bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Reinforced Thermoplastic Pipe RTP Insertion for Offshore Application
Authors: Abu Bakar Azlan , Eka Putra I. Wayan , Badaruddin M. Fauzi , M. Ali M. Nazmi 
Published: March 2021

Abstract
Reinforced Thermoplastic Pipe (RTP) design has been improved to meet the very specific requirement of handling corrosive fluids such as crude oil and sour gas up to certain pressure. RTP might have been widely used for onshore application. However, its application as offshore pipeline is not common compared to carbon steel or flexible steel pipeline due to some limitations.
PETRONAS Carigali Sdn. Bhd (PCSB) has undertook a pipeline replacement project at offshore Peninsular Malaysia to reverse flow 17km of existing 12" carbon steel pipeline with 3" Reinforced Thermoplastic Pipe (RTP) pipeline from Platform-A to Platform-B for crude and condensate services. This technology was the first being implemented by PETRONAS and in Asia Pacific region for offshore application.
RTP pipeline was installed from the Shut Down Valve (SDV) of Platform A to SDV of Platform B by insertion methodology into existing 12" carbon steel pipeline. Special inline connectors were used to connect different sections of RTP pipeline, which came in several reels. Specific inspection to be performed at the connection considering the swaging method used and its effect. RTP hang-off and end termination was conducted upon completion of RTP insertion. Specific RTP pre-commissioning and hydrotest procedure was developed and executed with certain acceptance criteria. The pipeline was then commissioned smoothly indicating the successful completion of the project.
It has proven that RTP pipeline insertion for offshore application was technically feasible for a long pipeline. This technology of offshore RTP pipeline provides alternative to the conventional carbon steel pipeline with the advantages of anti-corrosion, high flexibility and low total lifecycle cost.
The aim of this paper is to highlight the analysis and methodology for RTP Pipeline Insertion for offshore application as well as the technical challenges during offshore execution.
Overview the 5 Years Experience of Intelligent Separate-Layer Injection Technology in B Offshore Oilfield
Authors: Liu Yigang , Chen Zheng , Meng Xianghai , Zhang Zhixiong , Zou Jian , Zhang Le , Lan Fei 
Published: March 2021

Abstract
Nowadays intelligent injection is considered as a new frontier for offshore oilfield. In order to improve the water injection indicators such as allocation frequency and qualification rate, intelligent separate-layer injection technology (ISIT) was researched, deployed and optimized in B offshore oilfield from 2015. In the course of 5 years’ project operation, some experience of success or failure was achieved.
B offshore oilfield is the largest offshore oilfield in China with 33 water flooding oilfields and more than 800 water injection wells. With the continuous development, the problem of injection management mainly reflected in the contradiction between increasing demand of allocation and limited operation time and space was exposed. Two kinds of ISIT, cable implanted intelligent separate-layer injection technology(CISIT) and wireless intelligent separate-layer injection technology(WISIT), were deployed to solve the above problem. CISIT controlled the distributor downhole by electricity while WISIT controlled the distributor downhole by pressure pulse. By the use of ISIT, downhole nozzle's action, packer testing and downhole data monitoring could be remotely controlled on the ground. During the 5 years’ test, ISIT was optimized from the field breakdown including large flow range flowing test, cable protection project, efficient coding mode, water seepage resistance and so on. With the continuous optimization and quality control improvement, ISIT has overcome many problems, such as downhole short circuit and communication loss, and is becoming more stable and reliable. At present, ISIT can meet the needs of large flow injection(max 800m3/d per layer) and can adapt to the high frequency of acidizing and fracturing in offshore oilfield. The failure rate of ISIT has dropped to nearly 20% in 2020.
As of December 2020, ISIT has formed series products for different internal diameter wells and applied in 156 water injection wells in B offshore oilfield. The average allocation frequency has increased from less than one time to 2 times per year. Through the application of ISIT, B offshore oilfield has accumulatively saved more than 2100 days of platform occupation and more than 73 million RMB yuan of allocation cost.
The use of ISIT makes B offshore oilfield's injection become more efficient and intelligent. The 5 years’ experience of ISIT applicationin B offshore oilfield has a fairly referential significance for other offshore oilfields.
Ultra-Strong and Catalyst-Free Polycrystalline Diamond Cutting Materials for One-Run-To-TD Game-Changing Drilling Technology
Authors: Zhan Guodong David , Gooneratne Chinthaka , Moellendick Timothy Eric , He Duanwei , Xu Jianhui , Alalsayednassir Alawi 
Published: March 2021

