bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation and Determination of Optimal Variables for Increased Oil Recovery Potential of Surfactant Polymer Flooding
Authors: Singh Arunima , Jindal Rohan , Saxena Amit 
Published: November 2020

Abstract
Enhanced oil recovery methods have been largely discussed in the petroleum industry. Many new techniques are being tested to grapple the situation of high recovery with the least expenditure. As the petroleum industry is striving for it, the EOR process of surfactant polymer flooding is quickly gaining traction. However, testing new technologies directly itself is a costly affair. Our study aims at simulating and understanding the effects of surfactant flooding in subsurface conditions using a Fluent module.
The research was conducted to alleviate the inputs of the industry by providing them faster oil recovery while viably dealing with cost-effectiveness. For simulation studies, a 2-D replica of sand packed bed core {8.49 cm×3.66 cm} is created. The core is modeled for porosity and the average permeability. Physio-chemical properties of anionic natural surfactant extracted from Madhuca longifolia {Mahua} oil and PHPA {Partially Hydrolyzed polyacryl amide} polymer has been exclusively used in the simulations. Eulerian multiphase model is used for studying the volume of oil swept out of the core by introducing the water and surfactant + polymer slug. The simulation results were influenced by the control mechanism and parameters like inlet velocity of the fluids and gauge pressure, porosity and permeability of the core sample supported by appropriate boundary conditions. Taking the retarding effects of turbulence, and shear and tear caused on the rocks in the reservoir into consideration an optimum set of values for velocity and pressure are selected for maximal recovery.
The results indicate that with a small change in parameters a huge change in breakthrough point is observed. Breakthrough indicates the starting time for the production of the primary phase present within the core. On plotting an oil volume fraction v/s flow timeline chart we could observe the quantitative dependence of breakthrough time over different variables. The plots suggested that on increasing the conventional velocity 25%, an unexpected high decrease in breakthrough time is observed for the core under consideration. Moreover, a 25% rise in pressure resulted in a substantial increase in the recovery of oil in minimal time. These results show that the velocity has a more significant impact on the breakthrough total recovery of oil in minimal time. Since, the core is a smaller scale representative of a whole reservoir, the recovery of oil is expected to enhance significantly during actual flooding.
The study extends to simulating the flow in varying subsurface conditions as well as on different material reservoirs alleviating our in-depth knowledge of breakthrough behavior within different cores as well. The exhaustive study of parameters on faster breakthrough accedes with the motive of the industry of improved recovery incurring a minimum cost.
Ceramic Sand Screen Design Enhancement Lessons Learnt from Initial Field Installations of through Tubing Applications in Offshore East Malaysia to Improve Well Performance
Authors: Gundemoni Bhargava Ram , Jackson Steven Richard , Zimmermann-Ptacek Johanna , Barth Peter , Idris Khairul Nizam , Yeap Wei Jian , Catherine TangYe Lin 
Published: November 2020

Abstract
Formation sand production is one of the major production challenges in most of the mature fields in Malaysia. Often, failure in primary sand control equipment requires the operators to adopt through-tubing sand screens as a remedial sand control. Current remedial sand control techniques utilizing metallic through tubing sand screens experience rapid wear, forcing the operator to control sand production by beaning down wells and thereby managing sand production at surface, in worst cases wells have to be shut-in. More robust technologies replacing conventional metallic screens are required. For these applications, alternative technology with ceramic sand screens have been deployed to enable higher productivity and offer enhanced resistance against erosion.
Ceramic sand screens passed through a technical qualification process at Petronas and deployed in field applications both in oil and gas producers for through tubing interventions. To date 30 well interventions have been performed in various Petronas assets of Offshore East Malaysia with mixed results. Eight screen failures were observed with longevity ranging from 2.5 days to 15 months of production after installation. On average, ceramic sand screens greatly enhanced productivity return through longer performance than the conventional through tubing metallic screens from previous deployments. However, it was both the intent of product provider and Petronas to further improve Through Tubing Ceramic Sand Screen (TTCSS) performance based on the lessons learned from these failures.
The TTCSS failures were first presented in the paper: SPE 196479 MS published at SPE APOGCE October 2019, Bali, Indonesia which which focused on the failures of these first generation TTCSS screen designs.
This paper describes in more detail the value driven process and collaboration steps between 3M and Petronas to improve TTCSS field performance as a methodology to increase incremental field production to further increase longevity of downhole sand control in these applications. To enable this goal, a root cause analysis process entailed involving tear down investigation, hypothesis of failure characteristics, application review and investigation analysis with tools such as CFD and laboratory testing resulting in the implementation of ceramic sand screen design enhancements to improve performance in further Petronas deployments.
Innovative Analysis Approach for Installation of in Line Tee Structure in S Lay Mode
Authors: Shahyarfar Shahreyar , Kristiani Desy , Sinha Ritesh Kumar 
Published: November 2020

