bluuebunny/crossref_metadata_2025_split huggingface dataset:
Middle East Conference Focuses on Energy Future Key Enablers
Authors: Henni Abdelghani 
Published: February 2015

Conference review
More than 2,000 oil and gas professionals from all over the world converged at the Bahrain International Exhibition in March to attend the 18th Middle East Oil and Gas Show and Conference (MEOS 2013).
Organized by SPE, the conference’s opening session presented a panel of high-ranking industry figures, who delivered their perspectives on this year’s theme, “Transforming the Energy Future.” The theme focused on current issues the oil and gas industry faces as it strives to meet future global energy demand with emphasis on the processes, technologies, business models, and human skills that will be required to meet those needs effectively and efficiently.
Delivering the keynote speech, H.E. Shaikh Ahmed bin Mohammed Al Khalifa, Bahrain Minister of Finance and Minister in Charge of Oil and Gas Affairs, said the theme of the conference was appropriate. “Transforming the energy future is well chosen as we live in an era where change is the norm and agility and proactivity mean the difference between success and failure,” he said.
Shaikh Al Khalifa said that the biggest challenge facing the industry is adapting to the accelerated rate of change that will propel the oil and gas industry into the future. “To adapt, we need to introduce new methods of thinking and new work processes to be able to meet the challenges faced by society in general and the energy sector in particular,” he said.
The game changers that will potentially have the most impact on the industry are unconventional resources, renewable energy, and energy efficiency, Shaikh Al Khalifa said. “One of the challenges facing the industry is the availability of skilled human resources. It is important that the industry ensure the continuous investment in human resources to supply the industry with adequate number of skilled engineers.”
Remarks during the executive panel session followed from Amin Nasser, senior vice president for upstream at Saudi Aramco; Martin Craighead, president and chief executive officer (CEO) at Baker Hughes; Paal Kibsgaard, CEO of Schlumberger; Sami Al-Rushaid, chairman and managing director of Kuwait Oil Company (KOC); and Sara Ortwein, president of ExxonMobil Upstream Research.
Q&A with Phil Andrews, CEO, Getenergy
Authors: Andrews Phil 
Published: February 2015

Q&A
What is the mission of Getenergy?
Getenergy was originally created on the fringes of the Offshore Europe exhibition in Aberdeen in 2003. I was asked by the British government to run a meeting on education and training for 20 staff from national and international oil companies who were visiting the show. The meeting clearly demonstrated that the upstream industry desired a dedicated event entirely focused on education and training. Getenergy (Global Education and Training for Energy) was the company that emerged in 2004 following this discussion.
Getenergy was founded by accident, not design, based on a niche, yet clear, industry need. Getenergy does not provide or sell training; rather it is a platform for those who do, to meet the needs of those who require often complex training and education solutions, particularly in developing hydrocarbon provinces, where training is both part of the contractual obligation for IOCs and at the heart of the national economic development agenda.
Are most of your events designed to bring together NOCs, IOCs, academia, and the service sector?
Rather like preparing drilling muds, our meetings require all the right ingredients in the correct quantity. We seek, in every event, to have an equal number of universities, local colleges, training providers, and national and international oil and gas company representatives. We have a Learning Arena exhibition, which allocates space to exhibitors representing the world’s largest oil companies or the smallest university departments. In many of our meetings, universities from brand-new hydrocarbon provinces participate in what often represents the first international meeting they have attended.
You have an upcoming training event in London. What will the focus be? How is it unique? How many countries will be represented?
In addition to regional and national meetings Getenergy has, since 2005, organized an annual global meeting. This is really our flagship event, which has taken place in Houston (2005), Dubai (2006–07), London (2008–09), Kuala Lumpur (2010), Calgary (2011), and London (2012–13). The next global meeting is in London during 3–5 June and will see participation from those concerned with education, training, and technical learning delivery from 45 countries for 3 days of workshops, our Learning Arena Exhibition, and our “Power Point-free” Exchange sessions. We will have delegations from universities, institutes, and the oil and gas industry in Brazil, Ghana, Kazakhstan, Kurdistan, Malaysia, China, Mozambique, Nigeria, and Tanzania, among others. Our annual global event is unique not only in terms of audience, but also the detailed discussions among national and international oil and gas companies and the global education and training community that take place.
