bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oil and Condensate Types In Cenozoic Basins Offshore Vietnam: Composition And Derivation
Authors: Petersen Henrik I. , Nytoft Hans P. , Fyhn Michael B.W. , Dau Nguyen T. , Huong Ha T. , Bojesen-Koefoed J.A. , Nielsen Lars H. 
Published: May 2016

Abstract
The Vietnamese shelf contains several petroleum-producing Cenozoic rift basins, including the Song Hong, Cuu Long, Nam Con Son, and Malay-Cho Thu basins. This study describes geochemical data of oils and condensates from these basins, including new data from the Song Hong and Malay-Tho Chu basins, and demonstrates the variability in composition and source of the petroleum. The results contribute to a better understanding of oil types and petroleum-generating source rocks offshore Vietnam. All investigated samples contain angiosperm biomarkers (e.g. oleanane, bicadinane) indicating sourcing from post-Late Cretaceous source rocks. The Cuu Long Basin is the major oil-producing basin in Vietnam and the highly paraffinic oils have a lacustrine source (high TPP ratios, low C31R/C30 hopane ratios, Pr/Ph ratios of 2-4) and were generated from rocks within the early- to mid-oil window. Lacustrine oils are also known from wells at the northern margin of the Song Hong Basin, and analyses of offshore condensate discoveries show they were generated from relatively mature lacustrine source rocks. However, oil with a conspicuous coaly biomarker signature occurs in the Nam Con Son Basin. Further, a number of the condensates from the Song Hong Basin contain high proportions of higher land plant biomarkers suggesting significant contributions from coaly source rocks. Recently analysed oils from the Malay-Cho Thu Basin (northern margin of the Malay Basin) have likewise a geochemical composition strongly suggesting a coaly source (high wax, Pr/Ph ratios up to &gt;10, dominance of C29 steranes). Hence, new data together with previous data emphasize that coaly source rocks are important petroleum producers on the Vietnamese shelf. Coal-bearing strata in the syn- and post-rift successions in the Cenozoic basins should thus be considered as important additional source rocks offshore Vietnam.
Concepts in Gas Compressor Station Configuration
Authors: Kurz Rainer , Lubomirsky Matt 
Published: May 2016

Abstract
The number of compressors installed in each compressor station of a pipeline system, as well as their arrangement, has a significant impact on the availability, fuel consumption and capacity of the system. This paper discusses the impact of the type and arrangement of turbomachinery equipment used in compressor stations.

Introduction
The economic success of a gas compression operation depends to a significant extent on the operation of the compressors involved. Important criteria include first cost, operating cost (especially fuel cost), life cycle cost, and emissions. Decisions about the layout of compressor stations (Figure 1) such as the number of units, standby requirements, type of driver, and type of compressors have an impact on cost, fuel consumption, operational flexibility, emissions, as well as availability of the station.

Capital Cost: First Cost and Installation Cost
Capital cost for a project consists of first cost and installation cost. First cost not only includes the cost for the driver and compressor, and their skid or foundation, but also the necessary systems that are required for operating them, including filters, coolers, instruments, and valves, and, if reciprocating compressors are used, pulsation bottles.
Although not intuitively obvious, this is also the area that is affected by driver derates due to site ambient temperature and site elevation: The power demand of the compressor has to be met at site conditions, not at ISO or NEMA conditions.
The Path to a Real-Time Optimized, Integrated Gas Network - Smart Fields Applied
Authors: Gobel Derek , Cramer Ron , Briers Jan , de Boer Frank , Lai Kok-Lam , Hooimeijer Martijn 
Published: May 2016

Abstract
This paper describes the successful application of Real-Time Optimization by Shell Malaysia E&P on the Integrated Gas Production System in Sarawak, implementing models for real-time monitoring and optimization of wells and facilities on a gas production network spanning more than 100 wells on more than 40 platforms across a number of different Production Sharing Contracts. We highlight how Digital Oil Field practices enable field-based data to be turned into information, support decision making, and lead to actions that ensure production is optimized continuously.
The technology described in this paper is applied to achieve consistent gas supply to meet demand, maximize revenue, and enable improved and timely operational decisions - striking a balance between short- and long-term value, and taking into account the reality of commercial and contractual constraints, finance, and economics. The optimization is data-driven and covers more than 1,000 variables and features multiple, mutually dependent objectives and constraints.
The solution has proven significantly better than prior physical model-based solutions, which deliver optimized field settings, but with inherently unstable results, and not fast enough for application in a real-time decision making environment. Field trials have proven a result of: increased condensate production at current or improved expected Ultimate Recovery, whilst maintaining a stable gas supply, fulfilling quality constraints and contractual LNG nominations.
This is one of the first successful attempts to implement truly-real-time optimization in a production environment of this size and complexity, including a complicated set of commercial and contractual constraints, and striking a transparent balance between short-term and long-term value. Having proven that a multi-departmental reality can be successfully captured and modeled, might markt the start of a transformation towards embedding intelligent energy to its true potential.
Sequence Stratigraphy of Clastic Overburden of the Miocene Carbonate Play in Central Luconia, Offshore Sarawak, NW Borneo: Implications for Hydrocarbon-Retention Capacity
Authors: Kosa Eduard , Hafrez Amirool , Boey Kenneth , Anuar Azhar , Wee Geoffrey 
Published: May 2016

