bluuebunny/crossref_metadata_2025_split huggingface dataset:
PEMANFAATAN PERPUSTAKAAN UK/UPT LINGKUP KEMENTERIAN PERTANIAN
Authors: Suryantini Heryati , Rufaidah Vivit Wardah 
Published: October 2016

Perpustakaan unit kerja (UK)/unit pelaksana teknis (UPT) lingkup Kementerian Pertanian merupakan perpustakaan khusus yang berperan dalam penyediaan informasi untuk mendukung kegiatan penelitian dan pengembangan pertanian. Upaya pembinaan pengelolaan perpustakaan lingkup Kementerian Pertanian telah dilakukan untuk meningkatkan kinerja perpustakaan tersebut. Untuk mengetahui pemanfaatan perpustakaan tersebut oleh pengguna, suatu pengkajian dilakukan dengan metode survei. Sampel ditentukan sebanyak 36 perpustakaan dengan 57 responden. Pengumpulan data dilakukan pada bulan Juni-September 2013 melalui wawancara langsung dan melalui e-mail dengan menggunakan panduan kuesioner. Variabel yang diamati adalah karakteristik responden pengguna perpustakaan, pemanfaatan perpustakaan, dan tanggapan pengguna terhadap sumberdaya manusia, sarana prasarana dan sumberdaya koleksi perpustakaan. Kuesioner bersifat ordinal menggunakan skala Likert dan sebagian bersifat terbuka untuk mendapatkan saran dan masukan dari responden. Data yang terkumpul ditabulasi dan dianalisis secara deskriptif. Hasil pengkajian memperlihatkan bahwa pemanfaatan perpustakaan lingkup Kementerian Pertanian oleh pengguna belum optimal, terlihat dari frekuensi kunjungan pengguna ke perpustakaan dan lamanya responden berada di perpustakaan, yaitu hanya 4-6 kali/bulan dengan lamanya pengguna berkunjung di perpustakaan kurang dari 2 jam. Sebagian besar pengguna lebih banyak memanfaatkan layanan manual dibandingkan dengan layanan elektronis. Jenis koleksi yang paling banyak dimanfaatkan pengguna berturut-turut adalah buku, disusul majalah ilmiah dan jurnal online. Layanan perpustakaan yang disediakan cukup memuaskan, namun informasi yang diperoleh kadang-kadang sesuai kebutuhan. Sarana dan prasarana perpustakaan seperti komputer, ruangan perpustakaan, dan jaringan internet belum memadai. Petugas perpustakaan/pustakawan di instansi lingkup Kementerian Pertanian masih sangat terbatas baik kuantitas maupun kualitas sesuai bidang keahlian yang dibutuhkan.
Using Composite Modeling as a Means to Maximize Profitability
Authors: Ortiz Tom 
Published: October 2016

Management
Oil companies exist to make money. Many companies too often focus solely on maximizing current production when they should really be focusing on maximizing profitability. A holistic, total asset modeling process is needed to reorient the focus of digital oilfield systems to make the net present value (NPV) of every project the centerpiece of all decisions.
Digital oil field providers have spent the past decade enabling a growing variety of specific workflows to automate isolated engineering tasks. These efforts have significantly reduced nonproductive time and costs. Nevertheless, transformational productivity increases will be required for operators to thrive in a prolonged, low oil price environment. For this reason, digital oil fields must become less about workflow orchestration and more about financial optimization.
A variety of metrics are used in the industry to measure financial performance or to make capital budgeting decisions. In addition to NPV, the metrics may include internal rate of return (IRR), real options analysis, or payback period. Among these, payback fails to account for the time value of money, IRR does not return a unique solution in cases where positive and negative cash flows alternate over time, and real options analysis can be shown to be equivalent to the NPV method if risk is properly accounted for.*
Less formalistic measurements may also come into play, particularly where projects involve national oil companies for whom politics, short-term cash flow pressures, and regulatory frameworks can exert large influences over the selection of a project.
Without a significant loss of generality, we claim that if a business activity is not expected to increase NPV, then it should not be undertaken. Under this assumption, well-intentioned, but NPV-reducing, programs of activity that are proposed to improve a technical metric should be reconsidered. For example, reservoir engineers will always try to improve their recovery factors, but economic limits will dictate the scenarios in which oil should be left in the reservoir.
In a company in which groups or teams are accustomed to operating in silos, the financial effect of decisions can be opaque, particularly at the level of decision making required to manage globally dispersed, cross- functional teams. To improve transparency, it is insufficient for only managers to have visibility into the financial effect of technical decisions. Technical personnel also need to know that their work is improving the bottom line. As they gain greater financial awareness, employees will begin making more improvements to their technical projects in ways that optimize profitability.
Case Study Shows Benefits of Applying Hollow Glass Spheres to Drilling Fluids
Authors: Wilson Adam 
Published: October 2016

