bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Update: Directional Hybrid Drill Bit Pushes Performance Standards
Authors: Holliday Alan 
Published: February 2015

Technology Update
It is inspiring to look back to 1909 when Howard Hughes Sr. and Walter Sharp introduced the roller-cone bit. The invention was the foundation for the discovery of vast amounts of oil in medium-and hard-rock formations, oil that many drillers suspected was there but was nearly impossible to reach with the bits of that day.
The roller-cone bit changed the industry, but we may forget why its immediate predecessor, the fish-tail bit, was such a burden on drillers as they strived to probe deeper targets. Often 24 hours would not go by without a twist-off occurring, and rig hands were constantly changing bits and “fishing” parts out of the hole. For drilling anything other than loose formations near the surface, it had proved impractical.
In a century’s time, the industry has made tremendous progress. But the limitations of physics continue to challenge the dynamic performance of the bit and bottomhole assembly (BHA) in the demanding downhole environments of today’s wells.
Tools come equipped with features such as torque reducers, depth-of-cut controls, and more flexible assemblies, to mention a few. The inherent problem of controlling the reactive torque between the bit and formation, while achieving optimal performance to reduce the number of drilling days, has remained a challenge.
The introduction of the hybrid drill bit in 2011, which combined roller cones and fixed cutters, was a catalyst to revisit these basic principles and better understand the benefits and efficacy of smooth drilling. The bit excelled in controlling torque fluctuations and exceeded the durability of fixed-cutter bits and the penetration rates of roller-cone bits.
The hybrid bit soon became the standard bit for drilling in hard and interbedded formations, such as those in certain Oklahoma and Canadian plays, because it enabled drillers to reduce the number of curve runs needed. The use of the bit expanded globally, helping to improve drilling results in interbedded applications that historically have met with mixed success when medium-set roller cone or fixed-cutter bits have been used. As results continued to improve, interest in stretching the capability of the technology increased.
Can Waste Water Be Disposed of Safely?
Authors: Rao Vikram 
Published: February 2015

Beyond the Headlines
Editor’s note: Professionals in the oil and gas industry often receive questions about how industry operations affect public health, the environment, and the communities in which they operate. Of particular concern today is the impact of hydraulic fracturing on the environment. In this new column, JPT is inviting energy experts to put those questions and concerns about industry operations into perspective. Additional information about the oil and gas industry, how it affects society, and how to explain industry operations and practices to the general public is available on SPE’s Energy4me website at www. energy4me.org.

Shale oil and gas wells use a lot of water in fracturing operations. Each well may use up to 8 million gallons, and as much as 35% of this can return as flowback water. Safe disposition of this waste water is an industry priority especially because of the widely reported past missteps in Pennsylvania. Safe disposition is completely feasible and, in fact, is being broadly practiced today.
The Nature of Flowback Water
Even if fresh water is used as the base fracturing fluid, what returns to the surface is salty. This is because the water found in association with hydrocarbons has high salinity. Shale oil and gas flowback water salinity typically range from 16,000 parts per million (ppm) to more than 300,000 in some instances. For comparison, sea water runs around 35,000 ppm. The chemicals introduced into the fracturing fluid will also be present in some proportion. These will be low in concentration because even the original fracturing fluid contains only up to about 0.5% chemicals.
Finally, one could also encounter species present in subterranean rock. These could include aromatic compounds (such as benzene) and radioactive species. Some state regulations, such as the ones pending in North Carolina, prohibit the use of aromatics in fracturing fluid so, if present, they could only have come from the subsurface. The same holds for radioactive species. In most instances, subterrestrial bacteria will also be present. All of these render the flowback water unsuited for direct discharge.
Re-use of Flowback Water
Flowback water may be reused to formulate fracturing fluid for the next operation. But since only about a third of injected water returns, additional water is needed (makeup water). In the early going, reuse was rendered costly due to the need to desalinate down to fresh water. However, more recently, all service companies have announced that they can tolerate salinities in excess of 250,000 ppm.
Low Oil Prices Make Innovation a Priority
Authors: Rassenfoss Stephen , Henni Abdelghani 
Published: February 2015

Conference Review - 2014 International Petroleum Technology Conference
A sharp decline in oil prices is pushing oil and gas companies to innovate to increase efficiency and prepare to meet the world’s long-term energy needs, panelists said at the International Petroleum Technology Conference (IPTC) held in Kuala Lumpur, Malaysia, in December.
Under the theme of “Innovation and Collaboration: Keys to Affordable Energy,” the IPTC attracted an attendance record 10,318 industry professionals from 68 countries. Hosted by Malaysian state oil company Petronas and cohosted by Shell and Schlumberger, the conference featured a ministerial session, high-level plenary and panel sessions, a comprehensive multidisciplinary technical program, an exhibition, a young professionals workshop, and various educational activities.
The 3-day conference was opened by Dato’ Sri Abdul Wahid Omar, a minister in the Office of the Prime Minister of Malaysia, who delivered the keynote speech about the paradox of energy affordability. One side is positive, with more affordable prices for those buying oil and gas, thus aiding consumers and the economy. The other side is negative for oil producing countries such as Malaysia, whose collections on production represent more than half of government revenues.
The New Pathways of Multiphase Flow Modeling
Authors: Jacobs Trent 
Published: February 2015

