bluuebunny/crossref_metadata_2025_split huggingface dataset:
Managed-Pressure Drilling: Kick Detection and Well Control
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124664, ’Roles of Managed-Pressure-Drilling Technique in Kick Detection and Well control - The Beginning of the New Conventional Drilling Way,’ by Paco Vieira, SPE, Maurizio Arnone, SPE, and Fabian Torres, Weatherford International, and Fernando Barragan, AGR Group, 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 The paper has not been peer reviewed.
In times when the oil industry is looking for drilling technologies to optimize field development, managed-pressure drilling (MPD) has become an attractive technology, offering considerable benefits. MPD is an optimized drilling process used to control the annular pressure profile more precisely throughout the wellbore. The annular pressure profile is controlled from surface so that the bottomhole circulating pressure (BHCP) is balanced with the pore pressure at all times.
Introduction
Controlled-pressure-drilling (CPD) technology has enabled the commercial development of numerous oil and gas reservoirs worldwide that otherwise would not have been exploited because of technical and/or economic limitations. CPD has become possible only as a result of the integration of many developing technologies that facilitate directional control of the well trajectory, control of the BHCP, and the safe handling of drilling fluids and drill cuttings at surface.
MPD is a drilling technology that uses a pressurizable fluid system and specialized equipment to control the wellbore pressure profile more precisely. Application of this technology optimizes the drilling process by decreasing nonproductive time and mitigating drilling hazards associated with pressure fluctuations that occur when conventional drilling techniques are used.
Many drilling and wellbore-stability-related issues stem from the significant fluctuations in bottomhole pressure (BHP) that are inherent to conventional drilling practices. These fluctuations stem from the stopping and starting of circulation during drillstring connections in jointed-pipe operations; specifically, they result from a change in equivalent circulating density (ECD) that occurs when the pumps are turned on and off. MPD technology, and more specifically, constant BHP (CBHP) as a variation of MPD, is applicable to avoid changes in ECD by applying appropriate levels of surface backpressure, a technique that maintains a CBHP during the complete drilling operation. Additionally, CBHP enables safe application of conventional well-control procedures when unexpected high-pore-pressure formations are encountered. This requires that MPD systems play roles in kick detection and well control.
Kicks in Offshore UK Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119942, ’Kicks in Offshore UK Wells - Where Are They Happening and Why?,’ by J.D. Dobson, SPE, Health and Safety Executive, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.
The first well on the UK continental shelf (UKCS) was spudded 44 years ago, and the area long has been considered a mature province. Despite this, kicks are still a frequent occurrence. Kicks occur in high-pressure/high-temperature (HP/HT) condensate exploration wells and in production wells in depleted subnormally pressured oil reservoirs. They occur during drilling operations and during workover operations. Analysis of data on well incidents has identified where, geographically, kicks occur most frequently.
Introduction
The Health and Safety Executive (HSE) is the regulator for oil and gas drilling on land in UK and on the UKCS. UK health and safety regulations specify which well incidents must be reported by well operators. These reportable incidents are kicks, blowouts both underground and at surface, the unanticipated presence of hydrogen sulfide (H2S), unplanned intersections and near misses, and serious failure of a safety-critical element including the primary pressure-containment envelope of the well.
The purpose of the regulation is not merely to inform HSE of the incident, but also to allow the regulator to spot trends in the industry that may not be noticeable to individual well operators and drilling contractors. The full-length paper focuses on kicks and their consequences, rather than on other incidents, but with the intention of sharing the overview more widely.
Exploration on the UKCS began in the mid-1960s, with the first major discovery in December 1965. In a mature oil and gas province such as the North Sea, it might be assumed that the frequency of kicks during drilling or workover operations would be decreasing. This study indicates otherwise.
Approach
The study is based on a review of all kicks and blowouts reported for the area in the 10 years since 1999. The intent in reviewing the data is to consider which areas of the UKCS, and which type of operation, carry the greatest risk of kicks. A second, more detailed, review was carried out for incidents in the 3-year period 2006 to 2008, which examined each reported incident in more detail, reviewing the circumstances under which the kick occurred and, where possible, identifying the underlying cause.
Areas of the UKCS
Over the last 44 years, wells have been drilled in each of a variety of discrete geographical and geological areas off the coast of the UK (Fig. 1). Although wells have been drilled in all the basins shown, the vast majority of the drilling activity on the UKCS has been limited to six discrete geological areas—southern North Sea, central North Sea, Moray Firth, northern North Sea, West of Shetland, and Irish Sea. It is in these areas that the reported incidents considered in this study have occurred.
