bluuebunny/crossref_metadata_2025_split huggingface dataset:
Molecular-Dynamics Study Examines Effect of Nanoparticles on Oil/Water Flow
Authors: Wilson Adam 
Published: February 2015

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 The paper has not been peer reviewed.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.
Techbits: First SPE Workshop-Webinar Held on Waterflooding
Authors: JPT staff _ 
Published: February 2015

Techbits
The Technical Aspects of Waterflooding workshop held 23 October in Long Beach, California, was the first SPE event to involve both live participants and members participating around the world through a real-time video feed. The workshop drew more than 70 participants from various companies and organizations, including Occidental, Signal Hill Petroleum, Berry Petroleum, Santa Maria Energy, Termo, Spec Services, the California State Lands Commission, SPE board members, and students from the University of Southern California and California State University of Long Beach. The workshop was held by the SPE Los Angeles Section and the one-day live webinar by SPE. Following are highlights from the workshop.
When Water and Oil Mix byAbbas Firoozabadi
Water and oil sometimes mix due to formation of certain structures known as emulsions, small droplets of water in oil or small droplets of oil in water that add surfactants.
Waterflood Management and Surveillance byGanesh Thakur
This presentation illustrated how practical application of surveillance and monitoring principles are key to understanding reservoir performance and identifying opportunities that can improve oil production and ultimate oil recovery.
Waterflooding Process and Design by Abdus Satter
Waterflooding as a process is the most widely used post-primary recovery method in the United States and contributes substantially to current production and reserves.
Waterflood on a Chip byBaldev S. Gill
Microfluidics are used to displace one phase with another in a water-wet prefabricated microchip and the displacement can be seen under a microscope.
Application of a Nanofluid for Asphaltene Inhibition in Colombia
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24310, ’Application and Evaluation of a Nanofluid Containing Nanoparticles for Asphaltene Inhibition in Well CPSXL4,’ by R. Zabala, E. Mora, C. Cespedes, L. Guarin, H. Acuna, and O. Botero, Ecopetrol; J.E. Patino, Petroraza; and F.B. Cortes, Universidad Nacional de Colombia, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
This paper describes the evaluation of a nanofluid containing nanomaterials with high adsorption capacity used for asphaltene inhibition in the volatile Cupiagua Sur oil field in Colombia. Asphaltene precipitation has been identified as one of the most potentially damaging mechanisms affecting this field’s productivity. The goal of the injection of nanofluids containing nanoparticles of alumina with high surface area is to absorb the asphaltenes and carry them with the condensate, avoiding precipitation near the wellbore.
Introduction
The Cupiagua Sur field is located 110 km northeast of Bogota in the foothills of the Colombian Andes, close to other fields such as Floreña, Pauto, Volcanera, Recetor, Cupiagua, and Cusiana (Fig. 1). Despite the fact that Cupiagua Sur is very close to Cupiagua, this reservoir is totally independent and separate. It is a compositional volatile-oil reservoir with an average gravity of 38°API; there is no free-gas cap at initial conditions (for a discussion of asphaltene precipitation in volatile oil, please see the complete paper). The main formations are Mirador and Barco, which are quite similar in terms of petrophysical and fluid properties (average permeability is 21 md, and average porosity is 6.5%).
Cupiagua Sur is a prolific oil field that in 15 years of production has recovered 88 million STB/D gross out of 189 million STB/D originally in place from Mirador and Barco reservoirs in a developed area with four producer and two injector wells.
The current reservoir conditions in this field are highly dependent on the way the reservoir has been produced. The first production well, CPXP1, started producing in March 1998, while the first gas-injector well went into action in January 2000; at that time one volatile well was on production. There are currently six active wells in the field. There are four producers and two gas injectors.
Oil production reached its peak in March 2001 at 41,722 STB/D. The average gas production at that date was 175 MMscf/D. Today, the recovery factors are 48.2% and 29.5% in the Mirador and Barco formations, respectively. There was no production plateau in Cupiagua Sur; instead, a constant decline rate is observed. This indicates the extreme conditions under which the reservoir was depleted, as well as the sources of damage.
