bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: Drilling and Cementing Technology (February 2007)
Authors: Dupuis Dominique 
Published: February 2015

2006 confirmed foreseen changes. The demand for oil was near the offer or production capacity and the rather stable high oil prices induced new drilling programs. The result was a drilling-rig market with use near 100% and new rig construction for the offshore fleet nearing 100 rigs. The wake-up was rather sudden. If current programs use mostly conventional drilling technology while constant technology evolution improves productivity, new prospects soon will require new drilling technology. Papers highlighted here and listed for additional reading describe recent technology advances.
R&D programs in 2005 and 2006 anticipated the need for new technology.In the ultradeep offshore, water depth more than 10,000 ft, conventional riser architecture has reached its limit; the hyperstatic riser is one solution.In deep prospects and extended-reach wells that require multiple intermedi-ate casings, monobore architecture renders these projects feasible.In deep buried reservoirs, the effects of high temperature require careful review of the cement formulation.In some mature or shallow unconsolidated prospects with low fracture gradients, the use of ultralight cements may be required.For production from acidic environments, long-term cement-sheave durability must be studied.
Noticeable efforts have been made to improve more-conventional drilling.Understanding drillstring behavior and taking into account contact forces related to string bending will improve trajectory prediction, and its monitoring will certainly increase the overall rate of penetration.Various methods of cuttings disposal exist, and the understanding of cuttings reinjection is improving.The reliability of cement-bond logs has improved with respect to zone isolation, especially when communication tests are impractical or cost-prohibitive.
Drilling and Cementing Technology additional reading available at the SPE eLibrary: www.spe.org
SPE 99105 "Durability of Oilwell Cement Formulations Aged in H2S-Containing Fluids" by E. Lecolier, SPE, Inst. Français du Pétrole, et al.
SPE 98124 "Ultralightweight Cementing Technology Sets World Record for Liner Cementing With a 5.4-lbm/gal Slurry Density" by D. Kulakofsky, SPE, Halliburton, et al.
SPE 99005 "First Hyperstatic Riser Joint Field Tested for Deep Offshore Drilling" by Y. Poirette, SPE, Inst. Français du Petróle, et al.
SPE 98965 "Advancements in 3D Drillstring Mechanics: From the Bit to the Topdrive" by S. Menand, SPE, École des Mines de Paris, et al.
Fixed-Offshore-Platform Performance in Hurricane Ivan
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18325, "Assessment of Fixed-Offshore-Platform Performance in Hurricane Ivan," by F.J. Puskar, R.E. Spong, and A. Ku, Energo Engineering, and R.B. Gilbert and Y.J. Choi, U. of Texas at Austin, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.
Hurricane Ivan provided an opportunity to evaluate the American Petroleum Inst. (API) RP 2A design process for fixed platforms to ensure that it provides for well-designed structures. Specific findings and trends are reported related to global platform performance as well as component performance. A quantitative assessment to determine the adequacy of the API RP 2A design process uses a probability-based process that compares analytically predicted platform damage and survival to that actually observed after Ivan.

Introduction
Ivan was one of several hurricanes in the last 12 years that have damaged or destroyed fixed offshore platforms. Previous hurricanes were Andrew in 1992 and Lili in 2002. Katrina and Rita in 2005 also caused significant platform damage and destruction. These types of events provide an opportunity to determine how fixed platforms in the Gulf of Mexico (GOM) perform in hurricanes on both a qualitative and quantitative basis. The qualitative basis includes a review of the typical types of damage to topsides and jackets, as well as the general trends observed, such as the number and type of platforms with wave-in-deck damage. The quantitative basis involves the comparison of observed damage with what would have been predicted by API RP 2A, which is the basis for design of fixed platforms in the GOM. This provides a quantified assessment of the accuracy of API RP 2A and whether it is adequate for design. The full-length paper describes these assessments for Ivan on the basis of an in-depth study performed for the U.S. Minerals Management Service focusing on fixed platforms.

Path
By late afternoon on 15 September 2004, Ivan was in the east-central GOM, approaching the deepwater oil and gas facilities. During this time, the hurricane was a Category 4 storm on the Saffir-Simpson scale, with maximum sustained wind speeds of more than 135 miles/hr. Ivan tracked north over the deepwater facilities in the Mississippi Canyon blocks and into the Viosca Knoll (VK) and Main Pass (MP) block areas. The majority of the destroyed or damaged fixed platforms were in the VK and MP block areas. Ivan continued its northerly track through the eastern edge of the Mobile block area, making landfall as a major hurricane with maximum winds of 130 miles/hr on the early morning of 16 September just west of Gulf Shores, Alabama.
Building Bridges: My Journey Continues... What SPE Is Doing To Improve Peer Review
Authors: Cobb Bill 
Published: February 2015

