bluuebunny/crossref_metadata_2025 huggingface dataset:
A Comprehensive Review on the Application of 3D Printing in the Aerospace Industry
Authors: Martinez Dan William , Espino Michaela T. , Cascolan Honelly Mae , Crisostomo Jan Lloyd , Dizon John Ryan C.
Published: March 2022

Additive manufacturing is a process wherein a three-dimensional object is created layer-by-layer. It offers adaptability to the geometrical complexity and customizability of the design, which is difficult to manufacture using conventional manufacturing. The aerospace industry is one of the sectors that first adopted additive manufacturing, particularly three-dimensional printing (3D printing) in the production of aircraft parts such as rocket engine components, oil fuel tanks, environmental control system ducting, combustor liner, custom cosmetic aircraft interior components, and unmanned aerial vehicle (UAV) components. The aircraft's most common materials used in the 3D printing prototype parts are acrylonitrile butadiene styrene (ABS) thermoplastic, carbon-fiber and thermoplastic composite, and nylon 12 using selective laser sintering, fused deposition modeling, or composite filament co-extrusion technology. One of the aerospace industry's challenges is ensuring the efficiency and quality of aircraft structural parts that typically require complicated manufacturing due to their complexity and variability of function. Additive manufacturing is seen to respond to this challenge by developing and prototyping 3D printed parts and exploring practical 3D printing technologies.
Dielectric Dispersion Response of Binary Mixtures of n-Butanol and Valeronitrile
Authors: Patel Shivani P. , Prajapati Ashvin N. , Vankar H.P. , Rana V.A.
Published: March 2022

Complex permittivity spectra of various concentrations (0.0 → 1.0) of n-Butanol and its mixtures with Valeronitrile were obtained in the radio and microwave frequency range (0.2 GHz to 20 GHz) using Vector network analyzer (VNA). Complex permittivity data points were fitted into Havriliak-Negami Model. CNLS fitting using LEVMW software used to obtain dielectric parameters. Excess static dielectric constant and excess inverse relaxation time for the binary mixtures were calculated and fitted in Redlich-Kister polynomial to derive the binary coefficients and standard deviations. Variation of these parameters were discussed in terms molecular interaction between molecular species.
Photocatalytic Activity of Nickel Ferrite Nanoparticles Synthesized via Sol-Gel Auto Combustion Method
Authors: Jadhav Swapnil A. , Raut Anil V. , Khedkar Mangesh V. , Somvanshi Sandeep B. , Jadhav K.M.
Published: March 2022

Nickel ferrite NiFe2O4 nanoparticles were synthesized through sol-gel auto combustion method using dextrose as a fuel. The prepared nanoparticles were investigated for their structural, optical and magnetic characterization. X-ray diffraction (XRD) revealed the development of single-phase cubic spinel with crystallite size of 14 nm. The optical study showed that the compound has an optical band gap 2.26 eV. The magnetic properties were investigated through M-H hysteresis curve. The photocatalytic activity of nickel ferrite was studied based on the degradation of methylene blue (MB) as a model compound, where the results showed that prepared nanoparticles possess a good photocatalytic activity.
Properties of Fiber Cement Boards Influenced by BSCH (Banana Stem and Corn Husk) Fibers and Citric Acid Addition
Authors: Sales Showna Lee T. , Aldamia Feabie Jessa , Gonzaga Princess Stiffany , Montesclaros Adrian Jose S. , Lawagon Chosel P.
Published: March 2022

At present, the amount of organic wastes including banana stem and corn husk produced from the Philippines is roughly 56 million technical tons. On the other hand, the construction industry demands innovation to some of the construction materials including cement fiber boards (CFB). The objective of this study is to address the increasing volume of organic wastes including banana stem and corn husk (BSCH) by incorporating BSCH fibers in to cement boards. To test whether the boards fabricated with BSCH fibers is a viable option, the study determined the physical and mechanical properties of cement boards reinforced with BSCH fibers added with citric acid. The experimental results obtained from this study showed that the flexural strength of the cement boards reinforced with banana stem and corn husk fibers is higher than the cement boards without fibers. On the other hand, the compressive strength the cement fiber boards increased in 8% fiber reinforcement and gradually decreased as more fibers were added to the mix. Furthermore, the boards with fibers showed effective drilling characteristics. From the tested cement fiber boards, the cement fiber boards with 8% fiber reinforcement showed the most promising results in both physical and mechanical properties of the fiber cement board.
Mechanical Characterization of AA 6061-T6 MIG Welded Aluminum Alloys Using a Robotic Arm
Authors: Mahdi Elsadig , Eltai E. , Alabtah Fatima Ghassan , Eliyan Faysal Fayez
Published: March 2022

