bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study on Nanoparticle Stabilized Emulsions for Chemical Flooding Enhanced Oil Recovery
Authors: Zhu Youyi , Yu Peng , Fan Jian 
Published: March 2021

Abstract
Chemical flooding is one of enhanced oil recovery (EOR) methods. The primary mechanism of EOR of chemical flooding is interfacial tension reduction, mobility ratio improvement and wettability changes. Recent studies showed that enhancing emulsification performance was beneficial to improve oil displacement efficiency. The formation of Pickering emulsion by nanoparticles could greatly improve the emulsifying performance. Using nanoparticles stabilized emulsions for chemical EOR application is a novel method.
In this study, six different types of nanoparticles were selected, including hydrophilic nano silica, modified nano silica, carbon nanotubes and bentonite, etc. The nanoparticle combine with petroleum sulfonate could form a stable emulsion. Particle wettability were measured by using contact angle measurement (OCA20). Emulsifying intensity index was measured for different nanoparticle-stabilized emulsions. The mechanisms of nanoparticle-stabilized emulsions and relationship between emulsion stability have been investigated. The influence of dispersant on nanoparticle-stabilized emulsions also has been investigated.
Nanoparticles mainly play a role in improving the stability of emulsions while surfactant play a major role in enhancing the emulsifying dispersion. The wettability of solid particles was one of the most important factors that affects the stability of emulsions. Partial hydrophobic nanoparticles were much easier to form stable emulsions than hydrophilic nanoparticles. Nanoparticles could form a three-dimensional network structure, thereby the stability of the emulsion was improved. Use of surfactant to disperse nanoparticles could further improve the emulsion stability. Finally, three nanoparticles stabilized emulsion formulations were developed for chemical flooding EOR.
Nanoparticle-stabilized emulsions could improve oil displacement efficiency in chemical combination flooding. This research was used to optimize chemical combination flooding formulation and has a guidance function for application of nanoparticles in chemical flooding EOR.
Assessing the Impact of Shallow Gas Hydrate Dissociation on Structural Integrity in Deepwater Wells
Authors: Suryanarayana P. V. , Bogdanovic Miodrag , Thavaras Pathy Kuhanesapathy , Paimin M. Razali 
Published: March 2021

Abstract
Shallow gas hydrate zones are present in some deepwater fields. During production, the shallow hydrates may dissociate due to heat-up of the near wellbore formation, which can extend radially to several meters from the wellbore. This can compromise structural integrity of the well (particularly structural strings), cause subsidence, and impact subsea equipment installations. This problem is well known, and has been addressed in the literature. An enthalpy-based transient thermal simulation is required to determine the dissociation front. Further, post-dissociation formation mechanics and well integrity assessment are complex, requiring numerical approaches such as Finite Element Analyses. In this paper, we present an approach that allows a preliminary assessment of the severity of the impact of dissociation on well integrity, so that a more complex assessment may be undertaken only for severe situations. The main objectives of the preliminary assessment are: to model hydrate dissociation front and the radial extent of dissociation as a function of depth; evaluate response of formation to this dissociation; analyze mechanical response of the well to the modified mechanical properties within dissociated zone; and confirm well integrity. The paper describes the approach, and introduces two thermal metrics to assess the likely severity of the integrity impact of hydrate dissociation. Using these metrics, the need for a more detailed analysis can be determined. Further, load analysis and integrity checks of the structural strings and the wellhead that can be performed as part of the preliminary assessment are discussed. An illustrative example is used to demonstrate the approach.
Integrated Gas Source Analysis for Wells with Sustained Casing Pressure: A Case Study from Sour Gas Fields in Sichuan Basin, China
Authors: Su San , Vo Minh , Jia Changqing , Yuan Jianbo , Zhang Junliang , Zhang Qiang 
Published: March 2021

