bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prevention and Control Effect of Rockburst in Superhigh-Water Backfilling Mining under Deep Coal Seam
Authors: Ren Shuai , Yu Guofeng , Luo Yong , Lu Dechao 
Published: March 2022

Abstract
Safe, efficient, and green mining of deep coal seams is a major problem to ensure the healthy development of China’s national modern energy economy. To explore the prevention and control effect of superhigh-water backfilling mining on rockburst, taking CG1302 working face of Shandong Yineng coal mine as the engineering background, it is explored through theoretical analysis, numerical simulation, and field monitoring. It is concluded that mining depth, mechanical properties of coal and rock mass, overburden conditions, geological structure, and roadway layout of the working face are the main influencing factors to induce rockburst, and it is determined that the Yineng coal mine has the conditions for rockburst. Based on the energy theory, the distribution law of coal deformation energy is analyzed, and the minimum kinetic energy of rockburst is calculated as Emin=77 kJ/m3. The energy accumulation in coal seams under different backfilling rates is simulated. Compared with caving mining, superhigh-water backfilling mining can effectively reduce the energy accumulation degree of coal seams and prevent the occurrence of impact dynamic disasters. Field microseismic and coal body stress monitoring results show that superhigh-water backfilling mining can effectively reduce the working face pressure and achieve the effect of preventing rockburst.
Characterization of the Giant Chicontepec Tight Oil Paleochannel in Mexico and Integration With Actual Cumulative Oil Production
Authors: Gutierrez Oseguera Alejandra , Aguilera Roberto 
Published: March 2022

AbstractThe Chicontepec Paleochannel contains unconventional tight oil shaly sandstone reservoirs also characterized by natural fractures. Chicontepec ranks as a giant reservoir with volumes of Original-Oil-in-Place (OOIP) ranging between 137,300 and 59,000 MMbbls (Guzman, 2019). Although the cumulative oil is significant (440.38 MMbbls) it only represents 0.32 to 0.75% of the OOIP. The objective of this study is developing a new characterization methodology with a view to increase oil recovery from Chicontepec. OOIP in Chicontepec paleochannels was estimated originally at 137,300 MMbbls. Despite several studies using state of the art methodologies, contracting major oil field services companies to test new technologies, and significant investments, the OOIP was decreased recently to 59,000 MMbbls due to lack of any significant success on the implemented projects.This study shows that the key to success is understanding the contribution of natural fractures. This is demonstrated with a new dual porosity petrophysical model for naturally fractured laminar shaly sandstone reservoirs developed in this study. The model assumes that matrix and fractures are in parallel. Laminar shaliness is handled with a parameter (Alam) that is a function of true and shale resistivities, and fractional shale volume.The methodology integrates data from observations in outcrops, quantitative evaluation of cores, well logs and actual production data. Past Chicontepec studies have assumed that the porosity exponent (m) in Archie and shaly sandstone equations, is constant. However, core studies indicate that Chicontepec m values become smaller as porosity decreases. The proposed dual porosity petrophysical model, when applied to actual Chicontepec wells, matches properly the laboratory values of m, and generates results that compare well with actual production data, e.g., the larger the value of fracture partitioning the larger is the cumulative oil production. Pattern recognition allows estimating fracture intensity with a partitioning coefficient, which is calculated as the ratio of fracture porosity to total porosity.The novelty of this study is the development of a new petrophysical dual porosity model for naturally fractured shaly sandstone reservoirs that integrates variable values of m from cores, fracture intensity, and cumulative production of individual Chicontepec wells. Thirty-one wells have been evaluated with good results using the proposed model.
Natural Gas Hydrate Equilibria in Brine Including the Effect of Inhibitors on Hydrate Formation
Authors: Sahari Moghaddam Farzan , Mahmoodi Maziyar , Zare Marziyeh , Goodarzi Fatemeh , Abdi Majid , James Lesley 
Published: March 2022

