bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Tool Improves Hole-Cleaning Efficiency in Extended-Reach Wells
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 175165, “Use of an Innovative Tool To Improve Hole-Cleaning Efficiency in Extended-Reach Wells in Saudi Arabia,” by Mike Okot, Marlio Campos, German Muñoz, and Alawi G. Alalsayednassir, Saudi Aramco; Matt Weber, Frank’s International; and Zahid Muneer, SPE, Schlumberger, prepared for the 2015 SPE Kuwait Oil and Gas Show and Conference, Mishref, Kuwait, 11–14 October. The paper has not been peer reviewed.
Saudi Aramco operates a large offshore oilfield development that has driven achievements in multilateral and extended-reach directional wells. One challenge the operator faces is to maintain proper hole cleaning in extended 8½-in. tangent sections at 85–87° inclinations, which are drilled in excess of 10,000 ft. In an effort to drill efficiently, a new technology to increase cuttings removal was trial tested on Well A1 from an onshore location of the field.
Introduction
Historically, drilling very long tangent sections required the use of several tandem sweep pills, wiper trips, and reaming and back reaming to maintain hole quality and remove cuttings from the wellbore efficiently. Poor hole cleaning can lead to tight intervals, increased torque and drag, and, eventually, stuck pipe.
Extended-reach Well A1 was drilled to a measured depth (MD) of 30,480 ft [8,650-ft true vertical depth (TVD)] into a stratigraphic environment composed of limestone, shale, and siltstone. The objective of the trial test for the tool was to improve the drilling efficiency. To obtain the best possible hole cleaning, a simulation was performed by placing the new tools every three stands along the tangent section in the 8½-in.-hole section.
The goals of the trial test were
To enhance hole cleaning by removal of cuttings
To reduce the frequency and number of tandem sweep pills
To reduce the frequency and number of wiper trips
To reduce torque and drag levels and make them comparable with those of offset wells
To reduce drilling cost
Well A1 resumed drilling from a preset 9?-in.-casing point in December 2013 in the Manifa field. The well was drilled from surface to 30,480-ft MD and into a stratigraphic environment composed of limestone, sandstone, and siltstone. The objective was to hold vertical from surface to 1,535 ft, build up to 85° from 1,535 to 11,659 ft, and hold an 85–90° inclination to total depth.
The challenges were to clean hole while drilling the long 8½-in. tangent section from 11,659 to 24,160 ft. To address these challenges, the tool company recommended the use of 5-in. cuttings-bed- impeller (CBI) tools at a frequency of one tool per three stands on the 5-in. drillpipe.
The 8½-in. tangent section was drilled smoothly without any hole-cleaning issues (no tight hole or stuck pipe). The primary hole cleaning was achieved during drilling, and no secondary hole cleaning was required.
A service company installed a cuttings-flowmeter system at the shakers to evaluate hole-cleaning efficiency and performance of the hole-cleaning tools.
Re-Emergent Iran Brings Large Potential
Authors: Parshall Joel 
Published: January 2017

The re-emergence of Iran as a full player in the global oil and gas market is a major development and would be so under any market conditions. In the current environment, the collapse of oil prices accentuates concern over market stability, the prospects for price recovery, and the implications of both issues for the global financial system. While the concerns are justified, the most important global dimensions of Iran’s return to the market have to do with the country’s long-term oil and gas potential.
The recently implemented Joint Comprehensive Plan of Action (JCPOA)* lifts nuclear-related sanctions against Iran to restore the country’s access to world oil and gas markets and its freedom to seek international investment in its industry.
Imposed in December 2011 and the first half of 2012 in connection with Iranian nuclear activity, the sanctions placed restrictions on Iran’s central bank, Iranian imports, and the country’s access to international shipping insurance.
Dramatic Impact
As the sanctions took hold, Iran’s production of crude oil and noncrude liquids fell from 4.4 million B/D in 2011 to an average of 3.6 million B/D over the next 3 years. Crude oil production, which excludes noncrude liquids, fell from a previous 3.7 million B/D to an average of 2.8 million B/D under the sanctions. Crude oil exports were cut in half, falling from 2.2 million B/D to 1.1 million B/D. Many oil fields and wells had to be shut in. Development projects were halted or seriously delayed, and the financial consequences of the restrictions that stemmed from the sanctions cascaded through the Iranian economy.