Abstract
Sustained casing pressures are observed in many gas-field wells in Sichuan Basin. The presence of corrosive sour gas i.e. H2S and/or CO2 in the annulus, coupling with the none corrosion-resistant alloy (CRA) casing materials, may damage the casing and lead to loss of containment, which could be a disaster to the asset, local communities, and the environment. It is thus of significance to identify the gas source for the wells with sustainable casing pressure.
Several wells in the study area were identified as risky wells with an initial risk screening exercise. The further determination of gas source, either sweet gas in the shallow formation or sour gas in the deep formation, would have a big impact on the risk levels and subsequent mitigation plans. An integrated forensic study was conducted to investigate the gas source, including annulus gas composition analysis, isotope fingerprinting, casing pressure profile construction and analysis, casing pressure bleed-off and build-up operations, cement quality evaluation, temperature and noise logging analysis, etc.
In this paper, the integration of various tools and data enabled a quality diagnosis of the gas source for two risky wells. It is believed the most likely gas source for the first well is from the shallow sweet gas formation. The risk was then revised down to Low-Medium, and the well was temporarily plugged and abandoned (P&A) for future use. For the second well, the gas source is confirmed from the deep sour gas formation, and thus the risk is relatively high. A permanent P&A program was performed, and both the sour and sweet gas layers were successfully isolated per the standard barrier requirement to protect community and environment.
In conclusion, most of the subsurface measurements have limitations and thus result in the imperfect data. The key to solving the subsurface puzzle is to consolidate all the perceptions together after reviewing the problem from different angles. The integration of multiple types of data in this study, including geological and engineering data, static and dynamic measurements, etc., allows a mostly likely interpretation of gas source to support the key operations decision. The results from integrated data analysis have helped improve the risk assessment, guide the development of risk mitigation plans and operations procedures to eliminate and/or reduce the risk of these wells and secure the subsurface integrity.
Pore Pressure Estimation by Using Machine Learning Model
Authors: Booncharoen Pichita , Rinsiri Thananya , Paiboon Pakawat , Karnbanjob Supaporn , Ackagosol Sonchawan , Chaiwan Prateep , Sapsomboon Ouraiwan 
Published: March 2021

Abstract
In the past few years, over hundreds of wells were drilled in Gulf of Thailand, had faced with the depletion and lost circulation issues resulted from a lack of pressure data. A prior research of reservoir depletion pressure (Fangming, 2009) in oil field, China was obtained from multivariate statistic and regression by using density and neutron porosity log curves in logging-while-drilling data. However, the relative errors are 7.5% from the actual formation pressure. Thus, there are several latent variables in the model like drilling parameters (Rehm, 1971) which part of formation pressure. From 2018 initiative model in Satun-Funan, the classification model was obtained by using mud gas, porosity, water saturation, net sand thickness, net-hydrocarbon-pore thickness and neutron-density separation. However, the limitation is drilling parameters could not account by classifier, and accurate only original pressure category. So, this study has expanded scope to include other reservoir properties and drilling parameters then applied with machine learning on offset well dataset by using three regressors such quantile, ridge and XGBoost regressors. The pore pressure estimation model aims to improve efficiency for making decision in execution phase, increasing confidence in perforation strategy. The model parameters, pay thickness, porosity, water saturation, original pressure from local pressure profile and total gas show are accounted into this model. As of regressor assumption, some facts are conducted to logarithm and perform 2nd polynomial feature for model flexibility. There are three steps for building model such as data manipulation, analysis and deployment. Two purposes of pressure prediction impact algorithm selection, for operational phase, quantile regressor is implemented to provide conservative prediction while Ridge or XGBoost regressors are alternatives for perforation strategy, provide mid case result of pressure prediction. Overall model performance was measured using root mean square error (RMSE) on train & test dataset which show approximately 1.2 and 1.5 ppg range of accuracy respectively from total 12 drilling projects in Pattani basin. Overall model fitting is within reasonable range of generalization capacity to apply with unknown data point (test set). The future model will continue to improve accuracy and manage imbalanced dataset between original pressure and depleted sands.
Smart Facility Advanced Separator
Authors: Watcharasing Sunisa , Lamsunthia Surachai , Phuphuak Yupin , Malatip Atipong , Pratumwal Yotsakorn , Kiattikomol Prapoj 
Published: March 2021

