bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cyber Security, the Cloud, and Oil and Gas
Authors: Black Peter 
Published: October 2018

Abstract
The rapid acceleration in the adoption of cloud services has increased the focus on cyber security. While data protection and privacy have always been key concerns in the oil and gas industry, this has frequently been achieved by isolating networks and strengthening perimeter defences. However, the weaknesses in this approach have been demonstrated, and it has masked poor practices in many areas. This paper will argue that the advent of cloud technology should not be regarded as a further challenge to security, but an opportunity to dramatically revitalise and improve a company's defences.
We will present a systematic overview of the kind of hybrid architecture that is increasingly common in many oil and gas companies, with on-premises and cloud systems. We will examine the key areas of authentication and authorisation and examine how these must evolve to address the cloud. We will also look at key pain points, like systems integration and legacy platforms, and examine how these are accommodated in a cloud-first architecture.
In examining the issues involved, we will see that cloud does not really introduce new security challenges but tends to highlight problems with existing practices. Historic failures to implement federated identity, or to secure and patch individual systems, or to allow unencrypted and largely insecure SQL access to corporate databases, represent a clear and present danger. By returning the focus to system security, and moving on the conversation from perimeter defence, cloud is providing a valuable service. Interestingly, this new technology also provides a range of answers, as we'll discuss, but it cannot be a universal panacea.
While adoption grows daily, cloud is still relatively novel to many companies. The lessons learned across multiple large-scale implementations of cloud technology in production data management allows us to derive general, vendor-independent guidance on cloud architectures, cyber security issues that must be addressed, and best practices that should be followed.
Progress Towards an Oil and Gas Industry Alternative to Mea Triazine in Hydrogen Sulfide Mitigation
Authors: Taylor Grahame , Wylde Jonathan , Oliveiro Antonio Pedro , Smith-Gonzalez Monica 
Published: October 2018

Abstract
Hexahydro-1,3,5-tris(hydroxyethyl)-s-triazine (MEA-triazine) is by far the most ubiquitous H2S scavenger used globally and occupies at least 80% of the available oilfield market. While almost the perfect scavenger in terms of kinetics and H2S uptake, this product does suffer from a number of undesirable effects which are usually tolerated or managed by various engineering modifications. For example, pH elevation causes scaling issues, deposition of intractable polymeric solids and increased ethanolamine load in crudes entering a refinery are some of the most prominent. A new scavenging technology has been developed that offers an alternative to triazine. This chemistry has undergone successful field trials and roll out in the US. The guiding principles in the design of this technology were to achieve, equal or better scavenger efficiency compared to triazine, equal or better reaction kinetics compared to triazine, "best in class" solids control, minimal pH impact, cost competitive with triazine, no impact on fluid separation and minimal refinery impact. The design, development, properties and field trial results for this exciting new technology are discussed as well as a critical evaluation against the aforementioned triazine industry benchmark.
Experience in Implementation of Polymer Flooding on East Messoyakhskoye Oil Field
Authors: Zagrebelnyy Evgeniy , Glushenko Nikolay , Komarov Vladimir , Nemirovich Gennadiy , Ilyasov Ilnur , Sugaipov Denis , Ushmaev Oleg , Pleshanov Nikolay , Iskhakov Ruslan 
Published: October 2018

Abstract
Development of reservoirs with high oil viscosity is usually challenging because of requirement to apply comlex technologies for economical efficient oil recovery. East Messoyakhskoye oil field is a complex project both from geological caracteristics (viscous oil with viscosity 111 cP, highly heterogeneous reservoir with permeability 50-2500 mD, presence of gas cap and aquifer) and due to its remote location (arctic climatic conditions, no transport and industrial facilities).
Main reserves are located in reservoir PK, senomanian formation. At the field development plan stage calculations showed requirement of flooding for reservoir pressure maintenance, but waterflooding expected to be risky due to fingering and it was obvious that for efficient reservoir development enhanced oil recovery methods should be considered.
This paper presents choosen enhanced oil recovery strategy, the way passed in polymer flooding implementation and current results.
Comprehensive Approach to Development of Prirazlomnoye Oil Field
Authors: Koloda Alexey , Morozov Oleg , Andriyanov Maksim , Kuntsevich Vitaly , Mukhametshin Ilkam , Galimzyanov Artem , Nukhaev Marat 
Published: October 2018

