bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Chelating Agent EOR Solutions for Carbonate Reservoirs
Authors: Hassan Amjed M. , Al-Hashim Hasan S. 
Published: October 2018

Abstract
This paper presents a novel approach for optimizing the chemical concentrations for EOR applications in carbonate reservoirs characterized by high salinity and high temperature. The chelating agent fluid systems used in this study were prepared using undiluted seawater. The approach is found to be a cost effective and resulted in very significant incremental oil recovery when applied after the conventional seawater-flooding, and could be used as an alternative to the conventional and low salinity waterflooding. The used chemicals are environmental friendly, stable at high salinity and high temperature and do not required additional chemical additives.
A comparison of two chelating agent EOR solutions having concentrations ranging from 3 to 10 wt.% prepared using undiluted Arabian Gulf seawater and used in sequential coreflooding tests to identify the best chelating agent solution and its optimum concentration for getting the highest incremental oil recovery after conventional seawater flooding with a minimum impact on rock integrity. The impact of fluid concentrations and pH on oil recovery and permeability improvements was analyzed, and the productivity index of each solution at the end of each injection sequence has been evaluated. Finally, a chemical cost evaluation study was conducted to identify the optimum chemical concentration that minimize the usage of chelating agents and maximize the oil recovery.
Laboratory Study of CO2 Foam for Enhanced Oil Recovery: Advanced Screening, Optimization, and Evaluation
Authors: Ahmed Shehzad , Elraies Khaled Abdalla , Hashmet Muhammad Rehan , Hanamartani Alvinda Sri , Bt Mohd Shafian Siti Rohaida 
Published: October 2018

AbstractCO2 foam has been proposed as mobility control agent to overcome various limitation of CO2 injection such as viscous fingering, gravitational override and reservoir heterogeneities which lead to poor sweep efficiency. In this study, CO2 foam formulation was screened and optimized under HPHT conditions to achieve strong foam which results in high oil recovery. For this purpose, different surfactant formulations were prepared in brine with fixed salinity. The stability of bulk foam was measured using FoamScan (Teclis) in the presence of Malaysian crude oil. Whereas, a HPHT foam rheometer was used to perform advanced level screening and optimization at different foam qualities and shear rates. The best foam formulation obtained was then evaluated in core flooding experiment using Berea sandstone (250mD) by co-injection mode under HPHT condition. Among various formulated surfactant mixtures, the combination of alpha olefin sulfonate (AOS) and betaine with specific composition was able to generate strong supercritical CO2 foam at different shear rates under reservoir conditions. Foam rheology results showed that 80% foam quality as the optimum condition for having a high apparent viscosity. Results from co-injection experiments in porous media show that the designed CO2 foam has successfully improved the cumulative oil recovery from 57.58% to 74.08%.
Using Managed Pressure Drilling to Reduce Stuck Pipe Problem
Authors: Alkamil Ethar H. , Abbood Husam R. , Flori Ralph E. , Medley George , Nauduri Sagar , Alsaba Mortadha 
Published: October 2018

Abstract
Differences between mud pressure in a wellbore and pore pressure in high permeability rocks can lead to differential sticking, particularly when drilling deviated wells and encountering mud losses. Several solutions, all challenging, can be used to address this problem, where the conventional mitigation method of managing the mud weight (MW) is often used. However, managed pressure drilling (MPD) offers a promising solution with a positive risk-adjusted cost and other benefits.
Wells in the E oilfield in southern Iraq are typically drilled overbalanced and therefore often experience a high percentage of non-productive time (NPT) due to differential sticking. This study evaluates the feasibility of using MPD to optimize the drilling process by decreasing the mud weight while applying the required surface pressure to achieve the target bottom hole pressure (BHP). A simulation software, which uses different mud weights to determine the required choke surface backpressure (SBP) to achieve the targeted equivalent circulation density (ECD).
Historically, differential sticking has not been a primary driver to justify MPD. However, MPD offers more dynamic and rapid wellbore pressure control by adjusting SBP applied to the annulus for a given MW, and can actually decrease the risk of differential sticking. Instead of shifting MW or changing other drilling parameters, MPD adjusts the required ECD and/or equivalent static density (ESD) based on the formation pore pressure gradient. Additionally, MPD directly lowers SBP in the event of mud losses due to high ECD/ESD to decrease the BHP without the need to reduce MW.
This paper discusses the application of using a hydraulic simulation software to model the drilling development plan. The software optimizes MW and SBP while drilling, making pipe connections, and completing the well. Furthermore, it discusses the sensitivity effects of each parameter on wellbore pressure and provides guidelines for managing pressure by adjusting these variables.
IIncreasing ANN Accuracy, by Improving the Training Dataset Criteria. Case Study: Identify the Formation Density from The Drilling Surface Parameters in Real-Time
Authors: Al Gharbi Salem , Liao Qinzhuo , Elkatatny Salaheldin , Abdulraheem Abdulazeez 
Published: October 2018

Abstract

Objective
The objective of this paper is to introduce a new methodology to increase the accuracy of the Artificial Neural Network (ANN) by improving the selection criteria of training dataset. Such approach will result in faster and better prediction models.