President's column
Happy New Year, Fellow SPE Members.
Yes, this is February, but as I finalize these comments it's January 1st. I hope 2008 will bring good health, happiness, and prosperity to you and your families.
During the holiday period, I have had discussions with several of our members and the SPE staff regarding SPE's technical-paper peer review. I would like to share with you some of our thoughts and action items for the near future.
Peer review is very important to SPE. While peer-approved papers comprise a small part of our eLibrary collection, peer review plays an important part in SPE's mission as a technical society. It enhances SPE's reputation as a learned society, and benefits both authors and readers.
Regardless of whether his/her paper is accepted for publication, the author benefits from suggestions for improving the work from individuals with special expertise or experience. Having a paper published in an SPE peer-reviewed journal merits a lot of prestige in our industry—only about 22% of submitted papers are accepted for publication.
Readers benefit because the review process selects among the enormous number of papers written each year and gives them a literature base of papers that subject-matter experts have found to be exceptional in some manner.
Today, we have some significant issues with the performance of this important part of SPE. In recent years, the average time that it takes for a paper to complete peer review has stretched to 8 months or longer. Several factors have contributed to this unsatisfactory state.
First, the number of papers submitted for peer review has grown by more than 25% since 2004, tracking the increase in SPE conferences offered each year—32 were held last year. In 2007, nearly 2,200 papers were submitted for review.
Second, too often, authors submit papers for peer review automatically when they submit papers for SPE meetings, without fully considering whether their papers are right for peer review. As a result, reviewers (who are all volunteers) spend considerable time sifting through papers that fall outside the coverage areas of our journals or that don't contribute something new to the industry's literature.
Third, at this busy time in our industry, our volunteers have less time than ever to devote to peer review. (Many years ago, I served as a reviewer, and I know how much time and effort our volunteers put into selecting and enhancing the best papers that ultimately become a part of our industry's archival literature. Currently, more than 800 volunteers review submissions for the five SPE journals.)
Overview: Offshore Facilities: Construction and Design (February 2008)
Authors: Valenchon Claude 
Published: February 2015

Overview
Deepwater and the Arctic, which, today, represent more than half of the world's undiscovered oil and gas resources, often are associated when it comes to the current challenges in exploration and production. But even if deepwater and the Arctic share a few common problems, those associated with arctic conditions present many unique specificities and a much wider range of technological issues.
Among the reasons, arctic areas are interpreted as those with prevailing cold-climate conditions and include, in addition to the whole area north of the Arctic Circle, the subarctic regions down to northeast Canada, Sakhalin, and the Caspian Sea (just to name the more active ones). Also, arctic means not only offshore deep and shallow areas—sometimes including areas with many challenges for very shallow developments (e.g., Kashagan) and for all shore approaches—but also onshore, with long pipelines, large plants, and all the associated infrastructure (e.g., roads and buildings).
Common features include high-technological content, heavy logistics, high sophistication of required equipment, and, certainly, high cost of development and production. In addition, subsea processing (separation, boosting, and compression) that enables solving deepwater flow-assurance issues and increasing recovery rates should bring the same advantages to Arctic production and ultimately, in some cases, could allow subsea-to-beach configurations, thus greatly reducing interaction with ice.
Remoteness, personnel safety, and environmental footprint (already very important in deepwater) take an even more important place in the highly sensitive Arctic zones. Obvious unique specificities of the Arctic are those related to the low temperatures (i.e., ice, icing, and interaction of ice, ridges, and icebergs with structures and pipelines), leading to ice strengthening and/or disconnect-ability of structures, deep burial of pipelines, ice management for offshore developments, and (for both onshore and offshore) all the difficulties linked to the presence of permafrost. All of these concerns have common major uncertainties linked to the current situation, as well as to their evolution in the future.
Even with all the unique challenges of the Arctic, these offshore developments will certainly benefit from the great experience that operators and contractors have already gained in the deepwater scene. However, developments in the Arctic will have to cope with even-more-difficult environmental challenges and larger uncertainties.
Offshore Facilities: Construction and Design additional reading available at the OTC Library: www.otcnet.org
OTC 18768 "Polyester Mooring Lines on Platforms and MODUs in Deep Water" by John F. Flory, Tension Technology International, et al.
OTC 18903 "Development of Revised Gulf of Mexico Metocean Hurricane Conditions for Reference by API Recommended Practices" by E.P. Berek, ExxonMobil, et al.
Alternative Approach to Wellhead Flowline-Pressure Protection
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18613, "An Alternative Approach to Wellhead Flowline-Pressure Protection," by Angela E. Summers and Bryan Zachary, SIS-Tech Solutions, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
For many years, pipe-specification standards have required that piping downstream of the wellhead be adequate to sustain a full wellhead shut-in. This inherently safe design practice ensured that the flowline pipe was specified with a maximum allowable working pressure (MAWP) equal to or greater than the maximum pressure expected to be produced by the well. This practice has proved to provide adequate protection in thousands of wellhead installations throughout the world. Inherently safe practice has been challenged when retrofitting electrical submersible pumps (ESPs). In such cases, the maximum discharge pressure under block-in conditions is greater than the MAWP of existing flowline pipe. A safe alternative to replacing the pipe is the use of a high-integrity protective system (HIPS) designed and managed as a safety-instrumented system (SIS) with a Safety Integrity Level (SIL) of 3.