Aluminum alloys are of particular interest in the design of lightweight structures in different applications. Accordingly, welding aluminum alloys (AA) is a critical issue; for example, welding defects could arise during the traditional welding of aluminum alloys. This paper investigates the effects of welding using a robotic arm on the mechanical properties of 6061-T6 Aluminum alloy, as plates joined by Metal Inert Gas (MIG) welding. The tensile behavior and mechanical properties were investigated using tensile testing, hardness testing, and impact testing. The tensile behavior of AA-6061-T6 un-welded and welded specimens showed a decrease in the tensile strength of the welded specimens due to the fusion of the welded zone and the partially melted zone (PMZ). The hardness test showed an increase in the hardness values away from the welded zone, attributed to voids and defects in the welded and HAZ zones. In addition, the impact behavior showed that the maximum impact is in the base metal zone, and the minimum is in the HAZ. Scanning electron microscopy was used to investigate the welded and un-welded Aluminum microstructures. The mechanical properties of AA 6061-T6 Aluminum alloy were sensitive to the novel welding process.
Billions of Barrels at Risk in Southeast Asia Due to Sour Gas
Authors: Pandey Prateek
Published: March 2022

Southeast Asia is one of the leading regions globally in terms of planned gas developments in the next decade. We estimate sour gas contamination in Southeast Asian gas discoveries is one of the major challenges delaying over 10 billion barrels of oil equivalent gas resources from coming online. These developments are planned in Malaysia, Indonesia, and Vietnam, requiring around $20 billion of investments, and could potentially make a significant contribution to regional production post-2030. But the fields contain high levels of sour gas, which makes development challenging and costly. Sour gas refers to natural gas that contains significant amounts of acidic gases such as hydrogen sulfide and carbon dioxide (CO2). Some industry majors are moving forward with exploration and development - albeit at a slow pace. Off Malaysia, work on Petronas’ Kasawari, Shell's Rosmari-Marjoram and PTTEP's Lang Lebah fields have been lined up, while Indonesia has witnessed similar slow progress on similar projects operated by IOCs and the government is also hoping the potential of its Natuna D-Alpha field will attract investors. However, as domestic gas demand in the countries increases and output drops, efforts must be made to overcome the complex geology and associated challenges. In fact, globally SE Asia & NW Australia are one of the largest regions with concentrations of sour gas. The paper intends to highlight Southeast Asia's role in planned gas developments globally and the significance of these developments in regional production. We deep dive into the planned developments risked by the sour gas contamination which makes up over 40% of the gas resources planned for development in Southeast Asia by 2030.
Determination of Fluid Properties and Reservoir Net Pay Cutoffs by Production Logging and Conventional Logs in Exploration Wells :A Case Study of the Granite Fractured Reservoir in JZ Oilfiled in Bohai Sea
Authors: Shi Xinlei , Cui Yunjiang , Xu Sainan , Wang Ruihong , Zhang Hao
Published: March 2022

Since resistivity logging is much more sensitive to rocks than to hydrocarbons in granite reservoirs, conventional logging methods cannot always accurately evaluate fluid properties and identify pay zones. Drill Stem Test (DST) is often used to identify fluid properties and hydrocarbon production potentials. However, DST in granite reservoirs cannot accurately determine production from sub-layers which leads to inaccurate net pay zone identification and reserve estimation. The accurate determination of fluid properties and net pay zones in fractured granite reservoirs remains a challenging topic.

This study proposes the use of Production Profile Logging (PLT)Logging in exploration wells in JZ oilfield characterized by fractured granite reservoirs, where DST could not characterize the sub-layers’ PLTs with in the thick layer of the combined test. With the use of open hole completion test, PLT logging can easily identify the production from sub-layers. The fluid density and water hold-up are consistent with the response of flowmeter logs. The method not only identifies production from sub-layers but also determines fluid properties. Meanwhile, it can quantify the production from each sub-layer according to PLT logging interpretation. It has satisfactory application in productivity evaluation in JZ oilfield.

Results indicate that the use of PLT logging in four exploration wells in JZ oilfield is successful. Sub-layers are identified in DST based on PLT logging interpretations of flow rate, density, and water hold-up. The productivity index of each sub-layer is calculated by PLT logging interpretation. Combining lateral resistivity logs with sonic logging data, Draw porosity and ratio of the deep and shallow lateral resistivity plot based on each sub-layer’ production with PLT interpretation Logging results. Net pay cutoffs of JZ oilfield is determined to be φ≥3.0% and (RD/RS) *DT≥90. This method improves the accuracy of reserve evaluation and solves the problem that the estimates of net pay cutoffs are larger than actual values in DST. Compared with DST in fractured granite reservoirs, PLT logging not only leads to accurate determination of fluid properties and identification of net pay cutoffs but also largely reduces the costs.

