Noordwijk

ABSTRACT Scaled physical model testing of a hybrid coastal structure concept consisting of a rubble mound with varying sand dune cover thickness was carried out in a wave flume with moveable-bed capabilities. The morphological changes of the sand dune cover over time were captured by laser line scanner measurements and hydrodynamic conditions produced by irregular wave trains were measured by capacitance wave gauges. Results show that the sand layer thickness and its morphological evolution affect hydrodynamic conditions in overtopping critical for the design of such structures. INTRODUCTION Increasing pressure on most of the world's coastlines from human development calls for innovative approaches to coastal protection. One option are hybrid structures that combine the benefits of different types of coastal protection concepts. Specifically, the combination of rubble mound coastal structures and soft protection such as nourished beaches and sand dunes have great potential to fulfill a multitude of functions related to storm protection and ecosystem restoration. Several researchers have studied or reported on combinations of hard and soft coastal protective structures for various reasons (e.g Boers, 2012; Voorendt, 2012; Van Mechelen, 2013). Voorendt (2012) evaluated multifunctional flood defenses and listed the most common reasons to adopt hybrid defense approaches such as improving the spatial quality, enabling recreation, providing spaces for agriculture and providing shelter places and more. Van Mechelen (2013) assessed the impact of hard structures inside a coastal dike in light of the most critical failure mechanisms related to overtopping, piping and stability. Boers (2012) looked at a hybrid barrier as a combination of a sand dune and a hard structure for flood defense purposes. This type of barrier satisfies other needs such as added recreational space and dune ecosystem functionality. The protection concept of this type of hybrid structure is to reduce wave attack on the hard structure by providing an erodible sand layer that can provide a buffer and form sediment deposits in the foreshore that can cause increased wave energy dissipation before waves hit the structure (Boers, 2012). The idea of having a classical coastal structure covered by a natural sand cover has been implemented at various locations around the world. In the Netherlands, a dike-indune concept has been used at two different locations fronting the North Sea, Katwijk and Noordwijk. The combination of both hard and soft engineering solutions in those areas offers multiple benefits such as enhancing the natural qualities of the area and providing spatial development options while protecting the area from coastal storm impact. In the United States, only few examples of such hybrid solutions exist. However, some of those structures are not intended by design to be hybrid coastal defense systems but rather fulfill that function accidentally. One example is a relic rock seawall covered by a sand dune via natural processes and nourishment activity in Bay Head, New Jersey. Irish et al. (2013) show that the portion of the beach including the sand-covered seawall fared better against storm-induced erosion than adjacent stretches of coastline without this hybrid setup. Basco (1998) reported on a dune system with a buried seawall/revetment that successfully provides protection for naval infrastructure in Virginia, US. This unique design alternative was selected over the traditional shore protection solutions based on an economic analysis and the potential benefits the chosen alternative can provide.

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ISOPE

ISOPE-I-17-351

The 27th International Ocean and Polar Engineering Conference

Country:

North America > United States > Texas (0.29)
North America > United States > Virginia (0.24)
North America > United States > New Jersey (0.24)
(5 more...)

Genre:

Research Report > New Finding (1.00)
Research Report > Experimental Study (1.00)

Industry: Energy (0.76)

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization (0.56)

Technology: Information Technology > Artificial Intelligence (0.48)

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Modeling Formation Damage and Completion Geometry in the Gyda Reservoir

Carpenter, Chris (JPT Technology Editor)

