bluuebunny/crossref_metadata_2025_split huggingface dataset:
Next-Gen Drilling: Harnessing Rig Action Plan Cloud-Edge Integration for Well Cycle Improvement and Enhanced Crew Dynamics
Authors: Zarate P. , Bott R. , Varghese B. , Borges T. 
Published: September 2024

Abstract
Improving well cycle time efficiency involves automating the benchmarking and replication of top-performer activities across a fleet, enhancing safety, reducing learning curves, and enabling real-time well performance monitoring for consistent operational excellence beyond on-bottom activities. The process involves consuming data from any digital well program, automatically converting it into a Driller's Roadmap for the digital execution of well-defined sequence of activities to eliminate guesswork and delays, to help with knowledge sharing minimizing the learning curve. Efficiently disseminating and implementing best practices, lessons learned and operational procedures by activity backed by data driven insights. Sending timely notifications and alerts to drillers and preparing crews to transition seamlessly into the next operation. The rig execution engine includes optimizing various drilling activities through specific recipe parameters, which will enable automation within a rig operating system all while providing visibility for all stakeholders.
As the industry progresses towards automating well design, a key innovation is the integration of these designs with a versatile rig execution engine, accessible at the edge and the cloud. An implementation conducted across 5 rigs working for a major operator in the Permian Basin demonstrated significant improvements in well cycle efficiency, highlighting the potential of this approach to transform well operations in the industry. The integration of a versatile rig execution engine with cloud-edge technology and enhanced crew dynamics resulted in observable well cycle time efficiencies, emphasizing the value of this innovative approach through flat time optimization. This integration between a rig plan and the rig execution engine increases procedural adherence through execution using a rig operating system that automates tasks according to the well program. Additionally, improves driller training and crew retention by providing timely, relevant information and resources, including multi-lingual support, thereby fostering greater inclusion in operations.
Field X Fail-Less Strategy: Journey Towards Esp Best in Class Performance and Achieving Record Low Subsurface Unscheduled Deferment
Authors: Al Shukaili Ghosin , Al Kindi Said , Al Riyami Said , Al Hatmi Fahad , Al Ajmi Ahmed , Al Riyami Yaqoob , Al Lawati Mehdi 
Published: September 2024

Abstract
The Field X is the largest cluster fields (23 Sub-Fields) in Petroleum Development Oman (PDO), producing the highest oil production and operating the highest number of well stock (over 2800 wells). Most of these fields are very mature with many old wells and aging facilities. Operations in Field X are very dynamic with more than 1600 well interventions yearly; critical activities to restore and optimize production and arrest the field's decline. Before 2020 Field X was experiencing significant subsurface unscheduled deferment (USSD) at 3.7% of total field potential and an artificial lift failure index of 28%, well above industry standards.
To address this issue, a dedicated workshop on artificial lift failures and USSD reduction was carried out with stakeholders, resulting in the development and implementation of the Field X artificial lift fail-less strategy. This strategy aims to convert frequently failing Beam Pump (BP) wells to Electrical Submersible Pump (ESP) and Long Stork Unite (LSU). Over 340 BP wells were converted to ESP and LSUs from 2020-2023.
Between 2020 and 2023 and as a result of Field X Fail-Less Strategy, there has been a dramatic improvement in Field X's performance. The overall artificial lift failure index has dropped from 28% to 18%. Moreover, Field X achieve a significant drop in ESP failure index from 14.4% in 2020 to 7.5% in 2023. This success exceeds the Global Top-Quartile Benchmark of 10.8% and field X is now considered as best in class performance in ESP. The subsurface unscheduled deferment rate of Field X has decreased from 3.7% to 2.1%, and some fields have achieved ZERO unscheduled subsurface deferment. The success is attributed to several innovative solutions, including the "Fast Track" conversion of frequent failure wells to a different type of artificial lift, converting non-frequent failure wells with good potential to electrical submersible pumps ESP, and aggressive installation of the Long Stork Unite (LSU) system. The implementation of various new technologies in artificial lift and optimizing well operating philosophies also contributed to the success.
Field X artificial lift strategy resulted in significant value realized for PDO and a positive impact on HSE. This paper will explain the journey towards achieving a lower Artificial lift failure index and how the Field X artificial lift strategy was developed and implemented.
Simulation and Prediction of CO2 Injection Characteristics in Carbonate Gas Reservoirs
Authors: Huang Yize , Li Xizhe , Elsworth Derek , Liu Xiaohua , Yu Pengliang , Qian Chao 
Published: September 2024

