bluuebunny/crossref_metadata_2025_split huggingface dataset:
Startup of Pazflor Giant Offshore Angola Tackles Challenges From Two Reservoirs
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23176, ’Startup of a Giant,’ by Arnaud Constant and Lionel Ramat, Total E&P Angola, prepared for the 2012 Offshore Technology Conference, Houston, 30 April- 3 May. The paper has not been peer reviewed.
The Pazflor development includes four reservoirs in Block 17 deep offshore Angola, which produce to a floating production, storage, and offloading (FPSO) unit through one Oligocene subsea loop and three Miocene lines connected to subsea separation units (SSUs) and subsea pumps, with associated-gas and water-injection facilities (Fig. 1). The startup of the Pazflor field required a response to three simultaneous challenges—startup of a large complex facility; flow assurance for two different reservoirs and oil qualities, an Oligocene field with light oil and Miocene fields with heavy viscous oil; and operating innovative Miocene subsea facilities with gas/liquid separation on the seabed.
Startup Preparation
Manning and Training. Although most of the production personnel were already experienced with FPSO operations, specific attention was given to training and a local training center at the Total E&P Angola offices was maximized.
One of Pazflor’s innovations was the design and use of an immersive training simulator (Fig. 2). This simulator was generated from construction of a 3D model and represents all the topside facilities with realistic rendering. In this 3D environment, operators move virtually through a simple interface, allowing for familiarization with their future facilities. Because all equipment is tagged, the operator can easily link his work documents, such as process flow diagrams and piping and instrumentation diagrams, to the actual FPSO environment before its completion or without actually being there. This simulator also can be used to simulate procedures execution, either individually or in a group, thanks to preloaded scenarios.
Startup Milestones and Initial Planning. The precommissioning, commissioning, and startup activities were structured according to milestones defined in the early project stage by field operations teams and included in relevant project-packages contracts. This breakdown by startup milestones was taken into account by the commissioning team from the early onshore commissioning stage and was later used to prioritize offshore construction, commissioning, and startup activities during the offshore campaign.
Eighteen startup milestones were considered initially, focusing on utilities, oil production, water injection, gas injection, and export systems and covering prestartup, startup, and normal- operations phases. The facilities were split into systems and subsystems, with a total of 669 subsystems, each linked to a specific startup milestone.
Geosteering With Sonic-Log Data
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146732, ’Geosteering With Sonic in Conventional and Unconventional Reservoirs,’ by Jason Pitcher, SPE, Jennifer Market, and David Hinz, Halliburton, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
Azimuthal variations with sonic logs have been observed in wireline and logging-while-drilling (LWD) data. Basic reactive-geosteering methods have been used, including drilling until a real-time sonic log detected a change in formation velocity then altering the wellbore trajectory. Taking sonic geosteering a step further has been proposed by providing real-time azimuthal images that show the velocities as they vary around the wellbore. These images can be transmitted at shallow and deep depths of investigation (DOIs) to determine how close an approaching boundary might be.
Introduction
LWD sonic tools have been used for simple geosteering since their introduction in the 1990s. The measurements typically were limited to the compressional-wave arrivals and (if available) refracted-shear-wave velocities. The use of real-time information was limited to simple correlation or direct-interpretation techniques. The practical use of these measurements was limited by the complexity of the measurement in terms of environmental conditions. These tools have found new application and use in recent work in shale-reservoir systems, including the Haynesville, Eagle Ford, Woodford, and Marcellus. In addition to using the compressional- and shear-wave data, these measurements are processed to provide dynamic data for Young’s modulus and Poisson’s ratio. The tools then are used to produce a real-time brittleness index that can be used to land and geosteer within the optimal production zone.
Measurement Considerations DOI/Depth of Detection. The sonic-tool DOI depends on the source frequency, formation resonant frequency, source/receiver spacing, and the configuration (i.e., monopole, dipole, or quadrupole) of the source. A general rule of thumb is to estimate the DOI as approximately one wavelength. Thus, for a given formation, a high-frequency source (10 kHz) would yield half the DOI of a low-frequency source at 5 kHz. Or, use of the same 10-kHz source in a 100sec/ft-velocity formation vs. a 50-sec/ft-velocity formation, the 50sec/ft-velocity formation would have a deeper DOI. This effect is complicated by each formation having a natural resonant-frequency range. In general, fast formations favor high frequencies and slow formations favor low frequencies. Annulus size also can affect the resonant frequency: A small annulus shifts the resonant-frequency range higher than a large annulus. Though the rule of thumb is a reasonable starting estimate, several factors can increase or decrease the DOI. Fig. 1 shows the effects of frequency and slowness on DOI.
