bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Selfish Technology Gene
Authors: Perrons Robert K. , Watts Lew 
Published: February 2015

Guest editorial
Mother Nature may be beautiful, but she is also unapologetically harsh. Changes in an environment—such as an increase in temperature or a shift in precipitation patterns—can act as triggers that ruthlessly reshuffle the fortunes of living things within an ecosystem. Organisms that are best suited to the new conditions will prosper; the rest are swiftly killed off without an ounce of remorse. Similarly, changes in one's business environment should act as a trigger to pause and reflect on the future. Seemingly innocent changes in the prevailing winds of an industry can reshape the competitive landscape of the market with brutal efficiency.
The upstream oil and gas sector is beginning to feel the effects of just such a change, and there is every reason to believe that this shift will have a dramatic impact on the industry's "ecosystem." The sector has historically been very slow to develop and adopt new technologies, and relative investment in R&D by Big Oil has traditionally been only a fraction of that spent in other industries. Much of the oil and gas sector's R&D activities have shifted throughout the past decade toward service companies and, in some areas, to national oil companies (NOCs). But the industry is undergoing a significant transformation. With future hydrocarbon resources being in more technologically challenging environments, future winners in the industry are likely to be firms that have the ability to innovate and develop unique breakthrough technologies, and international oil companies (IOCs) are now working hard to strengthen their in-house R&D capabilities.
Just as important as the technologies themselves, however, is how companies try to deploy them. Several of the accepted norms of the oil and gas sector are also barriers that impede the introduction of innovations in the industry. First, companies in the oil and gas market have used shared asset-ownership structures as a way to manage risk, but firms quite reasonably refrain from laying their cards on the table—that is, from revealing their cutting-edge innovations—if they believe that these tools and techniques will be immediately absorbed and replicated by the other partners. Second, partner firms often quash new-technology proposals because they are not convinced of the value of the innovation and/or they are uneasy about the additional layers of perceived risk that new technologies tend to carry with them. There always seems to be a reason not to use a new technology, and having many partners in an asset frequently begets frustratingly long lists of excuses.
New R&D White Paper Addresses Challenges for Future Energy Supply
Authors: Moon Ted 
Published: February 2015

R&D white paper
Over the next 30 years, the world's economies will need more energy to fuel their growth, and the oil and gas industry will have to increase investment substantially in research and development (R&D) in order to keep pace. This fact is the central theme of a new white paper from SPE's R&D Advisory Committee titled "The R&D Challenges to Secure Energy Supply for the Third Trillion Barrels and Beyond."
The third trillion refers to a US Geological Survey estimate that there are more than 3 trillion bbl of recoverable conventional oil worldwide, with one-third already consumed and the remaining two-thirds largely in the possession of national oil companies (NOCs). As worldwide energy demand grows by more than 50% by 2030 [according to the International Energy Agency (IEA) World Energy Outlook 2006], the oil and gas industry will need to rely heavily on R&D advances, according to Vikram Rao, SPE, Chairman of the R&D Advisory Committee and Senior Vice President and Chief Technology Officer for Halliburton.
"The 12-member R&D Advisory Committee has raised a number of initiatives since its inception in 2002, all designed to raise the profile of R&D in the energy industry," Rao said. "The committee's new white paper was written with one initiative in mind, to promote awareness of R&D challenges impacting the industry to an audience outside of the petroleum community."
"The white paper is mainly concentrated on demographics of what the next 1 to 2 trillion bbl will look like," said Arnis Judzis, SPE, one of the paper's main committee coauthors and Vice President of Schlumberger Data and Consulting Services. "We wanted to relate the myriad challenges associated with producing the unconventional and alternative energy sources that will be needed."
Rao agreed, adding that, "It was intended to be a manifesto, a way to shed light on the imperatives for the industry, and to begin a dialog on the areas of endeavor that are fruitful for R&D."
Before the industry can bear the fruits of an increased energy offering, a significant increase in oil and gas R&D spending will be needed. According to 2007 estimates by the IEA, this investment will need to be on the order of USD 8.2 trillion over the next 25 years. Over the past 25 years, energy R&D investment as a percentage of total R&D declined from 10% to roughly 2% in the US alone. The IEA reports similar declines on a global scale over the same time period.
Major R&D investments over the past 15 to 20 years have focused on technologies designed to find and produce more conventional hydrocarbons, including advances in 3D and 4D seismic, directional drilling, and production in frontier areas such as the deepwater Gulf of Mexico and Brazil. "These technologies will not meet our future needs, and we will need to collaborate on new technical innovations and diversify our energy supply going forward," said Rao.
Trapped Annular Pressure: A Spacer Fluid That Shrinks
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 104698, "Trapped Annular Pressure - A Spacer Fluid That Shrinks," by B. Bloys, SPE, and M. Gonzalez, SPE, Chevron; R. Hermes, Los Alamos Natl. Laboratory; R. Bland, R. Foley, SPE, and R. Tijerina, Baker Hughes Drilling Fluids; J. Davis and T. Cassel, Baker Oil Tools; J. Daniel, I. Robinson, and F. Billings, Lucite Intl.; and R. Eley, ICI, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February. The paper has not been peer reviewed.
In subsea-completed wells, fluids commonly are trapped in casing annuli above the top of cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced oil and gas, thermal expansion can create very high pressures and cause the collapse of casing and tubing strings. A successful midscale field trial has been conducted in a 500-ft test well to gauge the ability of a liquid monomer that shrinks 20% upon experiencing heat-triggered polymerization to mitigate trapped annular pressure (TAP). A method was devised to add the initiator on the fly as the spacer is pumped downhole.