Summary
Methods of field development of the Arctic shelf significantly different from oil land fields. The key features of the shelf fields are high costs and limited space to place the equipment. The field devepment plan should ensure high recovery factors with the relatively small number of production wells within the short period of time. The main factor to achieve the planned oil recovery factor is implementation of new technologies and approaches in the advanced well completion, well stimulation, and the use of full field reservoir model to take the best effective decisions in the part of the existing and project wells focused to increase the technological and economic efficiency of the project.
This work is devoted to the comprehensive approach to field development based on hydrodynamic and tracer studies, generalization of field-geological information and geological and hydrodynamic stimulation.
Improving Hydraulic Fracturing Fluids Through Dual Polymer Technology
Authors: Almubarak Tariq , Ng Jun Hong , Sokhanvarian Khatere , AlKhaldi Mohammed , Nasr-El-Din Hisham 
Published: October 2018

Abstract
As exploration for oil and gas continues, it becomes necessary to produce from formations that are deeper, have low permeability, and higher temperature. Conventionally, guar and its derivatives have been successfully utilized as hydraulic fracturing fluids. However, they require higher polymer loading to withstand the high-temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, they do not break completely and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.
In this work, a new hybrid dual polymer hydraulic fracturing fluid is developed for high-temperature applications. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings.
The polymer mixture solutions were prepared at concentrations ranging from 20 to 40 lb/1,000 gal at a ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300-350°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at these harsh conditions. HP/HT rheometer was used to measure viscosity and elastic modulus. HP/HT see-through cell was utilized for proppant settling.
Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300-350°F and 100 s−1. Results show that the dual polymer fluid can generate higher viscosity compared to the individual single polymer system. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance even at 20 lb/1,000 gal. The two polymers form a shared crosslinking network that improves proppant carrying capacity at lower polymer loadings and high temperatures. It also demonstrates a clean and controlled break performance with an oxidizer.
The major benefit of using a mixed polymer system is to reduce polymer loading at harsher conditions. Lower loading is highly desirable because it reduces material cost, eases field operation and lowers damage to the fracture face, proppant pack and formation.
Inhibition of Gas Channeling by CO2 Foam in Ultra-high Watercut Reservoir: Experimental Investigation Using NMR
Authors: Du Qingjun , Shi Lina , Hou Jian , Ji Yunkai , Zhou Kang 
Published: October 2018

Abstract
The oil recovery is improved by CO2 huff and puff in the ultra-high watercut reservoir, but gas channeling is very easy to occur. In this paper, the mechanism of increasing driving pressure and inhibiting gas channeling by CO2 foam puff-and-huff in ultra-high watercut reservoir was studied by nuclear magnetic resonance (NMR).
The experimental equipment is a visualization experiment system using nuclear magnetic resonance for oil and gas displacement (the magnetic field intensity: 0.3±0.05T). The influence of CO2/water ratio, permeability and displacement velocity on displacement pressure was carried out. The water saturation was determined on the basis of T2 spectrum, and the water distribution image during the experiments were obtained using imaging software. The ratio of displacement pressure difference between the CO2 foam flooding and water flooding at the same injection velocity is defined as resistance factor. The correlation between the resistance factor of CO2 foam and water saturation was established. The experimental results show that with the increase of injected CO2 foam volume, the water saturation decreased gradually, but the resistance factor changed little. After the injection volume reaches 0.5PV, the water saturation is reduced to about 0.62, the resistance factor increases rapidly, thus the water saturation defined as rising pressure water saturation. After the injection volume reaches 5.0PV, the water saturation is reduced to about 0.4, the resistance factor becomes stable. It is shown that the lower the permeability is, the greater the rising pressure water saturation, the smaller the resistance factor. When the CO2/water ratio is low, the foam is at low-quality state, the resistance factor is mainly controlled by the gas flow velocity; when the CO2/water ratio is high, the foam is at high-quality state, the resistance factor is mainly controlled by the water flow velocity; overall, the resistance factor firstly increased and then decreased as the CO2/water ratio increased. The corresponding CO2/water ratio is the optimal value when the resistance factor is maximum. The results helps to further analyze the mechanism of CO2 foam plugging and gas channeling inhibition.
Evolving Proppant Supply and Demand: The Implications on the Hydraulic Fracturing Industry
Authors: Olmen Brian D. , Anschutz Donald A. , Brannon Harold D. , Stribling Katherine M. 
Published: October 2018

