly crystalline basements.
In 2023, the Department of Energy, Mines, Industry Regulation and Safety (DEMIRS) awarded six geothermal exploration permits (GEP), with two of these located in the northwest of Western Australia within the onshore Canning Basin. The onshore Canning Basin consists of Ordovician to Cretaceous sediments up to 18 km thick overlain on a Proterozoic-Archean basement of varying composition. The Area of Investigation (AOI) for this study encompasses over 66 000 km2 of the west onshore Canning Basin; namely the Broome Platform and Willara Sub-basin in addition to the Munro Arch and Mowla Terrace.
The USGS's volumetric heat-in-place (HIP) calculation methodology was utilized to quantify the geothermal resource size of the west onshore Canning Basin using a fit-for-purpose basement model from existing sparse geological and geophysical datasets. The P90 HIP across the AOI was determined to be 5.5x107 PJ with an average of 830 PJ/km2. The region of most prospective basement HIP was found to be the southwestern edge of the Willara Sub-basin with the majority of HIP highs measured across the AOI primarily driven by shallow basement, at depths less than 500 m. Volumetric estimations of energy recovery are premature in this study due to the sparse datasets available in the calculation. To determine a recoverable power quantity further studies and exploration well drilling with flow testing needs to be undertaken.
Managing Gas-Constrained Facility: Converting Oil Producer into Gas Injection Well
Authors: Kurniawan M. F. , Desmono L. 
Published: October 2024

Abstract
In accordance with Banyu Urip reservoir simulation for production outlook, produced gas is increasing over time causing the facility to become gas-constrained. With approximately 80% of the gas is being re-injected back for reservoir pressure maintenance, the existing Gas Injection (GI) capacity is limited by the backpressure which is close to the compressor pressure limit. Well conversion helps to resolve these challenges, subsequently allowing more gas production which translates to higher oil production.
Repurposing the existing shut-in oil producers into gas injection wells require surface piping modification. The development of this project needs Surface and Subsurface team collaboration to acquire both hydraulic benefit and meet reservoir pressure maintenance requirement. It mainly consists of:
Well selection criteria for shut-in oil producers Surface piping system modification concept and hydraulic calculation Gas injection wells operation and injectivity performance observation Address challenges from the converted wells (sulfur deposition, schmoo formation, injectivity loss)
Subsurface selection criteria for conversion well candidate include ensuring all perforation intervals are already within gas zone by performing contact logging to evaluate the latest gas-oil contact.
Selecting the appropriate gas supply route proved to be beneficial for gas injection wells operation and performance, as well as for the oil production. Injectivity data suggests that supplying gas injection from the gas lift manifold resulted in lower backpressure by 900 kPag, compared to flowing gas from gas injection manifold. Furthermore, two additional Gas Injection (GI) wells resulted in the significant reduction of compressor discharge pressure, allowing more gas to be re-injected back to the reservoir. It also provides more flexibility to perform one GI well preventive maintenance without continuous flaring.
The project has successfully increased the gas injection capacity by approximately 30%, thus allowing higher produced gas to be handled by the system. It translates to additional oil production of 4,000 – 6,000 bbls/day while maintaining lower emission.
This paper provides insight of successful effort in converting oil producer wells into gas injection wells with a proper measure and precautions for a gas-constrained facility. Simple modification of well conversion proved to be giving higher injection capacity and significantly impact the oil production.
New Production Technology Implementation, as an Effort to Achieve 1 Million Barrels Oil for National Production Per Day in 2030
Authors: Falach Achmad Rocky , Ihsan Alfandra , Kauripan Satria Panji , Warasta Ageng , Dewi Amalia Kusuma 
Published: October 2024

