bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: Health, Safety and Environment (July 2007)
Authors: Veil John 
Published: February 2015

In March, professionals from many countries gathered in Galveston, Texas, for the biennial SPE E&P Environmental and Safety Conference. Although this conference has included some safety papers in the past, this time safety was one of the featured themes. The industry's safety experts presented many excellent papers, several of which are featured here. Likewise, the conference included many fine papers on environmental topics.
Each day, the media bring us stories about climate change. Most scientists now agree that the climate is getting warmer and that human activities, including combustion of fossil fuels, are contributing to the warming. Although the international community has not reached consensus on the causes of and the solutions to the warming trend, even some previously reluctant executives and politicians are joining the call for some type of action. The oil and gas community has contributed and will continue to contribute information and research on ways to mitigate the warming trend. Many good papers on carbon dioxide capture and storage were presented during the past year.
The health and safety of oil industry workers remains a priority for industry managers. Even routine operations, such as driving trucks or unloading work-boats, pose risks that must be evaluated and addressed. One of the featured papers describes the important work of an industry task force in identifying and compiling recommended land-transportation practices to protect workers.
During late 2005, Hurricanes Katrina and Rita moved through the Gulf of Mexico, creating major disruptions of offshore and onshore activities in the area. Numerous platforms were damaged. The occurrence of two large and violent storms in a high-petroleum-activity area points out the risks of working in the offshore environment. Much of the damage has been repaired or removed. Several papers this year describe the devastation caused by the storms as well as the measures taken by the industry for coping with future storms.
Health, Safety, and Environment additional reading available at the SPE eLibrary: www.spe.org.
SPE 106827 "OGP Land-Transport-Safety Recommended Practice: An Industry Standard for Land-Transport Safety" by Derek Tate, SPE, Schlumberger
SPE 106610 "Mercury-Removal System for Upstream Application: Experience in Treating Mercury From Raw Condensate" by Muhamad Rashid Sainal, Petronas Carigali, et al.
SPE 106697 "Security Is Everybody's Business: Transforming Security Into a Core Business Practice in the HSE Model" by Stephen B. Simmons, ExxonMobil, et al.
SPE 106913 "An Innovative Utilization of Drilling Wastes as Building Materials" by Ta-Lin Chen, National Cheng Kung University, et al.
Top 10 Risks for the Oil and Gas Industry
Authors: Jessen Rob 
Published: February 2015

Guest editorial
Risks are inherent in every forward-looking business decision. As a result, there has been a great deal of work done and resources invested in risk management in the oil and gas industry in recent years. Financial and regulatory risks have been the focus of much of this effort. But more recently, companies have started including operational risks, prioritizing them and thinking about how they can manage and monitor all risks in a coordinated way.
In collaboration with Oxford Analytica, Ernst & Young examined the strategic risks facing oil and gas companies. This study was not a random selection exercise but rather a structured consultation with industry leaders and subject matter professionals from around the world (Fig. 1). What follows are the top 10 identified strategic risks for oil and gas companies.

1. Human Capital Deficit
The growing human capital deficit in the sector has become a significant strategic threat to the industry. One study participant set out the issue: "The ability of the oil and gas services sector to expand sufficiently to meet future demand growth is questionable, not least in terms of staff. Project delays and abandonment are as much a result of capacity constraints as financial calculations, although the two are intimately linked."

2. Worsening Fiscal Terms
Worsening fiscal terms are seen as a high risk. In some cases, this is due to energy nationalism, although in others it is purely the result of political opportunism and high prices. Tax regime changes can spur additional oil and gas industry restructuring in countries such as Canada, Venezuela, Russia, and Algeria. The impact of political opportunism and high prices is a device that has been seen in both the developing and nondeveloping world.

