bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comments: 2014 Outlook
Authors: Donnelly John 
Published: February 2015

Editor's column
Signs point to sustained strong oil prices this year, levels that will continue to support upstream unconventional projects in North America and elsewhere.
North Sea Brent and West Texas Intermediate (WTI) crude oil, the world’s two key benchmark prices, averaged around USD 108/bbl and USD 97/bbl, respectively, in 2013. And most price forecasts for 2014, which began emerging from analysts and investment houses in the fourth quarter, predict similar price levels in the new year. The wild card in that scenario, however, is the growth of non-OPEC supply and production levels from Libya and Iraq, which are difficult to anticipate. North American supply is expected to continue its upward swing, and significant increases in Kazakhstan are also forecast. Commercial production at Kashagan, Kazakhstan’s giant Caspian Sea oil field, is expected to begin in the first half of the year. The field was discovered in 2000, one of the largest finds in decades, but development has faced rising costs and numerous delays.
US crude oil production is expected to rise again this year. The US Energy Information Administration (EIA) says US crude output averaged 7.5 million BOPD in 2013 and will average 8.5 million BOPD in 2014. When US production hit 8 million BOPD in November, it was the highest monthly output level since 1988. The EIA believes that growth shows no signs of stopping, with US crude production forecast to come to a high of 9.6 million BOPD in 2016, a level not seen since 1970.
The EIA sees non-OPEC production growing from 54.2 million BOPD in 2013 to 55.9 million BOPD this year. Most of the non-OPEC production growth will be from US onshore tight oil formations and Canadian oil sands, with smaller increases from Africa, South America, and Asia. That will continue to put pressure on OPEC, which has watched its market share erode recently. OPEC countries are expected to produce 29.4 million BOPD this year, compared with an average of 30.3 million BOPD in 2013.
Oil prices are notoriously hard to predict. Some of the same analysts who forecasts strong prices this year predicted a sharp drop in oil prices in 2013, something that never happened. Nevertheless, there seems to be a consensus that Brent and WTI will remain near their current levels in the new year.
A survey of price forecasters published by Petroleum Intelligence Weekly in December showed most analysts seeing Brent in a USD 100-110/bbl range for the near year, and WTI at around USD 90-100/bbl. The survey of 10 analysts at consulting groups and investment banks shows Brent crude averaging USD 106/bbl for 2014, while the average for WTI is USD 97/bbl. Forecasters were optimistic that Libyan output would recover after months of disruption, and that a strengthening global economy would help absorb oil supply growth. JPT
Modeling Options for Drill-Cuttings Management
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164983, ’Modeling the Options for Managing Drill-Cuttings Piles on Decommissioning,’ Sean Hayes, SPE, Genesis, and Liz Galley, CNR International, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16-18 April. The paper has not been peer reviewed.
Advances in modeling techniques allow quantitative prediction of long-term trends in cuttings-pile characteristics and environmental risks, providing firm direction in mitigating risks. Modeling involving fluid dynamics, soil mechanics, scientifically verified 3D dispersion modeling, contaminant degradation, and seabed recovery was used in several scenarios: the extant pile, moving the pile across the seabed using suction pumps, backflush discharges related to retrieving the pile, and disturbance from remaining jacket footings ultimately falling into the pile after several hundred years.
Introduction
The Murchison platform is located in 156 m of water in the northern North Sea and is operated by CNR International. Drilling operations had been conducted at the field since the 1970s, ending in 2008. Discharges of drill cuttings and drilling mud have resulted in the formation of a drill-cuttings pile beneath the platform jacket structure. Between 1980 and 2000, oil-based muds were used and oil-contaminated discharges took place in line with normal permitted operations, and the cuttings pile now in place is consequently oil-contaminated. Fig. 1 shows the location of the Murchison platform and the local bathymetry, and Fig. 2 illustrates the jacket base.
The Convention for the Protection of the Marine Environment of the North- East Atlantic (OSPAR) Commission Recommendation 2006/5 sets out a management regimen for such oily-cuttings piles, depending largely on thresholds against which the level of pollution attributable to a historical cuttings pile may be measured in order to determine whether the level of pollution could be significant. An assessment of the Murchison pile was submitted to the commission in 2008 as part of the regulator’s implementation report, concluding that the Murchison pile did not exceed the relevant criteria and that it could be left to degrade by natural processes. For those piles that can be demonstrated to have characteristics below OSPAR thresholds, the recommendation states that no further action is required and that the cuttings piles may be left in situ to degrade naturally.