Abstract
Preventing hydrate formation is critical to safely and economically manage subsea tiebacks. Thermodynamic Hydrate Inhibitors (THI) and Low Dosage Hydrate Inhibitors (LDHI) help manage hydrate formation. Here, we use a novel isothermal approach using a PVT cell to experimentally find the hydrate equilibrium point of natural gas and brine. In addition, a constant temperature and pressure condition is used to compare hydrate formation with and without hydrate inhibitors.
First, to better understand the novel isothermal technique, natural gas-brine equilibrium experiments were conducted. Secondly, a constant pressure and temperature approach is used to investigate Kinetic Hydrate Inhibitors (KHIs) and low dosage methanol performance on hydrate formation. The formation and dissociation points are detected through a sudden drop or peak in the pressure profile, respectively, and by visual observation. To evaluate inhibitor performance, the experiments were conducted at challenging temperatures between -0.5°C to 3°C, applicable to the environment offshore Newfoundland and Labrador.
Two commercial KHIs and one THI were tested. Both KHIs showed good performance up to certain level of subcooling according to their concentration. However, KHI-B performed better at inhibiting hydrates compared to KHI-A despite its lower concentrations compared to KHI-A. The induction time for 1 wt% KHI-A under 10°C subcooling at a temperature of 0.75°C was 311 min. The induction time for 1 wt% KHI-B under 12°C subcooling at a temperature of 2.66°C was 184 min. Yet, in the case of KHI B, with half the concentration (0.5 wt%), no hydrate formed at temperature of 1.21°C and 10°C subcooling. Low dosage methanol (a common THI) was also assessed. Although the induction time under 10.36°C subcooling and constant temperature of −0.43°C was only 47 min, no hydrate formed within 22 hours at −0.12°C under 7.5°C subcooling.
This work uses a novel experimental isothermal approach by PVT cell to investigate hydrate equilibrium and the effectiveness of different inhibitors. Hence, a better understanding of natural gas hydrate equilibrium in brine is developed. Based on significant costs associated with injecting high quantities of THI (e.g., methanol) to prevent hydrate formation, this work also compares the performance of KHIs and low dosage THI (methanol).
The Application of Complex Displacement in Cyclic Steam Stimulation CSS & Steam Flooding SF Development in Liaohe Oilfield: A Field Performance Study
Authors: Liu Jianfeng , Wu Xiaoming , Sun Shouguo , Hao Ling 
Published: March 2022

Abstract
The oil/steam ratio for both Cyclic Steam Stimulation (CSS) and Steam Flooding (SF) has almost reached economic limits in Liaohe, China's largest heavy oilfield. Complex displacement of CSS and SF assisted with foaming agents and CO2 has been applied at commercial scale to increase the oil production. In this paper, we will present a field case study of the complex displacement operation. We will discuss the details from the foaming agent selection, completion design, operation management and performance data analysis.
To improve production rates for the low producing CSS and SF wells, a recovery method of complex displacement has been implemented at commercial scale in Liaohe oilfield. The application of the method depends on the reservoir condition, well completion design, injection time, types of foaming agents and so on. After a complicated optimization and careful field implementation, a satisfactory result was achieved. A complete field case will be studied in detail and comprehensive field performance data will be presented and analyzed.
For both CSS and SF operations, the type of foaming agent and especially its injection rates for each of these operations is the key to the success of the project. Different types of foaming agents and injection rates have been trialed. The injection rates of CO2,and steam to form the agent have been optimized. Relatively mature complex displacement development technology has been developed for both CSS and SF and will be presented in the paper. As of today, more than 480 CSS wells have been operated with the assistance of CO2. The oil/steam ratio in those application well groups has increased by 7%, while the operating cost has decreased by 7.9%. Three SF well groups assisted with hot air foam have been tested. The incremental oil production was more than 60%. The goals of cost reduction and oil production increase have been achieved with the complex displacement method in both CSS and SF.
As far as we know, this is the first paper to comprehensively introduce this type of complex displacement recovery method for CSS and SF in heavy oil operations.
This complex displacement recovery method has been proved to be an effective method to improve the heavy oil recovery in Liaohe. It is believed the learning and experience can be beneficial for the other heavy oilfields around the world. In the meantime, it could also facilitate the utilization and storage of CO2.
On Numerical Modelling of the Hydraulic-Fractured Closed Loop Systems: Single Producer
Authors: Irani Mazda , Ghannadi Sahar , Nick Daprocida Nick Daprocida , Lacoste-Bouchet Pierre , DiStefano Vince 
Published: March 2022

