bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Fracturing Fluid for HP/HT Applications
Authors: Zhao Haiyan , Nasr-El-Din Hisham A. , Al-Bagoury Mohamed 
Published: May 2015

Abstract
Hydraulic fracturing is used extensively to develop oil and gas wells in both high and low-permeability formations. Biopolymer-based fluids, including guar or guar derivatives, constitute the majority of polymers in fracturing fluids. These polymers cause formation damage, which is a serious problem on production enhancement. Therefore, the search for an alternative to guar is meaningful to the oil industry. In this paper, a novel viscosifier (V1) was developed to prepare fracturing fluids.
The rheological properties and proppant suspending ability of V1-based fluid have been studied with the effects of viscosifier concentration, temperature, and salts. Formation damage of the new type of hydraulic fracturing fluid in sandstone has been evaluated and compared to guar, hydroxypropyl guar (HPG), and viscoelastic surfactant (VES) fluids. The effects of temperature, viscosifier type, concentration, and formation permeability were investigated. The regained permeability of sandstone cores (expressed as a percentage of the initial permeability) was used to quantify the damage degree in coreflood tests.
The viscosity measurements have shown that V1-based fluids were stable up to 350°F with a high tolerance to KCl and CaCl2. Moreover, V1-based fluids had a good proppant suspending ability at 75 and 250°F, which out-performanced guar-based fluids. Coreflood tests were run using Berea and Bandera sandstone cores. As for V1 fluids, the regained permeabilities of the cores were 88% or higher of the initial permeabilities, suggesting that V1 caused a slight damage. However, guar and HPG fluids caused much more damage than V1 fluids under same conditions. The effects of temperature, viscosifier concentration, and formation type were different for guar-based fluids from V1 fluids. The external filter cake was formed when the V1 fluid was injected; however, no external filter cake was found for guar, HPG, or VES. The filter cake could be removed by injecting 5 wt% KCl brine in the opposite direction.
It was the first time to use this new cellulosic viscosifier in hydraulic fracturing fluids. The new type of fracturing fluid has better thermal stability and proppant suspending ability than guar-based fluids under the same conditions. Moreover, high regained permeability of sandstone cores can be maintained when treated by the new fracturing fluid.
Halite Envelope for Downhole Salt Deposition Prediction and Management
Authors: Zhang Yuping , Isaj Elisabeta 
Published: May 2015

Abstract
Halite salt deposition in the near wellbore formation and the wellbore of a gas well can dramatically reduce its productivity within a very short period of time. In order to minimise the salt induced formation damage, it is essential to identify if, where and how much halite will be deposited. The main objective of this work is to develop an easy- to-use tool for downhole salt deposition risk assessment and management.
The main mechanism for halite deposition in the near wellbore formation and the wellbore of a gas producer is water evaporation at a reduced pressure. A high deposition risk is expected at a high drawdown and a low produced formation water to gas ratio (FWGR). Halite deposition can also occur at a reduced temperature or pressure due to reduced halite solubility in water. A halite envelope can be used to determine the downhole halite deposition risk, which is a boundary marker for the start of halite deposition at which point halite is saturated in water. Two types of halite envelopes are introduced in this paper. One is for different reservoir pressures at differing FWGRs and but at a fixed temperature. The second is for different temperatures at differing FWGRs at a given reservoir pressure.
A number of North Sea gas field halite deposition cases will be presented in this paper. Each case will illustrate how the halite envelope technique can be used to identify high risk wells; their salt free operating conditions or to determine the requirement for water washes, and their associated injected water volumes. It will also demonstrate that for its successful application, reliable measurement of the water and gas production, along with an understanding of the water/gas influx, are both prerequisites in the validation of a halite envelope.
Efficient Proppant Flowback Prevention Strategy Allows Production of a Multi Fractured Offshore Horizontal Well Equipped With ESP and Screenless Completion
Authors: Martocchia Francesco , Dirya Ahmad D. , Baretti Salvatore , Farina Lisa , Rizza Giovanni , Okassa Fabrice , Haaland Tor G. 
Published: May 2015