PLT logging is conventionally used to dynamically monitor cased hole wells. The novelty of this study is the successful application of PLT logging in reserve estimation. Compared to the conventional reserve estimation method based on DST, this new strategy accurately identifies net pay zones and determines net pay cutoffs in fractured granites to improve the accuracy of reserve estimation. Thus, the field can be developed more economically when oil prices are low.
Digital Transformation for the Gulf of Thailand's Assets Condensate Stabilizer Real-Time Optimization
Authors: Atibodhi Nopparat , Dhadachaipathomphong Supha-Kitti , Nazir Fahd , Namwong Nathachok
Published: March 2022

PTTEP's natural gas fields in Gulf of Thailand, has encountered losses in Condensate yield due to suboptimal operating conditions as variation in feed compositions occurs when production line up changes. As a result of this suboptimal operation, some light Condensate is lost into gas phase resulting in lower overall profitability.

As part of company's Digital Transformation initiatives, a Condensate Stabilizer Optimization (CSO) solution has been implemented to minimize or eliminate these losses. The objective of CSO is to provide real-time recommended operating conditions to maximize condensate production while maintaining sale condensate specification using optimization technology that considers all relevant condensate stabilization process parameters.

The CSO solution leverages Multivariable Predictive Control or Model Predictive Control (MPC) technology and communicates the obtained results to offshore teams via an online web user interface.

Besides the dynamic models and MPC technology, the solution also includes an important component of the CSO solution which is the web based online dashboards as they are the key to communicate between the solution and the users. The dashboards include the following key features:

– Key operating parameters of Condensate Stabilizer Units including Controlled, Manipulated, and Disturbance Variables – Recommended optimal values of Manipulated Variables to achieve maximum condensate production – Difference between actual vs predicted RVP. This is to visualize current model accuracy – Captured Benefit

As of December 2021, the CSO solution has been fully utilized for 5 months, i.e. Go-Live since August 2021. During this period, it has successfully delivered not only safe operating window but also benefits which adds up to 1.49 MUSD/year. As the benefits of the solution have been proven, a plan to proceed with Phase 2 of this project, in which the CSO solution will be integrated with the Distributed Control System (DCS) allowing MPC Controller to automatically adjust process parameters to achieve the most optimal conditions, has been set.

Apart from process optimization, the CSO solution can be used to evaluate operating scenarios based on given simulated process parameters, thus becoming a true "Digital Twin" of the Condensate Stabilizer that can replicate its operation at different operating conditions.
Mitigation of Slim Open Hole Wireline Logging Risk Under High Overbalance Conditions
Authors: Siregar Ronald , Ramli Safuan , Turner David , Prachayarittikool Kachin , Iffwad Mohammad
Published: March 2022

The oil and gas fields offshore Malaysia-Thailand border are well known for the presence of high pressure and high temperature reservoir characteristics. The hot environment favours the use of hostile wireline logging tools over logging while drilling tools for some measurements.

High overbalance conditions are sometimes a necessary requirement to safely drill particular formations but bring with them operational challenges. For wireline logging a critical hazard is that of becoming differentially stuck, especially in the case of stationary logs such as pressure measurements, sampling, and coring. A reduction in allowable safe stationary times for these measurements can also compromise the quality of the results.

Production wells in this area are generally drilled with slim 6-1/8″ sections through the reservoir. As the borehole becomes smaller the risk of sticking increases as the tool contact area increases and so is a particular concern in slim holes. This often leads to logging being run using costly pipe conveyed methods or the inability to obtain required data altogether.

This paper presents case histories of wireline formation pressure testing and sampling in 6-1/8″ sections with high deviation, 3D trajectory boreholes with overbalance pressures of over 2,000 psi. The use of a high-performance roller system to create tool stand-off to mitigate differential sticking as well as eliminate friction is described, along with the use of an engineered hole finder to address hole access concerns. The importance of wireline simulation models to identify risks and test solutions in such conditions is also considered.

Slim hole logging and logging under overbalanced conditions are often a source of concern for subsurface, drilling and service company personnel alike. Describing a successful approach to address both is of interest to all involved parties and should provide ideas and confidence to plan cost-effective logging in similar wells.
L53-DD, On-Shore Thailand a Case Study of Integrated Geoscience to Engineering Approach Improving Reserve Estimation and Field Development Planning
Authors: Yew Zhen-Xuan , Kosolpinete Monthathip , Lerdsuwankij Thiti , Sen Gargi , Harun Mohd Fadzil , Duangprasert Tanabordee , Noomee Lakkanaporn , Thongseng Jeerisuda , Wongsawat Thanitha
Published: March 2022

The study emphasized on a collaborative work across various domains to improve reserve estimation utilizing integrated analysis from geological understanding, seismic interpretation, petrophysical log to sampled pressure and production data. A cross-disciplined approach was tailored for this complex marginal field and it included a fast loop full-field reservoir modeling and simulation to delineate the reservoir characteristics in a timely manner.

The study improves the confidence level in reserve estimation of the field with a range of 30-35% primary recovery factor interpreted across different sands which is in line with other publications that in a typical Gulf of Thailand oil reservoir, in the presence of a strong water drive, the most likely primary recovery factor is between 18-40%, depending on the thickness of the oil column, bottom water versus edge water and the presence of a gas cap. The study helps to drive real field decision making for upcoming drilling campaigns to further improve the economic life of the field. This paper presents a fit-for-purpose reservoir modeling while drilling approach demonstrating how the company used newly drilled well data to validate the reservoir model and to drive new decisions for field development planning.

