bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Load Shedding and Gas Turbine Generator Control Improvement for Banyu Urip Field Blackout Prevention
Authors: Kusumaskiki Galih , Putra Yoga Hutomo 
Published: November 2020

Abstract
Banyu Urip, which is the highest producing oil facility in Indonesia with 220 kbd, generates up to 40 MW electrical power to maintain production. Any power blackout results in significant production upset including high flaring. This is exacerbated by usually extended recovery time post power blackout due to complex electrical distribution system. The Banyu Urip facility has experienced production loss due to historical power blackout events, most recently in 2019. This paper provides a case study on optimizing load shedding and gas turbine fuel control system, which could serve as learning for other power generation facilities in various industries for designing a robust blackout prevention system.
An integrated blackout prevention system comprises of Electrical Control and Monitoring System (ECMS) as primary load shedding, Gas Turbine Generator (GTG) temperature peaking control, and backup load shedding by under-frequency protection relay is designed. All these load shedding layer of protection cover multiple blackout prevention scenarios or protection system element failure such as GTG trip, overloading, and ECMS failure.
Multiple parameter analysis and simulation were performed to determine characteristic of each protection layer. Turbine exhaust temperature response, load, fuel supply, as well as generator frequency are all taken into consideration for the integration of blackout protection layer.
Key factor for the seamless integration is timeline of each element to work and for backup element to activate. All must be done within GTG overload capability corridor.
ECMS load shedding system is put as the frontline to prevent overload in case GTG trip. As the backup layer, protective relay will enable under-frequency load shedding upon overload and GTG slowdown. GTG temperature peaking control and under-frequency set point are properly designed to ensure that the under-frequency relay is operating.
After implementing these optimizations, load shedding is proven to work very effectively and there has been some GTG trip events without blackout nor significant production impact.
Evaluation of system performance continues as Banyu Urip Central Processing Facility (CPF) operates. The results will be critical for reliability improvement as well as production continuity assurance. In other words, this also provides a best practice for blackout mitigation to optimize successful power generation facility operation.
Investigation of the Failure Mechanism and Complicated Wellbore Instability Issues in the Drilling of the Extra Deep Fractured Carbonate Reservoirs in Shunbei Field, NW China
Authors: Chen Xiuping , Li Shuanggui , Wang Shanshan , Gui Feng , Zhou Yongsheng , White Adrian 
Published: November 2020

Abstract
The Ordovician fractured carbonate reservoir in the Shunbei field is buried ~7300m below ground level and has presented great challenges for the drilling of extra deep, deviated development wells. Borehole instability-related drilling problems including pipe stuck, pack-off, and mud losses have been experienced frequently during drilling, with many wells being sidetracked three or four times before reaching the target. To understand the failure mechanism and optimize the drilling design to mitigate the drilling risk has become crucial for the field development.
As the basis of the investigation, detailed geomechanical modelling was conducted for a selected area with the most representative drilling problems. Laboratory core tests, wireline logs, image data and drilling experiences were used to build geomechanical models characterizing the in situ stress, pore pressure and rock mechanical properties in both the overburden and reservoir sections. Stress-induced borehole failures observed in the image logs were analysed to help diagnose the failure mechanisms together with the cavings recovered from the problematic wells, which provided significant insights into the likely nature of instability problems in the wells.
The geomechanical modelling from a series of wells revealed that the stress magnitudes in the selected area vary based on the structural location. The wells near the major fault system appear to be in a normal faulting stress regime in the Ordovician reservoir, while the wells nearby the secondary fault system are in a strike-slip faulting stress regime. Different stress regimes and horizontal stress anisotropies have resulted in different behaviors during drilling, with breakouts seen in some vertical wells while not in other vertical wells despite using similar mud weights. during drilling. The variable stress conditions plus the highly developed fractures have caused serious borehole collapse in some wells, but reasonably good hole condition in other wells. Wells using higher mud weight are not necessarily the ones having fewer drilling problems. Although the complex lithology, great depth, and unpredictable distribution of intrusive rocks has complicated the drilling problems, a proper definition of suitable mud weight to control borehole collapse and understanding of the natural fractures might play a bigger role in maintaining borehole stability and mitigating drilling risk.
A good understanding of the stress condition and rock mechanical properties appears to be helpful in defining the proper mud weights and optimizing other drilling parameters to help mitigate the complex drilling problems encountered during drilling in the Shunbei field. However, additional work on the fracture distribution and trend of stress change in the field might be required to help investigate the problem further.
Operational Considerations During Gas-Condensate Well Start-Up
Authors: Chan Cynthia , Zhang Jeff 
Published: November 2020

