bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory-Scale CO2 Huff ‘n Puff EOR using Single Phase Solutions of CO2 and CO2 Soluble, Nonionic, Wettability Altering Additives
Authors: Haeri Foad , Burrows Lauren , Lemaire Peter , Alenzi Adel , Shah Parth , Tapriyal Deepak , Enick Robert , Crandall Dustin , Goodman Angela 
Published: October 2020

Abstract
This study attempts to determine if the efficacy of CO2-based enhanced oil recovery (EOR) techniques for unconventional liquid reservoirs (ULRs) can be increased through wettability alteration by adding a dilute non-ionic surfactant to CO2. The use of surfactants to increase the water-wetness of rock surfaces has previously been shown to improve oil recovery during water-based hydraulic fracturing and waterbased EOR in ULRs. In this study, nonionic surfactants are dissolved in CO2 to attain analogous significant shifts in wettability toward CO2-philic and oil-phobic. This could provide another EOR mechanism for the CO2-based recovery of oil from unconventional formations.
The solubility of a nonionic, water-soluble, surfactant (Indorama SURFONIC® TDA-9, an ethoxylated alcohol with a branched tridecyl, oil-philic tail and nine ethylene oxide groups in the hydrophilic head group) in CO2 has been measured between 25 – 100 °C. This surfactant exhibits a solubility of roughly 1 wt% at pressures of 2000 – 5000 psia, with lower pressures required for lower temperatures.
Eagle Ford outcrop samples were first aged in dead Eagle Ford crude oil at high temperature to attain oilwet characteristics. The oil wetness of shale samples was verified by measuring contact angles of water droplets in air. Then the samples were immersed in CO2 or CO2-surfactant solution for 16 h at 4000 psi and 80 °C. Contact angle measurements were then performed to identify shifts in wettability. No substantial change in wettability were observed for samples exposed to CO2, however the samples exposed to CO2-surfactant solution revealed a significant shift toward water-wet.
Two CO2 huff ‘n puff experiments were then conducted for small, oil-saturated shale cores at 80 °C and 4000 psi. Faster oil recovery (i.e. more oil recovery in the first cycle) and cumulative oil recovery of 73% (after 7 huff and puff cycles) were achieved for the core immersed in CO2-surfactant solution (0.7 wt% surfactant) compared to 78% recovery for the core immersed in pure CO2.
Continuing tests will examine the effects of rock type, oil properties, temperature, pressure, surfactant type (oil-soluble vs. water-soluble ethoxylated alcohols), surfactant concentration, and the presence of brine. CO2-soluble propoxylated alcohols will also be assessed because the polypropylene oxide oligomer is more CO2-philic than the conventional polyethylene oxide oligomer.
Learning Cycle-Based Project Management and Its Application
Authors: Zhong Allan , Dockweiler David 
Published: October 2020

Abstract
As downhole environments becomes harsher, especially for high-pressure/high-temperature (HPHT) conditions, product developments based on empirical knowledge and learning from trial-and-error testing has increasingly become inadequate, leading to long project delays, cost overruns, and information silos. A different development paradigm, which is first engineering principle based, engineering simulation aided, and materials science coupled, has emerged. Within this paradigm, knowledge-generation centric projects were initiated for specific product families. These projects have high degrees of uncertainty and are thus iterative in nature. Project management per gate-based product life cycle management, which is typically applied in the oil and gas industry, is not suitable for this type of project. A lean product development-based, event-driven project management methodology, featuring iterative learning cycles and information sharing, is tailored for execution of these projects.
Our approach for management of knowledge centric projects is based on lean product development. It consists of four main components: proactive learning cycles, cloud-based visual management, visible knowledge, and integration events. In our pilot projects, proactive learning cycles involve three interrelated knowledge domains: mechanical design, engineering mechanics, and materials science. The starting points, end goal, and number of learning cycles are determined, but not the specific goals of intermediate learning cycles, which are subject to the findings of previous learning cycles. The findings of learning cycles yield visible or reusable knowledge that can be effectively shared, including causal diagrams, limit curves, boundaries in higher-dimension design space, etc. A cloud-based visual management process is established for participating global multidiscipline teams for a virtual weekly or biweekly "standup" project meeting. Integration events define convergences between disciplines, teams, and facilitate workflow.
The impact of our project management approach is highlighted through a pilot project on sealing system design fundamentals. Cloud-based visual management enabled close collaboration between global teams and disciplines. Integration events helped to heighten urgency, prioritize issues and tasks, change course based on the previous learning cycle, and make fast technical and program decisions.
Application of Augmented Intelligence and Edge Analytics In Upstream Production Operations: An Innovative Approach for Optimizing Artificial Lift Systems Performance
Authors: Saghir Fahd , Gilabert Helenio , Mancuso Bernardo Martin 
Published: October 2020

