bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Fast Method to Estimate the Correlation Between Confining Stresses and Absolute Permeability of Propped Fractures
Authors: Al Balushi Faras , Dahi Taleghani Arash 
Published: October 2020

Abstract
Depletion of oil and gas reservoirs during production from fractured wells, or fluid injection through frack-packs may cause significant changes in the effective stress that proppants experience inside the fractures. Previous studies have shown that closure stress may change absolute permeability, however, deriving this relationship requires time-consuming and costly experiments that need to be repeated with the change of proppant or field parameters. Here, we propose a methodology to estimate absolute permeability magnitudes of the propped fracture direction by just using limited knowledge about grains' geometry. In this study, Lattice Boltzmann Methods (LBM) is used to simulate fluid flow to resemble flow in propped fractures under reservoir conditions. Due to the large number of particle and complexity of the sitting of proppant particles next to each other, intensive computational power is required to carry out simulations. Therefore, a parallelized LBM code is utilized to accelerate computations. The three-dimensional granular geometry was constructed from two-dimensional micro-Computed Tomography images. The geometry was then used as an input for the finite element analysis to simulate grain deformation/sliding upon applying different stresses on the samples. The captured deformation of the grains' geometry was then exported to the LBM code for calculation of permeability. Upon increasing confining stress on the samples, the proppant particles began to deform, slide on each other and the pore network evolved. While the standard API cell measures only conductivity changes under different normal stresses, the presented method gives a greater advantage by allowing determination of the simultaneous effect of normal and shear stresses on the components of the permeability of propped fractures. It is believed that parts of complex fracture networks may experience some shear stresses, but these effects could not be measured in the lab easily. Preserving core samples with the same conditions for a long time is not feasible. Therefore, using LBM, we present a fast and reliable method to measure absolute permeability of proppants during flowback and production using limited data in the form of micro-CT images or 3D images of the grains forming proppant packs.
Integrated Systems Approach Benefit of Optimizing Drill Bit Design with Rotary Steerable System Drive Mechanism
Authors: Bone Kim , Spencer Reed 
Published: October 2020

Abstract
An operator, drilling a 6-in horizontal production section in an offshore African field, observed diverging directional drilling steering behaviour that resulted in a round trip non-productive time (NPT) event. Being a mature field of known drilling performance and no significant structural or lithological variations, the interval was planned for one run with a Rotary-Steerable-System (RSS) bottom hole assembly (BHA). During the horizontal drilling of a particular well, the BHA began to build inclination, and all attempts to correct trajectory resulted in incremental build. Initial root cause indications were a malfunction in the RSS due to opposite steering behaviour and not a geological explanation. To complete the remaining drilling interval, the drill bit design was changed and the steering unit replaced with standby inventory. Drilling was resumed and the horizontal geosteering interval was completed with responsive directional control to the downlinked commands through the same reservoir geology.
Extensive root cause analysis that combined in-depth bit and BHA modelling, physical RSS tool workshop testing, and detailed plotting of all surface and downhole data, verified possible malfunctions and identified potential negative steering behaviour. Proprietary digital simulation tools modelled the BHA bending behaviour and build up rates. Simulations of bit-BHA interactions in formation scenarios were run to define build and/or drop capabilities. Different drill bit designs were evaluated through the modelling iteration process to understand the observed field responses.
Inspection and physical tool testing confirmed that the RSS tool was fully operational without any issues. Modelling matched the actual field outcomes in which drill bit features contributed to the observed lack of steering responsiveness, delivering drilling in a direction opposite to downlinked commands. An extended gage length bit drilled a 3.3deg/100ft build up rate, with an average 93% downward steer force, when a drop rate of 6.0deg/100ft was expected. Applying the new drill bit design with key gage features corrected the well trajectory with a 65% reduction in steering force. After 0.45hours of directional corrections, subsequent drilling kept precise target inclination enabling a 56% rate of penetration (ROP) improvement compared to the first run.
Quality wellbore placement and NPT risk reduction can be achieved by utilizing proven and state-of-the-art digital simulations that combine bit with BHA and formation during the pre-planning phase to ensure appropriate drill bit designs are harmonized to the BHA and directional requirements. This paper illustrates the benefits when applying and adverse risk when not applying an integrated systems approach.
Multi-Basin Case Study of Real-Time Perforation Quality Assessment for Screen Out Mitigation and Treatment Design Optimization Using Tube Wave Measurements
Authors: Merry Hoagie , Dalamarinis Panayiotis 
Published: October 2020

