bluuebunny/crossref_metadata_2025_split huggingface dataset:
En Route: How Do We Pay for SPE Programs and Services?
Authors: Labastie Alain 
Published: February 2015

President's column
The issue of costs of SPE programs and services comes up periodically, so I would like to talk about that in this column. We recently received remarks from some members about the fees they were paying to attend an SPE workshop. Their perception was that because the workshop program was organized by volunteers, there was virtually no cost for SPE and thus SPE was making a huge profit. Although I can see how this perception can come about, the conclusion is simply not accurate. Most SPE events break even financially, and any surplus that is generated by SPE events is used to support other SPE programs that members value but are not self-supporting.
First, it is important to remember that SPE is a not-for-profit organization. This means that we do not conduct programs just to make money—we put our revenues back into member programs and services. Our programs fall into four substantially different financial perspectives:
A few—mostly the major conferences (Offshore Technology Conference and Offshore Europe, for example)—generate large financial surpluses.
Some—workshops, for example—generate modest surpluses, but we are continually challenged to maintain a positive balance overall.
Some—like the peer-reviewed journals—are not self-supporting, since subscriptions and advertising provide only partial recovery of expenditures.
And finally, some—like the Distinguished Lecturers program and scholarships—generate zero income and have only costs associated with them. These programs simply could not be continued if we did not have a financially successful meetings portfolio.
Events are the primary source of SPE revenues. Because they are so critical to supporting the other programs and services, let me talk about those in a little more detail.
Yes, volunteers’ efforts are critical to formulation of the technical program. But there are many direct costs associated with an event. We have to pay for all logistics: meeting rooms, audio-visual equipment, coffee and food for breaks and lunches, printing and distribution of materials, etc. These events also require a lot of staff time. It is not only the event staff, but also staff who work on marketing, website, registration, accounting, sponsorships, and other activities required to run the events and make them successful. At the end, most of the fee paid by a workshop registrant is used to cover the direct costs. To generate some revenue for other SPE activities valued by members that generate little or no revenue, we target a modest profit—much less than people are very often thinking; Even so, many workshops just break even or lose money.
Shell: Leadership Built on Innovation and Technology
Authors: Parshall Joel 
Published: February 2015

Company Profile Series - This is the latest in a series of profiles of leading operators, including key international and national oil companies, around the globe. The focus is on the company's strategic direction, relationship to its government, major upstream activity, and significant technology challenges and applications.
Royal Dutch Shell stands among the very largest international oil and gas companies (IOCs) by any measure. The most recent Fortune Global 500 ranked Shell as the world’s largest energy and second largest publicly traded company by revenues. Figures and rankings fluctuate from year to year, but few corporate names, if any, are more widely known worldwide, and the company’s shell symbol—the pecten, as it is precisely called—is surely one of the most recognized logos around the globe.
Shell has reserves of 12.4 billion BOE, consisting of 4 billion bbl of crude oil and natural gas liquids (NGLs) and 49.1 Tscf of natural gas. Shell in 2009 produced nearly 1.6 million B/D of oil and NGLs and 8.5 Bscf/D of natural gas, along with 80,000 B/D of synthetic crude and 19,000 B/D of bitumen. The company reported income of USD 12.7 billion in 2009 on revenue of 278.2 billion. Shell has 101,000 employees and conducts business operations in more than 90 countries.
Based in The Hague and incorporated in England and Wales, Shell has its roots in the United Kingdom and the Netherlands.
Company Origins
“Shell” Transport and Trading was founded in 1897 by merchant Marcus Samuel in London, an outgrowth of a successful export-import business started in 1832 by his father, also named Marcus Samuel. During a trip to the Caucasus and Japan in 1890, the younger Samuel first recognized the potential of trading lamp oil from Baku, Russia, to the Far East and while by the Black Sea saw a very primitive bulk tanker. Vessels that could carry oil in bulk tank-age, he reasoned, would be far more efficient than the oil tankers of that day, which carried barrels that took up extra hold space, added weight, and were prone to leak.
Understanding First, Simulation Later
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132781, ’Understanding First, Simulation Later: Using Basic and Modern Reservoir- Engineering Techniques To Understand Reservoir Dynamics: A Proven Case,’ by Hector Gomez Alonso, SPE, Sarawak Shell Berhad, originally prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.
The full-length paper describes a mature field in which water production was seen very early in production life and rapidly increased to the current level of 80% water cut. At well level, a similar behavior has been noticed: high initial oil rates with subsequent strong decline once water breakthrough occurs. This type of behavior has been observed in most of the wells completed among the different reservoirs that make up the field. Long-term production data and modern decline analysis strongly indicated the presence of two systems in the reservoir.
