bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Investigation of Proppant Transport and Placement Along Opened Bedding Interfaces
Authors: Xie Jun , Tang Jizhou , Sun Sijie , Li Yuwei , Song Yi , Huang Haoyong , Pei Hao , Zhang Fengshou 
Published: April 2021

Abstract
Slurry, as a proppant-laden fluid for hydraulic fracturing, is pumped into initial perforated cracks to generate a conductive pathway for hydrocarbon movement. Recently, numerous studies have been done to investigate mechanisms of proppant transport within vertical fractures. However, the distribution of proppant during stimulation becomes much more complicated if bedding planes (BPs), natural fractures (NFs) or other discontinuities pervasively distributed throughout the formation. Thus, how to capture the transport and placement mechanisms of proppant particles in the opened BPs becomes a significant issue. In this paper, we propose a closed-form continuous proppant transport model based on the conservation of total proppant volume and sedimentation of proppant particles. This model enables to integrate with the fluid flow section of a 3-D hydro-mechanical coupled fracture propagation model and then predict the distribution of proppant velocity and slurry volume fraction within a dynamic fracture network. Stokes’ law is applied to determine the sedimentation velocity. In the fracture propagation model, rock deformation is governed by the analytical solution of penny-shaped crack to determine fracture width. Fluid flow is characterized by finite differentiation scheme and then the fluid velocity is obtained. These two parameters above are inputs for the proppant transport model and both slurry viscosity and density are updated in this step. Afterwards, both fracture width and fluid velocity would be altered in the fracture model.
Analysis of the proppant distribution within crossing-shaped fracture is conducted to study mechanisms of proppant transport along opened BPs. From our numerical analysis, we find that the distribution of proppant concentration is independent with the fluid viscosity, but highly dependent on the volume fraction of pumping slurry, under a given pumping pressure. Due to the difference of viscosity and proppant volume fraction at locations of upper and lower BPs, we observe that two symmetric BPs are unevenly opened, with different channel length along BP. Moreover, the width of opened upper BP is much smaller than that of opened lower BP as a result of discrepancy of proppant sedimentation. Last but not the least, a criterion of flow bed mobilization is established for dynamically tracking the sedimentation along the BP. Then the effect of different parameters (such as proppant size, proppant density, fluid viscosity, injection rate) on proppant distribution along opened BPs is also studied.
Our model fully considers the proppant transport and settlement, proppant bed formation and interaction between fracture and proppant, which helps to predict the influence of proppant during fracturing treatment. Additionally, our model is also capable of dynamically tracking the settlement of proppant along opened BPs.
An Industry Overview of Downhole Monitoring Using Distributed Temperature Sensing: Fundamentals and Two Decades Deployment in Oil and Gas Industries
Authors: Soroush Mohammad , Mohammadtabar Mohammad , Roostaei Morteza , Hosseini Seyed Abolhassan , Mahmoudi Mahdi , Keough Daniel , Cheng Li , Moez Kambiz , Fattahpour Vahidoddin 
Published: April 2021

Abstract
Distributed Temperature Sensing (DTS) system using optical fiber has been deployed for downhole monitoring over two-decades. Several technological advancements led to a wide acceptance of this technology as a reliable surveillance technique. This paper presents a comprehensive technical review of all the applications of the DTS, with focus on oil and gas industrial deployments.
The paper starts with the advantages of the DTS over other methods and an overview of the DTS basics, including theory, the DTS components, deployment types, fiber types, design and limitations. Then, it is followed by the oil and gas applications of the DTS including hydraulic fracturing (during and after fracturing), well treatment/stimulation (acid injection, fluid distribution, diversion monitoring), inorganic (scaling) and organic (wax/asphaltene/hydrate) deposition detection, leak detection (in well and pipeline), flow monitoring (rate monitoring, water/steam injection and SAGD monitoring, CO2 storage monitoring, zonal contribution determination, gas lift optimization) and reservoir/fluid characterization (facies, porosity, permeability and fluid composition determination).
This study reviews the historical development, applications and limitations of the DTS systems. The paper mainly focusses on deployment techniques, the application of the DTS for the prediction and surveillance of the non-thermal and thermal producer/injector wells, hydraulically fractured wells and those wells with treatments. The paper provides a concise review using several field cases from over two hundred published papers of Society of Petroleum Engineering (SPE) and journal databases.
The application of the DTS in downhole monitoring can be divided into the qualitative and quantitative applications. In quantitative approaches, numerical models should be combined with the DTS data. This study discusses case by case worldwide field applications of DTS along with proposed modeling methods and interpretations. It also summarizes main challenges, including the fiber reliability, longevity, and operational limitations such as the installation and the complexity of quantitative approaches.
This study is the foundation for an ongoing study on wellbore and reservoir surveillance through real-time distributed fiber optic sensing recordings along the wellbore. It summarizes the historical development and limitations to identify the existing gaps and reviews the lessons learned through the two decades of the application of the DTS in production performance.
Parameters Estimation for Chemical Flooding Modeling Using Ensemble-Based Method
Authors: Wang Xindan , Zhang Yin , Dandekar Abhijit , Wang Yudou 
Published: April 2021