The industry has limited published case studies on medium to heavy oil (19 to 25 degree API) with strong aquifer support in the region of onshore Thailand. This case study presents an approach in addressing multiple challenges faced to unlock the high oil potential of the region. In summary, a cross-disciplined, fit-for-purpose and practical approach using latest available commercial technology enabled real-field decisions being made timely and accurately. Similar approach will be undertaken in other fields of the company in the region.
Pressure Transient Behaviors of Discretely Fractured Reservoirs Using a Numerical Discrete Fracture Model
Authors: Chen Zhiming , Zhou Biao
Published: March 2022

The conventional dual-porosity model (Warren and Root 1963) may not apply to naturally fractured reservoirs which have poorly connected fractures. To narrow this gap, a discrete fracture model based numerical well testing (NWT) model is developed for pressure transient analysis in vertical wells interacting with natural fractures.

The accuracy and practicality of the proposed model have been demonstrated by model verifications. The results show that the flow regimes of the vertical well interacting with natural fractures can be divided into wellbore storage and skin effects, bilinear flow, linear flow, radial flow, natural-fracture (NF) effect, and boundary-dominated flow. This radial flow is the radial flow of the formation before pressure propagates to natural fractures, which is virtually quite different from that in the conventional dual-porosity model (Warren and Root 1963). However, there are no bilinear and linear flow stages in the vertical well interacting with no natural fractures. It is found that the vertical well interacting with natural fractures has a lower pressure depletion. It is also found that the "V-shape" caused by the NF effect in the pressure derivative curve becomes deeper when there are more natural fractures, longer natural fractures, and higher fracture conductivity. Furthermore, the "V-shape" appears earlier and the duration of the NF effect is longer as the number of natural fractures increases. Besides, with the decrease of the distance between the fracture and well, the impacts of natural fractures on pressure transient behaviors of the vertical well are more significant. This work provides a meaningful way to understand the pressure transient behaviors of discrete natural fractures.
Injector Design Plays an Important Role In Maximisation of CO2 Trapping in Geological Formations
Authors: Chidambaram Prasanna , Patil Parimal A , Tiwari Pankaj Kumar , Das Debasis P , Tewari Raj Deo
Published: March 2022

Storing CO2 in geological formations is gaining greater importance as various companies start transitioning towards a carbon neutral future. CO2 storage in depleted hydrocarbon reservoirs and saline aquifers is considered an effective and secure option to reduce atmospheric CO2. Once underground, four different mechanisms keep the supercritical CO2 securely stored. The mechanisms, in increasing order of storage security are, 1. Structural/stratigraphic trapping, 2. Residual trapping, 3. Solubility trapping, and 4. Mineral trapping. Optimization of injector design to increase the amount of CO2 trapped in one of the more secure mechanisms is desirable.

Structural trapping is the most dominant and least secure trapping mechanism for CO2 storage. Any opportunity to move structurally trapped CO2 into one of the other trapping mechanisms is preferable from the standpoint of storage security. Mechanistic models are used to study ways to improve amount of CO2 trapped by certain mechanisms. Residual trapping is affected by several factors including path traveled from perforation to the top of the structure. Similarly, solubility trapping is influenced by several factors including the amount of contact CO2 has with water. Injected CO2, due to buoyancy, rapidly rises to the top of the structure. There is potential to increase residual trapping and solubility trapping by optimizing the injector design to increase volume of reservoir contacted by CO2.

Mechanistic modeling study shows that residual trapped and solubility trapped CO2 volume can be increased by optimizing injector design. There is up to 50% improvement observed in both trapping mechanisms depending on the reservoir characteristics and injector design. Interestingly, lower permeability reservoirs are more sensitive to injector design compared to higher permeability reservoirs. Of the injector designs studied, horizontal injectors placed at the bottom of the structure show the most improvement in both residual and solubility trapping mechanisms. Pressure of the reservoir also influences trapping mechanisms. At higher reservoir pressures, density difference between CO2 and water is smaller. This affects how CO2 plume migrates in the reservoir.
The Achievement of Resource Optimisation on Lean Remote Wellhead Platform Visit with Collaborative 52 Weeks Plan
Authors: Zar Soe Thin , Leelaratsameephanit Anucha , Jitputti Phanuwat , Charoensook Sayan , Rodthip Alongkorn , Chitkla Sathit , On-Dam Apichai , Sirijitt Perapon
Published: March 2022

To survive in oil and gas industry, Operating Expenditure (OPEX) must be well controlled for profit maximization. One of the most resource-utilizing activities in Zawtika offshore field is remote wellhead platform (WHP) visit which was previously bi-weekly for operations activities, maintenance activities such as preventive maintenance (PM), etc., inspection activities like flowline erosion monitoring and wells annulus pressure monitoring, thereby high Marine Gas Oil (MGO) consumption due to vessel trips/routes and increased in manpower utilization. Currently, Zawtika Offshore field has a main platform called Zawtika Processing and Living Quarter Platform (ZPQ) and 10 remote wellhead platforms (WHPs). When it is considered for future, there will be more remote wellhead platforms (WHPs) which will increase more OPEX for new phases.

