bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Importance of Collaboration, Integration, and Relational Database Management for Vast Corporate Data: A Case Study in Indonesian National Oil Company
Authors: Susanto Adeline , Satria Andrean , Octora Ade Veria , Desiani Nora , Alam Nur , Yulisasongko Freddy 
Published: October 2016

Abstract
The asset management of an Indonesia's national oil company (NOC) has become complex and challenging because every field acquisition and takeover becomes a new asset (subsidiary). Challenges, such as standard corporate database (e.g., cataloguing), seamless workflow in retrieving massive data, data retention ability, and cartographic reprojection lead to a need for data management optimization and integration, which needs to be securely and reliably managed.
The smart vision methodology migrates architecture from an existing system to a new integrated system. The workflow consists of steps designed to gather information, engage the customer in a collaborative manner, and assemble opportunities into an orderly plan that has strategic alignment and cost-benefit justifications for each case. The approach used by the company refers to the professional petroleum data management (PPDM) data model, which helps move collaboration, integration, and relational database management forward. Deployment of this model results in the standardization of a corporate database. As such, previous different data configurations have a standard cataloguing system, which results in consistent data retrieval.
The smart vision methodology is applied to capture and study the company's existing architecture. A major finding is tremendous data from each of its subsidiaries have their own standards and contain structured and unstructured data, which makes it troublesome for analysis to further determine best business decisions. History data, data retention, and data permission management are arduous and implausible. Distortion of cartographic projection data makes the data nonscalable. To overcome these challenges, the PPDM data model is deployed. Data mapping was performed on 18 of the NOC's subsidiaries' data. Company preference, policies, and regulations are standardized at the corporate level. As a result, an integrated database is being established. Corporate can observe all assets in a single project database, which allows further technical analysis and eliminates data duplication problems, making the data easy to manage. From a user management point of view, the presence of the interpreter source priority (ISP) concept allows user collaboration without disrupting either corporate data or other user's interpretation. Another result is the user's ability to track historical data. This is important for corporate; thereby, users can access not only interpretations results but also other users' knowledge content.
The deployment of this model provides the ability to manage all the seismic, well, and interpretation-related data into one consolidated project regionally in a scalable geographical area and complexity. This allows the company to perform various analytics processes related to all data owned by the company.
Hybrid Downhole Microseismic and Microdeformation Monitoring of a Vertical Coal Seam Gas Well
Authors: Durant R. , Francis T. , Braikenridge R. L. , Roy M. 
Published: October 2016

Abstract
The operator’s exploration of natural gas in coal seams within the Gloucester Basin, New South Wales (NSW), Australia presents technical challenges accessing and producing the gas economically while meeting stringent environmental standards. These standards are more stringent than those applied to petroleum exploration and production in other states of Australia. This paper presents hybrid downhole microseismic and microdeformation monitoring technologies applied in a vertical CSG well.
The Gloucester Basin is an area of complex geology with high horizontal stresses, some faulting/compartmentalization, dipping bedding planes, and multiple thin bands of coal strung out over hundreds of meters. Regulations have all but stopped some companies exploring for CSG in NSW. This is despite large identified petroleum reserves, importation of gas from interstate to supply the local market, and a NSW chief scientist and engineer report stating CSG carries risks no greater than any other of the extractive industries and that those risks are manageable (O’Kane 2014).
Providing confidence that hydraulic fracture geometries are relatively confined to target coal seams and do not grow upward into beneficial groundwater aquifers is a primary concern. A hybrid downhole microseismic and microdeformation array was deployed to monitor fracture stimulation of a vertical CSG exploration well at Gloucester to provide more accurate insight into overall fracture height coverage. Downhole microseismic and microdeformation technologies complement one another by providing unique, far-field determinations of hydraulic fracture geometry. This is one of the first times downhole tiltmeters have been used to monitor microdeformation caused by hydraulic fracturing of a CSG vertical well in Australia and the first time either technology has been used in NSW. Results from work performed in November 2014 show relatively confined fracture height growth with good agreement between microseismic and microdeformation data. Low microseismic event magnitudes (-3.9 to -2.1 Mw) recorded indicate no interaction with faulting in proximity to the target well. In addition to a vertical fracture component, microdeformation data indicated presence of steeply dipping fracture components on all zones. This data, combined with high fracture gradients (well above overburden) observed with each stage, and increasing in shallow intervals, confirmed the prediction of complex fractures, especially for fracture zones shallower than 600 m.
Hybrid diagnostic results confirmed the 1D mechanical earth model (MEM) built for the target area and both fracture complexity and main fracture azimuth were generally as predicted. The complex nature of the fracture propagation prevents uncontrolled vertical growth, which gives confidence that hydraulic fractures are not growing into the vicinity of shallow beneficial aquifers.
A Review of Recent Safety Research Activities on LNG Operation
Authors: Shahri Hamid Reza , MahdaviNejad Ramezan Ali , Abedini Sanam 
Published: October 2016

