bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rheological Study of a Novel Sulfobetaine Surfactant-Based Acid System
Authors: Cetin S. , Nasr-El-Din H. A. 
Published: February 2017

Abstract
Viscoelastic surfactant (VES)-based acids have been employed for acidizing jobs due to their ability to build up sufficient viscosity for acid diversion and fluid loss reduction, and to break into low viscosity after the treatment is completed. This work studied rheological properties of a new zwitterionic viscoelastic surfactant-based stimulation fluid. İmpacts of many variables on the rheological characteristics of the VES-based live and spent acids were examined.
Rheological experiments were conducted using a high pressure/high temperature (HPHT) viscometer. Viscosity measurements were performed between the temperatures of 78 to 350°F and shear rates of 10 to 935 s−1 at 300 psi. Examined acid additives included: corrosion inhibitor, formic acid, methanol, demulsifier, H2S scavenger, iron control agents, and mutual solvent. As a contaminant, the effect of Fe (III) was investigated. In addition, the impacts of surfactant concentration, salt type and salt concentration on the viscosity of the VES-based acid systems were tested.
Experimental results indicated that the new VES-based acid system exhibits a sufficient viscosity for acid diversion at temperatures up to 270°F. Apparent viscosity of the spent acid showed a strong relation with surfactant concentration, salt type and salt concentration. Corrosion inhibitor concentration above 0.5 vol% caused a notable loss in the viscosity as the temperature increased gradually. Dependency on methanol was strong enough that it resulted in a decline of the apparent viscosity of both live and spent acid solutions. H2S scavenger and iron control agents (citric acid and EDTA) did not alter the viscous behavior notably, while demulsifier and mutual solvent caused a reduction in the apparent viscosity. Fe (III) contamination caused fluctuations in the live acid viscosity due to generated VES-iron complex. In spent condition, this complex caused phase separation that resulted in loss of viscosity. On the basis of the results obtained, optimum conditions to achieve the desired rheological profile for a successful well stimulation operation are presented.
Overlooked Opportunity - Steam Traps
Authors: Khulaify M. S. 
Published: February 2017

Abstract
In Saudi Aramco, Abqaiq plants, steam is produced by boiling water via sever-al boilers segregated in two plants. The steam produced is connected to the main steam header supplying all Abqaiq plant users, mainly steam turbines with a 625 psig. All Abqaiq plant steam turbines are designed to receive 625 psig and produce 60 psig which is then connected to a separate steam header for further utilization before it is condensed back as water and returned to our water tanks facility. Along the steam piping network, there are drain lines con-nected to the atmosphere to release and vent accumulated condensed water to prevent hammering issues in the steam piping network. In order to prevent steam from escaping along these drains, a "Steam Traps" device is installed to allow condensed water to be released and prevent steam from leaking. Howev-er, as with most facilities worldwide, steam trap failure rates cause a nuisance to plant operations and are a major energy waste issue. After the troubleshoot-ing phase, survey completion and trialing different types of steam traps, a permanent solution was found and is planned to be implemented and will gen-erate an approximate savings of $ 828,000 per year. In this paper, trouble-shooting stages, technology trialed and results will be presented.
Effect of CO2 Content on the Natural Gas Production from Tight Gas Sandstone Reservoirs
Authors: Eliebid Mohammed , Mahmoud Mohamed , Shawabkeh Reyad , Elkatatny Salaheldin , Hussein Ibnelwaleed 
Published: February 2017

Abstract
The simulation of the gas flow in tight sandstone reservoir is a very complicated process. Several mechanisms contributed to the natural gas production in tight sandstone reservoirs. One of the main mechanisms is the gas desorption from the rock surface to the pore body. All the existing models did not consider the effect of CO2 content in the natural gas on the gas desorption from the rock surface. Also all the existing models used desorption models from the literature and they neglect the effect of rock type and reservoir conditions on the gas desorption behavior.
In this study and for the first time we will investigate the effect of CO2 content (0 to 20 vol%) on the natural gas desorption from the tight sandstone rocks. Accurate desorption isotherm will be developed based on the rock type and gas composition. Adsorption/desorption experiments will be carried out at different pressures and temperatures to develop a robust model for the natural gas desorption from the rock. Also the effect of tight sandstone rock mineralogy was investigated on the adsorption/desorption of the natural gas. Increasing CO2 fraction in the mixture from 0% to 10% CO2 the total gas uptake is increased to approximately 28%, 22% and 33% at 50°C, 100°C and 150°C respectively which reflects the high affinity toward CO2 from the tight sandstone core. The tight sandstone mineralogy also affected the desorption behavior of the natural gas. The presence of water bearing clay minerals such as illite exhibited a vast sensitivity to temperature causing damage to crystal structure and expulsion of bounded water which resulted in huge increase in the adsorption uptake.
The results of the experimental studies showed that the CO2 content in the natural gas has a big effect on the desorption of the natural gas from the tight sandstone rocks. The CO2 content also affected the desorption isotherm model for the natural gas. The tight sandstone mineralogy also affected the desorption behavior of the natural gas.
The output from this study is a robust model that explain the contribution of the desorption of the natural gas to the total gas production. Also, it will enhance the simulation and flow models that describe the flow of natural gas in porous media in tight sandstone reservoirs.
Sensitivity Study on the Impact of Sub-Volume and Image Resolution on the Prediction of Petrophysical Properties Using Micro CT Technology
Authors: F Alzayer Mohammed 
Published: February 2017