Abstract
The objective of this work was to develop the prototype unit of Advanced Production Separator (APS) for simultaneous removal of sand, out from production separator. APS unit was fabricated with size Diameter × Length: 1 × 2 m. System controlling of rotational blades impellers was installed at the bottom section of separator, to prevent sand accumulation at bottom of separator while on-service. This facility will help in preventing of sand accumulation in the separator, leading to minimize period of separator downtime during annual maintenance period, and allowing more working volume for open fluid reservoir to gas-oil phase production separator. Moreover, this will minimize working period for worker going inside the separator for sand clean-out, as a concern of working in the confine space.
The optimum conditions for separation of sand and crude oil will be examined, with Computational Fluid Dynamics (CFD) model simulation to observe hydrodynamic flow, relating the experimental conditions. The effects of size of 1) Imperller shapes (model A, B, and C), and 2) Rotational speed of impellers (0, 50, 100, 150, and 200 rpm) were investigated to determine the optimal conditions for APS system.
In this work, experimental test run result were compared with CFD simulation result. The optimum conditions for prototype APS unit (800 Litres capacity) is Fan C impeller shape for 5 items, and rotation speed for 150 rpm. This result shows the percentage of sand removal reaching to about 70%. The highest amount of sand in water outlet was found at this optimal condition, corresponding with the small part of sand dune at the bottom of the separator after impellers were driving sand to the outlet channel. From the test run, it was found that experimental results, and CFD simulation are consistent. CFD simulation result can be applied as a first screening to forecast sand removal pattern.
This research illustrate the alternative novel solution for solving sand production accumulation problem in production separator, by instantly clear sand out while crude oil operation was on-going. In the future phase, CFD simulation will be further used as a first step for predicting result before separator scale-up. Separator will be experimented with 4-phases (oil, water, gas, and sand), and further expand for 4X of the original size to see an effect of scale-up. Aim to unlock high potential field, by reducing downtime of the separation during sand cleaning, and providing more working volume of separator after sand was removed out from self-cleaning separator.
Full Wavefield Redatuming: Accurate Velocity Modelling for Imaging Beneath Complex Overburden
Authors: Dzulkefli Farah Syazana , Xin Kefeng , Ghazali Ahmad Riza , Qiang Guo , Alkhalifah Tariq 
Published: March 2021

Abstract
Salt is known for having a generally low density and higher velocity compared with the surrounding rock layers which causes the energy to scatter once the seismic wavefield hits the salt body and relatively less energy is transmitted through the salt to the deeper subsurface. As a result, most of imaging approaches are unable to image the base of the salt and the reservoir below the salt. Even the velocity model building such as FWI often fails to illuminate the deeper parts of salt area. In this paper, we show that Full Wavefield Redatuming (FWR) is used to retrieved and enhance the seismic data below the salt area, leading to a better seismic image quality and allowing us to focus on updating the velocity in target area below the salt. However, this redatuming approach requires a good overburden velocity model to retrieved good redatumed data. Thus, by using synthetic SEAM model, our objective is to study on the accuracy of the overburden velocity model required for imaging beneath complex overburden. The results show that the kinematic components of wave propagation are preserved through redatuming even with heavily smoothed overburden velocity model.
Qualification and Application of All Electric and Topside Less Subsea Multiphase Pump Technology in Subsea Factory Mission to Minimise the Life Cycle Cost
Authors: Ilangovan Karthik , Dindi Mazlan , Fuglesang Alexander , Van Der Rest Bastiaen 
Published: March 2021

