bluuebunny/crossref_metadata_2025_split huggingface dataset:
Thermosensitive water soluble polymers: a solution to high temperature and high salinity reservoirs
Authors: Kamal Muhammad Shahzad , Sultan Abdullah 
Published: June 2017

Abstract
Partially hydrolyzed polyacrylamide (HPAM) is one of the most widely reported polymers for chemical enhanced recovery (EOR) since most of the previous work deals with low-temperature and low-salinity reservoirs. As most of the remaining oil is in the deeper and hotter reservoirs, application of HPAM is limited because it is not suitable for high-temperature and high-salinity (HTHS) conditions. HPAM suffer a huge viscosity loss due to charge shielding effect and hydrolysis of the amide group. In presence of divalent cations, hydrolyzed product may also precipitate. In this work, we propose a novel thermo-sensitive water soluble polymer for HTHS conditions. Due to the presence of thermo-sensitive monomer, as the temperature exceeds lower critical solution temperature (LCST), the formation of physical network takes place. This formation of physical network results in the viscosity enhancement. The rheological behavior of the polymer was investigated using Discovery Hybrid Rheometer (DHR-3) at different polymer concentrations, temperatures, and in presence of different ions. Two different regions were observed in the viscosity-temperature plot. At lower temperatures (T&lt; LCST), thermothinning behavior was observed i.e. viscosity decreased with temperature. At higher temperatures (T&gt; LCST), the thermo-thickening behavior was observed i.e. the viscosity increased with temperature. This thermo-thickening also depends on the salinity of the solution. By increasing the salinity of the solution, the LCST shifted at low temperatures. In deionized water, no thermo-thickening was observed and only thermo-thinning behavior was noted. Such type of viscosity behavior is highly desirable for EOR operation as low viscosity at low temperatures ease the pumping operation. As the liquid move down the reservoir, the solution viscosity increases due to the formation of network structure.
New Technique to Determine the Total Organic Carbon Based on Well Logs Using Artificial Neural Network (White Box)
Authors: Mahmoud Ahmed Abdulhamid , ElKatatny Salaheldin , Abdulraheem Abdulazeez , Mahmoud Mohamed , Omar Ibrahim Mohamed , Ali Abdulwahab 
Published: June 2017

Abstract
Total organic carbon (TOC) is the amount of carbon present in an organic compound and is often used as an essential factor for unconventional shale resources evaluation. The previous models for TOC determination were either based on density log data only and considered the presence of organic matter is proportional to the bulk density, or based on resistivity log, sonic or density logs as well as the formation level of maturity (LOM), where these models assumed a linear relation between resistivity and porosity logs. The average absolute deviation (ADD) of the previous model was not less than 1.20wt% of TOC with a coefficient of determination (R2) of less than 0.85.
The objective of this research is to develop new empirical correlation to determine the TOC based on well logs using artificial neural network for Barnett shale formation. Core TOC data (442 data point) and well logs (resistivity, gamma ray, sonic transit time, and bulk density) were used to develop the ANN model. For the first time, the ANN model will change to a white box by extracting the weights and biases of the model to form the empirical equation.
The results obtained showed that TOC is strong function of bulk density, and moderate function of gamma ray, compressional sonic time, and week function of deep resistivity. The developed ANN model is able to predict the TOC based on conventional log data with high accuracy (the ADD is 0.91wt% of TOC and R2 between estimated and actual TOC is 0.93). The developed empirical equation for TOC determination from the ANN model outperformed the previous available models, which had an ADD of 1.20 wt% or more and R2 of less than 0.85. The developed TOC model and equation can be applied using simple computer without the need for a specific software.
The novelty of this new research is the simplicity and high accuracy of the developed model for estimating the total organic carbon based on conventional log data. The developed empirical equation will help the geologists and reservoir engineers to predict the TOC without the need for hard lab work or complicated softwares.
Utilization of Real-Time Data and Advanced Correlation/Interpretation Tool for Picking the Formation Tops and Casing Points Remotely: A Cost Effective Solution by RCC
Authors: AlAbdulkarim Dana , Saklou Mohammed , Al Khudiri Musab , Ghamdi Yasser , Barayyan Mohammad , Attique Amer Muhammad , Rasheed Farhan , Kashif Muhammad 
Published: June 2017