Introduction
Central Luconia, offshore NW Borneo, is a mature gas province with over 45TCF of gas discovered to date in Miocene carbonate build-ups buried under Miocene-Recent deltaic clastics. Most commercial discoveries to date are in carbonate platforms whose large areas contain substantial hydrocarbon volumes even with relatively short columns. However, the remaining prospectivity resides mostly in pinnacle-shape carbonates where commercial volumes require long hydrocarbon columns (Fig. 1A).

Overburden Sequence Stratigraphy
Central Luconia has been characterized by tectonic stability throughout the Miocene resulting in depositional cyclicity and carbonate-clastic interactions chiefly reflecting eustatic sea-level variations. It thus differs from the surrounding basins (i.e., West Baram Delta and West Luconia Delta; Fig. 1B) where high subsidence rates have largely over-written the eustatic signal and where the dominant stratigraphic pattern is aggradation with high-relief clinoforms deposited in front of the deltas. In contrast, gentle subsidence across the Central Luconia plateau has produced slabs of relatively thin shallow-water shelf systems characterized by far (up to 150km) and swift migrations of the palaeocoastlines across the flat shelf-top in response to eustatically driven sea-level oscillations. Back-steps of the systems resulting from sea-level rises were followed by swift regressions of the deltas back to the loci of the previous shelf edges (Fig. 2).
The overburden clastic stratigraphy is thus organised into a succession of deltaic to shallow-marine shelf units punctuated by erosional unconformities and flooding surfaces. In a vertical sense, the stacked depositional cycles show a shallowing-up tendency with sand-prone lithologies resting on top of each cycle (Fig 2). In a lateral sense, well-developed clinoforms allow the extent of each cycle to be mapped out, along with internal building blocks such as topsets, foresets and bottomsets (Fig. 3A). The terminal shelf edges for most overburden cycles are found along the seaward limit of Central Luconia (Fig. 3B), suggesting that carbonate build-ups have been repeatedly transgressed by the topsets of the advancing shallow-marine shelves and land-locked during lowstands. The same pattern of cyclicity and shallowing-up trends can be followed throughout the stratigraphy. Strata surrounding carbonate platforms still growing near the current shelf-edge, some 150km from the present shoreline and submerged under some 100m of seawater, are demonstrably fluvial in origin and sand-rich (Fig. 4).
Instrumentation and Automation Project Costs: The Value Evaluation Dilemma
Authors: Chandrasekar Sarah 
Published: May 2016

Abstract
A series of case studies have been performed for both offshore and onshore projects, focusing on instrumentation and automation portions as pertaining to corporate Intelligent Field Instrumentation (IFI) programs. In green field and brown field projects alike, instrumentation and automation has become a de-facto standard of design and operation. As a matter of form, such projects are justified based on reliability and efficiency gains. Project cost for instrumentation and automation can be significant based on a variety of factors such as complexity, uptime requirements, field topology and extent, infrastructure constraints, redundancy, and other IFI constraints.
In reviewing several such implementations we have encountered instances of cost overruns, often driven by late-emerging requirements, requirement changes, and scope creep. In some instances we discovered cost escalation driven by evolving technology, as "new and improved" products have been rapidly entering the market. In green field cases we found cost overruns driven mainly by changes in field development plans, revised well plans and corresponding production tie-ins. In brown field cases, on the other hand, we observed frequent instances of hidden costs related to process redesign, personnel changes, and training required for new monitoring, control, and operational supervision.
In an uncertain market where oil and gas prices have seen extreme swings, all project costs are monitored closely, and any project cost overruns are viewed in a harsh light. In our look-back we note several observations that provide guidance in terms of estimating, budgeting, and contingency planning for instrumentation and automation. A key finding pertains to organizational culture, for which executive leadership must champion the strategic value of IFI programs.
In summary, the real value of IFI programs lies in the operational reliability and efficiency gains through automation, which in turn supports reduced personnel exposure, early warning, safer operations, and disaster avoidance. In light of a strong safety culture, therefore, instrumentation and automation project costs are progressively being regarded as a cost of doing business.