Abstract
In recent years, various operating companies have been working on the processes of "Simplification, Standardization, Automation, Digitalization, and Optimization in several elements". To achieve this, there are tremendous subsea technology developments going on all over the world in many areas such as; design in terms of size and weight, improvement in reliability, advanced materials, flow assurance, digital tools, real time condition monitoring and control, installation and operation.
The development of Subsea technology continues to be an important part of subsea field development projects to reduce the life cycle costs, increase recovery, provide solution to long tieback problems and challenges. PETRONAS ("the Company") is pursuing an Upstream Life Cycle Cost (CAPEX/OPEX) reduction approach under the Facilities of Future (FOF) program and mission called "Subsea Factory". The FOF target is to reduce Upstream life cycle cost by 40% starting from 2025 and Subsea Factory is one of the enablers to contribute to the reduction. There are four primary technologies focused on Subsea Factory: Subsea Separation, Subsea Multiphase Pump, Water Injection and Subsea Storage. The Subsea Multiphase Pump is one of the prioritized technologies for Subsea Factory to contribute to a 40% reduction. Subsea multiphase pump technology has great potential to reduce the CAPEX/OPEX and increase oil recovery, but due to the high equipment cost, huge topside space requirement, reliability and operating issues become very challenging and limit its application to operating companies.
The Company collaborates with FASTsubsea AS on a Joint Industry Project to develop and qualify "the World first All Electric & Topside-less Subsea Multiphase Pump Technology". The uniqueness about this technology compared to commonly installed subsea pump is that it requires much less topside space as there is no need for variable speed drives or barrier fluid hydraulic power units.
This paper describes the qualification and application of All-electric & Topside-less subsea multiphase pump technology in the Company - Subsea Factory mission, including: pain point with conventional subsea multiphase pumpthe Joint Industrial Project initiative with respect to technology development to pilot test to maturityimplementation of this technology and value creation in upcoming field development projectthe case study and potential of this technology for the Company future field development project
Material Selection and Corrosion Rate Analysis for CO2 Injection Well: A Case Study of K1 Field CO2 Sequestration Project
Authors: Abu Bakar Mohd Azuan , Wan Mohamad Wan Amni , Moh Wahi M Wahidullah , Ebining Amir Muhammad Syafeeq 
Published: March 2021

Abstract
The CO2 sequestration project is becoming increasingly attractive due to tax exemption benefits and as an initiative to reduce the global warming effect (D'Alesio, P., Poloni, R., Valente, P., & Magarini, P. A.2010). One of the major challenges in CO2 sequestration project is to ensure that the injection well integrity is intact throughout the well operating life. CO2 gas leakage to the surface or sea is unacceptable. Therefore, the considerations of using exotic/premium tubing materials are usually considered as the base case for continuous long-term operations (Baklid, A., Korbol, R., & Owren, G.1996).
Typical materials used for CO2 injector wells are either Corrosion Resistant Alloy (CRA) or epoxy lined tubulars. The most widely adopted CRA material is 25 Cr (L. Smith, M.A. Billingham, C.-H. Lee, D. Milanovic, 2011). Selection of 25 Cr material is considered as conservative and may well be overdesigning. The main drawback is the high well cost associated with the application of 25 Cr tubing. Meanwhile, alternative materials such as epoxy lined tubulars are exposed to high temperature and pressure blistering effects and prone to mechanical damage caused by wireline activities, hauling, running, and pulling off the tubing (Newton, L. E., & McClay, R. A, 1977).
Application of materials other than 25 Cr for CO2 injector wells, such as 22 Cr, Super 17 Cr, Super 15 Cr, Super 13 Cr, 13 Cr and carbon steel are uncommon but may be fit for purpose. Detailed studies using analytical method and physical tests are required to further qualify these materials for application in CO2 injector wells. These studies should cover all possible conditions throughout the well life such as injection, shut-in, flowback and by considering surface and bottom hole conditions which may contribute to increase in the corrosion rates for different types of materials. Other tests warranted before selecting the suitable material for field application include physical coupon, Sulfide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC) tests.
This paper describes the material selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using the other materials mentioned above as an effort to optimize well costs and improve overall project economics without jeopardizing the CO2 injector well integrity.
Experimental Study on Water Imbibition Law of Longmaxi Formation Shale in the Sichuan Basin
Authors: Tao Liang , Zhao Yuhang , Zhang Xiaozhuo , Wang Yanxing , Feng Hongbo , Cao Yujie , Zhao Zhihong 
Published: March 2021

