bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coupled Enhanced Natural Gas Recovery and Blue Hydrogen (EGRBH) Generation
Authors: Hatzignatiou Dimitrios Georgios , Ehlig-Economides Christine 
Published: September 2022

Abstract
Natural gas can be used to generate either blue or grey hydrogen depending on whether or not the carbon dioxide byproduct is captured and stored. When captured, the carbon dioxide (CO2) produced from a steam methane reforming (SMR) or partial oxidation (POX) process can be injected into the same natural gas reservoir for enhanced gas recovery (EGR) while simultaneously storing CO2. The objective of this work is the effective integration of these three major processes – blue hydrogen generation, carbon dioxide capture and storage, and enhanced natural gas production.
Surface processes include separation of methane from CO2 and other inorganic and organic components in the produced natural gas. Produced CO2 will be injected back into the reservoir, and other components would be managed in ways standard to produced natural gas processing. An SMR or POX process followed by a shift reaction one will generate hydrogen and CO2 followed by separation of the hydrogen and CO2. To avoid a need for post combustion capture, continuous operation can use produced hydrogen to energize the SMR process. Integration of natural gas reservoir production, blue hydrogen generation, and CO2 injection back into the same reservoir leads to a process termed enhanced gas recovery and blue hydrogen (EGRBH). To optimize the reservoir management, analytical and numerical simulation models that address physical mechanisms such as CO2 diffusion, advection, and CO2 solubility in connate water provide guidelines on placement of injection and production wells, on their geometry (vertical or horizontal) and completion interval locations, and on well operating conditions.
Displacing methane with CO2 is a miscible process with favorable mobility ratio, and simulations show that the methane recovery factor at CO2 breakthrough depends on both molecular diffusion and dispersivity related to reservoir heterogeneity. Continued production at constant methane rate enables additional blue hydrogen generation while increasing CO2 flow through the reservoir under declining average reservoir pressure. Injection of additional CO2 captured from other stationary point sources can achieve enhanced CO2 storage (ECS) up to a limit pressure less than the original reservoir pressure.
The EGRBH process produces blue hydrogen at a price competitive with gasoline or diesel for transportation applications. When used for power generation, blue hydrogen decarbonizes natural gas fired generation at lower cost than can be achieved with post combustion capture from standard natural gas power plants. Blue hydrogen is also less than half the cost of so-called green hydrogen produced via electrolysis using electricity generated with renewable energy. This appears to be an ideal approach for developing and producing new natural gas discoveries.
Fit-For-Purpose Fracturing Technique Enables Breakthrough in Marginal Gas Field Development of Ordos Basin, China
Authors: Ma Zhanguo , Bi Man , Chen Junjie , Shi Mingxing , Li Haoyan , Fu Yunlong , Zhang Jie , Luo Yin , Liu Yuan 
Published: September 2022

Abstract
Some areas in Ordos basin, such as Sudong block, suffer from poor economic returns caused by low production. The development of this reservoir has multiple geologic and engineering restrictions. In addition to the complex lithology and abundant clay content that reduce formation effective gas porosity and permeability, the low net-to-gross (NTG) ratio requires a larger quantity of proppant to adequately support a fracture that covers the entire thickness of the sand interval.
Because of these issues, the reservoir potential is not capable of supporting costly conventional fracturing techniques. Finding a fit-for-purpose stimulation solution that balances the cost effectiveness and production enhancement has been a challenge for years.
Channel fracturing has been introduced to achieve better fracture performance with less cost. A pilot project of one deviated well and one horizontal well was done in 2019. The goal of this step was to verify the subsurface suitability and engineering feasibility.
Despite the smooth operation and record-breaking post-fracturing test results, multifaceted study continued. The laboratory study of proppant and formation rock established a solid foundation for fluid formulation and proppant concentration design. The design optimization with a multiphysics simulator minimized the fluid volume while ensuring conductivity and lateral coverage. Finally, the equipment layout and rate distribution among pumps was planned so that the slurry pulses formed at the blender would be delivered to downhole with integrity.
These success of these efforts is proven by the outstanding post-fracturing results of two vertical wells and one horizontal well in 2021. Despite the discrepancy in reservoir quality, all the wells had faster cleanup period, less gas kickoff, and 80% increase in horizontal well absolute open flow (AOF) compared with 2019.
As is demonstrated by field observation and production results, channel fracturing creates highly conductive channels in the fracture with less material consumption and less cost, sustainably. Compared to the conventional fracturing solution, channel fracturing technology enables balancing of budget saving and production increase. The success of implementation has led the way to a more economic cost model to develop the marginal fields in Ordos basin.
Petroleum Engineers Need a Strong Professional Society
Authors: Michael Andreas 
Published: September 2022