Multiphase Flow
In the realm of enabling technologies, multiphase flow modeling has proven to be one of the most important to the oil and gas industry. Without it, nearly all subsea wells would be too costly or dangerous to develop. While working to fine-tune its offshore capabilities, developers are also busy expanding the technology’s application areas to include shale field development, hydrate remediation, and heavy oil extraction.
In the 1960s, when the industry began studying how to model multiphase flow, which is the science of how liquid and gas interact inside wellbores and pipelines, little was known about the complex physics involved. Back then, an engineer’s ability to predict flow behavior was strictly limited to what could be observed at the wellhead.
Over the years, the industry invented devices that could accurately calculate flow rates, velocities, and volume fractions, along with downhole temperatures and pressures. Armed with these tools, engineers and scientists had the measurements they needed to marry computational science and fluid dynamics. More than anything else, this advancement is what has allowed offshore operators to extend their reach beyond the shallow-water fields and into those thousands of feet deep.
“What we have done is to make it possible for the industry to live with the complex multiphase flow problems that face them on a daily basis,” said James Brill, a multiphase flow expert who recently retired as a research professor of petroleum engineering at the University of Tulsa. “When the industry first moved offshore, they were afraid to go with multiphase flow pipelines because they did not know what was happening inside of them, or what kind of facilities they would have to have at the outlet end in order to handle the fluctuating rivals of gas and liquid.”
In lieu of a complete understanding of multiphase flow, Mack Shippen, a product champion for one of Schlumberger’s top multiphase modeling programs, said early offshore explorers were forced to make conservative design decisions when building a production platform.
That meant using larger than needed processing equipment and pipelines to compensate for what they did not know about the behavior of the multiphase flow. “So yes, you had a safe design but you did not have one that in today’s world would be economic,” he said, explaining that, “if it is overdesigned, then essentially money has been wasted on equipment that is more than what is necessary.” If an operator can reduce the diameter of a subsea pipeline by just 1 in. or 2 in., “the difference can be on the scale of millions of dollars in capital investment,” he said.
Drilling of Multilateral Wells in Kuwait Aided With Geochemical Analysis
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16617, ’Drilling of Multilateral Wells Aided With Geochemical Analysis, Kuwait,’ by Taher El Gezeery, Abdul Aziz Ismail, Khalaf Al Anezi, Monirah Al Jeaan, Jeevan Kumar Silambuchelvan, and G.S. Padhy, Kuwait Oil, and Atul Wasnik and Ahmed Al Shoeibi, Geolog International, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
The Burgan reservoir consists of vertically stacked channel sands along with a fault network connected to the aquifer and contains highly viscous reservoir fluid. This dramatically enhances the water mobility and results in severe premature water breakthrough, bypassing zones of oil. This paper describes the use of real-time geochemical analysis to support geosteering of a smart multilateral well located in one of the highest-potential-flow areas of Kuwait.
Introduction
The Minagish field in Kuwait was discovered in 1959 and is located in the southwestern part of the country. It contains several reservoir intervals in its stratigraphic column, varying from Early Jurassic to Late Cretaceous. The field is situated 12 km northwest of the west Umm Gudair field. The field has been penetrated by more than 180 wells, to contact not only the middle and lower Minagish reservoirs of the Lower Cretaceous but also other shallow reservoirs such as the Mishrif/ Rumaila carbonates and the Wara/Burgan sandstone. The Minagish field structure of the Wara and Burgan formations is a closed elongated asymmetrical anticline oriented in a north/south direction. The top of the Burgan structure is located at approximately 5,500-ft true vertical depth subsea.
Burgan Reservoir. This reservoir is informally divided into the upper and lower Burgan sections. Lower Burgan sands are more extensive and blocky in nature, with few variations in their properties. The lower Burgan reservoir section lies above the oil/water contact (OWC) and is of significance from a hydrocarbon-bearing perspective. Upper Burgan sands are mainly in the form of channel sands, ranging in thickness from a few feet to nearly 45 ft, and they have extensive lateral facies variation. The lower part of the Burgan has active bottomwater drive, whereas the upper part of the reservoir has an edgewater-drive system. The reservoir contains high-permeability sands on the order of a few darcies associated with active faults and has highly viscous reservoir fluid (approximately 40 cp at reservoir conditions). This heterogeneous nature of the reservoir accelerates water movement inside the reservoir and results in premature water breakthrough in the existing vertical wells and in horizontal wells, in spite of maintaining the highest standoff from the OWC.
Advanced Technologies and Solutions for Challenging Drilling Applications
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170566, ’Advanced Technologies and Practical Solutions for Challenging Drilling Applications,’ by M.J. Jellison, SPE, NOV Grant Prideco, and A. Chan, Workstrings International, prepared for the 2014 SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, 25-27 August. The paper has not been peer reviewed.
This paper provides a review of recent technology advancements and addresses practical considerations associated with drillpipe and drillstem components for extreme drilling applications. Recent developments and enhancements in these connection designs, including new higher-strength materials, advanced thread forms, and associated improvements in torsional strength and fatigue performance, are presented. The paper discusses the engineering solutions implemented to overcome the high forces, slip-crushing concerns, and material-strength and toughness considerations for these critical applications.
Third-Generation Double-Shoulder Connection
Since the introduction of the second-generation double-shoulder connection (DSC), the industry trend has continued toward deeper and longer-reach wells, which has dictated the need for drillpipe connections with enhanced mechanical and dimensional characteristics coupled with improved makeup/ breakout speeds.
