bluuebunny/crossref_metadata_2025_split huggingface dataset:
AI Based Intelligent Pigging Solution
Authors: Nidhi Varun , Rao Rakesh , Mittal Aakash 
Published: November 2019

Abstract
Pigging is a process used by operators to efficiently run oil and gas pipelines. It involves PIGs short form for Pipeline Inspection Gauge, to perform various maintenance operations. PIG tool is pushed in the pipeline using the pressure inside the pipeline. This is known as the pigging process. It is used for cleaning and inspection of pipelines among other functions. PIGs are launched and received using special purpose sections installed at various locations of the pipelines called launching and receiving stations. In this paper we will be discussing the use of smart or intelligent PIGs, used for inspection of pipelines.
An intelligent PIG has many sensors along its circumference to capture the information about the health of the pipeline. Some of the most used sensors used for inspection are Magnetic Flux Leakage (MFL), Ultrasonic and Eddy current. PIG also contains other sensors like Gyro, Odometer used to estimate the location of the PIG and other diagnostics parameters for sensors and corresponding electronics. In this paper we are covering PIGs with MFL sensors used for the inspection. The tool contains a data storage device to store the data captured by the sensors for post processing and analysis. Once an inspection run is completed the storage device is used to download the data to computer system for analysis. Pigging companies generally use their proprietary software tools to analyze the inspection data.
The data contains signatures from the inspected pipeline. A skilled analyst with the help of the software tool is able to classify the signatures. The classification is divided into known features of the pipeline like weld, magnetic marker, sleeve, flange and more. The other division is defects namely metal loss, dents and more. Efficient detection and classification of defects allows the operators to take proactive actions, increasing operational efficiency, life of pipeline and reducing chances of faults and unplanned shutdowns. Some of the critical parameters used by operators to analyze the corrosion in the pipeline are wall loss percentage due to metal loss, depth profile, repair factor and metal loss clusters. Major part of this paper covers the use of software to detect and classify different metal loss features in the pipeline.
A New Methodology for Total Gas Monitoring to Improve Well Safety Assurance
Authors: Shahini Edisa , Nonno Lamberto , Zanchi Augusto , Pozzovivo Vincenzo 
Published: November 2019

Abstract
At a time when maximizing operational efficiency is needed more than ever, advancements in data processing and analytical capacity may provide a sustainable path for uncovering hidden correlations and other insights from one of the basic roles and responsibilities of any surface logging services provider. This paper showcases a side-by-side comparison of two gas extraction devices and how they influence gas readings and, eventually, total gas measurement related to well control operations monitoring.
Although the trend analysis from gas reading values is imperative for pore pressure predictions and other classical readings, this paper negates its use for lower explosive limits (LEL) by using laboratory methods paired with a study in the field. The apparatus used to extract total gas in water-based mud was a constant-volume, constant-temperature and constant-flow system. The detector used to measure the total gas concentration was a flame-ionized detector (FID) system.
The influence of gas extraction devices on gas data is crucial for the determination of total gas. Conditions affecting gas readings have been explored at length, and they include gas extraction temperature, mud flow rates, gas flow rates, and drill rates (i.e., rate of penetration). Due to the development of analytical capacity, the extraction method and the analysis devices are compared in this paper.
Wellsite total gas monitoring, which usually provides common wellsite total gas values, has been heavily analysed regarding what it fundamentally represents. Total gas also helps operators to harness their data and use it to identify process safety indicators, as well as other environmental emissions applications.
Estimates of total gas concentration in the drilling fluid, as detected by a gas extraction device, can vary, based on the device type. This paper shows how the different extraction methodologies fit into well safety operations monitoring and process safety requirements to better evaluate and define new risk communication and safety practices in the industry.
Can HVFRs Increase the Oil Recovery in Hydraulic Fractures Applications?
Authors: Ellafi Abdulaziz , Jabbari Hadi , Ba Geri Mohammed , Alkamil Ethar 
Published: November 2019

