bluuebunny/crossref_metadata_2025_split huggingface dataset:
IPTC Highlights the Importance of Technology and Collaboration in Unlocking Future Resources
Authors: Wilson Adam , Henni Abdelghani , Jacobs Trent 
Published: February 2015

Conference review
Technology, research, and project best practices critical for producing the next generation of energy resources was the focus of panel discussions and technical paper presentations at the International Petroleum Technology Conference (IPTC), held 20–22 January in Doha, Qatar.
The seventh edition of IPTC attracted more than 6,000 attendees representing 523 companies from 63 countries, including top executives from both national and international oil companies. The largest multisociety, multidisciplinary oil and gas event in the Eastern Hemisphere, IPTC was hosted by Qatar Petroleum, with ExxonMobil as cohost. The conference was sponsored by SPE, the European Association of Geoscientists and Engineers, the Society of Exploration Geophysicists, and the American Association of Petroleum Geologists.
Andrew Swiger, senior vice president and principal financial officer for ExxonMobil and IPTC executive committee cochairperson, said that the event has become an important global forum for highlighting the research and innovation that will shape the exploration and production (E&P) industry’s future. The speakers and attendees at the event, agreeing that the era of easy oil is over, said that now is the time to deploy all technical capabilities to unlock future resources. The theme of the conference was “Unlocking Energy Through Innovation, Technology, and Capability.”
Qatar’s prime minister and interior minister, Abdullah Bin Naser Bin Khalifa Al-Thani, said during the conference opening ceremony that Qatar was eager to host and sponsor this event because of the importance of the energy sector in the prosperity and the development of the country. Meanwhile, Qatar’s minister of energy and industry, Mohamed bin Saleh Al-Sada, said that Qatar’s success in developing its natural resources and exploiting them wisely comes mainly from its long-term strategy that involved creating a well-developed infrastructure and a solid and diversified economy, as well as offering a stable investment climate.
A New Outlook
At ITPC’s plenary session, panelists described a world in which the conventional wisdom of yesteryear has been supplanted with a new outlook for the future, ushered in by a wave of new technologies. The speakers, representing six international and national oil companies, spoke about the challenges facing the industry with optimism based on the industry’s increasing success in tapping into complex resources to produce them safely and more efficiently.
Impact of the Big Crew Change on Employee Retention
Authors: Sprunt Eve , Howes Susan , Pyrcz Michael 
Published: February 2015

Talent & Technology
You have invested a lot of time and money training new employees. Once employees are fully qualified, how do you retain them? The SPE Talent Council survey on factors affecting employee attraction and retention provides valuable insights. Documented in paper SPE 168112, the survey received responses from 1,737 people, and the results indicated that for those surveyed there are many important ways in which younger employees differ from older ones and that key retention factors differ with age.
Survey respondents were asked to rate 31 factors for staying with an employer and 31 factors for leaving an employer on a 6-choice scale that ranged from “most important” to “not at all important” and “not applicable.” Only people who reported having more than one employer were asked questions about leaving. Most of the survey respondents had worked for multiple employers (Fig. 1). Once people have experience switching employers, it may take less provocation or less enticement to persuade them to make another change.
For survey respondents, “golden handcuffs” were not very effective. “To qualify for a future benefit such as a pension or retiree medical coverage” ranked 15th out of 31 factors for staying for men over the age of 40, 22nd for women over age 40, and 26th for men and women under age 40.
Opportunity’s Siren Call
Opportunity was clearly the number one driver, but the results indicated the intensity of that driving force varies with age and gender. When people were asked to rate factors for leaving an employer, 53% of women and 49% of men under the age of 40 identified “insufficient opportunity, challenge, career potential” as “most important,” in comparison with 35% of women and 29% of men over the age of 40. When the question was worded “Why do you stay with an employer?” 53% of both men and women under age 40 identified “opportunity, challenge, career potential” as “most important,” in comparison with 39% of women and 32% of men over age 40.
Opportunity, while clearly of paramount importance, was only part of the answer. The top factor captures 7% to 8% of the “most important” responses for why survey respondents stayed, and 10% to 12% for why they left (Fig. 2). Capture of 50% of the “most important” responses for why survey respondents leave requires seven to eight factors. Capture of 80% of the “most important” responses for why people leave takes 15 to 16 factors. The results of this survey indicated that for companies to have attrition rates below 20% requires attention to many factors.
Defining Regions of Hydraulic-Fracture Connectivity Aids in Designing Completions
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166505, ’Defining Three Regions of Hydraulic-Fracture Connectivity in Unconventional Reservoirs Helps in Designing Completions With Improved Long-Term Productivity,’ by Roberto Suarez-Rivera, SPE, Schlumberger; Larry Behrmann, Schlumberger consultant; Sid Green, SPE, Schlumberger and University of Utah; and Jeff Burghardt, SPE, Sergey Stanchits, Eric Edelman, SPE, and Aniket Surdi, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
Using large-scale hydraulic-fracturing experiments on tight shale outcrops, three dominant regions controlling stage production were identified—the connector between the wellbore and the fracture system, the near-wellbore fracture, and the far-wellbore fracture network. The particular nature of these regions may change depending on the play, the reservoir makeup, its relation to the in-situ stress, and the distribution of rock properties; however, these regions are always well differentiated. Understanding the role of each of these components in hydrocarbon production is fundamental to identifying the dominant sources of fracture-conductivity loss and accelerated production decline.
Introduction
Achieving economic production from nanodarcy-scale-permeability, organic-rich- mudstone reservoirs requires creating large surface area by hydraulic fracturing. More importantly, economic production depends on preserving the created surface area and fracture conductivity during long-term production. This paper is about understanding the surface area (fracture geometry) that is created in heterogeneous rocks with complex makeup, preserving the surface area after fracturing, and maintaining adequate fracture conductivity during long-term production.
Fig. 1 shows a conceptual representation of the interaction of the propagating fracture with weak interfaces and weak bedding as a function of distance from the wellbore. Branching and stepovers (not shown) also develop vertically, providing resistance to flow and to upward fracture growth. Three regions of fracturing with unique properties emerge from this concept: the wellbore/fracture connector, the near-wellbore fracture, and the far-wellbore fracture. The wellbore connector (possibly 10–30 ft) is the region of highest hydraulic convergence and appears to be a choking point for production. This is particularly so if it is not propped appropriately. The near-wellbore fracture is of limited extent (200–400 ft) and represents most of the propped surface area and possibly most of the produced hydrocarbons. Unfortunately, proppant transport in the far-wellbore fracture region is minimal; the created far-field surface area is easily lost and does not contribute to production. This loss of surface area at the farwellbore region may not be avoidable by operational changes at the wellbore.
Technology Focus: Production Operations (March 2014)
Authors: Alhanati Francisco J.S. 
Published: February 2015