The effects on Iran’s natural gas industry were not as great, as the country has been a limited gas exporter. Some project development activities were slowed or stalled by the sanctions. However, the National Iranian Oil Company (NIOC) brought five new phases of the offshore South Pars gas field on stream over the past 2 years without help from foreign companies. South Pars in the Persian Gulf is the world’s largest gas field, and the new phases are expected to increase domestic gas supplies by about 40%.
On the oil side, Iran could realistically add 500,000 B/D of production to global markets this year, according to Homayoun Falakshahi, Middle East and North Africa upstream research analyst at Wood Mackenzie.
Energizing Worldwide Oil and Gas Deepwater Developments
Authors: Dekker Martijn , McEvilly Mike , Beattie Mike , Laws Bruce , Goodwin Deanna , Khurana Sandeep 
Published: January 2017

Management
The precipitous drop in oil prices is putting higher-cost plays such as deepwater under the microscope. Key questions include: How will the industry energize deepwater developments to close the gap between cost and current commodity prices? What oil price is required to keep deepwater viable over the long term? These topics will undoubtedly be at the top of the mind for oil company executives over the months to come, and were the focus of a panel discussion at the Offshore Technology Conference (OTC) conference titled “Energizing Worldwide Oil and Gas Developments.” Also participating was Kassia Yanosek of McKinsey & Company, which provided break-even cost analyses and historical data on deepwater developments.
By reflecting on the past and looking at the current situation, the panelists explored scenarios on how deepwater breakeven prices can be brought down significantly.
The Past and Present
In the run-up to the oil price drop in late 2014, deepwater had spectacular investment and production growth. However, even then there were signs of increasingly challenging project economics. Global deepwater investment increased from USD 16 billion in 2003 to more than USD 70 billion in 2013 with production more than doubling in that time period to almost 6 million B/D, or 7% of the world’s total oil supply. However, toward the end of this period, there were buildups in costs and cycle times. In the USD 100/bbl price environment of 2012–2013, deepwater breakeven costs for green field projects ranged from USD 70/bbl in the US Gulf of Mexico (GOM) to USD 75/bbl in West Africa, 2-3 times the costs in the previous decade. This was due primarily to three factors: increased geologic complexity (for example, the Paleogene in the GOM, and the pre-salt in Brazil and Angola), increased government take and local content requirements, and project cost escalations beyond supplier margin/ commodity costs (such as increased design complexity.)
In today’s “lower-for-longer” price environment, deepwater greenfield project economics are challenged, yielding dramatic cuts in investment. As of early 2016, approximately 35 billion BOE or approximately 6 million BOEPD of deepwater reserves and production, respectively, has been deferred. The good news is that in today’s price environment, project costs have been reduced across the board, primarily driven by supply chain margin compression. In regions with competitive supply chains, such as the GOM, breakeven costs for greenfield developments have decreased 20% on average to USD 50–60/bbl and ultradeepwater rig day rates have fallen 40% from the first quarter of 2014 to the first quarter of 2016.
Operators Begin Considering Pumps on Older Subsea Fields
Authors: Rassenfoss Stephen 
Published: January 2017

Spotting oil wells on land is easy, just look for the pump jacks. They are a common sight because about 90% of the oil wells on land are on some kind of artificial lift.
Don Underwood, director of subsea processing at FMC Technologies, cited that estimate to make the case that the same factors that make pumps standard equipment on land should increasingly apply to wellheads on the seabed. “If it is 90% onshore versus single digits under the ocean, there is growth potential,” he said.
Realizing that potential has long proved elusive, made more so by the deep funk now in the offshore oil business. But he and others selling pumps sound upbeat about calls from potential customers looking at ways to add oil output without the cost of drilling wells.
“The (oil) companies’ management is demanding gains to production … but they are not willing to go out and do enormous greenfield projects,” Underwood said.