3. Cost Controls
The third operational threat is the inability to control costs. This threat was considered great enough to have a strategic impact, and a failure to manage the threat could undermine the competitiveness of oil and gas companies. Participants agreed that the problem extends from exploration all the way through the value chain, impacting everything from refinery build costs to pipeline construction. The Upstream Capital Costs Index, which measures cost inflation in oil and gas projects, has gone up by 79% since 2000, with most of that increase coming since May 2005.
Improved UOE Pipe-Manufacturing Process Helps Meet Deepwater Pipeline Challenges
Authors: JPT staff _ 
Published: February 2015

Technology Update
Conventional pipeline design, although concerned with many factors, generally centers on the need to withstand the internal pressure in the line. The higher the pressure at which throughput can flow, the higher the flow rate, and the greater the revenue potential for the operator. However, when considering the factors critical for deepwater pipelines, much of the focus shifts to the need to withstand the external pressure on the line, particularly during installation.
With local "infield" lines, such as subsea umbilicals, risers, and flowlines, the challenge is modest because the lines are small in diameter and, thus, inherently resistant to hydrostatic collapse. These lines are generally produced as seamless pipe, which in smaller sizes is readily available and generally a suitable economic solution.
However, deepwater trunklines, especially with long-distance tiebacks, present a greater challenge. These lines must be wider in diameter to meet the production demands of large-scale, high-cost projects. Thicker pipe wall is required to ensure that pipes can withstand the hydrostatic pressure and bending that affect them as they are laid to the seabed. Often, these are 16- to 20-in.-diameter lines, which places them at the economic limit for seamless pipe production methods. A project table including some typical deepwater pipe properties is shown in Fig. 1.
It is possible to produce thick-walled, seamless pipe at these diameters by means of the Pilger process, in which hot round steel billets that have been hollowed in the initial phase of production are rolled and stretched until the desired length and diameter are achieved. However, the manufacturing process is slow and the cost of material high.
The most economic method of manufacturing pipe at these wall thicknesses and diameters is the UOE process, in which steel plate is pressed into a U and then an O shape and then is expanded circumferentially. (This process was used in the projects shown in Fig. 1.) The advantages of the UOE process notwithstanding, the current wall-thickness and diameter requirements for deepwater trunkline pipe still have proved challenging from the standpoint of manufacturing economics and installation capabilities. Only a handful of manufacturers are capable of supplying double-submerged, arc-welded (DSAW) pipe that meets specifications for the deepest projects, such as the Shell Perdido development in the Gulf of Mexico.
The acceptability of a pipeline design for a given water depth is determined by means of standard equations that measure the relationship between outside diameter, wall thickness, pipe shape, and material compressive strength.
Coalbed-Methane Pilots: Timing, Design, and Analysis
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 114169, "Coalbed-Methane Pilots: Timing, Design, and Analysis," by R.D. Roadifer, SPE, ConocoPhillips Alaska, and T.R. Moore, CDX Gas, prepared for the 2008 SPE Unconventional Reservoirs Conference, Keystone, Colorado, 10–12 February. The paper has not been peer reviewed.
Four distinct, sequential phases form a recommended process for coalbed-methane (CBM) -prospect assessment: initial screening, reconnaissance, pilot testing, and final appraisal. A step-wise approach through these phases provides a program of progressively ramping work and cost, while creating a series of discrete decision points at which analysis of results and risks can be assessed. The focus here is on the third phase, pilot testing, which normally takes place after reconnaissance and before final appraisal.

