bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterization of Micro-Nano Pore Structures in Shale Oil Reservoirs and FIB-SEM 3D Reconstruction: A Case Study
Authors: Zhang Yunfei , Song Zhaojie , Meng Yufan , Zhang Lichao , Zhou Qiancheng 
Published: October 2023

Abstract
Shale reservoirs in lacustrine sedimentary basins represent crucial sectors for shale oil exploration and development. Given their mixed sedimentation, complex origins, and pronounced heterogeneity, the stratigraphic reservoirs exhibit diverse spatial types. Identifying the characteristics of the shale reservoir, such as the distribution pattern of storage space, porosity volume distribution, reservoir properties, and three-dimensional structure of porosity, assists in pinpointing high-quality reservoirs, thus reducing exploration and development risks. This study examines representative shale samples from three formations of a lacustrine sedimentary basin, analyzing shale reservoir pore size and distribution characteristics, and characterizing the complexity of their porosity through low-temperature nitrogen adsorption and high-pressure mercury intrusion experiments. Argon ion polishing-scanning electron microscopy and focused ion beam-scanning electron microscopy techniques provide an intuitive characterization of the form and size of the shale reservoir space/porosity. In particular, FIB-SEM can reconstruct the spatial distribution of shale on a nanometer scale, authentically reproducing the three-dimensional structure features of shale nanopores, allowing for more precise results in analyzing porosity three-dimensional spatial components, pore size distribution, and connectivity. The study reveals that the quartz-rich Formation A exhibits developed mesopores and macropores in the shale, with large pore and small throat interwoven arrangements. Simple and well-connected pore structures render it easily exploitable, albeit with a smaller storage volume. Formations B and C, dominated by dolomitic shale and mixed shale properties respectively, show extremely developed shale mesopores and underdeveloped macropores. Their complex pore structures house larger storage spaces, indicating high extraction potential. Shale in Formation B, enriched with carbonate rock minerals, presents interwoven arrangements of microcracks and pore systems, featuring a higher coordination number and superior seepage capacity, despite a considerable number of unconnected closed pores. Formation C, having a higher clay content, contains numerous and dispersed isolated pores, incapable of interconnection. Connectivity can only be achieved through a small number of lamellar cracks.
Artificial Lift Real-Time Monitoring Digitalization Method: An Advanced Approach with Artificial Intelligence to Achieve Efficient Well Surveillance by Utilizing SCADA
Authors: Putra Hilman Lazuardi , Tanjungsari Fadhila , Edyawan Wuldan Sokery , Hidayat Azis , Suwono Sugiyanto 
Published: October 2023

Abstract
In Block X, there are a limited number of engineers and a vast number of wells that require to be monitored on a daily basis. Before 2018, engineers must visit each well to survey and monitor its status. This process proved to be inefficient due to the shortage of engineers which was aggravated by arduous journeys to remote areas, and long response time during test line leakage.
To improve the quality of surveillance and artificial lift systems, Medco E&P proposed the installation of Supervisory Control and Data Acquisition (SCADA) monitoring systems. SCADA was installed using Global System Mobile Communication (GSM) modem in ESP wells while SRP wells used Rod Pump Controlled modem. Data from both artificial lift wells is sent automatically to the user's platform through the installed system. By implementing this SCADA system, the data can be acquired more efficiently without the need for engineers to be present in the field. This leads to an effective surveillance monitoring activity where well status can be determined remotely and shorten response time when problems arise. Since the installation of the SCADA system, the average loss potential oil of ESP wells was decreased to around 24% while the down duration was decreased by 33%. These percentages correspond to a savings of $20,000 per month in LPO (Loss Potential Oil) after the implementation of SCADA.
The test line leakage problem can be solved through creating a virtual metering feature using machine learning based on the SCADA data acquired. This virtual metering is used to predict the liquid rate of each well using already existing well parameters without the need for well testing.
The SCADA data can be further used for further analysis to prevent Sucker Rod Pump (SRP) pump failure and increase lifespan of the pump by determining SRP Unit Balance.
Case Study for Enhancement of Production of Heavy and Highly Viscous Crude Oil Using Electrical Downhole Heater
Authors: Kumar Rakesh , Kakati Pinku , Lone Aqib Showkat , Bharadwaj Shailaj , Gurjar Satyaveer Singh , Pathak Diganta 
Published: October 2023

