bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Deepwater Projects (May 2014)
Authors: Salies Jacques Braile 
Published: February 2015

Technology Focus
In the kingdom of wet completion, Petrobras has just installed its first tension-leg wellhead platform, in the field of Papa Terra in 1190-m-deep water. It is going to be a revolution regarding how to operate such an installation and be able to produce the heavy oil of Papa Terra (14–17°API). For many years, Petrobras engineers have being analyzing the use of a tension-leg platform or a spar as a solution for their field developments, and, finally, it came through. I strongly believe that all the lessons learned from installation (completed by now) to operation will result in much better solutions for the future of dry completion in our industry. In past JPT reviews, I wrote about the effect for field developments of the first floating production, storage, and offloading vessel in the Gulf of Mexico installed by Petrobras in Cascade and Chinook. And I believe that, once again, Petrobras is creating the same impact now in its own backyard.
In February 2014, Petrobras reached a production of 400,000 B/D in the Brazilian presalt 8 years after of the discovery of the first field. In this presalt cluster, the consortium led by Petrobras, including Total, Shell, CNOOC, and CNPC, will be developing the Libra field, one of the biggest discoveries in ultradeep waters in the world. The estimated reserves of 8 billion to 12 billion bbl of recoverable oil will demand a great amount of resources to cope with the challenges of developing this gigantic field. If you are an engineer looking for an opportunity for technological growth and learning experiences, do not miss this chance.
Lately, I have been reading a lot about the shale gas/oil developments in the United States, and I am amazed to see the forecasts showing that this gas/oil production will lead the United States to be self-sufficient by 2020 and a net exporter by 2030. It is a good example of what technology can do for you when combined with entrepreneurship. I have been reading also that unconventional oil and gas has taken money out of deepwater developments and that some majors have deferred their projects because of economics compared with tight oil projects. Equilibrium will come, and I believe both will contribute to our oil/gas supply. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 166337 Water-Depth Record for Electric-Line Operations—Retrieving Asphaltenes With Riserless Light Well Intervention by Steven Ashcraft, Anadarko, et al.
OTC 24529 Roncador Module IV: A Successful Case in Heavy-Oil Projects In Ultradeep Water by E. Bordieri, Petrobras, et al.
OTC 24508 Scale Management in Deep and Ultradeepwater Fields by M.C.M. Bezerra, Petrobras, et al.
Complex-Event Processing for the Intelligent Field
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167817, ’Implementation of Complex-Event Processing for the Intelligent Field,’ by Muhammad Al-Gosayir, Moayad Al-Nammi, Waleed Awadh, Abdullah Al-Bar, and Nasser Nasser, Saudi Aramco, prepared for the 2014 SPE Intelligent Energy Conference and Exhibition, Utrecht, the Netherlands, 1-3 April. The paper has not been peer reviewed.
Every day, reservoir and production engineers are presented with massive streams of real-time data from all kinds of intelligent-field equipment. The existing systems for data cleansing and summary are based on batch processing; hence, engineers find it challenging to make the right decision on time and do not have the capacity to instantly detect interesting patterns as data arrive in streams. This paper addresses the architecture, implementation, and benefits of complex-event processing (CEP) as a solution for the intelligent field.
Introduction
CEP is an innovative, rising technology designed to handle large amounts of data with minimal latency in real time. This technology can aid in the detection of trends and anomalies in the data stream such as unusual buildup or drawdown in well pressure in real time. Furthermore, CEP is an event-driven solution, meaning that it is triggered by events such as changes in downhole pressure in order to perform computational logic to calculate average reservoir pressure. This process will in turn provide reservoir and production engineers with clean real- time data and notifications of prominent events.
Overview of Intelligent-Field Structure. For the implementation of the intelligent field, Saudi Aramco has adopted a four-layered architecture. These layers are surveillance, integration, optimization, and innovation, as shown in Fig. 1. The surveillance layer is responsible for continuous monitoring of real-time production data and makes use of data-management tools to ensure the validity of the data. The integration layer processes real-time data to detect trends and anomalies. These anomalies are referred to reservoir engineers for analysis and resolution. The optimization layer streamlines field-optimization capabilities and management recommendations. The innovation layer stores event knowledge and triggers optimization processes and actions throughout the field’s life cycle. This final layer captures “intelligence” and injects it into the system.