Abstract
The introduction of high-resolution micro-CT scanners in oil & gas industry has provided a cost effective approach to numerically calculate the important petrophysical properties of reservoir rocks. High-resolution rock images are acquired and later processed to capture all the pore types and mineralogy to enable accurate prediction. This study focuses on estimating the representative elementary volume (REV) of porosity and absolute permeability from micro-CT images of carbonate and sandstone formations.
Using topological representative networks and robust pore scale simulator, the effects of different volumes (100-1024 voxels) and resolutions (2.7-27 μm) on the estimation of petrophysical properties are examined. Four different formations are analyzed: Berea (medium-permeability sandstone), Doddington (high-permeability sandstone), Estaillades (medium-permeability limestone), and Ketton (high-permeability limestone). Simulation results are benchmarked to core measurements.
The results of this study are very encouraging as sandstone porosity estimates were not affected by resolution coarsening and their absolute permeability was predicted accurately at a resolution up to 18 µm in Berea and between 8-27 µm in Doddington. In limestones, the ratio of micro-pores to macro-pores can be an indication of the accuracy of pore-scale simulation results. Micro-pores in limestone are not well captured with a 2-3 μm resolution. Therefore, pore-scale simulations can be run successfully if the flow is dominated by the macro-pores. In general, results can be improved by increasing sample volume beyond 1024 voxels then coarsening it to be computationally feasible.
This study gives insights and guidance on defining the appropriate micro-CT scan sub-volumes and resolutions for different rock types when designing and testing pore-scale simulation experiments. Ultra-high resolution imaging and enhanced pore-scale simulation efficiently provide basic and advanced petrophysical data that are comparable to core lab measurements.
Production Optimization of High Temperature Liquid Hold Up Gas Well Using Capillary Surfactant Injection
Authors: Kalwar S. A. , Awan A. Q. , Rehman A. U. , Abbasi H. S. 
Published: February 2017

Abstract
Depletion of the reservoirs leads to a decrease in field production rate. Wells production rate continue to drop below the minimum critical velocity, at which point the liquid that was previously carried upward by the gas begins to fall back. The produced liquid accumulates in the well creating a static column of liquid, therefore creating a backpressure against formation pressure and reducing production until the well ceases production. Capillary Surfactant Injection (CSI) is installed on the wells to overcome the liquid loading symptom by generating foam, thereby reducing the surface tension, lowering the fluid density, and lowering critical rate.
This paper presents the comprehensive strategy of CSI application in high temperature gas well in Pakistan. Well 1A has been flowing under the critical conditions of liquid hold up with WGR of 82 bbl/MMscfd in high temperature (355 °F), deeper (11350 ft.), bigger tubing of size 5-1/2" and 7" Liner below the end of tubing along with compressor installed on it.
Based on nodal analysis, CSI was found the suitable Artificial Lift System (ALS) to deliquify this well. The procedure involved - laboratory analysis to monitor the temperature stability test of foamer (OMNIFOAM-HT) and defoamer (Alpha-2325) - scrutinizing the amount of foamer injected in the well to generate the foam - design of defoamer injection point and dosage to break the foam on surface - operational procedure - optimization mechanism - production enhancement and rapid payout time while executing CSI.
The lab results and field optimization showed OMNIFOAM worked successfully at high temperature and converted 350 - 400 barrels/day of formation water into foam at optimum injection rate of 4-5 gal/day. Defoamer injection (0.25-0.5 gal/day) was effectively carried from the injection point of corrosion inhibitor, around 150 feet upstream of compressor. CSI deployment significantly enhanced 15% rate of previous gas production and extended the life of the well to 4.0 years. If injection had been continued, the payback period was estimated to be 04 months. Based on these results, permanent deployment of CSI with renaissance wellhead system was recommended as promising solution for prolonging the life of well, sustaining its production in a short payout time and improving the reserve recovery.
A Comparative Study of Experimental Design Techniques in Assisted History Matching
Authors: Shams Mohamed , El-Banbi Ahmed. H. , Sayyouh Helmy 
Published: February 2017

