bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Use of Advanced Logging Technologies to Identify the Hidden Hydrocarbons in an Interbedded Sandstone-Shale Reservoir
Authors: Nugroho Cahyo , Bouchou Ramdane , Ghioca Monica , Le Viet , al-Turkey Shaikha 
Published: March 2018

Abstract
This paper presents a detailed study on how to detect the presence of light-oil in a low-resistivity and interbedded sandstone-shale environment. Based on the basic log response (high GR readings, 45-55 API, low resistivity values, 3-5 ohm.m, low-to-moderate porosity), the studied interval was considered a non-oil bearing zone. The interval was re-evaluated by adding some advanced technologies and the results showed the zone to be oil bearing. Fluid sampling has confirmed that the zone is oil bearing zone.
The advanced logging technologies were magnetic resonance, mineralogy and high-resolution borehole electrical imaging. The mineralogy tool was logged to identify and quantify the formation minerals and also the clay typing. The magnetic resonance tool was used to identify the different fluids inside the pores and also to measure the fluids saturations. The high-resolution borehole electrical imaging was used to analyze the sedimentary facies and the formation structures. At last a sample of the formation fluid was successfully taken after flushing out the filtrate from the formation for about 10 hours and pumping out about 40 liters.
The NMR technology played an important role in detecting and quantifying the oil over the interbedded sandstoneshale zone. The fluid typing analysis of magnetic resonance measurements identified up to 50% oil saturation with permeability index ranging from 10 to 20 mD. As the tool can only read between 2 and 4.2 inches inside the formation, the saturation analysis is affected by the mud filtrate. This means that the actual oil saturation might be much higher than 50%. The mineralogy tool showed 25-35% volume fraction of clay, mainly illite, kaolinite, smectite, and the remaining volume is quartz. These fractions indicate that the interval is shaley. Because of its low vertical resolution, it was not possible to see any interbeds with the mineralogy tool. However, the high resolution borehole electrical imaging showed clearly the formation sedimentary structures which are interbedded sandstoneshale. The fluid sampling has confirmed that the low resistivity pay in the interbedded sandstone-shale interval is an oil bearing reservoir.
This type of reservoirs is usually underestimated when evaluated with only the standard logging technologies, because of the effect of the shale laminations on the measured formation resistivity. So, in such environment, the use of different technologies is required to first understand the nature of the environment and also to overcome the impact of the laminations in identifying the presence of oil and also quantify it.
The combination of the NMR, mineralogy, high resolution imaging and fluid sampling technologies has proven its successfulness over interbedded sandstone-shale reservoirs.
Development of a Novel Compact Sand Sample Analyzer Mitigates Space and Time Constraint
Authors: Gupta A. , Salleh N. I. , Tan B. C. , Choi Y. X. , Zulkifli N. M. Q. M , Hassan A. F. , Manaharan I. , Harun H. E. 
Published: March 2018