Abstract
Polycrystalline diamond compact (PDC) bits have been increasing their application drilling many formations in the past 20+ years. However, their performance in drilling very hard, abrasive and interbedded formations still needs improvement. The main weak point comes from their primary cutting elements, PDC cutters, which still need improvements of wear resistance, impact resistance, and thermal stability. During the traditional manufacturing of the PDC cutters, cobalt catalyst has to be used to lower the pressure and temperature. In this study, we developed an ultra high pressure and high temperature (UHPHT) technology to make the PDC cutters without metallic catalyst into reality. Through this development, we can generate pressures of 14 GPa-35 GPa, which is three to seven times of that in the traditional PDC cutter manufacturing technology. In addition, the extreme high temperatures ranging from 1,900 °C to 2,300 °C are achieved, which is 500-900 °C higher than that in traditional process. Using this UHPHT technology, we successfully processed ultra-strong and catalyst-free PDC materials with two high pressures at 14 GPa and 16 GPa, respectively, to study the different responses of the material properties from different processing parameters. The new process applied industry available micro-sized synthetic diamond powders as starting material to eliminate the large volume shrinkage in phase transformation from graphite to diamond which is typically experienced in traditional manufacturing process. The hardness of the 14-GPa CFPCD materials reaches the top limit of the single crystal diamond, more than double that of the traditional PDC cutters. The material also possesses the near-metallic fracture toughness – more than two times of the traditional PDC cutters. Furthermore, the 16-GPa CFPCD material breaks all four single crystal diamond indenters in Vickers hardness tester, an indication of the world's hardest material in the family of diamonds. As a result, the material exhibits industry-recorded wear resistance and thermal stability. The combination of these breakthrough properties of the new CFPCD materials activates the goal in the effort of "One-Run-To-TD" in drilling operation, after the implementation of CFPCD materials as PDC cutters for PDC drill bits.
Microbiologically Influenced Corrosion Combined with Under-Deposit Corrosion Mechanism and Control Technology in Water Injection Wells of Middle East Carbonate Oilfield
Authors: Ye Zhengrong , Chi Huachang , Zhou Xiang , Yang Zhiwen , Jiang Weidong , Li Weixiao , Qiu Zhichao , Cui Xiaodong , Chen Guohao , Wang Xiuyun 
Published: March 2021

Abstract
A carbonate oilfield in the Middle East carries out the mixed water injection of produced water and fresh water, after 1 year of its rapid exploration. The injected water is highly corrosive, with high salinity, high chloride concentration and high hydrogen sulfide. Recently, there are dozens of corrosion perforations on L80 tubing in injectors within 2 years in the field and the corrosion rate reaches 3.6 mm/a. After the tubing leaks, the injected water enters into the annulus between the tubing and casing, which causes casing corrosion, damages the well integrity, and greatly influences the field production.
In this paper, the causes for such rapid tubing corrosion failure are investigated by using optical metallographic microscopy, scanning electron microscopy (SEM), energy dispersive spectrometer (EDS) X-ray diffraction (XRD), and combined with the weight loss and bacteria testing. Firstly, test the element composition of the L80 tubing to verify the tubing quality. Secondly, conduct the corrosion experiments of H2S and dissolved oxygen. Thirdly, analyze the morphology and corrosion product composition of failure tubing.
The results indicate that the failed L80 tubing material meets the requirements of API SPEC 5CT-2011 standard. The localized corrosion rate of L80 is 0.293~0.697 mm/a at whole well depth in the simulated injection water. Bacteria were detected in both the injected water and the corrosion products of the failed tubing. In addition, the corrosion products of failed tubing are mainly FeS, CaCO3 and Fe3O4, which indicates that the synergistic effect of microbiologically influenced corrosion and under-deposited corrosion promote the perforation of tubing. Then the corrosion prevention strategy of UHMWPE lined tubing was proposed. UHMWPE lined tubing has been applied in nine water injectors. After one year and a half, one of the water injector’s UHMWPE lined tubing has been detected, no corrosion perforations observed, and the scale deposition became slightly. This case provides useful practical experience for corrosion prevention of high salinity and high acid injection well in carbonate oilfields.
Field Application of Deep Learning for Flow Rate Prediction with Downhole Temperature and Pressure
Authors: Wang Fuyong , Zai Yun , Zhao Jiuyu , Fang Siyi 
Published: March 2021

