bluuebunny/crossref_metadata_2025_split huggingface dataset:
Passive Inflow-Control Device Maximizes Productivity Through Every Phase of a Well's Life
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13863, ’The First Passive Inflow-Control Device That Maximizes Productivity During Every Phase of a Well's Life,’ by Luis A. Garcia, SPE, Martin P. Coronado, SPE, Ronnie D. Russell, Gonzalo A. Garcia, SPE, and Elmer R. Peterson, SPE, Baker Hughes, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed.
In long horizontal wells, production rate typically is higher at the heel than it is at the toe. This imbalanced production profile may cause early water or gas breakthrough into the wellbore. To eliminate this imbalance, inflow-control devices (ICDs) are placed in each screen joint to balance the production-influx profile across the entire lateral length to compensate for permeability variations. Passive ICDs (PICDs) could control the influx without the need for intervention.
Introduction
The primary purpose of ICDs is balancing well production throughout the operational life of the completion to optimize hydrocarbon recovery. Because a typical well with ICDs can produce for 5 to 20 years or longer, the long-term reliability of such a device is crucial to the well’s overall success. If an ICD cannot maintain a uniform flux rate, increased localized production rates will occur and the well will become unbalanced. Thereby, the ICD becomes ineffective, leading to premature water and/or gas breakthrough and possible loss of sand control. Water can reach the wellbore in certain sections because of formation heterogeneities and/or vertical fractures. Ideally, once breakthrough occurs, flow contribution from these water-producing zones should be less than that of the oil-producing sections. The ICD device should increase the flow restriction at the onset of water production, thus allowing other oil-producing zones to continue flowing effectively. In wells with oil viscosity &gt;10 cp, ICD-type selection becomes more critical because of the large difference in viscosity between the oil and produced water. To maintain an even flow profile across the entire wellbore lateral, the pressure-reduction mechanism in the ICD situation must have the lowest sensitivity to viscosity. A restrictive-type ICD can provide desirable results in this regard with its lower sensitivity to viscosity. However, this type of ICD requires a very small flow area to generate the pressure drop (restriction) required in ICD applications. This small flow area has a greater potential for erosion and a low plugging resistance.
Another solution is to enable lower viscosity sensitivity in the restrictive device with the low erosion and high plugging-resistance level of the frictional design. The restrictive-pressure-loss mechanism can be used while limiting the fluid velocity through the device below the critical level, which will minimize erosion potential.
Technology Focus: Drilling Management (September 2010)
Authors: Cunha J.C. 
Published: February 2015

Technology Focus
Certainly there is not a single JPT reader that has not already read and heard about the Macondo-well blowout in the Gulf of Mexico (GOM). Over the last few months, this accident has been present in almost every conversation about the oil industry. Many articles have been written, and many more certainly will be prepared and presented at future conferences. The subject has been present in the daily media around the world. In the SPE Drilling and Offshore Operations technical interest groups, several posts have generated heated discussions as well as a diverse array of propositions about how our industry should proceed from now on. So it seems natural that this JPT section dedicated to drilling management also should address the subject.
For those of us working in the GOM area, it is more than clear by now that this accident will change the industry forever; and not only in the GOM. Members of the industry, managers and technical experts alike, are taking this occasion to reassess operational procedures, equipment safety, and training needs to find opportunities for improvement that will make our operations safer and more efficient. A proficient drilling-management process is now more important than ever. This process must permeate all phases of a project, from early planning to final execution. Risk assessment of all operations must become a routine.
Last year, I wrote in this space about the importance of risk management for drilling and completion operations. I mentioned that there are many articles concerning successful projects in which risk analysis was a fundamental part of all operations. Now may be the right moment for all of us to follow those engaging examples. At the risk of being repetitive, I would like to conclude with exactly the same words that I used to close last year: “It is clear to me that drilling management is related closely to risk management. The correct assessment of all risks involved in drilling operations will provide better planning and consequently will improve operational results.”
Drilling Management additional reading available at OnePetro: www.onepetro.org
SPE 128288 • “Drilling Efficiency and Rate of Penetration—Definitions, Influencing Factors, Relationships, and Value” by Graham Mensa-Wilmot, SPE, Chevron, et al.
SPE 128222 • “High Performance and Reliability for MPD Control System Ensured by Extensive Testing” by John-Morten Godhavn, SPE, Statoil, et al.