Introduction
When the price of crude oil rose above USD 50/bbl, oil-producing companies pursued efforts to increase or renew production in existing oil wells. One solution, especially in ultradeep (4,000-ft water depth) subsea applications, is to boost well pressure. A major challenge in developing these deepwater solutions is the MAWP limitation of the downstream flowline pipe. An HIPS can close block valves placed in front of the low-specification pipe, protecting the lower-rated downstream piping.
The introduction of high-pressure ESPs in many offshore fields has increased the maximum shut-in pressure beyond the MAWP of the downstream flowline pipe. The design of the instrumented-system response is complicated by the need to respond quickly. Upon shut-in, the ESP can produce pressure sufficient to challenge the mechanical integrity of the flowline very quickly. The pressure rise is related to the compressibility of the material, but the pressure rise generally is rapid, resulting in a very-short process safety time (e.g., in liquid service, the time may be less than 5 seconds).
In typical onshore process-industry applications, an overpressure hazard such as that encountered by the ESP-well flowline would be addressed by a pressure-relief device (PRD) and a disposal system, such as a flare or scrubber to safely process the material relieved during an overpressure event. When PRDs are installed in conventional flowline designs, they typically are sized to mitigate only thermal expansion of the material when the flowline is blocked-in. For HIPS flowline designs, the PRD sizing also should consider possible block-valve leakage.
A safe and reliable alternative to replacing the existing wellhead flowlines relies on the use of an HIPS to detect unacceptable operating pressure and initiate closure of block valves. An HIPS is a special class of SIS.
Integrating Pressure-Transient-Test Data With Seismic-Attribute Analysis To Characterize an Offshore Fluvial Reservoir
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110272, "Integrating Pressure- Transient-Test Data With Seismic-Attribute Analysis To Characterize an Offshore Fluvial Reservoir," by Akshay Sahni, SPE, Ken Kelsch, SPE, Hathaiporn Samorn, and Chalatpon Boonmeelapprasert, SPE, Chevron, prepared for the 2007 SPE Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, 30 October-1 November.
Interpreting pressure-transient tests in complex faulted and stratigraphic environments can be difficult. In fluvial-depositional environments, in which sand continuity is a significant uncertainty, pressure-transient-test interpretation can generate several nonunique solutions, all of which may match test data. Use of seismic-attribute analysis to constrain pressure-transient-test interpretation leads to a better understanding of reservoir heterogeneities and boundaries.

Introduction
The integration of geology with well-test interpretation has been discussed in industry literature, as noted in the full-length paper. It has been stated that integration of geoscience and well testing reduces uncertainty in reservoir description, especially in fluvial reservoirs. This paper builds on work done in the past, use of a data set comprising seismic-attribute analysis and a long-duration pressure-buildup test, along with core, well-log, and production data.

Reservoir
Reservoir sands in the area of interest primarily are Tertiary sequences, predominantly of nonmarine origin, and deposited in fluvial to lacustrine environments. The net-to-gross ratio over the entire reservoir interval (more than 3,000 ft) typically is between 0.15 and 0.20. At this low ratio, the vertical connectivity of sands generally is very poor. Areas with a greater concentration of high-amplitude seismic events likely are associated with a high probability of better net-to-gross-ratio development (more sand prone), but not directly related to better pay (hydrocarbon-bearing sands). It can be difficult to distinguish better sand quality from pay sand. Seismic modeling of sands indicates that gas sands yield higher seismic-reflection amplitudes, but only 5 to 10% gas saturation is necessary to change the acoustic impedance significantly.
Reservoir-compartment size of the hydrocarbon-bearing sands identified in wells can be estimated by use of the seismic inlines, crosslines, and time slices. For the reservoir area under consideration, time-slice mapping indicates that the average reservoir compartment size is relatively small and is supported in most cases by well-test interpretation, production, and pressure data. There is a high level of faulting, subdividing the channel systems, and thus reducing the connected-sand area to approximately 30 to 50 acres. Larger connected areas (250 acres or more) are found on structural shoulders or outer fault blocks of a fault complex. The sand area/volume connected to a well remains one of the largest uncertainties in estimating reserves.
Comments: Recessions and Oil
Authors: Donnelly John 
Published: February 2015