Abstract
Analysis of sand sample to get sand concentration in oil wells requires a proper set-up with significant footprint in a sand producing oil platform. Also, the conventional procedure used by most operators result in high time consumption leading to delay in results if required immediately. Logistics of having a lab at the platform is also a challenge. Further, evaluation of particle size distribution becomes a further challenge in a limited space. The paper describes development of a compact sand sample analyzer with a reduced foot print and quick analysis for better decision making. The current methods of sand count analysis were analyzed in detail and various options were look into to save the foot print and time on the analysis of sample so that sampling compliance can be met. The two main steps in standard sand production concentration measurement method i.e. heating of sample to dry and remove moisture and weighing the sample accurately required two different sets of equipment and it is time consuming. A moisture analyzer equipment is replaced by these two equipment making the entire system very compact and reducing the duration of results from hours to minutes. Also, the sieve size of sample collection was reduced to accommodate a smaller footprint PSD Analyzer as well. The proposed set-up was tested in lab and it is found that a 3 hours procedure of evaluating sand count was reduce to 20 minutes i.e. increasing the efficiency almost ten times. When comparing the logistics challenge, the sand count result turn around time was reduced from almost 7 days to few hours. Similarly, the compact PSD set -up resulted in cost saving of conducting in house PSD and getting such a data in a matter of hours. All this lead to huge cost saving and most importantly efficiency in complying with sampling standards. The standard practice where minimum of 3 personnel with more than 10 sq. ft. of equipment footprint and more than a day require to get the result is reduced to a 20 kg suitcase with only one personnel and less than 30 minutes for the total analysis. The novel idea of using a moisture analyzer in place of the two equipment had a uniqueness because in this case moisture analyzer was indirectly used for some other purpose. Also, the modification in sieve could not have made this set-up compact. The sampler has proved a breakthrough for sampling analysis for all major sand producing fields within operator and this unique idea will benefit industry as a whole.
Real Time Condition Monitoring of the Wellbore Seal through Hydraulic Fluid Analysis Using an Active Wellbore Sealing System during Managed Pressure Drilling
Authors: Johnson Austin , Sundaramoorthy Saravanan , Piccolo Brian , Fraczek Justin 
Published: March 2018

Abstract

Objectives/Scope
This paper introduces an active wellbore sealing system for use in Managed Pressure Drilling (MPD) incorporating a wellbore seal condition monitoring system. The paper will discuss how finite element analysis which has previously been validated with full scale testing can be expanded to develop the condition monitoring system.

Methods, Procedures, Process
In contrast to a passive rotating control device, an active MPD wellbore sealing system requires hydraulic pressure to engage a sealing element and form a wellbore seal. The paper will investigate the relationship between wellbore sealing pressure and hydraulic fluid parameters using the results of finite element analysis on a sealing technology which has been previously operated offshore in addition to extensive full-scale testing in a lab environment.

Results, Observations, Conclusions
The paper will show how the required hydraulic fluid requirements to form a wellbore seal change over time due to sealing element wear. The information can be used to predict the remaining life of the existing sealing element as well as proactively alarm the driller of the need to replace a seal sleeve due to a sudden deviation from expected behavior. The implementation of a real-time, condition monitoring system for the MPD wellbore seal is intended to increase the rig's confidence toward using MPD for challenging hole sections as well as circulating out small influxes from the well without closing the SSBOP, further reducing the risk of stuck pipe events.

Novel/Additive Information
The active MPD wellbore sealing system is a non-rotating, offshore wellbore annular sealing device which is integrated into the riser. It contains a seal of elastomeric composition which seals against drill pipe during all tripping and drilling operations. As the seal wears, the hydraulic closing fluid requirement to maintain an annular seal changes, which indicates the amount of seal material remaining.
High-Speed Robust Simulation Delivers Fast, Detailed Results for a Complex Offshore Field
Authors: Thapliyal Anil , Kundu Sudeb , Dimri Sunil Kumar , Dutt Ankit , Mishra Shubham , Aggarwal Akshay , Agarwal Ankit , Ojha Aditya , Bradley David , Giddins Marie Ann 
Published: March 2018