Emerging Frontiers: The Arctic Frontier
Authors: Spath Jeff 
Published: February 2015

President's column
One of the oil and gas industry’s most talked about emerging frontiers—but perhaps least understood in terms of familiar metrics—is the Arctic region. The Arctic refers to a portion of the globe above 66.5o N latitude that is roughly the size of Africa. Encompassing about 6% of the Earth’s surface, the Arctic consists of about one-third land, one-third continental shelf, and one-third waters deeper than 500 m (Budzick. 2009).
The Arctic contains portions of eight countries: Canada, Denmark (Greenland), Finland, Iceland, Norway, Russia, Sweden, and the United States. I cannot imagine any other region on Earth this large that has had so few efforts to explore for, develop, and produce hydrocarbons.
Arctic History
Indigenous people of the Arctic have known for centuries about oil seeps along the coastal plains, and even used pitch as a sealant on canoes. Back in 1789, oil seeps along the Mackenzie River, located within Canada, were reported by Russian settlers in Alaska (Bishop. 2011). Shell geologists first investigated Alaska’s oil potential in 1918. Sub-arctic oil was first discovered in Canada’s Northwest Territories in the 1920s. Russian geoscientists began exploring northern Siberia during World War II, and made their first major oil and gas discoveries there in the early 1960s (Bishop. 2011).
The first US federal lease sale on Alaska’s North Slope was held in 1958, and the first offshore lease sale in the Beaufort Sea in 1979. From the 1960s through the late 1980s, oil was discovered at Prudhoe Bay, gas was discovered in the Barents Sea, and the first exploration wells were drilled in the US Chukchi Sea.
After a period of inactivity due to low oil prices, exploration resumed in Canada’s Mackenzie Delta region in 2000, and in the US portion of the Beaufort Sea in 2005. The 5-month 2010 US moratorium on new deepwater drilling had an adverse impact on US Arctic drilling activity, and political and environmental opposition to Arctic exploration has been tougher since the moratorium was lifted, both in the US and elsewhere.
Nevertheless, due to growing demand and declining production from mature oil fields worldwide, international operators and governments have been initiating new Arctic exploration activities. This past summer, Norway opened a new area in the southeastern Barents Sea to offshore drilling. The service sector is following. Schlumberger and Baker Hughes, for example, opened new bases in the Norwegian town of Hammerfest, on the 71st parallel.
Size of the Prize
Any estimate of Arctic hydrocarbon resources suffers from considerable uncertainty, due to the limited amount of data from wells drilled throughout this enormous region.
In 2008, the US Geological Survey completed the Circum-Arctic Resource Appraisal. The study estimated total undiscovered conventional hydrocarbon resources of 90 billion bbl of oil, 1,669 Tcf of natural gas, and 44 billion bbl of natural gas liquids—a total of 412 billion BOE. That constitutes about 30% of the world’s undiscovered gas and 13% of the undiscovered oil (Bishop. 2011).
Displacing Diesel: The Rising Use of Natural Gas by Onshore Operators
Authors: Jacobs Trent 
Published: February 2015

Natural Gas
Seizing on historic margins in domestic prices, North American oil and gas companies are increasing their efforts to use more natural gas and less diesel fuel to power their field operations. Until now, oil and gas companies have been ordering natural gas-powered rigs to qualify the technology through pilot programs in the field. However, “the inflection point” may have been reached, said Brad Bodwell, senior vice president of corporate and business development at Prometheus Energy. The company is one of the largest suppliers of liquefied natural gas (LNG) to the North American oil and gas industry and is entering a stage of “rapid growth” because of economic forces and major gains in domes-tic gas production. As the technology is evolving, so is its nomenclature. Operators and service companies are using two terms to describe engines that are fueled by a simultaneous injection of natural gas and diesel: “dual fuel” and “bifuel.”
Prometheus fueled up its first natural gas-powered generator sets on a drilling rig for operator EnCana in the Haynesville shale in mid-2010. “Since then, we have grown at a rate of about 80% per annum in terms of volume that we ship to our customers,” said Bodwell. In 2013, Prometheus had access to about 500,000 gal/D of LNG and was supplying seven operators in the United States and Canada. In total, North American LNG facilities produced 800,000 gal/D in 2013. New LNG facilities under construction and expansions of older facilities will bring the available supply of LNG up to 1.1 million gal/D by year-end. With several more plants already funded and expected to come online after 2014, the daily supply of LNG is projected to soar to 2.6 million gal/D after next year.
Bodwell estimates that natural gas is fueling as much as 7% of North America’s 1,100 horizontal drill rig fleets, but he predicts that share to soar to 50% within the next 2 years. There are environmental drivers as well since natural gas is the cleanest burning of all fossil fuels (Table 1). “You’re getting a fuel that is going to reduce your environmental footprint and, at the same time, it saves enough money that it pays for the cost of conversion,” he said. “So we don’t need to wait to achieve some sort of scale benefit or a government injection of capital into the industry to make it work. It is all stuff we know how to do.”
