bluuebunny/crossref_metadata_2025_split huggingface dataset:
High Fluid Loss Squeeze and Reticulated Foam Lost Circulation Material LCM Plugs 40,000 Microns Lab Simulated Fracture/Vug Opening
Authors: Savari Sharath , Butcher Jacques , Al Hulail Mustafa 
Published: October 2022

Abstract
Controlling severe to total lost circulation in naturally fractured/vugular formations has always been challenging, especially in carbonate formations across the Middle East. In these environments, conventional particulate lost circulation materials (LCMs) may not be effective due to the uncertainty regarding fracture and vug sizes. This paper presents an extension to previous work on a high fluid loss squeeze (HFLS) and reticulated foam LCM, providing further technical justification for implementing this technology to cure severe to total lost circulation events.
An earlier paper presented laboratory evaluation methodology, test results, and field application of the subject HFLS and reticulated foam LCM. At the time, laboratory test data was presented for an LCM combination that could seal a laboratory simulated fracture size of 9,800 microns.
In the current work, a similar laboratory test set up was used to evaluate the efficiency of this LCM combination to seal larger size openings. An adapter with an opening size of 40,000 microns (1.57 inch/4 cm), was used and the combination of HFLS and reticulated foam LCM successfully sealed the opening when tested using an industry standard test set up. The LCM combination was also weighted with barite to determine if the sealing performance was consistent for anticipated applications.
The LCM plug formed in the test set up was evaluated for the maximum differential pressure it could withstand in wet conditions, as well as its compressive strength. Under wet conditions, the plug withheld 4,000 psi differential pressure and yielded a compressive strength in the range of 3,170 psi to 4335 psi in duplicate tests. The plugs were also analyzed using CT scanners to visualize the alignment of foam and the particles within the plug. The additional test data supports a more detailed assessment of the LCM combination for specific applications prior to deployment.
The results of this extensive laboratory testing on a combination of HFLS, and reticulated foam LCM demonstrates the potential of such materials for reducing or curing severe to total lost circulation events in naturally fractured/vugular formations. The test data presented in this work is the first to be reported in the petroleum industry literature for any comparable LCM at 40,000 microns fracture/slot size.
The most notable advantages of improved LCM technology are the increased control of hydrostatic pressure in the well bore by minimizing fluid losses downhole as well as a reduction in well construction costs through decreased rig time associated with lost circulation.
New Generation of Environmentally Friendly Nanoshale Inhibitor Water-Based Drilling Fluids
Authors: Alqahtani Hassan Sakar , Al-Arfaj Mohammed Khaled , Alhasseni Mohammed Faisal , Alotaibi Mohammed Abdullah 
Published: October 2022

Abstract
Environmentally friendly Mesoporous Silica Nanoparticles (MSNs) has been used for the first time as a Nanoshale inhibitors in water-Based Drilling Fluids. Nanoshale inhibitors used in this study eliminate the use of toxic high potassium chloride (KCl) concentration in shale drilling operations and reduce the waste management associated cost with drilling fluid treatment and disposal.
The dispersion test of MCM41 Nanoshale inhibitor with Silurian shale samples revealed to be an effective candidate with significant interaction reduction between the drilling fluids and the shale particles. This new Nanoshale inhibitor maintains the integrity of the cuttings and minimize the interaction of fluids with shale sections during the rolling test. XRD patterns has been conducted to determine the crystalline structure of shale and nanomaterial samples.
Although the application of nanomaterials to improve the performance of conventional water-based drilling fluid was studied by researchers, it is the novelty of this research to eliminate use of KCl and to develop the new generation of Nanoshale water-based drilling fluid with economical consideration and lower environmental impact.
Innovative Fluid Technology Enhanced Wellbore Integrity, Optimizing Casing Sections in the Bandurria Sur Field in Argentina
Authors: Cejas Martin , Juaristi Jose Manuel , Hedegaard Allan Claus , Maldonado Reinaldo 
Published: October 2022