Consequently, a project was commissioned to design, analyze, laboratory test, and field trial the industry’s first third-generation DSC. A key objective of the project was to improve connection makeup/breakout speeds significantly. Mechanical and hydraulic gains were also dictated on the basis of the industry’s trend toward deeper and longer-reach wells.
Creating Value With Permanent Downhole Gauges in Tight Gas Appraisal Wells
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164039, ’Creating Value Through Permanent Downhole Gauges in Oman Block A Tight Gas Appraisal,’ by Badar Al Busafi, SPE, Robert A. Clark Jr., SPE, and Imtiaz Adil, SPE, BP, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed.
Downhole instrumentation of the Khazzan tight gas appraisal wells provides a rare opportunity to quantify reservoir pressure and temperature dynamics. Several appraisal wells were tested initially for 3–4 weeks and subsequently shut in for approximately 1 year. The continuous downhole-gauge recordings of the resulting pressure buildups were then analyzed to quantify understanding of stimulation effectiveness, reservoir quality away from the wellbore, total producible connected gas, geomechanics, and wellbore hydraulics. This paper examines the pressure-transient analysis (PTA) of one representative well in the field.
Value of Permanent Downhole Gauges in Tight Gas
Dual permanent downhole gauges (PDHGs) were spaced approximately 100 m apart in the upper- completion design, close to the perforations, to fulfill various surveillance requirements and provide the ability to measure gradients in the wellbore in real time. The completion could be tested with PDHGs and surface gauges. A considerable effort was made to ensure that the completions could withstand multiple high-pressure fracture-stimulation jobs. This included installing polished-bore packers and special-thickness tubulars. Preplanning of fracture designs using a variety of friction factors and likely fracture gradients was performed to narrow options and design the completions. Monobore completions were planned to enable running various plugs to isolate the pay intervals as required and to ease the running of logs, tools, and coiled tubing into the wellbore. The size of the completions was optimized for fracturing, not for fluid flow.
Monitoring Hydraulic-Fracturing-Job Performance.
PDHGs have proved to be of considerable value in real-time monitoring of downhole treating pressure in stimulation jobs. For example, early detection of screenout events (before any indication of pressure problems was identified on the surface) has been demonstrated. In one case, a job was altered while pumping and proppant injection was halted before the wellbore actually screened out (Fig. 1). The surface pressure data did not reveal the pending screenout. Only a very small amount of proppant remained in the wellbore after halting pumping operations.
Tactics for Use of Diagnostic Fracture Injection Tests in Unconventional Reservoirs
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163863, ’Diagnostic-Fracture-Injection-Testing Tactics in Unconventional Reservoirs,’ by D.D. Cramer, SPE, and D.H. Nguyen, SPE, ConocoPhillips, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed.
To achieve optimal production from unconventional reservoirs, it is useful to determine the permeability, pore pressure, and state of stress of rock strata. An effective way to derive this information is to conduct in-situ pressure-transient tests. Because injecting fluid into or withdrawing fluid from the pore network of tight rock is difficult, diagnostic fracture injection tests (DFITs) have been used to create an analyzable pressure-decline response and to derive the minimum horizontal stress through fracture-closure identification.
Introduction
Well testing is the technique of establishing fluid flow in the reservoir by either producing from or injecting into a well and then changing or terminating the flow rate to create a transient event, usually by shutting in the well at the surface. The resulting wellbore-pressure response is then evaluated to derive reservoir properties, such as transmissibility and initial reservoir pressure.
Creating a hydraulic fracture bypasses wellbore damage and near-wellbore stress concentrations and connects the wellbore to a significant portion of the reservoir-layer thickness, enabling a representative investigation of reservoir properties.
A typical DFIT sequence is shown in Fig. 1.
Initially, the well is filled with water, with care taken to purge the fluid column of entrained air and gas.
Fines Migration in Fractured Wells: Integrating Modeling With Field and Laboratory Data
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165108, ’Fines Migration in Fractured Wells: Integrating Modeling With Field and Laboratory Data,’ by M. Marquez, W. Williams, and M. Knobles, Chevron, and P. Bedrikovetsky, SPE, and Z. You, SPE, University of Adelaide, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, The Netherlands, 5-7 June. The paper has not been peer reviewed.
Production and drawdown data from 10 subsea deepwater fractured wells have been modeled with an analytical model for unsteady-state flow with fines migration. The simulation results and the field data indicated a good match, within 5%. This paper describes the methodology used to integrate the modeling predictions with field and laboratory data to identify probable causes for increasing skins and declining productivity-index (PI) values.
Introduction
Fines migration is a complex phenomenon that can challenge the economic viability of a project because of well-productivity decline, lower-than- expected hydrocarbon recoveries per well, large capital expenditures to drill and complete additional wells, and high operating costs from suboptimal facility designs. Excessive fines production may also result in equipment erosion and corrosion, formation of hard-to-break emulsions, and plugging of flowlines and surface facilities, all leading to potential hazardous situations.
This paper describes a multidisciplinary approach in which fines-migration modeling has been integrated with field and laboratory data to ascertain whether fines migration may be associated with rapidly increasing skins and declining PI values observed in a subset of deepwater fractured wells. Laboratory studies exhibit fines release and migration during coreflooding and stress testing; the field well-productivity data are well-matched with the mathematical modeling.
Quantitative Trait Loci Mapping for Plant Height in Tobacco using Linkage and Association Mapping Methods
Authors: Cheng Lirui , Yang Aiguo , Jiang Caihong , Ren Min , Zhang Yu , Feng Quanfu , Wang Shaomei , Guan Yongsheng , Luo Chenggang 
Published: February 2015