Abstract
In unconventional reservoirs, such as Bakken Fm, the stimulation application is the required method to develop and produce economically from this vast reserve. However, the production process is still only through primary depletion mechanism with low recovery factor in ranging of 3-5% due to sharp decline in oil production by depletion in natural fracture networks as well as unsuccessful implementation hydraulic fracturing design. This paper aims to investigate the application of HVFRs with surfactant in high TDS condition to enhance Bakken oil wells production performance using an integral methodology between 3D/2D Pseudo hydraulic fracturing simulator and numerical reservoir simulation. Four types of fracturing fluids as follows: Linear Gel, HVFR-A (mixed with freshwater), HVFR-B (mixed with produced water plus surfactant as additives), and HVFR-C (mixed with produced water) were tested using an integral approach. The workflow in this paper was started by modeling the optimal fracture half-length using 2D/PKN model based on the slurry volume per stage. As a next step, the optimum pump schedule was created using 3D Pseudo hydraulic fracturing simulator. Furthermore, the sensitivity analysis was performed on HVFR-B at different pump rate, final proppant concentration, and proppant size to investigate the proppant transport and production performance. Finally, reservoir simulation tool was utilized to investigate the changing in fracture parameters and evaluating the Bakken oil production. The results showed that HVFRs with surfactant is the optimum hydraulic fracture fluids that showed better performance in proppant transport, which responded by high fracture capability to improve oil production. The findings can be applied and compared to other unconventional shale plays, such as Eagle Ford and Permian Basin.
Development and Application of Cyclic Stress Fracturing for Tight Oil Reservoir in Ordos Basin
Authors: Bai Xiaohu , Zhang Kuangsheng , Tang Meirong , Wang Chengwang , Wang Guanggao , Li Chuan , Zhang Tongwu , Xu Chuangchao , Wu Shunli , Wang Jianhui , Liu Shun , Wang Bei , Chen Qiang , Fu Yunlong 
Published: November 2019

Abstract
The Chang7 group in Ordos Basin usually shows low brittleness index, high differential principle stress and little natural fracture, which makes it difficult to generate complex fractures with traditional high rate hydraulic fracture practice. During a geomechanical test on core samples, complex fractures were unexpectedly found inside the test sample due to fatigue failure after cyclical stress loading below fracture gradient. Based on cyclic stress loading tests on cores and large-scale mockups, a cyclic stress fracturing technology was developed with specific operation procedure, downhole tools and optimized fracturing design parameters to generate complex fractures.
This technology injects high concentration slurry through tubing at low rate and slick-water through the annulus at various pump rate. The annulus injection rate changes constantly based on treating pressure and formation response, to achieve real-time control of bottomhole slurry concentration, in order to cyclically apply pressure on the formation rocks to induce fatigue failure, thus complex fractures are generated inside the low brittleness index Chang7 formation.
In the field trial of 24 wells, the wells fractured with cyclic stress technology showed increased fracture complexity, a 100% increase in stimulated reservoir volume in microseismic monitoring result and achieved 50% higher production than the wells treated by conventional fracturing technology.
Well Testing to Full Potential: Lessons Learned and Best Practices for High Rate Wells
Authors: Hollaender Florian , Shumakov Yakov , Karacali Ozgur , Theuveny Bertrand 
Published: November 2019

Abstract
Today many well test operations are performed in frontier environments targeting high potential oil and gas reservoirs or using high deliverability horizontal wells. Such highly productive wells cannot be dynamically evaluated to acquire representative reservoir data by small-scale flow tests.
High flow rate well tests are introducing a set of unique challenges that need to be addressed at the design stage of the test, each requiring an appropriate surface well test spread, DST string as well as job operation procedures and equipment planning. Currently, well tests aiming at achieving very high flow rates are often designed and executed on a case-by-case basis, and there are no practical recommendations available that would summarise the well testing experience in such environments and guide the operator through the process to efficiently plan the well test operations.
Well test operations are inherently challenging operations owing to the requirements for well control, accurate data acquisition, and the safe handling and disposal of produced fluids (hydrocarbons, completion brine, water, and solids), concerns are especially acute when considering high flow rates. Several past experiences have clearly shown limitations when trying to achieve high flow rates using conventional approaches and standard well test equipment.
Concerns range from equipment failure and operational issues to poor interpretability of acquired data from those tests, increasing the total costs of such well tests or in extreme cases leading to severe HSE incidents. Enhancements in well testing equipment such as new generation well test separators equipped with high-range Coriolis mass flow meters or new generation burners, combined with fit-for-purpose well testing techniques make it possible to overcome these challenges.
This paper will summarise the results and lessons learned from high flow rate well test operations performed around the globe on vertical and horizontal wells, in oil and gas reservoirs. The paper provides practical recommendations supported by a series of case studies from multiple oil and gas fields. The paper also describes a comprehensive list of challenges associated with high rate well test operations that can support successful operations design. Recipes for success are provided to ensure that safe operation can be performed in challenging environments.
Application of Hybrid ARIMA – Decision Tree Algorithm in Reservoir Pressure Surveillance
Authors: Mohammad Fuad Iqmal Irsyad , Rosli Luqman Hakim , Husni Husiyandi 
Published: November 2019

