bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Natural Gas Exploration and Production on Mercury Concentrations in Surface Sediment of the Gulf of Thailand
Authors: Sompongchaiyakul Penjai , Bureekul Sujaree , Sombatjinda Siriphorn 
Published: November 2018

Abstract
More than two decades that the Gulf of Thailand (GOT) has been installed with petroleum hydrocarbon production platforms, currently over 400 platforms were installed and operated. Since mercury is a common contaminant in petroleum hydrocarbon production in Southeast Asia, minimal risk and environmental integrity should be concerned. Mercury concentration in surface sediment collected from the Gulf of Thailand in 2003 (89 stations), 2012 (174 stations) and 2013 (45 stations).
Sedimentological characteristics, readily oxidizable organic carbon and calcium carbonate were determined. All analyses were carried out in our laboratory using cold vapor atomic absorption spectroscopy. The results show an increase in trace amount of mercury in the Gulf's sediment. Average concentrations of mercury in surface sediments in the lower GOT collected in 2003, 2012 and 2013 were 24.4±9.00, 34.9±21.5 and 41.4±15.3 μg/kg dry weight (carbonate free basis). It is coincident to an increment in the number of platforms for natural gas exploration and production in the Gulf of Thailand. Spatial distribution of mercury in the sediments indicates a clearly linked to the exploration, development, production, and processing in petroleum and gas operation. Although the elevation of mercury level in the GOT's sediment does not showed high risk yet, treating and recycling of mercury contaminated substances generated during production are required in order to minimize the health risk in consumption of seafood collecting from the GOT.
Wax Deposition and Hydrate Transport Dynamic Simulations on an Oil Pipeline - Experiences Applying Novel Models for Flow Assurance Assessment
Authors: Puente Patricio , Martinez Victor , Richon Vanessa , Morud John , Zambare Neeraj 
Published: November 2018

Abstract
To minimize capital costs, operating companies are choosing to produce oil and gas through longer and longer subsea tie-backs. Transportation of multiphase gas, oil and aqueous mixture over long pipelines under high pressure and low subsea temperatures present some unique challenges. One of the most important challenges in flow assurance for such more common long pipeline designs is the possibility of blockage due to hydrate formation and/or wax deposition.
This paper discusses results using the newly developed wax deposition and hydrate transport models for a pre-FEED study. The models demonstrated are integrated into a generic and well proven multiphase dynamic simulator framework designed to be used for pre-FEED and FEED studies for a green oil field as well as to trouble shoot production challenges and simulate production of an already producing field.
LedaFlow™ is the multiphase, transient simulator that was used during the study. It contains a framework which easily allowed implementation of the new modules for wax and hydrate.
Wax deposition and hydrate transport are two important challenges for pipeline design and operations with waxy oil fluids that are prone to hydrate formation. An accurate model for quantifying the wax deposition and hydrate transport processes is essential to assure secure and safe transportation of these hydrocarbons. In addition, providing accurate predictions of not only the pressure drop along the pipeline but also of the flow behavior during the transport will help to optimize the development schemes, avoiding over-design. There are several options for modeling both processes, however, for the evaluation reported here not only the process itself is important, but to model dynamic operational scenarios is also important. For this study a waxy and hydrate forming stream was selected. This stream comes from a single stage separator in an offshore facility.
The new wax model includes some key features, such as the non-Newtonian nature of the waxy oil, the growth of the wax layer and the effect on heat transfer throughout the pipeline. It is based on a known model from the literature, however, it brings a fundamental new framework for simulating the effect of wax on multiphase flow as it benefits from all the functionalities of the multiphase flow simulator like transient operations, accurate thermal modeling including use of heat tracing. All of this has been considered in our study of normal operations. In the hydrate transport model, mass transfer during hydrate formation, the hydrate former/water depletion in the pipeline and the slurry viscosity with hydrate particles have all been considered.
Innovative Water-Blocking Agent Based on High Stable Emulsion with Nanoparticles for IOR Implementation
Authors: Sergeev Vitaly , Kim Ijung , Zeigman Juri , Yakubov Ravil 
Published: November 2018