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174010, “Hollow-Glass-Sphere Application in Drilling Fluids: Case Study,” by Arminder Minhas, SPE, Halliburton; Brandon Friess, SPE, Farid Shirkavand, and Barry Hucik, Seven Generations Energy; Teresa Pena-Bastidas, 3M Canada; Bradley Ross, SPE, Halliburton; and Shawn Servinski and Frank Angyal, Seven Generations Energy, prepared for the 2015 SPE Western Regional Meeting, Garden Grove, California, USA, 27–30 April. The paper has not been peer reviewed.
In an effort to optimize drilling operations and economics, an operator examined the effect of adding hollow glass spheres (HGSs) directly to the drilling fluid instead of performing underbalanced drilling. Both nitrogen and HGSs were believed to reduce hydrostatic pressure of the mud column in the hole, resulting in higher drilling rates of penetration (ROPs) and reduced mud losses to the wellbore. This paper provides information on HGSs as an economic alternative to nitrogen to help reduce the hydrostatic pressure of invert-emulsion drilling fluids.
Introduction
This case study focuses on the application of HGSs in two different sections of the drilling operation—a horizontal section and a vertical intermediate section. Data from a base-case horizontal section using an all-oil drilling fluid were compared with data of another well on the same drilling pad using the same fluid with the addition of HGSs. The intermediate-section data were from a base-case well that used an invert-emulsion drilling fluid, and they were compared with data from other intermediate well intervals in the same field that used an invert-emulsion drilling fluid with the addition of HGSs.
Use of HGSs in Drilling Fluids
HGSs are inert materials that are used as density-reducing agents. In the oil and gas industry, they are used for reducing the density of drilling fluids and cement blends. These hollow spheres (Fig. 1) are chemically inert, thermally stable (with a softening temperature of 600°C), and made of soda-lime borosilicate with a high strength/density ratio, and they can be added to both oil- and water-based fluids. A density reduction of up to 2.086 lbm/gal is possible when using HGSs.
HGS addition helps reduce density and, consequently, the effective circulating density (ECD). Addition of HGSs to a lightweight drilling fluid allows consistent, stable properties and allows for measurement while drilling and controlled management of fluid properties. These lightweight fluids can be used for drilling at balanced, near-balanced, or underbalanced conditions. Applications include depleted reservoirs, geologically fractured formations, poorly consolidated formations, and high-permeability formations.
In general, a reduction of differential pressure can result in the elimination of differential sticking, reduction or elimination of fluid loss, and mitigation of formation damage. This can result in higher productivity during drilling operations and during production.
An Experimental Study of Multiphase Behavior for n-Butane/Bitumen/Water Mixtures
Authors: Gao Jianyi , Okuno Ryosuke , Li Huazhou Andy 
Published: October 2016