Conversations: Achieving Immortality
Authors: Fattahi Behrooz 
Published: February 2015

President's column
I am writing this column on the other side of the globe from my home in California, after flying for almost 20 hours to get here. The details of my trip, as in the case of many others, were arranged by SPE staff in Dallas working in concert with the SPE staff in our six other offices around the world. This first tour of 2010, 2½ weeks long, started in Jackson, Mississippi, where I spoke at a gathering of SPE members; on to Dallas for the SPE Board of Directors meeting; to Houston, where I spoke at an annual industry executives breakfast; on to Mumbai, India, to speak at the SPE Oil and Gas India Conference, and a 6-hour drive to visit a student chapter in Pune, India; and finally to Manama, Bahrain, to speak at the SPE Deep Gas Conference and Exhibition, before I go back home for a week to prepare for the next trip. This is a typical travel schedule for the SPE president nowadays. Traveling to some 30 countries, roughly 60 locations, traversing the globe for approximately 300,000 km, and for as many as 75 weeks on the road is not unusual for a president’s 3-year term as president-elect, president, and past president. Our professional society is truly an international organization.
Presiding over a complex and international operation requires reaching out to all of our members wherever they may reside. Today, we have more than 92,000 members scattered in 117 countries, with 173 sections and 207 student chapters. More than 55% of SPE’s total members, including more than 80% of student members, reside outside the U.S. (Figs. 1 and 2). But although this is a dramatic demographic shift since its beginnings, SPE’s globalization is not merely measured by the shift in its membership statistics.
SPE’s journey toward globalization started more than 50 years ago, with the establishment of the Venezuela Section in 1956. Almost 40 years ago, the first Offshore Europe conference was held in Great Yarmouth, Scotland, under the name Oiltech. In 1979, SPE held the first Middle East Oil and Gas Show and Conference. Although during the 1980s the industry suffered a downturn and roughly half of all jobs were lost, SPE membership experienced a growth throughout the decade. And it was in 1989 when the first Asia Pacific Oil and Gas Conference and Exhibition was held.
Technology Partnerships for Challenging Environments
Authors: Mahoney Garry P. 
Published: February 2015

Guest editorial
It is widely accepted today that for the remainder of Hydrocarbon Era, global energy stability will rely increasingly upon crude oil and natural gas recovered from giant offshore fields, many of which will be located far from major markets, in hostile environments such as ultradeepwater and the Arctic. Less understood is the fact that large-scale, multibillion-dollar developments are precisely where the principal technological and economic drivers to push beyond technological boundaries are the strongest and where stakeholder participation and partnering is most complex.
The different agendas of the various partners and stakeholders in such developments often compound the challenges of technological complexity. For example, a national oil company typically is seeking to ensure long-term domestic political stability and to invigorate the national economy with development of natural resources. A top-tier international oil company is generally aiming to maintain global production, improve unit production costs, and maintain reserves, while, for most smaller operators, the drivers tend to be rapid and reliable realization of assets that feed dynamic balance sheets. In the case of technology providers—namely vendors, constructors, and fabricators—the drivers tend to be stretching applications of established technology, early capitalization of investment in new equipment/assets, maintaining competitiveness, and vying for market share.
Against a backdrop of daunting technological challenges, operators, equity owners, and other stakeholders in demanding frontier developments frequently differ on such fundamental issues as contracting strategies; the timing of project milestones; or the program for technology selection, maturation, and implementation. Opinions are often divided, also, over how to balance the costs and risks of technology selection, or the extent of a given technological stepout. Such disagreements are compounded by the very different business drivers and risk appetites of project partners, stakeholders, and technology providers.