SPE 128871 • “Real-Time Drilling-Data Analysis: Building Blocks for the Definition of a Problem-Anticipation Methodology” by R.A. Gandelman, Petrobras, et al.
Interview with 2013 SPE President Egbert Imomoh
Authors: Donnelly John 
Published: February 2015

President's interview
Egbert Imomoh, the nonexecutive chairman and a cofounder of Afren, a Pan African independent oil and gas company with assets in Africa and Kurdistan, is the 2013 SPE president. He will take office during the 2012 SPE Annual Technical Conference and Exhibition in October in San Antonio.
Imomoh joined the oil and gas industry in 1968, working with Shell in Nigeria as a petroleum engineer after basic training in the Netherlands. He worked in Nigeria, the UK, and the Netherlands and rose to the position of deputy managing director of Shell Petroleum Development Company of Nigeria, a position he held until his retirement in February 2002. After that, he worked with Shell International in London as a senior corporate adviser on Nigeria during 2002–04.
Imomoh helped found Afren in 2004 and served as its managing director and executive chairman before assuming his current position. He led the growth of Afren’s Nigerian asset base, established a number of successful indigenous partnerships, and led the company to achieve its first oil milestone at the Okoro Setu project.
He has been a member of SPE since 1973 and was a founding member of the SPE Nigerian Section. He was chairman of SPE Nigeria Council in 1986 and was named a Distinguished Member of SPE in 1999. Imomoh served as the first regional director for Africa on the SPE Board of Directors between 2000 and 2003, and was the chairman of the Board Committee on Educational and Professional Activities during 2002–03. He has been chairman of the Board of Trustees, SPE Nigeria Council, since 2007. Imomoh was named an SPE Honorary Member, the highest honor that SPE presents to an individual, this past year. Imomoh graduated with a BS degree in mechanical engineering from the University of Birmingham, UK, and received an honorary Doctor of Science degree from the University of Port Harcourt this year.
You served on the SPE Board of Directors during 2000–03. Coming back to the board as president now, have you observed any changes in SPE during the intervening years?
Over the years, SPE has become even more international, increased its membership, and has continued to seek ways to serve its members better by organizing many more conferences and workshops, starting up new publications, and by creating regional offices to move its services closer to our members.
SPE’s membership—now more than 100,000—has continued to grow even as other associations lose members. To what do you attribute this success?
Our success can be attributed to a number of reasons. The board and staff have always focused on member needs; they foresaw the need to attract young members and created a student membership program that took off like a rocket. Our technical information offerings have continued to grow and, where necessary, we have formed partnerships with other associations that have strengthened our ability to deliver first-class technical programs at very competitive pricing.
Oil Sands Get Wired - Seeking More Oil, Fewer Emissions
Authors: Rassenfoss Stephen 
Published: February 2015

Heavy oil technology
Two projects in Canada are out to show that oil sands production need not remain in the steam age. Both are powered by electricity, though they use it quite differently. The motivations are the billions of barrels of crude in formations where current methods are not practical or economic, and a desire to find a way to produce heavy crude with less energy and water.
No one is talking about replacing steam for heavy oil production—it is an extremely efficient method for delivering the heat needed to reduce the viscosity of the heavy crude called bitumen. But the potential payoffs for finding a workable alternative is huge.
Of the total bitumen resource in the ground in Alberta, 7% is shallow enough to be mineable, said Todd Zahacy, senior engineering consultant for exploration and production at C-FER Technologies. While production using in-situ extraction techniques from deeper reserves has recently exceeded the output from mining, only about 9% of that vast resource is counted as reserves in Alberta’s 2012 survey of its oil, gas, and coal resources. “There is a massive prize out there if you can go after those areas that are not currently technically producible,” said Zahacy, with the research and testing company that has been evaluating electric methods for a client.
The goals of these two programs are electric-powered heating methods capable of eliminating the costly equipment needed to produce steam and process large volumes of water on site. Lower-temperature methods may also reduce energy use and open up access to underground formations not suited for high-pressure steaming.
The search for electric-powered heating in heavy oil fields goes back decades, but no one has made it work on a commercial scale. Les Little, executive director of energy technology for Alberta Innovates, has long followed the experiments with electric heating technology, and he knows many question if it can be more successful this time. The government technology promotion agency is backing another round of testing, though, because he said this technology “is not your dad’s electrical heating system.”
The province is putting up more than USD 23 million from the Climate Change and Emissions Management Corporation—the government arm is funding half the budgeted cost—because the two electric-powered heating projects could reduce the environmental impact of heavy oil production as measured by water use and carbon dioxide emissions.