Abstract
Gas hydrates are ice-like crystals formed by gas and water molecules under low temperature and high-pressure conditions. Avoiding the formation of hydrate plugs is one of the critical tasks that continuously challenges oil and gas operators, especially as oil and gas operations move into deepwater reserves. Common mitigation measures for hydrate formation and plugging include the traditional control methods of injecting thermodynamic inhibitor that assure the operational conditions are outside the hydrate risk region. However, inhibitor injection rates are typically designed based on the worst operating conditions (i.e., maximum pressure and minimum temperature) with significant safety margin. During transient operation such as well start-up, the risk of hydrate formation is higher compared to normal operation and requires significant volume of hydrate inhibitor. This paper presents two case studies that integrate field experience into design to optimize design scenarios for hydrate prevention during gas-condensate well start-up. The first case study shows how the shutdown and start-up scenarios typically considered for design are benchmarked with historical data to avoid unrealistic over-conservatism when creating design scenarios for well start-up. By benchmarking with historical data, the MEG injection rate is able to be reduced by 30%, which in turn increases economic feasibility of the offshore gas-condensate field development. In the second case study, the hydrate inhibitor rate was reduced by 50% by adopting current field practice into design and using state-of-the-art hydrate kinetic modelling to determine the likelihood of hydrate formation and the transportability of hydrates in flowlines. Combining field experience into design reduces constraint to the hydrate inhibitor distribution system, optimizes usage of topside facilities and aids in the development of hydrate management strategy for the field as a whole.
Flow Assurance Challenges for China’s First Deepwater Gas Field Development in South China Sea
Authors: Lau Lawrence Khin , An Kun , Tang Xian Di , Luo Fei Jian , Yang Yang , Zhao Wei Qing 
Published: November 2020

Abstract
This paper elucidates the key flow assurance challenges for China’s first National Deepwater gas field development in South China Sea and the facilities design forming the overall flow assurance management strategy. The discussion covers early stage feasibility studies through current stage of project execution. In addition, the finding of flow assurance analysis serves as key input for start-up and commissioning guidelines as well as operating procedures.
The development consists of a semi-submersible, with the Eastern and the Western loops spanning more than 40 km of Subsea Production System (SPS). Due to long subsea tiebacks, integrated flow assurance analysis is rolled out to ensure comprehensive risks analysis and active risks management. In particular, key challenges associated with typical Deepwater characteristics such as high pressure and low temperature are actively managed. With design water depth of more than 1500 m and more than 10 Deepwater subsea production wells, robust flow assurance management strategy is required from early activities such as well unloading, well test, pre-commissioning, first gas, through late life decommissioning.
Integrated approach is implemented for overall system thermohydraulics analysis, which is used as basis for key flow assurance assessments, including but not limited to management strategy for hydrate, scales, erosion, and slugging. Detailed management strategy and philosophy are discussed in the main body of this paper. Overall chemical management strategy, for instance, is fully optimized to reduce Health, Safety, Security and Environment (HSSE) impact, coupled with sufficient safety margin to ensure minimum downtime.
Through integrated flow assurance analysis, all key risks are identified and actively managed. This shows the importance of integrated flow assurance approach to ensure overall project safety and integrity. More importantly, overall optimization can be successful rolled out when the field is in production. This serves as a positive lesson learned for future Deepwater development in South China Sea.
Miscible CO2 Flooding Simulation with a Compositional Model in Middle East Carbonate Reservoir
Authors: Wu Shuhong , Fan Tianyi , Zhao Lisha , Peng Hui , Wang Baohua , Ma Xuesong 
Published: November 2020