Talent Council Workshop Focuses on Diversity Solutions
Authors: Howes Susan 
Published: February 2015

Talent & Technology
To meet the need for people to replace those due to retire during the “big crew change,” the oil and gas industry must attract, retain, and promote a more diverse workforce than it has in the past. In October 2009, the SPE Talent Council held a Diversity Workshop in Paris to explore ways the industry can be more attractive to today’s diverse work-force. Human resources professionals from 11 employers participated, sharing best practices in encouraging diversity in the workplace.
The SPE Talent Council, chaired by Fabrice Bouchard of Schlumberger, provides a forum in which industry and academia collaborate on initiatives to increase the quantity and quality of industry talent, including initiatives to increase industry attractiveness to a diverse workforce. Numerous opportunities exist for employers to collaborate in encouraging diversity/inclusion in the industry, including
Benchmarking maternity policies, especially for expatriates on international assignments
Encouraging more women and ethnic minorities to study engineering, math, and science
Sharing best practices in staffing difficult locations with women and ethnic minorities
Supporting dual-career couples
Providing industry role models from diverse backgrounds
Preparing for the crew change by accelerating competency development
Transferring the knowledge from the generation retiring to new recruits
Encouraging women and minorities to take assignments in global projects and in operations
Implementing nationalization strategies including the development of national work forces
Initiatives to Encourage Diversity Discussed
A number of examples of initiatives to encourage diversity were shared during the workshop. From employee networks and diversity training sessions to adapting the field work environment to women employees, participants elaborated on the many initiatives taken by their companies to encourage diversity in the workplace.
Nicky Jenkins, Baker Hughes Diversity manager, described a women’s resource group that was enthusiastically received among employees. Baker Hughes also launched an internal photographic competition to ensure inclusion of photos representative of its diverse workforce in its media bank.
Chiswick Field: Long Horizontal Wells and Innovative Fracturing Solutions in a Low-Permeability-Sandstone Gas Reservoir in the North Sea
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124067, “The Chiswick Field: Long Horizontal Wells and Innovative Fracturing Solutions in a Low-Permeability-Sandstone Gas Reservoir in the North Sea,” by G. Coghlan, SPE, and B. Holland, SPE, Venture Production, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4–7 October. The paper has not been peer reviewed.
To obtain commercial flow rates from the Chiswick field, a low-permeability gas reservoir in the UK Southern Gas basin, field development would require horizontal wells with multiple propped hydraulic fractures. Only a few such completions have been attempted in sandstone reservoirs of the North Sea. The initial field-development plan entailed two horizontal wells with 2-km-long reservoir sections, stimulated with several massive propped fractures.
Introduction
Chiswick is in a water depth of 42 m, approximately 160 km northeast of Great Yarmouth. A field-development plan was approved in 2006. The first-phase wells were completed on a minimum-facilities platform, and first gas was produced in September 2007. The field underwent a prolonged appraisal period following its discovery in 1984, directly reflecting the challenges posed by the low-quality Carboniferous sandstones that contain the majority of the gas.
Geology
The structure shown in Fig. 1 is a broad, northwest/southeast-trending, faulted anticline that is dip and fault closed with an almost square periphery. While a gas/water contact has never been drilled, a fieldwide contact at 3450 m true vertical depth subsea (TVDSS) can be inferred with fair accuracy. The area of closure is approximately 0.37 km2. The crestal part is at a depth of approximately 3250-m TVDSS. Crossfaults subdivide the field into five compartments: Alpha, Beta, Gamma, Delta, and Epsilon. Initial reservoir conditions were 3.92 MPa and 115°C at 3450 m TVDSS.
Porosity ranges from 3 to 14% and water saturation from 25 to 70%. Total gas initially in place for the Carboniferous reservoirs was estimated at 11.3×106 m2.
Chiswick Development Wells Initial development was two wells with 2- to 2.5-km-long horizontal sections, completed with five or six massive propped hydraulic fractures of 400,000 to 500,000 lbm each, spaced approximately 500 m apart. The formation dip allows a horizontal well to penetrate a succession of channels and connect several layered reservoirs. Within each channel, a propped fracture stimulates deliverability by exposing a large volume of rock to the wellbore.
