bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Challenges for Predicting Annulus Pressure Variation During Transient Operations in the Pre-Salt Wells
Authors: Duarte Ferreira Marcus Vinicius 
Published: October 2020

Abstract
The current scenario of many Pre-salt wells considers high rate stimulation process after a long-term shut-in due to temporary abandonment. Thus, the wellbore is at geothermal temperature in the beginning of an acidizing operation. In an ultra-deepwater environment, like the Pre-salt cluster, the temperature reaching the wellhead during acidification is near 4 °C. Numerical simulations have shown that the wellbore cooling down during short transient injection operation can lead to well integrity failure collapsing the intermediate casing.
The approach commonly employed in the industry considers just steady state injection operations which are not enough to describe what is happening in the field and are also not sufficient to support a suitable casing design. The industry must put efforts to develop and consolidate a methodology based on transient thermal analysis to deal with thermal shock events in the well, as proposed in this paper.
This paper aims to show the main findings of Petrobras wellbore design team to deal with reverse APB during well cooling down operation. In order to mitigate the decrease in pressure, unusual fluids were assessed as packer fluids. In addition, a comprehensive analysis was developed and proposed to deal with transient thermal phenomena in commercial wellbore thermal-structural simulators once some of the important identified loads are currently neglected by O&G industry standards.
Results have shown that several alternative packer fluids might reduce or prevent casing failure due to fluid thermal isolation and/or shrinkage. Several case studies that led to loads under the collapse safety factor before, are now meeting appropriate values. Also, it was demonstrated the key parameters that affect wellbore transient analysis. Overall, predicting reverse APB, especially during short transient wellbore cooling down must be faced carefully.
Case Studies of Emulsion System with Nanoparticles Application for Stimulation of Stagnant Zones in Carbonate Reservoir
Authors: Sergeev Vitaly , Tanimoto Kenji , Abe Masashi 
Published: October 2020

Abstract
A paper presents results of an industrial application of an innovative technology for oil and gas producing wells stimulation. Also, research results of a laboratory study of ESN (emulsion system with supercharged nanoparticles) physical and chemical properties under atmospheric and modeled reservoir conditions are briefly described in this paper. The technology is based on the use of an innovative emulsion system with supercharged nanoparticles (ESN) as a solution to solve two tasks at once: 1. to divert an active composition injected after; 2. to block water bearing most-permeable zones within a profile of productive interval for more than 12 months. The case studies considered in this paper focused on the technology application in two mature carbonate formations of Ural-Volga oil-gas province located in Russia. The formations have been under industrial development for almost 50 years and characterized by complicated geology and deteriorated reserves. A combination of effects of diverter and water-blocking agent, in one composition, provides significant competitive advantages, which resulted in two times increase in oil rates with a decrease in water cut of treated by the technology oil-gas producing wells. A duration of positive effect reached 14 months on average for ten treated wells, which is four times higher than a classical acidizing technology applied on the same formations. The main competitive advantages of the technology are enlarged surface charge (alteration of wettability of rock), high thermal stability (150 °C), predictable rheology (Herschel-Balkly model), reversible blocking effect and absence of negative impact on geological formation, downhole equipment and oil and gas collecting system (environmental friendly).
Alternative Method to Supply Pneumatic Air to an Unmanned Platform, In the Event of the Platform’s Instrument Gas System is on Downtime
Authors: Krishna Moorthy Utheswaran , Anding Denys , Ng Chieh Lung , Songli Sobri , Sahak Sahlan , Baharudin Mohd Hafiz 
Published: October 2020

Abstract
D-C is an unmanned, pneumatic operated wellhead platform located offshore Sarawak, Malaysia. D-C consists of oil producer and water injector wells, instrument gas system and four pipelines connected to a manned mother platform D-A which is around 2 nautical miles away. The four pipelines are dedicated for gas lift, High Pressure (HP) production, Low Pressure (LP) production and water injection respectively. Pneumatic supply medium for D-C is natural gas, tapped from the gas lift pipeline, which is supplied from the gas lift compressor at D-A. D-C does not have power generation system hence solely depends on instrument gas to energize the instrumentation. In 2019, the instrument gas scrubber on the platform experienced severe corrosion and was sent back to shore for repair, resulting in the natural gas was unable to be channeled to the platform’s instrumentation. This caused the platform to be on unplanned shut down. As D-C is an unmanned facility, a portable air compressor cannot be used for continuous pneumatic supply, as mechanic and fire watcher will be required to be onboard day and night. Hence, an alternative method of supplying pneumatic air for D-C was executed which enabled the platform to be back online without instrument gas scrubber, and in compliance to its unmanned philosophy. Compressed dry air was exported from D-A to D-C via the HP pipeline, and the air from the pipeline was supplied to the pneumatic instrumentation system of D-C. To achieve this, the HP pipeline was de-oiled and continuously pressurized by compressed air which was supplied by portable instrument air compressor at D-A. The compressed air in the HP pipeline was used to supply pneumatic air to the instrumentations at D-C. D-C was successfully operated continuously albeit with minor production deferment (some wells were closed in to minimize back pressure at the LP pipeline due to HP pipeline is unavailable for the wells), throughout the duration of instrument gas scrubber unavailability onsite (around one month). Threat of prolonged total production interruption from D-C was successfully eliminated and production from the platform was partially recovered.
Development of a Rapid Method for Measuring Preservative Biocide Performance in Hydraulic Fracturing
Authors: Solomon Ethan , Massie-Schuh Ella , Moore Makensie , Moran Ryan , Paschoalino Matheus , Moore Joseph , Wunch Kenneth 
Published: October 2020