Introduction
The full-length paper shows how important it is to have a strong understanding of reservoir dynamics before using 3D reservoir-simulation models and, especially in this case, how the use of simple and modern analytical techniques such as Chan plots, transient tests, and conventional and modern decline analysis can provide the reservoir engineer with sufficient background to take the next step confidently. The paper also describes how pseudosteady-state calculations provided information regarding the characteristics of the second system, which helped to optimize the original petrophysical interpretation in the static model. This represents a simple approach to consider how detailed a geological model need to be to reproduce production behavior.
Usually, in mature fields, there is a considerable amount of information available regarding production, pressures, fluid samples, and transient tests, which sometimes is not analyzed properly because there is not sufficient time or the data are not easy to find. Reservoir engineers sometimes have the tendency to jump directly into dynamic simulation to understand the dynamics in the reservoir and generate predictions. The objective of following the methodology described, before engaging in the use of reservoir simulation, is to try to understand what really is going on at the subsurface level. If this is achieved, the reservoir engineer always will be ahead of the simulation model and not the other way around. Simulation models should be treated as tools in which equations are solved, by using input data (e.g., rates, pressures, pressure/volume/temperature, and relative permeability).
Reducing the Hidden Costs of Subsea Well Completions
Authors: Rassenfoss Stephen 
Published: February 2015

Subsea completions have made it possible to produce oil in remote locations and from smaller reservoirs. But the cost of maintaining them may shorten their productive lives.
“Subsea wells have the same things that go wrong as other wells, but fixing them requires moving in a rig and the cost can often be USD 1 million a day,” said Matthew Law, technical manager of sales and marketing at Expro Ax-s Technology. “Where there is direct access from a production platform, there is generally regular well intervention. As a result, the recoverable reserves are higher.”
Major producers such as BP, Chevron, ExxonMobil, Statoil, and Shell are among those seeking to cut the cost of deepwater workovers by 50% or more to allow better maintenance. There is no accepted industry average for how much production can be gained from regular interventions. The consensus is that the potential impact on the thousands of subsea completions represents billions of dollars worth of hydrocarbons.
“One of the biggest challenges in (increasing) deepwater recovery rates is the cost of re-entry is so high,” said Peter Sharpe, executive vice president of wells at Shell.
Drilling rigs are capable, but it can cost USD 5 million to just diagnose why production is down on a subsea well. Based on offshore workovers generally, the payoff for deepwater work will range from simple fixes that yield significant gains, to difficult cases where the repair cost far exceeds the likely return. Most wells fall somewhere in between.
The experience of operators in the relatively shallow waters of the North Sea shows there is a return for investing in regular subsea well maintenance. The cost and technical challenges rise in deep water, where the lower-cost methods used in the North Sea are now being tested. Without significant cost reductions, the cost of repairs that can slow production declines on 10 wells can exceed the cost of a deepwater exploration that might deliver far more in the near term. To reduce cost, the industry is considering a mix of proven technologies and emerging ones. Much of the work is directed toward using construction boats rather than drilling rigs.
“Cost is one of the drivers, but we are also looking at keeping these activities off drilling rigs to allow more exploration and development work,” said Colin Buchan, well delivery manager for floating hoist at Shell. “They are complex machines designed to drill wells. They were not designed for well interventions.”
Storing CO2 With Next-Generation CO2-EOR Technology
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139717, ’Storing CO2 With Next-Generation CO2-EOR Technology,’ by R.C. Ferguson, SPE, V.A. Kuuskraa, SPE, and T.S. Van Leeuwen, SPE, Advanced Resources International, and D. Remson, US Department of Energy, National Energy Technology Laboratory, prepared for the 2010 SPE International Conference on CO2 Capture, Storage, and Utilization, New Orleans, 10-12 November. The paper has not been peer reviewed.
Carbon dioxide enhanced oil recovery (CO2-EOR) has potential for storing significant volumes of CO2 emissions while increasing domestic oil production. The causes of suboptimal CO2 storage and oil-recovery efficiencies by current CO2-EOR practices were examined to determine how a group of advanced or “next-generation” CO2-EOR technologies could increase CO2-storage volumes and oil recovery.
Introduction
A six-part method was used to assess CO2 storage and the EOR potential of domestic oil reservoirs. These steps were assembling and updating the major-oil-reservoirs database; calculating the minimum miscibility pressure for applying CO2-EOR; screening reservoirs favorable for CO2-EOR by use of the minimum miscibility pressure and other criteria; calculating oil recovery from applying next-generation CO2-EOR technology; applying updated costs in an economic model; and performing economic and sensitivity analyses to understand how the combined effects of technology and oil prices influence the results of applying next-generation CO2-EOR and CO2-storage technology.
Domestic-Oil-Resource Base
The USA has a large oil-resource base, on the order of 597 billion bbl of oil originally in place (OOIP). Approximately one-third of this oil-resource base, 204 billion bbl, has been recovered or placed into proved reserves with existing primary- and secondary-oil-recovery technologies. Therefore, 393 billion bbl remains unrecovered as “technically stranded” oil.