Abstract
Understanding the flow and transport characteristics and mechanisms of CO2 in water-saturated carbonate gas reservoirs is crucial for enhancing CH4 recovery and CO2 sequestration. We developed a multiphase multicomponent numerical model for gas and water phases, which considers the multiple transport mechanisms between CO2-CH4 and CO2-water and couples the chemical reactions of CO2 in water-saturated carbonate porous media. After validating the model with analytical solutions, we investigated the effects of CO2 injection density, in-situ CH4 density ratio, and initial fluid saturation on CO2 flow characteristics and porous media properties. The results indicate that the fluid density difference between different components controls their transport mechanisms: smaller density differences lead to higher concentration diffusion intensity between components, while larger density differences result in viscous flow with convective transport characteristics. The dissolution effect of CO2 on carbonate rock enhances the flow capacity of the porous medium for different components and provides greater storage space for CO2 sequestration. Fluid saturation is a key factor affecting the transport characteristics of CO2 in porous media. Due to the mutual solubility of CO2 and water, water accelerates the flow of CO2 in the porous medium, leading to premature CO2 breakthrough and negatively impacting CH4 recovery.
Experimental Investigation of How Supercritical CO2 Changes the Chemistry and Microstructure of Cements
Authors: Liu Y. , Hu K. , Kuru E. , Li H. , Lin Z. , Iremonger S. , DeBruijn G. 
Published: September 2024

Abstract
Carbon capture and storage (CCS) is a crucial technology for mitigating greenhouse gas emissions and combating climate change. However, the long-term integrity of well systems in CCS applications is a critical concern, as the supercritical CO2 (SC-CO2) can dissolve in water forming carbonic acid, which can chemically alter the cement. This study investigates the effects of SC-CO2 exposure on the integrity of cement blends used in well systems for CCS applications. Three cement blends were examined: neat class G based cement (G), neat class G based cement with fly ash (GF), and preliminary testing on a further optimized low Portland cement based system containing permeability reducing polymers (GFP). Samples were exposed to SC-CO2 for up to 56 days under 4,060 psi, 70°C, and the complex changes in their properties evaluated. A review of the various non-standard analytical techniques is described using the three cement systems and their associated changes as a case study for the unique insight and associated limitations that each of these analysis techniques can provide.
The results demonstrate that SC-CO2 exposure leads to dehydration, carbonation, and alteration of cement, affecting its pore structure, permeability, and mechanical properties. Blends GF and GFP exhibited improved resistance to SC-CO2-induced alteration compared to blend G, attributed to reduced starting portlandite (Ca(OH)2) content and less alteration of the pore size during exposure. Permeability tests using Nitrogen (N2) and water revealed that although SC-CO2 exposure increased permeability due to cement alteration and dehydration, the permeability remained low, in the tens of μD range. Post-CO2 exposure uniaxial compressive strength tests are difficult to interpret due to the non-uniform nature of the structure but short-term exposure to SC-CO2 enhanced the mechanical properties of cement due to CaCO3 precipitation, while prolonged exposure led to the carbonation of the outermost layer, creating a more complex failure mode. X-ray diffraction (XRD) analysis revealed that Calcium Silicate Hydrate (C-S-H) is more stable than the portlandite under SC-CO2 exposure, confirming the previously described results that minimizing portlandite content is an effective strategy for enhancing cement formulations for CCS applications.
The findings provide valuable insights for the development of robust well integrity systems in CCS applications. Future research should focus on optimizing cement blend compositions, exploring mitigation strategies, and establishing guidelines for the design and operation of well systems to ensure the safe and effective implementation of CCS technology.
Impact of Residual Fluid Composition and Injected Gas Purity on the Storage Capacity of the Depleted Shale Oil Reservoirs in the Presence of Diffusion and Sorption
Authors: Enab Khaled , Wang Zhicheng W. 
Published: September 2024