Abstract
It is a very challenging task to produce highly viscous and extra heavy crude oil from the Jodhpur Sandstone reservoir of Baghewala field of Western Rajasthan in India by any conventional methods. The crude obtained are having API in the range of 14 – 17 and viscosity ranging from 8000 to 15000 cP @ 50 deg C.
Considering above, it was planned to extract the oil from around 1100 m by using various thermal and non-thermal techniques. After a thorough study, it was found out that thermal methods performed better than the later in these kinds of fluid.
Accordingly, it was proposed to carry out the trial test with the Electrical Downhole Heater (EDH) in one of the horizontal wells and check the performance in the production rates in comparison with other wells without EDH. Since the maximum pressure loss observed in any heavy oil well is near the perforation, accordingly it was planned to carry out the test by placing the heater in a horizontal section with a drain hole and a slotted casing liner of 7 inch.
The methodology behind using the Electrical Downhole Heater was to increase the temperature in and around the wellbore, which will not only reduce the viscosity of the crude but will also help in increasing the production rate of crude. These kinds of techniques also help in increasing the efficiency of the downhole pumps and help in reducing the drag forces experienced on crude movement due to the presence of various downhole completion equipment. The installation of EDH in any well does not depend much on well integrity issues unlike other thermal EOR methods.
After applying the process, production initially increased from less than 20 bbl/ day to more than 80 bbl/day and stabilised at around 40-50 bbls /day.
This paper intends to present the design, placement, installation and performance of downhole heater in a horizontal well in comparison with a similar horizontal well in the same formation without any heater.
A Decision Method at the Concept Select Stage for Choosing Onshore LNG or Floating LNG Production Facilities for Large Offshore Gas Discoveries
Authors: Meulengracht Chresten Steen , Djukvik Jack Andre 
Published: October 2023

Abstract

Objectives/Scope
Several offshore areas with large gas discoveries (&gt; 2 Tcf of reserves) that are distant from markets now have 2 different LNG development options. The first is the classical onshore LNG production facility and the second is the offshore floating LNG (FLNG) production facility, a comparatively new development solution. This paper examines both options from technical and economic perspectives and proposes a method for selecting the best development solution at the Concept Select stage.

Methods, Procedures, Process
Appropriate gas production profiles and costs including DRILLEX, CAPEX and OPEX were determined for 2 remote prospective gas basins areas - Australia's North West Shelf and the Rovuma basin offshore Mozambique. Both areas have comparable physical settings in terms of reserves, reservoir depth, water depth and distance to shore but they are different from a gas industry maturity perspective. Australia's North West Shelf has both onshore LNG facilities and the Prelude FLNG in operation and is a mature oil and gas area with significant local construction and operational experience. Mozambique's Rovuma basin now features the Coral South FLNG in production, and several onshore LNG production facilities are being planned. However the latter area is in the early phase of building upstream construction and operational expertise. The technical analysis was based on a comparison of key physical settings and project parameters such as production profiles, costs and schedules. This was performed for both FLNGs and onshore LNG production facilities in the 2 mentioned areas. The economic analysis was based on detailed after-tax cash flows of all technical options and provided the key economic metrics for both types of solutions in both areas. Where appropriate a portfolio analysis was performed to include the effect of being in tax positions with multiple units (FLNGs) in operation.

Results, Observations, Conclusions
The technical and economic analyses were combined to create decision tables for both mature and less mature areas. These tables can be used as a tool at the Concept Select stage to determine under which conditions that an FLNG (or several) is a preferable development solution to onshore LNG, and vice versa. The method was applied to relevant examples.

Novel/Additive Information
The floating LNG production facility is a relatively new development solution for remote offshore gas discoveries compared with the classical onshore LNG supplied with offshore gas. The novelty of the developed decision tables is that they provide a simplified approach for making high level decisions on whether to choose onshore LNG or floating LNG production facilities at the Concept Select stage.
Best Practice Utilising New Drilled Well Data to Improve Workover Performance in Existing Old Wells
Authors: Rahman Yudi , Tjahjono Hendro , Al Marawi Faizal , Anggreiny Yayu 
Published: October 2023