Introduction
TAP, also called annular-pressure buildup, is caused by the thermal expansion of fluids trapped in casing annuli between the top of cement and the wellhead. The pressure buildup usually is a result of heat transfer from the produced fluids or from hot drilling fluids circulated while drilling a high-pressure/high-temperature (HP/HT) well. The pressure can exceed the collapse strength of the casing and production tubing. In land wells, the pressure is relieved easily by bleeding off some fluid through a casinghead valve. In subsea-completed wells, wellheads are much less accessible and generally not fitted with the necessary valves.
One of the best-documented cases involved the Marlin field, where the production casing and tubing of the first production well collapsed after only a few days of production. A wide range of mitigation techniques has been used, including vacuum-insulated tubing (VIT), leaving the previous casing shoe uncemented, burst disks in casing, nitrogen-based spacers, and crushable urethane foam.
Perhaps the most successful mitigation approach has been use of VIT. This technique generally has been successful in keeping the annular-fluid temperatures within an acceptable range. However, with the advent of deeper and hotter wells in deep water, the limits of the protection provided by VIT are being approached in two ways. First, deeper wells have much higher hanging weights that are reaching the stress limits of VIT designs. Second, the greater depths also are producing at higher temperatures. Even with the insulating effects of VIT, temperatures are sufficiently high that pressures are predicted to increase to dangerous levels.
Deepwater Blowout: A Case Study
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105914, "Deepwater Blowout - A Case History: Shallow Gas Hazards Hide in the Weeds," by William Flores Jr., John B. Garner, SPE, and Chris Scarborough, SPE, Boots & Coots, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20-22 February. The paper has not been peer reviewed.
The full-length paper details the sequence of events of a blowout in 2,400-ft water depth of a deepwater development well adjacent to the discovery well. Loop current prevented running the blowout-preventer (BOP) stack and riser after cementing surface casing. After 3 weeks, the loop current abated, and a remotely operated vehicle (ROV) could be deployed. Upon deployment, it was discovered that the development well was blowing out, with the blowout plume carrying more than 300 ft.

Introduction
The prospect was drilled initially in 1997 and abandoned as a result of economics at that time. In the course of planning, a shallow gas hazard was identified from seismic, and records from the 1997 well reported several nonproductive days fighting lost circulation and gas.
To avoid the nonproductive time encountered on the 1997 well, the operator designed a casing program for the first development well to include riserless drilling of the shallow gas hazard using the pump-and-dump process. Development Well 1 was drilled successfully in this manner and was completed as a producer in April 2006. The well currently is shut in, awaiting field development and production facilities.
The rig was moved to a second location. Well 2 was spudded on 3 April 2006 less than 2,000 ft from Well 1 and drilled riserless through the shallow hazard. Structural pipe was jetted to 2,778 ft, which is 285 ft below the mudline. The 30-in. casing was allowed to soak for 4 hours. A 24-in. hole was drilled to 3,200 ft using seawater and gel sweeps. From 3,200- to 3,899-ft total depth (TD), a pump-and-dump system was used, maintaining a 10.5-lbm/gal equivalent mud density, by monitoring equivalent circulating density (ECD) with pressure-while-drilling (PWD) instrumentation and vortex mixing 16.0-lbm/gal water-based mud "on the fly" with seawater. A wiper trip was attempted. However, the well appeared to begin to flow with pipe at 3,597 ft. The pipe was tripped to bottom where circulation was begun and the equivalent mud weight (EMW) was increased to 10.7 lbm/gal. Circulation was stopped, and the well was observed to be static. A wiper trip then was made without problems. With no fill on bottom, the well was circulated again with a 10.7-lbm/gal EMW. While keeping the hole full, the pipe was pulled out of the hole to run 20-in. casing. The well, standing full of mud, was monitored by an ROV while preparing to run casing.
Fluidic Oscillation With Acid Stimulation Improves Gas-Well Productivity
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11452, "Fluidic- Oscillation Technique in Conjunction With Acid Stimulation Improves Gas- Well Productivity," by Ahmed Hegazy, Belayim Petroleum Company, and Bruce Conrad, Arshad Waheed, and Osama Sanad, Halliburton, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4–6 December. The paper has not been peer reviewed. Copyright 2007 International Petroleum Technology Conference. Reproduced by permission.
Low productivity of gas wells in the offshore Mediterranean Sea operations of Egypt often is caused by near-wellbore formation damage. The stimulation technique will vary depending on the type of damage; however, prevalent techniques are hydraulic fracturing and matrix acid stimulation. A new technique called "fluidic oscillation" was proposed, which would be especially applicable in cases having uncertainties regarding rock mineralogy. Fluidic oscillation is a mechanical, nonfluid-invasive stimulation technique (i.e., it is not essential to inject the treatment fluid into the reservoir to break down damage, although its use in that manner is not precluded). This technique was successful in stimulating gas wells in Egypt.

