bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Use of Preservation Chemicals for Extended Shut-Ins Following Hydrostatic Testing of Gas and Service Pipelines
Authors: Hali A. L. , Lehmann M. N. , Cook S. E. , Russell R. D. , Hartley S. J. , Finan S. M. 
Published: March 2016

Abstract
This paper considers some of the challenges and learnings associated with the application of chemicals for preservation of coated pipe/flow line for a major LNG project in Australia. This includes a comparison of the effectiveness of biocide and oxygen scavenger chemistries for treating seawater. It also discusses monitoring philosophies and the unique approach taken in designing and optimizing the chemical injection system to address the environmental and technical challenges of this project.
The gauge testing of flowlines and pipelines in large-scale LNG projects of Australasia is an important compliance stage required prior to commissioning. Due to the extended timeline necessary to complete downstream infrastructure, pipelines and flowlines are usually deployed well before the treatment facilities are constructed, and may be shut-in awaiting connection for relatively long durations, following the hydrotesting procedures. If left unprotected, the pipeline becomes susceptible to corrosion predominately due to the presence of bacteria, but also due to the presence of dissolved oxygen and the saline nature of the hydrotest fluid which is typically seawater. Chemical treatment strategies for preserving these lines can consist of a bacteria control agent (biocide), and an oxygen scavenger, and occasionally a corrosion inhibitor which is added to mitigate corrosion in case all the oxygen has not been removed. Treatment strategies are often dependent on the required shut-in duration, local environmental regulations, and the asset integrity management specifications defined by the operator.
For the project presented in this paper, the integration of data obtained from the various stages of testing and computational modeling supported the design of an effective treatment program for this application. This was achieved despite of a number of unique challenges arising from stringent environmental constraints and the tight operating specifications required in this project.
A case history is provided describing the novel approach adopted in selection of pipeline preservation treatment chemicals through the assessment of various parameters, including laboratory studies (conducted to verify product performance under different operating conditions), as well as Computational Fluid Dynamics (CFD) modeling studies aimed at optimizing the chemical injection location, residence time, and flow regime. It is anticipated that such a systematic approach in design and optimization of treatment programs can provide a multitude of benefits in similar projects operating in environmentally-sensitive locations.
Acoustic Transmitter Active Vibration Control for Sonic Logging
Authors: Zhao Yiming , Song Xingyong , Dykstra Jason 
Published: March 2016

Abstract
Sonic logging tools are commonly used in wireline logging and logging-while-drilling (LWD) operations for determining formation lithology along the wellbore. Having an understanding of the near-wellbore rock with high certainty can significantly reduce risk when planning well stimulation and completion. The quality of sonic logging data is critical for decision making, especially in offshore applications for which mistakes can be costly. While much of the progress towards improving sonic logging data quality has been pursued via mechanical and electrical design along with post-process signal analysis, little has been done with using advanced control systems to boost performance of the sonic logging tools.
In this paper, the authors demonstrate noticeable improvement in the sonic logging tool's performance by producing high-quality acoustic waves from the acoustic transmitter using a novel control system design. While with proper mechanical and electronic design a transmitter can generate acoustic waves with high-quality frequency characteristics for measurement, there can exist sustained resonance vibration that degrades the data. This paper introduces a control method that mitigates excessive transmitter vibrations, releasing the full potential of the transmitter mechanical design. The robustness of this control system allows for peak performance over the range of high-pressure/high-temperature (HP/HT) environments the tool might experience downhole.
The control method described in this paper operates on similar principle as noise-cancelling headphones; however, because there is no external microphone or other sensing device, the control system is challenging to design. Essentially, it cancels out undesired vibration by generating a second waveform of equal strength but opposite direction and superimposing it to the existing waveform. The challenge of generating the proper cancelation waveform is overcome by a multistep learning algorithm. To sense the vibration, it uses the back-electromotive force (back-EMF); a voltage signal determined from the actuation device itself. One of the issues with using the back-EMF is it is substantially smaller than the actuation voltage, making reading this value during firing difficult. The benefits of this approach include reducing sensor costs and improved robustness by reducing sensor failure modes. The only modification required for the implementation of this advanced control system is a firmware update, making it an effectively zero-cost solution for a step-change boost in performance. Both laboratory test results and field data are presented to demonstrate the effectiveness of the novel control algorithm.
How Can Suction Pile Foundations Help to Maximise Profitability of Marginal Fields?
Authors: Spanjaard T. , Romp R. H. 
Published: March 2016