Case Study 1: Mature Onshore Legacy Conventional Gas
This gas asset has been producing from complex layered conventional reservoirs for close to 50 years. Production comes from three principal formations, and the gas quality has been very high, close to 99% pure methane. The field production peaked at a rate of over 300 Mmcf per day in the early 1980's, and then proceeded to decline very rapidly through the 1990's to about 25 Mmcf per day. At that time the operating company undertook some measures to arrest production decline by means of infill drilling and stimulation, and managed to reverse the trend and increase production to over 75 Mmcf per day by the early 2000's. At that time favorable gas prices supported investment decision for automation equipment that targeted personnel safety and operational efficiency.
Open-Hole Completion with Swell Packer Case Study: What Parameters Can't Be Ignored during the Design Stage?
Authors: Horng Chen Jiun , Nordin Noridah , Zaman Nur Hazrina Kamarul , Riyanto Latief 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
As the worldwide oil and gas reserve shrinks with the soar of inflation everyday, most operators are looking for more innovative economical well completion design. Since the last decade, swell packer has emerged from pacing technology to commonly well-accepted technology. Today, swell packer technology is the fruit of numerous financial investments in its research and development. Swell packer now can be deployed in water based mud, oil based mud as well as synthetic based mud.
Whilst swell packer advancement continues, open-hole completion design is gaining its popularity in the industry. It offers 360°-complete-sandface-completion communication to reservoir(s) and tubular production conduit. This concept has advanced the conventional limited entrance perforation hole size, phasing and number of perforation shots. As such, open-hole completion has its productivity advantages over cased hole perforated completion. Its larger flow area offers lower drawdown; which leads to lower sand production risk. Coupling the swell packer with open-hole completion application, it makes multiple zonal pressure isolation in the following open-hole completion possible: bare foot condition, predrilled liner, stand alone screen, open-hole gravel pack or even open-hole fracturing packing. Besides open-hole completion duration is much shorter and cheaper than conventional cased perforated completion design.
The utmost extent of swell packer open-hole completion advantage seems invincible, what are the consideration and limitation then? This paper will discuss singular zonal pressure swell packer performance, different case histories of well design using open-hole swell packer in term of surveillance requirement and challenges. To bring the investigation and discussion to another greater height, case history of swell packer swelling effectiveness and its zonal pressure isolation verification will be shared. It breaks the myths of unable to perform swell packer pressure integrity test in open-hole condition.
Doubling the Production from a Mature Reservoir in North Kuwait-Challenges, Achievements & Lessons Learnt
Authors: Chetri Hom B. , Raju Mankala , Alam Harry , Al-Ajmi Hussain Zuyed 
Published: May 2016

Abstract
Sabiriyah Lower Burgan is a clastic reservoir in North Kuwait on continuous production for the last 45 years. The reservoir, on active water drive, has its inherent problem of rapid increase in water cut, the production performance of wells declining drastically after water cut level of 40%. Many wells became idle in the past, with overall well efficiency (ratio of flowing to total number of wells) of 60%. The formal strategy for production had been focused on "keeping the active perforations away from water". Attempts were made in the past neither to install any artificial lift nor to have a campaign for water shut off/new technology applications.
In order to double production within 6 months from the reservoir, extensive review of the performance, intelligent analysis of existing wells, identification of production enhancement opportunities vis-à-vis mapping resources needed, horizontal wells/ ESP installation for the first time, more ambitious ESP implementation than was comprehended earlier; proactive process to quickly evaluate/ implement rig/ rigless workovers; drill/ complete/ connect new wells on priority and the opportunistic utility of newly drilled wells slated for overlying reservoirs in Lower Burgan were the cornerstone of the strategy. This strategy also proved to be a gap-filler to supplement production gaps, if any, resulting due to delays in water injection projects for other reservoirs. The interlinked workflow processes were developed for other reservoirs with ambitious goal of similar magnitude.
The strategy was implemented during 2010–11 with a jump in production to twice the base level. The challenge was carried forward to sustain the oil rates with controlled water cuts.
Proposed paper is a reflection of a quantum change in the mindsets of the professionals to re-prioritize & re-focus on the reservoir management of mature reservoirs and accordingly align the resources to enhance the production delivery at Gathering centre.