Introduction
The main challenge after completing two high-rate gas wells was less-than-expected production. These wells are approximately 37 miles off the Mediterranean Sea coast in the PetroTemsah field, northwest of Port Said in Egypt. This field produces gas and condensate with a condensate/gas ratio (CGR) of 60 bbl/MMscf. The producing formation is the Sidi Salem formation of Serrvallian age (Miocene), with an average porosity of 22%, average water saturation of 30%, and an average permeability of 100 md. This formation consists of four main reservoir layers (Lobe-0, -1, -2, and -3) and is at a depth of approximately 14,000 ft with a bottomhole temperature of 230°F. The bottomhole pressure ranges from 7,400 to 8,000 psi. A complete mineralogical breakdown of the rock by weight is not available, but essentially the rock is clean sandstone (80% quartz with 3 to 4% calcium carbonate and 10 to 15% feldspars and clay).
The Sidi Salem formation is unconsolidated, and without adequate sand control, the wells tend to sand up, ceasing all flow from the reservoirs. The sand-control techniques used for the field include openhole gravel packs, expandable sand screens, and cased-hole gravel packs. The first example is an openhole completion with an expandable sand screen set across the zones of interest. The second well has an inside-casing gravel-pack completion.
High-Pressure/High-Temperature Consolidated Completion in the Gulf of Mexico
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18976, "High- Pressure, High-Temperature Consolidated Completion in the Continental Shelf Environment of the Gulf of Mexico: Case History," by Richard E. Patterson, SPE, and Trevor J. Willms, SPE, El Paso E&P, and Keith Foley, SPE, and Jason Edwards, SPE, Halliburton, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
Decades after the first completion in the Gulf of Mexico (GOM) continental shelf, the logical expansion of these mature assets has extended into reservoirs that are deeper, hotter, and higher-pressured than wells completed previously. These high-pressure/high-temperature (HP/HT) wells can cause extreme completion challenges. HP/HT formations also tend to have low permeabilities, which is the opposite of most GOM reservoirs. To make these low-permeability formations economical in an offshore environment, it is imperative that stimulation treatments be completely effective.

Introduction
The West Cameron 62 field, on the continental shelf just south of Louisiana at a water depth of 35 ft, had its first well completed more than 20 years ago. Since that time, more than 30 different intervals have been completed at depths ranging from a few thousand feet to more than 10,000 ft. In recent years, it has become necessary to focus on reservoirs that exist in the 18,000 to 20,000 ft true vertical depth (TVD) range. At these depths, the pressures and temperatures of the formation trend toward the limit of what current technology allows when completion equipment and fluids are considered. The West Cameron 62 Well A-2 was completed at these depths in the Cris R formation.
The Cris R sand is located between 17,843 and 18,021 ft TVD, which correlates to 19,789 and 19,976 ft measured depth (MD), respectively. The initial bottomhole pressure (BHP) for the Cris R formation was measured at 16,500 psi at midperforation. The bottomhole temperature (BHT) at midperforation was 356°F.
Contrary to conventional GOM reservoirs, which typically have average permeabilities greater than 50 md, the permeability of the Cris R sand averaged only 0.64 md. The 18% porosity also was significantly lower than that of the well-sorted formations found at shallower depths. In fact, along with permeability and porosity, the rock mechanics falls more in line with typical south Texas "hard rock" reservoirs such as the Wilcox and Frio formations.
Despite the low permeability and porosity, the production of the well before the hydraulic-fracturing treatment was 12.0 MMscf/D and 396 B/D of condensate at a 8,572-psi flowing tubing pressure (FTP). Use of fracture models and nodal analysis led to the belief that the production rates could be increased by at least two-fold through implementation of a hydraulic fracture. However, very little information on HP/HT fracturing treatments in the GOM was available.
Your SPE: SPE Managing Costs and Maintaining Quality
Authors: Roodhart Leo 
Published: February 2015