Introduction
CBM gas accounts for 9% of US domestic natural-gas production. Its importance to the energy industry has grown dramatically in the past 20 years. CBM production is expected to continue to grow significantly over the next decade, both in the US and internationally.
Historically, the CBM opportunity-identification and -evaluation process has taken place in an ad hoc, almost happenstance manner. There is no comprehensive model for planning the exploration and evaluation of a CBM play. Several authors have detailed individual phases of the assessment process for CBM, while touching on assessment process only briefly. The aim of this paper is to develop a consistent approach to evaluating CBM opportunities (i.e., pilot testing).
A stepwise phased CBM-prospect-assessment process enables gaining local knowledge early at low cost; progressively acquiring appropriate data to assess the geological situation and reservoir conditions systematically; defining and attempting to fill knowledge gaps that represent risk and uncertainty; increasing understanding of the distributions of key parameters that control reserves, deliverability, and value; and staging expenditures and providing multiple decision points throughout the process. In the initial-screening phase, the broad basin, trend, or play is considered. The scope of investigation is narrowed and knowledge is high-graded to define a play- or lead-scale area of interest. Some sort of acreage position is obtained on that play or lead, enabling the acquisition of hard data on the coal quality and reservoir characteristics by drilling a small number of dispersed reconnaissance core holes. A favorable reconnaissance program provides justification for a CBM exploration pilot test on the prospect. The pilot test serves the same function as a conventional exploration well such that if it proves successful, then the prospect can be considered to be a discovery.
A Monitoring and Verification Plan for The Otway CO2 Pilot Project
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19202, "Developing a Monitoring and Verification Plan With Reference to the Australian Otway CO2 Pilot Project," by Kevin Dodds, SPE, CSIRO, and Sandeep Sharma, SPE, Schlumberger, originally prepared for the 2008 Offshore Technology Conference, Houston, 5–8 May. The paper has not been peer reviewed.
The Australian Cooperative Research Center for Greenhouse Gas Technologies (CO2CRC) currently is injecting 100,000 tons of CO2 in a large-scale test of storage technology in a pilot project in southeastern Australia called the CO2CRC Otway Basin Project (Otway). The Otway basin with its natural CO2 accumulations and many depleted gas fields, offers an appropriate site for such a pilot project. An 80% CO2 stream is produced from a well near the depleted gas reservoir used for storage. The goal of this pilot project is to demonstrate that CO2 can be transported and stored underground safely and its behavior tracked and monitored.

Introduction
The commercial oil and gas leases in the Otway basin in Victoria, selected for the pilot project, are in an undeveloped CO2 field (Buttress), which is the source of CO2, and a depleted gas reservoir (Naylor), which is the injection/containment site. The extracted and separated CO2 stream is transported by pipeline and injected into a new well (CRC-1), drilled downdip of the existing well, and into the depleted Waarre reservoir in the Naylor field at a depth of approximately 2000 m. The existing shut-in production well (Naylor-1) is being used as the monitoring well. Characterization of the site has involved the collection of a large quantity of geological, geophysical, and other regionally relevant data and the construction of static and dynamic reservoir models. The regional formations provide an excellent porous and permeable geological formation that provides a highly suitable reservoir system for CO2 storage. In summary, the site-assessment results, indicating that the Waarre formation is a suitable site for CO2 storage, conclude the following key attributes of the site. There are no significant faults evident in the wells at the Waarre C level; there is a fairly uniform Waarre C thickness. The local and regional seals have contained a number of natural CO2 accumulations in the eastern Otway basin over geological time. The storage reservoir has sufficient porosity and permeability to be able to accept the injected CO2 at forecast rates. The injected CO2 is predicted to move updip from the injector location and migrate to the crest of the fault block and accumulate below the residual-methane gas cap in the vicinity of the existing Naylor-1 well. The selected site has the major advantage of being onshore rather than offshore, allowing the project research teams to test and further refine the monitoring and verification techniques at a more accessible location.
Technology Focus: Artificial Lift (July 2009)
Authors: Noonan Shauna 
Published: February 2015