To tackle this, this paper describes that Myanmar Asset Zawtika launched a LEAN (Lean Six Sigma) initiative based on safely and cost-effectively reducing the frequency of remote wellhead platforms (WHP) visits, using collaborative 52 week planning to lessen OPEX cost from MGO consumption and manpower requirements as well as maintaining Zawtika Reliability and Asset Integrity (RAI) with the view of achieving resource optimization. This paper also illustrates the effective planning process across multiple functions/disciplines within different sessions/departments and at various locations called 52 weeks plan incorporating with "Integrated Operation Plan (IOP)" guideline established for the first time for Zawtika offshore field to help optimize the resources and activities plan of individual field or asset by ensuring the safety while sustaining the integrity. This paper also outlines the reduction in Greenhouse Gas (GHG) calculated back from MGO reduction which is one of PTTEP strategies for Sustainable Development (SD).
Pegaga Development Drilling Operations with PMCD and CDIV Applications
Authors: Mohammad Annas Omar , Bakar Azlee Abu , Mohd Khaidzir Khairil Azam , McKen Donald Robert , Yeow Lei Ming , McCluskey Timothy James
Published: March 2022

This paper describes the implementation of Pressurized Mud Cap Drilling (PMCD) and Casing Downhole Isolation Valve (CDIV) technology for the Pegaga Development Project to mitigate heavy fluid losses, allowing safe and effective drilling operations to reach well TD. The project consists of seven gas producers (deviated wells), drilled using a jack-up rig from a 10-slot wellhead deck.

This paper also describes the planning and operational challenges met to ensure the smooth application of PMCD, starting with selection of the rig and supply vessels, challenges related to adverse weather conditions, long distances between the supply base and drilling location, sufficient mud tank capacity, continuous supply of Light Annular Mud (LAM) for PMCD operations and pandemic related personnel movement restrictions.

A continuous learning process was applied for the drilling team where challenges experienced in drilling the first well in PMCD mode and lessons learned were captured and applied to the subsequent wells to improve drilling results. A comprehensive decision tree was established and refined to help the offshore team to make quick decisions when needed to switch to PMCD mode.

The Pegaga gas field is located in Block SK320 in the Central Luconia Province, off the coast of Sarawak, offshore Malaysia. The main reservoir is a Pinnacle Carbonate reservoir, which is made up of vugular/karstified carbonates that are likely to cause severe or total losses.

The top-hole sections for all seven wells were batched drilled before the PMCD system was rigged up prior to commencing the 12-1/4" intermediate and 8-1/2" reservoir hole sections. The 12-1/4" sections were drilled to above the target gas reservoir carbonate formations, with the PMCD system on standby in case the carbonate formations and severe losses were encountered shallower than prognosed. A single 9-5/8" CDIV (NACE standard) was run with the 9-5/8" × 10-3/4" casing string and permanently set (cemented) in the 12-1/4" open hole, which was the first time this had been done in Malaysia. The CDIVs were set in the open hole to reduce the potential volume of gas below the CDIV and reduce the mud volume required for tripping in PMCD conditions, while increasing the safety and efficiency of PMCD operations.

Seven wells were drilled to TD, five in PMCD mode, two conventionally. The lower and upper completions were run and set on six wells, with four of the lower completions run and set in PMCD mode. The CDIV was used to isolate the open hole for tripping out the BHA and running in the lower completion on two of the PMCD wells, while the other three used the top kill method.
Geological Field Characteristic of the Black Shales in the Belata Formation, Peninsular Malaysia
Authors: Owusu Esther Boateng , Tsegab Haylay Gebretsadik , Abubakar Rabiatuu
Published: March 2022

Peninsular Malaysia is made up of three fundamental stratigraphic belts; the Central Belt, the Eastern Belt, and the Western Belt with little data on their shale lithologies. The Belata Formation is situated in the Western Belt and is at the southernmost part of Tanjung Malim in the Perak State bordering the Selangor State. Belata Formation falls in between the Terolak and the Karak formations to the north and south respectively. Six Carboniferous shale outcrops were discovered during fieldwork. Outcrop description, sample collection, and laboratory studies were conducted on the Belata Formation. The outcrops include shales that range from black to grey. For laboratory investigation, twenty-two samples were obtained from the shale outcrops. Total organic carbon (TOC) analyses carried out on the samples revealed an average of 3.4 wt. %. The black color is possibly introduced in these shales because of organic matter incorporated in the sediments. Hence, these shales tentatively could be regarded as potential shale gas exploration targets in the Peninsular. However, the effect of the regional rnetarnorphisrn which affected the Sibumasu Terrane should be considered even though shales are not affected by contact metamorphism due to their distance further away from the granitic intrusions.
Preventing Halite Scaling in Offshore Pipelines Using Integrated Scale Management System and Modeling – Case Study from Gulf of Suez, Egypt
Authors: Darwish Abdallah Magdy , Khalil Ahmed Kamal , El-Dessouky Mohamed El-Hussein , Mohamed Islam Ibrahim , Abdelhalem Tamer Hosny
Published: March 2022

Halite scaling has a dreadful impact on production pipelines. Produced water from Nubia formation in "E" field has high level of total dissolved solids (TDS) concentration. Halite scale causes complete blockage of the flow paths, integrity complications and periodic production interruption. Pipeline pigging and flushing with fresh water were performed frequently to eliminate blockage and restore production.