Real-time data traverse multiple zones of instrumentation, networks, and data servers before they reach the corporate database and the engineer’s desktop (Fig. 2). A typical piece of data captured by a sensor will be transmitted automatically from the sensor and will pass through multiple data servers connected through wired/wireless networks. The data eventually reside in the corporate database.
Technology Focus: Well Construction (May 2014)
Authors: Carpenter Bob 
Published: February 2015

Technology Focus
Many good well-construction-technology papers came out last year, as well as a couple on older technologies that either had not been published earlier or had been released and were underappreciated. Two papers on cement technologies offer improved, relatively easy cementing success. The paper on the new, larger-diameter, high-pressure/ high-temperature (HP/HT) casing valve offers new capabilities for reducing risk in some managed-pressure-drilling applications.
Stinger or Tailpipe Placement of Cement Plugs. Everyone knows how to balance a cement plug, right? Well, if you are using the same approach to balance plugs with a stinger as that used without a stinger, this paper does an excellent job of demonstrating why you are performing your stinger applications incorrectly. While this technology has been available in a couple of forms for several years, I think it is still underused. This paper does a very good job of illustrating and explaining in simple terms how we may be contaminating 40% or so of our cement plug from unintended overdisplacement.
Newtonian Fluids in Cementing Operations in Deepwater Wells. The first field applications of this technology were as early as 2000, but this is its first publication. This technology is simple and relatively easy to apply and is most beneficial in wells where one is trying to gain increased cement coverage farther up the annulus when fighting a narrow pore-/fracture-pressure window. Improved mud-displacement efficiency can be an ancillary benefit. The authors have done a good job of detailing some of the more recent deepwater Gulf of Mexico case histories.
New Casing Valve in a Deep-Well Sour Environment. In HP/HT managed-pressure drilling, many bottomhole-assembly (BHA) components are too large to be tripped through the rotating head. Opening the rotating head to pull large BHA components requires a delicate fluid balance between losing and gaining while completely out of the hole, a high-risk operation. The equipment and techniques described in this detailed case history could add a significant safety barrier for similar HP/HT managed-pressure operations.
Thanks to John Lofton, Chevron senior drilling advisor, for his help with selection of these papers. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE/IADC 168056 Experimental Assessment of Casing Expansion as a Solution to Microannular Gas Migration by Darko Kupresan, Louisiana State University, et al.
SPE/IADC 167956 Constructing Difficult Colony Wash Lateral With Innovative Rolling-Cutter Technology Improves Drilling Performance by Greg Bruton, Chesapeake Energy, et al.
Technology Focus: Well Stimulation (June 2010)
Authors: Coulter Gerald 
Published: February 2015

Technology Focus
Reviewing the numerous papers for this feature showed that the primary theme worldwide, throughout the last approximately 18 months, has been acidizing carbonate formations. Fine tuning this information, it is further seen that the primary interest was zone isolation or diversion. Fracture acidizing seems to be on everyone’s mind as well. Certainly, acidizing sandstones is an important area, but only approximately 15% of the papers were related to sandstone acidizing; thus, with limited space, the emphasis here is on carbonates.
Too often, when multiple zones are to be acidized, mechanical isolation is not feasible and chemicals and/or particulate materials are used for diversion. Post-treatment production logging and results often indicate inadequate stimulation of the target zones. When matrix acidizing carbonates, there are many treatment options from which to choose. Choices relate to amount and type of acid per unit of zone, injection rates, heating the acid (cool dolomites), fluid-loss-control materials, diverting materials, as well as the many other additives including friction reducers, corrosion inhibitors, surfactants, iron control, and on and on. Many of the additives are necessary, but of utmost importance is getting the proper amount of acid into each zone.