Abstract
When production facilities are not equipped with a solid control device, proppant flowback becomes an issue throughout the entire productive life of a screenless multi fractured well. The challenge of minimizing proppant flowback is even more critical when dealing with offshore horizontal wells with ESP systems installed.
A wide selection of proppant flowback prevention additives is now available in the industry: most of them work either chemically or mechanically. At low formation temperature (150 F), the effectiveness of some additives such as resin coated proppant or fiber can be limited due to the temperature activation.
This paper will describe a successful strategy of proppant flowback control which was implemented in a multi stage fracturing treatment on a horizontal well in M- field, offshore Congo. It is the combination of resin coated proppant, enhanced by a chemical activator and inert fibers that provides double mechanism to eliminate proppant flowback issues during well production and sustaining life of ESP.
Success in this multi stage fracturing treatment has resulted in oil production from a pay zone that has never been produced due to poor petrophysical characteristics.
This document will describe: proppant flowback control additives selection process, placement strategy, hydraulic fracturing design and well execution considerations for multi stage fracturing treatments.
Controlling Excessive Water Production Using Induced Formation Damage
Authors: Zeinijahromi Abbas , Bedrikovetski Pavel 
Published: May 2015

Abstract
Excessive water production is one of the major factors in wells’ productivity reduction. It can be resulted from water coning and water channeling from water table to the wells through natural fractures, faults or high permeability zones. The use of foams or gels for controlling water production has been tested successfully in several field cases. However A large treatment volume is required to block the water influx that generally involves high operational and material costs. It is well know that injection of low salinity water into reservoir can mobilize reservoir fines and significantly decrease reservoir permeability. This paper presents the possibility of applying induced formation damage in order to block the water influx without hindering the oil production. This is a new cost-effective method using injection of low salinity water slug. It is shown that system of equations for water injection with induced fines migration and polymer injection is mathematically equivalent. Hence the polymer option in Eclipse-100 is applied to model low salinity water injection with induced fines migration. The modeling results showed that injection of 0.004 PVI of low salinity water above WOC resulted in significant reduction in produced water and improvement of oil recovery with no adverse effect on the oil production.
Hydraulic Fracturing in the Dutch Posedonia Shale
Authors: Janszen M. , Bakker T. , Zitha P. L. 
Published: May 2015

Abstract
This paper reports a critical review of the operational principles and the most important completions techniques used in hydraulic fracturing in the U.S.A. and investigate whether they are applicable to the Posedonia geological and surface environment conditions in Europe. It is found that both cemented liner and open-hole with external packers completions wells have been used in shale gas developments. Plug and Perf and continuous pumping multi-stage hydraulic fracturing methods were respectively used. Low viscosity fracturing fluids are preferred to increase fracture complexity in brittle shale. Large stimulated reservoir volume by increase fracture density effective fracture half-lengths and use of proppant techniques to increase fracture conductivity. It is found that the Posedonia shale is comparable to several U.S.A. shale pays in terms of geological and petrophysical attributes (porosity, permeability, thickness, gas, oil and water content water). Therefore, we expect the multi-stage fracturing techniques developed in the U.S.A. to be largely applicable for the Posedonia shale. However, larger softness and greater depths of the Posedonia shale make more viscous fracturing fluids and fewer but much longer horizontal wells inevitable. Provided such longer horizontal wells are used, production rates similar to those reached in U.S.A. shale gas wells could be achievable.
A New Technical Standard Procedure to Measure Stimulation and Gravel-pack Fluid Leak-off under Dynamic Conditions
Authors: Asadi Mahmoud , Ainley Brian , Archacki David , Aubry Eric , Brannon Harold , Ghalambor Ali , Parker Mark , Watson Russell 
Published: May 2015

Abstract
Historically, leak-off analyses of stimulation fluids have been performed using in-house laboratory procedures. The lack of industry standard procedures to perform leak-off and wall building coefficient analyses of stimulation fluids has introduced inconsistency in both results and reporting for many years. A technical standard adopted in 2006 by both API and ISO for static conditions has provided the oil and gas industry with the first standardized procedure to measure and report leak-off1. However, the more complex testing under dynamic conditions was not addressed. As a result, a group of industry experts have compiled their years of experiences in developing a new technical standard to measure the leak-off characteristics of stimulation and gravel-pack fluids under dynamic flow conditions.
Stimulation and gravel-pack fluids are defined, for the purpose of this technical standard, as fluids used to enhance production from oil and gas wells by fracturing and fluids used to place filtration media to control formation sand production from oil and gas wells. Leak-off is the amount of fluid lost to porous media during these operations. The leak-off procedure was developed through the collaboration of several industry companies by evaluating numerous in-house laboratory techniques and conducting round robin testing to ensure that any modifications to these procedures were reliable and repeatable. The new standard provides a step-by-step procedure that includes fluid preparation, experimental equipment design, testing procedure and data analyses for fluids exhibiting viscosity controlled leak-off or wall building characteristics. Example calculations are reviewed within this paper.
Comparison of Streamline Reservoir Simulation of Brine Flow, Mixing and Barium Sulphate Induced Formation Damage with Observed Produced Water Chemical Data to Aid Scale Management
Authors: Hu Yisheng , Mackay Eric , Vazquez Oscar , Ishkov Oleg 
Published: May 2015

