bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: EOR Performance and Modeling (January 2013)
Authors: Bai Baojun 
Published: February 2015

Technology Focus
Enhanced oil recovery (EOR) targets the approximately two-thirds of oil remaining in reservoirs after conventional recovery methods have been exhausted. More than 350 EOR papers were published from October 2011 to September 2012 because two major EOR meetings were held in Tulsa and Oman and a few international meetings had EOR sections as a primary topic, such as the International Petroleum Technology Conference in Thailand and the SPE Heavy Oil Conference Canada in Calgary. I categorized these EOR papers into the topics of EOR screening methodologies, reservoir problem identification and evaluation technologies, chemical EOR methods for conventional oil, chemical methods for heavy oil, gasflooding, conformance control using in-situ and preformed particle gels and foams, thermal EOR methods, smart-water flooding, nanofluid for EOR, EOR for shale oil, and new EOR technologies.
Five papers were published to provide methods to screen EOR technologies. More than 20 papers published were related to EOR by altering water salinity and compositions, such as low-salinity waterflooding, seawater flooding, and tuning water salinity and ionic content. More than 10 papers were published to address one recent interest: using chemical methods to enhance heavy-oil recovery. The development of high-molecular-weight polymer and new types of polymer such as associated polymer has made some chemical methods such as polymer flooding feasible for some heavy oils. However, these three types of papers were not featured this time, either because the category was featured in the last couple of years or because the papers are too long or too complex to be synopsized. But these topics, along with some others, such as gas-flooding for shale oil and nanoparticle EOR, are selected to form the list of papers suggested to be read.
I have selected the following four topics for the EOR feature this time: experience of alkaline/surfactant/polymer flooding in China, polymer flooding pilot in the Middle East, a review of mobility and conformance control for CO2 EOR, and a new correlation to predict optimum surfactant structure.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 141283 Full Barrel Analysis: A Simulation Model Interrogation Tool To Assess Sweep Efficiencies and Identify Targets for Improved Oil Recovery by M.S. Beckman, ExxonMobil, et al.
SPE 155546 PDO’s EOR Screening Methodology for Heavy-Oil Fractured Carbonate Fields—A Case Study by Georg Warrlich, Shell, et al.
SPE 154218 Four-Phase Equilibrium Calculations of CO2/Hydrocarbon/Water Systems Using a Reduced Method by Saeedeh Mohebbinia, The University of Texas at Austin, et al.
SPE 154675 Viscosifying Surfactant Technology for Chemical EOR: A Reservoir Case by G. Degré, Rhodia, et al.
SPE/CSUG 148971 Sweep Efficiency Improvement by Alkaline Flooding for Pelican Lake Heavy Oil by Mingzhe Dong, University of Calgary, et al.
Polymer Flooding in a Large Field in South Oman - Results and Plans
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 154665, ’Polymer Flooding in a Large Field in South Oman - Initial Results and Future Plans,’ by Faisal Salim Al-Saadi, SPE, Badr Ali Amri, Sami Nofli, John Van Wunnik, Henri F. Jaspers, SPE, Said Harthi, Khalfan Shuaili, Pradeep Kumar Cherukupalli, SPE, and Ravula Chakravarthi, Petroleum Development Oman, prepared for the 2012 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 16-18 April. The paper has not been peer reviewed.
In heavy-oil reservoirs, waterflooding leaves unswept-hydrocarbon volumes behind because of unfavorable mobility ratios, resulting in low ultimate recoveries. Increasing the viscosity of the injected water with polymer improves the water/oil mobility ratio, resulting in improved recovery factors. Following field trials and laboratory studies, a full-field polymer project was implemented in 2010. A key risk was poor polymer injectivity. However, initial field results showed injectivity to be better than expected. Study data indicate that wellbore cleanup from polymer injection improved as a result of the improved mobility ratio and that small-scale induced fractures in some injectors contribute to the improved injectivity. These factors enabled injection of more volumes of polymer than planned, resulting in improved volumetric sweep efficiency and producer response.
Introduction
This large sandstone field was discovered in 1956 and is on the eastern side of the South Oman basin. Five wells were drilled from 1956 through 1964, with the conclusion that field development would not be economically feasible. Another drilling campaign commenced in 1976, and the field was brought on stream in 1980. The oil is heavy (22°API) and viscous (90 cp). The field is highly heterogeneous, with sand, diamictite, and shale bodies. However, in the main reservoir units the net-sand/gross-reservoir ratio approaches 1.0 and the permeability can be many darcies.