Abstract
With the advent of robust and powerful IIoT Edge Devices, it is now possible to deploy Machine Learning models at the boundaries of a production network, i.e. using Smart Nodes directly at the wellhead that runs analytics in near real-time. These Smart Nodes, when paired with Augmented Intelligence capabilities, allow subject matter experts to interact with Machine Learning models and help improve their accuracy over time. This, in turn, helps increase confidence in data-based results and enables operators to make informed decisions.
This paper will define and discuss an end-to-end architecture on how Augmented Intelligence, in tandem with Edge Analytics, can be implemented in the upstream production environment. Results, methodologies and lessons learnt from an Edge Analytics solution deployed on Rod Pump wells will be discussed in this paper.
Effects of Constant Pressure Boundary on Multiphase Flow Behavior in Horizontal Wells
Authors: Uzunoglu Harun , Fan Yilin , Pereyra Eduardo , Sarica Cem 
Published: October 2020

Abstract
Multiphase flow behavior in a wellbore is inherently coupled with a reservoir, which is controlled by pressure boundaries. Most of the previous experimental studies in the laboratory have been performed at constant liquid and gas mass flow rates boundary conditions. This study experimentally compares the gas-liquid flow behaviors between constant pressure and constant mass flow rates boundary conditions in a toe-down horizontal well and investigates the effect of constant pressure boundary on the system stability.
The experiments were conducted in a large-scale experimental facility to study the flow behavior in a toe-down horizontal well. They were performed at two different permeabilities for a constant pressure boundary (CPB) condition. Results were compared against experiments with constant mass boundary (CMB) conditions from different aspects, including outflow performance relationship (OPR), liquid holdup, and dynamic analysis. The experimental study on system stability was analyzed for three different operating conditions, namely, constant flow rate, constant gas liquid ratio (GLR), and constant liquid permeability. Similar tests were also studied using a numerical simulator.
The results show that the time-averaged OPR and liquid holdup from constant mass and constant pressure boundary conditions match well. However, the amplitude of pressure and flow rate fluctuations are different, which causes the instabilities on the left side of the minimum of the OPR for high gas permeability reservoir at CPB conditions, where production persists for the CMB. The amplitude of pressure and gas rate fluctuation depends on reservoir permeability. It is found that the multiphase flow behavior in the wellbore for a constant mass boundary is closer to that for low permeability reservoirs, which commonly occur in shale plays. The total liquid inventory decreases as superficial gas velocity increases, and the fluctuations in superficial gas velocity have no evident impact on its behavior. Both experiments and numerical simulations show that system instability also depends on reservoir permeability. Stable production still exists on the left of the minimum OPR if the permeability is sufficiently low.
Field Trial of Methane Emission Quantification Technologies
Authors: Allen David , Stokes Shannon , Tullos Erin , Smith Brendan , Herndon Scott , Dewitt Langley , Flowers Bradley 
Published: October 2020

Abstract
Governments in the U.S, Canada, Europe and other countries have promulgated methane mitigation regulations, and many companies have undertaken voluntary programs beyond regulatory requirements. As programs expand, emerging technology developers have responded with the development of multiple monitoring, detection and quantification systems for methane emissions. Methane detection and quantification systems operate at multiple spatial and temporal scales and when these methods are compared against each other and against inventories of methane emissions, analyses must carefully match spatial and temporal scales. This field trial compares multiple methane detection and quantification methods and compares the measurements to engineering estimates of emissions. Engineering estimates of the detailed temporal patterns of methane emissions at oil and gas production sites reveals the challenges of comparing measurements of individual sources that are not exactly synchronized. Because some detection and quantification methods can interfere with one another, most inter-comparisons are based on asynchronous measurements and approaches for inter-comparing ensembles of measuements are suggested.
Evaluating Perforation Erosion and its Effect on Limited Entry by Distributed Acoustic Sensor DAS Monitoring
Authors: Pakhotina Julia , Zhu Ding , Hill A. Daniel 
Published: October 2020