Methods and Procedures
The strength of ANN is its capability to find a correlation between input and output. This correlation consists of several connections called neurons that represent coefficients and weight factors. Developing such neurons requires a large number of internal iterations and data processing, which include a lot of randomness, starting from identifying the training and testing dataset. This paper introduces a methodology that ensures the training dataset in ANN has a wide range and a small size, which improves the training dataset criteria and leads to results that are more accurate.

Results and Conclusions
A case study is conducted to identify the formation density from the drilling surface parameters. Several ANN models, including the proposed method, are constructed on the same dataset. Results show that the new methodology can be 85% faster and 18% more accurate than the traditional ANN on average. It is as accurate as the best traditional ANN, while the former is 90% faster than the latter.

Novel and Additive Information
The novelty in this approach is its methodology which results in much faster ANN development with higher accuracy. It is worth mentioning that the new methodology is based on 50% training dataset, which reduces the training dataset size up to 25% compared to the traditional methods.
Effect of the Type of Fracturing Fluid on the Breakdown Pressure of Tight Sandstone Rocks
Authors: Muqtadir Arqam , Elkatatny Salaheldin , Mahmoud Mohammed , Abdulraheem Abdulazeez , Gomaa Ahmed 
Published: October 2018

Abstract
Hydraulic fracturing is performed to enhance production in reservoirs with low permeability. It's an effective technique but there are still several uncertainties associated in its implementation. One of the uncertainties is the dependence of breakdown pressure on the type of fracturing fluid used. The objective of this paper is to perform an experimental study to determine the role of fracturing fluid on the breakdown pressure of tight sandstone rocks.
The dimensions of the samples are 2 in. (diameter) by 2 in. (length). A hole of 0.25-in. in diameter and 0.75-in. length is drilled on one face of each core through which the fracturing fluid is pumped. A strong power relation between the viscosity of the fracturing fluid and breakdown pressure was seen. As the viscosity increased, the breakdown pressure increased significantly. Computed Tomography (CT) scan showed that the direction of fracture is along the bedding plane. As the viscosity increased, the fracture width and height increased. For most tests, the fractures created were bi-wing fractures. Some single wing fractures were created due to deformities in the borehole.
A Hybrid Integrated Compositional Reservoir Simulator Coupling Machine Learning and Hard Computing Protocols
Authors: Putcha Venkataramana B. , Ertekin Turgay 
Published: October 2018

Abstract
The compositional representation of a petroleum system offers a greater detail in the phase equilibria calculations when compared to the black-oil approach. However, the slow and iterative nature of the numerical EOS based flash calculation is the primary drawback of compositional modeling. In this work we propose a hybrid model coupling machine learning and hard computing algorithms to accelerate the coupled wellbore hydraulic and numerical reservoir simulation processes. In this work, a robust compositional articificial neural network (ANN) based wellbore hydraulics tool is successfully coupled with a numerical compositional reservoir simulation model. The proposed hybrid simulation protocol is validated by comparing the results generated from the coupled ANN-numerical model against the fully numerical model, and a commercial compositional numerical simulation software package using a single-phase liquid, a single-phase gas and a two-phase liquid/gas case. Also, a comprehensive gas lift case study is discussed to compare the results and computational efficacy between the coupled ANN- numerical model and the full numerical model. It is observed that the mean deviation in the total oil production of the hybrid simulation protocol when compared to the full numerical model under the entire range of gas lift injection rates is approximately 5%, while the computational time taken by the coupled ANN-numerical model is 160 times less than the corresponding full numerical model. The proposed model can be employed as a practical gas lift optimization tool. More importantly, it gives the opportunity for simultaneously exploiting the strengths of both hard-computing and soft-computing algorithms.
Chemical Enhanced Oil Recovery with Water Soluble Poly Ionic Liquids in Carbonate Reservoirs
Authors: Alhussinan Saud N. , Alyami Hamdan Q. , Alqahtani Naif B. , AlQuraishi Abdulrahman A. 
Published: October 2018