Abstract
In the Neuquen Basin in Argentina, the Bandurria Field is notorious for its narrow operational window, which is caused by the difference in pressure gradients between formations. This environment often demands the use of managed pressure drilling (MPD) technology in addition to a robust well design, with several planned sections, and can substantially increase the cost of well construction. To extend the pressure-gradient operative window, the operator opted for a new drilling fluids-focused technology and operational strategy which reduced the number of casing sections. The ultimate objective of the operator was to construct a productive and cost-effective well, while maintaining wellbore stability between challenging formations.
Using a break-even price objective of just over 40 USD/bbl, a strategy the operator adopted was the use of an ultra-resistant and flexible fluid technology in the open hole section, using a technology engineered within the drilling fluid system to ensure that newly drilled rock was rapidly sealed and protected enabling to work with the same drilling fluid density two different formation pressures. Using this technique, the operator executed a successful operation, expanding the operating window and limiting wellbore instability while drilling into the two problematic formations.
With the use of MPD, offset wells on the same pad presented significant operational challenges, including wellbore instability from stuck pipe, sidetracks, and lost circulation of the drilling fluid. The implemented technology and technique, referred to as a Fluid Stabilization Additive (FSA), allowed the operator to perform a dynamic formation integrity test (DFIT) while drilling through the transition zone to evaluate the magnitude of the operative window increase and compare the results to offset wells on the same pad. The Fluid Stabilization Additive enabled a 1-2 lb/gal increase beyond the fracture gradient window, which was observed in the field.
The FSA was used in additional wells drilled in the same formation, which resulted in a considerable improvement in the drilling efficiency when compared to offset wells. Another economic advantage for the operator was the savings of oil-based drilling fluid (OBM) that was utilized for each well. Drilling fluid savings, and the prevention of lost mud to the formation minimized the total cost of the drilling fluid and helped to maximize the efficiency of the drilling operations.
Finally, a comprehensive laboratory evaluation was conducted to compare the efficacy of this unique approach. The Bandurria Sur Field was drilled at a much lower cost as a result of the FSA and modification to the drilling fluid formulation.
Removing the Requirement for Deburr Runs on a Field Development Multizones Well Completion
Authors: Jamieson Kyle Ivar , Cayao Joven John Ravelo , Hazel Paul Roderic , Prasad Bala , Ibitomihi Sunday Michael , Kolakalapudi Madan Kumar , Thomson Stewart James 
Published: October 2022

Abstract
A Metal Expandable Packer (MEP) as an Inner String Packer (ISP) that has the capability to run through multiple perforated zones, without the need for a deburr run was qualified for a BSP oil & gas field development in Brunei. Four injectors and four producers will be developed across a stacked sand shale sequence, requiring zonal isolation (ZI) and flow control to maximize production. The inclusion of this MEP technology provides a robust life-of-well Cased Hole (CH) sealing system with inherent anchoring and removes the deburr run, reducing associated rig time and cost.
Initial design for Shell Whale proved the sealing capability of the MEP after passing through a non-deburred 9-5/8″ perforated liner. The BSP well design and qualification required an MEP to pass through a 7″ cemented and perforated liner deployed on a 3-½" inner string comprising up to six zones – each zone with a mechanical sliding sleeve and control line for zonal Permanent Dowhole Pressure-Temperature Gauges (PDHG).
Job planning was conducted to configure the MEP, PDHG and SSD to minimize the erosion risks and maximise the perforation interval. Maximum use of onshore sub-assembly and SIT was identified to improve offshore rig-up efficiency.
BSP identified the worst-case load scenario with the MEP anchoring against the ID of the 7″ liner due to thermal, hydraulic, and ballooning effects by performing Wellcat simulation. Based on this simulation, the MEP product was successfully qualified in accordance with ISO 14310 V3 (and subsequent V0) including the load envelope.
Thorough FEA modelling validated the design, expansion and sealing capabilities, and demonstrated that a burr height of 0.17″ generated damage within the seal will be closed and sealed post expansion. Following the FEA, a rigorous ISO 14310 qualification was completed.
An estimated overall NPV improvement for the field development within the first two years compared to alternative swellable-type products, and the elimination of a further 2 days/well rig time (approximate) during well construction compared with a mechanical-type packer.
Further application of the MEP on multi-zone completions will enhance the ZI (sealing) of the 7″ to 8 ½" rock face (cement assurance or cement replacement) and may ultimately lead to the multi zone completion deployed within the open hole (OH) delivering further substantial cost reduction.
Beyond the Known Coiled Tubing Limits, First Coiled Tubing Intervention in a 40,000+ ft Well in the UAE: An Outlook of Downhole Tools Technology, Testing and Special Equipment Deployment to Successfully Accomplish the Project Objectives
Authors: Ottolina Renny , Ambrosi Giuseppe , Tuoyo Ella , Veronesi Miguel , Jimenez Jose , Al Marzooqi Abdulmohsen , Shbeb Yaman , Al Ali Salim , Al Braik Haitham , Humoudi Hassan Obaid , Correia Gladwin 
Published: October 2022