Technology Focus
Artificial-lift technology has been around for many years, yet the concept of artificial-lift selection and design has been more of an art than a science. Throughout the last decade, both operating companies and manufacturers have made considerable effort toward understanding the science behind artificial-lift systems and their performance. For example, research on beam-pump slippage and gas lift valve performance has greatly influenced the way in which the industry now designs those lift systems. In 2007, SPE published a revised Petroleum Engineering Handbook; Volume IV includes many of these advancements and understandings of lift performance for common forms of artificial lift. This publication is recommended highly for anyone involved in production engineering and artificial lift.
Artificial-lift systems continue to evolve, and their operational envelopes expand. The 2009 ATCE Technical Program Committee received a significant number of artificial-lift related abstracts, which resulted in two sessions showcasing great artificial-lift research, field trials, and case studies. When you come to New Orleans this October, you will learn about the most recent advancements and lessons learned on all types of artificial lift.
Three examples of such advancements are featured in this publication. Each of these technologies enhances a lift system or methodology that has been available for years, putting a new spin (pun intended) on something "old." While the field trials of these systems have been specific to a given region (i.e., Alaska, Cuba, and Russia), their application potential is global.
The papers selected for additional reading below, reflect other areas in the artificial-lift community that are "hot" topics—finding and understanding better gaswell-deliquification techniques, solutions to high-volume thermal applications, and effective artificial-lift optimization.
Artificial Lift additional reading available at OnePetro: www.onepetro.org
SPE 116659 - "Artificial Lift Optimization in the Orito Field" by Sandy Williams, SPE, ALP Ltd., et al.
SPE 115849 - "Pushing the Limit: High-Rate Artificial-Lift Evaluation for a Sour, Heavy-Oil, Thermal EOR Project in Oman" by G.H. Lanier, SPE, Petroleum Development Oman, et al.
SPE 115934 - "Development of a New Plunger-Lift Model Using Smart Plunger Data" by G.K. Chava, SPE, Texas A&M University, et al.
Experience With Metal PCPs in a Cuban Heavy-Oil Field
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120645, "Field- Implementation Experience With Metal- PCP Technology in Cuban Heavy-Oil Fields," by E. Guerra, SPE, and A. Sanchez, SPE, Sherritt International Oil and Gas, and C. Matthews, SPE, C-FER Technologies, originally prepared for the 2009 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 4-8 April. The paper has not been peer reviewed.
Progressing-cavity pumps (PCPs) have proved to be a successful and reliable artificial-lift system for production of heavy oil over the past few decades. The application of PCP technology for production of oil wells continues to expand rapidly because of ongoing advances in versatility, lift capacity, durability, and economy. As a result, the application envelope for PCP systems has grown substantially to the point where these systems now compete successfully in many areas that were traditionally reserved for rod- and electrical-submersible-pump technologies.

Introduction
PCPs have found numerous applications in many industries as an efficient means to transfer, transport, and/or lift fluids of a diverse nature. The use of PCPs as an artificial-lift method for oil wells has gained increasing acceptance since their first commercial use in heavy-oil applications in the 1980s, and they have now become the preferred lift method in numerous oilfield developments worldwide.

PCP Systems
A typical PCP consists of two basic components: the first is called the stator—it is typically run on the end of the production-tubing string and remains stationary during operation; the second is called the rotor—it is run on the end of a sucker-rod string and rotates within the fixed stator when in operation. The elongated steel rotor is machined with a circular cross section and a uniform helix with a prescribed eccentricity and pitch length. Rotors are normally chrome coated to reduce friction and improve wear resistance in service. The stator cavity takes the form of a double internal helix with a pitch length that is double that of the rotor—with the rotor installed, this configuration creates two series of parallel cavities within the pump that are filled by produced fluid. As the rotor spins within the stator through the application of torque to the rod string at surface, wellbore fluid is drawn into the pump and is displaced from the intake through the cavities along the stator to the discharge where it exits at high pressure into the production-tubing string.
Development of Natural-Gas Supply Chain by Means of Natural-Gas Hydrates
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12880, "Development of Natural Gas Supply Chain by Means of Natural-Gas Hydrate (NGH)," by Tomonori Nogami and Shigeru Watanabe, Mitsui Engineering & Shipbuilding, originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.
Because natural-gas hydrates (NGHs) can be stabilized at 253 K and are easy to handle, NGHs are expected to be an alternative natural-gas transportation medium to the currently available systems including liquefied natural gas (LNG). A joint industry and government project has been initiated to demonstrate the feasibility of natural-gas land transport and ocean transport in the form of NGH.