Abstract
Drilling and completion operations introduce microbial contaminants into the reservoir via numerous pathways including drilling muds and hydraulic fracturing fluids. Uncontrolled microbial growth in the reservoir can lead to reduced flow and production rate of hydrocarbons due to accumulation of biofilm and plugging. Microbial contaminants can also lead to microbially influenced corrosion (MIC) of topside and downhole production equipment, causing undesirable impacts to capital spending and operational efficiency. As a mitigation strategy, biocides are often added to hydraulic fracturing fluids to control microorganisms which cause these operational issues. Oilfield service laboratories often receive water samples from the field to provide recommendations on the most optimum biocide use and concentration. The standard industry method (NACE TM-0194) used for measuring biocide performance is based on a time-kill test in which water collected from the field is spiked with bacteria. Biocides are added at desired concentrations and samples are withdrawn to determine log reductions. Bacterial levels are often determined by ATP so results can be collected within minutes.
A wide number of biocides are available for oil and gas operations. They differ primarily by mechanism of action, speed of kill, and interaction with other components of fracturing fluids. As the NACE method relies on rapid activity, misleading test results are often observed with preservative biocides which are intended for slow-release / long-term activity. Preservatives are utilized for extended protection of the well and reservoir after drilling and/or completion operations, not for the rapid reduction of microbes in a water sample. Therefore, as current methods are intended for rapid-kill biocides, novel methods are required to demonstrate the efficacy of preservatives.
Methods were designed primarily to demonstrate efficacy of preservative treatment for waters used in hydraulic fracturing. Using culture-based methods, biocides were added to water samples that were incubated at elevated temperatures and challenged periodically. Glutaraldehyde was an effective preservative at 55 °C, providing antimicrobial efficacy for &gt;7 days. 4,4-dimethyloxazolidine (DMO) was effective for 4 weeks or more, with improved efficacy at elevated temperature.
The methods described in this work can differentiate rapid-kill from preservative biocides, be performed at a service company laboratory, and provide results within an "actionable" period (approximately 7-10 days) of time.
New Scale Prediction Approach Through Numerical Simulations
Authors: Duarte Ferreira Marcus Vinicius , Leibsohn Martins André , Simões Maciel Rodrigo , Fieni Fejoli Rômulo , Ressel Pereira Fabio de , Poletto Vinicius Gustavo , De Lai Fernando Cesar , De Mello Junqueira Silvio Luiz 
Published: October 2020

Abstract
One of the most concerns regarding the development of the Brazilian pre-salt cluster is due to scale issues. The huge carbonate reservoirs have a high potential for salt depositions while the produced fluid flow along the well. Furthermore, emerging wellbore configurations aiming the well construction cost reduction and improving reliability, also brings some drawbacks, such as the inability for downhole chemical injection in the open-hole full-eletric intelligent completion schemes, for instance.
Scale prediction is worldwide traditionally performed using the formation water thermodynamical evaluation under static conditions through commercial softwares, leading to conservative results that may not distinguish the scaling risk of two different wellbore configurations. The approach neglects th geometry of completion accessories and the fluid dynamics, both substantial factors that influence precipitated-crystals process such as agglomeration and adhesion to the surface. This paper aims to show two different methodologies under development, in two different universities in Brazil, for enhancing scale prediction studies. Both uses Computational Fluid Dynamics (CFD) techniques to describe the fluid flow through a completion accessory applying an Euler-Lagrange approach is applied. The first approach coupled the CFD study to the Discrete Phase Method (DPM). The second approach coupled the CFD to the Discrete Element Method (DEM). Results are explored by applying these two methodologies.
Implementing Human & Organizational Performance Concepts In Major Capital Projects
Authors: Joey Hill , Timothy Vidra , Karel Schnebele 
Published: October 2020