Abstract
Remote Casing Control (RCC) is an initiative of the Wellsite Geology Division with the support of Aramcolink. The aim of the RCC team is to provide 24/7 geological support about casing points remotely. Real-time data transmission and the advanced correlation tool are the basic requirements to achieve the end objective of picking the formation tops and casing points remotely.
This paper describes the case study that illustrates the great impact of utilization of real-time data transmission and advanced real-time tools to pick casing points and formation tops remotely. The RCC team monitors the active well operation remotely with the help of real-time data streamed by Aramcolink. Moreover, Aramcolink has developed a logic/algorithm to calculate Drill Time from the streamed realtime data. Additionally, the mud logging unit can upload and share the lithology data RCC through the Aramcolink portal. This real-time data is being displayed/exported and downloaded from the Aramcolink viewer. Later it is being used to correlate with some offset wells of the same or a nearby field. Based on the similar signatures of Drill Time and lithology data, formation top and casing points are being picked/ designed. Other than shallow casing points, the RCC team is also picking the 7" liner point remotely with the aid of a mud logging unit to provide them with the lithology and gas readings where the deeper section ROP is not enough to decide and pick the formation tops or casing points. The RCC team also uses RigChat to effectively communicate with rig personnel and keep involved parties informed.
This technique decreases the operational cost and avoids the mobilization of a dedicated wellsite geologist on each rig.
Ease to manage multiple wells at the same time from office location Effective surveillance and monitoring of the drilling operation Timely and collaborative decisions to save the rig time Effective communication with all involved parties Reduced travel and physical exposure which may cause HSE concerns Minimized logistical cost Record of the historical data for quick quality control (QC) Fast and flexible data interpretation with remote expert support Real-data accessible for surveillance at anytime, anywhere with Extranet Hence, saving time and costs, improving safety, boosting business and return on investment
The reliance on high quality real-time data from oil and gas operations has been significantly increased in the past few years. High rate real-time data is the baseline for critical remote analyses and decisions that can lead to a maximized oil/gas recovery, increasing the revenue, reducing the operational cost while minimizing the HSE concerns.
Improvements in Automated Continuous Measurement of Drilling Fluid Properties
Authors: Dotson Adam , Mahajan Lalit , Kulkarni Sandeep D. , Landry Andy , Eiland Edward 
Published: June 2017

Abstract
Various advances in automated drilling fluid property measurement have been made within the drilling industry in recent years. The automated monitoring system presented in this paper was developed for continuous measurement of drilling fluid density and viscosity in a field environment. The design of this new system, termed as a density rheology unit (DRU), was undertaken to address the major technical challenges identified in previous case studies and technical papers. The system has been field tested on both land and offshore drilling rigs, with corresponding accuracy and reliability studies.
This paper presents the results of field validation and statistical analysis of the system. The accuracy of the measurements was confirmed versus the standards outlined in American Petroleum Institute (API) procedures. Making this technology available to operators can result in safer and more cost-effective drilling operations. Avoiding well problems caused by fluctuating drilling fluid properties helps reduce nonproductive time (NPT) and maximize rate of penetration (ROP) during drilling operations.
Effect of Temperature and CO2 Content on the Natural Gas Production from Shale Gas Reservoirs
Authors: Eliebid Mohammed , Mahmoud Mohamed , Shawabkeh Reyad , Elkatatny Salaheldin , Sultan Abdullah , Abouelresh Mohamed , Al-Shehri Dhafer 
Published: June 2017

Abstract
Unconventional natural gas resources including shale and tight gas reservoirs hold most of natural gas reserves around the world. However, these resources pose a great challenge in reserve estimation, modeling flow behavior, reservoir simulation, drilling, history matching, and well testing. Because of high complexity of rock composition, poor petrophysical properties and tightness of the pore system gas-rock interactions can no longer be ignored since they provide crucial information about the flow and recovery processes. Gas adsorption is one of the most important mechanisms describing gas-rock interaction.
In this work, adsorption of CH4 and CO2 on the organic-rich Qusaiba Shale, Saudi Arabia was studied. XRD analysis showed that the shale consists mainly of clays, Quartz and K-feldspar. SEM characterization shows that the shale has a wide range of pore types and sizes. The total organuic carbon (TOC) of the studied samples has an average of 6.10 wt% and Tmax is 417°C which indicates the shale immaturity.
The results of the experimental study showed that the CO2 content in the natural gas has a noticeable effect on the desorption of the natural gas from the shale rock. The studied shale sample has no CH4 adsorption at 50°C and it increases slightly to 16 mg/g after increasing temperature to 100°C and further increased to 145 mg/g at 150°C which is attributed to opening of the pores that previously blocked by organic matter when the temperature increases at 50°C and 100°C. Increasing CO2 fraction in the mixture from 0% to 10% CO2 the total maximum gas uptake increased to approximately 24%, 26% and 31% at 50°C, 100°C and 150°C respectively. The pure CO2 adsorption on was the approximately 85 mg/g and increased to 555 mg/g at 150°C and 44 bar which reflects the high shale attraction toward CO2. Also, The TOC and shale mineralogy affected the adsorption behavior of CO2 and CH4 on the studied shale sample causing the adsorption behavior to be endothermic i.e. increasing adsorption with increasing temperature. The presence of water bearing clay minerals that are sensitivity to temperature causing damage to crystal structure which resulted in huge increase in the adsorption uptake at high temperatures. The adsorption isotherms analysis confirmed that Langmuir isotherm is not the suitable model to be used for adsorption for all studied gases at the studied temperatures. The temperature changes have projected a tremendous effect on the desorption process of the natural gas.
Successful Field Test of Real Time Inline Sensing System for Tracer Detection at Well Head
Authors: Ellis Erika S , Askar Mohammad N , Hotan Muhammad , Shateeb Hussain 
Published: June 2017

