bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Oil Chemistry on the Performance of Low Salinity Waterflooding: An Integrated Experimental Approach
Authors: Tawfik Miral S. , Karpyn Zuleima T. , Johns Russell T. 
Published: October 2020

Abstract
Chemical enhanced oil recovery (cEOR) relies on the interactions of the injected chemicals with the surface-active components (SACs) of the oil-in-place and the rock surface to induce favorable physico-chemical changes. In this study, we investigate the effect of oil composition on the performance of low salinity waterflooding (LSWF) in carbonate rocks using an integrated experimental approach. In addition, we assess the extent of usefulness of total acid number (TAN) as an oil screening criterion for LSWF application in carbonate reservoirs by using model oils that have different SACs, but the same TAN.
A variety of characterization techniques including thermal gravimetric analysis (TGA), attenuated total reflectance (ATR-FTIR) and zeta potential (ζ) are performed to investigate the molecular-scale effect of oil chemistry on rock-oil-brine interactions during LSWF. Sessile drop contact angle measurements are also performed to quantify the influence of different SACs on the wettability of carbonate rock samples. Concurrently, coreflood experiments are performed to evaluate the effect of oil composition on the performance of LSWF in carbonate rocks in terms of Darcy-scale oil recovery.
Results of this study show that oil chemistry significantly influences the performance of LSWF at all scales. Different molecular-scale interactions are observed in the presence of different SACs owing to differences in their affinity to the rock surface, strength of adsorption, solubility in brine, as well as their distinct pore-scale wetting abilities. These differences translate into significant variation in Darcy-scale oil recovery. In addition, carboxylic acid chain length is found to affect the amount of SACs adsorbed onto carbonate rocks during aging. Carboxylic acid chain length also affects the strength of adsorption, which in turn impacts the magnitude of wettability alteration during LSWF. Further, partitioning of SACs in brine is observed to influence the type of interactions taking place in the rock-oil-brine system, where carboxylate salts (soaps) generated in-situ are detected only in the presence of certain oil-brine pairs but not in the presence of others. Solubility of SACs in brine is also found to promote water-wetness. As a result, significant differences in the rate of oil recovery and ultimate recovery are observed when displacing four oils by the same low salinity brine at similar experimental conditions. Finally, the value of TAN is found to be insensitive to the type of acidic SACs present in the oil phase as long as they are monoprotic and their molar concentration in the oil is the same. Even within the same class of SACs, namely carboxylic acids, the usefulness of TAN is limited in differentiating between the type and molecular structure of the acid (i.e.: straight chain versus aromatic).
Mechanics of Fracture Propagation in Closely Spaced Clusters
Authors: Daneshy Ali 
Published: October 2020

Abstract
For more than a decade there has been a gradual reduction in perforation cluster spacing together with increased number of clusters and larger frac sizes. The main driver for this change has been increased production. In recent years the more common cluster spacing has been in the range of just a few tens of feet, even as low as only five feet.
This paper discusses the effect of reduced cluster spacing on propagation pattern of hydraulic fractures. It notes that fractures are more likely to initiate axially/longitudinally from perforations and reorient once they extend away from the wellbore to become perpendicular to the least principal stress. This process causes formation of a pseudo-open hole along the axial fracture near each perforation cluster and its existence has been verified by proppant tracer and fiber optic surveys. In cases of close cluster spacing these pseudo-open hole segments can merge and cover a much longer segment of the cemented liner. Merging of axial fractures will be further assisted by poor quality cement. This causes the fracture re-orientation to occur along a material weakness intersected by the merged axial fractures, somewhat like what would happen in an openhole completion. The net result is random location and number of fractures extending away from the wellbore. Presence and extent of the pseudo-open hole is demonstrated by proppant tracer surveys from actual field examples presented in the paper.
Paper concludes that there is a limit to usefulness of shorter spacing for increasing the number of created fractures. If too close, the randomness of fracture location and number can create results contrary to expectations. It recommends an alternate hybrid cluster arrangement consisting of bunching the closely spaced perforation clusters into multiple separate groups and using larger separation between the groups to avoid spread of the initiated axial fractures outside each group.
Robust Data Driven Well Performance Optimization Assisted by Machine Learning Techniques for Natural Flowing and Gas-Lift Wells in Abu Dhabi
Authors: Al Selaiti Iman , Mata Carlos , Saputelli Luigi , Badmaev Dorzhi , Alatrach Yara , Rubio Erismar , Mohan Richard , Quijada Daniel 
Published: October 2020

