bluuebunny/crossref_metadata_2025_split huggingface dataset:
Taking a Fresh View of Riser Margin for Deepwater Wells Potentially Boosts Safety
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22889, ’A Step Change in Safety: Drilling Deepwater Wells With Riser Margin,’ by Robert Ziegler, SPE, Petronas, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
Riser margins were abandoned when fluid columns in risers became too long with increasing water depth accessed when floating drilling units with subsea blowout preventers (BOPs) moved to deep water. Removing risers in disconnect events means wells go underbalanced and rely on BOPs to contain wellbore pressure. With the advent of a simple retrofit dual-gradient system based on partially evacuating the riser by pumping mud returns back to surface from an outlet in the riser, riser margin in the form of an overbalanced well can be reintroduced in many cases.
Setting the Scene
Deepwater drilling has a multitude of unique challenges.
Water depth: Cold temperatures combine with long fluid columns with high pressures at the seabed most often sitting squarely in the hydrate-formation zone. Ocean forces put mechanical stresses on the riser system. Perhaps most challenging, a highly complex hydraulic system, the subsea BOP, must be operated remotely in a very hostile environment.
Deepwater depositional environment: This leads in most cases to a very tight margin between formation strength and pore pressure.
Existing emergency procedures: In the case of a loss of position of the rig, a complex sequence of disconnecting from the BOP must be initiated. The BOP also needs to be closed before the lower marine riser package is disconnected and must reliably seal the wellbore because, by removing the riser, the well becomes underbalanced because primary well control by mud weight is lost.
Status Quo
The solutions that the industry has embarked on to address these challenges have often been overly complex evolutionary developments instead of clean-sheet designs, leading to high costs and an unavoidable increase of mechanical failure modes. The best example for this approach is the current generation of subsea BOPs. In their functionality, these devices remain close to the original patent in 1929; but, today, they are very large, complex, and heavy (350 tons) devices that require an enormous amount of maintenance and testing.
Even if a BOP is closed on an inflow in time so the flow is entirely contained below the BOP, circulating out this kick by an established “driller’s method” very often proves to be difficult if not impossible. This is mainly related to two factors. One is the risk of hydrate formation. The moment gas and free water are mixed in the BOP area, hydrates will form. The second factor is the narrow margin between fracture gradient and pore pressure. Very often, the formation is not able to support the backpressure created by the choke line friction, and circulation without losses can never be established.
Technology Focus: High-Pressure/High-Temperature Challenges (April 2013)
Authors: Payne Mike 
Published: February 2015

Technology Focus
High-pressure/high-temperature (HP/HT) operations are projected to double in well count over the next 6 years. In addition to this steady increase in activity, the conditions in these extreme wells will also become more severe as well depths, pressures, and temperatures also trend higher.
In the Norwegian sector of the North Sea, one of the most extreme HP/HT wells in that region has been drilled. As a means of addressing the challenges posed by tight pore-pressure/fracture-gradient windows, managed-pressure-drilling (MPD) technologies were applied to minimize the effects of pressure fluctuations that occur in standard drilling. The MPD technology, the so-called “backpressure” technique, uses the controlled application of surface backpressure when mud circulation stops to replace the incremental equivalent-circulating-density effects present when mud circulation is active. In addition to precise management of the pressure profiles imposed on the formations, this active circulation and pressurization technology increases the accuracy with which unwanted influxes can be detected. Influxes as small as 0.25 bbl can be identified, thereby improving kick-detection capability.
In south Louisiana, the largest onshore drilling rig in the world has been drilling the deepest well ever drilled in that state, an accolade that is impressive given the long heritage that Louisiana boasts with regard to HP/HT wells. Several operators are active in this area, with a new state depth record being set by one well reaching a depth of 25,500 ft. Another HP/HT prospect in this area is permitted for a total depth of 29,000 ft. In another part of the world, Malaysia, operators are planning ultra- HP/HT operations with bottomhole static temperatures above 430°F. This includes more than a dozen prospects in peninsular and east Malaysia. This region may prove to be one of the most active areas for HP/HT operations in the near future.
HP/HT drilling and completions require careful planning, attention to detail, robust testing and qualification programs, strong quality control, and thorough contingency planning. The ongoing industry successes addressing HP/HT challenges globally are testament to the focus that our industry brings to bear as these challenges are met and addressed.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 158851 Testing and Perforating in the HP/HT Deepwater and Ultradeepwater Environment by Curtis Wendler, Halliburton, et al.
SPE 154768 Developing Novel Wellbore-Heat-Transfer Strategies for HP/HT Wells by Mohd Amin Shoushtari, Universiti Teknologi Petronas, et al.
SPE/IADC 163557 Annular-Pressure-Buildup Analysis and Methodology With Examples From Multifrac Horizontal Wells and HP/HT Reservoirs by Jonathan Bellarby, Canmore Consulting, et al.
Design Advances of Ultra-HP/HT Completion and Production Tools
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166231, ’Design Verification, Optimization, and Validation of Ultra-HP/HT Completion and Production Tools,’ by Guijun Deng, James Doane, Antonio Ruffo, SPE, Goang-Ding Shyu, and Scott Collins, SPE, Baker Hughes, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September- 2 October. The paper has not been peer reviewed.
Ultra-high-pressure/high-temperature (HP/HT) wells are currently being drilled in the Gulf of Mexico on the shelf and in deep water. Many of these wells have a total depth in excess of 30,000 ft, where reservoir pressures and temperatures approach 30,000 psi and 500°F, respectively. There are currently few packer-type devices that are considered fit for service in these applications. This paper gives an overview of the latest developments in how advanced finite-element- analysis (FEA) tools are used to verify, optimize, and validate ultra- HP/HT completion and production tools.
Introduction
The classification of HP/HT reservoirs has varied over time. In the past, HP/HT fields were attributed to any condition of greater than 10,000-psi pressure and greater than 300°F temperature. But over the last 20 years, equipment has become widely available for pressures below 15,000 psi and temperatures lower than 350°F; therefore, those fields were no longer classified as HP/HT fields. HP/HT conditions were defined as having pressures between 15,000 and 20,000 psi and temperatures between 350 and 450°F. Ultra-HP/HT conditions were defined as having pressures between 20,000 and 35,000 psi and temperatures between 450 and 550°F. Fig. 1 is the visual representation of the latest HP/HT designations, which were reached by common agreement among oil operators and service companies.
There are several technological challenges that must be overcome for downhole service and completion tools to operate successfully in the ultra- HP/HT environment.
Holistic Project Planning: How Work-Force Development Impacts Business Results
Authors: Grimsley Jim 
Published: February 2015