An offshore platform with six online gas lifted wells; two high rate wells are producing from Nubia formation through the production pipeline and the remaining low rate wells are producing from other formations with a lower TDS through the test pipeline. High saline water flows through the production pipeline and cools down to seabed temperature resulting in halite precipitation, which regularly blocks the pipeline and requires repetitive fresh water flushing and pigging operations. Laboratory water analysis and scale tendency were conducted in conjunction with a pipeline network model to predict the halite precipitation temperature, actual friction coefficient and optimum fluid mixing and dilution strategy.

The combination of complete water analysis, scale tendency, real time remote monitoring system and pipeline network modeling showed that halite scaling started inside the subsea pipeline nearby the platform. The model matching revealed a high friction coefficient, which indicated partial plugging of the production pipeline. The model sensitivity analysis predicted that diluting the supersaturated water by mixing it with other wells’ lower salinity waters – into the same pipeline, would drop the mixture salinity with no halite scaling along the pipeline. As a result, the strategy of mixing was selected and optimized based on the modeling results and water compatibility tests to reduce losses due to back pressure and to minimize the risk of hard scale deposition. For more than a year, no halite has precipitated, which resulted in an uninterrupted production and allowed well testing of the remaining wells discretely through the test pipeline.

This paper demonstrates a comprehensive case in which halite scaling issues were predicted and mitigated through an integrated scale management system. The operating expenditures of pipeline flushing and pigging operations and oil losses were decreased due to interrupted production.
Cost Effective Framework of Integrated Development of Offshore Marginal Oilfields - Case Study of a Heavy Oil Reservoir with Thin Layers
Authors: Liu Yingxian , Shi Hongfu , Xu Zhongbo , Zhang Wenjun , Wang Xinpeng
Published: March 2022

The Bohai bay is rich in oil and natural gas resources. Over the past 40 years, a series of different types of large and medium-sized offshore oil and gas fields have been successfully discovered and developed. The newly discovers, however, is marginal either smaller in size or poor in reservoir quality which can't be economically and efficiently developed with the current conventional exploitation methods. The development of such marginal assets is of great significant for the the sustainability of Bohai production.

In this paper, L oilfield is taken as an example to explain how to establish a framework in developing such marginal oilfields cost-effectively through multi-disciplinary cooperation. The L oil field is one of the typical marginal green-oil fields discovered recently in the Bohai Bay which characterized as low OOIP, limited certain reservoir spaces for well placement and challenges economically for standalone development (Adeogun Oyebimpe, August 2018, Mohamed, A. Zakariya.March 2003). In addition, primarily thin oil layers at the average single layer thickness only 2.1 m, high crude oil viscosity at the average of 2000mpa·s, and low single well productivity less than 300 barrels per day. However, the L oil field geographically is next to a large oil field which is only 12km away. How to maximize the success chance of penetrating the sweet spot of those thin layers, and therefore achieve higher initial oil productivity, to form a complete injection-production well pattern for long period stability in production and to minimize capital investment through joint development with surrounding oilfields is the way out for L oilfield development.
Innovative Rigless-Deployed Electrical Submersible Pump ESP System for Installation at Floating Deep-Water Production Platform
Authors: Raman Intiran , Wardhana Yulian , Selamat Kasim , Shepheard Barry , Ghazali Muhammad Nabil , Blacklock Jon David , Tulathammakit Hattaya , Liu Zengzhen , Bathmanaaban Gopalan
Published: March 2022

Installing an electrical submersible pumping (ESP) system in an oil well is one of the optimal artificial lift methods to increase production and maximize ultimate recovery. However, installing and retrieving an ESP using an offshore rig is costly and presents planning challenges. In some geographies and projects, offshore intervention rig costs and risks sometimes outweigh the potential gains of an ESP system.

An operator in Malaysia was interested in installing an ESP system in an offshore well to maintain production rates, but the intervention costs were a roadblock. The challenge was to devise a rigless ESP deployment system that can be deployed through the existing completion to avoid the need for a rig, even on the initial deployment. The system would need to provide a 2000 BPD flow rate to justify the initial investment of the wellhead modifications, surface equipment, the newly developed rigless-deployed ESP system, and completions accessories.