“The subsea playing field changed a lot after the oil crisis,” said Sven Olson, a senior consultant for Leistritz Advanced Technologies, which sells pumps made by Leistritz, a German manufacturing company, for oil industry use. Rather than major new field investments, oil companies are looking to add barrels by taking better care of existing assets.
The two of them, who work for companies selling big, subsea pumps, use phrases like “enthused by the response we are getting,” “tipping point” for pump use, and Underwood went so far as to declare it a “golden age for subsea pumping.”
To put that in perspective, a major upswing in this sector would not require a lot of orders.
A 2016 survey of the market by Offshore magazine listed only 40 subsea boosting projects in the world, and 11 of those were classified as “abandoned/removed.” The number of working subsea systems that year rose to 17, with 12 projects at various stages of development, it said.
In comparison, there are about 5,000 subsea wells, according to a panel discussion at the 2016 Offshore Technology Conference.
The biggest cluster of new fields on the list is in the US Gulf of Mexico (GOM). Development in ultradeep water, such as Chevron’s Jack/St. Malo, have been equipped with pumps from the start. The goal is to sustain high production in water 7,000-ft deep from fields 25 miles apart to a floating production unit located in between.
“We are using subsea boosting pumps at Jack/St. Malo, and other recent Lower Tertiary fields like Julia and Cascade- Chinook, also use subsea boosting,” said Stephen Thurston, vice president, Deepwater Exploration and Projects, Chevron North America Exploration and Production Company, adding “Folks are seeing the utility and value.”
Those deepwater new field developments were approved before oil prices plunged and exploration and production (E&P) budgets shrank.
New Multilayer Boundary-Detection Service in Bohai Bay, Northern China
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176442, “New Multilayer Boundary-Detection Service Employed in Complex and Mature Reservoir in Bohai Bay, Northern China,” by Xija Guo, Yong Jia, Kai Fan, Liuhe Yang, and Guoquan Zhao, CNOOC, and Kai Wu, Fei Wang, Cang Li, and Zhujun Gao, Schlumberger, prepared for the 2015 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Nusa Dua, Indonesia, 20–22 October. The paper has not been peer reviewed.
Bohai Bay is northern China’s largest offshore basin. Its predominant depositional environment is a shallow delta and a meandering river system complicated by faults, an arrangement that leads to fully developed interbed interference and high geological uncertainty when horizontal wells are drilled within the greenfield. As a solution to resulting challenges, a new multilayer boundary-detection service has been introduced. This paper illustrates a case study in which this technology was applied.
Introduction
In 1967, CNOOC began commercially operating the oil and gas resources of the Bohai Sea (Fig. 1). Since then, more than 100 production platforms have been put into operation in a 43 000-km2 exploration area, including both development projects on the greenfield and infill projects on the brownfield.
After long-term development and production, an increasing number of conventional reservoirs have a depleted hydrocarbon capacity and the field’s water cut has increased quickly. Thus, the CNOOC client began to focus on the complex marginal reservoir and the infill projects of the brownfield.
The focus of this paper is to help achieve the geological objectives and, furthermore, optimize production by use of the new multilayer boundary-detection service.
Background
General Geology. The Bohai Bay basin formed at the end of the Tertiary on a crystalline basement solidified from the Archeozoic to the Early-Middle Proterozoic. After deposition in the Middle to Late Proterozoic and the Paleozoic, Mesozoic, and Cenozoic, a complex fluvial channel system was generated with features such as disconnected and isolated sand bodies, mingled structures between the hydrocarbon reservoir and aquifer, inconsistent properties both vertically and laterally, and fully developed heterogeneity. As of 1994, the Bohai Bay basin has been known to consist of 47 faulted depressions, in which 170 oil and gas fields have been found.