Abstract
Since LNG (Liquefied Natural Gas) is a combustible cryogenic liquid and as such presents specific safety hazards, the safety of LNG utilization has become an issue that requires a comprehensive study on the risks. Hence, various safety aspects connected with the operation of LNG need to be analyzed. The purpose of this paper is to review recent researchers' LNG safety studies and analysis. Specific safety characteristics of the equipment involved are incorporated in the analysis. The analysis of important risks show that at pressures near atmospheric, the hazards of LNG are comparable to those of conventional liquid fuels such as gasoline. At higher pressures, it behaves more like a combustible gas liquefied by compression. Also reviewed in this paper is the state of the art in modeling important LNG Hazards (like pool and vapor fires modeling). Totally, this paper identifies different possible risks in and out LNG plants and describes the results obtained from modeling of identified issues.
Towards the Development of Chemical Selection Criteria for Subsea Preservation, a Practical Example
Authors: Shepherd A. G. , Hoban P. , Venugopal S. , Bos T. , Lorimer S. , Shade R. , Jensen N. , Backus F. , Luderer M. 
Published: October 2016

Abstract
Industry best practices dictate minimum fluid requirements for preservation of subsea equipment. The choice of chemical package to be used in such operations may be guided by a number of criteria, such as: carrier fluid composition and quality, exposure temperatures, pressures, preservation time, metallurgy, risk of microbial induced corrosion, predicted marine growth, expected concentrations of oxygen and or other contaminants (to name a few). Rules of thumb and regulatory/HSSE/regional considerations play an important role in chemical selection. More often than not, there is no off the shelf/one size fits all solution, particularly for deepwater and or remote locations. Thus selection criteria and performance indicators need to be clearly defined, verified and assured under laboratory conditions, before deployment. A well selected formulation is an enabler in ensuring readiness of a fit for purpose package in the operational environment.
In this work we present an example of the steps required for a structured approach to chemical selection for preservation. The selection involved looking at various MEG/water ratios proposed as carrier fluids. In addition, specific additives were considered for a defined set of conditions (e.g. temperature, oxygen content, metallurgy). The work focused on traditional chemistries used widely in preservation and novel applications. Some of the chemistries described here have not been reported previously for either water-based and or MEG/water based preservation, to our knowledge.
The results from this work show that there are differences in behavior for traditional chemistries employed for water based preservation formulations compared with MEG/water based options. However, it is possible to have an optimum formulation for a MEG/water based preservation fluid to meet KPIs if a structured approach is followed.
Industry Collaboration on Technology Development in WA
Authors: Kavanagh Neil , Otto Claus , Korsen Peter 
Published: October 2016

Abstract
During 2015, it became apparent oil prices were going to remain ‘lower for longer’ and budgets would be adjusted accordingly. As such technology development would be reduced and slowed down. As a result Western Australian oil and gas operators Woodside, Shell and Chevron are considering if and how increased collaboration in technology and innovation can support each individual company and the industry as a whole, by joining efforts and therefore leveraging investments and sharing lessons learned and best practices.
Modelling Carbon Storage Prospectivity in the Southern Margin of the Offshore Gippsland Basin, Australia
Authors: Ricard Ludovic P. , Michael Karsten , Dance Tess 
Published: October 2016

Abstract
A collaborative study has recently completed a storage capacity prospectivity assessment and pre-competitive data acquisition program in the southern margin of the offshore Gippsland Basin, Australia. Potential CO2 storage sites that could become available in the next ~25 years will be restricted to sites in the nearshore and southern parts of the offshore Gippsland Basin. This is in order to minimize possible resource interactions with ongoing petroleum production and low salinity groundwater in the northern and central parts of the basin. The injection target, the Latrobe Group has been identified as a suitable candidate for large-scale CO2 geological storage.
As part of the storage capacity assessment, a detailed geological model of the Latrobe Group sequence was constructed in an area of the southern margin of the basin. The model evaluates two main east-west-trending fault systems separating the model into three structural segments: a deep depocentre, flanked by the Southern Terrace, and thin Southern Platform. The sedimentary sequences comprise coastal plain to shallow marine sandstone deposits interbedded with laterally continuous coals and mudstones, which act as seals and baffles of varying quality. Uncertainty in the reservoir architecture and the impact on connectivity of the permeability field was assessed by way of multiple model realizations. The model was then used as the basis for a series of capacity and injectivity estimations employing theoretical, analytical, and numerical flow simulation modelling techniques.
At the highest end, for an area excluding the platform and assuming low sweep efficiency, estimates of the theoretical CO2 storage capacity ranged between 865 million tons (Mt) and 2,800 Mt. For the analytical model estimates were up to 900 Mt and numerical methods estimates were in the order of 200 Mt to 550 Mt assuming 3 injection wells in a 40 × 40 km area over 30 years. All of the results are highly sensitive to the estimation method used and input provided such as, net area defined, injection interval selected, uncertainties on fault seal, and boundary conditions. However, the insights gained from the numerical modelling studies in the region have indicated that carbon storage injection has the greatest potential south-west of the Bream field. After 1,000 years post injection, accumulations of mobile gas can be observed at different locations within the model, suggesting several vertical and lateral pathways. Key outcomes of the simulations support the concept of the southern margin of the Gippsland Basin being prospective for further CO2 storage exploration, namely that it is feasible to achieve injection and containment of commercial scale volumes of CO2 in parts of this region without adversely impacting existing resources.
Zonal Water Injection for a Nine-Layer Reservoir-A Case Study
Authors: Fuchao Sun , Zhenkun Zhu , Yulin Yang , Mingxin Zhao , Yang Gao , Jiaqing Yu , Tao Zhang 
Published: October 2016