Abstract
Limited entry is used in multistage fracturing to attempt to distribute fracture fluid among multiple perforation clusters evenly. As the slurry is pumped through perforations, the perforation holes can be eroded because of abrasion by the proppant, and therefore become enlarged, resulting in less effective limited entry and lower efficiency of the fracture treatment. Distributed Acoustic Sensing (DAS) is a method used for monitoring of fluid flow during hydraulic fracturing. By evaluating the changing DAS responses at perforation cluster locations during fracture pumping, DAS can be used to evaluate perforation erosion. DAS is a measurement of acoustic energy induced by fluid movement with fiber optic sensing cables. A raw acoustic signal recorded by the interrogator is transformed into an energy response (Frequency Band Energy), which is used for further interpretation of fluid volume distribution among perforated clusters on each stage of the fracturing treatment.
Based on previous laboratory experiments and computational simulations, there is a correlation between the Frequency Band Energy and fluid flow rate. As the flow rate is a function of fluid velocity and perforation area (diameter of perforation), the same flow rate could be attained with a combination of different velocities and areas, leading to a non-unique solution when interpreting DAS measurements. We transferred the correlation into the relationship between velocity and Frequency Band Energy, using the perforation area as an additional parameter. It enforces avoiding non-unique solutions in the interpretation process.
Perforation diameter is a function of erosion rate, which depends on the proppant concentration and velocity of fluid passing through the perforation. In order to connect correlation parameters with the diameter of perforations, computational simulations of fluid injection were conducted with different perforations geometries. Based on these simulations, a function that connects the area of perforation with a correlation parameter was obtained. It allows us to include the diameter of perforation in the analytical equation explicitly.
The application of the enhanced correlation in the interpretation process leads to increased accuracy of the fluid distribution calculation. For each time step, the velocity of the fluid, the mass of proppant, and the diameter of the perforations are computed, allowing the calculation of the flow rate in each perforation cluster. Perforation erosion is included in the model. Examples using field data are presented in the paper.
Distributed Sensing and Real Time Visualization of Gas Kick Dynamics in a Full-Scale Wellbore
Authors: Williams W. C. , Taylor C. E. , Almeida M. A. , Sharma J. , Waltrich P. J. , Chen Y. , Feo G. , Kunju M. , Santos O.L.A. , Ogunsanwo O. A. , Paulk D. , Kortukov D. 
Published: October 2020

Abstract
Early detection and quantification of gas kicks during drilling and completions is essential to proper well control and in the prevention of blowouts. The utilization of distributed sensing techniques, acoustic (DAS) and temperature (DTS), enables real-time elucidation of these multiphase flow events. Identifying and validating event signatures (fingerprinting) in these sensing technologies is crucial to informing operators of how to interpret these data streams. Performing full-scale analysis allows these events to be properly characterized, given the complexities in the fluid mechanics and gas dynamics.
This project utilizes a 9-5/8 inch and 5200 foot deep wellbore at the LSU PERTT Laboratory retrofit with distributed fiber optics (DAS and DTS) and 4 permanent pressure-temperature gauges to sense and visualize gas kick dynamics downhole in real time. Several experiments were performed involving the injection of nitrogen kicks through a chemical injection line and also by bullheading down 2-7/8 inch tubing in both stagnant and circulating water. Variations in flow rate, kick size, and backpressure are investigated including gas migration during shut-in. DTS and DAS data are collected downhole, along with gauge pressure and temperature at four depths along the wellbore. Data is consolidated with the rig recorded surface data to create a complete picture of the experiments.
Several observations are possible with this new methodology. First, the gas kick is immediately visible (audible) entering the wellbore by the sensors and the gas front was traceable in real time as it rose to the surface, allowing for detection of a kick, improved estimation of kick size, and easy calculation of rise velocity. Second, the distribution of gas axially in the wellbore was visible and provided insights into the duration of the event. Third, the compressibility dynamics can be visualized with the DAS thus elucidating details of bubble and slugging sizes and dynamics and when discrete gas has completely circulated out of the wellbore. The frequency ban filtering of the data further augments the fidelity of gas bubble sizes and dynamics. These initial results provide a proof of concept for using downhole sensing for real time riser gas dynamic detection and characterization.
Production Optimisation Using a 24/7 Distributed Fibre Optic DFO Sensing Based Multiphase Inflow Profiling Capability
Authors: Sadigov Teymur , Ramsay James , Cerrahoglu Cagri , Salt Michael , Thiruvenkatanathan Pradyumna 
Published: October 2020

Abstract
This paper shares the results from the first successful deployment of a real-time, multiphase inflow profiling technology applied to BP operated Clair Ridge asset. Uncertainty around distribution and the dynamic behaviour of the fractured reservoir required the deployment of Distributed Fibre Optic Sensing (DFOS) capabilities as part of the well completions across a selection of the well stock, to enable in-depth real-time flow surveillance and maximize recovery from the field. Unlike conventional wireline conveyed sensors and logs that provide static measurements of flow conditions, the DFO data will be used to provide a more comprehensive, dynamic inflow distribution across multizone completion uniquely including flow in the annular space behind blank sections.
This paper summarizes key findings from the first deployment of a new real-time technology solution that employs novel signal processing techniques using the DFO data as key sensor inputs to detect relative inflow rates of different fluid types along the wellbore during production. The solution presents inflow logs for each fluid phase in near real-time through proprietary streaming analytics capabilities embedded in a cloud-based software solution. This facilitates 24×7, real-time flow surveillance across wells equipped with fibre in the field. This paper also presents early results from the use of the technology on the first platform drilled production well and discusses how these real-time insights have been effectively applied to provide significant business value, including but not limited to new well start-up optimization, well management and zonal fluid inflow allocation. The paper also detail the use of the technology for water inflow detection and quantification and discusses the implementation of drawdown optimization strategies based on the insight to control water inflow that have already resulted in significant production benefits.
Development of a Realtime Gas Monitoring System Architecture for Manned and Unmanned Oil and Gas Processing Facilities
Authors: Idachaba Francis 
Published: October 2020