Upgrading Soft Skills During Boom and Bust Business Cycles
Authors: Eagleson Narandja Milanovich , Fattahi Behrooz , Howes Susan , Solomon Greg , Ben-Naceur Kamel 
Published: January 2017

Talent & Technology
It is challenging for the oil and gas industry to survive and thrive despite continued low oil prices. How might individuals and companies prepare for a potential re-emergence of the boom cycle of our industry? During periods of low prices, companies focus on strategies to maintain profit margins, high-grading portfolios of assets, workforce, technology, and knowledge. In 2015, the SPE Soft Skills Committee (SSC) concentrated on soft skills during a downturn in our industry’s business cycle and SSC’s ongoing efforts to institutionalize soft skills within the SPE community (Milanovich-Eagleson et al. 2015). This article emphasizes the importance of soft skills in navigating the inevitable impact of systems and structures on human patterns of behavior.

Systems Dynamics View of Boom to Bust Business Cycle
The cyclical nature of business and the consequences of boom and bust is modeled by a game simulation developed by the Massachusetts Institute of Technology in the 1960s (Senge 1990; Sterman 1989; 1992). The lessons learned from the simulation (Senge 1990; 1994; Sterman 1989) include the use of soft skills to deliver superior business results.
Systems influence patterns of human behavior. Simulations generally compress time and space so that the participants can experience the impact of their own decisions and actions. “All you have to do is meet customer demand and order enough from your own supplier to keep your inventory low while avoiding costly backlogs” (Sterman 1989). The results demonstrate the influence of the system structures on human behavior and the predictable patterns of human thinking. “Though individual games differ quantitatively they always exhibit the same pattern of behavior” (Sterman 1989). System dynamics and mental model soft skills are essential for managing the downturn and the return of higher prices.
SAGD and Fiber-Optic Distributed Acoustic and Temperature Sensing
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180726, “SAGD Production Observations With Fiber-Optic Distributed Acoustic and Temperature Sensing,” by Warren MacPhail and James Kirkpatrick, Devon, and Ben Banack, Bryan Rapati, and Alex Ali Asfouri, Halliburton, prepared for the 2016 SPE Canada Heavy Oil Technical Conference, Calgary, 7–9 June. The paper has not been peer reviewed.
Distributed temperature sensing (DTS) is the most common fiberoptic measurement used for steam-assisted- gravity-drainage (SAGD) reservoir monitoring. In 2013, Devon Canada installed DTS in the trial production well at its Jackfish 2 asset. DTS was installed parallel to existing standard instrumentation. In early 2015, a distributed-acoustic-sensing (DAS) fiber-optic line was added in parallel along with multimode optic fiber, allowing simultaneous logging of DTS and DAS. DAS helped to improve confidence in and extend the definition of wellbore effects observed with DTS.
Background
DTS with a fiber-optic cable has been established as a reliable and tested method for monitoring thermal wellbores in heavy-oil production. For its part, DAS has been established as a valuable diagnostic tool in unconventional reservoirs as a completion, stimulation, and production-monitoring tool. DAS interrogators turn a fiber-optic line into an array of thousands of virtual microphones, picking up acoustic signatures across a broad range of frequencies. In SAGD production, DAS has generated significant interest throughout the industry as a potential new reservoir- monitoring tool.
Quadlateral Success Story in a Heavy-Oil Reservoir
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180433, “Quadlateral Success Story in a Heavy-Oil Reservoir,” by E. Livingston, D. Lee, M. Werner, B. Tejo, K. Wibisono, and S. Redman, ConocoPhillips, and D. Callis and C. Bostick, Baker Hughes, prepared for the 2016 SPE Western Regional Meeting, Anchorage, 23–26 May. The paper has not been peer reviewed.
This paper documents the success story of the first quadlateral completion for an Alaskan operator by use of stacked, rotatable, Technical Advancement for Multilaterals Level-3 junction systems. This well is also the first in the world in which the junction system is stacked more than twice in a single well. This quadlateral completion design is the product of targeting multiple formation layers from a single wellbore by use of openhole horizontals with slotted liners. The rotatable, multilateral junction system accommodates the increased number of laterals necessary for continued economic exploitation of the West Sak heavy oil reservoir.
Introduction
The West Sak in the Kuparuk River Unit Drillsite 1D area is a 300-ft-thick Upper Cretaceous shallow marine sequence comprising very-fine-grained single and amalgamated hummocky cross-stratified sandstone beds.