Driving Project Efficiency and Cost Control in the Upstream Oil and Gas Industry
Authors: Bleackley David , Strathman Michael S. 
Published: February 2015

Management
Today’s upstream oil and gas companies are focused on keeping pace with growing demand and driving incremental revenues by exploiting hydrocarbon reserves. This trend is particularly marked in fast-emerging, dynamic new markets such as Brazil, Russia, India, and China where operators are aggressively pursuing new market opportunities both domestically and further afield.
These opportunities include finding and developing new reserves, and equally extending the production life of existing assets. Achieving these goals presents a range of related challenges to operators.
New exploration has the inherent risk of finding new reservoirs, can be very expensive, and often takes place in challenging locations. The Macondo well blowout in the Gulf of Mexico has painfully reminded the industry of the risk and challenges. By extending the life of existing assets and production systems, the risk of the resource base is minimized and the location challenges are at least known. Oil and gas production is notoriously complex to manage and difficult to optimize due to the sometimes unpredictable nature of reservoirs. As with exploration, carefully managing expenses is always a challenge, even more so as operational costs continue to rise, while the internal expertise becomes increasingly scarce as a experienced workforce retires.
Together, these trends are stimulating demand for a potent combination of technology and talent. Operators require high-quality process engineering solutions to address complexity of operations, which are accurate, robust, easy to use, and help drive user productivity.
The best of these solutions are capable of delivering engineering efficiency throughout the design lifecycle whether they are used to help achieve minor modifications and revamps to facilities, or to deliver efficiency across the world’s largest mega-projects.
Discipline in Capital Spending and Managing the Asset Lifecycle
Getting to “first oil” as quickly as possible is important, but choosing the right assets to develop is equally critical. Fortunately, to support these business objectives operating companies can now draw on a range of process engineering, cost estimating, and integrated engineering solutions.
Engineering technology helps operators throughout the oil and gas industry control capital spending and stay on schedule when designing and building assets. In this capital-intensive business, getting oil reserves into production sooner enables organizations to achieve their return on investment objectives.
Alternative Initial Responses to Kicks Taken During Managed-Pressure Drilling
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 128424, ’Evaluation of Alternative Initial Responses to Kicks Taken During Managed-Pressure Drilling,’ by Majid Davoudi, SPE; John Rogers Smith, SPE; Bhavin M. Patel, SPE, and Jose E. Chirinos, SPE, Louisiana State University, prepared for the 2010 IADC/SPE Drilling Conference and Exhibition, New Orleans, 2-4 February. The paper has not been peer reviewed.
An industry-supported research project completed its evaluation of alternative initial responses to kicks taken during the constant-bottomhole-pressure (CBHP) method of managed-pressure-drilling (MPD) operations. This first phase was intended to provide a basis for comprehensive, reliable well-control procedures for MPD operations. Three responses were concluded to have general application: increasing casing pressure until flow out (Qout) equals flow in (Qin), shutting in the well, and adapting an MPD pump-shutdown schedule to detect and shut in low-rate kicks. Selection of the most practical response depends on well conditions and the equipment being used. Potential advantages of and constraints on the use of these responses were summarized.
Introduction
MPD is an evolving technology used to address drilling problems encountered when using conventional, hydrostatically overbalanced drilling methods. MPD is defined by the International Association of Drilling Contractors (IADC) as a “drilling process used to control precisely the annular pressure profile throughout the wellbore.” The definition also points out that an influx of formation fluids (i.e., a kick) “will be safely contained using an appropriate process.” Establishing the basis for identifying an appropriate process or processes was the focus of this study.
CBHP Method of MPD. This method keeps the wellbore pressure relatively constant at a selected depth. This constant wellbore pressure is achieved by adjusting the surface pressure on the annulus to offset changes in the wellbore frictional pressure losses as the pump speed is varied or stopped, such as when making connections. The ability to adjust the surface pressure on the annulus is provided by a rotating control device (RCD), such as a rotating control head, by closing the annulus and directing flow through an adjustable drilling choke. Therefore, the CBHP method of MPD avoids the wellbore-pressure fluctuations that occur when starting and stopping pumps in conventional operations. Consequently, it allows drilling within a narrower “window” between fracture and pore pressures than is safe or practical with conventional methods.