A primary issue with fracture acidizing is obtaining conductivity and length, with the decision being which is more important, conductivity or length. In most cases, it is not possible to have both (i.e., long conductive length), particularly in high-temperature situations. In a low-permeability situation, length becomes more important than conductivity, and the requirements may be met more easily with an inert fluid and proppant. In a high-permeability situation, conductivity becomes more important than length, more easily met with acid. Production-increase predictions can help sort out the required balance between length and conductivity.
The following summaries provide insight into acidizing carbonates.
Well Stimulation additional reading available at OnePetro: www.onepetro.org
IPTC 13203 • “Case Study of Successful Matrix Stimulation of High-Water-Cut Wells in Dubai Offshore Fields” by F. Shnaib, SPE, Dubai Petroleum, et al.
SPE 128043 • “Stimulation of Multilayered High-Carbonate-Content Sandstone Formations in West Africa Using Chelant-Based Fluids and Mechanical Diversion” by M. Parkinson, SPE, Chevron, et al.
SPE 127768 • “Acid/Scale-Inhibitor Stimulation Treatment for High-Temperature Cased-Hole Frac-Pack Subsea Wells: Fluid Qualification and Formation-Damage Assessment” by M. Marquez, Chevron, et al.
Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13327, ’Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar,’ by Kristian Mogensen, SPE, and Soren Frank, SPE, Maersk Oil Qatar, and Rashed Noman, SPE, Qatar Petroleum, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December.
The planning and implementation of a lean-gas-injection trial conducted in the low-permeability Kharaib B carbon-ate reservoir of the Al Shaheen field, offshore Qatar, is described. The main objectives of the trial were to determine whether premature gas breakthrough would occur in the neighboring production wells and whether water injectivity after the gasflood would be reduced as a result of the presence of high gas saturation around the injection well.
Introduction
The Al Shaheen field began production in 1992 from two thin separate Cretaceous carbonate formations and an overlying sandstone formation. Field development used horizontal wells, some placed in radial patterns and others in parallel line-drive patterns of alternating water injectors and oil producers.
These carbonate reservoirs are relatively thin oil columns with a large areal extent (25×45 km) with permeabilities in the 1- to 10-md range. The reservoir-fluid properties exhibit large lateral variations, with oil gravities ranging from 16 to 38°API within the same reservoir. The field contains several gas caps and shows large variations in solution gas/oil ratio (GOR) and in saturation pressures.
Development studies focus on expanding of the current waterflood and on enhanced oil recovery (EOR). A promising EOR process is water-alternating-gas (WAG) injection that uses either CO2 or hydrocarbon gas as the injectant. A coordinated effort was initiated in 2006 to evaluate the scope for incremental field oil recovery.
An important part of the EOR evaluation was to conduct an early gas-injection trial for a period of 6 months in the Kharaib B reservoir. The purposes of the trial were to investigate whether unexpected large-scale permeability heterogeneities exist in the reservoir, to gather gas- and water-injectivity data, and to gain experience for planning potential WAG-injection applications for the whole field.
Planning Phase
The most important part of the preparatory phase was to select the correct injection well for the trial to ensure that the trial objectives could be met. Once selected, the required modifications to the surface facilities then could be scheduled and a data-gathering program set up.
R&D on Campus: Evolving Operations Drive New Technologies
Authors: Braswell Gentry 
Published: February 2015

Editor’s note: JPT surveyed major universities around the world regarding their key upstream research and development projects and activities. The second installment of this series will be published in the July issue.
The signposts ahead show that applied, improved technologies such as enhanced oil recovery (EOR), nanotechnology and state-of-the-art reservoir treatment, monitoring and modeling, and unconventional extraction will define the future of the oil and gas industry. As the demand and need for these techniques and technologies increase, research is under way at numerous universities on how to improve recovery factors to meet future world consumption.
Institute of Petroleum Engineering, Heriot-Watt University, UK
Petroleum engineering at Heriot-Watt University comprises eight general areas of expertise: geomechanics and rock physics, hydrates, hydrocarbon recovery mechanisms, production chemistry, reservoir description, reservoir fluids, reservoir geophysics, and uncertainty quantification.