Abstract
This paper presents the results from a successful field test of a real-time portable sensing system for fluorescent nanoparticle tracers directly from the well head, reducing previous sample processing and detection time by over 99%. In 2014, the first oil industry nanoparticle tracers (ADOTS), were injected at a tertiary produced reservoir to demonstrate for the first time, the ability of nanoparticles to successfully traverse Arab-D reservoir rock. The ADOTS proved to be remarkable reservoir agents showing excellent stability and mobility and are still being recovered more than two years later. ADOTS are inexpensive to produce and can be prepared at the well site. ADOTS sample collection and processing was performed manually, as are most tracer samples and results were obtained at a minimum of 30 hours after sample collection due to the time consuming laboratory processes needed in order to analyze the water with sophisticated instruments for accuracy. To address this issue, a portable real-time sensing system was developed to collect, process and analyze samples directly from the well head in about 5 minutes and is capable of measuring fluorescent tracer concentration at the ppb level. The portable sensing system, was tested, directly from a wellhead currently producing fluorescent nanoparticle tracers from a related injection test. The system was able to process, analyze and report accurate data in about 5 minutes, demonstrating a &gt;99% increase in process efficiency and eliminating the large cost of standard chemical tracer processing. This prototype system provides a revolutionary breakthrough in reducing the time and money associated with detecting fluorescent tracers used for decades in the industry. For the first time, a fluorescent tracer can be detected at the well site in real time using inexpensive, portable equipment.
Development of Large-hydrophobe Betaine Surfactants for Chemical Enhanced Oil Recovery in Low/High Salinity Reservoirs
Authors: Hongyan Cai , Jian Fan , Dong Han , Zhang Fan , Zhu Youyi , Hu Ziqiao 
Published: June 2017

Abstract
For chemical enhanced oil recovery in high temperature, high salinity (HTHS) reservoirs, the development of surfactant faces great technical challenges. Conventional surfactants industrially applied such as heavy alkyl benzyl sulfonate, petroleum sulfonate, and polyoxyethylene ether are excluded due to poor properties in high salinity or high temperature conditions. Heat tolerant and salt resistant criteria dramatically narrow the screening window and make it very difficult to obtain a suitable surfactant candidate. On the other side, for reservoirs with low to medium salinity, it is not easy to find suitable surfactants either. Less of salts in solution needs surfactant having higher interfacial activity to attain ultralow interfacial tension (i.e. IFT, 10−3 mN/m magnitude).
In this study, two betaine surfactants, amidobetaine and etherbetaine were developed from long chain fatty acid and alcohol. Properties with respect to long term thermal stability, salt resistance, interfacial activity were evaluated. Besides, the synergistic effect of combined surfactants were also studied. After that, core flooding tests were conducted to evaluate the performance of the concerned betaine/polymer SP formulation.
The prepared betaine surfactants showed high interfacial activity with several crude oil, reaching ultralow IFT within surfactant concentration range of 0.05%-0.30%. For amidobetaine surfactant, excellent salt resistant property was observed at salinity as high as 200,000 mg/L. Sound stability of betaine solutions at high temperature, high salinity conditions were observed within 90 days aging test. In addition, the combined amidobetaine and conventional long-chain betaine/gemini surfactant demonstrated positive synergistic effect at low salinities. Moreover, amidobetaine surfactant showed remarkable viscosifying capability, displaying mobility control potential. Core flooding tests of binary amidobetaine/polymer formulation showed an average incremental oil recovery of around 17%.
The developed betaine surfactants provide good chemical candidates for CEOR in HTHS reservoirs.
Instantaneous Shut-in Wellhead Pressure for SSA Field Oil Wells
Authors: Al-Zayer Rayed M. , Al-Hussain Ali Musa , Arukhe James , Al-Khamees Saud A. 
Published: June 2017