Abstract
This article represents the results of the research and development project that has been conducted with the goal to create an innovative and environmental water-blocking agent for the enhancement efficiency of the improved oil recovery methods. The innovation of the developed water-blocking agent lies in the combination of unique physical and chemical properties: high thermal stability (140 °C), improved rheology (viscoplastic properties), outstanding surface activity (regulation of the wettability of rock surface), and selective blocking effect. The key factor to combine all of these properties in one solution is to apply colloidal silicon dioxide nanoparticles with modified surface as a stabilizer and surface-active phase in the emulsion system. Also, a technology on the new water-blocking agent for the effective application in the intensification of oil production (well stimulation, IOP) methods has been developed, and well-tested in the field. For the investigation of the unique properties of the new emulsion systems with colloidal silicon dioxide nanoparticles, different types of laboratory experiments were carried-out, including coreflooding tests on the oilfield cores by using the facility with parallel coreholders for stand modelling of the developed technology in the IOP. The main task of the IOP technology is to redistribute the filtration inflows in the near-wellbore zone by selectively blocking the most permeable water-saturated intervals and to penerate through the less permeable inter-layers of the bottomhole zone by the acid composition.
Bitumen Identification from NMR and Triple Combo Logs in Tight Gas Formation in the Sultanate of Oman
Authors: Lukmanov Rinat 
Published: November 2018

Abstract
The presence of bitumen is an obvious risk for reservoir development. Pore-filling bitumen degrades reservoir quality. Sweetspotting, discriminating between producible oil and gas and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and the optimal development planning. However it is in most cases impossible to make such differentiation using conventional logs.
It is well known that the Nuclear Magnetic Resonance (NMR) log provides an opportunity to identify the presence of reservoir bitumen in oil bearing reservoirs. The zones containing bitumen within oil and water reservoirs are characterized by lower NMR porosity estimates when compared to porosity from the density and neutron tools. But in gas reservoirs, bitumen identification from NMR porosity deficit is not a common industry practice. The porosity deficit could be related not only to the presence of bitumen, but also to the presence of gas in the pore space.
The case studies include tight gas reservoirs in Miqrat and Middle Gharif formations, both located in the Sultanate of Oman. Well tests showed gas rates lower than expected, accompanied by low mobility and sometimes water production from intervals with relatively good porosity and saturation calculated from logs. Besides, bitumen was identified from core. A new methodology was developed which can differentiate between residual gas and bitumen presence based on Density, Neutron and NMR logs in conjunction with resistivity. One of the pre-requisites is that the reservoir lithology must be known. The remaining gas saturation is quantified from Density-Neutron separation. If we know the Hydrogen index (HI) of gas, the NMR porosity deficit can be compensated for residual gas effect. Bitumen saturation can be quantified from the difference of total porosity and NMR compensated porosity.
The methodology was tested on two tight gas reservoirs of the Sultanate of Oman. Core analysis, production data, and total organic carbon (TOC) derived from pulsed neutron logs were used to verify the results of the suggested methodology. The comparison shows that the methodology can be used for semi-qualitative identification of bitumen. It was also observed that the bitumen distribution varies across the field, and overall the majority of reservoir hydrocarbons are moveable. Recommendations on the workflow for static and dynamic modeling were provided.
The suggested novel approach of bitumen identification in gas bearing reservoirs is relatively simple. It provides fit for purpose results for gas bearing reservoirs including tight gas which in turn can be used for more accurate estimation of gas volumes and optimizing development planning.
Deepwater HPHT Drilling through Ultra Narrow PPFG Window: A Case Study by ENI Where the Combination of Continuous Circulation Technology Together with MPD Drilling has been Successfully Applied to Extreme Drilling Environment Condition in HPHT Ultra Deepwater Well
Authors: Squintani Enrico , Uslenghi Andrea , Ferrari Susanna , Affede Luca 
Published: November 2018

Abstract
Ultra Deepwater wells are commonly characterized by a narrow margin between pore and fracture gradients. Eni pioneer of the Continuous circulation technique has pushed the control of annulus dynamic pressure to the limit. The experience presented in this paper cover the drilling of an HPHT Deepwater well, through an ultra narrow PPFG window by means of technology application and strict procedural control.
In the case study presented the reservoir section of an HPHT well was planned to be reached with an adequate kick tolerance and choke margin by applying the ENI near balance drilling technique (e-nbd™) in order to ensure strict control on the primary barrier and achieving the aimed operational and safety performance. The plan required the use of e-cd™ (eni circulating devices) system installed for the first time on a drilling ship with the 6 5/8″ DPs.
Performance of an Electric Submersible Pump with Gas Slugs and Different Inlets
Authors: Perisho Randal , Robinson Mark 
Published: November 2018