Patrick Corbett, Total professor of petroleum geoengineering, said the reservoir description group is a coming together of joint industry projects at the university. Furthermore, this kind of collaborative, interdisciplinary model is evolving into research networks among multiple universities working on the same project, he said.
Industry collaborators with the institute include Shell, ExxonMobil, BG Group, Weatherford, Wintershall, PetroChina, Schlumberger, BP, Chevron, Conoco Phillips, Hess, Landmark, Maersk Oil, Marathon Oil, Petrobras, Statoil, Total, Anadarko, Saudi Aramco, and Eni.
The reservoir description group specializes in the integration of geology and engineering for improved quantitative reservoir performance characterization. The reservoir geophysics group’s seismic history matching project uses Schlumberger’s Eclipse, Frontsim and Petrel reservoir data software, Roxar RMS process management software, and Malcolm Sambridge’s NA Algorithm, approaching the subject with geological modeling. The group’s Edinburgh Time-Lapse Project develops reservoir analysis tools for quantitative seismic data interpretation.
The main consortium of the production chemistry group is a flow assurance and scale team joint industry project that develops software used to design field scale inhibitor treatments.
The reservoir fluids group collaborates with carbon dioxide injection research in partnership with the European Carbon Dioxide Thematic Network, the European Network of Excellence on Geological Storage of Carbon Dioxide, the UK Carbon Capture and Storage Edinburgh Consortium, and the Scottish Centre for Carbon Storage. The uncertainty quantification group is in its third phase, addressing problems of uncertainty and error modeling in production. The geomechanics and rock physics group developed the true triaxial Smart Cell for measurement of stress-sensitive petrophysical and rock property data, and created the spinout company PetroMagnetics.
Technology Focus: Coiled Tubing Applications (June 2011)
Authors: Misselbrook John 
Published: February 2015

Technology Focus
The overwhelming focus on “shale plays” in North America has spurred many innovative developments in well design and in completion techniques. The increasing drive toward ever greater reservoir contact in these tight formations has changed the landscape, not only for drilling contractors and fracturing companies but also for the coiled-tubing (CT) industry because today, to achieve increased lateral reach and as a direct result of North American activity, more than 50% of all CT supplied globally has a diameter of 2 in.
The drive toward large CT and correspondingly larger and heavier CT units and reels has totally eclipsed the smaller 11/4- and 11/2-in. units, of which a significant number are sitting underused in various companies’ operating districts across North America.
There remains, however, a moderately healthy demand in many other locations for smaller, more-economical CT packages. Therefore, two of the papers I have selected for this feature describe innovative intervention solutions that use “smaller” CT, from two geographically diverse locations.
The third paper introduces a new material development, which, while originally aimed at ultradeep applications and larger sizes of CT, might actually have the potential to enable improved opportunities for the smaller CT packages. CT practitioners generally are an innovative group and I will be interested to see how they exploit whatever opportunities arise from this development.
Coiled Tubing Applications additional reading available at OnePetro: www.onepetro.org
SPE 143261 • “Unconventional P&A Intervention With Coiled Tubing Below a School Building: Comodoro Rivadavia, South Argentina, Case History” by H. Graterol, SPE, YPF, et al.
SPE 142769 • “New Hybrid System Brings the Flexibility of Coiled Tubing to Long, Extended-Reach Wells” by F. McNeil, SPE, Halliburton, et al.
SPE 143371 • “Spoolable Coiled-Tubing Spears: Recovering Subsea Wells After Emergency Shutdowns” by C. Guidry, SPE, Baker Hughes, et al.