Abstract
Flashback 10 years ago to 2008: the North American hydraulic fracturing industry utilized a then record breaking 21.41 Billion pounds and experienced exponential growth year-over-year (excluding 2015 and 2016). Prior to 2008, proppant demand grew at a relatively modest pace and overwhelmingly consisted of 20/40 mesh high quality natural sands and synthetic proppants. Fundamental changes in drilling and completion practices has given rise to a significant increase in the application of smaller mesh proppants, most notably 40/70, 30/50 and various forms of what is generically referred to as 100 mesh sand (i.e., sands that are predominantly smaller than 70 mesh) in natural gas and liquid applications. Proppant demand has now soared, increasing significantly as a result of the new high-intensity completions practices in horizontal wells. In 2018, an estimated 200 Billion pounds will be used for the first time in history (or 10 times that used in 2008).
The proppant supply industry responded well to the increased demand in the past decade, but the industry is increasingly concerned about future supply limitations and the potential impact on completion practices subject to high volume, quality and mesh size availability.
This paper summarizes the historical supply of proppant by type and source, and the driver for each proppant type based on the authors’ current and prior research. The paper will further clarify the basics of proppant by type and size (e.g., what is 100 mesh?) and will address some of the challenges that both the proppant supplier and end-user may face subject to current or desired completion practices. Key observations will be: 1) Potential limitations in the amount of proppant size and type, 2) The impact that specific proppant shortages may have on both supplier and end-user, and 3) Risk factors the proppant supply base may experience subject to future changes in completion design.
The objective of this effort is to encourage the need to study alternative completion designs subject to proppant availability. It is specifically not the intent of this paper to propose one form of completion practice or proppant type over the other.
Determining Gravel Pack Fluidization Velocity
Authors: Bhowmick Ankit , Amritkar Amit , Ehlig-Economides Christine 
Published: October 2018

Abstract
In a gravel pack completion, non-uniform reservoir inflow with a very high velocity can fluidize the gravel and/or erode the sand screen. The gravel pack screen is equipped with a basepipe with a pattern of holes through which fluid must pass after flowing through the gravel pack and screen. In a cased hole completion, fluid reaches the pack through a pattern of perforation tunnels opening into the gravel pack. The result is a complex flow pattern inside the pack involving both vertical and annular flow in addition to the expected radial flow. Previous studies have addressed the risks of fluidizing the gravel pack in high flow rate deepwater wells and have quantified a critical velocity above which fluidization is at risk. However, no formal mathematical model has justified the value, and details of the failure mechanism are lacking. This paper presents a Computational Fluid Dynamics (CFD) model that captures the complex flow dynamics within a cased hole gravel pack completion.
An ANSYS-FLUENT simulator was used to create a CFD model that simulated fluid flow through a gravel pack in conjunction with full particle motion phenomena. The Euler-Euler option treated each of two phases (flowing hydrocarbon and the gravel) as a continuum and enabled replication of gravel pack dynamics under producing conditions. Using well casing, screen, and basepipe geometries based on an actual field case from a conventional deepwater Gulf of Mexico well completion, the model provided visualizations of the nature of fluid flow through a gravel pack and captured destabilization (aka fluidizing) of gravel in a cased hole gravel pack completion.
The CFD model replicated the velocity changes projected by Wong for cased hole gravel pack completions. Fluidization tendencies and estimation of the minimum fluidization velocity in a gravel pack cased hole completion were determined. Sensitivities to flow rate, perforation density, base pipe geometry, and packing efficiency were evaluated. The model illustrated that at sufficiently high flow rates for certain gravel pack configurations, alignment of a basepipe and perforation holes can produce a jetting effect that could cause screen erosion. The model also revealed how the jetting effect could be suppressed.
This work underscores the importance of the gravel pack reserve height and packing efficiency. The fluidization velocity depends on gravel pack parameters that can guide the completion design. The model developed for this work enables testing whether a completion strategy is conservative enough to maintain the integrity of the pack. With aid of this model this study will be useful in designing gravel pack completions in ultra-high rate wells.
Exploration Portfolio Optimization for Increase of Investment Effectiveness
Authors: Zhukov Vladislav , Pogrebnyuk Sergey , Gazaliev Rinat , Bogdanovich Elena 
Published: October 2018