Abstract
Depleted shale oil reservoirs signify a forward-looking solution for CO2 storage that leverages existing resources — It presents an ideal opportunity for CO2 storage, primarily because extensive data collection from prior extraction activities offers a detailed understanding of their geological characteristics. Additionally, the massive number of depleted wells in the US shales makes it a viable option for carbon storage. Shales are known for their high organic content, which enhances CO2 adsorption into the geological formation, which in turn enhances the storage capacity and formation integrity. On the other hand, due to the high CO2 concentration gradient, the diffusion process plays a significant role in CO2 storage. The wealth of information collected throughout the lifetime of those wells, including the adsorption and diffusion rates, ensures precise planning and safe implementation of CO2 sequestration projects. This precise planning for carbon storage contributes to the environmental and energy sustainability goals. In this study, we evaluate the storage performance in shales to evaluate the impact of reservoir fluid composition, diffusion, and adsorption. Furthermore, the impact of the injection gas purity on storage capacity is evaluated. In this study, we assessed the CO2 storage in shales by conducting large-scale numerical simulations for a wide range of reservoir fluid compositions—retrograde-condensate, volatile-oil, black oil—and different purities of injected CO2 by considering diffusion and sorption.
The results showed that ignoring the adsorption and diffusion underestimated shale storage capacity while ignoring the diffusion only overestimated the storage capacity. These results emphasize the importance of including adsorption and diffusion when modeling CO2 storage. Furthermore, the purity of the injected CO2 is positively proportional to the storage capacity as the storage capacity is reduced when the purity is reduced due to the increasing competition of the impurities to be adsorbed into the shales.
Validation of the First Industrial High-Power Laser Perforation Deployment
Authors: Batarseh Sameeh I. , Alerigi Damian P. San Roman , Marshall Scott , BuHassan Shaker 
Published: September 2024

Abstract
This paper presents the methods for validating the first successful industrial and field deployment of a high-power laser (HPL) perforating tool. The technology is able to perforate wells without damaging the surrounding substrate's integrity and improving the formation's flow-related properties. Validating the successful operation and the tool's performance is comprehensive and rigorous, relying on qualitative assessments of the data collected from built-in sensors and conventional logs.
The accomplishment of the first deployment is a testament to the meticulous research process that has led to the development of the first high-power laser field system. The tool integrates optical, mechanical, and sensing components. The optical and opto-mechanical assembly steers the beam to a target at any azimuthal angle. The sensor array collects data about pressure, temperature, and luminosity that are crucial to monitoring the operation, ensuring the tool's correct functionality, and validating the process. The high-power laser generator is located at the surface and transmitted via fiber-optic cable to the tool in the downhole.
The first industrial high-power laser perforation technology was successfully tested and deployed in a cased well; lab and field data proved that the technology could effectively perforate all types of rocks, demonstrating its versatility and adaptability. The tool created several perforations and slots through casing, cement, and formation. The validation of the operation is critical to evaluate the technology's performance and to compare it with current practices (e.g., shaped charges). This assessment used data from routine field measurements and the tool's onboard sensors, including a downhole camera, injectivity test, and sonic and caliper logs. The sensors measured temperature, pressure, and backscattered luminosity. The last is essential to characterize the laser-rock interaction since it is correlated with the effectiveness of the removal process. Temperature readings inside the tool provide information about the health of the optical components. In contrast, the outer temperature and pressure sensors are proxies of the wellbore's flowing dynamics and can help confirm the successful perforation.
This HPL perforating method is an innovative and non-explosive alternative to conventional shaped-charge guns. It is cost-effective and enables precise beam control, targeting specific zones and creating enhanced perforation tunnels uninfluenced by the formation's state of stress.
Applying Boundary Conditions for Large Aquifer Models in Geological CO2 Storage Projects; Why and How?
Authors: Ghomian Yousef , Bennett Matthew , Skrivanos Chris , Marchiano Iryna , Haynes Andrew K. 
Published: September 2024

Abstract
Around the world many projects are being considered for the geological storage of CO2 in large saline aquifers. The aerial extent of pressure and saturation plume forecasts, known as Area of Review (AOR) in the United States, can have a significant impact on the monitoring costs and liabilities associated with existing legacy wells within the vicinity of the carbon storage projects. Appropriately modeling how aquifer systems react to large scale CO2 injection has relevance to potential geomechanical integrity, fault reactivation, seismicity, and impact on underground sources of drinking water (USDW). Static and dynamic models are generally built over a smaller portion of large saline aquifer system. This is typically tied to the balance between model size, fidelity, and computational expenses. Assigning the appropriate boundary conditions to replicate the true extent of the aquifer is investigated in this study. Scoping the aquifer's size, geology, and properties is an important step that allows for the quantification of the appropriate pore volume beyond the area of the numerical model. Results from our study indicate that using pore volume (PV) multipliers is a reasonable approach if accompanied by transmissibility reduction at the interface between the PV modifications and the reservoir model. A simple model was developed to create the true solution for comparison and verification purposes.
Based on the results of this study, we find that using a combination of PV and transmissibility multipliers replicates the true solution more accurately. We demonstrate that large PV adjustments without transmissibility reductions overestimates the true aquifer strength, resulting in overall lower pressures due to large-scale CO2 injection. We demonstrate a systematic methodology for calculating the simultaneous PV increase and transmissibility reduction that scales easily for a wide range of scenarios.
Further investigation shows that as the PV multiplier grows large, the approach of reducing the transmissibility with a single multiplier starts to choke off the large added pore volume. This study proposes an innovative approach which demonstrates that applying a gradually increasing PV multiplier combined with gradually reducing transmissibility is a more accurate representation of the true aquifer system when compared to a single large PV multiplier and a single transmissibility reduction. The proposed approach was applied to large 3-D models and significant impact was observed in pressure diffusion front shape and extent when compared to more simplified approaches.
Assignment of boundary conditions for a variety of different scenarios were also investigated in this study. It was shown that this novel approach will be the most accurate method of applying appropriate boundary conditions in obtaining reliable AOR forecasts when modeling large aquifer systems for CO2 storage projects.
Enhanced Hydrogen Generation from Olivine Sand
Authors: Vega B. , Ross C.M. , Kim T. , Frouté L. , Kovscek A. 
Published: September 2024