AbstractWell real-time flow rate is one of the most important production parameters in oilfield and accurate flow rate information is crucial for production monitoring and optimization. With the wide application of permanent downhole gauge (PDG), the high-frequency and large volume of downhole temperature and pressure make applying of deep learning technique to predict flow rate possible. Flow rate of production well is predicted with long short-term memory (LSTM) network using downhole temperature and pressure production data. The specific parameters of LSTM neural network are given, as well as the methods of data preprocessing and neural network training. The developed model has been validated with two production wells in the Volve Oilfield, North Sea. The field application demonstrates that the deep learning is applicable for flow rate prediction in oilfields. LSTM has the better performance of flow rate prediction than other five machine learning methods, including support vector machine (SVM), linear regression, tree, and Gaussian process regression. The LSTM with a dropout layer has a better performance than a standard LSTM network. The optimal numbers of LSTM layers and hidden units can be adjusted to obtain the best prediction results, but more LSTM layers and hidden units lead to more time of training and prediction, and LSTM model might be unstable and cannot converge. Compared with only downhole pressure or temperature data used as input parameters, flow rate prediction with both of downhole pressure and temperature used as input parameters has the higher prediction accuracy.
Pre-Drilled ECD Design by Using Fracture Pressure Model in Satun-Funan Fields, Pattani Basin, Gulf of Thailand
Authors: Kananithikorn Nardthida , Songsaeng Teenarat 
Published: March 2021

Abstract
Lost circulation is the most common drilling issue for infill drilling projects in Satun-Funan Fields, South Pattani Basin, Gulf of Thailand (GOT). The depleted sand is possible to be a root cause in many wells based on observation from resistivity time-lapse separation in depleted sands or shale nearby. Therefore, the objective of this study is to estimate fracture pressure related to the depleted sand and design an appropriate Equivalent Circulating Density (ECD) threshold for each well to avoid or minimize lost circulation and well control complication during drilling a new well.
This study model is using Eaton (1969) equation. There are 3 input parameters which are Poisson's Ratio and pre-drilled estimated depletion pressure and depth. With limitations of no actual fracturing data and limited sonic log, the maximum ECD while lost circulation reading from Pressure While Drilling (PWD) tool and formation pressure test data were used to back-calculate for Poisson's Ratio and identified a relationship with depth. From the total of 68 wells in the Satun and Funan areas, the interpreted Poisson's Ratio ranges from 0.36 to 0.44 and its linear trend is apparently increasing with depth. To minimize the variation of back calculated Poisson's Ratio the local data become an important key for model validation and maintain the similarity of subsurface factors. This interpreted Poisson's ratio trend will be used to calculate for fracture pressure by incorporating with estimated depletion pressure and depth that expect to encounter in each planned well. The lowest fracture pressure in a planned well is used to prepare pre-drilled ECD management plan and a real-time well monitoring plan. Additionally, the model can be adjusted during the operational phase based on the new drilled well result.
This alternative model was applied in 4 trial drilling projects in 2019 and fully implement in 6 drilling projects in 2020. The lost circulation can be prevented with value creation from expected gain reserves section is $57M and cost avoidance from non-productive time due to lost circulation is $3.4M. With an effort, good communication and great collaboration among cross-functional teams, the model success rate increases by 12%. However, there are some unexpected lost events occurred even though the maximum ECD lower than expected fracture pressure. This suspect as a combination of limitations and uncertainties on key input parameters and drilling parameters.
In the future, the model is planned to expand to other gas fields in the Pattani Basin which will move to more infill phase and have higher chance of getting lost circulation to maximize benefits as the success case in Satun and Funan fields.
A Case Study on Chemical Free System for Crude Sweetening: A first in Indian Offshore; Design Challenges and Post Installation Performance Evaluation
Authors: Gupta M K , Singh V K , Sharma MSK , Katre N V , Boddu V , Nath Siddharth Priya , Reddy Rajesh , Raman Ravi 
Published: March 2021