Abstract
Human and Organizational Performance (HOP) is about the way people, culture, equipment, work systems, and processes interact as a system. By improving the interaction between individuals and the critical systems they work with, we can reduce the seriousness and frequency of failures. HOP is a different lens through which we look at how work gets done. The goal of HOP is to make it easier to get it right and harder to get it wrong.
Guided by seven HOP principles, we formulated a strategy and plan to integrate HOP concepts into our Gulf of Mexico Major Capital Projects (MCPs). The focus is to continually identify how HOP concepts can be leveraged and incorporated into existing work processes and procedures. This paper will outline general HOP concepts and our efforts to operationalize them to enable improve Health, Safety and Environmental outcomes.
A Step Change in Real-Time Near-Bit Measurements from an Instrumented Downhole Drilling Motor Improves Directional Drilling Accuracy and Geo Steering Capability
Authors: Jones Steve , Sugiura Junichi 
Published: October 2020

Abstract
Downhole drilling motors are the workhorse of our industry and are used on almost every well drilled globally. This makes an instrumented drilling motor the perfect tool for geosteering with near-bit inclination and formation-change-detection sensors. There have been a number of drilling motors and near-bit subs designed to provide near-bit inclination and gamma/azimuthal gamma measurements over the years. These designs provide the measurements but typically compromise drilling motor mechanical strength or directional response. This paper explains a new type of instrumented drilling motor with real-time continuous inclination and drilling dynamics.
The instrumented wired motors described in this paper have taken a completely different design approach. Using already-existing drilling-motor technology, the necessary sensors, electronics, wiring and short-hop technology have been transplanted into the centerline of the drilling motor without compromising mechanical strength. In addition, the design allows for fast turn-around service times in an existing drilling-motor workshop.
Directional drillers rely on measurement-while-drilling (MWD) real-time data to maintain the well-path on trajectory or within zone. MWD measurements are taken behind the drilling motor and are typically more than 50 feet behind the bit. Real-time near-bit inclination measurements allow for more accurate and precise directional drilling. The new instrumented drilling motor delivers real-time near-bit inclination just 5 feet behind the bit. In addition, near-bit vibration measurements can be used to identify formation changes. The new instrumented drilling motor can be used for geosteering using vibration measurements.
The instrumented wired motor has undergone extensive testing in West Texas to ensure the main components are reliable and can survive harsh drilling conditions. Testing was performed in three main phases; 1) through-wire communication, 2) dynamic inclination and vibration measurements; and 3) short-hop to MWD.
When all three phases of testing were complete the entire instrumented wired motor was deployed to deliver near-bit real-time inclination and drilling dynamics measurements to improve directional drilling. The near-bit inclination measurements allow the directional driller to respond to unpredictable directional changes such as formation push and formation tracking. This provides increased accuracy to keep the wellpath in the zone of interest, particularly in lateral wellbores. This paper will detail the innovative drilling motor design and results obtained during product validation.
Development And Application Of Emulsion-based Conformance Control Method For Enhanced Bitumen Recovery By Steam-assisted Gravity Drainage
Authors: Ding Boxin , Shi Longyang , Dong Mingzhe 
Published: October 2020

Abstract
Bottom water, which is defined as a zone below the base of bitumen pay with high water saturation, has been encountered in many currently operated steam-assisted gravity drainage (SAGD) projects. It has been widely accepted that the bottom water lying under bitumen in SAGD act as a heat sink which is a result of the much higher mobility of water compared to that of the bitumen. This has a detrimental effect on the project economy because of the resulted greater steam-oil ratio (SOR) and less oil recovery. Therefore, it is essential to reduce the mobility of bottom water in SAGD operations to avoid the water coning and steam loss to the bottom water. In this study, emulsion-based conformance control treatment is introduced and investigated in oil sands reservoirs to reduce the mobility of bottom water to avoid the water coning and steam loss to the bottom water during the SAGD operations. To accurately simulate the emulsion plugging performance during the SAGD process, it is essential to optimize the emulsion flow model in water saturated porous media to better describe the flow mechanism. There are three main mathematical models applied to describe the dynamics of emulsion flow in porous media: the bulk viscosity model, the retardation model and the filtration model.
In this paper, the newly proposed emulsion flow model was optimized on the basis of the conventional filtration model with considering the process of emulsion droplets trapped and released by the pore throats. Three different types of emulsion flow tests were collected and analysed from previous publications, including permeability reduction of an emulsion in a specific sandpack, an emulsion slug injection followed by water injection in a specific sandpack and conformance control performance in parallel-sandpack. The optimized emulsion flow model can successfully simulate all of the three different types of emulsion flow process and have a good agreement with the experimentally obtained results. A new method for predicting permeability reduction by emulsion plugging was firstly determined by fully incorporating with the emulsion and sandpack properties. By successfully simulating the emulsion plugging process in a specific sandpack followed by water injection, a desired conformance control performance can be predicted by injection of a prepared emulsion in a specific parallel-sandpack. This may give an instruction on optimal emulsion design in the field application. The optimized emulsion flow model shows a wide application in different types of experiments and flexible control on the parameters, showing a huge potential for the reservoir-scale simulation.
Transient Simulation Study of Well Trajectory Effect on Sand Transport in Multiphase Flow
Authors: Mustafa Ahmed 
Published: October 2020

