bluuebunny/crossref_metadata_2025_split huggingface dataset:
Potential for Additional CO2-Flood Projects in the US
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 113975, "The Potential for Additional Carbon Dioxide Flooding Projects in the United States," by Hitesh Mohan, SPE, Marshall Carolus, SPE, and Khosrow Biglarbigi, SPE, Intek, prepared for the 2008 SPE Improved Oil Recovery Symposium, Tulsa, 19-23 April. The paper has not been peer reviewed.
There is renewed interest in carbon dioxide enhanced oil recovery (CO2 EOR). Growing concern about climate change and greenhouse gases has increased interest in carbon capture and sequestration. CO2 EOR provides a value-added opportunity to increase crude-oil production while sequestering substantial volumes of industrial CO2. An analysis was conducted to determine the incremental domestic production that could be realized if industrially produced CO2 were available for EOR. Challenges include available volumes of CO2, infrastructure requirements, and prices of the CO2.

Introduction
US conventional crude-oil production continues to decline while demand for crude and finished products rises. According to the US Department of Energy Energy Information Administration (US DOE EIA) and shown in Fig. 1, the US demand will be greater than 27 million B/D by 2030, while total production will be less than 10 million B/D.
Four factors were identified that will have a significant effect on widespread implementation of CO2 EOR.Target resourceTechnologyAvailability of CO2Economics

Target Resource
There are 1,673 reservoirs onshore in the continental US that are candidates for CO2-miscible flooding. Fig. 2 shows the reservoirs that were identified on the basis of the following criteria.Gravity greater than 22°APIReservoir pressure greater than the minimum miscibility pressureDepth greater than 2,500 ftOil viscosity less than 10 cpCurrent oil saturation greater than 20%Either sandstone or carbonate rock

Technology
CO2-EOR technologies have been demonstrated to be profitable in commercial-scale applications for nearly 30 years. As of 2006, 80 CO2-EOR projects in the US had a combined production of 234,000 BOPD. Ten of these projects were started between 2004 and 2006. Of the projects active in 2006, 58 are in the Permian Basin. The reason is partly because of the prevalence of candidate reservoirs in that region, and because of the steady availability of natural CO2.
Technology Focus: Mature Field Revitalization (January 2009)
Authors: Ali Syed A. 
Published: February 2015

Technology Focus
Even as new discoveries are developed and produced, substantial additional reserves can be secured by enhancing recovery from mature fields. Mature fields have the potential to contribute significantly to future reserves—provided that recovery can be optimized.
Usually, it is the new discoveries that capture the attention of the oil industry; however, 70% of the hydrocarbon liquids produced in the world today actually come from mature fields. With most of the world's potential oil provinces having already been explored and major new discoveries becoming increasingly rare, mature fields are destined to play an ever-more-prominent role in energy supply.
It is generally accepted that 30 to 35% of the original oil in place will be recoverable by the end of the normal production period. However, advances in technology (fueled by higher oil prices) are making it feasible to access remaining reserves. Considering the substantial quantities of remaining oil at stake, boosting the recovery factor on all the world's oil fields by a mere 1% would cover 3 years of worldwide consumption. Techniques to improve the recovery factor include: secondary- and tertiary-recovery schemes, horizontal and multilateral drilling, improved perforation and stimulation methods, new completion techniques, advanced logging procedures, and optimal placement of the new wells.
Mature fields, however, offer their own set of challenges. In addition to dealing with aging installations and earmarking investments to access additional reserves, all aspects must be considered carefully from a project-economics point of view. Water is another problem in reservoirs nearing the end of their production life; most oil companies produce far more water than oil, raising environmental concerns and water-handling expenses. Consequently, mature fields would require a strategy that is based on tapping bypassed oil, improving recovery from existing producing zones, cutting costs, and implementing leading-edge technologies to maximize production.
Mature Field Revitalization additional reading available at the SPE eLibrary: www.spe.org
SPE 113684 • "Mature-Field Rejuvenation of a Tight Gas Carbonate Utilizing Coiled-Tubing Underbalanced-Drilling Techniques" by C. Mykytiw, SPE, FX Solutions Group, et al.
SPE 113271 • "Techniques in Marginal and Mature Fields in the Pannonian Basin, Hungary: Case Study" by A. Holoda, MOL, et al.
SPE 112940 • "The Omar Field (NE Syria) Is Overcoming Its Mid-Life Crisis" by J. Neidhardt, Shell, et al.
SPE 112586 • "Horizontal Extended-Reach Re-Entry Drilling of Sidetracks at Sakhalin Island Increases Oil Production From Mature Oil Fields" by M.L. Drnec, SPE, Schlumberger, et al.
Techbits (February 2005)
Authors: JPT staff _ 
Published: February 2015