Abstract
KILAU Field is a mature field that produced through primary recovery. Managing mature field to keep performance in existing wells has many challenges, especially in performing workover activity. With limited data to knowing current subsurface condition, it has a high level of uncertainty in achieving a success rate in workover activity.
In 2021, 10 workover programs were executed but success rate was only 30%. Five jobs were failed with no oil gain and others only delivered average 19 BOPD/well. Part of improvement process, it conducted lookback to find the root cause. The result observed that if the well was produced from A-1 sand, it would have failed. The type of well completion, both even produced with commingled completion or single completion were failed since producing the A-1 sand.
Detailed subsurface review as part of lookback process was carried out. It turns out that the A-1 sand, based on log data from new wells (which were drilled in Q3-2021 until Q1-2022), shown that the level of OWC (Oil water contact) has clearly raised, or the oil already drained. So, if the well was perforated or produced from A-1 sand, then the production of the well will experience high water (high WC).
Another analysis result obtained from information of new wells was a high oil opportunity in sand of A-3, A-5, & C-1. So, the new wells log data told the mystery of the current condition of the subsurface. This very meaningful information enabled revised strategy to optimize existing old wells.
This paper discusses how to utilize new wells data to improve success rate of doing workover job by integrating updated subsurface information and production data though well log correlation and mimicking the completion of high production wells. The improvement process has been carried out in 7 wells through workover programs, which targeted reservoir A-3, A-5, & C-1 and to avoid producing sand A-1. It was obtaining a 100% success ratio with total oil gain of 966 BOPD.
Can Artificial Intelligence Enhance Gas Well Deliverability Testing? Exploring the Application of Machine Learning in Backpressure Testing
Authors: Bestman Somiari , Almahdi Rasheed Mahdi , Alyomny Assem Ahmed , Lawson-Jack Awoye 
Published: October 2023

Abstract
A deliverability test is a flow test performed to generate data utilized in the characterization of the short and long-term production performance of a well for various conditions of reservoir and bottomhole pressure. The generated data includes bottomhole pressure and temperature, flowing wellhead pressure and temperature measurements as well as the associated flow rates. An analysis of the acquired data ultimately yields a well model capable of predicting a tested well's productivity under stipulated conditions.
This paper presents a methodology by which the data output from a flow-after-flow test may be generated without ever performing the actual test. A machine learning (ML) model developed and trained on historic production data is used to simulate a producing wells performance at several rates as is typical for an actual flow-after-flow test.
The methodology utilizes a ML model trained on recent historical production data comprising of flow rates, flowing pressures and flowing temperatures, measured at surface and/or downhole. The ML model is then used to predict the flowing pressures and temperatures for a user specified flow rate. In its current form, the model is designed to utilize a continuous data stream that may be from a real time or archived source. The model may also be adapted to utilize data with a batch type configuration.
By minimizing the need for actual deliverability tests, or altogether eliminating the need for testing, operators stand to benefit immensely. The benefits include minimization or reduction of costs associated with testing requirements, curtailed production, as well as the minimization of emissions.
Novel Compact Integrated Cyclone and Filtration System for Solid Mercury Removal
Authors: Mohd Sahak Muhammad Zakwan , Myo Thant Maung Maung , Alias Azila , Abdul Salam Safwan , Ehsan Muhammad Ariff Asyraf , Mohd Hanafiah Ahmad Syukri Na'im 
Published: October 2023

Abstract
Mercury presence in produced fluid poses serious issues to gas production process due to HSSE risk, process disturbance and product quality for export. Mercury management is conducted based on type of mercury presence, for instance elemental mercury and solid mercury. For elemental mercury, adsorbent is typically being used, while solid mercury removal is managed via filtration. However, established mercury removal strategy is limited to "single" phase (gas, hydrocarbon liquid, water) thus can only be carried out post phase separation, while there is no available mercury removal technology for full well stream (FWS) treatment as early as at the wellhead.
A novel compact separation concept based on integrated cyclone and filtration design for removing solid mercury in gas dominant full well stream was developed, to allow for flexibility in implementation location (from multiphase at wellhead to single phase post separation) and achieve reliable and consistent separation performance at 1 μm particulate size. Testing with solid mercury particles demonstrated the technology feasibility in removing particles of 1 μm and larger, where particles of 1 μm and larger was not detected by the high-speed imaging camera used at the clean fluid outlet for solid monitoring. CFD simulation conducted provided reference on the feasibility of the technology based on fluid regime and dynamics in removing solid mercury at test conditions, as well as at intended site conditions. A reliable and flexible solution is key to ensure effective contaminant management from the target production, and safeguarding production loss due to contaminant presence in the long run.
The Guiding Principle of Well Placement to Maximise Hydrocarbon Recovery through Enhanced Reservoir Characterisation and Prolific Seismic-Driven Approaches
Authors: Zulkipli Siti Najmi Farhan , Hendrawati May Sari , Abdullah Noor Azmah , Hardiani Rosidah 
Published: October 2023