OnePetroFebruary, 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165113, ’Modeling Formation Damage and Completion Geometry in an Old Well Enables Better Planning for New Wells: Gyda Development Case Study,’ by M. Byrne, SPE, and E. Rojas, SPE, Synergy, and V.B. Holst, SPE, Talisman Energy, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, The Netherlands, 5-7 June. The paper has not been peer reviewed. This study concerns the mature Gyda reservoir, where some recent production wells have underperformed relative to equivalent initial wells. In particular, a sidetrack to an early successful well had very poor performance on initial startup. Subsequently, the geometry of both the original well and the sidetrack was simulated. In the original well, an attempted hydraulic fracture was assumed to have failed. This assumption was challenged in the model. The model has enabled evaluation of old wells and, more importantly, design of new wells in this mature-reservoir development. Introduction Gyda is a mature oil development in the Norwegian sector of the North Sea. The first production wells were drilled more than 20 years ago. Some recently drilled Gyda wells have not fulfilled production objectives. A numerical 3D model was proposed in order to investigate and understand the flow dynamics and the production potential from the Gyda A19 and A19A wells. This modeling process includes a detailed numerical 3D fluid-flow simulator based on computational fluid dynamics (CFD), which captures the reservoir, well, and completion geometry complexity. The CFD simulations are used to determine potential explanations for the wells’ performance and lead to stimulation options and development of optimum drilling and completion for future wells. Because Well A-19 is very similar to Well A19A, some conclusions may be derived from the present study that could support the understanding of the productivity behavior of Well A19A. To achieve the objective, one CFD model of both wells was constructed. Different completion options were provided, including the case of the hydraulically fractured well. Several sensitivity analyses were carried out in order to depict the well potential.

OnePetro

doi: 10.2118/0215-0126-JPT

SPE

SPE-0215-0126-JPT

Journal of Petroleum Technology

Country:

Europe > United Kingdom > North Sea (0.25)
Europe > Norway > North Sea (0.25)
Europe > Netherlands > South Holland > Noordwijk (0.25)
(2 more...)

Genre: Research Report (0.49)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Zechstein Formation (0.98)
Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Ula Formation (0.98)

SPE Disciplines:

Well Drilling > Formation Damage (1.00)
Well Completion > Hydraulic Fracturing (1.00)
Well Completion > Completion Installation and Operations (1.00)
Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)

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Fines Migration in Fractured Wells: Integrating Modeling With Field and Laboratory Data

Carpenter, Chris (JPT Technology Editor)

OnePetroFebruary, 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165108, ’Fines Migration in Fractured Wells: Integrating Modeling With Field and Laboratory Data,’ by M. Marquez, W. Williams, and M. Knobles, Chevron, and P. Bedrikovetsky, SPE, and Z. You, SPE, University of Adelaide, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, The Netherlands, 5-7 June. The paper has not been peer reviewed. Production and drawdown data from 10 subsea deepwater fractured wells have been modeled with an analytical model for unsteady-state flow with fines migration. The simulation results and the field data indicated a good match, within 5%. This paper describes the methodology used to integrate the modeling predictions with field and laboratory data to identify probable causes for increasing skins and declining productivity-index (PI) values. Introduction Fines migration is a complex phenomenon that can challenge the economic viability of a project because of well-productivity decline, lower-than- expected hydrocarbon recoveries per well, large capital expenditures to drill and complete additional wells, and high operating costs from suboptimal facility designs. Excessive fines production may also result in equipment erosion and corrosion, formation of hard-to-break emulsions, and plugging of flowlines and surface facilities, all leading to potential hazardous situations. This paper describes a multidisciplinary approach in which fines-migration modeling has been integrated with field and laboratory data to ascertain whether fines migration may be associated with rapidly increasing skins and declining PI values observed in a subset of deepwater fractured wells. Laboratory studies exhibit fines release and migration during coreflooding and stress testing; the field well-productivity data are well-matched with the mathematical modeling.

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doi: 10.2118/0215-0129-JPT

SPE

SPE-0215-0129-JPT

Journal of Petroleum Technology

Country:

Europe > Netherlands > South Holland > Noordwijk (0.24)
North America > United States > Texas > Dawson County (0.24)

Genre: Research Report (0.34)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

Well Drilling > Formation Damage > Fines invasion (1.00)
Well Completion > Hydraulic Fracturing (1.00)
Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
(2 more...)

Technology: Information Technology > Modeling & Simulation (0.36)

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Self-Diverting Acid for Effective Carbonate Stimulation Offshore Brazil

Carpenter, Chris (JPT Technology Editor)