The Murchison field is in the process of being put forward for decommissioning, and the assessment made in 2008 regarding the rate of oil loss and the persistence footprint has been re-evaluated. By use of records of the discharges made from the platform, survey data from the Murchison cuttings pile, and industry data sources on the composition of drill-cuttings piles, a model of the existing pile has been constructed and used to understand the present condition and long-term fate of the pile.
Technology Focus: Drilling Technology (February 2010)
Authors: Menand Stephane 
Published: February 2015

Technology Focus
Many discussions have taken place recently about the excessive nonproductive time (NPT) incurred in the drilling industry today and about the use of cutting-edge technology. From these discussions, it is believed that the drilling industry relies much more on cutting-edge technology than optimized-drilling practice to address downhole problems. Indeed, too many failures or dysfunctions still happen and are unexplained, even in supposedly simple wells, because of the lack of knowledge of what is happening downhole. Without having identified and understood the real cause of a given problem, one solution is to use a new technology that may overcome the problem without curing it. For economic reasons, cutting-edge technology often is used in complex and high-cost-environment drilling operations. For example, high-end rotary-steerable systems combined with downhole vibration measurements transmitted at high-speed along wired pipes enable achieving very complex and accurate drilling trajectories in geosteering. However, this accuracy is achieved as a result of the measurements but without necessarily understanding the drilling fundamentals and the physical phenomena involved. This method is a costly trial-and-error procedure. Indeed, in this complex-drilling operation, drillstring mechanics and hydraulics are very complicated, and physical models sometimes fail to predict and reproduce the actual drilling process. The solution to reduce NPT could be to use instrumentation and new technology in allegedly simple or basic wells to:
Understand the new-technology function and performance
Validate the physical models (mechanics and hydraulics)
Improve fundamental drilling practices
Even though this high-end technology used in low-cost environments sounds contradictory, it should clarify our understanding of what is happening downhole to improve the overall drilling efficiency. Once fundamental drilling mechanics and processes are completely understood, one can go further in complex-drilling operations with the same technology and validated models. And as the proverb says, “Don’t put the cart before the horse!”
Drilling Technology additional reading available at OnePetro: www.onepetro.org
SPE 124142 • “Comprehensive Drilling Model Analyzes BHT Parameters” by A.W. Iyoho, SPE, Shell, et al.
SPE 123374 • “Statistical Method for Detection of Poor Hole Cleaning and Stuck Pipe” by Thor O. Gulsrud, SINTEF Petroleum Research, et al.
SPE 124631 • “Advanced Automatic Control for Dual-Gradient Drilling” by øyvind Breyholtz, International Research Institute of Stavanger, et al.
SPE 121752 • “Modeling the Effect of a Downhole Vibrator” by Ken Newman, NOV CTES, et al.
Using MPD To Drill Wells With Narrow Operating Windows: Pressure and Temperature Effects
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119882, ’Drilling Wells With Narrow Operating Windows Applying the MPD Constant Bottom Hole Pressure Technology - How Much the Temperature and Pressure Affects the Operation's Design,’ by M. Arnone and P. Vieira, SPE, Weatherford International, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.
Narrow pore-/fracture-pressure-gradient margins translate to a real drilling-hazard scenario where a slight change in the bottomhole-pressure (BHP) conditions can lead to an increase in the nonproductive time (NPT) because of time spent in solving possible fluid losses or gas kicks. In specific and nonrare cases, deep formations with small gaps between pore and fracture pressure are undrillable with conventional drilling practices. Constant BHP (CBHP), one of a number of variants of managed-pressure drilling (MPD), enables staying in the window between pore- and fracture-pressure gradients.
Introduction
The International Association of Drilling Contractors (IADC) recently has updated the definition of MPD. MPD is an adaptive drilling process used to precisely control the annular-pressure profile throughout the wellbore. The objectives are to ascertain the downhole-pressure-environment limits and to manage the annular-hydraulic-pressure profile accordingly. MPD is intended to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be contained safely by use of an appropriate process.
The IADC definition for MPD also includes some key technical notes:
The MPD process employs a collection of tools and techniques that may mitigate the risks and costs associated with drilling wells that have narrow downhole environmental limits by proactively managing the annular-hydraulic-pressure profile.
MPD may include control of backpressure, fluid density, fluid rheology, annular fluid level, circulating friction, and hole geometry, or combinations thereof.
MPD may allow faster corrective action to deal with observed pressure variations. The ability to control annular pressures dynamically facilitates drilling of what might otherwise be economically unattainable prospects.
At present, there are four recognized variations of MPD.