SPE/IADC Drilling Conference Highlights Industry Challenges
Authors: Parshall Joel 
Published: February 2015

Conference review
The challenges of the drilling industry, technology advances, and the improvements needed to meet growing global oil demand in a safe, environmentally sound manner were the center of attention at the 25th SPE/IADC Drilling Conference held 5–7 March in Amsterdam.
A final attendance of 2,079 was the highest since the record level of 2,113 in 2007, a clear sign of the industry’s return to strength since the 2008–2009 global economic downturn. This year’s attendance was the second highest in conference history.
In 18 technical sessions, the conference covered a full slate of subjects including deepwater drilling; wellbore placement; drilling automation; early detection and well control; managed pressure and underbalanced drilling; and health, safety, and environment. A total of 102 papers were presented, selected from more than 350 abstracts, and there were 28 ePoster presentations.
The exhibition featured displays by 128 organizations, providing attendees the opportunity to see and discuss the latest in equipment, services, and other resources supporting the global exploration and production industry. In addition, a Young Professionals luncheon featured keynote speaker Eric van Oort, Lancaster Professor in Petroleum Engineering at the University of Texas at Austin, who addressed “The Great Crew Change.”
Delivering Wells
“Delivering Wells in a Critical World” was the theme of the conference plenary session on 6 March. Moderator Ole Slorer, director of global oilfield services at Morgan Stanley Research, framed the industry’s challenge over the next 7 years. The drilling sector will need to bring on 27 million BOPD of new production to meet expected world demand by 2020, with most of the increase anticipated to come from fields already discovered. The biggest contributors will be deepwater fields, particularly those in ultradeepwater, and liquids-rich shale formations in North America, he said.
Environmental risk and rising costs will put increasing pressure on drillers, and projects will become more complex, Slorer said. In addition, the world’s floating offshore drilling rig fleet will need to expand from 300 today to about 500 by 2020. Is the industry “ready for this challenge?” he asked.
Mensa Field: Deepwater Gulf of Mexico Case Study
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159741, ’Mensa Field, Deepwater Gulf of Mexico - Case Study,’ by Muhammad Razi and Peter Bilinski, Shell Exploration & Production, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.
The Mensa field is a deepwater Gulf of Mexico (GOM) geopressured gas field, producing from Upper Miocene sand with faulted four-way closure. During the early life, pressures fell sharply, with the field performing as a dominantly depletion-drive reservoir. The trend indicated isolated compartments. After a few years of production, pressures leveled off significantly. This midlife trend seemed to be in contact with originally isolated gas compartments and an aquifer. The late-life pressure trend indicates aquifer influx that effectively blocked the main producing wells from a significant gas area and pressure support.
Introduction
The Mensa field is a deepwater GOM subsea development in Mississippi Can-yon (MC) Blocks 686, 687, 730, and 731 (Fig. 1). The field was discovered in 1987 with Well MC731-1, which penetrated 110 ft of net gas pay in the I sand. Appraisal Well MC730-1, drilled in 1988, penetrated 168 ft of net gas pay in the same sand.
On the basis of seismic interpretation and well information, the I sand was modeled as a thick high-net-/gross-pay-ratio (NTG) sand with 29 to 33% porosity, 250- to 1,000-md permeability, and a gas-in-place volume of up to 1.5 Tcf (Fig. 2). North/south-striking faults divide the main I sand into eastern and western fault blocks. The fault tips out to the south such that the fault blocks are in good pressure communication (confirmed later by depleted pressures recorded in Well A2). A basinwide aquifer was modeled in the south, with the original gas/water contact (GWC) set at 15,750 ft subsea. The I sand was assumed to produce by moderate-to-strong aquifer support.
The Mensa field faced many challenges.
Deep water (approximately 5,300 ft) resulted in high subsea-well and system costs.
Nearest facility was approximately 68 miles away (West Delta Block 143), involving high development cost to connect.
Low ultimate recoveries because of the almost flat structure (approximately 5° dip), large aquifer, and high-permeability sand (wells water out immediately after water breakthrough).
Poor economics because of the low condensate yield and low gas prices at that time (approximately USD 1.5/Mcf).
High subsea-intervention cost and long time required (e.g., wireline job, acid treatment, or workover/sidetrack).
High rock compressibility (30 to 60 microsip), which resulted in collapsed casing and sand-control issues.