Abstract
As per January 2014, Petronas estimated Malaysia has some 106 marginal oil fields with approximately 580 million barrels of oil. Development of these fields require platforms almost similar to commercial fields, while total production is typically lower due to smaller reservoirs. Therefore, the total revenues are smaller and thus development is often questionable. More efficient technical solutions can contribute to cost reductions and hence turning marginal fields into commercial fields. This paper outlines a cost-efficient technical solution that contributes to profitability of marginal field platforms.
Re-use of platforms will lower the total investment required. The main technical challenge is to find a foundation method that is suitable for decommissioning and allows for reinstallation. A suction pile foundation is characterized by relatively fast installation and easy decommissioning. Installation is done by a discharge of water from the inside of the suction pile, leading to pressure difference between the inside and outside of the suction pile. This causes a net downward installation force, resulting in a penetration of the soil. The reversed principle is used for decommissioning or relocation of a suction pile founded platform.
Cost reductions in construction, installation and decommissioning phases are combined in the Self-Installing Platform (SIP) concept. The concept comprises of onshore construction of a one-piece platform, followed by transportation to field location without the need of HLV's. Hence, transportation is done either floating, towed or lifted by a sheer leg vessel. At site, the platform is lowered on the seabed and subsequently the suction piles are installed to target penetration. Once the wells are depleted, the SIP allows for relocation and subsequent installation at other marginal fields.
Suction piles are successfully used since 90's for many offshore applications with soils ranging from soft to stiff clays, loose and dense sands and in layered soils. Currently, four (4) SIP-1 concepts and three (3) SIP-2 concepts are successfully installed. This proves the potential economical benefit of future developments of the SIP concept in marginal fields.
Experience on Deepwater Drilling Riser about Hang-off Modes in Typhoon Condition of South China Sea
Authors: Leixiang Sheng , Liangbin Xu , Jianliang Zhou , Shiquan Jiang , Xunke Li 
Published: March 2016

Abstract
Typhoon occurs frequently from July to November every year in South China Sea. It develops fast, moves in high speed, and changes trajectory frequently, especially the typhoon, which is formed in local sea area near the drilling rig. It always threatens the safety of deepwater drilling operation. Typhoon response plan is therefore required to avoid damage to the deepwater drilling operation. According to traditional response plan, all the riser joints should be retrieved onto the rig floor and then the drilling rig should be steered away from the typhoon developing trajectory. However, it is a huge challenge to retrieve all the riser joints in deepwater due to limited response time. For example, the related T-time (typhoon prepare time) of L-1, with water depth over 2500m, is more than 6 days, but the forecast precision of typhoon is only 4-5 days. This indicates that it is not practical to retrieve all riser joints onto the rig in a limited response time, thus contingency plan of hanging off riser system to resist typhoon is more practical for deepwater drilling operations.
A case study example is presented in this paper to discuss soft hang-off and hard hang-off mode. Different hang-off lengths are analyzed in the case study. Also, combination effect of driving speed and drilling vessel heading is considered in the case study. This paper summarises the related experience of CNOOC about how to response to typhoon in hang-off mode.
Effect CO2-H2S on Corrosion of 3%Cr Carbon Steel in High pCO2 Environments
Authors: Abas Ahmad Zaki , Nor Azmi Mohamed , Suhor Muhammad Firdaus 
Published: March 2016

Abstract
The corrosion behavior of 3%Cr carbon steel was investigated under high pressure carbon dioxide environments, containing small amount of hydrogen sulfide, to simulate the condition of high carbon dioxide containing natural gas transporting offshore pipeline. It was systematically studied under high pressure carbon dioxide (range from 80 and 120 bars) with variation in other key parameters (temperature, water partitioning and hydrogen sulfide concentration). The corrosion rates were tested using High Pressure and High Temperature (HPHT) Autoclave and measured using the techniques such as linear polarization resistance (LPR), electrochemical impedance spectroscopy (EIS), iron count and weight loss (WL). The surface morphology and the composition of the corrosion product layers were analyzed by using scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDS) and X-ray diffraction (XRD). The results showed that in the water-rich phase, the addition of 200 ppm hydrogen sulfide instantaneously decreased the corrosion rate of 3%Cr at both 25°C and 80°C (80bar and 120 bar). It was also observed that the corrosion rates of 3%Cr carbon steel at 120bar and 80°C in the water-saturated CO2 phase are negligible. The addition of hydrogen sulfide increased the corrosivity of this phase and within the Minimum Acceptable Corrosion Rate (MACR) of 0.1 mm/year.
Integration/ Assimilation of Workflows to Describe and Characterise Low Resistivity/ Thin bed Reservoirs using Advanced Wireline and Core Data
Authors: Gaafar Gamal R , Altunbay M. Mehmet , Bonnye Yoel , Musa Faizah M , Bal Adriaan. , Belevich Alexander V. 
Published: March 2016