President's column
We are a bit further into the year since I wrote my last column, and unfortunately the global economic crisis deepens. Companies have already tightened such things as travel budgets and will certainly be watching cash flow very carefully. I maintain, however, that this is the time we should focus on preparing for the next upturn by retaining capacity and developing or improving the relevant technology. In an ideal world, R&D and training would be anti-cyclic to the economic cycle: use a lower demand on staff in a downturn to train them for the next phase and allow this human capital to develop new ideas/R&D when there is time for it. Now, more than ever, companies should be seeking innovative ideas and technology to reduce their operating costs and produce better results.
Crisis or no crisis, SPE presidents have to travel. So, I am writing this column on a low-cost airliner visiting sections in India. I am over 6 ft tall, so I am particularly averse to cramped budget seating! However, if our members have to tighten their belts, so does SPE.
The Fiscal Year 2010 budget, which begins 1 April, reflects significant economies in both operating (which includes staff travel) and program expenses. Through the year, we will exercise additional cost-cutting measures to achieve even more savings in program expenses. We'll use technologies like Skype or WebEx for committee meetings, renegotiate contracts with hotels and conference venues wherever possible, and hold both committee meetings and events in more cost-effective locations. For instance, why do we need to hold a workshop committee meeting in a hotel for USD 1,000 if one of the committee members has an office with meeting rooms to do the same! At the same time, both volunteers and staff will do everything possible to increase the quality of SPE programs. We might have fewer papers at a conference, but we (the program committee) will ensure that the quality of the papers will be higher. We can do that, as most conferences now get more abstracts than previously (in earlier downturns, the saying in my company was "He who publishes, stays."), which allows us to choose the very best and focus presentations in fewer but better sessions. So please come, as SPE conferences will be better than ever!
For many of you, though, travel constraints are a bottleneck. Our response is to place SPE's technical conferences and workshops close to major petroleum operations to help reduce or eliminate travel costs. We are even examining whether we can relocate some currently scheduled events to be more conveniently placed. We also plan to make greater use of technology in the development of event programs to make members’ participation easier and to reduce the number of committee meetings that volunteer organizers will be asked to attend.
Proper Inventory Management Requires Sound Analysis and Technology
Authors: Turner Bert 
Published: February 2015

Management
Corrosion remains a major challenge to maintaining the integrity of infrastructure in oil and gas fields, particularly at the subsurface. A recent SPE Applied Technology Workshop in Abu Dhabi, UAE called "Subsurface Corrosion Risks and Challenges" highlighted critical aspects of subsurface corrosion control, including selection of corrosion-protection methods, improving drilling practices to minimize corrosion, and assessing downhole corrosion-monitoring techniques.
The welcome address by Qasem al-Kayoumi of Zadco highlighted the importance of organizations working together to identify critical subsurface corrosion challenges, share and agree on best practices, and identify the best existing downhole corrosion-mitigation technologies. To understand the technical areas where additional focus is required, networks must be formed between the operators, well engineers, and service providers. Al-Kayoumi said that Zadco has gained valuable subsurface experience by creating a seamless co-operative relationship with other operators. Zadco has also sponsored projects for downhole corrosion-modeling programs.

Materials for Oil and Gas Production
The first technical session of the work-shop highlighted materials used in oil and gas production. Keynote speaker Bijan Kermani of KeyTech opened by stating that hydrocarbons will continue to be the world's principal energy source in the foreseeable future. The expected growth in energy demand will spur increases in production, which will become more multiphase in nature and contain higher percentages of harsh components such as hydrogen sulfide (H2S) and carbon dioxide (CO2). These acid gases in high water-cut production systems present major corrosion concerns.
Therefore, material selection must become more specific to mitigate corrosion, and the impact of corrosion with regards to health, safety, and the environment; capital expenditure; and operational expenditure must receive continued serious consideration. Kermani said that materials selection must be coupled with ‘near-realistic’ corrosion modeling and prediction for optimum integrity assurance.
Zadco's Obadah Al-Sawadi next discussed the principles of corrosion modeling and prediction as they relate to materials selection. He stated that any useful model should be able to accurately predict corrosion rates as operating conditions change and account for actual tubing conditions rather than predict the phenomena at only one set of design conditions. A successful modeling program should also clearly define target corrosion rates to assess whether carbon steel or a corrosion-resistant alloy (CRA) should be employed. Finally Al-Sawadi highlighted several continuing challenges for accurate modeling programs, including obtaining accurate field data, the large number of variables involved and their relevance, and changes in the operating regime.