Abstract
Sand transport in horizontal wells with multiphase flow is a complex phenomenon due to the horizontal well trajectory's having strong impact on multiphase flow and sand transport behaviors. Most of the previously published studies on sand transport centered around pipeline flow applications and less so on sand transport in wells, and particularly, on understanding the effects of well trajectory and the associated sand transport capacity for different well trajectories. Therefore, this study presents qualitative comparison between different well trajectories and their impact on sand transport. This is an important aspect of optimizing the well trajectory where co-sand production strategy is selected.
Five different well trajectories have been selected in this study, which include 90-degree horizontal, toe-up, toe-down, sump and hump trajectories. Multiphase transient simulation has been carried out for each case to evaluate the effect of well trajectories on sand transport in multiphase flow, and the sand deposition profiles including moving bed, stationary bed and suspended particles associated with each horizontal well trajectory.
The study results reveal that 90-degree horizontal, sump or hump well trajectories always have higher capacity to transport sand compared to toe-up and toe-down trajectories. Thus, it helps in delaying the plugging of the horizontal section, sustain well production and reduce sand cleanout requirements. In addition, the toe-up trajectory has higher capacity for sand transport than the toe-down trajectory. Sensitivity analysis has been performed to evaluate the effect of sand particle size, fraction, water cut and GOR on the sand transport capacity for each case of different trajectories. The overall observations showed that as the sand particle size and fraction increases, the sand deposition tendency to form stationary bed increases due to the increase of gravity force. On the other hand, as the water cut, and gas oil ratio increases, the sand deposition tendency to form stationary bed decreases, due to the weak lift force to carry the particles along as the liquid viscosity is low. It is noted however that that the magnitude of effect for each parameter on the sand capacity limits for sand transport is different.
This study presents a novel approach to improve the horizontal well planning where co-sand production strategy is selected. This would help in achieving sustainable production and reducing the number of cleaning operations required during the well life cycle.
Improved Robustness In Long-term Pressure Data Analysis Using Wavelets and Deep Learning
Authors: Orta Alemán Dante , Horne Roland 
Published: October 2020

Abstract
The high frequency and long duration of well production data have high value for inferring reservoir properties, monitoring reservoir conditions and detecting changes in the well flow conditions. Unlike traditional well test data where the well flow-rate and the pressure response are carefully monitored, long-term pressure data is subject to abrupt changes in flow-rate, noise caused by hardware failures, missing data and physical changes in the reservoir. In this work, methodology to interpret long-term flow-rate and pressure data was developed using wavelet multiresolution analysis in combination with deep learning algorithms. The methodology requires little to no data preprocessing, no explicit knowledge of a physical model and has high robustness to noise.
The proposed methodology was found to exploit the ability of wavelets to capture and synthetize the relevant behavior of the reservoir performance history at multiple scales. This was achieved by applying the Maximal Overlap Wavelet Transform (MODWT) to long-term flow-rate data and using the output of the MODWT as the input for a Recurrent Neural Network (RNN) which creates a function map between flow-rate and pressure as a function of time. For the training of the RNN, synthetic well data were used.
The application of wavelet transforms allowed the neural network to perform an automatic noise filtering and simplified the training process while requiring no knowledge of noise levels, little to no manual preprocessing of data and no knowledge of the reservoir's physical model. Moreover, the mathematical formulation of the wavelet transforms allows the neural network to take advantage of the multiresolution properties, opening the door to executing the whole analysis procedure in a simplified way.
The proposed methodology aids in the inference of effects such as changes in skin factor, pressure depletion or changes in the reservoir model from the available production data, even when those data are noisy or incomplete. By using production data, the inference can be done without loss of production and used to support oil production enhancement operations. Moreover, the coupling of a neural network with multiresolution analysis eliminates the need for feature engineering and performs automatic denoising of the data, which were found to be extremely desirable properties for a methodology to be scalable and applicable to real well datasets.