Introduction
Since the idea of ocean transportation of natural gas in the form of NGH was advocated by J. S. Gudmundsson of the Norwegian University of Science and Technology in 1996, various research on NGH ocean transportation has been performed. A test plant for NGH production has been built in the US. One company has been conducting research and development on the NGH-production process, a carrier ship, and the regasification process since 2001. A new conceptual design has been developed for a process development unit (PDU).

NGH Process Developments
Mitsui Engineering & Shipbuilding succeeded in producing NGH continuously at a high speed in March 2001, and in September of that year they started research and development of NGH in full scale to commercialize the NGH process. In January 2002, a continuous-production plant was completed that produced NGH pellets, and in 2003 a regasification facility was added. These facilities began operation as the first-stage PDU (Fig. 1) with a 600-kg/d NGH-pellet production capacity. This plant can produce high-purity NGH pellets at a high speed continuously. Feed gas is contacted with water, causing a reaction that generates NGH, followed by dewatering and cooling. The PDU made it possible to operate a circuit process. NGH pellets are made of the powder produced in the process and then are regasified to natural gas to recycle in the plant.
In 2005, a second-stage NGH-production plant called a bench-scale unit (BSU) (Fig. 2) was completed. Although NGH production from mixed gas had seemed difficult to realize, artificial production of NGH succeeded at the BSU. Fig. 3 shows NGH pellets produced by the BSU in the pellet-storage drum. As an experiment of NGH land transportation, NGH pellets were transported 350 km to a 2005 World Exposition.
Technology Focus: CO2 Applications (July 2009)
Authors: Gomersall Sam 
Published: February 2015

Technology Focus
Can enhanced oil recovery (EOR) contribute to CO2 abatement as part of a climate-change-mitigation program?
EOR by use of CO2 is an important technique for increasing oil recovery. Carbon capture and storage (CCS) will be an increasingly important technique for reducing atmospheric emissions of CO2 as part of a climate-change-mitigation program. What role does EOR have in reducing CO2 emissions to the atmosphere and in supporting climate-change mitigation?
It is clear that the two processes have very different objectives: EOR focuses on maximizing the amount of oil recovered, whereas CCS focuses on sequestration of CO2 for the long term.
Most existing EOR projects use naturally occurring CO2, produced from subsurface traps especially for EOR. Rather than mitigating emissions, these projects contribute to global CO2 emissions. Clearly, this situation is not good for the climate.
Other emerging EOR projects and future projects could use anthropogenic CO2 (i.e., CO2 from industrial sources). When the CO2 associated with the use of the EOR oil is taken into account along with the processing and emissions from CO2 recycling, EOR is a significant producer of greenhouse gas and not a CO2-abatement technique.
However, EOR oil does have a lower emissions intensity than non-EOR oil, assuming that the CO2 is from anthropogenic sources. It would be much better, for example, to produce a barrel of EOR oil than a barrel of oil from oil sands.
EOR has an important role to play in energy security, but from a global-climate perspective, it is not a CO2-abatement technique.
CO2 Applications additional reading available at OnePetro: www.onepetro.org
SPE 116661 • "Optimizing Injection Intervals in Vertical and Horizontal Wells for CO2 Sequestration" by Navanit Kumar, SPE, University of Texas at Austin, et al.
SPE 119747 • "Thermodynamic Criteria and Final Results of WAG CO2 Injection in a Pilot Project in Croatia" by D. Novosel, INA-Naftaplin
SPE 114553 • "Produced CO2 Storage Into Aquifer in an Offshore Field, Malaysia" by Dewanto Odeara Kartikasurja, SPE, Senergy Ltd.