The Effect of Rotating Control Devices on the Incidence of Blowouts: Onshore Texas
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133019, ’The Impact of Rotating Control Devices on the Incidence of Blowouts: A Case Study for Onshore Texas, USA,’ by C.J. Jablonowski, SPE, and A.L. Podio, SPE, University of Texas at Austin, originally prepared for the 2010 SPE Trinidad and Tobago Energy Resources Conference, Port-of-Spain, Trinidad, 27-30 June. The paper has not been peer reviewed.
Rotating control devices (RCDs) are used to provide a closed circulating system. Conventional wisdom suggests that drilling with RCDs improves kick detection and suggests that fewer blowouts should occur when this equipment and related practices are deployed. The authors of the full-length paper find consistent statistical evidence, across a variety of regression models and variable specifications, that the use of RCDs decreases the incidence of blowouts.
Introduction
RCDs and related equipment are used to provide a closed circulating system. A closed system enables under-balanced operations (UBOs) and managed-pressure drilling (MPD). These drilling practices can facilitate drilling in otherwise undrillable formations, reduce formation damage, and reduce drilling problems such as blowouts. There is considerable literature on the technical aspects of closed systems, and industry associations and regulating authorities have promulgated guidelines for their use and for related practices.
Conventional wisdom suggests that drilling with RCDs improves kick detection and thus fewer blowouts should occur when this equipment and related practices are deployed. This outcome could be a result of active management of the pressure profile, and/or a faster response to influx where the closed system acts as a mode of initial well control before activating the blowout preventers (BOPs). Some insurers require RCDs on the basis, in part, of this perception. These views notwithstanding, there is no published analysis that demonstrates a definitive link between the use of RCDs and the incidence of blowouts. The purpose of the full-length paper is to address this gap. The authors use regression analysis to test the hypothesis that the use of RCDs decreases the likelihood of blowouts.
Data Sets
Previous studies have investigated the incidence of blowouts and have produced useful statistics and trends, and there are case studies that analyze individual blowout events in great detail. To implement the regression analyses proposed in the full-length paper, a new detailed data set is required on blowouts and on the hypothesized incidence factors. To this end, a data set was organized for onshore drilling activity in Texas during 1995–2007.
Comments: Optimism Reigns
Authors: Donnelly John 
Published: February 2015

Editor's column
This year promises to be another one of healthy upstream spending. Perhaps the only thing that can derail the optimistic outlook is the global economy.
Strong oil prices will lead 2012 worldwide E&P spending to a record high of USD 598 billion, according to a new report by Barclays Capital, which annually tracks oil and gas industry upstream spending. That reflects a 10% increase over 2011 E&P spending, which also set a record, according to the survey of 350 oil and gas firms. But Barclays notes that the rate of growth will be slower than last year’s because of the global economic uncertainty that is hanging over most industries. If that uncertainty were to disappear, the E&P forecast would appear very conservative, the report said.
Spending is forecast to increase by 8% within North America and by 11% outside of it. The increase in spending is across the board, with strong increases in the former Soviet Union and CIS countries (42%), Latin America (21%), and Africa (14%), and smaller increases in Europe and the Middle East. Latin America is seeing aggressive E&P spending by Brazil’s Petrobras, Colombia’s Ecopetrol, and Mexico’s Pemex. Mexico is trying to reverse rapidly declining production rates and Colombia is trying to jump-start an upstream profile that has largely languished since the mid-1990s. Brazil is forging ahead with its promising pre-salt development. Other large upstream spenders this year are expected to be ExxonMobil, PetroChina, Lukoil, and Chevron.
The survey said that oil and gas companies were basing their 2012 capital spending budgets on an average oil price of USD 87 a barrel for West Texas Intermediate and USD 98 a barrel for Brent. Global benchmark Brent was set to finish 2011 at its highest annual average price, in both real and nominal terms, since the modern oil industry began, according to an IHS Cambridge Energy Research Associates analysis released just before the end of the year. Continued strong global demand, concerns about sup-ply constraints in some regions, and higher production costs all combined to support the record-level price. Brent was expected to average USD 111/bbl last year.
In short, the supply/demand balance and higher labor and material costs are driving the highest prices. Upstream production in challenging areas is also a factor. Drilling in North America should continue to be strong, although low natural gas prices have caused companies to shift away from gas and toward liquids plays. Companies responding in the Barclay’s survey said that the biggest factor in determining their North American activity was oil prices, followed by gas prices and then cash flow. Spending growth in North America is forecast to last until at least 2015.