Abstract
Chemical flooding has been widely used to enhance oil recovery after conventional waterflooding. However, it is always a challenge to model chemical flooding accurately since many of the model parameters of the chemical flooding cannot be measured accurately in the lab and even some parameters cannot be obtained from the lab. Recently, the ensemble-based assisted history matching techniques have been proven to be efficient and effective in simultaneously estimating multiple model parameters. Therefore, this study validates the effectiveness of the ensemble-based method in estimating model parameters for chemical flooding simulation, and the half-iteration EnKF (HIEnKF) method has been employed to conduct the assisted history matching. In this work, five surfactantpolymer (SP) coreflooding experiments have been first conducted, and the corresponding core scale simulation models have been built to simulate the coreflooding experiments. Then the HIEnKF method has been applied to calibrate the core scale simulation models by assimilating the observed data including cumulative oil production and pressure drop from the corresponding coreflooding experiments. The HIEnKF method has been successively applied to simultaneously estimate multiple model parameters, including porosity and permeability fields, relative permeabilities, polymer viscosity curve, polymer adsorption curve, surfactant interfacial tension (IFT) curve and miscibility function curve, for the SP flooding simulation model. There exists a good agreement between the updated simulation results and observation data, indicating that the updated model parameters are appropriate to characterize the properties of the corresponding porous media and the fluid flow properties in it. At the same time, the effectiveness of the ensemble-based assisted history matching method in chemical enhanced oil recovery (EOR) simulation has been validated. Based on the validated simulation model, numerical simulation tests have been conducted to investigate the influence of injection schemes and operating parameters of SP flooding on the ultimate oil recovery performance. It has been found that the polymer concentration, surfactant concentration and slug size of SP flooding have a significant impact on oil recovery, and these parameters need to be optimized to achieve the maximum economic benefit.
A Systematic Design Approach for Bulk Gel Treatments Based on Average Gel Volume-Concentration Ratio
Authors: Aldhaheri Munqith , Wei Mingzhen , Bai Baojun 
Published: April 2021

Abstract
Controlling excessive water production in mature oil fields has always been one major objective of the oil and gas industry. This objective calls for planning of more effective water-control treatments with optimized designs to obtain more attractive outcomes. Unfortunately, planning such treatments still represents a dilemma for conformance experts due to the lack of systematic design tools in the industry.
This paper proposes and makes available a new design approach for bulk gel treatments by grouping designs of 62 worldwide field projects (1985-2018) according to gel volume-concentration ratio (VCR). After compiling them from SPE papers, the average gel volumes and polymer concentrations in the field projects were used to evaluate the gel VCR. Distributions of field projects were examined according to the gel VCR and the formation type using stacked histograms. A comprehensive investigation was performed to indicate the grouping criterion and design types of gel treatments. Based on mean-per-group strategy, the average VCR was estimated for each channeling and formation type to build a three-parameter design approach. Two approximations for the average polymer concentration and two correlations for minimum and maximum designs and were identified and included in the approach.
The study shows that the gel VCR is a superior design criterion for in-situ bulk gel treatments. Field applications tend to aggregate in three project groups of clear separating VCR cut-offs (&lt;1, 1-3, &gt;3 bbl/ppm). The channeling type is the dividing or distributing criterion of the gel projects among the three project groups. We identified that VCRs&lt;1 bbl/ppm are used to treat conformance problems that exhibit pipe-like channeling usually presented in unconsolidated and fractured formations with very long injection time (design type I). For fracture-channeling problems frequently presented in naturally or hydraulically-fractured formations, VCRs of 1-3 bbl/ppm are used (design type II). Large gel treatments with VCR&gt;3 bbl/ppm are performed to address matrix-channeling often shown in matrix-rock formations and fracture networks (design type III). Results show that the VCR approach reasonably predicts the gel volume and the polymer concentration in training (R2 of 0.93 and 0.67) and validation (AAPE &lt;22%) samples. Besides its novelty, the new approach is systematic, practical, and accurate, and will facilitate the optimization of the gel treatments to improve their performances and success rate.
The First Application of a Novel Reservoir Simulation Technology Comprising Radial Drilling and Hydraulic Fracturing in the Niobrara Shale
Authors: Potapenko Dmitriy Ivanovich , Hart Timothy Brian , Kibsgaard Paal , Waters George Alan , Lewis Richard E. , Utter Robert J. , Brown J. Ernest , Ayala Salvador , Goudy Guy Thomas , Jelsma Henk H 
Published: April 2021