This new generation rigless-deployed ESP system features an inverted ESP with the ESP motor on top, connected directly to the power cable. This revolutionary design eliminates the motor lead extension, removing the weakest connection in traditional ESP systems. The rigless deployed ESP system enables deployment under live well conditions, eliminating the need to kill the well and the need for a rig – inclusive of the initial deployment. This paper reviews the design and deployment process of the first installation in Southeast Asia.
An Experimental Investigation into the Potential of a Green Alkali-Surfactant-Polymer Formulation for Enhanced Oil Recovery in Sandstone Reservoir
Authors: Tackie-Otoo Bennet Nii , Ayoub Mohammed Mohammed Abdalla , Mohamad Ghani Muhammad Faiz , Jufar Shiferaw Regassa , Hassan Anas Mohammed
Published: March 2022

Despite the promising nature of alkali-surfactant-polymer (ASP) flooding, its application is limited by various technical issues and environmental concerns. The goal of mitigating the impact of these limitations has led to research into the oil recovery potential of alternative chemical agents. This study, therefore, focuses on investigating the potential of a "green" ASP formulation composed of monoethanolamine (ETA), sodium cocoyl alaninate (SCA) and Schizophyllan (SPG) for its enhanced oil recovery application. A conventional ASP formulation comprising sodium carbonate (Na2CO3), Sodium Dodecyl Sulfate (SDS) and partially hydrolyzed polyacrylamide (HPAM)was deployed for comparative purposes.

The hardness tolerance of the green ASP shows that surfactant precipitation and scale formation could be mitigated. Lower surfactant concentration required to achieve low IFT and contact angle upon addition of alkali shows synergism in interfacial properties and wettability alteration. The ETA–SCA system yielded a better synergy in IFT reduction (minimum IFT of 4.73 × 10-2 mN/m) and wettability alteration (contact angle of 3° in 600 seconds) than the Na2CO3–SDS system (minimum IFT of 0.22 mN/m and contact angle of 5° in 600 seconds). Nevertheless, the conventional AS formulation exhibited better synergism with brine yielding minimum IFT of 1.52 × 10-2 mN/m. The ETA–SCA system also exhibited the ability to emulsify crude oil and form stable emulsions, a desirable property in chemical EOR processes. ETA had an insignificant impact on SPG's rheology, and the viscosity increased when SCA was added. The ETA–SCA–SPG solution showed shear thinning behavior at low shear rates. The oscillatory studies showed that both SPG and HPAM possess viscoelastic properties, with the green ASP retaining the viscoelasticity of SPG while HPAM loses its viscoelasticity in the presence of Na2CO3. SCA adsorption onto the sand surface was made unfavourable at a threshold of 0.3 wt% ETA. The green ASP formulation achieved an additional recovery of ~22%, while the conventional ASP formulation achieved ~19% additional recovery. Therefore, the green ASP formulation proves to have excellent oil recovery potential compounded by its environmentally benign nature.
Case Study of Managing Surplus Surfactant-Foam Generated from Foam Assisted-Water Alternating Gas
Authors: Borhan Noorazlenawati , Saadon Shazleen , Hassan Almila
Published: March 2022

A comprehensive series of experiments on foaming of two (2) types of crude oil and four (4) types of synthesized Gemini silicone- amine base defoamer in simulated produced water system containing foam surfactant Foam Assisted-Water Alternating Gas (FAWAG) package were investigated under the influence of column temperature at 30 – 60 °C, applied pressure of 1 – 4 bar, and fixed fluid flowrate of 0.5 L/min. In this study, the presence of high saturates composition in the crude oil which at 45 – 75.8 % influence the foam stability of the fluids. This reflects the waxy types of crude oils with higher density properties of 0.8768 – 0.858 Kg/L and increase concentration of foam surfactant from 30% to 90% in the produced water system influences the foaming stability. The microscopic observation shows that bigger bubble size about the average of 400 – 500 µm would slows down the liquid drainage, resulting in foam stability behavior. Defoamers with various structures ranged from amine short-chain, amine long-chain, amine branched-chain and amide-chain were analysed to determine the effect of molecular structure at various concentration from 5 – 40ppm. The defoaming ability was determined by foam height and collapse time. The amide short-chain and amine branched –chain had excellent foam breaking performance which was observed from the mean bubble size reduction to 50 – 100 µm resulting from formation of unstable bridge across lamellae causing the foam to rupture, allowing faster liquid drainage, thus improving suppression performance.
U-IMAGe: An Optimised, Efficient and Cost Effective Approach to the Inspection and Maintenance of Upstream Facilities
Authors: W Shafie W Hariz Fadli , Khan Riaz , Mahmood M Rashdan , Mohd Ali Mazri , Zubir Hafiz Azzad , Kamal Girish Chander
Published: March 2022