Searching for Opportunities in Environmental Trouble
Authors: Rassenfoss Stephen 
Published: February 2015

Water Reuse
There are more than 4,000 miles of rivers and creeks in Pennsylvania as a result of the water draining out of abandoned coal mines. The orange-tinted water and rust-colored rocks are reminders of the damage going on since the days Pennsylvania mines powered the United States’ rise as a global industrial power.
Now producing natural gas by fracturing, the Marcellus shale is driving the state’s economy and those dead streams could present an unusual opportunity: offering both a source of much-needed water and a way to help clean up of waterways polluted by coal mine waste.
There is an exploration and production (E&P) company in the state, Seneca Resources, using the abandoned mine drainage (AMD) water for fracturing. By pumping as much as 500,000 gal/D of water from an old coal mine with low levels of sulfates, iron, and often other metals, it can improve the quality of the water downstream by taking those things out.
“There are a lot of opportunities in the southwestern part of the state,” because there are so many flooded old mine shafts draining into waterways, said Doug Kepler, vice president of the environmental engineering group at Seneca Resources. “There is a lot of activity. A lot of operators are looking into whether they can do that.”
Water used by Seneca requires little treatment because the sulfate and iron levels are low, but that is the exception in Pennsylvania, where chemicals leached from the water in old coal mines and from mining waste heaps can create metal-laden, acidic water that is deadly to fish, insects, and plant life in rivers.
While many E&P companies are interested in AMD water for fracturing, there are technical and legal obstacles to overcome.
Treatment methods are needed for water that is often highly acidic, loaded with sulfates, and high in iron or other metals. The cost of that water has to be competitive with relatively inexpensive freshwater sources, and that amount must cover the cost of disposal of any byproducts. And environmental regulators need to answer a critical question: If an oil company uses mine drainage for a time as a source of water for fracturing, will it be responsible for that water source forever?
The state has said it supports the use of AMD for fracturing, and Pennsylvania environmental regulators have supported a bill limiting liability for AMD use by the oil industry. The US Environmental Protection Agency has remained mute on liability questions related to AMD use, said Tom Gray, energy and natural resources manager at Tetra Tech, who delivered a presentation on the advantages of using mine water for fracturing. “To my knowledge, the EPA has never provided a direct written response.”
Recently Released Guidelines Supplement Petroleum Resources Management System
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 162520, ’New Guidelines Document Assists With PRMS Applications,’ by W. John Lee, SPE, University of Houston; Satinder Purewal, SPE, Energy Equity Resources; and D. Ronald Harrell, SPE, Ryder Scott, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.
The Guidelines for Application of the Petroleum Resources Management System (AG) document was issued in November 2011 to accompany and support the Petroleum Resources Management System (PRMS). The AG updates the 2001 document Guidelines for the Evaluation of Petroleum Reserves and Resources. This document will assist reserves evaluators throughout the world in understanding PRMS and how it should be applied in financial, regulatory, and reporting activities. Two new chapters have been added to the AG, eight others have been updated, and a comprehensive glossary has been added.
Introduction
The AG was issued by SPE, along with the American Association of Petroleum Geologists (AAPG), the World Petroleum Council (WPC), the Society of Petroleum Evaluation Engineers (SPEE), and the Society of Exploration Geophysicists (SEG). It is available free to the public on the SPE website.
SPE has a long history of developing common standards for petroleum-resource definitions to provide consistency, transparency, and reliability to benefit stakeholders involved in international finance, regulation, and reporting. In 1997, SPE and the WPC achieved a milestone in standardization when they approved the Petroleum Reserves Definitions. In 2000, SPE, WPC, and AAPG approved an updated version of the definitions, published as the Petroleum Resources Classification System and Definitions. In 2001, SPE issued Guidelines for the Evaluation of Petroleum Reserves and Resources, the predecessor of AG, to provide guidance for application of the 1997 and 2000 definitions. Then, in 2007, SPE, WPC, AAPG, and SPEE approved the PRMS. SEG subsequently endorsed PRMS.
PRMS has rapidly become the global standard for resources definitions and classification. For example, the US Securities and Exchange Commission used PRMS as a guide for its updated rules, Modernization of Oil and Gas Reporting, published 31 December 2008.