Abstract
In a producing field of western offshore, H2S content in oil was found to be in the range of 3000-5000 ppm against the desired level of 200ppm. High H2S concentration posed a serious threat to pipelines integrity and downstream equipment. Mitigation by conventional means such as chemical injection is generally avoided at offshore due to constraint like continuous pumping, storage of chemicals, frequent monitoring, logistical impediments and disposing off by-products in compliance with statutory requirements. Considering many limitations at offshore, an approach was adopted for reduction of H2S utilizing Henry's principle which states that the amount of dissolved gas in a liquid is proportional to its partial pressure. Reducing the partial pressure by utilizing sweet natural gas or some other inert gas, H2S can be removed. Same principle was applied to conceptualize a processing system wherein sour crude can be sweetened to the desired level utilizing sweet gas as stripping gas. Processing System was designed considering many downstream and upstream constraints in the existing system and without any rotating and heating requirement. Unlike conventional way of sweetening such as chemical injection which requires continuous dosing of chemical and disposing off by-products in compliance with statutory requirements and hence, found not feasible at offshore to sweet enormous amount of crude. The designed processing system, a first in Indian offshore environment, is commissioned at one of the offshore complex and has proved it efficacy wherein H2S content of around 3000 ppm in around 6000 barrel/day of crude is being reduced to less than 10 ppm level without use of any hazardous chemicals and without any need of rotating and heating equipment's and with minimum maintenance and manual intervention requirement. The system has lowest operating cost, low maintenance and without use of any rotating and heating equipment's and hence can be emerged as an ideal solution for crude oil sweetening at offshore environment or in an environment where bare manual intervention is required.
Seismic Data Processing and Depth Imaging for Yingxionglin Complex Structures-Belt in Qaidam Basin, Tibetan Plateau
Authors: Wang Yongsheng , Tan Chenqing , Zhu Bo , Tong Yanming , Wang Haifeng , Wu Chuan , Dong Yongcang , Li Rong 
Published: March 2021

Abstract
The Yingxionglin structural belt located in the world's highest-altitude petroliferous basin, Qaidam Basin. Due to its complex surface condition, subsurface structure and low signal-to-noise ratios (SNR) of seismic data, exploration and production is quite challenging. From 2012 to now, we continued developing and improving seismic data processing and interpretation workflow. After several rounds field support and testing, new techniques exploring and velocity modelling iteration, we gradually developed a suitable workflow for complex dipping structure imaging including signal processing, velocity modeling, and depth migration. The quality of final delivered 3D seismic data is significantly improved with the integrated static correction techniques, fidelity multi-domain noise attenuation, 5D MPFI regularization, integrated velocity modelling and final pre-stack depth migration. According to our final deliverables, we identified credible traps and high-production reservoirs were found.
Factors Controlling Porosity Permeability Relationship for Reservoir Quality Prediction: A Case Study of Malay Basin Reservoir, Malaysia
Authors: Kasim Fadzlin Hasani , Kantaatmadja Budi Priyatna , Wan M Zainudin Wan Nur , Ali Amita , Ismail Hasnol Hady , Ahmed Siddiqui Numair 
Published: March 2021

Abstract
Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin.
Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy.
Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization.
The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.