Abstract
Finding the best well location to drain the remaining hydrocarbon volume often poses a challenge particularly in the absence of good quality seismic data, presence of heavy fault compartments, uncertainty in the production data and limited well penetration in the surrounding area. Targeting the well penetration solely based on the brightest seismic amplitude carries significant uncertainties which may undermine the project economics and attainability. Aggressive well surveillance, sand correlation and lateral connectivity are among the mitigation measures taken to minimize the uncertainties. This paper will highlight several case studies and best practices of improving technical success in well placement through various well intervention, data acquisition and seismic-driven approaches to maximize the drainage volume and recovery.
Several infill wells have been drilled post proactive seismic reinterpretation to include the RGB blending, VpVs and also spectral decomposition approaches. Regional geological understanding on depositional environment, reservoir body geometry and rock quality delineation have improved as a result. Drilling multiple pilot holes dedicated for data acquisition, intervening nearby wells for fluid contact surveillance and effectively geosteering the pay zones to maximize hydrocarbon recovery have been properly planned and conducted during the project execution. In addition, identifying zonal flow contribution and reinventing continuous gas lift supply during well unloading, strategizing well drilling and testing sequences and prioritizing cement barrier for zonal isolation throughout production period are also emphasized to gain fruitful production insights.
Results from the post drill well test operation indicate that more than 3000 barrels cumulative oil and 25 MMBOE cumulative gas had been successfully produced following the rigorous intervention and prolific subsurface approaches mentioned. Production has sustained since from beginning till now which helps to arrest the field production decline by 22% and sustain the gas supply for regional gas network for power generation.
In conclusion, strategic well placement and production play a key role in determining the success of monetizing the remaining hydrocarbon reserves in a mature producing field. Integrating various subsurface lenses and guided by prolific seismic perspectives will reduce the uncertainties and open up more pathways to maximize the production.
Optimization Chemical Acid Stimulation by Improving Selection Intervals in Lateral Section of Horizontal Well in X Field Heavy Oil Steam Flood
Authors: Fatichin Fatichin , Paksi Willy Rhauda , Apriyanto Zepri 
Published: October 2023

Abstract
The production of horizontal wells in X field has decreased since 2019-2021 at a decline rate of 40% per year. Therefore, it is essential to increase production of horizontal wells through proper and effective jobs. The decreased production rate of the horizontal well due to plugging by CaCO3 scale in the wellbore along the lateral part of the horizontal well. It is because during the process drilling horizontal well using a fluid loss additive in the form of CaCO3 to prevent total loss circulation. To eliminate the problem of plugging scale along the lateral section of the horizontal well, chemical acid stimulation job is required. Some chemical stimulation jobs on horizontal well have been carried out, such as acid bullhead, solvent bullhead, and chemical acid CTU (Coiled Tubing Unit). The chemical bullhead work in 2020 is less effective on horizontal wells because it cannot reach the right target on the lateral section of the horizontal well. In 2020 there were 20 CTU chemical acid of horizontal wells were stimulated in all lateral areas even though there were areas that had low resistivity values because the wells penetrated the shaly sand. This has resulted in the ineffectiveness of the acid treatment area on the lateral section resulting in a low average oil gain of 2 bopd/job and a low success rate of 40%. It is caused by two factors, methods, and materials. The first factor is methods due to horizontal wells were stimulated in all areas section of lateral horizontal even though there were areas that had low resistivity values. It caused some of volume chemical acid treated at improper zone in lateral section of horizontal well. The second factor is materials due to HCl15% didn't effective working properly at immature reservoir. This paper shows how to improve two main factors that caused low oil gain and failures job of previous acid CTU in horizontal well. The improvement process must solve both two factors caused failed acid CTU jobs. The first improvement for the factor method by selecting intervals only for zones which have resistivity above 10 ohm and no found cross over between Neutron and Density log. The second improvement is to ensure that reservoir is mature (hot) for candidates of chemical acid CTU horizontal well to ensure that oil will flow from reservoir to wellbore. By improving selection process of chemical acid CTU in horizontal wells, it successfully achieves to improve oil gain from 2 bopd/job to 28 bopd/job, success ratio increased 40% to 98% and decline rate of oil production horizontal well 40%/year to incline rate 14%/year. Besides that, this improvement process success to deliver actual financial benefit about $US 4 MM. The new smart method for selecting effective area in lateral section of horizontal well successfully significantly improve result of oil gain and success ratio in performance of stimulation acid job using coiled tubing in horizontal well.