Abstract
The scope of this work is to introduce a technology that measures perforation effectiveness on a stage by stage basis before the hydraulic fracturing process begins. The measurement utilizes surface generated tube waves to interrogate the perforated section of the wellbore. We present three case studies demonstrating how "low perforation quality alerts" mitigate operational issues, achieving the deployment of appropriate stimulation treatments for several operators in the Eagle Ford, Haynesville, and Niobrara formations.
The reflections of tube waves are analyzed to characterize perforation effectiveness on a stage by stage basis. This methodology is non-intrusive, infinitely repeatable and can be performed in the short time interval between removing the perforating equipment from the well and beginning the fracture treatment process. The operators in our study were alerted to stages with a high likelihood of pumping issues such as high treating pressure, screen outs, or low proppant volume placement. Real-time measurements flagged these stages as having poor wellbore connectivity to the reservoir.
Prior to pumping, the operator and crew in the field were alerted to the stages that showed low perforation quality. This allowed modifications to the stage design, such as additional acid, sweeps, finer proppant, gel, increased pad, lower rate, or an additional perforation run. In the cases where changes were made to the design, the objective of mitigating pumping problems due to poor perforation performance was a success. In all the cases where preventive design changes were not implemented, downhole difficulties were experienced resulting in sub-optimal stage execution and/or screen outs. Cost savings in the range of $300,000 on some wells were achieved due to the mitigation of pumping problems associated with poor wellbore to reservoir connectivity.
Perforation quality and reservoir rock geomechanics play a dominant role in hydraulic fracturing operational success or failure. Although there have been extensive studies focusing on the role that perforation diameter plays on treatment efficiency, these studies do not adequately consider the importance of the perforation tunnel (depth and quality of perforation penetration into the near well region). Having real-time, non-intrusive, field-based data that provides a direct measurement of this essential element can influence the execution of the hydraulic fracture design. This mitigates the costly exercise of recovering from a screen out and improves the likelihood of a productive stage.
Interwell Fracturing Interference Evaluation of Multi-Well Pads in Shale Gas Reservoirs: A Case Study in WY Basin
Authors: He Youwei , Guo Jianchun , Tang Yong , Xu Jianliang , Li Yanchao , Wang Yong , Lu Qianli , Patil Shirish , Rui Zhenhua , Sepehrnoori Kamy 
Published: October 2020

Abstract
Severe fracturing interference in multi-well pads has been identified in shale gas reservoirs. The gas production of affected multi-fractured horizontal wells (MFHWs) decrease a lot and is hard to restore for most wells even after fracturing fluid flowback. Currently, well interference caused by fracturing operations has become the most important factor affecting the shale gas production. However, the mechanism of fracturing interference and its quantitative impact on gas production in shale gas reservoir are not clear.
The aim of this work is to assess the mechanism and dominated factors of fracturing interference of multi-well pads in shale gas reservoirs, and evaluate the impact of interwell fracturing interference on shale gas production. Firstly, field data in WY Basin are applied to calculate the ratio of impacted wells to newly fractured wells and understand the influencing degree and recovering degree of gas production. The main controlling factors of fracturing interference are determined and the interwell fracturing interacting types are presented. Furthermore, the production recovering potential for impacted wells are analyzed. Finally, some suggestions for mitigating fracturing interference are provided.
The impact degree and recovering degree of gas production are divided into three categories. The dominated factors of fracturing interference include well spacing, pressure of the affected wells before interference, gas production before interference, and flowback ratio of fracturing fluid. The influencing degree of gas production can be estimated by using the generated equations of impact degree of gas production per well spacing (IDGPs) or impact degree of gas production per flowback ratio (IDGPf) Another novel finding is that 70% of affected parent wells belong to adjacent well pad compared with the newly fractured child well. The interwell fracturing interference is divided into four types, including pressure interference without direct communications between two MFHWs (Type I), fracturing interference through natural fracture/secondary fractures (Type II), fracturing interference through hydraulic fractures (Type III), and direct communication between hydraulic fractures and wellbore of adjacent well (Type IV). Fracturing communication through hydraulic fractures or secondary/natural fractures are more common, and the impact on well safety and production performance increases from Type I to Type IV. Therefore, the fracturing parameters need to be optimized to reduce the fracturing interference. This study can provide reasonable suggestions for infill well optimization, fracturing design, and interwell fracturing interference mitigation to achieve the highest gas recovery of all multi-well pads in shale gas reservoirs.
Frac Hit in Complex Tight Oil Reservoir in Ordos Basin: The Challenges, the Root Causes and the Cure
Authors: Wang Lipeng , Du Xianfei , Qiu Kaibin , Wu Shunlin , Zhuang Xiangqi , Bai Xiaohu , Wang Lizhi , Pan Yuanwei 
Published: October 2020