The importance of interpreting and applying right decisions in data management and technology development in Central and Eastern European fields was the focus of the Applied Technology Workshop (ATW) “Field Management of Mature Reservoirs” held in Vienna, Austria. Through presentations, case studies, and syndicate sessions, participants conferred on the following topics:
- Accessing data and discovering the value of mature reservoirs.
- Recognizing existing technologies that can be applied success-fully in mature reservoirs.
- Tools to unlock value in mature assets.
- How future technologies will affect mature assets.
- From today’s reality to tomorrow’s dream as described by E&P and service company senior management.
Good reservoir review, field management, and using the right technologies were considered in the first technical session. Particular emphasis was placed on the importance of standards, change management, documentation of a good track record in conjunction with business processes, and collaboration with people. The fact that a significant amount of data can no longer be read or accessed as a result of changes in asset management was also addressed.
The second session highlighted case histories that illustrated how existing technologies provided correct solutions in alignment with best practices in Central Europe’s Mesozoic formations and in the Carpathian range. The session was devoted to proving that right understanding of mature-reservoir problems must exist in advance to select proper technologies for application. When the right degree of understanding exists, a substantial number of existing methods and equipment is available for use in mature reservoirs.
The impact of differing stakeholder perspectives and requirements on the management of mature E&P assets was presented in the third technical session. Steve Mills from the Royal Bank of Scotland presented the investor’s point of view toward the materializing process and the importance of selecting the proper investment plan. Beate Raabe of the Intl. Assn. of Oil and Gas Producers presented the European Union administrative viewpoint regarding development of mature assets and taking into account future regulatory requirements. Representatives from Wintershall A.G. and Industrija Nafte d.d. presented company strategies for development of mature fields as part of an asset portfolio and showed how these fields still can offer attractive options for E&P companies.
Educating the Next Generation of Engineers
Authors: Langley Diane 
Published: February 2015

Lifelong learning is a prominent issue currently on the minds of educators and employers, as illustrated in discussions during the SPE Sixth Colloquium on Petroleum Engineering Education (CPEE 2004). Lifelong learning, the focus of this colloquium, includes developing learning skills while in college and continuing education of engineers beyond college. Working together to build a stronger educational experience for petroleum engineers, academics, and employers identified the technical and personal strengths being required of engineers by industry and began to implement several action items to communicate the evolving educational roles of academia, industry, the service sector, government, and SPE.
The 49 session participants—representing academia, industry, and the service sector—met for 3 days in August 2004 at the Colorado School of Mines in Golden, Colorado, to enhance under-standing of industry education needs and to discuss how universities—in partnership with industry, service companies, and government—can help fill those needs.
Qualifying the Graduate Engineer
Assessment of technical and personal qualifications of recently graduated engineers, the establishment and global acceptance of certification standards, a look at innovative teaching programs, and information gleaned from a survey of young energy professionals were topics highlighted in five Colloquium sessions. The session titled “From Emerging Graduate to Emerging Leader” focused on the viewpoints and expectations of employers, recent graduates, and academics. Brice Peterson of Shell, Larry Schwartz of Schlumberger, Julie Struble of Anadarko, and Ganesh Thakur of ChevronTexaco examined their respective current viewpoints and expectations as engineering employers. From the industry perspective, some of the skills and attributes that recruiters seek in new hires are effective communication and teamwork abilities, analytical and problem-solving skills, judgment and decision-making capabilities, adaptability, initiative and motivation, all in addition to technical and professional knowledge.
High-Performance Slimhole Drilling With 4-in. Drillpipe and a Streamline Connection
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87988, "High-Performance, Slimhole Drilling With 4-in. Drillpipe and a Streamline Connection," by Guillaume J. Plessis, SPE, Grant Prideco; Andre Glowacz, Total; John M. Pasnak, SPE, Saudi Aramco; and Michael J. Jellison, SPE, Grant Prideco, prepared for the 2004 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Kuala Lumpur, 13-15 September.
Saudi Aramco and Total Indonesia used 4-in. drillpipe with streamlined double-shoulder connections to drill wells for which 3 1/2-in. drillpipe was unsuitable. The 4-in. drillpipe with enhanced torsional, tensile, and hydraulic characteristics was used to drill longer slimholes at a lower overall cost. The selected double-shoulder connection has an outside diameter (OD) similar to standard 3 1/2-in.-drillpipe tool joints while maintaining the fishability of the 4-in. pipe in casing and open hole. The stream-line-connection design provides 22,000 ft-lbf of working torque, a 4 7/8-in. OD, and an oversized internal bore that promotes hydraulic efficiency.