Abstract
Quantifying the uncertainty of reservoir models has always been considered as a major concern. Uncertainty and sensitivity analyses provide us with information about how "incorrect" a proposed prediction scenario is. One effective approach to quantify reservoir uncertainties is to apply the concept of Experimental Design. As the name indicates, experimental design is the technique used to guide the choice of the experiments to be conducted in an efficient way. Samples are selected in the design space of the uncertain parameters in order to obtain the maximum amount of information using low number of experiments. Geoscientists and engineers are building larger models to address reservoir heterogeneity and hence reservoir simulation is usually expensive (takes significant time to run). Experimental design techniques became very useful in assisted history matching. Several experimental design techniques are introduced in literature, some must be more effective than others in typical reservoir simulation problems.
The objective of this paper is to compare different experimental design techniques and to introduce two efficient ones (Halton and Sobol sequences) to reservoir engineering problems. To show the potentiality and efficiency of the Halton and Sobol sequences design techniques, a comparative study is conducted to compare between their performance in solving assisted history matching problems and the performance of the most widely used experimental design technique, Latin hypercube. Other conventional techniques were compared too, but found to be less efficient than Latin hypercube. Two different scale reservoir models are used as test problems. A performance indicator is developed to compare between the three studied techniques in terms of the relative error between the estimated values of history matching parameters calculated using the proposed assisted history matching procedure and their exact solutions.
The results of this work indicate that the Sobol and Halton sequences experimental design techniques are superior to Latin hypercube method.
An Overview of Experimental Studies Examining the Reliability of Hollow Glass Spheres as a Density Reduction Agent in Oil Field Applications
Authors: AlBahrani Hussain I. , Wagle Vikrant , Al-Yami A. S. 
Published: February 2017

Abstract
Hollow glass spheres (HGS) present a novel solution and a practical tool for the drilling industry. HGS can function as a density reduction agent for various types of fluids and slurries used in drilling. A major advantage of HGS is that they are an inert additive to drilling fluids and slurries that can perform their function without affecting other properties of the composition. Another advantage is that the field application of HGS require no extra equipment for maintaining compressibility or extra training for rig personnel. These attributes are vital when drilling using techniques such as underbalanced drilling or managed pressure drilling. HGS are also extremely beneficial for drilling through depleted or naturally fractured formations. In spite of these positives, HGS are still considered as newcomers for drilling applications and they still require an extensive investigation of their ability and reliability to perform as density reduction agents.
A wide range experimental and theoretical study was conducted to examine the performance of HGS from different aspects. Theoretically, HGS should perform their function as drilling fluids density reduction agents readily. Consequently, the downhole environment can present a grueling challenge to HGS as it can subject them to elevated temperatures, elevated pressures, a wide range of chemical environments, and a wide range of dynamic and physical interactions. This highlights that there is a necessity to examine HGS in terms of their chemical, mechanical, and thermal stabilities before confidently employing them in the oilfield applications. To achieve this, a comprehensive set of experimental procedures and theoretical studies were performed.
The overview of the results of the experimental and theoretical studies showed that HGS performance can significantly vary based on the environment they experience. For theaspect of chemical stability, it is shown that HGS can perform their function reliably in a pH range that is typical for drilling operations. As for downhole environments with abnormal pH range, HGS exhibited minor degradation. For the aspect of mechanical stability, it is shown that some ratings or classes of HGS can degrade significantly when subjected to dynamic and physical forces mimicking the downhole environment. In the most extreme cases, the mechanical degradation of HGS is shown to be able to reach a limit where they no longer can function as density reduction agents. Finally, for the aspect of thermal stability, the theoretical study showed that HGS are generally reliable, even in conditions simulating the most extreme temperature typically experienced in a drilling downhole environment.
Nahr Umr Classical Waterflood: From Pattern Pilot to Peripheral Waterflood, Bahrain
Authors: Al Janahi Ahmed , Buali Yusuf , Nemmawi Nadia , Al Saati Fahad 
Published: February 2017