Abstract
Severe frac hit incidents were encountered during stimulating horizontal production wells in a pilot pad of a tight oil reservoir in Ordos basin. The reservoir is interbedded, highly heterogeneous both vertically and horizontally as result of gravity flow deposition. This raised a big concern on the stimulation treatment size and well spacing of the pad and further implication on the field development plan of the reservoir. A deep understanding of root causes and an effective frac hit prevention and mitigation strategy were much needed to address the problem.
A multidisciplinary team was formed to investigate the problem. Initial analysis on the frac hit incidents showed that the frac hits were not correlated to well spacing, or stimulation volume as frac hits only occurred at certain stages out of those with the same stimulation volume or well spacing. Then the study turned the focus to investigating the problem from the geological and geomechanical perspective through leveraging a 3D high definition (HD) geological and geomechanical model.
The detailed investigation revealed that the root causes of the frac hits were multiple folds: Existence of natural fracture corridors led to frac hit of wells in much longer distance.Alignment of hydraulic fractures among horizontal wells also increased the chance of frac hits as the result of alignment of perforations among horizontal wells.Asymmetrical propagation of hydraulic fracture (e.g., deviated to one side of horizontal laterals increased the chance of frac hit as the result of heterogeneous sand body and in-situ stress field.)Lack of vertical fracture containment resulted in the crossing-layer frac hits.
With the good understanding of the root causes of frac hits, a frac hit risk map was generated based on the 3D HD geoscience model, which highlighted high frac risk zone in the pad. The frac hits observed from subsequent stimulations of the horizontal wells occurred only in the high frac hit risk zone, which validated the frac hit risk map. Based on the findings from the study, the frac hit prevention and mitigation strategy was developed.
Automated Lease Operating Statements for Cost Optimization and Reserve Evaluation Using Artificial Intelligence
Authors: Klie Arturo , Klie Hector , Vuong Duc , Chaban Fady , Chaban Nidal 
Published: October 2020

Abstract
The objective of the present work is to streamline the analysis of Lease Operating Statements (LOS) with advanced learning paradigms from artificial intelligence (AI). The proposed approach aims at the: (a) consolidation of disparate expenses data; (b) timely expense assessment at field, pad or well level; (c) prevention and quick identification of negative cash flow trends (d) robust LOS predictions; and (e) optimal budget planning under uncertainty. To achieve this objective, a LOS acceleration platform was developed for the automatic integration of volume estimation with Lease Operating Expenses (LOE). Historical data from production volumes, revenues, price differentials, LOEs, marketing and transportation costs, taxes, CAPEX, P&A costs and others considered to strengthen the accuracy of individual expense categories and the overall LOS predictive model. The predictive model consists of a combined blend of analytical and machine learning models that allows to reliably forecast trends and proactively detect anomalies that may be negatively affecting the operational cash flow. Intuitive and portable visualizations allow a quick interpretation and communication of results among engineers and managers. The implemented platform fills a gap between traditional LOS analysis and preemptive expense planning involving many wells and expense categories that are hard to track daily. It is shown that the proposed approach can lead to savings of the order of 30% in incurred expenses.
Improving Well Economics Through Reservoir Characterization and Optimized Completion Design in Horizontal, Unconventional Reservoir Development
Authors: Schubarth Stephen , Bozeman Tim , Lestz Robert 
Published: October 2020

Abstract
Completion designs in horizontal, multi-stage wellbores is a complex problem and has many potential scenarios depending on the desired well performance. Up until recently the industry has been focused on improving early-time productivity; 90-day cumulative production, 24-hour initial potential (IP) or achieving a target daily rate. Many operators are now refocusing on a desired economic outcome; achieving free cash flow, improving return on investment and increased net present value. Our paper will discuss the effects that different completion design changes have on these desired results and present examples of past well performance and new well performance utilizing these changes.
Our methodology will include the analysis of producing well histories to determine average reservoir permeability and completion effectiveness as described by the number of created, producing transverse fractures and the average effective length of those fractures. From this characterization of the reservoir and past completions we will forward model completion design scenarios to determine the effect changes in design have on the performance parameters we wish to achieve. The process used includes hundreds of completion design scenarios which are compared to each other to find the design which maximizes the desired economic result. Multiple examples of this will be presented.
Increasing early-time production performance has resulted in increasing capital expenditure. Several completion design parameters lead to increases in this performance parameter (IP); increasing lateral length, increasing stage volume and decreasing stage spacing. However, all of these changes increase the capital spent on the completion. To achieve improved economic performance parameters, balancing the total capital expenditure against the revenue generated becomes the primary focus. What may have worked in the past to meet past goals does not work to meet new, economic focused goals. The most important parameter we must know when designing the completion is the reservoir permeability. This value determines the reservoirs ability to deliver hydrocarbons to the well and how effective the reservoir can be to creating the revenue necessary to pay for the capital spent. Identifying the balance between capital spent and revenue generated leads to completion designs that reduce well cost while maximizing economic parameters versus maximizing early-time production alone.
The results and conclusions from this paper will run contrary to the industry's past trends in completion design. However, the focus on economic improvement can be a pathway to our industry to achieve better economic results. Our industry has provided increased energy independence for our nation, but far too many companies are suffering financially while doing so. Billions of barrels of oil have been produced, yet many are going broke.
Case Study: Intelligent RSS Improving Drilling Performance on Three Mile Laterals in the Appalachian Basin
Authors: Tilley Jim , Nair Vakkeyil Naveen , Hamoudi Lotfi 
Published: October 2020

