bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design of Steel Catenary Risers for Deepwater Offshore Brazil
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19249, "Influence of Fatigue Issues on the Design of SCRs for Deepwater Offshore Brazil," by A.L.F.L. Torres, M.M. Mourelle, S.F. Senra, E.C. Gonzalez, and J.M.T. da Gama Lima, Petrobras S.A., originally prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
Petrobras has been investigating the steel-catenary-riser (SCR) alternative since the beginning of the 1990s. Since then, fatigue verification has been an important issue, demanding good representation of the loading conditions that occur during the lifetime of the riser. The concern with fatigue has motivated Petrobras to research several areas, such as metocean data acquisition, hull design for motion optimization, special touch-down-point (TDP) joints, accurate models for vortex-induced-vibration (VIV) analysis, and the corrosion-fatigue effect.

Introduction
Installation of the P-18 SCR was a pioneer project of a free-hanging SCR connected to a semisubmersible, and it proved the technical feasibility of the concept. Although this riser was installed as a prototype, it is still working in the gas transfer from platform P-18 to platform P-26. It has been monitored since 1999, and the results are being compared with the design data and with simulations performed with in-house computer programs and other commercial packages that include the complete design methodology. Other SCRs were studied, such as the 12-in. oil-export riser for the P-19 semisubmersible in 770 m of water and the 10-in. oil- and gas-export lines for the P-36 semisubmersible at a water depth of 1360 m.
The free-hanging SCR configuration is considered as an available technology for semisubmersible applications, and there is interest in the application of SCRs connected to floating production, storage, and offloading units (FPSOs) because of the trend to use these units for exploration and production in deep water. This has caused a need to study this concept carefully, given the high offsets and heave motions imposed by the vessel at the top of the riser.
Fatigue verification is an important issue that requires accurate evaluation of the loading conditions that occur during the riser lifetime, and it also requires a precise knowledge of construction aspects that could decrease or change riser-materials resistance.

Wave-Induced Fatigue
Over the past few decades, Petrobras has acquired Campos basin wave, current, and wind data, resulting in a metocean database containing more than 7,000 records. Within these data, the occurrence of multimodal/multidirectional sea states was identified. To use this database in riser design, the in-house software tools for structural fatigue analysis were upgraded to consider bimodal/bidirectional sea states.
Management of Offshore-Ice Operations
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19275, "Ice Management for Ice Offshore Operations," by A.J. Keinonen, AKAC Inc., prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
The use of icebreakers in support of offshore-ice operations, and specifically their efficiency in support of vessel-shaped floating platforms in ice, is discussed. New-technology icebreakers equipped with azimuth thrusters achieve high levels of operability with various levels of ice management in a wide range of effective ice thickness.

Introduction
The oil industry has increased its interest in ice-covered waters. Operations, especially in water deeper than 100 m, use various vessels for drilling or production, with icebreakers supporting their station keeping. The use of icebreakers enables stationary operations in ice to continue with increasing degrees of difficulty. The use of vessels in such offshore-ice operations is substantially different from and more demanding than traditional ice-transit operations or port operations in ice-covered ports and terminals.
Offshore-ice projects, which operate in moving pack ice, must ensure that station-keeping operations continue with a high degree of confidence that the station-keeping limits of the floating platform will not be exceeded. Rigorous risk control also is needed to ensure that, if needed, all operations can be stopped and the platform can be removed safely from the location. A high confidence required in the capability to stay on location before such an operation is justifiable. The overall scope of ice management is more accurately "risk management for offshore-ice operations." The following are an integral part of the ice management.Ice and environment intelligenceIce and environment forecastingDefining operability and safe ice operational envelope for the stationary vesselOperational-risk evaluation and assessmentAlerting of operations
Only after the above are completed can the actual physical ice management (i.e., breaking and clearing ice) take place. Safe ice-management logic applies to all floating platforms and to any platforms intended to be removable from their stationary operational locations. This paper focuses on the most demanding version of the ice management, operations of ship-shaped platforms. Vessel-shaped platforms are unique in that they offer a highly favorable ice-interaction condition when ice moves in the direction of the vessel. However, the challenge is that if ice comes from the side, the ice loads are so much higher that the benefit of the low loads in one direction is totally lost and operation might not be feasible.
Lessons Learned From 12 Years of Operations of a Prestressed High-Performance-Concrete Floating Production Unit
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12546, "Lessons Learned From 12 Years of Operations of a Huge Floating-Production Unit Made of Prestressed High-Performance Concrete," by Bertrand Lanquetin, Heidi Dendani, and Pascal Collet, Total, and Jose Esteve, Bureau Veritas, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.
Lessons learned from use of a floating-production unit (FPU), made of pre-stressed high-performance concrete, in operation for Total E&P Congo are pre-sented. The unit has been in use for 12 years on the N'Kossa oil field in 170-m water depth. The focus is on structural-modeling techniques, aging processes, and development of an inspection program. The paper is not intended to make a recommendation between steel and concrete, which would entail many other considerations.