Setting the Bear Free: Challenges of the Deepwater Ursa A-10 ERD Well
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163525, ’Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater ERD Well,’ by John Gradishar, SPE, and Gustavo Ugueto, SPE, Shell Upstream Americas, and Eric van Oort, University of Texas at Austin (formerly with Shell Upstream Americas), prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
This case history presents the highly challenging extended-reach deepwater well, Ursa A-10, drilled in the Ursa (Latin for bear) prospect in the US Gulf of Mexico (GOM). This 30,000-ft well, drilled from the Ursa tension-leg platform (TLP) to a vertical depth of 18,000 ft and a horizontal displacement (HD) of 20,000 ft, targeted the Yellow sand in the Ursa/Princess section of the greater Mars-Ursa basin. During drilling of the original hole, a subsequent sidetrack, and two mechanical bypasses, several significant hole problems materialized that led to extensive nonproductive time. At least five independent borehole-failure mechanisms were encountered.
Introduction
In the aftermath of the tragic 2010 Macondo/Deepwater Horizon event, it is important that the industry share case studies on successful wells. It also is important to share information on wells that proved to be very challenging. Sharing learnings, best practices, and experiences on such wells will raise the overall level of proficiency in constructing these wells throughout the industry. As is often the case, more is learned from adversity than from outright success. This is the main reason that the Ursa A-10 case is presented.
Over the last decade, world-class extended-reach-drilling (ERD) wells have been drilled in the continued development of the Mars-Ursa basin in the GOM. These high-deviation wells are distinguished by depth [true vertical depth (TVD) greater than 17,000 ft], HD greater than equal to ;20,000 ft, and overall measured depth (MD) greater than equal to 30,000 ft. Challenges include a geopressured deepwater environment, complex casing programs, and special drilling issues.
The combination of these challenges makes the Ursa A-10 case noteworthy. ERD wells have been drilled to longer HD and overall MD, but those wells generally had simpler casing programs and a more-forgiving pore-pressure/fracture-gradient environment with associated drilling margins. Larger margins leave more room for such things as equivalent-circulating-density (ECD) and annular-pressure fluctuations, mud problems (such as barite sag and hole-cleaning and associated pack-off problems), accommodating manageable levels of borehole instability, and implementation of limited redesign philosophies.
Technology Focus: Well Construction (May 2013)
Authors: Carpenter Bob 
Published: February 2015

Technology Focus
In 2012, the number of unconventional tight gas/shale and high-pressure/high-temperature (HP/HT) papers continued to grow. This year, we had some very interesting developments in these and other areas of well construction.
Paper SPE/IADC 163544 demonstrates that there is still much we do not understand regarding HP/HT cement chemistry. This paper discusses how well-temperature increases and cement designs densified with various weighting materials can negatively affect cement strength stability and permeability. Surprisingly, the subject materials that have been employed have, for decades, generally been considered inert. We see that the chemistry and even the particle size of these weighting materials can negatively affect cement strength stability and permeability as maximum well temperatures increase.
Paper SPE/IADC 163534 describes a new hydraulically set, permanent, openhole whipstock that has been field proved on multiple wells to provide a reliable, time-saving, single-trip solution in the Granite Wash formation. The Granite Wash formation in southwestern Oklahoma has been a directional-drilling nightmare. This is a hard, abrasive, multilayered formation generally requiring significant rig time and multiple trips to kick off successfully and build to horizontal. I appreciate the support of John Lofton, senior drilling consultant with Chevron Exploration and Technology Company, in recognizing the value of this paper.
Paper SPE 163842 relates the potential time saving available through the use of multiple sliding sleeves along a horizontal annulus. The sliding sleeves allowed for near-continuous pumping of 15 stimulation treatments in 24 hours rather than the 3-day average required to place similar stimulation treatments in other Eagle Ford wells by use of the plug-and-perforate process. The authors report similar productivity while providing less risk and execution time.
In addition to these selected papers, be sure to check out the papers listed under additional reading.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE/IADC 163452 HP/HT Well Construction With Closed-Loop Cementing Technology by Don Hannegan, Weatherford, et al.
SPE 159589 New Pressure-Actuated Valve Allows for Interventionless Access to Formation in Cemented Applications by C. Christopher Johnson, Baker Hughes, et al.
SPE/IADC 163459 Dynamic Cementation: A Solution to Well-Integrity Problems by Calvin Holt, Tesco, et al.