Editor's column
Steep or sudden oil price spikes and recessions often have gone hand in hand. Some economists contend that a causal relationship exists between oil price shocks and global recessions, noting that nine of 10 post-World War II recessions were preceded by oil price run-ups, although the timing of the two has varied.
The global recession of 1958 curtailed oil demand and job prospects and contributed to a dramatic decline in student interest in petroleum engineering schools. However, SPE membership continued to grow during this time and it was then that the Society launched some of its most important initiatives, including the Distinguished Lecturer Series and its first technical journal. The student decline would continue to 1963 as the industry faced some of the same challenges it does today—competition from seemingly more glamorous professions, the cyclical nature of supply and demand, a weak public image, and reports that the world might no longer rely on oil in the near future. The resulting industry staffing shortage that occurred in the mid to late 1960s gave many young professionals opportunities and prosperous careers they otherwise might not have had.
In 1973, the so-called Arab oil embargo that occurred during the Arab-Israeli War led to a sudden price spike that plunged industrial nations into recession and caused steep inflation. The 1974–75 recession would cause petroleum demand to drop by 4.5%. Then the Iranian revolution and Iran-Iraq War caused another price spike in 1979. The inflation of the 1970s led to tighter monetary policies, which contributed to the deep recession of the early 1980s and significantly lower oil demand. Oil's share of global energy consumption fell to under 50% by 1985. By 1986, oil prices had plummeted to USD 9/bbl, leading to major layoffs and industry consolidation.
Subsequent recessions have had less impact on worldwide petroleum demand. The recession of 1992 saw consumption fall by about 3.5% and the recession of 2001–02 had little effect on demand. Asia's recession in the late 1990s and OPEC's slowness in reacting to it is largely blamed for the steep collapse in prices to USD 10/bbl in 1998. That price collapse helped touch off a wave of megamergers that ended the existence of such well-known companies as Arco, Amoco, and Mobil.
Economic downturns and price drops have caused significant structural changes in the oil and gas industry in the past. The shift in research and development from operators to the service sector, the loss of personnel that has led to today's shortage of technical talent, the swings in petroleum engineering enrollment, and the dramatic consolidation that occurred in the 1990s all were products to some degree of price volatility and supply/demand corrections. Some analysts caution that sharp cutbacks in capital spending, R&D, and personnel this time may only complicate things for the industry in the future. How the industry reacts to the current economic downturn will no doubt help determine its future as well.
Comments: Positive Forecasts
Authors: Donnelly John 
Published: February 2015

Editor's column
Higher oil prices, continued enthusiasm over shale, and the influx of capital are combining to paint a bright picture for the oil and gas industry this year. Both operators and the service sector appear optimistic for growth opportunities—despite some uncertainty surrounding offshore drilling—as the industry quickly rebounds from recession.
The Original E&P Spending Survey by Barclays Capital forecasts that global E&P spending will increase 11% this year, from USD 442 billion in 2010 to USD 490 billion in 2011. The survey is based on information from 402 international oil companies, national oil companies, and independents. The outlook for spending in Latin America, the Middle East and North Africa, and Southeast Asia appears particularly bright. International oil companies will post the largest increases in spending, says the study, a reversal from previous years when national oil companies led spending increases. BP, Chevron, ConocoPhillips, ExxonMobil, Shell, and Total are expected to boost expenditures by 18% in the aggregate.
Factors driving the increased spending by operators include engineering and construction spending for several large liquefied natural gas projects, increased spending in Iraq, and an increase in deepwater activity, the report said.
A recent Wood Mackenzie analysis reported that global upstream capital spending for 2010 would hit USD 380 billion and that many regions and sectors of the upstream industry are regaining confidence. Spending last year was about USD 19 billion higher than in 2009 but 10% lower than 2008. The Wood Mackenzie report said it expects spending to continue to increase in the short term and recover to 2008 levels by 2012 or 2013. The industry’s recovery is largely being led by spending on developing unconventional resources such as shale, the report said. Although most of the spending to date has been in developing US shale plays, operators are increasingly eyeing opportunities in Eastern Europe and elsewhere.
Also boosting recovery is the influx of capital. More than half of chief financial officers (CFOs) in the oil and gas industry report that their companies’ ability to access capital and credit is either the same or better than it was a year ago, according to a study by BDO USA, an accounting and consulting organization. That renewed access to capital is allowing companies to aggressively pursue the acquisition of new properties, technologies, and other companies. In addition, 95% of the CFOs surveyed expect to maintain or increase the number of personnel employed by their companies this year.
The oilfield services sector also appears healthy. The annual IHS Herold Review of the Oil Field Services Sector reported that key oil company financial performance for service companies by late last year had greatly improved, including for Baker Hughes, Halliburton, and Schlumberger as well as for offshore drilling contractors Transocean, Diamond Offshore, and Oceaneering International, among others.