Abstract
The thrust of this paper is to objectively challenge the recently-emergent talking point for a "Society of Professionals in Energy," which manifests a mentality which heralds trouble for the future of the petroleum engineering (PE) discipline and profession. Such approach dilutes any domain expertise and competitive advantage that PE graduates should have over non-PE graduates, with the next step inadvertently being the gradual phasing of PE into something along the lines of "energy engineering," all this while oil and gas (O&G) production keeps growing year-after-year.
Petroleum reservoirs are the result of subsurface processes that took place through an extensive geological history. Conceptualizing how petroleum reservoirs are configured underground, at great depths and sometimes also below thousands-of-feet of water, is an extremely challenging task. This unique-to-PE visional barrier is an inherent challenge to every subsurface O&G project, making technical expertise (not essentially experience) invaluable, as it requires more than basic critical thinking to understand what goes on in the opaque underground.
One may disregard the 2021-22 merger fiasco between SPE and the American Association of Petroleum Geologists (AAPG) as an aberration. It certainly can serve as a teaching moment for its architects. There are many within and outside PE who would question even the need for the existence of PE academic programs. The reason students enroll in PE programs is supposed to be for developing expertise in solving upstream O&G problems. Rebranding or generalizing to "energy engineering" will make more harm than good, diluting any competitive advantage for PE graduates within what should be their domain of expertise.
Application of Novel Advanced Numerical Modeling of Nanoparticles for Improved Oil Recovery: Laboratory- To Field-Scale
Authors: Hendraningrat Luky , Majidaie Saeed , Kechut Nor Idah , Tewari Raj Deo , Sedaralit M Faizal , Skoreyko Fraser , MousaviMirkalaei Seyed Mousa , Edmondson Mark , Chandrasekar Vikram 
Published: September 2022

Abstract
The deployment at the field-scale of a novel technique to improve oil recovery using nanoparticles injection is challenging. It requires a comprehensive evaluation of a series of laboratory experiments, to translate and validate the mechanisms into a numerical model to predict accurately and reduce uncertainty parameters. This paper describes the application of novel advanced reservoir modeling for nanoparticles from pore-scale to field-scale, using an offshore Malaysian oilfield as a pilot field case.
A series of laboratory experiments (fluid-fluid and fluid-rock) and numerical studies: nanofluid formulation, pore-scale studies, validation, and upscaling process into the field-scale model were carried out. The development of nanofluids was formulated to meet key criteria such as compatibility and thermal stability at the intended field condition. Prior to coreflooding tests with native core, a series of experiments to observe mechanisms were carried out. The results of the laboratory experiments were then validated in the 1D coreflooding model. The procedure was continued with observed critical parameters being scaled-up into 3D field-scale model before running the prediction scenarios.
The newly developed nanofluids for the intended field performed well in compatibility and thermal stability tests at reservoir temperature. Precipitation and sedimentation were not observed in this solution. The wettability alteration to more water-wet was observed with consistent results through interfacial tension measurements, contact angle measurements, and relative permeability measurements. Coreflooding was performed using native core, and the reduction of residual oil saturation was approximately 25% between pre- and post-nanoflooding. The adsorption of nanofluids was measured to be around 1.12 mg/g of rock. All these results were input into the model and the history match quality index achieved an acceptable match of ~95%. Several critical parameters for the upscaling process were investigated such as reaction rate of particle aggregation, adsorption, and retention factor. During the scale-up process, the velocity of the fluids and pressure drop were conserved because the recovery is sensitive to flooding rate and the viscosity of the fluids are pressure dependent. The field-scale model was run for the intended field location. The potential of using nanoparticles was evaluated and compared to the no further activity scenario giving an additional recovery factor of approximately 1% per year.
The developed method of novel robust advanced reservoir modeling for nanoparticles creates a new reference as the first application in the world of novel advanced numerical modeling at field-scale.
Building a Bulletproof System for Automatic MWD Survey Processing
Authors: Ploskikh Viktor , Bulychenkov Konstantin 
Published: September 2022