Abstract
Asset management success is accomplished when the integrated production system is operating close to its intended potential. Continuous awareness of wells and facility conditions are key factor in the realization of designed capacity. In contrast, unknown status and conditions can severely limit production capacity.
The rise of instrumentation technologies over the last four decades have created new opportunities to understand well and reservoir behavior. However, despite of being proved as a cost-effective surveillance initiative, remote monitoring is still not adopted in over 60% of oil and gas fields around the world. Understanding the value of data through machine learning techniques is the basis for establishing a robust surveillance strategy.
The objective of this paper is to develop a data-driven approach, enabled by Artificial Intelligence (AI) methodologies including machine learning (ML), to find optimal operating envelope for gas-lift wells. The process involves building ML models for generating instantaneous predictions of multiphase flow rates and other quantities of interest, such as GOR, WCT, using real-time sensor data at the surface, historical performance, and sporadic test data.
Additionally, forecasting models were developed for generating short-term (30 days) forecast of cumulative oil, water, gas, and liquid production, multiphase flow rates, WCT, GOR, and reservoir pressure. Using time-series forecasting models, a sensitivity analysis was performed to generate short-term well response for a selected number of combinations of choke settings, and gas injection rates. Sensitivity analysis provides 2D maps of well response highlight an operating envelope, which are proposed to be combined with physical and operational constraints to arrive at optimal operating conditions, which may effortlessly add 2.5% net profit from optimum gas-lift alocation.
The results of this work show encouraging results, and demonstrate value that AI-enabled methodologies can provide in instrumented wells by enabling automated workflows for virtual metering, production allocation, short-term production forecasting, and deriving optimal operating conditions. The developed AI methodology has tremendous potential of integration in an end-to-end workflow of autonomous well control by utilizing available data to produce easy to update ML models, with little to no human intervention.
How Much Can You Afford to Ignore Casing Failure During Hydraulic Fracturingš the Search for a Non Damaging Frac Plug
Authors: Stolyarov Sergey , Casanova Gabriel , Xu YingQing , Deng Guijun , Holmes Kevin , Gomez Ricardo , Young Aaron 
Published: October 2020

Abstract
Frac plugs remain the most common zonal isolation tool in multistage stimulation. However, while manufacturers in recent past have focused on improving frac plug drillability and dissolvability, the industry critically overlooked significant plug design flaws. Among these flaws is mechanical damage to horizontal well casing caused by inadequate plug construction, poor isolation integrity, and cycled pressure stress on the pipe throughout the entire fracture treatment. Until recently, casing integrity issues had never even been associated with frac plugs.
Today, significant improvements in ultrasonic wellbore diagnostics, downhole cameras, and fiber optic well monitoring visualizing post-frac casing integrity have revealed widespread casing breaches at plug setting depths. These recently discovered flaws called for a frac plug with non-damaging slips and optimized packing element systems for improved zonal isolation. Three-dimensional finite element analysis was performed to understand casing damage caused by various slip designs currently being utilized in the market. Extensive laboratory tests were conducted on slip and packing element designs to further support and validate the numerical study. Finally, fiber-optic diagnostic data was used to confirm interstage isolation efficiency by a non-damaging frac plug.
This paper will review findings that some slips, under certain scenarios, cause severe casing wall damage. It will also review findings that some packing element designs provide inadequate isolation during the fracture–posing considerable challenges to casing integrity. Based on extensive numerical analyses, laboratory tests, and field trials, a frac plug with non-damaging slips, as well as anti-extrusion packing element systems, limit the frac plug's impact on the casing during high fracture pressure treatments.
Digital Transformation of Well Completion Selection and Design Through Data Insights
Authors: Gottumukkala Varma , Worthington Matthew , Basak Debasmita , Radhakrishnan Renuka , Srinivasan Jay , Ramesh Smitha 
Published: October 2020