CBHP: Narrow pore- and fracture-pressure-gradient windows present a drilling hazard. When the hole is being drilled or circulated, the additional circulating friction to hydrostatic head can result in formation fracture. When circulation is ceased, the hydrostatic pressure is below the formation pore pressure. A kick/loss situation ensues, and NPT, lost-fluid cost, and health, safety, and environment (HSE) risk escalate. This variation is applicable to avoid changes in equivalent circulating density (ECD) by applying appropriate levels of surface backpressure, a technique that maintains CBHP during the complete drilling operation.
Multistation Analysis of MWD Magnetic Directional Surveys
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125677, ’Minimum Requirements for Multi-Station Analysis of MWD Magnetic Directional Surveys,’ by Erik Nyrnes, SPE, StatoilHydro ASA; Torgeir Torkildsen, SPE, SINTEF Petroleum Research; and Harry Wilson, Baker Hughes, originally prepared for the 2009 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Manama, Bahrain, 26-28 October. The paper has not been peer reviewed.
Multistation analysis (MSA) is a technique widely used in measurement-while-drilling (MWD) directional surveying to provide additional quality control and to correct for systematic errors. Although the potential of the method to enhance survey quality has been demonstrated, experience has shown that MSA can produce unstable solutions and poorly interpretable results. The full-length paper presents a set of fundamental requirements that have to be fulfilled to ensure the correct application of MSA. The requirements consist of a set of mathematical rules and corresponding acceptance limits.
Introduction
MSA is a more-powerful survey-quality-evaluation method than conventional single-station calculations. It makes it possible to identify and quantify different types of systematic errors, providing greater proof of whether or not surveys meet specification. Where systematic errors of significant magnitude are identified, they can be corrected for. However, the ability of MSA to correct failed surveys and provide increased confidence that surveys meet their stated specification is limited by several factors. For example, only a limited number of systematic-error terms can be estimated accurately for a given set of survey data, this being dependent on factors such as the geometry of the wellbore, the number of survey stations, and the number of estimated error terms. In current common practice, it is not always clear how the application of MSA to a given survey log affects its status with respect to its own accuracy specification.
Improved accuracy may be claimed, but the link between MSA data manipulation and the error model that quantifies accuracy usually is not explicit.
In the full-length paper, a basic MSA methodology suitable for adoption across the industry is proposed. The methodology consists of a set of requirements and acceptance limits that have to be fulfilled when applying MSA. The requirements can be applied to any survey log to determine which error terms can be estimated validly. In addition, mechanisms are included to ensure that the random-noise level in the survey data is of tolerable magnitude. The requirements are easy to apply and straightforward to implement and, therefore, should be easily communicated throughout the survey industry.
Technology Focus: Offshore Facilities (February 2010)
Authors: Ball Ian G. 
Published: February 2015

Technology Focus
In the relentless quest for reserves replacement, global upstream oil and gas operators continue their migration into deeper waters. The latest generation of subsea production facilities is widely applicable with confidence when specified correctly. However, selecting the optimum associated surface-processing facilities, and how best to link them to the subsea system, generally requires a more location-specific deliberation.
While field developments in established deepwater provinces such as the Gulf of Mexico, Brazil, and west Africa continue to expand, new deepwater regions such as in Southeast Asia and the Bay of Bengal off the east coast of India are being opened. However, even the well-established structural-design standards evolved by the industry for the Gulf of Mexico were recently shown by hurricanes Katrina and Rita to need a further overhaul in the way they are applied.
An unprecedented scarcity of equipment and resources suitable for deepwater drilling and construction also has driven up the unit costs and project durations sharply for deepwater developments in recent times.
All these factors have, collectively, encouraged the industry to seek and qualify an expanded and more flexible range of modular and integrated field-development solutions that can be optimized and applied more quickly in a reliable and cost-effective manner for the wider spectrum of deepwater challenges ahead. Among the most notable is the industry’s first floating-drilling, -production, -storage, and -offloading-based system that went into operation in deep water offshore west Africa during the past year.
These innovative floating and subsea deepwater solutions, when demonstrated by analyses and tests to be truly fit for purpose, are, however, only of meaningful value if upstream operators respond proactively with practical ways to apply them in the field quickly and confidently.
Offshore Facilities additional reading available at OnePetro: www.onepetro.org
OTC 19929 • “The Greater-Plutonio Riser Tower” by Daniel de la Cruz, BP, et al.
OTC 19857 • “Tahiti Spar as a Wet-Tree Concept” by P. Griffin, Chevron, et al.
SPE 124158 • “Northwest Hutton: Decommissioning the UK North Sea’s First Large Platform With a Fixed Steel Jacket: Topside Removal” by Chris R. Farrow, BP, et al.