OnePetroJune, 2014

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165089, ’Self-Diverting Acid for Effective Carbonate Stimulation Offshore Brazil: A Successful History,’ by A.T. Jardim Neto, C.A.M. Silva, R.S. Torres, R.L. Farias, F.G.M. Prata, and L.A.M. Souza, Baker Hughes, and A.Z.I. Pereira, A. Calderon, and E.F. Sandes, Petrobras, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, the Netherlands, 5-7 June. The paper has not been peer reviewed. This work describes the positive results experienced when a self-diverting acid system based on a viscoelastic-surfactant (VES) technology was introduced for carbonate-reservoir stimulation offshore Brazil. The self-diverting (SD) VES (SD-VES) promotes viscosity development when the acid comes in contact with the carbonate formation. Since the SD-VES was introduced in this environment in 2009, more than 40 wells have been treated with the system. Introduction Matrix acidizing is frequently used to stimulate carbonate reservoirs offshore Brazil. In these treatments, a proper diversion technique is required to direct the treatment fluid to lower-permeability or more-damaged zones and ensure the treatment of the entire production interval. The chemicals developed and used as diverting agents include polymer gels, foams, oil-soluble resins, and rock salt, among others. Offshore Brazil, polymer-based systems have been applied successfully. Such systems are easier to handle than particulates, and diversion is achieved through the formation of natural resistance to viscous flow. Generally, the treatment is divided into three phases: a regular 15-wt% hydrochloric acid (HCl) is pumped first, followed by a gelled 15-wt% HCl, and finally by a pill of insitu- crosslinked gelled 3-wt% HCl. In most cases, several stages are pumped, repeating the three phases in order to cover the entire interval. Despite the success experienced with polymer systems, concerns about the potential damage to the formation provided an impetus for the successful introduction of a viscoelastic-acid system offshore Brazil.

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doi: 10.2118/0614-0092-JPT

SPE

SPE-0614-0092-JPT

Journal of Petroleum Technology

Country:

South America > Brazil (1.00)
South America > Colombia > Risaralda Department > Pereira (0.24)
Europe > Netherlands > South Holland > Noordwijk (0.24)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

Well Completion > Completion Installation and Operations > Perforating (1.00)
Well Completion > Acidizing (1.00)
Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)

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Produced-Water-Reinjection Design and Uncertainties Assessment

Carpenter, Chris (JPT Technology Editor)

OnePetroDecember, 2013

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165138, ’Produced-Water-Reinjection Design and Uncertainty Assessment,’ by Jalel Ochi, Dominique Dexheimer, and Vincent Corpel, Total EP France, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, the Netherlands, 5-7 June. The paper has not been peer reviewed. Produced-water reinjection (PWR) is an important strategy for deriving value from waste water, but its implementation can face challenges related to injectivity and safety issues. The first objective of a PWRI-design study is to supply water-quality specifications, and the second is to supply injection-pressure specifications. The objective of this paper is to detail how water quality and injection pressure are deduced when uncertainties of input data are considered. Introduction Before any PWRI design commences, a feasibility study is performed to assess any compatibility issues and evaluate the risk of scaling and souring and the viability of the project. Bacteria growth and corrosion of the installations have to be tackled and mitigated upstream in the early phase of the project. The first objective of a PWRI-design study is to determine the water quality in terms of optimum total-suspended-solid (TSS) and oil-in-water (OIW) contents, which could remain in the water after treatment and which would enable maintaining the injectivity under PWRI during the field life. These two parameters allow design of the water-treatment installations. The second objective is to determine the pressure needed to achieve PWRI sustainability; the pump power and the injection-network size will be designed on the basis of this pressure. PWRI-Design Approaches There are three main approaches to PWRI design. The first approach is based on analogs and correlation laws, the second is based on laboratory experiments, and the third uses simulations with predictive models. Of these, the most effective is that of running simulations with predictive models, because this allows simultaneous determination of the water quality and the injection pressure needed to sustain injectivity. Field evidence indicates that, whatever the quality of produced waters, PWRI in matrix (or radial injection) regimes inexorably leads to a continuous decline of injectivity. PWRI is viable only in a fractured regime, and pressure and water quality have to be designed for long-term efficiency of this regime. Fractured injection, though a complex process to model, is now considered to be a part of the PWRI strategy for field developments. New PWRI simulators are based on modules describing the flow in both matrix and fractured regimes coupled with a module describing the plugging inside and around the well, as well as plugging within and around the fracture, if any. Compared with conventional fracture software used for stimulation jobs, the fracture module takes into account the thermal and poroelastic effects generated by the high leakoff of cool water.