Abstract
In waterflooded reservoirs under active scale management produced water samples are routinely collected and analysed, yielding information on the evolving variations in chemical composition. These produced water chemical compositional data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale management programmes designed to minimise damage and enable improved recovery.
In this interdisciplinary paper, the analyses of produced water compositional data from the Miller Field are presented and a 1D reactive transport model is developed to study possible geochemical reactions taking place within the reservoir through matching model results with observed produced water data. However, in the 1D reactive transport model, only one flow path was simulated; this does not fully represent the fluid flow and mixing behaviour in the reservoir.
Therefore, this paper also presents a fully 3D reservoir simulation study for the Miller Field to evaluate brine flow and mixing processes occurring in the reservoir, using an available history matched streamline reservoir simulation model integrated with produced water chemical data. Conservative natural tracers were added into the modelled injection water, and then the displacement of injection water and the behaviours of the produced water in two given production wells were further studied. In addition, the connectivity between producers and injectors was investigated based on the comparison of production behaviour calculated by the reservoir model with produced water chemical data, and an assessment of the properties of the intervening faults was also performed. Finally, a model of BaSO4 scale precipitation was included in the model, and the simulation results with and without barite precipitation were compared with produced water chemical data (observed barium and sulphate concentrations in the produced brine). In general, the modelled and observed data were found to be in good agreement, but any discrepancies were in fact found to be very informative also. The model assumes scale deposition is possible everywhere in the formation, whereas in reality the near production well zones were generally protected by scale inhibitor squeeze treatments, and thus the discrepancies between modelled and observed data could be used to diagnose the effectiveness of the chemical treatments to prevent formation damage around the production wells.
In-Situ Microemulsions Enhance Removal of Non-Aqueous Drilling Fluid in Gulf of Guinea Wells
Authors: Pietrangeli Gianna , Quintero Lirio , Gonzalez Yohnny 
Published: May 2015

Abstract
Efficient removal of the drilling fluid from tubulars, screens, and near-wellbore mineral surfaces is essential to the successful completion of wells. Cleaning and removal of the non-aqueous drilling fluid (NADF) from all of the well surfaces is not an easy task. Microemulsion fluids provide a highly-successful solution to this problem.
Carefully designed and customized microemulsion fluids have been used to remediate and increase well productivity and injectivity in wells located in the Gulf of Guinea. Due to their uniform wellbore cleanup, optimum results were achieved in open-hole horizontal and highly-deviated wells. The robust microemulsion fluid systems are capable of accommodating changes in temperature, density, and salinity. They restore the water-wettability of the rock and increase injectivity or productivity of the wells.
Some water injectors and oil producers from the Gulf of Guinea exhibited low injection or production rate. The purpose of pumping the treatment downhole was to improve injectivity by removing skin damage and screen blockage by using in-situ generated microemulsions, thus allowing efficient oil production from the formation or water injection at sustainable high-injection rates into the formation.
Field data shows that injectivity and productivity increased after treatment. In some cases, the downhole pressure decreased for the injectors. Cleanup and removal of the NADF from the Gulf of Guinea wells was beyond the capabilities of conventional treatments. Laboratory tests confirmed that the in-situ microemulsion treatment removes the damage and helps to achieve the desired and predicted injection and production rates. This paper presents field data, before and after the successful microemulsion fluid treatment, and describes various laboratory tests performed prior to the Gulf of Guinea field applications.
Next Generation Acid System – First Field Trial of a New Biodegradable Fluid in a Sandstone/Granite Formation
Authors: Lummer Nils Recalde , Rauf Omair , Gerdes Steffan 
Published: May 2015

Abstract
This paper introduces a new retarded stimulation system which is based upon an environmentally friendly, biodegradable acid and highlights its first field trial in a sandstone/granite formation. Here, demanding borehole conditions (165°C, anhydrite and carbonate scales, highly fractured sandstone and granite) as well as strict regulations regarding environmental impact of stimulation fluids set forth by mining and water authorities were encountered.
Extensive laboratory tests regarding reactivity, acid corrosion tendency, and fluid compatibility were conducted preparing the first application in a geothermal well. In contrast to HCl-based fluids, this state of the art acid system has a low corrosion tendency and an excellent compatibility profile, even at high temperature.
The superior chemical properties of this stimulation system combined with an outstanding performance of inflatable packers in the openhole section lead to a greatly enhanced injectivity of the geothermal well. Laboratory and field results impressively proved that this new biodegradable acid system is an excellent alternative to commonly used HCl-based fluids.
Nanosilica-based Conformance Gels
Authors: Boul Peter J. , Ye Allan , Pang Xueyu , Goel Vivek , Eoff Larry , Reddy B R 
Published: May 2015