Background
Sabiriyah Lower Burgan(SA LB) is a clastic reservoir on continuous production for the last 45 years. It is a prolific reservoir with natural aquifer support. The crude oil quality produced from the reservoir is of light quality with an average API gravity of about 33 degree and % Sulphur of less than 2.8%. The reservoir has cumulatively produced about 40%of reserves so far. The long term production aspirations from SA LB to the asset is quite significant, with expected peak production of about three time the present levelonce the ESP plan is fully operational and planned infill drilling is complete, as per the forecast from simulation models. The reservoir had been under production with all producers on natural flow at a daily rate of about 50,000 bopd (for the last 3–4 years), with average water cut of about 29%.
Hydraulic Fracturing Stimulation Executions in Brunei.
Authors: Talib Norliny , Omar Amirul Sabrin 
Published: May 2016

Abstract
The West Asset of Brunei Shell Petroleum (BSP) is an offshore-based oil & gas production asset with substantial volumes of non-associated gas from deep, low permeability reservoirs. The typical depths of these reservoirs are from ca. 9000 ft to 11000 ft tvdss having a permeability range of 0.1 - 10 mD and porosity range of 9% -13%.
In the past, the completion type for the deep, tight gas reservoirs has been primarily cased-hole and perforated. The production rates has not been sustainable and was observed to decline faster than expected and ceased production, at reservoir pressures significantly higher than expected abandonment pressure. Investigation showed that these wells quit prematurely due to high skin, although the actual damage mechanism i.e. from fines migration, condensate banking, water banking or clay swelling, is still unknown. Production remediation via acid stimulation and through-tubing re-perforation did not achieve the desired results.
Consequently, there is a demand for the West Asset to pursue different completion strategies primarily dedicated to develop deep, tight gas reservoirs. Hydraulic fracturing is one of the completion concepts proposed to test the reservoir producibility performance. Other than a failed "Skin-Frac" campaign attempt in the past, hydraulic fracturing technology has not been widely applied in BSP. With a lack of geomechanics data and fracturing experience, a number of challenges were confronted during well planning and completion design phase as well as during planning and execution of the hydraulic fracturing campaign.
In the past two years, two wells have been hydraulically fractured by bull heading through 4-1/2" monobore completion via frac boat. Therefore, this case study documents the evolvement of completion and hydraulic fracturing strategies, emphasizing the importance of perforation selection, fluid selection and hydraulic fracture designs to the overall outcome of well performance. This paper also captures the operational challenges and learnings experienced throughout the campaign. This campaign has gathered valuable information on fracturing data and provided better understanding on future completion and fracturing approaches for new tight gas wells in the West Asset and similar assets in Brunei.
Storage and Transportation of Natural Gas at Moderate Pressures using Adsorption in Porous Materials
Authors: Cavalcante Celio L. , Rios Rafael B. , Torres A. Euricio B. , Azevedo Diana C.S. 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
The use of vessels filled with porous materials to store and transport natural gas at moderate pressures (about 3.5 MPa) and ambient temperature (about 298 K) has been studied as a potential alternative to compressed natural gas storage at high pressures (ca. 20 MPa). The present study provides an experimental investigation of charge and discharge cycles of natural gas in a prototype storage vessel filled with activated carbon and analyses the effect of the gas composition on the adsorption capacity. The adsorption properties were evaluated by measuring isotherms for each component of natural gas in a magnetic suspension balance and compared with the isotherms measured in a storage vessel using natural gas. The selectivities of the main constituents of natural gas in relation to methane were determined and the influence of the pressure on the selectivity was also observed. Although natural gas is composed mainly of methane (ca. 90% vol.), our experimental results indicate that the preferential adsorption of the heavier hydrocarbons and CO2 should be properly taken into account for the evaluation of the behavior of adsorbed natural gas systems along several charge and discharge cycles.
Vital Role of Nanotechnology and Nanomaterials in the Field of Oilfield Chemistry
Authors: Li Long , Yuan Xubo , Sun Jinsheng , Xu Xianguang , Li Shuang , Wang Lihui 
Published: May 2016

Abstract
Nanotechnology has the potential to introduce revolutionary change in the energy industries such as exploration, development and production. Nanotechnology can revolutionalise the additive properties by tuning particle characteristics to meet certain environmental, operational and technical requirements. Nanotechnology produces nanomaterials that are ultra fines in nature, usually smaller than ordinary micro particles and thus has very high specific surface area with enormous area of interactions.
Recent research has indicated that nanomaterials have unique properties for a broad range of applications in the field of oilfield chemistry, where fluid loss control, borehole stability, cementing quality of a well, remediation of damaged reservoirs, hydrocarbon recovery efficiency, oilfield wastewater treatment are of interest.
This paper presents an extensive literature review of assessing the applications of nanotechnology and nanomaterials in the field of oilfield chemistry, investigating the existing problems in the application of nanomaterials in oilfield chemistry, and evaluating the potential technical and economic benefits that nanotechnology and nanomaterials might provide to petroleum development and production.