Abstract
The oil industry has been experiencing issues with "slugs" of gas that limit the ability of the pump to create head and causes a low amp or underload shutdown. Baker Hughes has developed special gas inlets to improve flow in high gas wells. Electric submersible pump (ESP) performance is evaluated with a new "Slug" test to determine how a "slug" (or short burst) of gas affects the output flow.
Several different inlet devices are tested with a mixed flow pump in a high gas environment using water and nitrogen. An annular ring introduces gas below the pump inlet and partial flow is allowed to bypass the pump inlet to simulate real well conditions. Three inlet devices are compared to a standard pump inlet to determine how long it takes a slug of gas to terminate flow. In addition, these inlet devices are tested at steady state conditions with different flow rates and gas volume fractions (GVF).
The "gas slug handling" capabilities of a standard mixed flow pump stage is compared with three different inlet devices. The test is repeated at several different flow rates to document the time required for a slug of gas to stall the system. A standard pump running at 1000 bpd stalls in 20 seconds as compared to 70 seconds on the best inlet when a slug of 95% gas is introduced. When the system is tilted 30 degrees off vertical, a slug of gas will cause them all stall in 30 to 41 seconds.
Steady state gas tests were conducted at a variety of gas volume fractions to find the resulting output flow and pressure for each inlet device at flows between 500 and 2500 barrels per day. The resulting gas curves are presented for each inlet device with the system running in a vertical and 30 degrees off vertical. One of the inlets was able to generate four times the output pressure of a standard pump at 40% gas volume fraction. The production inlet ran better than any other inlet when the system is tilted 30 degrees off vertical.
Experimental Investigation of Osmosis as a Mechanism for Low-Salinity EOR
Authors: Pollen Erik Norrud , Berg Carl Fredrik 
Published: November 2018

Abstract
The objective of this paper is to describe experiments conducted to investigate osmosis as a mechanism for low-salinity enhanced oil recovery (EOR). For this purpose, an experiment was designed to facilitate enhanced oil recovery by osmosis-induced connate water expansion, while at the same time reducing the contributions of other proposed low-salinity mechanisms. Considerations were also made to achieve osmotic water transport rates comparable to what is expected at reservoir temperature.
The correlation between enhanced oil recovery and the surface-to-volume ratio was of particular interest. Because the osmotic pressure gradients occur over distances comparable to the pore size, it is plausible that fluid redistribution due to osmosis would lead to a fairly local redistribution of oil, and thereby have a small impact on overall enhanced recovery in the field. However, near exposed surfaces, this local redistribution may result in oil production.
Previous investigations of osmosis as an underlying low-salinity mechanism have consisted of visualization experiments, where water transport and oil movement under influence of osmotic gradients have been observed. Our experiments are intended to increase the understanding of the relative importance of osmosis in both small-scale low-salinity experiment results, and for field-scale low-salinity flooding.
In the experiments, oil-wet sandstone samples with different surface-to-volume ratios were saturated with high-salinity water and oil to irreducible water saturation. The samples were first left to spontaneous imbibe in high-salinity water and afterward in low-salinity water. Additional oil production from spontaneous imbibition of low-salinity was recorded and compared with the surface-to-volume ratio. The experiment was performed twice, at both ambient and elevated temperatures.
The experiments at ambient temperature resulted in increased oil production values of 8-22% of pore volume by low-salinity spontaneous imbibition. No clear correlation was found between increased oil recovery and the surface-to-volume ratio. A correlation was, however, seen between increased oil production and the pore volume. Thus, increased oil production by low-salinity imbibition seems to be proportionate to the pore volume.
The experiments at elevated temperature resulted in low values of increased oil production by low-salinity spontaneous imbibition, and the values do not seem to correlate with either surface area or pore volume. The low response is believed to be caused by thermal effects from repeated heating and cooling of the samples during the preparations.
Our results cannot dismiss osmosis as an important mechanism for low-salinity EOR. Possible explanations for the correlation between increased oil production and pore volume are hysteresis and simultaneous connate water expansion throughout the core.
New Model for Wettability Change with Depth in Mixed-Wet Complex Carbonates
Authors: C. Ferreira Flavio , Stukan Mikhail , Liang Lin , Souza Andre , Venkataramanan Lalitha , Beletskaya Anna , Dias Daniel , Dantas da Silva Marianna 
Published: November 2018