Abstract
Water imbibition is a key factor affecting the flowback system of shale gas wells after volume fracturing. This paper took shale samples from the Longmaxi formation (LF) in the Sichuan Basin as subjects, the experiments of shale water imbibition under different influencing factors were carried out. The water imbibition law was analyzed, and the shale water imbibition capacity was quantitatively characterized, the question if shut-down is necessary after volume fracturing of wells in shale gas reservoir has been answered objectively. The experimental results show that: according to imbibition saturation, the shale water imbibition can be divided into 3 periods, imbibition diffusion, imbibition transition and imbibition balance periods. Among them, the imbibition diffusion period is the main period for imbibition capacity rise. The shale sample with horizontal bedding had much larger imbibition capacity than the sample with vertical bedding. The initial micro-fractures provide percolation pathways for shale imbibition, making flow resistance drop and imbibition capacity increase rapidly. Imbibition capacities of the shale samples to different types of fluids in descending order were: deionized water, slick water, 2% KCl solution and kerosene. The micro-fracfures induced by shale hydration were mainly lamellation, with obvious directionality. Shale hydration can improve the fracturing effect of reservoir, resulting in the increase of porosity of 0.08-1.04 times and increase of permeability of 2.3-173.6 times. The study results can provide scientific basis for the optimization of flowback system of shale gas wells.
A Data-Driven Approach to Evaluate Fracturing Practice in Tight Sandstone in Changqing Field
Authors: Wu Tao , Fang Hanzhi , Sun Hu , Zhang Feifei , Wang Xi , Wang Yidi , Li Siyang 
Published: March 2021

Abstract
Unconventional reservoirs such as shale and tight sandstones that with ultra-low permeability, are becoming increasingly significant in global energy structures (Pejman T, et al., 2017). For these reservoirs, successful hydraulic fracturing is the key to extract the hydrocarbon resources efficiently and economically. However, the intrinsic mechanisms of fracturing growth in the tight formations are still unclear. In practice, fracturing design mainly depends on hypothetical models and previous experience, which leads to difficulties in evaluating the performance of the fracturing jobs. Therefore, an improved method to optimize parameters for fracturing is necessary and beneficial to the industry.
In this paper, a data-driven approach is used to evaluate the factors that dominate the production rate from tight sandstone formation in Changqing Field which is the largest oil field in China. In the model, the input parameters are classified into two categories: controllable parameters (e.g. stage numbers, fracturing fluid volume) and uncontrollable parameters (e.g. formation properties), and the output parameter is the accumulated oil production of the wells. Data for more than 100 wells from different formations and zones in Changqing Field are collected for this study. First, a stepwise data mining method is used to identify the correlations between the target parameter and all the available input parameters. Then, a machine learning model is developed to predict the well productivity for a given set of input parameters accurately.
The model is validated by using separate data-sets from the same field. An optimize algorithm is combined with the data-driven model to maximize the cumulative oil production for wells by tuning the controllable parameters, which provides the optimized fracturing design. By using the developed model, low productivity wells are identified and new fracturing designs are recommended to improve the well productivity.
This paper is useful for understanding the effects of designed fracturing parameters on well productivity in Changqing Oilfield. Furthermore, it can be extended to other unconventional oil fields by training the model with according data sets. The method helps operators to select more effective parameters for fracturing design, and therefore reduce the operation costs for fracturing and improve the oil and gas production.