Abstract
There are large regions of the subsurface where the temperature is sufficiently hot to generate geothermal electricity within reasonable drilling depths, but the formation does not have enough permeability to create heated water productivity. The primary bottleneck is the difficulty of achieving adequate flow rate in such geothermal reservoirs. These formations are referred as hard dry rock (HDR). In these formations two common applications are conducted: Enhanced (or Engineered) geothermal systems (EGS) and Advanced geothermal systems (AGS). AGS is a closed-loop system that are built on wells drilled that connect with each other allowing a heat exchange-type to set up beneath the surface. There has recently been a lot of attention to the concept of ‘closed-loop geothermal’. The concept is still evolving and few startups such as E2E Energy Solutions, Eavor Technologies, and Green Fire Energy suggested different types of the closed-loop to optimize the technology. Since the technology only relies on conduction as the only source of heat transfer to improve the economics of the closed-loop E2E Energy Solutions suggested to use the hydraulic fracture to increase the surface area between the well and the geothermal reservoir. Such process is called Enhanced Geothermal Reservoir Recovery System (EGRRS).
In the E2E's EGRRS process, a fluid would be produced from an existing hot subterranean aquifer reservoir, close to a favorable geothermal zone, instead of creating the whole loop from the surface. The fluid withdrawn from a hot subterranean reservoir would be contacted with a hydraulically fractured zone in the geothermal zone, which would result to additional energy transfer and therefore a higher enthalpy once the fluid reaches the surface. The plan is to reach temperatures above 200°C that greatly increasing the electrical generation potential.
Although to implement the EGRRS process we are using the common oil and gas practice but to optimize and design the process using current modelling techniques is not achievable. Current simulation schemes cannot model such complex system, and to resolve this, a new framework must be designed to resolve the challenge. In this paper we present a new method that calculate rate to each branch by a new iterative approach that resolve the problem on how fractions of different pipe should be solved. Since the closed-loop wells are connected to the subterranean aquifer reservoirs and operator required to keep the WHP at constant pressure, there is another layer of iteration that required to solve for fraction on each pipe and BHP at the aquifer. Finally, to model the heating in the fractured zone, a new resistance is added to the model to mimic the heating exchange between the fracture and the fluid? and also the fracture and the radiator formation.
Improvement of Energy Efficiency in Gas Condensate Stabilization Unit: Process Optimization Through Exergy Analysis
Authors: Hajizadeh Abdollah , Mohamadi-Baghmolaei Mohamad , Mirghaderi Fatemehsadat , Azin Reza , Zendehboudi Sohrab , Saneei Taghi , Rajaei Hamid , Keshavarzian Sajjad 
Published: March 2022

Abstract
Gas condensate stabilization is a common process in gas refineries and petrochemical industries. This process is energy-consuming since it uses distillation columns and furnaces to separate different cuts from the condensate feed. This study aims to improve the performance of the gas condensate stabilization unit in a large petrochemical company in terms of energy efficiency and loss prevention. The case under investigation is the gas condensate stabilization unit in the Nouri Petrochemical Company, treating 568 t/h of raw condensate feed. This plant includes two distillation columns, two furnaces, pumps, heat exchangers, and air coolers. A hybrid energy and exergy analysis is conducted in this study. First, the validation of the simulation phase is performed, and a parametric sensitivity analysis is conducted to explore the effects of various parameters, such as operating temperature and pressure, on the process performance. After that, the most influential variables are identified using thermodynamic analyses for optimization and design purposes.
An optimization method is employed to attain the maximum production improvement and exergy efficiency. The exergy analysis shows 187.4 MW total exergy destruction in the plant; furnaces account for 79% of the total exergy destruction. According to the sensitivity analysis results, the energy consumption of the process could be reduced by 33.7 MW; this is an 18% reduction in the plant's energy consumption. The optimal process conditions outperform the current and design states (4.6% improvement in exergy efficiency). The fuel gas consumption is reduced by 2.1 t/h, leading to a reduction of 128 t/d CO2 emissions.
Tripping Optimisation for Drilling Systems Automation: Potential of Digital Twins, Transient Models and Control Systems to Reduce Invisible Lost Time in Well Construction
Authors: Forshaw Matthew J. , Madeira Rafael A. , Arévalo Pedro J. 
Published: March 2022

Abstract
Tripping, the process whereby a string is moved in either axial direction makes up 30% of the well construction time and is therefore responsible for a significant portion of capital expenditure by operators. Typically, the focus in the industry in optimizing this segment of the operation has centered on minimizing the slips-to-slips connection time. This references the time taken to swing in and make-up, or breakout and rack-back a stand before engaging elevators to either run-in or pull-out with the next component. This required both human-process optimization through training and technological development of topside equipment, first in isolation and then through systems automation. This paper recognizes these optimization efforts but identifies additional potential to significantly reduce invisible-lost-time (ILT) during tripping operations even further by reducing out-of-slips running time in tripping operations, all while keeping wellbore pressures within the safe operating envelope.
Physics-based steady-state fluid dynamics models have been in use for decades to define boundary conditions for these operations. These swab and surge calculations output a velocity limit for moving pipe. Models that are more complex have begun to diffuse into the commercial environment over the last decade and enhance borehole protection by providing a coupled acceleration limit. Acceleration and velocity are inherently linked so an optimization must be performed to arrive at the optimum velocity-time curve.
In this paper we present real-time engineering simulations to create a digital twin of the downhole environment and calculate optimum tripping parameters for every stand. The parameters are then passed as set-points to automated rig control systems. The paper summarizes the physics-based modelling as well as the mathematical optimization. The system, including interfaces required to implement control in the context of drilling systems automation is also described. Field examples are presented whereby exposing actual real-time measurements and derived tripping boundary conditions in an intuitive, accessible user interface can lead to performance improvements.
The ability to calculate the optimum velocity-time curve is the essential ingredient in gaining efficiency while out-of-slips during tripping operations, and simultaneously staying within a safe operating envelope. The resulting reduction in invisible-lost-time demonstrated, and associated reduction in rig time has obvious financial implications for operators and increasingly more important, helps achieve critical ESG targets. Finally, the paper will touch the need, and applicability of such technology in the energy transition new frontiers, specifically geothermal.
A Machine Learning Approach to Real-Time Uncertainty Assessment of SAGD Forecasts and the Optimization of Steam Allocation
Authors: Hunyinbo Seyide , Azom Prince , Ben-Zvi Amos , Leung Juliana Y. 
Published: March 2022