That is a potent motivation in Alberta. Projects critical to tapping the oil sands, such as the Keystone pipeline running from western Canada to US Gulf Coast refineries, have been threatened by environmentalists who point out the energy and water required for heavy oil extraction mean it has a larger environmental impact than conventional production.
Virtual-Measurement Value During Startup of Major Offshore Projects
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14518, ’Virtual-Measurement Value During Startup of Major Offshore Projects,’ by R. Cramer, SPE, N. Griffiths, P. Kinghorn, SPE, and D. Schotanus, Shell Global Solutions; John Brutz, SPE, Shell USA; and Klaus Mueller, SPE, Shell Oman, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.
How can wells be managed optimally if one does not know continuously what they are producing? This problem is more critical at initial startup of the wells. Shell uses a real-time well virtual-flow-measurement tool, running on 60% of Shell’s global production, which has enabled significant added value in the areas of real-time surveillance and optimization. The virtual-flow-measurement tool has been applied in the startup of several of Shell’s offshore projects in the Arabian Gulf and in the Gulf of Mexico.
Introduction
Shell has several large upstream offshore projects in various stages of startup or commissioning. These projects have large capital investments and reserves contribution and a high degree of difficulty (e.g., very deep water, subsea processing, long subsea multiphase pipelines, and feeding large onshore gas plants). Hence, it is imperative to start up the processes as quickly and efficiently as possible, yet maintain the highest possible standards of technical integrity, safety, and environmental effects. Key aspects for efficient and effective project startup are well and reservoir surveillance and hydrocarbon accounting. It is important to know how much the wells are producing and the composition of the fluid streams to maximize production and for flow assurance, asset technical integrity, and accounting purposes. Ideally, this would be achieved by use of multiphase flowmeters (MFMs) on each well to measure the oil, gas, and water flows physically and continuously, or by routing each well progressively to a test separator as the wells are started up. However, at the time of startup, MFMs may not have been installed for all wells, and for wells that do have them, they usually are not yet commissioned because MFM commissioning requires fluid samples from the wells, and for subsea wells, sampling usually is performed robotically and at a later stage of startup. Virtual flow meters (VFMs) can be operational when production begins. Similarly, test separators may not be commissioned at the time of initial well production, and if they are operational, they are not suitable for tracking production from multiple wells. Hence, virtual flow measurement has significant value for well/reservoir surveillance and hydrocarbon accounting from initiation of startup to the time when MFMs are effectively commissioned and, thereafter, as effective insurance in case of individual-meter failure.
Discussion/Reply: Downhole Steam Generation Pushes Recovery Beyond Conventional Limits
Authors: Jones Jeff , Capper Laura , Kuhlman Myron , Vassilellis George , Schneider M.J. , Fitzpatrick Nick 
Published: February 2015

Discussion/Reply
The authors of paper SPE 150515, titled “Downhole Steam Generation Pushes Recovery Beyond Conventional Limits,” (JPT June 2012), are commended for bringing the topic to the forefront. However, the article is a little too optimistic and may lead the reader to wrong conclusions. With all the perceived promise over the decades, this technology is still in the conceptual stage, especially in the reservoir EOR mechanisms envisioned by the authors and in the basic operational design.
Playing devil’s advocate, here is a short list of possible “cons” to accompany the article’s list of “pros” for the process:
Conventional steam-enhanced oil recovery (EOR) depends on the latent fraction of heat contained in quality steam. Sensible heat in water has proven to be of little help in the recovery of incremental oil. For the typical project that operates at &lt;&lt;100 psig, the latent fraction of heat in the steam is in the range of 80%. For steam at the proposed &gt;2,000 psig the latent fraction falls to about 35%. If applicable, this changes the mechanism displacing oil from the reservoir; it is no longer a conventional steamflood.
In general, the deeper the reservoir, the hotter the formation. The hotter the formation, the lower the oil viscosity and less need for steam. In California, the typical reservoir at 2,000 ft is 130°F and at 5,500 ft, it is 200°F. Granted, other parts of the world have lower temperatures at depth (e.g., the Alberta fields are about 130°F at 5,000 ft); however, this is a limiting factor for deep thermal processes.
Deeper reservoirs tend to be tighter sands and the downhole steam generation (DHSG) demands that all the fluid sent downhole is injected. This will require either reduction of injection, which has implications for the reservoir process, or injecting at fracture pressures, which has its own set of problems.