Abstract
For planning the operations of Oil and Natural Gas Corporation Limited (ONGC) in the complex Heera field, it was estimated that over one hundred simulation runs would be needed to complete the history match of the field and almost the same number of simulations would be needed for production forecasting. Heera is a large field, with multiple faults and seven stacked carbonate formations. There are significant variations in petrophysical properties, and variable degrees of communication between reservoir zones. The simulation models include 479 wells with commingled production or injection. Well trajectories are complex and include multilateral and horizontal configurations. Field development options include use of simultaneous water alternating gas (SWAG) for enhanced oil recovery.
Combining all these features, it would be difficult to run all the necessary sensitivity cases within the required project timeline, using a conventional reservoir simulator. Therefore, it was decided to test the applicability of a new generation simulation tool to address the challenges of the study.
To ensure that the change of simulator would not impact the integrity of the model, rigorous quality checks were performed on the input data. After successful evaluation, the new software was used for the reservoir engineering study.
The decision to apply the new simulator significantly reduced the elapsed time, with some realizations over 20 times faster compared to the original base case. As a result of this speed-up, numerous runs could be carried out to refine the history match. Multiple sensitivities could be used to help understand and reduce the uncertainties in a more comprehensive manner. Moreover, the prediction cases could be optimized to identify the best recovery strategy.
This study has demonstrated the value of reducing simulation run times, to complete the project with greater efficiency and more confidence in the results. In future studies, high performance software tools can also enable use of fine resolution models, to capture detailed heterogeneities and optimize areal and vertical sweep.
FIELD A A New Solution for Marginal Field Development
Authors: Shaipulah Ahmad Adzwan Bin M , Ahmad Mohammad Azharie B , Othman Sy Nafisah Bt Sy , Rahman Ahiruddin B Ab 
Published: March 2018

Abstract
FIELD ‘A’ Project is presented as a low cost development concept for marginal oil field. The development concept consists of wellhead platform with a full well stream evacuation scheme through a flexible flow line to FPSO for further processing and subsequently for export. The unutilized associated gas is flared. As a part of cost reduction strategy and incentive, the Host Authority has approved a new contract model and technological approaches for implementation.
FIELD ‘A’ Project is undertaken and monetized via a new approach of marginal oil field development under the Risk Service Contract (RSC). The uniqueness of the FIELD ‘A’ development concept is the technological introduction of re-locatable type fixed asset using Suction Pile Technology (SPT) for jacket installation thus allowing it to be transported and utilized at other potential marginal field within the asset design life. SPT is a traditional jacket with integrated suction pile foundation, which triggered significant benefit and long term cost reductions in the fabrication and offshore installation.
The 1100 MT jacket is designed using suction pile technology that enables the platform to be relocated to other potential marginal field. SPT is proven to be a highly efficient and very swift concept where the jacket offshore installation campaign can be successfully executed in less than 24 hours as compared to the conventional jacket installation, which require several days of pile driving. Fabrication costs are reduced significantly since no requirement on the pile sleeves, catchers, centralizers, mud mats, and leveling pad eyes. Substantially, SPT jacket is proven to be that of one of the most cost effective in comparison to other re-locatable type offshore mobile facilities such as MOPU and MOAB. SPT is also integrated with scour protection; hence no seabed preparation or rock dumping is required. Therefore, the offshore campaign for SPT would promote lower installation cost, improved schedule and most importantly safety. In conclusion, the jacket with integrated suction pile foundation promotes and accordingly justifies the development of marginal field.
In the current environment of low oil price, developing a new marginal field in such a way is necessary so as to maintain or improve the overall economic of the project. This fit for purpose and hybrid SPT concept with a rigid substructure that can be easily relocated is definitely worth to be implemented.
Approach to Corrosion Management Program and Risk Based Inspection Development for the World's First Floating LNG
Authors: Mohamed Nurul Asni , Mahani Zulkarnain , Razak Liyana Afiqah Abd 
Published: March 2018