Abstract
Bottom hole pressures are valuable source of information for reservoir surveillance and management and are the heart of reservoir engineering. Real – time pressure measurements record pressure data at 5 second interval resulting in enormous accumulation of data. The size and volume of the accumulated data limit the capability of existing analysis software to load and interpret data. This paper presents an improved methodology for data quality checking and data optimization in determining reservoir pressure depletion via Autoregressive Integrated Moving Average (ARIMA) and Decision Tree Model.
Dataset was gathered from a representative reservoir from Malay Basin. The ARIMA algorithm presented was designed for quick and efficient data quality checking. The Decision Tree Model in other hand was utilized to select maximum buildup pressure for reservoir depletion point via well status parameters. The maximum pressures were selected from buildup up data when the decision tree conditions were met. Versus classical methods, the algorithm has obtained around 90% similarity. The resulting data were then can fully optimized for reserve reporting and forecasting study i.e. analysis and numerical simulation.
The paper also reports on the advantages in the application of ARIMA – Decision Tree Algorithm in pressure surveillance revealing few key advantages namely minimize the need of well intervention and optimized workflow for reservoir engineer to view, utilize, and detect reservoir depletion data. ARIMA – Decision Tree Algorithm is targeted to be installed and integrated in field historian for better overall data analysis and visualization. Results produced from the ARIMA – Decision Tree Algorithm which consist of reservoir pressure depletion data will then improve more advance analysis such as simulation and forecasting in terms of overall speed and accuracy.
As a conclusion, this paper presents the importance and application of incorporating Big Data Analytics Algorithm in reservoir management and reporting. Future work, deliverability calculations can be incorporated in the model to identify and rectify any abnormal reservoir behavior.
New Synthetic Acid Technology Used to Successfully Removing Scale Damage by Laboratory Custom-Designed Systems in HPHT Wells in Mexico´s Offshore
Authors: Diaz Perez Pablo Javier , Juarez Portillo Ernesto Adrian , Solano Gonzalez Francisco del , Jimenez Osorio Jose del 
Published: November 2019

Abstract
Stoichiometric evaluation performed in laboratory is presented comparing conventional hydrochloric acid and Synthetic Acid based stimulation systems in static and dynamic conditions to verify the speed and reaction performance applied in real tubing segments with severe Carbonate Scale at different times verifying efficiencies. With these tests, it was determined that Synthetic Acid system showed a higher dissolution efficiency, and it was applied in the stimulation of several wells located in Mexico´s Offshore, achieving successful results. Conventionally, carbonate scale complications in tubing production, downstream pipes, wellhead choke pipes, gas lift mandrels valves and surface pipes are corrected mostly with hydrochloric acid and occasionally with organic acids; in the quest of a solution to reduce the corrosion rate in pipes, increase in reaction efficiency and stability at critical pressure and temperature conditions, a synthetic acid system was developed which meets the established objectives compared to conventional systems. Tubing production pipes with carbonate scales was recovered during minor repair and cut into segments with equal dimensions, which were measured and weighed to quantify the stoichiometry of the two types of acid. The evaluation developed to dynamic and static conditions verified the impact that the turbulence has on the efficiency and speed of reaction in different observation times. Based on the results obtained from the laboratory tests, a stimulation treatment with Synthetic Acid was carried out in the oil producing well in the BKS formation, achieving immediate increases in their operating conditions (temperature, pressure in the downstream pipe, pressure in wellhead); subsequently the well maintained an incremental trend of its flow conditions over time. The use of synthetic acid to stimulate and remove the damage by precipitation of carbonate scale present in the formation water, allows it to do so without practically causing any corrosive damage, is highly efficient in dissolution and friendly to the environment.
Improvement in Rheological Features, Fluid Loss and Swelling Inhibition of Water-Based Drilling Mud by Using Surfactant-Modified Graphene
Authors: Rana Azeem , Saleh Tawfik A. , Arfaj Mohammad K. 
Published: November 2019