Abstract
Longer lateral length in unconventional wells has proven to increase hydrocarbon recovery and lower overall development costs for oil and gas operators in North America. The application of rotary steerable system (RSS) technology aids this effort by improving and sustaining penetration rates to reduce well time and maximize reservoir drainage. A new "intelligent" RSS has been deployed to enhance drilling efficiency with industry-leading operating limits, automated steering controls, and a global lifecycle maintenance system to drive reliability.
The new RSS bottomhole assembly (BHA) consists of an advanced downhole motor, a matched bit design, and high-speed geosteering control. An automation process helps operators meet the challenges of drilling time and wellbore placement in long laterals. High rate of penetration (ROP), rotation per minute (RPM) and weight on bit (WOB) limits are controlled by sophisticated sensor technology that enables precise steerability. The RSS platform includes multiple directional sensors and real-time processors capable of reducing hole tortuosity and optimizing reservoir exposure while drilling. It also includes automated inclination and azimuth control features. Furthermore, a structured, pre-job design process evaluates critical engineering risks and mitigates those risks using a systematic methodology.
The initial testing of the new RSS on a test beam qualified its ability to operate at high speeds and high loads. Multiple holes were drilled in cement blocks to benchmark performance. Beam testing was followed by full-scale testing at a dedicated drilling rig, where over 40,000 ft was drilled in a variety of configurations, including vertical, curve, and lateral trajectories. After the extensive field testing program, the intelligent RSS was utilized to drill multiple ~14,000-ft, 8.5-in. lateral hole sections in the Utica Shale. A significant reduction of drilling time was achieved in these long laterals, with an average ROP of 245 ft/hr. A record 5,300 ft were drilled in 24 hours, beating previous wells by 600 ft. The activation of inclination and azimuth control delivered a smooth, high-quality wellbore with minimal tortuosity. Inclination was maintained within +/− 0.5° and azimuth +/− 1°. The outstanding performance of the innovative BHA enabled the longest one-run lateral to be drilled with an RSS.
The new, intelligent RSS has successfully demonstrated it can decrease well time and drilling costs, while increasing wellbore placement accuracy. The improvement in drilling efficiency and lateral length capability will enhance unconventional asset value across North America, and elsewhere around the world.
Integrated Reservoir Characterization with Spectroscopy, Dielectric and NMR T1-T2 Maps in Freshwater Environment, Case Studies from Alaska
Authors: Shi ZhanGuo , Akindipe Tunde , Wendt Brett L. , Garcia German 
Published: October 2020

Abstract
Hydrocarbon identification and evaluation with conventional triple-combo logs and Archie-based equations in freshwater environments has been a challenge for petrophysicists. In the first case study from Alaska, shallow reservoir information from non-Archie based technologies including total organic carbon (TOC) from spectroscopy measurements, hydrocarbon volume derived from dielectric and NMR logs were used for quick hydrocarbon bearing zones identification, decision making on fluid sampling and early determination of oil properties. The high-resolution NMR T1-T2 maps, derived from the latest inversion, revealed the presence of viscous oil.
Another targeted formation is a laminated shaly sand sequence, also in a freshwater environment. The array resistivity logs show a low contrast profile and it is more challenging for fluid identification and evaluation. Relatively high resistivity anisotropy from 3D induction suggest the formation is potentially hydrocarbon bearing. TOC from spectroscopy and water filled porosity from dielectric compared to the total porosity are direct indicators of the presence of hydrocarbons in the formation, but the interpretation is complicated by water-based mud (WBM) filtrate invasion. The stacked T1-T2 maps generated immediately after NMR logging for selected intervals, clearly showed the presence of light oil. This was confirmed by the latest wireline formation testing in the next logging run.
Instead of quantitative formation properties evaluation this paper focuses on qualitative fluid identification with non-resistivity-based technologies, particularly with T1-T2 maps. NMR T1-T2 fluid mapping has been traditionally used for unconventional reservoir and is well discussed in various literatures. In our case, this technique has been applied for conventional reservoirs in the freshwater environment.