Abstract
In performing the Corrosion Management Program (CMP) study for PETRONAS Floating Liquefied Natural Gas Satu (PFLNG1) which is located at the Kumang-Kanowit Gas Field in Sarawak, a total of 59 Process, Utility and Marine units were analysed which resulted in the development of 111 Corrosion Groups (CGs). 17 potential degradation mechanisms are identified, encompassing internal and external corrosion. Anticipating the short term and long term corrosion rates are made possible by leveraging on PETRONAS database. Appropriate corrosion mitigation and monitoring recommendations are made for the control of a few corrosion mechanisms. These are managed through the application of the in-house software, CARAT.
Some challenges were encountered during the PETRONAS Risk Based Inspection (PRBI) assessment. The Plant and Instrument drawings for the shipping industry are not as detailed as that typically used for the oil and gas industry, giving rise to general assumptions for PRBI evaluation. The consequence of failures in the risk assessment are assigned taking into account the available maintenance items onboard and anticipated deployment of items from onshore. Risk analysis helps to identify critical items to be kept onboard. The Inspection Reference Plan developed evaluates the most efficient inspection intervals and the identified CMLs will reflect susceptible as well as accessible areas. CARAT and PRBI are now online and dutifully used by the end user to complement the execution of CMP and PRBI programs.
Engineering Simulation for Loadout of a Tension Leg Platform
Authors: Sinha S. K. , Luquiau Eric , Reddi Satish 
Published: March 2018

Abstract
Accurate prediction of loads on any large offshore structure during loadout and transportation is of utmost importance, not only for the design of the structure but also to predict operational margin and prevent any unwanted damage onto the structure during the process.
The design and engineering of Tension Leg Platforms (TLP) are usually carried out in accordance with the API 2T, MODU Codes and applicable company specifications/requirements. These codes provide extensive guidelines on design of TLP with respect to operational loads but specifics of simulation of loadout are not explicitly mentioned. This paper presents a method to estimate the loadout loads on any large offshore structure, in this case a TLP.
The loadout operation of TLP usually comprises of lifting of the structure, i.e. the hull with its topsides, to transfer the loads from temporary support blocks onto jacks followed by skidding of the structure through a distance to the quayside and then crossing over the structure from the quayside to the Heavy Transport Vessel (HTV) and finally setting down the structure onto the HTV to transfer the loads from the jacks to the skid shoe guide posts and additional support structures, on HTV.
It is the objective of this paper to present an optimized method of grouping the jacking system for safe transfer of loads during the above operation. This paper also talks about simulating and predicting the series of loads on the hull of the TLP during the entire process of loadout, crossover and setting down.
From Resource Extraction to Knowledge Creation: The Promotion of Local R&D through Upstream Regulations
Authors: Lima-de-Oliveira Renato 
Published: March 2018

Abstract
Oil-rich countries have long attempted to maximize its capture of oil wealth, traditionally using the direct production through NOCs or setting a high government take in contracts with IOCs. More recently, contracts and regulations have also focused in localizing manufacturing (local content) and promoting domestic capabilities in R&D. While local content regulations have received more attention in the scholarly literature, regulations to promote R&D, their effectiveness in promoting spillovers and their effect on oil company's strategy is yet an understudied area. This work studies the regulations and practices put in place by oil-rich countries, and particularly Brazil, Mexico, and Malaysia, to promote R&D through contractual obligations, such as levies earmarked to R&D and investments in knowledge institutions. It is based on the analysis of legislations, data on funding for research institutions, and interviews in the three countries with policymakers, regulators, oil company executives, and scientists to answer two questions: a) What policies have been used by oil-rich countries to promote R&D&I in the oil industry?; and b) how these policies influence the strategies of oil companies? This study shows that regulations in the oil industry can effectively contribute to the promotion of local capabilities in R&D, but issues of policy design are crucial to maximize the effectiveness of such policies. As the oil industry, and the offshore in particular, becomes more high-tech and subject to pressures to localize their investment, demands for local R&D are expected to increase. However, the set of policies that can capture wealth from current oil production – maximize government take – differ substantively from the capabilities and institutional complementarities necessary to promote knowledge.
Operating Envelope for Oil Pipelines in Caspian Sea
Authors: Azman Syahida Husna bt , Norpiah Rohaizad b M 
Published: March 2018