Introduction
The FPU NKP is 220 m long, 46 m wide, and 16 m high, with a displacement of 107 000 tonnes. It contains 27 000 m3 of concrete, 2350 tonnes of prestressed steel, and 5000 tonnes of passive steel. During its 12 years of operation, the FPU has undergone one technical stop for process maintenance, as scheduled in the design; otherwise, it has been in uninterrupted service. The unit, shown in Fig. 1, was built in southern France in 1994–95 and installed 1 year later in the N'Kossa oil field in 170-m water depth, 60 km off the Congo coast.
The production facilities and living quarters for 160 people are fitted on the 10 000-m2 deck, which for construction purposes was subdivided into six modules: accommodation and central control, utilities, electric-power generation, gas compression for re-injection, crude oil, and gas. Design production is 16 000 tonne/d of oil and 1300 tonne/d of liquefied petroleum gas. The unit is held in place, 70 m away from the NKF2 platform, with a spread-moored configuration by means of 12 mooring lines.

Asset-Integrity Management
A special method was developed to analyze and monitor the condition of the units. The aim of the floating-units integrity-management process is to ensure management and continuous follow-up of floating units from safety, environmental, operational, maintenance, and quality-management view-points. It includes recommendations on inspection, maintenance, and repairs. This process calls for the following.Structural and anchoring modeling and analysisQualitative [risk-based inspection (RBI)]Yearly reviews of the inspection, repair, and maintenance (IRM) planData management and storage (including reports)Assistance for emergency responseFramework for analysis
Technology Focus: Well Testing (February 2009)
Authors: Stratton Jay 
Published: February 2015

Technology Focus
Many of us, at one time or another in our careers, have encountered industry colleagues or team members convinced of the need to gather information, sometimes at any cost. In contrast, just as many struggle with advocating even the most rudimentary data gathering to decision makers within their company. A common problem, particularly in small companies, can be a tendency to make quick decisions without considering possible effects by relying on past experience and judgment to expedite decision making for new problems. Planning can seem bureaucratic and unnecessary, particularly to less-experienced or nontechnical professionals. However, when objectives are not established and deliverables are not determined before making the final decision, the result can be a large invoice and information or service that is essentially useless.
Modern software, sometimes with less effort than my children put into mastering the latest "Xbox 360" release, will transform any kind of input data into an impressive array of results that can provide compelling justification for a completely wrong conclusion. I am picturing trainloads of investors passing through early oil fields where a strong pump and full tank battery could provide an impressive "gusher" timed by the promoter for just the right moment! And even a cursory look at input and assumptions going into some of our modern analysis can keep us from drawing wrong conclusions. Along with colorful or animated results, the most useful and relevant analysis in our industry will always invest the necessary time to confirm quality of the input data and verify the purpose or application of the results.
The papers highlighted on the following pages provide good examples of how unmet needs can provide insight into better analysis methods. New tools result from the need to acquire important information that would otherwise be uneconomic. Thorough engineers and technicians will be interested in the accuracy of their analysis as it relates to the quality of the input data. Solid analysis over time can uncover further insight into the performance of a hydrocarbon asset. I hope that you will find the selected papers of interest and that they will provide stimulation for new approaches in your well-testing and surveillance activities.
Well Testing additional reading available at the SPE eLibrary: www.spe.org
SPE 116744 • "Equivalent Skin Factors for Nonuniformly Damaged Horizontal and Multilateral Wells" by Turhan Yildiz, SPE, Colorado School of Mines
SPE 118940 • "Evaluation of Skin Factor From Single-Rate Gas-Well Test" by K. Aminian, West Virginia University, et al.
Additional reading available at OnePetro: www.onepetro.org
OTC 19140 • "Oilwell Transient Testing by Injection of Miscible Liquid" by J.J. Voelker, SPE, Chevron
Planning Successful EOR Projects
Authors: Hite J. Roger , Avasthi S.M. , Bondor Paul L. 
Published: February 2015