Abstract
A novel reservoir stimulation methodology combines oriented extended perforation tunnels of lengths up to 300 ft with specially designed hydraulic fracturing operations. The new stimulation methodology was introduced in the Florence Field in Colorado and primarily targeted the Niobrara Formation.
The technology test included two vertical wells completed with two and five pairs, respectively, of extended perforation tunnels, each 300 ft in length, jetted using radial drilling technology. The jetting operation was followed by a fracture stimulation treatment. The orientation of the extended perforation tunnels and the design of the fracturing treatment were based on analysis of the geological data and were defined using geomechanical modeling as well as far-field and near-wellbore flow simulations. The use of radial drilling technology to create extended perforation tunnels for the vertical wells offered a cost-effective way to significantly increase the reservoir contact area ofthe wellbore, making it similar to that of horizontal wells in the area. The engineered fracture treatments were performed at low treating pressures, and low proppant and fluid volumes.
The initial production rates of the two vertical wells included in this technology test exceeded expectations and are comparable to the initial production rate of the offset horizontal well that was completed in the same zone with significantly greatervolumes of proppant and fluid. The initial evaluation of the economic efficiency of this novel reservoir stimulation technology showed that its deploymentdelivered improved production rate to cost ratio for the second vertical well, compared to the reference horizontal well.
Based on the test results from the two wells, we conclude that the proposed reservoir stimulation methodology leads to substantial improvements in well production performance compared to traditional reservoir stimulation methods. Both the applied cost-effective approach for increasing the reservoir contact and the significantly lower resource intensity required for the hydraulic fracturing treatment further improve the economic benefits of this methodology.
This novel reservoir stimulation methodology opens the way for reconsidering well completion practices in the Niobrara Formation and holds significant potential for improving the hydrocarbon production economics in the Florence Field.
Lost Hills Solar Project: Powering an Oil and Gas Field with California Sunshine
Authors: Demayo Trevor N. , Herbert Nevil K. , Hernandez Dulce M. , Hendricks Jana J. , Velasquez Beberly , Cappello David , Creelman Ian 
Published: April 2021

Abstract
This paper outlines one of the first efforts by a major oil and gas company to build a net exporting, behind the meter solar photovoltaic (PV) plant to lower the operating costs and carbon intensity of a large, mature oil and gas field in Lost Hills, California. The 29 MWAC (35 MWDC) Lost Hills solar plant, commissioned in April 2020, covers approximately 220 acres on land adjacent to the oil field and is designed to provide more than 1.4 billion kilowatt hours of solar energy over 20 years to the field's oil and gas field production and processing facilities. The upgrades to the electrical infrastructure in the field also include new technology to reduce the risk of sulfur hexafluoride (SF6) emissions, another potent greenhouse gas (GHG).
Prior to solar, the Lost Hills field was importing all its electricity from the grid. With the introduction of the Innovative Crude Program as part of California's Low Carbon Fuel Standard (LCFS) and the revisions to the California Public Utilities Commission Net Energy Metering program, Lost Hills was presented with a unique opportunity to reduce its imported electricity expenses, reduce its carbon intensity, while also generating LCFS credits. The plant was designed to power the field during the day and export excess power to the grid to help offset night-time electricity purchases. The solar plant operates under a Power Purchase Agreement (PPA) with the solar PV provider and, initially, will meet approximately 80% of the oil field's energy needs. Future plans include the incorporation of lithium ion batteries, DC-coupled with the solar inverters, and with a total capacity of 20 MWh. This energy storage system will increase the amount of solar electricity fed directly into the field and reduce costs by controlling when the site uses stored solar electricity rather than electricity from the grid. The battery system will also increase the number of LCFS credits by 15% over credits generated by solar alone. Together, solar power plus energy storage provides a robust renewable energy solution.
This project will generate multiple co-benefits for the Lost Hills oil field by lowering the cost of power, reducing GHG emissions, generating state LCFS credits and federal Renewable Energy Certificates, and demonstrating a commitment to energy transition by investing in renewable technology. Hopefully, Lost Hills solar can be a model for similar future projects in other oil fields, not only in California, but across the globe.
Modeling of Injection-Induced Particle Movement Leading to the Development of Thief Zones
Authors: Qi Qianru , Ershaghi Iraj 
Published: April 2021