Abstract
Flow assurance problems related to flow slugging, hydrates, and wax gelling lead to this study, post two integrated oil pipelines clogged in the Caspian Sea during the winter season. The methods and proposed solutions will be further deliberate, which includes the development of operating envelope to ease implementation. The overall methodology is based on dynamic flow assurance simulation and mathematical analysis, which was adapted depending on the problem being studied. Reduced production and terrain undulations had caused severe slugging in both pipelines which are flowing multiphase fluids. The bifurcation analysis of slug control valve will be discussed to determine the best choke opening that can eliminate slugging. The flow slugging also caused hydrate risk that was made worst during shutdown. Few strategies of hydrate mitigation including implementing extra heat insulation at riser air gap, gas flaring, optimised and overdose injection of mono ethylene glycol (MEG) were considered. Hydrate mass was evaluated for all the mitigations and requirement to inject lean MEG immediately after shutdown or prior start-up was identified. In terms of wax management, lower Flowing Tubing Head Temperature (FTHT) from wells added a challenge with limited facilities capability to operate more than the wax appearance temperature (WAT). Operating envelope of crude oil heater under heating limitation will be clearly shown to avoid operating in wax region. The development of operating envelope had enabled Operations personnel to know the safe condition to operate both pipelines during critical scenarios. The approach has changed the way the company operates, to ensure production is protected and maintained with minimal disruption caused by slugging, hydrate and wax gelling events.
Numerical Simulation of Free Surface Flows Using Overset Mesh
Authors: Khaware Alok , Srikanth Kvss , Gupta Vinay Kumar 
Published: March 2018

Abstract
Overset method is validated for different free surface flow applications to demonstrate its capabilities and benefits over traditional dynamic mesh approach. An overset mesh consists of a set of overlapping component meshes, which allows complex geometries to mesh with lesser effort. Interpolation methods are enforced at internal boundaries to ensure a continuous solution in overlapping component zones. Overset methodology is not perfectly mass conservative by its design. Present study in this regard, demonstrates the benefit of higher order interpolation method on simulation accuracy and mass conservation. The simulation results for various case studies involving static and moving overset meshes are validated against analytical, experimental and equivalent non-overset mesh results using ANSYS Fluent.
Finite volume method (FVM) with pressure based coupled solver is used to solve Reynolds Averaged Navier Stokes equations. Free surface flow is modeled using Volume of Fluid Method (VOF) which capture interfaces between immiscible fluids. Pseudo-transient method is adopted for steady state applications to get better robustness. A pure advection of slotted circle is simulated where its revolution is forced along the static overlapping zone, final shape and position is compared with initial state after one revolution. A non-linear Stokes wave with high steepness is propagated in a numerical wave tank which contains multiple static overlapping zones in the vicinity of free surface, where simulation results of free surface and velocity profiles are verified against analytical profiles. Flow over a bump for subcritical to subcritical and subcritical to supercritical regimes are verified against analytical results. Flow over a submerged hydrofoil using static overset mesh is validated against experimental result for free surface profile. A rotating gear case involving moving overset mesh is compared with sliding mesh results for free surface and pressure profiles. A case involving transient heave oscillation of floating cylinder is validated with theoretical, experimental and equivalent dynamic mesh results.
Floating Hydrocarbon Storage Facility
Authors: Awn Paul Ong Pang , Chai Patrick Yap Gwo 
Published: March 2018

Abstract
Bunkering and oil storage is a growing and important business in Singapore. Driven by land scarcity, NUS and SINTEF are tasked to jointly explore the innovative concept of a Floating Hydrocarbon Storage and Bunkering Facility (FHSBF) off the coast of Singapore. The research collaboration, funded by Land and Livability National Innovative Challenge (L2 NIC) and JTC Corporation, aims to explore new ways to create useable space from sea. The floating facility will add to the current storage capacities of Singapore without the need for land reclamation. The Floating Hydrocarbon Storage Facility is a novel and viable concept to introduce useable space on sea. It allows for a land-scare country like Singapore to increase oil storage capacities without the need for land reclamation. The concept can be relocated and replicated in other locations with similar needs.