Abstract
Well testing in offshore environments is critical, challenging and often costly in terms of operations and logistics. The means of periodic testing for monitoring well performance offshore is typically through the use of a test barge. Tide cycles, which often pose mobility problems for the test barge, typically affect testing efficiency. Reducing the duration of normal production test improves field operations because of the increase of the possible number of wells that can be tested. This paper illustrates the benefits of using instantaneous shut-in wellhead pressure (ISWHP) for generating a pressure rate (PQ) curve in an offshore field in Saudi Arabia.
Test barge optimization is shown through the construction of PQ curve for a well with single test data. In theory at least two points are required to construct the PQ curve. Since a single test data is typically obtained because of rate test scheduling optimization, the ISWHP technique for constructing the PQ curve would be an appropriate approach to optimize testing requirements each month and to obtain the base potential of each well. With the ISWHP measurement technique/methodology, a unique rate test will be enough to construct the PQ curve instead of two or more rate test data. This methodology is based on the principle of pressure transient analysis to distinguish the type of flow regime. The use of the pressure derivative plot (log pressure vs. log time) from gauge data and history plot of time verses pressure from Supervisory Control and Data Acquisition (SCADA) helps to determine the start of ISWHP. Field and hypothetical examples are provided to explain the methodology.
Instead of an average two days of typical test barge activity for well testing, the ISWHP technique allows the termination of a test within 10 minutes after recording a rate test, with a significant improvement in testing efficiency. The number of well tests per month has almost doubled from applying the method in the field. A field wide application of the ISWHP decreases the need to conduct several tests per well, resulting in accurate or rapid diagnosis for well-timed decisions to enhance the field's production offshore.
Sedimentological and Stratigraphic Characterization of Late Paleozoic Unayzah Reservoirs, Central Arabia, Saudi Arabia
Authors: Alaboud Fares , Melvin John 
Published: June 2017

Abstract
The Unayzah reservoirs are Late Carboniferous-Early Permian in age and represent deposition under variable climatic conditions in different depositional environments. The deposition of the lower Unayzah reservoirs commenced in late Carboniferous to early Permian during the global Late Paleozoic Ice Age. They comprise glaciogenic deposits of the Juwayl Formation and are divided into two members: Ghazal Member and Jawb Member. The upper Unayzah reservoirs are found in the Nuayyim Formation, which consists of post-glacial sandstones and siltstones representing a number of depositional facies of variable reservoir quality which in general indicate an arid to semi-arid depositional settings. Depositional environments in the Nuayyim Formation include ephemeral (playa) lake, ephemeral fluvial, tidal flats, estuarine, nearshore marine, and eolian environments. In Central Arabia, Unayzah reservoirs are prolific oil and gas producers and their characterization is important for production and development. This study was aimed at identifying, characterizing and understanding facies and depositional environments distribution to produce a robust depositional model for these reservoirs.
Detailed description and facies analysis of over 6,300 ft of Unayzah reservoirs core were carried out. The lithofacies were grouped into facies associations, representing depositional environments. Stratigraphic correlation was performed using core and logs to discern vertical stacking patterns and establish lateral continuity.
The highly variable depositional environments that were identified indicate a dramatic change in climatic conditions during the deposition times, from glaciogenic deposits in the lower section into much warmer, arid environments in the upper part of the formation. The Ghazal Member is highly variable in thickness and represents glacial valley deposits. The Jawb Member is more widely spread in the study area and consists of more variable facies than the Ghazal Member. The Nuayyim Formation contains post-glacial deposits that are more complex and variable across the study area.
The results of the study contribute to the understanding of Unayzah reservoirs not only in Central Arabia but also in Eastern Saudi Arabia. It also provides new insights into the facies architecture and stacking patterns of the encountered depositional environments.
Assessment of Explosion Hazards Associated with Nano-Powders
Authors: Deshmukh Adnan , Varma Sangit , Sakpal Nilesh , Wakale Sagar , Agwan Akshay , Patwardhan Samarth D. 
Published: June 2017

Abstract
Nano-powders are composed of particles in size range from about 1 to 100 nano-metres (nm). The growing demand for nano-powders arises from the change in physical, chemical and electrical properties exhibited by such particles when their size falls below 100 nm. Along with the increasing production and use of Nano scale particles, there has been a growing concern over the impact of this new technology on health, safety and environment. This has almost exclusively concentrated on the potential health hazards of nano-powders. One potential hazard that appears to have received little attention to date is their explosivity. Explosive dust clouds can be generated from most organic materials, many metals and even some non-metallic inorganic materials. Dust explosions involving particle sizes ranging from a few microns to hundreds of microns, there is a need for these particles to be extensively studied. This work involves computationally modelling the explosion, and investigation of critical parameters that can enhance the severity of the explosion. These parameters include but are not limited to effect of particle size, dust concentration and composition, ignition strength, degree of dust dispersion, explosion characteristics of nano-particles, operating conditions. Further, the work involved in this paper looks at the impact onto the environment by explosion of such nano-powders. The possibility of dust generation accumulation and explosion in various areas of the facility are investigated. A checklist for adequacy of existing safety measures is prepared, and requirement for additional safeguards is studied, in order to avoid catastrophic effects.