Technology Focus: Well Stimulation (June 2011)
Authors: Coulter Gerald 
Published: February 2015

Technology Focus
Reviewing technical papers from recent SPE meetings around the world, it is apparent that many innovative and creative approaches are being employed to enhance production or injection. Many previously hydraulically fractured formations—carbonates, sands, and shales—are candidates for refracturing, as discussed in the first highlighted paper. Refracturing can be applicable with all reservoir-access methods (i.e., vertical, horizontal, multilateral, and deviated wells). Of utmost importance is the initial completion. Too often, wells are completed initially for expediency, cost reduction, and related factors without planning for “life-of-the-well” scenarios. Experience shows refracturing to be very economical if the correct candidate is chosen and the existing completion allows for proper restimulation. History shows that those wells responding favorably to the first hydraulic-fracturing treatment have the best chance for a successful refracturing treatment.
It is common to think of nonproppant well stimulation as some application of acid. However, we know that there are many well production or injection problems for which acids are not the answer. Near-wellbore nonacid techniques used to overcome these problems seem to have become more popular recently. Examples include gas generators/propellants, acoustics, and other methods to provide energy waves that disrupt and/or remove near-wellbore restrictions. Additionally, improved perforating techniques and nanotechnology are examples of nonacid approaches to assist with near-wellbore issues. Many of these nonacid approaches may be beneficial when paraffin, asphaltenes, inorganic scales, water blocks, and other problems restrict production. This is not to imply that acids cannot be successful in overcoming near-wellbore issues; but when acids are used, they should be used for an identified, specific, near-wellbore problem.
Well Stimulation additional reading available at OnePetro: www.onepetro.org
SPE 138726 • “Successful Well-Stimulation Projects Boost Production From Iraq’s South Oil Fields” by Loayd Al-Hashmi, SPE, Weatherford, et al.
SPE 138357 • “Acid-Stimulation Results of Arab Carbonate Reservoirs in Offshore Field, UAE: 10 Years of Review; How To Prepare for the Future Challenges Linked to Stimulation” by Ahmed F. Shokry, Abu Dhabi Marine Operating Company, et al.
SPE 131551 • “A Successful Application of Near-Wellbore Stimulation Using Fluidic-Oscillation Technique in North Africa Oil Field” by Kritsana Kritsanaphak, SPE, Halliburton, et al.
A Tricky Tradeoff - Can Adding a Little Solvent Yield a Lot More Heavy Crude?
Authors: Rassenfoss Stephen 
Published: February 2015

Years of small-scale testing have shown that adding a small amount of a light hydrocarbon to steam can yield large gains in heavy-oil output and reduce emissions; but, no one has proven it can be done on the large scale common in the Canadian oil sands.
That could change soon. Two innovative Canadian operators—Imperial Oil and Cenovus Energy—are working on commercial steam-injection installations.
They have spent more than a decade developing and testing ways to add solvents such as butane to steam to increase production and ultimate recoveries. If it works on a large scale, it will allow heavy-oil producers to use significantly less steam per barrel to coax out thick crude.
Lowering the steam/oil ratio (SOR)—which represents the barrels of water used to produce an added barrel of oil—could offer a profitable path to reduced emissions.
“If you can improve the thermal efficiency—the steam/oil ratio—emissions go down. Also, costs go down,” said Ian Gates, an associate professor at the University of Calgary, whose research includes solvents. “It all goes in the same direction. You make more money with lower greenhouse emissions.”
Based on laboratory work and field tests, the combination of heat and solvents can increase production—30% or more is often cited—though some have done better and some worse.
Cenovus’ pilot program, which was run at two locations, showed it could reduce its steam/oil ratio by 25%, said Subodh Gupta, chief of technology development for the company spun off by Encana. He also said the greater efficiency could allow wide well spacing.
Imperial said it sees a significant increase in the amount of oil it will ultimately be able to produce. The operator, which improved its estimated recoveries from 20% to 40% at its Cold Lake field by improved reservoir analysis, steam injection, and drilling techniques, said that solvent use plus continued improvements in those three areas “have the potential to increase recovery to more than 60%.”
Despite the potential, many working on the technology express concerns about the cost of the solvent required. “There is no doubt it works, but solvent is quite expensive,” said Neil Edmunds, vice president for enhanced oil recovery at Laricina Energy, who has long been involved in solvent research and simulation work. For companies considering the idea, he said, the cost of the solvent can be “sobering.”