Abstract
80% reservoirs were developed by waterflooding in China. The average layer number lies between three and four. As old oilfields reached high water-cut period, the reservoir needs further subdivision, usually more than seven layers. Conventional zonal water injection technique cannot meet the need of more than seven-layer subdivision because of small distance between regulators, thin interlayer, big releasing force of tubing and low efficiency in zonal flowrate adjustment. To solve this problem, we developed a step-by-step type packer which was released by lifting. The release force has nothing to do with layer number. All the packers were designed to release one by one. The maximum force was 30t. For small distance of regulators, we used two types of eccentric bridges together called positive oriented type and negative oriented type. By this way, the smallest distance was less than 0.7m. Double tubing packer was applied to realize effective seal for thin interlayer and it could overcome tubing creep which made it successful seal within 0.5m. This technique has applied more than 1147 wells in Daqing. The minimum distance between regulators is 0.7m. The minimum interlayer is 0.5m and the maximum layer number was 10. The technique process is normal during whole operation including packer set, open every choke completely, packer seal status on-line test and on-line flowrate adjustment. Through zonal water injection for those more than 7 layers, we conclude that the ratio of water absorption has increased by 8.1%. And the corresponding production thickness increased by 7.5%. The production of surrounding well increased 0.43t and the water cut decreased by 0.56%. The average zonal test and flowrate adjustment time is within 3.98d. All in all, it is an effective way for further waterflooding oilfield. Conventional zonal water injection technique cannot meet the need of more than seven-layer subdivision because of small distance between regulators, thin interlayer, big releasing force of tubing and low efficiency in zonal flowrate adjustment. The technique this paper introduced can solve this problem and it is widely used in Daqing. The results showed its adaptability.
Application of Permanent Integrated Water Regulator in Offshore Oilfields
Authors: Deli Jia , He Liu , Fuchao Sun , Xiaohan Pei , Wei Sun , Shujin Zhang , Chongjiang Liu , Mingxin Zhao 
Published: October 2016

Abstract
In the Bohai Oilfield in China, the water injectors with sand control completion are characterized by multiple layers (2-6 layers), high single-layer injection rate (300-700 m3/d) and large borehole deviation (30-60°). The conventional wire fishing and the high-efficiency measuring and adjusting based separate layer water injection can not satisfy completely the production requirements of separate layer injection at offshore platforms. In order to solve this problem, a type of implanted integrated water regulator based separate layer water injection technology was designed and developed. The integrated water regulator is implanted with the tubing at the downhole injection interval. It is integrated with the functions of the injection rate and pressure monitoring in each interval and the opening monitoring and adjustment of regulating valve. A special type of three-way ceramic plug was developed for high injection rate, and the anti spitting valve was adopted. Enhanced steel cable was used for power supply and communication with the ground main frame. The ground main frame (explosion proof ExdII BT6) was set at the offshore platform for multi-well dragging control. A set of ground main frame can perform time-sharing monitoring and controlling on 8 intervals in 7 water injectors, so it can satisfy the requirements of most water injectors in Bohai Oilfield. Pilot test verifies that this technology reaches the design requirements and guarantees the qualification rate of water injection in each interval. Its technical monitoring data can be used for oil reservoir analysis to improve water flooding results.
Demystifying Log Quality Control
Authors: Storey M. C. 
Published: October 2016