Much of this “stranded” oil is in east and central Texas (74 billion bbl), the midcontinent (66 billion bbl), and the Permian Basin of west Texas and New Mexico (62 billion bbl). California, Alaska, the Gulf Coast, and the Rockies also have significant volumes of “stranded” oil.
Not all of the remaining domestic oil resource is technically amenable to CO2-EOR. Favorable reservoir properties for miscible CO2-EOR include sufficiently deep formations with lighter (higher-gravity) oil. Some of the shallower oil reservoirs with heavier (lower-gravity) oil may be amenable to immiscible CO2-EOR.
Impediments to Current CO2-EOR Performance
Large volumes of oil are left stranded after primary- and secondary-oil-recovery methods are completed. This includes oil that is bypassed because of poor water-flood sweep efficiency; oil that is physically unconnected to a wellbore; and, most importantly, oil that is trapped as residual oil by viscous, capillary, and interfacial-tension forces in the pore space.
Technology Focus: Mature Fields and Well Revitalization (January 2012)
Authors: Ali Syed A. 
Published: February 2015

Technology Focus
Revitalizing mature fields embraces multiple objectives, especially maximizing production while minimizing capital expense and reducing the inevitable decline rate and minimizing the operating expense. The collective approach to meet these objectives is application of practical and focused engineering and geology tied with the application of enabling technologies.
Key enabling technologies in the revitalization of mature fields include reservoir simulation, advanced characterization techniques (e.g., 3D seismic and new measurement, tomographic, and visualization techniques), permanent downhole reservoir monitoring, horizontal and multilateral drilling, geosteering, production-enhancement techniques (e.g., secondary- and tertiary-recovery schemes), improved perforation and stimulation methods, new fracturing techniques and fluids, cutting-edge completion technologies, advanced logging techniques, artificial-lift optimization, and conformance control.
Implementation of appropriate enabling technologies can extend the producing life of mature fields. Yet the complexity of some of these fields can still present formidable challenges. It takes the right data, the right tools and techniques, and the right team to create an efficient, cost-effective field-development plan to optimize an aging asset.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 142790 Cleveland Formation—Recent Results and Lessons Learned During Horizontal Redevelopment of a Mature Field. By David Bumbaugh, BP.
SPE 138202 Identifying the Remaining Opportunities in a Mature Field—A Case Study. By Badr Ali Al-Amri, Petroleum Development Oman, et al.
OTC 21382 Marginal Fields: Technology Enables Profitability—Marginal Fields and Their Challenges. By Samuel Husy, Total.
IPTC 14258 Burgan Multilateral Campaign: A Success Story in Development of a Complex Siliciclastic Reservoir in Kuwait. By Javed Ahsan, Kuwait Oil Company, et al. This conference was rescheduled to 7–9 February 2012; the paper will be available at that time.
Marlim Field: Mature-Field Optimization
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139376, ’Marlim Field: An Optimization Study on a Mature Field,’ by Dirceu Bampi, Petrobras, and Odair Jose Costa, Halliburton, prepared for the 2010 SPE Latin American & Caribbean Petroleum Engineering Conference, Lima, Peru, 1-3 December. The paper has not been peer reviewed.
Giant fields provide a significant portion of the total hydrocarbon production in Brazil. Most of these fields are in advanced exploitation stages. A drainage-optimization study was performed on the Marlim field, a giant and mature field in the Brazilian Campos basin. Reservoir-flow simulations were used to optimize the methodology and increase the recoverable-oil volume by accelerating the oil production. As a result, new-well proposals became more economically attractive.
Introduction
The Marlim field, discovered in 1985, is in the northeastern part of the Campos basin in water depths between 600 and 1200 m. Reservoir depths are 2500 to 2750 m, with temperatures between 65 and 72°C. Marlim is part of a large complex of reservoirs including the Marlim Sul and Marlim Leste fields. The original oil in place is 1.012×109 std m3, and the maximum permeable thickness is 125 m. The reservoir is unconsolidated sand-stone with an average net-/gross-thick-ness ratio of 86%, average porosity of 30%, and permeability of 1 to 10 dar-cies. The petrophysical analysis indicated original water saturation of 15%, saturation pressure of 265 kgf/cm2, and residual-oil saturation of 23%. The oil at reservoir conditions has a viscosity of 4–8 cp and gravity of 18–25°API. The reservoir is divided into five stratigraphic zones. Every zone is in hydraulic communication, although, in some areas, the communication is somewhat constrained. The reservoir has small aquifers underlying the oil, and solution-gas drive is the main production mechanism. The reservoir is undergoing a secondary-recovery process by use of seawater injection.