Inflow-Control Devices for Reducing Water Production
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124154, ’Practical Consideration of an Inflow Control Device Application for Reducing Water Production,’ by Liang-Biao Ouyang, SPE, Chevron Energy Technology Company, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.
Inflow-control devices (ICDs) have been developed to improve well performance and enhance reservoir management by mitigating undesired water and/or gas breakthroughs that often occur as a result of a variety of factors, including reservoir-permeability heterogeneity, heel/toe effects, and different reservoir pressures in different regions penetrated by a well. Success of an ICD completion relies heavily on appropriate completion design. The full-length paper identifies several key issues that should be addressed in designing an ICD completion and discusses their effects on performance of a well equipped with ICDs.
Introduction
Despite their superiority in production and recovery to conventional wells by maximizing reservoir contact, horizontal and multilateral completions are more prone to water and/or gas coning toward the heel of the well as a result of frictional pressure drop from toe to heel and/or breakthrough anywhere in the well because of permeability variation along the well and proximity of water traps. ICDs, a choking device installed as part of sandface completion hardware, were proposed in the early 1990s as a solution to the difficulties particularly associated with horizontal and multilateral wells. An ICD completion offers a number of potential unique benefits:
Optimize production
Delay water progress
Minimize /eliminate annular flow and thus reduce the risk of sand production behind screen and subsequent plugging or erosion “hot spots”
Mitigate the nonuniform production profile across the horizontal hole, especially in highly heterogeneous and fractured reservoirs that may result in premature water production, bypassed oil, and lower ultimate recovery
Improve well cleanup and reduce the effect of formation damage caused by drilling of the well
For sandstone, the application of ICDs should reduce the effect of heel/toe effects and high-permeability intervals, defer water/gas breakthrough, and improve well cleanup and sweep efficiency. For carbonate, the application of ICDs should help to control inflow from high-permeability intervals and limit production from each compartment based on lateral offset from gas/oil and oil/water contact to prevent premature gas and/or water breakthrough. ICDs have gained increasing popularity and increasingly are being applied to a wide range of reservoir types.
Identifying Point of Failure and Repairing Damaged Sand Screens
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 122153, ’Identifying Point of Failure and Repairing Damaged Sand Screens in Gravel Packed Wells. A Case History From the Heidrun Field,’ by Per Einar Svela, SPE, Oyvind Gustavsen, Hilde Songstad Solli, SPE, and Oystein Brandal, StatoilHydro, originally prepared for the 2009 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 27-29 May.
The full-length paper describes a method used on several wells in the Heidrun field to mitigate failures in gravel-packed screens. The method described includes how to identify sand production, the preferred way to run the well after sand production has been identified, and how to perform data acquisition to determine the point of failure. The data acquisition described includes gravel-pack logging, injection logging, and saturation logging.
Heidrun Field
The Heidrun field is located on Haltenbanken in the Norwegian Sea. The sea depth in the area is 350 m. The field has been developed with a floating concrete tension-leg platform installed over a subsea template with 56 well slots. The northern part of the field is developed with five subsea templates. Oil and gas production started in October 1995.
The reservoir consists of sandstones in the Garn, Ile, Tilje, and Aare formations of the Early and Middle Jurassic. The reservoir is heavily faulted. The Garn and Ile formations have good reservoir quality, while the Tilje and Aare formations are more complex. Most of the formations produced in the Heidrun field have a moderate-to-low sand strength and are prone to sand production. Several approaches to sand control have been tried, and the current base-case solution is openhole gravel-packed screens. The recovery strategy for the field is pressure maintenance using water and gas injection.
Sand Management
Sand production has both a production and a health, safety, and environmental (HSE) impact. Massive sand production can result in unwanted discharge into the environment during jetting of separators because oil coats the sand being jetted out. With regard to the safety aspects, gas velocity has to be considered. A high gas velocity means high erosion risk during sand production. Wells are divided into three categories, high-, medium-, and low-erosion risk, depending on the gas rate of the well.