Abstract
CO2 injection has proven to be a promising technology in enhancing oil recovery in low-permeablility carbonate reservoirs, especially in miscible flooding. How to demonstrate near-miscible/miscible mechanisms and their influence on production performance is a difficult issue to deal with in a compositional simulation. In this paper, considerable research has been conducted on compositional models, especially miscible gas flooding models, by identifying the near-miscible/miscible state and its influence on relative permeability.
This paper describes a multi-component, three-phase, compositional model for simulating miscible CO2 flooding problems. An EOS equation is constructed for phase equilibrium and property calculations. Gibbs stability model is developed to determine whether a hydrocarbon mixture at a particular temperature and pressure is more stable in a single-phase state or in a two-phase state. An interfacial tension (IFT) weighted relatively permeability model is developed to calculate the relative permeability in a near-miscible state. With the help of the Gibbs and Kr models, miscible CO2 flooding in a carbonate reservoir is simulated to evaluate the miscible and immiscible state and demonstrate the production performance.
The Gibbs stability model determines the tangent plane of the Gibbs energy surface at the mixture composition and parallel tangent planes at possible incipient phase compositions. If any of the parallel tangent planes lie below the tangent plane of the mixture composition, a two-phase state will exist. The simulation shows that a Gibbs stability model in CO2 injection can identify whether the hydrocarbon mixture (oil) and CO2 at reservoir pressure and temperature is in one phase state (miscible) or in a two-phase state (immiscible). The IFT weighted Kr model determines an interpolation between immiscible and miscible states using a weighting function, which is a function of IFT with a specified critical gas/oil IFT to control the contribution of the near-miscible effect on kr. The compositional simulation shows that CO2 becomes miscible with a hydrocarbon mixture under the condition of CO2 multi-contact with the hydrocarbon mixture in the reservoir pressure and temperature. Three areas exist between the injector and the producer which are the immiscible area (IFT: about initial value), near-miscible area (IFT: 0.5~2) and miscible area (IFT: lower than 0.5). The residual oil saturation of the miscible CO2 flooding area is around 5%. Oil recovery is enhanced compared with the previous hydrocarbon gas injection.
CO2 injection represents a promising technology to improve production performance and to enhance oil recovery for the carbonate reservoir mentioned in the paper.
Inversion of Advanced Full Waveform Sonic Data Provides Magnitudes of Minimum and Maximum Horizontal Stress for Calibrating the Geomechanics Model in a Gas Storage Reservoir
Authors: Pallikathekathil Zachariah John , Yang Xing Wang , Hafezy Saeed , Puspitasari Ratih , Harris Rodney I. , Sutton Jacqueline T. 
Published: November 2020

Abstract
In 1D Geomechanics projects, calibration of stress is extremely important in the construction of a valid Mechanical Earth Model (MEM). The minimum horizontal stress data is usually available from LOT (Leak-off test), XLOT (Extended Leak-off test), Open hole stress tests, or cased hole Mini Fall off Test (also called Diagnostic Fracture Injection Test – DFIT). These traditional measurements have a few deficiencies.
This paper presents an application to a gas storage field, where stresses are derived from a newer unique approach where the radial variation of acoustic velocity from advanced dipole sonic logging tool is inverted to obtain stress. These derived stresses are then utilized to calibrate the 1D MEM for the gas field. This approach addresses some of the deficiencies of traditional approaches of deriving stress magnitudes. The characteristics of this approach are:Both the minimum horizontal stress (Shmin) and maximum horizontal stress (SHmax) are obtained. Traditional approach provides a value for Shmin only.These measurements are obtained in reservoir zones at multiple depth intervals. Traditional approaches provide a measurement at one depth only.This method is applicable to all formations that are acoustically stress sensitive.This method is relatively more cost effective as compared to traditional approaches where rig time is a premium considering that advanced sonic logs are routinely run for other applications as well.
The sonic data was processed to derive a dispersion plot (velocity versus frequency). From this plot, a plot of velocity versus radial distance is derived. As Kirsch equation provides a radial variation of the stress with distance for a hole drilled in a uniform stress field, and variation of stress translates to variation with velocity, a parametric inversion is utilised to derive the stress.
In this gas field, no LOT or XLOT were available. However, the advanced dipole sonic logging tool was recorded in a well recently drilled and some of the formations were found to be acoustically stress sensitive as observed from the dispersion plot. Therefore, this inversion technique was applied and Shmin and SHmax were obtained that were extremely useful to calibrate the 1D MEM.
This technique is unique in the industry and complements existing methods to obtain stress measurements for 1D MEMs where stress measurements are either not available or expensive to obtain. This method is not widely used. The authors hope that this paper will illustrate how this method was used in this gas field and encourages other users to investigate the application of this method in their fields, when traditional data is limited.
Regulatory Challenges and Opportunities for Optimising Petroleum Resource Stewardship in Offshore Australia
Authors: Miranda John , Hamp Roland , Cocodia Erebi , Filbay Nicole 
Published: November 2020

Abstract
The challenges and insights presented in this paper provide a unique case study of Australia’s evolving offshore petroleum industry from a regulatory lens. It documents how a regulating agency’s unique perspective can identify opportunities to optimise recovery, contribute towards improvements in good oil practice and ultimately adapt to the changing requirements of industry.
This paper sets out the regulatory landscape, as well as the challenges that exist in managing an innovative, adaptive and evolving offshore petroleum industry. Australia’s offshore resource stewardship strategies must now respond to a more established, maturing, more ‘crowded’ and dynamic petroleum landscape. This challenges regulators to be increasingly responsive, adaptive, continuously improve practices and be well-informed regarding global trends, such as those affecting mature provinces. Opportunities to exchange ideas, collaborate and incorporate key learnings from other offshore regulatory regimes are considered key enablers towards achieving these goals.
Australia’s maturing petroleum provinces are impacted by long distances, (relatively) low infrastructure density and greater water depths; whilst increasingly challenged to integrate smaller, deeper and economically marginal resources. Conversely, emerging/recently established production areas are now facing an increasingly dense infrastructure landscape with multiple potential development pathways. In contrast to traditional system-wide blanket or "title-by-title" approaches (particularly with respect to optimal use of existing infrastructure), effective resource stewardship requires an increased level of consideration of "area" or "regional" developments. A more responsive and adaptive approach, which fosters collaboration and effective dialogue between the regulator and industry, improves regional understanding and contributes toward optimum resource recovery (via lower life-cycle costs and accelerated production opportunities).
Experimental Investigation on EOR and Flowback Rate of Using Supercritical CO2 as Pre-Fracturing Fluid in Tight Oil Reservoir
Authors: Li Lei , Su Yuliang , Chen Zheng , Fan Liyao , Tang Meirong , Tu Jiawei 
Published: November 2020