Abstract
Portfolio analysis is a tool to optimize investments, which is successfully used in various companies. While the principles and approaches of portfolio analysis have been known for a long time, examples of its application in the oil industry are limited. Exploration projects are often characterized by a low level of knowledge and a high degree of uncertainty of reservoir characteristics which determines the possibility of using portfolio analysis approaches in order to further select the optimal set of projects. It is important to understand that results of the analysis create the basis for the Company's development scenarios and balanced diversification of portfolio risks but they are not the final outcome of the work. The resulting scenarios are analyzed and corrected with a view to include particular projects in the regions of presence important for the Company or those projects than need to be implemented on a mandatory basis. Similarly, projects that are attractive by results of the scoring but not included in the current portfolio version can be added to the final set. This paper reviews some approaches based on portfolio analysis that can be applied to create a flexible basis for making decisions on the formation of a set of exploration projects. Forty five exploration projects in the perimeter of a number of Gazprom Neft subsidiaries are considered.
Capacity Assessment of CO2 Storage and Enhanced Oil Recovery in Residual Oil Zones
Authors: Chen Bailian , Pawar Rajesh 
Published: October 2018

Abstract
Residual oil zones (ROZs) are defined as those zones where oil is swept over geologic time period (natural flush) and exists at residual saturation. ROZs are increasingly being commercially exploited using CO2-enhanced oil recovery (EOR) (in Permian Basin). In this study, CO2 storage potential, long-term CO2 fate and oil recovery potential in ROZs are characterized. We use numerical simulations of CO2 injection with a reservoir model based on data from the Permian Basin. The changes of CO2 storage capacity and potential oil recovery with amount of CO2 injection are investigated. The effects of different well patterns (five-spot and line drive) and well spacing on fraction of CO2 retained in reservoir and cumulative oil production are also investigated. Furthermore, the effect of different CO2 injection modes, i.e., continuous CO2 injection and water-alternating-gas injection (WAG), on the CO2 storage and EOR potential are evaluated and compared. After the preliminary characterization of CO2 storage and EOR potential in ROZs, we next develop empirical models that can be used for estimating the CO2 storage capacity and oil production potential for different ROZs. A supervised machine learning algorithm, Multivariate Adaptive Regression Splines (MARS, (Jamali et al.)) is used for developing the empirical models.
Results show that CO2 retention efficiency and oil recovery vary non-linearly with amount of CO2 injected. It is observed that long-term CO2 fate is a function of CO2 injection amount and significant fraction of reservoir CO2 resides in hydrocarbon phase. Five-spot well pattern results in more oil production and larger amount of CO2 retained in reservoir than line-drive well pattern. During the investigation of well spacing, we observe that less number of wells actually results in higher CO2 retention and oil recovery, and less number of wells can also result in less probability of wellbore leakage. In comparison of WAG and continuous CO2 injection modes, it is observed that WAG injection has higher fraction of injected CO2 retained in reservoir, but with slightly lower cumulative oil production. In the study of empirical models for the capacity assessment of CO2 storage and EOR, results show that MARS can generate high-fidelity empirical models that can be used to predict the cumulative CO2 storage capacity and cumulative oil production for different ROZs.
Existence and Prediction of Severe Slugging in Toe-Down Horizontal Wells
Authors: Nair Jayanth , Pereyra Eduardo , Sarica Cem 
Published: October 2018

Abstract
Severe slugging is an important flow assurance issue, typically observed in offshore pipeline-riser systems. The consequences of severe slugging include flooding of downstream production facilities and an overall decrease in productivity. It had been previously thought that severe slugging would be limited to systems with a downward inclined pipeline and vertical, catenary or lazy-S shaped riser. This paper presents the results of an experimental and modeling study, which demonstrates the existence of severe slugging in systems with upward inclined lateral flow paths such as a toe-down well.
The severe slugging phenomena described in this paper was observed in a large scale experimental facility constructed for the purpose of studying flow behavior in horizontal wells. The facility enabled the study of the effect of the completion parameters like end of tubing location and the presence of a packer. Various gas and liquid rates were tested in the facility, and slug flow was the dominant flow pattern in the lateral section. The facility was also designed to test gas lift performance in horizontal wells. Therefore, the effect of gas lift on the severe slugging phenomenon was also studied.
Based on the experimental observations, two severe slugging prediction models were developed. The first was a transient model based on the Balino et al. (2010) model. The second was a single point criterion based on the Bøe (1981) criterion. The constitutive equations and modeling results are also presented in this paper.