Technology Focus
Production engineers are facing a new challenge when trying to select optimal well-production systems (in particular artificial lift) for important, relatively new resources: liquids-rich shale and deepwater subsalt applications. They are being asked to make such a selection when there are still large uncertainties about the well productivity and the produced-fluids thermodynamics (i.e., unclear functional requirements).
These applications are overall quite different, and the reasons for the large uncertainties are not the same. On the other hand, both applications involve relatively deep wells and relatively high pressures and temperatures downhole and the associated complications. For both applications, one needs to try to select a system that is flexible, so that it can work properly in a relatively wide range of operating conditions; that is reliable, so that it does not require frequent interventions; and that is easily retrievable, so that there is no need to have an intervention with a full-size rig every time you have to replace a key part of the system. By the way, space is limited both in the casing downhole and in the tubing hanger (for extra penetrations); therefore, there is only so much you can install in the well to try to achieve all this.
The recent increased cost and decreased availability of high-capacity rigs have certainly provided extra incentive for the development of rigless deployment and intervention techniques. Nevertheless, further technology development is still required to make available production and intervention systems that meet the demands of these applications.
Meanwhile, what is a production engineer to do? The best approach will depend on the business drivers for the operator, in particular the right balance between shortand long-term goals. Some solutions may require a lower capital investment or allow for higher production rates initially but at the cost of a lower overall recovery from the reservoir in the long term. If the focus is on long-term reservoir recovery, the best approach likely will involve a higher capital investment and lower production rates (and lower drawdowns), at least initially. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 166177 Completion and Production Strategies for Liquids-Rich Wells in Ultralow-Permeability Reservoirs by Amit Kumar, Halliburton, et al.
SPE 166027 Decision Analysis of Long-Term and Short-Term Production Optimization Applied to the Voador by Agus Hasan, Norwegian University of Science and Technology, et al.
SPE 166379 A Case History: The Installation of a System To Restore Full Safety-Valve Functionality to a Malaysia Offshore Well With a Damaged Control Line by M.K.M. Aminuddin, Petronas, et al.
Improved Recovery Rate in Subsea Wells by Use of Riserless Light Well Intervention
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24367, ’Improved Recovery Rate in Brownfield Subsea Wells Using Riserless Light Well Intervention,’ by O.E. Karlsen, SPE, B. Morrison, SPE, and P. Maciel, SPE, Welltec, 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.
The number of subsea wells has increased steadily to more than 5,500 by the end of 2012. Unfortunately, because of their location in deep water, interventions in subsea wells have typically required drilling rigs, and operators have been reluctant to perform interventions on these wells. Cost-effective riserless light well interventions (RLWIs) are crucial if subsea operators are to realize the full potential of 50% oil recovery (or more) from their subsea fields.
Introduction
Traditionally, subsea intervention has required a deepwater drilling rig to be freed from the drilling schedule and mobilized to the subsea wellsite. Then, a riser is connected to the subsea well, allowing electric-line, coiled-tubing, or heavier pipe-conveyed interventions. These types of operations are challenging to schedule, time consuming, and costly and can have high risk. With this combination of factors, operators often decide that costs and potential risks of an intervention to improve production are too high and choose to forgo this work on an adequately producing well with no operational problems. Thus, recovery factors in subsea wells are much lower compared with recovery rates of dry-tree, platform-based wells.
RLWI
RLWI is run from smaller, dynamically positioned light-well-intervention vessels instead of large workover ships. RLWI reduces costs and improves scheduling flexibility, thereby reducing barriers to performing subsurface well interventions and helping subsea operators improve recovery rates.
The key to the low cost of RLWI is that the subsea well-control package (or “subsea stack”) is deployed subsea as a single lift. Once landed on the subsea tree, wireline tools are deployed in a subsea lubricator through open water from the vessel down to the subsea stack. The electric line runs through the open water rather than inside a riser from the surface. On top of the lubricator pipe, a pressure- control head is connected to avoid spills. Fig. 1 shows the combination of technology and services used to perform an RLWI.
In addition to eliminating rig-rental costs, mobilization and rig up/down is faster, and thus the intervention process naturally has less nonproductive time. The ease of operations and light weight of the equipment provide a further cost savings because fewer people are needed. One intervention study showed that RLWI was accomplished at 50% of the cost of conventional interventions.
The Evolution and Potential of Networked Pipe
Authors: Hernandez Maximo , Long Roy 
Published: February 2015