Abstract
Recovering oil from carbonate reservoirs by waterflooding is often ineffective due to the combination of ineffective sweep and the originally oil-wet nature of that rocks. Ionic liquid monomers and polymers have recently attracted attention as chemical agents for enhanced oil recovery. 2-acrylamido-2- methylpropane sulfonic acid copolymer with methacrylic acid (AMPSA/MAA) diluted in sea water at 3000 ppm was previously screened among other polyionic liquids (PILs) at different concentrations (Abdullah et. al, 2017) and proved to be the most effective enhanced oil recovery chemical. The PIL AMPSA/MAA was tested with sandstone and proved efficient on enhancing oil recovery. In this study, we extend the work to explore the efficiency of such PIL on carbonates.
A post-secondary water flooding was conducted and an incremental tertiary recovery of 6% original oil in place (OOIP) corresponding to 12% residual oil in place (ROIP) was obtained indicating the efficiency of the AMPSA/MAA PIL. This carbonate recovery compares to 10% OOIP in sandstone as reported in previous study (Abdullah et. al, 2017). This difference can be attributed to the low permeability characterizing the carbonate sample used in this work in comparison to the sandstone tested earlier. Seawater-crude oil Interfacial tension and contact angle measurements on carbonate substrate were performed at elevated temperature and pressure to investigate the possible recovery mechanisms. Interfacial tension (IFT) resulted in insignificant IFT drop. On the other hand, contact angle measurements confirmed wettability alteration towards more water wet state indicating it as the main recovery mechanism in carbonates.
Key Factors in Managed Pressure Cementing for Deep Water
Authors: De La Cruz Sasso Alejandro , Paredes Jose Luis , Puerto Gustavo , Bedoya Jorge 
Published: October 2018

Abstract
Both minimizing risks and providing adequate barriers are targets during cementing operations. This paper discusses key factors to consider during the design and execution of managed pressure cementing (MPC) operations in deep water. These factors are the result of important best practices identified for dependable results. The key learnings from different applications can provide more reliable MPC applications while minimizing associated risks.
Accurate data collection is necessary to understand cementing simulation results. The process discussed used pressure while drilling (PWD) to collect data, such as equivalent circulating density (ECD) and equivalent static density (ESD). This data, in combination with data generated at the surface from the annulus, and a fit-for-purpose temperature profile were then used in a state-of-the-art software to help replicate actual drilling wellbore conditions and enable model calibration for the cement operation. Using a calibrated model, MPC analysis performed during the planning stage was updated to help predict different MPC scenarios.
Cementing simulation results should provide the pumping schedule [e.g., volume in, volume out, planned surface backpressure (SBP), contingency SBP, and critical events along the schedule]. During the planning phase, the simulation results helped address misconceptions regarding MPC operations (e.g., rate out equal to rate in) and the SBP interpretation by accounting for surface equipment setup. The design accuracy was confirmed during the MPC application. Two cement operations were completed, with minor deviations that were addressed properly as a result of the analysis and risk assessment previously performed. Variable sensitivity (temperature, mud compressibility properties, fluids rheology, geometries downhole and at surface, MPD choke limitations) was important to maintaining SBP within the operational window to avoid influxes or losses. This paper discusses recommendations to provide guidelines for deepwater MPC design and execution.
MPC operations in deepwater environments have a few applications within the oil and gas industry. This paper provides important information that can help improve this method and provide optimal design modeling and analysis. Additionally presented are key factors for zonal isolation in deep water engineering and operative considerations for improvement of this unconventional method.
Polyoxyethylene Ether Sulfate Surfactant for SP Flooding in High Temperature, High Salinity Reservoirs
Authors: Hongyan Cai , Qun Zhang , Youyi Zhu , Zhaohui Zhou , Hongzhuang Wang , Jianfeng Sun 
Published: October 2018

Abstract
Chemical combination flooding technique (CCF) meets great technical challenges in High temperature, High salinity (HTHS) reservoir. The requirements on thermal stability, salt tolerance, solubility and interfacial activity of surfactant greatly narrow the selection scope of chemical agent. Conventional anionic surfactant heavy alkyl benzyl sulfonate (HABS), petroleum sulfonate (PS) or nonionic surfactant Ninol are not suitable due to drawbacks of solubility and stability.
A novel extended surfactant alkyl polyoxyethylene Ether Sulfate (AES) was developed for CCF in HTHS reservoir. Compatibility with reservoir conditions and other surfactants of prepared AES surfactant were tested. Interfacial activity and phase behavior of related formulations were studied. In addition, the wettability alteration capability of AES was also investigated.
The experimental results demonstrate surfactant AES has very strong salt tolerance capability, showing a clear solution at salinity as high as 200,000 mg/L. As a comparison, conventional surfactants HABS and PS have poor solubility under high salinity environment. The addition of AES in surfactant solution greatly improves solubility of anionic surfactants HABS and PS. At the same time, interfacial tension (IFT) of these combined formulations is also remarkably decreased to ultralow magnitude (10−3 mN/m or lower). Electrolyte screening in oil/water phase behavior test demonstrates gradual transfer of phase type from Winsor I, Winsor III to Winsor II with the increase of salt concentration from 0 to 200,000 mg/L. Contact angle of 0.20% AES solution on modified silicon film decreases with the increase of electrolyte content.
The developed extended sulfate surfactant shows unique advantages under HTHS reservoir. The combined AES and HABS formulation makes it possible for the application of conventional anionic surfactant in HTHS conditions.
Experimental Study on a Novel Thickened Supercritical CO2 System and its EOR Performance in Low Permeability Reservoir
Authors: Sun Xin , Dai Caili , Sun Yongpeng , Zhao Mingwei , Wang Xin , Guan Baoshan , Liu Ping , Fan Xiqun 
Published: October 2018