Abstract
Well completion selection and design involve the selection of optimum well completion architecture and associated downhole equipment to deliver hydrocarbon to surface in a safe and efficient manner. A number of well architectures can be conceived for a given application, and a plethora of equipment is available across the industry, with hardware to meet a wide range of operating conditions including hole size, pressure, temperature, flow rate and fluid type. This wealth of choice results in a highly complex and challenging selection process that today is done manually, relying on subject matter experts and local best practices through trial and error approach. As a result, the process can be quite inefficient, designs can be suboptimal and fail to consider unique reservoir and well conditions leading to premature equipment failure causing loss of production and well integrity. These failures can have impact ranging from unplanned well intervention, equipment pull outs, fishing operations, extended rig time, workovers, or even complete well loss—costing the oil and gas industry billions of dollars. The shortcomings in design are therefore ripe for innovative digital solutions.
This paper describes how manual completion selection process can be seamlessly transformed into an intuitive digital solution providing insights for the well completion selection process. The proposed digital solution describes software tools and architecture used to consolidate thousands of historic, unstructured, completion schematic data into a structured database. It automatically maps the completion architecture and equipment details to relevant operating environments, captures nonproductive time and highlights installation challenges. The solution also identifies correlations and data trends across various types of well designs and equipment categories, using advanced artificial intelligence and machine learning algorithms to provide insights into equipment reliability, operational efficiency, total cost of ownership and production performance. A minimum viable product consisting of 24,000 wells from across the world has been successfully developed to demonstrate key value propositions.
New data coming in from recently completed wells can be seamlessly integrated with the existing data bases and the algorithms constantly improvise its learning process to provide better accuracy. The digital solution proposed for well completion selection and design process ultimately enables oil and gas companies to optimize well completion configurations and equipment that can deliver maximum value. It allows them to identify offset well issues, derisk operational concerns, check compatibility of equipment with respect to dimensional constraints, pressure and load rating requirements, thread configurations, metallurgy constraints, seal elements, complete well on digital file with tracing and accountability.
Data Analysis of the Permian Basin Wolfcamp and Bone Spring Leads to Better Understanding of Production Sweetspots
Authors: Sorkhabi Rasoul , Panja Palash 
Published: October 2020

Abstract
The Wolfcamp and Bone Spring formations of Lower Permian age in the Permian superbasin of west Texas and southeast New Mexico have contributed greatly to the US shale oil revolution in the recent decade. These formations were deposited in a rapidly subsiding basin at the southern margin of the North America craton during collisional tectonics in Late Paleozoic times. Here we analyze production data from nearly 4,800 horizontal wells drilled into Welfcamp and Bone Spring to constrain petroleum accumulations. The data indicate a bimodal distribution of oil and gas occurrence in Wolfcamp suggesting the migration of oil and gas from deeper (∼11,000 ft.) to shallower levels (4,000-6,000 ft.) in the same formation. Oil accumulation in Bone Spring is concentrated at the depths of 11,000-7,000 ft. with some intervals being more productive mimicking the alternating position of shaley and sandy layers in this formation. High gas-to-oil ratios are found at shallower levels for both formations. This study offers an application of reverse engineering to petroleum system analysis and supports the concept of intra-formational migration in the tight (shale) oil formations.
Optimization of Multi-Stage Hydraulic Fracturing in Unconventional Reservoirs in the Context of Stress Variations with Depth
Authors: Singh Ankush , Zoback Mark , McClure Mark 
Published: October 2020

Abstract
Stage length and perforation cluster spacing are important design parameters for multi-stage hydraulic fracturing. This study aims to demonstrate that the interplay between subtle variations of the least principal stress (Shmin) with depth and the stress shadows induced by simultaneously propagating hydraulic fractures from multiple perforation clusters, primarily determines the propped and fractured area in the target formations. This principle is illustrated with the help of a case study in a prolific unconventional formation in the north eastern US, where the vertical stress variations are well characterized through discrete multi-depth stress measurements and actual stage design parameters used by the operator are known. At first, we show how the hydraulic fracture footprint and proppant distribution varies with a change in the vertical stress profile. The stress profile is shown to be a very important in determining the optimal vertical and lateral well spacing. The evolution of the stress shadow in the different layers is shown during the pumping as the fracture propagates across multiple layer boundaries. Subsequently, we demonstrate that by changing the magnitude of stress perturbations caused by the stress shadow effect, the distribution of propped area can be altered significantly. We use this method to determine the optimal cluster spacing keeping other design parameters constant such as flow rate, perforation diameter, etc. Simulations from selected cluster spacing realizations are run with high and low permeability scenarios to show the importance of correct matrix permeability inputs in determining the three-dimensional depletion profile and ultimate production. By varying the cluster spacing we show the hydraulic fracture propagation change from being solely stress layering driven to stress shadow influenced. The effect of stress shadow on the final fracture footprint is highly specific depending on the given stress layering and is thus case-dependent. This study demonstrates that knowledge of stress variations with depth and modeling are critical for optimizing stimulation efficiency.
Application of Flexible Variable Frequency Drive Systems in Low-Volume Pumping Wells
Authors: Fu Zhijun , Wang Qian , Wang Lei , Xu Jingjing , Qiu Yiwang , Li Chaofeng 
Published: October 2020