Because of the relatively viscous nature of the crude oil and the resulting poor mobility ratio with the displacing water, the conditions for waterflooding were not ideal. The Buckley-Leverett analytical model indicated that no distinct flood front exists early in the field life and that water was mobile throughout the reservoir. Once water reached a producing well, the water cut would rise rapidly and many pore volumes (&gt;2 pore volumes) must be flushed through the rock to produce the recoverable oil. The achievable recovery by waterflooding was estimated at 20 to 30%. Different enhanced-oil-recovery (EOR) field-scale pilots (polymer and steam) were completed. The two polymer pilots showed that the polymer would be stable in the reservoir for many years and that the incremental-oil response from the use of polymer would be substantial. Pilot testing polymer-EOR technologies in this field provided early insight that the use of polymer is the optimal EOR concept.
Dynamic Well-Control Response to Gas Influx in Managed-Pressure Drilling
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 151392, ’An Improved Dynamic-Well-Control Response to a Gas Influx in Managed-Pressure-Drilling Operations,’ by William Bacon, SPE, Blade Energy Partners; Albert Tong, University of Texas at Arlington; and Oscar Gabaldon, SPE, Catherine Sugden, SPE, and P.V. Suryanarayana, SPE, Blade Energy Partners, prepared for the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed.
Managed-pressure drilling (MPD) offers the capability to control an influx dynamically, without shutting the well in conventionally. Some current methods use applied backpressure (ABP) to restrict the flow exiting the annulus to equal the flow entering the drillpipe, which is interpreted as influx cessation. However, ensuring only flow continuity does not imply influx cessation, unless the annular fluids are incompressible. This work investigated the effect of compressibility on dynamic well control. The transient response of compressible multiphase flow in the annulus was examined by use of mass conservation over a control volume. Introduction
MPD is a class of techniques that enables management of the annular-pressure profile through a combination of controlling the wellhead pressure (WHP), or backpressure, and the drilling-fluid density and flow rate. With the ability to manipulate backpressure, MPD can be used to control an influx without shutting in the well. Performing well control without conventionally shutting the well in is referred to here as dynamic well control. Well control in MPD operations, dynamic or otherwise, must be performed with several objectives in mind. The most important objectives include minimizing peak WHP and surface flow rates, managing wellbore pressures tightly within the pore-/fracture-pressure window, maximizing the chance of successful well control, and reducing nonproductive time.
Influx
When an influx is detected during MPD, one of the most important decisions is whether dynamic well control should be used to control the well rather than conventional well control. Dynamic well control is applicable up to only a certain size and rate of influx, such that the influx can be controlled and circulated out of the system safely and effectively while achieving all of the objectives stated previously. Particularly important is quantifying peak surface flow rates and the point at which it would no longer be safe to shut in conventionally. However, when used appropriately, dynamic well control allows more-rapid control of an influx.
Emerging Frontiers: Big Data!
Authors: Spath Jeff 
Published: February 2015

President's column
“Big data,” once only the concern of database geeks or a marketing technique among retailers, is now part of our mainstream consciousness and vocabulary. Big data is having a profound impact on the upstream E&P industry as well.
What is “big data”? According to a McKinsey Global Institute report, “big data refers to datasets whose size is beyond the ability of typical database software tools to capture, store, manage, and analyze.” I like this definition because it does not require a dataset of any specific size. It allows datasets to increase as technology advances. This definition also varies to the extent that different industries have different standards of database and analytic software tools.
To get a feel for just how big data has become, consider recent rates of data growth. In 2012, disk drives worldwide added 7 exabytes (1018) of new data. Global data volumes are projected to increase 40% per year, while global information technology (IT) spend will grow only 5%. Thirty billion pieces of content are shared on Facebook each month. Or consider that Asia now leads the world in the generation and storage of personal location data due simply to the number of mobile phones—an estimated 800 million in China alone.
How mainstream has big data become? Consider these examples of wide-spread usage:
High-speed supercomputers statistically analyze massive amounts of data, enabling scientific breakthroughs such as the gene sequencing of individual organisms and entire ecosystems.
Coaxing the Higgs boson into a nanosecond of existence required the global distribution and analysis of roughly 200 petabytes of data.
Or, more familiar to most of us, retail organizations cleverly obtain our behaviors, preferences, and product perceptions by monitoring our Facebook and Twitter information.
The combination of massive amounts of data and sophisticated analytics is profoundly affecting a spectrum of industries, and oil and gas is no exception.
Big Data in the Oil Field
The amount of data that our industry acquires, communicates, stores, and analyzes is exploding exponentially. For example, the growth of land seismic acquisition is one of the most data-intensive phases of our industry. Channel count has roughly doubled every 3.5 years since 1970. Together with advances in the acquisition technology— which now measures vector information rather than scalar—the data acquired and stored in a typical survey has grown from gigabytes to petabytes. Furthermore, the growing popularity of permanently installed geophones for monitoring fluid fronts, passive monitoring of carbon capture sequestration sites, and observing microseismic events during hydraulic fracturing has driven an extraordinary and daunting growth in seismic data of all forms.