ABSTRACTPlant height (PH) is one of the most important agronomic traits in tobacco (Nicotiana tabacum L.). To gain a better understanding of its genetic basis, the F2 and F2:3 populations derived from NC82 (P1) and Kang88 (P2) cross were developed. The 193 F2 individuals and 145 F2:3 lines were further used to identify quantitative trait loci (QTL) affecting to PH in tobacco. Two main quantitative trait loci (M‐QTL), designated qPH‐6 and qPH‐12, were mapped on genetic linkage groups 6 and 12, respectively, using linkage mapping (LM). The QTL qPH‐12 was identified as stably expressed in different tobacco generations as well as in various environments. To further verify the chromosomal interval harboring qPH‐12, a total of 96 accessions were subsequently evaluated for PH at two different sites and genotyped by 46 markers evenly distributed on chromosome 12. We found a total of four significant marker‐trait associations that were identified with three different SSR markers (P < 0.01) and could explain 11.7 to 14.8% of the phenotypic variation in PH. One marker, PT55174, showed a significant association with PH (P < 0.01) and explained 13.9 and 14.4% of the phenotypic variation at two different sites. Taken together, our results could provide a new avenue for investigating the QTL in tobacco by combining LM and association mapping (AM), and facilitating our understanding of the inheritance of PH for marker‐assisted selection (MAS) in tobacco.
Genetic and Environmental Variation in a Commercial Breeding Program of Perennial Ryegrass
Authors: Fè Dario , Pedersen Morten Greve , Jensen Christian S. , Jensen Just 
Published: February 2015

ABSTRACTImplementation of genomic selection (GS) for the genetic improvement of forage crops, such as perennial ryegrass, requires the establishment of sufficiently large training populations with high‐quality phenotype and genotype data. This paper presents estimates of genetic and environmental variance and covariance components, obtained in a training population of 1453 F2 families. These families were produced in 2001, 2003, 2005, and 2007, and they were tested at seven locations throughout Europe. Families were cultivated together with commercial varieties that were used as control. Analyses focused on forage yield (green and dry matter) and six traits scored by visual inspection (i.e., rust resistance, aftermath heading, spring growth, density, winter hardiness, and heading date). Data were analyzed with linear mixed models, including fixed effects (trial and control varieties, within year and location), and random effects (breeding values, pedigree or parents, repeated effects of family or parents within location, and within trial environmental effects, to recover interblock information). Results showed very significant genetic variances for all traits, which provide good opportunities for future GS‐based breeding programs. Forage yield showed family heritabilities of up to 0.30 across locations and up to 0.60 within a location. Similar or moderately lower values were found for the other traits. In particular, the heritabilities of rust resistance and aftermath heading were very promising. Genetic correlations between traits were generally low but positive, which increases the potential for multitrait selection.