Technology Update
The need for “next-generation” technology for improved data transmission up the hole in drilling operations has been acknowledged for more than 2 decades. The term “next generation” typically implied a quantum leap in transmission speed from that available, by means of current state-of-art telemetry. That need is now filled by networked drillpipe (Figs. 1 and 2). Development of the technology began in 1997. Initial R&D addressed two problems, the growing need for a high-rate data-communications system that would allow high-resolution downhole drilling information to facilitate informed drilling decisions in real time and the attendant need to bring data-transmission rates to up to five orders of magnitude from mud-pulse telemetry’s approximate high of 10 bits per second.
Evolution of Networked Pipe Networked pipe had its genesis in a program undertaken by Novatek in 1997 to develop a mud-actuated hammer and a unique hammer bit. The company proposed to develop a set of complementary technologies integrated into the mud hammer that would enable various functionalities of the bit, including: 1) downhole bit rotation, 2) sensing and control, 3) data transmission, and 4) directional-drilling capability.
In the case of data transmission, the company concluded that a much higher data bandwidth was needed by the oil and gas industry than could be delivered by either existing mud-pulse telemetry or a new hammer acoustic-telemetry system. This was particularly true when considering the need for real-time data to support seismic while drilling (SWD), another possible offshoot of the hammer development. With this conclusion in mind, other acoustic sources with higher frequency ranges than the hammer were investigated. Substantial project focus was directed to this area of R&D, as it was deemed to be a critical enabling technology for the rest of the drilling system under development.
Initial development focused on the use of acoustic transmissions to carry high-frequency data through a single length of standard drillpipe. Data-rate limitations led to the abandonment of the concept and to the investigation of wired pipe that transmitted data across the tool joints using high-frequency acoustic transducers. However, the need for electric power and electronic support for each transducer, and the need for timing of the threaded connections when made up, led to the abandonment of that approach also. The company then directed its focus to fundamental work performed with a high-efficiency inductive-coupling sys-tem that looked promising. That technology resulted in networked drillpipe.
Presalt Propels Brazil into Oil's Front Ranks
Authors: Parshall Joel 
Published: February 2015

In an industry whose scale and character have arisen so much from great discoveries of vast fields, the recent oil discoveries in the deepwater presalt layers off Brazil could rank as some of the biggest, most important globally in several decades.
At the center of the expansive presalt play is Petrobras, the Brazilian national oil company, which operates most of the concession acreage that has been awarded and has drilled most of the discoveries. With the discoveries made in the presalt, Petrobras President Sergio Gabrielli has said Brazil will rise to eighth place in oil and gas reserves among the world’s producing countries. Based on current rankings, this would place it above Nigeria and below Venezuela. To optimize the development of the presalt, a host of major challenges—geological, engineering, commercial, and financial among them—will need to be met.
Until the discoveries of 2007–09, there had been little drilling in Brazil’s presalt structures for many years. A number of shallow-water presalt discoveries had been drilled and developed in the Campos Basin during the 1970s and 80s. However, giant discoveries in post-salt reservoirs at that time shifted most attention toward those strata. Major questions remained about the suitability of presalt targets and the risks of drilling through salt layers as thick as 6,600 ft. The difficulties of seismic imaging beneath salt also were a considerable barrier, not to mention the challenges of deepwater drilling and development pertaining to some potential future targets.
Over the following 10 to 15 years, however, the industry’s deepwater capabilities progressed, along with the realization that the largest remaining prospects lay in deeper and deeper waters. In bidding rounds during 2000–01, Petrobras acquired a cluster of deepwater and ultradeepwater presalt leases in the Santos Basin—acreage that in total was larger than the entire Campos Basin to the north. The company then launched one of the largest seismic programs in industry history to image and interpret the geology of the lease acreage.
Technology Focus: Offshore Drilling and Completion (April 2010)
Authors: Jousseaume Jean-Louis 
Published: February 2015