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doi: 10.2118/1213-0129-JPT

SPE

SPE-1213-0129-JPT

Journal of Petroleum Technology

Country: Europe > Netherlands > South Holland > Noordwijk (0.25)

Genre: Research Report (0.68)

Industry:

Energy > Oil & Gas > Upstream (1.00)
Water & Waste Management > Water Management > Lifecycle > Treatment (0.53)

SPE Disciplines:

Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.97)

Technology: Information Technology > Modeling & Simulation (0.54)

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Novel, Thermally Stable Fluid-Loss Pill Performs Better Than Guar-Based Gels

Wilson, Adam (JPT Special Publications Editor)

OnePetroNovember, 2013

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165096, ’Performance and Formation-Damage Assessment of a Novel, Thermally Stable Solids-Free Fluid-Loss Gel,’ by Pubudu Gamage, Jay P. Deville, SPE, and Bill Shumway, SPE, Halliburton, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, The Netherlands, 5-7 June. The paper has not been peer reviewed. A novel solids-free fluid-loss pill for higher-temperature reservoirs has been formulated. This pill can be used effectively in reservoirs with temperatures up to 350°F. Static thermal aging at 320°F demonstrated no noticeable loss of gel strength for at least 20 days. With regard to thermal stability and fluid loss, the synthetic-polymer-based gel outperforms guar-/borate-based gels tested under similar conditions. Introduction High downhole temperatures put a strain not only on equipment but also on the complex chemistry of drilling muds, drill-in fluids, and viscous pills. Some conventional materials, such as polysaccharide gums and sodium tetraborate crosslinking agents, are demonstrably unstable or simply rendered useless under high thermal loads for extended periods. This paper describes the development of a material for one such challenge—replacement of biopolymer-based gels for high-temperature applications. Research produced a novel, workable aqueous monovalent brine-based gel derived from a synthetic water-soluble polymer. The gel, which can be used for a variety of downhole applications including well kills, perforations, and other fluid-loss applications, is thermally stable and can be applied at temperatures up to 350°F, conditions where both polysaccharides and borate crosslinking begin to fail. The gel was specifically developed to be used in a 320°F gas reservoir. Gas regained permeability was used to assess any formation-damage issues of the gel in downhole applications. However, leakage of brine into the core during the hold-off period alters the water saturation of the core, adding complication in the regained permeability experiments because of water blockage. Experimental Section Gel Formulation. Gel was formulated with a high-density brine solution of a synthetic water-soluble polymer and a metal-based crosslinker. Further additives include pH buffers to lower the pH to an appropriate range for crosslinking to occur (pH of 4 to 5) and thermal stabilizers to mitigate gel decomposition by radical reactions and other processes. Concentration of polymer, the polymer/crosslinker ratio, and the pH of the formulation were tuned carefully to provide optimized gelling and fluid-loss properties. The formulations presented in this paper were based on 10.0-lbm/gal brine prepared by diluting stock 12.5-lbm/gal NaBr brine with water.

OnePetro

doi: 10.2118/1113-0134-JPT

SPE

SPE-1113-0134-JPT

Journal of Petroleum Technology

Country: Europe > Netherlands > South Holland > Noordwijk (0.24)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

Well Drilling > Pressure Management > Well control (1.00)
Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)

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Development of a Volumetric Horizontal-Well-Stimulation Model

Carpenter, Chris (JPT Technology Editor)