The initial 1997 West Sak development drilling in this area consisted of all vertical producers. The thinner A4, A3, and A2 sands were targeted along with the D and B sands. These wells had fracpack completions for sand control and were supported by vertical water injectors. With the start of horizontal multilateral drilling in 2000, the focus shifted to the thicker D- and B-sand targets using sand-exclusion wire-wrapped screens. In 2004, the completion strategy changed from sand exclusion to sand management, for development to remain economically viable. The 1E and 1J projects used slotted liners and targeted the D, B, and, in some areas, the A sands from a single wellbore by use of dual- and trilateral completions.
Use of Life-Cycle Drilling-Simulation System on Challenging HP/HT Drilling Operation
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 178207, “Use of a Life-Cycle Drilling Simulation System on a Challenging HP/ HT Drilling Operation in the Norwegian Sea,” by Laurie Scott, Wintershall; Just Sverre Wessel, SPE, Maersk Training; and Josef Nabavi and Rolv Rommetveit, SPE, eDrilling Solutions, prepared for the 2016 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Abu Dhabi, 26–28 January. The paper has not been peer reviewed.
A life-cycle drilling-simulation system (LCDSS) was used during planning, training, and operation in support of a very challenging high-pressure/ high-temperature (HP/HT) drilling operation in the Norwegian Sea. The LCDSS consists of a total modeling system tailor-made for planning, advanced training, and real-time simulation and decision support. This paper presents the LCDSS and elaborates on the use of it in the preparation and training phase and the operational phase, including forecasting.
LCDSS
The LCDSS used in this work consists of advanced dynamic drilling models and diagnosis technology merged with 3D visualization into a virtual wellbore. The interactions between the various drilling models are seamless and are used in the whole drilling value chain—from planning through training and, subsequently, real-time operations with forecasting.
Work-Process Modifications
In order to set up the LCDSS delivery, it became apparent that the existing structure of communication and work processes had to adopt the delivery of this service. Therefore, a thorough evaluation had to be conducted in order to include the service into the operation properly.
The main challenge was to ensure that the operator was allowed access to relevant data when needed without interfering with everyday tasks. To achieve this, a strong communication line had to be established, to ensure that the communication worked optimally among rig, operator, and remote center.
Mitigating Drilling Dysfunction With a Drilling Advisory System
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18333, “Mitigating Drilling Dysfunction With a Drilling Advisory System: Results From Recent Field Applications,” by Gregory S. Payette, SPE, Darren Pais, SPE, Benjamin Spivey, SPE, and Lei Wang, SPE, ExxonMobil Upstream Research Company; Jeffrey R. Bailey, SPE, and Paul Pastusek, SPE, ExxonMobil Development Company; and Michael Owens, XTO Energy, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed.
The ExxonMobil Drilling Advisory System (DAS) is a rig-based drilling-surveillance and -optimization platform that encourages regular drilloff tests, carefully monitors drilling performance, and provides recommendations for controllable drilling parameters to help improve the overall drilling process. Key technical components of the DAS include high-quality adaptive filtering algorithms for computing various drilling-system-performance measures, data-encapsulation/ dimensionality-reduction techniques, and reduced-order-modeling techniques that are ultimately used to generate recommendations for improved performance.
Introduction
Approximately a decade ago, the company initiated an internal program to pursue real-time rigsite mechanical-specific- energy (MSE) surveillance. MSE, a quantity initially developed and applied in the mining industry and subsequently applied to oilwell drilling, provides a measure of the energy required for a drilling assembly to drill through an interval of subterranean formation; and underefficient drilling conditions correlate with the compressive strength of the rock being drilled. It was quickly demonstrated that frequent drilloff tests using MSE trends to maximize drilling performance were an effective means of optimizing the drilling process. The basic idea was to use MSE trends to identify and respond to drilling-system- performance limiters such as bottomhole-assembly (BHA) whirl, bit balling, and stick/slip, with the ultimate goal of producing consistently better and longer bit runs. The initial program was deemed highly successful and since has become a key component of the rate-of-penetration (ROP) -optimization process.