Abstract
Conformance gels based on nanosilicas are used as environmentally acceptable materials for plugging and sealing water- or gas-producing zones and controlling water production. Because of the lower pH(compared to sodium silicate solutions) of these solutions, they are environmentally acceptable in the North Sea area. The gelling agents required to activate the materials to produce gels are typically common salts, such as sodium chloride and potassium chloride.
The reduced environmental impact of nanosilica has led to its commercial success in the North Sea. At temperatures greater than 80°F, the gel time of nanosilica can be controlled to desirable values by adjusting concentrations of the gelation agents. The nanosilicas that are currently used in the oilfield, however, are not suitable for low-temperature applications (e.g., below 80°F) because of extremely long gel times.
This paper describes a new nanosilica system that demonstrates non-spherical-shaped nanosilica particle assemblies, such as rod-like and string-of-pearl geometries that display superior gelation activity in the presence of salts, exemplified by sodium chloride, compared with their spherical counterparts. These materials can gel in a reasonable time frame in the presence of an activator at temperatures as low as 50°F.
A trend of increasing reactivity in nanosilicas based on their geometries is presented in this paper. In particular, nanosilicas with a high aspect ratio render stable gels in a shorter period of time than their spherical counterparts. It is proposed that the aspect ratio could enable formation of a networked superstructure of silica at lower concentrations than required for a networked structure of nanosilica spheres of similar diameter.
Prevention of Calcium Carbonate Precipitation during Water Injection into High-Pressure High-Temperature Wells
Authors: Khormali Azizollah , Petrakov Dmitry G. , Lamidi Abdul-Latif Benson , Rastegar Reza 
Published: May 2015

Abstract
Complex technical problems, including salt precipitation, can occur during the entire period of the operation and production of the oil from reservoirs in high-pressure/high-temperature (HPHT) condition. Inorganic salts deposition occurs during the mixtures of different waters, which are incompatible with each other. These combinations of waters mostly can be done during waterflooding into the reservoirs to pressure maintenance. For the effective development of oil reservoirs, which are associated with the deposition of inorganic salts in HPHT, the selection of inhibitors is required to prevent scaling accounts for the characteristics of the reservoirs. Effectiveness of the scale inhibitors concentration for specific well conditions is verified by laboratory tests, considering total dissolved salts and hydrochemical conditions of the formation. The amount of calcium carbonate (CaCO3)) precipitation in synthetic formation water was investigated in mixing with the injected water in the range of 100-200°C for temperature and 40-70 MPa for pressure. Also, calcium carbonate precipitation was considered in a well at 200°C and 70 MPa in a simulation model with an electrical submersible pump (ESP). The results of the experiments showed that the possibility of calcium carbonate deposition was increased by growing the amount of the formation water and temperature. Increasing the pressure had reverse effect on scale formation. In this investigation, a new inhibitory chemical composition was developed. This scale inhibitor is based on the aqueous solutions of different acids and isopropyl alcohol. The inhibitor was considered for compatibility with formation water and core samples; and it was compatible with them at reservoir condition. The new scale inhibitor had a greater inhibition efficiency and low permeability damage in comparison with the tested inhibitors. The used materials were effective for scale prevention at high-level. The synergistic inhibitory effect has been considered for mixtures of inhibitors.
A Model for Real Gas Transfer in Nanopores of Shale Gas Reservoirs
Authors: Wu Keliu , Chen Zhangxin , Wang Heng , Yang Sheng , Li Xiangfang , Shi Juntai 
Published: May 2015

Abstract
The gas transport in nanopores of shale gas reservoirs is significantly different from that in conventional gas reservoirs. A model for ideal gas in nanopores is derived based on a weighted summation of slip flow and Knudsen diffusion, where ratios of intermolecular collisions and molecular and nanopores wall collisions to total collisions are the weighted factors of slip flow and Knudsen diffusion, respectively. This model is extended to the application of real gas transport in nanopores by taking into account the effects of intermolecular force and gas molecule volume on mass transport under the condition of high pressure. The model is validated by published molecular simulation data. The results show that the model is more reasonable to describe all of the gas transport mechanisms known, including continuous flow, slip flow and transition flow; the degree of real gas effects on gas transport is up to 23%, which is controlled by pressure, temperature, nanopores radius and gas type; and methane transport capacity is underestimated by 65.09% with helium and overestimated by 106.27% with nitrogen in simulation of methane transport in shale nanopores under the condition of laboratory experiments.