Abstract
This paper introduces an approach for automatic measurement while drilling (MWD) survey processing that can work fully autonomously and covers the entire workflow: geomagnetic reference calculation, survey data prefiltration, corrections for drillstring interference (DSI), bottom hole assembly (BHA) sag, Stockhausen effect (Stockhausen and Lesso 2003), system health monitoring, survey quality control (QC), and toolcode proposal.
The main focus of this study is to formulate principles to realize high reliability of the system, and the reliability of all subalgorithms must be close to 100% to reach the system autonomy requirement. This article highlights four major cornerstones for building such a system:
Initialization data validation Static and continuous survey filtration Robustness of the key algorithms QC of output data and system operation.
The cornerstones are implemented as follows:
Formalization of data schemes and algorithms for internal validation and cross-validation Development of highly robust survey filtration algorithms that are resistant to noise: prefiltration multistation analysis (MSA) algorithm, dogleg severity (DLS) capacity filter, and continuous inclination DLS filter Improvement of accuracy and robustness for MSA, BHA sag, and Stockhausen effect corrections: the calculation of the geomagnetic reference along the trajectory, novel MSA with a priori and steering control information utilization, input smoothing for BHA sag correction, and continuous static survey fusion steady against continuous inclination errors New dynamic acceptance criteria for the total G, total B, and dip angle based on an MWD error model; novel steering acceptance criteria for inclination and azimuth; internal control system for MSA correction, BHA sag correction, and high-definition trajectory calculation; general external control for output trajectory vs. plan; and toolcode assignment based on full covariance analysis
Consequently, the automatic system demonstrates complete stability to the noisy data streams of static surveys, continuous inclinations, rotor/slide intervals, capability to work without the no-go zone restriction, correct work within high direction and inclination (D&I) and DSI error ranges, the effective detection of geomagnetic reference issues and system malfunctions, and realistic toolcode assignment. The system significantly reduces human engagement in real-time survey QC and correction. An expert is only involved in case of an issue (D&I module failure, strong external magnetic interference, etc.).
First Evidence for Shale Production Decline Due to Formation Damage Caused by C60+ Paraffin Wax Deposition: A Permian Case Study
Authors: Mahmoudkhani Amir , Rogers Jonathan , Shumway Martin , Au Yong Hin Cheong 
Published: September 2022