SPE and its sister organizations recognized that new guidelines were required to provide guidance for application of PRMS, replacing the 2001 guidelines. The 2001 guidelines were the starting point for AG, which has been updated by adding two new chapters and by modifying eight existing chapters. The two new chapters are
Assessment of Petroleum Resources Using Deterministic Procedures (Chapter 4)
Unconventional Resources Estimation (Chapter 8)
Probabilistic and Deterministic Methods: Applicability in Unconventional Reservoirs
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164820, ’Probabilistic and Deterministic Methods: Applicability in Unconventional Reservoirs,’ by C. Coll, SPE, and S. Elliott, BG, prepared for the 2013 EAGE Annual Conference and Exhibition/SPE Europec, London, 10-13 June. The paper has not been peer reviewed.
Reserves- and resources-evaluation methods in unconventional reservoirs are different from those for conventional reservoirs. Depending on the phase of the resource play, a deterministic, probabilistic, or hybrid method may be required, with the most effective method evolving from deterministic toward probabilistic as the resource play moves from the early phase to the mature phase. To define the best method to use in a particular area, the evaluator should first identify the phase of the resource play and evaluate the amount of data available.
Introduction
For unconventional reservoirs, classification systems similar to those for conventional reservoirs can be used (Fig. 1). These systems include prospective resources, estimated contingent resources at discovery, followed by reserves, with maturation linked to the phases of the resource play.
As the resource play matures and technologies are screened, the development projects are better defined. Sections of the estimated resource volumes may be assigned to the contingent- resources subclasses using, for instance, the SPE Petroleum Resources Management System (PRMS) that recognizes the technical and commercial maturation toward reserves. Because unconventional accumulations are pervasive and developed with high-density drilling, well counts are typically large, making statistical analysis of well performance feasible. As a result, probabilistic techniques may be more appropriate to understand the uncertainty ranges of estimated ultimate recovery (EUR) per well and associated confidence levels. Extrapolation of results requires careful consideration of the geology and engineering characteristics of a particular area to predict well productivity. This analysis could be more intricate than that for conventional reservoirs because of the short production history and the particularly complex displacement mechanisms that may be happening in these reservoirs.
For the estimation of resources in both conventional and unconventional reservoirs, it is important to understand the effect of reservoir uncertainties and development plans. Geological uncertainties such as gross rock volume, porosity, permeability, hydrocarbon saturation, and reservoir continuity have a large effect on in-place volumes. Engineering uncertainties (e.g., relative permeability, capillary pressures, viscosities, aquifer properties) affect the physical processes in the reservoir during the production of hydrocarbons, determining gas/oil recoveries and, finally, the ultimate reserves/resources.
Integrating Well, Reservoir, and Facility Management Improves Field's Production
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 16523, ’Oman's Large-Carbonate-Field Production Improvement Through Integrated Well, Reservoir, and Facility Management,’ by S.M. Al-Khadhuri, M.M. Al-Harthi, and A. Alkalbani, Petroleum Development Oman, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
A carbonate field developed by Petroleum Development Oman is one of the largest fields in the Sultanate of Oman and has been running for more than 4 decades. An integrated wells, reservoir, and facility management approach has been implemented to create more focus and discipline with the aim of achieving an efficiently monitored and controlled asset and highly synchronized multiteam actions.
Introduction
The field is located in the north of the Sultanate of Oman, and it is one of Oman’s largest fields. The reservoir layers dip uniformly at 15° to the northeast (Fig. 1). The field is a highly complex carbonate reservoir of the Natih formation and is subdivided into seven units, Natih A through Natih G, and the Shuabia reservoir. It has been running since 1967 and continues to contribute significantly.
The development strategy began with natural depletion with vertical wells and followed with two mechanisms, gas/oil gravity drainage (GOGD) and waterflood. The GOGD process concentrates more on fractured reservoir rock, while the waterflood process targets the layers with a relatively low degree of fracturing.
The GOGD development consists of five crestal gas-injection wells and rows of down-flank producers that tap oil from a fractured oil rim. The reservoir pressure is managed by gas injection. The gas-injection rates are set to replace voidage and to maintain reservoir pressure. For the matrix wells, the reservoir pressure is managed by waterflood (water injection).
This combination of different drive mechanisms in a highly fractured reservoir that yields to interference and gas/water short-circuiting makes the management of the field very challenging.
To overcome these challenges, an integrated well, reservoir, and facility management strategy has been established in a way that ensures integration with multiple disciplines and uses many tools. As a result, an improvement in production has been seen that reflects successful implementation of the strategy.
Wells and Reservoir Reviews
Wells are reviewed on a yearly basis in order to have a systematic approach for reviewing wells. Approximately 26 sectors (more than 450 wells) from different reservoirs have been reviewed collaboratively. Multidisciplinary involvement from the well and reservoir management (WRM) team, the development and planning (DP) team, and the new oil (NO) team, and alignment to mature identified activities, played a crucial role in effectively sharing ideas and lessons learned and implementing activities.