E&P companies that are trying to meet growing energy demand know that prudent exploitation and replacement of their asset base is critical to long-term success. Supermajors and independents are increasingly depending on an asset base that is characterized by multiyear, multibillion-dollar projects in remote, developing, and technically challenging environments. The planning, construction, operation, and maintenance of these assets, such as deepwater platforms and liquefied natural gas facilities, require holistic project planning and superior execution.
A key component of holistic project planning in the frontier areas that in the past has been often underestimated is work-force development. But companies that take a disciplined approach in this area achieve:
- Improved alignment with the host government.
- Lower operating costs.
- Higher return on their investment.
So, how does work-force development fit into a holistic project plan? What is it, and how does it deliver business results?
A New Opportunity
Holistic project planning synchronizes the various asset development, operating, and work-force strategies to optimize each phase of the asset life cycle. Over the past several years, both through experience and because of the size of the investments as well as the production-deferral implications, operators have become increasingly proficient and focused on planning and executing the development of assets in frontier markets. Project management, risk management, supply chain, and logistics processes are being adapted to the challenges presented by frontier development. As projects have grown into the multibillion-dollar range, the work-force development strategy represents an increasing area of risk and opportunity.
The strategy traditionally used by operators relied heavily on expatriates. But times have changed, and operators are facing aggressive local content targets. Using a national work force is no longer an option; it is a requirement.
It is also a major challenge. The national work force in frontier markets oftentimes does not have the technical capabilities and management skills required to operate and support today’s increasingly complex oil and gas operations. Operators must determine how the national work force can be developed effectively to sustain their operations.
Overview: Formation Evaluation (May 2005)
Authors: Unalmiser Servet 
Published: February 2015

A new generation of downhole intelligent systems has made real-time reservoir evaluation the new norm in the industry. Advances in formation-evaluation tools, such as the modern capture and near-infrared spectroscopy tools, allowing more-accurate determination of petrophysical data and in-situ fluid composition, have matched the growing sophistication in geosteering and well placement through improved measurement-while-drilling and logging-while-drilling technologies. The emerging real-time character of formation evaluation brings along a host of new challenges for the industry. We need to ponder the answers to questions such as the following.
- How do we manage the enormous growth in the volume of data?
- How do we convert the extra data to higher-accuracy reservoir characterization?
Fuzzy logic and neural networks may point to potential pathways. Another noteworthy evolution is occurring in the area of formation imaging. Spanning across many scales, ranging from the pore throat to the wellbore, new dual-energy computer-tomography-scanning and nuclear-magnetic-resonance mapping techniques enable us to peer inside the rock to get a better understanding of multiphase-flow experiments. Wells with vastly complex subsurface architectures give us the ability to image reservoirs (e.g., fractures, boundaries, and orientation frequency) in greater detail than ever before. In short, formation evaluation is getting better and smarter.
Additional Formation Evaluation Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 88688 Image Enhancement, Automated Interpretation, and 3D Visualization of Borehole-Image Logs in Characterization and Calibration of Fractures in Kuwait
SPE 88636 Design Considerations for a New High-Data-Rate LWD Acoustic Telemetry System
SPE 88519 A Case Study of Carbon-Oxygen Logging Through Multiple Tubular Strings Offshore Indonesia: Reservoir-Model Verification With Emphasis on Fluid Contact and Bypass Oil Identification
SPE 91607 Damage Interpretation of Properly and Improperly Drilled Underbalanced Horizontals in the Fractured Jean Marie Reservoir Using Novel Modeling and Methodology
Overview: Wellbore Tubulars (May 2005)
Authors: Mabile Claude 
Published: February 2015