AbstractTapping into low resistivity (LR) pay zones in brown fields requires less capital expenditure (CAPEX) than developing new fields or embarking on enhaced oil recovery (EOR). Therefore, the economic significance of commonly overlooked LR thin-bed reservoirs drew significant attention from asset managers, particularly in the current rapidly declining economics of the hydrocarbon (HC) business of today. LR reservoirs however, are difficult to identify. Therefore, they can easily be bypassed unless a comprehensive identification program is employed. Identification, evaluation and quantification of LR reservoirs require integration of different workflows that address different aspects of geophysical, geological, petrophysical and reservoir engineering challenges. In this study, a workflow and case study for selection of key wells with the highest potential of by-passed LR reservoirs and integration of computational workflows, with appropriate algorithms, are demonstrated for the monetisation of LR pay zones.We are proposing a systematic approach to identify LR-prone areas of a given basin or field prior to screening petrophysical data for verification and evaluation. The approach first identifies areas where depositional processes are conducive for developing LR reservoirs. For example, areas associated with channels that may have well-developed crevasse splays. These potential LR areas are then selected for more detailed petrophysical investigation to confirm the potential presence of LR pay. If available, bypassed but potentially productive zones can be verified with advanced logging data using integrated algorithms. The elimination of unnecessary testing in parts of a basin, or field, having low potential for LR pay zones, yields the sought-after gains in economics and augments the concept of a "financially less demanding" project.
A Novel Workflow for Modelling Complex Compartmentalised Structures Leads to Enhanced Field Development Strategy
Authors: Iskenova Gulnara , Ram Bhargava , Maldonado Jorge , Kumaran Prashanth , Meyer Juergen , Chabernaud Thierry , Casado Jonathan H. , Sharma Sachin K. , Rahman Mohd Ramziemran Abdul , Moreno Juan Carlos , Ibrahim Ramli B 
Published: March 2016

Abstract
Reservoir compartmentalisation, whether structural or stratigraphic, is one of the most prominent parameter for accurately characterising the distribution of hydrocarbons in the subsurface and it is a key element for optimising hydrocarbon recovery. In order to accurately characterise its compartmentalisation, a new volume-based structural modelling technique have been applied for generating a geocellular model of the complex, highly faulted east flank of the studied field (Sabah, Malaysia). Benefits over existing pillar-based and surface-based techniques are discussed.
The volume-based modelling technique consists of interpolating a continuous 3D property representing the relative stratigraphic age of the formations from all available well and seismic interpretation data. A watertight structural framework composed of faults and horizon surfaces is then extracted from this property, and converted to a geocellular grid in which the faults are stair-stepped. New workflows were developed for early integration of fluid distribution and production data during the creation of the geological framework, leading to an accurate delineation of fault compartments.
The fault network of the new east flank model is composed of over 90 synthetic and antithetic faults, forming X and Y-shaped truncations and subdivided into over 35 geological units. Fault truncations are located within the volume of interest and have key bearing on the understanding of fault sealing potential. The subsequent 3D grids include all interpreted faults and integrate fluid contacts, pressure and production data, capturing essential compartmentalisation characteristics.
The main benefit of the volume-based technique over pillar-based methodologies is that it incorporates all the fault network complexity. Indeed, as their coordinate lines must be parallel to fault surfaces, grids which geometry is extruded along curvilinear pillars can generally not be used to represent fault systems with X or Y-shaped truncations. Besides, grid cells may become excessively skewed in presence of synthetic and antithetic faults, which can trigger inaccuracies when performing flow simulations.
Finally, thanks to early integration of production data during the interpretation phase the dynamic model could easily be history matched by adjusting fluid transmissibility across nearby fault blocks and between adjacent sand layers.
Modifying the Hall Plot for Analysis of Immiscible Gas Injection Wells
Authors: Talabi O. A. 
Published: March 2016

Abstract
The Hall plot is a proven, useful tool for evaluating performance of injection wells. It was originally developed for single-phase, steady-state, radial flow of liquids. It continues to be used to analyse water-injection wells and has also been modified and applied to the injection of polymer micellar solutions for enhanced oil recovery (EOR). However, published studies into its applicability for gas injection scenarios are very limited. This paper discusses the applicability of, and modifications to, the Hall plot for evaluating injection of gas into a reservoir under specific conditions—particularly immiscible gas injection into a gas cap.
Three commonly used expressions of the Darcy equation applied to gas wells exist—the low pressure approximation, the high pressure approximation and the method of real-gas pseudopressures. For this study, a methodology similar to that which was originally used to derive the Hall plot for liquids is applied to these expressions in order to derive modified ‘Hall’ expressions for gas wells, making appropriate assumptions. The validity of the resulting derived expressions was then verified using results from a commercial reservoir simulator. Published correlations were used to evaluate pressure-dependent properties for the plot, where required.
Based on the analysis, it was found that at low pressures, using the original expression of the Hall plot introduces a nonlinearity that could be misinterpreted as a change in injectivity. The modified expression for the Hall plot, based on the low-pressure approximation and published correlations, removes this artificial nonlinearity and straightens the plot, greatly improving its diagnostic value. It was also seen that at high-pressures, the attempts to re-derive a Hall plot expression for gas flow lead to an expression of the same form as the original Hall plot. Therefore the original Hall plot can be used without modification as it produces a straight line with no curvature. The method of pseudopressures gives the most comprehensive solution over the entire pressure range as expected, although it is more difficult to evaluate due to the need for numerical integration.
The results from this work indicate that modified versions of the Hall plot can be used qualitatively by engineers to identify injectivity problems during injection of gas into a reservoir under specific conditions—immiscible gas injection into a gas cap—as long as the appropriate approximations and correlations are used.
Geomorphology and Karstification of the Southern Field High Carbonates in Central Luconia Province
Authors: Wei Kiat Chung , Menier David , Jamaludin SN Fathiyah , Ghosh Deva 
Published: March 2016