Abstract
An experimental setup was created to study serpentinization of an olivine sand sample and study hydrogen production. Inspired by the so-called "white" hydrogen sources, enhanced serpentinization of olivine represents an attractive opportunity to produce hydrogen from geological resources. Literature offers examples of experimental conditions that achieve hydrogen production at laboratory scale with different degrees of success. We made a preliminary selection of experimental parameters and assembled a setup capable of replicating conditions suitable for hydrogen production from enhanced olivine serpentinization. Commercially available olivine sand was selected with a grain size range of 250 to 355 µm for the experiment. The sample was subjected to 18 days of high pH brine exposure via continuous inflow, while inside a reactor heated by a furnace. The operating temperature range inside the reactor was between 80 and 245°C. The produced gas phase was separated, periodically collected, and analyzed via gas chromatography calibrated for hydrogen. Analysis of the produced gas showed hydrogen concentrations of 9 and 13% by mole. The precursor olivine sand was characterized in pre- and post-reaction states using scanning electron microscopy and analytical techniques (x-ray diffraction and x-ray fluorescence). A significant amount (14 wt% of the reacted sample) of serpentine precipitate was observed, coating the grains. The analysis suggests that the serpentinization reaction was maintained by the large grain size and the development of accessible porosity between the grains and grain-coating serpentine precipitates. Minor amounts of carbonate, magnetite, and variable composition (Ca-Fe-Mg-Ti) silicate precipitates were also observed. These preliminary results suggest that it is possible to enhance, at laboratory scale, serpentinization of olivine and generate hydrogen with significant H2 compositional yields. Our findings are supported by produced gas analysis and evidence collected on the reacted sample.
Production Decline Analysis of Horizontal Shale Wells in Presence of Stress-Controlled Flow Rates
Authors: Wheeler Austin W. , Aldana-Gallego Ivan C. , Akkutlu I. Yucel 
Published: September 2024

Abstract
Decline curve analysis (DCA) methods curve-fit historical production data of a well and forecast the recoverable reserve. However, these methods do not consider the underlying physics of production and therefore they are not used as diagnostic tools. In this paper a new physics-based DCA method is introduced for reserve estimation and as a diagnostic tool for unconventional wells with long lateral length and with a great many hydraulic fractures. The method considers that the shale wells produce at flow rates that are influenced by in situ stresses. Namely, the reservoir matrix delivers the fluids to the fractures in an effective stress field, and the hydraulic fractures deliver the fluids to the well under fracture closure stress. The stresses change dynamically during the production due to withdrawal of the fluids and pressure depletion. We propose the production decline due to stresses can be captured by considering both the matrix and the fracture have stress-dependent permeability. We consider exponential function to capture this decline with a time-dependent exponent a representing the overall permeability loss ratio. The ratio changes over the production time as a function of the geo-mechanical properties and the changing stresses. It is the new DCA parameter to be determined by curve-fitting the production data. We used fourteen Marcellus shale gas wells, twenty shale oil wells (including wells from Permian, Eagle Ford, Anadarko basins) and utilized MS-Excel solver to demonstrate the application of the new stress-controlled DCA. On average a 30% loss in Marcellus gas reserve is estimated due to stress-controlled production rate decline. The shale oil wells analyzed also show strong dependence to stresses. The new approach could help operators identify the shale wells producing with flow rates under significant stress effects but also help improve the reserve estimation by adding new relevant physics and, hence, reducing uncertainty. In addition, it may be considered as a simple proxy model to use along with the complex reservoir flow simulation modeling approaches or as alternative to simulation in the absence of data needed for reservoir modeling.