More and more is asked of the tubulars used downhole, such as for drilling deeply buried reservoirs or for producing acidic oil or gas. Therefore, improvement must be continuous in the steel and the connections. Breakthrough technologies, such as expandable casing and the intelligent drillstring, also are necessary to enable producing from new reserves.
Tubing strings are exposed to corrosive fluids during completion and production. Tubing strings also are subjected to different kinds of stress induced by their own weight and also by pressure and temperature. Even chromium steels can corrode in these conditions. It is, therefore, necessary to have a good understanding of how corrosion-induced cracks can be generated and grow so that we are able to predict the service life of tubing strings.
Expandable casing is used more and more. In most cases, cement must be set in the annulus between the expandable casing and the formation. The cement slurry must have very particular characteristics because it must remain in a liquid state for a longer time than usual, yet it must provide a perfect seal in a narrower annulus.
The technology of transmitting data while drilling has made little progress since the 1970s when the mud-pulse system was invented. Different solutions were developed in efforts to increase the data rate drastically, but none came to the market. Recently, a new solution having nearly the same data-rate transmission as that of an electric cable, but avoiding the weak-ness of electric connectors, was developed, and field trials have been run. This type of “intelligent” drillpipe should enhance logging-while-drilling performances and could enable new techniques such as seismic while drilling.
Additional Wellbore Tubulars Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 90151 The Heat-Transfer Characteristics of Vacuum-Insulated Tubing
SPE 90904 A New OCTG Strength Equation for Collapse Under Combined Loads
Development Status of a Metal Progressing Cavity Pump for Heavy-Oil and Hot-Production Wells
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97796, "Development Status of a Metal Progressing Cavity Pump for Heavy-Oil and Hot-Production Wells," by J.-L. Beauquin and C. Boireau, Total E&P, and L. Lemay and L. Seince, PCM Pompes, prepared for the 2005 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 1–3 November.
Progressing cavity pumps (PCPs) often are used for cold heavy-oil production because of their adaptability to viscous and abrasive fluids. However, for thermal recovery, a standard PCP is not adaptable because the elastomer of the stator, the heart of the pump, cannot withstand fluid temperatures higher than 160°C. An all-metal pump, avoiding the elastomer weakness, has been developed. Validation tests began in early 2005 using extra heavy crude with temperatures up to 200°C, pressure up to 75 bar, and flow rates up to 260 m3/d at 350 rpm. The flow-rate range will be as high as 1000 m3/d.

Introduction
Most oil fields require some type of artificial lift at some point in time. When sufficient gas is available, gas lift may be a viable lift method because it involves relatively low-cost well interventions and tolerates numerous flow constraints, such as high gas content, gas slugging, sand production, and high temperature.
When a gas lift system is inadequate, too expensive, or not possible, the artificial-lift needs challenge downhole pump capabilities and features. Some wells are able to use hydrodynamic pumps such as centrifugal, helicoaxial, or hydraulic-jet pumps because of the very high volume to be lifted. However, these pumping technologies are expensive. Most pumped wells are equipped with positive-displacement pumps, which can be adapted to changing conditions of pumped fluid.
Beam- and rod-driven plunger pumps can be adapted to handle many types of fluids because they are simple, robust, and well understood. However, in heavy oil, rod failure is the most common limitation, which leads to limiting the well production, which, in turn, worsens the risk of sand settling in the pump. Also, slow closure of traveling and standing valves is a cause of poor efficiency in viscous mixtures.
Pumping in horizontal or highly deviated wells also limits the plunger downstroke because it is powered by the driving part of the rod-string weight. Thermal production methods generate fluctuating inflow properties that change rod-failure causes and reduce the run life of the system.
During the 1980s, rotating-rod-driven PCPs were developed for oilfield applications. PCPs are used for viscous oil, horizontal wells, and sandy production. Rod-driven PCPs are used for cold pro-duction of heavy oil and often are used in conventional mature fields as a cheaper lift method than beam pumps. The standard PCP stator is made of elastomer, which is the source of most of the pump's limitations including fluid temperature and gas and aromatics content.
Overview: Wellbore Tubulars (May 2006)
Authors: Baker David A. 
Published: February 2015