OnePetroNovember, 2013

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165143, ’Development of a Volumetric Horizontal-Well-Stimulation Model,’ by Linus A. Nwoke, SPE, Shell Petroleum Development Company of Nigeria, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, the Netherlands, 5-7 June. The paper has not been peer reviewed. The elliptical (conical) damage profile associated with horizontal wells is well-known, but review of industry-wide applications by different operators shows no corresponding uniform correlation between the damage profile and actual treatment volumes that have been applied. This inadequacy has often led to suboptimal post-stimulation performances. Furthermore, funds spent on stimulating horizontal wells did not yield the expected rewards; the stimulation gains are mostly short-lived because of flawed volume design and application. Introduction Unlike the vertical-well-damage profile, the damage profile around a horizontal wellbore is neither radial nor distributed evenly along its entire length because of formation anisotropy that creates an elliptical damage profile normal to the wellbore. The exposure time to fluids during drilling and completion operations, or the varying magnitude of fluid flow quantities across the various segments of the drainhole length during the production and injection process, will result in a truncated elliptical cone of damage along the length of the well, representing a frustum (Fig. 1) with the base of the cone nearest to the heel (near the vertical section of the wellbore). Fluid diversion is often difficult to achieve in horizontal wells because fluids tend to take the path of least resistance, even when using mechanical diverting aids or coiled tubing. Considering the fact that large quantities of acid are required for matrix stimulation of horizontal sections, it is often desirable to assume partial damage removal, but this often results in the creation of a stimulated zone with improved permeability surrounded by a collar of damage. Notwithstanding these challenges, effective distribution of the stimulation fluid along the entire length of the well is desirable, and this is why a consideration of the nature of the damage distribution in horizontal wells is very important and key to achieving a true stimulation. In order to address this first step in horizontal-well-stimulation fluid design, a model development was carried out to simultaneously determine the acid volume required to cover the damage area of the horizontal near-wellbore region and each of the segments as desired on the basis of operational feasibilities. The required input parameters for the new model are the drainhole length, the number of desired treatment segments, average porosity, wellbore radius, and estimated damage radius at the heel. The output parameters from the model include the acid volume required to treat each segment of the drainhole, which decreases from the heel toward the toe in conformance with the established elliptical damage profile.

OnePetro

doi: 10.2118/1113-0144-JPT

SPE

SPE-1113-0144-JPT

Journal of Petroleum Technology

Country: Europe > Netherlands > South Holland > Noordwijk (0.25)

Genre: Overview > Innovation (0.35)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines: Well Drilling > Drilling Operations > Directional drilling (1.00)

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Particle Size Analysis For Sand Control Applications

Ballard, Tracey (Weatherford) | Beare, Steve (Weatherford)

OnePetroJune, 2013

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE European Formation Damage Conference and Exhibition held in Noordwijk, The Netherlands, 5-7 June 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Sand screen selection relies on accurate particle size information for the sands that need to be controlled. Within the oil industry there is awareness of the differences between dry sieve analysis and laser particle size analysis (LPSA), but there can also be wide variations between LPSA performed in different laboratories even when such variables as sample preparation are taken into consideration. Recent work by the authors has shown that such variables as sonication time and amplitude can have a significant effect on certain sands, and there is evidence to indicate that the sensitivity to sonication is dependent on the mineralogy of the sand. Other factors have also been examined to address the widespread view within the oil industry that LPSA exaggerates the fines content, whereas the opposite view is held in sedimentology and soil science in that the coarse fraction is believed to dominate.

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doi: 10.2118/165119-MS

SPE

SPE-165119-MS

SPE European Formation Damage Conference & Exhibition

Country: Europe > Netherlands > South Holland > Noordwijk (0.24)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

Reservoir Description and Dynamics (1.00)
Well Completion > Sand Control > Screen selection (0.87)
Well Completion > Sand Control > Sand/solids control (0.82)

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Controlled-Electrolytic-Metallics Completion Devices Combine Strength With Dissolution

Wilson, Adam (JPT Editorial Manager)

OnePetroFebruary, 2013

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153428, ’Controlled Electrolytic Metallics—An Interventionless Nanostructured Platform,’ by Bobby J. Salinas, SPE, Zhiyue Xu, SPE, Gaurav Agrawal, SPE, and Bennett Richard, SPE, Baker Hughes, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed. Experiments on oil/water nanoparticle flow behavior in confined clay nanochannels were conducted with molecular-dynamics simulations. Three sizes of nanochannels and different numbers of nanoparticles were considered. The results show that the pressure to drive the oil/water binary mixture through a periodic confined channel increases dramatically with the reduction of the channel size. In the absence of nanoparticles, the pressure increases with the propelled displacement. An opposite behavior is observed in the oil/water system mixed with a small amount of nanoparticles: The pressure decreases with the increase of the displacement. The findings from molecular-dynamics simulations may elucidate the role of nanoparticles in the transport of oil in nanoscale porous media. Introduction One of the more promising applications of nanotechnology in the field of oil and gas, in particular for enhanced oil recovery and drilling, is the creation of a new generation of fluids. Nanofluids are a class of fluids engineered by dispersing nanoparticles (nanofibers, nanotubes, nanowires, or nanodrops) in base fluids. Nanofluids were first recognized because of their thermal properties. The most commonly studied nanoparticles for enhanced oil recovery are the spherical silica nanoparticles with a diameter in the range of several to tens of nanometers. Functionalized nanoparticles can form a highly stable emulsion to determine the oil-saturation situation, improve the oil-flow mechanism, and identify the location of bypassed oil. Al-though the exact interface mechanisms are still unclear, it is generally expected that silica nanoparticles will also reduce the surface tension between oil and rock and enhance the depletion of oil from porous media. Before full-scale deployment of silica nanoparticles occurs, many issues remain to be resolved, such as how the particles behave in a reservoir and how to design the appropriate silica nanoparticles. This study focused on the fundamental understanding of the role of silica nanoparticles in the oil/water binary mixture in a confined nanochannel. Structure and Simulation Details Rocks that are rich in kaolinite are known as kaolin clay. Kaolinite has the chemical composition Al4Si4O10(OH)8 (Fig. 1). Kaolinite is a layer clay with neutral charge, and the asymmetric structure allows the formation of hydrogen bonds between consecutive layers.