Abstract
All would agree that bad data should not be let into the organization’s systems and its decision-making processes, yet there are no industry standard methods on how best to assure this for well log data. Electric well logs are the principal data sets for all geotechnical personnel in this industry: logs generally constitute the main continuous and relatively high-resolution records describing a wellbore, and they are available over the main depth intervals of most wells drilled for hydrocarbon exploration and production.
The specialized contractor companies that acquire the logs have quality management systems in place to ensure compliance and consistency with their own specifications. The data deliverables are therefore subject to some quality control before delivery to the operating companies, although it is of a general nature and focused on the acquired data, rather than on their future exploitation.
On delivery, the responsibility for any post-acquisition quality control of the well logs frequently falls on inadequately trained and supervised geotechnical persons, who may skim over it on account of its being "too hard" or "too urgent". People responsible for log quality control frequently report that they find it "difficult" or "overwhelming" and that they "don’t know where to start". Subject matter experts themselves know that logs must always be checked and perhaps conditioned before they can be used. Yet few of them have simultaneously the knowledge, the experience, the reference information, the tools and the time to verify the fitness-for-purpose of the data methodically and confidently. This systematic requirement is costly for organizations, and its uncertainty exposes them to unnecessary risks. The situation is exacerbated by concurrent increases in the variety, volume and complexity of the log data and in their rates of change.
There must be a better way to assure log data quality and readiness for exploitation. The objective of this paper is to propose a framework to formalize and simplify log quality control in operating companies and other data-user organizations.
Gravity Driven Fingering and Mixing During CO2 Sequestration
Authors: Ajibola Jeuspelumi , Adam Alexander , Muggeridge Ann 
Published: October 2016

Abstract
Injection of carbon dioxide into deep saline aquifers is one way to reduce greenhouse gas emissions. Carbon dioxide, usually a super critical fluid at aquifer pressure and temperature conditions, is lighter than the resident brine and so forms a gas cap above the water. However, over time it dissolves in the water, creating a density inversion which induces gravitational instability. Understanding whether the dominant mixing mechanism is convective mixing rather than pure diffusion is important as this controls the timescale over which the carbon dioxide-saturated brine mixes with the unsaturated brine. This paper presents numerical simulations, using a finite difference reservoir simulator, to evaluate the predictions of analytical solutions for stability analysis and growth rate of the fingers of different wavenumbers at different Rayleigh numbers (Ra). The effects of density difference, permeability anisotropy and diffusion (both longitudinal and transverse) on fingering behaviour were investigated through the dimensionless Rayleigh number. The density difference and the vertical permeability were found to mainly control the degree of instability. At Rayleigh numbers greater than 800, fingers are present and the degree of fingering increases with Rayleigh number. Growth rate analysis showed that growth rate is directly proportional to Rayleigh number and time. The critical time (at which flow becomes unstable) varies inversely with the Rayleigh number whilst the corresponding critical wavenumber number varies linearly with the Rayleigh number. These results are consistent with previously reported linear stability analyses providing a validation of the simulator. Numerical simulation results were also validated against experiments. These validations both show that the simulator is robust and can thus be used to investigate more complex situations (heterogeneity) that cannot be analysed mathematically.
Investigation of Shale Gas Numerical Simulation with Fracture Stress-Sensitive Using Discrete Fracture Network Model
Authors: Mi Lidong , Jiang Hanqiao , Tang Ligen , Li Junjian , Killough John E. 
Published: October 2016

Abstract
The exploitation of unconventional reservoirs is increasingly a major source of long-term energy in the word. Research results have revealed that the natural fractures occur in shale gas reservoirs and many shale outcrops, cores, and image logs contain fractures or fracture traces, and microseismic event patterns associated with the hydraulic fracture stimulation have been ascribed to the natural fractures reactivation. Hydraulic fracture treatments also induce complex fracture geometries in naturally fractured shale gas reservoirs.
The production performance of shale gas plays denpend strongly on the existence of a dense and conductive network volume of the well. Most of shale gas reservoirs exhibit a higher degree of heterogeneity and complexity created by both natural and hydraulic fractures, whose permeability is stress-dependent. In order to describe the fracturs's seepage characterization explicity, the discrete fracture network (DFN) model is adopted in this research when the conventional continuum model cannot meet the requirements of the fractured shale gas reservoirs numerical simulation. The nonlinear partial differential equations about the seepage flow mathematic model are solved by finite volume method using the C-sharp programming language. The fracture permeability stress-dependent experiments have been conducted on shale core samples, and then the fracture aperture-pressure correlation is combined with the mathematic model of DFN to demonstrate the fracture conductivity potential impact as pressure drops during production.
The lab experiment results show that the fracture aperture is strong stress-sensitive at low pressure (0~20MPa). The model is used to do a simulation on a random generated fractures network, which is used to represent the fractured shale gas reservoir, to study the effect of the stress-sensitive on the flow and transport characteristics in the fractured porous media. Results show that: the fracture permeability stress-sensitive has a significant impact on the production and should not be ignored.