Abstract
The development of the Central Luconia carbonates in offshore Sarawak has been governed by the orientation of the Luconia Platform, syn-depositional features generated by the rifting and oceanographic parameters, such as sea level fluctuations, hydrodynamic, climate changes, salinity, and oxygen levels. The studied carbonate platform is developed over a southern field high of Central Luconia Province. The prevalent high frequency sea level fluctuations during the Miocene (Burdigalian to Serravallian stages) developed an extensive array of karst by rapid sub-aerial exposure and re-submergence of the carbonate platforms. Multi-attribute was applied to the 3D seismic volume of one of the selected carbonate platforms in Central Luconia Province to recognise karstic feature developed within the platforms. Though it is explicit that karstification occurred mainly along fractures and faults, the karst distribution in the Central Luconia carbonates remains to be an enigma due to their heterogeneous nature, which in turn provides a challenge in drilling and exploration. The studied platform exhibits patchy growth distribution during the Burdigalian stage. This growth is deemed as the initial stage of carbonate growth followed by a combination of build-out and backstepping for the second growth stage. A major karstification stage is highlighted on the second stage build-up, which correlates with a major sea level drop and the distinctive collapsed-paleocave topography. Drowning is evident on the final stage of the platform that can be correlated to the final surge of sea level rise in the Serravallian.
Innovative Multi Technologies Collaboration for Ultra-HP/HT Offshore Fracturing Stimulation
Authors: Christiawan Arya B. , Buelvas Manuel L. , Shukla Sourabh 
Published: March 2016

Abstract
The ultra-high pressure and temperature (HPHT) lower Cretaceous sand-shale layer in Krishna-Godavari basin (KG basin), in eastern India offshore shallow water, in the Godavari River interdeltaic region, is currently the world's highest-temperature petroleum reservoir being explored in the marine environment. It is a part of the fluvial sedimentary KG basin, which is recognized as holding India's largest gas reserves. Its area is approximately 50,000 km2 and it extends from land to the shelf-slope and adjacent deep-sea area along the eastern passive continental margin of India. The bottomhole static temperature of the reservoir ranges from 350 to 450°F at 16,000 to 18,000 ft true vertical depth (TVD), with pore pressure gradient up to 0.85 psi/ft. The hydraulic propped fracturing technique is integral to the completion and well testing program in this typical tight reservoir
Krishna-Godavari basin, seismological cross section, source from Sorkhabi et al, Geotimes, and Sahu et al.
The design and delivery of hydraulic propped fracturing in such a complex reservoir and operational environment requires advanced technologies and meticulous planning and execution, including reservoir and geomechanical characterization derived from latest HPHT formation evaluation logging tools, implementation of integrated production simulation and fracturing modeling software, and application of ultra-HT completion and fracturing products. In addition to technical complexity, the limited drilling unit capability also required equipment planning that involved an integrated fracturing and testing wellhead-string-packer system, a project-specific modular HPHT stimulation boat and post-fracture flowback testing plan and equipment that included surface well testing and a coiled tubing nitrogen fleet.
Several successful hydraulic fracturing operations were performed in this tight ultra-HPHT reservoir for multiple operators. This paper will describe the case history of the hydraulic fracturing completion campaign for one operator in the basin, in particular describing ultra-HPHT techniques and products that were key to the project delivery:
Basin modeling, reservoir, and geomechanical characterization workflow as an integral part of hydraulic fracturing design in complex frontier reservoir
Installation and preparation of modular HP/HT stimulation vessel custom built for this project
Implementation of synthetic fracturing fluids developed specifically for ultra-HT application up to 450°F in a high-pressure and high-shear environment.
This fracturing project has been compared to previous similar treatment in the same basin, and lessons learnt from this campaign has been summarized for similar future ultra HPHT projects globally.