Abstract
Tatweer Petroleum completed the first successful Bahrain Field waterflood in 2014. The waterflood pilot and ultimate peripheral development was completed in the NahrUmr "CC" Reservoirs and demonstrates classical and economic waterflood performance. This paper describes the initial pilot and ultimate peripheral design and results. The paper also describes the systematic effective and efficient Tatweer pilot management approach which allowed an impressive pilot to peripheral time frame less than two years.
Early in 2013, a 30 acre waterflood pilot was initiated in Cc reservoir in the central structural area, consisting of an inverted 5-spot pattern; one injector and four surrounding producers. The pilot was selected in a confined area where there was good pressure data coverage, relatively low GOR and WC, good reservoir continuity, high productivity and good reservoir characteristics (So, Net Pay). Initial pilot results showed classical reduction of gas production and increase gross production within a couple of months of injection. Based on this observation, the pilot team reassessed overall structural reservoir performance and determined the structure would benefit from a peripheral waterflood to augment natural water influx.
The peripheral design covered 870 acers and was completed with 11 injection wells and 21 producers. The analytical approach designing the peripheral flood fell into five categories listed below: Re-assessed natural water influx; This was done by comparing voidage pulled from the reservoirs vs. pressurePetrophysical and Geological revision to the area of interestRe-evaluated the size of the prize; using analytical and simulation modelsInterpreting results and observations from the inverted 5-spot pilotRe-assessed development costs and reserves impact for pattern vs. peripheral considerations.
Since the peripheral waterflood implementation in late 2014; 170,000 barrels of incremental oil has been recovered through February 2016 and reservoir pressure has increased by 50 psi. Current injection rate is 18,500 BWIPD in 11 injectors. Current incremental oil production is nearly 400 bopd from 21 producers.
In this paper, the key elements of waterflood surveillance and assessment are described and used to help Tatweer Reservoir Management Team (RMT) to effectively and efficiently determine that the structure would benefit from a peripheral waterflood rather than a pattern design. An impressive multi-disciplinary work was done in order to change the plan and still execute the project in less than two years. In addition to that, this paper covers the process followed by the RMT to manage the waterflood conformance and monitor the injection and production simultaneously.
Near Real-Time Return-on-Fracturing-Investment ROFI Optimization for Shale Fracturing by Integrating Anisotropic Acoustic Interpretation, 3D Fracture Modeling, and Neural Networks
Authors: Gu Ming , Quirein John , Chen Dingding 
Published: February 2017

Abstract
Current fracturing designs based on 3D fracture modeling have two major issues. First, most current commercial simulators do not account for shale mechanical anisotropy. Second, running fracture simulation coupled with reservoir simulation for the purpose of return-on-fracturing-investment (ROFI) optimization is time consuming, particularly if numerous cases have to be run for parametric study of multiple stimulation treatment parameters including perforating/staging parameters, pumping parameters, proppant and fluid properties, etc. This paper proposes a robust, near real-time workflow with improved prediction of fracture geometry in anisotropic formations for shale fracturing optimization.
The workflow has four key steps. The anisotropic models are used to predict an isotropic elastic moduli and closure stress from sonic and density logs. Based on the existence of the Stoneley wave velocity, one can choose Stoneley methods such as ANNIE (Schoenberg et al. 1996) and M-ANNIE 1 (Quirein et al. 2014) or non-Stoneley methods, (Murphy et al. 2015) such as V-reg, M-ANNEI 2, or their combinations. The log interpreted mechanical properties are then input into a 3D fracture simulator to run different cases by varying the treatment parameters. The critical conductivity concept is used to determine the effective propped area (EPA) from the simulation results. Third, input (treatment parameters) and output (EPA) pairs are used to train and validate the neural network (NN) model. Finally, analytical solutions for the linear transient flow regime and boundary dominant flow regime (Wattenbarger et al. 1998) are applied in combination with NN predicted EPA to estimate time-dependent productions and ROFI. Parametric studies can be conducted through NN modeling to investigate the impact of each treatment parameter on the ROFI. Finally, the workflow is applied to optimize one shale example. The results show that the first year ROFI can be improved by 50% after optimizing the perforating and pumping strategy through the workflow.
Next Generation Well Integrity Evaluation through Cross-Segment Integration for Saudi Aramco
Authors: Amri Faisal , Hababi Ayedh , Ramirez Andres , Faraj Omar , Shankar Rohit , Alshafai Ali , Martanto Roni , Elmarsafawi Youssef , Abdurrahman Riefky 
Published: February 2017

Abstract
With the advent of the API RP 65 – Part 2 (post-Macondo), the concept of well integrity evaluation has been given an entirely new meaning and importance. Watching acoustic logs in isolation without sufficient correlation with the formation evaluation logs and cement placement simulation yields a lot of unanswered questions.
It was at this stage that Schlumberger (SLB) was approached by Saudi Aramco's drilling optimization team to evaluate the zonal isolation between the Formations Shale A and Sandstone B in Well-A, which was a well from the unconventional resources group. The objective was to assess the zonal isolation with a high level of assurance and provide feedback for obtaining better results in subsequent wells.
The paper showcases the technique applied to assess the well integrity through an integrated holistic approach for the first time in the Middle East that looks all data available rather than being confined to looking up the acoustic logs in isolation that many times provides only part of the answer.