Abstract
Analysis of the production decline curve revealed that the three candidate wells in West Texas depleted faster than a type decline curve, potentially indicating an abnormal permeability reduction mechanism. With the scaling tendency determined to be low to mild for carbonate scale in the formation brine, the use of acids for restimulation was ruled out. However, careful hydrocarbon analysis revealed the presence of a significant amount of heavy paraffin molecules with carbon number higher than C60 that comprise linear, branched and cyclic alkanes. Becasue lighter hydrocarbons permeate faster through the porous media than heavier fractions, dynamic and preferential adsorption-desorption of crude oil components on mineral surfaces account for changes occurring in hydrocarbon compositions during the life of a producing shale oil well. Furthermore, precipitation of heavy organics on the formation matrix could have contributed to the observed permeability reduction and production declines by causing flow restriction in pores and channels and changing wettability of rock surface. With the recent development and utilization of glycolipids, a biosurfactant-based squeeze program was tailored and applied on the three horizontal wells. Forecasted post-treatment production for a 16-month period following treatment was estimated to be 36,500 barrels of oil and 1.391 billion cubic feet of gas. After treatment, over the same period, the facility produced approximately 10,800 barrels of oil and 111,000 thousand cubic feet of gas above the forecasted production volumes, which is a 30% increase in oil volumes and 8% increase in gas volumes. Produced fluids have been collected over the period of 18 months after treatment application to monitor movement of heavy hydrocarbons and residual biosurfactants in both oil and water samples. The impact on improved oil recovery has been very significant with return on investment (ROI) occurring in less than three months.
Autonomous ICD Introduction in Singue Field Ecuador: Completion Methodology and Production Evaluation
Authors: Chacon Alejandro , Corona Georgina , Pico Juan , Bastidas Christopher , Diaz Marlon , Gualsaqui Felipe , Saraguro Alex , Velasquez Fernando 
Published: September 2022

Abstract
Inflow Control Device (ICD) technology delays the production of unwanted fluids while addressing some of the challenges associated with long horizontal and deviated wells. Autonomous ICD (AICD) technology functions like ICDs during dry oil production by balancing the flow. AICDs proactively delay the onset of unwanted fluids (water and gas) and additionally, reactively, restrict the flow of water and gas upon breakthrough. This paper presents AICD installations in multiple horizontal wells of the Singue oil field development in Ecuador.
The fluidic diode AICDs are fluid dependent and will react to the viscosity of the downhole fluid creating an additional pressure differential to restrict the production of unwanted fluids. The paper presents the introduction of this technology into the first horizontal wells of the Singue field. The wells are in a sandstone reservoir with an underlying aquifer and demonstrate increasing water cut over time. The completion designs and optimization of these wells were based on the production objectives and calibrated with field production data. Best practices of simulation modelling for both design phase and post-match results are presented.
Production data of WC% reduction and Oil production continuity over time demonstrate the value of the AICD completions. Post-match simulation modelling is used for the analysis of the technology at different conditions over the production life of the wells. Historical production data is used to build numerical models for comparison and evaluation purposes. It is observed from these results and analysis, that installing AICDs on the horizontal wells delays the increase rate of water cut curve which results in higher recovery over time and longer wells longevity.
Operational considerations including ESP pump parameters for completion design and future well management are discussed. Well clean-up and fluid conditioning recommendations are included as part of the best practices and lessons learned.
The AICD technology, design methodology and production performance evaluation for the AICD completions were applied for the first time in this new field development. The analysis covers the complete cycle from reservoir modelling, completion design, post-drilling match, calibration and production performance analysis over time for evaluation of the technology.
Kaolinite Effects on Injectivity Impairment: Field Evidence & Laboratory Results
Authors: Renna Simona , Sabatino Luigina Maria Flora , Viareggio Alberto , Rossi Lucia , Colombo Marco , Parisi Salvatore 
Published: September 2022