Abstract
Field development planning and economic analysis require reliable forecasting of bitumen production. Forecasting at the field level may be done using reservoir simulations, type-curve analysis, and other (semi-)analytical techniques. Performing reservoir simulation is usually computationally expensive and the non-uniqueness of a history-matched solution leads to uncertainty in the model predictions and production forecasts. Analytical proxies, such as Butler's model and its various improvements, allow for sensitivity studies on input parameters and forecasting under multiple operational scenarios and geostatistical realizations to be conducted rather quickly, despite being less accurate than reservoir simulation. Similar to their reservoir simulation counterparts, proxy models can also be tuned or updated as more data are obtained. Type curves also facilitate efficient reservoir performance prediction; however, in practice, the performance of many SAGD well-pairs tends to deviate from a set of pre-defined type curves.
Historical well data is a digital asset that can be utilized to develop machine learning or data-driven models for the purpose of production forecasting. These models involve lower computational effort compared to numerical simulators and can offer better accuracy compared to proxy models based on Butler's equation. Furthermore, these data-driven models can be used for automated optimization, quantification of geological uncertainties, and "What If" scenario analysis due to its lower computational cost.
This paper presents a novel machine learning workflow that includes a predictive model development using the random forest algorithm, clustering (to group wells by geological properties), Bayesian updating, Monte Carlo sampling (for uncertainty quatification), and genetic algorithm for the forecasting of real-world SAGD injection and production data, and optimization. The training dataset involves field data that is typically available for a SAGD well-pair (e.g., operational data, geological, and well design parameters). Just as importantly, this machine learning workflow can update predictions in real-time, be applied for the quantification of the uncertainties associated with the forecasts, and optimize steam allocation, making it an important step for development planning and field-wide optimization. To the best of the author's knowledge, this is the first time that machine learning algorithms have been applied to a SAGD data set of this size.
The Impact of Increase in Lateral Length on Production Performance of Horizontal Thermal Wells
Authors: Izadi Hossein , Roostaei Morteza , Mahmoudi Mahdi , Hosseini Seyed Abolhassan , Soroush Mohammad , Rosi Giuseppe , Stevenson Jesse , Tuttle Aubrey , Sutton Colby , Leung Juliana , Fattahpour Vahidoddin 
Published: March 2022

Abstract
Drilling the horizontal wells was the beginning of unlocking the enormous potential of Western Canada oil-sands. However, several technical and operational challenges avoid the so-called extended reach Steam Assisted Gravity Drainage (SAGD) wells. The last few years drive to reduce Capital Expenditures (CAPEX) encouraged the development of key innovative tools to make long thermal wells a reality. SAGD pad development using maximum possible well-length has taken significant leaps in economical assessment of SAGD projects. The goal of this paper is investigating the impact of Flow Control Devices (FCDs) on the overall performance of the long wells in SAGD projects.
In this paper, seven major thermal projects in Western Canada were investigated. Production history of all the wells is normalized by the variation of the geological condition, operational parameters, and well length. Following a convention in the industry, the wells with lateral length longer than 850 meters are labeled as "long" and those shorter than 850 meters are labeled as "short". Eventually, normalized oil production by long wells completed or retrofitted with FCDs is compared with those without FCDs to supply insight on the role of completion design on relative performance of drilling long wells. The comparison has been conducted with respect to different completion types such as Liner or Tubing Deployed FCDs (LDFCD or TDFCDs).
On average, long wells produced 2% more normalized oil compared to short wells for all projects, while they produced on average 16% more normalized oil in the projects 1, 2, 6, and 7 in which long wells successfully drilled. The historical production performances show that FCDs are the key enablers and innovative strategy to drill longer wells. For successful long wells with FCDs, the normalized oil production is improved as high as 81%, and the improvement rate is 108% and 10% for LD and TD FCDs, respectively. Furthermore, the completion strategy of combining long wells with FCDs improved the normalized oil production about 33% compared to short wells. This study shows that switching from short wells to long wells in SAGD projects and completing them with FCDs is a synergic approach to increase the oil production (33%).
The results of this paper confirmed that drilling long wells with FCDs is a win-win strategy resulted in more oil production compared to long/ short wells without FCDs; since CAPEX is reduced by long wells and oil production is increased by FCDs. The results also help completion and production engineers to get a better understanding of the contribution of FCDs in long lateral wells.