Abstract
Improving pumping system efficiency in low production wells has been a big challenge for most of mature fields in China. These wells often cause high energy consumption and additional mechanical wear because of relatively high pumping speed and nonoptimalpower input for motor drive, even though operators respond it by simply turning down the stroke per minute (SPM) or adopting variable intermittent production scheme based on the well conditions. Therefore, for low production wells, it is important to produce more oil with lower energy input or operational cost. In recent years, researchers proposed a few high-efficiency intelligent control strategies used for these wells, but rarely could be effective and widely used in the field due to the lack of behavior improvement and adaptability. Based on the results from previous research, this paper provides a new solution on flexible variable frequency drive to address the aforementioned challenges.
To obtain high system efficiency for low production well, firstly new solution, under a preset and fixed SPM, manage to change pumping speed within each cycle. This can be done utilizing the pumping net load data which is calculated by controller algorithm. Then, it will regulate the SPM based on the real time production data (mainly for fluid rate) which is automatically collected by a specialized wellhead flow meter. Since flow rate is the most effective and direct data to demonstrate reservoir capacity, it can guarantee an accurate and reasonable pump SPM. All adjustments above would be done through continuously regulating the motor electrical parameters, such as voltage and current, using converter and control algorithm built in the flexible controller. Real-time matching to the lifting load and well capacity can realize the best motor drive pattern and avoid the waste of energy. Tow set of process control makes up the new control strategy and fulfills a more ideal pumping operation.
For different well capacity, new technology allows the pump frequency to be regulated from 0.5 SPM to 12 SPM under a stable running condition. Each stroke has an adjustable rate process to match inconstant net load. For those low production wells, relatively low and constant-changing pumping speed not only largely decrease producing energy needs, but also reduce rod-on-tubing wear. Thus, the test wells have improved system efficiency and prolonged mean time between failures (MTBF). This paper would describe the control principle of flexible variable frequency drive system in detail and demonstrate its application through two well cases.
Improving ESP Performance with Two Stages of Gas Separation in 7 Casing Case Study
Authors: Delgado Anderson , Espinosa Jorge , Hernandez Maria , Guanacas Luis , Gonzalez Gustavo , Aya William 
Published: October 2020

Abstract
The Electrical Submersible Pump (ESP) has become one of the most popular ALS worldwide due to its capacity of lifting high fluid volumes with high efficiency, however, its application is questioned under some circumstances related to difficulties that this system presents when managing high gas rates. Even though the ESPs can handle high volumes, they are also highly affected by gas bubbles flowing through each component, affecting: the motor temperature, lifting efficiency, the integrity of the motor and cable, situations that can lead to premature failure and expensive workover operations. This is the reason why some companies decide to install a different ALS instead of an ESP. The present study shows a successful ESP optimization in combination with a new gas mitigation system that allowed to manage high GOR and GLR and avoid gas locking, low lifting efficiency, multiple shutdowns due to poor cooling in the motor, and surge production (changes on motor load). The new double stage gas mitigation system was designed to manage a GOR&gt;1,200 SCF/STB with a WC of &lt;1%, BHT of 200 °F, and 85% of free gas flowing into the pump intake. This gas separation system for ESP was complemented by installing a shrouded ESP to assure a proper cooling of the motor and to prevent the free gas to flow directly to the pump intake. This paper contains all the descriptions of each component of the 2 stage gas mitigation/separation system.
The well showed a notorious production improvement and the operator was able to decrease the PIP below 630 psi (Max limitation on the Jet pump system due to low efficiency of this ALS) achieving a production increase from 300 to 700 BOPD (↑400 BOPD)
Laboratory Measurement of Cement Stress Before, During, and After Curing Under Undrained Condition with Constant Hydrostatic Pressure
Authors: Meng Meng , Frash Luke , Carey James , Li Wenfeng , Welch Nathan 
Published: October 2020

Abstract
Wellbore integrity analysis should consider the cement setting process in a confined downhole environment, noting that cement is initially a liquid that becomes a solid. In our study, the state of stress of cement specimens is measured during cure from a liquid to a solid at laboratory simulated downhole conditions. We apply accurate control of axial stress, confining pressure, and pore pressure inside cement specimens during the entire setting process combined with strain gauges mounted on the outer surface of the steel pipe to measure the cement's state of stress during the setting process. The setup allows multiple experimental conditions to be investigated, including constant axial stress, constant axial displacement, drained and undrained conditions. Different controlling conditions represent different field scenarios since the process of cement setting in the downhole situations is a highly complex process that depends on the in-situ condition, formation lithology, cement slurry composition, mud cake composition, drill bit type, etc. In this work, the Class-G cement slurry is cured under constant axial stress, confining pressure, and undrained conditions. This represents a field condition where the top of the cement can drop during setting, the vertical component of cement weight is not significantly affected by bonding, and the formation is quite impermeable with a very difficult fluid exchange between formation and cement. Our results show that under such a scenario, no significant pressure drop occurs after seven days of the setting process, and the cement initial total stress is close to its hydrostatic pressure.