Summary
Steam/solvent coinjection has been studied and pilot tested as a potential method to improve steam-assisted gravity drainage (SAGD) for bitumen recovery. Reliable design of coinjection requires reliable pressure/volume/temperature (PVT) data for bitumen/solvent/water mixtures, which are scarce and fragmentary in the literature.
The main objective of this research was to present a new set of PVT and multiphase data for n-butane/Athabasca-bitumen/water mixtures at pressures up to 10 MPa and temperatures up to 160°C. Experiments were conducted with a conventional PVT apparatus. The data presented include multiphase equilibria up to four coexisting phases and liquid densities for 100% bitumen, two mixtures of n-butane/bitumen, and one mixture of n-butane/bitumen/water.
Liquid/liquid separation of hydrocarbons was experimentally observed at the n-butane concentration of 97 mol% in the n-butane/bitumen system with/without water, for a wide range of temperatures at operating pressures for expanding-solvent SAGD (ES-SAGD). This may indicate the limited solubility of n-butane in bitumen even when a high level of accumulation of n-butane takes place near a chamber edge in ES-SAGD for Athabasca bitumen. The multiphase transition that involves appearance/disappearance of the vapor phase was observed to occur near the vapor pressure of n-butane or its extension. Such phase transition occurs at a higher pressure in the presence of water, because of its vapor pressure, than in the absence of water at a given temperature. This is the first time four coexisting phases are reported for n-butane/Athabasca-bitumen/water mixtures at temperature/pressure conditions relevant to ES-SAGD.
Effective Marketing Leadership, Strategies and Tactics During Turbulent Times in the Oil and Gas Industry
Authors: Ferrero Ricardo , Varer Melis , Bowling David 
Published: October 2016

Abstract
Turbulence in the oil and gas industry requires a sharper focus on value selling as operators place increasing emphasis on real-time remote operations to improve efficiency while reducing health, safety and environmental (HSE) risks. All companies now operate in an international, interconnected environment where customers are scattered around the globe. Even companies that market only to a single country or region must think globally.
The challenge for marketing in the oil and gas industry during this volatile period is ensuring delivery of value propositions so operators can make informed decisions about solutions that provide the greatest benefit for operational improvement and HSE risk reduction.
This paper describes the key strategic elements of this marketing process, from value creation to value delivery. Marketing challenges are explored in addition to knowledge on how to develop a marketing plan (including segmentation and targeting) using customer needs and insights, as well as competitor analysis, for a globally interconnected business environment.
The paper explains how to develop effective brand and positioning strategies in addition to the best use of all elements of the marketing mix to deliver successful marketing plans in an international context and their application to the oil and gas industry.
The paper also provides a comprehensive study of translating strategy into action for effective value message delivery. The role of new media is examined using inbound marketing techniques for an array of communication tools and tradeshows in combination with the strict requirement for appropriate resource allocation.
High Stress Contrast between Different Lithologies and its Implications for Drilling and Stimulation in the Northern Cooper Basin
Authors: Gui Feng , Rahman Khalil , Lockhart Duncan , Cunha Diogo , Meadows Dylan 
Published: October 2016