There are few better filters in the oil field than a wellbore sand face. Couple this with the inevitable particulate generation in DHSG, and well plugging problems are likely to occur.
Comments: Looking Ahead
Authors: Donnelly John 
Published: February 2015

Editor's column
Initial forecasts for 2014 predict continued growth in global oil supply, relatively moderate demand, and a potential softening of oil prices. International events could change that picture overnight but, for now, the industry’s three leading forecasters—the International Energy Agency (IEA), the US Energy Information Administration (EIA), and OPEC—are in agreement about what to expect next year.
The boom in oil production—primarily from North American unconventionals—should lead to another year of global surplus, with supply outstripping world demand. Global demand will actually rise next year, but at a lesser rate than non-OPEC oil supply. In addition to the US, supplies are expected to increase from Canada, Brazil, and Kazakhstan. ExxonMobil’s Kearl project will boost Canadian output, while the startup of the Kashagan project in the Caspian Sea should add 250,000 BOPD in production in Kazakhstan.
The IEA believes that non-OPEC output will rise by 1.3 million BOPD next year, annual growth that has occurred only once in the past 20 years. The largest increase will come from the US, with that country’s production rising 500,000 BOPD. In July, US crude production increased to 7.5 million BOPD, the highest monthly level of production since 1991. The EIA forecasts that US total crude oil production will average 7.4 million BOPD this year and 8.2 million BOPD in 2014.
Total global demand is forecast to rise 1.3 million BOPD next year, to more than 90 million BOPD, according to the IEA, with OPEC slightly less optimistic with a forecast of a 1 million BOPD rise. Global oil demand has grown approximately 7 million BOPD since 2005. OPEC member countries will meet in December to formalize strategy for 2014.
Meanwhile, OPEC is coming to grips with the US shale boom. At its meeting in July, OPEC ministers conceded that the world will need less of its crude even though world demand will grow at its healthiest pace since 2010. The organization said that demand for OPEC crude will fall by 300,000 BOPD to 29.6 million BOPD. Production from OPEC leader Saudi Arabia is healthy, as output has grown to historic levels.
Differences exist among these three major forecasts. The EIA is more optimistic about global demand and supply growth while OPEC is the most pessimistic. All three forecasters predict that OECD demand will decline, although at a slower rate, while non-OECD demand growth will continue to increase. China is something of a wild card. The EIA predicts a slight rise in Chinese demand growth next year to 389,000 BOPD from 360,000 BOPD this year. But OPEC sees that demand growth relatively flat.
Top Trends in the Oil and Gas Sector
Authors: Karev Adi 
Published: February 2015

Management
The past 12 to 18 months witnessed the oil and gas sector drifting away from the rule of certainty and the return of uncertainty. Uncertainty required more focus, deeper analysis, and operational determination. Deloitte’s fourth annual Oil & Gas Reality Check identifies five trends and delves into the fundamental characteristics of each trend: the supply, demand, macroeconomic, regulatory, cost, price, and competitive behavior factors.
Given the rise of shale gas resources and with new countries entering the ranks of net energy exporters, some are proclaiming that a global revolution is at hand with fundamental shifts in energy geopolitics because of newly found energy independence. A closer examination of the development progress of countries with major shale gas resources reveals a vastly different picture. Countries that can commercially produce unconventional and conventional gas seek higher returns by exporting or planning to export liquefied natural gas (LNG) to Asia Pacific countries that have historically agreed to long-term purchase contracts at oil indexed prices. The expected increase and diversity of LNG supply is spurring transition away from oil price indexation, and the rise of gas hub and hybrid price indexation.
The discovery of new resources across various geographies coupled with the technical challenges of developing those resources are softening governments’ resource policies—an indicator of the degree of resource nationalism. As production efficiency rates and capabilities improve, will resource national-ism surge or will it pale in comparison with the competitive rise of national oil companies (NOCs)? How companies react to and deal with this uncertainty is changing the notion of a singular business model and giving rise to different business models.
Each of these questions and the five trends are discussed below:
Shale gas: A global or regional resource?
The success of North American shale gas has created interest in duplicating the results in other countries. An April 2011 study by the US Energy Information Administration estimated that world shale technically recoverable resources outside the United States were 5,760 Tcf, sparking widespread interest in international shale. However, the presence of shale gas in the ground does not guarantee the unearthing of a fortune.