Objective

The key objective of this paper is to present the methodology of the Upstream Inspection, Maintenance and Assurance Guideline (U-IMAGe) and its implementation across a fleet of ageing assets. The U-IMAGe has been developed within PETRONAS’, Upstream Operational Excellence (OE), Center of Excellence (CoE). The U-IMAGe provides a flexible, efficient, cost effective new way of inspecting and maintaining current assets and equipment, without compromising the inherent safety and health of the asset. The U-IMAGe is applicable to Upstream assets, facilities and equipment including disciplines such as wells, pipelines, structural (offshore, fixed and floating and onshore), electrical, instrumentation, telecommunications, process, storage tanks, mechanical static, rotating equipment, subsea, single point moorings and piping systems.
Autonomous Robot in the Field of Inaccessible Piping System Inspection
Authors: Al-Hannabi Abdoulelah Naji , Rehman Aziz U. , Al-Munif Yousef A. , Al-Musabbeh Kazem Hussain
Published: March 2022

Autonomous inspection robots have emerged as a theme in the digital transformation era, under the umbrella of industrial smart plants for their claimed superiority, safe operation, and cost-effectiveness. Autonomous inspection robots play an essential role in inspecting inaccessible pipelines and process piping, due to their great maneuverability to traverse various bends and geometries, e.g., elbows and T-joints. Saudi Aramco Inspection Department, in collaboration with Shaybah Producing Department, conducted a field trial of an autonomous robot to apply multiple inspection methods simultaneously, in an inaccessible 30" gas pipeline. The robotic system is equipped with motored magnetic wheels to enable movement inside the pipe and can hold the inspection system at certain pre-defined coordinates. The pilot study concluded that the autonomous robot provides accurate corrosion mapping and performs different inspection simultaneously. In addition, the robot has demonstrated great maneuverability inside the pipe in all orientations, i.e. axial, circumferential, and in between. The system has shown a strong potential to inspect inaccessible piping system while minimizing extremely expensive practices, e.g. scaffold erections, excavations, in a timely manner, with ease on logistics and labor.

The use of autonomous robotic scanner provides the operating facility with an option, which is cost-effective and requires a single deployment to complete multiple inspection tasks. The system is capable of replacing the current practice of deploying multiple technologies for a complete inspection inside the pipeline. The system is a self-contained inspection robot that conduct various inspection functions simultaneously, including: Optical Video System, Ultrasonic Guided Waves, Ultrasonic Shear Wave and Ultrasonic Corrosion Mapping with dry-point contact transducers. The system will detect flaws, identify their type and measure the parameters of the pipeline's base metal, welding defects, and provided detailed information and data on the condition of the examined assets, while internally scanning the pipeline. The robot requires, minimum clean-up, and has great maneuverability to go through various bends and geometries, i.e. elbows, T-joints, etc. The autonomous robot can be inserted through the available manhole hatches. The robot is wireless capable and can reach up to 1,000 — 1,500 meters inside the pipe, while being controlled and inspection data is received continuously in outside control room.
Extending the Life Cycle of Old Wells: Fracturing and Replenishing Formation Energy at the Same Time
Authors: Chunpeng Wang , Weiyao Zhu , Weixiang Cui , Min Zhang , Xueqin Huang , Shuzhe Shi , Zhen Nie
Published: March 2022

In order to extend the life cycle of the developed oilfield and ensure the stable production of the oilfield, the exploration and practice of supplementary energy refracturing has been carried out in a small block in eastern China which is on the verge of shutdown since 2017. All of the well in this block are vertical wells. This technology breaks the injection production relationship of the original well pattern. The injection wells and production wells are fractured at the same time. Fracturing fluid is not only used for fracturing, but also for supplementing formation energy. In order to produce more new fractures and make them more complex, low viscosity slippery water is used in hydraulic fracturing. It ensures that the material cost is reduced while the amount of fracturing fluid is increased. In addition, the multi-stage proppant combination is used to support all levels of fractures, which improves the conductivity of all levels of fractures. During the implementation of refracturing, the amount of fluid used in single layer is gradually increased, from 2300 to 3500 cubic meters, the maximum amount of fracturing fluid injected in single layer is 10000 cubic meters, and the proportion of slippery water is increased from 80% to 95%. The proppant is composed of 100/140 mesh and 40/70 mesh ceramic proppant, with an average sand content of 97.7 cubic meters per layer. From the perspective of construction data, after increasing the amount of fracturing fluid used in single well, the average pump stopping pressure of the later batch of construction wells is increased by 3.5 Mpa and the construction pressure is increased by 4.5MPa. After adding temporary plugging agent, the average construction pressure increased by 1.8 MPa, and the opening characteristics of new joints were obvious. After refracturing, all test wells are produced by automatic injection production, the total number of automatic injection production days is 5.2 times of the initial fracturing, and the cumulative oil production is 1.5 times of the initial fracturing. Through practice, the original injection production relationship is broken. Increasing the amount of fracturing fluid can not only supplement the formation energy, but also improve the complexity of fractures. The multi-stage proppant slug can significantly improve the conductivity of fractures at all levels, prolong the life cycle of old wells, and provide technical support for multi thin layer reconstruction.