Abstract
Fracturing is the necessary means of tight oil development and the most common fracturing fluid is slickwater. However, the loess plateau of ordos basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely expensive and bad for the environment. In this paper, a new method using CO2 as pre-fracturing fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of supercritical CO2 characteristics and mixed water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production after full interaction with formation fluid, which is a development method with broad application prospect.
In this work, the main mechanism, the the system energy enhancement, and flowback rate of CO2 as pre-fracturing fluid are investigated. Firstly, the microscopic mechanism of CO2 fracturing was studied, and the effects of CO2 on pores and rock minerals were analyzed by NMR test, XRD analysis and SEM experiment. Secondly, the high pressure chamber reaction experiment was conducted to study the distribution and existence state of supercritical CO2 in the multiphase fluid during the full-cycle fracturing process. Finally, four injection modes of CO2 injection experiments were designed to compare the pressure increase, production enhancement, and flowback rate of CO2 and slickwater, so as to optimize the optimal CO2 injection mode and the optimal injection amount of CO2 slug.
The results show that supercritical CO2 can increase the porosity of rocks by dissolving calcite and clay minerals (illite and chlorite) that gather around the pores according to the changes of pore size and rock composition before and after CO2 action. Supercritical CO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of fracturing energy increase and production enhancement. After analyzing the four different injection modes tests, the optimal one is to first inject CO2 and then inject slickwater for fracturing. The CO2 slug has the optimal value which is 0.5 pore volume in this study.
In this study, supercritical CO2 is used as the pre-fracturing fluid, providing a new idea for the stimulation of tight oil. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 pre-fracturing. The application of this method is of great significance to the protection of water resources and the improvement of fracturing effect.
A Comparative Review of Production Logging Techniques in Open Hole Extended Reach Wells
Authors: S Duthie Laurie , A Saiood Hussain , A Al-Anizi Abdulaziz , A AlGhamdi Talal 
Published: November 2020

Abstract
Successful reservoir surveillance is a key component to effectively manage any field production strategy. For open hole extended reach horizontal wells, including some wells over 30,000 ft in length, the challenges to successfully deploy real-time logging tools are greatly magnified. This is further complicated by constraints in the completion where Electrical Submersible Pumps (ESP's) are installed. A comparative review of the latest technologies and methods available to overcome these challenges will be explored.
The challenges are formidable and extensive; logging these extreme lengths in cased hole would be difficult enough, but are considerably exaggerated in the open-hole condition. The logging run in open hole must also contend with increased frictional forces, high dogleg severity, washouts and an increased well bore rugosity. The main challenges to achieve the logging objectives in open hole extended reach wells, are 2-fold, namely;
To log the entire open hole section and reach the Total Depth (TD) of the well. To obtain high quality data from the logging tools, despite the adverse downhole environment.
To achieve these 2 main objectives, a comprehensive approach is taken while designing the logging operation. The choices available to deploy the logging tools are mainly on electric-line cable with an electric powered tractor or on coil tubing with a hydraulically powered tractor. The most common type of log performed in these extended reach wells is a production log to measure multi-phase inflow contributions. To improve the success rate of the logs, a number of initiatives have been implemented, including deployment of custom designed coil tubing tractors and state of the art wireline tractors. The logging tools and job programs are adapted based on the results of simulations, accounting for many variables, including the completion, well type, deviation and target depth.
The ability to successfully log these extended reach wells cannot be understated, reservoir simulations and management decisions can only as good as the quality of data available. Some of the advantages of drilling mega reach wells such as increased reservoir contact, reduced footprint and less wells drilled will be lost if adequate reservoir surveillance cannot be achieved. To meet the key objectives, creative solutions including designing and upgrading the best fit for purpose technologies are applied for the extended reach wells. These steps taken not only improve the overall logging performance, they can also result in cost savings by avoiding multiple unsuccessful logging runs.