Abstract
Due to the strong mobility and energizing effect, CO2 can be injected into reservoir as a displacement agent to increase oil production in low permeability reservoir. However, low viscosity of pure supercritical CO2 (SC-CO2) resulted poor sweep efficiency. Therefore, it is essential to thicken SC-CO2 during displacement in low permeability reservoir.
In this study, a novel thickened SC-CO2 system was developed. Its viscosity with different thickener was measured by HP/HT core flooding setup. To explain the EOR mechanism, the oil saturation and sweep area in low permeability core by pure/thickened SC-CO2 flooding system was monitored through NMR on time. Furthermore, the effect of thickener concentration and flooding rate were investigated in detail, respectively.
With the HP/HT core flooding setup, the viscosity of thickened SC-CO2 system can reach to over 0.20 mPa·s while it is 0.04 mPa·s for pure SC-CO2. Increased thickener content leads to enlarged fluid viscosity within system. The increased viscosity resulted in longer breakthrough time of thickened system. After breakthrough, the continuous injection of thickened SC-CO2 system further decreases the remaining oil saturation much more obvious than that with pure SC-CO2. By analyzing the real-time distribution from T2 spectra and NMR imaging, the thickened system can involve the smaller pores which the pure SC-CO2 cannot get through. Meanwhile, thickened system can form a near piston displacement while pure system has an obvious viscous fluid advantage channel. The combination of these two processes results in higher sweep efficiency with thickened SC-CO2. Furthermore, the effect of thickener concentration and flooding rate were shown in detail. The results showed that higher thickener concentration and lower flooding rate all corresponded to higher sweep efficiency.
Due to the high injection pressure of water flooding and low sweep efficiency of pure CO2 flooding, thickened SC-CO2 flooding is proved to be a more applicable flooding agent to develop low permeability reservoir even tight oil. This study will provide new thoughts and insights mechanism about how to develop low permeability reservoir more efficiently and economically.
Enhancing Carbon Dioxide Flooding Sweep Efficiency in High Permeability Hydrocarbon Reservoirs Using Micro-Particle Gels
Authors: Fakher Sherif M. , Imqam Abdulmohsin , Bai Baojun 
Published: October 2018

Abstract
Carbon dioxide (CO2) flooding is one of the most applied enhanced oil recovery processes nowadays. Conformance problems such as reservoir heterogeneity can diminish the amount of hydrocarbons produced using CO2 flooding, thus resulting in a lower than expected oil recovery. This research studies the ability of a chemical conformance control agent referred to as micro-sized particle gel (PPG) to improve CO2 sweep efficiency in hydrocarbon reservoirs thus increasing oil recovery. Several core flooding experiments were conducted using a high permeability sand pack model. The factors that were examined include gel strength, varied using PPG swollen in 0.05, 0.25, 1, and 10 wt% NaCl, gel concentration using 0.5, and 2 wt% gel, presence of residual oil, and CO2 injection flow rate using flow rates of 2, 4, 6, and 8 ml/min. The ability of PPG to improve CO2 conformance was quantified using the PPG's plugging efficiency improvement. PPG with low gel strength resulted in poor CO2 conformance, but when gel strength increased above approximately 1000 Pascal, a much better CO2 conformance was observed. Higher gel concentrations resulted in an improved plugging efficiency; however, the injection of the particles took a longer time. Increasing the CO2 injection flow rate resulted in a decreased plugging efficiency. Residual oil reduced the gel strength and thus the sweep efficiency was reduced. To the authors' knowledge, no detailed core flooding experiments have been conducted to study the PPG's ability to improve CO2 conformance thus making this a very important and insightful research on the utilization of PPG during CO2 flooding. By identifying, studying and analyzing the factors that impact PPG's ability to improve CO2 conformance, novel PPG technologies can be developed and utilized in the industry to improve CO2 flooding and increase oil recovery.