Robotic Roustabouts for Tomorrow's Subsea Fields
Authors: Jacobs Trent 
Published: February 2015

Robotic submarines, capable of operating by themselves thousands of feet underwater for months or perhaps years at a time, are under development as the vanguard of tomorrow’s subsea oil and gas fields. This development comes as the offshore oil and gas industry moves into ever-deeper waters and remote areas of the world, where installing a floating production facility is either economically unjustifiable or infeasible.
The industry’s solution is to install production equipment on the seafloor, where someone, or something, must keep a close eye on all of it. That something is likely to be what are known as field resident autonomous underwater vehicles (AUVs). Nonresident AUVs have already paved the way by proving they can carry out detailed inspections of platforms and pipelines in some cases four times faster than a human-piloted remotely operated vehicle (ROV). Two of the leading companies in the resident AUV business, Lockheed Martin and Saab Seaeye, are blending proven military technology with new software and hardware optimized for the offshore industry. Their emerging systems represent a new breed of subsea robots that will be capable of much more than earlier generations of autonomous systems. As their capabilities are realized, resident AUVs will eventually be assigned many of the same tasks that ROVs are carrying out today.
To achieve that end, offshore operators are working with manufacturers to identify how best to fully deploy this emerging technology. Much of the groundwork is being laid through DeepStar, a research and development consortium that counts 11 operating companies as members. “We are already using AUVs for certain functions on a sporadic basis, but we’re trying to understand, as operators, what else this technology can do reliably,” said Greg Kusinski, DeepStar director and Chevron senior advisor to DeepStar.
DeepStar’s primary goal is to accelerate the development and adoption of AUV technology by drafting interface standards, similar to the standards already developed for ROVs. Among the interface issues yet to be resolved is how resident AUVs will connect to life support systems in a subsea field. Because resident AUVs will have to remain submerged for months to possibly years at a time, the docking station is a critical piece of equipment that will charge up the AUV and upload its data to the operator’s server by a subsea Internet connection.
Once the particulars of the docking station are understood, Kusinski said careful consideration must be given to other issues, such as where to place it among the subsea infrastructure. “There are a lot of questions of that nature,” he said. “As responsible operators, we are addressing these issues in a very systematic and methodical manner. I don’t think anyone is interested in putting a bunch of them down there and just seeing what happens.” DeepStar expects to conclude its AUV study on interfaces in about a year and will deliver its recommended best practices to the American Petroleum Institute for review.
Zonal Isolation Through Gas Hydrates Offshore Tanzania
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163462, ’Zonal Isolation Through Gas Hydrates Offshore Tanzania,’ by J. Volstad and T. Tveit, Statoil, and P. Aguilar, N. Hurtado, and M. Bogaerts, Schlumberger, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
Deepwater cementing becomes increasingly challenging as drilling operations move to greater water depths and more-remote locations. Before the first exploration well for an operator offshore Tanzania was spudded, an extensive cementing-operations risk analysis was performed. The risks determined were low temperatures at seabed, unconsolidated formations close to seabed, potential shallow gas, and likely presence of hydrates. To drill further sections successfully, objectives were identified as zonal isolation across the shallow-flow and hydrate zones, cementing back to seabed, and good cement around the casing shoe.
Introduction
Block 2 (Fig. 1) is located southeast of Tanzania’s capital, Dar es Salaam. The water depths in Block 2 vary from 1000 to 3000 m. The target is an excellent-quality sandstone gas reservoir with very large potential. The seabed consists of soft clays and silts with minor sandy intervals. Shallow hazards were identified for this block from seismic data.
Preparation for the exploration phase started in 2007 when the license for Block 2 was awarded. Two exploration wells have been drilled in Block 2 offshore Tanzania to date. The wells were drilled in ultradeep water, with respective water depths of 2419 and 2627 m. Both wells were drilled successfully and have found commercial gas reserves.
Well Design
The well design for both wells was jetting a 36-in. conductor casing to provide sufficient well-bearing capacity. The surface casing was set deep enough to isolate all shallow zones with potential hydrates and shallow water and gas flow. The intermediate string was set above the top of the target reservoir, and the reservoir was drilled and plugged after the reservoir was evaluated. Both exploration wells were drilled vertically to total depth. The riserless section was drilled with seawater and water-based mud, while the deeper sections were drilled with a synthetic-based mud.