Abstract
Installation of an In-Line Tee Assembly (ILTA) in S-lay mode is a challenging task. Specifically, the ILTA stinger exit process is a susceptible operation due to the risk of overstressing the pipeline and excessive rolling of the ILTA structure. Installation in rough weather with long-period swells makes the task even more challenging as it requires an efficient and robust installation methodology to carry out the operation safely within a limited time window. This paper details the analysis techniques and installation methodology adopted to optimise the ILTA stinger exit process while reducing the associated operational risk.
Analysis of Tubing-Casing Annular Pressure in Early Production Stage in High Temperature High Pressure Wells
Authors: LI Cheng , Guan Zhichuan , Zhang Bo , Cao Lihu , Xu Zhixiong , Xie Junfeng , Liu Hongtao , Lou Erbiao , Zhang Xuesong 
Published: November 2020

Abstract
High annular pressure still happens in tubing-casing annulus (TCA) in early production stage in high temperature high pressure (HTHP) well may due to the thermal expansion of annulus liquid. This pressure will damage the tubing string and casing, besides, it will also have great influence on wellhead and packer. This paper develops numerical method to explain this phenomenon to provide some theoretical guidance for the risk response. Based on the theory of energy transfer in confined space, gas state equation and thetheory of elastic-plastic mechanics, a numerical model is established to calculate the annular pressure in TCA caused by thermal expansion of annulus liquid. Then a wellbore temperature prediction model is established based on the theory of heat transfer through multi-layer thick wall cylinder. By using the model, the trapped annular pressure (TAP) is the decisive parameter to determine the annular pressure. Based on a case well, the influence factors such as reservoir temperature & pressure, setting depth of packer and production rate etc. are analyzed, and the specific properties of TAP in TCA are studied. Referring to the calculation of TAP under the condition of gas-liquid coexistence inside TCA, the influence of gas existing in annulus on the TAP caused by thermal expansion is studied, so as to distinguish it from the continuous TAP caused by channeling flow. The results show that the reservoir temperature has a great influence on the tubing-casing annular pressure.Reason being, in the upward flow process of the production fluid with high temperature, it has transferred a lot of heat radially to the TCA, thus directly improving the TAP. In addition, the design and production stages should be combined to realize the analysis and control of each influencing factor, so as to mitigate the TAP. According to the calculation of the TAP under the condition of gas-liquid coexistence inside TCA, if there is gas in annulus, the TAP will be greatly reduced. Besides, if there is still continuous high pressure in TCA at this time, it means that the wellbore integrity is damaged, and there is gas channeling into TCA, resulting in the generation of continuous TAP. In the field work, the gas also can be injected into annulus to mitigate the TAP actively. This paper builds a model to explain the high annular pressure of TCA. This can help to identify the well integrity. Also, the study on the condition of gas-liquid coexistence in annulus can provides theoretical guidance for mitigating the TAP. This can help engineers get better understanding of well integrity.
Evaluation the Geological Uncertainties to Increase the Benefit of Offshore Project
Authors: Shi Hongfu , Chen Jianbo , He Yifan , Yue Baolin 
Published: November 2020

Abstract
The quality of oil and gas reservoirs, initial production and the recovery factor are important factors affecting the revenue of development projects. Understanding geological potential and risk is of great significance for judging the uncertainty of a project, avoiding risks, and improving project returns. Reservoir depth, sand thickness, connectivity, permeability, porosity, oil viscosity, etc. determine the quality of reservoirs. In addition, well pattern, well type (horizontal or vertical wells), well spacing, reservoir pressure, artificial lifting method, injection fluid and sand wettability play important roles in the final recovery factor. This research takes an oil field in the Bohaibay as an example, and analyzes how to make full use of seismic data, geological data, and drill stem test (DST)data to understand geological uncertainties, to tap underground potentials, and to increase the project revenue, thereby promoting project implementation.
Biocide Chemistries Used in Nitrite Inhibited Closed Loop Cooling Medium at High pH
Authors: Fisher Nicholas , Lehmann Marc , Brunt Steve , Parker Andrew , Barrett Shandelle , Gloyn Mark 
Published: November 2020