Introduction
Drilling deeper slimhole wells has revealed limitations of the 3 1/2-in. drillpipe traditionally used to drill the 6- to 6 1/4-in. hole sections. The torque level that American Petroleum Inst. (API) rotary shoulder and first-generation double-shoulder connections can deliver does not match the new requirements for these deeper drilling programs. The increase in drillstring length also imposes an addition-al constraint on hydraulic performance.
Targeted Development of Low-Cost 3D Rotary-Steerable Systems
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87165, "An Operator's Targeted Development of Low-Cost 3D Rotary-Steerable Systems," by J.T. Travis Jr., SPE, J.H. Moss, SPE, and G.M. Browning, SPE, ExxonMobil Development Co., prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
The many benefits of 3D rotary-steering systems (RSSs) are well documented. ExxonMobil Development Co. (EMDC) Drilling continues to expand its use of 3D RSSs in its daily drilling operations. Its drilling operations include a variety of well architectures in both the high-cost and low-cost markets. Because of the high price of RSSs currently on the market, EMDC is unable to justify use of these systems in lower-cost wells. However, the low-cost market would benefit from the higher rates of penetration (ROPs), reduced risk through improved hole cleaning, reduced wellbore tortuosity, and more-efficient directional control.

Introduction
Three-dimensional RSSs currently are being deployed in approximately 5% of EMDC’s daily rig operations. Very high spread costs and/or well profiles beyond the capabilities of conventional directional-drilling methods usually justify these applications. Spread costs are defined as the daily operating cost less tangible items such as tubulars, wellheads, and completions equipment. The costs of high-cost floating-drilling, platform, and deep-remote land wells range from U.S. $100,000/day to U.S.$500,000/day. Normal land operations average only U.S. $15,000/day.
As experience was gained, it become apparent to the drilling organization that there was a large well inventory in need of the benefits of a 3D RSS that cannot currently justify its application economically.
The initial 3D RSS providers’ market was, and in most cases still is, a higher-operating-cost environment that does not fit lower-cost market needs. The high-cost environment needs only a 10% improvement to justify a 3D RSS, whereas the low-cost environment would require approximately 100% improvement to justify a 3D RSS. The high prices charged for these first systems are driven by the following.
Overview: Offshore Facilities Construction and Design (February 2005)
Authors: Valenchon Claude 
Published: February 2015

Liquefied natural gas (LNG) and offshore activities have much in common.
- The ultimate goal of each is to produce and deliver hydrocarbons to the market.
- The main oil operators are active in LNG as well as other offshore activities (e.g., ExxonMobil, Shell, BP, Total, and ChevronTexaco).
- Production is transported over long distances by carriers (even if LNG carriers are far more sophisticated than oil tankers!).
But, until now, LNG production plants have always been built onshore, even when gas is produced offshore (e.g., Qatar, Trinidad, and Sakhalin). The first concepts of LNG floating production, storage, and offloading (FPSO) vessels were presented by the industry in the mid-1970s. These concepts were targeting stand-alone gasfield developments or associated gas fields.
Even if an LNG FPSO appears economically very attractive when compared with a “grass roots” onshore LNG plant, the operators seem not to have found the proper location or the correct “scheme” to select an LNG FPSO for developing an offshore gas field. At the other end of the LNG chain, huge investments also are foreseen to build facilities for the reception and regasification of LNG to cope with a fast-growing demand for gas.
Many terminals are under construction or planned in many countries. This increased demand is not without obstacles. In some areas of North America or Europe (Italy for example), environmental constraints prevent the installation of newly built, land-based LNG terminals. As a result, the projects are moving offshore, taking the shape of fixed, gravity-based structures or floating storage and regasification units.
In this offshore move of the LNG industry—“tomorrow” for the receiving terminals and the “day after tomorrow” for LNG FPSOs—those who combine LNG and offshore expertise will be key players in this new arena.
Additional Offshore Facilities Construction and Design Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 89998 - Subsea HIPPS: A Way To Develop High-Pressure Subsea Fields
Available at the OTC Library: www.otcnet.org
OTC 16106 - Monitoring of Sand Deposition in Subsea Separators
OTC 16185 - High-Strength Aluminum Alloys for Deepwater Riser Applications
Spar Vortex-Induced-Vibration Prediction
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16343, "Advancement of Spar VIV Prediction," by T.-W. Yung, R.E. Sandstrom, S.T. Slocum, Z.J. Ding, and R.T. Lokken, SPE, ExxonMobil Upstream Research Co., originally presented at the 2004 Offshore Technology Conference, Houston, 3-6 May.
Vortex-induced vibration (VIV) of spar hulls is an operational issue in high-current environments and an important consideration for mooring and riser integrity. On the basis of extensive analytical, laboratory, and field studies, ExxonMobil has developed a reliable methodology for predicting the VIV of classic spars that has been validated by field measurements.