Abstract
Arresting decline and maintaining high existing production is one of the main strategy to achieve Indonesia's main goal oil production one million barrels oil per day in 2030. Most of existing fields in Indonesia are mature fields, where there are no more "easy oil" to boost up production with conventional methods. In other words, we need more advanced technology to seek the possibility to increase production. This paper will describe the effort of implementing new production technology since 2020 until 2023 and how its impact on the national oil production. It is hoped that an overview of the effectiveness of new production technology implementation will be obtained as well as possible improvements or massive implementation that can be made in the future.
This evaluation process was done by analysing new production technology implementation since 2020 until 2023, consist of type of the technology, its direct impact on national oil production, possible contract scheme to open the opportunity and also challenges that we were facing during the implementation process.
Monitoring the implementation started in 2020, where there were eight technologies that successfully implemented which gave production gain around 451 BOPD. On the following year, six technology implemented gave 557 BOPD additional gain. A higher production gain, around 1,778 BOPD, was achieved in 2022 from fifteen technology implementation. And, last in 2023, there were seven technology giving another success in production with gain around 532 BOPD.
From 2020 to 2023, technology implementation successfully gave positive impact to national oil production, especially on existing wells. Technology implemented consists of sand control technology, artificial lift and stimulation. The more technology applied, the more the results would be. But, factors like subsurface condition, integrity of the wells, contracts, and economics appeared to be the key parameters that determine the success of the technology applied.
Implementing new technology is one of the potential solution to increase production and seek to open new potential for field or wells that could not produce using conventional method. But to make it into a bigger scale and massive implementation would need a solid collaboration between services company, oil company, government, academic institution and other stakeholders also a win-win contract scheme.
Applied Modelling of Shale Oil Cross-Scale Flow Behaviors in Gulong, China
Authors: Lei Zhengdong , Ge Chenqi , Ji Dongqi , Peng Yingfeng , Zhang Guangming , Chen Zhewei , Liu Yishan 
Published: October 2024

Abstract
Gulong shale oil is characterized by abundantly enriched nanopores and bedding fractures. A critical challenge of shale oil reservoir simulation is the representation of complex cross-scale flows among tight matrix, bedding fractures and hydraulic fractures, which require fine gridding and massive computation. A simulation approach of shale oil flow by combining multiple-interacting-continua (MINC) and discrete-fracture-network (DFN) is provided to investigate the flow behaviors of shale oil. Dynamic bedding fractures dilation under varying reservoir stresses is predicted by the Barton-Bandis model. Compared to the conventional methods of Gulong shale oil simulation by simple grid system, the resultant coupled MINC and DFN model with dynamic bedding fractures consists of an approach at constructing a rigorous relation between the flow nature of the macroscopic hydraulic fractures and the shale microstructures mainly characterized by the presence of shale matrix and bedding fractures. Cross-scale flow behaviors are investigated and numerical simulations are performed to efficiently predict production performance in Gulong shale oil reservoir. Relevant analysis based on simulation results suggest further considerations on the efficient modelling of cross-scale flows in shale oil reservoirs.
Application of Integrated Production System Modelling (IPSM) for Long-Term Production Forecasting and Optimization, a Case Study in Deepwater Assets, Malaysia
Authors: Surin N. , Kok K. C. , Hutamin N. , Rofieq S. K. , MousaviMirkalaei S. M. , Syah G. , Edmondson M. 
Published: October 2024

Abstract
In typical integrated simulation projects involving multiple reservoirs connected to a single producing facility, poor communication between production and reservoir engineers, who use different analysis tools, often leads to unreliable results. CoFlow is an integrated production system modelling (IPSM) tool and platform that helps RE's and PE's overcome these challenges. This work studies how CoFlow was used to provide robust, long-term (10 years plus) production forecasting and optimization for a deepwater oil development in Malaysia.
Currently ongoing deepwater projects off the coast of Sabah are critical to sustaining Malaysia's crude oil output. These projects face high costs due to specialized equipment and subsea infrastructure installation, making it a necessity to simulate the complete fluid journey from the subsurface all the way to the oil platforms to ensure engineering design and consistency during forecasting. One such project, henceforth named Field G, has been built as an IPSM model in CoFlow. An IPSM model includes the reservoir model(s), the wellbore models as well as the piping and equipment that form the asset's surface network.
Field G IPSM model was used to couple two reservoirs and link them to a complex surface network system, whereby the produced gas was separated and re-injected into the reservoirs using a custom algorithm. The IPSM model was operated using network-level constraints, which mimic the maximum fluid handling capacities of certain equipment on the production platforms. This is a unique and often overlooked capability of IPSM models, and it helps to make sure that the system is not producing beyond the limitations imposed by its surface network. The model was run for simulation times greater than 16 years, enabling forecasts that reach critical junctures in the field life such as the end of a PSC. Furthermore, maximum gas and liquid rate constraints were imposed on the models and various well operating scenarios were assessed to find the most optimum solution. All this could not be captured with just regular reservoir simulation, hence showcasing the value and importance of IPSM for large offshore projects.
This was the first time that the G field was collaboratively modelled using IPSM approach and used to simulate forecast periods longer than 10 years. The CoFlow platform provided fast runtimes which allowed the authors to run multiple prediction scenarios and saved many man hours. Moreover, the IPSM model helped capture the complex interactions between facilities and reservoir performance through integration and multi-disciplinary collaboration.