OnePetro

doi: 10.2118/0213-0145-JPT

SPE

SPE-0213-0145-JPT

Journal of Petroleum Technology

Country: Europe > Netherlands > South Holland > Noordwijk (0.25)

Genre: Research Report (0.75)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

Well Completion > Hydraulic Fracturing (1.00)
Reservoir Description and Dynamics > Reservoir Simulation (1.00)
Reservoir Description and Dynamics > Improved and Enhanced Recovery (0.93)
(3 more...)

Technology: Information Technology (0.54)

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Molecular-Dynamics Study Examines Effect of Nanoparticles on Oil/Water Flow

Wilson, Adam (JPT Editorial Manager)

OnePetroFebruary, 2013

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156995, ’Effect of Nanoparticles on Oil/Water Flow in a Confined Nanochannel: A Molecular-Dynamics Study,’ by Jianyang Wu, Jianying He, Ole Torsæter, SPE, and Zhiliang Zhang, Norwegian University of Science and Technology, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed. Experiments on oil/water nanoparticle flow behavior in confined clay nanochannels were conducted with molecular-dynamics simulations. Three sizes of nanochannels and different numbers of nanoparticles were considered. The results show that the pressure to drive the oil/water binary mixture through a periodic confined channel increases dramatically with the reduction of the channel size. In the absence of nanoparticles, the pressure increases with the propelled displacement. An opposite behavior is observed in the oil/water system mixed with a small amount of nanoparticles: The pressure decreases with the increase of the displacement. The findings from molecular-dynamics simulations may elucidate the role of nanoparticles in the transport of oil in nanoscale porous media. Introduction One of the more promising applications of nanotechnology in the field of oil and gas, in particular for enhanced oil recovery and drilling, is the creation of a new generation of fluids. Nanofluids are a class of fluids engineered by dispersing nanoparticles (nanofibers, nanotubes, nanowires, or nanodrops) in base fluids. Nanofluids were first recognized because of their thermal properties. The most commonly studied nanoparticles for enhanced oil recovery are the spherical silica nanoparticles with a diameter in the range of several to tens of nanometers. Functionalized nanoparticles can form a highly stable emulsion to determine the oil-saturation situation, improve the oil-flow mechanism, and identify the location of bypassed oil. Although the exact interface mechanisms are still unclear, it is generally expected that silica nanoparticles will also reduce the surface tension between oil and rock and enhance the depletion of oil from porous media. Before full-scale deployment of silica nanoparticles occurs, many issues remain to be resolved, such as how the particles behave in a reservoir and how to design the appropriate silica nanoparticles. This study focused on the fundamental understanding of the role of silica nanoparticles in the oil/water binary mixture in a confined nanochannel. Structure and Simulation Details Rocks that are rich in kaolinite are known as kaolin clay. Kaolinite has the chemical composition Al4Si4O10(OH)8(Fig. 1). Kaolinite is a layer clay with neutral charge, and the asymmetric structure allows the formation of hydrogen bonds between consecutive layers.

OnePetro

doi: 10.2118/0213-0148-JPT

SPE

SPE-0213-0148-JPT

Journal of Petroleum Technology