Introduction
Spar technology continues to evolve and currently is experiencing wide application in deep- to ultradeepwater fields in the Gulf of Mexico (GOM). Eight spars have been installed in the GOM since 1996, and five more are in various stages of design and construction. These include classic spars [deep-draft caisson vessel (DDCV)], truss spars, and cell spars. A spar platform is characterized by a large, usually cylindrical, hull that extends deep into the water.
In the GOM, the loop current and loop-current eddies (Fig. 1) have the potential to cause VIV on the spar hull. Speeds in these currents can remain high well below the surface, exposing the entire hull to large forces. In addition, hurricane currents also may cause VIV spar motion. Field measurements have shown that all of the three classic spars (Hoover, Genesis, and Neptune) have experienced VIV. From these experiences, it was observed that both loop/eddy currents and inertial currents (after a severe storm) could cause VIV. For the Hoover DDCV, eddy currents with speeds as low as 1 to 2 knots have caused VIV.
Industrial experience with VIV started many decades ago with the development of VIV-suppression devices for smokestacks and chimneys. Over the years, there have been numerous studies on VIV physics as well as VIV-suppression devices for onshore and offshore structures. In recent years, there has been an increased interest in spar-VIV-design practice, highlighted by the first-ever industrywide workshop dedicated exclusively to spar VIV. The October 2003 workshop addressed a wide range of topics. In the workshop, the ExxonMobil spar VIV-design practice, based on work for the Hoover project, was presented. The design practice is based on a combined analytical, model-testing, and field-measurement approach. The discussion was focused on key factors for reliable prediction of classic-spar hull-VIV response and comparisons between model test results and field measurements.
Overview: Well Testing (February 2005)
Authors: Stratton Jay 
Published: February 2015

The industry spends millions of dollars to achieve success in reaching the target objectives for an exploration well. Even with impressive petrophysical data, the well-test information will determine the potential commerciality of the exploration project. Similarly, in the production environment, reservoir descriptions that are always more complex than idealized reservoir models present unique challenges to the accurate char still can arrive at valid yet surprisingly different conclusions from the same well-test analysis. Even with current advances in technology, there is no replacing the sound engineering judgment necessary for analysis of a complete set of well-test data.
Our industry continues to seek improved and innovative methods of improving our well-test data-gathering and -analysis methods. Accuracy of the pressure/volume/temperature data is fundamental to the well-test analysis, and errors in this input will compromise the final analysis. Numerical methods that more accurately describe reservoir conditions during testing will allow modeling of more-complex descriptions. Tools to allow earlier and more accurate analysis of reservoir fluids and rock properties accelerate our understanding of a new prospect and can save time and cost of unnecessary delays in analysis and completion recommendations. Real-time production monitoring of wells can lower the cost of gathering ongoing well-test data and improve our understanding of the reservoir relative to infrequent snapshots of data common to most projects.
Advances are being made in all the components of well-test-analysis technology. Fluid-sampling and -analysis tools; well-test-analysis software; and pressure-, temperature-, and rate-monitoring technology are improving. Reservoir models are adapting to more-complex environments. Artificial intelligence is used in efforts to discern accurate well-test-analysis results with less applied-engineering judgment. However, with increased technology, a flood of additional data and models are available from which a rigorous engineering analysis must be completed. Engineering judgment with assistance of the technical capabilities of an entire multidisciplinary team is still the most critical component needed to determine the unique solution that will most accurately complete a reservoir and well description. The following pages provide examples of the broad range of reservoir information being gathered, analyzed, and managed to make the exploitation of hydrocarbon resources more efficient and profitable.
Additional Well Testing Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 90236 - Uncertainties in Standard Analyses of Boundary Effects in Buildup Data
SPE 90960 - Simultaneous Estimation of In-Situ Multiphase Petrophysical Properties of Rock Formations From Wireline-Formation-Tester and Induction-Logging Measurements
SPE 92041 - Grid-System Requirements in Numerical Modeling of Pressure-Transient Tests in Horizontal Wells