The Tantalizing Promise of Oil Shale
Authors: Beckwith Robin 
Published: February 2015

Oil Shale
A vast energy treasure lies within an 18,963-sq-mile area of Colorado, Utah, and Wyoming: an estimated 4.28 trillion BOE of in-place resources of oil shale, according to US Geological Survey (USGS) research geologist Ronald Johnson. He presented the new assessment at the 31st Oil Shale Symposium, held mid-October 2011 at the Colorado School of Mines.
In other countries, while far fewer oil shale resources are thought to exist, their presence is nonetheless formidable. China contains an estimated 333 billion BOE; Russia, 248 billion BOE; Democratic Republic of Congo, 100 billion BOE; Jordan, 90 billion BOE; Brazil, 82 billion BOE; Italy, 73 billion BOE; Morocco, 53 billion BOE; Australia, 32 billion BOE; and Estonia, 16 billion BOE. Israel indicated at the 30th Oil Shale Symposium that its resources may be as much as 250 billion BOE.
The CIA World Factbook estimates 2011 world proved reserves of crude oil at 1.47 trillion bbl. Total annual production of oil shale in the only three countries today where it is exploited for commercial use is 73% less than daily worldwide crude oil production of approximately 86.74 million B/D.
With oil shale estimates vastly overshadowing those for crude oil, why does oil shale remain a scarcely touched resource?
The Bottom Line
“In-place resources” and “proved reserves” have markedly different meanings. The former speaks of potential; only the latter indicates the existence of hydrocarbons that can be exploited economically. “No attempt was made to estimate the amount of oil that is economically recoverable,” explains the USGS in the introduction to its 2011 assessment of US Greater Green River Basin oil shale resources, “because there has not yet been an economic method developed to recover the oil from … oil shale.” This statement might be amended, says Center for Oil Shale Technology and Research (COSTAR) director Jeremy Boak, to reflect a view that current producers might suggest, ’whereby, while methods have been developed to recover the oil from oil shale, none has yet demonstrated commercial production of Green River formation shale oil.”
Taking Advantage of Vessels of Opportunity
Authors: JPT staff _ 
Published: February 2015

Colin Buchan’s job at Shell is to find ways to find other vessels of opportunity—offshore construction vessels adapted to do what drilling rigs are not so well equipped to do faster and for less.
I think it was one size fits all before. A drilling rig is what you used,” Buchan said. “Now there are more options there to pick from.” His job title, well delivery manager for floating hoist at Shell, is an indication of what the options look like. Hoisting is a reference to many devices lowered to the bottom using a wireline, rather than sending them down to the well through a riser.
“We’re not seeing drilling rigs going out of business,” he said. But the high cost of repairing wells using drilling rigs and their limited number compared with the number of subsea well completions both argue for new approaches.
The goal is to do as much as possible to improve production from subsea wells by expanding the roles of vessels now doing deepwater construction work, such as installing manifolds or anchors on the seafloor. Construction vessels would play a growing role, from wellsite preparation through completions and maintenance, to plugging and abandonment.
Wireline well interventions have become common in the North Sea and will be moving to deep water. Offshore Brazil construction boats are coming in behind drilling rigs to complete wells by installing production hardware, such as subsea trees to control the flow and connecting them into the production system.
The high cost of drilling, completions, and repairs has a direct bearing on the ultimate output of reservoirs. To ensure the ultimate return exceeds the ultimate cost over the life of the well, operators will only develop discoveries with 150 million bbl of recoverable reserves or more into production, said Keith Millheim, managing director of Nautilus International. He, along with others, has started a pair of companies to commercialize a self-standing riser technology that he says will reduce costs sufficiently to change how deepwater fields are managed.
One of the companies, MEPS First Oil, is focused on reducing the cost of extended well tests and reducing the time it takes to begin production. More testing could reduce the risk that a field will fall short of expectations because of an incomplete understanding of a reservoir.
Significantly reducing the cost of field evaluation, construction, maintenance, and production could expand the universe of deepwater fields that can be profitably produced. Millheim estimates that there are 3,000 deepwater fields globally with less than 50 million bbl of reserves that cannot be produced without shifting the cost curve to allow more testing, maintenance, and artificial lift to be used.