Production startup occurred in March 1991, and water injection began in September 1994. Peak production occurred in April 2002 with 9.79×104 m3/d. Oil production averaged 4.48×104 m3/d, with water cut of 54% in April 2010. The cumulative oil production surpassed 3.18×108 m3 in April 2010, representing 32% recovery. The field contains more than 200 wells, with 125 in operation and a producer/injector ratio of 1.85.
The current reservoir-exploitation stage, with oil-production decline and a significant increase in water production, presents serious challenges in maintaining extraction cost at acceptable levels. To accelerate field oil production and increase the recoverable volume, this simulation-optimization study considered drilling 16 new producing wells and attempted to identify targets for future sidetracks from these new wells.
Technology Focus: Well Control (January 2012)
Authors: Schubert Jerome 
Published: February 2015

Technology Focus
Procrastination: Is it too many things going on at once that causes us to rush to meet deadlines, or makes us forget to complete important tasks in a timely manner, or even try to do too many things at once, resulting in nothing getting done correctly? You probably are wondering how this relates to well control. In our work schedules, we all are faced with situations in which we are required to complete multiple concur-rent tasks. This often is the case when we rush to finish drilling a problem well so that we can get the drilling rig moved to the next location and turn this well over to the completions team. Multiple activities must be completed concurrently that, individually, are relatively simple, but each activity requires the attention of the driller, tool pusher, company man, and others on the crew. When one of these tasks begins to go awry, our attention may be on something else, and we can miss important warnings until it is too late to avoid a disaster.
What is the point? Once again, I will use the Macondo blowout as an example. To leave the well in a position to be completed by another crew, mud had to be removed from the riser and top of the well and be replaced with seawater. A spacer was pumped between the mud and seawater to prevent mixing of the seawater and mud. This is a simple enough operation, it seems, but when seawater is being pumped into the well, mud has to be pumped onto a workboat to prevent the pits from running over, and the spacer is being dumped overboard; keeping track of how much of each fluid is going where becomes a daunting task. Could this have been a contributing factor in not recognizing the beginning of the kick?
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 138465 Qualification of Well-Barrier Elements—Test Medium, Test Temperatures, and Long-Term Integrity. By Birgit Vignes, SPE, University of Stavanger.
SPE 142076 Well-Integrity Analysis in Gulf of Mexico Wells Using Passive Ultrasonic Leak-Detection Method. By J.E. Johns, Seawell, et al.
SPE 140255 Development of an Automated System for the Rapid Detection of Drilling Anomalies Using Standpipe and Discharge Pressure. By Don Reitsma, SPE, @balance-A Schlumberger Company.
SPE 143101 A Proposed Method for Planning the Best Response to Kicks Taken During Managed-Pressure-Drilling Operations. By J.R Smith, SPE, Louisiana State University, et al.
Kick Mechanisms and Well-Control Practices in Deepwater Vugular Carbonate
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14423, ’Kick Mechanisms and Unique Well-Control Practices in Vugular Deepwater Carbonates,’ by F.E. Dupriest, SPE, ExxonMobil, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 15-17 November. The paper has not been peer reviewed. Conference rescheduled to 7-9 February 2012. Copyright 2011 International Petroleum Technology Conference. Reproduced by permission.
Standard well-control training that drillers receive prepares them to respond to an influx that occurs during underbalanced conditions. The mechanism by which hydrocarbons may enter the wellbore following a vugular loss can be different. One potential result is that the influx may not be detected as early as during conventional underbalanced conditions. A model was developed to explain the unique mechanism by which kicks may occur following vugular losses. Effective recognition and response practices are proposed that are consistent with that model.
Introduction
When massive losses occur in vugular formations, the well’s behavior does not follow a conventional well-control scenario. Gains in pit volumes are not seen despite hydrocarbon entry, and kicks can go undetected until they have traveled some distance up the annulus. Once the kick is detected, backpressure cannot be held effectively to prevent further influx while circulating the initial kick out and the annulus-pressure trends and values appear to be unpredictable. It also is difficult to control the placement of fluids or pills. The most significant challenge is the inability to detect an influx as soon as it occurs. In deepwater wells, the distance from the vugular zone to the subsea blowout preven-ters (BOPs) may be short, as shown in Fig. 1.
Operators are aware of these behaviors, and the industry has developed unique practices for drilling vugular carbonates safely. Rigs having surface BOPs address the risks by use of a rotating control device (RCD). RCDs have been used in a similar fashion at the surface on marine risers with subsea BOPs. The RCD has been installed at the top of the riser above the slip joint, and a tension-ring system is under development that will enable the RCD to be placed below the slip joint. In subsea applications, the pressure that can be applied below the RCD is more limited than on land locations, usually to the rating of the slip joint or marine riser. In some cases, the rating is adequate for the given well. In other situations, the pressure limitations of the riser system or RCD may not provide the robust capability needed.