Abstract
This paper is a contribution to failure prediction of unconsolidated intervals that could have a negative impact on injection efficiency because of susceptibility to structural changes under fluid injection processes. In unconsolidated formations, formation fines may be subjected to drag forces by injected water because of poor cementation. This results in small grain moments, and continuation can result in a gradual increase in permeability and eventual development of washed-out or thief zones. This paper presents a new modeling approach using information from profile surveys and grain and pore size distribution to model the process of injection and the induced particle movement.
The motivation came from field observations and realization of permeability increase from profile surveys and substantial fines movement, leading to an increase in rock permeability. A series of case studies based on realistic published data on pore and grain size distribution are included to demonstrate the estimated increases in formation permeability. In our modeling approach, once we establish the range of grain sizes that fits the criterion for particle movement, a probabilistic algorithm, developed for the study, is applied to track changes in porosity and associated variations in permeability. This algorithm, presented for the first time, considers a stochastic approach to monitor the reservoir particle movements, pore size exclusion by particle accumulation and their resultant changes in rock properties. For this methodology, we ignored potential effects of wettability and clay swelling, and considered perfect spheres to represent the various grain sizes.
Predictions made using various realizations of channel formation and petrophysical alterations show the significance of having access to three sources of information; pore size distribution, grain size distribution, and profile surveys. Through inverse modeling using these pieces of information for a particular formation, we demonstrate how we can predict realistic changes and map rock transport properties.
Modeling and Simulation of Asphaltene Inhibition and Remediation Using Aromatic Solvents
Authors: Abouie Ali , Sepehrnoori Kamy 
Published: April 2021

Abstract
Asphaltene precipitation and deposition occur in the reservoir, near-wellbore, inside the tubing, and production facilities during primary, secondary, or tertiary production. As more water-flooded oil fields produce under miscible gas flooding, this problem becomes more common around the world. If asphaltene deposition occurs in the reservoir or wellbore, it can severely affect the economics of the field in terms of production loss, intervention cost, and the requirement for chemical additives, if necessary. In some severe cases, intervention would be impossible and side-track well needs to be drilled. Hence, the best strategy for oil production in asphaltenic reservoirs is to control asphaltene precipitation and deposition through prevention and remediation jobs to minimize the number of well shut-ins, the downtime of the wells, and the associated cost.
In this paper, we reviewed the common asphaltene prevention and remediation techniques along with their pros and cons. Since removing asphaltene deposits from the problematic wells is relatively expensive and sometimes requires substantial downtime of the well, we focused on one of the prevention techniques (i.e., continuous solvent injection through capillary injection string), which has become more popular, to control asphaltene precipitation in the wellbore. We obtained the physical properties of an aromatic solvent from literature and then characterized it as a component to be used with PC-SAFT EOS. Subsequently, we used the in-house wellbore model to evaluate the effectiveness of the continuous solvent injection with different injection rates on preventing asphaltene precipitation and deposition along the wellbore.
Experimental Investigation of Hybrid Techniques for Enhancing Alaska North Slope Viscous Oil Recovery
Authors: Cheng Yaoze , Zhang Yin , Dandekar Abhijit 
Published: April 2021

Abstract
Alaska North Slope (ANS) contains vast viscous oil resources that have not been developed effectively due to the lack of efficient Enhanced Oil Recovery (EOR) techniques. This study investigates the EOR performance of three new hybrid EOR techniques: HSW-LSW-LSP flooding, solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding. Additionally, pressure-volume-temperature (PVT) tests have been conducted to investigate the oil swelling and viscosity reduction effects of the proposed solvent. It has been found that the oil recovery of HSW flooding was 43.42%, while the tested HSW-LSW-LSP flooding, solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding could improve the oil recovery to 74.17%, 79.73%, and 85.87%, respectively. All three proposed hybrid EOR techniques can significantly enhance the viscous oil recovery since they were all designed to both improve the microscopic and macroscopic sweep efficiencies. In particular, the PVT test results confirmed that the proposed solvent in this study could effectively swell the viscous oil over 30% and significantly reduce the viscous oil viscosity by about 97%. However, the initially designed solvent-alternating-LSP flooding displacement experiment had to be terminated after the first slug of polymer injection due to the extremely high differential pressure, which was over the measurement range of the pressure gauge. Thus, the actually tested displacement process in this study was solvent-LSP flooding. The extremely high differential pressure was found to result from the polymer deposit and blockage at the outlet. Although the proposed solvent-alternating-LSP flooding may produce the highest oil recovery, it cannot be applied in the field until the issue of polymer precipitation is understood and solved. The study has practical guidance to the selection of proper EOR techniques to enhance viscous oil recovery on ANS.