Challenges
The main challenges for the two wells were related to the great water depth (low fracture gradients and low temperatures) and the risk of encountering hydrates and potential shallow flows, which would need to be isolated by the surface casing.
Comments: Academic Leaders
Authors: Donnelly John 
Published: February 2015

Editor's column
With sadness, we note the loss of two members who mentored countless students and colleagues during their distinguished careers on different sides of the globe. Kermit Brown, a longtime professor at the University of Tulsa and the University of Texas, died on 10 December at the age of 86. Ion Cretu, a professor and leader in the Romanian scientific community, died on 15 November. He was 76. Colleagues speak warmly of both men and the influence they had on them and others in the profession.
Brown was honored at last year’s SPE Annual Technical Conference and Exhibition with the JPT Legends of Production and Operations award. He was a noted authority on artificial lift and changed the way the industry viewed that technology, and contributed to the industry as an educator, researcher, and consultant in a career that spanned more than 50 years. He wrote portions of the Gas Lift Manual that transformed the way that technology was used and became the gas-lift authority in the industry. His book on nodal analysis is still widely used by those both inside and outside academia.
It was at the University of Tulsa that Brown had his biggest impact. Colleagues say he changed that school’s petroleum engineering department forever through his bold and innovative leadership. He started a doctoral program there, and he created a research model that other universities would later adopt. Brown developed a consortium in which oil companies would contribute a small amount of money each year and university faculty and students would conduct research of specific interest to the industry. The program put the department closer to the needs of oil and gas companies, benefiting students greatly in the process, and reduced the school’s reliance on government funding. Thorough his leadership, the University of Tulsa began its first research program, called the Tulsa University Drilling Research Project.
Cretu began working in 1958 with the Oil, Gas, and Geology Institute in Bucharest and then for the Petroleum-Gas University of Ploiesti as a lecturer, associate professor, and, beginning in 1978, as professor in the Department of Hydraulics, Thermotechnics, and Reservoir Engineering. He held numerous positions at the university during his academic career, including head of the department, vice dean and dean of the Well Drilling and Reservoir Exploration Faculty, and vice rector of the school. He supervised more than 45 doctoral trainees at the university.
He was well known in the Romanian scientific community, was widely published, and was active in the International Association of Hydraulic Research, the Romanian National Committee of World Oil Congresses, and the Scientific Council of the Ministry of Geology. Cretu also served as president of the SPE Romanian Section.
India's First Deepwater Offshore Field Showcases Ingenuity
Authors: Kulkarni Pramod 
Published: February 2015

India’s first deepwater oil and gas field, located in the KG-D6 block 60 km off the east coast of India in the Bay of Bengal, is a success story of government initiative, private enterprise, and global engineering ingenuity. Operated by Reliance Industries, a multinational corporation based in Mumbai, KG-D6 is a world-class discovery at 1200-m depth with proved plus probable reserves of 11.3 Tcf. The fast-track construction of the oil and gas production facilities involved the mobilization of engineering talent, manufacturing capabilities, and construction skills in the US, Europe, the Middle East, and Asia (Fig. 1). In the process, the KG-D6 field has set numerous world records and milestones for India’s emerging oil and gas industry.
First Success of Licensing Round
The KG-D6 block was awarded in 2000 to a partnership of Reliance Industries (90%) and Niko Resources of Calgary (10%) in the first licensing round initiated by the government of India through its New Economic Licensing Program (NELP). Before NELP, India carried out E&P activities through public-sector companies such as the Oil and Natural Gas Corporation (ONGC). ONGC remains the leading operator in India, but eight rounds of NELP have opened the country’s oil and gas sector to a variety of other public-sector companies (Indian Oil, Hindustan Petroleum, Gujarat State Petroleum Corporation), international oil companies (Cairn Energy, British Gas, Eni), and Indian private companies in addition to Reliance (Essar, Jubilant).
Reliance Industries is an Indian conglomerate with extensive operations in the textile, petrochemical, and retail sectors with annual revenues of USD 28 billion. The company was launched in 1962 as yarn trading company by Dhirubhai Ambani. The growth of the company is a study in vertical integration. From yarn, Reliance built textile mills, petrochemical complexes, and entered the upstream oil and gas industry in 1999.
Deepwater Discoveries
The Krishna-Godavari (KG) Basin covers an area of more than 20 000 km2 on land and extends into the bay more than 24 000 km2 down a steep slope to 2000-m depth (Fig. 2). The Krishna and western part of the Godavari troughs are filled with mainly Paleozoic and Mesozoic sediments, while the eastern part of the Godavari trough contains a predominantly Upper Mesozoic and Tertiary section. The discovery of biogenic gas has been made primarily in the Upper Pliocene plays.