Abstract
Clay interaction with fluids is a well-known phenomenon that depends on formation mineralogy. This paper focuses on the impact of kaolinite clay dispersion on well injectivity impairment. It is based on field evidence from 50+ injectors and it is supported by a huge set of laboratory tests.
All analysed wells showed an initial injectivity lower than the theoretical potential, estimated on the base of reservoir quality and draw-down mobilities. This impairment occurs before connecting wells to the injection network, therefore injected water quality and network conditions do not take part in the damaging. Consequently, the impairment mechanism seems to be correlated to the interaction between formation and drilling fluids.
A set of laboratory experiments was planned on cuttings collected in two recently drilled wells. Different intervals were selected in the reservoir sandstones, representative of the facies where injected water is most likely to flow. Samples were first mineralogically characterized by different laboratory techniques (FT-IR, XRD and CEC). Then, swelling and recovery tests were performed using different fluids: mud (field formulation), mud filtrate, and water (varying pH and salinity). Results were correlated with petrophysical analysis, mercury injection tests on cores, and major injectivity impairments observed on the analysed wells.
Analysed samples showed the presence of kaolinite that may affect the formation permeability by filling porosity and pore throats (diagenetic effect). Moreover, in case of interaction with fluids, kaolinite can lead to an additional permeability reduction by disaggregation and dispersion phenomena.
Laboratory tests showed a clear trend: the higher the kaolinite content in the selected intervals, the higher the observed disaggregation, especially when samples interact with mud filtrate and water. It was observed that mud formulation is effective, allowing to preserve disaggregation, but only below a threshold of kaolinite content.
Field experience proved that the only effective remedial actions to restore the well injectivity potential are frac jobs, allowing to bypass the near wellbore damaged zone.
Remote Field Eddy Current System Using Three Axis Fluxgate Magnetometer for Corrosion Inspection
Authors: Khater Moutazbellah , Mostafa Tarek , Ooi Guang , Ozakin Mehmet , Larbi Zeghlache Mohamed , Bagci Hakan , Ahmed Shehab 
Published: September 2022

Abstract
Conventional remote field eddy current tools, which are developed for electromagnetic detection of corrosion on metallic pipes, use transmitter and receiver coils that are spaced apart by at least twice the inspected pipe's diameter. This large space and the low operation frequency required for electromagnetic fields to penetrate multiple casings weaken the voltage induced at the receiver. This challenge limits the quality of corrosion detection and characterization. In this work, a three-axis fluxgate magnetometer is used as a receiver to increase the sensitivity and to enable extraction of directional location of defect from measurements taken off axis. The improved sensitivity and the azimuthal detection capability for localized defects are confirmed by simulations and demonstrated experimentally in a single (4-1/2 in.) pipe and double pipes (4-1/2 in. inside a 7 in.) test setups. The limitations of current electromagnetic technologies in characterizing local defects beyond tubing are highlighted and the benefits of the proposed system are discussed.
Improving Machine Learning Predictions of Rock Electric Properties Using 3D Geometric Features
Authors: Chang Bernard , Santos Javier , Victor Rodolfo , Viswanathan Hari , Prodanovic Maša 
Published: September 2022

Abstract
Imaging technology is constantly improving and enabling accurate, deterministic simulations of transport properties through the pore space of the imaged rock sample. Meanwhile, data-driven machine learning has emerged as an alternate tool for modeling transport properties that, once trained, use a fraction of the computational resources that traditional simulations require. However, machine learning models often fail to strictly enforce the physical constraints of the system, leading to solutions that are less accurate than that of traditional solvers.
Here we propose a novel hybrid workflow that combines machine learning and conventional simulation methods. The workflow begins with a three-dimensional, binary image of a sample. A trained convolutional neural network extracts spatial relationships between the porous medium geometry and the electrostatic potential field and predicts the electrical properties through a new medium. Instead of assuming a linear potential gradient, this prediction is used as the initial condition of a validated finite difference solver. The implementation of this workflow can improve the simulation run time by an order of magnitude for small images.
The success of the proposed workflow heavily depends on the accuracy of model prediction. We previously developed successful methods for prediction of the velocity field (and permeability) of a Newtonian fluid in a porous medium in the laminar regime. Here, we extend the method to predict the electrical potential field. We explore one strategy of improving a model's ability to generalize to unseen samples by supplying geometric characterizations of the pore space. We find that models trained with these features individually do not result in an improvement over the baseline model trained with only the binary image. However, they do provide the model with relational information that can be incorporated into future models.
Analysis of electrical properties is one of the most common methods of delineating hydrocarbon saturation in reservoir rock. The proposed workflow helps accelerate the calculation of the electric potential field and can lead to estimating hydrocarbon saturation in real time. We also expect that this workflow is easily generalized to many other transport problems in porous media.