Technology Focus
After a high-activity and high-oil-price period, we again entered into a low phase of the cycle in which reducing costs becomes our priority. Meanwhile, we still must deliver barrels and wells, in due time, keeping employees safe and healthy, and without any damage to the environment. Consequently, we are obliged to intensify efforts to innovate and try new concepts, either to access prospects that were technically not possible just a few years ago or to increase recovery from mature and declining fields without spending excessive amounts of money.
But we should keep in mind that technical progress is not the only path to improve our global and economic performances. Such an improvement should include an established process of questioning all our practices, including but not limited to:
Adapted personnel management—because at the end of the day, the quality of the deliveries is linked closely with the training and knowledge of the employees running the job
Contractual changes that establish win-win relationships between the parties—it is always useful to remember that a good contract is a contract making both parties happy
Working transversely throughout all companies and contractors to establish and generalize commonly agreed on standards and best practices
The following summaries and additional reading suggestions provide good examples of our constant research of new technologies. But our scope of work is much larger, and every improvement in every aspect of our job will help us to push away this decline of our industry that some prophets foresee; it is not closer today than it was 10 or 20 years back.
Offshore Drilling and Completion additional reading available at OnePetro: www.onepetro.org
OTC 20295 • “SBOP Drilling Enables Efficient Drilling in Extreme Water Depths” by Michel Dib, Intecsea, et al.
IPTC 13142 • “Anticollision and Risk Management Offshore Qatar: A Successful Collaboration” by Benny Poedjono, SPE, Schlumberger, et al.
OTC 20277 • “Moho Bilondo—The First Deepwater Development Offshore the Republic of Congo” by Claude Cahuzac, Total, et al.
Technology Focus: Natural Gas Processing and Handling (April 2010)
Authors: Vitucci John 
Published: February 2015

Technology Focus
Industry forecasts continue to cite demand for natural gas as one of the fastest-growing hydrocarbon demands over the next 20 years. Demand for natural gas will challenge our industry to provide gas from conventional and unconventional gas supplies as well as from remote locations such as deepwater areas and the Arctic region. It also will require development of liquefied natural gas (LNG) and other transportation methods to link end-user markets with supply globally. In reviewing papers for this feature, the number of natural-gas transportation papers far outnumbered papers from other natural-gas technology areas and the number of papers for LNG far outnumbered other types of transportation-technology papers. LNG continues to gain momentum as a preferred method to commoditize natural gas on a global basis.
LNG projects are technically complex and require large long-term investments and a multidisciplinary engineering approach for successful execution. The Qatargas-2 LNG project illustrates the complexity and large number of engineering and technical disciplines required of an LNG project: well-completion designs that provide sustained deliverability over the life of the facility; process designs incorporating new liquefaction technology, advanced power-generation designs, improved efficiency, and cleaner emissions; and LNG carriers that continue to push single-ship transport volumes ever higher while meeting strict safety and environmental standards. Such projects require large efforts from a broad spectrum of engineering disciplines, technical specialties, and project management. They provide for some of the most technically challenging work found in the industry today.
The papers highlighted in this feature and the suggested readings merely scratch the surface of LNG and other alternative-gas-transportation technologies. Regardless of technical discipline, I am confident there is a technical topic here that each reader will find touches upon his/her area of expertise.
Natural Gas Processing and Handling additional reading available at OnePetro: www.onepetro.org
OTC 20048 • “LNG STS Operations in Arctic Waters” by Tor Einar Berg, Marintek, et al.
SPE 120745 • “Economics of LNG Projects” by Faleh T. Al-Saadoon, Texas A&M University–Kingsville, et al.
IPTC 13707 • “Qatargas-2—Leading the Way in Clean LNG-Train Technology” by M.D. Pratt, Qatar Liquefied Gas, et al.
OTC 20145 • “Marine CNG—Why Hasn’t It Happened?” by C. Young, Centre for Marine CNG, et al.