Abstract
This paper presents the development of a real-time gas monitoring system with alerts transmitted to the office domain, and the team leads whenever the gases are detected. The system monitors the presence of the hazardous H2S gas. It sends signals to the control room in the manned plants so that operators can take the necessary precautions when stepping into these locations. It also sends alerts to the office domains when the permit to work is being prepared for any facility. It provides a continuous real-time update of the gas present in the location to a cloud-based platform. This is beneficial as it will enable plant operators to take the necessary precautions to both protect themselves and also protect the facilities if the gas discharge spreads across the plant's zone classifications
Tracer Evaluations for Seawater Fraction Monitoring During Offshore Seawater Flooding
Authors: Wang Yanqing , Li Xiang , Lu Jun 
Published: October 2020

Abstract
Seawater breakthrough percentage monitoring is critical for offshore oil reservoirs as seawater fraction is an important parameter for estimating the severity of many flow assurance issues that caused by seawater injection and further developing effective strategies to mitigate the impact of those issues on production. The validation of using natural ions as tracer to calculate seawater fraction was investigated systematically by studying the natural chemical composition evolution in porous media using coreflood test.Results indicate that chloride, bromide and sodium can be regarded as conservative tracers to calculate seawater fraction as long as there is considerable concentration difference between seawater and formation water.Behavior of calcium shows acceptable error in seawater fraction calculation especially at high temperature and low clay content reservoirs. Application of barium and sulfate reaction model in coreflood test works not as well as in bottle test because of not taking account of fluid flow in porous media.Magnesium,potassium, and boron have significant interactions with core matrix, and thus cannot be used as tracers directly to calculate seawater fraction. Behavior of all ions gives a guideline on selecting suitable ions as tracer. Besides, ions evolution is helpful in understanding the mechanisms of low salinity waterflooding.
Experimental Performance of Steam-Based Hybrid Technologies to Improve Energy Efficiency in a Colombian Heavy Oil Reservoir
Authors: Perez Romel , Garcia Hugo , Manrique Eduardo , Rodriguez Hector , Mehta Sudarshan , Moore Robert Gordon , Ursenbach Matthew , Sequera-Dalton Belenitza , Gutierrez Dubert 
Published: October 2020

Abstract
Due to the large amount of heavy oil reserves, thermal recovery projects have been developed in Colombia in the last decade. Several fields under Cyclic Steam Stimulation (CSS), and Steam Flooding (SF) plans are currently underway at field scale. In the country there are also significant reserves of heavy oil which are still under cold production which represent an important opportunity to implement novel technologies that improve energy efficiency. Such technologies should be implemented based on the maturity of the current recovery process and reservoir characteristics. Implementation of steam-based hybrid technologies are under evaluation in Ecopetrol as a strategy to increase both heavy oil recovery and energy efficiency.
This work is focused on the design, execution, and results of two physical simulation experiments developed to study the behavior of the Teca Cocorná core and fluids with a combination of steam-based hybrid injection technology. Both tests were performed under similar conditions of temperature and pressure to assess the effect of a hybrid injection process on the residual oil saturation, produced hydrogen sulfide (H2S) and changes in produced fluids. The experimental methodology is described in detail for both experiments as well as relevant test results which constitute important parameters for reservoir simulation forecasts.
The first hybrid test was a combination of steam flood and solvent injection (naphtha) which consisted of the injection of 0.38 pore volumes (PV) of cold water equivalent (CWE) superheated steam at 271°C, followed by the injection of 0.05 PV of naphtha solvent (CWE), and finally by the injection of 1.0 PV of superheated steam (CWE). The second hybrid test combined steam flood with injection of flue gas consisting of 15 percent carbon dioxide (CO2) and 85 percent nitrogen (N2). The injection scheme for this test was similar to the first test and consisted of the injection of 0.40 PV of superheated steam at a temperature of 271°C (CWE), followed by 0.30 PV of flue gas (CWE) and finally by 0.71 PV of superheated steam (CWE).
This study shows that the Teca Cocorná oil-core system, as tested, responded positively in the laboratory to hybrid steam methods in terms of production and energy efficiency. A detailed comparison including temperature front, steam-oil-ratio, produced fluids and residual saturations is presented. In addition, the energy consumption is estimated. These results provide valuable information required for numerical and economic evaluations of steam-based processes prior to field tests.