Abstract
Objectives/Scope: The latest developments in well construction demand equipment that defies the current industry limits to access the full length of the pay zones in 40,000+ ft wells. With the growing trend of drilling horizontal wells in the mega reach category and beyond, there is a need for a new level of engineering design of Coiled Tubing (CT) strings and downhole technology with a specific approach to reach these new and expanding requirements.
Methods, Procedures, Process: Extended reach conveyance of CT is a challenge that service companies and operators have progressively addressed as wells are drilled deeper into the mega reach area. Advanced CT string designs and materials, as well as systematic variations of parameters affecting friction coefficients between CT and wellbore completions, provide benefits to operators in extending the reach of the horizontal sections. Special downhole tools and engineering testing are required to plan the best outcome from the available downhole force technology to increase wellbore coverage while maintaining well underbalance, reducing operational footprint, and safely deploying the heaviest 40,000 ft 2-3/8 in CT pipe offshore.
Results, Observations, Conclusions: This paper describes the systematic process used to address the mega reach challenges, as CT is required to reach Total Depth (TD) in wells longer than 40,000 ft in one offshore oil field in Abu Dhabi. It summarizes the considerations taken to design the right string for the project and describes the multiple technologies used to extend the reach of the CT in the horizontal sections while remaining underbalanced. Additionally, this paper discusses the implementation of a surfactant-based Friction Reducer (FR) system to extend the CT reach and the friction matching analysis performed while calculating the extended lock-up depth. In addition, the special transportation solutions to deploy the CT reel to the wellhead are discussed, along with the track stack required to make these operations possible.
Novel/Additive Information: Detailed data collected throughout the campaign enabled the operating company and the service company to benchmark the results of the operations, drawing better conclusions well after well and enabling a positive loop of improvement leading to economic gains as the campaign was executed.
Technical challenges, downhole tools, and fluid solutions to reach TD Transportation solutions for mega reach CT string deployment
Extending the Performance of Standalone Sand Screens (SAS) with Flow Segmentizers in Gas Wells
Authors: Shaffee Siti Nur Amira , Ghazali Hasyimah , Rajan Preveen Kumar , Wan Mohamad Wan Amni , Thant Maung Maung Myo , Bakar M Farris 
Published: October 2022

Abstract
Sand control application in gas wells is very challenging, especially in the application of a standalone sand screen (SAS) due to the high erosional risks. Many failures have been observed in the industry over the years causing production deferments and additional OPEX to the operators for remedial sand control operations. This work presents the performance evaluation of a unique SAS in open hole completion concept piloted in a horizontal gas well and the replication in other new wells in a Malaysian gas field.
In 2012, a pilot gas well was completed with SAS with optimally placed flow segmentizers along the horizontal completion to limit the screen erosional risks. The placement was determined using a tool developed through an R&D. It estimates the optimum locations of the flow segmentizers based on the targeted SAS life or erosional velocity limit imposed. At the heart of it is a proprietary erosion model specifically developed for SAS application. The well performance was compared to adjacent wells producing from the same reservoir but completed using the conventional open-hole gravel pack.
The pilot well achieved higher Productivity Index in comparison to the adjacent wells. Over the 10-year observation period, the production performance was consistent with minimal skin values and no sand production issues. Multifinger Imaging Tool (MIT) was run to measure the erosion levels in the tubing and the result indicated very minimal erosion because of sand production even after several years of production. Recently, another one (1) new infill well was drilled and completed with the same concept as the pilot well. The segmentizer placements were supported by an optimization study based on the expected production scenario. Positive flow back results with no indication of sand production was detected from the intrusive sand monitoring equipment. With the application of SAS and flow segmentizers, a cost reduction of 25% as compared to more complex application of open-hole gravel pack was realized.
Unlocking the Potential of Twin-Screw Multiphase Pumps: Field Applications, Performance Simulation, and Recent Challenges with Case Study
Authors: Abdalla Mohamed Gamal Mohamed , Ali Ramzi 
Published: October 2022