High oil prices and concerns about future oil supply are leading to a renewed interest in enhanced oil recovery (EOR), a group of technologies that can significantly increase recovery from existing oil reservoirs. Most of the experience with EOR is still in the United States, principally with CO2 flooding in the Permian Basin in west Texas and with the several thermal processes in the San Joaquin Valley in California. A listing of these projects is compiled every 2 years. But worldwide applications are growing. Thermal recovery of bitumen in Alberta, Canada, is increasing rapidly, and thermal projects have been successful in Venezuela, Indonesia, and elsewhere. Chemical and polymer floods are being implemented in China.
New applications increasingly will be worldwide. Each one will depend on careful planning to design an EOR project specific to the properties of the oil, the reservoir conditions, and the availability of injectants. In many situations, new EOR technology will be necessary. The processes being applied in the United States were tailored for those conditions and do not necessarily translate to other geologic provinces. This article attempts to distill past experience to define the state of the art in planning EOR projects. It is grounded in more than 30 years of experience by the authors in a wide variety of EOR applications.

The Planning Process
Successful EOR project management depends on good planning. “Prior proper planning prevents poor performance,” they say, and it is especially true when EOR is involved. Planning includes:
- Identifying the appropriate EOR process.
- Characterizing the reservoir.
- Determining the engineering design parameters.
- Conducting pilots or field tests as needed.
- Finishing with a plan to manage the project to meet or exceed expectations.
From the outset, and at every step along the way, we strongly recommend that careful attention be paid both to economic studies and to reservoir simulation as the reservoir characterization and engineering design progresses. In this way, the chances of success are greatly improved. Fig. 1 illustrates the interaction of all three.
Economics is the ultimate project driver. After all, unless the project is comfortably profitable, it should not be pursued in the first place. But reliable economics need good performance predictions. Good simulation models need good data. And what data are needed is determined by which project elements the economics is sensitive to. Each guides and depends on the others.
Practical Diagnostics Using Production Data and Flowing Pressures
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89939, "Practical Diagnostics Using Production Data and Flowing Pressures," by David Anderson, SPE, and Louis Mattar, SPE, Fekete Assocs. Inc., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Three important advances in production-data analysis are the inclusion of flowing pressures into analysis methods; the use of a “boundary-dominated” equivalent-production-time function to make constant rate and constant pressure equivalent; and the use of pseudo-time, which corrects for gas properties varying with pressure. Their value depends on the quality of real production data and, more importantly, the analyst’s ability to filter out the “junk” and retain the true reservoir signal. Blind application of decline-analysis methods without consideration of data-quality issues can lead to misinterpretation and erroneous results. Several practical diagnostic procedures, some general and others specific, can be applied to production data both on simple production charts and on advanced type curves.