Abstract
Oil-water relative permeability and capillary pressure are key inputs for multiphase reservoir simulations. These data are significantly impacted by the wettability state in the reservoir and by the pore space characteristics of the rock. However, in the laboratory, there are several challenges related to the validation and interpretation of the special core analysis (SCAL) measurements. They are mostly associated with the core preservation or restoration processes and resulting wettability states. To improve dynamic reservoir rock typing (DRRT) process, a new model, describing the change of wettability fraction with depth in mixed-wet reservoirs, is proposed. The proposed model is based on solid physics describing the interactions between the rock grain surfaces and the fluids filling the pore space. First, the model considers the oil migration from the source rock into the originally water-wet reservoir and the corresponding capillary pressure rise, as the height above the free water level (HAFWL) is progressively increased. Then, oil-wet and water-wet fractions are estimated for different static reservoir rock types (SRRT) and different HAFWL, based on the wettability change potential of the rock-fluid system and oil-water capillary pressure curves. Additionally, mixed-wet capillary pressure and relative permeability curves are estimated for both oil displacing water (drainage) and water displacing oil (imbibition) processes, based on the estimated mixed-wet fractions and single-wet curves. We discussed the model assumptions and its parameters’ uncertainties. We prepared a comprehensive sensitivity study on the impact of wettability variability with depth on oil recovery results. This study used a synthetic carbonate-reservoir simulation model, under waterflooding, by incorporating the concept of DRRT defined according to the different SRRT and estimated wettability fractions. The results showed a significant impact of wettability variability on oil in place and reserves estimates for waterflooding processes in typical complex, mixed-wet carbonate reservoirs, such as the ones found in the Brazilian Pre-Salt. We also discuss the potential impact of wettability change with depth on well logs like resistivity, nuclear magnetic resonance (NMR) and dielectric logs. The proposed reservoir wettability model and its corresponding DRRT workflow is relatively simple and widely applicable, and may significantly improve reservoir simulation and wettability uncertainty analysis. It also explicitly identifies the required wettability parameters to be obtained from laboratory experiments and well logs. Finally, the proposed model may be integrated with special core analysis, well logs and digital-rock analysis.
Application of Point on Wave Controlled Switching on High Voltage Systems for Weak Offshore Grids
Authors: Al Ammari Sara , Kotrappa Murugendrappa N. , Manna Malay , Abou El Makarem Mohamed 
Published: November 2018

Abstract
At offshore oil and gas islands, on site generators running independently are often utilized. These on site generators have their benefits but also pose their own drawbacks and may have their own problems. Due to the instability of those weak offshore grids, the grid disturbances may cause power outages, voltage fluctuations, changes in frequency, blackouts …etc. which are easily felt by the consumers and can also impact the performance and the service life of the electrical equipment.
A study has been performed to examine different methods to improve the reliability of the overall network. Circuit breakers are designed to react by opening or closing the circuit as soon as a command is received. While doing so, the circuit breakers go through tremendous high stresses which ultimately may cause it to produce an arc. This phenomenon can be mitigated and reduced using controlled switching. This technology involves pre-defined control strategy for opening and closing each circuit breaker pole independently. Controlled switching methodologies are used to minimize the stress on circuit breakers, prevent failure of electrical equipment and improve power quality without affecting the overall grid. This new cost effective technology helps in reducing disturbances while improving electrical reliability to the end consumer. High Voltage Shunt Reactors, Subsea Cables and Transformer Energization and De-energization cause high inrush current on the system. Power system study software has been utilized to identify which loads will provide the optimum benefit when implementing the Controlled Switching application.
This paper addresses the benefits of using controlled switching on high voltage circuit breakers on weak offshore grids. This paper also studies the applications and advantages of controlled switching of 132kV long subsea cable and transformer feeders wherein high inrush current is expected while showing the outcomes of research results and actual scenarios that have been implemented
Enhanced Solvent-Based Remediation of Waxy Deposits
Authors: Zadeh Kamran Akbar , Tatavalli-Mittadar Nirmal , Abd-Rahman A-Sukaimy , Jain Shekhar , Ashtekar Sunil , McGregor Stuart , Degaleesan Sujatha 
Published: November 2018

Abstract
Restriction or blockage of flow path due to waxy deposits is a global issue in the oil and gas production. This undesirable flow assurance issue leads to increase in production deferment and OPEX for mitigation and frequent intervention. It may also result in huge CAPEX for pipeline sections replacement due to untreatable blockages.
Despite the current prevention and mitigation strategies in place, wax deposition cannot be fully eliminated. Existing remediation technologies can be broadly classified to mechanical, thermal, and chemical-based treatments. These also have some limitations such as availability, cost, deferment and effectiveness. Today, most effective solutions are often a combination of mechanical and chemical which are expensive in terms of cost and may result in additional deferment time. As such, the development of more effective remediation strategies is of great importance.
Solvent-based cleaning can be relatively less expensive if it is a viable option. However, experience suggests that conventional solvents such as xylene are generally not that effective in dissolving and breaking wide range of waxy deposits with varying compositions.
Enhanced solvent-based remediation is a novel approach with the focus to balance performance, cost, and safety for field applications. Based on this approach, understanding the field deposit, optimizing solvent's performance in the lab under representative field conditions, selecting a solvent that balances performance with cost and safety, scaling up from lab to the field conditions based on the field's limitations, and proper deployment of the selected solvent in the field play important roles in effective remediation of deposits.
In this work, the enhanced solvent-based remediation approach and the lab procedure for primary screening of solvents are described. In addition, the procedure for cleaning a flowline that was restricted by wax deposit in an onshore field in South-East Asia is explained. The results of this successful field application that led to increase in net oil production and OPEX saving are also discussed.