AbstractClosed loop cooling medium systems are fundamental systems offshore oil and gas production facilities. Integrity or fouling issues in cooling loops have the potential to limit or jeopardise oil and gas production. Glutaraldehyde and isothiazolone biocides are reported in current literature as being effective chemistries for use in closed cooling mediums. This study showed these biocides initially display good initial effectiveness at high pH. However, the long-term bacterial control is poor due to a lack of persistency. The longer-term biocidal control of glutaraldehyde was far worse than that of isothiazolone in part due to chemical instability at high pH but also due to glutaraldehyde decomposition products presumably providing a food source for bacteria growth. This hypothesis was confirmed by adding elevated levels of bacteria to glutaraldehyde, which had been aged in a nitrite-based corrosion inhibitor solution. Results were compared with the non-traditional biocides, biguanide and 4,4-dimethyl-oxazolidine for cooling medium treated with a nitrite based corrosion inhibitor. Both biguanide and 4,4-dimethyl-oxazolidine showed significantly greater persistency compared to traditional closed loop biocides.
Unlocking Potential in a Thinly Laminated Reservoir by Integrating Electric Logs, Images and Core Analysis: First Case Study in Vietnam
Authors: Nguyen Pham Kim Thien , Doan Dung Thi , Nguyen The Dac , Lee Samie , Nguyen Luc Quoc , Ngo Hai Huu , Ngo Quan Anh , Khuc Giang Hong , Tran Hung Ngoc 
Published: November 2020

AbstractThin beds are capable of yielding a reasonable amount of hydrocarbon if discovered and evaluated. However, most thin beds are bypassed due to the low vertical resolution of conventional logging tools, which results in significant underestimation of hydrocarbon in the sedimentary unit. To better characterize thin beds and maximize reservoir potential in the thinly bedded reservoirs, a novel methodology has been developed that integrates resistivity images and core data with standard logs.First, lamination and thin-bed intervals were identified with the help of borehole images and mud logs. Also, high-resolution shallow resistivity from the images was used to output a set of high-resolution logs with a log resolution enhancement technique. This set represents the true layer property and was applied in petrophysical analysis incorporating core study to yield accurate estimations of porosity, water saturation, and permeability. A saturation height function was built from special core analysis (SCAL) to provide an independent saturation estimate for calibrating the petrophysical model. The Thomas-Stieber method, a well-known method for detecting and quantifying laminated sand-shale, was also referenced.This methodology was applied in the evaluation of five gas wells producing from the same formation. The key well with images, core, and electric logs was used to build the petrophysical and saturation height models. The results show good agreement in estimation of water saturation between independent techniques in the key well and hence demonstrate the value of this technique. The model was propagated to other wells in the same field, and this again showed the validity of the methodology with good agreement in the result between different techniques. The success of the study demonstrates how an integrated thin-bed evaluation model can provide a more definitive representation of thinly bedded sands in terms of their volumes in net sand, sand porosity, and hydrocarbon in place. The methodology yielded considerable improved estimation of hydrocarbons in place compared to the evaluation using only standard resolution measurements. In the thin-bed intervals in the target reservoir, the net thickness increases more than 50% in comparison to the estimation with standard logs.The improvement in formation evaluation in thin-bed reservoirs resulting from this methodology provides a comprehensive picture of the field reserve that not only helps in the new production plan as input into static and dynamic reservoir models but also leads to effective strategies in field development and management.
A Discussion on Wet-Gas Meter Performance Under Field Conditions
Authors: Chinello Gabriele , Pinguet Bruno G. 
Published: November 2020