Introduction
Most concepts underlying production-data analysis are based on pressure-transient (drawdown) theory. A model based on diffusive fluid-flow physics is used to describe the reservoir, fluid, and well as a system. Like well-test analysis, production-data-analysis techniques use type curves, which enable quantitative and qualitative evaluation of a system by identifying and matching trends in the data that are similar to the shape of the underlying type-curve model. Superposition in time converts variable inner-boundary conditions into an equivalent constant inner-boundary condition (usually constant production rate). In pressure-transient analysis, this superposition time usually is based on radial flow, while in production-data analysis, it is based on boundary-dominated (depletion) flow (i.e., material-balance time). An issue that is unique to long-term production-data analysis is the handling of fluid properties that vary with pressure. This issue is critical during depletion of a gas reservoir because the strongly varying compressibility is the dominant term in the depletion equation. The correction is a concept called pseudotime.
Acoustic Stimulation to Mitigate Near-Wellbore Damage
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90356, "Acoustic Stimulation to Mitigate Near-Wellbore Damage," by Fred van der Bas, SPE, Eric de Rouffignac, SPE, and Pedro Zuiderwijk, SPE, Shell Intl. E&P B.V., and Diederik van Batenburg, SPE, Halliburton, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 October.
Near-wellbore formation damage reduces productivity in oil and gas wells. Formation damage can be caused by fluid invasion during the drilling and completion process and by particles in the production stream. The conventional technique to remove this damage is fluid injection to dissolve the damage. A promising new technique to remove the near-wellbore damage is high-frequency acoustic stimulation. A specially designed acoustic tool is deployed on wireline or coiled tubing (CT) to selectively treat damaged reservoir intervals.

Introduction
Near-wellbore formation damage can result from many activities during drilling, completion, and production. One of the most pervasive damage mechanisms is pore plugging by solid particles from drilling mud, drilled solids, or particles from the formation. It is not always possible to prevent formation damage, and well-stimulation techniques have been used to remove or mitigate the effect of formation damage for more than half a century. Although conventional well-stimulation techniques have been used very successfully, they have significant limitations in long horizontal wells and in wells with multiple branches.
Acoustic cleaning is a promising well-stimulation technology that complements existing stimulation technologies and extends the range of options available for cost-effective well stimulation. High-frequency sound waves are used to “shake loose” damaging particles, and their effectiveness can be enhanced substantially by maintaining an underbalanced pressure in the well.
The experiments described in the full-length paper are the first, to the authors’ knowledge, to be conducted with oil and connate water. The ultimate proof of acoustic-stimulation feasibility requires field trials.
Reliability by Design - HP/HT System Development
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16393, "Reliability by Design - HP/HT System Development," by Dave Harrold, Eric Ringle, Michael Taylor, Scott Timte, and Frank Wabnitz, FMC Energy Systems, originally presented at the 2004 Offshore Technology Conference, Houston, 3-6 May.
The full-length paper details the design and qualification of a subsea completion system for the technically challenging high-pressure/high-temperature (HP/HT) environment. The focus is on the application of reliability engineering from the concept-development and design stages to the equipment-qualification process and how use of a comprehensive reliability-assurance program influenced the decision-making process and resulted in a highly functional and reliable system.

Introduction
Worldwide, the larger reserves of oil and gas that were located in the more accessible and, therefore, economically attractive shallow-water regions are being depleted. This is leaving operators with the choice of either pursuing the remaining, economically marginal, shallow-water finds or moving into deeper water. In the past 2 years, more than 20 new deepwater discoveries have been made in the Gulf of Mexico (GOM) alone.
The economics of deepwater developments depends heavily on equipment performance, mainly maintaining high system availability. For deepwater applications, operators are requiring system-availability numbers greater than 95% just to ensure that the projects remain economically viable. Although achievable, these targets exceed the expected availability for shallow-water applications. To be profitable in deep water, the higher production rates must be not only realized but also maintained throughout the life of the project. Downtime is considered unacceptable, especially problems caused by equipment failure.
Since 1948, the true vertical depth of the deepest well in the GOM has more than doubled to the current record of 29,680 ft. Drilling deeper takes longer and, therefore, costs more. As much as half of the cost of drilling a deeper well can be spent in just the last 10 to 25% of the total well depth, where rock formations are harder and pressures and temperatures are higher. Wells drilled beyond 20,000 ft can be even more problematic because of the high probability of encountering HP/HT conditions. Although a universal definition for HP/HT has not been established, most operators consider any well with a bottomhole temperature greater than 300°F and surface shut-in pressure greater than 10,000 psi as an HP/HT application. While HP/HT conditions are not new for onshore and offshore platform applications, the first true subsea HP/HT completion has yet to be brought online.