Abstract
Over the past decades, the term -artificial lift- has mainly referred to the conventional techniques of downhole pumping (e.g., electrical submersible, sucker rod, progressing cavity, others) and gas lift. Today, a more comprehensive definition is becoming evident, a definition which matches all the major changes happening in the oil & gas industry. Accordingly, artificial lift is not limited to techniques conducted in the wellbore; instead, techniques used throughout the whole production system to "lift" the produced fluids towards their final destination are included.
All petroleum wells’ production lives are brought to an end when the downhole reservoir pressure cannot deliver fluids traveling up to the processing facility due to high flowline pressure. Numerous technological approaches were practically implemented at many fields, approaching the end of their lives, to extend the field exploitation. One such technique is to introduce Multiphase Pumps to add energy to the unprocessed crude at the wellhead to transport oil / gas / water mixture to the Central Processing Facility (CPF) -without the need for preliminary separation or well interventions, to install downhole equipment- while maintaining an environmentally friendly performance as gas flaring is no longer required and oil spills are avoided. This paper aims at addressing the difficulties in the evaluation of multiphase Pumps; especially those handling high gas volume fraction (GVF). These problems are related to uncertainty about the approach adopted to test the pump. Minimal information about the multiphase pump performance leads to difficulty for any new pump model to evaluate its applicability as the performance curve of the pump is dependent on the inlet fluid properties, such as fluid inlet pressure, temperature, water cut, GVF, etc. Therefore, the correct prediction requires the evaluation of the pump performance for each change in fluid properties.
The results of this study clearly demonstrate the tremendous effect of multiphase pumps in reactivating dying wells and enhancing production from brown fields providing a cost effective solution rather than conventional methods. Some operation challenges are very important to be considered especially when operating the pump at high GVF as a liquid recirculation system is required coupled with precise evaluation of system operational parameters to avoid gas flashing within the pump leading to reduction of pump efficiency. As well, solids handling measures upstream of the pump are essential to enhance the integrity of the system. This systematic, transformative research aims at improving our understanding of multiphase pumping and optimizing the operation parameters of Twin-screw pumps through data-driven models and field experiences leading to production optimization and sustainable future profitability.
Sedimentology and Diagenesis and Their influence on the Reservoir Quality: A Case Study of the Late Cenomanian Mishrif Formation, Western Region, Abu Dhabi
Authors: Phukan Madhujya L , Siddiqi Saad A , Alshehyari Shamma , Mansour Bashar , Alshehhi Maryam , Shashanka Ashis , Guangcheng Hu 
Published: October 2022

Abstract
The Cenomanian-early Turonian Mishrif Formation is an important reservoir rock throughout the Middle East. Although extensive studies have been carried out on the Mishrif Formation across the Middle East, very limited information is available about the Mishrif Formation from the western region of Abu Dhabi. The primary objective of this study is to review the sedimentology of the Mishrif Formation in the oilfields of the western region of Abu Dhabi and to define the petrology, the depositional and diagenetic history, and the reservoir quality.
The Mishrif Formation is sedimentologically characterized using an industry-standard lithofacies classification scheme. Subsequent sedimentological interpretations define the depositional evolution of the sediments. Petrologic assessment highlights the depositional texture and successive diagenetic alterations that have affected the sediments, thereby modifying the reservoir properties.
The Mishrif sediments represent deposition on a carbonate ramp system modified by a potential barrier shoal, along with localized relief developing shoal-like geobodies. A broad range of lithofacies represent the range from wackestone to boundstones, with the sediments interpreted to represent deposition in a shoal complex through backshoal and rudist buildups to a distal mid-ramp to an outer ramp setting. A petrographic study reveals multiple diagenetic phases have affected the sediments. Porosity is enhanced considerably due to multiple leaching phases, which are followed by subsequent cementing phases comprised of calcite and dolomite that degrades the porosity in places. Fracture events do not seem to have any significant impact towards enhancing the reservoir properties as they remain dominantly filled by cements but locally, a few fractures, which are open, contribute to enhancing the connectivity. A moderate to very good reservoir quality is inferred for the sediments of the Mishrif Formation. The porosity values range between 7% to 34% and permeability values from 0.06mD to &gt;10 D. Interrogation of the core analysis data indicates a depositional control along with a diagenetic influence on the reservoir quality.
This study helps to resolve the complexities associated with the sedimentological makeup and diagenesis of the Mishrif Formation in the western region of Abu Dhabi. The understanding from this study will help in further works related to reservoir geomodelling and pattern prediction, which may also be extrapolated to uncored intervals for representativeness and regional correlation of the Mishrif Formation.
Integrated Multiple Seismic Attributes Study for Value-Based Insight and Reservoir Characterization of Hydrocarbon Assets - A Data Science Approach
Authors: Roy Samiran , Saikia Kalyan 
Published: October 2022

SummaryThe objective of this paper is to demonstrate how advanced data analytics algorithm with Machine Learning (ML) techniques proves to be advantageous for effective integration of multi-attribute seismic data in reservoir characterization and identification of sweet spots for well location release. The paper exhibits that ML based technique helps revealing sweet-spot insights. The workflow describes how identification of hidden characteristics of data is achieved through this technique. Several ML techniques have found application for reservoir characterization in recent years. This very study based on a use case of an exploratory field shows data driven ML based algorithm can be applied efficiently if the design of the solution is built on a proper understanding of domain and different ML algorithm or techniques. Overall, the ML based workflow can be very useful in early exploration stages of reservoirs where mainly seismic data is available with very few or limited exploratory well data. A novel approach where ML has been used in integration with geo-cellular gridding and multiple seismic attributes; and it resulted a Machine Learning Predicted Composite (MLPC) attribute.