Abstract
The improved rheological properties of the drilling fluid are very critical for the oil well drilling operation. The present work reports the effect of sodium dodecyl sulfate modified graphene (SDS-Gr) on the rheological features, fluid loss and swelling inhibition mechanism of clay. The rheology and filtration test of drilling mud were conducted after being hot rolled for 16 h at 150oF and under 500 Psi pressure. The inhibition characteristics were evaluated by the dispersion test and shale inhibition durability test, where SDS-Gr modified drilling mud shows the highest recovery as compared to KCl and traditional drilling mud. The inhibition mechanism was investigated by various kind of techniques such as thermogravimetric analysis, scanning electron microscopy, and energy dispersive X-Ray spectroscopy. The outcomes revealed that the addition of SDS-Gr to the traditional drilling mud clearly affect the rheological properties and make it more suitable for the drilling. Moreover, SDS-Gr additive reduces fluid loss by 20% as compared to the mud without SDS-Gr. The Fourier transform infrared spectroscopic study also confirms the adsorption of SDS-Gr on clay. SDS carries the negatively charged functional group that help SDS-Gr to binds to the cations present on the clay surface and graphene plug the pores in the clay. The intercalation and adsorption of SDS-Gr on to the surface of clay hinder water molecules from invading the clay that helps in mitigation of swelling due to hydration. We report for the first time the SDS modified graphene (SDS-Gr) that successfully binds to the clay surface. In order to combine the features of SDS and graphene, the graphene surface is factionalized with SDS that modify the drilling mud rheology, control fluid loss and inhibit the clay swelling.
Integrating Digital Image Processing and Machine Learning for Estimating Rock Texture Characterization from Thin Section
Authors: Alkamil Ethar H. , Abbas Ahmed K. , Almubarak Haidar 
Published: November 2019

Abstract
A methodical rock texture characterization of core samples and cuttings can provide powerful information that can be used reliably and cost-effectively to optimize fracture stimulation designs by placing fracture stages based on rock characteristics and drill bit selection. This paper presents a method to quantify rock texture using a developed integrated digital image processing to the neural network segmentaion for the analysis of the core-plug thin section.
The standard routine uses the binarization process that converts the colored (RGB; Red Green Blue) core-plug thin section image into a set of binary images corresponding to different mineralogy content using the R, G, and B pixel values for thresholding. The idea is that the threshold values must accommodate all different colors that correlate to the rock texture and pore and help in creating a different mask (binary image) for each content type based on the threshold values used. The collection of the binary images for the different mineralogy will help in the rock texture interpretation. However, the neural network method used the data for multiple thin section images to learn based on the pattern of the color difference between pores and matrix. All results are validated with x-ray deflection (XRD).
The proposed integrated system results show that, the thin section used in this work from an oilfield in the southern of Iraq is mainly quartz with minor Kaolinite and other components, where the mineral color code and weight percentages are recorded and validated with XRD. The comparison between the proposed image processing approach, neural network, and the XRD analysis show that good agreement with an acceptable percentage of error. These variations can help in understanding the rock behavior, optimize fracture stimulation designs and selecting the appropriate drill bits for drilling applications. The variations can also help in smart completion designs.
Formation Damage Assessment and Waterflooding Incompatibility Study for Reduced Sulfate Injection Water
Authors: AlAamri Jamal , AlDahlan Mohammad , S Al-Yami Ibrahim , A. Al-Ghamdi Abdulaziz 
Published: November 2019

Abstract
Waterflooding has always been considered as a favorable technology to support reservoir pressure during production and enhance recovery. The main challenge that needs to be addressed is the increase in scale potential due to incompatibility of mixing two different waters of different physical and chemical properties. Calcium sulfate scaling can form as a result of the reaction of high calcium produced water with high sulfate injection water. Since there is no feasible method that can efficiently be used to reduce the high calcium content in the formation water, treating the injection water by adding scale inhibitor or lowering its sulfate content is of high interest. Reducing the sulfate content physically through RO membranes or chemically through ion exchange methods can be considered a solution.
In this study, different scenarios for using reduced sulfate simulated injection water (SIW) in addition to untreated SIW have been examined as options for waterflooding prior to field application recommendations. Three different concentrations of reduced sulfate SIW (100, 200 and 300 SO4− ppm) in addition to the untreated SIW with almost 4000 ppm of SO4− were used to study water-water reaction and water-rock interaction. The study scheme included static bottle testing for compatibility of the synthetic flooding water and SPW at different mixing ratios and coreflooding at different temperatures for the water-rock interaction.
Water-water interaction tests revealed that the reduced sulfate SIW was found to be compatible, and no sign of precipitatation was observed. Untreated SIW showed white precipitates of calcium sulfate when mixed with the high calcium synthetic simulated production water (SPW) at different ratios and temperature. Coreflooding formation damage assessment indicated a reduction in the commercial core plug permeability of less than 12%.
Reduced sulfate waterflooding can eliminate the risk of calcium sulfate scale formation damage and minimizing scaling mitigation and challenges requirements.