Abstract
Drilling in the Cooper Basin faces challenges from the hostile stress environment, high-pressure and high-temperature conditions, and variations in rock properties with depth. The current understanding is that the Cooper Basin is under a highly deviatoric, strike-slip stress regime with significant stress contrasts between different lithologies. These conditions create challenges for drilling and well stimulation.
A series of wells have been reviewed to understand the vertical and lateral stress changes in the Patchawarra Trough in the Northern Cooper Basin. The temperature anomaly at this location appears to be lower than in the Nappamerri Trough in the south. A different level of overpressure is also observed, and the formation pressure appears to vary depending on structural location. Shallow wells on the ridge appear to be near hydrostatic in the Permian sands, but overpressure is as high as 10.5-11 ppg on structures in the deeper part of the Patchawarra Trough. Rocks appear to be generally strong, with siltstones in the Permian section being only slightly weaker than sandstones. The stress anisotropy in the sandstone is large; the SHmax/Shmin ratio is greater than 2. The stress anisotropy is considered to be the reason for preferential wellbore failure in sands instead of shaly siltstones. The stresses in interlayered thick coals tend to be near isotropic. It is also thought that the stress regime is not necessarily uniform with depth; the maximum horizontal stress decreases drastically at shallower depths, and the stress regime becomes normal faulting.
The detailed geomechanical analysis shows that the drilling challenges faced in the deeper section are mainly caused by the thick coal sequences. Sandstones and siltstones are relatively strong, should not cause much wellbore instability, and are only expected to develop narrow breakouts. For hydraulic fracturing, the small stress contrast (similar minimum horizontal stress magnitudes) between sandstone and siltstone in the Permian formation would result in difficulty in confining the fracture in zone. Consequently, excessive height growth may cause the fracture to grow into highly fractured coals and may lead to early screen-outs.
Detailed geomechanical modeling for a series of wells in the Patchawarra Trough has enabled a thorough understanding of variations in rock properties, pressure and stress in the area. Optimised drilling strategies for mud weight and mud properties were adopted for the drilling of vertical and horizontal wells. Accurate stress modelling also helped the optimisation of hydraulic fracture design to achieve successful fracture treatments for improved production.
Numerical Modeling of Nanoparticles Transport in Porous Media for Optimisation in Well Stimulation and EOR Using Electromagnetic Heating
Authors: Santoso R. K. , Rachmat S. , Putra W. D. , Resha A. H. , Hartowo H. 
Published: October 2016

Abstract
Electromagnetic heating has been recently introduced as an effective technology to enhance production of heavy and extra-heavy oil reservoir. Several investigations using metal oxide nanoparticles have successfully proven to increase the effectiveness of heating process. Nanoparticles act as thermal-conducting agent during the heating process. Thus, heat distribution along the reservoir strongly depends on the nanoparticles distribution (concentration profile along the reservoir). In this study, we develop a mathematical model to characterize the concentration distribution of nanoparticles along the reservoir during injection phase. The model is developed using material balance and fluid flow in porous media. Several empirical correlations are also adopted to describe the adsorption phenomenon during the nanoparticles flow in the reservoir. Using coreflood experiment data of iron oxide nanoparticles, the model is simulated and fitted to look for several constants and confirm the minimum error. From the simulation results, the model matched with tracer data and had small squared error with nanoparticles data.
Discovering New Hydrocarbon Pay Sand Beyond The Wellbore With Reservoir Mapping While Drilling Tool – A Case Study From Offshore Sabah, Malaysia
Authors: Kyi Ko Ko , Latiff Nazri Abdul , Yen Kok Kwi , Saadon Danial , Rahim M Ikhlas , Jaafar Juhaidi , Afandi Tomi , Fei Ng Kiang 
Published: October 2016

Abstract
Tango Field, located offshore Sabah in East Malaysia, is a mature field which has been producing oil and gas for more than forty years. This field has many fault blocks, thus creating barriers to fluid and pressure communication between different fault blocks. Furthermore, the reservoir sands are turbidite sands which are difficult to correlate across the whole field. Being fan lobes, it is not easy to target these sands in drilling development wells. As part of the campaign to improve recovery and sustain production, two infill wells were drilled during 2014, by sidetracking two existing wells from the Tango-B Platform, which is located in the western part of the field. The target reservoirs are M1 and M2 sands, which still carry some upside potential based on the latest review of the field performance. To properly target and penetrate these sands in the planned wells, the Reservoir Mapping While Drilling LWD (DDEM) tool, in combination with standard triple combo LWD (Logging While Drilling) tools, was deployed. This is to ensure that the well trajectory stays within the targeted sands and the bed boundaries are detected long before the drill bit exits the sand body. Unlike previous deep reading LWD resistivity tools, the DDEM tool is a Deep Directional Electromagnetic Propagation tool which has the capability to see about 30 meters laterally beyond the wellbore. While drilling the first well, the target sands were penetrated as planned. However, there was a pleasant surprise where a new hydrocarbon sand was detected by the DDEM tool about 10 meters below the wellbore. The DDEM reservoir mapping software was used to image the newly found sand body. Based on this new finding, the drilling Bottom Hole Assembly was pulled back and the hole was side-tracked to target this new sand, which was successfully penetrated and completed. This new sand, which would not have been discovered with standard LWD tools has increased the well production by a factor of two or more. Being a turbidite sand, it was not picked up on the surface seismic section. The reservoir mapping software technology, together with the deep sensing resistivity imaging LWD tool, was instrumental in finding the new hydrocarbon sand which has substantially increased the production of Tango Field.
Reactive Transport Modelling of CO2 Injection Into High CO2 Field
Authors: Amin S. Mohd , Azuddin F. Jaafar 
Published: October 2016