Last year, this section opened with a statement that tubulars were being asked to do more and more. This was ever apparent at last year's SPE High-Pressure/High-Temperature (HP/HT) Sour-Well-Design Advanced Technology Workshop in that tubulars are being used in deeper, hotter, and more-challenging environments. In fact, we are trying to do more and more with less and less: drilling with casing, using thinner-walled tubulars downhole, and using less weight offshore.
As a relatively new engineer in this industry, I am still exploring and still asking questions. What fatigue life can we get out of the threaded connection? What materials really are required for the HP/HT application? We need to ask the questions not only for product development, but also for product implementation.
Understanding the fundamentals is an important aspect of all our endeavors, especially if we are trying to achieve "more with less." There is an appropriate systematic process to evaluate the appropriate use of tubular technology for each application. This process requires not only taking advantage of the modeling and experimental tools available to us, but also an understanding of the mechanics of the application. For example: Are the proper equations or models being used to describe the anticipated behavior?
The papers presented on the following pages and in the additional reading take a step back to help us understand and explore these fundamentals. Materials selection is a key aspect in the tubular-design process, especially in a sour or otherwise challenging environment, and it often requires a balance between longevity and economics. Fatigue arises in nearly every well, from drillstem vibrations to thermal-cycle loading. These two situations also represent different regimes of fatigue behavior: high-cycle (low-stress amplitude) and low-cycle (high-stress amplitude). Other loading scenarios, such as wear, collapse, burst, and buckling, are examined in detail in the additional reading.
Wellbore Tubulars additional reading available at the SPE eLibrary: www.spe.org
SPE 94300 "Contact-Pressure Threshold: An Important New Aspect of Casing Wear," by R.W. Hall Jr., SPE, Mohr Engineering, et al.
SPE 94304 "Casing Burst Strength After Casing Wear," by J. Wu, ChevronTexaco, et al.
SPE 96131 "Tubing Buckling—The Rest of the Story," by R.F. Mitchell, SPE, Halliburton Digital & Consulting Services
SPE 95691 "Collapse Resistance of Tubular Strings Under Geotectonic Load," by N. Morita, SPE, Waseda U., et al.
Building Bridges: My Journey Continues… SPE Board Meeting Update
Authors: Cobb Bill 
Published: February 2015

President's column
The SPE Board of Directors meets four times a year. Our most recent meeting was at the end of March in Bangkok, Thailand. The board does its work through five board committees—Finance and Administration (comprising the SPE officers and chairs of the other board committees), Print and Electronic Media, Technical Programs and Meetings, Education and Professional Activities, and Membership. Here are some highlights of the March meeting.
Finance and AdministrationWe reviewed the expected budget outcome for Fiscal Year 08, ending 31 March. I'm delighted to report that our income from operations was forecast to be roughly USD 4 million, with meetings contributing the lion's share.We established an Investment Advisory Committee to offer advice on management of SPE's investment portfolios and the Society's investment policies. Committee members are Behrooz Fattahi, SPE Vice President of Finance; Bruce Bernard, 2001 SPE President, SPE Foundation Treasurer; Ian Phillips, SPE Europe Board member; Janet Handley, Investment Director, Texas A&M Foundation; and David Meade, General Manager Pension Investments, Shell Oil Company.
Print and Electronic MediaThe board committee approved the prototype for a multi-language "wiki-type" glossary of oilfield terminology, to be introduced on SPE.org in June. During meetings with members in China, Russia, and Latin America in the last few years, members told us that oilfield terminology is not always easily translatable from English into other languages. The online glossary will allow members to contribute terms and definitions in English and, initially, Chinese, Russian, Spanish, and Portuguese.
The SPE staff presented a high-level assessment of future enhancements for SPE.org. The report addressed the evolution of SPE's website in three areas:Content collection—expanding and disseminating content on a broader scale;Technology—using information technology to connect the parts and make content consumption easier; andInteraction—ways to serve our members, volunteers, and customers through innovative Internet services. The board committee will in coming meetings look at specific initiatives in these areas.
Technical Programs and MeetingsThe board committee discussed a Strategic Meetings Initiative proposal, designed to look at the relationship of SPE meetings and member needs. This initiative is meant to evaluate each of SPE's technical meetings as it relates to SPE's mission of value to members, exhibitors, sponsors, and the industry, as well as both strategic and financial value to SPE.The board committee discussed implementation of procedures to reduce the number of authors who do not show up to present a paper that has been accepted for meeting presentation. Presenting authors will now be required to give written notice no less than 45 days prior to the first day of the meeting to avoid censure.