Drilling System With Built-In Kickoff Ramp Allows for Dependable Curve Building
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163534, ’Innovative Drilling System With a Built-In Kickoff Ramp Allows Dependable Curve Building in Granite Wash Formation,’ by G.A. Bruton, SPE, and J. Talkington, Chesapeake, and P. Desai, S. Swadi, SPE, and J. Kelley, Schlumberger, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
The Granite Wash formation presents several challenges in drilling the build section from a vertical open hole to form a lateral. The formation is hard and abrasive, and it is difficult to anticipate downhole rock properties. The erratic nature of the formation results in unpredictable performance by the steerable drilling assembly and drill bits. In most cases, the target build rates are not achieved, forcing multiple trips. An innovative drilling system has been developed that provides a dependable kickoff ramp and a firm beginning for initiating the build section without having to rely on the fulcrum point of the drilling bottomhole assembly (BHA) in a single trip downhole.
Challenges
The complex Granite Wash formation (Fig. 1) presents many drilling challenges, particularly beyond 12,000 ft, specifically when building a curve to horizontal at 14°/100 ft.
One of many formation-related challenges was to reduce the number of trips. The conventional sidetracking technique for the open hole has been to run and set a whipstock/anchor assembly at the kickoff point in a separate trip using a different BHA. Once the whipstock was secured, the directional-drilling assembly was run to initiate and finish the curve and reach the landing point. The extra trip, however, needed to be eliminated.
The erratic nature of the formation also makes it difficult for the driller to use the offset to optimize bit selection to drill the highly abrasive formation efficiently. The driller usually selects a proven tricone bit dressed with abrasion-resistant cutters. Despite that, the bit’s cutting structure wears pre-maturely, forcing the operator to make multiple trips downhole with a new polycrystalline-diamond-compact (PDC) bit to finish the curve.
Solution: Innovative Drilling System
The most prevalent sidetracking technique in an openhole application has been to set a cement plug and time drill with controlled rate of penetration (ROP) with a directional-drilling assembly. The cement-plug method generally required 3 to 5 days to get a plug set and dressed off in an oil-based mud. The cement-plug method was replaced by a conventional but reliable whipstock/anchor system, which required a separate trip.
Comments: Mexico's Next Step
Authors: Donnelly John 
Published: February 2015

Editor's column
The opening of Mexico’s energy sector to private foreign investment continues to move forward, with more details of the landmark legislation expected soon. The potential impact this will have on Mexico, its state oil company, and the upstream industry in general is hard to overestimate. Mexico, with all its hydrocarbon riches, has essentially been closed to outsiders since 1938, when the country declared that all mineral and oil reserves in Mexico belong only to the nation.
Mexico has watched its neighbor to the north, the United States, reap the benefits of shale development and ultradeepwater production in the Gulf of Mexico with oil prices hovering around USD 100/bbl. The country now would be reversing decades of resource nationalism, allowing foreign oil firms access to potentially world-class fields.
In March, national oil company Pemex submitted to the government its list of fields and acreage that it would like to keep under the new energy reform regime. Fields not on the list are expected to be offered in auctions, with Pemex allowed to bid on those as well. The first licensing round is not expected to be held until 2015 with production-sharing and profit-sharing contracts both under discussion. Acreage would likely include conventional resources, unconventional, and deep water. Pemex may also seek partnerships with foreign firms for acreage under deals that could be signed as soon as this year.
Published reports say that Pemex requested acreage containing 83% of Mexico’s proved and probable hydrocarbons reserves and 31% of its prospective resources. The acreage includes conventional onshore and shallow water fields, in addition to deepwater fields already under development as well as deepwater areas where discoveries have unveiled attractive prospects, such as in the Gulf of Mexico Perdido Fold Belt. Mexico’s energy ministry has a September deadline to decide what acreage Pemex can keep and what will be available for bidding.
International oil companies may be particularly interested in prospective unconventional acreage, such as in the northern part of the country near south Texas, and the unexplored deep water. The state oil company is thought to have neither the finances nor the technology to develop those areas on its own.
Pemex is trying to shore up its declining oil production. Current crude output is averaging slightly more than 2.5 million BOPD this year, the same level of production since 2012, and down significantly from a peak of almost 3.4 million BOPD in 2004. Enhanced oil recovery methods at mature fields and plateauing production at the main offshore Cantarell complex are helping keep output from falling further. Crude oil exports average approximately 1.27 million BOPD. Mexico’s once-prolific Cantarell field is producing about 355,000 BOPD, down from 2 million BOPD a decade ago, and the offshore Ku-Maloob-Zaap complex is expected to start declining soon from its current 860,000 BOPD output. JPT