Abstract
Gas reservoirs often contain a proportion amount of naturally occurring CO2, ranging from a few percent up to 70% by volume. A carbonate gas field located in offshore Sarawak, eastern Malaysia has a very high concentration of CO2 and expected to be a world pioneer offshore CO2 storage in high CO2 field with the accumulated amount of 70 % mole of the gas in place. Carbon dioxide from the gas field is removed from the gas production stream in a central gas processing facility and then the CO2 is compressed, transported and stored underground in the carbonate reef reservoir of the same gas field. This study details the geochemical effects of CO2 injection into the field as part of the proposed field development. In this study, we ran a two-dimensional reactive transport models using TOUGHREACT. The model was run for 300 years at the temperature of 140°C and pressure of 352 bars. The CO2 was injected for 30 years below gas water contact (GWC) in the aquifer. The modelling results shows that the overall geochemical alterations of injected CO2 into solid phase are minimal and is confined to the region below the original gas water contact with the minimal additional impact on injectivity. This is due to the dry-out formation vicinity to the injection well that lead to the small amount of salt precipitation. These findings demonstrate the importance of geochemical reactions study when injecting CO2 into high CO2 gas field at high pressure and temperature.
Conceptual City-Oilfield Development of a Complex Turbidite Reservoir
Authors: Mishra Shubham , Hii Sing Kiet , Corbett Chip , Noor Amin Edalat , Sharma Sigra 
Published: October 2016

Abstract
This theoretical study about the development of a turbidite reservoir is unique because it considers the combination of the surface and the health, safety, and environment (HSE) constraints of the urban overlying the reservoir. Although geology poses deep challenges in terms of reservoir heterogeneity, anisotropy, compartmentalization, and pressure drives, the attempt to develop oil fields in an urban environment makes it very difficult to plan facilities, transport, services, and operations because of HSE issues. This study is a continuation of a previous study in which the background, modeling, and economic analysis of the earlier study is combined with stronger HSE concepts to make the study more holistic.
With a strong focus on health and environment, this paper establishes guidelines for managing the risks of urban development. Reservoir management is guided by sensitivities and uncertainties on CAPEX and OPEX, establishing novel ways of optimizing infill well locations, drilling practices in a city, and enhancing hydrocarbon production through reservoir simulation practices. The geological, geophysical, and engineering data for the study are generated to represent analogous turbidite reservoirs whereas the HSE well planning recommendations are derived from urban oilfield developments in Los Angeles and Long Beach, California.
The methodology of dynamic modeling is nonconventional in terms of analyzing the field for forecasting immediately after initialization followed by a detailed history match considering the numerous hurdles of turbidite environment. This allows greater time for field development planning, which is conventionally given the least attention because of time constraints. Therefore, the prediction comprises a no-further-action case, an infill wells case, and waterflood scenarios, with a combination of vertical and horizontal well trajectories exhibiting the best output in a span of vast economic sensitivities over multiple scenarios. The most noticeable part of the study is the wide range of realizations on well trajectories, well placement, optimizing drilling, and production services. Our modeled city was Houston, Texas, a well-known urban environment. As a result of the modeling, a technique was developed to guide for environmentally safe development within this example.
The technological and economic conclusions make this a foundation study for profitable development of reservoirs underneath a populated area. The study may also be instrumental in exploitation of turbidite reservoirs, which present challenges in current North Sea and Brazil offshore development and in recently discovered submarine fans in the Gulf of Mexico deep marine environment.