Abstract
Venturi tubes are one of the most common types of flow measurement devices used worldwide for wet-gas conditions as they are simple, well-established technology, robust, and cost-effective flowmeters. They also form the main component in most of the commercial multiphase flowmeters.
An extensive research effort has been spent over the past 60 years to develop robust correlations for the use of Venturi flowmeters to correct the over-reading due to the unexpected or not the presence of liquid in the gas phase; this led to the writing of the ISO 2012. The uncertainty quoted for using this correlation is claimed to be between ±2.5% to ±3% and was based on extremely low uncertainties input parameters; in other words, the correlation was developed using data from flow laboratories with well-characterized fluids. However, in the field conditions, the input parameters uncertainty, which contributes to overall gas and liquid flow rate measurements, could be substantially higher.
When using Venturi flowmeters for wet-gas flows and looking at the actual performance based on the uncertainty of all input parameters, the uncertainties quoted are often from testing in flow measurement facilities with well-defined fluid properties, and they are always at line conditions or without any additional fluid properties uncertainties, however, in the field, the uncertainties from the meters can be substantially different and much higher.
The purpose of this paper is to highlight this statement to compensate for well-defined over/under-readings, and not forgetting that the uncertainty of the input parameters must be considered to state the correct performance. This is often overlooked.
Furthermore, the uncertainty from the correlation equations is used as the total uncertainty on the wet-gas flowmeter performance, but this over-simplifies other significant uncertainty contributions and can result in considerable measurement discrepancies. These discrepancies can critically affect the allocation and lead to potential disputes between different production platforms or more critical in custody transfer applications.
Wet-gas business is growing around the world, particularly in the Asia Pacific and the Middle East, where many installations are using such Venturi equipment and proper performance, or uncertainties should be stated. This paper will provide practical information and recommendations about meter performance.
Deep Shear Wave Imaging Helps Making Sidetrack Decisions in Fracture-Cave Carbonate Reservoir
Authors: Wang Chenglong , Xiao Chengwen , Xin Yi , Duan Wenxing , Zhang Chengsen , Zeng Xianlei , Han Dongchun 
Published: November 2020

Abstract
The development of a vuggy carbonate reservoir is very challenging because of low porosity and permeability in the matrix. Natural fractures and caves play a dominate role in this kind of reservoir. Production of these reservoirs highly depend on whither fracture-cave cubes are successfully targeted. Consequently, it is very important to determine the entire picture of the natural fracture-cave systems near to and away from the borehole.
The traditional ways to evaluate fractures or caves in acoustic logging are Stoneley permeability, azimuthal shear-wave anisotropy analysis, along with resistivity image logging. However, the depth of investigation of all these methods is limited from less than one inch to a few feet from the borehole wall. Deep shear wave imaging is a new way to image the reflectors offside the borehole. This imaging technique uses the shear body wave that is reflected back to the borehole by the acoustic impendence differences caused by planar features (such as fractures and caves) in the formation. After suppression of the direct wave mode and migration of the reflected wave, it gives a picture of the fracture system around the borehole. In addition, it has a much deeper depth of investigation, which depends on the shear slowness and attenuation of the formation. Normally, in carbonate formations with shear slowness at 80 ft/us, deep shear wave imaging manages to see reflectors as far as 100 ft from the borehole. Compared to methods using monopole wave to imaging reflectors, deep shear-wave imaging has another important feature. Because it is using cross-dipole waveforms, which is azimuthally sensitive, therefore, the deep shear wave imaging can provide the azimuthal of the fractures—usually very important information for penetration and stimulation of the formation, also the possible locations of the reflectors are defined to help making sidetrack drilling decisions.
This paper describes a case study of deep shear-wave imaging application in a vuggy carbonate reservoir in Tarim basin. Conventional pertrophsical interpretation does not show good signatures in the borehole. Deep shear-wave imaging analysis shows two major reflectors away from the borehole. Combining seismic attributes and inversion analysis, the caves offside the borehole are located, helping the operator to make sidetrack decision. The sidetrack is successfully drilled into the cave. The value of deep shear-wave imaging is to provide a further insight of the natural fracture and cave system around the borehole, which cannot be achieved by conventional petrophysical methods.
A New Method of Bit Selection using Drill Bit Images
Authors: Manuel Yasshene ann , Momeni Mohammadsadegh , Hamdi Zakaria , Zivar Davood 
Published: November 2020

Abstract
Research on bit selection in rotary drilling work and its relationship with different geological, operational parameters and bit type demands an improved procedure to select the best bit. Most researchers and studies done currently have failed to account for the bit shape and type among other features which have significance in bit selection and ROP prediction. Thus, this thesis demonstrates a pathway where bits can be easily photographed and have its features extracted in numerical form for the ROP prediction. Several objectives were put forth including extracting drill bit features from 18 different bit images, each with a unique IADC bit code in combination with drilling parameters from previous bit records to effectively create a model to predict the ROP in order to create a new method for bit selection. After pre-processing the images, 13 unique features were selected; area, perimeter, major and minor axis length, eccentricity, equivalent diameter, convex area, orientation, contrast, homogeneity and energy which were compressed into two principal components in order to simplify the prediction stage. Using the multiple linear regression, ROP was predicted with R2 and MSE of 0.47and 3.325 respectively. Using ANN showed a large improvement in R2 and MSE values where the values were 0.08579 and 0.9347 respectively. The last method was using PSO to train the ANN for a better ROP prediction. Better R2 and MSE combinations were evident giving values of 0.9434 and 0.03918 respectively where the input data consisted of both drilling parameters and bit image features.