Practical Solutions for Pressure-Transient Responses of Fractured Horizontal Wells in Unconventional Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125043, ’Practical Solutions for Pressure-Transient Responses of Fractured Horizontal Wells in Unconventional Reservoirs,’ by M. Brown, SPE, and E. Ozkan, SPE, Colorado School of Mines; R. Raghavan, SPE, Phillips Petroleum Company (Retired); and H. Kazemi, SPE, Colorado School of Mines, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.
An analytical trilinear-flow solution was developed to simulate the pressure-transient and production behavior of fractured horizontal wells in unconventional reservoirs. This solution provides an alternative to rigorous solutions, which can be cumbersome to evaluate. These solutions provide insight about and the conditions leading to these flow regimes. Identifying these flow regimes is important to characterize unconventional reservoirs from pressure-transient tests.
Introduction
Although it is possible to develop detailed analytical models to represent transient fluid flow toward a multiple-fractured horizontal well in tight unconventional reservoirs such as shale, the difficulties of these models are the increased computational requirements, the implicit functional relationships of key parameters, and the inconvenience of their use in iterative applications. Despite the complex interplay of flow among matrix, natural fractures, and hydraulic fractures, the key characteristics of flow convergence toward a multiple-fractured horizontal well may be preserved in a relatively simple, trilinear-flow model. The basis of the trilinear-flow model is that the productive lives of fractured horizontal wells in tight formations are dominated by linear-flow regimes.
Physical Model and Assumptions
For hydraulically fractured horizontal wells in unconventional reservoirs with microdarcy matrix permeabilities (such as shale), the contribution of the reservoir beyond the stimulated volume usually is negligible. Hydraulic fracturing also changes the stresses in the fracture-drainage area, which may create or rejuvenate natural fractures near the horizontal well. Under these conditions, flow convergence is mainly in the linear direction perpendicular to the surfaces of the hydraulic fractures, and, despite the complex interplay among matrix, natural fractures, and hydraulic fractures, a relatively simple, trilinear-flow model may represent the key characteristics of flow toward a multiple-fractured horizontal well.
The trilinear-flow model couples linear flows in three contiguous flow regions, as shown in Fig. 1: the outer reservoir beyond the tips of the hydraulic fractures, the inner reservoir between hydraulic fractures, and the hydraulic fracture. Each region can have distinct properties. The inner reservoir may be homogeneous or naturally fractured, and the hydraulic fractures may have finite conductivity.
Installation of a Damaged-Control-Line Replacement-Safety-Valve System in a North Sea Well
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 134500, ’A Case History: The Installation of a Damaged- Control-Line Replacement-Safety-Valve System in a North Sea Well,’ by T. Barratt, B. Goldsworthy, SPE, and S. Hamilton, Shell UK, and R. Lacy, SPE, M. Taylor, A. Ross, S. Mackie, SPE, E. Calzoncinth, S. Dennistoun, and J-L. Jacob, Weatherford International, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.
Well GA-03 on the Gannet platform in the UK sector of the North Sea developed a blockage in the safety-valve control line that rendered the existing tubing-retrievable subsurface safety valve (TRSSSV) inoperable. Also, the sealbores inside the valve were scarred and damaged badly enough that a conventional wireline safety valve would not seal. A method was examined that would allow replacement of the safety valve and control line without pulling the production tubing or making changes to the wellhead configuration.
Introduction
Well GA-03 was spudded from the Gannet platform in 1994 and completed as a horizontal oil producer in 1995. In 1997, the water cut reached 95% and the well was shut in. In 2003, the well was reopened after a successful coiled-tubing (CT) water-shutoff intervention. In 2005, the water made production uneconomical again and a CT-drilled sidetrack of 257 ft completed with a slotted liner into the top of the reservoir was carried out.
In August 2007, the TRSSSV failed and was locked open. Many attempts were made to set an insert wireline-retrievable subsurface safety valve (WRSSSV), but the top seal stacks were damaged each time and it was not possible to get them to hold control-line pressure. This inability to obtain a pressure test indicated damage to the seal bores and to the inside of the tubing directly above and below the TRSSSV, although it was not possible to see the damage on caliper/video logs.
In December 2007, a 43-ft-long three-piece straddle assembly, including a 23/8-in. TRSSSV with a filter on the control-line port, was run across the existing locked-open TRSSSV. The packers were spaced out above and below the safety valve to be in what was assumed to be undamaged areas of tubing. The control-line pressure activated the TRSSSV by pressuring the whole annular volume of the straddle and, thus, the new TRSSSV through the filter. Although this system was unlikely to be a long-term solution, it was considered a good way to get the well back on stream in the short term. This safety-valve system functioned, despite losing control-line fluid for much of the time that it operated; this fluid loss required the well to be on its own fluid pump with frequent fluid top-ups, although once the well was flowing, the rate of losses reduced to near zero.